EX-99.2 3 a992fortis2018annualfs.htm EXHIBIT 99.2 Exhibit

Exhibit 99.2

 
 
 










FORTIS INC.


Audited Consolidated Financial Statements
As at and for the years ended December 31, 2018 and 2017


 
 
 


 
 
 

TABLE OF CONTENTS
Management's Report on Internal Control over Financial Reporting

 
NOTE 12
Property, Plant and Equipment
Report of Independent Registered Public Accounting Firm - Opinion on the
Consolidated Financial Statements
 
NOTE 13
Intangible Assets
Report of Independent Registered Public Accounting Firm - Opinion on Internal
Control over Financial Reporting
 
NOTE 14
Goodwill
Consolidated Balance Sheets
 
NOTE 15

Accounts Payable and Other Current Liabilities
Consolidated Statements of Earnings
 
NOTE 16
Long-Term Debt
Consolidated Statements of Comprehensive
Income

 
NOTE 17
Capital Lease and Finance Obligations
Consolidated Statements of Cash Flows
 
NOTE 18
Other Liabilities
Consolidated Statements of Changes in Equity
 
NOTE 19
Earnings per Common Share
Notes to Consolidated Financial Statements
 
NOTE 20
Preference Shares
NOTE 1
Description of Business
 
NOTE 21

Accumulated Other Comprehensive Income
NOTE 2
Regulation
 
NOTE 22
Stock-Based Compensation Plans
NOTE 3

Summary of Significant Accounting Policies
 
NOTE 23
Other Income, Net
NOTE 4
Future Accounting Pronouncements
 
NOTE 24
Income Taxes
NOTE 5
Segmented Information
 
NOTE 25
Employee Future Benefits
NOTE 6
Revenue
 
NOTE 26
Terminated Acquisition

NOTE 7

Accounts Receivable and Other Current Assets
 
NOTE 27
Supplementary Cash Flow Information
NOTE 8
Inventories
 
NOTE 28

Fair Value of Financial Instruments and Risk Management
NOTE 9
Regulatory Assets and Liabilities
 
NOTE 29
Variable Interest Entity
NOTE 10
Assets Held for Sale
 
NOTE 30
Commitments and Contingencies
NOTE 11
Other Assets
 
NOTE 31
Comparative Figures

 
 
 


 
 
 

Management's Report on Internal Control over Financial Reporting


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

The Corporation's management, including its CEO and CFO, assessed the effectiveness of the Corporation's ICFR as at December 31, 2018, based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concluded that, as at December 31, 2018, the Corporation's ICFR was effective.

The Corporation's ICFR as at December 31, 2018 has been audited by Deloitte LLP, an Independent Registered Public Accounting Firm, which also audited the Corporation's consolidated financial statements for the year ended December 31, 2018. Deloitte LLP issued an unqualified opinion for both audits.


February 14, 2019


/s/ Barry V. Perry

Barry V. Perry
President and Chief Executive Officer, Fortis Inc.



/s/ Jocelyn H. Perry

Jocelyn H. Perry
Executive Vice President, Chief Financial Officer, Fortis Inc.

St. John's, Canada

 
i
 


 
 
 

Report of Independent Registered Public Accounting Firm




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


Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Fortis Inc. and subsidiaries (the "Corporation") as at December 31, 2018 and 2017, the related consolidated statements of earnings, comprehensive income, cash flows, and changes in equity for each of the two years in the period ended December 31, 2018, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Corporation as at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) ("PCAOB"), the Corporation's internal control over financial reporting as at December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 14, 2019, expressed an unqualified opinion on the Corporation's internal control over financial reporting.

Basis for Opinion
These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on the Corporation's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.


/s/ Deloitte LLP
Chartered Professional Accountants

St. John's, Canada
February 14, 2019

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

 
ii
 


 
 
 

Report of Independent Registered Public Accounting Firm



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

Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Fortis Inc. and subsidiaries (the "Corporation") as at December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as at December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) ("PCAOB"), the consolidated financial statements as at and for the year ended December 31, 2018, of the Corporation and our report dated February 14, 2019, expressed an unqualified opinion on those financial statements.

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

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

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

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


/s/ Deloitte LLP
Chartered Professional Accountants

St. John's, Canada
February 14, 2019


 
iii
 

FORTIS INC.
Consolidated Balance Sheets
As at December 31
(in millions of Canadian dollars)
 
2018

 
2017

 
 
 
 
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
332

 
$
327

Accounts receivable and other current assets (Note 7)
1,357

 
1,131

Prepaid expenses
84

 
79

Inventories (Note 8)
398

 
367

Regulatory assets (Note 9)
324

 
303

Assets held for sale (Note 10)
766

 
—

Total current assets
3,261

 
2,207

Other assets (Note 11)
552

 
480

Regulatory assets (Note 9)
2,854

 
2,742

Property, plant and equipment, net (Note 12)
32,654

 
29,668

Intangible assets, net (Note 13)
1,200

 
1,081

Goodwill (Note 14)
12,530

 
11,644

Total assets
$
53,051

 
$
47,822

 
 
 
 
LIABILITIES AND EQUITY
 
 
 
Current liabilities
 
 
 
Short-term borrowings (Note 16)
$
60

 
$
209

Accounts payable and other current liabilities (Note 15)
2,289

 
2,053

Regulatory liabilities (Note 9)
656

 
490

Current installments of long-term debt (Note 16)
926

 
705

Current installments of capital lease and finance obligations (Note 17)
252

 
47

Liabilities associated with assets held for sale (Note 10)
69

 
—

Total current liabilities
4,252

 
3,504

Other liabilities (Note 18)
1,138

 
1,210

Regulatory liabilities (Note 9)
2,970

 
2,956

Deferred income taxes (Note 24)
2,686

 
2,298

Long-term debt (Note 16)
23,159

 
20,691

Capital lease and finance obligations (Note 17)
390

 
414

Total liabilities
34,595

 
31,073

Commitments and contingencies (Note 30)

 

Equity
 
 
 
Common shares (1) 
11,889

 
11,582

Preference shares (Note 20)
1,623

 
1,623

Additional paid-in capital
11

 
10

Accumulated other comprehensive income (Note 21)
928

 
61

Retained earnings
2,082

 
1,727

Shareholders' equity
16,533

 
15,003

Non-controlling interests
1,923

 
1,746

Total equity
18,456

 
16,749

Total liabilities and equity
$
53,051

 
$
47,822

 
 
 
 
(1) No par value. Unlimited authorized shares; 428.5 million and 421.1 million
issued and outstanding as at December 31, 2018 and 2017, respectively
Approved on Behalf of the Board
 
/s/ Douglas J. Haughey
 
/s/ Tracey C. Ball
 
 
 
Douglas J. Haughey,
Tracey C. Ball,
 
See accompanying Notes to Consolidated Financial Statements
Director
 
Director

1

FORTIS INC.
Consolidated Statements of Earnings
For the years ended December 31
(in millions of Canadian dollars, except per share amounts)
 
 
 
 
 
 
 
2018

 
2017

 
 
 
 
 
Revenue (Note 6)
$
8,390

 
$
8,301

 
 
 
 
 
Expenses
 
 
 
Energy supply costs
2,495

 
2,361

Operating expenses
2,287

 
2,250

Depreciation and amortization
1,243

 
1,179

Total expenses
6,025

 
5,790

Operating income
2,365

 
2,511

Other income, net (Note 23)
60

 
116

Finance charges
974

 
914

Earnings before income tax expense
1,451

 
1,713

Income tax expense (Note 24)
165

 
588

Net earnings
$
1,286

 
$
1,125

 
 
 
 
 
Net earnings attributable to:
 
 
 
 
Non-controlling interests
$
120

 
$
97

 
Preference equity shareholders
66

 
65

 
Common equity shareholders
1,100

 
963

 
 
$
1,286

 
$
1,125

 
 
 
 
 
Earnings per common share (Note 19)
 
 
 
Basic
$
2.59

 
$
2.32

Diluted
$
2.59

 
$
2.31

 
 
 
 
 
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)
 
 
2018

 
2017

 
 
 
 
 
Net earnings
$
1,286

 
$
1,125

 
 
 
 
 
Other comprehensive income (loss)
 
 
 
Unrealized foreign currency translation gains (losses), net of hedging activities and income tax recovery (expense) of $11 million and $(2) million, respectively
985

 
(781
)
Other, net of income tax expense of $2 million and nil, respectively
6

 
(2
)
 
991

 
(783
)
Comprehensive income
$
2,277

 
$
342

 
 
 
 
Comprehensive income (loss) attributable to:
 
 
 
 
Non-controlling interests
$
244

 
$
(2
)
 
Preference equity shareholders
66

 
65

 
Common equity shareholders
1,967

 
279

 
$
2,277

 
$
342

 
 
 
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)
 
 
 
2018

 
2017

 
 
 
 
 
 
Operating activities
 
 
 
Net earnings
$
1,286

 
$
1,125

Adjustments to reconcile net earnings to net cash provided by
 
 
 
operating activities:
 
 
 
 
 
Depreciation - property, plant and equipment
1,107

 
1,055

 
 
Amortization - intangible assets
106

 
97

 
 
Amortization - other
30

 
27

 
 
Deferred income tax expense (Note 24)
136

 
544

 
 
Equity component, allowance for funds used during construction
(Note 23)
(64
)
 
(74
)
 
 
Other
92

 
11

Change in long-term regulatory assets and liabilities
13

 
68

Change in working capital (Note 27)
(102
)
 
(97
)
Cash from operating activities
2,604

 
2,756

Investing activities
 
 
 
Capital expenditures - property, plant and equipment
(3,032
)
 
(2,813
)
Capital expenditures - intangible assets
(186
)
 
(211
)
Contributions in aid of construction
106

 
102

Other
(140
)
 
(103
)
Cash used in investing activities
(3,252
)
 
(3,025
)
Financing activities
 
 
 
Proceeds from long-term debt, net of issuance costs (Note 16)
1,566

 
2,538

Repayments of long-term debt and capital lease and finance obligations
(563
)
 
(952
)
Borrowings under committed credit facilities (Note 31)
5,666

 
6,461

Repayments under committed credit facilities (Note 31)
(5,523
)
 
(7,480
)
Net change in short-term borrowings (Note 31)
38

 
(192
)
Issue of common shares, net of costs, and dividends reinvested
34

 
561

Dividends
 
 
 
 
Common shares, net of dividends reinvested
(459
)
 
(419
)
 
Preference shares
(66
)
 
(65
)
 
Subsidiary dividends paid to non-controlling interests
(85
)
 
(109
)
Other
36

 
(4
)
Cash from financing activities
644

 
339

Effect of exchange rate changes on cash and cash equivalents
24

 
(12
)
Change in cash and cash equivalents
20

 
58

Less: Cash associated with assets held for sale (Note 10)
(15
)
 
—

Cash and cash equivalents, beginning of year
327

 
269

Cash and cash equivalents, end of year
$
332

 
$
327

 
 
 
 
 
 
Supplementary Cash Flow Information (Note 27)
 
 
 
 
 
 
See accompanying Notes to Consolidated Financial Statements

3

FORTIS INC.
Consolidated Statements of Changes in Equity
For the years ended December 31, 2018 and 2017
(in millions of Canadian dollars, except share numbers)
 
Common Shares
(millions)
Common
Shares
 
Preference Shares
(Note 20)
 
Additional Paid-In
Capital
 
Accumulated Other Comprehensive Income (Loss)
(Note 21)
 
Retained
Earnings
 
Non-Controlling
Interests
 
Total
Equity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
As at December 31, 2017
421.1

$
11,582

 
$
1,623

 
$
10

 
$
61

 
$
1,727

 
$
1,746

 
$
16,749

Net earnings
—

—

 
—

 
—

 
—

 
1,166

 
120

 
1,286

Other comprehensive income
—

—

 
—

 
—

 
867

 
—

 
124

 
991

Common shares issued
7.4

307

 
—

 
(1
)
 
—

 
—

 
—

 
306

Subsidiary dividends paid to non-controlling interests
—

—

 
—

 
—

 
—

 
—

 
(85
)
 
(85
)
Dividends declared on common shares ($1.75 per share)
—

—

 
—

 
—

 
—

 
(745
)
 
—

 
(745
)
Dividends declared on preference shares
—

—

 
—

 
—

 
—

 
(66
)
 
—

 
(66
)
Other
—

—

 
—

 
2

 
—

 
—

 
18

 
20

As at December 31, 2018
428.5

$
11,889

 
$
1,623

 
$
11

 
$
928

 
$
2,082

 
$
1,923

 
$
18,456

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
As at December 31, 2016
401.5

$
10,762

 
$
1,623

 
$
12

 
$
745

 
$
1,455

 
$
1,853

 
$
16,450

Net earnings
—

—

 
—

 
—

 
—

 
1,028

 
97

 
1,125

Other comprehensive loss
—

—

 
—

 
—

 
(684
)
 
—

 
(99
)
 
(783
)
Common shares issued
19.6

820

 
—

 
(5
)
 
—

 
—

 
—

 
815

Subsidiary dividends paid to non-controlling interests
—

—

 
—

 
—

 
—

 
—

 
(109
)
 
(109
)
Dividends declared on common shares ($1.65 per share)
—

—

 
—

 
—

 
—

 
(691
)
 
—

 
(691
)
Dividends declared on preference shares
—

—

 
—

 
—

 
—

 
(65
)
 
—

 
(65
)
Other
—

—

 
—

 
3

 
—

 
—

 
4

 
7

As at December 31, 2017
421.1

$
11,582

 
$
1,623

 
$
10

 
$
61

 
$
1,727

 
$
1,746

 
$
16,749

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See accompanying Notes to Consolidated Financial Statements
 
 
 
 
 
 
 


4


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

1. DESCRIPTION OF BUSINESS

Fortis Inc. ("Fortis" or the "Corporation") is principally a North American electric and gas utility holding company. Entities within the reporting segments that follow operate with substantial autonomy.

Regulated Utilities

ITC: Primarily comprised of ITC Holdings Corp., ITC Investment Holdings Inc. and the electric transmission operations of its regulated operating subsidiaries, which include International Transmission Company ("ITCTransmission"), Michigan Electric Transmission Company, LLC ("METC"), ITC Midwest LLC ("ITC Midwest"), and ITC Great Plains, LLC. Fortis owns 80.1% of ITC and an affiliate of GIC Private Limited owns a 19.9% minority interest.

ITC owns and operates high-voltage transmission lines in Michigan's lower peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma.

UNS Energy: Comprised of UNS Energy Corporation, which primarily includes Tucson Electric Power Company ("TEP"), UNS Electric, Inc. ("UNS Electric") and UNS Gas, Inc. ("UNS Gas").

UNS Energy's largest operating subsidiary, TEP, and UNS Electric are vertically integrated regulated electric utilities. They generate, transmit and distribute electricity to retail customers in southeastern Arizona, including the greater Tucson metropolitan area in Pima County and parts of Cochise County, as well as in Santa Cruz and Mohave counties. TEP also sells wholesale electricity to other entities in the western United States. Together they own generation capacity of 3,377 megawatts ("MW"), including 57 MW of solar capacity. Several generating assets in which they have an interest are jointly owned.

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

Central Hudson: Primarily comprised of CH Energy Group, Inc. and Central Hudson Gas & Electric Corporation. Central Hudson is a regulated electric and gas transmission and distribution utility that serves portions of New York State's Mid-Hudson River Valley and owns gas-fired and hydroelectric generating capacity totalling 64 MW.

FortisBC Energy: Primarily comprised of FortisBC Energy Inc., which is the largest regulated distributor of natural gas in British Columbia, providing transmission and distribution services in over 135 communities. FortisBC Energy obtains natural gas supplies primarily from northeastern British Columbia and Alberta on behalf of most customers.

FortisAlberta: FortisAlberta Inc. is a regulated electricity distribution utility operating in a substantial portion of southern and central Alberta. It is not involved in the direct sale of electricity.

FortisBC Electric: Primarily comprised of FortisBC Inc., an integrated regulated electric utility operating in the southern interior of British Columbia. It owns four hydroelectric generating facilities with a combined capacity of 225 MW. It also provides operating, maintenance and management services relating to four hydroelectric generating facilities in British Columbia that are owned by third parties and to the 335-MW Waneta Expansion hydroelectric generating facility ("Waneta Expansion") in which Fortis indirectly holds a 51% controlling interest (Notes 10 and 29).

Other Electric: Comprised of utilities in eastern Canada and the Caribbean, as follows: Newfoundland Power Inc. ("Newfoundland Power"); Maritime Electric Company, Limited ("Maritime Electric"); FortisOntario Inc. ("FortisOntario"); a 49% equity investment in Wataynikaneyap Power Limited Partnership ("Wataynikaneyap Partnership") (Note 11); an approximate 60% controlling interest in Caribbean Utilities Company, Ltd. ("Caribbean Utilities"); FortisTCI Limited and Turks and Caicos Utilities Limited (collectively "FortisTCI"); and a 33% equity investment in Belize Electricity Limited ("BEL") (Note 11).

In January 2019 Fortis reduced its equity investment in Wataynikaneyap Partnership from 49% to 39% to facilitate the inclusion of two additional First Nations communities into the partnership.

