EX-99.2

EX-99.2 3 d251833dex992.htm EX-99.2 EX-99.2

Exhibit 99.2

LOGO

Management’s Discussion & Analysis

As at February 14, 2022

Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its subsidiaries and investments during the fourth quarter of 2021 relative to the same quarter in 2020; for the full year of 2021 relative to 2020 and selected financial information for 2019; and its financial position as at December 31, 2021 relative to December 31, 2020. Throughout this discussion, “Emera Incorporated”, “Emera” and “Company” refer to Emera Incorporated and all of its consolidated subsidiaries and investments. The Company’s activities are carried out through five reportable segments: Florida Electric Utility, Canadian Electric Utilities, Other Electric Utilities, Gas Utilities and Infrastructure, and Other.

This discussion and analysis should be read in conjunction with the Emera Incorporated annual audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2021. Emera follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”).

The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities, revenues and expenses. At December 31, 2021, Emera’s rate-regulated subsidiaries and investments include:


Emera Rate-Regulated Subsidiary or Equity Investment		Accounting Policies Approved/Examined By
Subsidiary
Tampa Electric – Electric Division of Tampa Electric Company (“TEC”)		Florida Public Service Commission (“FPSC”) and the Federal Energy Regulatory Commission (“FERC”)
Nova Scotia Power Inc. (“NSPI”)		Nova Scotia Utility and Review Board (“UARB”)
Barbados Light & Power Company Limited (“BLPC”)		Fair Trading Commission, Barbados (“FTC”)
Grand Bahama Power Company Limited (“GBPC”)		The Grand Bahama Port Authority (“GBPA”)
Dominica Electricity Services Ltd. (“Domlec”)		Independent Regulatory Commission, Dominica (“IRC”)
Peoples Gas System (“PGS”) – Gas Division of TEC		FPSC
New Mexico Gas Company, Inc. (“NMGC”)		New Mexico Public Regulation Commission (“NMPRC”)
SeaCoast Gas Transmission, LLC (“SeaCoast”)		FPSC
Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”)		Canadian Energy Regulator (“CER”)
Equity Investments
NSP Maritime Link Inc. (“NSPML”)		UARB
Labrador Island Link Limited Partnership (“LIL”)		Newfoundland and Labrador Board of Commissioners of Public Utilities (“NLPUB”)
St. Lucia Electricity Services Limited (“Lucelec”)		National Utility Regulatory Commission (“NURC”)
Maritimes & Northeast Pipeline Limited Partnership and Maritimes & Northeast Pipeline, LLC (“M&NP”)		CER and FERC

On March 24, 2020, the Company completed the sale of Emera Maine. For further detail, refer to the “Significant Items Affecting Earnings” section.

All amounts are in Canadian dollars (“CAD”), except for the Florida Electric Utility, Other Electric Utilities and Gas Utilities and Infrastructure sections of the MD&A, which are reported in US dollars (“USD”), unless otherwise stated.

Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR at www.sedar.com.

TABLE OF CONTENTS


Forward-looking Information		3
Introduction and Strategic Overview		3
Non-GAAP Financial Measures		5
Consolidated Financial Review		7
Significant Items Affecting Earnings		7
Consolidated Financial Highlights by Business Segment		8
Consolidated Income Statement Highlights		9
Business Overview and Outlook		13
COVID-19 Pandemic		13
Florida Electric Utility		13
Canadian Electric Utilities		14
Other Electric Utilities		18
Gas Utilities and Infrastructure		19
Other		21
Consolidated Balance Sheet Highlights		22
Developments		23
Outstanding Stock Data		24
Financial Highlights		25
Florida Electric Utility		25
Canadian Electric Utilities		28
Other Electric Utilities		32
Gas Utilities and Infrastructure		34
Other		38
Liquidity and Capital Resources		41
Consolidated Cash Flow Highlights		42
Working Capital		43
Contractual Obligations		43
Forecasted Gross Consolidated Capital Expenditures		44
Debt Management		45
Credit Ratings		47
Guaranteed Debt		47
Share Capital		48
Pension Funding		48
Off-Balance Sheet Arrangements		49
Dividend Payout Ratio		50
Transactions with Related Parties		50
Enterprise Risk and Risk Management		51
Risk Management including Financial Instruments		63
Disclosure and Internal Controls		65
Critical Accounting Estimates		66
Changes in Accounting Policies and Practices		72
Future Accounting Pronouncements		72
Summary of Quarterly Results		73

FORWARD-LOOKING INFORMATION

This MD&A contains “forward-looking information” and statements which reflect the current view with respect to the Company’s expectations regarding future growth, results of operations, performance, carbon dioxide emissions reduction goals, business prospects and opportunities, and may not be appropriate for other purposes within the meaning of applicable Canadian securities laws. All such information and statements are made pursuant to safe harbour provisions contained in applicable securities legislation. The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecast”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time at which, such events, performance or results will be achieved.

The forward-looking information is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors that could cause results or events to differ from current expectations include without limitation: regulatory risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; liquidity and capital market risk; future dividend growth; timing and costs associated with certain capital investments; the expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology that could reduce demand for electricity; global climate change; weather; unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk; counterparty risk; disruption of fuel supply; country risks; environmental risks; foreign exchange; regulatory and government decisions, including changes to environmental, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology infrastructure and cybersecurity risks; uncertainties associated with infectious diseases, pandemics and similar public health threats, such as the COVID-19 novel coronavirus (“COVID-19”) pandemic; market energy sales prices; labour relations; and availability of labour and management resources.

Readers are cautioned not to place undue reliance on forward-looking information, as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking information in this MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise.

INTRODUCTION AND STRATEGIC OVERVIEW

Based in Halifax, Nova Scotia, Emera owns and operates cost-of-service rate-regulated electric and gas utilities in Canada, the United States and the Caribbean. Cost-of-service utilities provide essential electric and gas services in designated territories under franchises and are overseen by regulatory authorities. Emera’s strategic focus continues to be safely delivering cleaner, affordable and reliable energy to its customers.

Emera’s investment in rate-regulated businesses is concentrated in Florida and Nova Scotia. These service areas have generally experienced stable regulatory policies and economic conditions. Emera’s portfolio of regulated utilities provides reliable earnings, cash flow and dividends. Earnings opportunities in regulated utilities are generally driven by the magnitude of net investment in the utility (known as “rate base”), and the amount of equity in the capital structure and the return on that equity (“ROE”) as approved through regulation. Earnings are also affected by sales volumes and operating expenses.

Emera’s capital investment plan is $8.4 billion over the 2022-to-2024 period (including a $240 million equity investment in the LIL in 2022), with an additional $1 billion of potential capital investments over the same period. This results in a forecasted rate base growth of approximately 7 per cent to 8 per cent through 2024. The capital investment plan continues to include significant investments across the portfolio in renewable and cleaner generation, reliability and integrity investments, infrastructure modernization and customer-focused technologies. Emera’s capital investment plan is being funded primarily through internally generated cash flows and debt raised at the operating company level. Equity requirements in support of the Company’s capital investment plan are expected to be funded through the issuance of preferred equity and the issuance of common equity through Emera’s dividend reinvestment plan and at-the-market program. Maintaining investment-grade credit ratings is a priority of management.

Seasonal patterns and other weather events affect demand and operating costs. Similarly, mark-to-market adjustments and foreign currency exchange can have a material impact on financial results for a specific period. Emera’s consolidated net income and cash flows are impacted by movements in the US dollar relative to the Canadian dollar and benefit from a weaker Canadian dollar. Emera may hedge both transactional and translational exposure. These impacts, as well as the timing of capital investments and other factors, mean that results in any one quarter are not necessarily indicative of results in any other quarter or for the year as a whole.

Energy markets worldwide are facing significant change and Emera is well positioned to respond to shifting customer demands, digitization, decarbonization, complex regulatory environments and decentralized generation.

Customers are looking for more choice, better control, and enhanced reliability in a time where costs of decentralized generation and storage have become more competitive in some regions. Advancing technologies are transforming the way utilities interact with their customers and generate and transmit energy. In addition, climate change and extreme weather are shaping how utilities operate and how they invest in infrastructure. There is also an overall need to replace aging infrastructure and further enhance reliability. Emera sees opportunity in all of these trends. Emera’s strategy is to fund investments in renewable energy and technology assets which protect the environment and benefit customers through fuel or operating cost savings.

For example, significant investments to facilitate the use of renewable and low-carbon energy include the Maritime Link in Atlantic Canada, the ongoing construction of solar generation and modernization of the Big Bend Power Station at Tampa Electric and planned NSPI investments to enable the retirement of its coal units and to achieve renewable energy targets. Emera’s utilities are also investing in reliability projects and replacing aging infrastructure. All of these projects demonstrate Emera’s strategy of safely delivering cleaner, reliable, and affordable energy for its customers.

Building on its decarbonization progress over the past 15 years, Emera is continuing its efforts by establishing clear carbon reduction goals and a vision to achieve net-zero carbon dioxide emissions by 2050.

This vision is inspired by Emera’s strong track record, the Company’s experienced team, and a clear path to Emera’s interim carbon goals. With existing technologies and resources and the benefit of supportive regulatory decisions, Emera plans and expects to achieve the following goals compared to corresponding 2005 levels:

•

A 55 per cent reduction in carbon dioxide emissions by 2025.

•

An 80 per cent reduction in coal usage by 2023 and the retirement of Emera’s last existing coal unit no later than 2040.

•

At least an 80 per cent reduction in carbon dioxide emissions by 2040.

Emera seeks to deliver on its Climate Commitment while maintaining its focus on investing in reliability and never losing sight of affordability for customers. Emera is also committed to identifying emerging technologies and continuing to work constructively with policymakers, regulators, partners, investors and customers to achieve these goals and realize its net-zero vision.

Emera is committed to world-class safety, operational excellence, good governance, excellent customer service, reliability, being an employer of choice, and building constructive relationships.

NON-GAAP FINANCIAL MEASURES

Emera uses financial measures that do not have standardized meaning under USGAAP and may not be comparable to similar measures presented by other entities. Emera calculates the non-GAAP measures by adjusting certain GAAP measures for specific items the Company believes are significant, but not reflective of underlying operations in the period. These measures are discussed and reconciled below.

