Exhibit 99.2

FORTIS INC.

Audited Consolidated Financial Statements

As at and for the years ended December 31, 2016 and 2015

Prepared in accordance with accounting principles generally accepted in the United States

TABLE OF CONTENTS

Management’s Report		i	NOTE 15	Capital Lease and Finance Obligations	38
Independent Auditors’ Report of Registered Public Accounting Firm		ii	NOTE 16	Other Liabilities	40
Consolidated Balance Sheets		1	NOTE 17	Common Shares	41
Consolidated Statements of Earnings		2	NOTE 18	Earnings per Common Share	41
Consolidated Statements of Comprehensive Income		2	NOTE 19	Preference Shares	42
Consolidated Statements of Cash Flows		3	NOTE 20	Accumulated Other Comprehensive Income	44
Consolidated Statements of Changes in Equity		4	NOTE 21	Non-Controlling Interests	45
Notes to Consolidated Financial Statements			NOTE 22	Stock-Based Compensation Plans	45
NOTE 1	Description of Business	5	NOTE 23	Other Income (Expenses), Net	49
NOTE 2	Nature of Regulation	7	NOTE 24	Finance Charges	49
NOTE 3	Summary of Significant Accounting Policies	11	NOTE 25	Income Taxes	50
NOTE 4	Future Accounting Pronouncements	22	NOTE 26	Employee Future Benefits	52
NOTE 5	Segmented Information	25	NOTE 27	Business Acquisitions	58
NOTE 6	Accounts Receivable and Other Current Assets	26	NOTE 28	Dispositions	60
NOTE 7	Inventories	27	NOTE 29	Supplementary Information to Consolidated Statements of Cash Flows	61
NOTE 8	Regulatory Assets and Liabilities	27	NOTE 30	Fair Value Measurements and Financial Instruments	61
NOTE 9	Other Assets	31	NOTE 31	Variable Interest Entity	65
NOTE 10	Utility Capital Assets	32	NOTE 32	Financial Risk Management	66
NOTE 11	Intangible Assets	34	NOTE 33	Commitments	70
NOTE 12	Goodwill	35	NOTE 34	Contingencies	73
NOTE 13	Accounts Payable and Other Current Liabilities	35	NOTE 35	Comparative Figures	73
NOTE 14	Long-Term Debt	36

Management’s Report

The accompanying Annual Consolidated Financial Statements of Fortis Inc. have been prepared by management, who is responsible for the integrity of the information presented including the amounts that must, of necessity, be based on estimates and informed judgments. These Annual Consolidated Financial Statements were prepared in accordance with accounting principles generally accepted in the United States.

In meeting its responsibility for the reliability and integrity of the Annual Consolidated Financial Statements, management has developed and maintains a system of accounting and reporting which provides for the necessary internal controls to ensure transactions are properly authorized and recorded, assets are safeguarded and liabilities are recognized. The systems of the Corporation and its subsidiaries focus on the need for training of qualified and professional staff and the effective communication of management guidelines and policies. The effectiveness of the internal controls of Fortis Inc. is evaluated on an ongoing basis.

The Board of Directors oversees management’s responsibilities for financial reporting through an Audit Committee which is composed entirely of outside independent directors. The Audit Committee oversees the external audit of the Corporation’s Annual Consolidated Financial Statements and the accounting and financial reporting and disclosure processes and policies of the Corporation. The Audit Committee meets with management, the shareholders’ auditors and the internal auditor to discuss the results of the external audit, the adequacy of the internal accounting controls and the quality and integrity of financial reporting. The Corporation’s Annual Consolidated Financial Statements are reviewed by the Audit Committee with each of management and the shareholders’ auditors before the statements are recommended to the Board of Directors for approval. The shareholders’ auditors have full and free access to the Audit Committee. The Audit Committee has the duty to review the adoption of, and changes in, accounting principles and practices which have a material effect on the Corporation’s Annual Consolidated Financial Statements and to review and report to the Board of Directors on policies relating to the accounting and financial reporting and disclosure processes.

The Audit Committee has the duty to review financial reports requiring Board of Directors’ approval prior to the submission to securities commissions or other regulatory authorities, to assess and review management judgments material to reported financial information and to review shareholders’ auditors’ independence and auditors’ fees. The 2016 Annual Consolidated Financial Statements were reviewed by the Audit Committee and, on their recommendation, were approved by the Board of Directors of Fortis Inc. Ernst & Young LLP, independent auditors appointed by the shareholders of Fortis Inc. upon recommendation of the Audit Committee, have performed an audit of the 2016 Annual Consolidated Financial Statements and their report follows.

/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

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 sheets as at December 31, 2016 and 2015, and the consolidated statements of earnings, comprehensive income, cash flows and changes in equity for the years 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 audits. 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 audits 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 audits 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 2015, and its financial performance and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States.

/s/ Ernst & Young LLP

St. John’s, Canada

February 15, 2017    Chartered Professional Accountants

ii

Fortis Inc.
Consolidated Balance Sheets
As at December 31
(in millions of Canadian dollars)
	2016		2015
ASSETS
Current assets
Cash and cash equivalents	$	269	$	242
Accounts receivable and other current assets (Note 6)	1,127		964
Prepaid expenses	85		68
Inventories (Note 7)	372		337
Regulatory assets (Note 8)	313		246
	2,166		1,857
Other assets (Note 9)	406		352
Regulatory assets (Note 8)	2,620		2,286
Utility capital assets (Note 10)	29,337		19,595
Intangible assets (Note 11)	1,011		541
Goodwill (Note 12)	12,364		4,173
	$	47,904	$	28,804
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings (Note 32)	$	1,155	$	511
Accounts payable and other current liabilities (Note 13)	1,970		1,419
Regulatory liabilities (Note 8)	492		298
Current installments of long-term debt (Note 14)	251		384
Current installments of capital lease and finance obligations (Note 15)	76		26
	3,944		2,638
Other liabilities (Note 16)	1,279		1,152
Regulatory liabilities (Note 8)	1,691		1,340
Deferred income taxes (Note 25)	3,263		2,050
Long-term debt (Note 14)	20,817		10,784
Capital lease and finance obligations (Note 15)	460		487
	31,454		18,451
Shareholders’ equity
Common shares (1) (Note 17)	10,762		5,867
Preference shares (Note 19)	1,623		1,820
Additional paid-in capital	12		14
Accumulated other comprehensive income (Note 20)	745		791
Retained earnings	1,455		1,388
Total Fortis Inc. shareholders’ equity	14,597		9,880
Non-controlling interests (Note 21)	1,853		473
	16,450		10,353
	$	47,904	$	28,804
(1) No par value. Unlimited authorized shares; 401.5 million and 281.6 million issued and outstanding as at December 31, 2016 and 2015, respectively	Approved on Behalf of the Board
	/s/ Douglas J. Haughey		/s/ Peter E. Case
Commitments (Note 33)
Contingencies (Note 34)	Douglas J. Haughey,		Peter E. Case,
See accompanying Notes to Consolidated Financial Statements	Director		Director

1

Fortis Inc.
Consolidated Statements of Earnings
For the years ended December 31
(in millions of Canadian dollars, except per share amounts)
		2016		2015
Revenue		$	6,838	$	6,757
Expenses
	Energy supply costs	2,341		2,591
	Operating	2,031		1,874
	Depreciation and amortization	983		873
		5,355		5,338
Operating income		1,483		1,419
Other income (expenses), net (Note 23)		53		197
Finance charges (Note 24)		678		553
Earnings before income taxes		858		1,063
Income tax expense (Note 25)		145		223
Net earnings		$	713	$	840
Net earnings attributable to:
	Non-controlling interests	$	53	$	35
	Preference equity shareholders	75		77
	Common equity shareholders	585		728
		$	713	$	840
Earnings per common share (Note 18)
	Basic	$	1.89	$	2.61
	Diluted	$	1.89	$	2.59
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)
		2016			2015
Net earnings		$	713		$	840
Other comprehensive (loss) income (Note 20)
Unrealized foreign currency translation (losses) gains, net of hedging activities and tax		(50		)	660
Reclassification to earnings of foreign currency translation loss on disposal of investment in foreign operations, net of tax		—			2
Net change in available-for-sale investment, net of tax		2			(2		)
Net change in fair value of cash flow hedges, net of tax		3			1
Net change in employee future benefits, net of tax		(1		)	1
		(46		)	662
Comprehensive income		$	667		$	1,502
Comprehensive income attributable to:
	Non-controlling interests	$	53		$	35
	Preference equity shareholders	75			77
	Common equity shareholders	539			1,390
		$	667		$	1,502
See accompanying Notes to Consolidated Financial Statements

2

Fortis Inc.
Consolidated Statements of Cash Flows
For the years ended December 31
(in millions of Canadian dollars)
			2016			2015
Operating activities
Net earnings			$	713		$	840
Adjustments to reconcile net earnings to net cash provided by
operating activities:
		Depreciation - capital assets	873			785
		Amortization - intangible assets	79			64
		Amortization - other	31			24
		Deferred income tax expense (Note 25)	98			164
		Accrued employee future benefits	58			(19		)
		Equity component of allowance for funds used during construction (Note 23)	(37		)	(23		)
		Gain on sale of non-utility capital assets (Note 23)	—			(131		)
		Gain on sale of non-regulated generation assets (Note 23)	—			(62		)
		Other	64			79
Change in long-term regulatory assets and liabilities			(17		)	(89		)
Change in non-cash operating working capital (Note 29)			22			41
			1,884			1,673
Investing activities
Change in other assets and other liabilities			(89		)	(36		)
Capital expenditures - capital assets			(1,912		)	(2,131		)
Capital expenditures - intangible assets			(149		)	(112		)
Contributions in aid of construction			50			59
Purchase of assets held for sale (Note 6)			—			(32		)
Proceeds on sale of assets (Note 28)			50			922
Business acquisitions, net of cash acquired (Note 27)			(4,841		)	(38		)
			(6,891		)	(1,368		)
Financing activities
Change in short-term borrowings			392			148
Proceeds from long-term debt, net of issue costs (Note 14)			4,136			1,002
Repayments of long-term debt and capital lease and finance obligations			(336		)	(602		)
Net borrowings (repayments) under committed credit facilities			93			(622		)
Advances from non-controlling interests (Notes 21 and 27)			1,361			20
Issue of common shares, net of costs and dividends reinvested (Note 17)			45			40
Redemption of preference shares (Note 19)			(200		)	—
Dividends
	Common shares, net of dividends reinvested		(316		)	(232		)
	Preference shares		(72		)	(77		)
	Subsidiary dividends paid to non-controlling interests		(53		)	(23		)
			5,050			(346		)
Effect of exchange rate changes on cash and cash equivalents			(16		)	53
Change in cash and cash equivalents			27			12
Cash and cash equivalents, beginning of year			242			230
Cash and cash equivalents, end of year			$	269		$	242
Supplementary Information to Consolidated Statements of Cash Flows (Note 29)
See accompanying Notes to Consolidated Financial Statements

3

Fortis Inc.
Consolidated Statements of Changes in Equity
For the years ended December 31, 2016 and 2015
(in millions of Canadian dollars)
	Common Shares		Preference Shares			Additional Paid-In Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Non-Controlling Interests			Total Equity
	(Note 17)		(Note 19)						(Note 20)						(Note 21)
As at January 1, 2016	$	5,867	$	1,820		$	14		$	791		$	1,388		$	473		$	10,353
Net earnings	—		—			—			—			660			53			713
Other comprehensive loss	—		—			—			(46		)	—			—			(46		)
Common share issues	4,895		—			(4		)	—			—			—			4,891
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 (Note 3)	—		—			—			—			16			—			16
As at December 31, 2016	$	10,762	$	1,623		$	12		$	745		$	1,455		$	1,853		$	16,450
As at January 1, 2015	$	5,667	$	1,820		$	15		$	129		$	1,060		$	421		$	9,112
Net earnings	—		—			—			—			805			35			840
Other comprehensive income	—		—			—			662			—			—			662
Common share issues	200		—			(4		)	—			—			—			196
Stock-based compensation	—		—			3			—			—			—			3
Advances from non-controlling interests	—		—			—			—			—			20			20
Foreign currency translation impacts	—		—			—			—			—			20			20
Subsidiary dividends paid to non-controlling interests	—		—			—			—			—			(23		)	(23		)
Dividends declared on common shares ($1.43 per share)	—		—			—			—			(400		)	—			(400		)
Dividends declared on preference shares	—		—			—			—			(77		)	—			(77		)
As at December 31, 2015	$	5,867	$	1,820		$	14		$	791		$	1,388		$	473		$	10,353
See accompanying Notes to Consolidated Financial Statements

4

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

1. DESCRIPTION OF BUSINESS

Fortis Inc. (“Fortis” or the “Corporation”) is principally an international electric and gas utility holding company. Fortis segments its utility operations by franchise area and, depending on regulatory requirements, by the nature of the assets. Fortis also holds investments in non-regulated energy infrastructure, which is treated as a separate 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 profit and loss responsibility and is accountable for its own resource allocation.

The following summary describes the operations included in each of the Corporation’s reportable segments.

REGULATED UTILITIES

Electric & Gas Utilities - United States

a. ITC: Primarily comprised of ITC Holdings Corp. (“ITC Holdings”) 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 (“ITC Great Plains”), (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 21 and 27).

ITC owns and operates high-voltage transmission lines serving a system peak load exceeding 26,000 megawatts (“MW”) along approximately 25,000 kilometres in Michigan’s lower peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from approximately 570 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”).

TEP, UNS Energy’s largest operating subsidiary, 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 2,994 MW, including 54 MW of solar capacity. Several of the generating assets in which TEP and UNS Electric have an interest are jointly owned. As at December 31, 2016, approximately 47% of the generating capacity was fuelled by coal.

UNS Gas is a regulated gas distribution utility, serving retail customers in Arizona’s Mohave, Yavapai, Coconino, Navajo and Santa Cruz counties.

c. Central Hudson: Central Hudson Gas & Electric Corporation (“Central Hudson”) is a regulated transmission and distribution (“T&D”) utility, serving eight counties of New York State’s Mid-Hudson River Valley. The Company owns gas-fired and hydroelectric generating capacity totalling 64 MW.

Gas & Electric Utilities - Canadian

a. FortisBC Energy: FortisBC Energy Inc. (“FortisBC Energy” or “FEI”) is the largest distributor of natural gas in British Columbia, serving more than 135 communities. Major areas served by the Company are the Mainland, Vancouver Island and Whistler regions of British Columbia. FEI provides T&D 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 FEI’s Southern Crossing pipeline, from Alberta.