 
5
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Newfoundland Power is an integrated regulated electric utility and the principal distributor of electricity on the island portion of Newfoundland and Labrador with a generating capacity of 139 MW, of which 97 MW is hydroelectric. Maritime Electric is an integrated regulated electric utility and the principal distributor of electricity on Prince Edward Island ("PEI") with on-Island generating capacity of 145 MW. FortisOntario is comprised of three regulated electric utilities that provide service to customers in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario. Wataynikaneyap Partnership is a partnership between 24 First Nations communities and Fortis with a mandate of connecting remote First Nations communities to the electricity grid in Ontario through the development of new transmission lines.

Caribbean Utilities is an integrated regulated electric utility and the sole electricity provider on Grand Cayman with a diesel-powered generating capacity of 161 MW. FortisTCI is comprised of two integrated regulated electric utilities that provide electricity to certain Turks and Caicos Islands and has a diesel-powered generating capacity of 91 MW. BEL is an integrated electric utility and the principal distributor of electricity in Belize.

Non-Regulated

Energy Infrastructure: Primarily comprised of long-term contracted generation assets in British Columbia and Belize, and the Aitken Creek natural gas storage facility ("Aitken Creek"). Generation assets in British Columbia include the Corporation's interest in the Waneta Expansion (Note 10), whose output is sold to British Columbia Hydro and Power Authority ("BC Hydro") and FortisBC Electric under 40-year power purchase agreements ("PPAs"). Generation 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 BEL under 50-year PPAs. Fortis indirectly owns 93.8% of Aitken Creek, with the remainder owned by BP Canada Energy Company. Aitken Creek is the only underground natural gas storage facility in British Columbia and has a working gas capacity of 77 billion cubic feet.

Corporate and Other: Captures 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, including net corporate expenses of Fortis and the non-regulated holding company FortisBC Holdings Inc. ("FHI").


2. REGULATION

General

The earnings of the Corporation's regulated utilities are determined under cost of service ("COS") regulation, with some using performance-based rate setting ("PBR") mechanisms.

Under COS regulation the regulator sets customer rates to permit a reasonable opportunity for the timely recovery of estimated costs of providing service, 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 to recover prudently incurred costs of providing service and earn the regulator‑approved rate of return on common shareholders' equity ("ROE") and/or rate of return on rate base assets ("ROA") may depend on achieving the forecasts established in the rate-setting process. Usage of a historical test year may cause regulatory lag between when costs are incurred and when they are reflected in customer rates.

When PBR mechanisms are utilized in determining customer rates, a formula is generally applied that incorporates inflation and assumed productivity improvements for a set term. 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 regulators to flow through to customers, without markup, the cost of natural gas, fuel and/or purchased power through base customer rates and/or the use of rate stabilization and other mechanisms (Note 9).

 
6
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

ITC

ITC is regulated by the Federal Energy Regulatory Commission ("FERC") under the Federal Power Act (United States). Rates are set annually, using FERC-approved cost-based formula rate templates, and remain in effect for one year, which provides timely cost recovery. An annual true-up mechanism compares actual revenue requirements to billed revenues, and any variances 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 by customers with FERC. ITC's rates reflect an allowed ROE ranging from 11.07% to 12.16% on a capital structure of 60% common equity for 2018 (ROE range of 11.32% to 12.16% and 60% common equity for 2017).

Incentive Adder Complaint
In April 2018 a third-party complaint was filed with FERC challenging the independence incentive adders that are included in transmission rates charged by transmission owners operating in the Midcontinent Independent System Operator ("MISO") region, which includes ITCTransmission, METC and ITC Midwest (collectively "ITC's MISO Subsidiaries"). The adder allowed up to 0.50% or 1.00% to be added to the authorized ROE, subject to any ROE cap established by FERC. In October 2018 FERC issued an order reducing the adders to 0.25%, effective April 20, 2018. This equates to a 0.25% decrease in ROE, down from the approximate 0.50% that ITC was earning in rates previously approved by FERC. ITC's MISO Subsidiaries sought rehearing of this order and began reflecting the 0.25% adder in transmission rates in November 2018. Refunds began in the fourth quarter of 2018 and were completed in the first quarter of 2019. The order is not expected to have a material impact on the Corporation's earnings or cash flows.

ROE Complaints
Two third-party complaints requested that the base ROE for MISO transmission owners, including ITC's MISO Subsidiaries, be found to no longer be just or reasonable. The complaints cover two consecutive 15-month periods from November 2013 through February 2015 (the "Initial Refund Period" or "Initial Complaint") and February 2015 through May 2016 (the "Second Refund Period" or "Second Complaint"). FERC orders on the complaints will also set the ROE that will be effective prospectively from the order dates.

In September 2016 FERC ordered that the base ROE for the Initial Refund Period be set at 10.32%, down from 12.38%, with a maximum of 11.35%. The resultant rates apply prospectively from September 2016 until an approved ROE is established for the Second Refund Period. The MISO transmission owners sought rehearing of this order. The total refund for the Initial Complaint as a result of the September 2016 FERC order was $158 million (US$118 million), including interest, and was paid in 2017 (Note 9).

In June 2016 the presiding Administrative Law Judge ("ALJ") issued an initial decision on the Second Complaint, recommending a base ROE of 9.70%, with a maximum of 10.68%. The initial decision of the ALJ is a non-binding recommendation to FERC, and FERC has yet to issue its order on the Second Complaint. In September 2017 certain MISO transmission owners filed a motion for FERC to dismiss the Second Complaint. Pending an order from FERC, an estimated regulatory liability of $206 million (US$151 million) has been recognized (December 31, 2017 - $182 million (US$145 million)) (Note 9).

There is uncertainty regarding the final outcome of the Initial and Second Complaints due in part to a November 2018 FERC order proposing a new methodology for determining a just and reasonable base ROE. If finalized, this proposed methodology will be used to address ITC's outstanding ROE complaints. Briefs are due to be filed in the first half of 2019 on the proposed adoption of the new methodology.

UNS Energy

UNS Energy is regulated by the Arizona Corporation Commission ("ACC") and certain activities are subject to regulation by FERC under the Federal Power Act (United States). UNS Energy uses a historical test year to establish retail electric and gas rates.

Effective February 27, 2017, TEP's rates reflect an allowed ROE of 9.75% on a capital structure of approximately 50% common equity, effective from July 1, 2013, prior to which its allowed ROE was 10.0% on a capital structure of 43.5% common equity. Effective August 1, 2016, UNS Electric's rates reflect an allowed ROE of 9.5% on a capital structure of 52.8% common equity. Effective May 1, 2012, UNS Gas' rates reflect an allowed ROE of 9.75% and a capital structure of 50.8% common equity.

 
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FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Central Hudson

Central Hudson is regulated by the New York State Public Service Commission ("PSC") and certain activities are subject to regulation by FERC under the Federal Power Act (United States). Central Hudson uses a future test year to establish rates.

Effective July 1, 2018, pursuant to a three-year settlement agreement arising from a 2017 general rate application, Central Hudson's rates reflect an allowed ROE of 8.8% on a capital structure of 48%, 49% and 50% common equity in rate years one, two and three, respectively. Prior thereto, effective from July 1, 2015, Central Hudson's allowed ROE was 9.0% on a capital structure of 48% common equity.

Central Hudson is also subject to an earnings sharing mechanism whereby the Company and its customers share equally earnings between 50 and 100 basis points above the allowed ROE. Earnings beyond this are primarily returned to customers.

FortisBC Energy and FortisBC Electric

FortisBC Energy and FortisBC Electric are regulated by the British Columbia Utilities Commission ("BCUC") pursuant to the Utilities Commission Act (British Columbia), and are subject to multi-year PBR plans for 2014 through 2019 whereby a going-in revenue requirement is first established and used to set initial rates and thereafter a prescribed formula is applied annually to the previous year's rates to establish new rates for the remainder of the multi-year period.

The PBR plans incorporate incentive mechanisms for improving operating and capital expenditure efficiencies. Operation and maintenance expenses and base capital expenditures during the PBR period are subject to an incentive formula reflecting incremental costs for inflation and half of customer growth, less a fixed productivity adjustment factor of 1.1% for FortisBC Energy and 1.03% for FortisBC Electric each year. The approved PBR plans also include a 50/50 sharing of variances from the formula‑driven operation and maintenance expenses and capital expenditures over the PBR period, and a number of service quality measures designed to ensure FortisBC Energy and FortisBC Electric maintain specified service levels.

FortisBC Energy is the benchmark utility in British Columbia, as designated by the BCUC, and effective January 1, 2016, its rates reflect an allowed ROE of 8.75% and a capital structure of 38.5% common equity.

Effective January 1, 2016, FortisBC Electric's rates reflect an allowed ROE of 9.15% and a capital structure of 40% common equity.

FortisAlberta

FortisAlberta is regulated by the Alberta Utilities Commission 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 multi-year PBR plans for 2013-2017 and 2018-2022 whereby a going-in revenue requirement is first established and used to set initial rates and thereafter a prescribed formula is applied annually to the previous year's rates to establish new rates for the remainder of the multi-year period.

The PBR plans include 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 ("capital tracker" or "K-bar"). It also includes a Z factor, a PBR re-opener, and an efficiency carry-over mechanism. The Z factor permits an application for recovery of costs, subject to certain thresholds, related to significant unforeseen events. The PBR re-opener permits, subject to certain thresholds, an application to re-open and review the PBR plan to address specific problems with its design or operation. The 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.

 
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FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Pursuant to generic cost of capital proceedings completed in 2018, FortisAlberta's rates reflect an allowed ROE of 8.5% on a capital structure of 37% common equity for 2018-2020, unchanged from 2017.

Other Electric

Newfoundland Power is regulated by the Newfoundland and Labrador Board of Commissioners of Public Utilities under the Public Utilities Act (Newfoundland and Labrador) and uses a future test year to establish rates. Effective 2016 to 2018, Newfoundland Power's rates reflect an allowed ROE of 8.5% on a capital structure of 45% common equity.

Maritime Electric is regulated by the Island Regulatory and Appeals Commission under the provisions of the Electric Power Act (PEI), the Renewable Energy Act (PEI) and the Electric Power (Electricity Rate-Reduction) Amendment Act (PEI), and uses a future test year to establish rates. Effective March 1, 2016 for a three-year period, Maritime Electric's rates reflect an allowed ROE of 9.35% on a capital structure of 40% common equity.

FortisOntario's three electric utilities are regulated by the Ontario Energy Board under the Electricity Act (Ontario) and the Ontario Energy Board Act (Ontario). Two of FortisOntario's utilities use a future test year to establish rates under five-year PBR plans whereby a going-in revenue requirement is first established and used to set initial rates and thereafter a prescribed formula using inflationary factors less an efficiency target is applied annually to the previous year's rates to establish new rates for the remainder of the five-year period. The allowed ROEs ranged from 8.78% to 9.30% for both 2018 and 2017, on a capital structure of 40% common equity. FortisOntario's remaining utility is subject to a 35-year franchise agreement, expiring in 2033, whereby rates are based on a price cap with commodity cost flow through and with the base revenue requirement adjusted annually for inflation, load growth and customer growth.

Caribbean Utilities operates under licences from the Government of the Cayman Islands. Its exclusive transmission and distribution licence is for an initial period of 20 years, expiring in April 2028, with a provision for automatic renewal. Its non-exclusive generation licence is for a term of 25 years, expiring in November 2039. It is regulated under a rate‑cap adjustment mechanism based on published consumer price indices. The licences detail the role of the Cayman Islands Utility Regulation and Competition Office, which oversees all licences, establishes and enforces licence standards, reviews the rate-cap adjustment mechanism, and annually approves capital expenditures. Its allowed ROA for 2018 was in the range of 7.00% to 9.00% (range of 6.75% to 8.75% for 2017).

FortisTCI operates under two 50-year licences from the Government of the Turks and Caicos Islands, which expire in 2036 and 2037. Rates reflect a historical test year and a targeted 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 cumulative amount by which actual operating profits fall short of the Allowable Operating Profit (the "Cumulative Shortfall"). The calculated Allowable Operating Profit and Cumulative Shortfall are submitted to the Government annually. The recovery of the Cumulative Shortfall is dependent on future sales volumes and expenses. The achieved ROAs at the utilities have been significantly lower than those allowed as a result of the inability, due to economic and political factors, to increase rates to support significant capital investment in recent years.


3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

These consolidated financial statements have been prepared and presented in accordance with accounting principles generally accepted in the United States of America ("US GAAP") for rate-regulated entities, and are in Canadian dollars unless otherwise indicated.


 
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FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

These consolidated financial statements include the accounts of the Corporation and its subsidiaries and controlled variable interest entity. They reflect the equity method of accounting for entities in which Fortis has significant influence, but not control, and proportionate consolidation for assets that are jointly owned with non-affiliated entities. Intercompany transactions have been eliminated, except for transactions between non-regulated and regulated entities in accordance with US GAAP for rate-regulated entities.

Cash and Cash Equivalents

Cash and cash equivalents include cash, cash held in margin accounts, and short-term deposits with initial maturities of three months or less from the date of deposit.

Allowance for Doubtful Accounts

Fortis and each subsidiary, other than ITC, maintains an allowance for doubtful accounts that is estimated based on a variety of factors, including receivables aging, historical experience, specific events such as customer bankruptcy and economic conditions. ITC recognizes losses for uncollectible accounts based upon their specific identification. Accounts receivable are written off in the period in which they are deemed uncollectible.

Inventories

Inventories, consisting of materials and supplies, gas, fuel and coal in storage, are measured at the lower of weighted average cost and net realizable value.

Regulatory Assets and Liabilities

Regulatory assets and liabilities arise as a result of the utility rate-setting process and are subject to regulatory approval. Regulatory assets represent future revenues and/or receivables associated with certain costs incurred that will be, or are expected to be, recovered from customers in future periods through the rate-setting process. Regulatory liabilities represent 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.

Certain remaining recovery and settlement periods are those expected by management and the actual periods could differ based on regulatory approval.

Investments

Investments accounted for using the equity method are reviewed annually for potential impairment in value. Impairments are recognized when identified.

Property, Plant and Equipment

Property, plant and equipment ("PPE") are recognized at cost less accumulated depreciation. Contributions in aid of construction by customers and governments are recognized as a reduction in the cost of, and are amortized in a manner consistent with, the related PPE.

Depreciation rates of the Corporation's regulated utilities include a provision for estimated future asset removal costs not identified as a legal obligation. The provision is recognized as a long-term regulatory liability (Note 9) against which actual asset removal costs are netted when incurred.

Most of the Corporation's regulated utilities derecognize PPE on disposal or when no future economic benefits are expected from their use. Upon derecognition, any difference between cost and accumulated depreciation, net of salvage proceeds, is charged to accumulated depreciation. No gain or loss is recognized as it is expected that such amounts will be reflected in future depreciation expense when they are refunded or collected in customer rates.

Through methodologies established by their respective regulators, most of the Corporation's regulated utilities capitalize: (i) overhead costs that are not directly attributable to specific PPE but relate to the overall capital expenditure program; and (ii) an allowance for funds used during construction ("AFUDC").

 
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FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

The debt component of AFUDC totalling $31 million (2017 - $38 million) is reported as a reduction of finance charges and the equity component is reported as other income (Note 23). Both components are charged to earnings through depreciation expense over the estimated service lives of the applicable PPE.

At FortisAlberta the cost of PPE includes required contributions to the Alberta Electric System Operator ("AESO") toward funding the construction of transmission facilities.

Excluding UNS Energy, PPE includes inventory held for the development, construction and betterment of other assets. As required by its regulator, UNS Energy recognizes such items as inventory until used and reclassifies them to PPE once put into service.

Repairs and maintenance costs are charged to earnings in the period incurred. Replacements and betterments that extend the useful lives of PPE are capitalized.

PPE is depreciated using the straight-line method based on the estimated service lives of the assets. Depreciation rates for regulated PPE are approved by the respective regulators. Depreciation rates for 2018 ranged from 0.9% to 34.6% (2017 - 0.9% to 34.6%). The weighted average composite rate of depreciation, before reduction for amortization of contributions in aid of construction, was 2.5% for 2018 (2017 – 2.6%).

The service life ranges and weighted average remaining service life of the Corporation's PPE as at December 31 were as follows.
 
 
2018
2017
(years)
Service Life Ranges
Weighted Average Remaining Service Life
 
Service Life Ranges
Weighted Average Remaining Service Life
Distribution
 
 
 
 
 
 
Electric
5-80
33
 
5-80
33
 
Gas
14-95
35
 
14-95
34
Transmission
 
 
 
 
 
 
Electric
20-90
42
 
20-80
41
 
Gas
5-85
41
 
5-80
34
Generation
1-85
24
 
5-85
28
Other
3-70
15
 
3-70
14
Leases

Leases that transfer to the Corporation substantially all of the risks and benefits incidental to ownership of the leased item are capitalized at the present value of the minimum lease payments. Capital leases are depreciated over the lease term, except where: (i) ownership of the asset is transferred at the end of the lease term, in which case depreciation is over the estimated service life of the underlying asset; and (ii) the regulator has approved a different recovery methodology for rate-setting purposes, in which case the timing of the expense recognition will conform to the regulator's requirements.

Operating lease payments are recognized as an expense on a straight-line basis over the lease term.

Intangible Assets

Intangible assets are recorded at cost less accumulated amortization. Their useful lives are assessed to be either indefinite or finite.

Intangible assets with indefinite useful lives are not amortized and are tested for impairment annually, either individually or, where the particular entity also has goodwill, at the reporting unit level in conjunction with goodwill impairment testing. An annual review is completed to determine whether the indefinite life assessment continues to be supportable. If not, the resultant changes are made prospectively.

