EX-99.3 4 a2020annual-993mda.htm EX-99.3 Document

Exhibit 99.3
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Management Discussion and Analysis
For the year ended December 31, 2020
Dated February 11, 2021


TABLE OF CONTENTS
About Fortis1Cash Flow Requirements19
Significant Items3Cash Flow Summary20
Performance at a Glance5Contractual Obligations22
The Industry8Capital Structure and Credit Ratings23
Operating Results9Capital Plan24
Business Unit Performance10Business Risks28
ITC11Accounting Matters35
UNS Energy11Financial Instruments38
Central Hudson12Long-Term Debt and Other38
FortisBC Energy12Derivatives39
FortisAlberta13Selected Annual Financial Information41
FortisBC Electric13Fourth Quarter Results42
Other Electric14Summary of Quarterly Results44
Energy Infrastructure14Related-Party and Inter-Company Transactions45
Corporate and Other14Management's Evaluation of Controls and Procedures45
Non-US GAAP Financial Measures15Outlook46
Regulatory Highlights15Forward-Looking Information46
Financial Position18Glossary48
Liquidity and Capital Resources19Annual Consolidated Financial StatementsF-1

This MD&A has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. It should be read in conjunction with the 2020 Annual Financial Statements and is subject to the cautionary statement and disclaimer provided under "Forward-Looking Information" on page 46. Further information about Fortis, including its Annual Information Form filed on SEDAR, can be accessed at www.fortisinc.com, www.sedar.com, or www.sec.gov.

Financial information herein has been prepared in accordance with US GAAP (except for indicated Non-US GAAP Financial Measures) and, unless otherwise specified, is presented in Canadian dollars based, as applicable, on the following US dollar-to-Canadian dollar exchange rates: (i) average of 1.34 and 1.33 for the years ended December 31, 2020 and 2019, respectively; (ii) 1.27 and 1.30 as at December 31, 2020 and 2019, respectively; (iii) average of 1.30 and 1.32 for the quarters ended December 31, 2020 and 2019, respectively; and (iv) 1.32 for all forecast periods. Certain terms used in this MD&A are defined in the "Glossary" on page 48.


ABOUT FORTIS

Fortis (TSX/NYSE: FTS) is a well-diversified leader in the North American regulated electric and gas utility industry, with revenue of $8.9 billion and total assets of $55 billion as at December 31, 2020.

Regulated utilities account for 99% of the Corporation's assets with the remainder primarily attributable to non-regulated energy infrastructure. The Corporation's 9,000 employees serve 3.3 million utility customers in five Canadian provinces, nine US states and three Caribbean countries. As at December 31, 2020, 66% of the Corporation's assets were located outside Canada and 59% of 2020 revenue was derived from foreign operations.

MANAGEMENT DISCUSSION AND ANALYSIS
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Total Assets at December 31, 2020
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Fortis is principally an energy delivery company, with 93% of its assets related to transmission and distribution. The business is characterized by low-risk, stable and predictable earnings and cash flows. Earnings, EPS and TSR are the primary measures of financial performance.

Fortis' regulated utility businesses are: ITC (electric transmission - Michigan, Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma); UNS Energy (integrated electric and natural gas distribution - Arizona); Central Hudson (electric transmission and distribution, and natural gas distribution - New York); FortisBC Energy (natural gas transmission and distribution - British Columbia); FortisAlberta (electric distribution - Alberta); FortisBC Electric (integrated electric - British Columbia); Newfoundland Power (integrated electric - Newfoundland and Labrador); Maritime Electric (integrated electric - Prince Edward Island); FortisOntario (integrated electric - Ontario); Caribbean Utilities (integrated electric - Grand Cayman); and FortisTCI (integrated electric - Turks and Caicos Islands). Fortis also holds equity investments in the Wataynikaneyap Partnership (electric transmission - Ontario) and Belize Electricity (integrated electric - Belize).

Non-regulated energy infrastructure consists of Aitken Creek (natural gas storage facility - British Columbia), BECOL (three hydroelectric generation facilities - Belize) and the Waneta Expansion up to its disposition in April 2019.

Fortis has a unique operating model with a small head office in St. John's, Newfoundland and Labrador and business units that operate on a substantially autonomous basis. Each utility has its own management team and most have a board of directors with a majority of independent members, which provides effective oversight within the broad parameters of Fortis policies and best practices. Subsidiary autonomy supports constructive relationships with regulators, policy makers, customers and communities. Fortis believes this model enhances accountability, opportunity and performance across the Corporation's businesses, and positions Fortis well for future investment opportunities.

Fortis strives to provide safe, reliable and cost-effective energy service to customers using sustainable practices while delivering long-term profitable growth to shareholders. Management is focused on achieving growth through the execution of its capital plan and the pursuit of investment opportunities within and proximate to its service territories.

Additional information about the Corporation's business and reporting units is provided in Note 1 in the 2020 Annual Financial Statements.
MANAGEMENT DISCUSSION AND ANALYSIS
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SIGNIFICANT ITEMS

COVID-19 Pandemic
The Corporation's utilities continue to reliably and safely deliver an essential service during the COVID-19 Pandemic. Developments are continuously monitored with commensurate measures being taken. The Corporation's utilities have assessed supply chain risk and other potential impacts of the pandemic to ensure that they can continue to provide safe, reliable service while supporting public health.

Excluding the impact of the delay in TEP's general rate application (see "Regulatory Highlights" on page 15), the COVID-19 Pandemic did not have a material impact on the Corporation's capital expenditures, revenue or earnings in 2020. The financial impact to Fortis approximated $0.05 per common share and reflected: (i) reduced sales in the Caribbean; and (ii) higher net operational expenses, including increased credit loss expense, largely at Central Hudson and UNS Energy.

Further information regarding the key impact areas for Fortis with respect to the pandemic is summarized below.

Revenue
Energy sales across all of the Corporation's utilities have been impacted by the closure and reopening of non-essential businesses along with stay-at-home orders and other economic impacts related to the COVID-19 Pandemic. Generally, work-from-home practices have resulted in an increase in residential sales while commercial and industrial sales have decreased.

Regulatory mechanisms function to protect approximately 62% of the Corporation's annual revenue from changes in sales. Of the remaining 38%, principally at UNS Energy and the Other Electric segment, approximately 21% is residential and 17% is commercial and industrial. Overall, approximately 83% of revenues are either protected by regulatory mechanisms or derived from residential sales.

Since the start of the COVID-19 Pandemic in 2020, as compared to the same period in 2019, residential electricity sales at UNS Energy increased by 17%, due mainly to warmer temperatures and work-from-home practices. Commercial and industrial electricity sales decreased by 2%, resulting in an overall sales increase of 7%. Excluding weather, retail electricity sales increased 2%.

Sales at the Other Electric segment decreased by 2% since the start of the COVID-19 Pandemic, as compared to the same period in 2019. This was comprised of a 3% increase in residential sales and an 8% decrease in commercial sales, due largely to reduced tourism-related activities in the Caribbean.

Overall, variations in 2020 sales associated with the COVID-19 Pandemic at UNS Energy and the Other Electric segment did not have a material impact on Fortis. While the Corporation does not expect the COVID-19 Pandemic to materially impact Fortis in 2021, the residential and commercial sales mix, particularly for UNS Energy and the Other Electric segment, will continue to be evaluated. Overall, the estimated annual impact on EPS of a 1% change in sales at each of UNS Energy and the Other Electric segment is approximately $0.01.

Capital Expenditures
Capital expenditures were not materially impacted by the COVID-19 Pandemic. Total expenditures of $4.2 billion were broadly consistent with the 2020 capital plan. The Corporation does not expect the COVID-19 Pandemic to impact its overall five-year capital plan, although certain planned expenditures may shift within the five-years depending on the length and severity of the pandemic.

Liquidity
Fortis is well positioned with strong liquidity due, in part, to a $1.2 billion common equity offering and the sale of the Waneta Expansion in 2019. As at December 31, 2020, total consolidated credit facilities were $5.6 billion with $4.3 billion unutilized.

Fortis and its utilities continue to be successful in accessing capital markets. See "Liquidity and Capital Resources" on page 19.


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The economic impact of the COVID-19 Pandemic has affected customers' ability to pay their energy bills with commensurate short-term working capital impacts. The Corporation's utilities have instituted various customer relief initiatives, including the temporary suspension of non-payment disconnects and late fees, delayed customer rate increases and the deferred recovery of costs. The Corporation has seen an increase in accounts receivable and, accordingly, its allowance for credit losses in 2020. While not material to Fortis, UNS Energy and Central Hudson, in particular, experienced an increase in credit loss expense in 2020 associated with slower customer collections largely due to the COVID-19 Pandemic. See Note 6 in the 2020 Annual Financial Statements.

The unfavourable impact on cash flow in 2020 associated with slower collection of customer balances was offset by other changes in Operating Cash Flow (see "Performance at a Glance - Operating Cash Flow" on page 7).

Regulatory Matters
Regulator and other stakeholder work schedule disruptions caused delays and postponements for certain regulatory proceedings in 2020. See "Regulatory Highlights" on page 15. The Corporation's significant regulatory proceedings, as discussed below, were concluded by the end of 2020.

Pension Plans
The Corporation's exposure to changes in pension expense is limited by regulatory mechanisms which cover approximately 80% of defined benefit pension plans. The remaining 20% relates primarily to UNS Energy and its exposure is largely attributable to the use of a historical test year in setting rates.

Based upon pension plan valuations as at December 31, 2020, the change in pension expense at UNS Energy in 2021, as compared to 2020, is not material to Fortis.

Outlook
The continued uncertainty surrounding the evolution of the pandemic makes it difficult to predict the ultimate operational and financial impacts on Fortis. Potential impacts are discussed under "Business Risks" on page 28.

Significant Regulatory Decisions

TEP Rate Order
In December 2020, the ACC issued a rate order on TEP's general rate application establishing new customer rates effective January 1, 2021, including: (i) an increase in non-fuel revenue of $77 million (US$58 million); (ii) an allowed ROE of 9.15%, with a 0.20% return on the fair value increment and a capital structure of 53% common equity; and (iii) a Rate Base of approximately $3.5 billion (US$2.7 billion) which includes post-test year investments in Gila River Unit 2 and 10 RICE Units.

FortisAlberta 2021 GCOC
In October 2020, the AUC concluded the 2021 GCOC proceeding and set the ROE for 2021 at 8.50% using a capital structure of 37% common equity, consistent with 2020.

November 2020 AUC Decision
In November 2020, the AUC issued a decision with respect to the 2018 Independent System Operator Tariff Application reversing proposed changes to the AESO's customer contribution policy. This resulted in FortisAlberta retaining approximately $400 million of unamortized customer contributions in its Rate Base.

See "Regulatory Highlights" on page 15 for further information on these significant regulatory developments.


MANAGEMENT DISCUSSION AND ANALYSIS
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PERFORMANCE AT A GLANCE
Key Financial Metrics
($ millions, except as indicated)2020 2019 Variance
Common Equity Earnings
Actual
1,209 1,655 (446)
Adjusted (1)
1,195 1,115 80 
Basic EPS ($)
Actual
2.60 3.79 (1.19)
Adjusted (1)
2.57 2.55 0.02 
Dividends
Paid per Common Share ($)
1.9375 1.8275 0.11 
Actual Payout Ratio (%)
74.5 48.2 26.3 
Adjusted Payout Ratio (%) (1)
75.4 71.7 3.7 
Weighted Average Number of Common Shares Outstanding (millions)
464.8 436.8 28 
Operating Cash Flow
2,701 2,663 38 
Capital Expenditures (2)
4,177 3,818 359 
(1)See "Non-US GAAP Financial Measures" on page 15
(2)    Includes Fortis' $138 million share of development costs and capital spending for the Wataynikaneyap Transmission Power Project

TSR (1) (%)
1-Year3-Year5-Year10-Year20-Year
Fortis 8.0 10.9 8.3 13.3 
(1)Annualized TSR per Bloomberg, as at December 31, 2020

Earnings and EPS
The $446 million decrease in Common Equity Earnings reflected significant one-time items: (i) a $484 million gain on the disposition of the Waneta Expansion in April 2019; and (ii) the $56 million net impact associated with the reversal of prior period liabilities as a result of the November 2019 and May 2020 FERC decisions at ITC (see "Regulatory Highlights" on page 15).

Excluding the significant one-time items, the Corporation delivered higher earnings of $94 million in 2020 reflecting: (i) Rate Base growth of 8.2%; (ii) increased retail electricity sales at UNS Energy, driven largely by weather; and (iii) higher earnings from Belize, mainly from increased hydroelectric production. Earnings were also favourably impacted by mark-to-market accounting of natural gas derivatives at Aitken Creek which resulted in unrealized losses of $15 million in 2019 compared to unrealized gains of less than $1 million in 2020. This growth was tempered by: (i) the delay in TEP's general rate application, resulting in approximately $1 billion of Rate Base not reflected in customer rates in 2020; and (ii) the impact of the COVID-19 Pandemic, reflecting lower sales in the Caribbean and higher net operational expenses, including increased credit loss expense, largely at Central Hudson and UNS Energy.

In addition to the above-noted items impacting earnings, the change in EPS reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's $1.2 billion common equity issuance in the fourth quarter of 2019.

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Adjusted Common Equity Earnings and Adjusted Basic EPS increased by $80 million and $0.02, respectively. Refer to "Non-US GAAP Financial Measures" on page 15 for a reconciliation of these measures. The changes in Adjusted Basic EPS are illustrated in the chart below.
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(1)    Primarily reflects Rate Base growth and an increase in the base ROE
(2)    FortisBC Energy, FortisBC Electric and FortisAlberta. Primarily reflects Rate Base and customer growth, partially offset by the elimination of the PBR efficiency carry-over mechanism at FortisAlberta
(3)    UNS Energy and Central Hudson. Increase at UNS Energy reflects higher retail sales driven by favourable weather, partially offset by higher costs associated with Rate Base growth not yet reflected in customer rates and higher net operational costs associated with the COVID-19 Pandemic. Increase at Central Hudson reflects Rate Base growth, partially offset by higher net operational expenses associated with the COVID-19 Pandemic.
(4)    Primarily reflects increased hydroelectric production in Belize due to higher rainfall. Excludes the impact of the disposition of the Waneta Expansion, which was neutral on consolidated earnings.
(5)    Primarily reflects higher equity income from Belize Electricity and Rate Base growth, partially offset by the impacts of the COVID-19 Pandemic, particularly in the Caribbean
(6)    Average foreign exchange rate of $1.34 in 2020 compared to $1.33 in 2019
(7)    Weighted average shares of 464.8 million in 2020 compared to 436.8 million in 2019

Dividends and TSR
Fortis paid a dividend of $0.505 per common share in the fourth quarter of 2020, up from $0.4775 paid in each of the previous four quarters.

The total 2020 dividend paid per common share was $1.9375, up $0.11 or 6.0% from 2019 and in line with the Corporation's dividend guidance. The Actual Payout Ratio was 74.5% in 2020 compared to 48.2% in 2019 and an annual average of 65.5% over the five-year period of 2016 through 2020. The lower Actual Payout Ratio in 2019 was driven by the gain on the disposition of the Waneta Expansion.

Fortis has increased its common share dividend for 47 consecutive years. The one-year TSR was flat reflecting market conditions in 2020. Growth of dividends and the market price of the Corporation's common shares have together yielded a three-year, five-year, 10-year and 20-year TSR of 8.0%, 10.9%, 8.3% and 13.3%, respectively.

In September 2020 Fortis extended its targeted average annual dividend growth of approximately 6% through 2025.