5

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

1. DESCRIPTION OF BUSINESS (cont’d)

Gas & Electric Utilities - Canadian (cont’d)

b. FortisAlberta:FortisAlberta Inc. (“FortisAlberta”) owns and operates the electricity distribution system in a substantial portion of southern and central Alberta. The Company does not own or operate generation or transmission assets and is not involved in the direct sale of electricity.

c. FortisBC Electric: Includes FortisBC Inc. (“FortisBC Electric”), an integrated 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”) and FortisOntario Inc. (“FortisOntario”). Newfoundland Power is an integrated 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 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 electric utilities that provide service to customers in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario.

Electric Utilities – Caribbean

The Electric Utilities – Caribbean segment includes the Corporation’s approximate 60% controlling ownership interest in Caribbean Utilities Company, Ltd. (“Caribbean Utilities”) (December 31, 2015 - 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 electric utility and the sole provider of electricity on Grand Cayman, Cayman Islands. The Company has an installed diesel-powered generating capacity of 161 MW. Caribbean Utilities is a public company traded on the Toronto Stock Exchange (“TSX”) (TSX:CUP.U). Fortis Turks and Caicos is comprised of two integrated electric utilities that provide electricity to certain islands in Turks and Caicos. The utilities have a combined diesel-powered generating capacity of 82 MW. Belize Electricity is an integrated electric utility and the principal distributor of electricity in Belize.

NON-REGULATED - ENERGY INFRASTRUCTURE

Non-Regulated - Energy Infrastructure is 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 (“ACGS”), acquired by Fortis in April 2016, owns 93.8% of Aitken Creek, with the remaining share owned by BP Canada Energy Company (Note 27). 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”) and in 2015 the Corporation sold its non-regulated generation assets in Upstate New York and Ontario (Note 28).

6

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

1. DESCRIPTION OF BUSINESS (cont’d)

NON-REGULATED - NON-UTILITY

The Non-Utility segment previously included Fortis Properties Corporation (“Fortis Properties”).Fortis Properties completed the sale of its commercial real estate and hotel assets in 2015(Note 28).

CORPORATE AND OTHER

The Corporate and Other segment 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”), CH Energy Group, Inc. (“CH Energy Group”), and UNS Energy Corporation. Also included in the Corporate and Other segment are the financial results of FortisBC Alternative Energy Services Inc. (“FAES”). FAES is a wholly owned subsidiary of FHI that provides alternative energy solutions, including thermal-energy and geo-exchange systems.

2. NATURE OF REGULATION

The earnings of the Corporation’s utilities are primarily determined under cost of service (“COS”) regulation and, in certain jurisdictions, performance-based rate-setting (“PBR”) mechanisms. 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 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 is as follows.

ITC

ITC is regulated by the U.S. Federal Energy Regulatory Commission (“FERC”) under the Federal Power Act (United States) and operates under COS regulation. 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, 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 2015 and 2016.

7

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

2. NATURE OF REGULATION(cont’d)

ITC (cont’d)

Since 2013 two third-party complaints were filed with FERC requesting that FERC find the Midcontinent Independent System Operator (“MISO”) regional base ROE for all MISO transmission owners, including ITCTransmission, METC and ITC Midwest, for the periods November 2013 through February 2015 (the “Initial Refund Period”) and February 2015 through May 2016 (the “Second Refund Period”) to no longer be just or reasonable. In September 2016 FERC issued an order affirming the presiding Administrative Law Judge’s (“ALJ’s”) initial decision for the Initial Refund Period and setting the base ROE for the Initial Refund Period at 10.32%, with a maximum ROE of 11.35%. Additionally, the rates established in the September 2016 order will be used prospectively from the date of the order until a new approved rate is established for the Second Refund Period. In June 2016 the presiding ALJ issued an initial decision for the Second Refund Period, which recommended a base ROE of 9.70%, with a maximum ROE of 10.68%, which is a recommendation to FERC. A decision from FERC for the Second Refund Period is expected in 2017. 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%. As at December 31, 2016, the estimated range of refunds for both periods was between US$221 million and US$258 million and ITC has recognized an aggregate estimated regulatory liability of US$258 million (Note 8 (xii)). In February 2017 ITC provided refunds totalling US$119 million, including interest, for the initial complaint. The estimated regulatory liability was accrued by ITC before its acquisition by Fortis. 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 operates under COS regulation as administered by the ACC, which provides for the use of 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.

TEP’s allowed ROE is set at 10.0% on a capital structure of 43.5% common equity, effective from July 1, 2013. In February 2017 the ACC approved an allowed ROE of 9.75% on a capital structure of 50%, effective on or before March 1, 2017. 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.

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 operates under COS regulation as administered by the PSC with the use of 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. Prior to July 1, 2015, Central Hudson was operating under a three-year rate order issued by the PSC effective July 1, 2010 with an allowed ROE set at 10.0% on a deemed capital structure of 48% common equity, which was extended for two years, through June 30, 2015, as part of the regulatory approval of the acquisition of Central Hudson by Fortis.

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. Prior to July 1, 2015, an earnings sharing mechanism was in place whereby the Company and customers shared equally earnings in excess of the allowed ROE up to an achieved ROE that is 50 basis points above the allowed ROE, and shared 10%/90% (Company/customers) earnings in excess of 50 basis points above the allowed ROE.

8

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

2. NATURE OF REGULATION (cont’d)

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). The Companies primarily operate under COS regulation and, from time to time, PBR mechanisms for establishing customer rates.

FEI is the benchmark utility in British Columbia, as designated by the BCUC, and the established allowed ROE for the benchmark utility was 8.75% on a 38.5% common equity component of capital structure, both effective January 1, 2013 through December 31, 2015. In August 2016 the BCUC issued its decision on the Generic Cost of Capital (“GCOC”) Proceeding which established that the ROE and common equity component of capital structure for the benchmark utility would remain unchanged at 8.75% and 38.5%, respectively, 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, also remained unchanged, effective January 1, 2016.

FEI and FortisBC Electric are subject to Multi-Year PBR Plans for 2014 through 2019. 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 FEI 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 FEI 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.

For 2013 through 2015, FortisAlberta’s allowed ROE was set at 8.30% with a common equity component of capital structure at 40%. In October 2016 the AUC issued its decision related to FortisAlberta’s 2016 and 2017 GCOC 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, down from 40% approved on an interim basis. 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.

9

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

2. NATURE OF REGULATION (cont’d)

Eastern Canadian Electric Utilities

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 operates under COS regulation with the use of 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, down from 8.80% in effect since January 1, 2013. The decision also established that Newfoundland Power’s common equity component of capital structure of 45%, effective January 1, 2013, remain unchanged. The June 2016 rate order will remain in effect for 2016 through 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) (“Accord Continuation Act”), which expired in February 2016. Maritime Electric operates under COS regulation with the use of 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 minimum 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 operate under COS regulation with the use of 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 8.93% to 9.30% for 2015 and 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 Electric Utilities - Caribbean

Caribbean Utilities operates under T&D and generation licences from the Government of the Cayman Islands. The exclusive T&D 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 Electricity Regulatory Authority, 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 2016 was in the range of 6.75% to 8.75%, compared to a range of 7.25% to 9.25% for 2015.

Fortis Turks and Caicos operates under two50-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 submissions for 2016 calculated the Allowable Operating Profit to be $58 million (US$44 million) and the Cumulative Shortfall as at December 31, 2016 to be $317 million (US$236 million). The recovery of the Cumulative Shortfall is, however, 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.

10

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“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. All material 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 31.

An evaluation of subsequent events through to February 15, 2017, the date these consolidated financial statements were approved by the Board of Directors of Fortis (“Board of Directors”), was completed to determine whether the circumstances warranted recognition and disclosure of events or transactions in the consolidated financial statements as at December 31, 2016.

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 market value.

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.

11

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d)

Investments

Portfolio investments are accounted for on the cost basis. Declines in value considered to be other than temporary are recorded in the period in which such determinations are made. 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. Should an impairment be identified, it will be recognized in the period in which such impairment is identified.

Available-for-Sale Assets

The Corporation’s assets designated as available-for-sale are measured at fair value based on quoted market prices. Unrealized gains or losses resulting from changes in fair value are recognized in accumulated other comprehensive income and are reclassified to earnings when the assets are sold.

Utility Capital Assets

Utility capital assets are recorded at cost less accumulated depreciation. Contributions in aid of construction represent amounts contributed by customers and governments for the cost of utility capital assets. These contributions are recorded as a reduction in the cost of utility capital assets and are being amortized annually by an amount equal to the charge for depreciation provided on the related assets.

The majority of the Corporation’s regulated utilities accrue non-asset retirement obligation (“ARO”) removal costs in depreciation, with the amount provided for in depreciation recorded as a long-term regulatory liability (Note 8(xi)). Actual non-ARO removal costs are recorded against the regulatory liability when incurred.

For the majority of the Corporation’s regulated utilities, utility capital assets are derecognized on disposal or when no future economic benefits are expected from their use. Upon retirement or disposal of utility capital assets, 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 utility capital assets but relate to the overall capital expenditure program. The methodology for calculating and allocating capitalized overhead costs to utility capital assets is established by the respective regulator.

The majority of the Corporation’s regulated utilities include in the cost of utility capital assets both a debt and an equity component of the allowance for funds used during construction (“AFUDC”). The debt component of AFUDC is reported as a reduction of finance charges (Note 24) and the equity component of AFUDC is reported as other income (Note 23). Both components of AFUDC are charged to earnings through depreciation expense over the estimated service lives of the applicable utility capital assets. AFUDC is calculated in a manner as prescribed by the respective regulator.

At FortisAlberta the cost of utility capital assets also includes Alberta Electric System Operator (“AESO”) contributions, which are investments required by FortisAlberta to partially fund the construction of transmission facilities.

Utility capital assets include inventories held for the development, construction and betterment of other utility capital assets. As required by its regulator, UNS Energy recognizes inventories held for the development and construction of other utility capital assets in inventories until consumed. When put into service, the inventories are reclassified to utility capital assets.

Maintenance and repairs of utility capital assets are charged to earnings in the period incurred, while replacements and betterments which extend the useful lives are capitalized.

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FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d)

Utility Capital Assets (cont’d)

The majority of the Corporation’s utility capital assets are depreciated using the straight-line method based on the estimated service lives of the utility capital assets. Depreciation rates for regulated utility capital assets are approved by the respective regulator. Depreciation rates for 2016 ranged from 0.9% to 34.6% (2015 - 1.3% to 43.2%). The weighted average composite rate of depreciation, before reduction for amortization of contributions in aid of construction, for 2016 was 2.8% (2015 – 3.1%).

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.

		2016		2015
(Years)		Service Life Ranges	Weighted Average Remaining Service Life	Service Life Ranges	Weighted Average Remaining Service Life
Distribution
	Electric	5-80	32	5-80	30
	Gas	7-95	33	4-95	33
Transmission
	Electric	20-80	41	20-80	29
	Gas	7-80	34	7-80	36
Generation		5-85	26	5-85	27
Other		3-70	14	3-70	8

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. Included as capital leases are any arrangements that qualify as leases by conveying the right to use a specific asset.

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 2016 ranged from 1.0% to 50.0% (2015 – 1.0% to 50.0%).

13

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d)

Intangible Assets (cont’d)

The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows.

	2016		2015
(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	30-80	57	30-80	37
Other	10-104	15	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 utility capital assets, 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. No such event or change in circumstances occurred during 2016 or 2015.

14

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d)

Goodwill (cont’d)

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 12 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 determined by an external consultant 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. Irrespective of the above-noted approach, a reporting unit to which goodwill has been allocated may have its fair value estimated by an external consultant as at the annual impairment date, as Fortis will, at a minimum, have fair value for each material reporting unit estimated by an external consultant once every five years.

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, a second measurement step is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the reporting unit’s assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill, and then comparing that amount to the carrying value of the reporting unit’s goodwill. Any excess of the carrying value of the goodwill over the implied fair value is the impairment amount recognized.

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 exceeded their respective carrying value and, therefore, no impairment provision was required in2016 or 2015.

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.

15

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d)

Employee Future Benefits (cont’d)

Defined Benefit and Defined Contribution Pension Plans (cont’d)

With the exception of FortisBC Energy and Newfoundland Power, pension plan assets are valued at fair value for the purpose of determining pension cost. At FortisBC Energy and Newfoundland Power, pension plan assets are valued using the market-related value for the purpose of determining pension cost, where investment returns in excess of, or below, expected returns are recognized in the asset value over a period of three years.

The excess of any cumulative net actuarial gain or loss over 10% of the greater of the projected benefit obligation and the fair value of plan assets (the market-related value of plan assets at FortisBC Energy and Newfoundland Power) at the beginning of the fiscal year, along with unamortized past service costs, are deferred and amortized over the average remaining service period of active employees.

The net funded or unfunded status of defined benefit pension plans, measured as the difference between the fair value of the plan assets and the projected benefit obligation, is recognized on the Corporation’s consolidated balance sheet.

For the majority of the Corporation’s regulated utilities, any difference between pension cost recognized under US GAAP and that recovered from customers in current rates for defined benefit pension plans, which is expected to be recovered from, or refunded to, customers in future rates, is subject to deferral account treatment (Note 8(ii)).

With the exception of Fortis and FHI, any unamortized balances related to net actuarial gains and losses, past service costs and transitional obligations associated with defined benefit pension plans, which would otherwise be recognized in accumulated other comprehensive income, are subject to deferral account treatment (Note 8(ii)). At Fortis and FHI, any unamortized balances related to net actuarial gains and losses, past service costs and transitional obligations associated with defined benefit pension plans are recognized in accumulated other comprehensive income.

The costs of the defined contribution pension plans are expensed as incurred.

Other Post-Employment Benefits Plans

The Corporation and its subsidiaries also offer other post-employment benefits (“OPEB”) plans, including certain health and dental coverage and life insurance benefits, for qualifying members. The accumulated benefit obligation and the cost associated with OPEB plans are actuarially determined using the projected benefits method prorated on service and management’s best estimate of expected plan performance, salary escalation, expected retirement ages of employees and health care costs. Discount rates reflect market interest rates on high-quality bonds with cash flows that match the timing and amount of expected OPEB payments.

The excess of any cumulative net actuarial gain or loss over 10% of the accumulated benefit obligation and the fair value of plan assets at the beginning of the fiscal year, along with unamortized past service costs, are deferred and amortized over the average remaining service period of active employees.

The net funded or unfunded status of OPEB plans, measured as the difference between the fair value of the plan assets and the accumulated benefit obligation, is recognized on the Corporation’s consolidated balance sheet.

For the majority of the Corporation’s regulated utilities, any difference between the cost of OPEB plans recognized under US GAAP and that recovered from customers in current rates, which is expected to be recovered from, or refunded to, customers in future rates, is subject to deferral account treatment (Note 8(ii)).