 
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FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Intangible assets with finite lives are amortized using the straight-line method based on the estimated service lives of the assets. Amortization rates for regulated intangible assets are approved by the respective regulators and ranged from 1.0% to 50.0% for 2018 (2017 – 1.0% to 50.0%).

The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows.
 
 
2018
 
2017
(years)
Service Life Ranges
Weighted Average Remaining Service Life
 
Service Life Ranges
Weighted Average Remaining Service Life
Computer software
3-10
4
 
3-10
4
Land, transmission and water rights
36-90
57
 
36-80
57
Other
10-100
13
 
10-100
10
Most of the Corporation's regulated utilities derecognize intangible assets on disposal or when no future economic benefits are expected from their use. Upon derecognition any difference between the cost and accumulated amortization of the asset, net of salvage proceeds, is charged to accumulated amortization. No gain or loss is recognized as it is expected that such amounts will be reflected in future amortization costs when they are refunded or collected in customer rates.

Impairment of Long-Lived Assets

The Corporation reviews the valuation of PPE, intangible assets with finite lives, and other long-term assets when events or changes in circumstances indicate that the carrying value may not exceed the total undiscounted cash flows expected to be generated by the asset. If that is determined to be the case, the asset is written down to estimated fair value and an impairment loss is recognized.

Goodwill

Goodwill represents the excess of the purchase price over the fair value of the identifiable net assets related to business acquisitions.

Impairment testing is performed if an event or change in circumstances indicates that the fair value of a reporting unit may be below its carrying value. If that is determined to be the case, goodwill is written down to estimated fair value and an impairment loss is recognized.

Otherwise, Fortis performs an annual assessment for each of the 11 reporting units having goodwill. The primary method for estimating the fair value of 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 underlying estimates and assumptions with varying degrees of uncertainty, including the amount and timing of expected future cash flows, growth rates, and 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, are also performed and compared to the results of the income approach.

Deferred Financing Costs

Issue costs, discounts and premiums are recognized against, and amortized over the life of, the related long-term debt.

Employee Future Benefits

Fortis and its subsidiaries each maintains one or a combination of defined benefit pension plans and defined contribution pension plans, as well as other post-employment benefit ("OPEB") plans, including certain health and dental coverage and life insurance benefits, for qualifying members.

 
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FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

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

For defined benefit pension plans and OPEB plans, the projected or accumulated benefit obligation and net benefit costs are actuarially determined using the projected benefits method prorated on service and management's best estimate of expected plan investment performance, salary escalation, retirement ages of employees and, for OPEB plans, expected health care costs. Discount rates reflect market interest rates on high‑quality bonds with cash flows that match the timing and amount of expected pension or OPEB payments.

Defined benefit pension plan and OPEB plan assets are recognized at fair value. For the purpose of determining defined benefit pension cost, FortisBC Energy and Newfoundland Power use the market-related value whereby investment returns in excess of, or below, expected returns are recognized in the asset value over a period of three years.

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

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

For most of the Corporation's regulated utilities, any difference between defined benefit pension or OPEB plan costs ordinarily recognized under US GAAP and those recovered from customers in current rates is subject to deferral account treatment and is expected to be recovered from, or refunded to, customers in future rates (Note 9).

For most of the Corporation's regulated utilities, any unamortized balances related to net actuarial gains and losses, past service costs and transitional obligations associated with defined benefit pension or OPEB plans, as applicable, which would otherwise be recognized in accumulated other comprehensive income, are subject to deferral account treatment (Note 9).

Stock-Based Compensation

Compensation expense related to stock options is measured at the grant date using the Black-Scholes fair value option-pricing model and each grant is amortized to compensation expense as a single award evenly over the four-year vesting period, with the offsetting entry to additional paid-in capital.

Fortis satisfies stock option exercises by issuing common shares from treasury. Upon exercise, proceeds are credited to capital stock at the option prices and the fair value of the options, as previously recognized, is reclassified from additional paid-in capital to capital stock.

Fortis recognizes liabilities associated with its Directors' Deferred Share Unit ("DSU"), Performance Share Unit ("PSU") and Restricted Share Unit ("RSU") Plans, all representing cash-settled awards, at fair value at each reporting date until settlement. The fair value of these liabilities is based on the five-day volume weighted average price ("VWAP") of the Corporation's common shares at the end of each reporting period. The VWAP as at December 31, 2018 was $45.14 (December 31, 2017 - $46.01). The fair value of the PSU liability is also based on the expected payout probability, based on historical performance in accordance with the defined metrics of each grant and management's best estimate.

Compensation expense is recognized on a straight-line basis over the vesting period, which for the PSU and RSU Plans is over the lesser of three years or the period to retirement eligibility and for the DSU Plan is at the time of grant. Forfeitures are accounted for as they occur.


 
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FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Foreign Currency Translation

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 at the balance sheet date and the resultant unrealized translation gains and losses are recognized in accumulated other comprehensive income. The exchange rate as at December 31, 2018 was US$1.00=CAD$1.36 (December 31, 2017 – US$1.00=CAD$1.25).

Revenue and expenses of the Corporation's foreign operations are translated at the average exchange rate for the reporting period, which was US$1.00=CAD$1.30 for 2018 (2017 - US$1.00=CAD$1.30).

Monetary assets and liabilities denominated in foreign currencies are translated at the exchange rate prevailing at the balance sheet date. Revenue and expenses denominated in foreign currencies are translated at the exchange rate prevailing at the transaction date. Translation gains and losses are recognized in earnings.

Translation gains and losses on foreign currency-denominated debt that is designated as an effective hedge of foreign net investments are recognized in other comprehensive income.

Derivatives and Hedging

Derivatives Not Designated as Hedges
Derivatives not designated as hedges are used by: (i) Fortis, to manage cash flow risk associated with forecast US dollar cash inflows and forecast future cash settlements of DSU and RSU obligations; (ii) UNS Energy, to meet forecast load and reserve requirements; and (iii) Aitken Creek, to manage commodity price risk, capture natural gas price spreads, and manage the financial risk of physical transactions. These derivatives are measured at fair value with changes thereto recognized in earnings.

Derivatives not designated as hedges are also used by UNS Energy, Central Hudson and FortisBC Energy to reduce energy price risk associated with purchased power and gas requirements. The settled amounts of these derivatives are generally included in regulated rates, as permitted by the respective regulators. These derivatives are measured at fair value with changes thereto recognized as regulatory assets or liabilities for recovery from, or refund to, customers in future rates (Note 9).

Derivatives that meet the normal purchase or normal sale scope exception are not measured at fair value and settled amounts are recognized in earnings as energy supply costs.

Derivatives Designated as Hedges
The Corporation, ITC and UNS Energy use cash flow hedges to manage interest rate risk. Unrealized gains and losses are initially recognized in accumulated other comprehensive income and reclassified to earnings when the underlying hedged transaction affects earnings. Any hedge ineffectiveness is immediately recognized in earnings.

The Corporation's earnings from, and net investments in, foreign subsidiaries and equity-accounted investments are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has hedged a portion of this exposure through US dollar-denominated debt at the corporate level. Exchange rate fluctuations associated with the translation of this debt and the foreign net investments are recognized in accumulated other comprehensive income.

Presentation of Derivatives
The fair values of derivatives are recognized as current or long-term assets and liabilities depending on the timing of settlements and resulting cash flows. Derivatives under master netting agreements and collateral positions are presented on a gross basis. Cash flows associated with the settlement of all derivatives are presented in operating activities in the consolidated statements of cash flows.


 
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FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Income Taxes

The Corporation and its taxable subsidiaries follow the asset and liability method of accounting for income taxes. Current income tax expense or recovery is recognized for the estimated income taxes payable or receivable in the current year.

Deferred income tax assets and liabilities are recognized for temporary differences between the tax and accounting basis of assets and liabilities, as well as for the benefit of losses available to be carried forward to future years for tax purposes that are more likely than not to be realized. They are measured using enacted income tax rates and laws in effect when the temporary differences are expected to be recovered or settled. The effect of a change in income tax rates on deferred income tax assets and liabilities is recognized in earnings in the period when the change occurs. Valuation allowances are recognized when it is more likely than not that all, or a portion of, a deferred income tax asset will not be realized.

Customer rates at ITC, UNS Energy, Central Hudson and Maritime Electric reflect current and deferred income tax. Customer rates at FortisAlberta reflect current income tax. Customer rates at FortisBC Energy, FortisBC Electric, Newfoundland Power and FortisOntario reflect current income tax and, for certain regulatory balances, deferred income tax. Caribbean Utilities, FortisTCI and, for the 50-year term of its power purchase agreements, BECOL are not subject to income tax.

Differences between the income tax expense or recovery recognized under US GAAP and that reflected in current customer rates, which is expected to be recovered from, or refunded to, customers in future rates, are recognized as regulatory assets or liabilities (Note 9).

At FortisAlberta the capital cost allowance pool for certain PPE for rate-setting purposes is different from that prescribed for Canadian tax filing purposes. In a future reporting period yet to be determined, the difference may result in reported income tax expense exceeding that reflected in customer rates.

Fortis does not recognize deferred income taxes on temporary differences related to investments in foreign subsidiaries where it intends to indefinitely reinvest earnings. The difference between the carrying values of these foreign investments and their tax bases, resulting from unrepatriated earnings and currency translation adjustments, is approximately $2.3 billion as at December 31, 2018 (December 31, 2017 - $561 million). If such earnings are repatriated, the Corporation may be subject to income taxes and foreign withholding taxes. The determination of the amount of unrecognized deferred income tax liabilities on such amounts is impractical.

Tax benefits associated with actual or expected income tax positions are recognized when the "more likely than not" recognition threshold is met. The tax benefits are measured at the largest amount of benefit that is greater than 50% likely to be realized upon settlement.

Income tax interest and penalties are recognized as income tax expense when incurred.

Asset Retirement Obligations

The Corporation's subsidiaries have asset retirement obligations ("AROs") associated with certain generation, transmission, distribution and interconnection assets, including land and environmental remediation and/or asset removal. These assets and related licences, permits, right-of-ways and agreements are reasonably expected to effectively exist and operate in perpetuity due to their nature. Consequently, where the final date and cost of remediation and/or removal of the noted assets cannot be reasonably determined, AROs have not been recognized.

Otherwise, AROs are recognized at fair value in the period incurred as an increase in PPE and long-term other liabilities (Note 18) if a reasonable estimate of fair value can be determined. Fair value is estimated as the present value of expected future cash outlays, discounted at a credit-adjusted risk-free interest rate. The increase in the liability due to the passage of time is recognized through accretion and the capitalized cost is depreciated over the useful life of the asset. Actual settlement costs are recognized as a reduction in the accrued liability.


 
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FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Contingencies

Fortis and its subsidiaries are involved in certain legal and environmental matters that arise in the normal course of business. Management makes judgments regarding the future outcome of contingent events and recognizes a loss based on its best estimate when it is determined that such loss, or range of loss, is probable and can be reasonably estimated. Legal fees are expensed as incurred. When a loss is recoverable in future rates, a regulatory asset is also recognized.

Management regularly reviews current information to determine whether recognized provisions should be adjusted and new provisions are required. However, estimating probable losses requires considerable judgment about potential actions by third parties and matters are often resolved over long time periods. Actual outcomes may differ materially from the amounts recognized.

New Accounting Policies

Revenue Recognition
Effective January 1, 2018, Fortis adopted Accounting Standards Codification ("ASC") 606, Revenue from Contracts with Customers, which clarifies the principles for recognizing revenue and requires additional disclosures (Note 6). Fortis adopted this standard using the modified retrospective approach, under which comparative periods are not restated and the cumulative impact is recognized at the date of adoption, supplemented by additional disclosures. Upon adoption, there were no adjustments to the opening balance of retained earnings.

Most revenue is derived from energy sales and the provision of transmission services to customers based on regulator-approved tariff rates. Most contracts have a single performance obligation, being the delivery of energy or the provision of transmission services. No component of the transaction price is allocated to unsatisfied performance obligations. Revenue is generally measured in kilowatt hours, gigajoules or transmission load delivered. The billing of energy sales is based on customer meter readings, which occur systematically throughout each month. The billing of transmission services at ITC is based on peak monthly load.

FortisAlberta is a distribution company and is required by its regulator to arrange and pay for transmission services with the AESO. This includes the collection of transmission revenue from its customers, which occurs through the transmission component of its regulator-approved rates. FortisAlberta reports transmission revenue and expenses on a net basis.

Electricity, gas and transmission service revenue includes an estimate for unbilled energy consumed or service provided since the last meter reading that has not been billed at the end of the reporting period. Sales estimates generally reflect an analysis of historical consumption in relation to key inputs, such as current energy prices, population growth, economic activity, weather conditions and system losses. Unbilled revenue accruals are adjusted in the periods actual consumption becomes known.

Generation revenue from non-regulated operations is recognized on delivery at contracted fixed or market rates.

Variable consideration is estimated at the most likely amount and reassessed at each reporting date until the amount is known. Variable consideration, including amounts subject to a future regulatory decision, is recognized as a refund liability until entitlement is certain.

Revenue excludes sales and municipal taxes collected from customers. Prior to the adoption of ASC 606, Central Hudson recognized sales tax and FortisAlberta recognized municipal tax on a gross basis in both revenue and expense. The exclusion of these taxes from revenue resulted in a decrease in revenue of $49 million for 2018 compared to 2017.

The Corporation has elected not to assess or account for any significant financing components associated with revenue billed in accordance with equal payment plans as the period between the transfer of energy to customers and the customers' payment will be less than one year.

Revenue is disaggregated by geography, regulatory status, and substantially autonomous utility operations (Note 5). This represents the level of disaggregation used by the Corporation's President and Chief Executive Officer ("CEO") to allocate resources and evaluate performance.

 
16
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Financial Instruments
Effective January 1, 2018, the Corporation adopted Accounting Standards Update ("ASU") No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities. Principally, it requires: (i) equity investments in unconsolidated entities not accounted for using the equity method to be measured at fair value through earnings; however, entities may 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 liabilities to be presented separately in the financial statement notes, grouped by measurement category and form. Adoption did not impact these consolidated financial statements.

Pension and Post-Retirement Benefit Costs
Effective January 1, 2018, the Corporation adopted ASU No. 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, which requires current service costs to be grouped in the statement of earnings with other employee compensation costs arising from services rendered. The remaining components of net periodic benefit costs must be presented separately and outside of operating income. Additionally, only the service cost component can be capitalized. On adoption, the Corporation applied the presentation guidance retrospectively and the capitalization guidance prospectively. This resulted in a retrospective $11 million reclassification from Operating Expenses to Other Income, Net in the consolidated financial statements.

Use of Accounting Estimates

The preparation of these consolidated financial statements in accordance with US GAAP requires management to make estimates and judgments, including those arising from matters dependent upon the finalization of regulatory proceedings, that affect the reported amounts of assets, liabilities, revenues, expenses, gains and losses. Management evaluates these estimates on an ongoing basis based upon historical experience, current conditions, and assumptions believed to be reasonable at the time they are made, with any adjustments being recognized in the period they become known. Actual results may differ significantly from these estimates.


4. FUTURE ACCOUNTING PRONOUNCEMENTS

Leases

ASU No. 2016-02, Leases ("ASC 842"), issued in February 2016, is effective for Fortis January 1, 2019 and is to be applied using a modified retrospective approach or an optional transition method with implementation options, referred to as practical expedients. Principally, it requires balance sheet recognition of a right-of-use asset and a lease liability by lessees for those leases that are classified as operating leases, along with additional disclosures.

Fortis has selected the optional transition method, which allows entities to continue to apply the current lease guidance in the comparative periods presented in the year of adoption and apply the transition provisions of the new guidance on the effective date of the new guidance. Fortis elected a package of practical expedients that allowed it to not reassess the lease classification of existing leases or whether existing contracts, including land easements, are or contain a lease. Finally, Fortis utilized the hindsight practical expedient to determine the lease term.

Upon adoption, Fortis will recognize right-of-use assets and corresponding lease liabilities of approximately $50 million for operating leases primarily related to office facilities and utility property. Operating leases related to vehicles and office equipment were identified and quantified as immaterial. Fortis has not identified an adjustment to opening retained earnings, and there will be no impact on earnings or cash flows.

Fortis implemented changes to processes and control activities related to monitoring the adoption of ASC 842 and made changes to accounting policies associated with accounting for lease assets and liabilities, and related income and expense, as of January 1, 2019.


 
17
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Financial Instruments

ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments, issued in June 2016, is effective for Fortis January 1, 2020 and is to be applied on a modified retrospective basis. Principally, it requires entities to use an expected credit loss methodology and to consider a broader range of reasonable and supportable information to estimate credit losses. The adoption of this ASU will not have a material impact on the consolidated financial statements and related disclosures.

Hedging

ASU No. 2017-12, Targeted Improvements to Accounting for Hedging Activities, issued in August 2017, is effective for Fortis January 1, 2019. Principally, it better aligns risk management activities and financial reporting for hedging relationships through changes to designation, measurement, presentation and disclosure guidance. For cash flow and net investment hedges that existed at the date of adoption, the amendments were applied as a cumulative-effect adjustment related to eliminating the separate measurement of ineffectiveness to accumulated other comprehensive income with a corresponding adjustment to opening retained earnings. Amended presentation and disclosure guidance was applied prospectively. The adoption of this ASU will not have a material impact on the consolidated financial statements and related disclosures.