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Operating Cash Flow
The $38 million increase in Operating Cash Flow was driven by higher cash earnings reflecting Rate Base growth, higher retail sales and fuel and non-fuel cost recoveries at UNS Energy, and an upfront payment received by FortisAlberta associated with a long-term energy retailer agreement. These were partially offset by: (i) higher transmission cost payments at FortisAlberta; (ii) the timing of recovery of higher gas costs at FortisBC Energy; and (iii) slower collections from customers due to the COVID-19 Pandemic.

Capital Expenditures
Capital expenditures in 2020 were $4.2 billion, $0.4 billion higher than in 2019 and broadly consistent with the 2020 capital plan. For a detailed discussion of the Corporation's capital expenditure program, see "Capital Plan" on page 24.

The Corporation's five-year 2021-2025 capital plan is targeted at $19.6 billion, $0.8 billion higher than the 2020-2024 capital plan of $18.8 billion disclosed in the 2019 MD&A. The increase is largely due to: (i) two new major capital projects at FortisBC Energy including the Tilbury LNG Resiliency Tank project and the AMI project, with total expected capital spend of approximately $500 million; (ii) $200 million of additional investment in information technology systems and storm hardening at Central Hudson; and (iii) $100 million of interconnections and system rebuilds to provide additional capacity and other improvements at ITC.

The Corporation currently does not expect the COVID-19 Pandemic to impact its overall five-year capital plan. Funding of the capital plan is expected to be primarily through Operating Cash Flow, regulated utility debt and common equity from the Corporation's DRIP.

The five-year capital plan is expected to increase midyear Rate Base from $30.5 billion in 2020 to $36.4 billion by 2023 and $40.3 billion by 2025, representing three- and five-year CAGRs of approximately 6.5% and 6.0%, respectively. Fortis expects this growth in Rate Base will support earnings and dividend growth.
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Beyond the five-year capital plan, Fortis continues to pursue additional energy infrastructure opportunities including: further expansion of LNG infrastructure in British Columbia; the fully permitted, cross-border, Lake Erie Connector electric transmission project in Ontario; and the acceleration of cleaner energy infrastructure investments across our jurisdictions.


THE INDUSTRY

The North American energy industry continues to transform. There is an understanding of the impacts of climate change and the need for an energy future with reduced carbon emissions. This creates the need for cleaner energy and energy conservation initiatives to preserve the environment for future generations. The trend toward carbon reduction creates the need for further technological advancements and has heightened customer expectations for cleaner energy. Renewable generation is key to a decarbonized future, with natural gas continuing as a key part of the energy mix. Over the long term, the use of hydrogen may also contribute to carbon reduction. Each of these factors, as well as the increasing affordability of cleaner energy, is driving significant investment opportunity in the utility sector.

Energy policies at the federal, state and provincial levels also reflect the rising focus on climate change, with clean energy and carbon reduction initiatives at the forefront. The regulatory and compliance operating environment is also evolving and becoming increasingly complex. These changes are creating additional opportunities to expand investment in new generation sources, including solar and wind, as well as transmission infrastructure to interconnect renewable energy sources to the grid. Investment opportunities in storage are also growing with the proliferation of various renewable generation sources and decreasing costs of energy storage technology. The electrification of the transportation sector is a significant opportunity for reducing GHG emissions. The Corporation's utilities are well positioned and actively involved in pursuing these opportunities.

New technology is driving change across all service territories. Energy delivery systems are being upgraded with advanced meters, additional grid automation, improved controls and more capable operational technology, providing utilities with detailed usage data. Energy management capabilities are expanding through emerging storage and demand response systems, and customers have been enabled with options to manage and reduce energy usage and access more affordable distributed generation technology. Grid hardening and resiliency technology investments are increasing in importance due to climate volatility resulting from more frequent and severe storms, hurricanes and wildfires.

While some of these new technologies challenge the traditional role of utilities as one-way service providers, they also offer strategic investment opportunities for improving and expanding service. The proliferation of information and operational technology, along with the exponential growth in data and grid interconnections, is driving the need for increased investment in cyber- and physical security systems.

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The COVID-19 Pandemic has created a number of challenges for the industry, including the need for remote and socially-distanced work environments. Technological advances in communications, videoconferencing, and information sharing have enabled Fortis, and the industry, to maintain productivity and safe, reliable service to customers.

Meaningful customer engagement is increasingly important for utilities as customer expectations change and competition for customer attention becomes more intense. Customers want to make informed energy choices and become active participants in the delivery of their energy services. They also expect personalized service, customized service offerings and more real-time, digital communication. Our utilities are capitalizing on this as an investment opportunity to provide enhanced customer information systems and digital technologies to improve customer service.

Fortis is well positioned to capitalize on evolving industry opportunities. Its decentralized structure and customer-focused business culture support the efforts required to meet changing customer expectations, to work with regulators on energy and service solutions, and to be an industry leader in clean energy. Fortis' culture of innovation underlies a continuous drive to find a better way to safely, reliably and affordably deliver the energy and services that customers want and need. To further advance innovation, Fortis is a strategic partner in the Energy Impact Partners utility coalition, which is a strategic private equity fund that invests in emerging technologies, products, services and business models that are transforming the industry. By leveraging these strengths and partnerships, Fortis expects to remain at the forefront of this ever-changing industry.


OPERATING RESULTS
Variance
($ millions)2020 2019 
FX
Other
Revenue8,935 8,783 59 93 
Energy Supply Costs2,562 2,520 14 28 
Operating Expenses2,437 2,452 19 (34)
Depreciation and Amortization1,428 1,350 70 
Gain on Disposition 577 — (577)
Other Income, Net154 138 (2)18 
Finance Charges1,042 1,035 (1)
Income Tax Expense231 289 — (58)
Net Earnings1,389 1,852 (471)
Net Earnings Attributable to:
Non-Controlling Interests
115 130 (16)
Preference Equity Shareholders
65 67 — (2)
Common Equity Shareholders
1,209 1,655 (453)
Net Earnings1,389 1,852 (471)

Revenue
The increase in revenue was due primarily to: (i) overall higher flow-through costs in customer rates; (ii) Rate Base growth; (iii) higher retail electricity sales driven by favourable weather in Arizona; and (iv) a $40 million favourable base ROE adjustment at ITC related to prior periods as a result of the May 2020 FERC decision. The increase was partially offset by: (i) a $91 million favourable base ROE adjustment at ITC in 2019 related to prior periods as a result of the November 2019 FERC decision; and (ii) lower short-term wholesale sales at UNS Energy. See "Regulatory Highlights" on page 15 for further details on the November 2019 and May 2020 FERC decisions.

Energy Supply Costs
The increase in energy supply costs was due primarily to overall higher commodity costs, partially offset by the impact of lower wholesale sales at UNS Energy.


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Operating Expenses
The decrease in operating expenses was due primarily to: (i) lower recoverable operating expenses at ITC due to temporary cost saving measures implemented in response to the COVID-19 Pandemic; and (ii) lower flow-through costs at TEP associated with Springerville Units 3 and 4. The decrease was partially offset by higher operating expenses at Central Hudson associated with general inflationary increases and storm events. UNS Energy and Central Hudson also had higher expenses in 2020 related to the COVID-19 Pandemic including an increase in credit loss expense.

Depreciation and Amortization
The increase in depreciation and amortization was due to continued investment in energy infrastructure at the Corporation's regulated utilities.

Gain on Disposition
The gain recorded in 2019 reflects the April 2019 disposition of the Waneta Expansion.

Other Income, Net
The increase in other income, net was due primarily to: (i) higher equity income from Belize Electricity; and (ii) the impact of non-service pension costs, partially offset by; (iii) an $11 million gain recognized in 2019 on the repayment of US$400 million of debt via tender offer.

Finance Charges
Finance charges were comparable to 2019. An increase in finance charges associated with continued capital investment was offset mainly by lower finance charges at Corporate due to the repayment of debt in 2019 using proceeds from the Waneta Expansion disposition and the $1.2 billion common equity offering.

Income Tax Expense
The decrease in income tax expense was driven by tax recorded in 2019 upon the disposition of the Waneta Expansion, partially offset by the impact of higher valuation allowances released in 2019.

Net Earnings
See "Performance at a Glance - Earnings and EPS" on page 5.


BUSINESS UNIT PERFORMANCE
Common Equity Earnings
Variance
($ millions)2020 2019 
FX (1)
Other
Regulated Utilities
ITC449 471 (30)
UNS Energy302 292 
Central Hudson91 85 — 
FortisBC Energy175 165 — 10 
FortisAlberta133 131 — 
FortisBC Electric56 54 — 
Other Electric (2)
112 106 — 
1,318 1,304 12 
Non-Regulated
Energy Infrastructure (3)
39 18 — 21 
Corporate and Other (4)
(148)333 (5)(476)
Common Equity Earnings1,209 1,655 (453)
(1)The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI and BECOL is the US dollar. The reporting currency of Belize Electricity is the Belizean dollar, which is pegged to the US dollar at BZ$2.00=US$1.00. The Corporate and Other segment includes certain transactions denominated in US dollars.
(2)Consists of the utility operations in eastern Canada and the Caribbean: Newfoundland Power; Maritime Electric; FortisOntario; Caribbean Utilities; FortisTCI; and Belize Electricity
(3)Primarily consists of long-term contracted generation assets in Belize, Aitken Creek in British Columbia and, until its April 16, 2019 disposition, the Waneta Expansion
(4)Includes Fortis net corporate expenses and non-regulated holding company expenses

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ITCVariance
($ millions)2020 2019 FXOther
Revenue (1)
1,744 1,761 22 (39)
Earnings (1)
449 471 (30)
(1)Revenue represents 100% of ITC. Earnings represent the Corporation's 80.1% controlling ownership interest in ITC and reflect consolidated purchase price accounting adjustments.

Revenue
The decrease in revenue, net of foreign exchange, was due primarily to: (i) a $91 million favourable base ROE adjustment recorded in 2019 related to prior periods as a result of the November 2019 FERC decision; and (ii) lower recoverable operating expenses due to cost saving measures implemented in response to the COVID-19 Pandemic. The decrease was partially offset by: (i) a $40 million favourable base ROE adjustment recorded in 2020 related to prior periods as a result of the May 2020 FERC decision; (ii) Rate Base growth; and (iii) an increase in the base ROE compared to 2019.

Earnings
The decrease in earnings, net of foreign exchange, was due to significant one-time items related to the reversal of prior period liabilities as a result of the base ROE decisions made by FERC in November 2019 and May 2020. The year over year impact of these one-time items was $56 million reflecting the net of: (i) an $83 million favourable adjustment in 2019; and (ii) a $27 million favourable adjustment in 2020. Excluding this impact, earnings from ITC grew by $26 million in 2020 reflecting growth in Rate Base, an increase in the base ROE compared to 2019, and lower business development costs.

See "Regulatory Highlights" on page 15 for further information on the November 2019 and May 2020 FERC decisions.

UNS EnergyVariance
2020 2019 FXOther
Retail electricity sales (GWh)
10,920 10,431 — 489 
Wholesale electricity sales (GWh) (1)
5,843 7,923 — (2,080)
Gas sales (PJ)
15 16 — (1)
Revenue ($ millions)
2,260 2,212 24 24 
Earnings ($ millions)
302 292 
(1)    Primarily short-term wholesale sales

Sales
The increase in retail electricity sales was due primarily to higher air conditioning load as a result of warmer temperatures in 2020 as compared to unseasonably cool temperatures in 2019. The COVID-19 Pandemic has not had a material impact on sales as the decrease in consumption by commercial and industrial customers, due to the temporary closure of non-essential businesses, was offset by an increase in consumption by residential customers, due to work-from-home practices.

The decrease in wholesale electricity sales was due primarily to the expiration of a short-term capacity sales transaction, which was established to offset costs associated with a Gila River Unit 2 tolling PPA during 2019. The capacity sales transaction ended in December 2019 with the purchase of Gila River Unit 2. Revenue from short-term wholesale sales is primarily credited to customers through regulatory deferral mechanisms and, therefore, does not materially impact earnings.

Gas sales were comparable to 2019.

Revenue
The increase in revenue, net of foreign exchange, was due primarily to higher revenue related to the recovery of fuel and non-fuel costs through the normal operation of regulatory mechanisms and higher retail sales mainly driven by weather. The increase was partially offset by lower short-term wholesale sales and a decrease in flow-through costs related to Springerville Units 3 and 4.

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Earnings
The increase in earnings, net of foreign exchange, was due primarily to higher retail electricity sales, partially offset by higher costs associated with Rate Base growth not reflected in customer rates in 2020. Beginning January 1, 2021, new customer rates are in effect following the conclusion of TEP's general rate application (see "Regulatory Highlights" on page 15). Higher net operational expenses associated with the COVID-19 Pandemic, including an increase in credit loss expense, also unfavourably impacted earnings.

Central HudsonVariance
2020 2019 FXOther
Electricity sales (GWh)
4,969 4,963 — 
Gas sales (PJ)
23 22 — 
Revenue ($ millions)
953 917 27 
Earnings ($ millions)
91 85 — 

Sales
Electricity sales were comparable to 2019. Higher average consumption by residential customers was largely offset by lower average consumption by commercial customers, both as a result of the COVID-19 Pandemic.

Gas sales were comparable to 2019.

Changes in electricity and gas sales at Central Hudson are subject to regulatory revenue decoupling mechanisms and, therefore, do not materially impact earnings.

Revenue
The increase in revenue, net of foreign exchange, was due primarily to an increase in gas and electricity delivery rates effective July 1, 2019 and July 1, 2020, reflecting a return on increased Rate Base assets as well as the recovery of higher operating and financing expenses (see "Regulatory Highlights" on page 15 for information on the July 1, 2020 rate increase). The increase was partially offset by the flow through of lower energy supply costs.

Earnings
The increase in earnings was due primarily to Rate Base growth, partially offset by higher net operational expenses associated with the COVID-19 Pandemic, including an increase in credit loss expense.

FortisBC Energy2020 2019 Variance
Gas sales (PJ)
219 227 (8)
Revenue ($ millions)
1,385 1,331 54 
Earnings ($ millions)
175 165 10 

Sales
The decrease in gas sales was due primarily to lower consumption by transportation customers, partially offset by higher consumption from residential customers, due partly to work-from-home practices as a result of the COVID-19 Pandemic.

Revenue
The increase in revenue was due primarily to a higher cost of natural gas to be recovered from customers and Rate Base growth.

Earnings
The increase in earnings was due primarily to Rate Base growth.

FortisBC Energy earns approximately the same margin regardless of whether a customer contracts for the purchase and delivery of natural gas or only for delivery. Due to regulatory deferral mechanisms, changes in consumption levels and commodity costs do not materially impact earnings.

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FortisAlberta2020 2019 Variance
Electricity deliveries (GWh)
16,092 16,887 (795)
Revenue ($ millions)
596 598 (2)
Earnings ($ millions)
133 131 

Deliveries
The decrease in electricity deliveries was due to lower average consumption by oil and gas and commercial customers, largely associated with the COVID-19 Pandemic and the downturn in the oil and gas sector. The decrease was partially offset by customer additions and higher average consumption by residential customers reflecting work-from-home practices as a result of the COVID-19 Pandemic.

As more than 85% of FortisAlberta's revenue is derived from fixed or largely fixed billing determinants, changes in quantities of energy delivered are not entirely correlated with changes in revenue. Revenue is a function of numerous variables, many of which are independent of actual energy deliveries.

Revenue
The decrease in revenue was due primarily to: (i) the impact of the AUC's November 2020 decision with respect to the 2018 Independent System Operator Tariff Application reflecting the flow through of lower depreciation costs with no material impact on earnings (see "Regulatory Highlights" on page 15); and (ii) the recognition of revenue in 2019 associated with the PBR efficiency carry-over mechanism. The decrease was partially offset by Rate Base growth and customer additions.

Earnings
The increase in earnings was due primarily to Rate Base growth, customer additions and a lower deferred tax expense due to the utilization of tax loss carryforwards in 2019. The increase was partially offset by higher operating expenses and the impact of the PBR efficiency carry-over mechanism.