16

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d)

Employee Future Benefits (cont’d)

Other Post-Employment Benefits Plans (cont’d)

At FortisAlberta, the difference between the cost of OPEB plans recognized under US GAAP and that recovered from customers in current rates does not meet the criteria for deferral account treatment and, therefore, FortisAlberta recognizes in earnings the cost associated with its OPEB plan as actuarially determined, rather than as approved by the regulator. Unamortized OPEB plan balances at FortisAlberta related to net actuarial gains and losses and past service costs are recognized in accumulated other comprehensive income.

Stock-Based Compensation

The Corporation records compensation expense related to stock options granted under its 2002 Stock Option Plan (“2002 Plan”), 2006 Stock Option Plan (“2006 Plan”) and 2012 Stock Option Plan (“2012 Plan”) (Note 22). 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. 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, 2016 was $41.46 (December 31, 2015 - $37.72). 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, 2016 was US$1.00=CAD$1.34 (December 31, 2015 – US$1.00=CAD$1.38). 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$1.33 for 2016 (2015 – US$1.00=CAD$1.28).

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.

17

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d)

Derivative Instruments and Hedging Activities

Non-Designated Derivatives

Derivatives not designated as hedging contracts are used by 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(ix)).

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, 2016, 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 income 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 significant influence investments are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has decreased a portion of the above-noted exposure through the use of US dollar-denominated borrowings at the corporate level. The Corporation has designated its corporately issued US dollar long-term debt as a hedge of a portion of the foreign exchange risk related to its foreign net investments. Foreign currency exchange rate fluctuations associated with the translation of the Corporation’s corporately issued US dollar-denominated borrowings designated as hedges are recognized in accumulated other comprehensive income and help offset unrealized foreign currency exchange gains and losses on the foreign net investments, which gains and losses are also recognized in accumulated other comprehensive income.

Presentation of Derivatives

The fair value of derivative instruments are recognized on the Corporation’s consolidated balance sheet as current or long-term assets and liabilities depending on the timing of the settlements and the resulting cash flows associated with the instruments. Derivative contracts under master netting agreements and collateral positions are presented on a gross basis. Cash flows associated with the settlement of all derivative instruments are included in operating activities on the Corporation’s consolidated statement of cash flows.

18

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d)

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. Therefore, with the exception of certain deferred tax balances of FortisBC Energy, FortisBC Electric, Newfoundland Power and FortisOntario, current customer rates do not include the recovery of deferred income taxes related to temporary differences between the tax basis of assets and liabilities and their carrying amounts for regulatory purposes, as these taxes are expected to be collected in customer rates when they become payable. These utilities recognize an offsetting regulatory asset or liability for the amount of deferred income taxes that are expected to be collected from or refunded to customers in rates once income taxes become payable or receivable (Note 8(i)).

For regulatory reporting purposes, the capital cost allowance pool for certain utility capital assets 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 (“GOB”) 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 $525 million as at December 31, 2016 (December 31,2015 - $565 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.

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FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d)

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(iii)).

In certain circumstances, UNS Energy enters 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 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 30).

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FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d)

Asset Retirement Obligations

AROs, including conditional AROs, are recorded as a liability at fair value and are classified as long-term other liabilities, with a corresponding increase to utility capital assets. 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 has AROs associated with the remediation of hydroelectric 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.

New Accounting Policies

Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern

Effective January 1, 2016, the Corporation adopted ASU No. 2014-15, which provides guidance on management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and provide related disclosures. The adoption of this update did not impact the Corporation’s consolidated financial statements and related disclosures.

Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items

Effective January 1, 2016, the Corporation prospectively adopted ASU No. 2015-01, which is part of the Financial Accounting Standards Board’s (“FASB’s”) initiative to reduce complexity in accounting standards by eliminating the concept of extraordinary items. The adoption of this update did not impact the Corporation’s consolidated financial statements.

Amendments to the Consolidation Analysis

Effective January 1, 2016, the Corporation adopted ASU No. 2015-02, which changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. Specifically, the amendments note the following regarding limited partnerships: (i) modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities; and (ii) eliminate the presumption that a general partner should consolidate a limited partnership. The amendments in this update did not materially impact the Corporation’s consolidated financial statements, however, did change the Corporation’s51%controlling ownership interest in the Waneta Partnership from a voting interest entity to a variable interest entity, resulting in additional disclosure(Note 31).

Simplifying the Accounting for Measurement-Period Adjustments

Effective January 1, 2016, the Corporation prospectively adopted ASU No. 2015-16, which requires that in a business combination an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Under previous guidance, these adjustments were required to be accounted for retrospectively. The adoption of this update did not impact the Corporation’s consolidated financial statements.

21

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d)

New Accounting Policies (cont’d)

Improvements to Employee Share-Based Payment Accounting

Effective January 1, 2016, the Corporation early adopted ASU No. 2016-09, which simplifies the accounting for share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance requires excess tax benefits and tax deficiencies to be recognized as an income tax benefit or expense in the consolidated statement of earnings. On adoption, using the modified retrospective method, the Corporation recognized a cumulative adjustment of $16 millionrelated to prior period unrecognized excess tax benefits at UNS Energy, which increased retained earnings and decreased deferred income tax liabilities. In 2016 the adoption of this update also resulted in a $7 milliondecrease in income tax expense and decrease in deferred income tax liabilities related to excess tax benefits at ITC from the date of acquisition, largely associated with the accelerated vesting of the Company’s stock-based compensation awards as a result of the acquisition. The guidance also allows for an accounting policy election to either estimate forfeitures or account for them when they occur. The Corporation elected to account for forfeitures when they occur. This policy election did not have a material impact on the Corporation’s consolidated financial statements.

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, 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, Utility Capital Assets, Intangible Assets, Goodwill, Employee Future Benefits, Income Taxes, Revenue Recognition, Asset Retirement Obligations 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 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 are 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 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 can be applied consistently across various transactions, industries and capital markets. In 2016 a number of additional ASUs were issued that clarify implementation guidance in ASC Topic 606. This standard, and all related ASUs, is effective for annual and interim periods beginning after December 15, 2017. Early adoption is permitted for annual and interim periods beginning after December 15, 2016. The Corporation has elected not to early adopt.

22

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

4. FUTURE ACCOUNTING PRONOUNCEMENTS (cont’d)

Revenue from Contracts with Customers (cont’d)

The new guidance permits two methods of adoption: (i) the full retrospective method, under which comparative periods would be restated, and the cumulative impact of applying the standard would be recognized as at January 1, 2017, the earliest period presented; 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, January 1, 2018. The Corporation expects to use the modified retrospective approach, however, it continues to monitor industry developments. Any significant industry developments could change the Corporation’s expected method of adoption.

The majority of the Corporation’s revenue is generated from energy sales to retail customers based on published tariff rates, as approved by the respective regulators, and from transmission services and is considered to be in the scope of ASU No. 2014-09. Fortis does not expect that the adoption of this standard, and all related ASUs, will have a material impact on the recognition of revenue generated from energy sales to retail customers, or on its remaining material revenue streams; however, the Corporation does expect it will impact its required disclosures. Certain industry specific interpretative issues, including contributions in aid of construction, remain outstanding and the conclusions reached, if different than currently anticipated, could have a material impact on the Corporation’s consolidated financial statements and related disclosures. Fortis continues to closely monitor industry developments related to the new standard.

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; however, entities will be able to elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and (ii) financial assets and financial liabilities to be presented separately in the notes to the consolidated financial statements, grouped by measurement category and form of financial asset. This update is effective for annual and interim periods beginning after December 15, 2017. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.

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 and related disclosures.

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. Early adoption is permitted for annual and interim periods beginning after December 15, 2018. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.

23

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

4. FUTURE ACCOUNTING PRONOUNCEMENTS (cont’d)

Simplifying the Test for Goodwill Impairment

ASU No. 2017-04, Simplifying the Test for Goodwill Impairment, was issued in January 2017 and 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. This update is effective for annual and interim periods beginning after December 15, 2019 and is to be applied on a prospective basis. Early adoption is permitted for interim and annual goodwill impairment tests performed on testing dates after January 1, 2017. Fortis expects to early adopt this update in 2017; however, does not expect that it will have a material impact on its consolidated financial statements and related disclosures.

24

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

5.    SEGMENTED INFORMATION

Information by reportable segment is as follows:

	REGULATED										NON-REGULATED
Year Ended	United States			Canada							Energy				Inter-
December 31, 2016		UNS	Central	FortisBC	Fortis		FortisBC	Eastern	Caribbean		Infra-	Non-	Corporate		segment
($ millions)	ITC	Energy	Hudson	Energy	Alberta		Electric	Canadian	Electric	Total	structure	Utility	and Other		eliminations		Total
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 (loss)	137	393	148	311	203		100	138	65	1,495	91	—	(103	)	—		1,483
Other income (expenses), 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 (recovery)	20	99	43	51	—		9	21	—	243	3	—	(101	)	—		145
Net earnings (loss)	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 (loss) 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
Identifiable assets	9,754	7,081	2,609	5,317	3,830		1,908	2,327	1,154	33,980	1,475	—	130		(45	)	35,540
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
Gross capital expenditures	223	524	233	336	375		74	161	106	2,032	19	—	10		—		2,061
Year Ended
December 31, 2015
($ millions)
Revenue	—	2,034	880	1,295	563		360	1,033	321	6,486	107	171	24		(31	)	6,757
Energy supply costs	—	820	315	498	—		116	673	169	2,591	1	—	—		(1	)	2,591
Operating expenses	—	573	381	292	183		89	143	46	1,707	19	124	36		(12	)	1,874
Depreciation and amortization	—	242	56	190	168		57	82	47	842	18	11	2		—		873
Operating income (loss)	—	399	128	315	212		98	135	59	1,346	69	36	(14	)	(18	)	1,419
Other income (expenses), net	—	5	8	11	3		—	2	2	31	56	109	2		(1	)	197
Finance charges	—	98	38	134	78		39	56	14	457	3	18	94		(19	)	553
Income tax expense (recovery)	—	111	40	51	(1	)	9	19	—	229	24	13	(43	)	—		223
Net earnings (loss)	—	195	58	141	138		50	62	47	691	98	114	(63	)	—		840
Non-controlling interests	—	—	—	1	—		—	—	13	14	21	—	—		—		35
Preference share dividends	—	—	—	—	—		—	—	—	—	—	—	77		—		77
Net earnings (loss) attributable   to common equity shareholders	—	195	58	140	138		50	62	34	677	77	114	(140	)	—		728
Goodwill	—	1,912	624	913	227		235	67	195	4,173	—	—	—		—		4,173
Identifiable assets	—	6,977	2,601	5,116	3,592		1,872	2,219	1,084	23,461	1,025	—	352		(207	)	24,631
Total assets	—	8,889	3,225	6,029	3,819		2,107	2,286	1,279	27,634	1,025	—	352		(207	)	28,804
Gross capital expenditures	—	669	181	460	452		103	175	137	2,177	38	9	19		—		2,243

25

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

5.    SEGMENTED INFORMATION (cont’d)

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 2016 or 2015.

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 2016 and 2015 are summarized in the following table.

(in millions)	2016		2015
Sale of capacity from Waneta Expansion to FortisBC Electric (Note 36)	$	45	$	30
Sale of energy from BECOL to Belize Electricity	33		30
Lease of gas storage capacity from Aitken Creek to FortisBC Energy	17		—

As at December 31, 2016, accounts receivable on the Corporation’s consolidated balance sheet included approximately $16 million due from Belize Electricity (December 31, 2015 - $5 million), in which Fortis holds a 33% equity investment.

From time to time, the Corporation provides short-term financing to certain of its subsidiaries to support capital expenditure programs, acquisitions and seasonal working capital requirements, bearing interest at rates that approximate the Corporation’s cost of short-term borrowing, and provides long-term financing to certain of its subsidiaries, bearing interest at rates that approximate the Corporation’s cost of long-term debt. There were no inter-segment loans outstanding as at December 31, 2016 (December 31, 2015 - $48 million) and total interest charged in 2016 was less than $1 million (2015 -$17 million).

6. ACCOUNTS RECEIVABLE AND OTHER CURRENT ASSETS

(in millions)	2016			2015
Trade accounts receivable	$	507		$	517
Unbilled accounts receivable	551			404
Allowance for doubtful accounts	(33		)	(66		)
Income tax receivable	26			—
Assets held for sale	—			38
Other	76			71
	$	1,127		$	964

The decrease in the allowance for doubtful accounts was due to the settlement and release of a reserve at UNS Energy in relation to billings to third-party owners of Springerville Unit 1.

Assets held for sale as at December 31, 2015 included utility capital assets of approximately $29 million (US$21 million) purchased by UNS Energy upon expiration of the Springerville Coal Handling Facilities lease in April 2015. UNS Energy has an agreement with a third party whereby they can purchase a 17.05% interest or continue to make payments to UNS Energy for the use of the facility. In March 2016 the third party notified UNS Energy that it was exercising its option to purchase, however, as at December 31,2016, it was no longer probable that the sale would be completed and UNS Energy reclassified the assets held for sale to utility capital assets (Note 10). As at December 31, 2015, assets held for sale also included the non-regulated Walden hydroelectric power plant assets of approximately $9 million, which were sold in February 2016 (Note 28).

Other consisted of customer billings for non-core services, collateral deposits for gas purchases at FortisBC Energy and advances on coal purchases at UNS Energy, as well as the fair value of derivative instruments (Note 30).

26

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

7. INVENTORIES

(in millions)	2016		2015
Materials and supplies	$	244	$	194
Gas and fuel in storage	98		101
Coal inventory	30		42
	$	372	$	337

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)	2016			2015			(Years)
Regulatory assets
Deferred income taxes (i)	$	1,260		$	936		To be determined
Employee future benefits (ii)	576			627			Various
Rate stabilization accounts (iii)	183			119			Various
Deferred energy management costs (iv)	178			145			1-10
Manufactured gas plant (“MGP”) site remediation deferral (v)	107			121			To be determined
Deferred lease costs (vi)	97			90			Various
Deferred operating overhead costs (vii)	78			66			Various
Natural gas for transportation incentives (viii)	40			25			10
Derivative instruments (ix)	19			74			Various
Other regulatory assets (x)	395			329			Various
Total regulatory assets	2,933			2,532
Less: current portion	(313		)	(246		)	1
Long-term regulatory assets	$	2,620		$	2,286
Regulatory liabilities
Non-ARO removal cost provision (xi)	$	1,194		$	1,060		To be determined
ROE refund liability (xii)	346			—			2
Rate stabilization accounts (iii)	230			212			Various
Electric and gas moderator account (xiii)	71			88			To be determined
Renewable energy surcharge (xiv)	53			47			To be determined
Energy efficiency liability (xv)	49			20			Various
Employee future benefits (ii)	42			44			Various
Other regulatory liabilities (xvi)	198			167			Various
Total regulatory liabilities	2,183			1,638
Less: current portion	(492		)	(298		)	1
Long-term regulatory liabilities	$	1,691		$	1,340

27

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

8. REGULATORY ASSETS AND LIABILITIES (cont’d)

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, 2016, $596 million (December 31, 2015 - $351 million) in regulatory assets for deferred income taxes was not subject to a regulatory return.