Fair Value Measurement Disclosures

ASU No. 2018-13, Changes to the Disclosure Requirements for Fair Value Measurement, issued in August 2018, is effective for Fortis January 1, 2020 and is to be primarily applied on a retrospective basis, with certain disclosures requiring prospective application. Principally, it improves the effectiveness of financial statement note disclosures by clarifying what is required and important to users of the financial statements. In addition, the amendment removes (a) the amount of, and reasons for, transfers between level 2 and level 3 of the fair value hierarchy, (b) the policy for timing of transfers between levels, and (c) the valuation processes for level 3 fair value measurements. Fortis does not expect the adoption of this ASU to have a material impact on the related disclosures.

Pensions and Other Post-Retirement Plan Disclosures

ASU No. 2018-14, Changes to the Disclosure Requirements for Defined Benefit Plans, issued in August 2018, is effective for Fortis January 1, 2021 and is to be applied on a retrospective basis for all periods presented. Principally, it modifies the disclosure requirements for employers with defined pension or other post-retirement plans and clarifies disclosure requirements. In addition, the amendments remove (a) the amounts in accumulated other comprehensive income expected to be recognized as components of net period benefit costs over the next fiscal period, (b) the amount and timing of plan assets expected to be returned to the employer, and (c) the effects of a one-percentage-point change on the assumed health care costs and the change in rates on service cost, interest cost and the benefit obligation for post-retirement health care benefits. Fortis does not expect the adoption of this ASU to have a material impact on the related disclosure.



 
18
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

5.    SEGMENTED INFORMATION

General

Fortis segments its business based on regulatory status and service territory, as well as the information used by its President and CEO in deciding how to allocate resources. The performance of each segment is primarily based on net earnings attributable to common equity shareholders.

Effective January 1, 2018, the former Eastern Canadian and Caribbean segments were aggregated as Other Electric as they individually do not meet the quantitative threshold for separate reporting.

Related-party and inter-company transactions

Related-party transactions are in the normal course of operations and are measured at the amount of consideration agreed to by the related parties. There were no material related-party transactions in 2018 or 2017.

Inter-company balances, transactions and 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. Inter-company transactions are summarized below.
(in millions)
2018

2017

Sale of capacity from Waneta Expansion to FortisBC Electric
$
47

$
46

Lease of gas storage capacity and gas sales from Aitken Creek to
FortisBC Energy
25

24


As at December 31, 2018, accounts receivable included approximately $16 million due from BEL (December 31, 2017 - $20 million).

The Corporation periodically provides short-term financing to subsidiaries to support capital expenditure programs, acquisitions and seasonal working capital requirements. There were no material inter-segment loans outstanding as at December 31, 2018 and 2017.



 
19
 

FORTIS INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2018 and 2017


 
REGULATED
 
NON-REGULATED
 
 
Year Ended
 
 
Energy
 
Inter-
 
December 31, 2018
 
UNS

Central

 
FortisBC

Fortis

FortisBC

Other

Sub

 
Infra-
Corporate

segment
 
(in millions)
ITC

Energy

Hudson

 
Energy

Alberta

Electric

Electric

total

 
structure

and Other

eliminations
Total

Revenue
$
1,504

$
2,202

$
924

 
$
1,187

$
579

$
408

$
1,412

$
8,216

 
$
184

$
—

$
(10
)
$
8,390

Energy supply costs
—

868

315

 
322

—

135

853

2,493

 
2

—

—

2,495

Operating expenses
448

609

410

 
308

167

105

182

2,229

 
40

28

(10
)
2,287

Depreciation and amortization
234

272

71

 
219

192

61

160

1,209

 
32

2

—

1,243

Operating income
822

453

128

 
338

220

107

217

2,285

 
110

(30
)
—

2,365

Other income, net
40

10

7

 
7

1

3

1

69

 
1

(10
)
—

60

Finance charges
285

104

41

 
134

100

40

76

780

 
6

188

—

974

Income tax expense
139

66

20

 
55

1

14

22

317

 
6

(158
)
—

165

Net earnings
438

293

74

 
156

120

56

120

1,257

 
99

(70
)
—

1,286

Non-controlling interests
77

—

—

 
1

—

—

15

93

 
27

—

—

120

Preference share dividends
—

—

—

 
—

—

—

—

—

 
—

66

—

66

Net earnings attributable
to common equity shareholders
$
361

$
293

$
74

 
$
155

$
120

$
56

$
105

$
1,164

 
$
72

$
(136
)
$
—

$
1,100

Goodwill
$
8,369

$
1,884

$
615

 
$
913

$
227

$
235

$
260

$
12,503

 
$
27

$
—

$
—

$
12,530

Total assets
19,798

10,182

3,670

 
6,815

4,691

2,244

4,119

51,519

 
1,478

127

(73
)
53,051

Capital expenditures 
998

599

245

 
486

433

106

300

3,167

 
44

7

—

3,218

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended
 
 
 
 
 
 
 
 
 
 
 
 
 


December 31, 2017
 
 
 
 
 
 
 
 
 
 
 
 
 


(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 


Revenue
$
1,575

$
2,080

$
872

 
$
1,198

$
600

$
398

$
1,363

$
8,086

 
$
226

$
1

$
(12
)
$
8,301

Energy supply costs
—

711

260

 
411

—

142

836

2,360

 
2

—

(1
)
2,361

Operating expenses
433

609

399

 
300

198

90

171

2,200

 
49

12

(11
)
2,250

Depreciation and amortization
220

260

65

 
198

190

62

150

1,145

 
32

2

—

1,179

Operating income
922

500

148

 
289

212

104

206

2,381

 
143

(13
)
—

2,511

Other income, net
37

19

5

 
22

2

2

1

88

 
1

28

(1
)
116

Finance charges
259

101

41

 
116

93

37

74

721

 
5

189

(1
)
914

Income tax expense
371

148

42

 
40

1

14

22

638

 
19

(69
)
—

588

Net earnings
329

270

70

 
155

120

55

111

1,110

 
120

(105
)
—

1,125

Non-controlling interests
57

—

—

 
1

—

—

13

71

 
26

—

—

97

Preference share dividends
—

—

—

 
—

—

—

—

—

 
—

65

—

65

Net earnings attributable
to common equity shareholders
$
272

$
270

$
70

 
$
154

$
120

$
55

$
98

$
1,039

 
$
94

$
(170
)
$
—

$
963

Goodwill
$
7,698

$
1,733

$
566

 
$
913

$
227

$
235

$
245

$
11,617

 
$
27

$
—

$
—

$
11,644

Total assets
17,581

8,596

3,188

 
6,418

4,454

2,197

3,814

46,248

 
1,605

76

(107
)
47,822

Capital expenditures
982

534

220

 
446

414

105

302

3,003

 
21

—

—

3,024


 
20
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

6. REVENUE
(in millions)
2018

2017

Electric and gas revenue
 
 
United States
 
 
ITC
$
1,539

$
1,583

UNS Energy
1,993

1,875

Central Hudson
963

814

Canada
 
 
FortisBC Energy
1,136

1,244

FortisAlberta
554

593

FortisBC Electric
354

347

Newfoundland Power
651

666

Maritime Electric
200

191

FortisOntario
197

197

Caribbean
 
 
Caribbean Utilities
253

222

FortisTCI
78

71

Total electric and gas revenue
7,918

7,803

Other services revenue (1)
408

395

Revenue from contracts with customers
8,326

8,198

Alternative revenue
16

(46
)
Other revenue
48

149

Total revenue
$
8,390

$
8,301

(1) 
Includes $234 million and $217 million from regulated operations for 2018 and 2017, respectively

Revenue from Contracts with Customers
Electric and gas revenue includes revenue from the sale and/or delivery of electricity and gas, transmission revenue, and wholesale electric revenue, all based on regulator-approved tariff rates.

Other services revenue includes: (i) the sale of energy from non-regulated generation operations; (ii) management fee revenue at UNS Energy for the operation of Springerville Units 3 and 4; (iii) revenue from storage optimization activities at Aitken Creek; and (iv) revenue from other services that reflect the ordinary business activities of Fortis' utilities.

Alternative Revenue
Alternative revenue programs allow utilities to adjust future rates in response to past activities or completed events if certain criteria are met. Alternative revenue is recognized on an accrual basis with a corresponding regulatory asset or liability until the revenue is settled. Upon settlement, revenue is not recognized as revenue from contracts with customers but rather as settlement of the regulatory asset or liability on the balance sheet. The Corporation's significant alternative revenue programs are summarized as follows.

ITC's formula rates include an annual true-up mechanism that compares actual revenue requirements to billed revenue, and any under- or over-collections are accrued as a regulatory asset or liability and reflected in future rates within a two-year period (Note 9). The formula rates do not require annual regulatory approvals, although inputs remain subject to legal challenge.


 
21
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

UNS Energy's lost fixed-cost recovery mechanism ("LFCR") surcharge recovers lost fixed costs, as measured by a reduction in non-fuel revenue, associated with energy efficiency savings and distributed generation. To recover the LFCR regulatory asset, UNS Energy is required to file an annual LFCR adjustment request with the ACC for the LFCR revenue recognized in the prior year. The recovery is subject to a year-over-year cap of 1% of total retail revenue. UNS Energy's demand side management surcharge, which is approved by the ACC annually, compensates for the costs to design and implement cost-effective energy efficiency and demand response programs until such costs, along with a performance incentive, are reflected in non-fuel base rates.

At FortisBC Energy and FortisBC Electric, the earnings sharing mechanism allows for a 50/50 sharing of variances from operating and maintenance expenses and capital expenditures approved as part of the annual revenue requirements. This mechanism is in place until the expiry of the current PBR plan in 2019. Additionally, variances in the forecast versus actual customer-use rate are captured throughout the year in a revenue stabilization adjustment mechanism and a flow-through deferral account, both of which are either refunded to, or recovered from, customers in rates within two years.

Other Revenue
Other revenue primarily includes gains or losses on energy contract derivatives and lease revenue.


7. ACCOUNTS RECEIVABLE AND OTHER CURRENT ASSETS
(in millions)
2018

2017

Trade accounts receivable
$
538

$
460

Unbilled accounts receivable
575

562

Allowance for doubtful accounts
(33
)
(31
)
Total accounts receivable
1,080

991

Income tax receivable
91

8

Other (1)
186

132

 
$
1,357

$
1,131

(1) 
Consists of customer billings for non-core services, gas mitigation costs and collateral deposits for gas purchases at FortisBC Energy, and the fair value of derivative instruments (Note 28)


8. INVENTORIES
(in millions)
2018

2017

Materials and supplies
$
280

$
238

Gas and fuel in storage
87

97

Coal inventory
31

32

 
$
398

$
367




 
22
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

9. REGULATORY ASSETS AND LIABILITIES
(in millions)
2018

2017

Regulatory assets
 
 
Deferred income taxes (Notes 3 and 24)
$
1,532

$
1,403

Employee future benefits (Notes 3 and 25)
485

510

Deferred energy management costs (i)
230

200

Deferred lease costs (ii)
110

104

Deferred operating overhead costs (iii)
103

91

Generation early retirement costs (iv)
98

105

Rate stabilization and related accounts (v)
90

95

Manufactured gas plant site remediation deferral (Note 18)
73

75

Derivatives (Notes 3 and 28)
57

87

Other regulatory assets (vi)
400

375

Total regulatory assets
3,178

3,045

Less: Current portion
(324
)
(303
)
Long-term regulatory assets
$
2,854

$
2,742

 
 
 
Regulatory liabilities
 
 
Deferred income taxes (Notes 3 and 24)
$
1,574

$
1,484

Asset removal cost provision (Note 3)
1,169

1,095

Rate stabilization and related accounts (v)
220

254

ROE complaints liability (Note 2)
206

182

Energy efficiency liability (vii)
106

82

Renewable energy surcharge (viii)
85

66

Electric and gas moderator account (ix)
60

58

Employee future benefits (Notes 3 and 25)
37

47

Other regulatory liabilities (vi)
169

178

Total regulatory liabilities
3,626

3,446

Less: Current portion
(656
)
(490
)
Long-term regulatory liabilities
$
2,970

$
2,956

(i)    Deferred Energy Management Costs
Certain regulated subsidiaries provide energy management services to facilitate customer energy efficiency programs where the related expenditures have been deferred as a regulatory asset and are being amortized, and recovered from customers through rates, on a straight-line basis over periods ranging from 1 to 10 years.

(ii)
Deferred Lease Costs
Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement ("BPPA") (Note 17). The depreciation of the asset under capital lease and interest expense on the capital lease obligation are not being fully recovered in current customer rates since these rates only reflect the cash payments required under BPPA. The annual differences are being deferred as a regulatory asset, which is expected to be recovered from customers in future rates over the term of the lease, which expires in 2056.

(iii)
Deferred Operating Overhead Costs
FortisAlberta has deferred certain operating overhead costs for collection in future customer rates over the lives of the related PPE and intangible assets.


 
23
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

(iv)
Generation Early Retirement Costs
UNS Energy holds an undivided interest in the jointly-owned Navajo Generating Station ("Navajo"), located on a site leased from the Navajo Nation with an initial lease term through December 2019. In June 2017 the Navajo Nation approved a land-lease extension that allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. Related retirement costs are being recovered through 2030.

UNS Energy owns the Sundt Generating Facility ("Sundt") and plans to early retire Sundt Units 1 and 2 by the end of 2020 as a result of the approved addition of gas-fired generation capacity at Sundt. Capital and operating costs related to Sundt Units 1 and 2 are being recovered through 2028 and 2030, respectively.

As a result of these planned early retirements, the associated assets and other related retirement costs were reclassified from PPE to regulatory assets.

(v)
Rate Stabilization and Related Accounts
Rate stabilization accounts mitigate the earnings volatility otherwise caused by variability in the cost of fuel, purchased power and natural gas above or below a forecast or predetermined level, and by weather-driven volume variability. At certain utilities, revenue decoupling mechanisms minimize the earnings impact resulting from reduced energy consumption as energy efficiency programs are implemented. Resultant deferrals are recovered from, or refunded to, customers in future rates as approved by the respective regulators.

Related accounts include the annual true-up mechanism at ITC (Note 6).

(vi)
Other Regulatory Assets and Liabilities
This balance is comprised of regulatory assets and liabilities individually less than $40 million.

(vii)
Energy Efficiency Liability
The energy efficiency liability primarily relates to Central Hudson's Energy Efficiency Program, established to fund environmental policies associated with energy conservation programs as approved by its regulator.

(viii)
Renewable Energy Surcharge
Under the ACC's Renewable Energy Standard ("RES"), UNS Energy is required to increase its use of renewable energy each year until it represents at least 15% of its total annual retail energy requirements by 2025. The cost of carrying out the plan is recovered from retail customers through an RES surcharge. Any RES surcharge collections above or below the costs incurred to implement the plans are deferred as a regulatory liability or asset.

The ACC measures RES compliance through Renewable Energy Credits ("REC"). Each REC represents one kilowatt hour generated from renewable resources. When UNS Energy purchases renewable energy, the premium paid above the market cost of conventional power equals the REC recoverable through the RES surcharge. When RECs are purchased, UNS Energy records their cost as long-term other assets (Note 11) with a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, energy supply costs and revenue are recognized in an equal amount.

(ix)
Electric and Gas Moderator Account
Under Central Hudson's 2018 three-year Rate Order certain regulatory assets and liabilities were approved by the PSC for offset and an electric and gas moderator account was established, which will be used for future customer rate moderation.

Regulatory assets not earning a return: (i) totalled $1,490 million and $1,464 million as at December 31, 2018 and 2017, respectively; (ii) are primarily related to deferred income taxes and employee future benefits; and (iii) generally do not represent a past cash outlay as they are offset by related liabilities that, likewise, do not incur a carrying cost for rate-making purposes. Recovery periods vary or are yet to be determined by the respective regulators.



 
24
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

10. ASSETS HELD FOR SALE

In 2018 Fortis solicited offers to sell its 51% ownership interest in the Waneta Expansion. In January 2019 the Corporation entered into a definitive agreement with Columbia Power Corporation ("CPC") and Columbia Basin Trust ("CBT") to sell its interest for approximately $1 billion. CPC and CBT, both 100% owned by the Government of British Columbia, are the Corporation's partners and together currently own 49% of the Waneta Expansion. Fortis expects the transaction to close in the second quarter of 2019 following the satisfaction of customary closing conditions. FortisBC Electric will continue to operate the Waneta Expansion facility and purchase its surplus capacity. The related assets and liabilities have been classified as held for sale and are detailed below.
(in millions)
2018

Cash
$
15

Accounts receivable and other current assets
3

PPE
718

Intangible assets
30

Total assets held for sale
$
766

 
 
Accounts payable and other current liabilities
$
2

Other liabilities
67

Total liabilities associated with assets held for sale
$
69


The non-controlling interest of $324 million remained classified in equity.

For both 2018 and 2017, the Waneta Expansion contributed $54 million to earnings before income tax expense, of which 51% is attributable to common equity shareholders.


11. OTHER ASSETS
(in millions)
2018

2017

Supplemental Executive Retirement Plan
$
143

$
130

Renewable Energy Credits (Note 9 (viii))
88

62

Equity investment - BEL
76

73

Equity investment - Wataynikaneyap Partnership
43

22

Other investments
34

29

Defined benefit pension plan (Note 25)
26

31

Deferred compensation plan
26

24

Other (1)
116

109

 
$
552

$
480

(1) 
Other assets are generally recorded at cost and recovered or amortized over the estimated period of future benefit, where applicable. Other assets also include the fair value of derivatives (Note 28).