FortisBC Electric2020 2019 Variance
Electricity sales (GWh)
3,291 3,326 (35)
Revenue ($ millions)
424 418 
Earnings ($ millions)
56 54 

Sales
The decrease in electricity sales was due to lower average consumption by commercial and industrial customers, partially offset by higher average residential consumption, both due to the impact of the COVID-19 Pandemic.

Revenue
The increase in revenue was due primarily to higher third-party contract work and Rate Base growth, partially offset by the absence of revenue associated with the provision of operating, maintenance and management services to the Waneta Expansion, which was sold in April 2019.

Earnings
The increase in earnings was due primarily to Rate Base growth, partially offset by the sale of the Waneta Expansion, discussed above.

Due to regulatory deferral mechanisms, changes in consumption levels do not materially impact earnings.


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Other ElectricVariance
2020 2019 FXOther
Electricity sales (GWh)
9,175 9,366 — (191)
Revenue ($ millions)
1,485 1,467 14 
Earnings ($ millions)
112 106 — 

Sales
The decrease in electricity sales was due primarily to overall lower average consumption driven by the COVID-19 Pandemic, largely reflecting the temporary closure of non-essential businesses and border closures affecting tourism-related sales in the Caribbean.

Revenue
The increase in revenue, net of foreign exchange, was due primarily to the flow through of overall higher energy supply costs and Rate Base growth, partially offset by lower sales.

Earnings
The increase in earnings was due to higher equity income from Belize Electricity and Rate Base growth, partially offset by the impact of the COVID-19 Pandemic, largely reflecting lower sales in the Caribbean.

Energy Infrastructure2020 2019 Variance
Electricity sales (GWh)
229 144 85 
Revenue ($ millions)
88 82 
Earnings ($ millions)
39 18 21 

Sales
The increase in electricity sales reflected increased hydroelectric production in Belize due to higher rainfall levels, partially offset by the Waneta Expansion disposition in 2019, which contributed sales of 80 GWh in that year.

Revenue and Earnings
The increases in revenue and earnings reflected: (i) higher hydroelectric production in Belize; and (ii) the favourable impact of mark-to-market accounting of natural gas derivatives at Aitken Creek which resulted in unrealized losses of $15 million in 2019 compared to unrealized gains of less than $1 million in 2020. The increases in revenue and earnings were partially offset by the Waneta Expansion disposition in 2019.

Aitken Creek is subject to commodity price risk, as it purchases and holds natural gas in storage to earn a profit margin from its ultimate sale. Aitken Creek mitigates this risk by using derivatives to materially lock in the profit margin that will be realized upon the sale of natural gas. The fair value accounting of these derivatives creates timing differences and the resultant earnings volatility can be significant.

Corporate and OtherVariance
($ millions)2020 2019 FXOther
Net (expenses) income (148)333 (5)(476)

The increase in net expenses was due to one-time items: (i) the net after-tax gain of $484 million on the April 2019 disposition of the Waneta Expansion; and (ii) a $7 million gain on the repayment of debt recognized in 2019. Excluding these one-time items, Corporate expenses, net of foreign exchange, decreased by $10 million. The decrease was driven by lower finance charges, due to the repayment of debt using proceeds from the Waneta Expansion disposition and the $1.2 billion common equity offering, and lower operating expenses, partially offset by an increase in tax expense due to valuation allowances released in 2019.

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NON-US GAAP FINANCIAL MEASURES

Adjusted Common Equity Earnings, Adjusted Basic EPS and Adjusted Payout Ratio are Non-US GAAP Financial Measures and may not be comparable with similar measures used by other entities. They are presented because management and external stakeholders use them in evaluating the Corporation's financial performance and prospects.

Net earnings attributable to common equity shareholders (i.e., Common Equity Earnings) and basic EPS are the most directly comparable US GAAP measures to Adjusted Common Equity Earnings and Adjusted Basic EPS, respectively. The Actual Payout Ratio calculated using Common Equity Earnings is the most comparable US GAAP measure to the Adjusted Payout Ratio.

Adjusted Common Equity Earnings and Adjusted Basic EPS reflect the removal of items that management excludes in its key decision-making processes and evaluation of operating results, and are reconciled as follows.

Non-US GAAP Reconciliation
($ millions, except as shown)2020 2019 Variance
Common Equity Earnings1,209 1,655 (446)
Adjusting items:
FERC base ROE decisions (1)
(27)(83)56 
US tax reform (2)
13 12 
Unrealized loss on mark-to-market of derivatives (3)
 15 (15)
Gain on disposition (4)
 (484)484 
Adjusted Common Equity Earnings1,195 1,115 80 
Adjusted Basic EPS ($)
2.57 2.55 0.02 
(1)    Represents prior period impacts of the May 2020 and November 2019 FERC base ROE decisions, respectively (see "Regulatory Highlights" below), included in the ITC segment
(2)    The finalization of US tax reform regulations associated with anti-hybrid regulations in 2020 and base-erosion and anti-abuse tax in 2019, included in the Corporate and Other segment
(3)    Represents timing differences related to the accounting of natural gas derivatives at Aitken Creek, included in the Energy Infrastructure segment
(4)    Gain on sale of the Waneta Expansion, net of expenses, in April 2019, included in the Corporate and Other segment


REGULATORY HIGHLIGHTS

General

The earnings of the Corporation's regulated utilities are determined under COS Regulation, with some using PBR mechanisms.

Under COS Regulation, the regulator sets customer rates to permit a reasonable opportunity for the timely recovery of the estimated costs of providing service, including a fair rate of return on a regulatory deemed or targeted capital structure applied to an approved Rate Base. PBR mechanisms generally apply a formula that incorporates inflation and assumed productivity improvements for a set term.

The ability to recover prudently incurred costs of providing service and earn the regulator‑approved ROE or ROA generally depends on achieving the forecasts established in the rate-setting process. There can be varying degrees of regulatory lag between when costs are incurred and when they are reflected in customer rates.

Transmission operations in the US are regulated federally by FERC. Remaining utility operations in the US and Canada are regulated by state or provincial regulators. Utility operations in the Caribbean are regulated by governmental authorities.

Additional information about regulation and the regulatory matters discussed below is provided in Note 2 in the 2020 Annual Financial Statements. Also refer to "Business Risks - Regulation" on page 28.
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COVID-19 Pandemic Impacts
The COVID-19 Pandemic resulted in several customer relief initiatives as well as the delay and postponement of several regulatory proceedings in 2020, as described below. The Corporation's significant regulatory proceedings, including TEP's general rate application as well as FortisAlberta's 2021 GCOC and AESO customer contribution proceedings, were concluded by the end of 2020.

Customer Relief Initiatives

UNS Energy
Pursuant to the ACC's approval of the utility's customer relief initiatives, TEP refunded to customers approximately $11 million of collected demand side management funds in excess of program costs.

In December 2020, the ACC enacted a bill credit and payment program for residential electric customers who are behind on their electric bills as a result of the COVID-19 Pandemic, including automatic enrollment into an eight-month payment plan for qualified customers. TEP voluntarily created payment arrangements for commercial customers.

Central Hudson
In March 2020, as agreed with the PSC, Central Hudson postponed the collection in customer rates of approximately $4 million of deferred costs related mainly to environmental remediation until July 1, 2021.

FortisBC Energy and FortisBC Electric
In April 2020, pursuant to the BCUC's approval of the utilities' customer relief initiatives, FortisBC Energy and FortisBC Electric implemented three-month bill deferrals for certain customer classes, the repayment of which commenced in the third quarter of 2020. The BCUC also authorized the deferral of otherwise uncollectible revenue from customers, the recovery of which will be determined through a future rate filing once the financial impact of the pandemic is known.

Delayed and Postponed Regulatory Proceedings

UNS Energy
General Rate Application: TEP filed a rate application in April 2019 based on a 2018 test year. In December 2020 the ACC issued a rate order including new customer rates effective January 1, 2021. Provisions of the order include: (i) an increase in non-fuel revenue of $77 million (US$58 million); (ii) an allowed ROE of 9.15%, with a 0.20% return on the fair value increment and a capital structure of 53% common equity; and (iii) a Rate Base of approximately $3.5 billion (US$2.7 billion) which includes post-test year investments in Gila River Unit 2 and 10 RICE Units.

Central Hudson
2020 Rates: In June 2020, the PSC approved Central Hudson's request to postpone scheduled electric and gas delivery rate increases, reflecting an increase in the equity component of its capital structure from 49% to 50%, from July 1, 2020 to October 1, 2020. The deferred revenue associated with the delay is being collected over the nine-month period to June 30, 2021.

COVID-19 Proceeding: In June 2020, the PSC initiated a generic proceeding to identify and address the effects of the COVID-19 Pandemic. The outcome of this proceeding and potential impacts, if any, are unknown at this time.

FortisAlberta
Generic Cost of Capital Proceeding: In December 2018, the AUC initiated a GCOC proceeding to consider a formula-based approach to setting the allowed ROE beginning in 2021 and whether any process changes were necessary for determining capital structure in years in which a ROE formula is in place. In October 2020, given the time that had passed since initiation of the proceeding and ongoing economic uncertainty, the AUC concluded the proceeding and set the ROE for 2021 at 8.50% using a capital structure of 37% common equity, consistent with 2020. In December 2020, the AUC initiated a new GCOC proceeding to establish the cost of capital parameters for 2022 and possibly one or more future years. This proceeding is expected to be ongoing throughout 2021.


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Other Electric
Caribbean Utilities: In August 2020, the Utility Regulation and Competition Office approved the postponement of Caribbean Utilities' scheduled June 1, 2020 annual rate adjustment to January 1, 2021 to provide customer relief from the economic effects of the COVID-19 Pandemic. The deferred revenue associated with the delay is being collected over a two-year period beginning January 2021.

FortisTCI: In February 2020, the Government of the Turks and Caicos Islands approved a 6.8% average increase in FortisTCI's electricity rates, effective April 1, 2020, including the recovery of hurricane-related costs incurred in 2017. In March 2020, to provide customer relief from the economic effects of the COVID-19 Pandemic, the effective date was postponed and new rates became effective July 22, 2020.

FortisTCI sought regulatory approval to defer its incremental operating expenses associated with the COVID-19 Pandemic. Approval was granted in December 2020 to allow the deferral of approximately $1.5 million in costs, to be amortized over the remaining 15-year life of FortisTCI's licence.

Significant Regulatory Developments

ITC
ROE Complaints: In May 2020, FERC issued an order on the rehearing of its November 2019 decision on the MISO transmission owner ROE complaints and set the base ROE for the periods from November 2013 through February 2015 and from September 2016 onward at 10.02%, up to a maximum of 12.62% with incentive adders. This represents an increase from the base ROE of 9.88%, up to a maximum of 12.24% with incentive adders, determined in FERC's November 2019 decision. Including incentive adders, the May 2020 FERC decision implies an all-in ROE for ITC's subsidiaries operating in the MISO region of 10.77%, up from 10.63% as set in the November 2019 decision.

Net regulatory liabilities of $6 million and $91 million were recorded at December 31, 2020 and 2019, respectively, reflecting: (i) the terms of the May 2020 and November 2019 decisions; and (ii) $42 million refunded to customers in 2020. The May 2020 FERC decision resulted in an increase in Fortis' net earnings of $29 million in 2020, including $27 million related to the reversal of liabilities established in prior periods (2019 - November 2019 FERC decision increased Fortis' net earnings by $63 million, including $83 million related to the reversal of liabilities established in prior periods).

Review of Transmission Incentives Policy: In March 2020, FERC issued a NOPR proposing to update its transmission incentives policy for transmission owners, including ITC, to grant incentives to projects based upon benefits to customers regarding reliability and cost savings through the reduction of transmission congestion. FERC proposed total ROE incentives of up to 250 basis points that would not be limited by the upper end of the base ROE zone of reasonableness. The NOPR also proposed, among other things, to eliminate the ROE adder for independent transmission ownership, and to increase the ROE adder for regional transmission owner participation. Comments from stakeholders, including ITC, were provided to FERC through July 2020. The outcome of these proceedings may impact future incentive adders that are included in transmission rates charged by transmission owners, including ITC.

Central Hudson
General Rate Application: In August 2020, Central Hudson filed a rate application with the PSC requesting an increase in electric and natural gas delivery revenue of $44 million and $19 million, respectively, effective July 1, 2021. An order from the PSC is expected in 2021.

FortisBC Energy and FortisBC Electric
Multi-Year Rate Plan Applications: In June 2020, the BCUC issued a decision on FortisBC Energy's and FortisBC Electric's MRP for 2020 to 2024. The decision sets the rate-setting framework for the five-year period including: (i) the level of operation and maintenance expense and growth capital to be included in customer rates, indexed for inflation less a fixed productivity adjustment factor; (ii) a forecast approach to sustainment capital; (iii) an innovation fund recognizing the need to accelerate investment in clean energy innovation; and (iv) a 50/50 sharing between customers and the utilities of variances from the allowed ROE. In the fourth quarter of 2020, the BCUC approved: (i) the January 1, 2020 delivery rate increase; and (ii) an increase in 2021 delivery rates, effective January 1, 2021, reflecting the terms of this decision.

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Generic Cost of Capital Proceeding: In January 2021, the BCUC issued a notice that a GCOC proceeding will be initiated in the second quarter of 2021 and will include a review of the common equity component of capital structure and the allowed ROE effective January 1, 2022.

FortisAlberta
2018 Independent System Operator Tariff Application: In September 2019, the AUC issued a decision that addressed, among other things, a proposal to change how the AESO's customer contribution policy ("ACCP") is accounted for between distribution facility owners, such as FortisAlberta, and TFOs. The decision prevented any future investment by FortisAlberta under the policy and directed unamortized customer contributions of approximately $400 million as at December 31, 2017, which form part of FortisAlberta's Rate Base, be transferred to the incumbent TFO in FortisAlberta's service area.

In November 2020, the AUC issued a decision: (i) reversing the proposed changes to the ACCP resulting in FortisAlberta retaining its unamortized customer contributions; and (ii) directing a change in the depreciation rate for AESO contributions to reflect the parameters of the underlying transmission facilities. FortisAlberta has adjusted the estimated service life and the associated depreciation rate of the unamortized AESO contributions resulting in a decrease in depreciation expense and an associated decrease in revenue in 2020.

The AUC initiated a new proceeding in November 2020 to consider whether the ACCP should be modified on a prospective basis. A decision is expected in the second quarter of 2021.


FINANCIAL POSITION
Significant Changes between December 31, 2020 and 2019
Increase (Decrease)
FXOther
Balance Sheet Account($ millions)($ millions)Explanation
Cash and cash equivalents(3)(118)Related to the timing of debt and equity issuances, and the related reinvestment in capital and operating requirements.
Regulatory assets (current and long-term)(25)230Due primarily to deferred income taxes, and the operation of energy management cost and employee future benefits deferrals, partially offset by lower derivative loss deferrals at UNS Energy.
Property, plant and equipment, net
(425)2,435Due to capital expenditures, partially offset by depreciation.
Goodwill
(212)

Short-term borrowings
(10)(370)Reflects the repayment of short-term borrowings at UNS Energy and commercial paper at ITC.
Other liabilities(16)169
Reflects employee future benefits, refundable deposits received by ITC for transmission network upgrades, and an upfront payment received by FortisAlberta associated with a long-term energy retailer agreement.
Regulatory liabilities (current and long-term)(48)(207)Due to ROE complaints liability at ITC, deferred income taxes, and the normal operation of rate stabilization and related accounts.
Deferred income tax liabilities
(34)409Due to higher temporary differences associated with ongoing capital investment.
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Significant Changes between December 31, 2020 and 2019
Increase (Decrease)
FXOther
Balance Sheet Account($ millions)($ millions)Explanation
Long-term debt (including current portion)
(296)2,472Reflects debt issuances, partially offset by debt repayments at the regulated utilities, largely at ITC and UNS Energy.
Shareholders' equity

(279)445Due primarily to: (i) Common Equity Earnings for 2020, less dividends declared on common shares; and (ii) the issuance of common shares.