(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, which are expected to be recovered from, or refunded to, customers in future rates (Note 26). 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, 2016, regulatory assets of approximately $346 million associated with employee future benefits were not subject to a regulatory return (December 31, 2015 - $367 million). As at December 31, 2016, regulatory liabilities of approximately $31 million associated with employee future benefits were not subject to a regulatory return (December 31, 2015 - $36 million).

(iii) 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. Included in the rate stabilization accounts at ITC is US$29 million related to regional cost allocation recovery for refunds ITC paid to other regional transmission organizations, which will be recovered from network customers in 2017.

As at December 31, 2016, approximately $135 million and $173 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, 2015 -approximately $49 million and $142 million, respectively).

28

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

8. REGULATORY ASSETS AND LIABILITIES (cont’d)

Description of the Nature of Regulatory Assets and Liabilities (cont’d)

(iii) Rate Stabilization Accounts (cont’d)

As at December 31, 2016, regulatory assets of approximately $139 million associated with rate stabilization accounts were not subject to a regulatory return (December 31, 2015 ‑ $44 million). As at December 31, 2016, regulatory liabilities of approximately $180 million associated with rate stabilization accounts were not subject to a regulatory return (December 31, 2015 ‑ $123 million).

(iv) 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, 2016, $42 million of the regulatory asset balance associated with deferred energy management costs was not subject to a regulatory return (December 31, 2015 - $25 million).

(v) 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 13and16). Central Hudson’s MGP site remediation costs are not subject to a regulatory return.

(vi)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. 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 2016, of the $31 million (2015 - $30 million) of interest expense related to the capital lease obligations and the $6 million (2015 - $6 million) of depreciation expense related to the assets under capital lease, $27 million (2015 - $26 million) was recognized in energy supply costs and $3 million (2015 - $3 million) was recognized in operating expenses, as approved by the regulator, with the balance of $7 million (2015 - $7 million) deferred as a regulatory asset (Note 15).

(vii) Deferred Operating Overhead Costs

As approved by the regulator, FortisAlberta has deferred certain operating overhead costs. The deferred costs are expected to be collected in future customer rates over the lives of the related utility capital and intangible assets.

29

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

8. REGULATORY ASSETS AND LIABILITIES (cont’d)

Description of the Nature of Regulatory Assets and Liabilities (cont’d)

(viii) Natural Gas for Transportation Incentives

The deferral for natural gas transportation incentives at FortisBC Energy is comprised of subsidy payments to assist customers in purchasing natural gas vehicles in lieu of vehicles fueled by diesel as part of the incentive program pursuant to the greenhouse gas reductions regulations under the Clean Energy Act (British Columbia). The regulator has approved recovery in rates over a 10-year period.

(ix) 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 $6 million as at December 31, 2016 was not subject to a regulatory return (December 31, 2015 - $57 million).

(x) 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, 2016, $296 million (December 31, 2015 - $265 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, 2016, $217 million (December 31, 2015 ‑ $168 million) of the balance was not subject to a regulatory return.

(xi) Non-ARO Removal Cost Provision

As required by the respective regulators, depreciation rates include an amount allowed for regulatory purposes to accrue for non-ARO removal costs. Actual non‑ARO removal costs are recorded against the regulatory liability when incurred. This regulatory liability represents amounts collected in customer rates at the respective utilities in excess of incurred non-ARO removal costs.

(xii) ROE Refund Liability

The ROE refund liability at ITC relates to two third-party complaints filed with FERC dating back to 2013, requesting that FERC find the MISO regional base ROE for all MISO transmission owners, including ITC for the periods November 2013 through February 2015 and February 2015 through May 2016, to no longer be just and reasonable (Note 2). As at December 31, 2016, the estimated range of refunds for both periods was between US$221 million and US$258 million and ITC has recognized an aggregate estimated regulatory liability of US$258 million, of which US$119 million has been classified as current regulatory liabilities.

(xiii) 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 is not subject to a regulatory return.

30

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

8. REGULATORY ASSETS AND LIABILITIES (cont’d)

Description of the Nature of Regulatory Assets and Liabilities (cont’d)

(xiv) 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 not 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 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 (Note 9). 

(xv) Energy Efficiency Liability

The energy efficiency regulatory 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.

(xvi) 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, 2016, $190 million (December 31, 2015 - $156 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, 2016, $51 million (December 31, 2015 – $80 million) of the balance was not subject to a regulatory return.

9. OTHER ASSETS

(in millions)	2016		2015
Supplemental Executive Retirement Plan assets	$	115	$	58
Equity investment - Belize Electricity	78		79
Renewable Energy Credits (Note 8 (xiv))	39		17
Defined benefit pension plan assets (Note 26)	32		11
Deferred compensation plan assets (Note 16)	24		25
Other investments	21		13
Available-for-sale investment (Notes 28 and 30)	—		33
Deposit on acquisition of Aitken Creek (Note 27)	—		38
Other	97		78
	$	406	$	352

31

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

9. OTHER ASSETS (cont’d)

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 30). Included in SERP assets are available-for-sale-securities at ITC of US$42 million, for which gains and losses are recorded in other comprehensive income.

In August 2015 the Corporation agreed to terms of a settlement with the GOB regarding the GOB’s expropriation of the Corporation’s approximate 70% interest in Belize Electricity in June 2011. The terms of the settlement included a one-time US$35 million cash payment to Fortis from the GOB and an approximate 33% equity investment in Belize Electricity. As a result of the settlement, the Corporation recognized an approximate $9 million loss in 2015 (Note 23).

Other assets are recorded at cost and are recovered or amortized over the estimated period of future benefit, where applicable. Other assets also includes the fair value of derivative instruments (Note 30).

10. UTILITY CAPITAL ASSETS

		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

32

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

10. UTILITY CAPITAL ASSETS (cont’d)

		2015
(in millions)		Cost		Accumulated Depreciation			Net Book Value
Distribution
	Electric	$	9,245	$	(2,634	)	$	6,611
	Gas	3,829		(1,021		)	2,808
Transmission
	Electric	3,093		(997		)	2,096
	Gas	1,735		(531		)	1,204
Generation		6,465		(2,241		)	4,224
Other		2,429		(849		)	1,580
Assets under construction		886		—			886
Land		186		—			186
		$	27,868	$	(8,273	)	$	19,595

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 27).

As at December 31, 2016, 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 utility capital assets under capital lease as at December 31, 2016 was $539 million (December 31, 2015 - $496 million) and related accumulated depreciation was $231 million (December 31, 2015 - $221 million).

33

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

10. UTILITY CAPITAL ASSETS (cont’d)

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 utility capital assets, and are proportionately liable for the associated operating costs and liabilities. As at December 31, 2016, interests in jointly owned facilities consisted of the following.

	Ownership			Accumulated			Net Book
(in millions)	%	Cost		Depreciation			Value
San Juan Units 1 and 2	50.0	$	670	$	(352	)	$	318
Navajo Units 1, 2 and 3	7.5	206		(153		)	53
Four Corners Units 4 and 5	7.0	185		(103		)	82
Luna Energy Facility	33.3	73		(3		)	70
Gila River Common Facilities	25.0	44		(15		)	29
Springerville Coal Handling Facilities (1)	83.0	270		(108		)	162
Transmission Facilities	1.0-80.0	750		(236		)	514
		$	2,198	$	(970	)	$	1,228

⁽¹⁾  In 2016 UNS Energy reclassified an additional 17.05% undivided interest in the Springerville Coal Handling Facilities from assets held for sale (Note 6).

11. INTANGIBLE ASSETS

	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
	2015
			Accumulated			Net Book
(in millions)	Cost		Amortization			Value
Computer software	$	685	$	(436	)	$	249
Land, transmission and water rights	328		(76		)	252
Other	17		(13		)	4
Assets under construction	36		—			36
	$	1,066	$	(525	)	$	541

Included in the cost of land, transmission and water rights as at December 31, 2016 was $138 million (December 31, 2015 - $106 million) not subject to amortization.

Amortization expense related to intangible assets was $79 million for 2016 (2015 - $64 million). Amortization is estimated to average approximately $96 million annually for each of the next five years.

34

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

12. GOODWILL

(in millions)	2016		2015
Balance, beginning of year	$	4,173	$	3,732
Acquisition of ITC (Note 27)	8,106		—
Acquisition of Aitken Creek (Note 27)	27		—
Foreign currency translation impacts	58		441
Balance, end of year	$	12,364	$	4,173

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.

13. ACCOUNTS PAYABLE AND OTHER CURRENT LIABILITIES

(in millions)	2016		2015
Trade accounts payable	$	554	$	414
Customer and other deposits	287		160
Interest payable	218		127
Employee compensation and benefits payable	178		137
Gas and fuel cost payable	175		153
Accrued taxes other than income taxes	168		108
Dividends payable	166		113
Fair value of derivative instruments (Note 30)	28		69
Defined benefit pension and OPEB liabilities (Note 26)	26		13
MGP site remediation (Notes 8 (v) and 16)	21		32
Other	149		93
	$	1,970	$	1,419

Customer and other deposits include $64 million at FortisBC Energy related to the pipeline expansion to the proposed Woodfibre LNG export facility, and US$17 million associated with refundable deposits from generators for transmission network upgrades at ITC.

35

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

14. LONG-TERM DEBT

(in millions)		Maturity Date	2016			2015
Regulated Utilities
ITC
Secured US First Mortgage Bonds -
	4.81% weighted average fixed rate	2017-2055	$	1,994		$	—
Secured US Senior Notes -
	4.19% weighted average fixed rate	2040-2046	638			—
Unsecured US Senior Notes -
	4.80% weighted average fixed rate	2017-2043	3,160			—
Unsecured US Shareholder Note -
	6.00% fixed rate (Note 27)	2028	267			—
UNS Energy
Unsecured US Tax-Exempt Bonds - 3.87% weighted
	average fixed and variable rate (2015 - 3.83%)	2020-2040	827			852
Unsecured US Fixed Rate Notes -
	4.26% weighted average fixed rate (2015 - 4.26%)	2021-2045	1,511			1,557
Central Hudson
Unsecured US Promissory Notes - 4.25% weighted
	average fixed and variable rate (2015 - 4.30%)	2017-2046	768			728
FortisBC Energy
Secured Purchase Money Mortgages -
	10.30% weighted average fixed rate (2015 - 10.30%)	n/a	—			200
Unsecured Debentures -
	5.24% weighted average fixed rate (2015 - 5.73%)	2026-2047	2,220			1,770
Government loan		n/a	—			5
FortisAlberta
Unsecured Debentures -
	4.82% weighted average fixed rate (2015 - 4.95%)	2024-2052	1,834			1,684
FortisBC Electric
Secured Debentures -
	8.80% fixed rate (2015 - 8.80%)	2023	25			25
Unsecured Debentures -
	5.22%weighted average fixed rate (2015 - 5.36%)	2021-2050	635			660
Eastern Canadian
Secured First Mortgage Sinking Fund Bonds -
	6.48% weighted average fixed rate (2015 - 6.72%)	2020-2045	516			553
Secured First Mortgage Bonds -
	6.19% weighted average fixed rate (2015 - 7.18%)	2018-2061	195			167
Unsecured Senior Notes -
	6.11% weighted average fixed rate (2015 - 6.11%)	2018-2041	104			104
Caribbean Electric
Unsecured US Senior Loan Notes and Bonds - 4.92% weighted
	average fixed and variable rate (2015 - 4.89%)	2018-2046	499			467
Corporate
Unsecured US Senior Notes and Promissory Notes -
	3.43% weighted average fixed rate (2015 - 4.43%)	2019-2044	4,353			1,720
Unsecured Debentures -
	6.50% weighted average fixed rate (2015 - 6.49%)	2039	200			201
Unsecured Senior Notes - 2.85% fixed rate		2023	500			—
Long-term classification of credit facility borrowings (Note 32)			973			551
Total long-term debt (Note 30)			21,219			11,244
Less: Deferred financing costs and debt discounts			(151		)	(76		)
Less: Current installments of long-term debt			(251		)	(384		)
			$	20,817		$	10,784

36

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

14. LONG-TERM DEBT (cont’d)

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.

As at December 31, 2016, the Corporation and its subsidiaries were in compliance with their debt covenants.

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 April 2016 FortisBC Energy issued $300 million of unsecured debentures in a dual tranche of 10-year $150 million unsecured debentures at 2.58% and 30-year $150 million unsecured debentures at 3.67%. In December 2016 FortisBC Energy issued 30-year $150 million unsecured debentures at 3.78%. The net proceeds from the issuances were used to repay short-term borrowings and to finance capital expenditures.

In May and September 2016, Fortis Turks and Caicos issued 15-year US$45 million unsecured notes in a dual tranche of US$22.5 million at 5.14% and 5.29%, respectively. In July 2016 Fortis Turks and Caicos issued 15-year US$5 million unsecured bonds at 5.14%. The net proceeds were used to finance capital expenditures and for general corporate purposes.

In June 2016 Central Hudson issued 4-year US$24 million unsecured notes at 2.16%. The net proceeds were used to finance capital expenditures and for general corporate purposes. In October 2016 Central Hudson issued US$30 million of unsecured notes in a dual tranche of 10-year US$10 million unsecured notes at 2.56% and 30-year US$20 million unsecured debentures at 3.63%. The net proceeds were used to finance capital expenditures and for general corporate purposes.

In August 2016 Maritime Electric issued 40-year $40 million secured first mortgage bonds at 3.657%. The net proceeds were primarily used to repay long-term debt and short-term borrowings.

In September 2016 FortisAlberta issued 30-year $150 million unsecured debentures at 3.34%. The net proceeds were used to repay credit facility borrowings, to finance capital expenditures and for general corporate purposes.

In October 2016 a 12-year shareholder note of US$199 million at 6.00% was issued to an affiliate of GIC as part of its minority investment in ITC. The proceeds were used to finance a portion of the cash purchase price of the acquisition of ITC (Note 27).

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.

37

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

14. LONG-TERM DEBT (cont’d)

Corporate (cont’d)

In October 2016 the Corporation issued 5-year US$500 million unsecured notes at 2.100% and 10-year US$1.5 billion unsecured notes at 3.055%. The net proceeds were used to finance a portion of the cash purchase price of the acquisition of ITC (Note 27). In December 2016 the Corporation issued 7-year $500 million unsecured notes at 2.85%. The net proceeds were used to repay credit facility borrowings, mainly related to the financing of the acquisition of Aitken Creek in April 2016 and the redemption of First Preference Shares, Series E in September 2016, and for general corporate purposes.

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.