ITC, UNS Energy and Central Hudson provide additional post-employment benefits through Supplemental Executive Retirement Plans ("SERPs") and deferred compensation plans for Directors and Officers. The assets held to support these plans are reported separately from the related liabilities (Note 18). Most plan assets are held in trust and funded mainly through trust-owned life insurance policies and mutual funds. Assets in mutual and money market funds are recorded at fair value on a recurring basis (Note 28). Included in SERP assets are available-for-sale securities at ITC of $72 million (2017 - $66 million), for which gains and losses are recognized in earnings.



 
25
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

12. PROPERTY, PLANT AND EQUIPMENT
(in millions)
Cost
 
Accumulated Depreciation
 
Net Book Value

2018
 
 
 
 
 
Distribution
 
 
 
 
 
 
Electric
$
10,880

 
$
(3,076
)
 
$
7,804

 
Gas
4,767

 
(1,244
)
 
3,523

Transmission


 


 


 
Electric
14,665

 
(3,212
)
 
11,453

 
Gas
2,214

 
(639
)
 
1,575

Generation
6,164

 
(2,279
)
 
3,885

Other
3,877

 
(1,251
)
 
2,626

Assets under construction
1,478

 
—

 
1,478

Land
310

 
—

 
310

 
 
$
44,355

 
$
(11,701
)
 
$
32,654

2017
 
Distribution
 
 
 
 
 
 
Electric
$
9,963

 
$
(2,864
)
 
$
7,099

 
Gas
4,093

 
(1,157
)
 
2,936

Transmission


 


 


 
Electric
12,571

 
(2,838
)
 
9,733

 
Gas
1,954

 
(596
)
 
1,358

Generation
6,079

 
(1,996
)
 
4,083

Other
3,608

 
(1,130
)
 
2,478

Assets under construction
1,717

 
—

 
1,717

Land
264

 
—

 
264

 
 
$
40,249

 
$
(10,581
)
 
$
29,668


Electric distribution assets are those used to distribute electricity at lower voltages (generally below 69 kilovolts ("kV")). These assets include poles, towers and fixtures, low-voltage wires, transformers, overhead and underground conductors, street lighting, meters, metering equipment and other related equipment. Gas distribution assets are those used to transport natural gas at low pressures (generally below 2,070 kilopascals ("kPa")) or a hoop stress of less than 20% of standard minimum yield strength. These assets include distribution stations, telemetry, distribution pipe for mains and services, meter sets and other related equipment.

Electric transmission assets are those used to transmit electricity at higher voltages (generally at 69 kV and higher). These assets include poles, wires, switching equipment, transformers, support structures and other related equipment. Gas transmission assets are those used to transport natural gas at higher pressures (generally at 2,070 kPa and higher) or a hoop stress of 20% or more of standard minimum yield strength. These assets include transmission stations, telemetry, transmission pipe and other related equipment.

Generation assets are those used to generate electricity. These assets include hydroelectric and thermal generation stations, gas and combustion turbines, coal-fired generating stations, dams, reservoirs, photovoltaic systems and other related equipment.

Other assets include buildings, equipment, vehicles, inventory, information technology assets and the Aitken Creek natural gas storage facility.


 
26
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

As at December 31, 2018, assets under construction were primarily associated with ongoing transmission projects at ITC and the addition of gas-fired generation capacity at UNS Energy.

The cost of PPE under capital lease as at December 31, 2018 was $656 million (December 31, 2017 -$423 million) and related accumulated depreciation was $203 million (December 31, 2017 - $176 million).

Jointly-Owned Facilities

UNS Energy and ITC hold undivided interests in jointly-owned generating facilities and transmission systems, are entitled to their pro rata share of the PPE, and are proportionately liable for the associated operating costs and liabilities. As at December 31, 2018, interests in jointly-owned facilities consisted of the following.
 
Ownership
 
Accumulated

Net Book

(in millions, except as noted)
%
Cost
Depreciation

Value

San Juan Unit 1
50.0
$
397

$
(183
)
$
214

Four Corners Units 4 and 5
7.0
239

(104
)
135

Luna Energy Facility
33.3
79

(5
)
74

Gila River Common Facilities
25.0
45

(16
)
29

Springerville Coal Handling Facilities
83.0
284

(117
)
167

Transmission Facilities
1.0-80.0
1,018

(397
)
621

 
 
$
2,062

$
(822
)
$
1,240



13. INTANGIBLE ASSETS
 
 
Accumulated

Net Book

(in millions)
Cost

Amortization

Value

2018
 
 
 
Computer software
$
860

$
(533
)
$
327

Land, transmission and water rights
855

(125
)
730

Other
120

(58
)
62

Assets under construction
81

—

81

 
$
1,916

$
(716
)
$
1,200

 
 
 
 
2017
 
 
 
Computer software
$
784

$
(474
)
$
310

Land, transmission and water rights
743

(103
)
640

Other
117

(49
)
68

Assets under construction
63

—

63

 
$
1,707

$
(626
)
$
1,081


Included in the cost of land, transmission and water rights as at December 31, 2018 was $131 million (December 31, 2017 - $150 million) not subject to amortization. Amortization expense was $106 million for 2018 (2017 - $97 million). Amortization is estimated to average approximately $81 million for each of the next five years.



 
27
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

14. GOODWILL
(in millions)
2018

2017

Balance, beginning of year
$
11,644

$
12,364

Acquisition of ITC
—

(6
)
Foreign currency translation impacts (1)
886

(714
)
Balance, end of year
$
12,530

$
11,644

(1) 
Relates to the translation of goodwill associated with the acquisitions of ITC, UNS Energy, Central Hudson, Caribbean Utilities and FortisTCI, whose functional currency is the US dollar

No goodwill impairment was recognized by the Corporation in 2018 or 2017.


15. ACCOUNTS PAYABLE AND OTHER CURRENT LIABILITIES
(in millions)
2018

2017

Trade accounts payable
$
679

$
696

Gas and fuel cost payable
281

146

Customer and other deposits
267

204

Interest payable
230

223

Accrued taxes other than income taxes
206

178

Dividends payable
199

185

Employee compensation and benefits payable
193

184

Fair value of derivatives (Note 28)
69

71

Manufactured gas plant site remediation (Note 18)
32

35

Defined benefit pension and OPEB liabilities (Note 25)
25

22

Other
108

109


$
2,289

$
2,053




 
28
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

16. LONG-TERM DEBT
(in millions)
Maturity Date
2018

2017

ITC
 
 
 
Secured US First Mortgage Bonds -
 
 
 
 
4.51% weighted average fixed rate (2017 - 4.67%)
2020-2055
$
2,652

$
2,063

Secured US Senior Notes -
 
 
 
 
4.19% weighted average fixed rate (2017 - 4.19%)
2040-2046
648

596

Unsecured US Senior Notes -
 
 
 
 
3.91% weighted average fixed rate (2017 - 3.91%)
2020-2043
3,751

3,451

Unsecured US Shareholder Note -
 
 
 
 
6.00% fixed rate (2017 - 6.00%)
2028
271

250

Unsecured US Term Loan Credit Agreement -
 
 
 
 
2.03% weighted average variable rate
n/a
—

63

UNS Energy
 
 
 
Unsecured US Tax-Exempt Bonds - 4.66% weighted
 
 
 
 
average fixed and variable rate (2017 - 4.04%)
2020-2040
654

773

Unsecured US Fixed Rate Notes -
 
 
 
 
4.38% weighted average fixed rate (2017 - 4.26%)
2021-2048
1,943

1,411

Central Hudson
 
 
 
Unsecured US Promissory Notes - 4.43% weighted
 
 
 
 
average fixed and variable rate (2017 - 4.28%)
2019-2057
938

770

FortisBC Energy
 
 
 
Unsecured Debentures -
 
 
 
 
5.03% weighted average fixed rate (2017 - 5.13%)
2026-2048
2,595

2,395

FortisAlberta
 
 
 
Unsecured Debentures -
 
 
 
 
4.64% weighted average fixed rate (2017 - 4.70%)
2024-2052
2,185

2,035

FortisBC Electric
 
 
 
Secured Debentures -
 
 
 
 
8.80% fixed rate (2017 - 8.80%)
2023
25

25

Unsecured Debentures -
 
 
 
 
5.05% weighted average fixed rate (2017 - 5.05%)
2021-2050
710

710

Other Electric
 
 
 
Secured First Mortgage Sinking Fund Bonds -
 
 
 
 
6.14% weighted average fixed rate (2017 - 6.14%)
2020-2057
578

585

Secured First Mortgage Bonds -
 
 
 
 
5.66% weighted average fixed rate (2017 - 6.19%)
2025-2061
220

195

Unsecured Senior Notes -
 
 
 
 
4.45% weighted average fixed rate (2017 - 6.11%)
2041-2048
152

104

Unsecured US Senior Loan Notes and Bonds - 4.76% weighted
 
 
 
 
average fixed and variable rate (2017 - 4.80%)
2020-2048
584

525

Corporate
 
 
 
Unsecured US Senior Notes and Promissory Notes -
 
 
 
 
3.41% weighted average fixed rate (2017 - 3.41%)
2019-2044
4,398

4,046

Unsecured Debentures -
 
 
 
 
6.50% weighted average fixed rate (2017 - 6.50%)
2039
200

200

Unsecured Senior Notes - 2.85% fixed rate (2017 - 2.85%)
2023
500

500

Long-term classification of credit facility borrowings
1,066

671

Fair value adjustment - ITC acquisition
 
161

167

Total long-term debt (Note 28)
 
24,231

21,535

Less: Deferred financing costs and debt discounts
 
(146
)
(139
)
Less: Current installments of long-term debt
 
(926
)
(705
)
 
 
 
$
23,159

$
20,691



 
29
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Most long-term debt at the Corporation's regulated utilities is redeemable at the option of the respective utility at the greater of par or a specified price, together with accrued and unpaid interest. Security, if provided, is typically through a fixed or floating first charge on specific assets of the utility.

The Corporation's unsecured debentures and senior notes are redeemable at the option of Fortis at the greater of par or a specified price together with accrued and unpaid interest.

Certain long-term debt at the Corporation has covenants restricting the issuance of additional debt such that consolidated debt cannot exceed 70% of the Corporation's consolidated capital structure.

One long-term debt obligation at the Corporation has a covenant which provides that Fortis shall not declare or pay any dividends, other than stock dividends or cumulative preferred dividends on preference shares not issued as stock dividends, make any other distribution on its shares, redeem any of its shares or prepay subordinated debt if, immediately thereafter, its consolidated funded obligations would exceed 75% of its total consolidated capitalization.

Long-Term Debt Issuances

(in millions, except %)
Month Issued
Interest Rate
(%)

Maturity
 
Amount

Use of Proceeds

ITC
 
 
 
 
 
 
First mortgage bonds
March
4.00

2053
 
US
225

(1) (2) (3) (4) 

First mortgage bonds
November
4.32

2051
 
US
175

(2) (3) (4) 

UNS Energy
 
 
 
 
 
 
Unsecured notes
November
4.85

2048
 
US
300

(1) (4) 

Central Hudson
 
 
 
 
 
 
Unsecured notes
June
4.27

2048
 
US
25

(3) (4) 

Unsecured notes
October
3.99

2026
 
US
40

(1) (3) (4) 

Unsecured notes
October
4.21

2033
 
US
40

(1) (3) (4) 

FortisBC Energy
 
 
 
 
 
 
Unsecured debentures
December
3.85

2048
 
200

(2) (4) 

FortisAlberta
 
 
 
 
 
 
Unsecured debentures
September
3.73

2048
 
150

(2) (4) 

FortisOntario
 
 
 
 
 
 
Unsecured notes
August
4.10

2048
 
100

(1) (4) 

Maritime Electric
 
 
 
 
 
 
First mortgage bonds
December
4.15

2058
 
40

(2) (4) 

FortisTCI
 
 
 
 
 
 
Unsecured notes
February
(5 
) 
2023
 
US
25

(6 
) 
Unsecured non-revolving term loan (7)
September
(5 
) 
2025
 
US
5

(4 
) 
(1) 
Repay maturing long-term debt
(2) 
Repay credit facility borrowings
(3) 
Finance capital expenditures
(4) 
General corporate purposes
(5) 
Floating rate of a one-month LIBOR plus a spread of 1.75%
(6) 
Repay a hurricane-related emergency standby loan
(7) 
Maximum amount of borrowings under this agreement is US$10 million.


 
30
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Long-Term Debt Repayments

The consolidated requirements to meet principal repayments and maturities in each of the next five years and thereafter are as follows.
 
Total

(year)
(in millions)

2019
$
926

2020
731

2021
1,324

2022
1,125

2023
1,605

Thereafter
18,520

 
$
24,231


Credit Facilities

As at December 31, 2018, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.2 billion, of which approximately $3.9 billion was unused, including $1.0 billion unused under the Corporation's committed revolving corporate credit facility.

The following summarizes the credit facilities of the Corporation and its subsidiaries.
(in millions)
Regulated
Utilities

Corporate
and Other

2018

2017

Total credit facilities
$
3,780

$
1,385

$
5,165

$
4,952

Credit facilities utilized:








Short-term borrowings (1)
(60
)
—

(60
)
(209
)
Long-term debt (including current portion) (2)
(731
)
(335
)
(1,066
)
(671
)
Letters of credit outstanding
(65
)
(54
)
(119
)
(129
)
Credit facilities unutilized
$
2,924

$
996

$
3,920

$
3,943

(1)    The weighted average interest rate was approximately 4.2% (December 31, 2017 - 1.8%).
(2) 
The weighted average interest rate was approximately 3.3% (December 31, 2017 - 2.5%). The current portion was $735 million (December 31, 2017 - $312 million).

Credit facilities are syndicated primarily with large banks in Canada and the United States, with no one bank holding more than 20% of the total facilities. Approximately $5.0 billion of the total credit facilities are committed facilities with maturities ranging from 2019 through 2023.


 
31
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Consolidated credit facilities of approximately $5.2 billion as at December 31, 2018 are itemized below.
(in millions)
Amount

Maturity
Unsecured committed revolving credit facilities
 
 
Regulated utilities
 
 
ITC (1)
US
900

October 2022
UNS Energy
US
500

October 2022
Central Hudson
US
250

(2) 
FortisBC Energy
700

August 2023
FortisAlberta
250

August 2023
FortisBC Electric
150

April 2023
Other Electric
190

(3) 
Other Electric
US
50

January 2020
Corporate and Other
1,350

(4) 
Other facilities
 
 
Central Hudson - uncommitted credit facility
US
40

n/a
FortisBC Electric - unsecured demand overdraft facility
10

n/a
Other Electric - unsecured demand facilities
25

n/a
Other Electric - unsecured demand facility and emergency
standby loan
US
60

April 2019
Corporate and Other - unsecured non-revolving facility
35

n/a
(1) 
ITC also has a US$400 million commercial paper program, under which no amounts were outstanding as at December 31, 2018.
(2) 
US$50 million in July 2020 and US$200 million in October 2020
(3) 
$50 million in February 2019, $40 million in June 2021, and $100 million in August 2023
(4) 
$1.3 billion in July 2023, with the option to increase by an amount up to $500 million, and $50 million in April 2021


17. CAPITAL LEASE AND FINANCE OBLIGATIONS

Capital Lease Obligations

UNS Energy
Following the acquisition of Gila River generating station Units 1 and 2 by a third party with whom TEP has a power purchase agreement, TEP anticipates exercising its option to purchase Gila River Unit 2 in December 2019 for approximately $224 million (US$164 million). Over the 20-month lease term, TEP will pay a monthly demand charge consisting of a capacity charge and an operating fee.

For 2018 $10 million (2017 - nil) of demand charges were recognized related to the Gila River Unit 2 capital lease obligation.

TEP is party to two Springerville Common Facilities leases with fixed purchase options totalling US$68 million and initial terms to January 2021. TEP has the option to renew the leases for periods of two or more years or exercise the purchase options. Additionally, TEP has entered into agreements with third parties that if the Springerville Common Facilities leases are not renewed, TEP will exercise the purchase options thereunder and the third parties would be obligated to buy a portion of these facilities or continue to make payments to TEP for their use.

The Springerville Common Facilities lease obligations bear interest at a six-month LIBOR plus a spread of 2.00%. TEP holds an interest rate swap that effectively fixes the LIBOR rate at 5.77% on $16 million (December 31, 2017 - $23 million) of the total lease obligation of $19 million (December 31, 2017 - $26 million). The swap is recognized as a cash flow hedge (Note 28).

For 2018 $3 million (2017 - $4 million) of interest expense and $8 million (2017 - $8 million) of depreciation expense was recognized related to the Springerville capital lease obligation.

 
32
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

FortisBC Electric
FortisBC Electric has a capital lease obligation with respect to the operation of the Brilliant hydroelectric plant ("Brilliant Plant") in British Columbia. FortisBC Electric operates and maintains the Brilliant Plant under the BPPA, which expires in 2056, in return for a management fee. In exchange for the specified take-or-pay amounts of power, the BPPA requires semi-annual payments based on a return on capital, comprised of the original plant capital charge and periodic upgrade capital charges, which are both subject to fixed annual escalators, as well as sustaining capital charges and operating expenses. The BPPA includes a market-related price adjustment in 2026. Approximately 94% of the output from the Brilliant Plant is purchased by FortisBC Electric through the BPPA. The capital lease obligation bears interest at a composite rate of 5.00%. Included in energy supply costs was $28 million (2017 - $27 million) recognized in accordance with the BPPA, as approved by the BCUC.

