Exhibit

(in millions)

Sale of capacity from Waneta Expansion to FortisBC Electric

Sale of energy from BECOL to Belize Electricity

Lease of gas storage capacity and gas sales from Aitken Creek to
FortisBC Energy

EX-99.2 3 a992fortis2017annualfs.htm EXHIBIT 99.2 Exhibit

Exhibit 99.2

FORTIS INC.

Audited Consolidated Financial Statements

As at and for the years ended December 31, 2017 and 2016

TABLE OF CONTENTS



Management's Report on Internal Control Over Financial Reporting		i	NOTE 12	Goodwill	34
Report of Independent Registered Public Accounting Firm Deloitte LLP - Opinion on the Consolidated Financial Statements		ii	NOTE 13	Accounts Payable and Other Current Liabilities	34
Report of Independent Registered Public Accounting Firm Deloitte LLP - Opinion on Internal Control over Financial Reporting		iv	NOTE 14	Long-Term Debt	35
Independent Auditors' Report of Registered Public Accounting Firm Ernst & Young LLP		v	NOTE 15	Capital Lease and Finance Obligations	38
Consolidated Balance Sheets		1	NOTE 16	Other Liabilities	40
Consolidated Statements of Earnings		2	NOTE 17	Earnings per Common Share	41
Consolidated Statements of Comprehensive Income		2	NOTE 18	Preference Shares	42
Consolidated Statements of Cash Flows		3	NOTE 19	Accumulated Other Comprehensive Income	44
Consolidated Statements of Changes in Equity		4	NOTE 20	Non-Controlling Interests	45
Notes to Consolidated Financial Statements			NOTE 21	Stock-Based Compensation Plans	45
NOTE 1	Description of Business	5	NOTE 22	Other Income, Net	49
NOTE 2	Nature of Regulation and Regulatory Matters	7	NOTE 23	Income Taxes	49
NOTE 3	Summary of Significant Accounting Policies	11	NOTE 24	Employee Future Benefits	52
NOTE 4	Future Accounting Pronouncements	21	NOTE 25	Business Acquisitions	57
NOTE 5	Segmented Information	23	NOTE 26	Dispositions	59
NOTE 6	Accounts Receivable and Other Current Assets	25	NOTE 27	Supplementary Information to Consolidated Statements of Cash Flows	59
NOTE 7	Inventories	25	NOTE 28	Fair Value Measurements and Financial Instruments	60
NOTE 8	Regulatory Assets and Liabilities	26	NOTE 29	Variable Interest Entity	65
NOTE 9	Other Assets	31	NOTE 30	Commitments and Contingencies	67
NOTE 10	Property, Plant and Equipment	31	NOTE 31	Comparative Figures	69
NOTE 11	Intangible Assets	33

Management's Report on Internal Control over Financial Reporting

Management of Fortis Inc. and its subsidiaries (the "Corporation") is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is designed by, or under the supervision of, the Corporation's President and Chief Executive Officer ("CEO") and Executive Vice President and Chief Financial Officer ("CFO") and effected by the Corporation's board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The Corporation's management, including the Corporation's CEO and CFO, assessed the effectiveness of the Corporation's internal control over financial reporting as at December 31, 2017, based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concluded that, as at December 31, 2017, the Corporation's internal control over financial reporting was effective.

Deloitte LLP, an Independent Registered Public Accounting Firm, as auditors of the Corporation's consolidated financial statements for the year ended December 31, 2017, has also audited the effectiveness of the Corporation's internal control over financial reporting as at December 31, 2017. As stated in the Report of Independent Registered Public Accounting Firm, Deloitte LLP expressed an unqualified opinion on the effectiveness of the Corporation's internal control over financial reporting as at December 31, 2017.

February 14, 2018

/s/ Barry V. Perry

Barry V. Perry

President and Chief Executive Officer, Fortis Inc.

/s/ Karl W. Smith

Karl W. Smith

Executive Vice President, Chief Financial Officer, Fortis Inc.

St. John's, Canada



	i

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Fortis Inc.

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated financial statements of Fortis Inc. and subsidiaries (the "Corporation"), which comprise the consolidated balance sheet as at December 31, 2017, the consolidated statement of earnings, consolidated statement of comprehensive income, consolidated statement of changes in equity and consolidated statement of cash flows for the year then ended, and the related notes, including a summary of significant accounting policies and other explanatory information (collectively referred to as the "financial statements").

In our opinion, the financial statements present fairly, in all material respects, the financial position of the Corporation as at December 31, 2017, and its financial performance and its cash flows for the year then ended in accordance with accounting principles generally accepted in the United States of America.