	Subsidiaries		Corporate		Total
Year	(in millions)		(in millions)		(in millions)
2017	$	249	$	2	$	251
2018	929		2		931
2019	556		123		679
2020	544		181		725
2021	460		1,296		1,756
Thereafter	12,963		3,914		16,877
	$	15,701	$	5,518	$	21,219

15. CAPITAL LEASE AND FINANCE OBLIGATIONS

Capital Lease Obligations

UNS Energy

TEP is party to three Springerville Common Facilities leases, which have a fixed purchase price of US$38 million and an initial term to December 2017 for one lease and a fixed purchase price of US$68 million and an initial term to January 2021 for the other two leases. In December 2016 TEP notified the owner participant and the lessor that TEP has elected to purchase a 17.8% undivided ownership interest in the Springerville Common Facilities at the fixed purchase price of US$38 million upon the expiration of the lease term in December 2017. Under the remaining two leases, TEP has the option to renew the leases for periods of two or more years or exercise the purchase options under these contracts. In addition, TEP has entered into agreements with third parties that if the Springerville Common Facilities leases are not renewed, TEP will exercise the purchase options under these contracts. The third parties would be obligated to buy a portion of these facilities or continue to make payments to TEP for the use of these facilities.

TEP entered into an interest rate swap that hedges a portion of the floating interest rate risk associated with the Springerville Common Facilities lease obligation. As at December 31, 2016, interest on the lease obligation is payable at a six-month LIBOR plus a spread of 1.88% (December 31, 2015 - 1.88%). The swap has the effect of fixing the interest rate on a portion of the amortizing principal balance of US$23 million (December 31, 2015 - US$29 million). The interest rate swap expires in 2020 and is recorded as a cash flow hedge (Note 30).

The Springerville Common Facilities capital lease obligation bears interest at a rate of 5.08%. For 2016$4 million (2015 - $5 million) of interest expense and $7 million (2015 - $8 million) of depreciation expense was recognized related to the Springerville capital lease obligations and for 2015$3 million of depreciation expense was recognized in energy supply costs.

38

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

15. CAPITAL LEASE AND FINANCE OBLIGATIONS (cont’d)

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 2016 was $27 million (2015 - $26 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 2016 was $3 million (2015 ‑ $3 million) recognized in accordance with the BTS agreement, as approved by the BCUC.

Finance Obligations

Between 2000 and 2005 FEI entered into arrangements whereby certain natural gas distribution assets were leased to certain municipalities and then leased back by FEI. 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 6.78% to 8.40% and are being repaid over a 35-year period. Each of the lease-in lease‑out arrangements allows FEI, at its option, to terminate the lease arrangement early, after 17 years. If the Company exercises this option, FEI would pay the municipality an early termination payment which is equal to the carrying value of the obligation at that point in time.

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)
2017	$	116	$	5	$	121
2018	60		32		92
2019	61		15		76
2020	70		3		73
2021	46		35		81
Thereafter	1,976		3		1,979
	$	2,329	$	93	$	2,422
Less: Amounts representing imputed interest and executory costs on capital lease and finance obligations					(1,886		)
Total capital lease and finance obligations					536
Less: Current installments					(76		)
					$	460

39

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

16. OTHER LIABILITIES

(in millions)	2016		2015
OPEB plan liabilities (Note 26)	$	411	$	385
Defined benefit pension plan liabilities (Note 26)	410		368
MGP site remediation (Notes 8 (v) and 13)	77		96
Customer and other deposits	69		38
Waneta Partnership promissory note (Notes 30, 31 and 33)	59		56
Asset retirement obligations	58		49
Mine reclamation and retiree health care liabilities	40		39
Deferred compensation plan liabilities (Note 9)	27		25
DSU, PSU and RSU liabilities (Note 22)	24		20
Fair value of derivative instruments (Note 30)	10		13
Other	94		63
	$	1,279	$	1,152

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, 2016, an obligation of US$73 million was recognized, including a current portion of US$16 million included in accounts payable and other current liabilities. It is estimated that total costs to remediate these sites over the next 30 years will not exceed US$169 million. 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.

The Waneta Partnership promissory note is non-interest bearing with a face value of $72 million. As at December 31, 2016, its discounted net present value was $59 million (December 31, 2015 - $56 million). The promissory note is payable on April 1, 2020, the fifth anniversary of the commercial operation date of the Waneta Expansion.

TEP pays ongoing reclamation costs related to three coal mines that supply generating stations in which the Company has an ownership interest but does not operate. TEP’s share of the reclamation costs is expected to be US$61 million (December 31, 2015 - US$43 million) upon expiry of the coal agreements, which expire between 2019 and 2031. The mine reclamation liability recognized as at December 31, 2016 was US$25 million (December 31, 2015 - 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.

Customer and other deposits include US$27 million of refundable deposits from generators for transmission network upgrades at ITC. These deposits are to be refunded under generator interconnection agreements at a future date.

Other liabilities primarily include long-term accrued liabilities, deferred lease revenue, funds received in advance of expenditures and unrecognized tax benefits.

40

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

17. COMMON SHARES

Common shares issued during the year were as follows.

	2016			2015
	Number			Number
	of Shares	Amount		of Shares	Amount
	(in thousands)	(in millions)		(in thousands)	(in millions)
Balance, beginning of year	281,562	$	5,867	275,997	$	5,667
Public Offering	114,364	4,684		—	—
Dividend Reinvestment Plan	4,100	163		4,272	157
Consumer Share Purchase Plan	31	1		28	1
Employee Share Purchase Plan	377	15		356	13
Stock Option Plans	1,042	32		885	28
Conversion of Convertible Debentures	10	—		24	1
Balance, end of year	401,486	$	10,762	281,562	$	5,867

Public Offering

To finance a portion of the acquisition of ITC, in October 2016 Fortis issued approximately 114.4 million common shares 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 (Note 27).

18. EARNINGS PER COMMON SHARE

The Corporation calculates earnings per common share (“EPS”) on the weighted average number of common shares outstanding. The weighted average number of common shares outstanding was 308.9 million for 2016 and 278.6 million for 2015.

Diluted EPS was calculated using the treasury stock method for options and the “if‑converted” method for convertible securities.

	2016					2015
	Net Earnings		Weighted			Net Earnings		Weighted
	to Common		Average			to Common		Average
	Shareholders		Shares			Shareholders		Shares
	($ millions)		(# millions)	EPS		($ millions)		(# millions)	EPS
Basic EPS	$	585	308.9	$	1.89	$	728	278.6	$	2.61
Effect of potential dilutive securities:
Stock Options	—		0.7			—		0.7
Preference Shares	7		3.8			10		5.4
Diluted EPS	$	592	313.4	$	1.89	$	738	284.7	$	2.59

41

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

19. 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

	2016			2015
First Preference Shares	Number			Number
	of Shares	Amount		of Shares	Amount
	(in thousands)	(in millions)		(in thousands)	(in millions)
Series E	—	$	—	7,994	$	197
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	74,194	$	1,820

In September 2016 the Corporation redeemed all of the issued and outstanding $200 million4.9% 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.

In June 2015, 2,975,154 of the 10,000,000 First Preference Shares, Series H were converted on a one-for-one basis into First Preference Shares, Series I.

42

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

19. PREFERENCE SHARES (cont’d)

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 (6)	4.25	0.6250	1.45	June 1, 2015	25.00	Series I
Series K	4.00	1.0000	2.05	March 1, 2019	25.00	Series L
Series M	4.10	1.0250	2.48	December 1, 2019	25.00	Series N
Floating rate reset (5) (7)
Series I (3)	2.10	—	1.45	June 1, 2015	25.50	Series H
Series L	—	—	2.05	March 1, 2024	—	Series K
Series N	—	—	2.48	December 1, 2024	—	Series M

⁽¹⁾   Holders are entitled to receive a fixed or floating cumulative quarterly cash dividend as and when declared by the Board of Directors of the Corporation, payable in equal 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 Cumulative Redeemable Five-Year Fixed Rate Reset First Preference Shares, on every fifth anniversary date, thereafter.

⁽³⁾  First Preference Shares, Series J are redeemable at $26.00 to December 1, 2018, decreasing $0.25 each year until December 1, 2021 and $25.00 per share thereafter. First Preference Shares, Series I are redeemable at $25.50 per share, up to and excluding June 1, 2020, and $25.00 per share on June 1, 2020, and on every fifth anniversary date, thereafter.

⁽⁴⁾  On the redemption and/or conversion option date, and each five-year anniversary thereafter, the reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield.

⁽⁵⁾  On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their Shares into an equal number of Cumulative Redeemable First Preference Shares of a specified series.

⁽⁶⁾  The annual fixed dividend per share for First Preference Shares, Series H was reset from $1.0625 to $0.6250 for the five-year period from and including June 1, 2015 to but excluding June 1, 2020.

⁽⁷⁾  The floating quarterly dividend rate will be reset every quarter based on the then current three‑month Government of Canada Treasury Bill rate plus the applicable reset dividend yield.

On the liquidation, dissolution or winding-up of Fortis, holders of Common Shares are entitled to participate ratably in any distribution of assets of Fortis, subject to the rights of holders of First 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, 2016 and 2015

20. 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.

	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: (Notes 9, 28 and 30)
Realized gain on available-for-sale investment	(2		)	2			—
Cash flow hedges: (Note 30)
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 26)
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
	2015
(in millions)	Opening balance January 1			Net Change			Ending balance December 31
Net unrealized foreign currency translation gains (losses):
Unrealized foreign currency translation gains on net investments in foreign operations	$	273		$	1,008		$	1,281
Losses on hedges of net investments in foreign operations	(131		)	(345		)	(476		)
Income tax recovery	2			(1		)	1
	144			662			806
Available-for-sale investment: (Notes 9, 28 and 30)
Unrealized loss on available-for-sale investment	—			(2		)	(2		)
Cash flow hedges: (Note 30)
Net change in fair value of cash flow hedges	1			2			3
Income tax expense	—			(1		)	(1		)
	1			1			2
Unrealized employee future benefits (losses) gains: (Note 26)
Unamortized net actuarial losses	(20		)	—			(20		)
Unamortized past service costs	(2		)	1			(1		)
Income tax recovery	6			—			6
	(16		)	1			(15		)
Accumulated other comprehensive income	$	129		$	662		$	791

44

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

21. NON-CONTROLLING INTERESTS

(in millions)	2016		2015
ITC (Note 27)	$	1,385	$	—
Waneta Partnership	330		335
Caribbean Utilities	122		122
Other	16		16
	$	1,853	$	473

22. 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, 2016, 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 2016 and 2015. The 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:

	2016	2015
Options granted (#)	788,188	667,244
Exercise price ($) (1)	37.30	39.25
Grant date fair value ($)	2.41	2.46
Assumptions:
Dividend yield (%) (2)	3.9	3.6
Expected volatility (%) (3)	16.4	14.6
Risk-free interest rate (%) (4)	0.7	0.9
Weighted average expected life (years) (5)	5.5	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

45

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

22. STOCK-BASED COMPENSATION PLANS (cont’d)

Stock Options (cont’d)

The Corporation records compensation expense upon the issuance of stock options granted under its 2002, 2006 and 2012 Plans. Using the fair value method, each grant is treated as a single award, the fair value of which is amortized to compensation expense evenly over the four-year vesting period of the options.

The following table summarizes information related to stock options for 2016.

	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, 2016	4,416,454		$	32.12	1,936,532		$	3.30
Granted	788,188		$	37.30	788,188		$	2.41
Exercised	(1,041,450	)	$	26.74	n/a		n/a
Vested	n/a		n/a		(906,702	)	$	3.57
Cancelled/Forfeited	(3,000	)	$	31.68	(3,000	)	$	3.66
Options outstanding, December 31, 2016	4,160,192		$	34.45	1,815,018		$	2.78
Options vested, December 31, 2016 (2)	2,345,174		$	33.14

⁽¹⁾  As at December 31, 2016, 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, 2016, the weighted average remaining term of vested options was six years with an aggregate intrinsic value of $20 million.

The following table summarizes additional 2016 and 2015 stock option information.

(in millions)	2016		2015
Stock option expense recognized	$	2	$	3
Stock options exercised:
Cash received for exercise price	28		24
Intrinsic value realized by employees	15		10
Fair value of options that vested	3		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.

46

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

22. STOCK-BASED COMPENSATION PLANS (cont’d)

Directors’ DSU Plan (cont’d)

Number of DSUs	2016		2015
DSUs outstanding, beginning of year	167,762		176,124
Granted	30,165		28,737
Granted - notional dividends reinvested	6,994		7,037
DSUs paid out	(5,510	)	(44,136	)
DSUs outstanding, end of year	199,411		167,762

For 2016 expense of $2 million (2015 - $1 million) was recognized in earnings with respect to the DSU Plan.

In 2016, 5,510 DSUs were paid out to a deceased director at a price of $40.05 per DSU for a total of less than $1 million.

As at December 31, 2016, 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 2016 of $41.46, for a total of $8 million (December 31, 2015 - $6 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. As at December 31, 2016, the Corporation had the following PSU plans: the 2013 PSU Plan, the 2015 PSU Plan, and certain subsidiaries of the Corporation have also adopted similar share unit plans that are modelled after the Corporation’s plans. 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 150%.

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 compound annual growth rate in 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, 2016, the estimated payout percentages for the grants under the 2013 and 2016 PSU Plans range from 88% to 113%.

47

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

22. STOCK-BASED COMPENSATION PLANS(cont’d)

PSU Plans (cont’d)

The following table summarizes information related to the PSUs for 2016 and 2015.

Number of PSUs	2016		2015
PSUs outstanding, beginning of year	694,386		481,700
Granted	351,737		276,381
Granted - notional dividends reinvested	34,439		25,687
PSUs paid out (1)	(148,168	)	(83,637	)
PSUs cancelled/ forfeited	(443	)	(5,745	)
PSUs outstanding, end of year	931,951		694,386

⁽¹⁾  Includes 2,432 PSUs paid to senior management on retirement in accordance with the PSU plan

In 2016, 145,736 PSUs were paid out to senior management of the Corporation and its subsidiaries at $37.72 per PSU, for a total of approximately $5 million. The payout was made in respect of the PSUs granted in 2013 at a payout percentage of 96% based on the Corporation’s performance over the three‑year period, as determined by the Human Resources Committee of the Board of Directors.

For 2016 expense of approximately $16 million (2015 - $12 million) was recognized in earnings with respect to the PSU Plans and there was $9 million of unrecognized compensation expense related to PSUs not yet vested, which is expected to be recognized over a weighted average period of approximately two years.