FortisBC Electric also has a capital lease obligation with respect to the operation of the Brilliant Terminal Station ("BTS") under an agreement, which expires in 2056. The agreement provides that FortisBC Electric will pay a charge related to the recovery of the capital cost of the BTS and related operating costs. The obligation bears interest at a composite rate of 9.00%. Included in operating expenses was $3 million (2017 ‑ $3 million) recognized in accordance with the BTS agreement, as approved by the BCUC.

Finance Obligations

Between 2000 and 2005 FortisBC Energy entered into arrangements whereby certain natural gas distribution assets were leased to certain municipalities and then leased back by FortisBC Energy. These assets are integral equipment to real estate assets and the transactions have been accounted for as finance transactions, with the proceeds thereof recognized as finance obligations. Lease payments, net of the portion recognized as interest expense, reduce the finance obligations.

The finance obligations have implicit interest rates ranging from 6.90% to 7.48% and are being repaid over an initial 35-year period with an early termination option after 17 years. If the Company exercises this option, it would pay the municipality an early termination payment equal to the carrying value of the obligation at termination. In October 2018 FortisBC Energy exercised an early termination payment option in the amount $27 million on one of these arrangements.

Capital Lease and Finance Obligations Repayments

Present values of the minimum lease payments over the next five years and thereafter are as follows.
 
 
 
Total

(year)
 
 
(in millions)

2019
 
 
$
313

2020
 
 
77

2021
 
 
80

2022
 
 
49

2023
 
 
47

Thereafter
 
 
1,885

 
 
 
$
2,451

Less: Imputed interest and executory costs
 
 
(1,809
)
Total capital lease and finance obligations
 
 
642

Less: Current installments
 
 
(252
)
 
 
 
$
390




 
33
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

18. OTHER LIABILITIES
(in millions)
2018

2017

Defined benefit pension plans (Note 25)
$
391

$
393

OPEBs (Note 25)
350

381

Asset retirement obligations (Note 3)
111

71

Customer and other deposits
57

67

Stock-based compensation plans (Note 22)
56

39

Mine reclamation obligations (1)
40

40

Manufactured gas plant site remediation (2)
32

34

Fair value of derivatives (Note 28)
30

37

Deferred compensation plan (Note 11)
29

28

Waneta Partnership promissory note (Note 10)
—

63

Other (3)
42

57

 
$
1,138

$
1,210

(1) 
TEP pays ongoing reclamation costs related to three coal mines that supply generating facilities in which it has an ownership interest but does not operate. Costs are deferred as a regulatory asset and recovered from customers as permitted by the regulator. TEP's share of the reclamation costs is estimated to be $90 million (US$66 million) upon expiry of the coal agreements between 2019 and 2031. The present value of the estimated future liability is shown in the table above.
(2) 
Environmental regulations require Central Hudson to investigate sites at which the Company or its predecessors once owned and/or operated manufactured gas plants and, if necessary, remediate those sites. Costs are accrued based on the amounts that can be reasonably estimated. As at December 31, 2018, an obligation of $64 million (US$47 million) was recognized, including a current portion of $32 million (US$23 million) recognized in accounts payable and other current liabilities (Note 15). Central Hudson has notified its insurers that it intends to seek reimbursement where insurance coverage exists. Differences between actual costs and the associated rate allowances are deferred as a regulatory asset for future recovery (Note 9).
(3) 
Primarily includes long-term accrued liabilities, deferred lease revenue, funds received in advance of expenditures and unrecognized tax benefits.


19. EARNINGS PER COMMON SHARE

Diluted earnings per share ("EPS") was calculated using the treasury stock method for options.
 
2018
2017
 
Net Earnings

Weighted

 
Net Earnings

Weighted

 
 
to Common

Average

 
to Common

Average

 
 
Shareholders

Shares

 
Shareholders

Shares

 
 
(in millions)

(in millions)

EPS

(in millions)

(in millions)

EPS

Basic EPS
$
1,100

424.7

$
2.59

$
963

415.5

$
2.32

Potential dilutive effect of
stock options
—

0.5

 
—

0.7

 
Diluted EPS
$
1,100

425.2

$
2.59

$
963

416.2

$
2.31




 
34
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

20. PREFERENCE SHARES

Authorized
An unlimited number of First Preference Shares and Second Preference Shares, without nominal or par value.
Issued and outstanding
2018
2017
First Preference Shares
Number

 
 
Number

 
 
of Shares

 
Amount

of Shares

 
Amount

(in thousands)

 
(in millions)

(in thousands)

 
(in millions)

Series F
5,000

 
$
122

5,000

 
$
122

Series G
9,200

 
225

9,200

 
225

Series H
7,025

 
172

7,025

 
172

Series I
2,975

 
73

2,975

 
73

Series J
8,000

 
196

8,000

 
196

Series K
10,000

 
244

10,000

 
244

Series M
24,000

 
591

24,000

 
591

 
66,200

 
$
1,623

66,200

 
$
1,623


Characteristics of the First Preference Shares are as follows.
 
 
 
 
Earliest
 
 
 
 
 
Reset

Redemption
 
Right to

 
Initial

Annual

Dividend

and/or
Redemption

Convert on

 
Yield

Dividend

Yield

Conversion
Value

a One-For-

First Preference Shares (1) (2)
(%)

($)

(%)

Option Date
($)

One Basis

Perpetual fixed rate
 
 
 
 
 
 
Series F
4.90

1.2250

—

December 1, 2011
25.00

—

Series J (3)
4.75

1.1875

—

December 1, 2017
25.75

—

Fixed rate reset (4) (5)
 
 
 
 
 
 
Series G (6)
5.25

1.0983

2.13

September 1, 2013
25.00

—

Series H
4.25

0.6250

1.45

June 1, 2015
25.00

Series I

Series K
4.00

1.0000

2.05

March 1, 2019
25.00

Series L

Series M
4.10

1.0250

2.48

December 1, 2019
25.00

Series N

Floating rate reset (5) (7)
 
 
 
 
 
 
Series I (3)
2.10

—

1.45

June 1, 2015
25.50

Series H

Series L
—

—

2.05

March 1, 2024
—

Series K

Series N
—

—

2.48

December 1, 2024
—

Series M

(1)  
Holders are entitled to receive a fixed or floating cumulative quarterly cash dividend as and when declared by the Board of Directors of the Corporation, payable in equal installments on the first day of each quarter.
(2) 
On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First Preference Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but excluding the dates fixed for redemption, and in the case of the First Preference Shares that reset, on every fifth anniversary date thereafter.
(3) 
First Preference Shares, Series J were redeemable at $26.00 until December 1, 2018, decreasing by $0.25 each year until December 1, 2021 and redeemable at $25.00 per share thereafter. First Preference Shares, Series I are redeemable at $25.50 per share, up to but excluding June 1, 2020, and at $25.00 per share on June 1, 2020, and on every fifth anniversary date thereafter.
(4) 
On the redemption and/or conversion option date, and each five-year anniversary thereafter, the reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield.
(5) 
On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their Shares into an equal number of Cumulative Redeemable First Preference Shares of a specified series.
(6)
The annual dividend per share for the First Preference Shares, Series G was reset from $0.9708 to $1.0983 for the five-year period from September 1, 2018 up to but excluding September 1, 2023.
(7) 
The floating quarterly dividend rate will be reset every quarter based on the then current three‑month Government of Canada Treasury Bill rate plus the applicable reset dividend yield.

 
35
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

On the liquidation, dissolution or winding-up of Fortis, holders of common shares are entitled to participate ratably in any distribution of assets of Fortis, subject to the rights of holders of First and Second Preference Shares and any other class of shares of the Corporation entitled to receive the assets of the Corporation on such a distribution in priority to or ratably with the holders of the common shares.


21. ACCUMULATED OTHER COMPREHENSIVE INCOME
(in millions)
Opening Balance

Net Change

Ending Balance

2018
 
 
 
Unrealized foreign currency translation gains (losses)
 
 
 
On net investments in foreign operations
$
247

$
1,223

$
1,470

On hedges of net investments in foreign operations
(172
)
(372
)
(544
)
Income tax (expense) recovery
(1
)
11

10

 
74

862

936

Other
 
 
 
Cash flow hedges (Note 28)
10

1

11

Unrealized employee future benefits (losses) gains (Note 25)
(26
)
6

(20
)
Income tax recovery (expense)
3

(2
)
1

 
(13
)
5

(8
)
Accumulated other comprehensive income
$
61

$
867

$
928

 
 
 
 
2017
 
 
 
Unrealized foreign currency translation gains (losses)
 
 
 
On net investments in foreign operations
$
1,227

$
(980
)
$
247

On hedges of net investments in foreign operations
(472
)
300

(172
)
Income tax recovery (expense)
1

(2
)
(1
)
 
756

(682
)
74

Other
 
 
 
Cash flow hedges (Note 28)
8

2

10

Unrealized employee future benefits losses (Note 25)
(22
)
(4
)
(26
)
Income tax recovery
3

—

3

 
(11
)
(2
)
(13
)
Accumulated other comprehensive income
$
745

$
(684
)
$
61



 
36
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

22. STOCK-BASED COMPENSATION PLANS

Stock Options

Officers and certain key employees of Fortis and its subsidiaries are eligible for grants of options to purchase common shares of the Corporation. Options are exercisable for a period of 10 years from the grant date, expire no later than three years after the termination, death or retirement of the optionee, and vest evenly over a four-year period on each anniversary of the grant date.

The following options were granted in 2018 and 2017.
 
2018
2017

 
February

March

February

Options granted (#)
721,536

39,972

774,924

Exercise price ($) (1)
41.27

42.00

42.36

Grant date fair value ($)
3.43

4.08

3.22

Valuation assumptions:
 
 
 
Dividend yield (%) (2)
3.7

3.7

3.8

Expected volatility (%) (3)
15.5

15.7

16.1

Risk-free interest rate (%) (4)
2.1

2.0

1.2

Weighted average expected life (years) (5)
5.6

5.6

5.6

(1) 
Five-day VWAP immediately preceding the grant date
(2) 
Reflects average annual dividend yield up to the grant date and the weighted average expected life of the options
(3) 
Reflects historical experience over a period equal to the weighted average expected life of the options
(4) 
Government of Canada benchmark bond yield at the grant date that covers the weighted average expected life of the options
(5) 
Reflects historical experience

The following table summarizes information related to stock options for 2018.
 
Total Options
 
Non-vested Options (1)
 
Number of Options

 
Weighted Average
Exercise Price

 
Number of Options

 
Weighted Average
Grant Date Fair Value

Options outstanding, January 1, 2018
3,702,294

 
$
36.65

 
1,812,319

 
$
2.86

Granted
761,508

 
$
41.31

 
761,508

 
$
3.46

Exercised
(357,120
)
 
$
33.49

 
n/a

 
n/a

Vested
n/a

 
n/a

 
(711,484
)
 
$
2.88

Cancelled/Forfeited
(91,216
)
 
$
40.44

 
(91,216
)
 
$
3.08

Options outstanding, December 31, 2018
4,015,466

 
$
37.73

 
1,771,127

 
$
3.10

Options vested, December 31, 2018 (2)
2,244,339

 
$
35.40

 
 
 
 
(1) 
As at December 31, 2018, there was $5 million of unrecognized compensation expense related to stock options not yet vested, which is expected to be recognized over a weighted average period of approximately three years.
(2) 
As at December 31, 2018, the weighted average remaining term of vested options was six years with an aggregate intrinsic value of $23 million.


 
37
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

The following table summarizes additional stock option information.
(in millions)
2018

2017

Stock option expense recognized
$
2

$
3

Stock options exercised:




Cash received for exercise price
12

40

Intrinsic value realized by employees
3

15

Fair value of options that vested
2

2


Directors' DSU Plan

Directors of the Corporation who are not officers are eligible for grants of DSUs representing the equity portion of their annual compensation. Directors can further elect to receive credit for their quarterly cash retainer in a notional account of DSUs in lieu of cash. The Corporation may also determine that special circumstances justify the grant of additional DSUs to a director.

Each DSU vests at the grant date, has an underlying value equivalent to that of one common share of the Corporation, is entitled to commensurate notional common share dividends, and is settled in cash.

The following table summarizes information related to DSUs.
 
2018

2017

Number of Units
 
 
Beginning of year
184,795

199,411

Granted
32,132

31,453

Notional dividends reinvested
7,518

7,294

Paid out
(47,898
)
(53,363
)
End of year
176,547

184,795

 
 
 
Additional Information (in millions)
 
 
Compensation expense recognized
$
2

$
3

Cash payout (1)
2

2

Accrued liability as at December 31 (2)
8

9

(1) 
Reflects a weighted-average payout price of $43.15 per DSU (2017 - $45.37)
(2) 
Recognized at the respective December 31st VWAP (Note 3) and included in long-term other liabilities (Note 18)

PSU Plans

Senior management of the Corporation and its subsidiaries, and all ITC employees, are eligible for grants of PSUs representing a component of their long-term compensation.

Each PSU vests over a three-year period or immediately upon retirement eligibility of the holder, has an underlying value equivalent to that of one common share of the Corporation, is entitled to commensurate notional common share dividends, and is settled in cash. At the end of the three-year vesting period, cash payouts are the product of: (i) the numbers of units vested; (ii) the VWAP of the Corporation's common shares for the five trading days prior to the maturity date; and (iii) a payout percentage that may range from 0% to 200%.

The payout percentage is based on the Corporation's performance over the three-year vesting period, mainly determined by: (i) the Corporation's total shareholder return as compared to a predefined peer group of companies; and (ii) the Corporation's cumulative EPS, or for certain subsidiaries the Company's cumulative net income, as compared to the target established at the time of the grant.

 
38
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

The following table summarizes information related to PSUs.
 
2018

2017

Number of Units
 
 
Beginning of year
1,350,960

931,951

Granted
668,995

711,749

Notional dividends reinvested
66,280

44,893

Paid out
(280,993
)
(239,509
)
Cancelled/forfeited
(42,471
)
(16,910
)
Transferred to RSU Plan
—

(81,214
)
End of year
1,762,771

1,350,960

 
 
 
Additional Information (in millions)
 
 
Compensation expense recognized
$
22

$
26

Compensation expense unrecognized (1)
27

17

Cash payout (2)
14

11

Accrued liability as at December 31 (3)
50

41

Aggregate intrinsic value as at December 31 (4)
77

58

(1) 
Relates to unvested PSUs and is expected to be recognized over a weighted-average period of two years
(2) 
Reflects a weighted-average payout price of $46.01 per PSU and a payout percentage of 109% (2017 - $41.46 and 113%, respectively)
(3) 
Recognized at the respective December 31st VWAP (Note 3) and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 15 and 18)
(4) 
Relates to outstanding PSUs and reflects a weighted-average contractual life of one year

RSU Plans

Senior management of the Corporation and its subsidiaries, and all ITC employees, are eligible for grants of RSUs representing a component of their long-term compensation.

Each RSU vests over a three-year period or immediately upon retirement eligibility of the holder, has an underlying value equivalent to that of one common share of the Corporation, is entitled to commensurate notional common share dividends, and is settled in cash.


 
39
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

The following table summarizes information related to RSUs.
 
2018

2017

Number of Units
 
 
Beginning of year
482,763

123,612

Granted
305,686

349,496

Notional dividends reinvested
26,263

15,407

Paid out
(75,427
)
(74,876
)
Cancelled/forfeited
(22,267
)
(12,090
)
Transferred from PSU plan
—

81,214

End of year
717,018

482,763

 
 
 
Additional Information (in millions)
 
 
Compensation expense recognized
$
11

$
8

Compensation expense unrecognized (1)
15

11

Cash payout (2)
3

3

Accrued liability as at December 31 (3)
19

11

Aggregate intrinsic value as at December 31 (4)
34

22

(1) 
Relates to unvested RSUs and is expected to be recognized over a weighted-average period of two years
(2) 
Reflects a weighted-average payout price of $45.55 per RSU (2017 - $43.42)
(3) 
Recognized at the respective December 31st VWAP (Note 3) and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 15 and 18)
(4) 
Relates to outstanding RSUs and reflects a weighted-average contractual life of one year


23. OTHER INCOME, NET
(in millions)
2018

2017

Equity component of AFUDC
$
64

$
74

Interest income
15

14

Equity (loss) income - BEL
(1
)
4

Net periodic pension cost
(1
)
(11
)
Net foreign exchange gain (1)
—

26

Other
(17
)
9

 
$
60

$
116

(1) 
Includes a one-time $21 million unrealized foreign exchange gain on US dollar-denominated affiliate loan in 2017



 
40
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

24. INCOME TAXES

Deferred Income Tax Assets and Liabilities

The significant components of deferred income tax assets and liabilities consist of the following.