Predecessor Auditor on Prior Period

The consolidated financial statements of the Corporation for the year ended December 31, 2016, were audited by another auditor who expressed an unmodified/unqualified opinion on those financial statements on February 15, 2017, except as to Note 31, which is as of February 14, 2018.

Report on Internal Control over Financial Reporting

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) ("PCAOB"), the Corporation's internal control over financial reporting as at December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 14, 2018 expressed an unqualified opinion on the Corporation's internal control over financial reporting.

Basis for Opinion

Management's Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility

Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with Canadian generally accepted auditing standards and the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement, whether due to fraud or error. Those standards also require that we comply with ethical requirements. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. Further, we are required to be independent of the Corporation in accordance with the ethical requirements that are relevant to our audit of the financial statements in Canada and to fulfill our other ethical responsibilities in accordance with these requirements.

An audit includes performing procedures to assess the risks of material misstatement of the financial statements, whether due to fraud or error, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Corporation's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies and principles used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.



	ii

We believe that the audit evidence we have obtained in our audit is sufficient and appropriate to provide a reasonable basis for our audit opinion.

/s/ Deloitte LLP

Chartered Professional Accountants

St. John's, Canada

February 14, 2018

We have served as the Corporation's auditor since 2017.



	iii

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Fortis Inc.

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Fortis Inc. and subsidiaries (the "Corporation") as at December 31, 2017, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as at December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) ("PCAOB") and Canadian generally accepted auditing standards, the Corporation's consolidated financial statements as at and for the year ended December 31, 2017, and our report dated February 14, 2018, expressed an unmodified/unqualified opinion on those financial statements.

Basis for Opinion

The Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte LLP

Chartered Professional Accountants

St. John's, Canada

February 14, 2018



	iv

Independent Auditors' Report of Registered Public Accounting Firm

To the Shareholders of Fortis Inc.

We have audited the accompanying consolidated financial statements of Fortis Inc., which comprise the consolidated balance sheet as at December 31, 2016, and the consolidated statement of earnings, comprehensive income, cash flows and changes in equity for the year then ended, and a summary of significant accounting policies and other explanatory information.

Management's responsibility for the consolidated financial statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors' responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audits in accordance with Canadian generally accepted auditing standards and with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors' judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audit is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of Fortis Inc. as at December 31, 2016, and its financial performance and its cash flows for the year then ended in accordance with accounting principles generally accepted in the United States.

/s/ Ernst & Young LLP

Chartered Professional Accountants

St. John's, Canada

February 15, 2017, except as to Note 31, which is as of February 14, 2018



	v



Fortis Inc.
Consolidated Balance Sheets
As at December 31
(in millions of Canadian dollars)
	2017		2016

ASSETS
Current assets
Cash and cash equivalents	$	327	$	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

LIABILITIES AND EQUITY
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	$	47,822	$	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	Approved on Behalf of the Board
	/s/ Douglas J. Haughey		/s/ Tracey C. Ball

	Douglas J. Haughey,		Tracey C. Ball,

See accompanying Notes to Consolidated Financial Statements	Director		Director



Fortis Inc.
Consolidated Statements of Earnings
For the years ended December 31
(in millions of Canadian dollars, except per share amounts)

		2017		2016

Revenue		$	8,301	$	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
		$	1,125	$	713

Earnings per common share (Note 17)
	Basic	$	2.32	$	1.89
	Diluted	$	2.31	$	1.89

See accompanying Notes to Consolidated Financial Statements



Fortis Inc.
Consolidated Statements of Comprehensive Income
For the years ended December 31
(in millions of Canadian dollars)
		2017			2016

Net earnings		$	1,125		$	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		—			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		)
		(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
		$	342		$	667

See accompanying Notes to Consolidated Financial Statements



Fortis Inc.
Consolidated Statements of Cash Flows
For the years ended December 31
(in millions of Canadian dollars)
			2017			2016

Operating activities
Net earnings			$	1,125		$	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)			—			(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			—
Issue of common shares, net of costs, and dividends reinvested			61			45
Redemption of preference shares (Note 18)			—			(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		)	—
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			$	327		$	269

Supplementary Information to Consolidated Statements of Cash Flows (Note 27)

See accompanying Notes to Consolidated Financial Statements



Fortis Inc.
Consolidated Statements of Changes in Equity
For the years ended December 31, 2017 and 2016
(in millions of Canadian dollars, except share numbers)
	Common Shares	Common Shares		Preference Shares			Additional Paid-In Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Non-Controlling Interests			Total Equity
	(# millions)			(Note 18)						(Note 19)						(Note 20)