As at December 31, 2016, the aggregate intrinsic value of the outstanding PSUs was $39 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 2016 of $41.46, for a total of $30 million (December 31, 2015 ‑ $19 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. 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	2016		2015
RSUs outstanding, beginning of year	58,740		—
Granted	70,393		59,462
Granted - notional dividends reinvested	4,709		2,150
RSUs paid out (1)	(10,201	)	—
RSUs cancelled/ forfeited	(29	)	(2,872	)
RSUs outstanding, end of year	123,612		58,740

⁽¹⁾  Reflects RSUs paid to senior management on retirement in accordance with the RSU plan

48

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

22. STOCK-BASED COMPENSATION PLANS (cont’d)

RSU Plans (cont’d)

For 2016 expense of approximately $2 million (2015 - $1 million) was recognized in earnings with respect to the RSU Plan and there was approximately $2 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, 2016, the aggregate intrinsic value of the outstanding RSUs was $5 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 2016 of $41.46, for a total of $3 million (December 31, 2015 - $1 million), and is included in long-term other liabilities (Note 16).

23. OTHER INCOME (EXPENSES), NET

(in millions)	2016		2015
Equity component of AFUDC	$	37	$	23
Interest income	7		8
Equity income - Belize Electricity	7		—
Net gain on sale of commercial real estate and hotel assets (Note 28) (1)	—		109
Gain on sale of non-regulated generation assets (Note 28) (2)	—		56
Net foreign exchange gain	—		13
Loss on settlement of expropriation matters (Note 9)	—		(9		)
Other	2		(3		)
	$	53	$	197

⁽¹⁾  Net of $23 million of expenses associated with the sale

⁽²⁾  Net of $6 million of expenses and foreign exchange impacts associated with the sale

The net foreign exchange gain relates to the translation into Canadian dollars of the Corporation’s previous US dollar-denominated long-term other asset, representing the book value of the Corporation’s expropriated investment in Belize Electricity, up to the date of settlement of expropriation matters in August 2015 (Note 9). As a result of the settlement, the Corporation recognized an approximate $9 million loss in 2015. Unrealized foreign exchange gains and losses associated with the Corporation’s 33% equity investment in Belize Electricity are recognized on the balance sheet in accumulated other comprehensive income.

24. FINANCE CHARGES

(in millions)		2016			2015
Interest	- Long-term debt and capital lease and finance obligations	$	658		$	572
	- Short-term borrowings	10			8
Acquisition credit facilities (Notes 27 and 32)		39			—
Debt component of AFUDC		(29		)	(27		)
		$	678		$	553

49

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

25. INCOME TAXES

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)	2016			2015
Gross deferred income tax assets
Tax loss and credit carryforwards	$	675		$	387
Regulatory liabilities	292			210
Employee future benefits	155			116
Fair value of long-term debt adjustment	88			—
Unrealized foreign exchange losses on long-term debt	56			65
Other	57			58
	1,323			836
Deferred income tax assets valuation allowance	(56		)	(73		)
Net deferred income tax assets	$	1,267		$	763
Gross deferred income tax liabilities
Utility capital assets	$	(4,213	)	$	(2,575	)
Regulatory assets	(242		)	(201		)
Intangible assets	(75		)	(37		)
	(4,530		)	(2,813		)
Net deferred income tax liability	$	(3,263	)	$	(2,050	)

The deferred income tax asset associated with unrealized foreign exchange losses on long‑term debt reflects $56 million of unrealized capital losses as at December 31, 2016 (December 31, 2015 - $65 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 $56 million valuation allowance against the deferred income tax asset as at December 31, 2016 (December 31, 2015 - $65 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 2016 and 2015.

(in millions)	2016		2015
Total unrecognized tax benefits, beginning of year	$	13	$	11
Additions related to the current year	10		1
Adjustments related to prior years	—		1
Total unrecognized tax benefits, end of year	$	23	$	13

Unrecognized tax benefits, if recognized, would reduce income tax expense by $1 million in 2016. Fortis has not recognized interest expense in 2016 and 2015 related to unrecognized tax benefits.

50

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

25. INCOME TAXES (cont’d)

The components of the income tax expense were as follows.

(in millions)	2016			2015
Canadian
Earnings before income taxes	$	357		$	544
Current income taxes	66			59
Deferred income taxes	54			113
Less: regulatory adjustments	(77		)	(100		)
	(23		)	13
Total Canadian	$	43		$	72
Foreign
Earnings before income taxes	$	501		$	519
Current income taxes	(19		)	—
Deferred income taxes	121			151
Total Foreign	$	102		$	151
Income tax expense	$	145		$	223

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)	2016			2015
Earnings before income taxes	$	858		$	1,063
Combined Canadian federal and provincial statutory income tax rate	28.0		%	27.5		%
Statutory income tax rate applied to earnings before income taxes	$	240		$	292
Difference between Canadian statutory income tax rate and rates applicable to foreign subsidiaries	(28		)	(7		)
Difference in Canadian provincial statutory income tax rates applicable to subsidiaries in different Canadian jurisdictions	(4		)	(4		)
Items capitalized for accounting purposes but expensed for income tax purposes	(40		)	(39		)
Difference between gain on sale of assets for accounting and amounts calculated for tax purposes	—			(18		)
Change in tax rates and legislation	(6		)	13
Difference between capital cost allowance and amounts claimed for accounting purposes	(25		)	(15		)
Other	8			1
Income tax expense	$	145		$	223
Effective tax rate	16.9		%	21.0		%

51

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

25. INCOME TAXES (cont’d)

As at December 31, 2016, the Corporation had the following tax carryforward amounts.

(in millions)	Expiring Year	Amount
Canadian
Capital loss	n/a	$	76
Non-capital loss	2025-2036	244
Other tax credits	2026-2035	2
		322
Unrecognized in the consolidated financial statements		(76		)
		$	246
Foreign
Capital loss	2020-2021	$	3
Federal and state net operating loss	2031-2036	862
Other tax credits	2032-2036	126
		991
Unrecognized in the consolidated financial statements		(2		)
		$	989
Total tax carryforwards		$	1,235

As at December 31, 2016, the Corporation had approximately $1,235 million in tax carryforward amounts recognized in the consolidated financial statements (December 31, 2015 - $912 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 2011 to 2016 taxation years are still open for audit in the Canadian jurisdictions and 2012 to 2016 taxation years are still open for audit in the United States jurisdictions. The Corporation is not currently under examination for income tax matters in any of these jurisdictions.

26. 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, 2013 for FortisBC Electric, FortisBC Energy (plans covering unionized employees) and Caribbean Utilities; December 31, 2014 for Newfoundland Power, FortisOntario and the Corporation; and December 31, 2015 for FortisAlberta and FortisBC Energy (plan covering non-unionized employees).

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.

52

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

26. EMPLOYEE FUTURE BENEFITS (cont’d)

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	2016 Target Allocation
(%)		2016	2015
Equities	50	50	51
Fixed income	46	45	44
Real estate	4	4	4
Cash and other	—	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 30, were as follows.

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
Fair value of plan assets as at December 31, 2015
(in millions)	Level 1		Level 2		Level 3		Total
Equities	$	417	$	922	$	—	$	1,339
Fixed income	—		1,166		—		1,166
Real estate	—		14		97		111
Private equities	—		—		10		10
Cash and other	3		18		—		21
	$	420	$	2,120	$	107	$	2,647

53

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

26. EMPLOYEE FUTURE BENEFITS (cont’d)

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, 2016 and 2015.

(in millions)	2016			2015
Balance, beginning of year	$	107		$	93
Actual return on plan assets held at end of year	8			9
Foreign currency translation impacts	(1		)	5
Purchases, sales and settlements	(1		)	—
Balance, end of year	$	113		$	107

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)	2016			2015			2016			2015
Change in benefit obligation (1)
Balance, beginning of year	$	2,828		$	2,604		$	574		$	564
Liabilities assumed on acquisition	167			—			111			—
Service costs	66			68			18			17
Employee contributions	17			17			2			1
Interest costs	112			109			23			23
Benefits paid	(119		)	(118		)	(23		)	(21		)
Actuarial losses (gains)	45			(102		)	(1		)	(50		)
Past service credits/plan amendments	(10		)	—			—			(10		)
Foreign currency translation impacts	(69		)	250			(28		)	50
Balance, end of year (2)	$	3,037		$	2,828		$	676		$	574
Change in value of plan assets
Balance, beginning of year	$	2,466		$	2,216		$	181		$	154
Assets assumed on acquisition	85			—			65			—
Actual return on plan assets	187			30			13			—
Benefits paid	(119		)	(118		)	(23		)	(21		)
Employee contributions	17			17			2			1
Employer contributions	47			99			18			17
Foreign currency translation impacts	(37		)	222			(4		)	30
Balance, end of year	$	2,646		$	2,466		$	252		$	181
Funded status	$	(391	)	$	(362	)	$	(424	)	$	(393	)

⁽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 $2,741 million as at December 31, 2016 (December 31, 2015 - $2,595 million).

54

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

26. EMPLOYEE FUTURE BENEFITS (cont’d)

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)	2016		2015		2016		2015
Assets
Defined benefit pension assets:
Long-term other assets (Note 9)	$	32	$	11	$	—	$	—
Liabilities
Defined benefit pension liabilities:
Current (Note 13)	13		5		—		—
Long-term other liabilities (Note 16)	410		368		—		—
OPEB plan liabilities:
Current (Note 13)	—		—		13		8
Long-term other liabilities (Note 16)	—		—		411		385
Net liabilities	$	391	$	362	$	424	$	393

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)	2016			2015			2016			2015
Components of net benefit cost
Service costs	$	66		$	68		$	18		$	17
Interest costs	112			109			23			23
Expected return on plan assets	(145		)	(140		)	(12		)	(12		)
Amortization of actuarial losses	48			57			2			5
Amortization of past service credits/plan amendments	1			2			(10		)	(12		)
Regulatory adjustments	6			1			9			6
Net benefit cost	$	88		$	97		$	30		$	27

55

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

26. EMPLOYEE FUTURE BENEFITS (cont’d)

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, 2016 and 2015, which have not been recognized as components of net benefit cost.

	Defined Benefit Pension Plans						OPEB Plans
(in millions)	2016			2015			2016			2015
Unamortized net actuarial losses	$	19		$	16		$	—		$	4
Unamortized past service costs	1			1			2			—
Income tax recovery	(5		)	(5		)	(1		)	(1		)
Accumulated other comprehensive loss (Note 20)	$	15		$	12		$	1		$	3
Net actuarial losses	$	479		$	513		$	53		$	41
Past service credits	(11		)	—			(31		)	(33		)
Amount deferred due to actions of regulators	12			23			32			39
	$	480		$	536		$	54		$	47
Regulatory assets (Note 8 (ii))	$	480		$	536		$	96		$	91
Regulatory liabilities (Note 8 (ii))	—			—			(42		)	(44		)
Net regulatory assets	$	480		$	536		$	54		$	47

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)	2016			2015			2016			2015
Current year net actuarial losses (gains)	$	4		$	—		$	(2	)	$	(1	)
Past service credits/plan amendments	—			—			—			(1		)
Amortization of actuarial gains	—			1			—			—
Income tax recovery	(1		)	—			—			—
Total recognized in comprehensive income	$	3		$	1		$	(2	)	$	(2	)
Assets assumed on acquisition	$	23		$	—		$	3		$	—
Current year net actuarial (gains) losses	(1		)	8			—			(28		)
Past service credits/plan amendments	(10		)	—			—			(10		)
Amortization of actuarial losses	(47		)	(56		)	(4		)	(5		)
Amortization of past service costs	(1		)	(1		)	13			(2		)
Foreign currency translation impacts	(9		)	49			1			(6		)
Regulatory adjustments	(11		)	5			(6		)	7
Total recognized in regulatory assets	$	(56	)	$	5		$	7		$	(44	)

Net actuarial losses of $1 million are expected to be amortized from accumulated other comprehensive income into net benefit cost in 2017 related to defined benefit pension plans.

Net actuarial losses of $43 million, past service credits of $1 million and regulatory adjustments of $2 million are expected to be amortized from regulatory assets into net benefit cost in 2017 related to defined benefit pension plans. Net actuarial losses of $1 million, past service credits of $10 million and regulatory adjustments of $8 million are expected to be amortized from regulatory assets into net benefit cost in 2017 related to OPEB plans.

56

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

26. EMPLOYEE FUTURE BENEFITS (cont’d)

Significant weighted average assumptions	Defined Benefit Pension Plans		OPEB Plans
%	2016	2015	2016	2015
Discount rate during the year (1)	4.08	4.00	4.14	3.95
Discount rate as at December 31	4.00	4.21	4.00	4.12
Expected long-term rate of return on plan assets (2)	6.25	6.25	6.25	6.95
Rate of compensation increase	3.36	3.48	—	—
Health care cost trend increase as at December 31 (3)	—	—	4.70	4.67

⁽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 2017 weighted average health care cost trend rate is 6.62% for OPEB plans and is assumed to decrease over the next 12 years by 2028 to the weighted average ultimate health care cost trend rate of 4.70% and remain at that level thereafter.

For 2016 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	$	89	$	(71	)
Increase (decrease) in service and interest costs	19		(13		)

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)
2017	$	133	$	24
2018	135		25
2019	140		27
2020	146		28
2021	152		30
2022 - 2026	848		173

During 2017 the Corporation expects to contribute $63 million for defined benefit pension plans and $31 million for OPEB plans.

In 2016 the Corporation expensed $31 million (2015 - $28 million) related to defined contribution pension plans.

57

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

27. BUSINESS ACQUISITIONS

ITC

On October 14, 2016, Fortis and GIC acquired all of the outstanding common shares of ITC for an aggregate purchase price of approximately US$11.8 billion ($15.7 billion) on closing, including approximately US$4.8 billion ($6.3 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 US$7.0 billion ($9.4 billion). The net cash consideration totalled approximately US$3.5 billion ($4.7 billion) and was financed using: (i) net proceeds from the issuance of US$2.0 billion unsecured notes in October 2016 (Note 14); (ii) net proceeds from GIC’s US$1.228 billion minority investment (Note 21), which includes a shareholder note of US$199 million(Note 14); and (iii) drawings of approximately US$404 million ($535 million) under the Corporation’s non-revolving term senior unsecured equity bridge credit facility (Note 32). On October 14, 2016, approximately 114.4 million common shares of Fortis were issued to shareholders of ITC, representing share consideration of approximately US$3.5 billion ($4.7 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 (Note 17). The financing of the acquisition was structured to allow Fortis to maintain investment-grade credit ratings.

ITC is the largest independent electric transmission company in the United States. Based in Novi, Michigan, ITC invests in the electrical transmission grid to improve reliability, expand access to markets, allow new generating resources to interconnect to its transmission systems and lower the overall cost of delivered energy. Through its regulated operating subsidiaries ITCTransmission, METC, ITC Midwest and ITC Great Plains, ITC owns and operates high-voltage transmission lines serving a combined peak load exceeding 26,000 MW along approximately 25,000 kilometres in Michigan’s lower peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from approximately 570 generating stations to local distribution facilities connected to ITC’s systems.