LIQUIDITY AND CAPITAL RESOURCES

CASH FLOW REQUIREMENTS

At the subsidiary level, it is expected that operating expenses and interest costs will be paid from Operating Cash Flow, with varying levels of residual cash flow available for capital expenditures and/or dividend payments to Fortis. Capital expenditures are expected to be financed primarily from borrowings under credit facilities, long-term debt offerings and equity injections from Fortis. Borrowings under credit facilities may be required periodically to support seasonal working capital requirements and there could be higher-than-normal working capital deficiencies in the short term, as the ongoing impacts of the COVID-19 Pandemic affects customers' ability to pay their energy bills. See "Business Risks" on page 28.

Cash required of Fortis to support subsidiary growth is generally derived from borrowings under the Corporation's committed credit facility, proceeds from the DRIP and issuances of common shares, preference equity and long-term debt. The subsidiaries pay dividends to Fortis and receive equity injections from Fortis when required. Both Fortis and its subsidiaries initially borrow through their committed credit facilities and periodically replace these borrowings with long-term debt. Financing needs also arise periodically for acquisitions and to refinance maturing debt.

Although Fortis and its utilities continue to be successful in accessing capital markets, the ability to access cash through capital markets may be impacted by the COVID-19 Pandemic.

Credit facilities are syndicated primarily with large banks in Canada and the US, with no one bank holding more than approximately 25% of the total facilities. Approximately $5.3 billion of the total credit facilities are committed with maturities ranging from 2021 through 2025. Available credit facilities are summarized in the following table.

Credit Facilities
As at December 31RegulatedCorporate
($ millions)
Utilities
and Other
20202019 
Total credit facilities (1)
3,700 1,881 5,581 5,590 
Credit facilities utilized:
Short-term borrowings
(132)— (132)(512)
Long-term debt (including current portion)
(714)(266)(980)(640)
Letters of credit outstanding(77)(53)(130)(114)
Credit facilities unutilized2,777 1,562 4,339 4,324 
(1)Additional information about these credit facilities is provided in Note 14 in the 2020 Annual Financial Statements.


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The Corporation's ability to service debt and pay dividends is dependent on the financial results of, and the related cash payments from, its subsidiaries. Certain regulated subsidiaries are subject to restrictions that limit their ability to distribute cash to Fortis, including restrictions by certain regulators limiting annual dividends and restrictions by certain lenders limiting debt to total capitalization. There are also practical limitations on using the net assets of the regulated subsidiaries to pay dividends, based on management's intent to maintain the subsidiaries' regulator-approved capital structures. Fortis does not expect that maintaining such capital structures will impact its ability to pay dividends in the foreseeable future.

As at December 31, 2020, consolidated fixed-term debt maturities/repayments are expected to average $891 million annually over the next five years and approximately 81% of the Corporation's consolidated long-term debt, excluding credit facility borrowings, had maturities beyond five years.

In December 2020, Fortis filed a short-form base shelf prospectus with a 25-month life under which it may issue common or preference shares, subscription receipts or debt securities in an aggregate principal amount of up to $2.0 billion. As at December 31, 2020, $2.0 billion remained available under the short-form base shelf prospectus.

Fortis is well positioned with strong liquidity due, in part, to its $1.2 billion common equity offering and sale of the Waneta Expansion in 2019. See "Cash Flow Summary - Financing Activities" on page 20.

This combination of available credit facilities and manageable annual debt maturities/repayments provides flexibility in the timing of access to capital markets. Given current credit ratings and capital structures, the Corporation and its subsidiaries currently expect to continue to have reasonable access to long-term capital in 2021.

Fortis and its subsidiaries were in compliance with debt covenants as at December 31, 2020 and are expected to remain compliant in 2021.


CASH FLOW SUMMARY
Summary of Cash Flows
Years ended December 31
($ millions)
2020 2019 
Variance
Cash, beginning of year
370 332 38 
Cash provided from (used in):
Operating activities
2,701 2,663 38 
Investing activities
(4,132)(2,768)(1,364)
Financing activities
1,327 154 1,173 
Effect of exchange rate changes on cash and cash equivalents
(17)(26)
Cash and change in cash associated with assets held for sale
 15 (15)
Cash, end of year
249 370 (121)

Operating Activities
See "Performance at a Glance - Operating Cash Flow" on page 7.

Investing Activities
Cash used in investing activities reflects higher capital expenditures in 2020. See "Performance at a Glance - Capital Expenditures" on page 7 and "Capital Plan" on page 24. Cash used in investing activities in 2019 was partially offset by proceeds from the Waneta Expansion disposition.

Financing Activities
Cash flow related to financing activities will fluctuate largely as a result of changes in the subsidiaries' capital expenditures and the amount of Operating Cash Flow available to fund those capital expenditures, which together impact the amount of funding required from debt and common equity issuances. See "Cash Flow Requirements" on page 19.

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In the fourth quarter of 2019, the Corporation issued approximately 22.8 million common shares at a price of $52.15 per share for gross proceeds of $1,190 million ($1,167 million net of commissions). The net proceeds were used to redeem US$500 million of its outstanding 2.10% unsecured senior notes due October 4, 2021, to repay credit facility borrowings and for general corporate purposes. Also in 2019, net proceeds of $995 million from the April 2019 Waneta Expansion disposition were used to repay credit facility borrowings and repurchase, via a tender offer, US$400 million of its outstanding 3.055% unsecured senior notes due in 2026.

Debt Financing

Long-Term Debt Issuances
Month Issued
Interest Rate
(%)
MaturityAmountUse of Proceeds
Year ended December 31, 2020

($ millions, except %)
ITC
Unsecured term loan credit agreementJanuary
(1)
2021US75 
(2)(3)
Unsecured term loan credit agreement (4)
January
(5)
2021US200 
(4)
Unsecured senior notesMay2.95 2030US700 
(2)(3)(6)
First mortgage bonds
July3.13 2051US180 
(2)(3)(7)
Secured senior notesOctober3.02 2055US150 
 (2)(3)(7)(8)
UNS Energy
Unsecured senior notesApril4.00 2050US350 
(2)(3)
Unsecured senior notesAugust1.50 2030US300 
(7)
Unsecured senior notesSeptember2.17 2032US50 
(2)(3)
Central Hudson
Unsecured senior notesMay3.42 2050US30 
(3)
Unsecured senior notesJuly3.62 2060US30 
(3)(7)
Unsecured senior notesSeptember2.03 2030US40 
(8)
Unsecured senior notesNovember2.03 2030US30 
(3)(7)
FortisBC Energy
Unsecured debentures
July2.54 2050200 
(7)
FortisAlberta
Unsecured senior debenturesDecember2.63 2051175 
(2)
FortisBC Electric
Unsecured debentures
May3.12 205075 
(2)
Newfoundland Power
First mortgage sinking fund bondsApril3.61 2060100 
(2)(3)
FortisTCI
Unsecured senior notesJune/October5.30 2035US30 
(7)(8)
Unsecured senior notesOctober/December3.25 2030US10 
(3)

(1)    Floating rate of a one-month LIBOR plus a spread of 0.45%
(2)    Repay credit facility borrowings
(3)    General corporate purposes
(4)    Maximum amount of borrowings under this agreement of US$400 million has been drawn; current period borrowings were used to repay an outstanding commercial paper balance.
(5)    Floating rate of a two-month LIBOR plus a spread of 0.60%
(6)    Early redemption of unsecured term loan borrowing of US$400 million
(7)    Finance capital expenditures
(8)    Repay maturing long-term debt

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Common Equity Financing
Common Equity Issuances and Dividends Paid
Years ended December 31
($ millions, except as indicated)2020 2019 Variance
Common shares issued:
Cash (1)
58 1,442 (1,384)
Non-cash (2)
116 314 (198)
Total common shares issued174 1,756 (1,582)
Number of common shares issued (# millions)
3.5 34.8 (31.3)
Common share dividends paid:
Cash
(786)(494)(292)
Non-cash (3)
(114)(299)185 
Total common share dividends paid
(900)(793)(107)
Dividends paid per common share ($)
1.93751.8275 0.1100 
(1)    Includes common shares issued under stock option and employee share purchase plans. For 2019, mainly reflects the issuance of shares in December 2019 and through the ATM Program.
(2)    Common shares issued under the DRIP and stock option plan. Effective March 1, 2020, the 2% discount offered on common share issuances under the DRIP was terminated and effective December 1, 2020 was reinstated. See "Cash Flow Requirements" on page 19 for further information.
(3)    Common share dividends reinvested under the DRIP

On February 11, 2021, Fortis declared a dividend of $0.505 per common share payable on June 1, 2021. The payment of dividends is at the discretion of the board of directors and depends on the Corporation's financial condition and other factors.

CONTRACTUAL OBLIGATIONS
Contractual Obligations
As at December 31, 2020
Due
($ millions)TotalYear 1Year 2Year 3Year 4Year 5Thereafter
Long-term debt:
Principal (1)
24,514 1,254 823 1,786 1,088 484 19,079 
Interest
16,113 980 949 919 859 824 11,582 
Finance leases (2)
1,225 33 34 34 34 34 1,056 
Other obligations
557 184 112 97 37 37 90 
Other commitments: (3)
Waneta Expansion capacity agreement2,576 52 53 54 55 56 2,306 
Gas and fuel purchase obligations 2,355 679 453 312 192 124 595 
Power purchase obligations1,867 249 208 188 191 180 851 
Renewable PPAs1,380 102 102 101 101 101 873 
ITC easement agreement 381 13 13 13 13 13 316 
Debt collection agreement 112 97 
Renewable energy credit purchase agreements97 15 14 16 36 
Other116 48 52 
51,293 3,612 2,769 3,527 2,586 1,866 36,933 
(1)Amounts not reduced by unamortized deferred financing and discount costs of $147 million. Additional information is provided in Note 14 in the 2020 Annual Financial Statements.
(2)Additional information is provided in Note 15 in the 2020 Annual Financial Statements.
(3)Additional information is provided in Note 28 in the 2020 Annual Financial Statements.

Other Contractual Obligations
The Corporation's regulated utilities are obligated to provide service to customers within their respective service territories. Consolidated capital expenditures are forecast to be approximately $3.8 billion for 2021 and approximately $19.6 billion over the five-year 2021-2025 capital plan. See "Capital Plan" on page 24.

MANAGEMENT DISCUSSION AND ANALYSIS
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Under a funding framework with the Governments of Ontario and Canada, Fortis will contribute a minimum of approximately $155 million of equity capital to the Wataynikaneyap Partnership based on Fortis' proportionate 39% ownership interest and the final regulatory-approved capital cost of the related project. In October 2019 the Wataynikaneyap Partnership entered into loan agreements to finance the project during construction. In the event a lender under the loan agreements realizes security on the loans, Fortis may be required to accelerate its equity capital contributions, which may be in excess of the amount otherwise required of Fortis under the funding framework, to a maximum total funding of $235 million.

UNS Energy has joint generation performance guarantees with participants at San Juan, Four Corners, and Luna, with agreements expiring in 2022 through 2046, and at Navajo through decommissioning. The participants have guaranteed that in the event of payment default, each non-defaulting participant will bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. In the case of Navajo, participants would seek financial recovery from the defaulting party. There is no maximum amount under these guarantees, except for a maximum of $318 million for Four Corners. As at December 31, 2020, there was no obligation under these guarantees.

Central Hudson is a participant in an investment with other utilities to jointly develop, own and operate electric transmission projects in New York State. Central Hudson's maximum commitment is $94 million, for which it has issued a parental guarantee. As at December 31, 2020, there was no obligation under this guarantee.

As at December 31, 2020, FortisBC Holdings Inc., a non-regulated holding company, had $69 million of parental guarantees outstanding to support storage optimization activities at Aitken Creek.

Off-Balance Sheet Arrangements
With the exception of letters of credit outstanding of $130 million as at December 31, 2020 and the unrecorded commitments in the table above, the Corporation had no off-balance sheet arrangements.

CAPITAL STRUCTURE AND CREDIT RATINGS

Fortis requires ongoing access to capital and, therefore, targets a consolidated long-term capital structure that will enable it to maintain investment-grade credit ratings. The regulated utilities maintain their own capital structures in line with those reflected in customer rates.

Consolidated Capital Structure (%)
As at December 312020 2019 
Debt (1)
54.8 53.1 
Preference shares
3.6 3.8 
Common shareholders' equity and minority interest (2)
41.6 43.1 
100.0 100.0 
(1)Includes long-term debt and finance leases, including current portion, and short-term borrowings, net of cash
(2)Includes minority interest of 3.5% as at December 31, 2020 (2019 - 3.7%)

Outstanding Share Data
As at February 11, 2021, the Corporation had issued and outstanding 466.8 million common shares and the following First Preference Shares: 5.0 million Series F; 9.2 million Series G; 7.7 million Series H; 2.3 million Series I; 8.0 million Series J; 10.0 million Series K; and 24.0 million Series M.

Only the common shares of the Corporation have voting rights. The Corporation's first preference shares do not have voting rights unless and until Fortis fails to pay eight quarterly dividends, whether or not consecutive or declared.

If all outstanding stock options were converted as at February 11, 2021, an additional 3.3 million common shares would be issued and outstanding.


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Credit Ratings
The Corporation's credit ratings shown below reflect its low risk profile, diversity of operations, the stand-alone nature and financial separation of each regulated subsidiary, and the level of holding company debt.
Credit Ratings
As at December 31, 2020RatingType Outlook
S&PA-CorporateNegative
BBB+Unsecured debt
DBRS MorningstarBBB (high)CorporatePositive
BBB (high)Unsecured debt
Moody'sBaa3IssuerStable
Baa3Unsecured debt

CAPITAL PLAN

Capital investment in energy infrastructure is required to ensure the continued and enhanced performance, reliability and safety of the electricity and gas systems, and to meet customer growth.

The COVID-19 Pandemic did not have a material impact on capital expenditures in 2020. Capital expenditures of $4.2 billion were broadly consistent with the 2020 capital plan as disclosed in the 2019 MD&A.

2020 Capital Expenditures (1)
Regulated Utilities
($ millions, except %)
ITC
UNS
Energy
Central
Hudson
FortisBC
Energy
Fortis
Alberta
FortisBC
Electric
Other Electric
Total
Regulated
Utilities
Non-Regulated (2)
Total
(%)
Generation— 639 — — — 26 42 707 5 712 17 
Transmission1,070 84 48 138 — 34 165 1,539  1,539 37 
Distribution— 330 188 207 333 46 167 1,271  1,271 30 
Other (3)
112 147 103 126 87 29 37 641 14 655 16 
Total1,182 1,200 339 471 420 135 411 4,158 19 4,177 100 
(%)29 29 11 10 10 100  100 
(1)    Reflects cash outlay for property, plant and equipment and intangible assets as shown on the Consolidated Statements of Cash Flows in the 2020 Annual Financial Statements, as well as Fortis' $138 million share of development costs and capital spending for the Wataynikaneyap Transmission Power Project included in the Other Electric segment.
(2)Includes Energy Infrastructure and Corporate and Other segments
(3)Includes facilities, equipment, vehicles and information technology assets, as well as AESO transmission-related capital expenditures at FortisAlberta

Planned capital expenditures are based on detailed forecasts of energy demand, labour and material costs, general economic conditions, foreign exchange rates and other factors. These could change and cause actual expenditures to differ from forecast or plan. The impact of the COVID-19 Pandemic on forecast capital expenditures will continue to be evaluated and, depending on the length and severity of the pandemic, certain planned expenditures may shift within the 2021-2025 capital plan.