As at December 31, 2016	401.5	$	10,762	$	1,623		$	12		$	745		$	1,455		$	1,853		$	16,450
Net earnings	—	—		—			—			—			1,028			97			1,125
Other comprehensive loss	—	—		—			—			(684		)	—			(99		)	(783		)
Common shares issued under private offering (Note 14)	12.2	500		—			—			—			—			—			500
Common shares issued under dividend reinvestment plan and other	7.4	320		—			(5		)	—			—			—			315
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 ($1.65 per share)	—	—		—			—			—			(691		)	—			(691		)
Dividends declared on preference shares	—	—		—			—			—			(65		)	—			(65		)
As at December 31, 2017	421.1	$	11,582	$	1,623		$	10		$	61		$	1,727		$	1,746		$	16,749

As at December 31, 2015	281.6	$	5,867	$	1,820		$	14		$	791		$	1,388		$	473		$	10,353
Net earnings	—	—		—			—			—			660			53			713
Other comprehensive loss	—	—		—			—			(46		)	—			—			(46		)
Common shares issued under public offering (Notes 25 and 27)	114.4	4,684		—			—			—			—			—			4,684
Common shares issued under dividend reinvestment plan and other	5.5	211		—			(4		)	—			—			—			207
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 ($1.55 per share)	—	—		—			—			—			(534		)	—			(534		)
Dividends declared on preference shares	—	—		—			—			—			(75		)	—			(75		)
Adoption of new accounting policy	—	—		—			—			—			16			—			16
As at December 31, 2016	401.5	$	10,762	$	1,623		$	12		$	745		$	1,455		$	1,853		$	16,450

See accompanying Notes to Consolidated Financial Statements



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

1. 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

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.

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

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.



	5



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016


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.

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).



	6



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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").

2. 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%.



	7



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.



	8



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.



	9



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.



	10



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.

3. 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.



	11



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.



	12



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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%).



	13



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.



	14



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.



	15



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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).



	16



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.



	17



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.



	18



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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 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).



	19



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.

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

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.



	20



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.

4. 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.



	21



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.



	22



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.

5. 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.



	23



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016



	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 to common equity shareholders	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 to common equity shareholders	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



	24



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.

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.

6. 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).

7. INVENTORIES



(in millions)	2017		2016
Materials and supplies	$	238	$	244
Gas and fuel in storage	97		98
Coal inventory	32		30
	$	367	$	372



	25



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

8. 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



	26



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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).



	27



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016


(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).



	28



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.



	29



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016


(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.



	30



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

9. 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.

10. 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



	31



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016



		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).



	32



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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

11. 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.



	33



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

12. GOODWILL



(in millions)	2017			2016
Balance, beginning of year	$	12,364		$	4,173
Acquisition of ITC (Note 25)	(6		)	8,106
Acquisition of Aitken Creek (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.

13. 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



	34



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

14. 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



	35



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.



	36



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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 Utilities			Corporate and Other			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.



	37



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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

15. 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.



	38



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.



	39



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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

16. 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.



	40



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.

17. 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



	41



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

18. 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.



	42



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.



	43



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

19. 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



	44



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

20. 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

21. 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.



	45



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

The following table summarizes information related to stock options for 2017.



	Total Options				Non-vested Options ⁽¹⁾
	Number of Options		Weighted Average Exercise Price		Number of Options		Weighted Average Grant Date Fair Value
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



	46



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.



	47



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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

In 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).



	48



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

22. 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.

23. 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	)



	49



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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 not 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



	50



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.



	51



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

24. 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 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



	52



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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 Pension Plans						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).



	53



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

The following table summarizes the employee future benefit assets and liabilities and their classifications on the consolidated balance sheet.



	Defined Benefit Pension Plans				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 Pension Plans						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



	54



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.



	55



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016



Significant weighted average assumptions	Defined Benefit Pension Plans		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 Pension Payments		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.



	56



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

25. 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.



	57



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 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.



	58



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.

26. 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.

27. 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



	59



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

28. 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	)



	60



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016



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		)



	61



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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)).

Energy 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.



	62



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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



	63



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.



	64



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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 Value		Estimated Fair Value	Carrying Value		Estimated Fair Value
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.

29. 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.



	65



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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).



	66



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

30. 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 5 years
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.



	67



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016


⁽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).



	68



FORTIS INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2017 and 2016

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.

31. 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.



	69