Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2017shares | |
Document and Entity Information [Abstract] | |
Entity Registrant Name | Fortis Inc. |
Entity Central Index Key | 1,666,175 |
Current Fiscal Year End Date | --12-31 |
Document Type | 40-F |
Document Period End Date | Dec. 31, 2017 |
Document Fiscal Year Focus | 2,017 |
Document Fiscal Period Focus | FY |
Amendment Flag | false |
Entity Common Stock, Shares Outstanding | 421,137,419 |
Entity Current Reporting Status | Yes |
Consolidated Balance Sheets
Consolidated Balance Sheets - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 | |
Current assets | |||
Cash and cash equivalents | CAD 327 | CAD 269 | |
Accounts receivable and other current assets (Note 6) | 1,131 | 1,127 | |
Prepaid expenses | 79 | 85 | |
Inventories (Note 7) | 367 | 372 | |
Regulatory assets (Note 8) | 303 | 313 | |
Total current assets | 2,207 | 2,166 | |
Other assets (Note 9) | 480 | 406 | |
Regulatory assets (Note 8) | 2,742 | 2,620 | |
Property, plant and equipment, net (Note 10) | 29,668 | 29,337 | |
Intangible assets, net (Note 11) | 1,081 | 1,011 | |
Goodwill (Note 12) | 11,644 | 12,364 | |
Total assets | 47,822 | 47,904 | |
Current liabilities | |||
Short-term borrowings (Note 14) | 209 | 1,155 | |
Accounts payable and other current liabilities (Note 13) | 2,053 | 1,970 | |
Regulatory liabilities (Note 8) | 490 | 492 | |
Current installments of long-term debt (Note 14) | 705 | 251 | |
Current installments of capital lease and finance obligations (Note 15) | 47 | 76 | |
Total current liabilities | 3,504 | 3,944 | |
Other liabilities (Note 16) | 1,210 | 1,279 | |
Regulatory liabilities (Note 8) | 2,956 | 1,691 | |
Deferred income taxes (Note 23) | 2,298 | 3,263 | |
Long-term debt (Note 14) | 20,691 | 20,817 | |
Capital lease and finance obligations (Note 15) | 414 | 460 | |
Total liabilities | 31,073 | 31,454 | |
Commitments and Contingencies (Note 30) | |||
Equity | |||
Common shares | [1] | 11,582 | 10,762 |
Preference shares (Note 18) | 1,623 | 1,623 | |
Additional paid-in capital | 10 | 12 | |
Accumulated other comprehensive income (Note 19) | 61 | 745 | |
Retained earnings | 1,727 | 1,455 | |
Shareholders' equity | 15,003 | 14,597 | |
Non-controlling interests (Note 20) | 1,746 | 1,853 | |
Total equity | 16,749 | 16,450 | |
Total liabilities and equity | CAD 47,822 | CAD 47,904 | |
[1] | No par value. Unlimited authorized shares; 421.1 million and 401.5 million issued and outstanding as at December 31, 2017 and 2016, respectively |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - shares shares in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Issued (shares) | 421.1 | 401.5 |
Outstanding (shares) | 421.1 | 401.5 |
Consolidated Statements of Earn
Consolidated Statements of Earnings - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Income Statement [Abstract] | ||
Revenue | CAD 8,301 | CAD 6,838 |
Expenses | ||
Energy supply costs | 2,361 | 2,341 |
Operating expenses | 2,261 | 2,031 |
Depreciation and amortization | 1,179 | 983 |
Total expenses | 5,801 | 5,355 |
Operating income | 2,500 | 1,483 |
Other income, net (Note 22) | 127 | 53 |
Finance charges | 914 | 678 |
Earnings before income tax expense | 1,713 | 858 |
Income tax expense (Note 23) | 588 | 145 |
Net earnings | 1,125 | 713 |
Net earnings attributable to: | ||
Non-controlling interests | 97 | 53 |
Preference equity shareholders | 65 | 75 |
Common equity shareholders | 963 | 585 |
Net earnings | CAD 1,125 | CAD 713 |
Earnings per common share (Note 17) | ||
Basic (CAD per share) | CAD 2.32 | CAD 1.89 |
Diluted (CAD per share) | CAD 2.31 | CAD 1.89 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Statement of Comprehensive Income [Abstract] | ||
Net earnings | CAD 1,125 | CAD 713 |
Other comprehensive (loss) income (Note 19) | ||
Unrealized foreign currency translation losses, net of hedging activities and income tax expense of $2 and $nil, respectively | (781) | (50) |
Available-for-sale investment, net of income tax expense, of $nil and $nil, respectively | 0 | 2 |
Cash flow hedges, net of income tax expense, of $nil and $2, respectively | 2 | 3 |
Employee future benefits, net of income tax expense, of $nil and $nil, respectively | (4) | (1) |
Other comprehensive loss | (783) | (46) |
Comprehensive income | 342 | 667 |
Comprehensive income attributable to: | ||
Non-controlling interests | (2) | 53 |
Preference equity shareholders | 65 | 75 |
Common equity shareholders | 279 | 539 |
Comprehensive income | CAD 342 | CAD 667 |
Consolidated Statements of Com6
Consolidated Statements of Comprehensive Income (Parenthetical) - CAD | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Statement of Comprehensive Income [Abstract] | ||
Unrealized foreign currency translation losses, tax | CAD 2,000,000 | CAD 0 |
Available-for-sale investment, tax | 0 | 0 |
Cash flow hedges, tax | 0 | 2,000,000 |
Employee future benefits, tax | CAD 0 | CAD 0 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Operating activities | ||
Net earnings | CAD 1,125 | CAD 713 |
Adjustments to reconcile net earnings to net cash provided by operating activities: | ||
Depreciation - property, plant and equipment | 1,055 | 873 |
Amortization - intangible assets | 97 | 79 |
Amortization - other | 27 | 31 |
Deferred income tax expense (Note 23) | 544 | 98 |
Accrued employee future benefits | 27 | 58 |
Equity component of allowance for funds used during construction (Note 22) | (74) | (37) |
Other | (16) | 64 |
Change in long-term regulatory assets and liabilities | 68 | (17) |
Change in working capital (Note 27) | (97) | 22 |
Cash from operating activities | 2,756 | 1,884 |
Investing activities | ||
Capital expenditures - property, plant and equipment | (2,813) | (1,912) |
Capital expenditures - intangible assets | (211) | (149) |
Contributions in aid of construction | 102 | 50 |
Proceeds on sale of assets | 6 | 50 |
Business acquisitions, net of cash acquired (Note 25) | 0 | (4,841) |
Other | (109) | (89) |
Cash used in investing activities | (3,025) | (6,891) |
Financing activities | ||
Proceeds from long-term debt, net of issuance costs (Note 14) | 2,538 | 4,136 |
Repayments of long-term debt and capital lease and finance obligations | (952) | (336) |
Borrowings under committed credit facilities (Note 31) | 2,085 | 668 |
Repayments under committed credit facilities (Note 31) | (2,039) | (499) |
Net repayments and borrowings under committed credit facilities (Note 31) | (365) | (76) |
Net change in short-term borrowings | (892) | 392 |
Advances from non-controlling interests | 4 | 1,361 |
Issue of common shares to an institutional investor | 500 | 0 |
Issue of common shares, net of costs, and dividends reinvested | 61 | 45 |
Redemption of preference shares (Note 18) | 0 | (200) |
Dividends | ||
Common shares, net of dividends reinvested | (419) | (316) |
Preference shares | (65) | (72) |
Subsidiary dividends paid to non-controlling interests | (109) | (53) |
Other | (8) | 0 |
Cash from financing activities | 339 | 5,050 |
Effect of exchange rate changes on cash and cash equivalents | (12) | (16) |
Change in cash and cash equivalents | 58 | 27 |
Cash and cash equivalents, beginning of year | 269 | 242 |
Cash and cash equivalents, end of year | CAD 327 | CAD 269 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Equity - CAD shares in Millions, CAD 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 (Note 20) |
Increase (Decrease) in Equity [Roll Forward] | |||||||
Adoption of new accounting policy | CAD 16 | CAD 16 | |||||
Beginning balance at Dec. 31, 2015 | 10,353 | CAD 5,867 | CAD 1,820 | CAD 14 | CAD 791 | 1,388 | CAD 473 |
Beginning balance (shares) at Dec. 31, 2015 | 281.6 | ||||||
Increase (Decrease) in Equity [Roll Forward] | |||||||
Net earnings | 713 | 660 | 53 | ||||
Other comprehensive loss | (46) | (46) | |||||
Common shares issued | 4,684 | CAD 4,684 | |||||
Common shares issued (shares) | 114.4 | ||||||
Common shares issued under dividend reinvestment plan and other | 207 | CAD 211 | (4) | ||||
Common shares issued under dividend reinvestment plan and other (shares) | 5.5 | ||||||
Stock-based compensation | 2 | 2 | |||||
Advances from non-controlling interests | 1,361 | 1,361 | |||||
Foreign currency translation impacts | 19 | 19 | |||||
Subsidiary dividends paid to non-controlling interests | (53) | (53) | |||||
Redemption of preference shares | (197) | (197) | |||||
Dividends declared on common shares | (534) | (534) | |||||
Dividends declared on preference shares | (75) | (75) | |||||
Ending balance at Dec. 31, 2016 | 16,450 | CAD 10,762 | 1,623 | 12 | 745 | 1,455 | 1,853 |
Ending balance (shares) at Dec. 31, 2016 | 401.5 | ||||||
Increase (Decrease) in Equity [Roll Forward] | |||||||
Net earnings | 1,125 | 1,028 | 97 | ||||
Other comprehensive loss | (783) | (684) | (99) | ||||
Common shares issued | 500 | CAD 500 | |||||
Common shares issued (shares) | 12.2 | ||||||
Common shares issued under dividend reinvestment plan and other | 315 | CAD 320 | (5) | ||||
Common shares issued under dividend reinvestment plan and other (shares) | 7.4 | ||||||
Stock-based compensation | 3 | 3 | |||||
Advances from non-controlling interests | 4 | 4 | |||||
Subsidiary dividends paid to non-controlling interests | (109) | (109) | |||||
Dividends declared on common shares | (691) | (691) | |||||
Dividends declared on preference shares | (65) | (65) | |||||
Ending balance at Dec. 31, 2017 | CAD 16,749 | CAD 11,582 | CAD 1,623 | CAD 10 | CAD 61 | CAD 1,727 | CAD 1,746 |
Ending balance (shares) at Dec. 31, 2017 | 421.1 |
Consolidated Statements of Cha9
Consolidated Statements of Changes in Equity (Parenthetical) - CAD / shares | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Statement of Stockholders' Equity [Abstract] | ||
Dividends declared (CAD per share) | CAD 1.65 | CAD 1.55 |
Description of Business
Description of Business | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Description of Business | DESCRIPTION OF BUSINESS Fortis Inc. ("Fortis" or the "Corporation") is principally an international electric and gas utility holding company. Fortis segments its business based on regulatory status and service territory, as well as the information used by the chief operating decision maker in deciding how to allocate resources and evaluate the performance of the segment. The Corporation's reporting segments allow senior management to evaluate the operational performance and assess the overall contribution of each segment to the long-term objectives of Fortis. Each entity within the reporting segments operates with substantial autonomy, assumes responsibility for net earnings and its own resource allocation. The following summary describes the operations included in each of the Corporation's reportable segments. Regulated Utilities - United States a. ITC : Primarily comprised of 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, (collectively "ITC"). ITC was acquired by Fortis in October 2016, with Fortis owning 80.1% of ITC and an affiliate of GIC Private Limited ("GIC") owning a 19.9% minority interest (Notes 20 and 25 ). Also included in the ITC segment is the net corporate expenses and activity of ITC Investment Holdings. ITC owns and operates high-voltage transmission lines, in Michigan's lower peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma, that transmit electricity from generating stations to local distribution facilities connected to ITC's systems. b. UNS Energy: Primarily comprised of Tucson Electric Power Company ("TEP"), UNS Electric, Inc. ("UNS Electric") and UNS Gas, Inc. ("UNS Gas"), (collectively "UNS Energy") . UNS Energy's largest operating subsidiary, TEP, is a vertically integrated regulated electric utility. TEP generates, transmits and distributes electricity to retail customers in southeastern Arizona, including the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County. TEP also sells wholesale electricity to other entities in the western United States. UNS Electric is a vertically integrated regulated electric utility, which generates, transmits and distributes electricity to retail customers in Arizona's Mohave and Santa Cruz counties. TEP and UNS Electric currently own generation resources with an aggregate capacity of 2,834 megawatts ("MW"), including 64 MW of solar capacity. Several of the generating assets in which TEP and UNS Electric 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. c. Central Hudson: Primarily comprised of Central Hudson Gas & Electric Corporation ("Central Hudson"), which is a regulated electric and gas transmission and distribution utility, serving portions of New York State's Mid-Hudson River Valley. The Company owns gas-fired and hydroelectric generating capacity totalling 64 MW. Also included in the Central Hudson segment is the net corporate expenses and activity of CH Energy Group, Inc. ("CH Energy Group"). Regulated Utilities - Canada a. FortisBC Energy: FortisBC Energy Inc. ("FortisBC Energy") is the largest regulated distributor of natural gas in British Columbia, serving more than 135 communities. FortisBC Energy provides transmission and distribution services to customers, and obtains natural gas supplies on behalf of most residential, commercial and industrial customers. Gas supplies are sourced primarily from northeastern British Columbia and, through FortisBC Energy's Southern Crossing pipeline, from Alberta. b. FortisAlberta: FortisAlberta Inc. ("FortisAlberta") is a regulated electricity distribution utility operating in a substantial portion of southern and central Alberta. The Company does not own or operate generation or transmission assets and is not involved in the direct sale of electricity. c. FortisBC Electric : Includes FortisBC Inc. ("FortisBC Electric"), an integrated regulated electric utility operating in the southern interior of British Columbia . FortisBC Electric owns four hydroelectric generating facilities with a combined capacity of 225 MW. Also included in the FortisBC Electric segment are the operating, maintenance and management services relating to five hydroelectric generating facilities in British Columbia primarily owned by third parties, one of which is the 335 -MW Waneta Expansion hydroelectric generating facility ("Waneta Expansion"), owned by Fortis and Columbia Power Corporation and Columbia Basin Trust ("CPC/CBT"). d. Eastern Canadian: Comprised of Newfoundland Power Inc. ("Newfoundland Power"), Maritime Electric Company, Limited ("Maritime Electric"), FortisOntario Inc. ("FortisOntario"), and the Corporation's 49% equity investment in Wataynikaneyap Power Limited Partnership ("Wataynikaneyap Partnership") (Note 9). Newfoundland Power is an integrated regulated electric utility and the principal distributor of electricity on the island portion of Newfoundland and Labrador. Newfoundland Power has an installed generating capacity of 139 MW, of which 97 MW is hydroelectric generation. Maritime Electric is an integrated regulated electric utility and the principal distributor of electricity on Prince Edward Island ("PEI"). Maritime Electric also maintains on-Island generating facilities with a combined capacity of 145 MW. FortisOntario is comprised of three regulated electric utilities that provide service to customers in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario. Wataynikaneyap Partnership is a partnership between 22 First Nation communities and Fortis with a mandate of connecting remote First Nation communities to the electricity grid in Ontario through the development of new transmission lines (the "Wataynikaneyap Power Project"). The Wataynikaneyap Power Project is in the development stage . Regulated Utilities – Caribbean Caribbean: Includes the Corporation's approximate 60% controlling ownership interest in Caribbean Utilities Company, Ltd. ("Caribbean Utilities") ( December 31, 2016 - 60% ), Fortis Turks and Caicos, and the Corporation's 33% equity investment in Belize Electricity Limited ("Belize Electricity") (Note 9) . Caribbean Utilities is an integrated regulated electric utility and the sole provider of electricity on Grand Cayman, Cayman Islands. Caribbean Utilities has an installed diesel-powered generating capacity of 161 MW. Fortis Turks and Caicos is comprised of two integrated regulated electric utilities that provide electricity to certain islands in Turks and Caicos. Fortis Turks and Caicos has a combined diesel-powered generating capacity of 84 MW. Belize Electricity is an integrated electric utility and the principal distributor of electricity in Belize. Non-Regulated - Energy Infrastructure Energy Infrastructure: Primarily comprised of long-term contracted generation assets in British Columbia and Belize, and the Aitken Creek natural gas storage facility ("Aitken Creek"). Generating assets in British Columbia include the Corporation's 51% controlling ownership interest in the 335 -MW Waneta Expansion, conducted through the Waneta Expansion Limited Partnership ("Waneta Partnership"), with CPC/CBT holding the remaining 49% interest. The output is sold to BC Hydro and FortisBC Electric under 40 -year contracts. Generating assets in Belize are comprised of three hydroelectric generating facilities with a combined capacity of 51 MW, conducted through the Corporation's indirectly wholly owned subsidiary Belize Electric Company Limited ("BECOL"). The output is sold to Belize Electricity under 50 -year power purchase agreements ("PPAs"). Aitken Creek Gas Storage ULC, acquired by Fortis in April 2016, owns 93.8% of Aitken Creek, with the remaining share owned by BP Canada Energy Company (Note 25) . Aitken Creek is the only underground natural gas storage facility in British Columbia and has a total working gas capacity of 77 billion cubic feet. In 2016 the Corporation sold its 16 -MW run-of-river Walden hydroelectric generating facility ("Walden") (Note 26) . Non-Regulated - Corporate and Other Corporate and Other: Captures expense and revenue items not specifically related to any reportable segment and those business operations that are below the required threshold for reporting as separate segments. The Corporate and Other segment includes net corporate expenses of Fortis and non-regulated holding company expenses of FortisBC Holdings Inc. ("FHI"). |
Nature of Regulation and Regula
Nature of Regulation and Regulatory Matters | 12 Months Ended |
Dec. 31, 2017 | |
Regulated Operations [Abstract] | |
Nature of Regulation and Regulatory Matters | NATURE OF REGULATION AND REGULATORY MATTERS The earnings of the Corporation's utilities are primarily determined under cost of service ("COS") regulation. Generally, under COS regulation the respective regulatory authority sets customer electricity and/or gas rates to permit a reasonable opportunity for the utility to recover, on a timely basis, estimated costs of providing service to customers, including a fair rate of return on a regulatory deemed or targeted capital structure applied to an approved regulatory asset value ("rate base"). The ability of a regulated utility 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 the utility achieving the forecasts established in the rate-setting processes. If a historical test year is used to set customer rates, there may be regulatory lag between when costs are incurred and when they are reflected in customer rates. When performance-based rate setting ("PBR") mechanisms are utilized in determining annual revenue requirements and resulting customer rates, a formula is generally applied that incorporates inflation and assumed productivity improvements. The use of PBR mechanisms should allow a utility a reasonable opportunity to recover prudently incurred costs and earn its allowed ROE or ROA. The Corporation's regulated utilities, where applicable, are permitted by their respective regulatory authority 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) . The nature of regulation at the Corporation's utilities and their significant regulatory matters are as follows. ITC ITC is regulated by the Federal Energy Regulatory Commission ("FERC") under the Federal Power Act (United States). Rates are set annually, using FERC-approved cost-based formula rate templates, and remain in effect for one year, which provides timely cost recovery and reduces regulatory lag. The formula rates include an annual true-up mechanism, that compares actual revenue requirements to billed revenues and any over- or under-collections are accrued and reflected in future rates within a two -year period. The formula rates do not require annual FERC approvals, although inputs remain subject to legal challenge with FERC. The common equity component of capital structure for ITC was 60% for 2017 and 2016 . ROE Complaints Two third-party complaints are pending before FERC requesting that the Midcontinent Independent System Operator ("MISO") regional base ROE of 12.38% for MISO transmission owners, including ITCTransmission, METC and ITC Midwest, be found to no longer be just or reasonable. The complaints cover two consecutive 15 -month periods from November 2013 through February 2015 (the "Initial Refund Period" or "Initial Complaint") and February 2015 through May 2016 (the "Second Refund Period" or "Second Complaint"). The FERC orders on the complaints will also set the ROE that will be in effect prospectively from the date that the FERC orders are issued. In September 2016 FERC issued an order setting the base ROE for the Initial Refund Period at 10.32% , with a maximum ROE of 11.35% . These rates apply prospectively from September 2016 until a new approved rate is established for the Second Refund Period. The MISO transmission owners have sought rehearing of the September 2016 order. In June 2016 the presiding Administrative Law Judge ("ALJ") issued an initial decision on the Second Complaint, recommending a base ROE of 9.70% , with a maximum ROE of 10.68% . The base ROE for the three effected utilities for the period of May 2016 through September 2016 was 12.38% and any authorized adders that were approved prior to the filing of the complaints were collected during this time, up to a maximum of 13.88% . The initial decision of the ALJ is a non-binding recommendation to FERC and FERC has yet to issue its order on the Second Complaint. In September 2017 certain MISO transmission owners filed a motion for FERC to dismiss the Second Complaint. If the Second Complaint is not dismissed, it is expected that FERC will establish a new going-forward base ROE and range of reasonableness, which will also be used to calculate the refund liability for the Second Refund Period. As at December 31, 2017 , the estimated range of refunds for the Second Refund Period was between US $106 million and US $145 million and ITC has recognized an aggregate estimated regulatory liability of $182 million (US $145 million ) (December 31, 2016 - $188 million (US $140 million )) (Note 8 (xiii) ). The total estimated refund for the Initial Complaint was $158 million (US $118 million ), including interest, as at December 31, 2016, which was paid in 2017. The estimated regulatory liabilities were accrued by ITC before its acquisition by Fortis. There is uncertainty regarding the final outcome of the Initial and Second Complaints and the timing of the completion of these matters. This is due, in part, to an April 2017 court decision requiring FERC to further justify the methodology used to establish new ROEs. It is possible that the outcome of these matters could differ materially from the estimated range of refunds. UNS Energy UNS Energy is regulated by the Arizona Corporation Commission ("ACC") and certain activities are subject to regulation by FERC under the Federal Power Act (United States). UNS Energy uses a historical test year in the establishment of retail electric and gas rates. Retail electric and gas rates are set to provide the utilities with an opportunity to recover their COS and earn a reasonable rate of return on rate base, including an adjustment for the fair value of rate base as required under the laws of the State of Arizona. General Rate Application In February 2017 the ACC issued a rate order for new rates for TEP that took effect February 27, 2017 (“2017 Rate Order”). Provisions of the 2017 Rate Order include: (i) an increase in non-fuel base revenue of approximately $108 million (US $81.5 million ), including approximately $20 million (US $15 million ) of operating costs related to the 50.5% undivided interest in Unit 1 of Springerville Generating Station purchased by TEP in September 2016; (ii) a 7.04% return on original cost rate base, including a cost of equity of 9.75% and an embedded cost of long-term debt of 4.32% ; (iii) a common equity component of capital structure of approximately 50% ; and (iv) the adoption of proposed depreciation rates which reflect a reduction in the depreciable life for Unit 1 of San Juan Generating Station. Prior to the 2017 Rate Order, effective from July 1, 2013, TEP's allowed ROE was set at 10.0% on a capital structure of 43.5% common equity. UNS Electric's allowed ROE is set at 9.50% on a capital structure of 52.8% common equity, effective from August 1, 2016, prior to which its allowed ROE was set at 9.50% on a capital structure of 52.6% , effective from January 1, 2014. UNS Gas' allowed ROE is set at 9.75% on a capital structure of 50.8% common equity, effective from May 1, 2012. FERC Order In 2015 and 2016 TEP reported to FERC that it had not filed on a timely basis certain FERC jurisdictional agreements and, at that time, TEP made compliance filings, including the filing of several TEP transmission service agreements, the majority of which were entered into before the acquisition of UNS Energy by Fortis in 2014, that contained certain deviations from TEP’s standard form of service agreement. In 2016 FERC issued orders relating to the late-filed transmission service agreements, which directed TEP to issue time value refunds to the counterparties of the agreements. In 2016 TEP accrued time value refunds of $29 million , of which $22 million had been paid, and as at December 31, 2016 $7 million was accrued related to time-value refunds. In June 2016, to preserve its rights, TEP petitioned the District of Columbia Circuit Court of Appeals to review the refund order. In January 2017 TEP and one of the counterparties to the late-filed transmission service agreements entered into a settlement regarding the time value refunds. Under the settlement, in January 2017, the counterparty paid TEP $11 million and TEP dismissed its appeal with prejudice. In May 2017 FERC informed TEP that no further enforcement actions were necessary regarding TEP’s transmission refunds and closed the related investigation. As a result, TEP reversed the remaining $7 million provision related to potential time-value refunds. Central Hudson Central Hudson is regulated by the New York State Public Service Commission ("PSC") and certain activities are subject to regulation by FERC under the Federal Power Act (United States). Central Hudson uses a future test year in the establishment of rates. Central Hudson's allowed ROE is set at 9.0% on a capital structure of 48% common equity, effective July 1, 2015 for a three -year term. Effective July 1, 2015, Central Hudson is also subject to an earnings sharing mechanism, whereby the Company and customers share equally earnings in excess of 50 basis points above the allowed ROE up to an achieved ROE that is 100 basis points above the allowed ROE. Earnings in excess of 100 basis points above the allowed ROE are shared primarily with the customer. General Rate Application In July 2017 Central Hudson filed a rate case with the PSC requesting an increase in electric and natural gas rates of $55 million (US $43 million ) and $23 million (US $18 million ), respectively. Included in the rate case was a request to increase Central Hudson's allowed ROE to 9.5% from 9.0% and the equity component of its capital structure to 50% from 48% . An order from the PSC is expected in August 2018 with the new rates to become effective no later than September 1, 2018, with a provision allowing the recovery of revenue as if approved rates went into effect July 1, 2018. FortisBC Energy and FortisBC Electric FortisBC Energy and FortisBC Electric are regulated by the British Columbia Utilities Commission ("BCUC") pursuant to the Utilities Commission Act (British Columbia), and are subject to Multi-Year PBR Plans for 2014 through 2019. FortisBC Energy is the benchmark utility in British Columbia, as designated by the BCUC, and the established allowed ROE for the benchmark utility is set at 8.75% on a 38.5% common equity component of capital structure, effective January 1, 2016. FortisBC Electric's allowed ROE of 9.15% on a 40% common equity component of capital structure, effective since January 1, 2013, remained unchanged, effective January 1, 2016. The PBR Plans, as approved by the BCUC, incorporate incentive mechanisms for improving operating and capital expenditure efficiencies. Operation and maintenance expenses and base capital expenditures during the PBR period are subject to an incentive formula reflecting incremental costs for inflation and half of customer growth, less a fixed productivity adjustment factor of 1.1% for FortisBC Energy and 1.03% for FortisBC Electric each year. The approved PBR Plans also include a 50% /50% sharing of variances from the formula‑driven operation and maintenance expenses and capital expenditures over the PBR period, and a number of service quality measures designed to ensure FortisBC Energy and FortisBC Electric maintain specified service levels. It also sets out the requirements for an annual review process which provides a forum for discussion between the utilities and interested parties regarding current performance and future activities. FortisAlberta FortisAlberta is regulated by the Alberta Utilities Commission ("AUC") pursuant to the Electric Utilities Act (Alberta), the Public Utilities Act (Alberta), the Hydro and Electric Energy Act (Alberta) and the Alberta Utilities Commission Act (Alberta). FortisAlberta is subject to a Multi-Year PBR plan for 2013 through 2017. Under PBR, each year the prescribed formula is applied to the preceding year's distribution rates, with 2012 used as the going-in distribution rates. The PBR plan includes mechanisms for the recovery or settlement of items determined to flow through directly to customers ("Y factor") and the recovery of costs related to capital expenditures that are not being recovered through the formula ("K factor" or "capital tracker"). The AUC also approved a Z factor, a PBR re-opener and an ROE efficiency carry-over mechanism. The Z factor permits an application for recovery of costs related to significant unforeseen events. The PBR re-opener permits an application to re-open and review the PBR plan to address specific problems with the design or operation of the PBR plan. The use of the Z factor and PBR re-opener mechanisms is associated with certain thresholds. The ROE efficiency carry-over mechanism provides an efficiency incentive by permitting the Company to continue to benefit from any efficiency gains achieved during the PBR term for two years following the end of that term. Generic Cost of Capital In October 2016 the AUC issued its decision related to the 2016 and 2017 Generic Cost of Capital Proceeding, establishing that FortisAlberta's allowed ROE remain unchanged at 8.30% , for 2016 and increase to 8.50% for 2017. The decision also set the common equity component of capital structure at 37% , effective January 1, 2016. Changes in FortisAlberta's allowed ROE and common equity component of capital structure impact only the portion of rate base that is funded by capital tracker revenue. In July 2017 the AUC established a proceeding to determine the ROE and capital structure for 2018, 2019 and 2020. The proceeding commenced in October 2017, with an oral hearing expected to commence in March 2018. The ROE and capital structure approved for 2017 will remain in effect on an interim basis pending the finalization of this proceeding. A decision is expected in the third quarter of 2018. Eastern Canadian Newfoundland Power is regulated by the Newfoundland and Labrador Board of Commissioners of Public Utilities ("PUB") under the Public Utilities Act (Newfoundland and Labrador). Newfoundland Power uses a future test year in the establishment of rates. In June 2016 the PUB set the allowed ROE at 8.50% , effective January 1, 2016 and established that Newfoundland Power's common equity component of capital structure of 45% remain unchanged. The June 2016 rate order will remain in effect for 2016 through 2018. Newfoundland Power is required to file its next General Rate Application on or before June 1, 2018. Maritime Electric is regulated by the Island Regulatory and Appeals Commission ("IRAC") under the provisions of the Electric Power Act (PEI), the Renewable Energy Act (PEI), the Electric Power (Electricity Rate-Reduction) Amendment Act (PEI), and the former Electric Power (Energy Accord Continuation) Amendment Act (PEI), which expired in February 2016. Maritime Electric uses a future test year for the establishment of rates. In March 2016 IRAC set the Company's allowed ROE at 9.35% , effective March 1, 2016 for a three -year period, down from 9.75% in effect since March 1, 2013, and established that Maritime Electric's targeted capital structure of 40% remain unchanged. FortisOntario's three electric utilities operate under the Electricity Act (Ontario) and the Ontario Energy Board Act (Ontario), as administered by the Ontario Energy Board ("OEB"). Fortis Ontario's utilities use a future test year in the establishment of rates. Earnings are regulated on the basis of rate of return on rate base, plus a recovery of allowable distribution costs. In non-rebasing years, customer electricity distribution rates are set using inflationary factors less an efficiency target as prescribed by the OEB. The allowed ROE for distribution assets for FortisOntario's utilities ranged from 8.78% to 9.30% for 2017 and 8.93% to 9.30% for 2016, both on a deemed capital structure of 40% common equity, with the exception of one of its utilities which is subject to a rate-setting mechanism under a 35 -year Franchise Agreement expiring in 2033, based on a price cap with commodity cost flow through. The base revenue requirement is adjusted annually for inflation, load growth and customer growth. Regulated Utilities - Caribbean Caribbean Utilities operates under transmission and distribution and generation licences from the Government of the Cayman Islands. The exclusive transmission and distribution licence is for an initial period of 20 years, expiring April 2028, with a provision for automatic renewal. A non-exclusive generation licence was issued for a term of 25 years, expiring November 2039. The licences detail the role of the Cayman Islands Utility Regulation and Competition Office ("OfReg"), which oversees all licences, establishes and enforces licence standards, reviews the rate‑cap adjustment mechanism ("RCAM"), and annually approves capital expenditures. The licences contain the provision for an RCAM based on published consumer price indices. Caribbean Utilities' targeted allowed ROA for 2017 and 2016 was in the range of 6.75% to 8.75% . In January 2017 a merger of regulatory bodies in the Cayman Islands, including the Electricity Regulatory Authority, resulted in the establishment of OfReg and this merger did not impact the terms and conditions of the licenses. Fortis Turks and Caicos operates under two 50 -year licences expiring in 2036 and 2037. Among other matters, the licences describe how electricity rates are set by the Government of the Turks and Caicos Islands, using a historical test year, in order to provide the utilities with an allowed ROA of between 15.0% and 17.5% (the "Allowable Operating Profit"). The Allowable Operating Profit is based on a calculated rate base, including interest on the amounts by which actual operating profits fall short of the Allowable Operating Profits on a cumulative basis (the "Cumulative Shortfall"). Annual submissions are made to the Government of the Turks and Caicos Islands calculating the amount of the Allowable Operating Profit and the Cumulative Shortfall. The recovery of the Cumulative Shortfall is dependent on future sales volumes and expenses. The achieved ROAs at the utilities have been significantly lower than those allowed under the licences as a result of the inability, due to economic and political factors, to increase base electricity rates associated with significant capital investment in recent years. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("US GAAP"), which for regulated utilities include specific accounting guidance for regulated operations, as outlined in Note 2, and the following summary of significant accounting policies. All amounts presented are in Canadian dollars unless otherwise stated. Basis of Presentation The consolidated financial statements reflect the Corporation's investments in its subsidiaries and variable interest entity, where Fortis is the primary beneficiary, on a consolidated basis, with the equity method used for entities in which Fortis has significant influence, but not control, and proportionate consolidation for generation and transmission assets that are jointly owned with non-affiliated entities. Intercompany transactions have been eliminated in the consolidated financial statements, except for transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. For further details on the Corporation's variable interest entity refer to Note 29 . Cash and Cash Equivalents Cash and cash equivalents include cash, cash held in margin accounts, and short-term deposits with initial maturities of three months or less from the date of deposit. Allowance for Doubtful Accounts Fortis and each of its subsidiaries, with the exception of ITC, maintain an allowance for doubtful accounts that is estimated based on a variety of factors including accounts receivable aging, historical experience and other currently available information, including events such as customer bankruptcy and economic conditions. ITC recognizes losses for uncollectible accounts based upon specific identification of such items. Accounts receivable are written-off in the period in which the receivable is 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. The cost of inventory at the Corporation's utilities is expected to be recovered in customer rates. Regulatory Assets and Liabilities Regulatory assets and liabilities arise as a result of the rate-setting process at the Corporation's utilities. Regulatory assets represent future revenues and/or receivables associated with certain costs incurred that will be, or are expected to be, recovered from customers in future periods through the rate-setting process. Regulatory liabilities represent future reductions or limitations of increases in revenue associated with amounts that will be, or are expected to be, refunded to customers through the rate-setting process. All amounts deferred as regulatory assets and liabilities are subject to regulatory approval. As such, the regulatory authorities could alter the amounts subject to deferral, at which time the change would be reflected in the consolidated financial statements. Certain remaining recovery and settlement periods are those expected by management and the actual recovery or settlement periods could differ based on regulatory approval. Investments Investments in which the Corporation exercises significant influence are accounted for on the equity basis. The Corporation reviews its investments on an annual basis for potential impairment in investment value. Any impairment will be recognized in the period in which such impairment is identified. Property, Plant and Equipment Property, plant and equipment are recorded at cost less accumulated depreciation. Contributions in aid of construction represent amounts contributed by customers and governments for the cost of property, plant and equipment. These contributions are recorded as a reduction in the cost of property, plant and equipment and are being amortized annually by an amount equal to the charge for depreciation provided on the related assets. Depreciation rates of the Corporation's regulated utilities include an estimate for future asset removal costs that have not been identified as a legal obligation, with the amount provided for in depreciation expense recorded as a long-term regulatory liability ( Note 8 (xii) ). Actual asset removal costs are recorded against the regulatory liability when incurred. For the majority of the Corporation's regulated utilities, property, plant and equipment are derecognized on disposal or when no future economic benefits are expected from their use. Upon retirement or disposal, any difference between the cost and accumulated depreciation of the asset, net of salvage proceeds, is charged to accumulated depreciation, with no gain or loss recognized in earnings. It is expected that any gains or losses charged to accumulated depreciation will be reflected in future depreciation expense when they are refunded or collected in customer rates. The majority of the Corporation's regulated utilities capitalize overhead costs that are not directly attributable to specific property, plant and equipment but relate to the overall capital expenditure program. The methodology for calculating and allocating capitalized overhead costs to property, plant and equipment is established by the respective regulator. The majority of the Corporation's regulated utilities include in the cost of property, plant and equipment both a debt and an equity component of the allowance for funds used during construction ("AFUDC"). The debt component of AFUDC totalling $38 million (2016 - $29 million ) is reported as a reduction of finance charges and the equity component of AFUDC is reported as other income (Note 22) . Both components of AFUDC are charged to earnings through depreciation expense over the estimated service lives of the applicable asset. AFUDC is calculated in a manner as prescribed by the respective regulator. At FortisAlberta the cost of property, plant and equipment also includes Alberta Electric System Operator ("AESO") contributions, which are investments required by FortisAlberta to partially fund the construction of transmission facilities. Property, plant and equipment include inventories held for the development, construction and betterment of other assets, with the exception of UNS Energy. As required by its regulator, UNS Energy recognizes inventories held for the development and construction of other assets in inventories until consumed. When put into service, the inventories are reclassified to property, plant and equipment. Maintenance and repairs of property, plant and equipment are charged to earnings in the period incurred, while replacements and betterments that extend the useful lives are capitalized. Property, plant and equipment is depreciated using the straight-line method based on the estimated service lives of the asset. Depreciation rates for regulated property, plant and equipment are approved by the respective regulator. Depreciation rates for 2017 ranged from 0.9% to 34.6% ( 2016 - 0.9% to 34.6% ). The weighted average composite rate of depreciation, before reduction for amortization of contributions in aid of construction, for 2017 was 2.6% ( 2016 – 2.8% ). The service life ranges and weighted average remaining service life of the Corporation's distribution, transmission, generation and other assets as at December 31 were as follows. 2017 2016 (Years) Service Life Ranges Weighted Average Remaining Service Life Service Life Ranges Weighted Average Remaining Service Life Distribution Electric 5-80 33 5-80 32 Gas 14-95 34 7-95 33 Transmission Electric 20-80 41 20-80 41 Gas 5-80 34 7-80 34 Generation 5-85 28 5-85 26 Other 3-70 14 3-70 14 Leases Leases that transfer to the Corporation substantially all of the risks and benefits incidental to ownership of the leased item are capitalized at the present value of the minimum lease payments. Capital leases are depreciated over the lease term, except where ownership of the asset is transferred at the end of the lease term, in which case capital leases are depreciated over the estimated service life of the underlying asset. Where the regulator has approved recovery of the arrangements as operating leases for rate-setting purposes that would otherwise qualify as capital leases for financial reporting purposes, the timing of the expense recognition related to the lease is modified to conform with the rate-setting process. Operating lease payments are recognized as an expense in earnings on a straight-line basis over the lease term. Intangible Assets Intangible assets are recorded at cost less accumulated amortization. The useful lives of intangible assets are assessed to be either indefinite or finite. Intangible assets with indefinite useful lives are tested for impairment annually, either individually or at the reporting unit level. Such intangible assets are not amortized. An intangible asset with an indefinite useful life is reviewed annually to determine whether the indefinite life assessment continues to be supportable. If not, the change in the useful life assessment from indefinite to finite is made on a prospective basis. 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 regulator. Amortization rates for 2017 ranged from 1.0% to 50.0% ( 2016 – 1.0% to 50.0% ). The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows. 2017 2016 (Years) Service Life Ranges Weighted Average Remaining Service Life Service Life Ranges Weighted Average Remaining Service Life Computer software 3-10 4 3-10 4 Land, transmission and water rights 36-80 57 30-80 57 Other 10-100 10 10-104 15 For the majority of the Corporation's regulated utilities, intangible assets are derecognized on disposal or when no future economic benefits are expected from their use. Upon retirement or disposal of intangible assets, any difference between the cost and accumulated amortization of the asset, net of salvage proceeds, is charged to accumulated amortization, with no gain or loss recognized in earnings. It is expected that any gains or losses charged to accumulated amortization will be reflected in future amortization costs when they are refunded or collected in customer rates. The majority of indefinite-lived intangible assets are held in the Corporation's regulated utilities that also have goodwill. For its annual testing of impairment for indefinite-lived intangible assets, Fortis includes these assets as part of the respective reporting units, which are tested on an annual basis for goodwill impairment, as disclosed in this Note under "Goodwill". Impairment of Long-Lived Assets The Corporation reviews the valuation of property, plant and equipment, intangible assets with finite lives, and other long-term assets when events or changes in circumstances indicate that the assets' carrying value may not be recoverable. If the carrying amount of the asset exceeds the expected total undiscounted cash flows generated by the asset, the asset is written down to estimated fair value and an impairment loss is recognized in earnings in the period in which it is identified. Asset-impairment testing is carried out at the reporting unit level to determine if assets are impaired. The net cash flows for reporting units are not asset-specific but are pooled for the entire reporting unit. The recovery of regulated assets' carrying value, including a fair rate of return, is provided through customer rates approved by the respective regulatory authority. Goodwill Goodwill represents the excess of the purchase price over the fair value of the identifiable net assets acquired relating to business acquisitions. The Corporation performs an annual impairment test for goodwill as at October 1, or more frequently if any event occurs or if circumstances change that would indicate that the fair value of a reporting unit was below its carrying value. Fortis performs an annual internal qualitative and quantitative assessment for each reporting unit to which goodwill has been allocated. The Corporation has a total of 11 reporting units that were allocated goodwill at the respective dates of acquisition by Fortis . For those reporting units where: (i) management's assessment of qualitative and quantitative factors indicates that fair value is not 50% or more likely to be greater than carrying value; or (ii) the excess of estimated fair value over carrying value, as of the date of the immediately preceding impairment test, was not significant, then fair value of the reporting unit will be estimated by an external consultant in the current year. In calculating goodwill impairment, the estimated fair value of the reporting unit is compared to its carrying value. If the fair value of the reporting unit is less than the carrying value, the excess of the carrying amount over fair value is recorded as goodwill impairment, not to exceed the total amount of goodwill allocated to the reporting unit. The primary method for estimating fair value of the reporting units is the income approach, whereby net cash flow projections for the reporting units are discounted using an enterprise value method. The income approach uses several underlying estimates and assumptions with varying degrees of uncertainty, including the amount and timing of expected future cash flows, growth rates, and the determination of appropriate discount rates. A secondary valuation method, the market approach, as well as a reconciliation of the total estimated fair value of all reporting units to the Corporation's market capitalization, is also performed as an assessment of the conclusions reached under the income approach. As a result of the Corporation's annual assessment for impairment of goodwill, the fair value of all of the reporting units that were allocated goodwill exceeded their respective carrying value and, therefore, no impairment provision was required in 2017 or 2016 . Deferred Financing Costs Any costs, debt discounts and premiums related to the issuance of long-term debt are recognized against long-term debt and are amortized over the life of the related long-term debt. Employee Future Benefits Defined Benefit and Defined Contribution Pension Plans The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans, including retirement allowances and supplemental retirement plans for certain executive employees, and defined contribution pension plans, including group Registered Retirement Savings Plans and group 401(k) plans for employees. The projected benefit obligation and the value of pension cost associated with the defined benefit pension plans are actuarially determined using the projected benefits method prorated on service and management's best estimate of expected plan investment performance, salary escalation and expected retirement ages of employees. Discount rates reflect market interest rates on high‑quality bonds with cash flows that match the timing and amount of expected pension payments. With the exception of FortisBC Energy and Newfoundland Power, pension plan assets are valued at fair value for the purpose of determining pension cost. At FortisBC Energy and Newfoundland Power, pension plan assets are valued using the market-related value for the purpose of determining pension cost, where 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 the projected benefit obligation and the fair value of plan assets (the market-related value of plan assets at FortisBC Energy and Newfoundland Power) 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 plans, measured as the difference between the fair value of the plan assets and the projected benefit obligation, is recognized on the Corporation's consolidated balance sheet. For the majority of the Corporation's regulated utilities, any difference between pension cost recognized under US GAAP and that recovered from customers in current rates for defined benefit pension plans, which is expected to be recovered from, or refunded to, customers in future rates, is subject to deferral account treatment ( Note 8 (ii) ). With the exception of Fortis and FHI, any unamortized balances related to net actuarial gains and losses, past service costs and transitional obligations associated with defined benefit pension plans, which would otherwise be recognized in accumulated other comprehensive income, are subject to deferral account treatment ( Note 8 (ii) ). At Fortis and FHI, any unamortized balances related to net actuarial gains and losses, past service costs and transitional obligations associated with defined benefit pension plans are recognized in accumulated other comprehensive income. The costs of the defined contribution pension plans are expensed as incurred. Other Post-Employment Benefits Plans The Corporation and its subsidiaries also offer other post-employment benefits ("OPEB") plans, including certain health and dental coverage and life insurance benefits, for qualifying members. The accumulated benefit obligation and the cost associated with OPEB plans are actuarially determined using the projected benefits method prorated on service and management's best estimate of expected plan performance, salary escalation, expected retirement ages of employees and health care costs. Discount rates reflect market interest rates on high-quality bonds with cash flows that match the timing and amount of expected OPEB payments. The excess of any cumulative net actuarial gain or loss over 10% of the accumulated benefit obligation and the fair value 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 OPEB plans, measured as the difference between the fair value of the plan assets and the accumulated benefit obligation, is recognized on the Corporation's consolidated balance sheet. For the majority of the Corporation's regulated utilities, any difference between the cost of OPEB plans recognized under US GAAP and that recovered from customers in current rates, which is expected to be recovered from, or refunded to, customers in future rates, is subject to deferral account treatment ( Note 8 (ii) ). Stock-Based Compensation The Corporation records compensation expense related to stock options granted under its stock option plans (Note 21) . Compensation expense is measured at the date of grant using the Black-Scholes fair value option-pricing model and each grant is amortized as a single award evenly over the four -year vesting period of the options granted. The offsetting entry is an increase to additional paid-in capital for an amount equal to the annual compensation expense related to the issuance of stock options. The stock options become exercisable once time-vesting requirements have been met. Upon exercise, the proceeds of the options 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. An exercise of options below the current market price of the Corporation's common shares has a dilutive effect on the Corporation's consolidated capital stock and shareholders' equity. Fortis satisfies stock option exercises by issuing common shares from treasury. The Corporation also records liabilities associated with its Directors' Deferred Share Unit ("DSU"), Performance Share Unit ("PSU") and Restricted Share Unit ("RSU") Plans, all representing cash-settled awards, at fair value at each reporting date until settlement. Compensation expense is recognized on a straight-line basis over the vesting period, which for the PSU and RSU Plans is over the shorter 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. The fair value of the DSU, PSU and RSU 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 of the Corporation's common shares as at December 31, 2017 was $46.01 ( December 31, 2016 - $41.46 ). 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 The assets and liabilities of the Corporation's foreign operations, all of which have a US dollar functional currency, are translated at the exchange rate in effect as at the balance sheet date. The exchange rate in effect as at December 31, 2017 was US$1.00=CAD$ 1.25 ( December 31, 2016 – US$1.00=CAD$ 1.34 ). The resulting unrealized translation gains and losses are excluded from the determination of earnings and are recognized in accumulated other comprehensive income until the foreign subsidiary is sold, substantially liquidated or evaluated for impairment in anticipation of disposal. Revenue and expenses of the Corporation's foreign operations are translated at the average exchange rate in effect during the reporting period, which was US$1.00=CAD$ 1.30 for 2017 ( 2016 – US$1.00=CAD$ 1.33 ). Foreign exchange translation gains and losses on foreign currency-denominated long-term debt that is designated as an effective hedge of foreign net investments are accumulated as a separate component of shareholders' equity within accumulated other comprehensive income and the current period change is recorded in other comprehensive income. 