EX-99.2 3 ex992fortis2016fs.htm EXHIBIT 99.2 Exhibit
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
 
NOTE 15
Capital Lease and Finance Obligations
Independent Auditors’ Report of Registered
Public Accounting Firm
 
NOTE 16
Other Liabilities
Consolidated Balance Sheets
 
NOTE 17
Common Shares
Consolidated Statements of Earnings
 
NOTE 18
Earnings per Common Share
Consolidated Statements of Comprehensive Income
 
NOTE 19
Preference Shares
Consolidated Statements of Cash Flows
 
NOTE 20

Accumulated Other Comprehensive Income
Consolidated Statements of Changes in Equity
 
NOTE 21
Non-Controlling Interests
Notes to Consolidated Financial Statements
 
NOTE 22
Stock-Based Compensation Plans
NOTE 1
Description of Business
 
NOTE 23
Other Income (Expenses), Net
NOTE 2
Nature of Regulation
 
NOTE 24
Finance Charges
NOTE 3

Summary of Significant Accounting Policies
 
NOTE 25
Income Taxes
NOTE 4
Future Accounting Pronouncements
 
NOTE 26
Employee Future Benefits
NOTE 5
Segmented Information
 
NOTE 27
Business Acquisitions
NOTE 6

Accounts Receivable and Other Current Assets
 
NOTE 28
Dispositions
NOTE 7
Inventories
 
NOTE 29


Supplementary Information to Consolidated Statements of Cash Flows
NOTE 8
Regulatory Assets and Liabilities
 
NOTE 30

Fair Value Measurements and Financial Instruments
NOTE 9
Other Assets
 
NOTE 31
Variable Interest Entity
NOTE 10
Utility Capital Assets
 
NOTE 32
Financial Risk Management
NOTE 11
Intangible Assets
 
NOTE 33
Commitments
NOTE 12
Goodwill
 
NOTE 34
Contingencies
NOTE 13

Accounts Payable and Other Current Liabilities
 
NOTE 35
Comparative Figures
NOTE 14
Long-Term Debt
 
 
 
 

 
 
 



 
 
 

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 two 50-year licences expiring in 2036 and 2037. Among other matters, the licences describe how electricity rates are set by the Government of the Turks and Caicos Islands, using a historical test year, in order to provide the utilities with an allowed ROA of between 15.0% and 17.5% (the “Allowable Operating Profit”). The Allowable Operating Profit is based on a calculated rate base, including interest on the amounts by which actual operating profits fall short of the Allowable Operating Profits on a cumulative basis (the “Cumulative Shortfall”). Annual submissions are made to the Government of the Turks and Caicos Islands calculating the amount of the Allowable Operating Profit and the Cumulative Shortfall. The 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.

 
12
 



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% (20153.1%).

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% (20151.0% 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 in 2016 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.


 
19
 



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).

 
20
 



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’s 51% 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 million related 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 million decrease 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 13 and 16). Central Hudson’s MGP site remediation costs are not subject to a regulatory return.