Forecast 2021 Capital Expenditures (1)
Regulated Utilities
($ millions, except %)
ITC
UNS
Energy
Central
Hudson
FortisBC
Energy
Fortis
Alberta
FortisBC
Electric
Other Electric
Total
Regulated
Utilities
Non-Regulated
Total
(%)
Generation— 117 — — 24 189 331 53 384 10 
Transmission949 191 41 168 — 23 310 1,682  1,682 44 
Distribution— 270 167 184 266 81 173 1,141  1,141 30 
Other51 171 97 115 80 25 49 588 18 606 16 
Total1,000 749 306 467 346 153 721 3,742 71 3,813 100 
(%)26 20 12 19 98 2 100 
(1)Excludes the non-cash equity component of AFUDC. Includes Fortis' share of development costs and capital spending for the Wataynikaneyap Transmission Power Project included in the Other Electric segment.
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Five-Year Capital Plan (1)
($ billions)20212022202320242025Total
3.8 3.9 3.9 4.0 4.0 19.6 
(1)Excludes the non-cash equity component of AFUDC. Includes Fortis' share of development costs and capital spending for the Wataynikaneyap Transmission Power Project included in the Other Electric segment.

The $19.6 billion five-year capital plan is $0.8 billion higher than the $18.8 billion five-year plan for 2020-2024, as disclosed in the 2019 MD&A. The increase is largely due to: (i) two new major capital projects at FortisBC Energy including the Tilbury LNG Resiliency Tank project and the AMI project, with total expected capital spend of approximately $500 million; (ii) $200 million of additional investment in information technology systems and storm hardening at Central Hudson; and (iii) $100 million of interconnections and system rebuilds to provide additional capacity and other improvements at ITC.

The capital plan is low risk and highly executable, with 99% of planned expenditures to occur at the regulated utilities and only 15% related to Major Capital Projects. Geographically, 55% of planned expenditures are expected in the US, including 26% at ITC, with 41% in Canada and the remaining 4% in the Caribbean.

Nature of Capital ExpendituresActualForecastFive-Year Plan
(%)20202021 2021-2025
Growth (1)
21 31 26 
Sustaining (2)
65 54 58 
Other (3)
14 15 16 
Total100 100 100 
(1)Relates to the connection of new customers and infrastructure upgrades required to meet load growth, including AESO transmission‑related investment at FortisAlberta
(2)Relates to the continued and enhanced performance, reliability and safety of generation, transmission and distribution assets
(3)Facilities, equipment, vehicles, information technology and other assets

Midyear Rate Base (1)
($ billions)2020 2021 2025 
ITC9.5 9.9 12.5 
UNS Energy5.7 6.2 7.6 
Central Hudson2.1 2.3 3.2 
FortisBC Energy5.1 5.2 6.8 
FortisAlberta3.7 3.8 4.2 
FortisBC Electric1.4 1.5 1.7 
Other Electric3.0 3.3 4.3 
Total30.5 32.2 40.3 
(1)Simple average of Rate Base at beginning and end of the year

Total midyear Rate Base is forecast to grow to $40.3 billion by 2025 under the five-year capital plan, representing a CAGR of approximately 6.0%, which is supportive of continuing growth in earnings and dividends.

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Major Capital Projects (1)
Forecast
Pre-Actual2022-Expected
($ millions)Project2020 2020 2021 2025 Completion
ITC (2)
Multi-Value Regional Transmission Projects 625 17 75 186 2023
34.5 to 69 kV Transmission Conversion Project352 93 41 107 Post-2025
UNS Energy
Vail-to-Tortolita Project
—  54 190 2023
Oso Grande Wind Project65 509 24 — 2021
FortisBC Energy
Lower Mainland Intermediate Pressure System
Upgrade
388 23 18 — 2021
Eagle Mountain Woodfibre Gas Line Project (3)
—  — 350 2025
Transmission Integrity Management Capabilities Project
13 8 434 Post-2025
Inland Gas Upgrades Project50 53 177 2025
Tilbury 1B12 375 2025
Tilbury LNG Resiliency Tank— 10 11 198 Post-2025
AMI Project—  243 Post-2025
Other Electric
Wataynikaneyap Transmission Power Project (4)
40 138 330 206 2023
Total860 618 2,466 
(1)Includes applicable AFUDC
(2)Pre-2020 capital expenditures are from the date of the ITC acquisition on October 14, 2016
(3)Net of forecast customer contributions
(4)Fortis' share of estimated capital spending, including deferred development costs. Under the funding framework, Fortis will be funding its equity component only.

Multi-Value Regional Transmission Projects
Four regional electric transmission projects that have been identified by MISO to address system capacity needs and reliability in various states. Three projects were completed pre-2020. The fourth project is expected to be placed in service in 2023.

34.5 to 69kV Transmission Conversion Project
Multiple capital initiatives designed to construct new 69 kV lines, upgrade existing 34.5 kV lines to 69 kV, and complete substation conversions with in service dates ranging from pre-2020 to post-2025.

Vail-to-Tortolita Project
A phase of the Southline Transmission Project that consists of new construction and upgrades to connect existing TEP substations. The project includes the construction of a new 230 kV line within TEP’s service territory. Construction is expected to begin in early 2022 with an in-service date of 2023.

Oso Grande Wind Project
Construction of a 750 MW wind-powered electric generating facility that complements UNS Energy's existing renewable solar generation portfolio, of which UNS Energy owns 250 MW. Construction is expected to be completed and the facility placed in service in the first half of 2021.

Lower Mainland Intermediate Pressure System Upgrade
Addresses system capacity and pipeline condition issues for the gas supply system in the Lower Mainland of British Columbia. The project is substantially complete, with one pipeline segment to be replaced in 2021. Final allowable project costs are subject to review by the BCUC.

Eagle Mountain Woodfibre Gas Line Project
Gas line expansion to a proposed LNG site in Squamish, British Columbia. In March 2020 Woodfibre LNG Limited, the owner of the proposed LNG facility, requested an extension to its British Columbia Environmental Assessment Certificate due to production and supply chain disruptions resulting, in part, from the COVID-19 Pandemic. In October 2020, the BC Environmental Assessment Certificate was extended for another five years.

FortisBC Energy's proposed pipeline expansion remains contingent on Woodfibre LNG Limited making a final decision to proceed with construction of the LNG facility. At this time, should the project proceed, the earliest construction start date expected is late-2021.

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Transmission Integrity Management Capabilities Project
This project improves gas line safety and transmission system integrity, including gas line modifications and looping. A CPCN application is expected to be filed with the BCUC in the first quarter of 2021.

Inland Gas Upgrades Project
Gas line modifications and replacements to enable in-line integrity inspection capabilities. In January 2020 the CPCN application was approved by the BCUC.

Tilbury 1B Project
Construction of additional liquefaction and dispensing, including on-shore piping, in support of marine bunkering and to further optimize the Tilbury Phase 1A Expansion Project. The project received an Order in Council from the Government of British Columbia in 2017. In February 2020 an initial project scope was filed with regulators to begin the federal impact assessment and provincial environmental assessment required to further expand the Tilbury site. Engineering design and related studies will continue in 2021.

Tilbury LNG Resiliency Tank
This project replaces the original LNG storage tank at the Tilbury site and increases the available regasification capacity to provide backup gas supply for lower mainland customers. In December 2020 FortisBC Energy filed a CPCN application for this project with the BCUC.

AMI Project
Replacement of residential and small commercial meters and installation of bypass valves to avoid future interruption of gas service. The project will assist in load management by allowing remote meter reading on a near real-time basis and remote shutoff of gas flow. FortisBC Energy plans to file a CPCN application for this project with the BCUC in the first half of 2021.

Wataynikaneyap Transmission Power Project
Construction of a 1,800 kilometre, Ontario Energy Board regulated transmission line to connect 17 remote First Nations communities in Northwestern Ontario to the main electricity grid, in which Fortis holds a 39% equity interest. FortisOntario is responsible for construction management and operation of the transmission line. The project is on track with completion expected in 2023.

Additional Investment Opportunities
Fortis is pursuing additional investment opportunities within existing service territories that are not yet included in the five-year capital plan.

ITC - Lake Erie Connector
Proposed 1,000 MW, bi-directional, high-voltage direct current underwater transmission line to directly link the markets of the Ontario Independent Electricity System Operator and PJM Interconnection, LLC. The project would enable transmission customers to more efficiently access energy, capacity and renewable energy credit opportunities in both markets. The major permits have been approved. The project continues to advance through regulatory, operational and economic milestones. Ongoing activities include completing project cost refinements and securing transmission service agreements. Completion would take approximately four years from the commencement of construction.

FortisBC Energy - LNG
Pursuit of additional LNG infrastructure opportunities in British Columbia, including further expansion of the Tilbury LNG facility, which is uniquely positioned to meet customer demand for clean-burning natural gas. The site is scalable and can accommodate additional storage and liquefaction equipment and is relatively close to international shipping lanes. FortisBC Energy continues to have discussions with potential export customers.

Other Opportunities
Includes incremental regulated transmission investment, contracted transmission and grid modernization projects at ITC; renewable energy investments, energy storage projects, grid modernization, infrastructure resiliency, and transmission investments at UNS Energy; further gas infrastructure opportunities at FortisBC Energy; and cleaner energy infrastructure investments across our jurisdictions.

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BUSINESS RISKS

Fortis has established an ERM process to help identify and evaluate risks by both severity of impact and probability of occurrence. Materiality thresholds are reviewed and, if necessary, updated annually. Non-financial risks that may impact the safety of employees, customers or the general public, as well as reputational risks, are also evaluated. Systems of internal controls are established to monitor and manage identified risks. The ERM process at the subsidiary level is overseen by each subsidiary’s board of directors and any material risks identified are communicated to Fortis management and form part of Fortis' ERM program. The Fortis board of directors, through the audit committee, oversees Fortis' ERM program, ensuring strategic objectives are achieved.

A summary of the Corporation's current significant business risks follows.

Regulation
Regulated utility assets represented approximately 99% of the Corporation's total assets as at December 31, 2020. Regulatory jurisdictions include five Canadian provinces, nine US states and three Caribbean countries, as well FERC regulation for transmission assets in the US.

Regulators administer legislation covering material aspects of the utilities' business, including: customer rates and the underlying allowed ROEs and deemed capital structures; capital expenditures; the terms and conditions for the provision of energy and capacity, ancillary services and affiliate services; securities issuances; and certain accounting matters. Regulatory or legislative changes and decisions, and delays in the recovery of costs in rates due to regulatory lag, could have a Material Adverse Effect. The risk of regulatory lag is particularly significant for UNS Energy given the use of historical test years in setting rates.

The ability to recover the actual cost of service and earn the approved ROE or ROA typically depends on achieving the forecasts established in the rate-setting process. Failure to do so could have a Material Adverse Effect. For those utilities subject to PBR mechanisms, rates reflect assumed inflation rates and productivity improvement factors, and variances therefrom could have a Material Adverse Effect. Under FortisAlberta's PBR mechanism there is an added risk that incremental incurred capital expenditures may not be approved for recovery in rates.

For transmission operations, the underlying elements of FERC-established formula rates can be, and have been, challenged by third parties which could result in, and has resulted in, lowered rates and customer refunds. These underlying elements include the assumed ROE, ROE adders for independent transmission ownership and deemed capital structure as well as operating and capital expenditures. These challenges could have a Material Adverse Effect.

Additionally, the US Congress periodically considers enacting energy legislation that could assign new responsibilities to FERC, modify provisions of the U.S. Federal Power Act or the Natural Gas Act, or provide FERC or another entity with increased authority to regulate US federal energy matters. Such changes could have a Material Adverse Effect.

The political and economic environments as well as their effect on energy laws and governmental energy policies have had, and may continue to have, negative impacts on regulatory decisions. While Fortis is well positioned to maintain constructive regulatory relationships through local management teams and boards comprised mostly of independent local members, it cannot predict future legislative or regulatory changes, whether caused by economic, political or other factors, or its ability to respond thereto in an effective and timely manner, or the resulting compliance costs. These dynamics could have a Material Adverse Effect.

Climate Change and Physical Risks
The provision of electric and gas service is subject to customary industry risks, including severe weather and natural disasters, wars, terrorism, critical equipment failure and other catastrophic events within and outside the Corporation's service territories. Resultant service disruption and repair and replacement costs could have a Material Adverse Effect if not resolved in a timely and effective manner and/or mitigated through insurance policies or regulatory cost recovery.


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Climate change is predicted to lead to more frequent and intense weather events, changing air temperatures, changing seasonal variations, and regulatory responses (see "Environmental Matters" on page 30), each of which could have a Material Adverse Effect. Severe weather impacts the Corporation’s service territories, primarily when thunderstorms, flooding, wildfires, hurricanes and snow or ice storms occur. Increased frequency of extreme weather events could increase the cost of providing service. Changes in precipitation that result in droughts could increase the risk of wildfire caused by the Corporation’s electricity assets or may cause water shortages that could adversely affect operations. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Changing air temperatures could also result in system stress and decreased efficiencies to operating facilities over time. Longer-term climate change impacts, such as sustained higher temperatures, higher sea levels and larger storm surges, could result in service disruption, repair and replacement costs, and costs associated with strengthened design standards and systems, each of which could have a Material Adverse Effect if not resolved in a timely and effective manner and/or mitigated through insurance policies or regulatory cost recovery.

Generating equipment and facilities are subject to risks, including equipment breakdown and flood and fire damage, that may result in the uncontrolled release of water, interruption of fuel supply, lower-than-expected operational efficiency or performance, and service disruption. There is no assurance that generating equipment and facilities will continue to operate in accordance with expectations.

The operation of transmission and distribution assets is subject to risks, including the potential to cause fires, mainly as a result of equipment failure, falling trees and lightning strikes to lines or equipment. Certain utilities operate in remote and mountainous terrain that can be difficult to access for timely repairs and maintenance, or otherwise face risk of loss or damage from forest fires, floods, washouts, landslides, earthquakes, avalanches and other acts of nature with a potential Material Adverse Effect.

The gas utilities are exposed to operational risks associated with natural gas, including fires, explosions, pipeline corrosion and leaks, accidental damage to mains and service lines, equipment failure, damage and destruction from earthquakes, fires, floods and other natural disasters, and other accidents and issues that can lead to service disruption, spills and commensurate environmental liability, or other liability with a Material Adverse Effect.

Risks associated with fire damage vary depending on weather, forestation, the proximity of habitation and third-party facilities to utility facilities, and other factors. The utilities may become liable for fire-suppression costs, regeneration and timber value costs, and third-party claims if their facilities are held responsible for a fire, and such claims, if successful, could have a Material Adverse Effect.

Electricity and gas systems require ongoing maintenance, improvement and replacement. Service disruption, other effects and liability caused by the failure to properly implement or complete approved maintenance and capital expenditures, the occurrence of significant unforeseen equipment failures, or the inability to recover requisite costs in customer rates, could have a Material Adverse Effect.

The electricity and gas systems are designed to service customers under various contingencies in accordance with good utility practice. The utilities are responsible for operating and maintaining their assets in a safe manner, including the development and application of appropriate standards, system processes and/or procedures to ensure the safety of employees, contractors and the general public. The impacts of climate change may necessitate the acceleration of these standards, processes and procedures. Failure to do so may disrupt the ability of the utilities to safely provide service, which could cause reputational harm and other impacts with a Material Adverse Effect.