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. Gains and losses on translation are recognized in earnings. Derivative Instruments and Hedging Activities Non-Designated Derivatives Derivatives not designated as hedging contracts are used by Fortis to manage cash flow risk associated with forecasted US dollar cash inflows and forecasted future cash settlements of DSU and RSU obligations; UNS Energy to meet forecast load and reserve requirements; and Aitken Creek to manage exposure to commodity price risk, to capture natural gas price spreads, and to manage the financial risk posed by physical transactions. These non-designated derivatives are measured at fair value with changes in fair value recognized in earnings. Derivatives not designated as hedging contracts are also used by UNS Energy, Central Hudson and FortisBC Energy to reduce exposure to 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 non-designated derivatives are measured at fair value and the net unrealized gains and losses associated with changes in fair value of the derivative contracts are recorded as regulatory assets or liabilities for recovery from, or refund to, customers in future rates (Note 8 (viii) ). Derivative instruments that meet the normal purchase or normal sale scope exception are not measured at fair value and settled amounts are recognized as energy supply costs on the consolidated statements of earnings. Derivatives in Designated Hedging Relationships For derivatives designated as hedging contracts, the Corporation and its utilities formally assess, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. The hedging strategy by transaction type and risk management strategy is formally documented. As at December 31, 2017 , the Corporation's hedging relationships primarily consisted of cash flow hedges and net investment hedges. The Corporation, ITC and UNS Energy use cash flow hedges to manage its exposure to interest rate risk. Unrealized gains or losses on these derivatives are initially recognized in accumulated other comprehensive income and reclassified to earnings when the underlying hedged transaction affects earnings. Any hedge ineffectiveness is recognized in net earnings immediately at the time the gain or loss on the derivatives is calculated. The Corporation's earnings from, and net investments in, foreign subsidiaries and equity method investments are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has decreased a portion of the above-noted exposure through the use of US dollar-denominated borrowings at the corporate level. The Corporation has designated its corporately issued US dollar long-term debt as a hedge of a portion of the foreign exchange risk related to its foreign net investments. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately issued US dollar-denominated borrowings designated as hedges are recognized in accumulated other comprehensive income and help offset unrealized foreign currency exchange gains and losses on the foreign net investments, which gains and losses are also recognized in accumulated other comprehensive income. Presentation of Derivatives The fair value of derivative instruments are recognized on the Corporation's consolidated balance sheet as current or long-term assets and liabilities depending on the timing of the settlements and the resulting cash flows associated with the instruments. Derivative contracts under master netting agreements and collateral positions are presented on a gross basis. Cash flows associated with the settlement of all derivative instruments are included in operating activities on the Corporation's consolidated statement of cash flows. Income Taxes The Corporation and its subsidiaries follow the asset and liability method of accounting for income taxes. Under this method, 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. Valuation allowances are recognized against deferred tax assets when it is more likely than not that a portion of, or the entire amount of, the deferred income tax asset will not be realized. Deferred income tax assets and liabilities 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 that the change occurs. Current income tax expense or recovery is recognized for the estimated income taxes payable or receivable in the current year. As approved by the respective regulator, ITC, UNS Energy, Central Hudson and Maritime Electric recover current and deferred income tax expense in customer rates. As approved by the regulator, FortisAlberta recovers income tax expense in customer rates based only on income taxes that are currently payable. FortisBC Energy, FortisBC Electric, Newfoundland Power and FortisOntario recover income tax expense in customer rates based only on income taxes that are currently payable, except for certain regulatory balances for which deferred income tax expense is recovered from, or refunded to, customers in current rates, as prescribed by the respective regulator. Deferred income taxes that are expected to be collected from or refunded to customers in rates once income taxes become payable or receivable are recognized as a regulatory asset or liability ( Note 8 (i) ). For regulatory reporting purposes, the capital cost allowance pool for certain property, plant and equipment at FortisAlberta is different from that for legal entity corporate income tax filing purposes. In a future reporting period, yet to be determined, the difference may result in higher income tax expense than that recognized for regulatory rate-setting purposes and collected in customer rates. Caribbean Utilities and Fortis Turks and Caicos are not subject to income tax as they operate in tax-free jurisdictions. BECOL is not subject to income tax as it was granted tax-exempt status by the Government of Belize for the terms of its 50 -year PPAs. Any difference between the income tax expense recognized under US GAAP and that recovered from customers in current rates that is expected to be recovered from customers in future rates, is subject to deferral account treatment ( Note 8 (i) ). The Corporation intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, the Corporation does not provide for deferred income taxes on temporary differences related to investments in foreign subsidiaries. The difference between the carrying values of these foreign investments and their tax bases, resulting from unrepatriated earnings and currency translation adjustments, is approximately $561 million as at December 31, 2017 ( December 31, 2016 - $525 million ). If such earnings are repatriated, in the form of dividends or otherwise, 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 income tax positions taken, or expected to be taken, in an income tax return are recognized only 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. The difference between a tax position taken, or expected to be taken, and the benefit recognized and measured pursuant to this guidance represents an unrecognized tax benefit. Income tax interest and penalties are expensed as incurred and included in income tax expense. Sales Taxes In the course of its operations, the Corporation's subsidiaries collect sales taxes from their customers. When customers are billed, a current liability is recognized for the sales taxes included on customers' bills. The liability is settled when the taxes are remitted to the appropriate government authority. The Corporation's revenue excludes sales taxes. Revenue Recognition Revenue from the sale and delivery of electricity and gas by the Corporation's regulated utilities is generally recognized on an accrual basis. Electricity and gas consumption is metered upon delivery to customers and is recognized as revenue using approved rates when consumed. Revenue at the regulated utilities is billed at rates approved by the applicable regulatory authority. Meters are read periodically and bills are issued to customers based on these readings. At the end of each reporting period, a certain amount of consumed electricity and gas will not have been billed, which is estimated and accrued as revenue. ITC's transmission revenue is recognized as services are provided based on FERC-approved cost-based formula rate templates. A reserve for revenue subject to refund is recognized as a reduction to revenue when such refund is probable and can be reasonably estimated ( Note 8 (vi) ). In certain circumstances, UNS Energy and Aitken Creek enter into purchased power and wholesale sales contracts that are not settled with energy. The net sales contracts and power purchase contracts are reflected at the net amount in revenue. As stipulated by the regulator, FortisAlberta is required to arrange and pay for transmission services with the AESO and collect transmission revenue from its customers, which is achieved through invoicing the customers' retailers through FortisAlberta's transmission component of its regulator-approved rates. FortisAlberta is solely a distribution company and, as such, does not operate or provide any transmission or generation services. The Company is a conduit for the flow through of transmission costs to end-use customers, as the transmission provider does not have a direct relationship with these customers. As a result, FortisAlberta report |
Future Accounting Pronouncement
Future Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Changes and Error Corrections [Abstract] | |
Future Accounting Pronouncements | FUTURE ACCOUNTING PRONOUNCEMENTS The Corporation considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board ("FASB"). The following updates have been issued by FASB, but have not yet been adopted by Fortis. Any ASUs not included below were assessed and determined to be either not applicable to the Corporation or not expected to have a material impact on the consolidated financial statements. Revenue from Contracts with Customers ASU No. 2014-09 was issued in May 2014 and the amendments in this update, along with additional ASUs issued in 2016 and 2017 to clarify implementation guidance, create Accounting Standards Codification ("ASC") Topic 606, Revenue from Contracts with Customers , and supersede the revenue recognition requirements in ASC Topic 605, Revenue Recognition , including most industry-specific revenue recognition guidance throughout the codification. This standard clarifies the principles for recognizing revenue and enables users of financial statements to better understand and consistently analyze an entity's revenues across industries and transactions. The new guidance permits two methods of adoption: (i) the full retrospective method; and (ii) the modified retrospective method, under which comparative periods would not be restated and the cumulative impact of applying the standard would be recognized at the date of initial adoption supplemented by additional disclosures. This standard is effective for annual and interim periods beginning after December 15, 2017. Fortis adopted this ASU on January 1, 2018 using the modified retrospective approach and there have been no material adjustments identified to opening retained earnings. Fortis has reviewed the final assessments and conclusions of its utilities on tariff-based sales to retail and wholesale customers, which represents more than 90% of the Corporation's consolidated revenue, and has concluded that the adoption of this standard will not affect revenue recognition for tariff-based sales and, therefore, will not have an impact on earnings. Fortis' subsidiaries have completed their final assessments and conclusions on less material revenue streams, and Fortis is reviewing these final assessments, particularly for consistency of implementation and accounting policy selection, and does not expect any adjustments. The Corporation will add additional disclosures to address the requirement to provide more information regarding the nature, amount, timing and uncertainty of revenue and cash flows, which will result in revenues that fall outside the scope of the new standard, including alternative revenue programs, being presented separately. The Corporation will present revenue in three categories: (i) revenue from contracts with customers which will include retail and wholesale tariff revenue; (ii) alternative revenue programs; and (iii) other revenue. The Corporation's revenue is currently disaggregated by: (i) geography; and (ii) substantially autonomous utility operations. This level of disaggregation will not change upon implementation of the new guidance as it is: (i) used by the Corporation's chief operating decision maker for evaluating the financial performance of operating subsidiaries and to make resource allocation decisions; (ii) used by external stakeholders for evaluating the Corporation's financial performance; and (iii) consistent with other externally reported documents of the Corporation. Fortis continues to monitor its adoption process under its existing internal control over financial reporting, including accounting processes and the gathering and evaluation of information used in assessing the required disclosures. As the Corporation finalizes its implementation in the first quarter of 2018, it will continue to assess any necessary changes to internal control over financial reporting. Recognition and Measurement of Financial Assets and Financial Liabilities ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities , was issued in January 2016 and the amendments in this update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. Most notably, the amendments require the following: (i) equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings; and (ii) financial assets and financial liabilities to be presented separately in the notes to the consolidated financial statements, grouped by measurement category and form of financial instrument. This update is effective for annual and interim periods beginning after December 15, 2017. Fortis will adopt this standard in the first quarter of 2018, with an effective date of January 1, 2018, however, it is not expected that this standard will have a material impact on its consolidated financial statements. Leases ASU No. 2016-02 was issued in February 2016 and the amendments in this update create ASC Topic 842, Leases , and supersede lease requirements in ASC Topic 840, Leases . The main provision of ASC Topic 842 is the recognition of lease assets and lease liabilities on the balance sheet by lessees for those leases that were previously classified as operating leases. For operating leases, a lessee is required to do the following: (i) recognize a right-of-use asset and a lease liability, initially measured at the present value of the lease payments, on the balance sheet; (ii) recognize a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis; and (iii) classify all cash payments within operating activities in the statement of cash flows. These amendments also require qualitative disclosures along with specific quantitative disclosures. This update is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using a modified retrospective approach with practical expedient options. Early adoption is permitted. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements. Measurement of Credit Losses on Financial Instruments ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments , was issued in June 2016 and the amendments in this update require entities to use an expected credit loss methodology and to consider a broader range of reasonable and supportable information to inform credit loss estimates. This update is effective for annual and interim periods beginning after December 15, 2019 and is to be applied on a modified retrospective basis. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements. Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost ASU No. 2017-07 , Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, was issued in March 2017 and the amendments in this update require that an employer disaggregate the current service cost component of net benefit cost and present it in the same statement of earnings line item(s) as other employee compensation costs arising from services rendered. The other components of net benefit cost are required to be presented separately from the service cost component and outside of operating income. Additionally, the amendments allow only the service cost component to be eligible for capitalization when applicable . The amendments in this update should be applied retrospectively for the presentation of the net periodic benefit costs and prospectively, on and after the effective date, for the capitalization in assets of only the service cost component of net periodic benefit costs. This update is effective for annual and interim periods beginning after December 15, 2017. Fortis adopted this standard on January 1, 2018 and concluded that this standard will not materially impact its consolidated financial statements. Targeted Improvements to Accounting for Hedging Activities ASU No. 2017-12 , Targeted Improvements to Accounting for Hedging Activities, was issued in August 2017 and the amendments in this update better align risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and presentation of hedge results. This update is effective for annual and interim periods beginning after December 15, 2018 . Early adoption is permitted. The amendments in this update should be reflected as of the beginning of the fiscal year of adoption. For cash flow and net investment hedges existing at the date of adoption, the amendments should be applied as a cumulative effect adjustment related to eliminating the separate measurement of ineffectiveness to accumulated other comprehensive income with a corresponding adjustment to the opening balance of retained earnings. Amended presentation and disclosure guidance is required only prospectively. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements. |
Segmented Information
Segmented Information | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Segmented Information | SEGMENTED INFORMATION Fortis segments its business based on regulatory status and service territory, as well as the information used by the chief operating decision maker in deciding how to allocate resources and evaluate the performance of each segment. Segment performance is evaluated based on net earnings attributable to common equity shareholders. A detailed description of each reportable segment is provided in Note 1. REGULATED NON-REGULATED Year Ended United States Canada Energy Inter- December 31, 2017 UNS Central FortisBC Fortis FortisBC Eastern Infra- Corporate segment ($ millions) ITC Energy Hudson Energy Alberta Electric Canadian Caribbean Total structure and Other eliminations Total Revenue 1,575 2,080 872 1,198 600 398 1,062 301 8,086 226 1 (12 ) 8,301 Energy supply costs — 711 260 411 — 142 692 144 2,360 2 — (1 ) 2,361 Operating expenses 436 609 402 298 198 89 134 44 2,210 49 13 (11 ) 2,261 Depreciation and amortization 220 260 65 198 190 62 95 55 1,145 32 2 — 1,179 Operating income 919 500 145 291 212 105 141 58 2,371 143 (14 ) — 2,500 Other income, net 40 19 8 20 2 1 1 7 98 1 29 (1 ) 127 Finance charges 259 101 41 116 93 37 56 18 721 5 189 (1 ) 914 Income tax expense 371 148 42 40 1 14 22 — 638 19 (69 ) — 588 Net earnings 329 270 70 155 120 55 64 47 1,110 120 (105 ) — 1,125 Non-controlling interests 57 — — 1 — — — 13 71 26 — — 97 Preference share dividends — — — — — — — — — — 65 — 65 Net earnings attributable 272 270 70 154 120 55 64 34 1,039 94 (170 ) — 963 Goodwill 7,698 1,733 566 913 227 235 67 178 11,617 27 — — 11,644 Total assets 17,581 8,596 3,188 6,418 4,454 2,197 2,489 1,325 46,248 1,605 76 (107 ) 47,822 Capital expenditures 982 534 220 446 414 105 156 146 3,003 21 — — 3,024 Year Ended December 31, 2016 ($ millions) Revenue 334 2,002 849 1,151 572 377 1,063 301 6,649 193 9 (13 ) 6,838 Energy supply costs — 740 253 347 — 132 698 137 2,307 35 — (1 ) 2,341 Operating expenses 151 605 387 295 189 88 136 45 1,896 39 108 (12 ) 2,031 Depreciation and amortization 46 264 61 198 180 57 91 54 951 28 4 — 983 Operating income 137 393 148 311 203 100 138 65 1,495 91 (103 ) — 1,483 Other income, net 9 7 5 17 3 — 2 9 52 2 — (1 ) 53 Finance charges 54 102 40 125 85 37 55 15 513 4 162 (1 ) 678 Income tax expense 20 99 43 51 — 9 21 — 243 3 (101 ) — 145 Net earnings 72 199 70 152 121 54 64 59 791 86 (164 ) — 713 Non-controlling interests 13 — — 1 — — — 13 27 26 — — 53 Preference share dividends — — — — — — — — — — 75 — 75 Net earnings attributable 59 199 70 151 121 54 64 46 764 60 (239 ) — 585 Goodwill 8,246 1,854 605 913 227 235 67 190 12,337 27 — — 12,364 Total assets 18,000 8,935 3,214 6,230 4,057 2,143 2,394 1,344 46,317 1,502 130 (45 ) 47,904 Capital expenditures 223 524 233 336 375 74 161 106 2,032 19 10 — 2,061 Related-party and inter-company transactions Related-party transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. There were no material related-party transactions in 2017 or 2016. Inter-company balances and inter-company transactions, including any related inter-company profit, are eliminated on consolidation, except for certain inter-company transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The significant inter-company transactions for 2017 and 2016 are summarized in the following table. (in millions) 2017 2016 Sale of capacity from Waneta Expansion to FortisBC Electric $ 46 $ 45 Sale of energy from BECOL to Belize Electricity 35 33 Lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy 24 17 As at December 31, 2017 , accounts receivable on the Corporation's consolidated balance sheet included approximately $20 million due from Belize Electricity ( December 31, 2016 - $16 million ). From time to time, the Corporation provides short-term financing to certain subsidiaries to support capital expenditure programs, acquisitions and seasonal working capital requirements. There were no inter-segment loans outstanding as at December 31, 2017 and December 31, 2016 . |
Accounts Receivable and Other C
Accounts Receivable and Other Current Assets | 12 Months Ended |
Dec. 31, 2017 | |
Receivables [Abstract] | |
Accounts Receivable and Other Current Assets | ACCOUNTS RECEIVABLE AND OTHER CURRENT ASSETS (in millions) 2017 2016 Trade accounts receivable $ 492 $ 507 Unbilled accounts receivable 575 551 Allowance for doubtful accounts (31 ) (33 ) Income tax receivable 8 26 Other 87 76 $ 1,131 $ 1,127 Other consisted of customer billings for non-core services, collateral deposits for gas purchases at FortisBC Energy, advances on coal purchases at UNS Energy, and the fair value of derivative instruments (Note 28) . |
Inventories
Inventories | 12 Months Ended |
Dec. 31, 2017 | |
Inventory Disclosure [Abstract] | |
Inventories | INVENTORIES (in millions) 2017 2016 Materials and supplies $ 238 $ 244 Gas and fuel in storage 97 98 Coal inventory 32 30 $ 367 $ 372 |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 12 Months Ended |
Dec. 31, 2017 | |
Regulated Operations [Abstract] | |
Regulatory Assets and Liabilities | REGULATORY ASSETS AND LIABILITIES Based on previous, existing or expected regulatory orders or decisions, the Corporation's regulated utilities have recognized the following amounts that are expected to be recovered from, or refunded to, customers in future periods. Remaining recovery period (in millions ) 2017 2016 (Years) Regulatory assets Deferred income taxes (i) $ 1,403 $ 1,260 To be determined Employee future benefits (ii) 510 576 Various Deferred energy management costs (iii) 200 178 1-10 Generation early retirement costs (iv) 105 — 11-13 Deferred lease costs (v) 104 97 Various Rate stabilization accounts (vi) 95 183 Various Deferred operating overhead costs (vii) 91 78 Various Derivative instruments (viii) 87 19 Various Manufactured gas plant ("MGP") site remediation deferral (ix) 75 107 To be determined Greenhouse gas reduction regulatory incentives (x) 35 40 10 Other regulatory assets (xi) 340 395 Various Total regulatory assets 3,045 2,933 Less: current portion (303 ) (313 ) 1 Long-term regulatory assets $ 2,742 $ 2,620 Regulatory liabilities Deferred income taxes (i) $ 1,484 $ — To be determined Asset removal cost provision (xii) 1,095 1,194 To be determined Rate stabilization accounts (vi) 254 230 Various ROE refund liability (xiii) 182 346 1 Energy efficiency liability (xiv) 82 49 Various Renewable energy surcharge (xv) 66 53 To be determined Electric and gas moderator account (xvi) 58 71 To be determined Employee future benefits (ii) 47 42 Various Other regulatory liabilities (xvii) 178 198 Various Total regulatory liabilities 3,446 2,183 Less: current portion (490 ) (492 ) 1 Long-term regulatory liabilities $ 2,956 $ 1,691 Description of the Nature of Regulatory Assets and Liabilities (i) Deferred Income Taxes The Corporation’s regulated utilities recognize deferred income tax assets and liabilities and related regulatory liabilities and assets for the amount of deferred income taxes expected to be refunded to, or recovered from, customers in future rates. As at December 31, 2017 , regulatory assets of approximately $754 million associated with deferred income taxes were not subject to a regulatory return ( December 31, 2016 - $596 million ). As at December 31, 2017 , regulatory liabilities of approximately $1,481 million associated with deferred taxes were not subject to a regulatory return. The balances for ITC, UNS Energy and Central Hudson reflect the effects of the significant changes to tax legislation signed into law in the United States in December 2017 ("U.S. Tax Reform"). As part of U.S. Tax Reform, utilities were required to remeasure their deferred income tax assets and liabilities (Note 23) . Included in regulatory liabilities is $1,453 million related to U.S. Tax reform, reflecting the reduction in deferred income tax expense expected to be refunded to customers. (ii) Employee Future Benefits The regulatory asset and liability associated with employee future benefits includes the actuarially determined unamortized net actuarial losses, past service costs and credits, and transitional obligations associated with defined benefit pension and OPEB plans maintained by the Corporation's regulated utilities (Note 24) , which are expected to be recovered from, or refunded to, customers in future rates. At the Corporation's regulated utilities, as approved by the respective regulators, differences between defined benefit pension and OPEB plan costs recognized under US GAAP and those which are expected to be recovered from, or refunded to, customers in future rates are subject to deferral account treatment and have been recognized as a regulatory asset or liability. These amounts would otherwise be recognized in accumulated other comprehensive income on the consolidated balance sheet. As at December 31, 2017 , regulatory assets of approximately $291 million associated with employee future benefits were not subject to a regulatory return ( December 31, 2016 - $346 million ). As at December 31, 2017 , regulatory liabilities of approximately $45 million associated with employee future benefits were not subject to a regulatory return ( December 31, 2016 - $31 million ). (iii) Deferred Energy Management Costs FortisBC Energy, FortisBC Electric, Central Hudson and Newfoundland Power provide energy management services to promote energy efficiency programs to their customers. As required by their respective regulator, these regulated utilities have capitalized related expenditures and are amortizing these expenditures on a straight-line basis over periods ranging from 1 to 10 years . This regulatory asset represents the unamortized balance of the energy management costs. UNS Energy is required to implement cost-effective Demand-Side Management ("DSM") programs to comply with the ACC's energy efficiency standards. The energy efficiency standards provide for a DSM surcharge to recover the costs of implementing DSM programs, as well as an annual performance incentive. The existing rate orders provide for a lost fixed-cost recovery mechanism to recover certain non-fuel costs that were previously unrecoverable, due to reduced electricity sales as a result of energy efficiency programs and distributed generation. As at December 31, 2017 , $41 million of the regulatory asset balance associated with deferred energy management costs was not subject to a regulatory return ( December 31, 2016 - $42 million ). (iv) Generation Early Retirement Costs UNS Energy holds an undivided interest in the jointly owned Navajo Generating Station ("Navajo"), located on a site leased from the Navajo Nation with an initial lease term through December 2019. In June 2017 the Navajo Nation approved a land-lease extension that allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. Retirement costs related to Navajo are currently being recovered through to 2030. UNS Energy owns the Sundt Generating Facility ("Sundt") and in August 2017 TEP submitted an application related to a generation modernization project at the facility, which will add generation capacity in the form of gas-fired reciprocating engines. As part of the application, TEP plans to early retire Sundt Units 1 and 2 by the end of 2020. Capital and operating costs related to Sundt Units 1 and 2 are currently being recovered through to 2028 and 2030, respectively. As a result of the planned early retirement of Navajo and Sundt Units 1 and 2, the net book value and other related retirement costs were reclassified from property, plant and equipment to regulatory assets, and as at December 31, 2017 the net book value of these assets was $105 million (US $84 million ). UNS Energy's generation early retirement costs are not subject to regulatory return. (v) Deferred Lease Costs Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement ("BPPA"), which ends in 2056. The depreciation of the asset under capital lease and interest expense associated with the capital lease obligation are not being fully recovered in current customer rates, since those rates include only the cash payments set out under the BPPA (Note 15) . The deferred lease costs are expected to be recovered from customers in future rates over the term of the lease and are not subject to a regulatory return. In 2017 , of the $31 million ( 2016 - $31 million ) of interest expense related to the capital lease obligations and the $6 million ( 2016 - $6 million ) of depreciation expense related to the assets under capital lease, $27 million ( 2016 - $27 million ) was recognized in energy supply costs and $3 million ( 2016 - $3 million ) was recognized in operating expenses, as approved by the regulator, with the balance of $7 million ( 2016 - $7 million ) deferred as a regulatory asset. (vi) Rate Stabilization Accounts Rate stabilization accounts associated with the Corporation's regulated utilities are recovered from, or refunded to, customers in future rates, as approved by the respective regulators. Electric rate stabilization accounts primarily mitigate the effect on earnings of variability in the cost of fuel and/or purchased power above or below a forecast or predetermined level and, at certain utilities, revenue decoupling mechanisms minimize the earnings impact resulting from reduced energy consumption as energy efficiency programs are implemented. Gas rate stabilization accounts primarily mitigate the effect on earnings of unpredictable and uncontrollable factors, namely volume volatility caused principally by weather, and natural gas cost volatility. At ITC, transmission revenue requirements are set annually using cost-based formula rates that remain in effect for a one -year period. The formula rates include a true-up mechanism, whereby the actual revenue requirement is compared to billed revenue for each year to determine any over- or under-collection of revenue requirement. Revenue is recognized based on the actual revenue requirement, and revenue accrual and deferral accounts represent the difference between the actual revenue requirement and billed revenue, and are collected from, or refunded to, customers within a two -year period. As at December 31, 2017 , approximately $75 million and $144 million of the rate stabilization accounts are expected to be recovered from, or refunded to, customers within one year and, as a result, are classified as current regulatory assets and liabilities, respectively ( December 31, 2016 -approximately $135 million and $173 million , respectively). As at December 31, 2017 , regulatory assets of approximately $91 million associated with rate stabilization accounts were not subject to a regulatory return ( December 31, 2016 ‑ $139 million ). As at December 31, 2017 , regulatory liabilities of approximately $114 million associated with rate stabilization accounts were not subject to a regulatory return ( December 31, 2016 ‑ $180 million ). (vii) Deferred Operating Overhead Costs As approved by the regulator, FortisAlberta has deferred certain operating overhead costs, which are expected to be collected in future customer rates over the lives of the related property, plant and equipment and intangible assets. (viii) Derivative Instruments As approved by the respective regulators, unrealized gains or losses associated with changes in the fair value of certain derivative instruments at UNS Energy, Central Hudson and FortisBC Energy are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates. These unrealized losses and gains would otherwise be recognized in earnings. UNS Energy and Central Hudson's regulatory asset balance totalling $38 million as at December 31, 2017 was not subject to a regulatory return ( December 31, 2016 - $6 million ). (ix) MGP Site Remediation Deferral As approved by the regulator, Central Hudson is permitted to defer for future recovery from its customers the difference between actual costs for MGP site investigation and remediation and the associated rate allowances (Notes 13 and 16 ). Central Hudson's MGP site remediation costs are not subject to a regulatory return. (x) Greenhouse Gas Reduction Regulatory Incentives The deferral for greenhouse gas reduction regulatory incentives at FortisBC Energy is mostly comprised of subsidy payments to assist customers to purchase natural gas vehicles in lieu of vehicles fueled by diesel as part of the incentive program pursuant to the Greenhouse Gas Reductions (Clean Energy) Regulations under the Clean Energy Act (British Columbia). The regulator has approved recovery in rates over a 10 -year period. (xi) Other Regulatory Assets Other regulatory assets relate to all of the Corporation's regulated utilities and are comprised of various items, each individually less than $40 million . As at December 31, 2017 , $306 million ( December 31, 2016 - $296 million ) of the balance was approved to be recovered from customers in future rates, with the remaining balance expected to be approved. As at December 31, 2017 , $145 million ( December 31, 2016 ‑ $217 million ) of the balance was not subject to a regulatory return. (xii) Asset Removal Cost Provision As required by the respective regulators, depreciation rates include an accrual for asset removal costs. Actual asset removal costs are recorded against the regulatory liability when incurred. This regulatory liability represents amounts collected in customer rates in excess of incurred asset removal costs. (xiii) ROE Refund Liability The ROE refund liability at ITC relates to two third-party complaints pending before FERC requesting that the MISO regional base ROE for MISO transmission owners, including ITC, be found to no longer be just and reasonable. The complaints cover two consecutive 15 -month periods from November 2013 through February 2015 and February 2015 through May 2016 (Note 2) . As at December 31, 2017 , the estimated range of refunds for the Second Complaint was between US $106 million and US $145 million and ITC has recognized an estimated liability of $182 million (US $145 million ), which has been classified as current regulatory liability. The total estimated refund for the Initial Complaint was $158 million (US $118 million ), including interest, as at December 31, 2016 , which was substantially finalized and paid in 2017. (xiv) Energy Efficiency Liability The energy efficiency liability primarily relates to Central Hudson's Energy Efficiency Program established to fund the costs of environmental policies associated with energy conservation programs and megawatt hour reduction goals, as approved by its regulator, and was not subject to a regulatory return. (xv) Renewable Energy Surcharge As ordered by the regulator under its 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 in 2025, with distributed generation accounting for 30% of the annual renewable energy requirement. The Company must file an annual RES implementation plan for review and approval by the ACC. The approved cost of carrying out the plan is recovered from retail customers through the RES surcharge until such costs are reflected in TEP and UNS Electric's non-fuel base rates. Any RES surcharge collections above or below the costs incurred to implement the plans are deferred as a regulatory asset or liability and is subject to a regulatory return. The ACC measures compliance with its RES requirements through Renewable Energy Credits ("REC"). Each REC represents one kilowatt hour generated from renewable resources. When UNS Energy purchases renewable energy, the premium paid above the market cost of conventional power equals the REC recoverable through the RES surcharge. When RECs are purchased, UNS Energy records the cost of the RECs as long-term other assets (Note 9) and a corresponding regulatory liability, to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, energy supply costs and revenue are recognized in an equal amount. (xvi) Electric and Gas Moderator Account Under the terms of Central Hudson's three -year Rate Order issued in June 2015, certain of the Company's regulatory assets and liabilities were identified and approved by the PSC for offset and a net regulatory liability electric and gas moderator account was established, which will be used for future customer rate moderation. This electric and gas moderator account was not subject to a regulatory return. (xvii) Other Regulatory Liabilities Other regulatory liabilities relate to all of the Corporation's regulated utilities and are comprised of various items, each individually less than $40 million . As at December 31, 2017 , $173 million ( December 31, 2016 - $190 million ) of the balance was approved for refund to customers or reduction in future rates, with the remaining balance expected to be approved. As at December 31, 2017 , $26 million ( December 31, 2016 – $51 million ) of the balance was not subject to a regulatory return. |
Other Assets
Other Assets | 12 Months Ended |
Dec. 31, 2017 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Other Assets | OTHER ASSETS (in millions) 2017 2016 Supplemental Executive Retirement Plan assets $ 130 $ 115 Equity investment - Belize Electricity 73 78 Renewable Energy Credits (Note 8 (xv) ) 62 39 Defined benefit pension plan assets (Note 24) 31 32 Other investments 29 21 Deferred compensation plan assets 24 24 Equity investment - Wataynikaneyap Partnership 22 3 Other (1) 109 94 $ 480 $ 406 (1) Other assets are generally recorded at cost and recovered/amortized over the estimated period of future benefit, where applicable. Other assets also includes the fair value of derivative instruments (Note 28) . ITC, UNS Energy and Central Hudson provide additional post-employment benefits through both deferred compensation plans for Directors and Officers of the Companies, as well as Supplemental Executive Retirement Plans ("SERP") and the assets held to support these plans are reported separately from the related liabilities (Note 16) . Most of the plan assets are held in trust and funded mainly through the use of trust-owned life insurance policies and mutual funds. Assets held in mutual and money market funds are recorded at fair value on a recurring basis (Note 28) . Included in SERP assets are available-for-sale-securities at ITC of $66 million ( 2016 - $56 million ), for which gains and losses are recorded in other comprehensive income. |
Property, Plant And Equipment
Property, Plant And Equipment | 12 Months Ended |
Dec. 31, 2017 | |
Regulated Operations [Abstract] | |
Property, Plant And Equipment | PROPERTY, PLANT AND EQUIPMENT 2017 (in millions) Cost Accumulated Depreciation Net Book Value Distribution Electric $ 9,963 $ (2,864 ) $ 7,099 Gas 4,093 (1,157 ) 2,936 Transmission Electric 12,571 (2,838 ) 9,733 Gas 1,954 (596 ) 1,358 Generation 6,079 (1,996 ) 4,083 Other 3,608 (1,130 ) 2,478 Assets under construction 1,717 — 1,717 Land 264 — 264 $ 40,249 $ (10,581 ) $ 29,668 2016 (in millions) Cost Accumulated Depreciation Net Book Value Distribution Electric $ 9,616 $ (2,752 ) $ 6,864 Gas 3,956 (1,096 ) 2,860 Transmission Electric 12,616 (2,876 ) 9,740 Gas 1,776 (562 ) 1,214 Generation 6,884 (2,474 ) 4,410 Other 3,497 (1,096 ) 2,401 Assets under construction 1,559 — 1,559 Land 289 — 289 $ 40,193 $ (10,856 ) $ 29,337 Electric distribution assets are those used to distribute electricity at lower voltages (generally below 69 kilovolt ("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 kilopascal ("kPa")) or a hoop stress of less than 20% of standard minimum yield strength. These assets include distribution stations, telemetry, distribution pipe for mains and services, meter sets and other related equipment. Electric transmission assets are those used to transmit electricity at higher voltages (generally at 69 kV and higher). These assets include poles, wires, switching equipment, transformers, support structures and other related equipment. Gas transmission assets are those used to transport natural gas at higher pressures (generally at 2,070 kPa and higher) or a hoop stress of 20% or more of standard minimum yield strength. These assets include transmission stations, telemetry, transmission pipe and other related equipment. Generation assets are those used to generate electricity. These assets include hydroelectric and thermal generation stations, gas and combustion turbines, coal-fired generating stations, dams, reservoirs, photovoltaic systems and other related equipment. Other assets include buildings, equipment, vehicles, inventory, information technology assets and the Aitken Creek natural gas storage facility (Note 25) . As at December 31, 2017 , assets under construction were primarily associated with FortisBC Energy's Tilbury liquefied natural gas facility expansion and ongoing transmission projects at ITC to upgrade or replace existing transmission assets to improve system reliability and transmission infrastructure to support generator interconnections and investments that provide regional benefits, such as the Multi-Value Projects. The cost of property, plant and equipment under capital lease as at December 31, 2017 was $423 million ( December 31, 2016 - $539 million ) and related accumulated depreciation was $176 million ( December 31, 2016 - $231 million ). Jointly Owned Facilities UNS Energy and ITC hold undivided interests in jointly owned generating facilities and transmission systems, are entitled to their pro rata share of the property, plant and equipment, and are proportionately liable for the associated operating costs and liabilities. As at December 31, 2017 , interests in jointly owned facilities consisted of the following. Ownership Accumulated Net Book (in millions) % Cost Depreciation Value San Juan Unit 1 50.0 $ 351 $ (104 ) $ 247 Four Corners Units 4 and 5 7.0 210 (98 ) 112 Luna Energy Facility 33.3 69 (4 ) 65 Gila River Common Facilities 25.0 41 (14 ) 27 Springerville Coal Handling Facilities 83.0 253 (102 ) 151 Transmission Facilities 1.0-80.0 854 (302 ) 552 $ 1,778 $ (624 ) $ 1,154 |
Intangible Assets
Intangible Assets | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Intangible Assets | INTANGIBLE ASSETS 2017 Accumulated Net Book (in millions ) Cost Amortization Value Computer software $ 784 $ (474 ) $ 310 Land, transmission and water rights 743 (103 ) 640 Other 117 (49 ) 68 Assets under construction 63 — 63 $ 1,707 $ (626 ) $ 1,081 2016 Accumulated Net Book (in millions ) Cost Amortization Value Computer software $ 748 $ (447 ) $ 301 Land, transmission and water rights 700 (108 ) 592 Other 128 (56 ) 72 Assets under construction 46 — 46 $ 1,622 $ (611 ) $ 1,011 Included in the cost of land, transmission and water rights as at December 31, 2017 was $150 million ( December 31, 2016 - $138 million ) not subject to amortization. Amortization expense related to intangible assets was $97 million for 2017 ( 2016 - $ 79 million ). Amortization is estimated to average approximately $108 million annually for each of the next five years. |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill | GOODWILL (in millions) 2017 2016 Balance, beginning of year $ 12,364 $ 4,173 Acquisition of ITC (Note 2 5) (6 ) 8,106 Acquisition of Aitken Cree k (Note 25) — 27 Foreign currency translation impacts (714 ) 58 Balance, end of year $ 11,644 $ 12,364 Goodwill associated with the acquisitions of ITC, UNS Energy, Central Hudson, Caribbean Utilities and Fortis Turks and Caicos is denominated in US dollars, as the functional currency of these companies is the US dollar. Foreign currency translation impacts are the result of the translation of US dollar-denominated goodwill and the impact of the movement of the Canadian dollar relative to the US dollar. In September 2017 the Turks and Caicos Islands were struck by Hurricane Irma, resulting in significant damage to Fortis Turks and Caicos' transmission and distribution systems. The Turks and Caicos Islands are still in the process of recovering from the hurricane impact but are resuming normal business operations. The annual goodwill impairment test performed at October 1, 2017 included an assessment of the impact of Hurricane Irma and has concluded that there is no impairment to goodwill. In December 2017 U.S. Tax Reform was enacted into law, passing significant changes to tax legislation in the United States. The goodwill impairment test considered the impact of U.S. Tax Reform and has confirmed that there is no impairment to goodwill. There were no other events or circumstances in 2017 which required the Corporation to perform an impairment test of goodwill. |
Accounts Payable and Other Curr
Accounts Payable and Other Current Liabilities | 12 Months Ended |
Dec. 31, 2017 | |
Payables and Accruals [Abstract] | |
Accounts Payable and Other Current Liabilities | ACCOUNTS PAYABLE AND OTHER CURRENT LIABILITIES (in millions) 2017 2016 Trade accounts payable $ 696 $ 554 Interest payable 223 218 Customer and other deposits 204 287 Dividends payable 185 166 Employee compensation and benefits payable 184 178 Accrued taxes other than income taxes 178 168 Gas and fuel cost payable 146 175 Fair value of derivative instruments (Note 28) 71 28 MGP site remediation (Notes 8 (ix) and 16) 35 21 Defined benefit pension and OPEB liabilities (Note 24) 22 26 Other 109 149 $ 2,053 $ 1,970 |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | LONG-TERM DEBT (in millions ) Maturity Date 2017 2016 Regulated Utilities ITC Secured US First Mortgage Bonds - 4.67% weighted average fixed rate (2016 - 4.81%) 2018-2055 $ 2,063 $ 1,994 Secured US Senior Notes - 4.19% weighted average fixed rate (2016 - 4.19%) 2040-2046 596 638 Unsecured US Senior Notes - 3.98% weighted average fixed rate (2016 - 4.80%) 2020-2043 3,618 3,160 Unsecured US Shareholder Note - 6.00% fixed rate (2016 - 6.00%) 2028 250 267 Unsecured US Term Loan Credit Agreement - 2.03% weighted average variable rate 2019 63 — UNS Energy Unsecured US Tax-Exempt Bonds - 4.04% weighted average fixed and variable rate (2016 - 3.87%) 2020-2040 773 827 Unsecured US Fixed Rate Notes - 4.26% weighted average fixed rate (2016 - 4.26%) 2021-2045 1,411 1,511 Central Hudson Unsecured US Promissory Notes - 4.28% weighted average fixed and variable rate (2016 - 4.25%) 2018-2057 770 768 FortisBC Energy Unsecured Debentures - 5.13% weighted average fixed rate (2016 - 5.24%) 2026-2047 2,395 2,220 FortisAlberta Unsecured Debentures - 4.70% weighted average fixed rate (2016 - 4.82%) 2024-2052 2,035 1,834 FortisBC Electric Secured Debentures - 8.80% fixed rate (2016 - 8.80%) 2023 25 25 Unsecured Debentures - 5.05% weighted average fixed rate (2016 - 5.22%) 2021-2050 710 635 Eastern Canadian Secured First Mortgage Sinking Fund Bonds - 6.14% weighted average fixed rate (2016 - 6.48%) 2020-2057 585 516 Secured First Mortgage Bonds - 6.19% weighted average fixed rate (2016 - 6.19%) 2018-2061 195 195 Unsecured Senior Notes - 6.11% weighted average fixed rate (2016 - 6.11%) 2018-2041 104 104 Caribbean Electric Unsecured US Senior Loan Notes and Bonds - 4.80% weighted average fixed and variable rate (2016 - 4.92%) 2018-2048 525 499 Corporate Unsecured US Senior Notes and Promissory Notes - 3.41% weighted average fixed rate (2016 - 3.43%) 2019-2044 4,046 4,353 Unsecured Debentures - 6.50% weighted average fixed rate (2016 - 6.50%) 2039 200 200 Unsecured Senior Notes - 2.85% fixed rate (2016 - 2.85%) 2023 500 500 Long-term classification of credit facility borrowings 671 973 Total long-term debt (Note 28) 21,535 21,219 Less: Deferred financing costs and debt discounts (139 ) (151 ) Less: Current installments of long-term debt (705 ) (251 ) $ 20,691 $ 20,817 Certain long-term debt instruments at the Corporation's regulated utilities are secured. When security is provided, it is typically a fixed or floating first charge on the specific assets of the Company to which the long‑term debt is associated. Covenants Certain of the Corporation's long-term debt obligations have covenants restricting the issuance of additional debt such that consolidated debt cannot exceed 70% of the Corporation's consolidated capital structure, as defined by the long-term debt agreements. In addition, one of the Corporation's long-term debt obligations contains a covenant which provides that Fortis shall not declare or pay any dividends, other than stock dividends or cumulative preferred dividends on preference shares not issued as stock dividends, or make any other distribution on its shares or redeem any of its shares or prepay subordinated debt if, immediately thereafter, its consolidated funded obligations would be in excess of 75% of its total consolidated capitalization. Regulated Utilities The majority of the long-term debt instruments at the Corporation's regulated utilities are redeemable at the option of the respective utilities, at any time, at the greater of par or a specified price as defined in the respective long-term debt agreements, together with accrued and unpaid interest. In March 2017 ITC entered into 1 -year and 2 -year unsecured term loan credit agreements at floating interest rates of a one-month LIBOR plus a spread of 0.90% and 0.65% , respectively. Borrowings under the term loan credit agreements were US $200 million and US $50 million , respectively, representing the maximum amounts available under the agreements. The net proceeds from these borrowings were used to repay credit facility borrowings and for general corporate purposes. The US $200 million term loan was subsequently repaid using long-term debt issued in November 2017. In April 2017 ITC issued 30 -year US $200 million secured first mortgage bonds at 4.16% . The net proceeds from the issuance were used to repay credit facility borrowings and for general corporate purposes. In November 2017 ITC issued 5 -year US $500 million unsecured notes at 2.70% and 10 -year US $500 million unsecured notes at 3.35% . The net proceeds from the issuances were used to repay long-term debt, including borrowings under the term loan as discussed above, to repay short-term borrowings, and for general corporate purposes. In March and May 2017 , Caribbean Utilities issued US $60 million of unsecured notes in a dual tranche of 15 -year US $40 million at 3.90% and 30 -year US $20 million at 4.64% , respectively. The net proceeds from the issuances were used to finance capital expenditures and repay short-term borrowings. In June 2017 Newfoundland Power issued 40 -year $75 million first mortgage sinking fund bonds at 3.815% . The net proceeds from the issuance were used to repay credit facility borrowings and for general corporate purposes. In August 2017 Central Hudson issued 30 -year US $30 million unsecured notes at 4.05% and 40 -year US $30 million unsecured notes at 4.20% . The net proceeds from the issuances were used to repay long-term debt and for general corporate purposes. In September 2017 FortisAlberta issued 30 -year $200 million unsecured debentures at 3.67% . The net proceeds from the issuance were used to repay credit facility borrowings, to finance capital expenditures and for general corporate purposes. In October 2017 FortisBC Energy issued 30 -year $175 million unsecured debentures at 3.69% . The net proceeds from the issuance were used to repay short-term borrowings and to finance capital expenditures. In December 2017 FortisBC Electric issued 32 -year $75 million unsecured debentures at 3.62% . The net proceeds from the issuance were used to repay short-term borrowings. Corporate The unsecured debentures and senior notes are redeemable at the option of Fortis at a price calculated as the greater of par or a specified price as defined in the respective long-term debt agreements, together with accrued and unpaid interest. Credit Facilities As at December 31, 2017 , the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.0 billion , of which approximately $3.9 billion was unused, including $ 1.1 billion unused under the Corporation's committed revolving corporate credit facility. The credit facilities are syndicated mostly with large banks in Canada and the United States, with no one bank holding more than 20% of these facilities. Approximately $ 4.7 billion of the total credit facilities are committed facilities with maturities ranging from 2019 through 2022 . The following summary outlines the credit facilities of the Corporation and its subsidiaries. (in millions) Regulated Corporate 2017 2016 Total credit facilities (1) $ 3,567 $ 1,385 $ 4,952 $ 5,976 Credit facilities utilized: Short-term borrowings (1) (2) (209 ) — (209 ) (1,155 ) Long-term debt (including current portion) (3) (465 ) (206 ) (671 ) (973 ) Letters of credit outstanding (73 ) (56 ) (129 ) (119 ) Credit facilities unused $ 2,820 $ 1,123 $ 3,943 $ 3,729 (1) As at December 31, 2017 , there was no commercial paper outstanding ( December 31, 2016 - $195 million ). Outstanding commercial paper does not reduce available capacity under the Corporation's consolidated credit facilities. (2) The weighted average interest rate on short-term borrowings was approximately 1.8% as at December 31, 2017 ( December 31, 2016 - 1.7% ). (3) As at December 31, 2017 , credit facility borrowings classified as long-term debt included $ 312 million in current installments of long-term debt on the consolidated balance sheet ( December 31, 2016 - $ 61 million ). The weighted average interest rate on credit facility borrowings classified as long‑term debt was approximately 2.5% as at December 31, 2017 ( December 31, 2016 - 1.8% ). As at December 31, 2017 and 2016 , certain borrowings under the Corporation's and subsidiaries' long‑term committed credit facilities were classified as long-term debt. It is management's intention to refinance these borrowings with long‑term permanent financing during future periods. Regulated Utilities ITC has a total of US $900 million in unsecured committed revolving credit facilities maturing in October 2022. ITC has an ongoing commercial paper program in an aggregate amount of US $400 million , under which ITC had no amounts outstanding as at December 31, 2017 . UNS Energy has a total of US $500 million in unsecured committed revolving credit facilities, maturing in October 2022. Central Hudson has a combined US $250 million unsecured committed revolving credit facility, with US $50 million maturing in July 2020 and the remaining maturing in October 2020. Central Hudson also has an uncommitted credit facility totalling US $40 million . FortisBC Energy has a $700 million unsecured committed revolving credit facility, maturing in August 2022. FortisAlberta has a $250 million unsecured committed revolving credit facility, maturing in August 2022. FortisBC Electric has a $150 million unsecured committed revolving credit facility, maturing in May 2022, and a $10 million unsecured demand overdraft facility. Newfoundland Power has a $100 million unsecured committed revolving credit facility, maturing in August 2022, and a $20 million demand credit facility. Maritime Electric has a $50 million unsecured committed revolving credit facility, maturing in February 2019, and a $5 million unsecured demand credit facility. FortisOntario has a $40 million unsecured committed revolving credit facility, maturing in June 2020. Caribbean Utilities has unsecured credit facilities totalling US $50 million . Fortis Turks and Caicos has short-term unsecured demand credit facilities of US $22 million , and an emergency standby loan of US $25 million both maturing in June 2018. Corporate and Other Fortis has a $1.3 billion unsecured committed revolving credit facility, maturing in July 2022. The Corporation has the option to increase the facility by an amount up to $0.5 billion and, as at December 31, 2017 , that option had not been exercised. In March 2017, the Corporation repaid a $500 million non-revolving term senior unsecured equity bridge credit facility, used to finance a portion of the cash purchase price of the acquisition of ITC, with proceeds from the issuance of common shares. Fortis issued approximately 12.2 million common shares, in a private placement to an institutional investor, representing share consideration of $500 million at a price of $41.00 per share. FHI has a $50 million unsecured committed revolving credit facility, maturing in April 2020. Repayment of Long-Term Debt The consolidated annual requirements to meet principal repayments and maturities in each of the next five years and thereafter are as follows. Regulated Corporate Utilities and Other Total Year (in millions) (in millions) (in millions) 2018 $ 499 $ 206 $ 705 2019 169 113 282 2020 516 157 673 2021 435 784 1,219 2022 1,060 — 1,060 Thereafter 13,904 3,692 17,596 $ 16,583 $ 4,952 $ 21,535 |