Each of the ITC regulated operating subsidiaries is an electric transmission utility subject to rate regulation by FERC (Note 2). The determination of revenue and earnings is based on regulated rates of return that are applied to historic values, which do not change with a change of ownership. Therefore, with the exception of a fair market value adjustment for long-term debt at the ITC parent company level outside of regulated operations, which debt does not form part of the rate-making process, along with the related impact on deferred income taxes, no other fair market value adjustments to ITC’s assets and liabilities have been recognized because all of the economic benefits and obligations associated with regulated assets and liabilities beyond regulated rates of return accrue to ITC’s customers.

The following table summarizes the preliminary 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. The purchase price allocation is preliminary pending final assessment of fair value estimates, income taxes, consideration transferred, and identification of assets and liabilities.

58

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

27. BUSINESS ACQUISITIONS (cont’d)

ITC (cont’d)

(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 (Notes 14 and 21)	1,621
	$	9,342
Fair value assigned to net assets:
Current assets	$	319
Long-term regulatory assets	319
Utility capital assets	8,345
Intangible assets	392
Other long-term assets	71
Current liabilities	(625		)
Assumed short-term borrowings	(311		)
Assumed long-term debt (including current portion)	(5,989		)
Long-term regulatory liabilities	(327		)
Deferred income taxes	(926		)
Other long-term liabilities	(166		)
	1,102
Cash and cash equivalents	134
Fair value of net assets acquired	1,236
Goodwill (Note 12)	$	8,106

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 (2015 - $10 million ($7 million after tax)). Acquisition-related expenses included: (i) investment banking, legal, consulting and other fees totalling approximately $79 million ($62 million after tax) in 2016 (2015 - $10 million ($7 million after tax)), 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 (2015 - nil), which were included in finance charges (Note 24). From the date of acquisition, ITC also recognized US$21 million ($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 US$17 million ($22 million).

Supplemental Pro Forma Data

The unaudited pro forma financial information below gives effect to the acquisition of ITC as if the transaction had occurred at the beginning of 2015. 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 2015, nor is it necessarily indicative of the results that may be expected in future periods.

(in millions)	2016		2015
Pro forma revenue	$	7,995	$	8,093
Pro forma net earnings attributable to common equity shareholders (1)	919		937

⁽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 years presented to reflect the Corporation’s after‑tax financing costs associated with the acquisition.

59

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

27. BUSINESS ACQUISITIONS (cont’d)

AITKEN CREEK

On April 1, 2016, Fortis acquired ACGS from Chevron Canada Properties Ltd. for approximately $349 million (US$266 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 (US$29 million) as part of the purchase consideration for the transaction (Note 9).

ACGS owns 93.8% of Aitken Creek, with the remaining share owned by BP Canada Energy Company. 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. The facility is an integral part of western Canada’s natural gas transmission network. ACGS also owns 100% of the North Aitken Creek gas storage site which offers future expansion potential.

The preliminary 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 is associated with deferred income tax liabilities. The purchase price allocation is preliminary pending final assessment of deferred income tax liabilities and working capital. 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.

28. 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.

Sale of Commercial Real Estate and Hotel Assets

In June 2015 the Corporation completed the sale of the commercial real estate assets of Fortis Properties for gross proceeds of $430 million. As a result of the sale, the Corporation recognized a gain on sale of $129 million ($109 million after tax), net of expenses (Note 23). As part of the transaction, Fortis subscribed to $35 million in trust units of Slate Office REIT in conjunction with the REIT’s public offering. The Corporation sold the trust units of Slate Office REIT in November 2016 for gross proceeds of $37 million.

In October 2015 the Corporation completed the sale of the hotel assets of Fortis Properties for gross proceeds of $365 million. As a result of the sale, the Corporation recognized a loss of approximately $20 million ($8 million after tax), which reflected an impairment loss and expenses associated with the sale transaction (Note 23).

Net proceeds from the sales were used by the Corporation to repay credit facility borrowings, the majority of which were used to finance a portion of the acquisition of UNS Energy, and for other general corporate purposes.

Earnings before taxes related to Fortis Properties of approximately $18 million were recognized in 2015, excluding the net gain on sale.

Sale of Non-Regulated Generation Assets in New York and Ontario

In June 2015 the Corporation sold its non-regulated generation assets in Upstate New York for gross proceeds of approximately $77 million (US$63 million). As a result of the sale, the Corporation recognized a gain on sale of $51 million (US$41 million) ($27 million (US$22 million) after tax), net of expenses and foreign exchange impacts (Note 23).

60

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

28. DISPOSITIONS (cont’d)

Sale of Non-Regulated Generation Assets in New York and Ontario (cont’d)

In July 2015 the Corporation sold its non-regulated generation assets in Ontario for gross proceeds of approximately $16 million. As a result of the sale, the Corporation recognized a gain on sale of $5 million ($5 million after tax) (Note 23).

Earnings before taxes of less than $1 million were recognized in 2015, excluding the gain on sale.

29. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)	2016			2015
Cash paid for:
Interest	$	644		$	561
Income taxes	62			109
Change in non-cash operating working capital:
Accounts receivable and other current assets	$	43		$	14
Prepaid expenses	(4		)	(1		)
Inventories	17			15
Regulatory assets - current portion	(58		)	57
Accounts payable and other current liabilities	25			(82		)
Regulatory liabilities - current portion	(1		)	38
	$	22		$	41
Non-cash investing and financing activities:
Common share dividends reinvested	$	162		$	156
Common shares issued on business acquisition (Notes 17 and 27)	4,684			—
Additions to utility capital assets and intangible assets included in    current and long-term liabilities	296			187
Commitment to purchase capital lease interest (Note 15)	48			—
Transfer of deposit on business acquisition (Note 27)	38			—
Contributions in aid of construction included in current assets	9			4
Exercise of stock options into common shares	4			4

30. 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.

61

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

30. FAIR VALUE MEASUREMENTS AND FINANCIAL INSTRUMENTS (cont’d)

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.

The following table presents, 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 and there were no transfers between the levels in the periods presented. For derivative instruments, the Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions.

	Fair value
(in millions)	hierarchy	2016			2015
Assets
Energy contracts subject to regulatory deferral (1) (2) (3)	Levels 1/2/3	$	19		$	7
Energy contracts not subject to regulatory deferral (1) (2)	Level 3	3			2
Interest rate swaps - cash flow hedges (4)	Level 2	11			—
Available-for-sale investment (Notes 9 and 28)	Level 1	—			33
Assets held for sale	Level 2	—			9
Other investments (5)	Level 1	69			12
Total gross assets		102			63
Less: Counterparty netting not offset on the balance sheet (6)		(9		)	(6		)
Total net assets		$	93		$	57
Liabilities
Energy contracts subject to regulatory deferral (1) (2) (7)	Levels 2/3	$	26		$	78
Energy contracts not subject to regulatory deferral (1)	Level 2	9			—
Interest rate swaps - cash flow hedges (4)	Level 2	3			5
Total gross liabilities		38			83
Less: Counterparty netting not offset on the balance sheet (6)		(9		)	(6		)
Total net liabilities		$	29		$	77

⁽¹⁾  The fair value of the Corporation’s energy contracts is recognized in accounts receivable and other current assets, long-term other assets, accounts payable and other current liabilities and long-term other liabilities. 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.

⁽²⁾  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 impacts of changes in fair value are subject to regulatory recovery, with the exception of long-term wholesale trading contracts and certain gas swap contracts.

⁽³⁾  As at December 31, 2016, includes $1 million - level 1, $13 million - level 2 and $5 million - level 3 (December 31, 2015 - $2 million - level 2 and $5 million - level 3)

⁽⁴⁾  The fair value of the Corporation’s interest rate swaps is recognized in accounts receivable and other current assets, accounts payable and other current liabilities and long-term other liabilities.

⁽⁵⁾  Included in long-term other assets on the consolidated balance sheet(Note 9).

⁽⁶⁾  Certain energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk and are netted by counterparty where the intent and legal right to offset exists.

⁽⁷⁾  As at December 31, 2016, includes $21 million - level 2 and $5 million - level 3 (December 31, 2015 - $1 million – level 1, $52 million - level 2 and $25 million - level 3)

62

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

30. FAIR VALUE MEASUREMENTS AND FINANCIAL INSTRUMENTS (cont’d)

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. The fair value of derivative instruments is the estimate of the amounts that the Corporation would receive or have to pay to terminate the outstanding contracts as at the balance sheet dates.

Energy Contracts Subject to Regulatory Deferral

UNS Energy holds electricity power purchase contracts and gas swap and option 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. The fair value of gas option contracts is estimated using a Black-Scholes option-pricing model, which includes inputs such as implied volatility, interest rates, and forward price curves. UNS Energy also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.

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 contract premiums 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 market prices and forward curves for the cost of natural gas.

As at December 31, 2016, these energy contract derivatives 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, 2016, unrealized losses of $19 million (December 31, 2015 - $74 million) were recognized in regulatory assets and unrealized gains of $12 millionwere recognized in regulatory liabilities (December 31, 2015 - $3 million) (Note 8(ix)).

Energy Contracts Not Subject to Regulatory Deferral

UNS Energy holds long-term wholesale trading contracts that qualify as derivative instruments. The unrealized gains and losses on these derivative instruments are recognized in earnings, as they do not qualify for regulatory deferral. Ten percent of any realized gains on these contracts are shared with customers through UNS Energy’s rate stabilization accounts.

Aitken Creek holds gas supply contract premiums and 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 provided by third parties. The unrealized gains and losses on these derivative instruments are recognized in earnings. As at December 31, 2016, unrealized losses totalled $9 million ($6 million after tax).

Cash Flow Hedges

UNS Energy holds an interest rate swap, expiring in 2020, to mitigate its exposure to volatility in variable interest rates on capital lease obligations (Note 15).

63

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

30. FAIR VALUE MEASUREMENTS AND FINANCIAL INSTRUMENTS(cont’d)

Cash Flow Hedges (cont’d)

ITC holds forward-starting interest rate swaps, effective January 2018 and expiring in 2028, with notional amounts totalling US$100 million. The agreements include a mandatory early termination provision and will be terminated no later than the effective date. The interest rate swaps manage the interest rate risk associated with the forecasted future issuance of fixed-rate debt related to the refinancing of maturing US$385 millionlong-term debt due in January 2018.As atDecember 31, 2016, the unrealized gain on the derivatives was $11 million (US$8 million).

The unrealized gains and losses on 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 (Note 20). The loss expected to be reclassified to earnings within the next twelve months is estimated to be approximately$5 million. Cash flows associated with the settlement of all derivative instruments are included in operating activities on the Corporation’s consolidated statement of cash flows.

Volume of Derivative Activity

As at December 31, 2016, the following notional volumes related to electricity and natural gas derivatives that are expected to be settled are outlined below.

	Maturity	Contracts						There-after
Volume(1)	(year)	(#)	2017	2018	2019	2020	2021
Energy contracts subject to regulatory deferral:
Electricity swap contracts (GWh)	2019	8	1,089	657	438	—	—	—
Electricity power purchase contracts (GWh)	2017	39	1,252	—	—	—	—	—
Gas swap and option contracts (PJ)	2019	108	20	11	4	—	—	—
Gas supply contract premiums (PJ)	2024	85	82	45	26	22	22	43
Energy contracts not subject to regulatory deferral:
Long-term wholesale trading contracts (GWh)	2017	18	2,058	—	—	—	—	—
Gas supply contract premiums (PJ)	2017	226	15	—	—	—	—	—
Gas swap contracts (PJ)	2017	7	4	—	—	—	—	—

⁽¹⁾  GWh means gigawatt hours and PJ means petajoules

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 fair values were measured using Level 2 pricing inputs, except as noted. 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.

	2016				2015
(in millions)	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt, including current portion (Note 14) (1)	$	21,219	$	22,523	$	11,244	$	12,614
Waneta Partnership promissory note (Note 16) (2)	59		61		56		59

⁽¹⁾  The Corporation’s $200 million unsecured debentures due 2039, $500 million unsecured senior notes due 2023, and consolidated borrowings under credit facilities classified as long-term debt of $973 million (December 31, 2015 - $551 million) are valued using Level 1 inputs. All other long-term debt is valued using Level 2 inputs.

⁽²⁾  Included in long-term other liabilities on the consolidated balance sheet (Note 16).

64

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

30. FAIR VALUE MEASUREMENTS AND FINANCIAL INSTRUMENTS(cont’d)

Financial Instruments Not Carried At Fair Value (cont’d)

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.

31. VARIABLE INTEREST ENTITY

On adoption of ASU No. 2015-02, Amendments to the Consolidation Analysis, effective January 1, 2016, Fortis was required to reassess its limited partnerships under the voting interest model. As a result, 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, therefore, continue to 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 output is sold to BC Hydro and FortisBC Electric under 40-year contracts.

The following table details the Waneta Partnership assets, liabilities, revenue, expenses, and cash flow, included in the Corporation’s consolidated financial statements.

(in millions)	2016			2015
ASSETS
Cash and cash equivalents	$	15		$	23
Accounts receivable and other current assets	14			14
Utility capital assets	696			708
Intangible assets	30			30
	$	755		$	775
LIABILITIES
Accounts payable and other current liabilities	$	(3	)	$	(18	)
Other liabilities	(79		)	(74		)
	(82		)	(92		)
Net assets before partners’ equity	$	673		$	683

65

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

31. VARIABLE INTEREST ENTITY (cont’d)

(in millions)	2016		2015
Revenue	$	91	$	70
Expenses
Operating	17		10
Depreciation and amortization	18		14
Finance charges	3		2
	38		26
Net earnings	$	53	$	44

Cash used in investing activities at the Waneta Partnership for 2016 included capital expenditures of $18 million (2015 - $32 million). Cash flow related to financing activities for 2016 included dividends paid by the Waneta Partnership to non-controlling interests of $31 million (2015 - $11 million) and for 2015 included advances from non-controlling interests of $9 million.

32. FINANCIAL RISK MANAGEMENT

The Corporation is primarily exposed to credit risk, liquidity risk and market risk as a result of holding financial instruments in the normal course of business.

Credit risk Risk that a counterparty to a financial instrument might fail to meet its obligations under the terms of the financial instrument.

Liquidity risk Risk that an entity will encounter difficulty in raising funds to meet commitments associated with financial instruments.

Market risk Risk that the fair value or future cash flows of a financial instrument will fluctuate due to changes in market prices. The Corporation is exposed to foreign exchange risk, interest rate risk and commodity price risk.

Credit Risk

For cash equivalents, trade and other accounts receivable, 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 70% 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. As at December 31, 2016, FortisAlberta’s gross credit risk exposure was approximately $123 million, representing the projected value of retailer billings over a 37-day period. The Company has reduced its exposure to $1 million 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, contractual arrangements also contain certain provisions requiring counterparties to derivative instruments to post collateral under certain circumstances.