Adjusted Net Income Attributable to Common Shareholders, Adjusted Earnings Per Common Share – Basic and Dividend Payout Ratio of Adjusted Net Income

Emera calculates an adjusted net income attributable to common shareholders (“adjusted net income”) measure by excluding the effect of mark-to-market (“MTM”) adjustments, impacts in 2020 of the gain on sale of Emera Maine, and impairment charges on certain other assets.

The MTM adjustments are a result of the following:

•

MTM adjustments related to Emera’s held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered, and the related amortization of transportation capacity recognized as a result of certain Emera Energy marketing and trading transactions;

•

MTM adjustments included in Emera’s equity income related to the business activities of Bear Swamp Power Company LLC (“Bear Swamp”);

•

MTM adjustments related to equity securities held in BLPC and Emera Reinsurance, a captive reinsurance company in the Other segment; and

•

MTM adjustments related to Emera’s foreign exchange cash flow hedges entered to manage foreign exchange earnings exposure.

Management believes excluding from net income the effect of these MTM valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows and ongoing operations of the business, and allows investors to better understand and evaluate the business. Management and the Board of Directors exclude these MTM adjustments for evaluation of performance and incentive compensation. For further detail on MTM adjustments, refer to the “Consolidated Financial Review”, “Financial Highlights – Other Electric Utilities”, and “Financial Highlights – Other” sections.

In 2020, the Company recognized a gain on the sale of Emera Maine and certain non-cash impairment charges. Management believes excluding these from net income better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business. For further details, refer to the “Significant Items Affecting Earnings” and “Financial Highlights – Other” sections. While the gain on sale has been excluded from adjusted earnings, earnings for the Other Electric Utilities segment includes earnings from Emera Maine up to the date of its sale on March 24, 2020.

Adjusted earnings per common share – basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are calculated using adjusted net income attributable to common shareholders, as described above. For further details on dividend payout ratio of adjusted net income, see the “Dividend Payout Ratio” section.

Emera calculates adjusted net income and adjusted earnings per common share – basic for the Other Electric Utilities and Other segments. Reconciliation to the nearest GAAP measure is included in each segment. Please refer to “Financial Highlights – Other Electric Utilities” and “Financial Highlights – Other” sections.

The following reconciles reported net income attributable to common shareholders to adjusted net income attributable to common shareholders; and reported earnings per common share – basic, to adjusted earnings per common share – basic:


	Three months ended				Year ended
For the	December 31				December 31
millions of Canadian dollars (except per share amounts)		2021		2020		2021		2020		2019

Net income attributable to common shareholders	$	324	$	273	$	510	$	938	$	663

Gain on sale, net of tax and transaction costs (1)		-		-		-		309		-

Impairment charges, net of tax (2)		-		-		-		(26)		(34)

After-tax MTM gains (losses) (3)		156		85		(213)		(10)		76

Adjusted net income attributable to common shareholders	$	168	$	188	$	723	$	665	$	621

Earnings per common share – basic	$	1.24	$	1.09	$	1.98	$	3.78	$	2.76

Adjusted earnings per common share – basic	$	0.64	$	0.75	$	2.81	$	2.68	$	2.59

(1) Net of income tax expense of $276 million for the year ended December 31, 2020
(2) Net of income tax expense of $1 million for the year ended December 31, 2020 (2019 – nil)
(3) Net of income tax expense of $63 million for the three months ended December 31, 2021 (2020 – $33 million expense) and $86 million recovery for the year ended December 31, 2021 (2020 – $8 million recovery) (2019 – $31 million expense)

EBITDA and Adjusted EBITDA

Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) is a non-GAAP financial measure used by Emera. EBITDA is used by numerous investors and lenders to better understand cash flows and credit quality. EBITDA is useful to assess Emera’s operating performance and indicates the Company’s ability to service or incur debt, invest in capital and finance working capital requirements.

Adjusted EBITDA is a non-GAAP financial measure used by Emera. Similar to adjusted net income calculations described above, this measure represents EBITDA absent the income effect of Emera’s MTM adjustments, the gain on sale of Emera Maine and impairment charges.

The Company’s EBITDA and Adjusted EBITDA may not be comparable to the EBITDA measures of other companies but, in management’s view, appropriately reflect Emera’s specific operating performance. These measures are not intended to replace “Net income attributable to common shareholders” which, as determined in accordance with GAAP, is an indicator of operating performance.

The following is a reconciliation of reported net income to EBITDA and Adjusted EBITDA:


	Three months ended				Year ended
For the	December 31				December 31
millions of Canadian dollars		2021		2020		2021		2020		2019

Net income (1)	$	338	$	284	$	561	$	984	$	710

Interest expense, net		151		159		611		679		738

Income tax expense (recovery)		85		57		(6)		341		61

Depreciation and amortization		227		217		902		881		903

EBITDA	$	801	$	717	$	2,068	$	2,885	$	2,412

Gain on sale, net of transaction costs (excluding income tax)		-		-		-		585		-

Impairment charges, excluding income tax		-		-		-		(25)		(34)

MTM gains (losses), excluding income tax		219		118		(299)		(18)		107

Adjusted EBITDA	$	582	$	599	$	2,367	$	2,343	$	2,339

(1) Net income is before Non-controlling interest in subsidiaries and Preferred stock dividends.

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Earnings

Earnings Impact of After-Tax MTM Gains and Losses

After-tax MTM gains increased $71 million to $156 million in Q4 2021, compared to $85 million in Q4 2020, primarily due to settlements and changes in existing positions at Emera Energy. These were partially offset by higher amortization on gas transportation assets in Q4 2021 at Emera Energy and the reversal of 2020 foreign exchange gains on cash flow hedges. For the year ended December 31, 2021, after-tax MTM losses increased $203 million to $213 million compared to $10 million for the same period in 2020 due to changes in existing positions at Emera Energy and the reversal of 2020 foreign exchange gains on cash flow hedges.

2020 TECO Guatemala Holdings (“TGH”) International Arbitration and Award

On November 24, 2020, a payment was made by the Republic of Guatemala in satisfaction of an award issued by the International Centre for the Settlement of Investment Disputes tribunal in 2013. The payment of $49 million ($36 million after tax or $0.15 per common share), net of legal costs was related to a dispute over an investment in a Guatemala local distribution company and was recognized in “Other Income” on the Consolidated Statements of Income. For further detail, refer to note 27 in the consolidated financial statements.

2020 Gain on Sale and Impairment Charges

On March 24, 2020, Emera completed the sale of Emera Maine for a total enterprise value of $2.0 billion ($1.4 billion USD). A gain on sale of $585 million ($309 million after tax, or $1.26 per common share), net of transaction costs, was recognized in “Other Income” on the Consolidated Statements of Income.

In addition, impairment charges of $25 million ($26 million after tax) for the year ended December 31, 2020 were recognized on certain other assets.

Consolidated Financial Highlights by Business Segment


For the	Three months ended				Year ended
millions of Canadian dollars		December 31				December 31
Adjusted net income		2021		2020		2021		2020		2019

Florida Electric Utility	$	85	$	101	$	462	$	501	$	419

Canadian Electric Utilities		67		57		241		221		229

Other Electric Utilities		5		8		20		33		76

Gas Utilities and Infrastructure		55		45		198		162		183

Other		(44)		(23)		(198)		(252)		(286)

Adjusted net income attributable to common shareholders	$	168	$	188	$	723	$	665	$	621

Gain on sale, net of tax and transaction costs		-		-		-		309		-

Impairment charges, net of tax		-		-		-		(26)		(34)

After-tax MTM gains (losses)		156		85		(213)		(10)		76

Net income attributable to common shareholders	$	324	$	273	$	510	$	938	$	663


The following table highlights the significant changes in adjusted net income attributable to common shareholders from 2020 to 2021:

For the		Three months ended		Year ended
millions of Canadian dollars		December 31		December 31

Adjusted net income – 2020	$	188	$	665

Operating Unit Performance
Increased earnings at Emera Energy Services (“EES”) due to favourable market conditions		9		37

Increased earnings at PGS due to higher base revenues as a result of a base rate increase on January 1, 2021 and customer growth		10		36

Increased earnings at NSPI due to increased sales volumes quarter-over-quarter. Year-over-year increased due to higher operating revenues, lower interest on the Fuel Adjustment Mechanism (“FAM”) regulatory deferral and decreased income tax expense		7		15

Decreased earnings at Tampa Electric due to higher depreciation and amortization expense, reflecting increased capital investment and a 2020 regulatory settlement, the impact of a stronger CAD and lower base revenue due to weather, partially offset by higher allowance for funds used during construction (“AFUDC”)		(16)		(39)

Decreased earnings due to the sale of Emera Maine in Q1 2020		-		(6)

Tax Related
Revaluation of Corporate, NSPI and Emera Energy net deferred income tax assets and liabilities in Q1 2020 due to the reduction in the Nova Scotia provincial corporate income tax rate		-		14

Recognition of corporate income tax recovery in Q1 2020 previously deferred as a regulatory liability in 2018 at BLPC		-		(10)

Corporate
Decreased interest expense, pre-tax, due to the impact of a stronger CAD and lower interest rates. Year-over-year also due to repayment of corporate debt		6		35

Realized gain on hedges entered into to hedge foreign exchange earnings exposure		2		19

TGH award, net of tax and legal costs in Q4 2020. Refer to the “Significant Items Affecting Earnings” section		(36)		(36)

Other Variances		(2)		(7)

Adjusted net income – 2021	$	168	$	723

For further details of reportable segments contributions, refer to the “Financial Highlights” section.


For the	Year ended December 31
millions of Canadian dollars		2021		2020		2019

Operating cash flow before changes in working capital	$	1,337	$	1,420	$	1,598

Change in working capital		(152)		217		(73)

Operating cash flow	$	1,185	$	1,637	$	1,525

Investing cash flow	$	(2,332)	$	(1,224)	$	(1,617)

Financing cash flow	$	1,311	$	(372)	$	14


For further discussion of cash flow, refer to the “Consolidated Cash Flow Highlights” section.