Capital Lease and Finance Oblig
Capital Lease and Finance Obligations | 12 Months Ended |
Dec. 31, 2017 | |
Leases [Abstract] | |
Capital Lease and Finance Obligations | CAPITAL LEASE AND FINANCE OBLIGATIONS Capital Lease Obligations UNS Energy TEP is party to three Springerville Common Facilities leases: (i) one lease with a fixed purchase price of US $38 million and an initial term to December 2017; and (ii) two leases with a fixed purchase price of US $68 million and an initial term to January 2021. In December 2017 TEP purchased a 17.8% undivided interest in the Springerville Common Facilities for $49 million bringing its total ownership of the assets to 67.8% . Upon purchase of the leased interest, current lease obligations on the consolidated balance sheet was reduced by $46 million . Under the remaining two leases, TEP has the option to renew the leases for periods of two or more years or exercise the purchase options under these contracts. In addition, TEP has entered into agreements with third parties that if the Springerville Common Facilities leases are not renewed, TEP will exercise the purchase options under these contracts. The third parties would be obligated to buy a portion of these facilities or continue to make payments to TEP for the use of these facilities. TEP entered into an interest rate swap that hedges a portion of the floating interest rate risk associated with the Springerville Common Facilities lease obligation. As at December 31, 2017 , interest on the lease obligation is payable at a six-month LIBOR plus a spread of 1.88% ( December 31, 2016 - 1.88% ). The swap has the effect of fixing the interest rate on a portion of the amortizing principal balance of $23 million ( December 31, 2016 - $31 million ). The interest rate swap expires in 2020 and is recorded as a cash flow hedge (Note 28) . The Springerville Common Facilities capital lease obligation bears interest at a rate of 5.08% . For 2017 $4 million ( 2016 - $4 million ) of interest expense and $8 million ( 2016 - $7 million ) of depreciation expense was recognized related to the Springerville capital lease obligations. FortisBC Electric FortisBC Electric has a capital lease obligation with respect to the operation of the Brilliant hydroelectric plant ("Brilliant Plant") located in British Columbia. FortisBC Electric operates and maintains the Brilliant Plant, under the BPPA which expires in 2056, in return for a management fee. In exchange for the specified take-or-pay amounts of power, the BPPA requires semi-annual payments based on a return on capital, comprised of the original plant capital charge and periodic upgrade capital charges, which are both subject to fixed annual escalators, as well as sustaining capital charges and operating expenses. The BPPA includes a market-related price adjustment in 2026. Approximately 94% of the output from the Brilliant Plant is being purchased by FortisBC Electric through the BPPA. The BPPA capital lease obligation bears interest at a composite rate of 5.00% . Included in energy supply costs for 2017 was $27 million ( 2016 - $27 million ) recognized in accordance with the BPPA, as approved by the BCUC. FortisBC Electric also has a capital lease obligation with respect to the operation of the Brilliant Terminal Station ("BTS"), under an agreement which expires in 2056. The agreement provides that FortisBC Electric will pay a charge related to the recovery of the capital cost of the BTS and related operating costs. The obligation bears interest at a composite rate of 9.00% . Included in operating expenses for 2017 was $3 million ( 2016 ‑ $3 million ) recognized in accordance with the BTS agreement, as approved by the BCUC. Finance Obligations Between 2000 and 2005 FortisBC Energy entered into arrangements whereby certain natural gas distribution assets were leased to certain municipalities and then leased back by FortisBC Energy. The natural gas distribution assets are considered to be integral equipment to real estate assets and, as such, the transactions have been accounted for as finance transactions. The proceeds from these transactions have been recognized as finance obligations on the consolidated balance sheet. Lease payments, net of the portion considered to be interest expense, reduce the finance obligations. Obligations under the above-noted lease-in lease-out transactions have implicit interest at rates ranging from 6.86% to 8.46% and are being repaid over an initial 35 -year period. Each of the lease-in lease‑out arrangements allows FortisBC Energy, at its option, to terminate the lease arrangement early, after 17 years. If the Company exercises this option, FortisBC Energy would pay the municipality an early termination payment which is equal to the carrying value of the obligation at that point in time. One of the early termination payments could potentially be due in 2018; however, the decision to early terminate has not yet been made by FortisBC Energy. This early termination payment has been included as due within one year in contractual obligations and has been recognized in current liabilities as at December 31, 2017. Repayment of Capital Lease and Finance Obligations The present value of the minimum lease payments required for the capital lease and finance obligations over the next five years and thereafter are as follows: Capital Finance Leases Obligations Total Year (in millions) (in millions) (in millions) 2018 $ 58 $ 32 $ 90 2019 59 15 74 2020 68 5 73 2021 46 32 78 2022 46 3 49 Thereafter 1,950 — 1,950 $ 2,227 $ 87 $ 2,314 Less: Amounts representing imputed interest and executory costs on capital lease and finance obligations (1,853 ) Total capital lease and finance obligations 461 Less: Current installments (47 ) $ 414 |
Other Liabilities
Other Liabilities | 12 Months Ended |
Dec. 31, 2017 | |
Other Liabilities Disclosure [Abstract] | |
Other Liabilities | OTHER LIABILITIES (in millions) 2017 2016 Defined benefit pension plan liabilities (Note 24) $ 393 $ 410 OPEB plan liabilities (Note 24) 381 411 Asset retirement obligations 71 58 Customer and other deposits 67 69 Waneta Partnership promissory note (Notes 28, 29 and 30) 63 59 Mine reclamation and retiree health care liabilities 40 40 DSU, PSU and RSU liabilities (Note 21) 39 24 Fair value of derivative instruments (Note 28) 37 10 MGP site remediation (Notes 8 (ix) and 13) 34 77 Deferred compensation plan liabilities (Note 9) 28 27 Other 57 94 $ 1,210 $ 1,279 The Waneta Partnership promissory note is non-interest bearing with a face value of $72 million . As at December 31, 2017 , its discounted net present value was $63 million ( December 31, 2016 - $59 million ). The promissory note is payable on April 1, 2020, the fifth anniversary of the commercial operation date of the Waneta Expansion. TEP pays ongoing reclamation costs related to three coal mines that supply generating stations in which the Company has an ownership interest but does not operate. TEP's share of the reclamation costs is expected to be US $61 million ( December 31, 2016 - US $61 million ) upon expiry of the coal agreements, which expire between 2019 and 2031. The mine reclamation liability recognized as at December 31, 2017 was $43 million (US $34 million ) ( December 31, 2016 - $35 million (US $25 million )), which represents the present value of the estimated future liability. TEP is permitted to recover these costs from customers and, accordingly, these costs are deferred and included in other regulatory assets. Central Hudson has been notified by the New York State Department of Environmental Conservation to investigate MGPs at sites that the Company or its predecessors once owned and/or operated and, if necessary, remediate these sites. Central Hudson accrues for remediation costs based on the amounts that can be reasonably estimated. As at December 31, 2017 , an obligation of $69 million (US $55 million ) was recognized, including a current portion of $35 million (US $28 million ) included in accounts payable and other current liabilities. Central Hudson has notified its insurers and intends to seek reimbursement, where coverage exists. Further, as authorized by the PSC, Central Hudson is currently permitted to defer, for future recovery from customers, differences between actual costs for MGP site investigation and remediation and the associated rate allowances ( Note 8 (ix) ). Other liabilities primarily include long-term accrued liabilities, deferred lease revenue, funds received in advance of expenditures and unrecognized tax benefits. |
Earnings Per Common Share
Earnings Per Common Share | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Earnings Per Common Share | EARNINGS PER COMMON SHARE The Corporation calculates earnings per common share ("EPS") on the weighted average number of common shares outstanding. Diluted EPS was calculated using the treasury stock method for options and the "if‑converted" method for convertible securities. 2017 2016 Net Earnings Weighted Net Earnings Weighted to Common Average to Common Average Shareholders Shares Shareholders Shares ($ millions) (# millions) EPS ($ millions) (# millions) EPS Basic EPS $ 963 415.5 $ 2.32 $ 585 308.9 $ 1.89 Effect of potential dilutive securities: Stock Options — 0.7 — 0.7 Preference Shares — — 7 3.8 Diluted EPS $ 963 416.2 $ 2.31 $ 592 313.4 $ 1.89 |
Preference Shares
Preference Shares | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Preference Shares | PREFERENCE SHARES Authorized (a) an unlimited number of First Preference Shares, without nominal or par value (b) an unlimited number of Second Preference Shares, without nominal or par value Issued and Outstanding 2017 2016 First Preference Shares Number Number of Shares Amount of Shares Amount (in thousands) (in millions) (in thousands) (in millions) Series F 5,000 $ 122 5,000 $ 122 Series G 9,200 225 9,200 225 Series H 7,025 172 7,025 172 Series I 2,975 73 2,975 73 Series J 8,000 196 8,000 196 Series K 10,000 244 10,000 244 Series M 24,000 591 24,000 591 66,200 $ 1,623 66,200 $ 1,623 In September 2016 the Corporation redeemed all of the issued and outstanding $200 million 4.9% First Preference Shares, Series E at a redemption price of $25.3063 per share, being equal to $25.00 plus the amount of accrued and unpaid dividends per share. Upon redemption, approximately $3 million of after-tax issuance costs associated with the First Preference Shares, Series E were recognized in net earnings attributable to preference equity shareholders. Characteristics of the First Preference Shares are as follows. Earliest Reset Redemption Right to Initial Annual Dividend and/or Redemption Convert on Yield Dividend Yield Conversion Value a One For First Preference Shares (1) (2) (%) ($) (%) Option Date ($) One Basis Perpetual fixed rate Series F 4.90 1.2250 — December 1, 2011 25.00 — Series J (3) 4.75 1.1875 — December 1, 2017 26.00 — Fixed rate reset (4) (5) Series G 5.25 0.9708 2.13 September 1, 2013 25.00 — Series H 4.25 0.6250 1.45 June 1, 2015 25.00 Series I Series K 4.00 1.0000 2.05 March 1, 2019 25.00 Series L Series M 4.10 1.0250 2.48 December 1, 2019 25.00 Series N Floating rate reset (5) (6) Series I (3) 2.10 — 1.45 June 1, 2015 25.50 Series H Series L — — 2.05 March 1, 2024 — Series K Series N — — 2.48 December 1, 2024 — Series M (1 ) Holders are entitled to receive a fixed or floating cumulative quarterly cash dividend as and when declared by the Board of Directors of the Corporation, payable in equal quarterly installments on the first day of each quarter. (2 ) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First Preference Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but excluding the dates fixed for redemption, and in the case of the First Preference Shares that reset, on every fifth anniversary date, thereafter. (3) First Preference Shares, Series J are redeemable at $26.00 until December 1, 2018, such redemption price decreasing by $0.25 each year until December 1, 2021 and redeemable at $25.00 per share thereafter. First Preference Shares, Series I are redeemable at $25.50 per share, up to but excluding June 1, 2020, and at $25.00 per share on June 1, 2020, and on every fifth anniversary date of June 1, 2020, thereafter. (4 ) On the redemption and/or conversion option date, and each five -year anniversary thereafter, the reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate, which is the sum of the five -year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield. (5) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their Shares into an equal number of Cumulative Redeemable First Preference Shares of a specified series. (6) The floating quarterly dividend rate will be reset every quarter based on the then current three‑month Government of Canada Treasury Bill rate plus the applicable reset dividend yield. On the liquidation, dissolution or winding-up of Fortis, holders of Common Shares are entitled to participate ratably in any distribution of assets of Fortis, subject to the rights of holders of First Preference Shares and Second Preference Shares and any other class of shares of the Corporation entitled to receive the assets of the Corporation on such a distribution in priority to or ratably with the holders of the Common shares. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Accumulated Other Comprehensive Income | ACCUMULATED OTHER COMPREHENSIVE INCOME Other comprehensive income or loss results from items deferred from recognition in the consolidated statement of earnings. The change in accumulated other comprehensive income by category is provided as follows. 2017 (in millions) Opening balance January 1 Net Change Ending balance December 31 Net unrealized foreign currency translation gains (losses): Unrealized foreign currency translation gains (losses) on net investments in foreign operations $ 1,227 $ (980 ) $ 247 (Losses) gains on hedges of net investments in foreign operations (472 ) 300 (172 ) Income tax recovery (expense) 1 (2 ) (1 ) 756 (682 ) 74 Cash flow hedges: (Note 28) Net change in fair value of cash flow hedges 8 (2 ) 6 Reclassification of cash flow hedges to finance charges — 4 4 Income tax expense (3 ) — (3 ) 5 2 7 Unrealized employee future benefits (losses) gains: (Note 24) Unamortized net actuarial losses (19 ) (3 ) (22 ) Unamortized past service costs (3 ) (1 ) (4 ) Income tax recovery 6 — 6 (16 ) (4 ) (20 ) Accumulated other comprehensive income $ 745 $ (684 ) $ 61 2016 (in millions) Opening balance January 1 Net Change Ending balance December 31 Net unrealized foreign currency translation gains (losses): Unrealized foreign currency translation gains (losses) on net investments in foreign operations $ 1,281 $ (54 ) $ 1,227 (Losses) gains on hedges of net investments in foreign operations (476 ) 4 (472 ) Income tax recovery 1 — 1 806 (50 ) 756 Available-for-sale investment: Realized gain on available-for-sale investment (2 ) 2 — Cash flow hedges: (Note 28) Net change in fair value of cash flow hedges 3 5 8 Income tax expense (1 ) (2 ) (3 ) 2 3 5 Unrealized employee future benefits (losses) gains: (Note 24) Unamortized net actuarial (losses) gains (20 ) 1 (19 ) Unamortized past service costs (1 ) (2 ) (3 ) Income tax recovery 6 — 6 (15 ) (1 ) (16 ) Accumulated other comprehensive income $ 791 $ (46 ) $ 745 |
Non-Controlling Interests
Non-Controlling Interests | 12 Months Ended |
Dec. 31, 2017 | |
Noncontrolling Interest [Abstract] | |
Non-Controlling Interests | NON-CONTROLLING INTERESTS (in millions) 2017 2016 ITC $ 1,290 $ 1,385 Waneta Partnership 322 330 Caribbean Utilities 118 122 Other 16 16 $ 1,746 $ 1,853 |
Stock-based Compensation Plans
Stock-based Compensation Plans | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock-based Compensation Plans | STOCK-BASED COMPENSATION PLANS Stock Options The Corporation is authorized to grant officers and certain key employees of Fortis and its subsidiaries options to purchase common shares of the Corporation. As at December 31, 2017 , the Corporation had the following stock option plans: the 2012 Plan and the 2006 Plan. The 2012 Plan was approved at the May 4, 2012 Annual General Meeting and will ultimately replace the 2006 Plan. The 2006 Plan will cease to exist when all outstanding options are exercised or expire in or before 2018. The former 2002 plan expired in February 2016. The Corporation has ceased the granting of options under the 2006 Plan and all new options granted after 2011 are being made under the 2012 Plan. Options granted under the 2006 Plan are exercisable for a period not to exceed seven years from the date of grant, expire no later than three years after the termination, death or retirement of the optionee and vest evenly over a four -year period on each anniversary of the date of grant. Options granted under the 2012 Plan are exercisable for a period not to exceed ten years from the date of grant, expire no later than three years after the termination, death or retirement of the optionee and vest evenly over a four -year period on each anniversary of the date of grant. The following options were granted in 2017 and 2016 . The accounting fair values of the options were estimated at the date of grant using the Black-Scholes fair value option-pricing model and the following assumptions: 2017 2016 Options granted (#) 774,924 788,188 Exercise price ($) (1) 42.36 37.30 Grant date fair value ($) 3.22 2.41 Assumptions: Dividend yield (%) (2) 3.8 3.9 Expected volatility (%) (3) 16.1 16.4 Risk-free interest rate (%) (4) 1.2 0.7 Weighted average expected life (years) (5) 5.6 5.5 (1) Five -day VWAP immediately preceding the date of grant (2) Based on average annual dividend yield up to the date of grant and the weighted average expected life of the options (3) Based on historical experience over a period equal to the weighted average expected life of the options (4) Government of Canada benchmark bond yield in effect at the date of grant that covers the weighted average expected life of the options (5) Based on historical experience The Corporation records compensation expense upon the issuance of stock options. Using the fair value method, each grant is treated as a single award, the fair value of which is amortized to compensation expense evenly over the four -year vesting period of the options. The following table summarizes information related to stock options for 2017 . Total Options Non-vested Options (1) Number of Options Weighted Average Number of Options Weighted Average Options outstanding, January 1, 2017 4,160,192 $ 34.45 1,815,018 $ 2.78 Granted 774,924 $ 42.36 774,924 $ 3.22 Exercised (1,217,029 ) $ 32.73 n/a n/a Vested n/a n/a (761,830 ) $ 3.03 Cancelled/Forfeited (15,793 ) $ 40.27 (15,793 ) $ 2.88 Options outstanding, December 31, 2017 3,702,294 $ 36.65 1,812,319 $ 2.86 Options vested, December 31, 2017 (2) 1,889,975 $ 34.25 (1) As at December 31, 2017 , there was $5 million of unrecognized compensation expense related to stock options not yet vested, which is expected to be recognized over a weighted average period of approximately three years. (2) As at December 31, 2017 , the weighted average remaining term of vested options was six years with an aggregate intrinsic value of $22 million . The following table summarizes additional 2017 and 2016 stock option information. (in millions) 2017 2016 Stock option expense recognized $ 3 $ 2 Stock options exercised: Cash received for exercise price 40 28 Intrinsic value realized by employees 15 15 Fair value of options that vested 2 3 Directors' DSU Plan Under the Corporation's Directors' DSU Plan, directors who are not officers of the Corporation are eligible for grants of DSUs representing the equity portion of directors' annual compensation. In addition, directors can elect to receive credit for their quarterly cash retainer in a notional account of DSUs in lieu of cash. The Corporation may also determine from time to time that special circumstances exist that would reasonably justify the grant of DSUs to a director as compensation in addition to any regular retainer or fee to which the director is entitled. Each DSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation and is entitled to accrue notional common share dividends equivalent to those declared by the Corporation's Board of Directors. The DSUs are fully vested at the date of grant. Number of DSUs 2017 2016 DSUs outstanding, beginning of year 199,411 167,762 Granted 31,453 30,165 Granted - notional dividends reinvested 7,294 6,994 DSUs paid out (53,363 ) (5,510 ) DSUs outstanding, end of year 184,795 199,411 For 2017 expense of $3 million ( 2016 - $2 million ) was recognized in earnings with respect to the DSU Plan. In 2017 , 53,363 DSUs were paid out to retired directors at a weighted average price of $45.37 per DSU for a total of approximately $2 million . As at December 31, 2017 , the liability related to outstanding DSUs has been recorded at the VWAP of the Corporation's common shares for the last five trading days of 2017 of $46.01 , for a total of $9 million ( December 31, 2016 - $8 million ), and is included in long-term other liabilities (Note 16) . PSU Plans The Corporation's PSU Plans represent a component of long-term compensation awarded to senior management of the Corporation and its subsidiaries, with the exception of ITC where PSUs were granted to all employees consistent with past practice. As at December 31, 2017 , the Corporation had the 2015 PSU Plan and subsidiaries of the Corporation have adopted similar share unit plans that are modelled after the Corporation's plan. The former 2013 PSU Plan expired in 2017 when all outstanding PSUs were paid. Each PSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation and is entitled to accrue notional common share dividends equivalent to those declared by the Corporation's Board of Directors. The PSUs are subject to a three -year vesting and performance period, at which time a cash payment may be made, as determined by the Human Resources Committee of the Board of Directors. Awards are calculated by multiplying the number of units outstanding at the end of the performance period by the VWAP of the Corporation's common shares for five trading days prior to the maturity of the grant and by a payout percentage that may range from 0% to 200% . The payout percentage for the PSU Plans is based on the Corporation's performance over the three -year period, mainly determined by: (i) the Corporation's total shareholder return as compared to a pre‑defined peer group of companies; and (ii) the Corporation's cumulative earnings per common share, or for certain subsidiaries the Company's cumulative net income, as compared to the target established at the time of the grant. As at December 31, 2017 , the estimated weighted average payout percentages for the grants under the 2015 PSU Plan range from 82% to 113% . The following table summarizes information related to the PSUs for 2017 and 2016 . Number of PSUs 2017 2016 PSUs outstanding, beginning of year 931,951 694,386 Granted 711,749 351,737 Granted - notional dividends reinvested 44,893 34,439 PSUs paid out (239,509 ) (148,168 ) PSUs cancelled/ forfeited (16,910 ) (443 ) Transferred to RSU Plan (81,214 ) — PSUs outstanding, end of year 1,350,960 931,951 In 2017 , 239,509 PSUs were paid out at $41.46 per PSU, for a total of approximately $11 million . The payout was made in respect of the PSUs granted in 2014 under the former 2013 PSU Plan. The PSU payout percentage was 113% based on the Corporation's and subsidiaries' performance over the three ‑year period, as determined by the respective Human Resources Committee. For 2017 expense of approximately $26 million ( 2016 - $16 million ) was recognized in earnings with respect to the PSU Plans and there was $17 million of unrecognized compensation expense related to PSUs not yet vested, which is expected to be recognized over a weighted average period of approximately two years. As at December 31, 2017 , the aggregate intrinsic value of the outstanding PSUs was $58 million , with a weighted average contractual life of approximately one year. The liability related to outstanding PSUs has been recorded at the VWAP of the Corporation's common shares for the last five trading days of 2017 of $46.01 , for a total of $41 million ( December 31, 2016 ‑ $30 million ), and is included in accounts payable and other current liabilities and long-term other liabilities (Notes 13 and 16 ). RSU Plans The Corporation's 2015 RSU Plan represents a component of long-term compensation awarded to senior management of the Corporation and its subsidiaries, with the exception of ITC where RSUs were granted to all employees consistent with past practice. Each RSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation and is subject to a three -year vesting period, at which time a cash payment may be made. Each RSU is entitled to accrue notional common share dividends equivalent to those declared by the Corporation's Board of Directors. Number of RSUs 2017 2016 RSUs outstanding, beginning of year 123,612 58,740 Granted 349,496 70,393 Granted - notional dividends reinvested 15,407 4,709 RSUs paid out (74,876 ) (10,201 ) RSUs cancelled/ forfeited (12,090 ) (29 ) Transferred from PSU Plan 81,214 — RSUs outstanding, end of year 482,763 123,612 I n 2017 , 74,876 RSUs were paid out at a weighted average price of $43.42 per RSU, for a total of approximately $3 million . In accordance with the respective RSU plans, the RSUs were paid to senior management upon retirement or death. For 2017 expense of approximately $8 million ( 2016 - $2 million ) was recognized in earnings with respect to the RSU Plan and there was approximately $11 million of unrecognized compensation expense related to RSUs not yet vested, which is expected to be recognized over a weighted average period of approximately two years. As at December 31, 2017 , the aggregate intrinsic value of the outstanding RSUs was $22 million , with a weighted average contractual life of approximately two years. The liability related to outstanding RSUs was recorded at the VWAP of the Corporation's common shares for the last five trading days of 2017 of $46.01 , for a total of $11 million ( December 31, 2016 - $3 million ), and is included in accounts payable and other current liabilities and long-term other liabilities ( Note 13 and 16 ). |
Other Income, Net
Other Income, Net | 12 Months Ended |
Dec. 31, 2017 | |
Other Income and Expenses [Abstract] | |
Other Income, Net | OTHER INCOME, NET (in millions) 2017 2016 Equity component of AFUDC $ 74 $ 37 Net foreign exchange gain (1) 26 — Interest income 14 7 Equity income - Belize Electricity 4 7 Other 9 2 $ 127 $ 53 (1) The net foreign exchange gain includes a one-time $21 million unrealized foreign exchange gain on US dollar-denominated affiliate loan. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | INCOME TAXES U.S. Tax Reform On December 22, 2017, the Tax Cuts and Jobs Act was signed into law by the President of the United States of America, enacting significant changes to tax legislation, including a reduction in the U.S. federal corporate income tax from 35% to 21% effective January 1, 2018. The Corporation's U.S. utilities and holding companies were required to remeasure their deferred tax assets and liabilities at the new corporate income tax rate as at the date of enactment. The one-time remeasurement resulted in a net decrease in deferred income tax liabilities of $1.3 billion , the recognition of a regulatory liability of $1.5 billion for the reduction in deferred income tax expected to be refunded to customers, and an unfavourable earnings impact of $168 million recognized in deferred income tax expense ( $146 million after non-controlling interest). Fortis is still evaluating the bonus depreciation exemption for its U.S. regulated utilities and anticipates further clarification. The Corporation's U.S. regulated utilities have recorded an estimated provision for bonus depreciation for property, plant and equipment in service between September 27, 2017 and December 31, 2017, which impacts the tax loss carryforward deferred tax asset and property, plant and equipment deferred tax liability. Deferred Income Taxes Deferred income taxes are provided for temporary differences. The significant components of deferred income tax assets and liabilities consist of the following. (in millions) 2017 2016 Gross deferred income tax assets Tax loss and credit carryforwards $ 571 $ 675 Regulatory liabilities 596 292 Employee future benefits 143 155 Fair value of long-term debt adjustment 43 88 Unrealized foreign exchange losses on long-term debt 28 56 Other 8 57 1,389 1,323 Deferred income tax assets valuation allowance (44 ) (56 ) Net deferred income tax assets $ 1,345 $ 1,267 Gross deferred income tax liabilities Property, plant and equipment $ (3,353 ) $ (4,213 ) Regulatory assets (203 ) (242 ) Intangible assets (87 ) (75 ) (3,643 ) (4,530 ) Net deferred income tax liability $ (2,298 ) $ (3,263 ) The deferred income tax assets associated with unrealized foreign exchange losses on long‑term debt and tax loss and credit carryforwards reflects $44 million of unrealized and realized capital losses as at December 31, 2017 ( December 31, 2016 - $56 million ). The deferred income tax asset can only be used if the Corporation has capital gains to offset the losses once realized. Management believes that it is more likely than not that Fortis will not be able to generate future capital gains and, as a result, the Corporation recorded a $44 million valuation allowance against the deferred income tax asset as at December 31, 2017 ( December 31, 2016 - $56 million ). Management believes that based on its historical pattern of taxable income, Fortis will produce sufficient income in the future to realize all other deferred income tax assets. Unrecognized Tax Benefits The following table summarizes the change in unrecognized tax benefits during 2017 and 2016 . (in millions) 2017 2016 Total unrecognized tax benefits, beginning of year $ 23 $ 13 Additions related to the current year 13 10 Adjustments related to prior years and U.S. Tax Reform (8 ) — Total unrecognized tax benefits, end of year $ 28 $ 23 Unrecognized tax benefits, if recognized, would reduce income tax expense by $2 million in 2017 . Fortis has no t recognized interest expense in 2017 and 2016 related to unrecognized tax benefits. The components of the income tax expense were as follows. (in millions) 2017 2016 Canadian Earnings before income taxes $ 461 $ 357 Current income taxes 41 66 Deferred income taxes 16 (23 ) Total Canadian $ 57 $ 43 Foreign Earnings before income taxes $ 1,252 $ 501 Current income taxes 3 (19 ) Deferred income taxes 528 121 Total Foreign $ 531 $ 102 Income tax expense $ 588 $ 145 Income taxes differ 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 taxes. The following is a reconciliation of consolidated statutory taxes to consolidated effective taxes. (in millions, except as noted) 2017 2016 Earnings before income taxes $ 1,713 $ 858 Combined Canadian federal and provincial statutory income tax rate 28.0 % 28.0 % Expected federal and provincial taxes at statutory rate $ 480 $ 240 Increase (decrease) resulting from: Enactment of U.S. Tax Reform 168 — Foreign and other statutory rate differentials 31 (28 ) Allowance for funds used during construction (26 ) (14 ) Effects of rate-regulated accounting: Difference between depreciation claimed for income tax and accounting purposes (26 ) (25 ) Items capitalized for accounting purposes but expensed for income tax purposes (21 ) (26 ) Release of valuation allowance and non-taxable portion of gain on dispositions (17 ) — Other (1 ) (2 ) Income tax expense $ 588 $ 145 Effective tax rate 34.3 % 16.9 % As at December 31, 2017 , the Corporation had the following tax carryforward amounts. (in millions) Expiring Year 2017 Canadian Capital loss n/a $ 70 Non-capital loss 2025-2037 326 Other tax credits 2026-2037 2 398 Unrecognized in the consolidated financial statements (65 ) $ 333 Foreign Capital loss 2018 $ 1 Federal and state net operating loss 2022-2037 1,850 Other tax credits 2021-2037 126 1,977 Unrecognized in the consolidated financial statements (1 ) $ 1,976 Total tax carryforwards $ 2,309 As at December 31, 2017 , the Corporation had approximately $2,309 million in tax carryforward amounts recognized in the consolidated financial statements ( December 31, 2016 - $1,235 million ). The Corporation and one or more of its subsidiaries are subject to taxation in Canada, the United States and other foreign jurisdictions. The material jurisdictions in which the Corporation is subject to potential examinations include the United States (Federal, Arizona, Kansas, Iowa, Michigan, Minnesota and New York) and Canada (Federal and British Columbia). The Corporation's 2012 to 2017 taxation years are still open for audit in the Canadian jurisdictions and 2013 to 2017 taxation years are still open for audit in the United States jurisdictions. |
Employee Future Benefits
Employee Future Benefits | 12 Months Ended |
Dec. 31, 2017 | |
Retirement Benefits [Abstract] | |
Employee Future Benefits | EMPLOYEE FUTURE BENEFITS The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans, OPEB plans, and defined contribution pension plans. For the defined benefit pension and OPEB plan arrangements, the benefit obligation and the fair value of plan assets are measured for accounting purposes as at December 31 of each year. Actuarial valuations are required to determine funding contributions for pension plans, at least, every three years for Fortis' Canadian and Caribbean subsidiaries. The most recent valuations were as of December 31, 2014 for Newfoundland Power, FortisOntario and the Corporation; December 31, 2015 for FortisAlberta and FortisBC Energy (plan covering non-unionized employees); and December 31, 2016 for FortisBC Electric, FortisBC Energy (plans covering unionized employees) and Caribbean Utilities. ITC, UNS Energy and Central Hudson perform annual actuarial valuations, as their funding contribution requirements are based on maintaining annual target fund percentages. ITC, UNS Energy and Central Hudson have all met the minimum funding requirements. 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 for its members. The investment objective of the defined benefit pension and OPEB plans is to maximize return 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 defined benefit pension and OPEB expense for consolidated financial statement purposes. The Corporation's consolidated defined benefit pension and OPEB plan weighted average asset allocations were as follows. Plan assets as at December 31 2017 Target Allocation (%) 2017 2016 Equities 48 47 50 Fixed income 45 46 45 Real estate 6 6 4 Cash and other 1 1 1 100 100 100 The fair value measurements of defined benefit pension and OPEB plan assets by fair value hierarchy, as defined in Note 28 , were as follows. Fair value of plan assets as at December 31, 2017 (in millions) Level 1 Level 2 Level 3 Total Equities $ 522 $ 949 $ — $ 1,471 Fixed income 133 1,289 — 1,422 Real estate — 13 168 181 Private equities — — 22 22 Cash and other 8 14 — 22 $ 663 $ 2,265 $ 190 $ 3,118 Fair value of plan assets as at December 31, 2016 (in millions) Level 1 Level 2 Level 3 Total Equities $ 507 $ 942 $ — $ 1,449 Fixed income 124 1,180 — 1,304 Real estate — 13 103 116 Private equities — — 10 10 Cash and other 6 13 — 19 $ 637 $ 2,148 $ 113 $ 2,898 The following table is a reconciliation of changes in the fair value of pension plan assets that have been measured using Level 3 inputs for the years ended December 31, 2017 and 2016 . (in millions) 2017 2016 Balance, beginning of year $ 113 $ 107 Actual return on plan assets held at end of year 12 8 Foreign currency translation impacts (2 ) (1 ) Purchases, sales and settlements 67 (1 ) Balance, end of year $ 190 $ 113 The following is a breakdown of the Corporation's and subsidiaries' defined benefit pension and OPEB plans and their respective funded status. Defined Benefit OPEB Plans (in millions) 2017 2016 2017 2016 Change in benefit obligation (1) Balance, beginning of year $ 3,037 $ 2,828 $ 676 $ 574 Liabilities assumed on acquisition — 167 — 111 Service costs 76 66 27 18 Employee contributions 16 17 2 2 Interest costs 115 112 25 23 Benefits paid (133 ) (119 ) (22 ) (23 ) Actuarial losses (gains) 217 45 (14 ) (1 ) Past service credits/plan amendments — (10 ) (3 ) — Foreign currency translation impacts (113 ) (69 ) (26 ) (28 ) Balance, end of year (2) $ 3,215 $ 3,037 $ 665 $ 676 Change in value of plan assets Balance, beginning of year $ 2,646 $ 2,466 $ 252 $ 181 Assets assumed on acquisition — 85 — 65 Actual return on plan assets 336 187 37 13 Benefits paid (127 ) (119 ) (22 ) (23 ) Employee contributions 16 17 2 2 Employer contributions 69 47 26 18 Foreign currency translation impacts (99 ) (37 ) (18 ) (4 ) Balance, end of year $ 2,841 $ 2,646 $ 277 $ 252 Funded status $ (374 ) $ (391 ) $ (388 ) $ (424 ) (1) Amounts reflect projected benefit obligation for defined benefit pension plans and accumulated benefit obligation for OPEB plans. (2) The accumulated benefit obligation for defined benefit pension plans, excluding assumptions about future salary levels, was $2,940 million as at December 31, 2017 ( December 31, 2016 - $2,741 million ). The following table summarizes the employee future benefit assets and liabilities and their classifications on the consolidated balance sheet. Defined Benefit OPEB Plans (in millions) 2017 2016 2017 2016 Assets Defined benefit pension assets: Long-term (Note 9) $ 31 $ 32 $ — $ — OPEB plan assets: Long-term (Note 9) — — 3 — Liabilities Defined benefit pension liabilities: Current (Note 13) 12 13 — — Long-term (Note 16) 393 410 — — OPEB plan liabilities: Current (Note 13) — — 10 13 Long-term (Note 16) — — 381 411 Net liabilities $ 374 $ 391 $ 388 $ 424 The net benefit cost for the Corporation's defined benefit pension plans and OPEB plans were as follows. Defined Benefit OPEB Plans (in millions) 2017 2016 2017 2016 Components of net benefit cost Service costs $ 76 $ 66 $ 27 $ 18 Interest costs 115 112 25 23 Expected return on plan assets (151 ) (145 ) (14 ) (12 ) Amortization of actuarial losses 45 48 2 2 Amortization of past service credits/plan amendments — 1 (12 ) (10 ) Regulatory adjustments 2 6 4 9 Net benefit cost $ 87 $ 88 $ 32 $ 30 The following table provides the components of accumulated other comprehensive loss and regulatory assets and liabilities, which would otherwise have been recognized as accumulated other comprehensive loss, for the years ended December 31, 2017 and 2016 , which have not been recognized as components of net benefit cost. Defined Benefit Pension Plans OPEB Plans (in millions) 2017 2016 2017 2016 Unamortized net actuarial losses $ 22 $ 19 $ — $ — Unamortized past service costs 1 1 3 2 Income tax recovery (5 ) (5 ) (1 ) (1 ) Accumulated other comprehensive loss (Note 19) $ 18 $ 15 $ 2 $ 1 Net actuarial losses $ 443 $ 479 $ 17 $ 53 Past service credits (11 ) (11 ) (23 ) (31 ) Amount deferred due to actions of regulators 10 12 27 32 $ 442 $ 480 $ 21 $ 54 Regulatory assets (Note 8 (ii) ) $ 442 $ 480 $ 68 $ 96 Regulatory liabilities (Note 8 (ii) ) — — (47 ) (42 ) Net regulatory assets $ 442 $ 480 $ 21 $ 54 The following table provides the components recognized in comprehensive income or as regulatory assets, which would otherwise have been recognized in comprehensive income. Defined Benefit Pension Plans OPEB Plans (in millions) 2017 2016 2017 2016 Current year net actuarial losses (gains) $ 5 $ 4 $ (1 ) $ (2 ) Past service costs/plan amendments — — 2 — Amortization of actuarial losses (1 ) — — — Foreign currency translation impacts (1 ) — — — Income tax recovery — (1 ) — — Total recognized in comprehensive income $ 3 $ 3 $ 1 $ (2 ) Assets assumed on acquisition $ — $ 23 $ — $ 3 Current year net actuarial losses (gains) 24 (1 ) (35 ) — Past service credits/plan amendments — (10 ) (5 ) — Amortization of actuarial losses (44 ) (47 ) (1 ) (4 ) Amortization of past service (costs) credits — (1 ) 12 13 Foreign currency translation impacts (17 ) (9 ) 2 1 Regulatory adjustments (1 ) (11 ) (6 ) (6 ) Total recognized in regulatory assets $ (38 ) $ (56 ) $ (33 ) $ 7 Net actuarial losses of $1 million are expected to be amortized from accumulated other comprehensive income into net benefit cost in 2018 related to defined benefit pension plans. Net actuarial losses of $46 million , past service credits of $1 million and regulatory adjustments of $1 million are expected to be amortized from regulatory assets into net benefit cost in 2018 related to defined benefit pension plans. Past service credits of $8 million and regulatory adjustments of $4 million are expected to be amortized from regulatory assets into net benefit cost in 2018 related to OPEB plans. Significant weighted average assumptions Defined Benefit OPEB Plans (%) 2017 2016 2017 2016 Discount rate during the year (1) 3.98 4.08 3.96 4.14 Discount rate as at December 31 3.58 4.00 3.59 4.00 Expected long-term rate of return on plan assets (2) 5.97 6.25 5.81 6.25 Rate of compensation increase 3.34 3.36 — — Health care cost trend increase as at December 31 (3) — — 4.71 4.70 (1) ITC and UNS use the split discount rate methodology for determining current service and interest costs. All other subsidiaries use the single discount rate approach. (2) Developed by management with assistance from external actuaries using best estimates of expected returns, volatilities and correlations for each class of asset. The best estimates are based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes. (3) The projected 2018 weighted average health care cost trend rate is 6.38% for OPEB plans and is assumed to decrease over the next 11 years by 2028 to the weighted average ultimate health care cost trend rate of 4.71% and remain at that level thereafter. For 2017 the effects of changing the health care cost trend rate by 1% were as follows. (in millions) 1% increase in rate 1% decrease in rate Increase (decrease) in accumulated benefit obligation $ 96 $ (74 ) Increase (decrease) in service and interest costs 26 (19 ) The following table provides the amount of benefit payments expected to be made over the next 10 years. Defined Benefit OPEB Payments Year (in millions) (in millions) 2018 $ 134 $ 23 2019 137 24 2020 142 25 2021 148 27 2022 156 29 2023-2027 860 160 During 2018 the Corporation expects to contribute $66 million for defined benefit pension plans and $36 million for OPEB plans. In 2017 the Corporation expensed $38 million ( 2016 - $31 million ) related to defined contribution pension plans. |
Business Acquisitions
Business Acquisitions | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
Business Acquisitions | BUSINESS ACQUISITIONS 2017 Terminated Acquisition of an Interest in Waneta Dam In May 2017 Fortis had entered into an agreement with Teck Resources Limited ("Teck") to acquire a two-thirds ownership interest in the Waneta Dam and related transmission assets in British Columbia. In August 2017 BC Hydro exercised its right of first offer to acquire Teck's two-thirds interest in the Waneta Dam and the purchase agreement between Fortis and Teck was terminated, resulting in the payment of a $ 28 million break fee to Fortis, which was recorded in operating expenses. 2016 ITC On October 14, 2016, Fortis and GIC acquired all of the outstanding common shares of ITC for an aggregate purchase price of approximately $15.7 billion (US $11.8 billion ) on closing, including approximately $6.3 billion (US $4.8 billion ) of ITC consolidated indebtedness. ITC is now a subsidiary of Fortis, with an affiliate of GIC owning a 19.9% minority interest in ITC. Under the terms of the transaction, ITC shareholders received US $22.57 in cash and 0.7520 of a Fortis common share per ITC share, representing total consideration of approximately $9.4 billion (US $7.0 billion ). The net cash consideration totalled approximately $4.7 billion (US $3.5 billion ) and was financed using: (i) net proceeds from the issuance of US $2.0 billion ( $2.6 billion ) unsecured notes in October 2016; (ii) net proceeds from GIC's US $1.228 billion ( $1.6 billion ) minority investment, which includes a shareholder note of US $199 million ( $263 million ); and (iii) drawings of approximately US $404 million ( $535 million ) under the Corporation's non-revolving term senior unsecured equity bridge credit facility. On October 14, 2016, approximately 114.4 million common shares of Fortis were issued to shareholders of ITC, representing share consideration of approximately $4.7 billion (US $3.5 billion ), based on the closing price for Fortis common shares of $40.96 and the closing foreign exchange rate of US$1.00=CAD $1.32 on October 13, 2016. The following table summarizes the final allocation of the purchase consideration to the assets and liabilities acquired as at October 14, 2016 based on their fair values, using an exchange rate of US$1.00=CAD $1.32 . (in millions) Total Share consideration $ 4,684 Cash consideration 4,658 Total consideration $ 9,342 Purchase consideration for 80.1% of ITC common shares $ 7,721 19.9% minority shareholder investment and shareholder note 1,621 $ 9,342 Fair value assigned to net assets: Current assets $ 319 Long-term regulatory assets 319 Property, plant and equipment 8,345 Intangible assets 399 Other long-term assets 71 Current liabilities (625 ) Assumed short-term borrowings (311 ) Assumed long-term debt (including current portion) (6,006 ) Long-term regulatory liabilities (327 ) Deferred income taxes (910 ) Other long-term liabilities (166 ) 1,108 Cash and cash equivalents 134 Fair value of net assets acquired 1,242 Goodwill (Note 12) $ 8,100 The acquisition has been accounted for using the acquisition method, whereby financial results of the business acquired have been consolidated in the financial statements of Fortis commencing on October 14, 2016. Acquisition-related expenses totalled approximately $118 million ( $90 million after tax) in 2016. Acquisition-related expenses included: (i) investment banking, legal, consulting and other fees totalling approximately $79 million ( $62 million after tax) in 2016, which were included in operating expenses; and (ii) fees associated with the Corporation's acquisition credit facilities and deal-contingent interest rate swap contracts totalling approximately $39 million ( $28 million after tax) in 2016, which were included in finance charges. From the date of acquisition, ITC also recognized in 2016 $27 million in after-tax expenses associated with the accelerated vesting of the Company's stock-based compensation awards as a result of the acquisition, of which the Corporation's share was $22 million . Pro Forma Data The unaudited pro forma financial information below gives effect to the acquisition of ITC as if the transaction had occurred at the beginning of 2016 . This pro forma data is presented for information purposes only, and does not necessarily represent the results that would have occurred had the acquisition taken place at the beginning of 2016 , nor is it necessarily indicative of the results that may be expected in future periods. (in millions) 2016 Pro forma revenue $ 7,995 Pro forma net earnings attributable to common equity shareholders (1) 919 (1) Pro forma net earnings attributable to common equity shareholders exclude all after-tax acquisition-related expenses incurred by ITC and the Corporation. A pro forma adjustment has been made to net earnings for the year presented to reflect the Corporation's after‑tax financing costs associated with the acquisition. Aitken Creek On April 1, 2016, Fortis acquired Aitken Creek Gas Storage ULC from Chevron Canada Properties Ltd. for approximately $349 million , plus the cost of working gas inventory. The net cash purchase price was initially financed through US dollar-denominated borrowings under the Corporation's committed revolving credit facility. In December 2015 the Corporation paid a deposit of $38 million as part of the purchase consideration for the transaction. The allocation of purchase consideration to the assets and liabilities acquired as at April 1, 2016, based on their fair values, resulted in the recognition of approximately $27 million in goodwill, which was associated with deferred income tax liabilities. The acquisition has been accounted for using the acquisition method, whereby financial results of the business acquired have been consolidated in the financial statements of Fortis commencing on April 1, 2016. The purchase price allocation was finalized during the first quarter of 2017. |
Dispositions
Dispositions | 12 Months Ended |
Dec. 31, 2017 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Dispositions | DISPOSITIONS Walden In February 2016 FortisBC Electric sold the non-regulated Walden hydroelectric power plant assets for gross proceeds of approximately $9 million , and as a result recognized a gain on sale of less than $1 million , after tax and transaction costs. |
Supplementary Information to Co
Supplementary Information to Consolidated Statements of Cash Flows | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplementary Information to Consolidated Statements of Cash Flows | SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions) 2017 2016 Cash paid for: Interest $ 927 $ 644 Income taxes 69 62 Change in working capital: Accounts receivable and other current assets $ (74 ) $ 43 Prepaid expenses (3 ) (4 ) Inventories (6 ) 17 Regulatory assets - current portion 39 (58 ) Accounts payable and other current liabilities 119 25 Regulatory liabilities - current portion (172 ) (1 ) $ (97 ) $ 22 Non-cash investing and financing activities: Common share dividends reinvested 253 162 Common shares issued on business acquisition (Note 25) — 4,684 Additions to property, plant and equipment, and intangible assets included in current and long-term liabilities 307 296 Commitment to purchase capital lease interest — 48 Transfer of deposit on business acquisition (Note 25) — 38 Contributions in aid of construction 35 9 Exercise of stock options into common shares 5 4 |
Fair Value Measurements and Fin