Pandemics and Public Health Crises, including the COVID-19 Pandemic
The Corporation could be negatively impacted by a widespread outbreak of communicable diseases or other public health crises that cause economic and/or other disruptions. The COVID-19 Pandemic continues to be an evolving situation that has adversely impacted economic activity and conditions around the world, including the Corporation's service territories (see "General Economic Conditions" and "Access to Capital" on page 34). The virus and efforts to reduce the health impacts and control its spread have led many jurisdictions around the world, including Canada, the US and the Caribbean, to institute restrictions on travel, gatherings and business operations. The Corporation and its utilities have been subjected to government and regulatory action in response to the COVID-19 Pandemic, including restrictions on business operations, customer deferrals and suspension of disconnections. Other potential impacts on the Corporation's operations may include reduced labour availability and
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productivity, disruptions to capital markets leading to share price volatility and liquidity issues, supply chain disruptions, project construction delays and a prolonged reduction in economic activity. An extended economic slowdown could reduce energy sales and adversely impact the ability of customers, contractors and suppliers to fulfill their obligations and could disrupt operations and capital expenditure programs or cause impairment of goodwill.

The overall impact will depend on the duration and severity of the pandemic, potential government actions to mitigate public health effects or aid economic recovery, and other factors beyond the Corporation's control. An extended period of economic disruption could have a Material Adverse Effect.

Environmental Matters
The Corporation's businesses are subject to environmental risks and environmental laws and regulations, including those which: (i) impose limitations or restrictions on the discharge of pollutants into the air, soil and water; (ii) establish standards for the management, treatment, storage, transportation and disposal of hazardous wastes; and/or (iii) impose obligations to investigate and remediate contamination.

The risk of contamination of air, soil and water at the electric businesses primarily relates to: (i) the transportation, handling, storage and combustion of fuel; (ii) the use of petroleum-based products, mainly transformer and lubricating oil; (iii) the management and disposal of coal combustion residuals and other wastes; and (iv) accidents resulting in hazardous release at or from coal mines that supply generating facilities. Contamination risks at the gas businesses primarily relate to leaks and other accidents involving gas systems. The key environmental risks for hydroelectric generation operations include dam failures and the creation of artificial water flows that may disrupt natural habitats.

Liabilities relating to contamination investigation and remediation, and claims for personal injury or property damage, may arise at many locations, including formerly and currently owned/operated properties and waste treatment or disposal sites, regardless of whether such contamination was caused by the business at the time it owned the property or whether it resulted from non-compliance with applicable environmental laws. Under some environmental laws, such liabilities may be joint and several, meaning that a party can be held responsible for more than its share of the liability involved or even the entire liability. These liabilities could lead to litigation and administrative proceedings that could result in substantial monetary judgments for clean-up costs, damages, fines and/or penalties. To the extent not fully covered by insurance, these costs could have a Material Adverse Effect.

The Corporation's businesses have incurred substantial expenses for environmental compliance, and they anticipate continuing to do so in the future. In particular, the management of GHG emissions is a major concern due to new and emerging federal, state and provincial GHG laws, regulations and guidelines.

The Corporation's businesses continue to develop compliance strategies and assess the impact of emerging legislative changes, but significant uncertainties remain. Increased compliance costs or additional operating restrictions from revised or additional regulation could have a Material Adverse Effect.

Growth
Fortis has a history of growth through acquisitions and organic growth from capital investment in existing service territories. Acquisitions include inherent risks that some or all of the expected benefits may fail to materialize, or may not occur within the time periods anticipated, and material unexpected costs may arise.

The Corporation's dividend growth guidance is significantly dependent upon achieving the Rate Base growth expected from the execution of the five-year capital plan described under "Capital Plan" on page 24. Projects, particularly Major Capital Projects, are subject to risks of delay and cost overruns during construction caused by inflation, supply and labour costs, supplier non-performance, weather, geologic conditions or other factors beyond the Corporation’s control. There is no assurance that regulators will approve: (i) all of the planned projects or their amounts or timing; (ii) permits in a timely manner, or with reasonable terms and conditions; or (iii) the recovery of cost overruns in customer rates. These risks could impact the successful execution of a project by preventing the project from proceeding, delaying its completion, increasing its projected costs or negatively impacting its financing.

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Weather Variability and Seasonality
Electricity consumption varies significantly in response to climate change and seasonal weather changes (see "Climate Change and Physical Risks" on page 28). In central and western Canada, Arizona and New York State, cool summers may reduce the use of air conditioning and other cooling equipment, while less severe winters may reduce heating load. Alternatively, severe weather could unexpectedly increase heating and cooling loads, negatively impacting system reliability.

Weather and seasonality have a significant impact on gas distribution volumes as a major portion of the gas is used for space heating by residential customers. The earnings of the Corporation's gas utilities and Aitken Creek are typically highest in the first and fourth quarters.

Hydroelectric generation is sensitive to rainfall levels.

Regulatory deferral and revenue decoupling mechanisms are in place at certain of the Corporation's utilities to minimize the volatility in earnings that would otherwise be caused by variations in weather conditions. Both the discontinuance of key regulatory mechanisms and their absence at other Fortis entities could result in significant and prolonged weather variations from seasonal norms having a Material Adverse Effect.

Natural Gas Competitiveness
Approximately 19% of the Corporation's revenue is derived from the delivery of natural gas. A decrease in the competitiveness of natural gas due to pricing or other factors could have a Material Adverse Effect.

In British Columbia, which accounts for 80% of the Corporation's natural gas revenue, natural gas primarily competes with electricity for space and hot water heating. Upfront capital costs for gas service continue to present competitive challenges for natural gas compared to electricity service. If gas becomes less competitive, the ability to add new customers could be impaired. Existing customers could also reduce their consumption or switch to electricity, placing further pressure on rates, whereby system costs must be recovered from a smaller customer and sales base, leading to further reductions in competitiveness.

Government policy could also impact the competitiveness of natural gas in British Columbia. The provincial government has introduced changes to energy policy, including GHG emission reduction targets and a tax on carbon-based fuels which is expected to increase in the future. However, the Government of British Columbia has yet to introduce a carbon tax on imported electricity generated through the combustion of carbon-based fuels. As all levels of government become more active in the development of policies to address climate change, any resultant changes to energy policy may have a material impact on the competitiveness of natural gas relative to non-carbon based energy sources or other energy sources.

There are other competitive challenges that are impacting the penetration of natural gas into new housing stock such as green attributes of the energy source, and type of housing stock being built. In addition, as part of their own climate change policy plans, local governments may use various tools at their disposal such as franchise agreements, permits, building codes and zoning bylaws to impose limitations on energy sources permitted in new and existing developments. The municipalities can also provide incentives, such as higher density allowance, to builders to adopt carbon free options for their developments. These actions and policies may hinder the Corporation's ability to attract new customers or retain existing customers.

Commodity Price Volatility
Purchased power and generation fuel costs are subject to commodity price volatility, which is managed through regulator-approved: (i) mechanisms that permit the flow through in customer rates of commodity price changes and/or that provide for rate-stabilization and other deferral accounts (see "Business Unit Performance" on page 10); and (ii) price-risk management strategies such as the use of derivative contracts that effectively fix costs (see "Financial Instruments - Derivatives" on page 39).

There is no assurance that current regulator-approved mechanisms will continue to exist in the future. Additionally, despite these mechanisms, severe and prolonged commodity price increases could result in rates that customers are unable to pay and/or could affect consumption and sales growth. These could have a Material Adverse Effect.


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Purchased Power Supply
A significant portion of electricity and gas sold by the Corporation's utilities is purchased through the wholesale energy markets or pursuant to contracts with energy suppliers rather than being generated. A disruption in the wholesale energy markets, or a failure on the part of energy or fuel suppliers or operators of energy delivery systems that connect to the Corporation's utilities, could have a Material Adverse Effect.

Required Approvals
The acquisition, ownership and operation of electric and gas businesses require numerous licences, permits, agreements, orders, certificates and other approvals from various levels of government, regulators, government agencies, Indigenous Peoples and/or third parties. The external environment has become more complex with heightened expectations from permitting agencies, local municipalities and Indigenous Peoples to be able to review and provide feedback on projects, largely driven by policy responses to climate change. There is no assurance that: (i) all of these approvals will be obtained, continuously maintained or renewed without delay; and (ii) the terms and conditions thereof will be fully complied with at all times and will not change in a material adverse manner. Significant failures in these regards could prevent the operation of the businesses and have a Material Adverse Effect.

Reliability Standards
The Energy Policy Act requires owners, operators and users of the bulk electric system in the US to meet mandatory reliability standards developed by the North American Electric Reliability Corporation and its regional entities, which are approved and enforced by FERC. Many of these, or similar, standards have been adopted in certain Canadian provinces including British Columbia, Alberta and Ontario. The failure to develop, implement and maintain appropriate operating practices/systems and capital plans to address reliability obligations could lead to compliance violations and a Material Adverse Effect, such as the exclusion from customer rates of related costs including potentially significant penalties.

Indigenous Peoples' Land Claims
In British Columbia, the Corporation's utilities provide service to customers on Indigenous Peoples' lands and maintain facilities on lands that are subject to Indigenous Peoples' land claims. Various treaty negotiation processes involving Indigenous Peoples and the Governments of British Columbia and Canada are underway, but the basis for potential settlements is unclear and not all Indigenous Peoples are participating in the processes. To date, the policy of the Government of British Columbia has been to structure settlements without prejudicing existing third-party rights. However, there is no assurance that the settlement processes will not have a Material Adverse Effect.

FortisAlberta has distribution assets on Indigenous Peoples' lands in Alberta with access permits held by TransAlta Utilities Corporation. To acquire these permits, FortisAlberta requires approval from First Nations and Crown-Indigenous Relations and Northern Affairs Canada. FortisAlberta may be unable to obtain such approvals or negotiate land-use agreements with reasonable terms. Significant failures in these regards could have a Material Adverse Effect.

Joint-Ownership Interests and Third-Party Operators
Certain generating facilities from which TEP receives power are jointly owned with, or are operated by, third parties. TEP may not have sole discretion or any ability to affect the management or operations of such facilities, including how to best address changing economic conditions or environmental requirements. A divergence in the interests of TEP and those of the joint owners or operators could have a Material Adverse Effect.

Wataynikaneyap Partnership, which is owned 51% by 24 First Nations communities and 49% by a partnership between Fortis (80%) and Algonquin Power & Utilities Corp. (20%), is responsible for the Wataynikaneyap Transmission Power Project. Fortis does not have sole discretion on decisions for the project and divergence in the interest of Fortis and the other partners could delay the project’s completion, increase its anticipated cost, or adversely affect the reputation of Fortis.

Counterparty Credit Risk
ITC has a concentration of credit risk as approximately 70% of its revenue is derived from three customers. These customers have investment-grade credit ratings and credit risk is further managed by MISO 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.

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FortisAlberta has a concentration of credit risk as its distribution service billings are to a relatively small group of retailers. Credit risk is managed by obtaining from the retailers either a cash deposit, letter of credit, an investment-grade credit rating, or a financial guarantee from an entity with an investment-grade credit rating.

UNS Energy, Central Hudson, FortisBC Energy, Aitken Creek and Fortis may be exposed to credit risk from non‑performance by counterparties to derivatives. Credit risk is managed 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.

There is no assurance that management strategies will continue to be effective. Significant counterparty defaults could have a Material Adverse Effect.

Cybersecurity
As operators of critical energy infrastructure, the Corporation's utilities face the risk of cybercrime, which has increased in frequency, scope and potential impact in recent years. Their ability to operate effectively is dependent upon developing and maintaining complex information systems and infrastructure that: (i) support the operation of electric generation, transmission and distribution facilities, including gas facilities; (ii) provide customers with billing, consumption and load settlement information, where applicable; and (iii) support financial and general operations.

Information and operations technology systems may be vulnerable to unauthorized access due to hacking, viruses, acts of war or terrorism, acts of vandalism and other causes. This can result in the disruption of energy service and other business operations, system failures and grid disturbances, property damage, corruption or unavailability of critical data, and the misappropriation and/or disclosure of sensitive, confidential and proprietary business, customer and employee information.

A material breach could adversely affect the financial performance of the Corporation, its reputation and standing with customers, regulators and financial markets, and expose it to claims for third-party damage. The resultant financial impacts may not be fully covered by insurance policies or, in the case of utilities, through regulatory cost recovery, and could have a Material Adverse Effect.

Technology Advances
The emergence of initiatives designed to reduce GHG emissions and control or limit the effects of climate change has increased the incentive for the development of new technologies that produce power, enable more efficient storage of energy or reduce power consumption.

New technology developments in distributed generation, particularly solar, and energy efficiency products and services, as well as the implementation of renewable energy and energy efficiency standards, will continue to impact retail sales. Heightened awareness of energy costs and environmental concerns have increased demand for products that reduce energy consumption. The Corporation's utilities are also promoting demand-side management programs.

New technologies include energy derived from renewable sources, customer-owned generation, energy-efficient appliances, battery storage and control systems. Advances in these or other technologies could have a significant impact on retail sales with a potential Material Adverse Effect.

Interest Rates
Generally, the market price of the Corporation's common shares is inversely sensitive to interest rate changes. Additionally, allowed ROEs are exposed to changes in long-term interest rates. A low interest rate environment could reduce allowed ROEs. Alternatively, if interest rates rise, regulatory lag may cause delays in any compensatory ROE increases. Borrowings under variable-rate credit facilities and long-term debt, as well as new debt issuances, are also exposed to interest rate changes.

Tax Laws
Fortis and its subsidiaries are subject to changes in income tax rates and other tax legislation in Canada, the US and other international jurisdictions. The nature, timing or impact of changes in future tax laws cannot be predicted and could have a Material Adverse Effect. Although income taxes at the regulated utilities are generally recovered in customer rates, regulatory lag can result in recovery delays or non-recovery for certain periods. A variety of other impacts are also possible. At the non-regulated level, changes in income tax rates and other tax legislation could materially affect the after-tax cost of existing and future debt which is not recoverable in customer rates.
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Foreign Exchange Exposure
The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI, BECOL and Belize Electricity is, or is pegged to, the US dollar. The earnings and cash flow from, and net investments in, these entities are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate.

Fortis has limited this exposure through hedging. As at December 31, 2020, US$2.3 billion (2019 - US$2.2 billion) of corporately issued US dollar-denominated long-term debt had been designated as an effective hedge of foreign net investments, leaving US$10.2 billion (2019 - US$9.7 billion) in foreign net investments unhedged. Fortis has also entered into foreign exchange contracts to manage a portion of its exposure to foreign currency risk.

Given only partial hedging, consolidated earnings and cash flow continue to be impacted by exchange rate fluctuations. On average, Fortis estimates that a five-cent increase or decrease in the US dollar relative to the Canadian dollar exchange rate of US$1.00=CA$1.34 as at December 31, 2020 would increase or decrease annual EPS by approximately six cents, which reflects the Corporation's hedging program.

The Corporation's $19.6 billion five-year capital plan for 2021 through 2025 also includes exposure to foreign exchange. On average, Fortis estimates that a five-cent increase or decrease in the US dollar relative to the Canadian dollar would increase or decrease capital expenditures by $400 million over the five-year planning period.

There is no assurance that existing hedging strategies will continue to be effective and the resultant financial impacts could have a Material Adverse Effect.

Access to Capital
Ongoing access to cost-effective capital is required to fund, among other things, capital expenditures and the repayment of maturing debt.

Operating Cash Flow may not be sufficient to fund the repayment of all outstanding liabilities when due or anticipated capital expenditures. The ability to meet long-term debt repayments is dependent upon obtaining sufficient and cost-effective financing to replace maturing indebtedness.

The ability to arrange such financing is subject to numerous factors, including the results of operations and financial condition of Fortis and its subsidiaries, the regulatory environments including regulatory decisions regarding capital structure and allowed ROEs, capital market conditions, general economic conditions and credit ratings. Changes in credit ratings could affect credit risk spreads on new long-term debt and credit facilities, as well as their availability.

There is no assurance that sufficient capital will continue to be available on acceptable terms. For further information see "Liquidity and Capital Resources" on page 19.

Insurance
Insurance is maintained with reputable industry insurers for property damage, potential liabilities and business interruption for coverage considered appropriate and in accordance with industry practice.