As at		December 31
millions of Canadian dollars		2021		2020		2019

Total assets	$	34,244	$	31,234	$	31,842

Total long-term debt (including current portion)	$	14,658	$	13,721	$	14,180

Consolidated Income Statement Highlights


For the	Three months ended						Year ended						Year ended
millions of Canadian dollars		December 31						December 31						December 31
(except per share amounts)		2021		2020		Variance		2021		2020		Variance		2019

Operating revenues	$	1,868	$	1,537	$	331	$	5,765	$	5,506	$	259			$	6,111

Operating expenses		1,352		1,148		(204)		4,835		4,359		(476)				4,768

Income from operations	$	516	$	389	$	127	$	930	$	1,147	$	(217)			$	1,343

Income from equity investments		32		36		(4)		143		149		(6)				154

Other income, net		26		75		(49)		93		708		(615)				12

Interest expense, net		151		159		8		611		679		68				738

Income tax expense (recovery)		85		57		(28)		(6)		341		347				61

Net income	$	338	$	284	$	54	$	561	$	984	$	(423)			$	710

Net income attributable to common shareholders	$	324	$	273	$	51	$	510	$	938	$	(428)			$	663

Gain on sale, net of tax and transaction costs		-		-		-		-		309		(309)				-

Impairment charges, net of tax		-		-		-		-		(26)		26				(34)

After-tax MTM gains (losses)		156		85		71		(213)		(10)		(203)				76

Adjusted net income attributable to common shareholders	$	168	$	188	$	(20)	$	723	$	665	$	58			$	621

Earnings per common share – basic	$	1.24	$	1.09	$	0.15	$	1.98	$	3.78	$	(1.80)			$	2.76

Earnings per common share – diluted	$	1.20	$	1.08	$	0.12	$	1.98	$	3.78	$	(1.80)			$	2.76

Adjusted earnings per common share – basic	$	0.64	$	0.75	$	(0.11)	$	2.81	$	2.68	$	0.13			$	2.59

Dividends per common share declared	$	0.6625	$	0.6375	$	0.0250	$	2.5750	$	2.4750	$	0.1000			$	2.3750

Adjusted EBITDA	$	582	$	599	$	(17)	$	2,367	$	2,343	$	24			$	2,339

Operating Revenues

For the fourth quarter of 2021, operating revenues increased $331 million compared to the fourth quarter in 2020. Absent increased MTM gains of $112 million, operating revenues increased $219 million due to:

•

$97 million increase in the Florida Electric Utility segment due to higher fuel recovery clause revenues as a result of higher fuel costs, partially offset by lower base revenue due to less favourable weather than in Q4 2020 and the impact of a stronger CAD;

•

$82 million increase in the Gas Utilities and Infrastructure segment due to base rate increases at PGS and NMGC effective January 1, 2021, customer growth at PGS, and higher purchased gas adjustment clause revenues at PGS and NMGC as a result of higher gas prices. These increases were partially offset by the impact of a stronger CAD;

•

$21 million increase in the Other Electric Utilities segment due to higher fuel revenue at BLPC due to higher fuel prices; and

•

$17 million increase in Other segment due to higher marketing and trading margin at EES, primarily driven by favourable market conditions.

For the year ended December 31, 2021, operating revenues increased $259 million compared to 2020. Absent increased MTM losses of $241 million, operating revenues increased by $500 million due to:

•

$244 million increase in the Florida Electric Utility segment due to higher fuel recovery clause revenues as a result of higher fuel costs, partially offset by lower base revenue due to less favourable weather than in the prior year and the impact of a stronger CAD;

•

$222 million increase in the Gas Utilities and Infrastructure segment due to base rate increases at PGS and NMGC effective January 1, 2021, customer growth at PGS, and higher purchased gas adjustment clause revenues at PGS and NMGC as a result of higher gas prices. These increases were partially offset by the impact of a stronger CAD; and

•

$64 million increase in Other segment due to higher marketing and trading margin at EES, primarily driven by favourable market conditions.

These impacts were partially offset by:

•

$29 million decrease in the Other Electric Utilities segment due to the sale of Emera Maine in Q1 2020.

Operating Expenses

For the fourth quarter of 2021, operating expenses increased $204 million compared to the fourth quarter of 2020. Operating expenses increased due to:

•

$121 million increase in the Florida Electric Utility segment due to higher natural gas prices, partially offset by the impact of a stronger CAD;

•

$73 million increase in the Gas Utilities and Infrastructure segment due to higher gas prices at PGS and NMGC, partially offset by the impact of a stronger CAD; and

•

$28 million increase in the Other Electric Utilities segment due to higher fuel prices at BLPC.

For the year ended December 31, 2021, operating expenses increased $476 million compared to 2020. Absent the 2020 impairment charges of $26 million, operating expenses increased $502 million due to:

•

$331 million increase in the Florida Electric Utility segment due to higher natural gas prices, partially offset by the impact of a stronger CAD;

•

$187 million increase in the Gas Utilities and Infrastructure segment due to higher gas prices at PGS and NMGC, partially offset by the impact of a stronger CAD; and

•

$42 million increase in the Other Electric segment due to higher fuel prices at BLPC.

These impacts were partially offset by:

•

$48 million decrease in the Other Electric Utilities segment due to the sale of Emera Maine in Q1 2020.

Other Income, Net

Other income, net decreased for Q4 2021 and year ended December 31, 2021, compared to the same periods in 2020, primarily due to the TGH award in Q4 2020. For the year ended December 31, 2021, the decrease was also primarily due to the pre-tax gain on sale of Emera Maine in Q1 2020.

Interest Expense, Net

Interest expense, net was lower for Q4 2021 and year ended December 31, 2021, compared to the same periods in 2020, due to the impact of a stronger CAD and lower interest rates. For the year ended December 31, 2021, the decrease was also due to the repayment of long-term corporate debt.

Income Tax (Recovery) Expense

The increase in income tax expense for Q4 2021, compared to the same period in 2020, was primarily due to increased income before provision for income taxes. The decrease in income tax expense in 2021, compared to 2020, was primarily due to the gain on sale of Emera Maine.

Net Income and Adjusted Net Income

For the fourth quarter of 2021, the decrease in net income attributable to common shareholders, compared to the same period in 2020, was favourably impacted by the $71 million increase in after-tax MTM gains primarily related to Emera Energy. Absent the favourable MTM changes, adjusted net income decreased $20 million. The decrease was primarily due to the TGH award in Q4 2020 and lower earnings at Tampa Electric, partially offset by higher earnings contribution from PGS, EES, and NSPI.

For the year ended December 31, 2021, net income attributable to common shareholders, compared to the same period in 2020, was unfavourably impacted by the $309 million after-tax gain on sale of Emera Maine in 2020, unfavourably impacted by the $203 million increase in after-tax MTM losses primarily related to Emera Energy, and favourably impacted by the $26 million after-tax impairment charge in 2020. Absent the net gain on sale of Emera Maine in 2020, the unfavourable MTM changes and the 2020 impairment charges, adjusted net income increased $58 million. The increase was primarily due to higher earnings contribution from EES, PGS and NSPI, lower corporate interest expense, realized gains on foreign exchange hedges and the 2020 revaluation of deferred taxes due to a reduction in the Nova Scotia corporate income tax rate. The increase was partially offset by the TGH award in Q4 2020, the impact of a stronger CAD, and the 2020 recognition of a corporate income tax recovery previously deferred as a regulatory liability in 2018 at BLPC.

Earnings and Adjusted Earnings per Common Share – Basic

Earnings per common share – basic were higher for Q4 2021, compared to Q4 2020 due to increased earnings as discussed above, partially offset by the impact of the increase in weighted average shares outstanding. Adjusted earnings per common share – basic were lower for Q4 2021 compared to Q4 2020 due to decreased earnings as discussed above, and the impact of the increase in weighted average shares outstanding.

Earnings per common share – basic for the year ended December 31, 2021 decreased compared to 2020 due to the decreased earnings as discussed above, and the impact of the increase in weighted average shares outstanding. Adjusted earnings per common share were higher for the year ended December 31, 2021, compared to 2020, due to increased adjusted earnings as discussed above, partially offset by the impact of the increase in weighted average shares outstanding.

Effect of Foreign Currency Translation

Emera operates internationally including in Canada, the US and various Caribbean countries. As such, the Company generates revenues and incurs expenses denominated in local currencies which are translated into CAD for financial reporting. Changes in translation rates, particularly in the value of the USD against the CAD, can positively or adversely affect results.

In general, Emera’s earnings benefit from a weakening CAD and are adversely impacted by a strengthening CAD. The impact of foreign exchange in any period is driven by rate changes, the timing of earnings from foreign operations during the period, the percentage of earnings from foreign operations in the period and the impact of entered foreign exchange cash flow hedges to manage foreign exchange earnings exposure.

Results of foreign operations are translated at the weighted average rate of exchange and assets and liabilities of foreign operations are translated at period end rates. The relevant CAD/USD exchange rates for 2021 and 2020 are as follows:


	Three months ended				Year ended
	December 31				December 31
	2021		2020		2021		2020

Weighted average CAD/USD	$	1.26	$	1.30	$	1.26	$	1.34

Period end CAD/USD exchange rate	$	1.27	$	1.27	$	1.27	$	1.27

Strengthening of the CAD decreased net income by $10 million and decreased adjusted net income by $1 million in Q4 2021, compared to Q4 2020. The strengthening of the CAD decreased net income by $17 million and adjusted net income by $28 million for the year ended December 31, 2021, compared to 2020.

Consistent with the Company’s risk management policies, Emera partially manages currency risks through matching US denominated debt to finance its US operations and uses foreign currency derivative instruments to hedge specific transactions and earnings exposure. Emera does not utilize derivative financial instruments for foreign currency trading or speculative purposes.

The table below includes Emera’s significant segments whose contributions to adjusted earnings are recorded in USD currency.


	Three months ended					Year ended
For the	December 31					December 31

millions of US dollars	2021			2020		2021			2020

Florida Electric Utility	$	67		$	76	$	369		$	372

Other Electric Utilities		4			5		16			24

Gas Utilities and Infrastructure (1)		37			30		130			97

Other segment (2)		(20	)		5		(98	)		(102	)

Total (3)	$	88		$	116	$	417		$	391

(1) Includes USD net income from PGS, NMGC, SeaCoast and M&NP.

(2) Includes Emera Energy’s USD adjusted net income from EES, Bear Swamp and interest expense on Emera Inc.’s USD denominated debt.