Fair Value Measurements and Financial Instruments | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements and Financial Instruments | FAIR VALUE MEASUREMENTS AND FINANCIAL INSTRUMENTS Fair value is the price at which a market participant could sell an asset or transfer a liability to an unrelated party. A fair value measurement is required to reflect the assumptions that market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model. A fair value hierarchy exists that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy are defined as follows: Level 1: Fair value determined using unadjusted quoted prices in active markets; Level 2: Fair value determined using pricing inputs that are observable; and Level 3: Fair value determined using unobservable inputs only when relevant observable inputs are not available. The fair values of the Corporation's financial instruments, including derivatives, reflect point-in-time estimates based on current and relevant market information about the instruments as at the balance sheet dates. The estimates cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in predicting the Corporation's future consolidated earnings or cash flows. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value to another. There were transfers between levels 2 and 3 during 2017. The following tables present, by level within the fair value hierarchy, the Corporation's assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. As at December 31, 2017 (in millions) Level 1 Level 2 Level 3 Total Assets Energy contracts subject to regulatory deferral (1) (2) $ — $ 19 $ 2 $ 21 Energy contracts not subject to regulatory deferral (1) — 26 4 30 Foreign exchange contracts (3) 3 — — 3 Other investments (4) 78 — — 78 Total assets $ 81 $ 45 $ 6 $ 132 Liabilities Energy contracts subject to regulatory deferral (2) (5) $ (1 ) $ (103 ) $ (2 ) $ (106 ) Energy contracts not subject to regulatory deferral (5) — — (1 ) (1 ) Interest rate and total return swaps (3) — (1 ) — (1 ) Total liabilities $ (1 ) $ (104 ) $ (3 ) $ (108 ) As at December 31, 2016 (in millions) Level 1 Level 2 Level 3 Total Assets Energy contracts subject to regulatory deferral (1) (2) $ 1 $ 13 $ 5 $ 19 Energy contracts not subject to regulatory deferral (1) — 1 2 3 Interest rate swaps (3) — 11 — 11 Other investments (4) 69 — — 69 Total assets $ 70 $ 25 $ 7 $ 102 Liabilities Energy contracts subject to regulatory deferral (2) (5) $ — $ (21 ) $ (5 ) $ (26 ) Energy contracts not subject to regulatory deferral (5) — (9 ) — (9 ) Interest rate and total return swaps (3) — (3 ) — (3 ) Total liabilities $ — $ (33 ) $ (5 ) $ (38 ) (1) The fair value of the Corporation's energy contracts is recognized in accounts receivable and other current assets and long-term other assets. (2) 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. (3) The fair value of the Corporation's foreign exchange contracts, interest rate and total return swaps is recognized in accounts receivable and other current assets, accounts payable and other current liabilities and long-term other liabilities. (4) Included in long-term other assets on the consolidated balance sheet (Note 9) . (5) The fair value of the Corporation's energy contracts is recognized in accounts payable and other current liabilities and non-current other liabilities. The Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions, which applies only to its energy contracts. The following tables present the potential offset of counterparty netting. As at December 31, 2017 (in millions) Gross Amount Recognized in Balance Sheet Counterparty Netting of Energy Contracts Cash Collateral Received/Posted Net Amount Derivative assets Energy contracts $ 51 $ 17 $ 7 $ 27 Derivative liabilities Energy contracts (107 ) (17 ) — (90 ) As at December 31, 2016 (in millions) Gross Amount Recognized in Balance Sheet Counterparty Netting of Energy Contracts Cash Collateral Received/ Posted Net Amount Derivative assets Energy contracts $ 22 $ 9 $ — $ 13 Derivative liabilities Energy contracts (35 ) (9 ) — (26 ) Derivative Instruments The Corporation generally limits the use of derivative instruments to those that qualify as accounting, economic or cash flow hedges, or those that are approved for regulatory recovery. The Corporation records all derivative instruments at fair value, with certain exceptions including those derivatives that qualify for the normal purchase and normal sale exception. Energy Contracts Subject to Regulatory Deferral UNS Energy holds electricity power purchase contracts and gas swap contracts to reduce its exposure to energy price risk associated with purchased power and gas requirements. UNS Energy primarily applies the market approach for fair value measurements using independent third-party information, where possible. When published prices are not available, adjustments are applied based on historical price curve relationships, transmission costs and line losses. Central Hudson holds swap contracts for electricity and natural gas to minimize price volatility by fixing the effective purchase price for the defined commodities. The fair value of the swap contracts was calculated using forward pricing provided by independent third parties. FortisBC Energy holds gas supply contracts and fixed-price financial swaps to fix the effective purchase price of natural gas, as the majority of the natural gas supply contracts have floating, rather than fixed, prices. The fair value of the natural gas derivatives was calculated using the present value of cash flows based on published market prices and forward curves for natural gas. These energy contracts were not designated as hedges; however, any unrealized gains or losses associated with changes in the fair value of the derivatives are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulators. These unrealized losses and gains would otherwise be recognized in earnings. As at December 31, 2017 , unrealized losses of $87 million ( December 31, 2016 - $19 million ) were recognized in regulatory assets and unrealized gains of $2 million were recognized in regulatory liabilities ( December 31, 2016 - $12 million ) (Note 8 (viii) ). E nergy Contracts Not Subject to Regulatory Deferral UNS Energy holds wholesale trading contracts that qualify as derivative instruments to fix power prices and realize potential margin, of which 10% of any realized gains are shared with customers through UNS Energy's rate stabilization accounts. The fair value of the wholesale contracts was measured using a market approach using independent third-party information, where possible. Aitken Creek holds gas swap contracts to manage its exposure to changes in natural gas prices, to capture natural gas price spreads, and to manage the financial risk posed by physical transactions. The fair value of the gas swap contracts was calculated using forward pricing from published market sources. These energy contracts were not designated as hedges and any unrealized gains or losses associated with changes in the fair value of the derivatives are recognized in revenue. As at December 31, 2017 , unrealized gain of $36 million ( December 31, 2016 - unrealized loss of $2 million ) was recognized in earnings. Foreign exchange contracts The Corporation holds US dollar foreign exchange contracts to mitigate its exposure to volatility of foreign exchange rates. The foreign exchange contracts expire in 2018 and have a combined notional amount of $160 million . The fair value of the foreign exchange contracts was measured using a valuation approach using independent third-party information. Any unrealized gains and losses are recognized in earnings. During 2017 unrealized gains of $3 million were recognized in earnings. Interest rate and total return swaps UNS Energy holds an interest rate swap to mitigate its exposure to volatility in variable interest rates on capital lease obligations (Note 15 ). The interest rate swap agreement expires in 2020 and has a notional amount of $23 million . The Corporation holds three total return swaps to manage the cash flow risk associated with forecasted future cash settlements of the respective DSU and RSU obligations (Note 21) . The total return swaps have a combined notional amount of $33 million and terms ranging from one to three years terminating in January 2018 , 2019 and 2020 . In November 2017 ITC terminated its forward-starting interest rate swaps that were used to manage the interest rate risk associated with the November 2017 issuance of US$1 billion fixed-rate debt. As at December 31, 2017 , ITC did not have any interest rate swaps outstanding. The fair value of interest rate swaps at UNS Energy was determined based on an income valuation approach based on the six month LIBOR rates. The fair value of the Corporation's total return swaps was measured using the income valuation approach based on forward pricing curves. The unrealized gains and losses on interest rate swaps, which qualify as cash flow hedges, are recognized in other comprehensive income and reclassified to earnings as a component of interest expense over the life of the hedged debt . The loss expected to be reclassified to earnings within the next twelve months is estimated to be approximately $3 million , net of tax. The unrealized gains and losses on the total return swaps are recognized in earnings. Cash flows associated with the settlement of all derivative instruments are included in operating activities on the Corporation's consolidated statement of cash flows. Other investments ITC and Central Hudson hold investments in trust associated with supplemental retirement benefit plans for selected employees. These investments consist of mutual funds and money market accounts, which are recorded at fair value based on quoted market prices in active markets. The gains and losses on these funds are recognized in earnings and gains and losses on investments classified as available-for-sale are recognized in accumulated other comprehensive income. Level 3 Fair Value Measurement Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude and direction of the change for each input. The impact of changes in fair value is subject to regulatory recovery, with the exception of long-term wholesale trading contracts and certain gas swap contracts. The following table presents a reconciliation of changes in the fair value of net assets and liabilities classified as level 3 in the fair value hierarchy. Transfers from level 3 to level 2 principally resulted from management's decision that inputs used to calculate the fair value of derivatives are observable and level 2 classification is appropriate. (in millions) 2017 2016 Balance, beginning of year $ 2 $ (18 ) Realized losses (10 ) (19 ) Unrealized (losses) gains (3 ) 12 Settlements 12 27 Transfers of assets out of level 3 (2 ) — Transfers of liabilities out of level 3 4 — Balance, end of year $ 3 $ 2 Volume of Derivative Activity As at December 31, 2017 , the Corporation had various energy contracts that will settle on various expiration dates through 2029. The volumes related to electricity and natural gas derivatives are outlined below. 2017 2016 Energy contracts subject to regulatory deferral (1) Electricity swap contracts (GWh) 1,291 2,184 Electricity power purchase contracts (GWh) 761 1,252 Gas swap contracts (PJ) 216 35 Gas supply contract premiums (PJ) 219 240 Energy contracts not subject to regulatory deferral (1) Wholesale trading contracts (GWh) 2,387 2,058 Gas supply contract premiums (PJ) — 15 Gas swap contracts (PJ) 36 4 (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, the Corporation's credit risk is generally limited to the carrying value on the consolidated balance sheet. The Corporation generally has a large and diversified customer base, which minimizes the concentration of credit risk. The Corporation and its subsidiaries have various policies to minimize credit risk, which include requiring customer deposits, prepayments and/or credit checks for certain customers and performing disconnections and/or using third-party collection agencies for overdue accounts. ITC has a concentration of credit risk as a result of approximately 69% of its revenue being derived from three primary customers. Credit risk is limited as such customers have investment-grade credit ratings. ITC further reduces its exposure to credit risk by requiring a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit-scoring model and other factors. FortisAlberta has a concentration of credit risk as a result of its distribution service billings being to a relatively small group of retailers. The Company reduces its exposure by obtaining from the retailers either a cash deposit, bond, letter of credit, an investment-grade credit rating from a major rating agency, or a financial guarantee from an entity with an investment-grade credit rating. UNS Energy, Central Hudson, FortisBC Energy and Aitken Creek may be exposed to credit risk in the event of non‑performance by counterparties to derivative instruments. The Companies use netting arrangements to reduce credit risk and net settle payments with counterparties where net settlement provisions exist. They also limit credit risk by only dealing with counterparties that have investment‑grade credit ratings. At UNS Energy and Central Hudson, contractual arrangements also contain certain provisions requiring counterparties to derivative instruments to post collateral under certain circumstances. The value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features was $57 million as of December 31, 2017 ( December 31, 2016 - $37 million ). If all the credit risk-related contingent features were triggered on December 31, 2017 , the Corporation would have been required to post an additional $57 million of collateral to counterparties. Foreign Exchange Hedge The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, Fortis Turks and Caicos and BECOL is the US dollar. The Corporation's earnings from, and net investments in, foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has decreased the above-noted exposure by designating US dollar-denominated borrowings at the corporate level as a hedge of its net investment in foreign subsidiaries. The foreign exchange gain or loss on the translation of US dollar-denominated interest expense partially offsets the foreign exchange gain or loss on the translation of the Corporation's foreign subsidiaries' earnings. As at December 31, 2017 , the Corporation's corporately issued US$ 3,385 million ( December 31, 2016 - US $3,511 million ) long-term debt has been designated as an effective hedge of a portion of the Corporation's foreign net investments. As December 31, 2017 , the Corporation had approximately US $7,548 million ( December 31, 2016 - US $7,250 million ) in foreign net investments that were unhedged. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately issued US dollar-denominated borrowings designated as effective hedges are recorded on the consolidated balance sheet in accumulated other comprehensive income and serve to help offset unrealized foreign currency exchange gains and losses on the net investments in foreign subsidiaries, which gains and losses are also recorded on the consolidated balance sheet in accumulated other comprehensive income. Financial Instruments Not Carried At Fair Value The following table discloses the estimated fair value measurements of the Corporation's financial instruments not carried at fair value. The carrying values of the Corporation's consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows. 2017 2016 (in millions) Carrying Estimated Carrying Estimated Long-term debt, including current portion (Note 14) (1) $ 21,535 23,481 $ 21,219 $ 22,523 Waneta Partnership promissory note (Note 16) 63 64 59 61 (1) Long-term debt is valued using Level 2 inputs. The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, as is the case with the Waneta Partnership promissory note and certain long-term debt, the fair value is determined by either: (i) discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills with similar terms to maturity, plus a credit risk premium equal to that of issuers of similar credit quality; or (ii) obtaining from third parties indicative prices for the same or similarly rated issues of debt of the same remaining maturities. Since the Corporation does not intend to settle the long-term debt or promissory note prior to maturity, the excess of the estimated fair value above the carrying value does not represent an actual liability. |
Variable Interest Entity
Variable Interest Entity | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Variable Interest Entity | VARIABLE INTEREST ENTITY The Corporation's ownership interest in the Waneta Partnership is considered to be a variable interest entity ("VIE") based on an assessment of the rights of the limited partners and the general partner. It was determined under the VIE model that the Corporation is the primary beneficiary of the Waneta Partnership and should consolidate its investment. As the primary beneficiary, the Corporation has the power to direct the activities of the partnership and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the partnership, as discussed below. The purpose of the Waneta Partnership was to construct, own and operate the Waneta Expansion on the Pend d'Oreille River south of Trail, British Columbia, which was completed in April 2015. The Corporation has a 51% controlling ownership interest in the Waneta Partnership, with CPC/CBT holding the remaining 49% interest. The general partner, which is owned by the Corporation and CPC/CBT in the same proportion as the Waneta Partnership, has a 0.01% interest in the Waneta Partnership. Each partner pays its proportionate share of the costs and is entitled to a proportionate share of the net revenue and expenses. The construction of the Waneta Expansion was financed and managed by the Corporation and CPC/CBT. The Waneta Expansion is operated and maintained by a wholly owned subsidiary of the Corporation and the output is sold to BC Hydro and FortisBC Electric under 40 -year contracts. The following table details the Waneta Partnership assets, liabilities, revenue, expenses, and cash flow included in the Corporation's consolidated financial statements. (in millions) 2017 2016 Assets Cash and cash equivalents $ 16 $ 15 Accounts receivable and other current assets 14 14 Property, plant and equipment 688 696 Intangible assets 30 30 $ 748 $ 755 Liabilities Accounts payable and other current liabilities $ (28 ) $ (3 ) Other liabilities (63 ) (79 ) (91 ) (82 ) Net assets before partners' equity $ 657 $ 673 (in millions) 2017 2016 Revenue $ 93 $ 91 Expenses Operating expense 17 17 Depreciation and amortization 18 18 Finance charges 4 3 39 38 Net earnings $ 54 $ 53 Cash used in investing activities at the Waneta Partnership for 2017 included capital expenditures of $5 million ( 2016 - $18 million ). Cash flow related to financing activities for 2017 included dividends paid by the Waneta Partnership to non-controlling interests of $34 million ( 2016 - $31 million ). |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | COMMITMENTS AND CONTINGENCIES As at December 31, 2017 , the Corporation's consolidated commitments in each of the next five years and for periods thereafter, excluding repayments of long-term debt and capital lease and finance obligations separately disclosed in Notes 14 and 15 , respectively, are as follows. (in millions) Total Due within 1 year Due in year 2 Due in year 3 Due in year 4 Due in year 5 Due after Interest obligations on long-term debt $ 14,575 $ 892 $ 878 $ 858 $ 837 $ 792 $ 10,318 Power purchase obligations (1) 2,240 275 157 126 118 117 1,447 Renewable power purchase obligations (2) 1,428 93 92 92 92 91 968 Gas purchase obligations (3) 1,085 278 201 189 147 112 158 Long-term contracts - UNS Energy (4) 910 157 158 125 79 50 341 ITC easement agreement (5) 413 13 13 13 13 13 348 Renewable energy credit purchase agreements (6) 125 20 13 11 10 10 61 Debt Collection Agreement (7) 122 3 3 3 3 3 107 Operating lease obligations 53 11 9 7 4 4 18 Purchase of Springerville Common Facilities (8) 85 — — — 85 — — Waneta Partnership promissory note (Note 16) 72 — — 72 — — — Joint-use asset and shared service agreements 52 3 3 3 3 3 37 Other (9) 462 97 53 71 31 32 178 Total $ 21,622 $ 1,842 $ 1,580 $ 1,570 $ 1,422 $ 1,227 $ 13,981 (1) Power purchase obligations include various power purchase contracts held by the Corporation's regulated utilities, of which the most significant contracts are described below. FortisOntario: Power purchase obligations for FortisOntario, totalling $ 692 million as at December 31, 2017 , include a contract with Hydro-Quebec for the supply of up to 145 MW of capacity and a minimum of 537 GWh of associated energy annually from January 2020 through to December 2030. This contract will replace FortisOntario's existing long-term take-or-pay contracts with Hydro-Quebec to supply 145 MW of capacity expiring in 2019. FortisBC Energy: FortisBC Energy is party to an electricity supply agreement with BC Hydro for the purchase of electricity supply to the Tilbury LNG Facility Expansion, with purchase obligations totalling $ 482 million as at December 31, 2017 . FortisBC Electric: Power purchase obligations for FortisBC Electric, totalling $ 333 million as at December 31, 2017 , include a PPA with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of associated energy annually for a 20-year term. FortisBC Electric is also party to the Waneta Expansion Capacity Agreement ("WECA"), allowing it to purchase 234 MW of capacity per month, on average, for 40 years, effective April 2015, as approved by the BCUC. Amounts associated with the WECA have not been included in the Commitments table as they will be paid by FortisBC Electric to a related party. Maritime Electric: Maritime Electric's power purchase obligations include two take-or-pay contracts for the purchase of either capacity or energy, expiring in February 2019, as well as an Energy Purchase Agreement with New Brunswick Power ("NB Power"). Maritime Electric has entitlement to approximately 4.55% of the output from NB Power's Point Lepreau nuclear generating station for the life of the unit. As part of its entitlement, Maritime Electric is required to pay its share of the capital and operating costs of the unit, and as at December 31, 2017 , had commitments of $ 511 million under this arrangement. (2) TEP and UNS Electric are party to long-term renewable PPAs that require TEP and UNS Electric to purchase 100% of the output of certain renewable energy generating facilities once commercial operation is achieved. While TEP and UNS Electric are not required to make payments under these contracts if power is not delivered, the Commitments table includes estimated future payments. These agreements have various expiry dates from 2027 through 2036. (3) Certain of the Corporation's subsidiaries, mainly FortisBC Energy, enter into contracts for the purchase of gas, gas transportation and storage services. FortisBC Energy's gas purchase obligations are based on gas commodity indices that vary with market prices and the obligations are based on index prices as at December 31, 2017 . (4) UNS Energy enters into various long-term contracts for the purchase and delivery of coal to fuel its generating facilities, the purchase of gas transportation services to meet its load requirements, and the purchase of transmission services for purchased power. Amounts paid under contracts for the purchase and delivery of coal depend on actual quantities purchased and delivered. Certain of these contracts also have price adjustment clauses that will affect future costs under the contracts. (5) ITC is party to an easement agreement with Consumers Energy, the primary customer of METC, which provides the Company 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 additional 50 -year renewals thereafter. (6) UNS Energy and Central Hudson are party to renewable energy credit purchase agreements, mainly for the purchase of environmental attributions from retail customers with solar installations. Payments for the renewable energy credit purchase agreements are made in contractually agreed-upon intervals based on metered renewable energy production. (7) Maritime Electric is party to a debt collection agreement with the PEI Energy Corporation for the initial capital cost of the submarine cables and associated parts of the New Brunswick Transmission system interconnection. The agreement expires in February 2056 . Payments under the agreement will be collected from customers in future rates. (8 ) UNS Energy has an obligation to purchase an undivided 32.2% interest in the Springerville Common Facilities if the related two leases are not renewed (Note 15). (9) Other contractual obligations include various other commitments entered into by the Corporation and its subsidiaries, including PSU, RSU and DSU plan obligations, land easements, asset retirement obligations, and defined benefit pension plan funding obligations. Other Commitments Capital Expenditures: The Corporation's regulated utilities are obligated to provide service to customers within their respective service territories. The regulated utilities' capital expenditures are largely driven by the need to ensure continued and enhanced performance, reliability and safety of the electricity and gas systems and to meet customer growth. The Corporation's consolidated capital expenditure program, including capital spending at its non-regulated operations, is forecast to be approximately $ 3.2 billion for 2018 . Over the five year period from 2018 through 2022 , the Corporation's consolidated capital expenditure program is expected to be approximately $14.5 billion , which has not been included in the Commitments table. Other: CH Energy Group is a participant in an investment with other utilities to jointly develop, own and operate electric transmission projects in New York State. In December 2014 an application was filed with FERC for the recovery of the cost of and return on five high-voltage transmission projects totalling $2.1 billion (US$ 1.7 billion ) . CH Energy Group's maximum commitment is $228 million (US$ 182 million ), for which it has issued a parental guarantee. As at December 31, 2017 , there was no obligation under this guarantee. As at December 31, 2017 , FHI had $80 million ( December 31, 2016 - $77 million ) of parental guarantees outstanding to support the storage optimization activities of Aitken Creek. The Corporation's regulatory liabilities of $ 3,446 million as at December 31, 2017 have been excluded from the Commitments table, as the final timing of settlement of such liabilities is subject to further regulatory determination or the settlement periods are not currently known ( Note 8 ). Contingencies The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with the ordinary course of business operations. Management believes that the amount of liability, if any, from these actions would not have a material effect on the Corporation's consolidated financial position, results of operations or cash flows. The following describes the nature of the Corporation's contingency. FHI In April 2013 FHI and Fortis were named as defendants in an action in the B.C. Supreme Court by the Coldwater Indian Band ("Band"). The claim is in regard to interests in a pipeline right of way on reserve lands. The pipeline on the right of way was transferred by FHI (then Terasen Inc.) to Kinder Morgan Inc. in April 2007. The Band seeks orders cancelling the right of way and claims damages for wrongful interference with the Band’s use and enjoyment of reserve lands. In May 2016 the Federal Court entered a decision dismissing the Band’s application for judicial review of the ministerial consent. In September 2017 the Federal Court of Appeal set aside the minister’s consent and returned the matter to the minister for redetermination. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements. |
Comparative Figures
Comparative Figures | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Comparative Figures | COMPARATIVE FIGURES The Corporation revised a line item within the financing activities section of its Statement of Cash Flow for the year ended December 31, 2016 to correct an immaterial error in the presentation of credit facility borrowings. The Corporation evaluated the error and determined that there was no impact to its results of operations or financial position in previously issued financial statements and that the impact was not material to its cash flows in previously issued financial statements. The correction resulted in $169 million , which was previously reported within Net Repayments and Borrowings under Committed Credit Facilities, being reported on a gross basis, with $668 million reported as Borrowings under Committed Credit Facilities and $499 million being reported as Repayments under Committed Credit Facilities. The correction did not change the total cash from financing activities. |
Summary of Significant Accoun41
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The consolidated financial statements reflect the Corporation's investments in its subsidiaries and variable interest entity, where Fortis is the primary beneficiary, on a consolidated basis, with the equity method used for entities in which Fortis has significant influence, but not control, and proportionate consolidation for generation and transmission assets that are jointly owned with non-affiliated entities. Intercompany transactions have been eliminated in the consolidated financial statements, except for transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. For further details on the Corporation's variable interest entity refer to Note 29 . |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents include cash, cash held in margin accounts, and short-term deposits with initial maturities of three months or less from the date of deposit. |
Allowance for Doubtful Accounts | Allowance for Doubtful Accounts Fortis and each of its subsidiaries, with the exception of ITC, maintain an allowance for doubtful accounts that is estimated based on a variety of factors including accounts receivable aging, historical experience and other currently available information, including events such as customer bankruptcy and economic conditions. ITC recognizes losses for uncollectible accounts based upon specific identification of such items. Accounts receivable are written-off in the period in which the receivable is 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. The cost of inventory at the Corporation's utilities is expected to be recovered in customer rates. |
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities Regulatory assets and liabilities arise as a result of the rate-setting process at the Corporation's utilities. Regulatory assets represent future revenues and/or receivables associated with certain costs incurred that will be, or are expected to be, recovered from customers in future periods through the rate-setting process. Regulatory liabilities represent future reductions or limitations of increases in revenue associated with amounts that will be, or are expected to be, refunded to customers through the rate-setting process. All amounts deferred as regulatory assets and liabilities are subject to regulatory approval. As such, the regulatory authorities could alter the amounts subject to deferral, at which time the change would be reflected in the consolidated financial statements. Certain remaining recovery and settlement periods are those expected by management and the actual recovery or settlement periods could differ based on regulatory approval. |
Investments | Investments Investments in which the Corporation exercises significant influence are accounted for on the equity basis. The Corporation reviews its investments on an annual basis for potential impairment in investment value. Any impairment will be recognized in the period in which such impairment is identified. |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment are recorded at cost less accumulated depreciation. Contributions in aid of construction represent amounts contributed by customers and governments for the cost of property, plant and equipment. These contributions are recorded as a reduction in the cost of property, plant and equipment and are being amortized annually by an amount equal to the charge for depreciation provided on the related assets. Depreciation rates of the Corporation's regulated utilities include an estimate for future asset removal costs that have not been identified as a legal obligation, with the amount provided for in depreciation expense recorded as a long-term regulatory liability ( Note 8 (xii) ). Actual asset removal costs are recorded against the regulatory liability when incurred. For the majority of the Corporation's regulated utilities, property, plant and equipment are derecognized on disposal or when no future economic benefits are expected from their use. Upon retirement or disposal, any difference between the cost and accumulated depreciation of the asset, net of salvage proceeds, is charged to accumulated depreciation, with no gain or loss recognized in earnings. It is expected that any gains or losses charged to accumulated depreciation will be reflected in future depreciation expense when they are refunded or collected in customer rates. The majority of the Corporation's regulated utilities capitalize overhead costs that are not directly attributable to specific property, plant and equipment but relate to the overall capital expenditure program. The methodology for calculating and allocating capitalized overhead costs to property, plant and equipment is established by the respective regulator. The majority of the Corporation's regulated utilities include in the cost of property, plant and equipment both a debt and an equity component of the allowance for funds used during construction ("AFUDC"). The debt component of AFUDC totalling $38 million (2016 - $29 million ) is reported as a reduction of finance charges and the equity component of AFUDC is reported as other income (Note 22) . Both components of AFUDC are charged to earnings through depreciation expense over the estimated service lives of the applicable asset. AFUDC is calculated in a manner as prescribed by the respective regulator. At FortisAlberta the cost of property, plant and equipment also includes Alberta Electric System Operator ("AESO") contributions, which are investments required by FortisAlberta to partially fund the construction of transmission facilities. Property, plant and equipment include inventories held for the development, construction and betterment of other assets, with the exception of UNS Energy. As required by its regulator, UNS Energy recognizes inventories held for the development and construction of other assets in inventories until consumed. When put into service, the inventories are reclassified to property, plant and equipment. Maintenance and repairs of property, plant and equipment are charged to earnings in the period incurred, while replacements and betterments that extend the useful lives are capitalized. Property, plant and equipment is depreciated using the straight-line method based on the estimated service lives of the asset. Depreciation rates for regulated property, plant and equipment are approved by the respective regulator. Depreciation rates for 2017 ranged from 0.9% to 34.6% ( 2016 - 0.9% to 34.6% ). The weighted average composite rate of depreciation, before reduction for amortization of contributions in aid of construction, for 2017 was 2.6% ( 2016 – 2.8% ). The service life ranges and weighted average remaining service life of the Corporation's distribution, transmission, generation and other assets as at December 31 were as follows. 2017 2016 (Years) Service Life Ranges Weighted Average Remaining Service Life Service Life Ranges Weighted Average Remaining Service Life Distribution Electric 5-80 33 5-80 32 Gas 14-95 34 7-95 33 Transmission Electric 20-80 41 20-80 41 Gas 5-80 34 7-80 34 Generation 5-85 28 5-85 26 Other 3-70 14 3-70 14 |
Leases | Leases Leases that transfer to the Corporation substantially all of the risks and benefits incidental to ownership of the leased item are capitalized at the present value of the minimum lease payments. Capital leases are depreciated over the lease term, except where ownership of the asset is transferred at the end of the lease term, in which case capital leases are depreciated over the estimated service life of the underlying asset. Where the regulator has approved recovery of the arrangements as operating leases for rate-setting purposes that would otherwise qualify as capital leases for financial reporting purposes, the timing of the expense recognition related to the lease is modified to conform with the rate-setting process. Operating lease payments are recognized as an expense in earnings on a straight-line basis over the lease term. |
Intangible Assets | Intangible Assets Intangible assets are recorded at cost less accumulated amortization. The useful lives of intangible assets are assessed to be either indefinite or finite. Intangible assets with indefinite useful lives are tested for impairment annually, either individually or at the reporting unit level. Such intangible assets are not amortized. An intangible asset with an indefinite useful life is reviewed annually to determine whether the indefinite life assessment continues to be supportable. If not, the change in the useful life assessment from indefinite to finite is made on a prospective basis. 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 regulator. Amortization rates for 2017 ranged from 1.0% to 50.0% ( 2016 – 1.0% to 50.0% ). The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows. 2017 2016 (Years) Service Life Ranges Weighted Average Remaining Service Life Service Life Ranges Weighted Average Remaining Service Life Computer software 3-10 4 3-10 4 Land, transmission and water rights 36-80 57 30-80 57 Other 10-100 10 10-104 15 For the majority of the Corporation's regulated utilities, intangible assets are derecognized on disposal or when no future economic benefits are expected from their use. Upon retirement or disposal of intangible assets, any difference between the cost and accumulated amortization of the asset, net of salvage proceeds, is charged to accumulated amortization, with no gain or loss recognized in earnings. It is expected that any gains or losses charged to accumulated amortization will be reflected in future amortization costs when they are refunded or collected in customer rates. The majority of indefinite-lived intangible assets are held in the Corporation's regulated utilities that also have goodwill. For its annual testing of impairment for indefinite-lived intangible assets, Fortis includes these assets as part of the respective reporting units, which are tested on an annual basis for goodwill impairment, as disclosed in this Note under "Goodwill". |
Impairment of Long-Lived Assets | Impairment of Long-Lived Assets The Corporation reviews the valuation of property, plant and equipment, intangible assets with finite lives, and other long-term assets when events or changes in circumstances indicate that the assets' carrying value may not be recoverable. If the carrying amount of the asset exceeds the expected total undiscounted cash flows generated by the asset, the asset is written down to estimated fair value and an impairment loss is recognized in earnings in the period in which it is identified. Asset-impairment testing is carried out at the reporting unit level to determine if assets are impaired. The net cash flows for reporting units are not asset-specific but are pooled for the entire reporting unit. The recovery of regulated assets' carrying value, including a fair rate of return, is provided through customer rates approved by the respective regulatory authority. |
Goodwill | Goodwill Goodwill represents the excess of the purchase price over the fair value of the identifiable net assets acquired relating to business acquisitions. The Corporation performs an annual impairment test for goodwill as at October 1, or more frequently if any event occurs or if circumstances change that would indicate that the fair value of a reporting unit was below its carrying value. Fortis performs an annual internal qualitative and quantitative assessment for each reporting unit to which goodwill has been allocated. The Corporation has a total of 11 reporting units that were allocated goodwill at the respective dates of acquisition by Fortis . For those reporting units where: (i) management's assessment of qualitative and quantitative factors indicates that fair value is not 50% or more likely to be greater than carrying value; or (ii) the excess of estimated fair value over carrying value, as of the date of the immediately preceding impairment test, was not significant, then fair value of the reporting unit will be estimated by an external consultant in the current year. In calculating goodwill impairment, the estimated fair value of the reporting unit is compared to its carrying value. If the fair value of the reporting unit is less than the carrying value, the excess of the carrying amount over fair value is recorded as goodwill impairment, not to exceed the total amount of goodwill allocated to the reporting unit. The primary method for estimating fair value of the reporting units is the income approach, whereby net cash flow projections for the reporting units are discounted using an enterprise value method. The income approach uses several underlying estimates and assumptions with varying degrees of uncertainty, including the amount and timing of expected future cash flows, growth rates, and the determination of appropriate discount rates. A secondary valuation method, the market approach, as well as a reconciliation of the total estimated fair value of all reporting units to the Corporation's market capitalization, is also performed as an assessment of the conclusions reached under the income approach. |
Deferred Financing Costs | Deferred Financing Costs Any costs, debt discounts and premiums related to the issuance of long-term debt are recognized against long-term debt and are amortized over the life of the related long-term debt. |
Employee Future Benefits | Employee Future Benefits Defined Benefit and Defined Contribution Pension Plans The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans, including retirement allowances and supplemental retirement plans for certain executive employees, and defined contribution pension plans, including group Registered Retirement Savings Plans and group 401(k) plans for employees. The projected benefit obligation and the value of pension cost associated with the defined benefit pension plans are actuarially determined using the projected benefits method prorated on service and management's best estimate of expected plan investment performance, salary escalation and expected retirement ages of employees. Discount rates reflect market interest rates on high‑quality bonds with cash flows that match the timing and amount of expected pension payments. With the exception of FortisBC Energy and Newfoundland Power, pension plan assets are valued at fair value for the purpose of determining pension cost. At FortisBC Energy and Newfoundland Power, pension plan assets are valued using the market-related value for the purpose of determining pension cost, where 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 the projected benefit obligation and the fair value of plan assets (the market-related value of plan assets at FortisBC Energy and Newfoundland Power) 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 plans, measured as the difference between the fair value of the plan assets and the projected benefit obligation, is recognized on the Corporation's consolidated balance sheet. For the majority of the Corporation's regulated utilities, any difference between pension cost recognized under US GAAP and that recovered from customers in current rates for defined benefit pension plans, which is expected to be recovered from, or refunded to, customers in future rates, is subject to deferral account treatment ( Note 8 (ii) ). With the exception of Fortis and FHI, any unamortized balances related to net actuarial gains and losses, past service costs and transitional obligations associated with defined benefit pension plans, which would otherwise be recognized in accumulated other comprehensive income, are subject to deferral account treatment ( Note 8 (ii) ). At Fortis and FHI, any unamortized balances related to net actuarial gains and losses, past service costs and transitional obligations associated with defined benefit pension plans are recognized in accumulated other comprehensive income. The costs of the defined contribution pension plans are expensed as incurred. Other Post-Employment Benefits Plans The Corporation and its subsidiaries also offer other post-employment benefits ("OPEB") plans, including certain health and dental coverage and life insurance benefits, for qualifying members. The accumulated benefit obligation and the cost associated with OPEB plans are actuarially determined using the projected benefits method prorated on service and management's best estimate of expected plan performance, salary escalation, expected retirement ages of employees and health care costs. Discount rates reflect market interest rates on high-quality bonds with cash flows that match the timing and amount of expected OPEB payments. The excess of any cumulative net actuarial gain or loss over 10% of the accumulated benefit obligation and the fair value 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 OPEB plans, measured as the difference between the fair value of the plan assets and the accumulated benefit obligation, is recognized on the Corporation's consolidated balance sheet. For the majority of the Corporation's regulated utilities, any difference between the cost of OPEB plans recognized under US GAAP and that recovered from customers in current rates, which is expected to be recovered from, or refunded to, customers in future rates, is subject to deferral account treatment ( Note 8 (ii) ). |
Stock-Based Compensation | Stock-Based Compensation The Corporation records compensation expense related to stock options granted under its stock option plans (Note 21) . Compensation expense is measured at the date of grant using the Black-Scholes fair value option-pricing model and each grant is amortized as a single award evenly over the four -year vesting period of the options granted. The offsetting entry is an increase to additional paid-in capital for an amount equal to the annual compensation expense related to the issuance of stock options. The stock options become exercisable once time-vesting requirements have been met. Upon exercise, the proceeds of the options 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. An exercise of options below the current market price of the Corporation's common shares has a dilutive effect on the Corporation's consolidated capital stock and shareholders' equity. Fortis satisfies stock option exercises by issuing common shares from treasury. The Corporation also records liabilities associated with its Directors' Deferred Share Unit ("DSU"), Performance Share Unit ("PSU") and Restricted Share Unit ("RSU") Plans, all representing cash-settled awards, at fair value at each reporting date until settlement. Compensation expense is recognized on a straight-line basis over the vesting period, which for the PSU and RSU Plans is over the shorter 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. The fair value of the DSU, PSU and RSU 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 of the Corporation's common shares as at December 31, 2017 was $46.01 ( December 31, 2016 - $41.46 ). 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 The assets and liabilities of the Corporation's foreign operations, all of which have a US dollar functional currency, are translated at the exchange rate in effect as at the balance sheet date. The exchange rate in effect as at December 31, 2017 was US$1.00=CAD$ 1.25 ( December 31, 2016 – US$1.00=CAD$ 1.34 ). The resulting unrealized translation gains and losses are excluded from the determination of earnings and are recognized in accumulated other comprehensive income until the foreign subsidiary is sold, substantially liquidated or evaluated for impairment in anticipation of disposal. Revenue and expenses of the Corporation's foreign operations are translated at the average exchange rate in effect during the reporting period, which was US$1.00=CAD$ 1.30 for 2017 ( 2016 – US$1.00=CAD$ 1.33 ). Foreign exchange translation gains and losses on foreign currency-denominated long-term debt that is designated as an effective hedge of foreign net investments are accumulated as a separate component of shareholders' equity within accumulated other comprehensive income and the current period change is recorded in other comprehensive income. 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. Gains and losses on translation are recognized in earnings. |
Derivative Instruments and Hedging Activities | Derivative Instruments and Hedging Activities Non-Designated Derivatives Derivatives not designated as hedging contracts are used by Fortis to manage cash flow risk associated with forecasted US dollar cash inflows and forecasted future cash settlements of DSU and RSU obligations; UNS Energy to meet forecast load and reserve requirements; and Aitken Creek to manage exposure to commodity price risk, to capture natural gas price spreads, and to manage the financial risk posed by physical transactions. These non-designated derivatives are measured at fair value with changes in fair value recognized in earnings. Derivatives not designated as hedging contracts are also used by UNS Energy, Central Hudson and FortisBC Energy to reduce exposure to 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 non-designated derivatives are measured at fair value and the net unrealized gains and losses associated with changes in fair value of the derivative contracts are recorded as regulatory assets or liabilities for recovery from, or refund to, customers in future rates (Note 8 (viii) ). Derivative instruments that meet the normal purchase or normal sale scope exception are not measured at fair value and settled amounts are recognized as energy supply costs on the consolidated statements of earnings. Derivatives in Designated Hedging Relationships For derivatives designated as hedging contracts, the Corporation and its utilities formally assess, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. The hedging strategy by transaction type and risk management strategy is formally documented. As at December 31, 2017 , the Corporation's hedging relationships primarily consisted of cash flow hedges and net investment hedges. The Corporation, ITC and UNS Energy use cash flow hedges to manage its exposure to interest rate risk. Unrealized gains or losses on these derivatives are initially recognized in accumulated other comprehensive income and reclassified to earnings when the underlying hedged transaction affects earnings. Any hedge ineffectiveness is recognized in net earnings immediately at the time the gain or loss on the derivatives is calculated. The Corporation's earnings from, and net investments in, foreign subsidiaries and equity method investments are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has decreased a portion of the above-noted exposure through the use of US dollar-denominated borrowings at the corporate level. The Corporation has designated its corporately issued US dollar long-term debt as a hedge of a portion of the foreign exchange risk related to its foreign net investments. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately issued US dollar-denominated borrowings designated as hedges are recognized in accumulated other comprehensive income and help offset unrealized foreign currency exchange gains and losses on the foreign net investments, which gains and losses are also recognized in accumulated other comprehensive income. Presentation of Derivatives The fair value of derivative instruments are recognized on the Corporation's consolidated balance sheet as current or long-term assets and liabilities depending on the timing of the settlements and the resulting cash flows associated with the instruments. Derivative contracts under master netting agreements and collateral positions are presented on a gross basis. Cash flows associated with the settlement of all derivative instruments are included in operating activities on the Corporation's consolidated statement of cash flows. |
Income Taxes | Income Taxes The Corporation and its subsidiaries follow the asset and liability method of accounting for income taxes. Under this method, 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. Valuation allowances are recognized against deferred tax assets when it is more likely than not that a portion of, or the entire amount of, the deferred income tax asset will not be realized. Deferred income tax assets and liabilities 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 that the change occurs. Current income tax expense or recovery is recognized for the estimated income taxes payable or receivable in the current year. As approved by the respective regulator, ITC, UNS Energy, Central Hudson and Maritime Electric recover current and deferred income tax expense in customer rates. As approved by the regulator, FortisAlberta recovers income tax expense in customer rates based only on income taxes that are currently payable. FortisBC Energy, FortisBC Electric, Newfoundland Power and FortisOntario recover income tax expense in customer rates based only on income taxes that are currently payable, except for certain regulatory balances for which deferred income tax expense is recovered from, or refunded to, customers in current rates, as prescribed by the respective regulator. Deferred income taxes that are expected to be collected from or refunded to customers in rates once income taxes become payable or receivable are recognized as a regulatory asset or liability ( Note 8 (i) ). For regulatory reporting purposes, the capital cost allowance pool for certain property, plant and equipment at FortisAlberta is different from that for legal entity corporate income tax filing purposes. In a future reporting period, yet to be determined, the difference may result in higher income tax expense than that recognized for regulatory rate-setting purposes and collected in customer rates. Caribbean Utilities and Fortis Turks and Caicos are not subject to income tax as they operate in tax-free jurisdictions. BECOL is not subject to income tax as it was granted tax-exempt status by the Government of Belize for the terms of its 50 -year PPAs. Any difference between the income tax expense recognized under US GAAP and that recovered from customers in current rates that is expected to be recovered from customers in future rates, is subject to deferral account treatment ( Note 8 (i) ). The Corporation intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, the Corporation does not provide for deferred income taxes on temporary differences related to investments in foreign subsidiaries. The difference between the carrying values of these foreign investments and their tax bases, resulting from unrepatriated earnings and currency translation adjustments, is approximately $561 million as at December 31, 2017 ( December 31, 2016 - $525 million ). If such earnings are repatriated, in the form of dividends or otherwise, 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 income tax positions taken, or expected to be taken, in an income tax return are recognized only 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. The difference between a tax position taken, or expected to be taken, and the benefit recognized and measured pursuant to this guidance represents an unrecognized tax benefit. Income tax interest and penalties are expensed as incurred and included in income tax expense. |
Sales Taxes | Sales Taxes In the course of its operations, the Corporation's subsidiaries collect sales taxes from their customers. When customers are billed, a current liability is recognized for the sales taxes included on customers' bills. The liability is settled when the taxes are remitted to the appropriate government authority. The Corporation's revenue excludes sales taxes. |
Revenue Recognition | Revenue Recognition Revenue from the sale and delivery of electricity and gas by the Corporation's regulated utilities is generally recognized on an accrual basis. Electricity and gas consumption is metered upon delivery to customers and is recognized as revenue using approved rates when consumed. Revenue at the regulated utilities is billed at rates approved by the applicable regulatory authority. Meters are read periodically and bills are issued to customers based on these readings. At the end of each reporting period, a certain amount of consumed electricity and gas will not have been billed, which is estimated and accrued as revenue. ITC's transmission revenue is recognized as services are provided based on FERC-approved cost-based formula rate templates. A reserve for revenue subject to refund is recognized as a reduction to revenue when such refund is probable and can be reasonably estimated ( Note 8 (vi) ). In certain circumstances, UNS Energy and Aitken Creek enter into purchased power and wholesale sales contracts that are not settled with energy. The net sales contracts and power purchase contracts are reflected at the net amount in revenue. As stipulated by the regulator, FortisAlberta is required to arrange and pay for transmission services with the AESO and collect transmission revenue from its customers, which is achieved through invoicing the customers' retailers through FortisAlberta's transmission component of its regulator-approved rates. FortisAlberta is solely a distribution company and, as such, does not operate or provide any transmission or generation services. The Company is a conduit for the flow through of transmission costs to end-use customers, as the transmission provider does not have a direct relationship with these customers. As a result, FortisAlberta reports revenue and expenses related to transmission services on a net basis. The rates collected are based on forecast transmission expenses. FortisAlberta is not subject to any forecast risk with respect to transmission costs, as all differences between actual expenses related to transmission services and actual revenue collected from customers are deferred to be recovered from, or refunded to, customers in future rates. FortisBC Electric has entered into contracts to sell surplus capacity that may be available after it meets its load requirements. This revenue is recognized on an accrual basis at rates established in the sales contract. All of the Corporation's non-regulated generation operations record revenue on an accrual basis and revenue is recognized on delivery of output at rates fixed under contract or based on observed market prices as stipulated in contractual arrangements. Revenue at Aitken Creek is generated from long-term lease storage, park and loan activities, and storage optimization activities and is generally recognized on an accrual basis over the term of the related contracts. Optimization revenue results from the purchase of natural gas and its forward sale through financial and physical trading contracts and consists of realized and unrealized gains and losses on the financial and physical energy trading contracts, not designated as derivatives, used to manage commodity price risk (Note 28) . |
Asset Retirement Obligations | Asset Retirement Obligations A conditional asset retirement obligation ("ARO") is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the Corporation's control. AROs are recorded as a liability at fair value and are classified as long-term other liabilities, with a corresponding increase to property, plant and equipment. The Corporation recognizes AROs in the periods in which they are incurred if a reasonable estimate of fair value can be determined. Fair value is based on an estimate of 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 recorded through accretion, and the capitalized cost is depreciated over the useful life of the asset. Actual costs incurred upon the settlement of AROs are recorded as a reduction in the liabilities. The Corporation's subsidiaries have AROs associated with the remediation of generation facilities, interconnection facilities, wholesale energy supply agreements, and certain electricity distribution system assets. While each of the foregoing will have legal AROs, including land and environmental remediation and/or removal of assets, the final date and cost of remediation and/or removal of the related assets cannot be reasonably determined at this time. These assets are reasonably expected to operate in perpetuity due to the nature of their operations. The licences, permits, interconnection facilities agreements, wholesale energy supply agreements and rights-of-way are reasonably expected to be renewed or extended indefinitely to maintain the integrity of the assets and ensure the continued provision of service to customers. In the event that environmental issues are identified, assets are decommissioned or the applicable licences, permits or agreements are terminated, AROs will be recognized at that time provided the costs can be reasonably estimated. |