A significant portion of transmission and distribution assets is uninsured, as is customary in North America, as the cost is prohibitive. Insurance is subject to coverage limits and deductibles as well as time-sensitive claims discovery and reporting provisions. There is no assurance that: (i) the amounts and types of actual damage, liabilities or business interruption will be fully covered; (ii) regulatory relief would be obtained for coverage shortfalls; (iii) adequate insurance at reasonable rates will continue to be available; or (iv) insurers will fulfill their obligations. Significant actual shortfalls could have a Material Adverse Effect.

Talent Management
The delivery of safe, reliable and cost-effective service depends on the attraction, development and retention of skilled workforces. Like its peers, Fortis faces demographic challenges and competitive markets relating to trades, technical and professional staff, particularly considering its significant capital plan. ITC relies heavily on agreements with third parties to provide services for the construction, maintenance and operation of certain aspects of its business. Significant failures in attracting or retaining a skilled workforce could have a Material Adverse Effect.

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Labour Relations
Most of the Corporation's utilities employ members of labour unions or associations under collective bargaining agreements. Fortis considers its labour relationships to be satisfactory but there is no assurance that this will continue or that existing collective bargaining agreements will be renewed on reasonable terms without work disruption or other job action. Significant failures in these regards could cause service interruptions and/or labour cost increases for which the regulator disallows full recovery in rates, and could have a Material Adverse Effect.

Post-Retirement Obligations
Fortis and most of its subsidiaries maintain a combination of defined benefit pension and/or OPEB plans for certain employees and retirees. The most significant cost drivers for these plans are investment performance and interest rates, which are affected by global financial markets. Market disruptions, significant declines in the market values of investments held to meet plan obligations, discount rate changes, participant demographics, and changes in laws and regulations may require additional plan funding. Significant increases in plan expenses and funding requirements could have a Material Adverse Effect.

General Economic Conditions
Fluctuations in general economic conditions, energy prices, employment levels, personal disposable incomes, housing starts, industrial activity and other factors may lower energy demand and reduce sales both directly and through reduced capital spending, particularly that related to new customer growth, which would affect Rate Base growth. A severe and prolonged economic downturn could have a Material Adverse Effect, including making it more difficult for customers to pay their bills.

Reputation, Relationships and Stakeholder Activism
The Corporation’s operations and growth prospects require strong relationships with key stakeholders, including regulators, governments and agencies, Indigenous communities, landowners, and environmental organizations. Inadequately managing expectations and issues important to stakeholders, including those arising during construction, could affect the Corporation’s reputation as well as have a significant impact on its operations and infrastructure development.

Additionally, external stakeholders are increasingly challenging utilities regarding climate change, sustainability, diversity, returns including ROEs, executive compensation and other matters. Public opposition to larger infrastructure projects is becoming increasingly common, which can challenge capital plans and resultant organic growth. While the Corporation actively monitors such activism and is committed to developing stronger relationships with its external stakeholders, failure to effectively maintain or respond to stakeholder activism could have a Material Adverse Effect.

Legal, Administrative and Other Proceedings
These proceedings arise in the ordinary course of business and may include environmental claims, employment-related claims, securities-based litigation, contractual disputes, personal injury or property damage claims, actions by regulatory or tax authorities, and other matters. Unfavourable outcomes such as judgments or settlements for monetary or other damages, injunctions, denial or revocation of permits, reputational harm, and other results could have a Material Adverse Effect.


ACCOUNTING MATTERS

New Accounting Policies

Financial Instruments
Effective January 1, 2020, the Corporation adopted ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments, which requires the use of reasonable and supportable forecasts in the estimation of credit losses and the recognition of expected losses upon initial recognition of a financial instrument, in addition to using past events and current conditions. The new guidance also requires quantitative and qualitative disclosures regarding the activity in the allowance for credit losses for financial assets within the scope of the guidance. Adoption did not have a material impact on the 2020 Annual Financial Statements and related disclosures. Further information is provided in Note 3 in the 2020 Annual Financial Statements.


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Critical Accounting Estimates

General
The preparation of the 2020 Annual Financial Statements required management to make estimates and judgments that affect the reported amounts of, and disclosures related to, assets, liabilities, revenues, expenses, gains, losses and contingencies. 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 recognized in the period they become known. Actual results may differ significantly from these estimates.

Regulatory Assets and Liabilities
As at December 31, 2020, Fortis recognized regulatory assets of $3.6 billion (2019 - $3.4 billion) and regulatory liabilities of $3.1 billion (2019 - $3.4 billion).

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: (i) 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; or (ii) obligations to provide future service that customers have paid for in advance.

The recognition of regulatory assets and liabilities and the period(s) of settlement are often estimates based on past, existing or expected regulatory orders in relation to the nature of the underlying amounts, and are subject to regulatory approval. There is no assurance that actual settlement amounts and the related settlement periods will not be materially different from those estimated. Differences arising from the regulator's orders would be recognized in accordance with those orders, whereby any amounts disallowed would be immediately recognized in earnings with the remainder recognized in earnings in accordance with their inclusion in customer rates.

Employee Future Benefits
Key Estimates and Assumptions
Defined Benefit
Pension Plans
OPEB Plans
Years ended December 312020 2019 2020 2019 
Funded status: (1) ($ millions)
Benefit obligation (2)
(3,995)(3,632)(789)(712)
Plan assets
3,528 3,208 391 343 
(467)(424)(398)(369)
Net benefit cost (2) ($ millions)
67 65 32 28 
Key assumptions: (weighted average %)
Discount rate: (3)
During the year
3.16 4.05 3.22 4.10 
As at December 31
2.63 3.20 2.64 3.25 
Expected long-term rate of return on plan assets (4)
5.52 5.78 5.28 5.50 
Rate of compensation increase
3.34 3.33  — 
Health care cost trend increase rate (5)
 — 4.61 4.62 
(1)Periodic actuarial valuations determine funding contributions for the pension plans and US OPEB plans, while Canadian OPEB plans are unfunded
(2)Actuarially determined using the projected benefits method prorated on service and management's best estimate of expected plan investment performance, salary escalation, average remaining service life of employees, mortality rates and, for OPEB plans, expected health care costs
(3)Reflects market interest rates on high‑quality bonds with cash flows that match the timing and amount of expected pension payments
(4)Developed using best estimates of expected returns, volatilities and correlations for each class of asset. Estimates are based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes.
(5)Actuarially determined, the projected 2021 rate is 5.91% and is assumed to decrease over the next 11 years to the ultimate rate of 4.61% in 2031 and thereafter.

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Sensitivity Analysis

Year ended December 31, 2020
Rate of Return -
1% change
Discount Rate -
1% change
Health Care Costs
Trend Rate -
1% change
($ millions)IncreaseDecreaseIncreaseDecreaseIncreaseDecrease
Defined benefit pension plans:
Net benefit cost
(30)25 (45)63 n/an/a
Projected benefit obligation
44 (82)(541)691 n/an/a
OPEB plans:
Net benefit cost
(4)4 (9)13 29 (21)
Accumulated benefit obligation
  (113)144 106 (84)

At the regulated utilities, changes in net benefit cost are generally expected to be reflected in customer rates, subject to regulatory lag and forecast risk at certain utilities.

At FortisAlberta, cash contributions are expensed and reflected in customer rates with any difference between the cash contributions and the net benefit cost deferred as a regulatory asset/liability. ITC, Central Hudson, FortisBC Energy, FortisBC Electric and Newfoundland Power have regulator‑approved mechanisms to defer variations between actual net pension cost and that forecast and reflected in customer rates. There is no assurance that these deferral mechanisms will continue in the future.

Depreciation and Amortization
As at December 31, 2020, Fortis recognized property, plant and equipment and intangible assets of $37.3 billion (2019 - $35.2 billion) representing 67% of total assets (2019 - 66%). Depreciation and amortization totalled $1.4 billion for 2020 (2019 - $1.4 billion).

Depreciation and amortization reflect the estimated useful lives of the underlying assets, which considers historical experience, manufacturers' ratings and specifications, the past and expected future pattern and nature of usage, and other factors.

At the regulated utilities, depreciation rates require regulatory approval and include a provision for estimated future asset removal costs not identified as a legal obligation. Estimates primarily reflect historical experience and expected cost trends. The provision is recognized as a long-term regulatory liability against which actual removal costs are netted when incurred. As at December 31, 2020, this regulatory liability was $1.2 billion (2019 - $1.2 billion).

Depreciation rates at the regulated utilities are typically determined through periodic depreciation studies performed by external experts. Where actual experience differs from previous estimates, resultant differences are generally reflected in future depreciation rates and thereby recovered or refunded through customer rates in the manner prescribed by the regulator.

Goodwill Impairment
As at December 31, 2020, Fortis recognized goodwill of $11.8 billion (2019 - $12.0 billion), representing 21% of total assets (2019 - 22%). The decrease in goodwill was due to the impact of foreign exchange associated with the translation of US dollar-denominated goodwill.

Goodwill at each of the Corporation's 11 reporting units is tested for impairment annually and whenever an event or change in circumstances indicates that fair value may be below carrying value. If so determined, goodwill is written down to estimated fair value and an impairment loss is recognized.

The Corporation performs a qualitative assessment on each reporting unit and if it is determined that it is not likely that fair value is less than carrying value, then a quantitative estimate of fair value is not required. When a quantitative assessment is necessary, the primary method for estimating fair value of the reporting units is the income approach, whereby net cash flow projections are discounted. Underlying estimates and assumptions, with varying degrees of uncertainty, include the amount and timing of expected future cash flows, growth rates, and discount rates. A secondary valuation, the market approach along with a reconciliation of the total estimated fair value of all the reporting units to the Corporation's market capitalization, is also performed and evaluated.


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The recognition of impairment losses could have a Material Adverse Effect. Such losses are not recoverable in regulated utility rates. To the extent impairment losses signal lower expected future cash flows to support interest payments on unregulated holding company debt and dividends on common shares, they could adversely affect the future cost of such capital, expressed as higher interest rates on such debt, which is not recoverable in regulated utility rates, and lower common share market prices.

Although the macro-economic impact of the COVID-19 Pandemic is pervasive throughout each reporting unit's service territory, it is expected to be short term in nature and therefore not expected to have a material impact on long-term sustaining cash flows. No goodwill impairment was recognized in 2020 or 2019, pursuant to the annual assessments.

Income Tax
As at December 31, 2020, deferred income tax liabilities, current income tax receivable included in accounts receivable, deferred income taxes included in regulatory assets, and deferred income taxes included in regulatory liabilities totalled $3.3 billion, $72 million, $1.7 billion and $1.4 billion, respectively (2019 - $3.0 billion, $35 million, $1.6 billion and $1.4 billion, respectively). Income tax expense was $231 million in 2020 (2019 - $289 million).

Current income taxes reflect the estimated taxes payable/receivable in the current year based on enacted tax rates and laws, and the estimated proportion of taxable earnings/loss attributable to various jurisdictions.

Deferred income tax assets/liabilities reflect temporary differences between the tax and accounting basis of assets/liabilities. A deferred income tax asset or liability is determined for each temporary difference based on enacted income tax rates and laws in effect when the temporary differences are expected to be recovered or settled. A valuation allowance is recognized in earnings to the extent that future tax recovery is not assessed as "more likely than not".

At the regulated utilities, differences between the tax expense/recovery normally recognized under US GAAP and that reflected in customer rates, which is expected to be recovered from/refunded to customers in future rates, are recognized as regulatory assets/liabilities. These are subsequently amortized to earnings in accordance with their inclusion in customer rates pursuant to the regulator's orders. Otherwise, changes in expectations and resultant estimates arising from changes in tax rates, tax laws, jurisdictional earnings allocations and other factors are recognized in earnings upon occurrence.

Derivatives
The fair values of derivatives are based on estimates that cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in predicting future earnings or cash flows. See "Financial Instruments - Derivatives" below.

Contingencies
The Corporation and its subsidiaries are subject to various legal proceedings and claims arising in the ordinary course of business, including those generally described under "Business Risks - Indigenous Peoples' Land Claims" on page 32, for which no amounts have been accrued because the outcomes currently cannot be reasonably determined. Further information is provided in Note 28 in the 2020 Annual Financial Statements.

While Fortis currently believes that these matters are unlikely to have a Material Adverse Effect, there is no assurance that this will be the case.


FINANCIAL INSTRUMENTS

LONG-TERM DEBT AND OTHER

As at December 31, 2020, the carrying value of long-term debt, including the current portion, was $24.5 billion (2019 - $22.3 billion) compared to an estimated fair value of $29.1 billion (2019 - $25.3 billion). Since Fortis does not intend to settle long-term debt prior to maturity, the excess of fair value over carrying value does not represent an actual liability.

The consolidated carrying value of the remaining financial instruments, other than derivatives, approximates fair value, reflecting their short-term maturity, normal trade credit terms and/or nature.
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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. Derivatives are recorded at fair value, with certain exceptions, including those derivatives that qualify for the normal purchase and normal sale exception.

Energy contracts subject to regulatory deferral
UNS Energy holds electricity power purchase contracts, customer supply contracts and gas swap contracts to reduce its exposure to energy price risk. Fair values are 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 are measured using forward pricing provided by independent third-party information.

FortisBC Energy holds gas supply contracts 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.

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, 2020, unrealized losses of $73 million (2019 - $119 million) were recognized as regulatory assets and unrealized gains of $17 million (2019 - $2 million) were recognized as regulatory liabilities.

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

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 are 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 revenue and were not material for 2020 and 2019.

Total return swaps
The Corporation holds total return swaps to manage the cash flow risk associated with forecast future cash settlements of certain stock-based compensation obligations. The swaps have a combined notional amount of $113 million and terms of one to three years expiring at varying dates through January 2023. Fair value is measured using an income valuation approach based on forward pricing curves. Unrealized gains and losses associated with changes in fair value are recognized in other income, net and were not material for 2020 and 2019.

Foreign exchange contracts
The Corporation holds US dollar-denominated foreign exchange contracts to help mitigate exposure to foreign exchange rate volatility. The contracts expire at varying dates through February 2022 and have a combined notional amount of $245 million. Fair value was measured using independent third-party information. Unrealized gains and losses associated with changes in fair value are recognized in other income, net and were not material for 2020 and 2019.

Interest rate swaps
ITC entered into forward-starting interest rate swaps to manage the interest rate risk associated with planned borrowings. The swaps, which had a combined notional value of $611 million, were terminated in May 2020 with the issuance of US$700 million senior notes. Realized losses of $31 million were recognized in other comprehensive income and are being reclassified to earnings as a component of interest expense over five years.
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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 are recognized in other income, net and were not material for 2020 and 2019.