(in millions)
2018

2017

Gross deferred income tax assets
 
 
Regulatory liabilities
$
635

$
596

Tax loss and credit carryforwards
522

571

Employee future benefits
153

143

Unrealized foreign exchange losses on long-term debt
69

28

Other
76

51

 
1,455

1,389

Valuation allowance
(56
)
(44
)
Net deferred income tax asset
$
1,399

$
1,345

 
 
 
Gross deferred income tax liabilities
 
 
PPE
$
(3,780
)
$
(3,353
)
Regulatory assets
(203
)
(203
)
Intangible assets
(102
)
(87
)
 
(4,085
)
(3,643
)
Net deferred income tax liability
$
(2,686
)
$
(2,298
)

The deferred income tax assets associated with unrealized foreign exchange losses on long‑term debt reflect $56 million of unrealized capital losses as at December 31, 2018 (December 31, 2017 - $44 million). These deferred income tax assets can only be utilized if the Corporation has capital gains to offset these losses once realized. Management believes that it is more likely than not that Fortis will not be able to generate sufficient future capital gains and, consequently, the Corporation recognized a valuation allowance.

Management believes that, based on its historical pattern of taxable income, Fortis will produce the necessary income in the future to realize all other deferred income tax assets.

Unrecognized Tax Benefits
(in millions)
2018

2017

Beginning of year
$
28

$
23

Additions related to the current year
6

13

Adjustments related to prior years and U.S. Tax Reform
4

(8
)
End of year
$
38

$
28


Unrecognized tax benefits, if recognized, would reduce income tax expense by $1 million in 2018. Fortis has not recognized interest expense in 2018 and 2017 related to unrecognized tax benefits.


 
41
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Income Tax Expense
(in millions)
2018

2017

Canadian
 
 
Earnings before income tax expense
$
376

$
461

 
 
 
Current income tax
51

41

Deferred income tax
(25
)
16

Total Canadian
$
26

$
57

 
 
 
Foreign
 
 
Earnings before income tax expense
$
1,075

$
1,252

 
 
 
Current income tax
(22
)
3

Deferred income tax
161

528

Total Foreign
$
139

$
531

Income tax expense
$
165

$
588


Income tax expense differs from the amount that would be expected to be generated by applying the enacted combined Canadian federal and provincial statutory income tax rate to earnings before income tax expense. The following is a reconciliation of consolidated statutory taxes to consolidated effective taxes.
(in millions, except %)
2018

2017

Earnings before income tax expense
$
1,451

$
1,713

Combined Canadian federal and provincial statutory income tax rate
28.5
%
28.0
%
Expected federal and provincial taxes at statutory rate
$
414

$
480

Increase (decrease) resulting from:
 
 
Enactment of U.S. Tax Reform (1)
—

168

Foreign and other statutory rate differentials
(110
)
31

Remeasurement of deferred tax liabilities
(44
)
—

AFUDC
(14
)
(26
)
Effects of rate-regulated accounting:
 
 
Difference between depreciation claimed for income tax and accounting purposes
(34
)
(26
)
Items capitalized for accounting purposes but expensed for income tax purposes
(21
)
(21
)
Other
(26
)
(18
)
Income tax expense
$
165

$
588

Effective tax rate
11.4
%
34.3
%
(1) 
In 2017 the Tax Cuts and Jobs Act implemented significant changes to U.S. tax legislation, including a reduction in the U.S. federal corporate income tax from 35% to 21%, effective January 1, 2018. The Corporation's U.S. utilities and holding companies were required to remeasure their deferred tax assets and liabilities at the new corporate income tax rate as at the date of enactment. The one-time remeasurement resulted in an unfavourable earnings impact of $168 million recognized in deferred income tax expense ($146 million after non-controlling interest).


 
42
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Income Tax Carryforwards
(in millions)
Expiring Year
2018

Canadian
 
 
Capital loss
n/a
$
59

Non-capital loss
2025-2038
387

Other tax credits
2026-2037
2

 
 
448

Unrecognized
 
(15
)
 
 
433

Foreign
 
 
Federal and state net operating loss
2022-2038
2,130

Other tax credits
2021-2038
115

 
 
2,245

Total income tax carryforwards recognized as at December 31
 
$
2,678


The Corporation and one or more of its subsidiaries are subject to taxation in Canada, the United States and other foreign jurisdictions. The material jurisdictions in which the Corporation is subject to potential examinations include the United States (Federal, Arizona, Kansas, Iowa, Michigan, Minnesota and New York) and Canada (Federal and British Columbia). The Corporation's 2012 to 2018 taxation years are still open for audit in the Canadian jurisdictions and its 2014 to 2018 taxation years are still open for audit in the United States jurisdictions.


25. EMPLOYEE FUTURE BENEFITS

For defined benefit pension and OPEB plans, the benefit obligation and fair value of plan assets are measured as at December 31.

For the Corporation's Canadian and Caribbean subsidiaries, actuarial valuations to determine funding contributions for pension plans are required at least every three years. The most recent valuations were as of December 31, 2015 for FortisBC Energy (plan covering non-unionized employees); December 31, 2016 for FortisBC Electric and FortisBC Energy (plans covering unionized employees); December 31, 2017 for Newfoundland Power, FortisAlberta, FortisOntario and the Corporation; and December 31, 2018 for Caribbean Utilities.

ITC, UNS Energy and Central Hudson perform annual actuarial valuations as their funding requirements are based on maintaining minimum annual targets, all of which have been met.

The Corporation's investment policy is to ensure that the defined benefit pension and OPEB plan assets, together with expected contributions, are invested in a prudent and cost-effective manner to optimally meet the liabilities of the plans. The investment objective is to maximize returns in order to manage the funded status of the plans and minimize the Corporation's cost over the long term, as measured by both cash contributions and recognized expense.


 
43
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Allocation of Plan Assets as at December 31
 
2018 Target Allocation
 
 
(weighted-average %)
2018

2017

Equities
46
45

47

Fixed income
47
47

46

Real estate
6
7

6

Cash and other
1
1

1

 
100
100

100


Fair value of plan assets as at December 31
(in millions)
Level 1 (1)

Level 2 (1)

Level 3 (1)

Total

2018
 
 
 
 
Equities
$
508

$
885

$
—

$
1,393

Fixed income
144

1,338

—

1,482

Real estate
—

14

190

204

Private equities
—

—

25

25

Cash and other
8

11

—

19

 
$
660

$
2,248

$
215

$
3,123

2017
 
 
 
 
Equities
$
522

$
949

$
—

$
1,471

Fixed income
133

1,289

—

1,422

Real estate
—

13

168

181

Private equities
—

—

22

22

Cash and other
8

14

—

22

 
$
663

$
2,265

$
190

$
3,118

(1) 
Refer to Note 28 for a description of the fair value hierarchy.

The following table reconciles the changes in the fair value of pension plan assets that have been measured using Level 3 inputs.
(in millions)
2018

2017

Balance, beginning of year
$
190

$
113

Return on plan assets
15

12

Foreign currency translation
3

(2
)
Purchases, sales and settlements
7

67

Balance, end of year
$
215

$
190



 
44
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Funded Status
Defined Benefit
Pension Plans
OPEB Plans
(in millions)
2018

2017

2018

2017

Change in benefit obligation (1)
 
 
 
 
Balance, beginning of year
$
3,215

$
3,037

$
665

$
676

Service costs
84

76

31

27

Employee contributions
16

16

2

2

Interest costs
114

115

23

25

Benefits paid
(145
)
(133
)
(26
)
(22
)
Actuarial losses (gains)
(217
)
217

(69
)
(14
)
Past service credits/plan amendments
(1
)
—

(3
)
(3
)
Foreign currency translation
141

(113
)
32

(26
)
Balance, end of year (2)
$
3,207

$
3,215

$
655

$
665

 
 
 
 
 
Change in value of plan assets
 
 
 
 
Balance, beginning of year
$
2,841

$
2,646

$
277

$
252

Actual return on plan assets
(93
)
336

(13
)
37

Benefits paid
(137
)
(127
)
(26
)
(22
)
Employee contributions
16

16

2

2

Employer contributions
79

69

29

26

Foreign currency translation
124

(99
)
24

(18
)
Balance, end of year
$
2,830

$
2,841

$
293

$
277

 
 
 
 
 
Funded status
$
(377
)
$
(374
)
$
(362
)
$
(388
)
 
 
 
 
 
Balance sheet presentation
 
 
 
 
Long-term assets (Note 11)
$
26

$
31

$
1

$
3

Current liabilities (Note 15)
(12
)
(12
)
(13
)
(10
)
Long-term liabilities (Note 18)
(391
)
(393
)
(350
)
(381
)
 
$
(377
)
$
(374
)
$
(362
)
$
(388
)
(1) 
Amounts reflect projected benefit obligation for defined benefit pension plans and accumulated benefit obligation for OPEB plans.
(2) 
The accumulated benefit obligation for defined benefit pension plans, excluding assumptions about future salary levels, was $2,936 million as at December 31, 2018 (December 31, 2017 - $2,940 million).
Net Benefit Cost
Defined Benefit
Pension Plans
OPEB Plans
(in millions)
2018

2017

2018

2017

Service costs
$
84

$
76

$
31

$
27

Interest costs
114

115

23

25

Expected return on plan assets
(162
)
(151
)
(16
)
(14
)
Amortization of actuarial losses
48

45

—

2

Amortization of past service credits/plan amendments
—

—

(10
)
(12
)
Regulatory adjustments
(1
)
2

6

4

Net benefit cost
$
83

$
87

$
34

$
32



 
45
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

The following table summarizes the accumulated amounts of net benefit cost that have not yet been recognized in earnings or comprehensive income and shows their classification on the consolidated balance sheets.
 
Defined Benefit
Pension Plans
OPEB Plans
(in millions)
2018

2017

2018

2017

Unamortized net actuarial losses (gains)
$
19

$
22

$
(2
)
$
—

Unamortized past service costs
1

1

2

3

Income tax recovery
(3
)
(5
)
(1
)
(1
)
Accumulated other comprehensive income 
(Note 21)
$
17

$
18

$
(1
)
$
2

 
 
 
 
 
Net actuarial losses (gains)
$
457

$
443

$
(25
)
$
17

Past service credits
(10
)
(11
)
(16
)
(23
)
Other regulatory deferrals
15

10

27

27

 
$
462

$
442

$
(14
)
$
21

 
 
 
 
 
Regulatory assets (Note 9)
$
462

$
442

$
23

$
68

Regulatory liabilities (Note 9)
—

—

(37
)
(47
)
Net regulatory assets
$
462

$
442

$
(14
)
$
21


The following table summarizes the components of net benefit cost recognized in comprehensive income or as regulatory assets, which would otherwise have been recognized in comprehensive income.
 
Defined Benefit
Pension Plans
OPEB Plans
(in millions)
2018

2017

2018

2017

Current year net actuarial (gains) losses
$
(3
)
$
5

$
(2
)
$
(1
)
Past service (credits) costs/plan amendments
—

—

(1
)
2

Amortization of actuarial losses
(1
)
(1
)
—

—

Foreign currency translation
1

(1
)
—

—

Income tax recovery
2

—

—

—

Total recognized in comprehensive income
$
(1
)
$
3

$
(3
)
$
1

 
 
 
 
 
Current year net actuarial losses (gains)
$
41

$
24

$
(39
)
$
(35
)
Past service credits/plan amendments
—

—

(3
)
(5
)
Amortization of actuarial losses
(47
)
(44
)
—

(1
)
Amortization of past service (costs) credits
1

—

11

12

Foreign currency translation
21

(17
)
(3
)
2

Regulatory adjustments
4

(1
)
(1
)
(6
)
Total recognized in regulatory assets
$
20

$
(38
)
$
(35
)
$
(33
)

Net actuarial losses of $1 million are expected to be amortized to net benefit cost from accumulated other comprehensive income in 2019 related to defined benefit pension plans.

Net actuarial losses of $24 million, past service credits of $1 million and regulatory adjustments of $1 million are expected to be amortized to net benefit cost from regulatory assets in 2019 related to defined benefit pension plans. Past service credits of $8 million, net actuarial gains of $4 million and regulatory adjustments of $4 million are expected to be amortized to net benefit cost from regulatory assets in 2019 related to OPEB plans.


 
46
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Significant Assumptions
Defined Benefit
Pension Plans
OPEB Plans
(weighted-average %)
2018

2017

2018

2017

Discount rate during the year (1)
3.56

3.98

3.57

3.96

Discount rate as at December 31
4.07

3.58

4.13

3.59

Expected long-term rate of return on plan assets (2)
5.80

5.97

5.48

5.81

Rate of compensation increase
3.35

3.34

—

—

Health care cost trend increase as at December 31 (3)
—

—

4.61

4.71

(1) 
ITC and UNS use the split discount rate methodology for determining current service and interest costs. All other subsidiaries use the single discount rate approach.
(2) 
Developed by management with assistance from external actuaries using best estimates of expected returns, volatilities and correlations for each class of asset. Best estimates are based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes.
(3) 
The projected 2019 weighted-average health care cost trend rate for OPEB plans is 6.35% and is assumed to decrease over the next 14 years to the weighted-average ultimate health care cost trend rate of 4.61% in 2032 and thereafter.

The following table summarizes for 2018 the effects of changing the health care cost trend rate by 1%.
(in millions)
1% increase

1% decrease

Increase (decrease) in accumulated benefit obligation
$
85

$
(67
)
Increase (decrease) in service and interest costs
11

(8
)

 
Defined Benefit

 
Expected Benefit Payments
Pension Payments

OPEB

(year)
(in millions)

(in millions)

2019
$
147

$
26

2020
152

28

2021
157

30

2022
165

32

2023
170

33

2024-2028
946

185


During 2019 the Corporation expects to contribute $47 million for defined benefit pension plans and $31 million for OPEB plans.

In 2018 the Corporation expensed $38 million (2017 - $38 million) related to defined contribution pension plans.


26. TERMINATED ACQUISITION

In May 2017 Fortis had entered into an agreement with Teck Resources Limited to acquire a two-thirds ownership interest in the Waneta Dam and related transmission assets in British Columbia. In August 2017 BC Hydro exercised its right of first offer in this regard. Consequently, the purchase agreement with Fortis was terminated, resulting in the payment of a $28 million break fee to Fortis, which was recognized in operating expenses.



 
47
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

27. SUPPLEMENTARY CASH FLOW INFORMATION
(in millions)
2018

2017

Cash paid for
 
 
Interest
$
969

$
927

Income taxes
73

69

Change in working capital
 
 
Accounts receivable and other current assets
$
(204
)
$
(74
)
Prepaid expenses
1

(3
)
Inventories
(8
)
(6
)
Regulatory assets - current portion
16

39

Accounts payable and other current liabilities
99

119

Regulatory liabilities - current portion
(6
)
(172
)
 
$
(102
)
$
(97
)
Non-cash investing and financing activities
 
 
Accrued capital expenditures
$
328

$
307

Common share dividends reinvested
272

253

Gila River generating station Unit 2 capital lease
223

—

Contributions in aid of construction
14

35

Exercise of stock options into common shares
1

5



28. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Derivatives

The Corporation generally limits the use of derivatives to those that qualify as accounting, economic or cash flow hedges, or those that are approved for regulatory recovery.

The Corporation records all derivatives at fair value, with certain exceptions, including those derivatives that qualify for the normal purchase and normal sale exception. Fair values reflect estimates based on current market information about the derivatives as at the balance sheet dates. The estimates cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in predicting the Corporation's future consolidated earnings or cash flows.

Cash flows associated with the settlement of all derivatives are included in operating activities in the consolidated statements of cash flows.

Energy contracts subject to regulatory deferral
UNS Energy holds electricity power purchase contracts and gas swap contracts to reduce its exposure to energy price risk. Fair values were measured primarily under the market approach using independent third-party information, where possible. When published prices are not available, adjustments are applied based on historical price curve relationships, transmission costs and line losses.

Central Hudson holds swap contracts for electricity and natural gas to minimize price volatility by fixing the effective purchase price. Fair values were measured using forward pricing provided by independent third-party information.

FortisBC Energy holds gas supply contracts and financial commodity swaps to fix the effective purchase price of natural gas. Fair values reflect the present value of future cash flows based on published market prices and forward natural gas curves.


 
48
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Unrealized gains or losses associated with changes in the fair value of these energy contracts are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulators. As at December 31, 2018, unrealized losses of $57 million (December 31, 2017 - $87 million) were recognized as regulatory assets and unrealized gains of $9 million (December 31, 2017 - $2 million) were recognized in regulatory liabilities (Note 9).

Energy contracts not subject to regulatory deferral
UNS Energy holds wholesale trading contracts that qualify as derivatives to fix power prices and realize potential margin, of which 10% of any realized gains are shared with customers through rate stabilization accounts. Fair values were measured using a market approach using independent third-party information, where possible.

Aitken Creek holds gas swap contracts to manage its exposure to changes in natural gas prices, capture natural gas price spreads, and manage the financial risk posed by physical transactions. Fair values were measured using forward pricing from published market sources.

Unrealized gains or losses associated with changes in the fair value of these energy contracts are recognized in earnings. During 2018 unrealized losses of $12 million (2017 - unrealized gains of $36 million) were recognized in revenue.

Foreign exchange contracts
The Corporation holds US dollar foreign exchange contracts to mitigate exposure to volatility of foreign exchange rates. The contracts expire in 2019 and have a combined notional amount of $161 million. Fair value was measured using independent third-party information.

Unrealized gains and losses associated with changes in fair value are recognized in earnings. During 2018 unrealized losses of $11 million (2017 - unrealized gains of $3 million) were recognized in other income, net.