(3) Net of $122 million in after-tax MTM gain for the three months ended December 31, 2021 (2020 – $62 million after-tax MTM gain) and after-tax MTM loss of $164 million for the year ended December 31, 2021 (2020 – $11 million after-tax MTM loss, and $212 million gain on sale of Emera Maine, net of tax and transaction costs).

BUSINESS OVERVIEW AND OUTLOOK

COVID-19 Pandemic

The Company’s priorities continue to be the reliable delivery of essential energy services to meet customers’ demands while maintaining the health and safety of its customers and employees and supporting the communities in which Emera operates.

While the ongoing COVID-19 pandemic continues to have varying effects on the service territories in which Emera operates, on a consolidated basis, COVID-19 did not have a material financial impact on net income in 2021. Capital project delays and supply chain disruptions have also been minimal. The Company continues to monitor developments, economic conditions and recommendations by local and national public health authorities related to COVID-19 and is adjusting operational requirements as needed.

The extent of the future impact of COVID-19 on the Company’s financial results and business operations cannot be predicted at this time but is not expected to have a material financial impact in 2022. Future impacts will depend on a variety of factors, including the duration and severity of the pandemic, timing and effectiveness of vaccinations, further government actions and future economic activity and energy usage.

Potential future impacts of COVID-19 on the business may include the following:

•

Lower earnings as a result of lower sales volumes due to economic slowdowns and the pace and strength of economic recovery;

•

Delays of capital projects as a result of construction shutdowns, government restrictions on non-essential capital work, travel restrictions for contractors or supply chain disruptions;

•

Deferral of and adjustment to regulatory filings, hearings, decisions and recovery periods; and

•

Decreased cash flow from operations due to lower earnings and slower collection of accounts receivable or increased credit losses.

The Company currently expects to continue to have adequate liquidity given its cash position, existing bank facilities, and access to capital, but will continue to monitor the impact of COVID-19 on future cash flows. For further detail, refer to the “Liquidity and Capital Resources” section.

Refer to the outlook sections by segment below, for affiliate specific impacts, if applicable.

Florida Electric Utility

Florida Electric Utility consists of Tampa Electric, a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity, serving customers in West Central Florida. Tampa Electric has $10.7 billion USD of assets and approximately 810,600 customers at December 31, 2021. Tampa Electric owns 5,919 MW of generating capacity, of which 77 per cent is natural gas-fired, 12 per cent is solar and 11 per cent is coal. Tampa Electric owns 2,165 kilometres of transmission facilities and 19,530 kilometres of distribution facilities.

Beginning in 2022, Tampa Electric’s approved regulated ROE range is 9.00 per cent to 11.00 per cent, based on an allowed equity capital structure of 54 per cent (2021 – 9.25 per cent to 11.25 per cent based on an allowed equity capital structure of 54 per cent). An ROE of 9.95 per cent (2021 – 10.25 per cent) will be used for the calculation of the return on investments for clauses. See below for further detail.

Tampa Electric anticipates earning within its ROE range in 2022. New base rates effective January 1, 2022 will result in higher 2022 USD earnings than in 2021. Tampa Electric sales volumes are expected to be similar to 2021, which benefited from weather that was warmer than normal (a 20-year statistical degree day average). Tampa Electric expects customer growth rates in 2022 to be consistent with 2021, reflective of current expected economic growth in Florida.

On January 19, 2022, Tampa Electric requested a mid-course adjustment to its fuel and capacity charges to recover an additional $169 million USD, effective with April 2022 customer bills, due to an increase in fuel commodity and capacity costs. The FPSC is expected to issue its decision in March 2022.

On August 6, 2021, Tampa Electric filed with the FPSC a joint motion for approval of a settlement agreement (the “Settlement Agreement”) by Tampa Electric and the intervenors in relation to its rate case filed with the FPSC in April 2021. The Settlement Agreement provides for a projected increase of $191 million USD in rates annually, effective with January 2022 bills. This increase will consist of $123 million USD in base rate charges and $68 million USD to recover the costs of retiring assets including, Big Bend coal generation assets Units 1 through 3 and meter assets. The Settlement Agreement further includes two subsequent year adjustments of $90 million USD and $21 million USD, effective January 2023 and January 2024, respectively related to the recovery of future investments in the Big Bend Modernization project and solar generation. The allowed equity in the capital structure will continue to be 54 per cent from investor sources of capital. The Settlement Agreement includes an allowed regulated ROE range of 9.0 per cent to 11.0 per cent with a 9.95 per cent midpoint. It also provides for a 25 basis point increase in the allowed ROE range and mid-point, and $10 million USD of additional revenue, if U.S. Treasury Bond yields exceed a specific threshold set on the date the FPSC votes to approve the agreement. Under the agreement, base rates will not further change from January 1, 2022 through December 31, 2024, unless Tampa Electric’s earned ROE were to fall below the bottom of the range during that time. The Settlement Agreement contains a provision whereby Tampa Electric agrees to quantify the future impact of a change in tax rates on net operating income through a reduction or increase in base revenues within 180 days of when such tax change becomes law or its effective date. The Settlement Agreement further creates a mechanism to recover the costs of retiring coal generation units and meter assets over a period of 15 years which survives the term of that agreement. The Settlement Agreement sets new depreciation and dismantlement rates effective January 1, 2022 and contains the provisions that Tampa Electric will not have to file another depreciation study during the term of the agreement but will file a new depreciation study no more than one year, nor less than 90 days, before the filing of its next general base rate proceeding. Tampa Electric agreed not to hedge natural gas through the period ending on December 31, 2024. On October 21, 2021, the FPSC approved the Settlement Agreement and the final order, reflecting such approval, was issued in November 2021.

In 2022, capital investment in the Florida Electric Utility segment is expected to be $1.1 billion USD (2021 - $1.2 billion USD), including AFUDC. Capital projects include continuation of the modernization of the Big Bend Power Station, solar investments, grid modernization and storm hardening investments.

Canadian Electric Utilities

Canadian Electric Utilities includes NSPI and ENL. NSPI is a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity and the primary electricity supplier to customers in Nova Scotia. ENL is a holding company with equity investments in NSPML and LIL: two transmission investments related to the development of an 824 MW hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador.

NSPI

With $6.1 billion of assets and approximately 536,000 customers, NSPI owns 2,420 MW of generating capacity, of which approximately 44 per cent is coal-fired; 28 per cent is natural gas and/or oil; 19 per cent is hydro and wind; 7 per cent is petcoke and 2 per cent is biomass-fueled generation. In addition, NSPI has contracts to purchase renewable energy from independent power producers (“IPPs”) which own 546 MW of capacity. NSPI owns approximately 5,000 kilometres of transmission facilities and 28,000 kilometres of distribution facilities.

NSPI’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 40 per cent. Due to continued rate base growth, NSPI anticipates earning within its allowed ROE range in 2022 and expects earnings to be consistent with 2021. Warmer than normal weather adversely affected NSPI’s sales volumes in 2021. Assuming normal weather in 2022, NSPI expects sales volumes to be higher than 2021.

NSPI is currently operating under a three-year fuel stability plan which results in an average annual overall rate increase of 1.5 per cent to recover fuel costs for the period of 2020 through 2022. These rates include recovery of Maritime Link costs (discussed below in the “ENL, NSPML” section).

On January 27, 2022, NSPI filed a General Rate Application (“GRA”) with the UARB. The GRA proposes a rate stability plan for 2022 through 2024 which includes average base rate increases of 2.9 per cent per year and average fuel rate increases pursuant to the FAM of 0.8 per cent per year on August 1, 2022, January 1, 2023 and January 1, 2024. The proposed rates would result in annualized incremental revenue (base and fuel rates) increases of $52 million in 2022 ($21 million related to August 1, 2022 through December 31, 2022), $54 million in 2023 and $56 million in 2024. A decision by the UARB is expected later this year.

NSPI is subject to environmental laws and regulations set by both the Government of Canada and the Province of Nova Scotia. NSPI continues to work with both levels of government to comply with these laws and regulations to maximize efficiency of emission control measures and minimize customer cost. NSPI anticipates that costs prudently incurred to achieve legislated reductions will be recoverable under NSPI’s regulatory framework.

Over the past several years, the requirement to reduce Nova Scotia’s reliance on higher carbon and GHG emitting sources of energy has resulted in NSPI making significant investments in renewable energy sources, including energy from the Maritime Link, and purchasing renewable energy from IPPs.

In Q1 2021, NSPI received its 2021 granted emissions allowances under the Nova Scotia Cap-and-Trade Program Regulations. These 2021 allowances will be used in 2021 or allocated within the initial four-year compliance period that ends in 2022. In addition to the granted allowances, NSPI is permitted to purchase up to five per cent of the credits available at provincial auctions. Any remaining allowance shortfall requires the purchase of reserve credits directly from the provincial government. Reserve credits are anticipated to be priced at a premium to provincial auction pricing. Compliance is forecast to be achieved through granted emissions allowances, reduced emissions partly due to delivery of energy from Muskrat Falls, and credit purchases under the Cap-and-Trade Program, including reserve credits. NSPI anticipates that any prudently incurred costs required to comply with the Government of Canada’s laws and regulations, and the Nova Scotia Cap-and-Trade Program Regulations, will be recoverable under NSPI’s regulatory framework.

Energy from renewable sources has increased with Nalcor Energy’s (“Nalcor”) NS Block delivery obligations from the Muskrat Falls hydroelectric project (“Muskrat Falls”) commencing August 15, 2021. Nalcor will provide NSPI with approximately 900 GWh of energy annually over 35 years. In addition, for the first five years of the NS Block, NSPI is also entitled to receive approximately 240 GWh of additional energy from the Supplemental Energy Block transmitted through the Maritime Link. As Nalcor is in the final stages of commissioning the LIL, there will be periodic commissioning related interruptions in supply with any resultant delivery shortfalls being delivered at a date to be agreed to by the companies. Commencing in September 2022, NSPI has the option of purchasing additional market-priced energy from Nalcor through the Energy Access Agreement. Pursuant to the Energy Access Agreement, Nalcor is obligated to offer NSPI a minimum average of 1.2 TWh of energy annually. Nalcor is forecasting it will achieve final commissioning of the Lower Churchill projects (including Muskrat Falls and LIL) in the first half of 2022.