Commitments | Contingencies Reserves for specific legal proceedings are established when the likelihood of an unfavourable outcome is probable and the amount of loss can be reasonably estimated. Significant judgment is required in predicting the outcome of these claims. The Corporation identifies certain other legal matters where the Corporation believes an unfavourable outcome is reasonably possible or no estimate of possible losses can be made. All contingencies are regularly reviewed to determine whether the likelihood of loss has changed and to assess whether a reasonable estimate of the loss or range of loss can be made. |
New Accounting Policies | New Accounting Policies Simplifying the Test for Goodwill Impairment Effective January 1, 2017 , the Corporation adopted Accounting Standards Update ("ASU") No. 2017-04 , Simplifying the Test for Goodwill Impairment. The amendments in this update simplify the subsequent measurement of goodwill by eliminating step two in the current two-step goodwill impairment test. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. The above-noted ASU was applied prospectively and did not impact the Corporation's consolidated financial statements. Inventories Effective January 1, 2017, the Corporation's utilities adopted ASU No. 2015-11, Inventory , which requires the measurement of inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The adoption of this update did not impact the Corporation's consolidated financial statements as the cost of inventory at the Corporation's utilities is recovered in customer rates. Revenue from Contracts with Customers ASU No. 2014-09 was issued in May 2014 and the amendments in this update, along with additional ASUs issued in 2016 and 2017 to clarify implementation guidance, create Accounting Standards Codification ("ASC") Topic 606, Revenue from Contracts with Customers , and supersede the revenue recognition requirements in ASC Topic 605, Revenue Recognition , including most industry-specific revenue recognition guidance throughout the codification. This standard clarifies the principles for recognizing revenue and enables users of financial statements to better understand and consistently analyze an entity's revenues across industries and transactions. The new guidance permits two methods of adoption: (i) the full retrospective method; and (ii) the modified retrospective method, under which comparative periods would not be restated and the cumulative impact of applying the standard would be recognized at the date of initial adoption supplemented by additional disclosures. This standard is effective for annual and interim periods beginning after December 15, 2017. Fortis adopted this ASU on January 1, 2018 using the modified retrospective approach and there have been no material adjustments identified to opening retained earnings. Fortis has reviewed the final assessments and conclusions of its utilities on tariff-based sales to retail and wholesale customers, which represents more than 90% of the Corporation's consolidated revenue, and has concluded that the adoption of this standard will not affect revenue recognition for tariff-based sales and, therefore, will not have an impact on earnings. Fortis' subsidiaries have completed their final assessments and conclusions on less material revenue streams, and Fortis is reviewing these final assessments, particularly for consistency of implementation and accounting policy selection, and does not expect any adjustments. The Corporation will add additional disclosures to address the requirement to provide more information regarding the nature, amount, timing and uncertainty of revenue and cash flows, which will result in revenues that fall outside the scope of the new standard, including alternative revenue programs, being presented separately. The Corporation will present revenue in three categories: (i) revenue from contracts with customers which will include retail and wholesale tariff revenue; (ii) alternative revenue programs; and (iii) other revenue. The Corporation's revenue is currently disaggregated by: (i) geography; and (ii) substantially autonomous utility operations. This level of disaggregation will not change upon implementation of the new guidance as it is: (i) used by the Corporation's chief operating decision maker for evaluating the financial performance of operating subsidiaries and to make resource allocation decisions; (ii) used by external stakeholders for evaluating the Corporation's financial performance; and (iii) consistent with other externally reported documents of the Corporation. Fortis continues to monitor its adoption process under its existing internal control over financial reporting, including accounting processes and the gathering and evaluation of information used in assessing the required disclosures. As the Corporation finalizes its implementation in the first quarter of 2018, it will continue to assess any necessary changes to internal control over financial reporting. Recognition and Measurement of Financial Assets and Financial Liabilities ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities , was issued in January 2016 and the amendments in this update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. Most notably, the amendments require the following: (i) equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings; and (ii) financial assets and financial liabilities to be presented separately in the notes to the consolidated financial statements, grouped by measurement category and form of financial instrument. This update is effective for annual and interim periods beginning after December 15, 2017. Fortis will adopt this standard in the first quarter of 2018, with an effective date of January 1, 2018, however, it is not expected that this standard will have a material impact on its consolidated financial statements. Leases ASU No. 2016-02 was issued in February 2016 and the amendments in this update create ASC Topic 842, Leases , and supersede lease requirements in ASC Topic 840, Leases . The main provision of ASC Topic 842 is the recognition of lease assets and lease liabilities on the balance sheet by lessees for those leases that were previously classified as operating leases. For operating leases, a lessee is required to do the following: (i) recognize a right-of-use asset and a lease liability, initially measured at the present value of the lease payments, on the balance sheet; (ii) recognize a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis; and (iii) classify all cash payments within operating activities in the statement of cash flows. These amendments also require qualitative disclosures along with specific quantitative disclosures. This update is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using a modified retrospective approach with practical expedient options. Early adoption is permitted. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements. Measurement of Credit Losses on Financial Instruments ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments , was issued in June 2016 and the amendments in this update require entities to use an expected credit loss methodology and to consider a broader range of reasonable and supportable information to inform credit loss estimates. This update is effective for annual and interim periods beginning after December 15, 2019 and is to be applied on a modified retrospective basis. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements. Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost ASU No. 2017-07 , Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, was issued in March 2017 and the amendments in this update require that an employer disaggregate the current service cost component of net benefit cost and present it in the same statement of earnings line item(s) as other employee compensation costs arising from services rendered. The other components of net benefit cost are required to be presented separately from the service cost component and outside of operating income. Additionally, the amendments allow only the service cost component to be eligible for capitalization when applicable . The amendments in this update should be applied retrospectively for the presentation of the net periodic benefit costs and prospectively, on and after the effective date, for the capitalization in assets of only the service cost component of net periodic benefit costs. This update is effective for annual and interim periods beginning after December 15, 2017. Fortis adopted this standard on January 1, 2018 and concluded that this standard will not materially impact its consolidated financial statements. Targeted Improvements to Accounting for Hedging Activities ASU No. 2017-12 , Targeted Improvements to Accounting for Hedging Activities, was issued in August 2017 and the amendments in this update better align risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and presentation of hedge results. This update is effective for annual and interim periods beginning after December 15, 2018 . Early adoption is permitted. The amendments in this update should be reflected as of the beginning of the fiscal year of adoption. For cash flow and net investment hedges existing at the date of adoption, the amendments should be applied as a cumulative effect adjustment related to eliminating the separate measurement of ineffectiveness to accumulated other comprehensive income with a corresponding adjustment to the opening balance of retained earnings. Amended presentation and disclosure guidance is required only prospectively. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements. |
Use of Accounting Estimates | Use of Accounting Estimates The preparation of the consolidated financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation's utilities operate often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances, and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, they are recognized in earnings in the period in which they become known. In the event that a regulatory decision is received after the balance sheet date but before the consolidated financial statements are issued, the facts and circumstances are reviewed to determine whether or not it is a recognized subsequent event. The Corporation's critical accounting estimates are described above in Note 3 under the headings Regulatory Assets and Liabilities; Property, Plant and Equipment; Intangible Assets; Goodwill; Employee Future Benefits; Income Taxes; Revenue Recognition; and Contingencies, and in the respective notes to the consolidated financial statements. |
Summary of Significant Accoun42
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Schedule of Property Plant and Equipment | The service life ranges and weighted average remaining service life of the Corporation's distribution, transmission, generation and other assets as at December 31 were as follows. 2017 2016 (Years) Service Life Ranges Weighted Average Remaining Service Life Service Life Ranges Weighted Average Remaining Service Life Distribution Electric 5-80 33 5-80 32 Gas 14-95 34 7-95 33 Transmission Electric 20-80 41 20-80 41 Gas 5-80 34 7-80 34 Generation 5-85 28 5-85 26 Other 3-70 14 3-70 14 2017 (in millions) Cost Accumulated Depreciation Net Book Value Distribution Electric $ 9,963 $ (2,864 ) $ 7,099 Gas 4,093 (1,157 ) 2,936 Transmission Electric 12,571 (2,838 ) 9,733 Gas 1,954 (596 ) 1,358 Generation 6,079 (1,996 ) 4,083 Other 3,608 (1,130 ) 2,478 Assets under construction 1,717 — 1,717 Land 264 — 264 $ 40,249 $ (10,581 ) $ 29,668 2016 (in millions) Cost Accumulated Depreciation Net Book Value Distribution Electric $ 9,616 $ (2,752 ) $ 6,864 Gas 3,956 (1,096 ) 2,860 Transmission Electric 12,616 (2,876 ) 9,740 Gas 1,776 (562 ) 1,214 Generation 6,884 (2,474 ) 4,410 Other 3,497 (1,096 ) 2,401 Assets under construction 1,559 — 1,559 Land 289 — 289 $ 40,193 $ (10,856 ) $ 29,337 |
Intangible Assets | The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows. 2017 2016 (Years) Service Life Ranges Weighted Average Remaining Service Life Service Life Ranges Weighted Average Remaining Service Life Computer software 3-10 4 3-10 4 Land, transmission and water rights 36-80 57 30-80 57 Other 10-100 10 10-104 15 2017 Accumulated Net Book (in millions ) Cost Amortization Value Computer software $ 784 $ (474 ) $ 310 Land, transmission and water rights 743 (103 ) 640 Other 117 (49 ) 68 Assets under construction 63 — 63 $ 1,707 $ (626 ) $ 1,081 2016 Accumulated Net Book (in millions ) Cost Amortization Value Computer software $ 748 $ (447 ) $ 301 Land, transmission and water rights 700 (108 ) 592 Other 128 (56 ) 72 Assets under construction 46 — 46 $ 1,622 $ (611 ) $ 1,011 |
Segmented Information (Tables)
Segmented Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Schedule of Information by Reportable Segment | REGULATED NON-REGULATED Year Ended United States Canada Energy Inter- December 31, 2017 UNS Central FortisBC Fortis FortisBC Eastern Infra- Corporate segment ($ millions) ITC Energy Hudson Energy Alberta Electric Canadian Caribbean Total structure and Other eliminations Total Revenue 1,575 2,080 872 1,198 600 398 1,062 301 8,086 226 1 (12 ) 8,301 Energy supply costs — 711 260 411 — 142 692 144 2,360 2 — (1 ) 2,361 Operating expenses 436 609 402 298 198 89 134 44 2,210 49 13 (11 ) 2,261 Depreciation and amortization 220 260 65 198 190 62 95 55 1,145 32 2 — 1,179 Operating income 919 500 145 291 212 105 141 58 2,371 143 (14 ) — 2,500 Other income, net 40 19 8 20 2 1 1 7 98 1 29 (1 ) 127 Finance charges 259 101 41 116 93 37 56 18 721 5 189 (1 ) 914 Income tax expense 371 148 42 40 1 14 22 — 638 19 (69 ) — 588 Net earnings 329 270 70 155 120 55 64 47 1,110 120 (105 ) — 1,125 Non-controlling interests 57 — — 1 — — — 13 71 26 — — 97 Preference share dividends — — — — — — — — — — 65 — 65 Net earnings attributable 272 270 70 154 120 55 64 34 1,039 94 (170 ) — 963 Goodwill 7,698 1,733 566 913 227 235 67 178 11,617 27 — — 11,644 Total assets 17,581 8,596 3,188 6,418 4,454 2,197 2,489 1,325 46,248 1,605 76 (107 ) 47,822 Capital expenditures 982 534 220 446 414 105 156 146 3,003 21 — — 3,024 Year Ended December 31, 2016 ($ millions) Revenue 334 2,002 849 1,151 572 377 1,063 301 6,649 193 9 (13 ) 6,838 Energy supply costs — 740 253 347 — 132 698 137 2,307 35 — (1 ) 2,341 Operating expenses 151 605 387 295 189 88 136 45 1,896 39 108 (12 ) 2,031 Depreciation and amortization 46 264 61 198 180 57 91 54 951 28 4 — 983 Operating income 137 393 148 311 203 100 138 65 1,495 91 (103 ) — 1,483 Other income, net 9 7 5 17 3 — 2 9 52 2 — (1 ) 53 Finance charges 54 102 40 125 85 37 55 15 513 4 162 (1 ) 678 Income tax expense 20 99 43 51 — 9 21 — 243 3 (101 ) — 145 Net earnings 72 199 70 152 121 54 64 59 791 86 (164 ) — 713 Non-controlling interests 13 — — 1 — — — 13 27 26 — — 53 Preference share dividends — — — — — — — — — — 75 — 75 Net earnings attributable 59 199 70 151 121 54 64 46 764 60 (239 ) — 585 Goodwill 8,246 1,854 605 913 227 235 67 190 12,337 27 — — 12,364 Total assets 18,000 8,935 3,214 6,230 4,057 2,143 2,394 1,344 46,317 1,502 130 (45 ) 47,904 Capital expenditures 223 524 233 336 375 74 161 106 2,032 19 10 — 2,061 |
Schedule of significant inter-company transactions | Inter-company balances and inter-company transactions, including any related inter-company profit, are eliminated on consolidation, except for certain inter-company transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The significant inter-company transactions for 2017 and 2016 are summarized in the following table. (in millions) 2017 2016 Sale of capacity from Waneta Expansion to FortisBC Electric $ 46 $ 45 Sale of energy from BECOL to Belize Electricity 35 33 Lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy 24 17 |
Accounts Receivable and Other44
Accounts Receivable and Other Current Assets (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Receivables [Abstract] | |
Schedule Of Accounts Receivable and Other Current Assets | (in millions) 2017 2016 Trade accounts receivable $ 492 $ 507 Unbilled accounts receivable 575 551 Allowance for doubtful accounts (31 ) (33 ) Income tax receivable 8 26 Other 87 76 $ 1,131 $ 1,127 |
Inventories (Tables)
Inventories (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Inventory Disclosure [Abstract] | |
Schedule of Utility Inventory | (in millions) 2017 2016 Materials and supplies $ 238 $ 244 Gas and fuel in storage 97 98 Coal inventory 32 30 $ 367 $ 372 |
Regulatory Assets and Liabili46
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Regulated Operations [Abstract] | |
Schedule of Regulatory Assets | Based on previous, existing or expected regulatory orders or decisions, the Corporation's regulated utilities have recognized the following amounts that are expected to be recovered from, or refunded to, customers in future periods. Remaining recovery period (in millions ) 2017 2016 (Years) Regulatory assets Deferred income taxes (i) $ 1,403 $ 1,260 To be determined Employee future benefits (ii) 510 576 Various Deferred energy management costs (iii) 200 178 1-10 Generation early retirement costs (iv) 105 — 11-13 Deferred lease costs (v) 104 97 Various Rate stabilization accounts (vi) 95 183 Various Deferred operating overhead costs (vii) 91 78 Various Derivative instruments (viii) 87 19 Various Manufactured gas plant ("MGP") site remediation deferral (ix) 75 107 To be determined Greenhouse gas reduction regulatory incentives (x) 35 40 10 Other regulatory assets (xi) 340 395 Various Total regulatory assets 3,045 2,933 Less: current portion (303 ) (313 ) 1 Long-term regulatory assets $ 2,742 $ 2,620 Regulatory liabilities Deferred income taxes (i) $ 1,484 $ — To be determined Asset removal cost provision (xii) 1,095 1,194 To be determined Rate stabilization accounts (vi) 254 230 Various ROE refund liability (xiii) 182 346 1 Energy efficiency liability (xiv) 82 49 Various Renewable energy surcharge (xv) 66 53 To be determined Electric and gas moderator account (xvi) 58 71 To be determined Employee future benefits (ii) 47 42 Various Other regulatory liabilities (xvii) 178 198 Various Total regulatory liabilities 3,446 2,183 Less: current portion (490 ) (492 ) 1 Long-term regulatory liabilities $ 2,956 $ 1,691 Description of the Nature of Regulatory Assets and Liabilities (i) Deferred Income Taxes The Corporation’s regulated utilities recognize deferred income tax assets and liabilities and related regulatory liabilities and assets for the amount of deferred income taxes expected to be refunded to, or recovered from, customers in future rates. As at December 31, 2017 , regulatory assets of approximately $754 million associated with deferred income taxes were not subject to a regulatory return ( December 31, 2016 - $596 million ). As at December 31, 2017 , regulatory liabilities of approximately $1,481 million associated with deferred taxes were not subject to a regulatory return. The balances for ITC, UNS Energy and Central Hudson reflect the effects of the significant changes to tax legislation signed into law in the United States in December 2017 ("U.S. Tax Reform"). As part of U.S. Tax Reform, utilities were required to remeasure their deferred income tax assets and liabilities (Note 23) . Included in regulatory liabilities is $1,453 million related to U.S. Tax reform, reflecting the reduction in deferred income tax expense expected to be refunded to customers. (ii) Employee Future Benefits The regulatory asset and liability associated with employee future benefits includes the actuarially determined unamortized net actuarial losses, past service costs and credits, and transitional obligations associated with defined benefit pension and OPEB plans maintained by the Corporation's regulated utilities (Note 24) , which are expected to be recovered from, or refunded to, customers in future rates. At the Corporation's regulated utilities, as approved by the respective regulators, differences between defined benefit pension and OPEB plan costs recognized under US GAAP and those which are expected to be recovered from, or refunded to, customers in future rates are subject to deferral account treatment and have been recognized as a regulatory asset or liability. These amounts would otherwise be recognized in accumulated other comprehensive income on the consolidated balance sheet. As at December 31, 2017 , regulatory assets of approximately $291 million associated with employee future benefits were not subject to a regulatory return ( December 31, 2016 - $346 million ). As at December 31, 2017 , regulatory liabilities of approximately $45 million associated with employee future benefits were not subject to a regulatory return ( December 31, 2016 - $31 million ). (iii) Deferred Energy Management Costs FortisBC Energy, FortisBC Electric, Central Hudson and Newfoundland Power provide energy management services to promote energy efficiency programs to their customers. As required by their respective regulator, these regulated utilities have capitalized related expenditures and are amortizing these expenditures on a straight-line basis over periods ranging from 1 to 10 years . This regulatory asset represents the unamortized balance of the energy management costs. UNS Energy is required to implement cost-effective Demand-Side Management ("DSM") programs to comply with the ACC's energy efficiency standards. The energy efficiency standards provide for a DSM surcharge to recover the costs of implementing DSM programs, as well as an annual performance incentive. The existing rate orders provide for a lost fixed-cost recovery mechanism to recover certain non-fuel costs that were previously unrecoverable, due to reduced electricity sales as a result of energy efficiency programs and distributed generation. As at December 31, 2017 , $41 million of the regulatory asset balance associated with deferred energy management costs was not subject to a regulatory return ( December 31, 2016 - $42 million ). (iv) Generation Early Retirement Costs UNS Energy holds an undivided interest in the jointly owned Navajo Generating Station ("Navajo"), located on a site leased from the Navajo Nation with an initial lease term through December 2019. In June 2017 the Navajo Nation approved a land-lease extension that allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. Retirement costs related to Navajo are currently being recovered through to 2030. UNS Energy owns the Sundt Generating Facility ("Sundt") and in August 2017 TEP submitted an application related to a generation modernization project at the facility, which will add generation capacity in the form of gas-fired reciprocating engines. As part of the application, TEP plans to early retire Sundt Units 1 and 2 by the end of 2020. Capital and operating costs related to Sundt Units 1 and 2 are currently being recovered through to 2028 and 2030, respectively. As a result of the planned early retirement of Navajo and Sundt Units 1 and 2, the net book value and other related retirement costs were reclassified from property, plant and equipment to regulatory assets, and as at December 31, 2017 the net book value of these assets was $105 million (US $84 million ). UNS Energy's generation early retirement costs are not subject to regulatory return. (v) Deferred Lease Costs Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement ("BPPA"), which ends in 2056. The depreciation of the asset under capital lease and interest expense associated with the capital lease obligation are not being fully recovered in current customer rates, since those rates include only the cash payments set out under the BPPA (Note 15) . The deferred lease costs are expected to be recovered from customers in future rates over the term of the lease and are not subject to a regulatory return. In 2017 , of the $31 million ( 2016 - $31 million ) of interest expense related to the capital lease obligations and the $6 million ( 2016 - $6 million ) of depreciation expense related to the assets under capital lease, $27 million ( 2016 - $27 million ) was recognized in energy supply costs and $3 million ( 2016 - $3 million ) was recognized in operating expenses, as approved by the regulator, with the balance of $7 million ( 2016 - $7 million ) deferred as a regulatory asset. (vi) Rate Stabilization Accounts Rate stabilization accounts associated with the Corporation's regulated utilities are recovered from, or refunded to, customers in future rates, as approved by the respective regulators. Electric rate stabilization accounts primarily mitigate the effect on earnings of variability in the cost of fuel and/or purchased power above or below a forecast or predetermined level and, at certain utilities, revenue decoupling mechanisms minimize the earnings impact resulting from reduced energy consumption as energy efficiency programs are implemented. Gas rate stabilization accounts primarily mitigate the effect on earnings of unpredictable and uncontrollable factors, namely volume volatility caused principally by weather, and natural gas cost volatility. At ITC, transmission revenue requirements are set annually using cost-based formula rates that remain in effect for a one -year period. The formula rates include a true-up mechanism, whereby the actual revenue requirement is compared to billed revenue for each year to determine any over- or under-collection of revenue requirement. Revenue is recognized based on the actual revenue requirement, and revenue accrual and deferral accounts represent the difference between the actual revenue requirement and billed revenue, and are collected from, or refunded to, customers within a two -year period. As at December 31, 2017 , approximately $75 million and $144 million of the rate stabilization accounts are expected to be recovered from, or refunded to, customers within one year and, as a result, are classified as current regulatory assets and liabilities, respectively ( December 31, 2016 -approximately $135 million and $173 million , respectively). As at December 31, 2017 , regulatory assets of approximately $91 million associated with rate stabilization accounts were not subject to a regulatory return ( December 31, 2016 ‑ $139 million ). As at December 31, 2017 , regulatory liabilities of approximately $114 million associated with rate stabilization accounts were not subject to a regulatory return ( December 31, 2016 ‑ $180 million ). (vii) Deferred Operating Overhead Costs As approved by the regulator, FortisAlberta has deferred certain operating overhead costs, which are expected to be collected in future customer rates over the lives of the related property, plant and equipment and intangible assets. (viii) Derivative Instruments As approved by the respective regulators, unrealized gains or losses associated with changes in the fair value of certain derivative instruments at UNS Energy, Central Hudson and FortisBC Energy are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates. These unrealized losses and gains would otherwise be recognized in earnings. UNS Energy and Central Hudson's regulatory asset balance totalling $38 million as at December 31, 2017 was not subject to a regulatory return ( December 31, 2016 - $6 million ). (ix) MGP Site Remediation Deferral As approved by the regulator, Central Hudson is permitted to defer for future recovery from its customers the difference between actual costs for MGP site investigation and remediation and the associated rate allowances (Notes 13 and 16 ). Central Hudson's MGP site remediation costs are not subject to a regulatory return. (x) Greenhouse Gas Reduction Regulatory Incentives The deferral for greenhouse gas reduction regulatory incentives at FortisBC Energy is mostly comprised of subsidy payments to assist customers to purchase natural gas vehicles in lieu of vehicles fueled by diesel as part of the incentive program pursuant to the Greenhouse Gas Reductions (Clean Energy) Regulations under the Clean Energy Act (British Columbia). The regulator has approved recovery in rates over a 10 -year period. (xi) Other Regulatory Assets Other regulatory assets relate to all of the Corporation's regulated utilities and are comprised of various items, each individually less than $40 million . As at December 31, 2017 , $306 million ( December 31, 2016 - $296 million ) of the balance was approved to be recovered from customers in future rates, with the remaining balance expected to be approved. As at December 31, 2017 , $145 million ( December 31, 2016 ‑ $217 million ) of the balance was not subject to a regulatory return. |
Schedule of Regulatory Liabilities | Based on previous, existing or expected regulatory orders or decisions, the Corporation's regulated utilities have recognized the following amounts that are expected to be recovered from, or refunded to, customers in future periods. Remaining recovery period (in millions ) 2017 2016 (Years) Regulatory assets Deferred income taxes (i) $ 1,403 $ 1,260 To be determined Employee future benefits (ii) 510 576 Various Deferred energy management costs (iii) 200 178 1-10 Generation early retirement costs (iv) 105 — 11-13 Deferred lease costs (v) 104 97 Various Rate stabilization accounts (vi) 95 183 Various Deferred operating overhead costs (vii) 91 78 Various Derivative instruments (viii) 87 19 Various Manufactured gas plant ("MGP") site remediation deferral (ix) 75 107 To be determined Greenhouse gas reduction regulatory incentives (x) 35 40 10 Other regulatory assets (xi) 340 395 Various Total regulatory assets 3,045 2,933 Less: current portion (303 ) (313 ) 1 Long-term regulatory assets $ 2,742 $ 2,620 Regulatory liabilities Deferred income taxes (i) $ 1,484 $ — To be determined Asset removal cost provision (xii) 1,095 1,194 To be determined Rate stabilization accounts (vi) 254 230 Various ROE refund liability (xiii) 182 346 1 Energy efficiency liability (xiv) 82 49 Various Renewable energy surcharge (xv) 66 53 To be determined Electric and gas moderator account (xvi) 58 71 To be determined Employee future benefits (ii) 47 42 Various Other regulatory liabilities (xvii) 178 198 Various Total regulatory liabilities 3,446 2,183 Less: current portion (490 ) (492 ) 1 Long-term regulatory liabilities $ 2,956 $ 1,691 Description of the Nature of Regulatory Assets and Liabilities (i) Deferred Income Taxes The Corporation’s regulated utilities recognize deferred income tax assets and liabilities and related regulatory liabilities and assets for the amount of deferred income taxes expected to be refunded to, or recovered from, customers in future rates. As at December 31, 2017 , regulatory assets of approximately $754 million associated with deferred income taxes were not subject to a regulatory return ( December 31, 2016 - $596 million ). As at December 31, 2017 , regulatory liabilities of approximately $1,481 million associated with deferred taxes were not subject to a regulatory return. The balances for ITC, UNS Energy and Central Hudson reflect the effects of the significant changes to tax legislation signed into law in the United States in December 2017 ("U.S. Tax Reform"). As part of U.S. Tax Reform, utilities were required to remeasure their deferred income tax assets and liabilities (Note 23) . Included in regulatory liabilities is $1,453 million related to U.S. Tax reform, reflecting the reduction in deferred income tax expense expected to be refunded to customers. (ii) Employee Future Benefits The regulatory asset and liability associated with employee future benefits includes the actuarially determined unamortized net actuarial losses, past service costs and credits, and transitional obligations associated with defined benefit pension and OPEB plans maintained by the Corporation's regulated utilities (Note 24) , which are expected to be recovered from, or refunded to, customers in future rates. At the Corporation's regulated utilities, as approved by the respective regulators, differences between defined benefit pension and OPEB plan costs recognized under US GAAP and those which are expected to be recovered from, or refunded to, customers in future rates are subject to deferral account treatment and have been recognized as a regulatory asset or liability. These amounts would otherwise be recognized in accumulated other comprehensive income on the consolidated balance sheet. As at December 31, 2017 , regulatory assets of approximately $291 million associated with employee future benefits were not subject to a regulatory return ( December 31, 2016 - $346 million ). As at December 31, 2017 , regulatory liabilities of approximately $45 million associated with employee future benefits were not subject to a regulatory return ( December 31, 2016 - $31 million ). (iii) Deferred Energy Management Costs FortisBC Energy, FortisBC Electric, Central Hudson and Newfoundland Power provide energy management services to promote energy efficiency programs to their customers. As required by their respective regulator, these regulated utilities have capitalized related expenditures and are amortizing these expenditures on a straight-line basis over periods ranging from 1 to 10 years . This regulatory asset represents the unamortized balance of the energy management costs. UNS Energy is required to implement cost-effective Demand-Side Management ("DSM") programs to comply with the ACC's energy efficiency standards. The energy efficiency standards provide for a DSM surcharge to recover the costs of implementing DSM programs, as well as an annual performance incentive. The existing rate orders provide for a lost fixed-cost recovery mechanism to recover certain non-fuel costs that were previously unrecoverable, due to reduced electricity sales as a result of energy efficiency programs and distributed generation. As at December 31, 2017 , $41 million of the regulatory asset balance associated with deferred energy management costs was not subject to a regulatory return ( December 31, 2016 - $42 million ). (iv) Generation Early Retirement Costs UNS Energy holds an undivided interest in the jointly owned Navajo Generating Station ("Navajo"), located on a site leased from the Navajo Nation with an initial lease term through December 2019. In June 2017 the Navajo Nation approved a land-lease extension that allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. Retirement costs related to Navajo are currently being recovered through to 2030. UNS Energy owns the Sundt Generating Facility ("Sundt") and in August 2017 TEP submitted an application related to a generation modernization project at the facility, which will add generation capacity in the form of gas-fired reciprocating engines. As part of the application, TEP plans to early retire Sundt Units 1 and 2 by the end of 2020. Capital and operating costs related to Sundt Units 1 and 2 are currently being recovered through to 2028 and 2030, respectively. As a result of the planned early retirement of Navajo and Sundt Units 1 and 2, the net book value and other related retirement costs were reclassified from property, plant and equipment to regulatory assets, and as at December 31, 2017 the net book value of these assets was $105 million (US $84 million ). UNS Energy's generation early retirement costs are not subject to regulatory return. (v) Deferred Lease Costs Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement ("BPPA"), which ends in 2056. The depreciation of the asset under capital lease and interest expense associated with the capital lease obligation are not being fully recovered in current customer rates, since those rates include only the cash payments set out under the BPPA (Note 15) . The deferred lease costs are expected to be recovered from customers in future rates over the term of the lease and are not subject to a regulatory return. In 2017 , of the $31 million ( 2016 - $31 million ) of interest expense related to the capital lease obligations and the $6 million ( 2016 - $6 million ) of depreciation expense related to the assets under capital lease, $27 million ( 2016 - $27 million ) was recognized in energy supply costs and $3 million ( 2016 - $3 million ) was recognized in operating expenses, as approved by the regulator, with the balance of $7 million ( 2016 - $7 million ) deferred as a regulatory asset. (vi) Rate Stabilization Accounts Rate stabilization accounts associated with the Corporation's regulated utilities are recovered from, or refunded to, customers in future rates, as approved by the respective regulators. Electric rate stabilization accounts primarily mitigate the effect on earnings of variability in the cost of fuel and/or purchased power above or below a forecast or predetermined level and, at certain utilities, revenue decoupling mechanisms minimize the earnings impact resulting from reduced energy consumption as energy efficiency programs are implemented. Gas rate stabilization accounts primarily mitigate the effect on earnings of unpredictable and uncontrollable factors, namely volume volatility caused principally by weather, and natural gas cost volatility. At ITC, transmission revenue requirements are set annually using cost-based formula rates that remain in effect for a one -year period. The formula rates include a true-up mechanism, whereby the actual revenue requirement is compared to billed revenue for each year to determine any over- or under-collection of revenue requirement. Revenue is recognized based on the actual revenue requirement, and revenue accrual and deferral accounts represent the difference between the actual revenue requirement and billed revenue, and are collected from, or refunded to, customers within a two -year period. As at December 31, 2017 , approximately $75 million and $144 million of the rate stabilization accounts are expected to be recovered from, or refunded to, customers within one year and, as a result, are classified as current regulatory assets and liabilities, respectively ( December 31, 2016 -approximately $135 million and $173 million , respectively). As at December 31, 2017 , regulatory assets of approximately $91 million associated with rate stabilization accounts were not subject to a regulatory return ( December 31, 2016 ‑ $139 million ). As at December 31, 2017 , regulatory liabilities of approximately $114 million associated with rate stabilization accounts were not subject to a regulatory return ( December 31, 2016 ‑ $180 million ). (vii) Deferred Operating Overhead Costs As approved by the regulator, FortisAlberta has deferred certain operating overhead costs, which are expected to be collected in future customer rates over the lives of the related property, plant and equipment and intangible assets. (viii) Derivative Instruments As approved by the respective regulators, unrealized gains or losses associated with changes in the fair value of certain derivative instruments at UNS Energy, Central Hudson and FortisBC Energy are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates. These unrealized losses and gains would otherwise be recognized in earnings. UNS Energy and Central Hudson's regulatory asset balance totalling $38 million as at December 31, 2017 was not subject to a regulatory return ( December 31, 2016 - $6 million ). (ix) MGP Site Remediation Deferral As approved by the regulator, Central Hudson is permitted to defer for future recovery from its customers the difference between actual costs for MGP site investigation and remediation and the associated rate allowances (Notes 13 and 16 ). Central Hudson's MGP site remediation costs are not subject to a regulatory return. (x) Greenhouse Gas Reduction Regulatory Incentives The deferral for greenhouse gas reduction regulatory incentives at FortisBC Energy is mostly comprised of subsidy payments to assist customers to purchase natural gas vehicles in lieu of vehicles fueled by diesel as part of the incentive program pursuant to the Greenhouse Gas Reductions (Clean Energy) Regulations under the Clean Energy Act (British Columbia). The regulator has approved recovery in rates over a 10 -year period. (xi) Other Regulatory Assets Other regulatory assets relate to all of the Corporation's regulated utilities and are comprised of various items, each individually less than $40 million . As at December 31, 2017 , $306 million ( December 31, 2016 - $296 million ) of the balance was approved to be recovered from customers in future rates, with the remaining balance expected to be approved. As at December 31, 2017 , $145 million ( December 31, 2016 ‑ $217 million ) of the balance was not subject to a regulatory return. (xii) Asset Removal Cost Provision As required by the respective regulators, depreciation rates include an accrual for asset removal costs. Actual asset removal costs are recorded against the regulatory liability when incurred. This regulatory liability represents amounts collected in customer rates in excess of incurred asset removal costs. (xiii) ROE Refund Liability The ROE refund liability at ITC relates to two third-party complaints pending before FERC requesting that the MISO regional base ROE for MISO transmission owners, including ITC, be found to no longer be just and reasonable. The complaints cover two consecutive 15 -month periods from November 2013 through February 2015 and February 2015 through May 2016 (Note 2) . As at December 31, 2017 , the estimated range of refunds for the Second Complaint was between US $106 million and US $145 million and ITC has recognized an estimated liability of $182 million (US $145 million ), which has been classified as current regulatory liability. The total estimated refund for the Initial Complaint was $158 million (US $118 million ), including interest, as at December 31, 2016 , which was substantially finalized and paid in 2017. (xiv) Energy Efficiency Liability The energy efficiency liability primarily relates to Central Hudson's Energy Efficiency Program established to fund the costs of environmental policies associated with energy conservation programs and megawatt hour reduction goals, as approved by its regulator, and was not subject to a regulatory return. (xv) Renewable Energy Surcharge As ordered by the regulator under its 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 in 2025, with distributed generation accounting for 30% of the annual renewable energy requirement. The Company must file an annual RES implementation plan for review and approval by the ACC. The approved cost of carrying out the plan is recovered from retail customers through the RES surcharge until such costs are reflected in TEP and UNS Electric's non-fuel base rates. Any RES surcharge collections above or below the costs incurred to implement the plans are deferred as a regulatory asset or liability and is subject to a regulatory return. The ACC measures compliance with its RES requirements through Renewable Energy Credits ("REC"). Each REC represents one kilowatt hour generated from renewable resources. When UNS Energy purchases renewable energy, the premium paid above the market cost of conventional power equals the REC recoverable through the RES surcharge. When RECs are purchased, UNS Energy records the cost of the RECs as long-term other assets (Note 9) and a corresponding regulatory liability, to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, energy supply costs and revenue are recognized in an equal amount. (xvi) Electric and Gas Moderator Account Under the terms of Central Hudson's three -year Rate Order issued in June 2015, certain of the Company's regulatory assets and liabilities were identified and approved by the PSC for offset and a net regulatory liability electric and gas moderator account was established, which will be used for future customer rate moderation. This electric and gas moderator account was not subject to a regulatory return. (xvii) Other Regulatory Liabilities Other regulatory liabilities relate to all of the Corporation's regulated utilities and are comprised of various items, each individually less than $40 million . As at December 31, 2017 , $173 million ( December 31, 2016 - $190 million ) of the balance was approved for refund to customers or reduction in future rates, with the remaining balance expected to be approved. As at December 31, 2017 , $26 million ( December 31, 2016 – $51 million ) of the balance was not subject to a regulatory return. |
Other Assets (Tables)
Other Assets (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Schedule of Other Assets | (in millions) 2017 2016 Supplemental Executive Retirement Plan assets $ 130 $ 115 Equity investment - Belize Electricity 73 78 Renewable Energy Credits (Note 8 (xv) ) 62 39 Defined benefit pension plan assets (Note 24) 31 32 Other investments 29 21 Deferred compensation plan assets 24 24 Equity investment - Wataynikaneyap Partnership 22 3 Other (1) 109 94 $ 480 $ 406 (1) Other assets are generally recorded at cost and recovered/amortized over the estimated period of future benefit, where applicable. Other assets also includes the fair value of derivative instruments (Note 28) . |
Property, Plant And Equipment (
Property, Plant And Equipment (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Regulated Operations [Abstract] | |
Schedule of Property Plant and Equipment | The service life ranges and weighted average remaining service life of the Corporation's distribution, transmission, generation and other assets as at December 31 were as follows. 2017 2016 (Years) Service Life Ranges Weighted Average Remaining Service Life Service Life Ranges Weighted Average Remaining Service Life Distribution Electric 5-80 33 5-80 32 Gas 14-95 34 7-95 33 Transmission Electric 20-80 41 20-80 41 Gas 5-80 34 7-80 34 Generation 5-85 28 5-85 26 Other 3-70 14 3-70 14 2017 (in millions) Cost Accumulated Depreciation Net Book Value Distribution Electric $ 9,963 $ (2,864 ) $ 7,099 Gas 4,093 (1,157 ) 2,936 Transmission Electric 12,571 (2,838 ) 9,733 Gas 1,954 (596 ) 1,358 Generation 6,079 (1,996 ) 4,083 Other 3,608 (1,130 ) 2,478 Assets under construction 1,717 — 1,717 Land 264 — 264 $ 40,249 $ (10,581 ) $ 29,668 2016 (in millions) Cost Accumulated Depreciation Net Book Value Distribution Electric $ 9,616 $ (2,752 ) $ 6,864 Gas 3,956 (1,096 ) 2,860 Transmission Electric 12,616 (2,876 ) 9,740 Gas 1,776 (562 ) 1,214 Generation 6,884 (2,474 ) 4,410 Other 3,497 (1,096 ) 2,401 Assets under construction 1,559 — 1,559 Land 289 — 289 $ 40,193 $ (10,856 ) $ 29,337 |
Schedule of Jointly Owned Facilities | As at December 31, 2017 , interests in jointly owned facilities consisted of the following. Ownership Accumulated Net Book (in millions) % Cost Depreciation Value San Juan Unit 1 50.0 $ 351 $ (104 ) $ 247 Four Corners Units 4 and 5 7.0 210 (98 ) 112 Luna Energy Facility 33.3 69 (4 ) 65 Gila River Common Facilities 25.0 41 (14 ) 27 Springerville Coal Handling Facilities 83.0 253 (102 ) 151 Transmission Facilities 1.0-80.0 854 (302 ) 552 $ 1,778 $ (624 ) $ 1,154 |
Intangible Assets (Tables)
Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of Indefinite-Lived Intangible Assets | 2017 Accumulated Net Book (in millions ) Cost Amortization Value Computer software $ 784 $ (474 ) $ 310 Land, transmission and water rights 743 (103 ) 640 Other 117 (49 ) 68 Assets under construction 63 — 63 $ 1,707 $ (626 ) $ 1,081 2016 Accumulated Net Book (in millions ) Cost Amortization Value Computer software $ 748 $ (447 ) $ 301 Land, transmission and water rights 700 (108 ) 592 Other 128 (56 ) 72 Assets under construction 46 — 46 $ 1,622 $ (611 ) $ 1,011 |
Schedule of Finite-Lived Intangible Assets | The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows. 2017 2016 (Years) Service Life Ranges Weighted Average Remaining Service Life Service Life Ranges Weighted Average Remaining Service Life Computer software 3-10 4 3-10 4 Land, transmission and water rights 36-80 57 30-80 57 Other 10-100 10 10-104 15 2017 Accumulated Net Book (in millions ) Cost Amortization Value Computer software $ 784 $ (474 ) $ 310 Land, transmission and water rights 743 (103 ) 640 Other 117 (49 ) 68 Assets under construction 63 — 63 $ 1,707 $ (626 ) $ 1,081 2016 Accumulated Net Book (in millions ) Cost Amortization Value Computer software $ 748 $ (447 ) $ 301 Land, transmission and water rights 700 (108 ) 592 Other 128 (56 ) 72 Assets under construction 46 — 46 $ 1,622 $ (611 ) $ 1,011 |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of Goodwill | (in millions) 2017 2016 Balance, beginning of year $ 12,364 $ 4,173 Acquisition of ITC (Note 2 5) (6 ) 8,106 Acquisition of Aitken Cree k (Note 25) — 27 Foreign currency translation impacts (714 ) 58 Balance, end of year $ 11,644 $ 12,364 |
Accounts Payable and Other Cu51
Accounts Payable and Other Current Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Payables and Accruals [Abstract] | |
Schedule of Accounts Payable and Other Accrued Liabilities | (in millions) 2017 2016 Trade accounts payable $ 696 $ 554 Interest payable 223 218 Customer and other deposits 204 287 Dividends payable 185 166 Employee compensation and benefits payable 184 178 Accrued taxes other than income taxes 178 168 Gas and fuel cost payable 146 175 Fair value of derivative instruments (Note 28) 71 28 MGP site remediation (Notes 8 (ix) and 16) 35 21 Defined benefit pension and OPEB liabilities (Note 24) 22 26 Other 109 149 $ 2,053 $ 1,970 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Schedule of Long-Term Debt | (in millions ) Maturity Date 2017 2016 Regulated Utilities ITC Secured US First Mortgage Bonds - 4.67% weighted average fixed rate (2016 - 4.81%) 2018-2055 $ 2,063 $ 1,994 Secured US Senior Notes - 4.19% weighted average fixed rate (2016 - 4.19%) 2040-2046 596 638 Unsecured US Senior Notes - 3.98% weighted average fixed rate (2016 - 4.80%) 2020-2043 3,618 3,160 Unsecured US Shareholder Note - 6.00% fixed rate (2016 - 6.00%) 2028 250 267 Unsecured US Term Loan Credit Agreement - 2.03% weighted average variable rate 2019 63 — UNS Energy Unsecured US Tax-Exempt Bonds - 4.04% weighted average fixed and variable rate (2016 - 3.87%) 2020-2040 773 827 Unsecured US Fixed Rate Notes - 4.26% weighted average fixed rate (2016 - 4.26%) 2021-2045 1,411 1,511 Central Hudson Unsecured US Promissory Notes - 4.28% weighted average fixed and variable rate (2016 - 4.25%) 2018-2057 770 768 FortisBC Energy Unsecured Debentures - 5.13% weighted average fixed rate (2016 - 5.24%) 2026-2047 2,395 2,220 FortisAlberta Unsecured Debentures - 4.70% weighted average fixed rate (2016 - 4.82%) 2024-2052 2,035 1,834 FortisBC Electric Secured Debentures - 8.80% fixed rate (2016 - 8.80%) 2023 25 25 Unsecured Debentures - 5.05% weighted average fixed rate (2016 - 5.22%) 2021-2050 710 635 Eastern Canadian Secured First Mortgage Sinking Fund Bonds - 6.14% weighted average fixed rate (2016 - 6.48%) 2020-2057 585 516 Secured First Mortgage Bonds - 6.19% weighted average fixed rate (2016 - 6.19%) 2018-2061 195 195 Unsecured Senior Notes - 6.11% weighted average fixed rate (2016 - 6.11%) 2018-2041 104 104 Caribbean Electric Unsecured US Senior Loan Notes and Bonds - 4.80% weighted average fixed and variable rate (2016 - 4.92%) 2018-2048 525 499 Corporate Unsecured US Senior Notes and Promissory Notes - 3.41% weighted average fixed rate (2016 - 3.43%) 2019-2044 4,046 4,353 Unsecured Debentures - 6.50% weighted average fixed rate (2016 - 6.50%) 2039 200 200 Unsecured Senior Notes - 2.85% fixed rate (2016 - 2.85%) 2023 500 500 Long-term classification of credit facility borrowings 671 973 Total long-term debt (Note 28) 21,535 21,219 Less: Deferred financing costs and debt discounts (139 ) (151 ) Less: Current installments of long-term debt (705 ) (251 ) $ 20,691 $ 20,817 |
Schedule of Credit Facilities | The following summary outlines the credit facilities of the Corporation and its subsidiaries. (in millions) Regulated Corporate 2017 2016 Total credit facilities (1) $ 3,567 $ 1,385 $ 4,952 $ 5,976 Credit facilities utilized: Short-term borrowings (1) (2) (209 ) — (209 ) (1,155 ) Long-term debt (including current portion) (3) (465 ) (206 ) (671 ) (973 ) Letters of credit outstanding (73 ) (56 ) (129 ) (119 ) Credit facilities unused $ 2,820 $ 1,123 $ 3,943 $ 3,729 (1) As at December 31, 2017 , there was no commercial paper outstanding ( December 31, 2016 - $195 million ). Outstanding commercial paper does not reduce available capacity under the Corporation's consolidated credit facilities. (2) The weighted average interest rate on short-term borrowings was approximately 1.8% as at December 31, 2017 ( December 31, 2016 - 1.7% ). (3) As at December 31, 2017 , credit facility borrowings classified as long-term debt included $ 312 million in current installments of long-term debt on the consolidated balance sheet ( December 31, 2016 - $ 61 million ). The weighted average interest rate on credit facility borrowings classified as long‑term debt was approximately 2.5% as at December 31, 2017 ( December 31, 2016 - 1.8% ). |
Schedule of Repayment of Long-Term Debt | The consolidated annual requirements to meet principal repayments and maturities in each of the next five years and thereafter are as follows. Regulated Corporate Utilities and Other Total Year (in millions) (in millions) (in millions) 2018 $ 499 $ 206 $ 705 2019 169 113 282 2020 516 157 673 2021 435 784 1,219 2022 1,060 — 1,060 Thereafter 13,904 3,692 17,596 $ 16,583 $ 4,952 $ 21,535 |
Capital Lease and Finance Obl53
Capital Lease and Finance Obligations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Leases [Abstract] | |
Schedule of Repayment of Capital Lease and Finance Obligations | The present value of the minimum lease payments required for the capital lease and finance obligations over the next five years and thereafter are as follows: Capital Finance Leases Obligations Total Year (in millions) (in millions) (in millions) 2018 $ 58 $ 32 $ 90 2019 59 15 74 2020 68 5 73 2021 46 32 78 2022 46 3 49 Thereafter 1,950 — 1,950 $ 2,227 $ 87 $ 2,314 Less: Amounts representing imputed interest and executory costs on capital lease and finance obligations (1,853 ) Total capital lease and finance obligations 461 Less: Current installments (47 ) $ 414 |
Other Liabilities (Tables)
Other Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Other Liabilities Disclosure [Abstract] | |
Schedule of Other Liabilities | (in millions) 2017 2016 Defined benefit pension plan liabilities (Note 24) $ 393 $ 410 OPEB plan liabilities (Note 24) 381 411 Asset retirement obligations 71 58 Customer and other deposits 67 69 Waneta Partnership promissory note (Notes 28, 29 and 30) 63 59 Mine reclamation and retiree health care liabilities 40 40 DSU, PSU and RSU liabilities (Note 21) 39 24 Fair value of derivative instruments (Note 28) 37 10 MGP site remediation (Notes 8 (ix) and 13) 34 77 Deferred compensation plan liabilities (Note 9) 28 27 Other 57 94 $ 1,210 $ 1,279 |
Earnings Per Common Share (Tabl
Earnings Per Common Share (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Schedule of Net Earnings to Common Shareholders | 2017 2016 Net Earnings Weighted Net Earnings Weighted to Common Average to Common Average Shareholders Shares Shareholders Shares ($ millions) (# millions) EPS ($ millions) (# millions) EPS Basic EPS $ 963 415.5 $ 2.32 $ 585 308.9 $ 1.89 Effect of potential dilutive securities: Stock Options — 0.7 — 0.7 Preference Shares — — 7 3.8 Diluted EPS $ 963 416.2 $ 2.31 $ 592 313.4 $ 1.89 |
Preference Shares (Tables)