Interest rate and total return swaps
UNS Energy holds an interest rate swap to mitigate exposure to volatility in variable interest rates on capital lease obligations (Note 17). The swap expires in 2020 and has a notional amount of $16 million. Fair value was measured using an income valuation approach based on six-month LIBOR.

Unrealized gains and losses associated with changes in the fair value of this interest rate swap, which was designated as a cash flow hedge, are recognized in other comprehensive income and reclassified to earnings through interest expense over the life of the hedged debt. The loss expected to be reclassified to earnings within the next 12 months is estimated to be approximately $3 million, net of tax.

The Corporation holds three total return swaps to manage the cash flow risk associated with forecasted future cash settlements of certain stock-based compensation obligations. The swaps have a combined notional amount of $41 million and terms ranging from one to three years, expiring in January 2019, 2020 and 2021. Fair value was measured using an income valuation approach based on forward pricing curves.

Unrealized gains and losses associated with changes in the fair value of the total return swaps are recognized in earnings. During 2018 unrealized gains of less than $1 million (2017 - unrealized losses of less than $1 million) were recognized in other income, net.

Other investments
ITC, UNS Energy and Central Hudson hold investments in trust associated with supplemental retirement benefit plans for select employees. These investments consist of mutual funds and money market accounts, which are recorded at fair value based on quoted market prices in active markets. Gains and losses on these funds are recognized in earnings. During 2018 unrealized gains of less than $1 million (2017 - unrealized gains of less than $1 million) were recognized in other income, net.


 
49
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

Recurring Fair Value Measures

The following table presents the fair value of the assets and liabilities that are accounted for at fair value on a recurring basis.
(in millions)
Level 1 (1)
Level 2 (1)

Level 3 (1)

Total

As at December 31, 2018
 
 
 
 
Assets
 
 
 
 
Energy contracts subject to regulatory deferral (2) (3)
$
—

$
33

$
8

$
41

Energy contracts not subject to regulatory deferral (2)
—

13

3

16

Other investments (4)
155

—

—

155


$
155

$
46

$
11

$
212

 
 
 
 
 
Liabilities
 
 
 
 
Energy contracts subject to regulatory deferral (3) (5)
$
—

$
(86
)
$
(3
)
$
(89
)
Energy contracts not subject to regulatory deferral (5)
—

(1
)
—

(1
)
Foreign exchange contracts, interest rate and total return swaps (6)
(8
)
(1
)
—

(9
)
 
$
(8
)
$
(88
)
$
(3
)
$
(99
)
As at December 31, 2017
 
 
 
 
Assets
 
 
 
 
Energy contracts subject to regulatory deferral (2) (3)
$
—

$
19

$
2

$
21

Energy contracts not subject to regulatory deferral (2)
—

26

4

30

Foreign exchange contracts (6)
3

—

—

3

Other investments (4)
78

—

—

78

 
$
81

$
45

$
6

$
132


 
 
 
 
Liabilities
 
 
 
 
Energy contracts subject to regulatory deferral (3) (5)
$
(1
)
$
(103
)
$
(2
)
$
(106
)
Energy contracts not subject to regulatory deferral (5)
—

—

(1
)
(1
)
Interest rate and total return swaps (6)
—

(1
)
—

(1
)
 
$
(1
)
$
(104
)
$
(3
)
$
(108
)
(1) 
Under the hierarchy, fair value is determined using: (i) level 1 - unadjusted quoted prices in active markets; (ii) level 2 - other pricing inputs directly or indirectly observable in the marketplace; and (iii) level 3 - unobservable inputs, used when observable inputs are not available. Classifications reflect the lowest level of input that is significant to the fair value measurement.
(2) 
Included in accounts receivable and other current assets or other assets
(3) 
Unrealized gains and losses arising from changes in fair value of these contracts are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates as permitted by the regulators, with the exception of long-term wholesale trading contracts and certain gas swap contracts.  
(4) 
Included in other assets
(5) 
Included in accounts payable and other current liabilities or other liabilities
(6) 
Included in accounts receivable and other current assets, accounts payable and other current liabilities or other liabilities

Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one hierarchical fair value level to another. There were no transfers between levels during 2018.

For level 3 measurements, changes in the unobservable inputs could have a significant impact on fair value. Excluding long-term wholesale trading contracts and certain gas swap contracts, the impacts of fair value changes are subject to regulatory recovery.


 
50
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

The following table reconciles changes in the fair value of level 3 net assets and liabilities.
(in millions)
2018

2017

Balance, beginning of year
$
3

$
2

Realized gains (losses)
14

(13
)
Settlements
(9
)
12

Transfers of assets out of level 3
—

(2
)
Transfers of liabilities out of level 3
—

4

Balance, end of year
$
8

$
3


The Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions, which applies only to its energy contracts. The following table presents the potential offset of counterparty netting.
Energy Contracts


(in millions)
Gross Amount Recognized on Balance Sheet

Counterparty Netting of Energy Contracts

Cash Collateral Received/Posted

Net Amount

As at December 31, 2018
 
 
 
 
Derivative assets
$
57

$
28

$
16

$
13

Derivative liabilities
(90
)
(28
)
—

(62
)
As at December 31, 2017
 
 
 
 
Derivative assets
$
51

$
17

$
7

$
27

Derivative liabilities
(107
)
(17
)
—

(90
)

Volume of Derivative Activity

As at December 31, 2018, the Corporation had various energy contracts that will settle on various dates through 2029. The volumes related to electricity and natural gas derivatives are outlined below.
As at December 31
2018

2017

Energy contracts subject to regulatory deferral (1)
 
 
Electricity swap contracts (GWh)
774

1,291

Electricity power purchase contracts (GWh)
651

761

Gas swap contracts (PJ)
203

216

Gas supply contract premiums (PJ)
266

219

Energy contracts not subject to regulatory deferral (1)
 
 
Wholesale trading contracts (GWh)
1,440

2,387

Gas swap contracts (PJ)
37

36

(1) 
GWh means gigawatt hours and PJ means petajoules.

Credit Risk

For cash equivalents, accounts receivable and other current assets, and long-term other receivables, credit risk is generally limited to the carrying value on the consolidated balance sheets. The Corporation's subsidiaries generally have a large and diversified customer base, which minimizes the concentration of credit risk. Policies in place to minimize credit risk include requiring customer deposits, prepayments and/or credit checks for certain customers, performing disconnections and/or using third-party collection agencies for overdue accounts.

ITC has a concentration of credit risk as approximately 70% of its revenue is derived from three customers. Credit risk is limited as such customers have investment-grade credit ratings. ITC further reduces credit risk by requiring a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit-scoring model and other factors.


 
51
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

FortisAlberta has a concentration of credit risk as distribution service billings are to a relatively small group of retailers. The Company reduces its exposure by obtaining from the retailers either a cash deposit, bond, letter of credit, an investment-grade credit rating from a major rating agency, or a financial guarantee from an entity with an investment-grade credit rating.

UNS Energy, Central Hudson, FortisBC Energy, Aitken Creek and the Corporation may be exposed to credit risk in the event of non‑performance by counterparties to derivatives. Credit risk is limited by net settling payments, when possible, and dealing only with counterparties that have investment-grade credit ratings. At UNS Energy and Central Hudson, certain contractual arrangements require counterparties to post collateral.

The value of derivatives in net liability positions under contracts with credit risk-related contingent features that, if triggered, could require the posting of a like amount of collateral was $75 million as at December 31, 2018 (December 31, 2017 - $57 million).

Foreign Exchange Hedge

The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI and BECOL is the US dollar. The Corporation's earnings from, and net investments in, foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has decreased this exposure by designating US dollar-denominated borrowings at the corporate level as a hedge of its net investment in foreign subsidiaries. The foreign exchange gain or loss on the translation of US dollar-denominated interest expense partially offsets the foreign exchange gain or loss on the translation of US dollar-denominated subsidiary earnings.

As at December 31, 2018, US$3,441 million (December 31, 2017 - US$3,385 million) of net investment in foreign subsidiaries was hedged by the Corporation's corporately issued US dollar-denominated long-term debt and approximately US$7,970 million (December 31, 2017 - US$7,548 million) was unhedged. Exchange rate fluctuations associated with the hedged net investment in foreign subsidiaries and the debt serving as the hedge are recognized in accumulated other comprehensive income.

Financial Instruments Not Carried at Fair Value

Excluding long-term debt, the consolidated carrying value of the Corporation's financial instruments approximates fair value, reflecting their short-term maturity, normal trade credit terms and/or nature.

As at December 31, 2018, the carrying value of long-term debt, including the current portion, was $24,231 million (December 31, 2017 - $21,535 million) (Note 16) compared to an estimated fair value of $25,110 million (December 31, 2017 - $23,481 million). Long-term debt is fair valued using level 2 inputs.

The fair value of long-term debt is calculated using quoted market prices or, when unavailable, by either: (i) discounting the associated future cash flows at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills with similar terms to maturity, plus a credit risk premium equal to that of issuers of similar credit quality; or (ii) obtaining from third parties indicative prices for the same or similarly rated issues of debt with similar maturities. Since the Corporation does not intend to settle the long-term debt prior to maturity, the excess of the estimated fair value above the carrying value does not represent an actual liability.



 
52
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

29. VARIABLE INTEREST ENTITY

The Waneta Partnership, which owns and operates the Waneta Expansion on the Pend d'Oreille River in British Columbia, is 51% owned by Fortis and 49% by CPC and CBT (Note 10). The Waneta Expansion is operated and maintained by a wholly owned subsidiary of the Corporation and the output is sold to BC Hydro and FortisBC Electric under 40-year contracts. Each partner pays its proportionate share of the costs and is entitled to a proportionate share of the net revenue.

The Corporation's ownership interest is a variable interest entity. Fortis is the primary beneficiary as it has the power to direct the activities of the partnership, the obligation to absorb losses and the right to receive benefits that could be significant to the partnership. Consequently, Fortis consolidates the Waneta Partnership. The Corporation's consolidated financial statements include the following with respect to the Waneta Partnership.
(in millions)
2018

2017

Assets




Cash and cash equivalents
$
15

$
16

Accounts receivable and other current assets
15

14

PPE
674

688

Intangible assets
30

30


$
734

$
748

Liabilities




Accounts payable and other current liabilities
$
(6
)
$
(28
)
Other liabilities
(67
)
(63
)

(73
)
(91
)
Net assets before partners' equity
$
661

$
657

 
 
 
Revenue
$
94

$
93

Expenses
 
 
Operating expenses
18

17

Depreciation and amortization
18

18

Finance charges
4

4

 
40

39

Net earnings
$
54

$
54


Cash used in investing activities at the Waneta Partnership for 2018 included capital expenditures of $27 million (2017 - $5 million). Cash flow related to financing activities for 2018 included dividends paid by the Waneta Partnership to non-controlling interests of $35 million (2017 - $34 million) and advances from non-controlling interests of $11 million (2017 - nil).



 
53
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

30. COMMITMENTS AND CONTINGENCIES

As at December 31, 2018, consolidated commitments in each of the next five years and for periods thereafter, excluding repayments of long-term debt and capital lease and finance obligations separately disclosed in Notes 16 and 17, respectively, were as follows.
(in millions)
Total

Due within 1 year

Due in year 2

Due in year 3

Due in year 4

Due in year 5

Due after
5 years

Interest obligations on long-term debt
$
16,345

$
994

$
973

$
950

$
902

$
870

$
11,656

Power purchase obligations (1)
2,438

254

191

174

170

172

1,477

Renewable power purchase obligations (2)
1,699

110

110

109

109

108

1,153

Gas purchase obligations (3)
1,348

359

290

242

202

144

111

Long-term contracts - UNS Energy (4)
777

176

142

92

60

46

261

ITC easement agreement (5)
436

14

14

14

14

14

366

Renewable energy credit purchase agreements (6)
146

24

26

18

11

11

56

Debt collection agreement (7)
119

3

3

3

3

3

104

Purchase of Springerville Common Facilities (8)
93

—

—

93

—

—

—

Joint-use asset and shared service agreements
52

3

3

3

3

3

37

Operating lease obligations
51

8

6

5

4

4

24

Other (9)
530

108

84

89

38

36

175

Total
$
24,034

$
2,053

$
1,842

$
1,792

$
1,516

$
1,411

$
15,420

(1) 
The most significant power purchase obligations are described below.

Maritime Electric ($771 million): includes an agreement entitling Maritime Electric to approximately 4.55% of the output of New Brunswick Power's Point Lepreau nuclear generating station and requiring Maritime Electric to pay its share of the station's capital operating costs for the life of the unit. Maritime Electric also has two take-or-pay contracts for the purchase of either capacity or energy, expiring in February 2024.

FortisOntario ($705 million): an agreement with Hydro-Québec for the supply of up to 145 MW of capacity and a minimum of 537 GWh of associated energy annually from January 2020 through December 2030.

FortisBC Energy ($522 million): an agreement with BC Hydro for the supply of electricity to the Tilbury liquefied natural gas facility expansion.

FortisBC Electric ($345 million): includes an agreement with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of associated energy annually for a 20-year term beginning October 1, 2013.

(2) 
TEP and UNS Electric are party to renewable PPAs, with expiry dates from 2027 through 2043, that require them to purchase 100% of the output of certain renewable energy generating facilities once commercial operation is achieved. Amounts shown are the estimated future payments.

(3) 
Certain of the Corporation's subsidiaries, mainly FortisBC Energy, enter into contracts for the purchase of gas, gas transportation and storage services. FortisBC Energy's gas purchase obligations are based on gas commodity indices that vary with market prices and the obligations are based on index prices as at December 31, 2018.

(4) 
UNS Energy enters into long-term contracts for the purchase and delivery of coal to fuel generating facilities, the purchase of gas transportation services to meet load requirements, and the purchase of transmission services for purchased power. Amounts paid for coal depend on actual quantities purchased and delivered. Certain contracts have price adjustment clauses that will affect future costs. These contracts have various expiry dates between 2019 and 2040.

 
54
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

(5) 
ITC is party to an agreement with Consumers Energy, the primary customer of METC, which provides METC with an easement for transmission purposes and rights-of-way, leasehold interests, fee interests and licences associated with the land over which its transmission lines cross. The agreement expires in December 2050, subject to 10 potential 50-year renewals thereafter.

(6) 
UNS Energy and Central Hudson are party to renewable energy credit purchase agreements, mainly for the purchase of environmental attributions from retail customers with solar installations or other renewable generators. Payments are primarily made at contractually agreed-upon intervals based on metered energy production.

(7) 
Maritime Electric is party to a debt collection agreement with PEI Energy Corporation for the initial capital cost of the submarine cables and associated parts of the New Brunswick transmission system interconnection. Payments under the agreement, which expires in February 2056, will be collected from customers in future rates.

(8) 
UNS Energy is obligated to purchase an undivided 32.2% interest in the Springerville Common Facilities if the related two leases are not renewed. The initial lease terms expire in January 2021 (Note 17).

(9) 
Includes stock-based compensation plan obligations, land easements, asset retirement obligations, and defined benefit pension plan funding obligations.

Other Commitments

The Corporation's regulated utilities are obligated to provide service to customers within their respective service territories. Their capital expenditures are largely to ensure continued and enhanced performance, reliability and safety of the electricity and gas systems and to meet customer growth. Consolidated capital expenditures are forecast to be approximately $3.7 billion for 2019 and approximately $17.3 billion over the five-year period from 2019 through 2023.

Central Hudson is a participant in an investment with other utilities to jointly develop, own and operate electric transmission projects in New York State. In December 2014 an application was filed with FERC for the recovery of the cost of and return on five high-voltage transmission projects totalling $2.3 billion (US$1.7 billion). Central Hudson's maximum commitment is $248 million (US$182 million), for which it has issued a parental guarantee. As at December 31, 2018, there was no obligation under this guarantee.

As at December 31, 2018, FHI had $77 million (December 31, 2017 - $80 million) of parental guarantees outstanding to support storage optimization activities at Aitken Creek.

Contingency

In April 2013 FHI and Fortis were named as defendants in an action in the British Columbia Supreme Court by the Coldwater Indian Band ("Band") regarding interests in a pipeline right of way on reserve lands. The pipeline was transferred by FHI (then Terasen Inc.) to Kinder Morgan Inc. in 2007. The Band seeks cancellation of the right of way and damages for wrongful interference with the Band’s use and enjoyment of reserve lands. In May 2016 the Federal Court dismissed the Band’s application for judicial review of the ministerial consent. In September 2017 the Federal Court of Appeal set aside the Minister’s consent and returned the matter to the Minister for redetermination. No amount has been accrued as the outcome cannot yet be reasonably determined.



 
55
 


FORTIS INC.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018 and 2017

31. COMPARATIVE FIGURES

Effective January 1, 2018, the Corporation elected to present, on the statement of cash flows, all borrowings and repayments under committed credit facilities on a gross basis and continue to present borrowings and repayments under uncommitted or demand credit facilities on a net basis as Net Change in Short-Term Borrowings. The presentation change resulted in $365 million, which was previously reported within Net Repayments and Borrowings under Committed Facilities, being reported on a gross basis, with (i) $4,376 million reported as Borrowings under Committed Credit Facilities, (ii) $5,441 million reported as Repayments under Committed Credit Facilities, and (iii) $700 million reported as Net Change in Short-Term Borrowings.

Comparative figures were reclassified to conform with the revised segmentation, as described in Note 5, and to reflect the retrospective adoption of ASU 2017-07, as described in Note 3.

 
56