Under the provincially legislated Renewable Energy Regulations, 40 per cent of electric sales must be generated from renewable sources. This standard was predicated on receipt of the full NS Block. Due to the delay of the NS Block, the provincial government provided NSPI with an alternative compliance plan in 2020, as permitted by the legislation. The alternative compliance plan requires NSPI to supply customers with at least 40 per cent of energy generated from renewable sources over the 2020 through 2022 period. With full delivery of the NS Block having only recently commenced, NSPI’s ability to achieve 40 per cent of total sales from renewable sources over the 2020 through 2022 period may be at risk. If NSPI is found not to have acted in a duly diligent manner, it could be subject to a maximum penalty of $10 million. As 2022 progresses, NSPI will monitor its progress toward achieving the 40 per cent standard and, as per the requirements of the Renewable Energy Regulations, NSPI intends to act in a duly diligent manner.

There have been several recent environmental developments at both the federal and provincial levels, as described further below. These developments are consistent with NSPI’s decarbonization strategy and will facilitate an accelerated transition to cleaner energy. NSPI is engaging with the federal and provincial governments, customers and stakeholders to work towards achieving these requirements, goals and targets with a focus on customer affordability.

On November 5, 2021, the provincial government enacted Bill 57, “Environmental Goals and Climate Change Reduction Act,” which signals the provincial government’s intent to implement several climate change related goals and greenhouse gas reduction targets, many of which overlap with and replace provisions of pre-existing acts. The legislation also introduces a goal to phase out coal-fired electricity generation in Nova Scotia by 2030. Subsequent provincial regulations will be required to detail how these goals and targets will be achieved.

On August 5, 2021, the federal government issued an update to the Pan-Canadian Framework on Clean Growth and Climate Change under the “Greenhouse Gas Pollution Pricing Act”. This update (the “Federal Benchmark”) applies to the 2023 through 2030 period and puts in place the legal mechanism for increasing the carbon tax in Canada by $15 per tonne annually and reaching $170 per tonne by 2030. It also outlines the minimum compliance criteria for recognizing systems like the Nova Scotia Cap-and-Trade Program to be considered equivalent to the Federal Benchmark.

On July 9, 2021, the provincial government amended the Renewable Electricity Regulations, mandating that 80 per cent of electric sales be generated from renewable sources by 2030.

On June 29, 2021, the federal government enacted Bill C-12 “Canadian Net-Zero Emissions Accountability Act” with the objective of attaining net-zero emissions by 2050.

In 2022, NSPI expects to invest $530 million (2021 – $388 million), including AFUDC, primarily in capital projects to support system reliability, renew hydroelectric infrastructure, and increase renewable energy.

ENL

Total equity earnings from NSPML and LIL are expected to be higher in 2022, compared to 2021. Both the NSPML and LIL investments are recorded as “Investments subject to significant influence” on Emera’s Consolidated Balance Sheets.

NSPML

Equity earnings from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. NSPML’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 30 per cent.

The Maritime Link assets entered service on January 15, 2018 enabling the transmission of energy between Newfoundland and Nova Scotia, improved reliability and ancillary benefits, supporting the efficiency and reliability of energy in both provinces. Nalcor continues to advance towards completion of the LIL with Nalcor forecasting it will achieve final commissioning in the first half of 2022. Nalcor’s NS Block delivery obligations commenced on August 15, 2021 and the NS Block will be delivered over the next 35 years pursuant to the project agreements. As Nalcor is in the final stages of commissioning the LIL, there will be commissioning related interruptions in supply with any resultant delivery shortfalls being delivered at a date to be agreed to by the companies.

NSPML received UARB approval to collect up to $172 million (2020 – $145 million) from NSPI for the recovery of costs associated with the Maritime Link in 2021. This was subject to a holdback of up to $10 million that was dependent upon the timing of commencement of the NS Block. On January 18, 2022, the UARB directed NSPI to pay to NSPML approximately $10 million of the 2021 holdback. NSPML has deferred collection and recognition of $23 million in depreciation expense. Approximately $162 million is included in NSPI rates in 2022.

On August 9, 2021, NSPML filed a final capital cost application with the UARB, seeking approval to recover capital costs associated with the Maritime Link and approval of NSPML’s 2022 assessment. In December 2021, NSPML obtained an interim decision from the UARB approving interim rates beginning January 1, 2022, until receipt of the UARB’s decision on the application. On February 9, 2022, the UARB issued its decision relating to the Maritime Link Project, approving NSPML’s requested rate base of approximately $1.8 billion less costs that would not otherwise have been recoverable if incurred by NSPI. The UARB also approved approximately $168 million of NSPML revenue requirement in 2022 subject to a holdback of $2 million per month beginning April 1, 2022 and thereafter to the end of the year. This holdback is to be used to fund any replacement energy costs incurred by NSPI due to a 10 per cent or greater shortfall in contracted NS Block deliveries each month and will otherwise be released to NSPML. NSPML is required to provide the UARB with a compliance filing by February 16, 2022 which will confirm the impacts of this decision including the amount of the unrecoverable items which are not expected to exceed $10 million (pre-tax).

In 2022, NSPML expects to invest approximately $5 million (2021 – $6 million) in capital.

LIL

ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and Nalcor is forecasting it will achieve final commissioning in the first half of 2022.

Equity earnings from the LIL investment are based upon the book value of the equity investment and the approved ROE. Emera’s current equity investment is $682 million, comprised of $410 million in equity contribution and $272 million of accumulated equity earnings. Emera’s total equity contribution in the LIL, excluding accumulated equity earnings, is estimated to be approximately $650 million after the Lower Churchill projects are completed.

Cash earnings and return of equity will begin after commissioning of the LIL by Nalcor, which is anticipated in the first half of 2022, and until that point Emera will continue to record AFUDC earnings.

Other Electric Utilities

Other Electric Utilities includes Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities. ECI’s regulated utilities include vertically integrated regulated electric utilities of BLPC on the island of Barbados, GBPC on Grand Bahama Island, a 51.9 per cent interest in Domlec on the island of Dominica and a 19.5 per cent interest in Lucelec on the island of St. Lucia which is accounted for on the equity basis.

On March 24, 2020, Emera completed the sale of Emera Maine which is included in the Other Electric Utilities segment for Q1 2020.

BLPC

With $489 million USD of assets and approximately 132,000 customers, BLPC owns 266 MW of generating capacity, of which 96 per cent is oil-fired and four per cent is solar. The utility has an additional 12 MW of capacity from rental units. BLPC owns approximately 188 kilometres of transmission facilities and 3,800 kilometres of distribution facilities. BLPC’s approved regulated return on rate base is 10.0 per cent.

GBPC

With $349 million USD of assets and approximately 19,000 customers, GBPC owns 98 MW of oil-fired generation, approximately 90 kilometres of transmission facilities and 670 kilometres of distribution facilities. Restoration of the generating units damaged by Hurricane Dorian was completed in 2021. GBPC’s approved regulatory return on rate base for 2022 is 8.23 per cent (2021 – 8.37 per cent). See below for further details.

Domlec

Domlec serves approximately 35,700 customers. Domlec owns 26.7 MW of generating capacity, of which 75 per cent is oil-fired and 25 per cent is hydro. Domlec owns approximately 475 kilometres of transmission facilities and 709 kilometres of distribution facilities. Domlec’s approved regulated return on rate base is 15.0 per cent.

Other Electric Utilities Outlook

Other Electric Utilities’ USD earnings in 2022 are expected to increase over the prior year due to higher earnings due to higher base rates at GBPC and BLPC and the continued recovery in local economies from the impacts of COVID-19.

BLPC currently operates pursuant to a franchise to generate, transmit and distribute electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation amending the number of licenses required for the supply of electricity from a single integrated license which currently exists, to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. In March 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject to the passage of implementing legislation. Following a general election called late in 2021 for January 19, 2022, the new licenses are expected to take effect in 2022 on completion of the legislative process. The Dispatch license will have a term of five years with the remaining licenses having terms ranging from 25-30 years. BLPC anticipates that any increased costs associated with the implementation of the new multi-licensed structure will be recoverable through BLPC’s regulatory framework. BLPC is currently assessing the full impact of the new licenses on its business and working towards the successful implementation of the licenses.

On October 4, 2021 BLPC submitted a general rate review application to the FTC. The application seeks a rate adjustment and the implementation of a cost reflective rate structure that will facilitate the changes expected in the newly reformed electricity market and the country’s transition towards 100 per cent renewable energy generation. The application seeks recovery of capital investment in plant, equipment and related infrastructure and results in an increase in annual non-fuel revenue of approximately $23 million USD upon approval. The application includes a request for an allowed regulatory ROE of 12.50 per cent on an allowed equity capital structure of 65 per cent. A decision is expected from the FTC in the second half of 2022.

On January 14, 2022, the GBPA issued its decision on GBPC’s application for rate review that was filed with the GBPA on September 23, 2021. The decision, which becomes effective April 1, 2022, allows for an increase in revenues of $3.5 million USD. The new rates include a regulatory ROE of 12.84 per cent.

In 2022, capital investment in the Other Electric Utilities segment is expected to be $100 million USD (2021 – $88 million USD), primarily in more efficient and cleaner sources of generation, including renewables and battery storage.

Gas Utilities and Infrastructure

Gas Utilities and Infrastructure includes PGS, NMGC, SeaCoast, Brunswick Pipeline and Emera’s non-consolidated investment in M&NP. PGS is a regulated gas distribution utility engaged in the purchase, distribution and sale of natural gas serving customers in Florida. NMGC is an intrastate regulated gas distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving customers in New Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering services in Florida. Brunswick Pipeline is a regulated 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick, to markets in the northeastern United States.

Peoples Gas System

With $2.2 billion USD of assets and approximately 445,000 customers, the PGS system includes 23,150 kilometres of natural gas mains and 13,100 kilometres of service lines. Natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) was 1.9 billion therms in 2021.

The approved ROE range for PGS is 8.9 per cent to 11.0 per cent, based on an allowed equity capital structure of 54.7 per cent. An ROE of 9.9 per cent is used for the calculation of return on investments for clauses.

New Mexico Gas Company, Inc.