Preference Shares (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Schedule of Preference Shares Issued and Outstanding | Characteristics of the First Preference Shares are as follows. Earliest Reset Redemption Right to Initial Annual Dividend and/or Redemption Convert on Yield Dividend Yield Conversion Value a One For First Preference Shares (1) (2) (%) ($) (%) Option Date ($) One Basis Perpetual fixed rate Series F 4.90 1.2250 — December 1, 2011 25.00 — Series J (3) 4.75 1.1875 — December 1, 2017 26.00 — Fixed rate reset (4) (5) Series G 5.25 0.9708 2.13 September 1, 2013 25.00 — Series H 4.25 0.6250 1.45 June 1, 2015 25.00 Series I Series K 4.00 1.0000 2.05 March 1, 2019 25.00 Series L Series M 4.10 1.0250 2.48 December 1, 2019 25.00 Series N Floating rate reset (5) (6) Series I (3) 2.10 — 1.45 June 1, 2015 25.50 Series H Series L — — 2.05 March 1, 2024 — Series K Series N — — 2.48 December 1, 2024 — Series M (1 ) Holders are entitled to receive a fixed or floating cumulative quarterly cash dividend as and when declared by the Board of Directors of the Corporation, payable in equal quarterly installments on the first day of each quarter. (2 ) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First Preference Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but excluding the dates fixed for redemption, and in the case of the First Preference Shares that reset, on every fifth anniversary date, thereafter. (3) First Preference Shares, Series J are redeemable at $26.00 until December 1, 2018, such redemption price decreasing by $0.25 each year until December 1, 2021 and redeemable at $25.00 per share thereafter. First Preference Shares, Series I are redeemable at $25.50 per share, up to but excluding June 1, 2020, and at $25.00 per share on June 1, 2020, and on every fifth anniversary date of June 1, 2020, thereafter. (4 ) On the redemption and/or conversion option date, and each five -year anniversary thereafter, the reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate, which is the sum of the five -year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield. (5) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their Shares into an equal number of Cumulative Redeemable First Preference Shares of a specified series. (6) The 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. Authorized (a) an unlimited number of First Preference Shares, without nominal or par value (b) an unlimited number of Second Preference Shares, without nominal or par value Issued and Outstanding 2017 2016 First Preference Shares Number Number of Shares Amount of Shares Amount (in thousands) (in millions) (in thousands) (in millions) Series F 5,000 $ 122 5,000 $ 122 Series G 9,200 225 9,200 225 Series H 7,025 172 7,025 172 Series I 2,975 73 2,975 73 Series J 8,000 196 8,000 196 Series K 10,000 244 10,000 244 Series M 24,000 591 24,000 591 66,200 $ 1,623 66,200 $ 1,623 |
Accumulated Other Comprehensi57
Accumulated Other Comprehensive Income (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Change in Accumulated Other Comprehensive Income by Category | The change in accumulated other comprehensive income by category is provided as follows. 2017 (in millions) Opening balance January 1 Net Change Ending balance December 31 Net unrealized foreign currency translation gains (losses): Unrealized foreign currency translation gains (losses) on net investments in foreign operations $ 1,227 $ (980 ) $ 247 (Losses) gains on hedges of net investments in foreign operations (472 ) 300 (172 ) Income tax recovery (expense) 1 (2 ) (1 ) 756 (682 ) 74 Cash flow hedges: (Note 28) Net change in fair value of cash flow hedges 8 (2 ) 6 Reclassification of cash flow hedges to finance charges — 4 4 Income tax expense (3 ) — (3 ) 5 2 7 Unrealized employee future benefits (losses) gains: (Note 24) Unamortized net actuarial losses (19 ) (3 ) (22 ) Unamortized past service costs (3 ) (1 ) (4 ) Income tax recovery 6 — 6 (16 ) (4 ) (20 ) Accumulated other comprehensive income $ 745 $ (684 ) $ 61 2016 (in millions) Opening balance January 1 Net Change Ending balance December 31 Net unrealized foreign currency translation gains (losses): Unrealized foreign currency translation gains (losses) on net investments in foreign operations $ 1,281 $ (54 ) $ 1,227 (Losses) gains on hedges of net investments in foreign operations (476 ) 4 (472 ) Income tax recovery 1 — 1 806 (50 ) 756 Available-for-sale investment: Realized gain on available-for-sale investment (2 ) 2 — Cash flow hedges: (Note 28) Net change in fair value of cash flow hedges 3 5 8 Income tax expense (1 ) (2 ) (3 ) 2 3 5 Unrealized employee future benefits (losses) gains: (Note 24) Unamortized net actuarial (losses) gains (20 ) 1 (19 ) Unamortized past service costs (1 ) (2 ) (3 ) Income tax recovery 6 — 6 (15 ) (1 ) (16 ) Accumulated other comprehensive income $ 791 $ (46 ) $ 745 |
Non-Controlling Interests (Tabl
Non-Controlling Interests (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Noncontrolling Interest [Abstract] | |
Schedule of Non-Controlling Interests | (in millions) 2017 2016 ITC $ 1,290 $ 1,385 Waneta Partnership 322 330 Caribbean Utilities 118 122 Other 16 16 $ 1,746 $ 1,853 |
Stock-based Compensation Plans
Stock-based Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of Stock Option Information | The following options were granted in 2017 and 2016 . The accounting fair values of the options were estimated at the date of grant using the Black-Scholes fair value option-pricing model and the following assumptions: 2017 2016 Options granted (#) 774,924 788,188 Exercise price ($) (1) 42.36 37.30 Grant date fair value ($) 3.22 2.41 Assumptions: Dividend yield (%) (2) 3.8 3.9 Expected volatility (%) (3) 16.1 16.4 Risk-free interest rate (%) (4) 1.2 0.7 Weighted average expected life (years) (5) 5.6 5.5 (1) Five -day VWAP immediately preceding the date of grant (2) Based on average annual dividend yield up to the date of grant and the weighted average expected life of the options (3) Based on historical experience over a period equal to the weighted average expected life of the options (4) Government of Canada benchmark bond yield in effect at the date of grant that covers the weighted average expected life of the options (5) Based on historical experience |
Summary of Stock Option Activity | The following table summarizes information related to stock options for 2017 . Total Options Non-vested Options (1) Number of Options Weighted Average Number of Options Weighted Average Options outstanding, January 1, 2017 4,160,192 $ 34.45 1,815,018 $ 2.78 Granted 774,924 $ 42.36 774,924 $ 3.22 Exercised (1,217,029 ) $ 32.73 n/a n/a Vested n/a n/a (761,830 ) $ 3.03 Cancelled/Forfeited (15,793 ) $ 40.27 (15,793 ) $ 2.88 Options outstanding, December 31, 2017 3,702,294 $ 36.65 1,812,319 $ 2.86 Options vested, December 31, 2017 (2) 1,889,975 $ 34.25 (1) As at December 31, 2017 , there was $5 million of unrecognized compensation expense related to stock options not yet vested, which is expected to be recognized over a weighted average period of approximately three years. (2) As at December 31, 2017 , the weighted average remaining term of vested options was six years with an aggregate intrinsic value of $22 million . |
Schedule of Additional Stock Option Information | The following table summarizes additional 2017 and 2016 stock option information. (in millions) 2017 2016 Stock option expense recognized $ 3 $ 2 Stock options exercised: Cash received for exercise price 40 28 Intrinsic value realized by employees 15 15 Fair value of options that vested 2 3 |
DSU Plan Activity | Number of DSUs 2017 2016 DSUs outstanding, beginning of year 199,411 167,762 Granted 31,453 30,165 Granted - notional dividends reinvested 7,294 6,994 DSUs paid out (53,363 ) (5,510 ) DSUs outstanding, end of year 184,795 199,411 |
PSU Plans Activity | The following table summarizes information related to the PSUs for 2017 and 2016 . Number of PSUs 2017 2016 PSUs outstanding, beginning of year 931,951 694,386 Granted 711,749 351,737 Granted - notional dividends reinvested 44,893 34,439 PSUs paid out (239,509 ) (148,168 ) PSUs cancelled/ forfeited (16,910 ) (443 ) Transferred to RSU Plan (81,214 ) — PSUs outstanding, end of year 1,350,960 931,951 |
RSU Plans Activity | Number of RSUs 2017 2016 RSUs outstanding, beginning of year 123,612 58,740 Granted 349,496 70,393 Granted - notional dividends reinvested 15,407 4,709 RSUs paid out (74,876 ) (10,201 ) RSUs cancelled/ forfeited (12,090 ) (29 ) Transferred from PSU Plan 81,214 — RSUs outstanding, end of year 482,763 123,612 |
Other Income, Net (Tables)
Other Income, Net (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Other Income and Expenses [Abstract] | |
Schedule of Other Income Net | (in millions) 2017 2016 Equity component of AFUDC $ 74 $ 37 Net foreign exchange gain (1) 26 — Interest income 14 7 Equity income - Belize Electricity 4 7 Other 9 2 $ 127 $ 53 (1) The net foreign exchange gain includes a one-time $21 million unrealized foreign exchange gain on US dollar-denominated affiliate loan. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Schedule of Deferred Income Taxes | Deferred income taxes are provided for temporary differences. The significant components of deferred income tax assets and liabilities consist of the following. (in millions) 2017 2016 Gross deferred income tax assets Tax loss and credit carryforwards $ 571 $ 675 Regulatory liabilities 596 292 Employee future benefits 143 155 Fair value of long-term debt adjustment 43 88 Unrealized foreign exchange losses on long-term debt 28 56 Other 8 57 1,389 1,323 Deferred income tax assets valuation allowance (44 ) (56 ) Net deferred income tax assets $ 1,345 $ 1,267 Gross deferred income tax liabilities Property, plant and equipment $ (3,353 ) $ (4,213 ) Regulatory assets (203 ) (242 ) Intangible assets (87 ) (75 ) (3,643 ) (4,530 ) Net deferred income tax liability $ (2,298 ) $ (3,263 ) |
Schedule of Unrecognized Tax Benefits | The following table summarizes the change in unrecognized tax benefits during 2017 and 2016 . (in millions) 2017 2016 Total unrecognized tax benefits, beginning of year $ 23 $ 13 Additions related to the current year 13 10 Adjustments related to prior years and U.S. Tax Reform (8 ) — Total unrecognized tax benefits, end of year $ 28 $ 23 |
Schedule of Components of Income Tax Expense | The components of the income tax expense were as follows. (in millions) 2017 2016 Canadian Earnings before income taxes $ 461 $ 357 Current income taxes 41 66 Deferred income taxes 16 (23 ) Total Canadian $ 57 $ 43 Foreign Earnings before income taxes $ 1,252 $ 501 Current income taxes 3 (19 ) Deferred income taxes 528 121 Total Foreign $ 531 $ 102 Income tax expense $ 588 $ 145 |
Schedule of Effective Income Tax Rate Reconciliation | The following is a reconciliation of consolidated statutory taxes to consolidated effective taxes. (in millions, except as noted) 2017 2016 Earnings before income taxes $ 1,713 $ 858 Combined Canadian federal and provincial statutory income tax rate 28.0 % 28.0 % Expected federal and provincial taxes at statutory rate $ 480 $ 240 Increase (decrease) resulting from: Enactment of U.S. Tax Reform 168 — Foreign and other statutory rate differentials 31 (28 ) Allowance for funds used during construction (26 ) (14 ) Effects of rate-regulated accounting: Difference between depreciation claimed for income tax and accounting purposes (26 ) (25 ) Items capitalized for accounting purposes but expensed for income tax purposes (21 ) (26 ) Release of valuation allowance and non-taxable portion of gain on dispositions (17 ) — Other (1 ) (2 ) Income tax expense $ 588 $ 145 Effective tax rate 34.3 % 16.9 % |
Summary of Operating Loss Carryforwards | As at December 31, 2017 , the Corporation had the following tax carryforward amounts. (in millions) Expiring Year 2017 Canadian Capital loss n/a $ 70 Non-capital loss 2025-2037 326 Other tax credits 2026-2037 2 398 Unrecognized in the consolidated financial statements (65 ) $ 333 Foreign Capital loss 2018 $ 1 Federal and state net operating loss 2022-2037 1,850 Other tax credits 2021-2037 126 1,977 Unrecognized in the consolidated financial statements (1 ) $ 1,976 Total tax carryforwards $ 2,309 |
Summary of Tax Carryforward Amounts | As at December 31, 2017 , the Corporation had the following tax carryforward amounts. (in millions) Expiring Year 2017 Canadian Capital loss n/a $ 70 Non-capital loss 2025-2037 326 Other tax credits 2026-2037 2 398 Unrecognized in the consolidated financial statements (65 ) $ 333 Foreign Capital loss 2018 $ 1 Federal and state net operating loss 2022-2037 1,850 Other tax credits 2021-2037 126 1,977 Unrecognized in the consolidated financial statements (1 ) $ 1,976 Total tax carryforwards $ 2,309 |
Employee Future Benefits (Table
Employee Future Benefits (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Retirement Benefits [Abstract] | |
Schedule of Allocation of Plan Assets | The Corporation's consolidated defined benefit pension and OPEB plan weighted average asset allocations were as follows. Plan assets as at December 31 2017 Target Allocation (%) 2017 2016 Equities 48 47 50 Fixed income 45 46 45 Real estate 6 6 4 Cash and other 1 1 1 100 100 100 The fair value measurements of defined benefit pension and OPEB plan assets by fair value hierarchy, as defined in Note 28 , were as follows. Fair value of plan assets as at December 31, 2017 (in millions) Level 1 Level 2 Level 3 Total Equities $ 522 $ 949 $ — $ 1,471 Fixed income 133 1,289 — 1,422 Real estate — 13 168 181 Private equities — — 22 22 Cash and other 8 14 — 22 $ 663 $ 2,265 $ 190 $ 3,118 Fair value of plan assets as at December 31, 2016 (in millions) Level 1 Level 2 Level 3 Total Equities $ 507 $ 942 $ — $ 1,449 Fixed income 124 1,180 — 1,304 Real estate — 13 103 116 Private equities — — 10 10 Cash and other 6 13 — 19 $ 637 $ 2,148 $ 113 $ 2,898 |
Schedule of Level 3 Changes in Plan Assets | The following table is a reconciliation of changes in the fair value of pension plan assets that have been measured using Level 3 inputs for the years ended December 31, 2017 and 2016 . (in millions) 2017 2016 Balance, beginning of year $ 113 $ 107 Actual return on plan assets held at end of year 12 8 Foreign currency translation impacts (2 ) (1 ) Purchases, sales and settlements 67 (1 ) Balance, end of year $ 190 $ 113 |
Schedule of Funded Status | The following is a breakdown of the Corporation's and subsidiaries' defined benefit pension and OPEB plans and their respective funded status. Defined Benefit OPEB Plans (in millions) 2017 2016 2017 2016 Change in benefit obligation (1) Balance, beginning of year $ 3,037 $ 2,828 $ 676 $ 574 Liabilities assumed on acquisition — 167 — 111 Service costs 76 66 27 18 Employee contributions 16 17 2 2 Interest costs 115 112 25 23 Benefits paid (133 ) (119 ) (22 ) (23 ) Actuarial losses (gains) 217 45 (14 ) (1 ) Past service credits/plan amendments — (10 ) (3 ) — Foreign currency translation impacts (113 ) (69 ) (26 ) (28 ) Balance, end of year (2) $ 3,215 $ 3,037 $ 665 $ 676 Change in value of plan assets Balance, beginning of year $ 2,646 $ 2,466 $ 252 $ 181 Assets assumed on acquisition — 85 — 65 Actual return on plan assets 336 187 37 13 Benefits paid (127 ) (119 ) (22 ) (23 ) Employee contributions 16 17 2 2 Employer contributions 69 47 26 18 Foreign currency translation impacts (99 ) (37 ) (18 ) (4 ) Balance, end of year $ 2,841 $ 2,646 $ 277 $ 252 Funded status $ (374 ) $ (391 ) $ (388 ) $ (424 ) (1) Amounts reflect projected benefit obligation for defined benefit pension plans and accumulated benefit obligation for OPEB plans. (2) The accumulated benefit obligation for defined benefit pension plans, excluding assumptions about future salary levels, was $2,940 million as at December 31, 2017 ( December 31, 2016 - $2,741 million ). |
Schedule of Amounts Recognized in Balance Sheet | The following table summarizes the employee future benefit assets and liabilities and their classifications on the consolidated balance sheet. Defined Benefit OPEB Plans (in millions) 2017 2016 2017 2016 Assets Defined benefit pension assets: Long-term (Note 9) $ 31 $ 32 $ — $ — OPEB plan assets: Long-term (Note 9) — — 3 — Liabilities Defined benefit pension liabilities: Current (Note 13) 12 13 — — Long-term (Note 16) 393 410 — — OPEB plan liabilities: Current (Note 13) — — 10 13 Long-term (Note 16) — — 381 411 Net liabilities $ 374 $ 391 $ 388 $ 424 |
Schedule of Net Benefit Costs | The net benefit cost for the Corporation's defined benefit pension plans and OPEB plans were as follows. Defined Benefit OPEB Plans (in millions) 2017 2016 2017 2016 Components of net benefit cost Service costs $ 76 $ 66 $ 27 $ 18 Interest costs 115 112 25 23 Expected return on plan assets (151 ) (145 ) (14 ) (12 ) Amortization of actuarial losses 45 48 2 2 Amortization of past service credits/plan amendments — 1 (12 ) (10 ) Regulatory adjustments 2 6 4 9 Net benefit cost $ 87 $ 88 $ 32 $ 30 |
Schedule of Amounts Recognized in AOCI and Net Regulatory Assets | The following table provides the components of accumulated other comprehensive loss and regulatory assets and liabilities, which would otherwise have been recognized as accumulated other comprehensive loss, for the years ended December 31, 2017 and 2016 , which have not been recognized as components of net benefit cost. Defined Benefit Pension Plans OPEB Plans (in millions) 2017 2016 2017 2016 Unamortized net actuarial losses $ 22 $ 19 $ — $ — Unamortized past service costs 1 1 3 2 Income tax recovery (5 ) (5 ) (1 ) (1 ) Accumulated other comprehensive loss (Note 19) $ 18 $ 15 $ 2 $ 1 Net actuarial losses $ 443 $ 479 $ 17 $ 53 Past service credits (11 ) (11 ) (23 ) (31 ) Amount deferred due to actions of regulators 10 12 27 32 $ 442 $ 480 $ 21 $ 54 Regulatory assets (Note 8 (ii) ) $ 442 $ 480 $ 68 $ 96 Regulatory liabilities (Note 8 (ii) ) — — (47 ) (42 ) Net regulatory assets $ 442 $ 480 $ 21 $ 54 |
Schedule of Amounts Recognized in OCI and Regulatory Assets | The following table provides the components recognized in comprehensive income or as regulatory assets, which would otherwise have been recognized in comprehensive income. Defined Benefit Pension Plans OPEB Plans (in millions) 2017 2016 2017 2016 Current year net actuarial losses (gains) $ 5 $ 4 $ (1 ) $ (2 ) Past service costs/plan amendments — — 2 — Amortization of actuarial losses (1 ) — — — Foreign currency translation impacts (1 ) — — — Income tax recovery — (1 ) — — Total recognized in comprehensive income $ 3 $ 3 $ 1 $ (2 ) Assets assumed on acquisition $ — $ 23 $ — $ 3 Current year net actuarial losses (gains) 24 (1 ) (35 ) — Past service credits/plan amendments — (10 ) (5 ) — Amortization of actuarial losses (44 ) (47 ) (1 ) (4 ) Amortization of past service (costs) credits — (1 ) 12 13 Foreign currency translation impacts (17 ) (9 ) 2 1 Regulatory adjustments (1 ) (11 ) (6 ) (6 ) Total recognized in regulatory assets $ (38 ) $ (56 ) $ (33 ) $ 7 |
Schedule of Assumptions Used | Significant weighted average assumptions Defined Benefit OPEB Plans (%) 2017 2016 2017 2016 Discount rate during the year (1) 3.98 4.08 3.96 4.14 Discount rate as at December 31 3.58 4.00 3.59 4.00 Expected long-term rate of return on plan assets (2) 5.97 6.25 5.81 6.25 Rate of compensation increase 3.34 3.36 — — Health care cost trend increase as at December 31 (3) — — 4.71 4.70 (1) ITC and UNS use the split discount rate methodology for determining current service and interest costs. All other subsidiaries use the single discount rate approach. (2) Developed by management with assistance from external actuaries using best estimates of expected returns, volatilities and correlations for each class of asset. The best estimates are based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes. (3) The projected 2018 weighted average health care cost trend rate is 6.38% for OPEB plans and is assumed to decrease over the next 11 years by 2028 to the weighted average ultimate health care cost trend rate of 4.71% and remain at that level thereafter. |
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates | For 2017 the effects of changing the health care cost trend rate by 1% were as follows. (in millions) 1% increase in rate 1% decrease in rate Increase (decrease) in accumulated benefit obligation $ 96 $ (74 ) Increase (decrease) in service and interest costs 26 (19 ) |
Schedule of Expected Benefit Payments | The following table provides the amount of benefit payments expected to be made over the next 10 years. Defined Benefit OPEB Payments Year (in millions) (in millions) 2018 $ 134 $ 23 2019 137 24 2020 142 25 2021 148 27 2022 156 29 2023-2027 860 160 |
Business Acquisitions (Tables)
Business Acquisitions (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
Schedule of Allocation of Purchase Consideration | The following table summarizes the final allocation of the purchase consideration to the assets and liabilities acquired as at October 14, 2016 based on their fair values, using an exchange rate of US$1.00=CAD $1.32 . (in millions) Total Share consideration $ 4,684 Cash consideration 4,658 Total consideration $ 9,342 Purchase consideration for 80.1% of ITC common shares $ 7,721 19.9% minority shareholder investment and shareholder note 1,621 $ 9,342 Fair value assigned to net assets: Current assets $ 319 Long-term regulatory assets 319 Property, plant and equipment 8,345 Intangible assets 399 Other long-term assets 71 Current liabilities (625 ) Assumed short-term borrowings (311 ) Assumed long-term debt (including current portion) (6,006 ) Long-term regulatory liabilities (327 ) Deferred income taxes (910 ) Other long-term liabilities (166 ) 1,108 Cash and cash equivalents 134 Fair value of net assets acquired 1,242 Goodwill (Note 12) $ 8,100 |
Supplemental Pro Forma Data | The unaudited pro forma financial information below gives effect to the acquisition of ITC as if the transaction had occurred at the beginning of 2016 . This pro forma data is presented for information purposes only, and does not necessarily represent the results that would have occurred had the acquisition taken place at the beginning of 2016 , nor is it necessarily indicative of the results that may be expected in future periods. (in millions) 2016 Pro forma revenue $ 7,995 Pro forma net earnings attributable to common equity shareholders (1) 919 (1) Pro forma net earnings attributable to common equity shareholders exclude all after-tax acquisition-related expenses incurred by ITC and the Corporation. A pro forma adjustment has been made to net earnings for the year presented to reflect the Corporation's after‑tax financing costs associated with the acquisition. |
Supplementary Information to 64
Supplementary Information to Consolidated Statements of Cash Flows (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplementary Information to Consolidated Statements of Cash Flows | (in millions) 2017 2016 Cash paid for: Interest $ 927 $ 644 Income taxes 69 62 Change in working capital: Accounts receivable and other current assets $ (74 ) $ 43 Prepaid expenses (3 ) (4 ) Inventories (6 ) 17 Regulatory assets - current portion 39 (58 ) Accounts payable and other current liabilities 119 25 Regulatory liabilities - current portion (172 ) (1 ) $ (97 ) $ 22 Non-cash investing and financing activities: Common share dividends reinvested 253 162 Common shares issued on business acquisition (Note 25) — 4,684 Additions to property, plant and equipment, and intangible assets included in current and long-term liabilities 307 296 Commitment to purchase capital lease interest — 48 Transfer of deposit on business acquisition (Note 25) — 38 Contributions in aid of construction 35 9 Exercise of stock options into common shares 5 4 |
Fair Value Measurements and F65
Fair Value Measurements and Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Hierarchy | The following tables present, by level within the fair value hierarchy, the Corporation's assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. As at December 31, 2017 (in millions) Level 1 Level 2 Level 3 Total Assets Energy contracts subject to regulatory deferral (1) (2) $ — $ 19 $ 2 $ 21 Energy contracts not subject to regulatory deferral (1) — 26 4 30 Foreign exchange contracts (3) 3 — — 3 Other investments (4) 78 — — 78 Total assets $ 81 $ 45 $ 6 $ 132 Liabilities Energy contracts subject to regulatory deferral (2) (5) $ (1 ) $ (103 ) $ (2 ) $ (106 ) Energy contracts not subject to regulatory deferral (5) — — (1 ) (1 ) Interest rate and total return swaps (3) — (1 ) — (1 ) Total liabilities $ (1 ) $ (104 ) $ (3 ) $ (108 ) As at December 31, 2016 (in millions) Level 1 Level 2 Level 3 Total Assets Energy contracts subject to regulatory deferral (1) (2) $ 1 $ 13 $ 5 $ 19 Energy contracts not subject to regulatory deferral (1) — 1 2 3 Interest rate swaps (3) — 11 — 11 Other investments (4) 69 — — 69 Total assets $ 70 $ 25 $ 7 $ 102 Liabilities Energy contracts subject to regulatory deferral (2) (5) $ — $ (21 ) $ (5 ) $ (26 ) Energy contracts not subject to regulatory deferral (5) — (9 ) — (9 ) Interest rate and total return swaps (3) — (3 ) — (3 ) Total liabilities $ — $ (33 ) $ (5 ) $ (38 ) (1) The fair value of the Corporation's energy contracts is recognized in accounts receivable and other current assets and long-term other assets. (2) 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. (3) The fair value of the Corporation's foreign exchange contracts, interest rate and total return swaps is recognized in accounts receivable and other current assets, accounts payable and other current liabilities and long-term other liabilities. (4) Included in long-term other assets on the consolidated balance sheet (Note 9) . (5) The fair value of the Corporation's energy contracts is recognized in accounts payable and other current liabilities and non-current other liabilities. |
Derivative Asset Contracts Under Master Netting Agreements and Collateral Positions | The Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions, which applies only to its energy contracts. The following tables present the potential offset of counterparty netting. As at December 31, 2017 (in millions) Gross Amount Recognized in Balance Sheet Counterparty Netting of Energy Contracts Cash Collateral Received/Posted Net Amount Derivative assets Energy contracts $ 51 $ 17 $ 7 $ 27 Derivative liabilities Energy contracts (107 ) (17 ) — (90 ) As at December 31, 2016 (in millions) Gross Amount Recognized in Balance Sheet Counterparty Netting of Energy Contracts Cash Collateral Received/ Posted Net Amount Derivative assets Energy contracts $ 22 $ 9 $ — $ 13 Derivative liabilities Energy contracts (35 ) (9 ) — (26 ) |
Derivative Liability Contracts Under Master Netting Agreements and Collateral Positions | The Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions, which applies only to its energy contracts. The following tables present the potential offset of counterparty netting. As at December 31, 2017 (in millions) Gross Amount Recognized in Balance Sheet Counterparty Netting of Energy Contracts Cash Collateral Received/Posted Net Amount Derivative assets Energy contracts $ 51 $ 17 $ 7 $ 27 Derivative liabilities Energy contracts (107 ) (17 ) — (90 ) As at December 31, 2016 (in millions) Gross Amount Recognized in Balance Sheet Counterparty Netting of Energy Contracts Cash Collateral Received/ Posted Net Amount Derivative assets Energy contracts $ 22 $ 9 $ — $ 13 Derivative liabilities Energy contracts (35 ) (9 ) — (26 ) |
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 | The following table presents a reconciliation of changes in the fair value of net assets and liabilities classified as level 3 in the fair value hierarchy. Transfers from level 3 to level 2 principally resulted from management's decision that inputs used to calculate the fair value of derivatives are observable and level 2 classification is appropriate. (in millions) 2017 2016 Balance, beginning of year $ 2 $ (18 ) Realized losses (10 ) (19 ) Unrealized (losses) gains (3 ) 12 Settlements 12 27 Transfers of assets out of level 3 (2 ) — Transfers of liabilities out of level 3 4 — Balance, end of year $ 3 $ 2 |
Schedule of Volume of Derivative Activity | As at December 31, 2017 , the Corporation had various energy contracts that will settle on various expiration dates through 2029. The volumes related to electricity and natural gas derivatives are outlined below. 2017 2016 Energy contracts subject to regulatory deferral (1) Electricity swap contracts (GWh) 1,291 2,184 Electricity power purchase contracts (GWh) 761 1,252 Gas swap contracts (PJ) 216 35 Gas supply contract premiums (PJ) 219 240 Energy contracts not subject to regulatory deferral (1) Wholesale trading contracts (GWh) 2,387 2,058 Gas supply contract premiums (PJ) — 15 Gas swap contracts (PJ) 36 4 (1) GWh means gigawatt hours and PJ means petajoules. |
Schedule of Financial Instruments Not Carried At Fair Value | The following table discloses the estimated fair value measurements of the Corporation's financial instruments not carried at fair value. The carrying values of the Corporation's consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows. 2017 2016 (in millions) Carrying Estimated Carrying Estimated Long-term debt, including current portion (Note 14) (1) $ 21,535 23,481 $ 21,219 $ 22,523 Waneta Partnership promissory note (Note 16) 63 64 59 61 (1) Long-term debt is valued using Level 2 inputs. |
Variable Interest Entity (Table
Variable Interest Entity (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Variable Interest Entities | The following table details the Waneta Partnership assets, liabilities, revenue, expenses, and cash flow included in the Corporation's consolidated financial statements. (in millions) 2017 2016 Assets Cash and cash equivalents $ 16 $ 15 Accounts receivable and other current assets 14 14 Property, plant and equipment 688 696 Intangible assets 30 30 $ 748 $ 755 Liabilities Accounts payable and other current liabilities $ (28 ) $ (3 ) Other liabilities (63 ) (79 ) (91 ) (82 ) Net assets before partners' equity $ 657 $ 673 (in millions) 2017 2016 Revenue $ 93 $ 91 Expenses Operating expense 17 17 Depreciation and amortization 18 18 Finance charges 4 3 39 38 Net earnings $ 54 $ 53 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Consolidated Commitments in the Next Five Years and Periods Thereafter | As at December 31, 2017 , the Corporation's consolidated commitments in each of the next five years and for periods thereafter, excluding repayments of long-term debt and capital lease and finance obligations separately disclosed in Notes 14 and 15 , respectively, are as follows. (in millions) Total Due within 1 year Due in year 2 Due in year 3 Due in year 4 Due in year 5 Due after Interest obligations on long-term debt $ 14,575 $ 892 $ 878 $ 858 $ 837 $ 792 $ 10,318 Power purchase obligations (1) 2,240 275 157 126 118 117 1,447 Renewable power purchase obligations (2) 1,428 93 92 92 92 91 968 Gas purchase obligations (3) 1,085 278 201 189 147 112 158 Long-term contracts - UNS Energy (4) 910 157 158 125 79 50 341 ITC easement agreement (5) 413 13 13 13 13 13 348 Renewable energy credit purchase agreements (6) 125 20 13 11 10 10 61 Debt Collection Agreement (7) 122 3 3 3 3 3 107 Operating lease obligations 53 11 9 7 4 4 18 Purchase of Springerville Common Facilities (8) 85 — — — 85 — — Waneta Partnership promissory note (Note 16) 72 — — 72 — — — Joint-use asset and shared service agreements 52 3 3 3 3 3 37 Other (9) 462 97 53 71 31 32 178 Total $ 21,622 $ 1,842 $ 1,580 $ 1,570 $ 1,422 $ 1,227 $ 13,981 (1) Power purchase obligations include various power purchase contracts held by the Corporation's regulated utilities, of which the most significant contracts are described below. FortisOntario: Power purchase obligations for FortisOntario, totalling $ 692 million as at December 31, 2017 , include a contract with Hydro-Quebec for the supply of up to 145 MW of capacity and a minimum of 537 GWh of associated energy annually from January 2020 through to December 2030. This contract will replace FortisOntario's existing long-term take-or-pay contracts with Hydro-Quebec to supply 145 MW of capacity expiring in 2019. FortisBC Energy: FortisBC Energy is party to an electricity supply agreement with BC Hydro for the purchase of electricity supply to the Tilbury LNG Facility Expansion, with purchase obligations totalling $ 482 million as at December 31, 2017 . FortisBC Electric: Power purchase obligations for FortisBC Electric, totalling $ 333 million as at December 31, 2017 , include a PPA with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of associated energy annually for a 20-year term. FortisBC Electric is also party to the Waneta Expansion Capacity Agreement ("WECA"), allowing it to purchase 234 MW of capacity per month, on average, for 40 years, effective April 2015, as approved by the BCUC. Amounts associated with the WECA have not been included in the Commitments table as they will be paid by FortisBC Electric to a related party. Maritime Electric: Maritime Electric's power purchase obligations include two take-or-pay contracts for the purchase of either capacity or energy, expiring in February 2019, as well as an Energy Purchase Agreement with New Brunswick Power ("NB Power"). Maritime Electric has entitlement to approximately 4.55% of the output from NB Power's Point Lepreau nuclear generating station for the life of the unit. As part of its entitlement, Maritime Electric is required to pay its share of the capital and operating costs of the unit, and as at December 31, 2017 , had commitments of $ 511 million under this arrangement. (2) TEP and UNS Electric are party to long-term renewable PPAs that require TEP and UNS Electric to purchase 100% of the output of certain renewable energy generating facilities once commercial operation is achieved. While TEP and UNS Electric are not required to make payments under these contracts if power is not delivered, the Commitments table includes estimated future payments. These agreements have various expiry dates from 2027 through 2036. (3) Certain of the Corporation's subsidiaries, mainly FortisBC Energy, enter into contracts for the purchase of gas, gas transportation and storage services. FortisBC Energy's gas purchase obligations are based on gas commodity indices that vary with market prices and the obligations are based on index prices as at December 31, 2017 . (4) UNS Energy enters into various long-term contracts for the purchase and delivery of coal to fuel its generating facilities, the purchase of gas transportation services to meet its load requirements, and the purchase of transmission services for purchased power. Amounts paid under contracts for the purchase and delivery of coal depend on actual quantities purchased and delivered. Certain of these contracts also have price adjustment clauses that will affect future costs under the contracts. (5) ITC is party to an easement agreement with Consumers Energy, the primary customer of METC, which provides the Company 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 additional 50 -year renewals thereafter. (6) UNS Energy and Central Hudson are party to renewable energy credit purchase agreements, mainly for the purchase of environmental attributions from retail customers with solar installations. Payments for the renewable energy credit purchase agreements are made in contractually agreed-upon intervals based on metered renewable energy production. (7) Maritime Electric is party to a debt collection agreement with the PEI Energy Corporation for the initial capital cost of the submarine cables and associated parts of the New Brunswick Transmission system interconnection. The agreement expires in February 2056 . Payments under the agreement will be collected from customers in future rates. (8 ) UNS Energy has an obligation to purchase an undivided 32.2% interest in the Springerville Common Facilities if the related two leases are not renewed (Note 15). (9) Other contractual obligations include various other commitments entered into by the Corporation and its subsidiaries, including PSU, RSU and DSU plan obligations, land easements, asset retirement obligations, and defined benefit pension plan funding obligations. |
Description of Business - Regul
Description of Business - Regulated Utilities - United States (Details) - MW | Dec. 31, 2017 | Oct. 31, 2016 | Oct. 14, 2016 |
TEP and UNS Electric, Inc | |||
Public Utilities, General Disclosures [Line Items] | |||
Generating capacity (MW) | 2,834 | ||
TEP and UNS Electric, Inc | Solar | |||
Public Utilities, General Disclosures [Line Items] | |||
Generating capacity (MW) | 64 | ||
Central Hudson | Gas-Fired and Hydroelectric Power Generation | |||
Public Utilities, General Disclosures [Line Items] | |||
Generating capacity (MW) | 64 | ||
ITC | |||
Public Utilities, General Disclosures [Line Items] | |||
Controlling ownership interest (percent) | 80.10% | 80.10% | |
Noncontrolling ownership (percent) | 19.90% | 19.90% |
Description of Business - Reg69
Description of Business - Regulated Utilities - Canada (Details) | Dec. 31, 2017communitycompanystationMW |
Wataynikaneyap Partnership | |
Public Utilities, General Disclosures [Line Items] | |
Equity investment ownership (percent) | 49.00% |
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 facilities | station | 4 |
Generating capacity (MW) | 225 |
Generating facilities, operating, maintenance and management services | station | 5 |
Waneta Partnership | Hydroelectric Power Generation | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 335 |
Newfoundland Power Inc. | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 139 |
Newfoundland Power Inc. | Hydroelectric Power Generation | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 97 |
Maritime Electric | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 145 |
FortisOntario | Electric Utilities | |
Public Utilities, General Disclosures [Line Items] | |
Number of utilities | company | 3 |
Fortis Inc. | Wataynikaneyap Partnership | |
Public Utilities, General Disclosures [Line Items] | |
Partnership with First Nation communities, number | community | 22 |
Description of Business - Reg70
Description of Business - Regulated Utilities - Caribbean (Details) | Dec. 31, 2017companyMW | Dec. 31, 2016 |
Fortis Turks and Caicos | ||
Public Utilities, General Disclosures [Line Items] | ||
Number of utilities | company | 2 | |
Diesel | Caribbean Utilities | ||
Public Utilities, General Disclosures [Line Items] | ||
Generating capacity (MW) | 161 | |
Diesel | Fortis Turks and Caicos | ||
Public Utilities, General Disclosures [Line Items] | ||
Generating capacity (MW) | 84 | |
Caribbean Utilities | ||
Public Utilities, General Disclosures [Line Items] | ||
Controlling ownership interest (percent) | 60.00% | 60.00% |
Belize Electricity | ||
Public Utilities, General Disclosures [Line Items] | ||
Equity investment ownership (percent) | 33.00% |
Description of Business - Non-R
Description of Business - Non-Regulated - Energy Infrastructure (Details) | 12 Months Ended |
Dec. 31, 2017stationMWBcf | |
Waneta Partnership | |
Public Utilities, General Disclosures [Line Items] | |
Long-term contract for electric power, term | 40 years |
Waneta Partnership | Hydroelectric Power Generation | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 335 |
BECOL | Hydroelectric Power Generation | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 51 |
Long-term contract for electric power, term | 50 years |
Generating facilities | station | 3 |
Waneta Partnership | |
Public Utilities, General Disclosures [Line Items] | |
Controlling ownership interest (percent) | 51.00% |
Generating capacity (MW) | 335 |
Noncontrolling ownership (percent) | 49.00% |
Aitken Creek | Aitken Creek Gas Storage ULC | |
Public Utilities, General Disclosures [Line Items] | |
Controlling ownership interest (percent) | 93.80% |
Generating capacity (billion cubic feet) | Bcf | 77 |
Walden | |
Public Utilities, General Disclosures [Line Items] | |
Generating capacity (MW) | 16 |
Nature of Regulation and Regu72
Nature of Regulation and Regulatory Matters - ITC (Details) - ITC CAD in Millions, $ in Millions | 1 Months Ended | 5 Months Ended | 12 Months Ended | 16 Months Ended | ||||
Sep. 30, 2016company | Jun. 30, 2016 | Sep. 30, 2016company | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Feb. 28, 2015complaintcomplaint_period | Dec. 31, 2017CAD | Dec. 31, 2016CAD | |
ROE refund liability, second refund period | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Estimated potential refund | $ 145 | $ 140 | CAD 182 | CAD 188 | ||||
ROE refund liability, second refund period | Minimum | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Estimated potential refund | $ | 106 | |||||||
ROE refund liability, second refund period | Maximum | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Estimated potential refund | $ | $ 145 | |||||||
ROE refund liability, initial and second refund periods | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Complaints (number) | complaint | 2 | |||||||
Number of complaint periods | complaint_period | 2 | |||||||
Complaint period | 15 months | |||||||
ROE refund liability, initial complaint | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Refunds, including interest | $ 118 | CAD 158 | ||||||
FERC | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Approved cost-based formula (years) | 1 year | |||||||
Approved cost-based formula, annual true-up (period) | 2 years | |||||||
Capital structure of common equity (percent) | 60.00% | 60.00% | ||||||
ROE (percent) | 10.32% | 12.38% | ||||||
Recommended ROE (percent) | 9.70% | |||||||
Number of utilities | company | 3 | 3 | ||||||
FERC | Maximum | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
ROE (percent) | 11.35% | 13.88% | ||||||
Recommended ROE (percent) | 10.68% | |||||||
FERC | ROE refund liability, initial and second refund periods | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Complaints (number) | complaint | 2 | |||||||
ROE (percent) | 12.38% |
Nature of Regulation and Regu73
Nature of Regulation and Regulatory Matters - UNS Energy (Details) CAD in Millions, $ in Millions | Feb. 27, 2017USD ($) | Feb. 27, 2017CAD | Aug. 01, 2016 | Jan. 01, 2014 | Jul. 01, 2013 | May 01, 2012 | May 30, 2017CAD | Jan. 31, 2017CAD | Dec. 31, 2016CAD |
TEP | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Ownership (percent) | 50.50% | 50.50% | |||||||
TEP | ACC | 2017 Rate Order | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Increase in non-fuel base revenue | $ 81.5 | CAD 108 | |||||||
Recovery of Operating Costs | $ 15 | CAD 20 | |||||||
Return on original cost rate base (percent) | 7.04% | 7.04% | |||||||
ROE (percent) | 9.75% | 9.75% | 10.00% | ||||||
Embedded cost of long-term debt (percent) | 4.32% | 4.32% | |||||||
Capital structure of common equity (percent) | 50.00% | 50.00% | 43.50% | ||||||
TEP | FERC | Time value refunds | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Accrued time value refunds | CAD 29 | ||||||||
Time value refunds paid | 22 | ||||||||
Contingency accrual related to time-value refunds | CAD 7 | ||||||||
Proceeds from Legal Settlements | CAD 11 | ||||||||
Reversal of provision | CAD 7 | ||||||||
UNS Electric | ACC | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
ROE (percent) | 9.50% | 9.50% | |||||||
Capital structure of common equity (percent) | 52.80% | 52.60% | |||||||
UNS Gas | ACC | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
ROE (percent) | 9.75% | ||||||||
Capital structure of common equity (percent) | 50.80% |
Nature of Regulation and Regu74
Nature of Regulation and Regulatory Matters - Central Hudson (Details) - PSC - Central Hudson CAD in Millions, $ in Millions | Jul. 01, 2015 | Jul. 31, 2017USD ($) | Jul. 31, 2017CAD |
Public Utilities, General Disclosures [Line Items] | |||
ROE (percent) | 9.00% | ||
Capital structure of common equity (percent) | 48.00% | ||
Approved return on equity and capital structure, term | 3 years | ||
Requested rate increase on ROE | 9.50% | 9.50% | |
Requested increase to equity component of capital structure | 50.00% | 50.00% | |
Electric rates | |||
Public Utilities, General Disclosures [Line Items] | |||
Requested increase in electric and natural gas rates | $ 43 | CAD 55 | |
Gas rates | |||
Public Utilities, General Disclosures [Line Items] | |||
Requested increase in electric and natural gas rates | $ 18 | CAD 23 | |
Equally shared earnings | |||
Public Utilities, General Disclosures [Line Items] | |||
Earnings in excess of (basis points) | 50.00% | ||
Primarily customer earnings | |||
Public Utilities, General Disclosures [Line Items] | |||
Earnings in excess of (basis points) | 100.00% |
Nature of Regulation and Regu75
Nature of Regulation and Regulatory Matters - FortisBC Energy and FortisBC Electric (Details) - BCUC | Jan. 01, 2016 | Jan. 01, 2013 | Dec. 31, 2017 |
FortisBC Energy and FortisBC Electric | |||
Public Utilities, General Disclosures [Line Items] | |||
Variance sharing (percent) | 50.00% | ||
FortisBC Energy | |||
Public Utilities, General Disclosures [Line Items] | |||
ROE (percent) | 8.75% | ||
Capital structure of common equity (percent) | 38.50% | ||
Fixed productivity adjustment (percent) | 1.10% | ||
FortisBC Electric | |||
Public Utilities, General Disclosures [Line Items] | |||
ROE (percent) | 9.15% | 9.15% | |
Capital structure of common equity (percent) | 40.00% | 40.00% | |
Fixed productivity adjustment (percent) | 1.03% |
Nature of Regulation and Regu76
Nature of Regulation and Regulatory Matters - FortisAlberta (Details) - FortisAlberta - AUC | Jan. 01, 2016 | Dec. 31, 2017 | Dec. 31, 2016 |
Public Utilities, General Disclosures [Line Items] | |||
Efficiency gains benefit period beyond initial term (period) | 2 years | ||
ROE (percent) | 8.50% | 8.30% | |
Capital structure of common equity (percent) | 37.00% |
Nature of Regulation and Regu77
Nature of Regulation and Regulatory Matters - Eastern Canadian (Details) - company | Mar. 01, 2016 | Jan. 01, 2016 | Mar. 01, 2013 | Dec. 31, 2017 | Dec. 31, 2016 |
Newfoundland Power Inc. | PUB | |||||
Public Utilities, General Disclosures [Line Items] | |||||
ROE (percent) | 8.50% | ||||
Capital structure of common equity (percent) | 45.00% | ||||
Maritime Electric | IRAC | |||||
Public Utilities, General Disclosures [Line Items] | |||||
ROE (percent) | 9.35% | 9.75% | |||
Capital structure of common equity (percent) | 40.00% | 40.00% | |||
ROE rate term | 3 years | ||||
FortisOntario | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Franchise agreement term | 35 years | ||||
FortisOntario | Electric Utilities | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Number of utilities | 3 | ||||
FortisOntario | OEB | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Capital structure of common equity (percent) | 40.00% | 40.00% | |||
FortisOntario | OEB | Minimum | |||||
Public Utilities, General Disclosures [Line Items] | |||||
ROE (percent) | 8.78% | 8.93% | |||
FortisOntario | OEB | Maximum | |||||
Public Utilities, General Disclosures [Line Items] | |||||
ROE (percent) | 9.30% | 9.30% |
Nature of Regulation and Regu78
Nature of Regulation and Regulatory Matters - Regulated Electric Utilities - Caribbean (Details) - license | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Caribbean Utilities | Government of the Cayman Islands | ||
Public Utilities, General Disclosures [Line Items] | ||
T & D license term | 20 years | |
Generation license term | 25 years | |
Caribbean Utilities | Government of the Cayman Islands | Minimum | ||
Public Utilities, General Disclosures [Line Items] | ||
ROA (percent) | 6.75% | 6.75% |
Caribbean Utilities | Government of the Cayman Islands | Maximum | ||
Public Utilities, General Disclosures [Line Items] | ||
ROA (percent) | 8.75% | 8.75% |
Fortis Turks and Caicos | Government of the Turks and Caicos Islands | ||
Public Utilities, General Disclosures [Line Items] | ||
Licenses (number) | 2 | |
Operating license term | 50 years | |
Fortis Turks and Caicos | Government of the Turks and Caicos Islands | Minimum | ||
Public Utilities, General Disclosures [Line Items] | ||
ROA (percent) | 15.00% | |
Fortis Turks and Caicos | Government of the Turks and Caicos Islands | Maximum | ||
Public Utilities, General Disclosures [Line Items] | ||
ROA (percent) | 17.50% |
Summary of Significant Accoun79
Summary of Significant Accounting Policies - Property, Plant and Equipment (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Regulated Operations [Abstract] | ||
Debt component of AFUDC | CAD 38 | CAD 29 |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, composite depreciation rate | 2.60% | 2.80% |
Property, plant and equipment, generation remaining useful life | 28 years | 26 years |
Property, plant and equipment, other remaining useful life | 14 years | 14 years |
Electric Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution remaining useful life | 33 years | 32 years |
Gas Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution remaining useful life | 34 years | 33 years |
Electric Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission remaining useful life | 41 years | 41 years |
Gas Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission remaining useful life | 34 years | 34 years |
Minimum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, straight line depreciation rate | 0.90% | 0.90% |
Property, plant and equipment, generation useful life | 5 years | 5 years |
Property, plant and equipment, other useful life | 3 years | 3 years |
Minimum | Electric Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution useful life | 5 years | 5 years |
Minimum | Gas Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution useful life | 14 years | 7 years |
Minimum | Electric Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission useful life | 20 years | 20 years |
Minimum | Gas Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission useful life | 5 years | 7 years |
Maximum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, straight line depreciation rate | 34.60% | 34.60% |
Property, plant and equipment, generation useful life | 85 years | 85 years |
Property, plant and equipment, other useful life | 70 years | 70 years |
Maximum | Electric Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution useful life | 80 years | 80 years |
Maximum | Gas Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, distribution useful life | 95 years | 95 years |
Maximum | Electric Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission useful life | 80 years | 80 years |
Maximum | Gas Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, transmission useful life | 80 years | 80 years |
Summary of Significant Accoun80
Summary of Significant Accounting Policies - Intangible Assets (Details) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Computer software | ||
Finite-Lived Intangible Assets [Line Items] | ||
Weighted Average Remaining Service Life | 4 years | 4 years |
Land, transmission and water rights | ||
Finite-Lived Intangible Assets [Line Items] | ||
Weighted Average Remaining Service Life | 57 years | 57 years |
Other | ||
Finite-Lived Intangible Assets [Line Items] | ||
Weighted Average Remaining Service Life | 10 years | 15 years |
Minimum | ||
Finite-Lived Intangible Assets [Line Items] | ||
Intangible asset amortization rate | 1.00% | 1.00% |
Minimum | Computer software | ||
Finite-Lived Intangible Assets [Line Items] | ||
Service Life Ranges | 3 years | 3 years |
Minimum | Land, transmission and water rights | ||
Finite-Lived Intangible Assets [Line Items] | ||
Service Life Ranges | 36 years | 30 years |
Minimum | Other | ||
Finite-Lived Intangible Assets [Line Items] | ||
Service Life Ranges | 10 years | 10 years |
Maximum | ||
Finite-Lived Intangible Assets [Line Items] | ||
Intangible asset amortization rate | 50.00% | 50.00% |
Maximum | Computer software | ||
Finite-Lived Intangible Assets [Line Items] | ||
Service Life Ranges | 10 years | 10 years |
Maximum | Land, transmission and water rights | ||
Finite-Lived Intangible Assets [Line Items] | ||
Service Life Ranges | 80 years | 80 years |
Maximum | Other | ||
Finite-Lived Intangible Assets [Line Items] | ||
Service Life Ranges | 100 years | 104 years |
Summary of Significant Accoun81
Summary of Significant Accounting Policies - Goodwill (Details) | 1 Months Ended | 12 Months Ended | |
Dec. 31, 2017CAD | Dec. 31, 2017CADreporting_unit | Dec. 31, 2016CAD | |
Accounting Policies [Abstract] | |||
Number of reporting units | reporting_unit | 11 | ||
Goodwill impairment loss | CAD | CAD 0 | CAD 0 | CAD 0 |
Summary of Significant Accoun82
Summary of Significant Accounting Policies - Employee Future Benefits and Stock-Based Compensation (Details) - CAD / shares | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Accounting Policies [Abstract] | ||
Defined benefit plan, market-related value of plan assets recognition period | 3 years | |
Options | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Award vesting period | 4 years | |
Exercise price, VWAP (period) | 5 days | |
DSUs | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Award vesting period | 3 years | |
Exercise price, VWAP (period) | 5 days | |
DSUs | Director | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Exercise price, VWAP (period) | 5 days | |
Volume weighted average price, share price (in dollars per share) | CAD 46.01 | CAD 41.46 |
PSUs | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Award vesting period | 3 years | |
Exercise price, VWAP (period) | 5 days | |
Volume weighted average price, share price (in dollars per share) | CAD 46.01 | 41.46 |
RSUs | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Award vesting period | 3 years | |
Exercise price, VWAP (period) | 5 days | |
Volume weighted average price, share price (in dollars per share) | CAD 46.01 | CAD 41.46 |
Summary of Significant Accoun83
Summary of Significant Accounting Policies - Foreign Currency Translation (Details) - CAD / $ | Dec. 31, 2017 | Dec. 31, 2016 | Oct. 14, 2016 | Oct. 13, 2016 |
Schedule of Equity Method Investments [Line Items] | ||||
Foreign exchange rate (CAD per USD) | 1.25 | 1.34 | 1.32 | 1.32 |
Weighted Average | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Foreign exchange rate (CAD per USD) | 1.30 | 1.33 |
Summary of Significant Accoun84
Summary of Significant Accounting Policies - Income Taxes, Sales Taxes, and New Accounting Policies (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Variable Interest Entity [Line Items] | ||
Undistributed earnings on foreign subsidiaries | CAD 561 | CAD 525 |
Hydroelectric Power Generation | BECOL | ||
Variable Interest Entity [Line Items] | ||
Long-term contract for electric power, term | 50 years |
Future Accounting Pronounceme85
Future Accounting Pronouncements (Details) | 12 Months Ended |
Dec. 31, 2017 | |
Tariff-based sales to retail and wholesale customers | |
Concentration Risk [Line Items] | |
Concentration risk percentage | 90.00% |
Segmented Information - Informa
Segmented Information - Information by Reportable Segment (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Segment Reporting Information [Line Items] | |||
Revenue | CAD 8,301 | CAD 6,838 | |
Energy supply costs | 2,361 | 2,341 | |
Operating expenses | 2,261 | 2,031 | |
Depreciation and amortization | 1,179 | 983 | |
Operating income | 2,500 | 1,483 | |
Other income, net | 127 | 53 | |
Finance charges | 914 | 678 | |
Income tax expense | 588 | 145 | |
Net earnings | 1,125 | 713 | |
Non-controlling interests | 97 | 53 | |
Preference share dividends | 65 | 75 | |
Common equity shareholders | 963 | 585 | |
Goodwill | 11,644 | 12,364 | CAD 4,173 |
Total assets | 47,822 | 47,904 | |
Capital expenditures | 3,024 | 2,061 | |
Inter-segment eliminations | |||
Segment Reporting Information [Line Items] | |||
Revenue | (12) | (13) | |
Energy supply costs | (1) | (1) | |
Operating expenses | (11) | (12) | |
Depreciation and amortization | 0 | 0 | |
Operating income | 0 | 0 | |
Other income, net | (1) | (1) | |
Finance charges | (1) | (1) | |
Income tax expense | 0 | 0 | |
Net earnings | 0 | 0 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 0 | 0 | |
Goodwill | 0 | 0 | |
Total assets | (107) | (45) | |
Capital expenditures | 0 | 0 | |
REGULATED | Operating segments | |||
Segment Reporting Information [Line Items] | |||
Revenue | 8,086 | 6,649 | |
Energy supply costs | 2,360 | 2,307 | |
Operating expenses | 2,210 | 1,896 | |
Depreciation and amortization | 1,145 | 951 | |
Operating income | 2,371 | 1,495 | |
Other income, net | 98 | 52 | |
Finance charges | 721 | 513 | |
Income tax expense | 638 | 243 | |
Net earnings | 1,110 | 791 | |
Non-controlling interests | 71 | 27 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 1,039 | 764 | |
Goodwill | 11,617 | 12,337 | |
Total assets | 46,248 | 46,317 | |
Capital expenditures | 3,003 | 2,032 | |
REGULATED | Operating segments | United States | ITC | |||
Segment Reporting Information [Line Items] | |||
Revenue | 1,575 | 334 | |
Energy supply costs | 0 | 0 | |
Operating expenses | 436 | 151 | |