Derivative Fair Values
The following table presents derivative assets and liabilities that are accounted for at fair value on a recurring basis.
($ millions)
Level 1 (1)
Level 2 (1)
Level 3 (1)
Total
As at December 31, 2020
Assets (2)
Energy contracts subject to regulatory deferral  38  38 
Energy contracts not subject to regulatory deferral 6  6 
Foreign exchange contracts and total return swaps16   16 
Other investments 126   126 
142 44  186 
Liabilities (3)
Energy contracts subject to regulatory deferral  (94) (94)
Energy contracts not subject to regulatory deferral (12) (12)
 (106) (106)
As at December 31, 2019
Assets (2)
Energy contracts subject to regulatory deferral — 22 — 22 
Energy contracts not subject to regulatory deferral — — 
Foreign exchange contracts, interest rate and total return swaps 14 — 18 
Other investments 121 — — 121 
135 34 — 169 
Liabilities (3)
Energy contracts subject to regulatory deferral(1)(138)— (139)
Energy contracts not subject to regulatory deferral— (12)— (12)
(1)(150)— (151)
(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)Current portion is included in accounts receivable and other current assets, with the remainder included in other assets
(3)Current portion is included in accounts payable and other current liabilities, with the remainder included in other liabilities

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Derivative Volumes
As at December 312020 2019 
Energy contracts subject to regulatory deferral (1)
Electricity swap contracts (GWh)
522 628 
Electricity power purchase contracts (GWh)
2,781 3,198 
Gas swap contracts (PJ)
156 168 
Gas supply contract premiums (PJ)
203 241 
Energy contracts not subject to regulatory deferral (1)
Wholesale trading contracts (GWh)
1,588 1,855 
Gas swap contracts (PJ)
36 43 
(1)Energy contracts settle on various dates through 2029


SELECTED ANNUAL FINANCIAL INFORMATION

Years ended December 31
($ millions, except as indicated)2020 2019 2018 
Revenue
8,935 8,783 8,390 
Net earnings
1,389 1,852 1,286 
Common Equity Earnings
1,209 1,655 1,100 
EPS: ($)
Basic
2.60 3.79 2.59 
Diluted
2.60 3.78 2.59 
Total assets
55,481 53,404 53,051 
Long-term debt (excluding current portion)
23,113 21,501 23,159 
Dividends declared: ($)
Per common share
1.965 1.855 1.750 
Per first preference share:
Series F
1.2250 1.2250 1.2250 
Series G (1)
1.0983 1.0983 1.0345 
Series H (2)
0.5003 0.6250 0.6250 
Series I (3)
0.4987 0.7771 0.7116 
Series J
1.1875 1.1875 1.1875 
Series K (4)
0.9823 0.9823 1.0000 
Series M (5)
0.9783 1.0133 1.0250 
(1)The annual dividend per share was reset to $1.0983 for the five-year period from September 1, 2018 up to but excluding September 1, 2023.
(2)The annual dividend per share was reset to $0.4588 for the five-year period from June 1, 2020 up to but excluding June 1, 2025.
(3)Floating quarterly dividend rate is reset every quarter based on the then current three-month Government of Canada Treasury Bill rate plus the applicable reset dividend yield.
(4)The annual dividend per share was reset to $0.9823 for the five-year period from March 1, 2019 up to but excluding March 1, 2024.
(5)The annual dividend per share was reset to $0.9783 for the five-year period from December 1, 2019 up to but excluding December 1, 2024.

2020/2019
For a discussion of the changes in revenue, net earnings, Common Equity Earnings, EPS, total assets and long-term debt see "Performance at a Glance" on page 5, "Operating Results" on page 9, and "Financial Position" on page 18.


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2019/2018
The increase in revenue reflected: (i) Rate Base growth, led by ITC; (ii) overall higher flow-through costs in customer rates; (iii) favourable foreign exchange; and (iv) a $91 million favourable adjustment associated with the November 2019 FERC decision at ITC. The increase was partially offset by: (i) lower revenue contribution from the Energy Infrastructure segment due primarily to the disposition of the Waneta Expansion and reduced hydroelectric production in Belize due to lower rainfall; and (ii) lower retail sales at UNS Energy due to weather.

The increase in Common Equity Earnings reflected the following significant one-time items: (i) a $484 million gain on the disposition of the Waneta Expansion; and (ii) an $83 million favourable adjustment resulting from the November 2019 FERC decision at ITC, discussed above.

Excluding the significant one-time items, the increase in Common Equity Earnings was primarily due to Rate Base growth; lower operating expenses, primarily at FortisAlberta; and favourable foreign exchange. The increase was partially offset by the impact of weather in Belize and Arizona, higher costs associated with Rate Base growth not reflected in customer rates at UNS Energy, regulatory decisions at ITC, and lower realized margins at Aitken Creek. One-time positive tax adjustments, primarily recognized in 2018, also contributed to the increase in earnings, as discussed below.

The one-time positive tax adjustments recognized in 2018 related to an election to file a consolidated state tax return and the designation of net assets related to the Waneta Expansion as held for sale totalling $30 million and $14 million, respectively. In addition, the finalization of US tax reform regulations associated with base-erosion and anti-abuse tax resulted in the recognition of income tax expense of $12 million in 2019.

The increase in EPS reflects the above-noted earnings increases, partially offset by a 12.1 million increase in the weighted average number of common shares outstanding associated with the Corporation's: (i) $1.2 billion common equity issuance in the fourth quarter of 2019; (ii) ATM Program; and (iii) DRIP and share purchase plan.

The increase in total assets was due to 2019 capital expenditures, partially offset by unfavourable foreign exchange on the translation of US dollar-denominated assets.


FOURTH QUARTER RESULTS
Sales2020 2019 Variance
Regulated utilities
UNS Energy
Retail Electricity (GWh)
2,345 2,223 122 
Wholesale Electricity (GWh)
1,871 1,814 57 
Gas (PJ)
5 — 
Central Hudson
Electricity (GWh)
1,200 1,188 12 
Gas (PJ)
7 
FortisBC Energy (PJ)
67 71 (4)
FortisAlberta (GWh)
4,138 4,279 (141)
FortisBC Electric (GWh)
894 888 
Other Electric (GWh)
2,362 2,427 (65)
Non-regulated
Energy Infrastructure (GWh)
103 14 89 

The increase in electricity sales was driven by: (i) higher retail electricity sales at UNS Energy due to favourable weather; and (ii) increased hydroelectric production in Belize due to higher rainfall levels. The increase was tempered by lower average consumption by oil and gas and commercial customers at FortisAlberta, largely associated with the COVID-19 Pandemic and the downturn in the oil and gas sector.

Gas volumes were slightly lower than 2019 due to lower consumption by transportation customers at FortisBC Energy.
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Revenue and Common Equity EarningsRevenueEarnings
($ millions, except as indicated)2020 2019 Variance2020 2019 Variance
Regulated utilities
ITC
419 500 (81)109 171 (62)
UNS Energy
525 510 15 45 38 
Central Hudson
242 226 16 35 30 
FortisBC Energy
476 428 48 74 77 (3)
FortisAlberta
139 150 (11)33 33 — 
FortisBC Electric
117 112 13 12 
Other Electric
381 381 — 32 22 10 
Non-regulated
Energy Infrastructure
47 19 28 27 21 
Corporate and Other
 — — (37)(43)
Total2,346 2,326 20 331 346 (15)
Weighted average number of common shares outstanding (millions)
465.8 447.1 18.7 
Basic EPS ($)
0.71 0.77 (0.06)

The increase in revenue was driven by: (i) overall higher flow-through costs, mainly at FortisBC Energy; (ii) Rate Base growth; and (iii) the impact of favourable weather including higher retail sales in Arizona and hydroelectric production in Belize. The increase was partially offset by the $91 million favourable ROE adjustment recorded in the fourth quarter of 2019 by ITC associated with the November 2019 FERC decision (see "Regulatory Highlights" on page 15).

The decrease in Common Equity Earnings was due primarily to the implementation of the November 2019 FERC decision in the fourth quarter of 2019 including the reversal of prior period liabilities. This impact was partially offset by Rate Base growth, the favourable impact of mark-to-market accounting of natural gas derivatives at Aitken Creek, and higher hydroelectric production in Belize.

The decrease in basic EPS reflects lower Common Equity Earnings and an increase in the weighted average number of common shares outstanding associated with the Corporation's December 2019 common equity offering.

Cash Flows
($ millions)2020 2019 Variance
Cash, beginning of period494 228 266 
Cash from (used in):
Operating activities
700 634 66 
Investing activities
(1,235)(1,104)(131)
Financing activities
308 627 (319)
Foreign exchange(18)(15)(3)
Cash, end of period249 370 (121)

Operating Activities
The variance largely reflects the upfront payment received by FortisAlberta in the fourth quarter of 2020 associated with a long-term energy retailer agreement. An increase in Operating Cash Flow associated with higher energy sales was largely offset by the timing of the recovery of flow-through costs and slower collections from customers associated with the COVID-19 Pandemic.

Investing Activities
The variance reflects higher capital expenditures in accordance with the Corporation's capital plan.

Financing Activities
See "Cash Flow Summary" on page 20.


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SUMMARY OF QUARTERLY RESULTS
Common Equity
RevenueEarningsBasic EPSDiluted EPS
Quarter Ended($ millions)($ millions)($)($)
December 31, 20202,346 331 0.71 0.71 
September 30, 20202,121 292 0.63 0.63 
June 30, 20202,077 274 0.59 0.59 
March 31, 20202,391 312 0.67 0.67 
December 31, 20192,326 346 0.77 0.77 
September 30, 20192,051 278 0.64 0.63 
June 30, 20191,970 720 1.66 1.66 
March 31, 20192,436 311 0.72 0.72 

Generally, within each calendar year, quarterly results fluctuate primarily in accordance with seasonality. Given the diversified nature of the Corporation's subsidiaries, seasonality varies. Most of the annual earnings of the gas utilities are realized in the first and fourth quarters due to space-heating requirements. Earnings for the electric distribution utilities in the US are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment.

Generally, from one calendar year to the next, quarterly results reflect: (i) continued organic growth driven by the Corporation's capital plan; (ii) any acquisitions and dispositions; (iii) any significant temperature fluctuations from seasonal norms; (iv) the timing and significance of any regulatory decisions; (v) for revenue, the flow through in customer rates of commodity costs; and (vi) for EPS, increases in the weighted average number of common shares outstanding.

December 2020/December 2019
See "Fourth Quarter Results" on page 42.

September 2020/September 2019
Common Equity Earnings increased by $14 million due mainly to: (i) Rate Base growth; (ii) increased retail sales at UNS Energy, driven largely by weather; and (iii) higher earnings from Belize, mainly from increased hydroelectric production. This growth was tempered by: (i) the delay in TEP's general rate application, resulting in approximately $1 billion of Rate Base not reflected in customer rates; and (ii) lower contributions from ITC, due to the timing of earnings associated with the FERC ROE decisions, and a lower effective tax rate in 2019. The $0.01 decrease in EPS was due primarily to an increase in the weighted average number of common shares outstanding, mainly associated with the Corporation's $1.2 billion common equity issuance in the fourth quarter of 2019, partially offset by the above noted factors.

June 2020/June 2019
Common Equity Earnings decreased by $446 million and basic EPS decreased by $1.07. Earnings for the quarter reflected significant one-time items: (i) a $484 million gain on the disposition of the Waneta Expansion in April 2019; and (ii) the reversal of a $13 million tax recovery, originally recognized in 2019, due to the finalization in April 2020 of anti-hybrid regulations associated with US tax reform, partially offset by; (iii) a $27 million favourable base ROE adjustment at ITC as a result of the May 2020 FERC decision reflecting the reversal of liabilities accrued in prior years. Notwithstanding the significant one-time items, the regulated utilities delivered improved financial results reflecting: (i) Rate Base growth; (ii) increased retail sales at UNS Energy, driven largely by weather; (iii) favourable foreign exchange; and (iv) timing of operating expenses at FortisBC Energy. This growth was tempered by lower sales in the Caribbean due to a decline in tourism-related activities and higher COVID-related expenses, driven by Central Hudson.


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March 2020/March 2019
Common Equity Earnings were comparable with 2019. Rate Base growth, lower non-recoverable operating expenses at ITC, and lower expenses in the Corporate and Other segment were tempered by: (i) higher costs associated with Rate Base growth at UNS Energy not yet reflected in rates; (ii) financial market volatility that caused a decline in the market value of certain investments that support retirement benefits at UNS Energy; and (iii) unrealized losses on foreign exchange contracts in the Corporate and Other segment. The decrease in EPS was due primarily to an increase in the weighted average number of common shares outstanding, mainly associated with the Corporation's $1.2 billion common equity issuance in the fourth quarter of 2019.


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 2020 or 2019. Inter-company balances, transactions and profit between non-regulated and regulated entities are not eliminated on consolidation. These related-party transactions include: (i) the lease of gas storage capacity and gas sales by Aitken Creek to FortisBC Energy; and (ii) the sale of capacity by the Waneta Expansion to FortisBC Electric up to the April 16, 2019 disposition of the Waneta Expansion. These transactions, which are not eliminated on consolidation, did not have a material impact on consolidated earnings, financial position or cash flows.

As at December 31, 2020, accounts receivable included approximately $28 million due from Belize Electricity (2019 - $8 million).

Fortis periodically provides short-term financing to its subsidiaries to support capital expenditures, acquisitions and seasonal working capital requirements. As at December 31, 2020, there were no material inter-segment loans outstanding (2019 - $279 million). The interest charged on inter-segment loans in 2020 and 2019 was not material.


MANAGEMENT'S EVALUATION OF CONTROLS AND PROCEDURES

Disclosure Controls and Procedures
DCP are designed to provide reasonable assurance that information required to be disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and US securities laws. As of December 31, 2020, an evaluation was carried out under the supervision of, and with the participation of, the Corporation's management, including the CEO and CFO, of the effectiveness of the Corporation's DCP, as defined in the applicable Canadian and US securities laws. Based on that evaluation, the CEO and CFO concluded that such DCP are effective as of December 31, 2020.

Internal Controls over Financial Reporting
ICFR is designed by, or under the supervision of, the Corporation's CEO and 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 US GAAP. 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 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.

The Corporation's management, including the Corporation's CEO and CFO, assessed the effectiveness of the Corporation's ICFR as of December 31, 2020, 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 of December 31, 2020, the Corporation's ICFR was effective.

During the year ended December 31, 2020, there have been no changes in the Corporation's ICFR that have materially affected, or are reasonably likely to materially affect, the Corporation's ICFR.


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OUTLOOK

The Corporation maintains its positive long-term outlook. Fortis continues to enhance shareholder value through the execution of its capital plan, the balance and strength of its diversified portfolio of utility businesses, and growth opportunities within and proximate to its service territories. While uncertainty exists due to the COVID-19 Pandemic, the Corporation does not currently expect it to have a material financial impact in 2021.

The Corporation's $19.6 billion five-year capital plan is expected to increase Rate Base from $30.5 billion in 2020 to $36.4 billion by 2023 and $40.3 billion by 2025, translating into three- and five-year CAGRs of approximately 6.5% and 6.0%, respectively. Beyond the five-year capital plan, Fortis continues to pursue additional energy infrastructure opportunities including: further expansion of LNG infrastructure in British Columbia; the fully permitted, cross-border, Lake Erie Connector electric transmission project in Ontario; and the acceleration of cleaner energy infrastructure investments across our jurisdictions.

Fortis expects long-term growth in Rate Base will support earnings and dividend growth. Fortis is targeting average annual dividend growth of approximately 6% through 2025. This dividend growth guidance is premised on the assumptions listed under "Forward-Looking Information" below, including no material impact from the COVID-19 Pandemic, the expectation of reasonable outcomes for regulatory proceedings, and the successful execution of the five-year capital plan.


FORWARD-LOOKING INFORMATION

Fortis includes forward-looking information in the MD&A within the meaning of applicable Canadian securities laws and forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, (collectively referred to as "forward-looking information"). Forward-looking information reflects expectations of Fortis management regarding future growth, results of operations, performance, business prospects and opportunities. Wherever possible, words such as anticipates, believes, budgets, could, estimates, expects, forecasts, intends, may, might, plans, projects, schedule, should, target, will, would and the negative of these terms and other similar terminology or expressions have been used to identify the forward-looking information, which includes, without limitation: the expectation that the COVID-19 Pandemic will not have a material financial impact in 2021 and will not impact the five-year capital plan; targeted average annual dividend growth through 2025; forecast capital expenditures for 2021-2025 and expected funding sources; forecast Rate Base and Rate Base growth for 2023 and 2025; the expectation that long-term growth in Rate Base will support earnings and dividend growth; the expectation that Fortis will remain at the forefront of the industry and is well positioned to capitalize on evolving industry opportunities; expected timing, outcome and impact of regulatory decisions; expected or potential funding sources for operating expenses, interest costs and capital plans; the exp