With $1.7 billion USD of assets and approximately 542,000 customers, NMGC serves approximately 60 per cent of New Mexico’s population in 24 of the state’s 33 counties. NMGC’s system includes approximately 2,424 kilometres of transmission pipelines and 17,593 kilometres of distribution pipelines. Annual natural gas throughput was approximately 839 million therms in 2021.

The approved ROE for NMGC is 9.375 per cent, on an allowed equity capital structure of 52 per cent.

Gas Utilities and Infrastructure Outlook

Gas Utilities and Infrastructure USD earnings are anticipated to be higher in 2022 than 2021, primarily due to rate base growth to expand the distribution system and to continue to reliably serve customers. The PGS rate case settlement provides the ability to reverse a total of $34 million USD of accumulated depreciation through 2023. PGS has not reversed any of this accumulated depreciation to date. The reversal of accumulated depreciation is expected to occur over the 2022 and 2023 periods.

PGS anticipates earning within its allowed ROE range in 2022 and expects rate base and USD earnings to be higher than in 2021. PGS expects favourable customer growth in 2022 (following Florida’s population growth and housing demands), PGS sales volumes in 2022 are expected to increase at a level consistent with customer growth.

NMGC anticipates earning near its authorized ROE in 2022 and expects rate base to be higher than 2021. NMGC expects customer growth rates to be consistent with historical trends.

On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective January 2023. NMGC requested a $41 million USD increase in annual base revenues primarily as a result of increased operating costs and capital investments in pipelines and related infrastructure. A decision from the NMPRC is expected by the end of 2022.

In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in an incremental $108 million USD for gas costs above what it would normally have paid during this period. NMGC normally recovers gas supply and related costs through a purchased gas adjustment clause. On April 16, 2021, NMGC filed a Motion for Extraordinary Relief, as permitted by the NMPRC rules, to extend the terms of the repayment of the incremental gas costs and to recover a carrying charge. On June 15, 2021 the NMPRC approved the recovery of $108 million USD and related borrowing costs over a period of 30 months beginning July 1, 2021.

In 2018, SeaCoast executed an agreement with Seminole Electric Cooperative, Inc. (“Seminole”) to provide long-term firm gas transportation service to Seminole’s new gas-fired generating facility being constructed in Putnam County, Florida. SeaCoast will operate a 21-mile, 30-inch pipeline lateral that will be treated as a sales-type lease for accounting purposes. The lease of the pipeline lateral to Seminole will commence in 2022. The capital investment is approximately $100 million USD, with the majority of the project investment completed through 2021.

In 2022, capital investment in the Gas Utilities and Infrastructure segment is expected to be approximately $445 million USD (2021 - $407 million USD), including AFUDC. PGS will make investments to expand its system and support customer growth. NMGC will continue to make investments to maintain the reliability of its system and support customer growth.

Other

The Other segment includes those business operations that in a normal year are below the required threshold for reporting as separate segments; and corporate expense and revenue items that are not directly allocated to the operations of Emera’s subsidiaries and investments.

Business operations in the Other segment include Emera Energy and Emera Technologies LLC (“ETL”). Emera Energy consists of EES, a wholly owned physical energy marketing and trading business and an equity investment in a 50.0 per cent joint venture ownership of Bear Swamp, a 633 MW pumped storage hydroelectric facility in northwestern Massachusetts. ETL is a wholly owned technology company focused on finding ways to deliver renewable and resilient energy to customers.

Corporate items included in the Other segment are certain corporate-wide functions including executive management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate business development, corporate governance, investor relations, risk management, insurance, acquisition and disposition related costs, gains or losses on select assets sales, and corporate human resource activities. It includes interest revenue on intercompany financings and interest expense on corporate debt in both Canada and the US. It also includes costs associated with corporate activities that are not directly allocated to the operations of Emera’s subsidiaries and investments.

Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas and electricity markets, which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 usually providing the greatest opportunity for earnings. EES is generally expected to deliver annual adjusted net income within its guidance range of $15 to $30 million USD ($45 to $70 million USD of margin).

The adjusted net loss from the Other segment is expected to be higher in 2022, based on EES returning to its normal earnings range in 2022, higher operating, maintenance and general (“OM&G”) expenses, lower realized foreign exchange gains on cash flow hedges and increased interest expense. The decrease is expected to be partially offset by decreased taxes due to a higher net loss.

In 2022, capital investment in the Other segment is expected to be $2 million (2021 – $1 million).

CONSOLIDATED BALANCE SHEET HIGHLIGHTS

Significant changes in the Consolidated Balance Sheets between December 31, 2020 and December 31, 2021 include:


millions of Canadian dollars	Increase (Decrease)	Explanation
Assets
Cash and cash equivalents	$ 174	Increased due to cash from operations, net issuances of debt at TEC, NMGC and GBPC, and issuance of preferred and common stock. This was partially offset by investments in property, plant and equipment and dividends on common stock.
Inventory	85	Increased due to higher commodity prices at Emera Energy, and higher fuel inventory and materials inventory at NSPI.
Derivative instruments (current and long-term)	203	Increased due to higher commodity prices and new derivative contracts, partially offset by settlements at NSPI.
Regulatory assets (current and long-term)	982	Increased due to the Tampa Electric capital cost recovery for early retired assets, increased deferrals related to the FAM and increased deferred income tax regulatory assets at NSPI, and the NMGC winter event gas cost recovery. These were partially offset by decreased pension and post-retirement plan deferrals at Tampa and PGS.
Receivables and other assets (current and long-term)	674	Increased due to higher cash collateral and trade receivables due to higher commodity prices and increased gas transportation assets at Emera Energy and higher pension and post-retirement assets at TEC and NSPI.
Property, plant and equipment, net of accumulated depreciation and amortization	818	Increased due to additions at Tampa Electric, PGS and NSPI, partially offset by the reclassification related to the Tampa Electric capital cost recovery for early retired assets.
Liabilities and Equity
Short-term debt and long-term debt (including current portion)	$ 1,054	Increased due to issuances of long-term debt at TEC, NMGC and GBPC and net issuance on committed credit facilities at TEC, NSPI and Corporate. These were partially offset by repayment of debt at TEC.
Accounts payable	337	Increased due to higher commodity prices at Emera Energy, higher natural gas prices at Tampa Electric, and increased cash collateral positions on derivative instruments at NSPI.
Deferred income tax liabilities, net of deferred income tax assets	153	Increased due to tax deductions in excess of accounting depreciation related to property, plant and equipment.
Derivative instruments (current and long-term)	344	Increased due to new contracts in 2021 and changes in existing positions, partially offset by reversal of 2020 contracts at Emera Energy.
Regulatory liabilities (current and long-term)	94	Increased due to deferrals related to derivative instruments at NSPI, partially offset by decreased deferred income tax regulatory liabilities, primarily due to amortization of excess deferred income taxes related to US Tax Reform at Tampa Electric, PGS and NMGC.
Pension and post-retirement liabilities	(83)	Decreased due to favourable changes in actuarial assumptions and higher investment returns on pension plan assets at NSPI.
Other liabilities (current and long-term)	113	Increased due to investment tax credits related to solar projects at Tampa Electric and emissions compliance charges at NSPI.
Common stock	537	Increased due to shares issued under Emera’s at-the-market equity program and the dividend reinvestment plan.
Cumulative preferred stock	418	Increased due to issuances of preferred shares.
Accumulated other comprehensive income	104	Decrease in unrecognized pension and post-retirement benefit costs due to favourable changes in actuarial assumptions, higher than anticipated investment returns and amortization at NSPI, partially offset by the effect of a stronger CAD on the translation of Emera’s foreign affiliates.
Retained earnings	(147)	Decreased due to dividends paid in excess of net income.

DEVELOPMENTS

Increase in Common Dividends

On September 24, 2021, the Emera Board of Directors approved an increase in the annual common share dividend rate to $2.65 from $2.55. The first payment was effective November 15, 2021. Emera also extended its dividend growth rate target of four to five per cent through 2024.

Tampa Electric Rate Case Settlement Agreement

On August 6, 2021, Tampa Electric filed with the FPSC a joint motion for approval of a Settlement Agreement by Tampa Electric and the intervenors in relation to its rate case filed with the FPSC in April 2021. The Settlement Agreement provides for a projected increase of $191 million USD in rates annually, effective with January 2022 bills. This increase will consist of $123 million USD in base rate charges and $68 million USD to recover the costs of retiring assets including Big Bend coal generation assets Units 1 through 3 and meter assets. The Settlement Agreement further includes two subsequent year adjustments of $90 million USD and $21 million USD, effective January 2023 and January 2024, respectively related to the recovery of future investments in the Big Bend Modernization project and solar generation. The allowed equity in the capital structure will continue to be 54 per cent from investor sources of capital. The Settlement Agreement includes an allowed regulated ROE range of 9.0 per cent to 11.0 per cent with a 9.95 per cent midpoint. On October 21, 2021, the FPSC approved the settlement agreement, and the final order reflecting such approval, was issued on November 10, 2021. For further information, refer to the “Business Overview and Outlook – Florida Electric Utility” section.

Delivery of NS Block

Nalcor’s NS Block delivery obligations commenced on August 15, 2021, and delivery will continue over the next 35 years pursuant to the project agreements. As Nalcor is in the final stages of commissioning the LIL, there will be commissioning related interruptions in supply, with any resultant delivery shortfalls being delivered at a date to be agreed to by the companies. On August 9, 2021, NSPML filed a final capital cost application with the UARB seeking approval to recover capital costs associated with the Maritime Link and approval of NSPML’s 2022 assessment. In December 2021, NSPML obtained an interim decision from the UARB approving interim rates beginning January 1, 2022, until receipt of the UARB’s decision on the application. On February 9, 2022, the UARB issued its decision relating to the Maritime Link Project, approving NSPML’s requested rate base of approximately $1.8 billion less costs that would not otherwise have been recoverable if incurred by NSPI. For further information on the NS Block and the UARB decision, refer to the “Business Overview and Outlook – Canadian Electric Utilities” and “Contractual Obligations” sections.

Preferred Shares

On September 24, 2021, Emera issued 9 million Cumulative Redeemable First Preferred Shares, Series L at $25.00 per share at an annual yield of 4.60 per cent. The aggregate gross and net proceeds from the offering were $225 million and $222 million, respectively. The net proceeds of the preferred share offering were used for general corporate purposes.