Depreciation and amortization | 220 | 46 | |
Operating income | 919 | 137 | |
Other income, net | 40 | 9 | |
Finance charges | 259 | 54 | |
Income tax expense | 371 | 20 | |
Net earnings | 329 | 72 | |
Non-controlling interests | 57 | 13 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 272 | 59 | |
Goodwill | 7,698 | 8,246 | |
Total assets | 17,581 | 18,000 | |
Capital expenditures | 982 | 223 | |
REGULATED | Operating segments | United States | UNS Energy | |||
Segment Reporting Information [Line Items] | |||
Revenue | 2,080 | 2,002 | |
Energy supply costs | 711 | 740 | |
Operating expenses | 609 | 605 | |
Depreciation and amortization | 260 | 264 | |
Operating income | 500 | 393 | |
Other income, net | 19 | 7 | |
Finance charges | 101 | 102 | |
Income tax expense | 148 | 99 | |
Net earnings | 270 | 199 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 270 | 199 | |
Goodwill | 1,733 | 1,854 | |
Total assets | 8,596 | 8,935 | |
Capital expenditures | 534 | 524 | |
REGULATED | Operating segments | United States | Central Hudson | |||
Segment Reporting Information [Line Items] | |||
Revenue | 872 | 849 | |
Energy supply costs | 260 | 253 | |
Operating expenses | 402 | 387 | |
Depreciation and amortization | 65 | 61 | |
Operating income | 145 | 148 | |
Other income, net | 8 | 5 | |
Finance charges | 41 | 40 | |
Income tax expense | 42 | 43 | |
Net earnings | 70 | 70 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 70 | 70 | |
Goodwill | 566 | 605 | |
Total assets | 3,188 | 3,214 | |
Capital expenditures | 220 | 233 | |
REGULATED | Operating segments | Canada | FortisBC Energy | |||
Segment Reporting Information [Line Items] | |||
Revenue | 1,198 | 1,151 | |
Energy supply costs | 411 | 347 | |
Operating expenses | 298 | 295 | |
Depreciation and amortization | 198 | 198 | |
Operating income | 291 | 311 | |
Other income, net | 20 | 17 | |
Finance charges | 116 | 125 | |
Income tax expense | 40 | 51 | |
Net earnings | 155 | 152 | |
Non-controlling interests | 1 | 1 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 154 | 151 | |
Goodwill | 913 | 913 | |
Total assets | 6,418 | 6,230 | |
Capital expenditures | 446 | 336 | |
REGULATED | Operating segments | Canada | FortisAlberta | |||
Segment Reporting Information [Line Items] | |||
Revenue | 600 | 572 | |
Energy supply costs | 0 | 0 | |
Operating expenses | 198 | 189 | |
Depreciation and amortization | 190 | 180 | |
Operating income | 212 | 203 | |
Other income, net | 2 | 3 | |
Finance charges | 93 | 85 | |
Income tax expense | 1 | 0 | |
Net earnings | 120 | 121 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 120 | 121 | |
Goodwill | 227 | 227 | |
Total assets | 4,454 | 4,057 | |
Capital expenditures | 414 | 375 | |
REGULATED | Operating segments | Canada | FortisBC Electric | |||
Segment Reporting Information [Line Items] | |||
Revenue | 398 | 377 | |
Energy supply costs | 142 | 132 | |
Operating expenses | 89 | 88 | |
Depreciation and amortization | 62 | 57 | |
Operating income | 105 | 100 | |
Other income, net | 1 | 0 | |
Finance charges | 37 | 37 | |
Income tax expense | 14 | 9 | |
Net earnings | 55 | 54 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 55 | 54 | |
Goodwill | 235 | 235 | |
Total assets | 2,197 | 2,143 | |
Capital expenditures | 105 | 74 | |
REGULATED | Operating segments | Canada | Eastern Canadian | |||
Segment Reporting Information [Line Items] | |||
Revenue | 1,062 | 1,063 | |
Energy supply costs | 692 | 698 | |
Operating expenses | 134 | 136 | |
Depreciation and amortization | 95 | 91 | |
Operating income | 141 | 138 | |
Other income, net | 1 | 2 | |
Finance charges | 56 | 55 | |
Income tax expense | 22 | 21 | |
Net earnings | 64 | 64 | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 64 | 64 | |
Goodwill | 67 | 67 | |
Total assets | 2,489 | 2,394 | |
Capital expenditures | 156 | 161 | |
REGULATED | Operating segments | Caribbean | Caribbean | |||
Segment Reporting Information [Line Items] | |||
Revenue | 301 | 301 | |
Energy supply costs | 144 | 137 | |
Operating expenses | 44 | 45 | |
Depreciation and amortization | 55 | 54 | |
Operating income | 58 | 65 | |
Other income, net | 7 | 9 | |
Finance charges | 18 | 15 | |
Income tax expense | 0 | 0 | |
Net earnings | 47 | 59 | |
Non-controlling interests | 13 | 13 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 34 | 46 | |
Goodwill | 178 | 190 | |
Total assets | 1,325 | 1,344 | |
Capital expenditures | 146 | 106 | |
NON-REGULATED | Operating segments | Energy Infra-structure | |||
Segment Reporting Information [Line Items] | |||
Revenue | 226 | 193 | |
Energy supply costs | 2 | 35 | |
Operating expenses | 49 | 39 | |
Depreciation and amortization | 32 | 28 | |
Operating income | 143 | 91 | |
Other income, net | 1 | 2 | |
Finance charges | 5 | 4 | |
Income tax expense | 19 | 3 | |
Net earnings | 120 | 86 | |
Non-controlling interests | 26 | 26 | |
Preference share dividends | 0 | 0 | |
Common equity shareholders | 94 | 60 | |
Goodwill | 27 | 27 | |
Total assets | 1,605 | 1,502 | |
Capital expenditures | 21 | 19 | |
NON-REGULATED | Operating segments | Corporate and Other | |||
Segment Reporting Information [Line Items] | |||
Revenue | 1 | 9 | |
Energy supply costs | 0 | 0 | |
Operating expenses | 13 | 108 | |
Depreciation and amortization | 2 | 4 | |
Operating income | (14) | (103) | |
Other income, net | 29 | 0 | |
Finance charges | 189 | 162 | |
Income tax expense | (69) | (101) | |
Net earnings | (105) | (164) | |
Non-controlling interests | 0 | 0 | |
Preference share dividends | 65 | 75 | |
Common equity shareholders | (170) | (239) | |
Goodwill | 0 | 0 | |
Total assets | 76 | 130 | |
Capital expenditures | CAD 0 | CAD 10 |
Segmented Information - Related
Segmented Information - Related-party and Inter-Company Transactions (Details) - CAD | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Related Party Transaction [Line Items] | ||
Intercompany loans | CAD 0 | CAD 0 |
Belize Electricity | Equity Method Investee | ||
Related Party Transaction [Line Items] | ||
Due from related party | 20,000,000 | 16,000,000 |
Waneta Partnership | ||
Related Party Transaction [Line Items] | ||
Intercompany revenue recognized | 46,000,000 | 45,000,000 |
BECOL | ||
Related Party Transaction [Line Items] | ||
Intercompany revenue recognized | 35,000,000 | 33,000,000 |
Aitken Creek | ||
Related Party Transaction [Line Items] | ||
Intercompany revenue recognized | CAD 24,000,000 | CAD 17,000,000 |
Accounts Receivable and Other88
Accounts Receivable and Other Current Assets - Schedule of Accounts Receivable and Other Current Assets (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Receivables [Abstract] | ||
Trade accounts receivable | CAD 492 | CAD 507 |
Unbilled accounts receivable | 575 | 551 |
Allowance for doubtful accounts | (31) | (33) |
Income tax receivable | 8 | 26 |
Other | 87 | 76 |
Accounts receivable and other current assets | CAD 1,131 | CAD 1,127 |
Inventories (Details)
Inventories (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Public Utilities, Inventory [Line Items] | ||
Inventories | CAD 367 | CAD 372 |
Materials and supplies | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 238 | 244 |
Gas and fuel in storage | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 97 | 98 |
Coal inventory | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | CAD 32 | CAD 30 |
Regulatory Assets and Liabili90
Regulatory Assets and Liabilities - Schedule of Regulatory Assets and Liabilities (Details) CAD in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($) | Dec. 31, 2017CAD | Dec. 31, 2016CAD | |
Regulatory Assets [Line Items] | |||
Total regulatory assets | CAD 3,045 | CAD 2,933 | |
Less: current portion | (303) | (313) | |
Long-term regulatory assets | 2,742 | 2,620 | |
Remaining recovery period | 1 year | ||
Regulatory Liabilities [Line Items] | |||
Total regulatory liabilities | 3,446 | 2,183 | |
Less: current portion | (490) | (492) | |
Long-term regulatory liabilities | 2,956 | 1,691 | |
Remaining recovery period | 1 year | ||
Deferred income taxes (i) | |||
Regulatory Liabilities [Line Items] | |||
Total regulatory liabilities | 1,484 | 0 | |
Asset removal cost provision (xii) | |||
Regulatory Liabilities [Line Items] | |||
Total regulatory liabilities | 1,095 | 1,194 | |
Rate stabilization accounts (vi) | |||
Regulatory Liabilities [Line Items] | |||
Total regulatory liabilities | 254 | 230 | |
Less: current portion | (144) | (173) | |
ROE refund liability (xiii) | |||
Regulatory Liabilities [Line Items] | |||
Total regulatory liabilities | 182 | 346 | |
Remaining recovery period | 1 year | ||
Energy efficiency liability (xiv) | |||
Regulatory Liabilities [Line Items] | |||
Total regulatory liabilities | 82 | 49 | |
Renewable energy surcharge (xv) | |||
Regulatory Liabilities [Line Items] | |||
Total regulatory liabilities | 66 | 53 | |
Electric and gas moderator account (xvi) | |||
Regulatory Liabilities [Line Items] | |||
Total regulatory liabilities | 58 | 71 | |
Employee future benefits (ii) | |||
Regulatory Liabilities [Line Items] | |||
Total regulatory liabilities | 47 | 42 | |
Other | |||
Regulatory Liabilities [Line Items] | |||
Total regulatory liabilities | 178 | 198 | |
Deferred income taxes (i) | |||
Regulatory Assets [Line Items] | |||
Total regulatory assets | 1,403 | 1,260 | |
Employee future benefits (ii) | |||
Regulatory Assets [Line Items] | |||
Total regulatory assets | 510 | 576 | |
Deferred energy management costs (iii) | |||
Regulatory Assets [Line Items] | |||
Total regulatory assets | 200 | 178 | |
Deferred energy management costs (iii) | Minimum | |||
Regulatory Assets [Line Items] | |||
Remaining recovery period | 1 year | ||
Deferred energy management costs (iii) | Maximum | |||
Regulatory Assets [Line Items] | |||
Remaining recovery period | 10 years | ||
Generation early retirement costs (iv) | |||
Regulatory Assets [Line Items] | |||
Total regulatory assets | 0 | ||
Generation early retirement costs (iv) | Minimum | |||
Regulatory Assets [Line Items] | |||
Remaining recovery period | 11 years | ||
Generation early retirement costs (iv) | Maximum | |||
Regulatory Assets [Line Items] | |||
Remaining recovery period | 13 years | ||
Generation early retirement costs (iv) | UNS Energy | |||
Regulatory Assets [Line Items] | |||
Reclassification from capital assets to regulatory assets | $ 84 | 105 | |
Deferred lease costs (v) | |||
Regulatory Assets [Line Items] | |||
Total regulatory assets | 104 | 97 | |
Rate stabilization accounts (vi) | |||
Regulatory Assets [Line Items] | |||
Total regulatory assets | 95 | 183 | |
Less: current portion | (75) | (135) | |
Deferred operating overhead costs (vii) | |||
Regulatory Assets [Line Items] | |||
Total regulatory assets | 91 | 78 | |
Derivative instruments (viii) | Energy contracts subject to regulatory deferral | |||
Regulatory Assets [Line Items] | |||
Total regulatory assets | 87 | 19 | |
Regulatory Liabilities [Line Items] | |||
Total regulatory liabilities | 2 | 12 | |
Manufactured gas plant (MGP) site remediation deferral (ix) | |||
Regulatory Assets [Line Items] | |||
Total regulatory assets | 75 | 107 | |
Greenhouse gas reduction regulatory incentives (x) | |||
Regulatory Assets [Line Items] | |||
Total regulatory assets | 35 | 40 | |
Remaining recovery period | 10 years | ||
Other | |||
Regulatory Assets [Line Items] | |||
Total regulatory assets | CAD 340 | CAD 395 |
Regulatory Assets and Liabili91
Regulatory Assets and Liabilities - Narrative Assets (Details) CAD in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2017USD ($) | Dec. 31, 2017CAD | |
Regulatory Assets [Line Items] | ||||
Regulatory assets | CAD 2,933 | CAD 3,045 | ||
Regulatory asset, amortization period | 1 year | |||
Current regulatory assets | 313 | 303 | ||
Deferred income taxes (i) | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets not subject to a regulatory return | 596 | 754 | ||
Regulatory assets | 1,260 | 1,403 | ||
Employee future benefits (ii) | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets not subject to a regulatory return | 346 | 291 | ||
Regulatory assets | 576 | 510 | ||
Deferred energy management costs (iii) | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets not subject to a regulatory return | 42 | 41 | ||
Regulatory assets | 178 | 200 | ||
Deferred energy management costs (iii) | Minimum | ||||
Regulatory Assets [Line Items] | ||||
Regulatory asset, amortization period | 1 year | |||
Deferred energy management costs (iii) | Maximum | ||||
Regulatory Assets [Line Items] | ||||
Regulatory asset, amortization period | 10 years | |||
Generation early retirement costs (iv) | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | 0 | |||
Generation early retirement costs (iv) | UNS Energy | ||||
Regulatory Assets [Line Items] | ||||
Reclassification from capital assets to regulatory assets | $ 84 | 105 | ||
Generation early retirement costs (iv) | Minimum | ||||
Regulatory Assets [Line Items] | ||||
Regulatory asset, amortization period | 11 years | |||
Generation early retirement costs (iv) | Maximum | ||||
Regulatory Assets [Line Items] | ||||
Regulatory asset, amortization period | 13 years | |||
Deferred lease costs (v) | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | 97 | 104 | ||
Deferred lease costs (v) | FortisBC Electric | ||||
Regulatory Assets [Line Items] | ||||
Interest expense related to capital lease obligations | CAD 31 | 31 | ||
Depreciation expense related to assets under capital lease | 6 | 6 | ||
Capital lease costs recognized in energy supply costs and operating expenses | 7 | 7 | ||
Deferred lease costs (v) | FortisBC Electric | Energy supply costs | ||||
Regulatory Assets [Line Items] | ||||
Capital lease costs recognized in energy supply costs and operating expenses | 27 | 27 | ||
Deferred lease costs (v) | FortisBC Electric | Operating expenses | ||||
Regulatory Assets [Line Items] | ||||
Capital lease costs recognized in energy supply costs and operating expenses | CAD 3 | 3 | ||
Rate stabilization accounts (vi) | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets not subject to a regulatory return | 139 | 91 | ||
Regulatory assets | 183 | 95 | ||
Current regulatory assets | 135 | 75 | ||
Rate stabilization accounts (vi) | ITC | ||||
Regulatory Assets [Line Items] | ||||
Approved cost-based formula (years) | 1 year | |||
Regulatory asset, amortization period | 2 years | |||
Derivative instruments (viii) | UNS Energy and Central Hudson | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets not subject to a regulatory return | 6 | 38 | ||
Greenhouse gas reduction regulatory incentives (x) | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | 40 | 35 | ||
Regulatory asset, amortization period | 10 years | |||
Greenhouse gas reduction regulatory incentives (x) | FortisBC Energy | ||||
Regulatory Assets [Line Items] | ||||
Regulatory asset, amortization period | 10 years | |||
Approved to be recovered from customers in future rates | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | 296 | 306 | ||
Threshold amount | 40 | |||
Other regulatory assets not subject to regulatory return | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets not subject to a regulatory return | 217 | 145 | ||
Other | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | CAD 395 | CAD 340 |
Regulatory Assets and Liabili92
Regulatory Assets and Liabilities - Narrative Liabilities (Details) CAD in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | 16 Months Ended | |||
Jun. 30, 2015 | Dec. 31, 2017CAD | Feb. 28, 2015complaintcomplaint_period | Dec. 31, 2017USD ($) | Dec. 31, 2017CAD | Dec. 31, 2016CAD | |
Regulatory Liabilities [Line Items] | ||||||
Current regulatory liabilities | CAD 490 | CAD 492 | ||||
Regulatory liability | 3,446 | 2,183 | ||||
Recognition of a regulatory liability, related to U.S. Tax reform | CAD (1,500) | |||||
Deferred income taxes (i) | ||||||
Regulatory Liabilities [Line Items] | ||||||
Regulatory liabilities not subject to regulatory return | 1,481 | |||||
Regulatory liability | 1,484 | 0 | ||||
Deferred income taxes (i) | US | ||||||
Regulatory Liabilities [Line Items] | ||||||
Recognition of a regulatory liability, related to U.S. Tax reform | CAD 1,453 | |||||
Employee future benefits (ii) | ||||||
Regulatory Liabilities [Line Items] | ||||||
Regulatory liabilities not subject to regulatory return | 45 | 31 | ||||
Regulatory liability | 47 | 42 | ||||
Rate stabilization accounts (vi) | ||||||
Regulatory Liabilities [Line Items] | ||||||
Current regulatory liabilities | 144 | 173 | ||||
Regulatory liabilities not subject to regulatory return | 114 | 180 | ||||
Regulatory liability | 254 | 230 | ||||
ROE refund liability (xiii) | ||||||
Regulatory Liabilities [Line Items] | ||||||
Regulatory liability | 182 | 346 | ||||
ROE refund liability (xiii) | ITC | ||||||
Regulatory Liabilities [Line Items] | ||||||
Complaints (number) | complaint | 2 | |||||
Number of complaint periods | complaint_period | 2 | |||||
Complaint period | 15 months | |||||
ROE refund liability, second refund period | ITC | Minimum | ||||||
Regulatory Liabilities [Line Items] | ||||||
Regulatory liability | $ | $ 106 | |||||
ROE refund liability, second refund period | ITC | Maximum | ||||||
Regulatory Liabilities [Line Items] | ||||||
Regulatory liability | $ | 145 | |||||
ROE refund liability, second refund period | ITC | Current regulatory liabilities | ||||||
Regulatory Liabilities [Line Items] | ||||||
Regulatory liability | 145 | 182 | ||||
ROE refund liability, initial complaint | ITC | ||||||
Regulatory Liabilities [Line Items] | ||||||
Regulatory liability | $ 118 | 158 | ||||
Renewable energy surcharge (xv) | ||||||
Regulatory Liabilities [Line Items] | ||||||
Regulatory liability | CAD 66 | 53 | ||||
Renewable energy surcharge (xv) | UNS Energy | ||||||
Regulatory Liabilities [Line Items] | ||||||
Renewable energy target (at least) (percent) | 15.00% | 15.00% | ||||
Distributed generation requirement percentage (percent) | 30.00% | 30.00% | ||||
Electric and gas moderator account (xvi) | ||||||
Regulatory Liabilities [Line Items] | ||||||
Regulatory liability | CAD 58 | 71 | ||||
Electric and gas moderator account (xvi) | Central Hudson | ||||||
Regulatory Liabilities [Line Items] | ||||||
Approved rate (period) | 3 years | |||||
Approved refund to customers or reduction in future rates | ||||||
Regulatory Liabilities [Line Items] | ||||||
Regulatory liability | 173 | 190 | ||||
Other liability threshold amount | 40 | |||||
Other | ||||||
Regulatory Liabilities [Line Items] | ||||||
Regulatory liabilities not subject to regulatory return | 26 | 51 | ||||
Regulatory liability | CAD 178 | CAD 198 |
Other Assets - Schedule of Othe
Other Assets - Schedule of Other Assets (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Renewable Energy Credits (Note 8 (xv)) | CAD 62 | CAD 39 |
Other investments | 29 | 21 |
Deferred compensation plan assets | 24 | 24 |
Other | 109 | 94 |
Other assets | 480 | 406 |
Belize Electricity | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Equity investment | 73 | 78 |
Wataynikaneyap Partnership | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Equity investment | 22 | 3 |
Supplemental Employee Retirement Plan | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Plan assets, noncurrent | 130 | 115 |
Defined Benefit Pension Plans | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Plan assets, noncurrent | CAD 31 | CAD 32 |
Other Assets - Narrative (Detai
Other Assets - Narrative (Details) - Supplemental Employee Retirement Plan - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Schedule of Investments [Line Items] | ||
Plan assets, noncurrent | CAD 130 | CAD 115 |
ITC | Available-for-sale securities | ||
Schedule of Investments [Line Items] | ||
Plan assets, noncurrent | CAD 66 | CAD 56 |
Property, Plant And Equipment -
Property, Plant And Equipment - Schedule of Utility Capital Assets (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | CAD 40,249 | CAD 40,193 |
Accumulated Depreciation | (10,581) | (10,856) |
Net Book Value | 29,668 | 29,337 |
Electric Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 9,963 | 9,616 |
Accumulated Depreciation | (2,864) | (2,752) |
Net Book Value | 7,099 | 6,864 |
Gas Distribution | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 4,093 | 3,956 |
Accumulated Depreciation | (1,157) | (1,096) |
Net Book Value | 2,936 | 2,860 |
Electric Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 12,571 | 12,616 |
Accumulated Depreciation | (2,838) | (2,876) |
Net Book Value | 9,733 | 9,740 |
Gas Transmission | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 1,954 | 1,776 |
Accumulated Depreciation | (596) | (562) |
Net Book Value | 1,358 | 1,214 |
Generation | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 6,079 | 6,884 |
Accumulated Depreciation | (1,996) | (2,474) |
Net Book Value | 4,083 | 4,410 |
Other | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 3,608 | 3,497 |
Accumulated Depreciation | (1,130) | (1,096) |
Net Book Value | 2,478 | 2,401 |
Assets under construction | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 1,717 | 1,559 |
Accumulated Depreciation | 0 | 0 |
Net Book Value | 1,717 | 1,559 |
Land | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Cost | 264 | 289 |
Accumulated Depreciation | 0 | 0 |
Net Book Value | CAD 264 | CAD 289 |
Property, Plant And Equipment96
Property, Plant And Equipment - Narrative (Details) CAD in Millions | 12 Months Ended | |
Dec. 31, 2017CADkPakV | Dec. 31, 2016CAD | |
Regulated Operations [Abstract] | ||
Electric distribution capacity (kV) | kV | 69 | |
Gas distribution capacity (kPa) | kPa | 2,070 | |
Gas distribution capacity, hoop stress (percent) | 20.00% | |
Electric transmission capacity (kV) | kV | 69 | |
Gas transmission capacity, and higher (kPa) | kPa | 2,070 | |
Gas transmission capacity, hoop stress (percent) | 20.00% | |
Capital assets under capital lease | CAD | CAD 423 | CAD 539 |
Capital assets under capital lease accumulated depreciation | CAD | CAD 176 | CAD 231 |
Property, Plant And Equipment97
Property, Plant And Equipment - Schedule of Jointly Owned Utility Plants (Details) CAD in Millions | Dec. 31, 2017CAD |
Jointly Owned Facilities [Line Items] | |
Cost | CAD 1,778 |
Accumulated Depreciation | (624) |
Net Book Value | CAD 1,154 |
San Juan Unit 1 | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 50.00% |
Cost | CAD 351 |
Accumulated Depreciation | (104) |
Net Book Value | CAD 247 |
Four Corners Units 4 and 5 | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 7.00% |
Cost | CAD 210 |
Accumulated Depreciation | (98) |
Net Book Value | CAD 112 |
Luna Energy Facility | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 33.30% |
Cost | CAD 69 |
Accumulated Depreciation | (4) |
Net Book Value | CAD 65 |
Gila River Common Facilities | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 25.00% |
Cost | CAD 41 |
Accumulated Depreciation | (14) |
Net Book Value | CAD 27 |
Springerville Coal Handling Facilities | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 83.00% |
Cost | CAD 253 |
Accumulated Depreciation | (102) |
Net Book Value | 151 |
Transmission Facilities | |
Jointly Owned Facilities [Line Items] | |
Cost | 854 |
Accumulated Depreciation | (302) |
Net Book Value | CAD 552 |
Transmission Facilities | Minimum | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 1.00% |
Transmission Facilities | Maximum | |
Jointly Owned Facilities [Line Items] | |
Ownership (percent) | 80.00% |
Intangible Assets - Schedule of
Intangible Assets - Schedule of Intangible Assets (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | CAD 1,707 | CAD 1,622 |
Accumulated Amortization | (626) | (611) |
Net Book Value | 1,081 | 1,011 |
Land, transmission and water rights | ||
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | 743 | 700 |
Accumulated Amortization | (103) | (108) |
Net Book Value | 640 | 592 |
Assets under construction | ||
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | 63 | 46 |
Accumulated Amortization | 0 | 0 |
Net Book Value | 63 | 46 |
Computer software | ||
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | 784 | 748 |
Accumulated Amortization | (474) | (447) |
Net Book Value | 310 | 301 |
Other | ||
Finite-Lived and Indefinite Lived Intangible Assets [Line Items] | ||
Cost | 117 | 128 |
Accumulated Amortization | (49) | (56) |
Net Book Value | CAD 68 | CAD 72 |
Intangible Assets - Narrative (
Intangible Assets - Narrative (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Finite-Lived and Indefinite-lived Intangible Assets [Line Items] | ||
Cost not subject to amortization | CAD 1,707 | CAD 1,622 |
Amortization - intangible assets | 97 | 79 |
Amortization expense, next twelve months | 108 | |
Amortization expense, year two | 108 | |
Amortization expense, year three | 108 | |
Amortization expense, year four | 108 | |
Amortization expense, year five | 108 | |
Land, transmission and water rights | ||
Finite-Lived and Indefinite-lived Intangible Assets [Line Items] | ||
Cost not subject to amortization | CAD 150 | CAD 138 |
Goodwill (Details)
Goodwill (Details) - CAD | Oct. 01, 2017 | Dec. 31, 2017 | Dec. 31, 2017 | Dec. 31, 2016 |
Goodwill [Roll Forward] | ||||
Balance, beginning of year | CAD 12,364,000,000 | CAD 4,173,000,000 | ||
Foreign currency translation impacts | (714,000,000) | 58,000,000 | ||
Balance, end of year | CAD 11,644,000,000 | 11,644,000,000 | 12,364,000,000 | |
Goodwill impairment loss | CAD 0 | 0 | 0 | |
Fortis Turks and Caicos | ||||
Goodwill [Roll Forward] | ||||
Goodwill impairment loss | CAD 0 | |||
ITC | ||||
Goodwill [Roll Forward] | ||||
Acquisition of ITC (Note 25) | (6,000,000) | |||
Acquisition | 8,106,000,000 | |||
Aitken Creek | ||||
Goodwill [Roll Forward] | ||||
Acquisition | CAD 0 | CAD 27,000,000 |
Accounts Payable and Other C101
Accounts Payable and Other Current Liabilities (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Payables and Accruals [Abstract] | ||
Trade accounts payable | CAD 696 | CAD 554 |
Interest payable | 223 | 218 |
Customer and other deposits | 204 | 287 |
Dividends payable | 185 | 166 |
Employee compensation and benefits payable | 184 | 178 |
Accrued taxes other than income taxes | 178 | 168 |
Gas and fuel cost payable | 146 | 175 |
Fair value of derivative instruments (Note 28) | 71 | 28 |
MGP site remediation (Notes 8 (ix) and 16) | 35 | 21 |
Defined benefit pension and OPEB liabilities (Note 24) | 22 | 26 |
Other | 109 | 149 |
Accounts payable and other current liabilities | CAD 2,053 | CAD 1,970 |
Long-Term Debt - Schedule of Lo
Long-Term Debt - Schedule of Long-Term Debt (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||
Total long-term debt | CAD 21,535 | CAD 21,219 |
Less: Deferred financing costs and debt discounts | (139) | (151) |
Less: Current installments of long-term debt | (705) | (251) |
Long-term debt | CAD 20,691 | CAD 20,817 |
Credit facility | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 2.50% | 1.80% |
Less: Current installments of long-term debt | CAD (312) | CAD (61) |
Credit facility | Long-term Credit Facility Borrowings | ||
Debt Instrument [Line Items] | ||
Total long-term debt | 671 | CAD 973 |
REGULATED | ||
Debt Instrument [Line Items] | ||
Total long-term debt | 16,583 | |
REGULATED | Credit facility | Long-term Credit Facility Borrowings | ||
Debt Instrument [Line Items] | ||
Total long-term debt | CAD 465 | |
REGULATED | ITC | Secured | Fixed Rate Secured US First Mortgage Bonds | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 4.67% | 4.81% |
Total long-term debt | CAD 2,063 | CAD 1,994 |
REGULATED | ITC | Secured | Fixed Rate Secured US Senior Notes | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 4.19% | 4.19% |
Total long-term debt | CAD 596 | CAD 638 |
REGULATED | ITC | Unsecured | Fixed Rate Unsecured US Senior Notes | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 3.98% | 4.80% |
Total long-term debt | CAD 3,618 | CAD 3,160 |
REGULATED | ITC | Unsecured | 6.00% Unsecured US Shareholder Note | ||
Debt Instrument [Line Items] | ||
Stated interest rate (percent) | 6.00% | 6.00% |
Total long-term debt | CAD 250 | CAD 267 |
REGULATED | ITC | Unsecured | Variable Rate Unsecured US Term Loan Credit Agreement | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 2.03% | |
Total long-term debt | CAD 63 | CAD 0 |
REGULATED | UNS Energy | Unsecured | Fixed and Variable Rate Unsecured US Tax-Exempt Bonds | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 4.04% | 3.87% |
Total long-term debt | CAD 773 | CAD 827 |
REGULATED | UNS Energy | Unsecured | Fixed Rate Unsecured US Notes | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 4.26% | 4.26% |
Total long-term debt | CAD 1,411 | CAD 1,511 |
REGULATED | Central Hudson | Unsecured | Fixed and Variable Rate Unsecured US Promissory Notes | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 4.28% | 4.25% |
Total long-term debt | CAD 770 | CAD 768 |
REGULATED | FortisBC Energy | Unsecured | Fixed Rate Unsecured Debentures | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 5.13% | 5.24% |
Total long-term debt | CAD 2,395 | CAD 2,220 |
REGULATED | FortisAlberta | Unsecured | Fixed Rate Unsecured Debentures | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 4.70% | 4.82% |
Total long-term debt | CAD 2,035 | CAD 1,834 |
REGULATED | FortisBC Electric | Secured | Fixed Rate Secured Debentures | ||
Debt Instrument [Line Items] | ||
Stated interest rate (percent) | 8.80% | 8.80% |
Total long-term debt | CAD 25 | CAD 25 |
REGULATED | FortisBC Electric | Unsecured | Fixed Rate Unsecured Debentures | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 5.05% | 5.22% |
Total long-term debt | CAD 710 | CAD 635 |
REGULATED | Eastern Canadian | Secured | Fixed Rate Secured First Mortgage Sinking Fund Bonds | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 6.14% | 6.48% |
Total long-term debt | CAD 585 | CAD 516 |
REGULATED | Eastern Canadian | Secured | Fixed Rate Secured First Mortgage Bonds | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 6.19% | 6.19% |
Total long-term debt | CAD 195 | CAD 195 |
REGULATED | Eastern Canadian | Unsecured | Fixed Rate Unsecured Senior Notes | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 6.11% | 6.11% |
Total long-term debt | CAD 104 | CAD 104 |
REGULATED | Caribbean Electric | Unsecured | Fixed and Variable Rate Unsecured US Senior Loan Notes and Bonds | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 4.80% | 4.92% |
Total long-term debt | CAD 525 | CAD 499 |
NON-REGULATED | ||
Debt Instrument [Line Items] | ||
Total long-term debt | 4,952 | |
NON-REGULATED | Credit facility | Long-term Credit Facility Borrowings | ||
Debt Instrument [Line Items] | ||
Total long-term debt | CAD 206 | |
NON-REGULATED | Corporate | Unsecured | Fixed Rate Unsecured Debentures | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 6.50% | 6.50% |
Total long-term debt | CAD 200 | CAD 200 |
NON-REGULATED | Corporate | Unsecured | Fixed Rate Unsecured US Senior Notes and Promissory Notes | ||
Debt Instrument [Line Items] | ||
Weighted average rate (percent) | 3.41% | 3.43% |
Total long-term debt | CAD 4,046 | CAD 4,353 |
NON-REGULATED | Corporate | Unsecured | Fixed Rate 2.85% Senior Notes | ||
Debt Instrument [Line Items] | ||
Stated interest rate (percent) | 2.85% | 2.85% |
Total long-term debt | CAD 500 | CAD 500 |
Long-Term Debt - Narrative (Det
Long-Term Debt - Narrative (Details) CAD / shares in Units, shares in Millions, CAD in Millions | Mar. 01, 2017CADshares | Dec. 31, 2017USD ($) | Nov. 30, 2017USD ($) | Oct. 31, 2017CAD | Sep. 30, 2017CAD | Aug. 31, 2017USD ($) | Jun. 30, 2017CAD | May 31, 2017USD ($) | Apr. 30, 2017USD ($) | Mar. 31, 2017CAD | Dec. 31, 2017CADshares | Dec. 31, 2016CADshares | Dec. 31, 2017CAD | Mar. 31, 2017USD ($) | Mar. 31, 2017CAD / shares | Oct. 13, 2016CAD / shares |
Debt Instrument [Line Items] | ||||||||||||||||
Total long-term debt | CAD 21,219 | CAD 21,535 | ||||||||||||||
Maximum borrowing capacity | 5,976 | 4,952 | ||||||||||||||
Repayments under credit facilities | CAD 2,039 | 499 | ||||||||||||||
Credit facilities unused | 3,729 | 3,943 | ||||||||||||||
Common shares issued | CAD 500 | CAD 4,684 | ||||||||||||||
Share Price (CAD per share) | CAD / shares | CAD 40.96 | |||||||||||||||
Revolving credit facility | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Credit facilities unused | 1,100 | |||||||||||||||
REGULATED | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Total long-term debt | 16,583 | |||||||||||||||
Maximum borrowing capacity | 3,567 | |||||||||||||||
Credit facilities unused | 2,820 | |||||||||||||||
NON-REGULATED | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Total long-term debt | 4,952 | |||||||||||||||
Maximum borrowing capacity | 1,385 | |||||||||||||||
Credit facilities unused | 1,123 | |||||||||||||||
NON-REGULATED | Revolving credit facility | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | 1,300 | |||||||||||||||
Additional borrowing capacity | 500 | |||||||||||||||
NON-REGULATED | Bridge loan | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Repayments under credit facilities | CAD 500 | |||||||||||||||
Committed facilities with maturities ranging from 2019 through 2022 | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | 4,700 | |||||||||||||||
No one bank | Bank concentration risk | Credit facility | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Concentration risk percentage | 20.00% | |||||||||||||||
ITC | REGULATED | Commercial paper | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | $ | $ 400,000,000 | |||||||||||||||
Amounts outstanding | $ | 0 | |||||||||||||||
ITC | REGULATED | Revolving credit facility | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | $ | 900,000,000 | |||||||||||||||
Caribbean Utilities | REGULATED | Unsecured credit facility | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | $ | 50,000,000 | |||||||||||||||
Newfoundland Power Inc. | REGULATED | Revolving credit facility | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | 100 | |||||||||||||||
Newfoundland Power Inc. | REGULATED | Demand credit facility | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | 20 | |||||||||||||||
Central Hudson | REGULATED | Revolving credit facility | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | $ | 250,000,000 | |||||||||||||||
Central Hudson | REGULATED | Revolving credit facility | Maturing in July 2020 | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | $ | 50,000,000 | |||||||||||||||
Central Hudson | REGULATED | Uncommitted credit facility | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | $ | 40,000,000 | |||||||||||||||
FortisAlberta | REGULATED | Revolving credit facility | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | 250 | |||||||||||||||
FortisBC Energy | REGULATED | Revolving credit facility | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | 700 | |||||||||||||||
FortisBC Electric | REGULATED | Revolving credit facility | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | 150 | |||||||||||||||
FortisBC Electric | REGULATED | Demand overdraft | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | 10 | |||||||||||||||
UNS Energy | REGULATED | Revolving credit facility | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | $ | 500,000,000 | |||||||||||||||
Maritime Electric | REGULATED | Revolving credit facility | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | 50 | |||||||||||||||
Maritime Electric | REGULATED | Unsecured demand credit facility | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | 5 | |||||||||||||||
FortisOntario | REGULATED | Revolving credit facility | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | 40 | |||||||||||||||
Fortis Turks and Caicos | REGULATED | Demand credit facility | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | $ | 22,000,000 | |||||||||||||||
Fortis Turks and Caicos | REGULATED | Emergency standby loan | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | $ | $ 25,000,000 | |||||||||||||||
FHI | NON-REGULATED | Revolving credit facility | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Maximum borrowing capacity | 50 | |||||||||||||||
Unsecured | ITC | One year floating rate unsecured term loan credit agreements | REGULATED | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt term | 1 year | |||||||||||||||
Total long-term debt | $ | $ 200,000,000 | |||||||||||||||
Debt repaid | $ | $ 200,000,000 | |||||||||||||||
Unsecured | ITC | One year floating rate unsecured term loan credit agreements | REGULATED | LIBOR | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Variable rate (percent) | 0.90% | |||||||||||||||
Unsecured | ITC | Two year floating rate unsecured term loan credit agreements | REGULATED | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt term | 2 years | |||||||||||||||
Total long-term debt | $ | 50,000,000 | |||||||||||||||
Unsecured | ITC | Two year floating rate unsecured term loan credit agreements | REGULATED | LIBOR | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Variable rate (percent) | 0.65% | |||||||||||||||
Unsecured | ITC | Five year 2.70% unsecured notes | REGULATED | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt term | 5 years | |||||||||||||||
Face value | $ | $ 500,000,000 | |||||||||||||||
Stated interest rate (percent) | 2.70% | |||||||||||||||
Unsecured | ITC | Ten year 3.35% unsecured notes | REGULATED | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt term | 10 years | |||||||||||||||
Face value | $ | $ 500,000,000 | |||||||||||||||
Stated interest rate (percent) | 3.35% | |||||||||||||||
Unsecured | Caribbean Utilities | Unsecured notes | REGULATED | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Face value | $ | $ 60,000,000 | |||||||||||||||
Unsecured | Caribbean Utilities | 15 year 3.90% unsecured notes | REGULATED | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt term | 15 years | |||||||||||||||
Face value | $ | $ 40,000,000 | |||||||||||||||
Stated interest rate (percent) | 3.90% | |||||||||||||||
Unsecured | Caribbean Utilities | 30 year 4.64% unsecured notes | REGULATED | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt term | 30 years | |||||||||||||||
Face value | $ | $ 20,000,000 | |||||||||||||||
Stated interest rate (percent) | 4.64% | |||||||||||||||
Unsecured | Central Hudson | 30 year 4.05% unsecured notes | REGULATED | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt term | 30 years | |||||||||||||||
Face value | $ | $ 30,000,000 | |||||||||||||||
Stated interest rate (percent) | 4.05% | |||||||||||||||
Unsecured | Central Hudson | 40 year 4.20% unsecured notes | REGULATED | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt term | 40 years | |||||||||||||||
Face value | $ | $ 30,000,000 | |||||||||||||||
Stated interest rate (percent) | 4.20% | |||||||||||||||
Unsecured | FortisAlberta | 30 year 3.67% unsecured debentures | REGULATED | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt term | 30 years | |||||||||||||||
Face value | CAD 200 | |||||||||||||||
Stated interest rate (percent) | 3.67% | |||||||||||||||
Unsecured | FortisBC Energy | 30 year 3.69% unsecured debentures | REGULATED | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt term | 30 years | |||||||||||||||
Face value | CAD 175 | |||||||||||||||
Stated interest rate (percent) | 3.69% | |||||||||||||||
Unsecured | FortisBC Electric | 32 year 3.62% unsecured debentures | REGULATED | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt term | 32 years | |||||||||||||||
Face value | CAD 75 | |||||||||||||||
Stated interest rate (percent) | 3.62% | 3.62% | ||||||||||||||
Secured | ITC | 30 year 4.16% secured first mortgage bonds | REGULATED | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt term | 30 years | |||||||||||||||
Face value | $ | $ 200,000,000 | |||||||||||||||
Stated interest rate (percent) | 4.16% | |||||||||||||||
Secured | Newfoundland Power Inc. | 40 year 3.815% first mortgage sinking fund bonds | REGULATED | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt term | 40 years | |||||||||||||||
Face value | CAD 75 | |||||||||||||||
Stated interest rate (percent) | 3.815% | |||||||||||||||
Maximum | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Debt to capital restriction on issuance of new debt (percent) | 0.7 | 0.7 | ||||||||||||||
Debt to capital restriction on dividends (percent) | 0.75 | 0.75 | ||||||||||||||
Common Shares | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Common shares issued (shares) | shares | 12.2 | 114.4 | ||||||||||||||
Common shares issued | CAD 500 | CAD 4,684 | ||||||||||||||
Private Offering | Common Shares | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||
Common shares issued (shares) | shares | 12.2 | |||||||||||||||
Common shares issued | CAD 500 | |||||||||||||||
Share Price (CAD per share) | CAD / shares | CAD 41 |
Long-Term Debt - Schedule of Cr
Long-Term Debt - Schedule of Credit Facilities (Details) - CAD | Dec. 31, 2017 | Dec. 31, 2016 |
Line of Credit Facility [Line Items] | ||
Total credit facilities | CAD 4,952,000,000 | CAD 5,976,000,000 |
Credit facilities utilized: | ||
Short-term borrowings | (209,000,000) | (1,155,000,000) |
Long-term debt (including current portion) | (21,535,000,000) | (21,219,000,000) |
Letters of credit outstanding | (129,000,000) | (119,000,000) |
Credit facilities unused | 3,943,000,000 | 3,729,000,000 |
Current installments of long-term debt | CAD 705,000,000 | CAD 251,000,000 |
Credit facility | ||
Credit facilities utilized: | ||
Short-term debt weighted average interest rate (percent) | 1.80% | 1.70% |
Current installments of long-term debt | CAD 312,000,000 | CAD 61,000,000 |
Long-term debt weighted average interest rate (percent) | 2.50% | 1.80% |
Long-term Credit Facility Borrowings | Credit facility | ||
Credit facilities utilized: | ||
Long-term debt (including current portion) | CAD (671,000,000) | CAD (973,000,000) |
Credit facility | ||
Credit facilities utilized: | ||
Short-term borrowings | (209,000,000) | (1,155,000,000) |
Credit facility | Commercial paper | ||
Credit facilities utilized: | ||
Short-term borrowings | 0 | CAD (195,000,000) |
REGULATED | ||
Line of Credit Facility [Line Items] | ||
Total credit facilities | 3,567,000,000 | |
Credit facilities utilized: | ||
Long-term debt (including current portion) | (16,583,000,000) | |
Letters of credit outstanding | (73,000,000) | |
Credit facilities unused | 2,820,000,000 | |
REGULATED | Long-term Credit Facility Borrowings | Credit facility | ||
Credit facilities utilized: | ||
Long-term debt (including current portion) | (465,000,000) | |
REGULATED | Credit facility | ||
Credit facilities utilized: | ||
Short-term borrowings | (209,000,000) | |
NON-REGULATED | ||
Line of Credit Facility [Line Items] | ||
Total credit facilities | 1,385,000,000 | |
Credit facilities utilized: | ||
Long-term debt (including current portion) | (4,952,000,000) | |
Letters of credit outstanding | (56,000,000) | |
Credit facilities unused | 1,123,000,000 | |
NON-REGULATED | Long-term Credit Facility Borrowings | Credit facility | ||
Credit facilities utilized: | ||
Long-term debt (including current portion) | (206,000,000) | |
NON-REGULATED | Credit facility | ||
Credit facilities utilized: | ||
Short-term borrowings | CAD 0 |
Long-Term Debt - Repayment of L
Long-Term Debt - Repayment of Long-Term Debt (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||
Due within 1 year | CAD 705 | |
Due in year 2 | 282 | |
Due in year 3 | 673 | |
Due in year 4 | 1,219 | |
Due in year 5 | 1,060 | |
Thereafter | 17,596 | |
Long-term Debt | 21,535 | CAD 21,219 |
REGULATED | ||
Debt Instrument [Line Items] | ||
Due within 1 year | 499 | |
Due in year 2 | 169 | |
Due in year 3 | 516 | |
Due in year 4 | 435 | |
Due in year 5 | 1,060 | |
Thereafter | 13,904 | |
Long-term Debt | 16,583 | |
Corporate and Other | ||
Debt Instrument [Line Items] | ||
Due within 1 year | 206 | |
Due in year 2 | 113 | |
Due in year 3 | 157 | |
Due in year 4 | 784 | |
Due in year 5 | 0 | |
Thereafter | 3,692 | |
Long-term Debt | CAD 4,952 |
Capital Lease and Finance Ob106
Capital Lease and Finance Obligations - UNS Energy (Details) CAD in Millions, $ in Millions | 12 Months Ended | |||||
Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2017USD ($)lease | Dec. 31, 2017CADlease | Dec. 31, 2016USD ($) | Dec. 31, 2016CAD | |
Capital Leased Assets [Line Items] | ||||||
Reduction of current lease obligation | CAD (47) | CAD (76) | ||||
Springerville Common Facilities | UNS Energy | ||||||
Capital Leased Assets [Line Items] | ||||||
Total number of capital lease obligations | lease | 3 | 3 | ||||
Interest expense related to capital lease obligations | CAD 4 | CAD 4 | ||||
Depreciation expense related to assets under capital lease | CAD 8 | CAD 7 | ||||
Springerville Common Facilities | UNS Energy | Capital Leases | ||||||
Capital Leased Assets [Line Items] | ||||||
Stated interest rate (percent) | 5.08% | 5.08% | ||||
Springerville Common Facilities | UNS Energy | Interest rate swaps | ||||||
Capital Leased Assets [Line Items] | ||||||
Amortized principal balance | $ | $ 23 | $ 31 | ||||
Springerville Common Facilities | UNS Energy | Interest rate swaps | Capital Leases | LIBOR | ||||||
Capital Leased Assets [Line Items] | ||||||
Variable rate (percent) | 1.88% | 1.88% | ||||
Springerville Common Facilities lease 1 | UNS Energy | ||||||
Capital Leased Assets [Line Items] | ||||||
Fixed-price purchase provision | $ | $ 38 | |||||
Capital lease interest purchased | 17.80% | 17.80% | ||||
Fixed purchase price | CAD 49 | |||||
Total ownership of the assets (percent) | 67.80% | 67.80% | ||||
Reduction of current lease obligation | CAD 46 | |||||
Springerville Common Facilities, leases expiring 2021 | UNS Energy | ||||||
Capital Leased Assets [Line Items] | ||||||
Fixed-price purchase provision | $ | $ 68 | |||||
Number of remaining capital lease obligations | lease | 2 | 2 | ||||
Springerville Common Facilities, leases expiring 2021 | UNS Energy | Minimum | ||||||
Capital Leased Assets [Line Items] | ||||||
Lease renewal term | 2 years |
Capital Lease and Finance Ob107
Capital Lease and Finance Obligations - FortisBC Electric (Details) - FortisBC Electric - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Brilliant Plant | ||
Capital Leased Assets [Line Items] | ||
Concentration purchased output percentage | 94.00% | |
Capital lease costs recognized in energy supply costs and operating expenses | CAD 27 | CAD 27 |
Brilliant Plant | Capital Leases | ||
Capital Leased Assets [Line Items] | ||
Stated interest rate (percent) | 5.00% | |
BTS | ||
Capital Leased Assets [Line Items] | ||
Capital lease costs recognized in energy supply costs and operating expenses | CAD 3 | CAD 3 |
BTS | Capital Leases | ||
Capital Leased Assets [Line Items] | ||
Stated interest rate (percent) | 9.00% |
Capital Lease and Finance Ob108
Capital Lease and Finance Obligations - Finance Obligations (Details) - FortisBC Energy - Natural gas distribution assets | 12 Months Ended |
Dec. 31, 2017 | |
Capital Leased Assets [Line Items] | |
Lease term (years) | 35 years |
Contract termination option (years) | 17 years |
Capital Leases | Minimum | |
Capital Leased Assets [Line Items] | |
Stated interest rate (percent) | 6.86% |
Capital Leases | Maximum | |
Capital Leased Assets [Line Items] | |
Stated interest rate (percent) | 8.46% |
Capital Lease and Finance Ob109
Capital Lease and Finance Obligations - Repayment of Capital Lease and Finance Obligations (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Year | ||
Due within 1 year | CAD 90 | |
Due in year 2 | 74 | |
Due in year 3 | 73 | |
Due in year 4 | 78 | |
Due in year 5 | 49 | |
Thereafter | 1,950 | |
Total | 2,314 | |
Less: Amounts representing imputed interest and executory costs on capital lease and finance obligations | (1,853) | |
Total capital lease and finance obligations | 461 | |
Less: Current installments | (47) | CAD (76) |
Capital lease and finance obligations, noncurrent portion | 414 | CAD 460 |
Capital Leases | ||
Year | ||
Due within 1 year | 58 | |
Due in year 2 | 59 | |
Due in year 3 | 68 | |
Due in year 4 | 46 | |
Due in year 5 | 46 | |
Thereafter | 1,950 | |
Total | 2,227 | |
Finance Obligations | ||
Year | ||
Due within 1 year | 32 | |
Due in year 2 | 15 | |
Due in year 3 | 5 | |
Due in year 4 | 32 | |
Due in year 5 | 3 | |
Thereafter | 0 | |
Total | CAD 87 |
Other Liabilities - Schedule of
Other Liabilities - Schedule of Other Liabilities (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Other Liabilities Disclosure [Abstract] | ||
Defined benefit pension plan liabilities (Note 24) | CAD 393 | CAD 410 |
OPEB plan liabilities (Note 24) | 381 | 411 |
Asset retirement obligations | 71 | 58 |
Customer and other deposits | 67 | 69 |
Debt Instrument [Line Items] | ||
Mine reclamation and retiree health care liabilities | 40 | 40 |
DSU, PSU and RSU liabilities (Note 21) | 39 | 24 |
Fair value of derivative instruments (Note 28) | 37 | 10 |
MGP site remediation (Notes 8 (ix) and 13) | 34 | 77 |
Deferred compensation plan liabilities (Note 9) | 28 | 27 |
Other | 57 | 94 |
Other liabilities | 1,210 | 1,279 |
Waneta Partnership | Waneta Partnership promissory note | ||
Debt Instrument [Line Items] | ||
Waneta Partnership promissory note (Notes 28, 29 and 30) | CAD 63 | CAD 59 |
Other Liabilities - Narrative (
Other Liabilities - Narrative (Details) $ in Millions | Dec. 31, 2017USD ($)mine | Dec. 31, 2017CADmine | Dec. 31, 2016USD ($) | Dec. 31, 2016CAD |
Debt Instrument [Line Items] | ||||
Mine reclamation liability | CAD 40,000,000 | CAD 40,000,000 | ||
Waneta Partnership | Promissory note | ||||
Debt Instrument [Line Items] | ||||
Face value | 72,000,000 | |||
Waneta discounted net present value on promissory note | 63,000,000 | 59,000,000 | ||
TEP | ||||
Debt Instrument [Line Items] | ||||
Expected reclamation costs | $ | $ 61 | $ 61 | ||
Mine reclamation liability | $ 34 | CAD 43,000,000 | $ 25 | CAD 35,000,000 |
TEP | Coal mine reclamation | ||||
Debt Instrument [Line Items] | ||||
Number of mines | mine | 3 | 3 | ||
Central Hudson | ||||
Debt Instrument [Line Items] | ||||
Remediation cost obligation | $ 55 | CAD 69,000,000 | ||
Central Hudson | Accounts payable and other current liabilities | ||||
Debt Instrument [Line Items] | ||||
Remediation cost obligation | $ 28 | CAD 35,000,000 |
Earnings Per Common Share (Deta
Earnings Per Common Share (Details) - CAD CAD / shares in Units, shares in Millions, CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Net Earnings to Common Shareholders | ||
Basic EPS | CAD 963 | CAD 585 |
Effect of potential dilutive securities: | ||
Stock Options | 0 | 0 |
Preference Shares | 0 | 7 |
Diluted EPS | CAD 963 | CAD 592 |
Weighted Average Shares | ||
Basic EPS (shares) | 415.5 | 308.9 |
Effect of potential dilutive securities: | ||
Stock Options (shares) | 0.7 | 0.7 |
Preference Shares (shares) | 0 | 3.8 |
Diluted EPS (shares) | 416.2 | 313.4 |
EPS | ||
Basic (CAD per share) | CAD 2.32 | CAD 1.89 |
Diluted (CAD per share) | CAD 2.31 | CAD 1.89 |
Preference Shares - Issued and
Preference Shares - Issued and Outstanding (Details) - CAD shares in Thousands, CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Class of Stock [Line Items] | ||
Preferred stock shares issued (shares) | 66,200 | 66,200 |
Preference stock issued | CAD 1,623 | CAD 1,623 |
Preferred stock outstanding (shares) | 66,200 | 66,200 |
Preferred stock outstanding | CAD 1,623 | CAD 1,623 |
Series F | ||
Class of Stock [Line Items] | ||
Preferred stock shares issued (shares) | 5,000 | 5,000 |
Preference stock issued | CAD 122 | CAD 122 |
Preferred stock outstanding (shares) | 5,000 | 5,000 |
Preferred stock outstanding | CAD 122 | CAD 122 |
Series G | ||
Class of Stock [Line Items] | ||
Preferred stock shares issued (shares) | 9,200 | 9,200 |
Preference stock issued | CAD 225 | CAD 225 |
Preferred stock outstanding (shares) | 9,200 | 9,200 |
Preferred stock outstanding | CAD 225 | CAD 225 |
Series H | ||
Class of Stock [Line Items] | ||
Preferred stock shares issued (shares) | 7,025 | 7,025 |
Preference stock issued | CAD 172 | CAD 172 |
Preferred stock outstanding (shares) | 7,025 | 7,025 |
Preferred stock outstanding | CAD 172 | CAD 172 |
Series I | ||
Class of Stock [Line Items] | ||
Preferred stock shares issued (shares) | 2,975 | 2,975 |
Preference stock issued | CAD 73 | CAD 73 |
Preferred stock outstanding (shares) | 2,975 | 2,975 |
Preferred stock outstanding | CAD 73 | CAD 73 |
Series J | ||
Class of Stock [Line Items] | ||
Preferred stock shares issued (shares) | 8,000 | 8,000 |
Preference stock issued | CAD 196 | CAD 196 |
Preferred stock outstanding (shares) | 8,000 | 8,000 |
Preferred stock outstanding | CAD 196 | CAD 196 |
Series K | ||
Class of Stock [Line Items] | ||
Preferred stock shares issued (shares) | 10,000 | 10,000 |
Preference stock issued | CAD 244 | CAD 244 |
Preferred stock outstanding (shares) | 10,000 | 10,000 |
Preferred stock outstanding | CAD 244 | CAD 244 |
Series M | ||
Class of Stock [Line Items] | ||
Preferred stock shares issued (shares) | 24,000 | 24,000 |
Preference stock issued | CAD 591 | CAD 591 |
Preferred stock outstanding (shares) | 24,000 | 24,000 |
Preferred stock outstanding | CAD 591 | CAD 591 |
Preference Shares - Narrative (
Preference Shares - Narrative (Details) - CAD CAD / shares in Units, CAD in Millions | 1 Months Ended | 12 Months Ended | |
Sep. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | |
Class of Stock [Line Items] | |||
Amount redeemed | CAD 0 | CAD 200 | |
Series E | |||
Class of Stock [Line Items] | |||
Amount redeemed | CAD 200 | ||
Dividend rate (percent) | 4.90% | ||
Redemption price including accrued and unpaid dividends (CAD per share) | CAD 25.3063 | ||
Preference shares, redemption price (CAD per share) | CAD 25 | ||
Issuance cost recognized, after tax | CAD 3 |
Preference Shares - Characteris
Preference Shares - Characteristics of Preference Shares (Details) | 12 Months Ended | |||
Dec. 31, 2017CAD / shares | Dec. 01, 2021CAD / shares | Jun. 01, 2020CAD / shares | Dec. 01, 2018CAD / shares | |
Class of Stock [Line Items] | ||||
Preferred shares rate dividend term | 5 years | |||
Series F | ||||
Class of Stock [Line Items] | ||||
Initial yield (percent) | 4.90% | |||
Annual Dividend (CAD per share) | CAD 1.2250 | |||
Reset Dividend Yield (percent) | 0.00% | |||
Redemption price (CAD per share) | CAD 25 | |||
Series J | ||||
Class of Stock [Line Items] | ||||
Initial yield (percent) | 4.75% | |||
Annual Dividend (CAD per share) | CAD 1.1875 | |||
Reset Dividend Yield (percent) | 0.00% | |||
Redemption price (CAD per share) | CAD 26 | |||
Series J | Forecast | ||||
Class of Stock [Line Items] | ||||
Redemption price (CAD per share) | CAD 25 | CAD 26 | ||
Preferred stock redemption price per share annual decrease (CAD per share) | CAD 0.25 | |||
Series G | ||||
Class of Stock [Line Items] | ||||
Initial yield (percent) | 5.25% | |||
Annual Dividend (CAD per share) | CAD 0.9708 | |||
Reset Dividend Yield (percent) | 2.13% | |||
Redemption price (CAD per share) | CAD 25 | |||
Series H | ||||
Class of Stock [Line Items] | ||||
Initial yield (percent) | 4.25% | |||
Annual Dividend (CAD per share) | CAD 0.6250 | |||
Reset Dividend Yield (percent) | 1.45% | |||
Redemption price (CAD per share) | CAD 25 | |||
Preferred shares exchange ratio | 1 | |||
Series K | ||||
Class of Stock [Line Items] | ||||
Initial yield (percent) | 4.00% | |||
Annual Dividend (CAD per share) | CAD 1 | |||
Reset Dividend Yield (percent) | 2.05% | |||
Redemption price (CAD per share) | CAD 25 | |||
Preferred shares exchange ratio | 1 | |||
Series M | ||||
Class of Stock [Line Items] | ||||
Initial yield (percent) | 4.10% | |||
Annual Dividend (CAD per share) | CAD 1.0250 | |||
Reset Dividend Yield (percent) | 2.48% | |||
Redemption price (CAD per share) | CAD 25 | |||
Preferred shares exchange ratio | 1 | |||
Series I | ||||
Class of Stock [Line Items] | ||||
Initial yield (percent) | 2.10% | |||
Annual Dividend (CAD per share) | CAD 0 | |||
Reset Dividend Yield (percent) | 1.45% | |||
Redemption price (CAD per share) | CAD 25.50 | |||
Preferred shares exchange ratio | 1 | |||
Series I | Forecast | ||||
Class of Stock [Line Items] | ||||
Redemption price (CAD per share) | CAD 25 | |||
Series L | ||||
Class of Stock [Line Items] | ||||
Initial yield (percent) | 0.00% | |||
Annual Dividend (CAD per share) | CAD 0 | |||
Reset Dividend Yield (percent) | 2.05% | |||
Redemption price (CAD per share) | CAD 0 | |||
Preferred shares exchange ratio | 1 | |||
Series N | ||||
Class of Stock [Line Items] | ||||
Initial yield (percent) | 0.00% | |||
Annual Dividend (CAD per share) | CAD 0 | |||
Reset Dividend Yield (percent) | 2.48% | |||