66

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

32. FINANCIAL RISK MANAGEMENT (cont’d)

Liquidity Risk

The Corporation’s consolidated financial position could be adversely affected if it, or one of its subsidiaries, fails to arrange sufficient and cost-effective financing to fund, among other things, capital expenditures, acquisitions and the repayment of maturing debt. The ability to arrange sufficient and cost-effective financing is subject to numerous factors, including the consolidated results of operations and financial position of the Corporation and its subsidiaries, conditions in capital and bank credit markets, ratings assigned by rating agencies and general economic conditions.

To help mitigate liquidity risk, the Corporation and its regulated utilities have secured committed credit facilities to support short-term financing of capital expenditures, seasonal working capital requirements, and for general corporate purposes. In addition to its credit facilities, ITC uses commercial paper to finance its short-term cash requirements, and may use credit facility borrowings, from time to time, to repay borrowings under its commercial paper program.

The Corporation’s committed corporate credit facility is used for interim financing of acquisitions and for general corporate purposes. Depending on the timing of cash payments from subsidiaries, borrowings under the Corporation’s committed corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends. As at December 31, 2016, over the next five years, average annual consolidated fixed-term debt maturities and repayments are expected to be approximately $680 million. The combination of available credit facilities and reasonable annual debt maturities and repayments provides the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.

As at December 31, 2016, the Corporation and its subsidiaries had consolidated credit facilities of approximately $6.0 billion, of which approximately $3.7 billion was unused, including $915 million 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 $5.1 billion of the total credit facilities are committed facilities with maturities ranging from 2017 through 2021.

The following summary outlines the credit facilities of the Corporation and its subsidiaries.

(in millions)	Regulated Utilities			Corporate and Other			2016			2015
Total credit facilities(1)	$	3,823		$	2,153		$	5,976		$	3,565
Credit facilities utilized:
Short-term borrowings (1) (2)	(640		)	(515		)	(1,155		)	(511		)
Long-term debt (Note 14)(3)	(508		)	(465		)	(973		)	(551		)
Letters of credit outstanding	(68		)	(51		)	(119		)	(104		)
Credit facilities unused (1)	$	2,607		$	1,122		$	3,729		$	2,399

⁽¹⁾  Total credit facilities and short-term borrowings as atDecember 31, 2016 include $195 million (US$145 million) outstanding under ITC’s commercial paper program. 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 1.7% as at December 31, 2016 (December 31, 2015 - 1.0%).

⁽³⁾  As at December 31, 2016, credit facility borrowings classified as long-term debt included $61 millionin current installments of long-term debt on the consolidated balance sheet (December 31, 2015 - $71 million). The weighted average interest rate on credit facility borrowings classified as long‑term debt was approximately 1.8% as at December 31, 2016 (December 31, 2015 - 1.5%).

As at December 31, 2016 and 2015, 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.

67

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

32. FINANCIAL RISK MANAGEMENT

Liquidity Risk (cont’d)

Regulated Utilities

ITC has a total of US$1.0 billion in unsecured committed revolving credit facilities maturing in March 2019. ITC has an ongoing commercial paper program in an aggregate amount of US$400 million, under which US$145 million in commercial paper was outstanding as atDecember 31, 2016.

UNS Energy has a total of US$350 millionin unsecured committed revolving credit facilities, with US$305 millionmaturing in October 2021, and US$45 millionmaturing in October 2020.

Central Hudson has a US$200 millionunsecured committed revolving credit facility, maturing in October 2020, and an uncommitted credit facility totalling US$25 million.

FortisBC Energy has a$700 millionunsecured committed revolving credit facility, maturing in August 2021.

FortisAlberta has a $250 millionunsecured committed revolving credit facility, maturing in August 2021, and a$90 millionbilateral credit facility, maturing in November 2017.

FortisBC Electric has a$150 millionunsecured committed revolving credit facility, maturing in May 2019, and a $10 millionunsecured demand overdraft facility.

Newfoundland Power has a$100 millionunsecured committed revolving credit facility, maturing in August 2021, and a $20 milliondemand credit facility. Maritime Electric has a $50 millionunsecured committed revolving credit facility, maturing in February 2019. FortisOntario has a$30 millionunsecured committed revolving credit facility, maturing in June 2019.

Caribbean Utilities has unsecured credit facilities totalling approximately US$49 million. Fortis Turks and Caicos has short-term unsecured demand credit facilities of US$31 million, maturing in June 2017.

Corporate and Other

Fortis has a $1.3 billionunsecured committed revolving credit facility, maturing in July 2021, and a$500 millionnon-revolving term senior unsecured equity bridge credit facility, used to finance a portion of the cash purchase price of the acquisition of ITC, maturing in October 2017.

UNS Energy Corporation has a US$150 millionunsecured committed revolving credit facility, with US$130 millionmaturing in October 2021, and US$20 millionmaturing in October 2020. CH Energy Group has a US$50 million unsecured committed revolving credit facility, maturing in July 2020. FHI has a$50 millionunsecured committed revolving credit facility, maturing in April 2019.

The Corporation and its currently rated utilities target investment-grade credit ratings to maintain capital market access at reasonable interest rates. As at December 31, 2016, the Corporation’s credit ratings were as follows.

Rating Agency	Credit Rating	Type of Rating	Outlook
Standard & Poor’s (“S&P”)	A-	Corporate	Stable
	BBB+	Unsecured debt	Stable
DBRS	BBB (high)	Unsecured debt	Stable
Moody’s Investor Service (“Moody’s”)	Baa3	Issuer	Stable
	Baa3	Unsecured debt	Stable

The above-noted credit ratings reflect the Corporation’s low business-risk profile and diversity of its operations, the stand-alone nature and financial separation of each of the regulated subsidiaries of Fortis, and the level of debt at the holding company. In September 2016 Moody’s commenced rating Fortis. In October 2016, following the completion of the acquisition of ITC, DBRS revised the Corporation’s unsecured debt credit rating to BBB (high) from A (low) and revised its outlook to stable from under review with negative implications, and S&P affirmed the Corporation’s long-term corporate and unsecured debt credit ratings as A- and BBB+, respectively, and revised its outlook to stable from negative.

68

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

32. FINANCIAL RISK MANAGEMENT (cont’d)

Market Risk

Foreign Exchange Risk

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 through the use of US dollar-denominated borrowings at the corporate level. The foreign exchange gain or loss on the translation of US dollar-denominated interest expense partially offsets the foreign exchange gain or loss on the translation of the Corporation’s foreign subsidiaries’ earnings.

As at December 31, 2016, the Corporation’s corporately issued US$3,511 million (December 31, 2015 -US$1,535 million) long-term debt had been designated as an effective hedge of a portion of the Corporation’s foreign net investments. As at December 31, 2016, the Corporation had approximately US$7,250 million (December 31, 2015 ‑ US$3,137 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.

As a result of the acquisition of ITC, consolidated earnings and cash flows of Fortis are impacted to a greater extent by fluctuations in the US dollar-to-Canadian dollar exchange rate. On an annual basis, it is estimated that a 5 cent increase or decrease in the US dollar relative to the Canadian dollar exchange rate of US$1.00=CAD$1.34 as at December 31, 2016 would increase or decrease earnings per common share of Fortis by approximately 7 cents. Management will continue to hedge future exchange rate fluctuations related to the Corporation’s foreign net investments and US dollar‑denominated earnings streams, where possible, through future US dollar‑denominated borrowings, and will continue to monitor the Corporation’s exposure to foreign currency fluctuations on a regular basis.

Interest Rate Risk

The Corporation and most of its subsidiaries are exposed to interest rate risk associated with borrowings under variable-rate credit facilities, variable-rate long-term debt and the refinancing of long-term debt. The Corporation and its subsidiaries may enter into interest rate swap agreements to help reduce this risk (Note 30).

Commodity Price Risk

UNS Energy is exposed to commodity price risk associated with changes in the market price of gas, purchased power and coal. Central Hudson is exposed to commodity price risk associated with changes in the market price of electricity and gas. FortisBC Energy is exposed to commodity price risk associated with changes in the market price of gas. The risks have been reduced by entering into derivative contracts that effectively fix the price of natural gas, power and electricity purchases. Aitken Creek is exposed to commodity price risk associated with changes in the market price of gas and enters into derivative contracts to manage the financial risk posed by physical transactions. These derivative instruments are recorded on the consolidated balance sheet at fair value and any change in the fair value is deferred as a regulatory asset or liability, as permitted by the regulators, for recovery from, or refund to, customers in future rates, except at Aitken Creek where the changes in fair value are recorded in earnings (Note 30).

69

FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

33. COMMITMENTS

As at December 31, 2016, 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	14,586	892	854	837	817	793	10,393
Power purchase obligations (1)	2,295	290	200	119	107	107	1,472
Renewable power purchase obligations (2)	1,625	100	99	99	98	97	1,132
Gas purchase obligations (3)	1,329	411	290	177	141	110	200
Long-term contracts - UNS Energy (4)	1,146	192	161	161	127	85	420
ITC easement agreement (5)	453	13	13	13	13	13	388
Operating lease obligations	175	13	13	11	8	7	123
Renewable energy credit purchase agreements (6)	154	20	15	12	12	12	83
Purchase of Springerville Common Facilities (7)	91	—	—	—	—	91	—
Waneta Partnership promissory note (Note 16)	72	—	—	—	72	—	—
Joint-use asset and shared service agreements	53	3	3	3	3	3	38
Other (8)	156	93	18	19	—	—	26
Total	22,135	2,027	1,666	1,451	1,398	1,318	14,275

⁽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 $743 millionas atDecember 31, 2016, 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 $486 millionas atDecember 31, 2016.

FortisBC Electric: Power purchase obligations for FortisBC Electric, totalling $288 millionas atDecember 31, 2016, include a PPA with BC Hydro to purchase up to 200MW of capacity and1,752 GWhof associated energy annually for a 20-year term. FortisBC Electric is also party to the Waneta Expansion Capacity Agreement (“WECA”), allowing it to purchase 234MW of capacity for40 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 includetwotake-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 approximately4.55% 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 atDecember 31, 2016, had commitments of $480 millionunder this arrangement.

⁽²⁾  TEP and UNS Electric are party to long-term renewable PPAs totalling approximately US$1,210 millionas atDecember 31, 2016, which require TEP and UNS Electric to purchase100% 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 2030 through 2036.

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FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

33. COMMITMENTS (cont’d)

⁽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, 2016.

⁽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, with obligations totalling US$496 million, US$244 millionand US$113 million, respectively, as at December 31, 2016. 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. UNS Energy’s renewable energy credit purchase agreements totalled approximately US$107 millionas at December 31, 2016 for the purchase of environmental attributions from retail customers with solar installations. Payments for the renewable energy credit purchase agreements are paid in contractually agreed-upon intervals based on metered renewable energy production.

⁽⁷⁾  UNS Energy has an obligation to purchase an undivided 32.2% leased interest in the Springerville Common Facilities if the related two leases are not renewed, for a total purchase price of US$68 million(Note 15).

⁽⁸⁾  Other contractual obligations include various other commitments entered into by the Corporation and its subsidiaries, including PSU, RSU and DSU plan obligations, 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 $3.0 billionfor 2017. Over the five years2017through2021, the Corporation’s consolidated capital expenditure program is expected to be approximately$13 billion,which has not been included in the Commitments table.

Other: CH Energy Group is party to an investment to 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 fivehigh-voltage transmission projects totalling US$1.7 billion, of which CH Energy Group’s maximum commitment is US$182 million. CH Energy Group issued a parental guarantee to assure the payment of the maximum commitment of US$182 million. As at December 31, 2016, there was no obligation under this guarantee.

In 2016 FHI issued a parental guarantee of $77 million to secure the storage optimization transactions of Aitken Creek.

The Corporation’s long-term regulatory liabilities of $2,183 millionas atDecember 31, 2016 have been excluded from the Commitments table, as the final timing of settlement of many of the liabilities is subject to further regulatory determination or the settlement periods are not currently known (Note 8).

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FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

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FORTIS INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2016 and 2015

34. 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 adverse effect on the Corporation’s consolidated financial position, results of operations or cash flows. The following describes the nature of the Corporation’s contingencies.

Central Hudson

Prior to and after its acquisition by Fortis, various asbestos lawsuits have been brought against Central Hudson. While a total of3,363asbestos cases have been raised, 1,175remained pending as at December 31, 2016. Of the cases no longer pending against Central Hudson,2,032have been dismissed or discontinued without payment by the Company, and Central Hudson has settled the remaining156cases. The Company is presently unable to assess the validity of the outstanding asbestos lawsuits; however, based on information known to Central Hudson at this time, including the Company’s experience in the settlement and/or dismissal of asbestos cases, Central Hudson believes that the costs which may be incurred in connection with the remaining lawsuits will not have a material effect on its financial position, results of operations or cash flows and, accordingly, no amount has been accrued in the consolidated financial statements.

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 Coldwater Band’s application for judicial review of the ministerial consent. The Band has appealed that decision. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.

Fortis and ITC

Following announcement of the acquisition of ITC in February 2016, complaints which named Fortis and other defendants were filed in the Oakland County Circuit Court in the State of Michigan (“Superior Court”) and the United States District Court in and for the Eastern District of Michigan. The complaints generally allege, among other things, that the directors of ITC breached their fiduciary duties in connection with the merger agreement and that ITC, Fortis, FortisUS Inc. and Element Acquisition Sub Inc. aided and abetted those purported breaches. The complaints seek class action certification and a variety of relief including, among other things, unspecified damages, and costs, including attorneys’ fees and expenses. In July 2016 the federal actions were voluntarily dismissed by the federal plaintiffs. The federal plaintiffs reserved the right to make certain other claims, and ITC and the individual members of the ITC board of directors reserved the right to oppose any such claim. The federal plaintiffs have sought a mootness fee application and the parties are currently exploring a mutually satisfactory resolution. In June 2016 the Superior Court granted a motion for summary disposition dismissing the aiding and abetting claims asserted against Fortis, FortisUS Inc. and Element Acquisition Sub Inc. In January 2017 the Superior Court issued a revised scheduling order, which, among other things, requires the parties, including ITC, to complete discovery by May 2017, and set a trial date for September 2017. A hearing on the plaintiff’s motion for class certification was held on February 9, 2017. A hearing on a motion of the defendants for summary disposition has been scheduled for March 2017. The outcome of these lawsuits cannot be predicted with any certainty and, accordingly, no amount has been accrued in the consolidated financial statements.

35. COMPARATIVE FIGURES

Certain comparative figures have been reclassified to comply with current period presentation. Acquisition-related expenses of $10 million in 2015 were previously included in other income, net of expenses, on the consolidated statement of earnings and have been reclassified to operating expenses (Note 27). Related-party transactions for the sale of energy from the Waneta Expansion to FortisBC Electric totalling $30 million in 2015 were previously eliminated on consolidation. Fortis no longer eliminates related-party transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities and, as a result, revenue and energy supply costs each increased by $30 million(Note 5).

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