On April 6, 2021, Emera issued 8 million Cumulative Minimum Rate Reset First Preferred Shares, Series J at $25.00 per share at an initial dividend rate of 4.25 per cent. The aggregate gross and net proceeds from the offering were $200 million and $196 million, respectively. The net proceeds of the preferred share offering were used for general corporate purposes.

Appointments

Board of Directors

Effective February 11, 2022, Paula Y. Gold-Williams joined the Emera Board of Directors. Ms. Gold-Williams is the former president and CEO of CPS Energy, the largest municipally-owned energy utility in the U.S., serving the city of San Antonio, Texas.

Effective February 11, 2022, Ian E. Robertson joined the Emera Board of Directors. Mr. Robertson is Chief Executive Officer of the Northern Genesis group of special purpose acquisition companies focused on identifying and acquiring energy transition businesses which demonstrate strong sustainability and Environmental, Social and Governance (“ESG”) alignment. He is the former CEO of Algonquin Power & Utilities Corp., a publicly traded, diversified international generation, transmission, and distribution utility.

Effective August 10, 2021, Gil C. Quiniones joined the Emera Board of Directors. Mr. Quiniones is the former President and Chief Executive Officer of the New York Power Authority. Effective October 13, 2021, Mr. Quiniones resigned from the Emera Board of Directors following an appointment to a new senior executive position at a different organization.

Executive

On September 14, 2021, Emera announced that Helen Wesley was appointed President of PGS effective December 1, 2021. Ms. Wesley was most recently the Chief Operating Officer at PGS and succeeds T.J. Szelistowski who retired in December 2021.

OUTSTANDING STOCK DATA


Common stock
	millions of		millions of
Issued and outstanding:	shares		Canadian dollars

Balance, December 31, 2019		242.48		$	6,216

Issuance of common stock (1)		4.54			251

Issued for cash under Purchase Plans at market rate		3.99			219

Discount on shares purchased under Dividend Reinvestment Plan		-			(4	)

Options exercised under senior management stock option plan		0.42			20

Employee Share Purchase Plan		-			3

Balance, December 31, 2020		251.43		$	6,705

Issuance of common stock (2)		4.99			284

Issued for cash under Purchase Plans at market rate		4.32			239

Discount on shares purchased under Dividend Reinvestment Plan		-			(4	)

Options exercised under senior management stock option plan		0.33			14

Employee Share Purchase Plan		-			4

Balance, December 31, 2021		261.07		$	7,242

(1) As at December 31, 2020, 4,544,025 common shares were issued under Emera’s at-the-market program (“ATM program”) at an average price of $56.04 per share for gross proceeds of $255 million ($251 million net of issuance costs).

(2) In Q4 2021, 1,247,300 common shares were issued under Emera’s ATM program at an average price of $59.89 per share for gross proceeds of $74 million ($73 million net of after-tax issuance costs). For the year ended December 31, 2021, 4,987,123 common shares were issued under Emera’s ATM program at an average price of $57.63 per share for gross proceeds of $287 million ($284 million net of after-tax issuance costs). As at December 31, 2021, an aggregate gross sales limit of $457 million remained available for issuance under the ATM program.

As at February 8, 2022, the amount of issued and outstanding common shares was 261.2 million.

The weighted average shares of common stock outstanding – basic, which includes both issued and outstanding common stock and outstanding deferred share units, for the three months ended December 31, 2021 was 260.8 million (2020 – 251.3 million). The weighted average shares of common stock outstanding – basic for the year ended December 31, 2021 was 257.2 million (2020 – 247.8 million).

ATM Equity Program

On August 12, 2021, Emera renewed its ATM Program that allows the Company to issue up to $600 million of common shares from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price. The ATM Program was renewed pursuant to a prospectus supplement to the Company’s short form base shelf prospectus dated August 5, 2021. The ATM program is expected to remain in effect until September 5, 2023.

FINANCIAL HIGHLIGHTS

Florida Electric Utility

All amounts are reported in USD, unless otherwise stated.


For the		Three months ended December 31				Year ended December 31
millions of US dollars (except per share amounts)		2021		2020		2021		2020

Operating revenues – regulated electric	$	561	$	468	$	2,174	$	1,849

Regulated fuel for generation and purchased power	$	212	$	127	$	713	$	428

Contribution to consolidated net income	$	67	$	76	$	369	$	372

Contribution to consolidated net income – CAD	$	85	$	101	$	462	$	501

Contribution to consolidated earnings per common share – basic – CAD	$	0.33	$	0.40	$	1.80	$	2.02

Net income weighted average foreign exchange rate – CAD/USD	$	1.25	$	1.31	$	1.25	$	1.34

Net Income

Highlights of the net income changes are summarized in the following table:


For the millions of US dollars	Three months ended December 31			Year ended December 31

Contribution to consolidated net income – 2020	$ 76		$	372

Increased operating revenues - see Operating Revenues - Regulated Electric below	92			324

Increased fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below	(85	)		(285	)

Increased OM&G expenses due to the timing of deferred clause recoveries, increased general consulting costs and higher insurance costs	(11	)		(15	)

Increased depreciation and amortization due to increase property, plant and equipment and a 2020 regulatory settlement	(7	)		(35	)

Increased AFUDC earnings due to the Big Bend Power Station modernization and solar projects	4			15

Other	(2	)		(7	)

Contribution to consolidated net income – 2021	$ 67		$	369

Florida Electric Utility’s CAD contribution to consolidated net income decreased $16 million in Q4 2021, compared to Q4 2020, and decreased $39 million in 2021, compared to 2020. Decreases in both periods were due to higher depreciation and amortization expense, reflecting increased capital investment and a 2020 regulatory settlement, the impact of a stronger CAD, and lower base revenue, partially offset by higher AFUDC earnings.

The impact of the change in the foreign exchange rate decreased CAD earnings for the quarter and year ended December 31, 2021 by $4 million and $34 million, respectively.

Operating Revenues – Regulated Electric

Electric revenues increased $93 million to $561 million in Q4 2021, compared to $468 million in Q4 2020, and increased $325 million to $2,174 million in 2021, compared to $1,849 million in 2020. Increases in both periods were due to higher fuel recovery clause revenue as a result of higher fuel costs, partially offset by lower base revenues resulting from less favourable weather compared to 2020.

Electric revenues and sales volumes are summarized in the following tables by customer class:


Q4 Electric Revenues
millions of US dollars

	2021		2020

Residential	$	289	$	256

Commercial		163		132

Industrial		48		34

Other (1)		61		46

Total	$	561	$	468

(1) Other includes sales to public authorities, off-system sales to other utilities and regulatory deferrals related to clauses.

Q4 Electric Sales Volumes


Gigawatt hours (“GWh”)

	2021		2020

Residential		2,312		2,465

Commercial		1,525		1,526

Industrial		537		460

Other		501		515

Total		4,875		4,966

Annual Electric Revenues


millions of US dollars

	2021		2020

Residential	$	1,156	$	1,018

Commercial		602		506

Industrial		172		133

Other (1)		244		192

Total	$	2,174	$	1,849

(1) Other includes sales to public authorities, off-system sales to other utilities and regulatory deferrals related to clauses.

Annual Electric Sales Volumes


GWh

	2021		2020

Residential		9,941		10,122

Commercial		6,144		6,058

Industrial		2,122		1,891

Other		2,000		1,958

Total		20,207		20,029

Regulated Fuel for Generation and Purchased Power

Tampa Electric is required to maintain a generating capacity greater than firm peak demand. The total Tampa Electric-owned generation capacity at December 31, 2021 is 5,919 MW. Tampa Electric meets the planning criteria for reserve capacity established by the FPSC, which is a 20 per cent reserve margin over firm peak demand.

Regulated fuel for generation and purchased power increased $85 million to $212 million in Q4 2021, compared to $127 million in Q4 2020, and increased $285 million to $713 million in 2021, compared to $428 million in 2020. The increases in both periods were primarily due to increased natural gas prices.

Q4 Production Volumes


GWh

	2021		2020

Natural gas		4,130		3,616

Coal		64		344

Solar		255		232

Purchased power		377		747

Total		4,826		4,939


Q4 Average Fuel Costs

US dollars	2021		2020

Dollars per Megawatt hour (“MWh”)	$	44	$	26

Annual Production Volumes


GWh

	2021		2020

Natural gas		16,142		16,523

Coal		1,342		904

Solar		1,252		1,120

Purchased power		2,301		2,513

Total		21,037		21,060


Annual Average Fuel Costs

US dollars	2021		2020

Dollars per MWh	$	34	$	20

Tampa Electric’s fuel costs are affected by commodity prices and generation mix that is largely dependent on economic dispatch of the generating fleet, bringing the lowest cost options on first (renewable energy from solar), such that the incremental cost of production increases as sales volumes increase. Generation mix may also be affected by plant outages, plant performance, availability of lower priced short-term purchased power, availability of renewable solar generation, and compliance with environmental standards and regulations.

Average fuel cost per MWh increased in Q4 2021 and for the year ended December 31, 2021, compared to the same periods 2020, primarily due to increased natural gas prices.

Regulatory Recovery Mechanisms

Tampa Electric is regulated by FPSC and is also subject to regulation by the FERC. The FPSC sets rates at a level that allows utilities such as Tampa Electric to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of Tampa Electric, the FPSC or other interested parties.

Solar Base Rate Adjustments Included in Base Rates

As of December 31, 2021, Tampa Electric has invested $850 million in 600 MW of utility-scale solar photovoltaic projects, which are recoverable through FPSC-approved solar base rate adjustments (“SoBRAs”). AFUDC was earned on these projects during construction. The FPSC has approved SoBRAs representing a total of 600 MW, or $104 million annually in estimated revenue requirements for in-service projects.

The true-up filing for SoBRAs tranche 1 and 2 revenue requirement estimates which were included in base rates as of September 2018 and January 2019, respectively, was submitted on April 30, 2020, and the FPSC approved the amount on August 18, 2020. A $5 million true-up was returned to customers in 2020. The true-up filing for SoBRA tranche 3, included in base rates as of January 2020, was approved by the FPSC on October 12, 2021. An estimated $4 million true-up was returned to customers during 2021. The true-up for SoBRA tranche 4 will be filed in early 2022.