Redemption price (CAD per share) | CAD 0 | |||
Preferred shares exchange ratio | 1 | |||
Fixed rate reset | ||||
Class of Stock [Line Items] | ||||
Annual Dividend (CAD per share) | CAD 25 |
Accumulated Other Comprehens116
Accumulated Other Comprehensive Income (Details) - CAD CAD in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Accumulated other comprehensive income | |||
Beginning balance | CAD 14,597 | ||
Other comprehensive loss | (684) | CAD (46) | |
Ending balance | 15,003 | 14,597 | |
Unrealized foreign currency translation gains (losses) on net investments in foreign operations | |||
Accumulated other comprehensive income | |||
Accumulated other comprehensive income (loss), before tax, opening balance | 1,227 | 1,281 | |
Other comprehensive income (loss), before tax | (980) | (54) | |
Accumulated other comprehensive income (loss), before tax, ending balance | 247 | 1,227 | |
(Losses) gains on hedges of net investments in foreign operations | |||
Accumulated other comprehensive income | |||
Accumulated other comprehensive income (loss), before tax, opening balance | (472) | (476) | |
Other comprehensive income (loss), before tax | 300 | 4 | |
Accumulated other comprehensive income (loss), before tax, ending balance | (172) | (472) | |
Net unrealized foreign currency translation gains (losses) | |||
Accumulated other comprehensive income | |||
Beginning balance | 756 | 806 | |
Income tax recovery (expense), opening balance | (1) | 1 | CAD 1 |
Other comprehensive income (loss), tax recovery (expense) | (2) | 0 | |
Other comprehensive loss | (682) | (50) | |
Ending balance | 74 | 756 | |
Realized gain on available-for-sale investment | |||
Accumulated other comprehensive income | |||
Beginning balance | 0 | (2) | |
Other comprehensive loss | 2 | ||
Ending balance | 0 | ||
Cash flow hedges (Note 28) | |||
Accumulated other comprehensive income | |||
Beginning balance | 5 | 2 | |
Accumulated other comprehensive income (loss), before tax, opening balance | 8 | 3 | |
Income tax recovery (expense), opening balance | (3) | (3) | (1) |
Other comprehensive income (loss), before tax | (2) | 5 | |
Other comprehensive income (loss), tax recovery (expense) | 0 | (2) | |
Other comprehensive loss | 2 | 3 | |
Accumulated other comprehensive income (loss), before tax, ending balance | 6 | 8 | |
Ending balance | 7 | 5 | |
Cash flow hedges (Note 28) | Reclassification | |||
Accumulated other comprehensive income | |||
Accumulated other comprehensive income (loss), before tax, opening balance | 0 | ||
Other comprehensive income (loss), before tax | 4 | ||
Accumulated other comprehensive income (loss), before tax, ending balance | 4 | 0 | |
Unamortized net actuarial losses | |||
Accumulated other comprehensive income | |||
Accumulated other comprehensive income (loss), before tax, opening balance | (19) | (20) | |
Other comprehensive income (loss), before tax | (3) | 1 | |
Accumulated other comprehensive income (loss), before tax, ending balance | (22) | (19) | |
Unamortized past service costs | |||
Accumulated other comprehensive income | |||
Accumulated other comprehensive income (loss), before tax, opening balance | (3) | (1) | |
Other comprehensive income (loss), before tax | (1) | (2) | |
Accumulated other comprehensive income (loss), before tax, ending balance | (4) | (3) | |
Unrealized employee future benefits (losses) gains | |||
Accumulated other comprehensive income | |||
Beginning balance | (16) | (15) | |
Income tax recovery (expense), opening balance | 6 | 6 | CAD 6 |
Other comprehensive income (loss), tax recovery (expense) | 0 | 0 | |
Other comprehensive loss | (4) | (1) | |
Ending balance | (20) | (16) | |
Accumulated other comprehensive income | |||
Accumulated other comprehensive income | |||
Beginning balance | 745 | 791 | |
Ending balance | CAD 61 | CAD 745 |
Non-Controlling Interests (Deta
Non-Controlling Interests (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Noncontrolling Interest [Line Items] | ||
Non-controlling interests | CAD 1,746 | CAD 1,853 |
ITC | ||
Noncontrolling Interest [Line Items] | ||
Non-controlling interests | 1,290 | 1,385 |
Waneta Partnership | ||
Noncontrolling Interest [Line Items] | ||
Non-controlling interests | 322 | 330 |
Caribbean Utilities | ||
Noncontrolling Interest [Line Items] | ||
Non-controlling interests | 118 | 122 |
Other | ||
Noncontrolling Interest [Line Items] | ||
Non-controlling interests | CAD 16 | CAD 16 |
Stock-based Compensation Pla118
Stock-based Compensation Plans - Stock Options (Details) - Options | 12 Months Ended |
Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Award vesting period | 4 years |
2006 Plan | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Exercisable period | 7 years |
Expiration period after termination, death or retirement | 3 years |
Award vesting period | 4 years |
2012 Plan | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Exercisable period | 10 years |
Expiration period after termination, death or retirement | 3 years |
Award vesting period | 4 years |
Stock-based Compensation Pla119
Stock-based Compensation Plans - Stock Options, Fair Value Assumptions (Details) - CAD / shares | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Options granted (shares) | 774,924 | |
Exercise price (CAD per share) | CAD 42.36 | |
Grant date fair value (CAD per share) | CAD 3.22 | |
Options | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Options granted (shares) | 774,924 | 788,188 |
Exercise price (CAD per share) | CAD 42.36 | CAD 37.30 |
Grant date fair value (CAD per share) | CAD 3.22 | CAD 2.41 |
Assumptions: | ||
Dividend yield (percent) | 3.80% | 3.90% |
Expected volatility (percent) | 16.10% | 16.40% |
Risk-free interest rate | 1.20% | 0.70% |
Weighted average expected life (years) | 5 years 7 months 6 days | 5 years 6 months |
Volume weighted average share price (period) | 5 days |
Stock-based Compensation Pla120
Stock-based Compensation Plans - Stock Option Activity (Details) - CAD CAD / shares in Units, CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Total Options, Number of Options | ||
Options outstanding, beginning balance (shares) | 4,160,192 | |
Granted (shares) | 774,924 | |
Exercised (shares) | (1,217,029) | |
Cancelled/Forfeited (shares) | (15,793) | |
Options outstanding, ending balance (shares) | 3,702,294 | 4,160,192 |
Options vested, number of options (shares) | 1,889,975 | |
Total Options, Weighted Average Exercise Price | ||
Options outstanding, beginning balance (CAD per share) | CAD 34.45 | |
Granted (CAD per share) | 42.36 | |
Exercised (CAD per share) | 32.73 | |
Cancelled/Forfeited (CAD per share) | 40.27 | |
Options outstanding, ending balance (CAD per share) | 36.65 | CAD 34.45 |
Options vested, weighted average exercise price (CAD per share) | CAD 34.25 | |
Non-vested Options, Number of Options | ||
Options outstanding, beginning balance (shares) | 1,815,018 | |
Granted (shares) | 774,924 | |
Vested (shares) | (761,830) | |
Cancelled/Forfeited (shares) | (15,793) | |
Options outstanding, ending balance (shares) | 1,812,319 | 1,815,018 |
Non-vested Options, Weighted Average Grant Date Fair Value | ||
Options outstanding, beginning balance (CAD per share) | CAD 2.78 | |
Granted (CAD per share) | 3.22 | |
Vested (CAD per share) | 3.03 | |
Cancelled/Forfeited (CAD per share) | 2.88 | |
Options outstanding, ending balance (CAD per share) | CAD 2.86 | CAD 2.78 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Unrecognized compensation expense | CAD 5 | |
Weighted average remaining term of vested options | 6 years | |
Aggregate intrinsic value | CAD 22 | |
Options | ||
Total Options, Number of Options | ||
Granted (shares) | 774,924 | 788,188 |
Total Options, Weighted Average Exercise Price | ||
Granted (CAD per share) | CAD 42.36 | CAD 37.30 |
Non-vested Options, Number of Options | ||
Granted (shares) | 774,924 | 788,188 |
Non-vested Options, Weighted Average Grant Date Fair Value | ||
Granted (CAD per share) | CAD 3.22 | CAD 2.41 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Remaining weighted average period to recognize compensation expense (years) | 3 years |
Stock-based Compensation Pla121
Stock-based Compensation Plans - Schedule of Additional Stock Option Information (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Stock options exercised: | ||
Cash received for exercise price | CAD 40 | CAD 28 |
Intrinsic value realized by employees | 15 | 15 |
Fair value of options that vested | 2 | 3 |
Options | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock option expense recognized | CAD 3 | CAD 2 |
Stock-based Compensation Pla122
Stock-based Compensation Plans - Directors' DSU Plan (Details) CAD / shares in Units, CAD in Millions | 12 Months Ended | |
Dec. 31, 2017CADCAD / sharesshares | Dec. 31, 2016CADCAD / sharesshares | |
Number of DSUs | ||
Stock unit liabilities | CAD | CAD 39 | CAD 24 |
DSUs | ||
Number of DSUs | ||
Volume weighted average share price (period) | 5 days | |
Director | DSUs | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Unit with underlying value equivalent to common shares | 1 | |
Number of DSUs | ||
DSUs outstanding, beginning of year (shares) | 199,411 | 167,762 |
Granted (shares) | 31,453 | 30,165 |
Granted - notional dividends reinvested (shares) | 7,294 | 6,994 |
DSUs paid out (shares) | (53,363) | (5,510) |
DSUs outstanding, end of year (shares) | 184,795 | 199,411 |
Non-employee expense recognized in earnings | CAD | CAD 3 | CAD 2 |
Awards paid (CAD per share) | CAD / shares | CAD 45.37 | |
Cash paid for award | CAD | CAD 2 | |
Volume weighted average share price (period) | 5 days | |
Volume weighted average price, share price (in dollars per share) | CAD / shares | CAD 46.01 | CAD 41.46 |
Stock unit liabilities | CAD | CAD 9 | CAD 8 |
Stock-based Compensation Pla123
Stock-based Compensation Plans - Schedule of PSU and RSU Plans Activity (Details) - shares | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
PSUs | ||
Number of Awards | ||
Outstanding, beginning of year (shares) | 931,951 | 694,386 |
Granted (shares) | 711,749 | 351,737 |
Granted - notional dividends reinvested (shares) | 44,893 | 34,439 |
Awards paid out (shares) | (239,509) | (148,168) |
Cancelled/forfeited (shares) | (16,910) | (443) |
Transferred in (out) (shares) | (81,214) | 0 |
Outstanding, end of year (shares) | 1,350,960 | 931,951 |
RSUs | ||
Number of Awards | ||
Outstanding, beginning of year (shares) | 123,612 | 58,740 |
Granted (shares) | 349,496 | 70,393 |
Granted - notional dividends reinvested (shares) | 15,407 | 4,709 |
Awards paid out (shares) | (74,876) | (10,201) |
Cancelled/forfeited (shares) | (12,090) | (29) |
Transferred in (out) (shares) | 81,214 | 0 |
Outstanding, end of year (shares) | 482,763 | 123,612 |
Stock-based Compensation Pla124
Stock-based Compensation Plans - PSU Plans (Details) - PSUs - CAD CAD / shares in Units, CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Unit with underlying value equivalent to common shares | 1 | |
Award vesting period | 3 years | |
Volume weighted average share price (period) | 5 days | |
Payout (percent) | 113.00% | |
Awards paid out (shares) | (239,509) | (148,168) |
Awards paid out, weighted average exercise price (CAD per share) | CAD 41.46 | |
Total paid out | CAD 11 | |
Expense recognized in earnings | 26 | CAD 16 |
Unrecognized compensation expense | CAD 17 | |
Remaining weighted average period to recognize compensation expense (years) | 2 years | |
Aggregate intrinsic value | CAD 58 | |
Weighted average contractual life (years) | 1 year | |
Volume weighted average price, share price (CAD per share) | CAD 46.01 | CAD 41.46 |
Liability related to outstanding awards | CAD 41 | CAD 30 |
Minimum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Payout (percent) | 0.00% | |
Estimated payout (percent) | 82.00% | |
Maximum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Payout (percent) | 200.00% | |
Estimated payout (percent) | 113.00% |
Stock-based Compensation Pla125
Stock-based Compensation Plans - RSU Plans (Details) - RSUs CAD / shares in Units, CAD in Millions | 12 Months Ended | |
Dec. 31, 2017CADCAD / sharesshares | Dec. 31, 2016CADCAD / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Awards paid out (shares) | shares | 74,876 | 10,201 |
Awards paid out, weighted average exercise price (CAD per share) | CAD / shares | CAD 43.42 | |
Total paid out | CAD 3 | |
Unit with underlying value equivalent to common shares | 1 | |
Award vesting period | 3 years | |
Expense recognized in earnings | CAD 8 | CAD 2 |
Unrecognized compensation expense | CAD 11 | |
Remaining weighted average period to recognize compensation expense (years) | 2 years | |
Aggregate intrinsic value | CAD 22 | |
Weighted average contractual life (years) | 2 years | |
Volume weighted average share price (period) | 5 days | |
Volume weighted average price, share price (CAD per share) | CAD / shares | CAD 46.01 | CAD 41.46 |
Stock unit current liabilities | CAD 11 | CAD 3 |
Other Income, Net (Details)
Other Income, Net (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Other Income and Expenses [Abstract] | ||
Equity component of AFUDC | CAD 74 | CAD 37 |
Net foreign exchange gain | 26 | 0 |
Interest income | 14 | 7 |
Entity Information [Line Items] | ||
Other | 9 | 2 |
Other income, net | 127 | 53 |
Unrealized foreign exchange gain | 21 | |
Belize Electricity | ||
Entity Information [Line Items] | ||
Equity income - Belize Electricity | CAD 4 | CAD 7 |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) CAD in Millions | 12 Months Ended |
Dec. 31, 2017CAD | |
Income Tax Disclosure [Abstract] | |
Decrease in deferred tax liabilities | CAD 1,300 |
Recognition of a regulatory liability | 1,500 |
Earnings impact | 168 |
Earnings impact after non-controlling interest | CAD 146 |
Income Taxes - Schedule of Defe
Income Taxes - Schedule of Deferred Income Taxes (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Income Tax Disclosure [Abstract] | ||
Unrealized foreign exchange losses on long‑term debt and tax loss and credit carryforwards | CAD 44 | CAD 56 |
Gross deferred income tax assets | ||
Tax loss and credit carryforwards | 571 | 675 |
Regulatory liabilities | 596 | 292 |
Employee future benefits | 143 | 155 |
Fair value of long-term debt adjustment | 43 | 88 |
Unrealized foreign exchange losses on long-term debt | 28 | 56 |
Other | 8 | 57 |
Deferred tax assets, gross | 1,389 | 1,323 |
Deferred income tax assets valuation allowance | (44) | (56) |
Net deferred income tax assets | 1,345 | 1,267 |
Gross deferred income tax liabilities | ||
Property, plant and equipment | (3,353) | (4,213) |
Regulatory assets | (203) | (242) |
Intangible assets | (87) | (75) |
Deferred tax liabilities, gross | (3,643) | (4,530) |
Net deferred income tax liability | (2,298) | (3,263) |
Unrealized Foreign Exchange Losses on Long-Term Debt | ||
Gross deferred income tax assets | ||
Deferred income tax assets valuation allowance | CAD (44) | CAD (56) |
Income Taxes - Summary of Unrec
Income Taxes - Summary of Unrecognized Tax Benefits (Details) - CAD | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||
Total unrecognized tax benefits, beginning of year | CAD 23,000,000 | CAD 13,000,000 |
Additions related to the current year | 13,000,000 | 10,000,000 |
Adjustments related to prior years and U.S. Tax Reform | (8,000,000) | 0 |
Total unrecognized tax benefits, end of year | 28,000,000 | 23,000,000 |
Unrecognized tax benefits that would impact tax expenses | 2,000,000 | |
Unrecognized tax benefits, interest expense | CAD 0 | CAD 0 |
Income Taxes - Schedule of Comp
Income Taxes - Schedule of Components of Income Tax Expense (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Canadian | ||
Earnings before income taxes | CAD 461 | CAD 357 |
Current income taxes | 41 | 66 |
Deferred income taxes | 16 | (23) |
Total Canadian | 57 | 43 |
Foreign | ||
Earnings before income taxes | 1,252 | 501 |
Current income taxes | 3 | (19) |
Deferred income taxes | 528 | 121 |
Total Foreign | 531 | 102 |
Income tax expense | CAD 588 | CAD 145 |
Income Taxes - Schedule of Effe
Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | ||
Earnings before income taxes | CAD 1,713 | CAD 858 |
Combined Canadian federal and provincial statutory income tax rate | 28.00% | 28.00% |
Expected federal and provincial taxes at statutory rate | CAD 480 | CAD 240 |
Expected federal and provincial taxes at statutory rate Increase (decrease) resulting from: | ||
Enactment of U.S. Tax Reform | 168 | 0 |
Foreign and other statutory rate differentials | 31 | (28) |
Allowance for funds used during construction | (26) | (14) |
Effects of rate-regulated accounting: | ||
Difference between depreciation claimed for income tax and accounting purposes | (26) | (25) |
Items capitalized for accounting purposes but expensed for income tax purposes | (21) | (26) |
Release of valuation allowance and non-taxable portion of gain on dispositions | (17) | 0 |
Other | (1) | (2) |
Income tax expense | CAD 588 | CAD 145 |
Effective tax rate | 34.30% | 16.90% |
Income Taxes - Tax Carryforward
Income Taxes - Tax Carryforward (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Tax Credit Carryforward [Line Items] | ||
Total tax carryforwards | CAD 2,309 | CAD 1,235 |
Canadian | ||
Tax Credit Carryforward [Line Items] | ||
Tax carryforward, gross | 398 | |
Unrecognized in the consolidated financial statements | (65) | |
Total tax carryforwards | 333 | |
Foreign | ||
Tax Credit Carryforward [Line Items] | ||
Operating loss carryforward | 1,850 | |
Tax carryforward, gross | 1,977 | |
Unrecognized in the consolidated financial statements | (1) | |
Total tax carryforwards | 1,976 | |
Capital loss | Canadian | ||
Tax Credit Carryforward [Line Items] | ||
Tax credit carryforward | 70 | |
Capital loss | Foreign | ||
Tax Credit Carryforward [Line Items] | ||
Tax credit carryforward | 1 | |
Non-capital loss | Canadian | ||
Tax Credit Carryforward [Line Items] | ||
Tax credit carryforward | 326 | |
Other tax credits | Canadian | ||
Tax Credit Carryforward [Line Items] | ||
Tax credit carryforward | 2 | |
Other tax credits | Foreign | ||
Tax Credit Carryforward [Line Items] | ||
Tax credit carryforward | CAD 126 |
Employee Future Benefits - Sche
Employee Future Benefits - Schedule of Allocation of Plan Assets (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Defined Benefit Plan Disclosure [Line Items] | |||
2017 Target Allocation (percent) | 100.00% | ||
Actual Plan Asset Allocations (percent) | 100.00% | 100.00% | |
Fair value of plan assets | CAD 3,118 | CAD 2,898 | |
Equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
2017 Target Allocation (percent) | 48.00% | ||
Actual Plan Asset Allocations (percent) | 47.00% | 50.00% | |
Fair value of plan assets | CAD 1,471 | CAD 1,449 | |
Fixed income | |||
Defined Benefit Plan Disclosure [Line Items] | |||
2017 Target Allocation (percent) | 45.00% | ||
Actual Plan Asset Allocations (percent) | 46.00% | 45.00% | |
Fair value of plan assets | CAD 1,422 | CAD 1,304 | |
Real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
2017 Target Allocation (percent) | 6.00% | ||
Actual Plan Asset Allocations (percent) | 6.00% | 4.00% | |
Fair value of plan assets | CAD 181 | CAD 116 | |
Private equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | CAD 22 | CAD 10 | |
Cash and other | |||
Defined Benefit Plan Disclosure [Line Items] | |||
2017 Target Allocation (percent) | 1.00% | ||
Actual Plan Asset Allocations (percent) | 1.00% | 1.00% | |
Fair value of plan assets | CAD 22 | CAD 19 | |
Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 663 | 637 | |
Level 1 | Equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 522 | 507 | |
Level 1 | Fixed income | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 133 | 124 | |
Level 1 | Real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 1 | Private equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 1 | Cash and other | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 8 | 6 | |
Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 2,265 | 2,148 | |
Level 2 | Equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 949 | 942 | |
Level 2 | Fixed income | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 1,289 | 1,180 | |
Level 2 | Real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 13 | 13 | |
Level 2 | Private equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 2 | Cash and other | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 14 | 13 | |
Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 190 | 113 | CAD 107 |
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 | 168 | 103 | |
Level 3 | Private equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 22 | 10 | |
Level 3 | Cash and other | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | CAD 0 | CAD 0 |
Employee Future Benefits - S134
Employee Future Benefits - Schedule of Level 3 Changes in Plan Assets (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Balance, beginning of year | CAD 2,898 | |
Balance, end of year | 3,118 | CAD 2,898 |
Level 3 | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Balance, beginning of year | 113 | 107 |
Actual return on plan assets held at end of year | 12 | 8 |
Foreign currency translation impacts | (2) | (1) |
Purchases, sales and settlements | 67 | (1) |
Balance, end of year | CAD 190 | CAD 113 |
Employee Future Benefits - S135
Employee Future Benefits - Schedule of Funded Status (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Change in value of plan assets | ||
Balance, beginning of year | CAD 2,898 | |
Balance, end of year | 3,118 | CAD 2,898 |
Defined Benefit Pension Plans | ||
Change in benefit obligation | ||
Balance, beginning of year | 3,037 | 2,828 |
Liabilities assumed on acquisition | 0 | 167 |
Service costs | 76 | 66 |
Employee contributions | 16 | 17 |
Interest costs | 115 | 112 |
Benefits paid | (133) | (119) |
Actuarial losses (gains) | 217 | 45 |
Past service credits/plan amendments | 0 | (10) |
Foreign currency translation impacts | (113) | (69) |
Balance, end of year | 3,215 | 3,037 |
Change in value of plan assets | ||
Balance, beginning of year | 2,646 | 2,466 |
Assets assumed on acquisition | 0 | 85 |
Actual return on plan assets | 336 | 187 |
Benefits paid | (127) | (119) |
Employee contributions | 16 | 17 |
Employer contributions | 69 | 47 |
Foreign currency translation impacts | (99) | (37) |
Balance, end of year | 2,841 | 2,646 |
Funded status | (374) | (391) |
Accumulated benefit obligation | 2,940 | 2,741 |
OPEB Plans | ||
Change in benefit obligation | ||
Balance, beginning of year | 676 | 574 |
Liabilities assumed on acquisition | 0 | 111 |
Service costs | 27 | 18 |
Employee contributions | 2 | 2 |
Interest costs | 25 | 23 |
Benefits paid | (22) | (23) |
Actuarial losses (gains) | (14) | (1) |
Past service credits/plan amendments | (3) | 0 |
Foreign currency translation impacts | (26) | (28) |
Balance, end of year | 665 | 676 |
Change in value of plan assets | ||
Balance, beginning of year | 252 | 181 |
Assets assumed on acquisition | 0 | 65 |
Actual return on plan assets | 37 | 13 |
Benefits paid | (22) | (23) |
Employee contributions | 2 | 2 |
Employer contributions | 26 | 18 |
Foreign currency translation impacts | (18) | (4) |
Balance, end of year | 277 | 252 |
Funded status | CAD (388) | CAD (424) |
Employee Future Benefits - S136
Employee Future Benefits - Schedule of Amounts Recognized in Balance Sheet (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Defined Benefit Pension Plans | ||
Assets | ||
Long-term (Note 9) | CAD 31 | CAD 32 |
Liabilities | ||
Current (Note 13) | 12 | 13 |
Long-term (Note 16) | 393 | 410 |
Net liabilities | 374 | 391 |
OPEB Plans | ||
Assets | ||
Long-term (Note 9) | 3 | 0 |
Liabilities | ||
Current (Note 13) | 10 | 13 |
Long-term (Note 16) | 381 | 411 |
Net liabilities | CAD 388 | CAD 424 |
Employee Future Benefits - S137
Employee Future Benefits - Schedule of Net Benefit Costs (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Benefit Pension Plans | ||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | ||
Service costs | CAD 76 | CAD 66 |
Interest costs | 115 | 112 |
Expected return on plan assets | (151) | (145) |
Amortization of actuarial losses | 45 | 48 |
Amortization of past service credits/plan amendments | 0 | 1 |
Regulatory adjustments | 2 | 6 |
Net benefit cost | 87 | 88 |
OPEB Plans | ||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | ||
Service costs | 27 | 18 |
Interest costs | 25 | 23 |
Expected return on plan assets | (14) | (12) |
Amortization of actuarial losses | 2 | 2 |
Amortization of past service credits/plan amendments | (12) | (10) |
Regulatory adjustments | 4 | 9 |
Net benefit cost | CAD 32 | CAD 30 |
Employee Future Benefits - Comp
Employee Future Benefits - Components of AOCI and Regulatory Assets and Liabilities (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Pension and Other Postretirement Benefit Plans, Net Regulatory Assets [Abstract] | ||
Regulatory assets (Note 8 (ii)) | CAD 3,045 | CAD 2,933 |
Regulatory liabilities (Note 8 (ii)) | (3,446) | (2,183) |
Defined Benefit Pension Plans | ||
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract] | ||
Unamortized net actuarial losses | 22 | 19 |
Unamortized past service costs | 1 | 1 |
Income tax recovery | (5) | (5) |
Accumulated other comprehensive loss (Note 19) | 18 | 15 |
Pension and Other Postretirement Benefit Plans, Net Regulatory Assets [Abstract] | ||
Net actuarial losses | 443 | 479 |
Past service credits | (11) | (11) |
Amount deferred due to actions of regulators | 10 | 12 |
Net regulatory assets | 442 | 480 |
Regulatory assets (Note 8 (ii)) | 442 | 480 |
Regulatory liabilities (Note 8 (ii)) | 0 | 0 |
OPEB Plans | ||
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract] | ||
Unamortized net actuarial losses | 0 | 0 |
Unamortized past service costs | 3 | 2 |
Income tax recovery | (1) | (1) |
Accumulated other comprehensive loss (Note 19) | 2 | 1 |
Pension and Other Postretirement Benefit Plans, Net Regulatory Assets [Abstract] | ||
Net actuarial losses | 17 | 53 |
Past service credits | (23) | (31) |
Amount deferred due to actions of regulators | 27 | 32 |
Net regulatory assets | 21 | 54 |
Regulatory assets (Note 8 (ii)) | 68 | 96 |
Regulatory liabilities (Note 8 (ii)) | CAD (47) | CAD (42) |
Employee Future Benefits - C139
Employee Future Benefits - Components Recognized in OCI and Regulatory Assets (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||
Total recognized in comprehensive income | CAD 4 | CAD 1 |
Defined Benefit Pension Plans | ||
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||
Current year net actuarial losses (gains) | 5 | 4 |
Past service costs/plan amendments | 0 | 0 |
Amortization of actuarial losses | (1) | 0 |
Foreign currency translation impacts | (1) | 0 |
Income tax recovery | 0 | (1) |
Total recognized in comprehensive income | 3 | 3 |
Regulatory Assets, Pension and Other Postretirement Benefit Plans [Abstract] | ||
Assets assumed on acquisition | 0 | 23 |
Current year net actuarial losses (gains) | 24 | (1) |
Past service credits/plan amendments | 0 | (10) |
Amortization of actuarial losses | (44) | (47) |
Amortization of past service (costs) credits | 0 | (1) |
Foreign currency translation impacts | (17) | (9) |
Regulatory adjustments | (1) | (11) |
Total recognized in regulatory assets | (38) | (56) |
Defined Benefit Plan, Expected Amortization, Next Fiscal Year [Abstract] | ||
Future amortization of loss from AOCI | 1 | |
Defined Benefit Plan, Amount to be Amortized from Regulatory Asset Next Fiscal Year [ [Abstract] | ||
Future amortization of loss from regulatory asset | 46 | |
Future amortization of prior service credit from regulatory asset | 1 | |
Future amorization of regulatory adjustments from regulatory asset | 1 | |
OPEB Plans | ||
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||
Current year net actuarial losses (gains) | (1) | (2) |
Past service costs/plan amendments | 2 | 0 |
Amortization of actuarial losses | 0 | 0 |
Foreign currency translation impacts | 0 | 0 |
Income tax recovery | 0 | 0 |
Total recognized in comprehensive income | 1 | (2) |
Regulatory Assets, Pension and Other Postretirement Benefit Plans [Abstract] | ||
Assets assumed on acquisition | 0 | 3 |
Current year net actuarial losses (gains) | (35) | 0 |
Past service credits/plan amendments | (5) | 0 |
Amortization of actuarial losses | (1) | (4) |
Amortization of past service (costs) credits | 12 | 13 |
Foreign currency translation impacts | 2 | 1 |
Regulatory adjustments | (6) | (6) |
Total recognized in regulatory assets | (33) | CAD 7 |
Defined Benefit Plan, Amount to be Amortized from Regulatory Asset Next Fiscal Year [ [Abstract] | ||
Future amortization of prior service credit from regulatory asset | 8 | |
Future amorization of regulatory adjustments from regulatory asset | CAD 4 |
Employee Future Benefits - S140
Employee Future Benefits - Schedule of Assumptions Used (Details) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Benefit Pension Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate during the year | 3.98% | 4.08% |
Discount rate as at December 31 | 3.58% | 4.00% |
Expected long-term rate of return on plan assets | 5.97% | 6.25% |
Rate of compensation increase | 3.34% | 3.36% |
Health care cost trend increase as at December 31 | 0.00% | 0.00% |
OPEB Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate during the year | 3.96% | 4.14% |
Discount rate as at December 31 | 3.59% | 4.00% |
Expected long-term rate of return on plan assets | 5.81% | 6.25% |
Rate of compensation increase | 0.00% | 0.00% |
Health care cost trend increase as at December 31 | 4.71% | 4.70% |
Health care cost trend rate assumed for next fiscal year | 6.38% | |
Remaining period until health care cost trend rate reaches ultimate trend rate | 11 years | |
Year that rate reaches ultimate trend rate | 2,028 |
Employee Future Benefits - Effe
Employee Future Benefits - Effect of Changing Health Care Cost Trend Rate by 1% (Details) - OPEB Plans CAD in Millions | 12 Months Ended |
Dec. 31, 2017CAD | |
Defined Benefit Plan Disclosure [Line Items] | |
1% increase in rate, increase (decrease) in accumulated benefit obligation | CAD 96 |
1% decrease in rate, increase (decrease) in accumulated benefit obligation Obligation | (74) |
1% increase in rate, increase (decrease) in service and interest costs | 26 |
1% decrease in rate, increase (decrease) in service and interest costs | CAD (19) |
Employee Future Benefits - S142
Employee Future Benefits - Schedule of Expected Benefit Payments (Details) CAD in Millions | Dec. 31, 2017CAD |
Defined Benefit Pension Payments | |
Defined Benefit Plan, Expected Future Benefit Payment [Abstract] | |
2,018 | CAD 134 |
2,019 | 137 |
2,020 | 142 |
2,021 | 148 |
2,022 | 156 |
2023-2027 | 860 |
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year | 66 |
OPEB Payments | |
Defined Benefit Plan, Expected Future Benefit Payment [Abstract] | |
2,018 | 23 |
2,019 | 24 |
2,020 | 25 |
2,021 | 27 |
2,022 | 29 |
2023-2027 | 160 |
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year | CAD 36 |
Employee Future Benefits - Defi
Employee Future Benefits - Defined Contribution Plan (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Retirement Benefits [Abstract] | ||
Defined contribution plan cost recognized | CAD 38 | CAD 31 |
Business Acquisitions - 2017 an
Business Acquisitions - 2017 and 2016 (Details) CAD / shares in Units, $ / shares in Units, CAD in Millions, $ in Millions | Oct. 14, 2016USD ($)$ / sharesCAD / $shares | Oct. 14, 2016CADshares | Aug. 31, 2017CAD | Dec. 31, 2016CADCAD / $ | Dec. 31, 2017CADCAD / $ | Dec. 31, 2016CADCAD / $ | May 31, 2017 | Oct. 31, 2016 | Oct. 14, 2016CADCAD / $ | Oct. 13, 2016CAD / sharesCAD / $ |
Business Acquisition [Line Items] | ||||||||||
Advances from non-controlling interests | CAD 4 | CAD 1,361 | ||||||||
Borrowings under committed credit facilities (Note 31) | 2,085 | 668 | ||||||||
Share consideration | CAD 0 | CAD 4,684 | ||||||||
Closing share price (CAD per share) | CAD / shares | CAD 40.96 | |||||||||
Foreign exchange rate (CAD per USD) | CAD / $ | 1.32 | 1.34 | 1.25 | 1.34 | 1.32 | 1.32 | ||||
ITC | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Noncontrolling ownership (percent) | 19.90% | 19.90% | 19.90% | |||||||
Teck Waneta Dam and related transmission assets | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Ownership interest | 66.67% | |||||||||
Break fee | CAD 28 | |||||||||
Teck Waneta Dam and related transmission assets | BC Hydro | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Ownership interest | 66.67% | |||||||||
ITC | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Aggregate purchase price | $ 11,800 | CAD 15,700 | ||||||||
Consolidated indebtedness at fair value acquired | $ 4,800 | CAD 6,300 | ||||||||
Cash paid per share (USD per share) | $ / shares | $ 22.57 | |||||||||
Entity shares issued per acquiree share | shares | 0.7520 | 0.7520 | ||||||||
Total consideration | CAD 9,342 | |||||||||
Cash and share consideration given | $ 7,000 | CAD 9,342 | ||||||||
Payment for ownership | 3,500 | 4,658 | ||||||||
Advances from non-controlling interests | $ 1,228 | CAD 1,600 | ||||||||
Shares issued per share purchased | shares | 114,400,000 | 114,400,000 | ||||||||
Share consideration | $ 3,500 | CAD 4,684 | ||||||||
Acquisition-related expenses | CAD 118 | |||||||||
Acquisition-related expenses, net of tax | 90 | |||||||||
Accelerated vesting of the stock-based compensation awards | CAD 22 | |||||||||
ITC | Operating expenses | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Acquisition-related expenses | 79 | |||||||||
Acquisition-related expenses, net of tax | 62 | |||||||||
ITC | Finance charges | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Acquisition-related expenses | 39 | |||||||||
Acquisition-related expenses, net of tax | CAD 28 | |||||||||
ITC | Bridge loan | Credit facility | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Borrowings under committed credit facilities (Note 31) | 404 | CAD 535 | ||||||||
ITC | 6.00% Unsecured US Shareholder Note | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Face value | 199 | 263 | ||||||||
ITC | Unsecured | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Face value | $ 2,000 | CAD 2,600 | ||||||||
ITC | ITC | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Accelerated vesting of the stock-based compensation awards | CAD 27 |
Business Acquisitions - Schedul
Business Acquisitions - Schedule of Preliminary Allocation of Purchase Consideration (Details) CAD in Millions, $ in Billions | Oct. 14, 2016USD ($) | Oct. 14, 2016CAD | Dec. 31, 2017CAD | Dec. 31, 2016CAD | Oct. 31, 2016 | Dec. 31, 2015CAD |
Business Combination, Consideration Transferred [Abstract] | ||||||
Share consideration | CAD 0 | CAD 4,684 | ||||
Fair value assigned to net assets: | ||||||
Goodwill (Note 12) | CAD 11,644 | CAD 12,364 | CAD 4,173 | |||
ITC | ||||||
Business Combination, Consideration Transferred [Abstract] | ||||||
Share consideration | $ 3.5 | CAD 4,684 | ||||
Cash consideration | 3.5 | 4,658 | ||||
Total consideration | $ 7 | 9,342 | ||||
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Less Noncontrolling Interest [Abstract] | ||||||
Purchase consideration for 80.1% of ITC common shares | 7,721 | |||||
19.9% minority shareholder investment and shareholder note | 1,621 | |||||
Total consideration | 9,342 | |||||
Fair value assigned to net assets: | ||||||
Current assets | 319 | |||||
Long-term regulatory assets | 319 | |||||
Property, plant and equipment | 8,345 | |||||
Intangible assets | 399 | |||||
Other long-term assets | 71 | |||||
Current liabilities | (625) | |||||
Assumed short-term borrowings | (311) | |||||
Assumed long-term debt (including current portion) | (6,006) | |||||
Long-term regulatory liabilities | (327) | |||||
Deferred income taxes | (910) | |||||
Other long-term liabilities | (166) | |||||
Fair value of net assets acquired, excluding cash and cash equivalents | 1,108 | |||||
Cash and cash equivalents | 134 | |||||
Fair value of net assets acquired | 1,242 | |||||
Goodwill (Note 12) | CAD 8,100 | |||||
ITC | ||||||
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Less Noncontrolling Interest [Abstract] | ||||||
Controlling ownership interest (percent) | 80.10% | 80.10% | ||||
Noncontrolling ownership (percent) | 19.90% | 19.90% |
Business Acquisitions - Sche146
Business Acquisitions - Schedule of Pro Forma Data (Details) - ITC CAD in Millions | 12 Months Ended |
Dec. 31, 2016CAD | |
Business Acquisition [Line Items] | |
Pro forma revenue | CAD 7,995 |
Pro forma net earnings attributable to common equity shareholders | CAD 919 |
Business Acquisitions - Aitken
Business Acquisitions - Aitken Creek (Details) - CAD CAD in Millions | Apr. 01, 2016 | Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 |
Business Acquisition [Line Items] | ||||
Cash purchase price, plus the cost of working gas inventory | CAD 0 | CAD 4,841 | ||
Goodwill (Note 12) | CAD 4,173 | CAD 11,644 | CAD 12,364 | |
Aitken Creek Gas Storage ULC | ||||
Business Acquisition [Line Items] | ||||
Cash purchase price, plus the cost of working gas inventory | CAD 349 | |||
Deposit on acquisition paid | CAD 38 | |||
Goodwill (Note 12) | CAD 27 |
Dispositions (Details)
Dispositions (Details) - FortisBC Electric - Walden Hydroelectric Power Plant Assets CAD in Millions | 1 Months Ended |
Feb. 29, 2016CAD | |
Long Lived Assets Held-for-sale [Line Items] | |
Proceeds from sale of assets | CAD 9 |
Gain (loss) on sale of non-regulated generation assets, net of expense and tax | CAD 1 |
Supplementary Information to149
Supplementary Information to Consolidated Statements of Cash Flows (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Cash paid for: | ||
Interest | CAD 927 | CAD 644 |
Income taxes | 69 | 62 |
Change in working capital: | ||
Accounts receivable and other current assets | (74) | 43 |
Prepaid expenses | (3) | (4) |
Inventories | (6) | 17 |
Regulatory assets - current portion | 39 | (58) |
Accounts payable and other current liabilities | 119 | 25 |
Regulatory liabilities - current portion | (172) | (1) |
Changes in non-cash operating working capital | (97) | 22 |
Non-cash investing and financing activities: | ||
Common share dividends reinvested | 253 | 162 |
Common shares issued on business acquisition (Note 25) | 0 | 4,684 |
Additions to property, plant and equipment, and intangible assets included in current and long-term liabilities | 307 | 296 |
Commitment to purchase capital lease interest | 0 | 48 |
Transfer of deposit on business acquisition (Note 25) | 0 | 38 |
Contributions in aid of construction | 35 | 9 |
Exercise of stock options into common shares | CAD 5 | CAD 4 |
Fair Value Measurements and 150
Fair Value Measurements and Financial Instruments - Fair Value Hierarchy (Details) - Recurring - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Assets | ||
Other investments | CAD 78 | CAD 69 |
Total assets | 132 | 102 |
Liabilities | ||
Total liabilities | (108) | (38) |
Energy contracts subject to regulatory deferral | ||
Assets | ||
Assets | 21 | 19 |
Liabilities | ||
Liabilities | (106) | (26) |
Energy contracts not subject to regulatory deferral | ||
Assets | ||
Assets | 30 | 3 |
Liabilities | ||
Liabilities | (1) | (9) |
Foreign exchange contracts | ||
Assets | ||
Assets | 3 | |
Interest rate swaps | ||
Assets | ||
Assets | 11 | |
Interest rate and total return swaps | ||
Liabilities | ||
Liabilities | (1) | (3) |
Level 1 | ||
Assets | ||
Other investments | 78 | 69 |
Total assets | 81 | 70 |
Liabilities | ||
Total liabilities | (1) | 0 |
Level 1 | Energy contracts subject to regulatory deferral | ||
Assets | ||
Assets | 0 | 1 |
Liabilities | ||
Liabilities | (1) | 0 |
Level 1 | Energy contracts not subject to regulatory deferral | ||
Assets | ||
Assets | 0 | 0 |
Liabilities | ||
Liabilities | 0 | 0 |
Level 1 | Foreign exchange contracts | ||
Assets | ||
Assets | 3 | |
Level 1 | Interest rate swaps | ||
Assets | ||
Assets | 0 | |
Level 1 | Interest rate and total return swaps | ||
Liabilities | ||
Liabilities | 0 | 0 |
Level 2 | ||
Assets | ||
Other investments | 0 | 0 |
Total assets | 45 | 25 |
Liabilities | ||
Total liabilities | (104) | (33) |
Level 2 | Energy contracts subject to regulatory deferral | ||
Assets | ||
Assets | 19 | 13 |
Liabilities | ||
Liabilities | (103) | (21) |
Level 2 | Energy contracts not subject to regulatory deferral | ||
Assets | ||
Assets | 26 | 1 |
Liabilities | ||
Liabilities | 0 | (9) |
Level 2 | Foreign exchange contracts | ||
Assets | ||
Assets | 0 | |
Level 2 | Interest rate swaps | ||
Assets | ||
Assets | 11 | |
Level 2 | Interest rate and total return swaps | ||
Liabilities | ||
Liabilities | (1) | (3) |
Level 3 | ||
Assets | ||
Other investments | 0 | 0 |
Total assets | 6 | 7 |
Liabilities | ||
Total liabilities | (3) | (5) |
Level 3 | Energy contracts subject to regulatory deferral | ||
Assets | ||
Assets | 2 | 5 |
Liabilities | ||
Liabilities | (2) | (5) |
Level 3 | Energy contracts not subject to regulatory deferral | ||
Assets | ||
Assets | 4 | 2 |
Liabilities | ||
Liabilities | (1) | 0 |
Level 3 | Foreign exchange contracts | ||
Assets | ||
Assets | 0 | |
Level 3 | Interest rate swaps | ||
Assets | ||
Assets | 0 | |
Level 3 | Interest rate and total return swaps | ||
Liabilities | ||
Liabilities | CAD 0 | CAD 0 |
Fair Value Measurements and 151
Fair Value Measurements and Financial Instruments - Derivative Contracts Under Master Netting Agreements and Collateral Positions (Details) - Energy contracts - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Derivative assets | ||
Gross Amount Recognized in Balance Sheet | CAD 51 | CAD 22 |
Counterparty Netting of Energy Contracts | 17 | 9 |
Cash Collateral Received/Posted | 7 | 0 |
Net Amount | 27 | 13 |
Derivative liabilities | ||
Gross Amount Recognized in Balance Sheet | (107) | (35) |
Counterparty Netting of Energy Contracts | (17) | (9) |
Cash Collateral Received/Posted | 0 | 0 |
Net Amount | CAD (90) | CAD (26) |
Fair Value Measurements and 152
Fair Value Measurements and Financial Instruments - Derivative Instruments Narrative (Details) CAD in Millions, $ in Billions | 12 Months Ended | ||
Dec. 31, 2017CAD | Dec. 31, 2016CAD | Nov. 30, 2017USD ($) | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Regulatory assets | CAD 3,045 | CAD 2,933 | |
Regulatory liability | 3,446 | 2,183 | |
Long-term debt | CAD 21,535 | 21,219 | |
UNS Energy | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Realized gain, portion shared with customers | 10.00% | ||
ITC | Fixed rate debt | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Long-term debt | $ | $ 1 | ||
Energy contracts subject to regulatory deferral | Derivative instruments | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Regulatory assets | CAD 87 | 19 | |
Regulatory liability | 2 | 12 | |
Energy contracts | Not designated as hedging instrument | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Unrealized gain (loss) recognized in earnings | 36 | CAD (2) | |
Unrealized gains recognized in earnings | 3 | ||
Foreign exchange contracts | Not designated as hedging instrument | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Notional amount | 160 | ||
Interest rate swaps | Cash flow hedges | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Losses expected to be reclassified to earnings within the next twelve month | (3) | ||
Interest rate swaps | UNS Energy | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Notional amount | 23 | ||
Total return swap | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Notional amount | CAD 33 | ||
Total return swaps held | 3 | ||
Total return swap | Minimum | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative terms | 1 year | ||
Total return swap | Maximum | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative terms | 3 years |
Fair Value Measurements and 153
Fair Value Measurements and Financial Instruments - Reconciliation of Changes in Fair Value of Assets Classified as Level 3 (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | ||
Balance, beginning of year | CAD 2 | CAD (18) |
Realized losses | (10) | (19) |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unrealized Gain (Loss) | (3) | 12 |
Settlements | 12 | 27 |
Transfers of assets out of level 3 | (2) | 0 |
Transfers of liabilities out of level 3 | 4 | 0 |
Balance, end of year | CAD 3 | CAD 2 |
Fair Value Measurements and 154
Fair Value Measurements and Financial Instruments - Volume of Derivative Activity (Details) kJ in Trillions | 12 Months Ended | |
Dec. 31, 2017GWhkJ | Dec. 31, 2016GWhkJ | |
Electricity swap contracts, subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | GWh | 1,291 | 2,184 |
Electricity power purchase contracts, subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | GWh | 761 | 1,252 |
Gas swap contracts, subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | 216 | 35 |
Gas supply contract premiums, subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | 219 | 240 |
Long-term wholesale trading contracts, not subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | GWh | 2,387 | 2,058 |
Gas supply contract premiums, not subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | 0 | 15 |
Gas swap contracts, not subject to regulatory deferral | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Volume (gwh / kj) | 36 | 4 |
Fair Value Measurements and 155
Fair Value Measurements and Financial Instruments - Credit Risk (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Concentration Risk [Line Items] | ||
Derivative instruments in net liability positions | CAD 57 | CAD 37 |
Additional collateral to counterparties | CAD 57 | |
Concentration of credit risk | Three customers | Revenue | ITC | ||
Concentration Risk [Line Items] | ||
Concentration risk percentage | 69.00% |
Fair Value Measurements and 156
Fair Value Measurements and Financial Instruments - Foreign Exchange Hedge (Details) - Foreign net investments - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Unhedged foreign net investments | $ 7,548 | $ 7,250 |
Designated as hedging instrument | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Long-term debt designated as an effective hedge | $ 3,385 | $ 3,511 |
Fair Value Measurements and 157
Fair Value Measurements and Financial Instruments - Financial Instruments Not Carried At Fair Value (Details) - CAD CAD in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Carrying Value | ||
Debt Instrument [Line Items] | ||
Long-term debt, including current portion (Note 14) | CAD 21,535 | CAD 21,219 |
Carrying Value | Waneta Partnership | ||
Debt Instrument [Line Items] | ||
Waneta Partnership promissory note (Note 16) | 63 | 59 |
Estimated Fair Value | ||
Debt Instrument [Line Items] | ||
Long-term debt, including current portion (Note 14) | 23,481 | 22,523 |
Estimated Fair Value | Waneta Partnership | ||
Debt Instrument [Line Items] | ||
Waneta Partnership promissory note (Note 16) | CAD 64 | CAD 61 |
Variable Interest Entity (Detai
Variable Interest Entity (Details) - CAD CAD in Millions | 1 Months Ended | 12 Months Ended | ||
Apr. 30, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
ASSETS | ||||
Cash and cash equivalents | CAD 327 | CAD 269 | CAD 242 | |
Accounts receivable and other current assets | 1,131 | 1,127 | ||
Property, plant and equipment | 29,668 | 29,337 | ||
Intangible assets | 1,081 | 1,011 | ||
Total assets | 47,822 | 47,904 | ||
Liabilities [Abstract] | ||||
Accounts payable and other current liabilities | (2,053) | (1,970) | ||
Other liabilities | (1,210) | (1,279) | ||
Total liabilities | (31,073) | (31,454) | ||
Net earnings | ||||
Revenue | 8,301 | 6,838 | ||
Expenses | ||||
Operating expenses | 2,261 | 2,031 | ||
Depreciation and amortization | 1,179 | 983 | ||
Finance charges | 914 | 678 | ||
Net earnings | 1,125 | 713 | ||
Capital expenditures | 3,024 | 2,061 | ||
Dividends paid to non-controlling interests | CAD 109 | 53 | ||
Waneta Partnership | ||||
Variable Interest Entity [Line Items] | ||||
Controlling ownership interest (percent) | 51.00% | |||
Noncontrolling ownership (percent) | 49.00% | |||
Variable Interest Entity | Waneta Partnership | ||||
Variable Interest Entity [Line Items] | ||||
Controlling ownership interest (percent) | 51.00% | |||
Noncontrolling ownership (percent) | 49.00% | |||
General partner ownership (percent) | 0.01% | |||
Long-term contract for electric power, term | 40 years | |||
ASSETS | ||||
Cash and cash equivalents | CAD 16 | 15 | ||
Accounts receivable and other current assets | 14 | 14 | ||
Property, plant and equipment | 688 | 696 | ||
Intangible assets | 30 | 30 | ||
Total assets | 748 | 755 | ||
Liabilities [Abstract] | ||||
Accounts payable and other current liabilities | (28) | (3) | ||
Other liabilities | (63) | (79) | ||
Total liabilities | (91) | (82) | ||
Net assets before partners' equity | 657 | 673 | ||
Net earnings | ||||
Revenue | 93 | 91 | ||
Expenses | ||||
Operating expenses | 17 | 17 | ||
Depreciation and amortization | 18 | 18 | ||
Finance charges | 4 | 3 | ||
Total operating expenses | 39 | 38 | ||
Net earnings | 54 | 53 | ||
Capital expenditures | 5 | 18 | ||
Dividends paid to non-controlling interests | CAD 34 | CAD 31 |
Commitments and Contingencies -
Commitments and Contingencies - Fiscal Year Maturity (Details) CAD in Millions | Dec. 31, 2017CAD |
Operating lease obligations: | |
Total | CAD 53 |
Due within 1 year | 11 |
Due in year 2 | 9 |
Due in year 3 | 7 |
Due in year 4 | 4 |
Due in year 5 | 4 |
Due after 5 years | 18 |
Promissory note: | |
Due within 1 year | 705 |
Due in year 2 | 282 |
Due in year 3 | 673 |
Due in year 4 | 1,219 |
Due in year 5 | 1,060 |
Due after 5 years | 17,596 |
Total | 21,622 |
Due within 1 year | 1,842 |
Due in year 2 | 1,580 |
Due in year 3 | 1,570 |
Due in year 4 | 1,422 |
Due in year 5 | 1,227 |
Due after 5 years | 13,981 |
Waneta Partnership | Waneta Partnership promissory note | |
Promissory note: | |
Total | 72 |
Due within 1 year | 0 |
Due in year 2 | 0 |
Due in year 3 | 72 |
Due in year 4 | 0 |
Due in year 5 | 0 |
Due after 5 years | 0 |
Power | |
Purchase obligations: | |
Total | 2,240 |
Due within 1 year | 275 |
Due in year 2 | 157 |
Due in year 3 | 126 |
Due in year 4 | 118 |
Due in year 5 | 117 |
Due after 5 years | 1,447 |
Renewable power | |
Purchase obligations: | |
Total | 1,428 |
Due within 1 year | 93 |
Due in year 2 | 92 |
Due in year 3 | 92 |
Due in year 4 | 92 |
Due in year 5 | 91 |
Due after 5 years | 968 |
Gas | |
Purchase obligations: | |
Total | 1,085 |
Due within 1 year | 278 |
Due in year 2 | 201 |
Due in year 3 | 189 |
Due in year 4 | 147 |
Due in year 5 | 112 |
Due after 5 years | 158 |
Long-term contracts - UNS Energy | UNS Energy | |
Purchase obligations: | |
Total | 910 |
Due within 1 year | 157 |
Due in year 2 | 158 |
Due in year 3 | 125 |
Due in year 4 | 79 |
Due in year 5 | 50 |
Due after 5 years | 341 |
Renewable energy credit purchase agreement | |
Purchase obligations: | |
Total | 125 |
Due within 1 year | 20 |
Due in year 2 | 13 |
Due in year 3 | 11 |
Due in year 4 | 10 |
Due in year 5 | 10 |
Due after 5 years | 61 |
Interest obligations on long-term debt | |
Other commitments: | |
Total | 14,575 |
Due within 1 year | 892 |
Due in year 2 | 878 |
Due in year 3 | 858 |
Due in year 4 | 837 |
Due in year 5 | 792 |
Due after 5 years | 10,318 |
ITC easement agreement | ITC | |
Other commitments: | |
Total | 413 |
Due within 1 year | 13 |
Due in year 2 | 13 |
Due in year 3 | 13 |
Due in year 4 | 13 |
Due in year 5 | 13 |
Due after 5 years | 348 |
Debt Collection Agreement | Maritime Electric | |
Other commitments: | |
Total | 122 |
Due within 1 year | 3 |
Due in year 2 | 3 |
Due in year 3 | 3 |
Due in year 4 | 3 |
Due in year 5 | 3 |
Due after 5 years | 107 |
Purchase of Springerville Common Facilities | |
Other commitments: | |
Total | 85 |
Due within 1 year | 0 |
Due in year 2 | 0 |
Due in year 3 | 0 |
Due in year 4 | 85 |
Due in year 5 | 0 |
Due after 5 years | 0 |
Joint-use asset and shared service agreements | |
Other commitments: | |
Total | 52 |
Due within 1 year | 3 |
Due in year 2 | 3 |
Due in year 3 | 3 |
Due in year 4 | 3 |
Due in year 5 | 3 |
Due after 5 years | 37 |
Other | |
Other commitments: | |
Total | 462 |
Due within 1 year | 97 |
Due in year 2 | 53 |
Due in year 3 | 71 |
Due in year 4 | 31 |
Due in year 5 | 32 |
Due after 5 years | CAD 178 |
Commitments and Contingencie160
Commitments and Contingencies - Fiscal Year Maturity (Footnotes) (Details) CAD in Millions | 1 Months Ended | 12 Months Ended |
Apr. 30, 2015MW | Dec. 31, 2017CADGWhleasecontractagreement_renewalMW | |
Long-term Purchase Commitment [Line Items] | ||
Number of agreement renewals | agreement_renewal | 10 | |
Agreement renewal term | 50 years | |
UNS Energy Corporation | Springerville Common Facilities | ||
Long-term Purchase Commitment [Line Items] | ||
Capital leases, undivided leased interest, percentage | 32.20% | |
Number of leases | lease | 2 | |
Power | ||
Long-term Purchase Commitment [Line Items] | ||
Purchase obligation | CAD 2,240 | |
Power | FortisOntario | ||
Long-term Purchase Commitment [Line Items] | ||
Purchase obligation | CAD 692 | |
Power | FortisOntario | Maximum | ||
Long-term Purchase Commitment [Line Items] | ||
Amount of volume required (in mw) | MW | 145 | |
Power | FortisOntario | Minimum | ||
Long-term Purchase Commitment [Line Items] | ||
Volume of energy required to be purchased (in GWh) | GWh | 537 | |
Power | FortisBC Energy | ||
Long-term Purchase Commitment [Line Items] | ||
Purchase obligation | CAD 482 | |
Power | FortisBC Electric | ||
Long-term Purchase Commitment [Line Items] | ||
Purchase obligation | CAD 333 | |
Amount of volume required (in mw) | MW | 234 | |
Long-term renewable PPA, term | 20 years | |
Power | FortisBC Electric | Maximum | ||
Long-term Purchase Commitment [Line Items] | ||
Amount of volume required (in mw) | MW | 200 | |
Volume of energy required to be purchased (in GWh) | GWh | 1,752 | |
Power | Maritime Electric | ||
Long-term Purchase Commitment [Line Items] | ||
Number of long-term take-or-pay contracts | contract | 2 | |
Power | Maritime Electric | Nuclear Generating Station | ||
Long-term Purchase Commitment [Line Items] | ||
Share of plant output, percentage | 4.55% | |
Power | Payment guarantee | Maritime Electric | ||
Long-term Purchase Commitment [Line Items] | ||
Purchase obligation | CAD 511 | |
WECA | FortisBC Electric | ||
Long-term Purchase Commitment [Line Items] | ||
Long-term renewable PPA, term | 40 years | |
Renewable Power | ||
Long-term Purchase Commitment [Line Items] | ||
Purchase obligation | CAD 1,428 | |
Renewable Power | TEP and UNS Electric, Inc | ||
Long-term Purchase Commitment [Line Items] | ||
Purchase commitment, percentage | 100.00% | |
Take-or-pay contract | FortisOntario | ||
Long-term Purchase Commitment [Line Items] | ||
Amount of volume required (in mw) | MW | 145 | |
Renewable Energy Credit | ||
Long-term Purchase Commitment [Line Items] | ||
Purchase obligation | CAD 125 |
Commitments and Contingencie161
Commitments and Contingencies - Other Commitments (Details) CAD in Millions | 12 Months Ended | 60 Months Ended | ||||||
Dec. 31, 2018CAD | Dec. 31, 2017CAD | Dec. 31, 2016CAD | Dec. 31, 2022CAD | Dec. 31, 2017USD ($) | Dec. 31, 2017CAD | Dec. 31, 2014USD ($)project | Dec. 31, 2014CADproject | |
Other Commitments [Line Items] | ||||||||
Capital expenditures | CAD 3,024 | CAD 2,061 | ||||||
Regulatory liability | 2,183 | CAD 3,446 | ||||||
CH Energy Group | ||||||||
Other Commitments [Line Items] | ||||||||
Number of high-voltage transmission projects | project | 5 | 5 | ||||||
Investment in electric transmission projects | $ 1,700,000,000 | CAD 2,100 | ||||||
CH Energy Group | Payment guarantee | ||||||||
Other Commitments [Line Items] | ||||||||
Maximum commitment | $ 182,000,000 | CAD 228 | ||||||
Obligation under guarantee | $ | $ 0 | |||||||
Parental guarantee | FHI | Payment guarantee | ||||||||
Other Commitments [Line Items] | ||||||||
Maximum commitment | CAD 77 | CAD 80 | ||||||
Forecast | ||||||||
Other Commitments [Line Items] | ||||||||
Capital expenditures | CAD 3,200 | CAD 14,500 |
Comparative Figures (Details)
Comparative Figures (Details) - CAD CAD in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||
Net repayments and borrowings under committed credit facilities | CAD (365) | CAD (76) |
Borrowings under committed credit facilities | 2,085 | 668 |
Repayments under credit facilities | CAD 2,039 | 499 |
Correction | ||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||
Net repayments and borrowings under committed credit facilities | 169 | |
Borrowings under committed credit facilities | 668 | |
Repayments under credit facilities | CAD 499 |