Other Cost Recovery

Fuel Recovery Clause

Tampa Electric has a fuel recovery clause approved by the FPSC, allowing the opportunity to recover fluctuating fuel expenses from customers through annual fuel rate adjustments. Differences between prudently incurred fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a fuel clause regulatory asset or liability and recovered from or returned to customers in a subsequent year.

Storm Protection Plan Cost Recovery Clause

Tampa Electric has a Storm Protection Plan cost recovery clause allowing recovery of prudent transmission and distribution storm hardening costs for incremental activities not already included in base rates as outlined in the programs in its approved Storm Protection Plan. Differences between prudently incurred clause-recoverable costs and amounts recovered from customers through electricity rates in a year are deferred and recovered from or returned to customers in a subsequent year.

Other Cost Recovery Clauses

The FPSC annually approves cost-recovery rates for purchased power, capacity, environmental and conservation costs including a return on capital invested. Differences between prudently incurred clause-recoverable costs and amounts recovered from customers through electricity rates in a year are deferred to a corresponding regulatory asset or liability and recovered from or returned to customers in a subsequent year.

Storm Reserve

The storm reserve is for hurricanes and other named storms that cause significant damage to Tampa Electric’s system. Tampa Electric can petition the FPSC to seek recovery of restoration costs over a 12-month period, or longer, as determined by the FPSC, as well as to replenish the reserve.

Capital Cost Recovery for Early Retired Assets

This regulatory asset is related to the remaining net book value of Big Bend Power Station Units 1 through 3 and smart meter assets that were retired. The balance earns a rate of return as permitted by the FPSC and will be recovered as a separate line item on customer bills for a period of 15 years. This recovery mechanism is authorized by and survives the term of the settlement agreement approved by the FPSC in 2021.

Canadian Electric Utilities


		Three months ended				Year ended
For the		December 31				December 31
millions of Canadian dollars (except per share amounts)		2021		2020		2021		2020

Operating revenues – regulated electric	$	389	$	377	$	1,501	$	1,494

Regulated fuel for generation and purchased power (1)	$	263	$	219	$	817	$	721

Income from equity investments	$	25	$	21	$	103	$	96

Contribution to consolidated net income	$	67	$	57	$	241	$	221

Contribution to consolidated earnings per common share – basic	$	0.26	$	0.23	$	0.94	$	0.89

(1) Regulated fuel for generation and purchased power includes NSPI’s FAM and fixed cost deferrals on the Consolidated Statements of Income, however it is excluded in the segment overview.

Canadian Electric Utilities’ contribution to consolidated net income is summarized in the following table:


		Three months ended				Year ended
For the		December 31				December 31
millions of Canadian dollars		2021		2020		2021		2020

NSPI	$	43	$	36	$	141	$	125

Equity investment in LIL		14		12		51		49

Equity investment in NSPML		10		9		49		47

Contribution to consolidated net income	$	67	$	57	$	241	$	221

Net Income

Highlights of the net income changes are summarized in the following table:


For the	Three months ended					Year ended
millions of Canadian dollars	December 31					December 31

Contribution to consolidated net income – 2020		$	57		$	221

Increased operating revenues - see Operating Revenues – Regulated Electric below			12			7

Increased fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below			(44	)		(96	)

Decreased FAM expense and fixed cost deferrals due to under-recovery of current period fuel costs compared to prior year’s over-recovery of fuel costs, partially offset by the refund to customers in 2020 of prior years’ fuel costs			40			101

Increased depreciation and amortization year-over-year due to increased property, plant and equipment			(1	)		(10	)

Decreased interest expense, net due to lower interest on the FAM regulatory deferral			1			7

Increased income tax expense quarter-over-quarter primarily due to increased income before provision for income taxes. Decreased income tax expense year-over-year primarily due to increased tax deductions in excess of accounting depreciation related to property, plant and equipment, partially offset by increased income before provision for income taxes.			(2	)		7

Other			4			4

Contribution to consolidated net income – 2021		$	67		$	241

Canadian Electric Utilities’ contribution to consolidated net income increased $10 million to $67 million in Q4 2021, compared to $57 million in Q4 2020, and increased $20 million to $241 million in 2021 compared to $221 million in 2020. Increases in both periods were primarily driven by higher contribution from NSPI. Quarter-over-quarter, the increase was primarily due to increased sales volumes. Year-over-year, the increase was primarily due to higher operating revenues, lower interest costs, and decreased income tax expense primarily due to tax deductions in excess of accounting depreciation related to property, plant and equipment. Increases were partially offset by higher depreciation and amortization.

The timing of regulatory deferrals causes quarterly earnings volatility, while full year results are more predictable.

NSPI

Operating Revenues – Regulated Electric

Operating revenues increased $12 million to $389 million in Q4 2021, compared to $377 million in Q4 2020 due to increased sales volume due to colder weather, fuel-related pricing, and increased customer sales volume, partially offset by lower Maritime Link assessment included in revenue compared to Q4 2020.

For the year ended December 31, 2021, operating revenues increased $7 million to $1,501 million, compared to $1,494 million in 2020 due to increased customer sales volume growth and fuel-related pricing, partially offset by lower Maritime Link assessment included in revenue compared to 2020.

Electric revenues and sales volumes are summarized in the following tables by customer class:


Q4 Electric Revenues
millions of Canadian dollars

	2021		2020

Residential	$	209	$	199

Commercial		104		102

Industrial		61		60

Other		6		7

Total	$	380	$	368


Annual Electric Revenues
millions of Canadian dollars

	2021		2020

Residential	$	797	$	806

Commercial		407		405

Industrial		237		224

Other		27		31

Total	$	1,468	$	1,466


Q4 Electric Sales Volumes
GWh

	2021		2020

Residential		1,229		1,159

Commercial		730		712

Industrial		629		629

Other		38		36

Total		2,626		2,536


Annual Electric Sales Volumes
GWh

	2021		2020

Residential		4,661		4,652

Commercial		2,902		2,850

Industrial		2,480		2,341

Other		153		185

Total		10,196		10,028

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $44 million to $263 million in Q4 2021, compared to $219 million in Q4 2020, and increased $96 million to $817 million in 2021, compared to $721 million in 2020. Increases in both periods were due to a provision for the Nova Scotia Cap-and-Trade program and higher commodity prices. See below for further information. Quarter-over-quarter, increases were partially offset by decreases due to changes in generation mix driven by emissions constraints. Year-over-year, changes in generation mix and higher Maritime Link assessment costs also contributed to the increase.

The provision for the Nova Scotia Cap-and-Trade program was $35 million in Q4 2021 and $38 million for the year ended December 31, 2021. This is due to higher than expected emissions primarily as a result of the delayed timing of Muskrat Falls Energy. The expense is accrued over the compliance period based on forecast emissions for the 2019 through 2022 period and is an estimate of expected costs but does not represent a fixed obligation.


Q4 Production Volumes
GWh

	2021		2020

Coal		1,224		1,249

Natural gas		371		351

Purchased power – other		196		235

Petcoke		208		148

Oil		14		26

Total non-renewables		2,013		2,009

Purchased power		536		509

Wind and hydro		243		215

Biomass		51		21

Total renewables		830		745

Total production volumes		2,843		2,754


Q4 Average Fuel Costs

	2021		2020

Dollars per MWh	$	93	$	80


Annual Production Volumes
GWh

	2021		2020

Coal		4,623		4,342

Natural gas		1,673		1,872

Purchased power – other		865		663

Petcoke		519		927

Oil		81		40

Total non-renewables		7,761		7,844

Purchased power		1,977		1,808

Wind and hydro		1,007		1,001

Biomass		160		106

Total renewables		3,144		2,915

Total production volumes		10,905		10,759


Annual Average Fuel Costs

	2021		2020

Dollars per MWh	$	75	$	67

Average fuel cost per MWh increased in Q4 2021, and for the year ended December 31, 2021 compared to the same periods in 2020. Quarter-over-quarter average fuel costs increased primarily due to the recognition of GHG emission expense as part of the Nova Scotia Cap-and-Trade Program and increased commodity pricing. See above for further information. Year-over-year, average fuel costs also increased due to changes in generation mix from lower carbon intensity sources such as IPPs, import and biomass generation and decreased generation from solid fuel and natural gas. Year-over-year, a higher Maritime Link assessment cost also contributed to the increase.

NSPI’s FAM regulatory balances increased $166 million, from a FAM regulatory liability of $21 million at December 31, 2020 to a FAM regulatory asset of $145 million at December 31, 2021, primarily due to under-recovery of current period fuel costs.

NSPI’s fuel costs are affected by commodity prices and generation mix, which is largely dependent on economic dispatch of the generating fleet, bringing the lowest cost options on stream first after renewable energy from IPPs including Community Feed-in Tariff (“COMFIT”) participants, for which NSPI has power purchase agreements in place.

NSPI-owned hydro and wind have no fuel cost component. After hydro and wind, historically, petcoke and coal have the lowest per-unit fuel cost, followed by natural gas. Oil, biomass and purchased power have the next lowest fuel cost, depending on the relative pricing of each. Generation mix may also be affected by plant outages, availability of renewable generation, availability of energy from the NS Block, plant performance and compliance with environmental standards and the Nova Scotia Cap-and-Trade Program.

The generation mix has undergone significant transformation with the addition of non-dispatchable renewable energy sources such as wind, including from IPPs and COMFIT, which typically have a higher cost per MWh than NSPI-owned generation or other purchased power sources.

Regulatory Recovery Mechanisms

NSPI

NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (the “Public Utilities Act”) and is subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings held from time to time at NSPI’s or the UARB’s request.

NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers and provide a reasonable return to investors.

NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel costs from customers through fuel rate adjustments. Differences between prudently incurred fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability.

As part of the three-year fuel stability plan, electricity rates have been set to include the $145 million approved Maritime Link assessment for 2020 and amounts of $164 million and $162 million for 2021 and 2022, respectively. On December 16, 2020, the UARB approved NSPML’s application to recover from NSPI the costs associated with the Maritime Link in 2021 of approximately $172 million. This is subject to a holdback of $10 million, pending UARB agreement that benefits from the Maritime Link are realized for NSPI customers. NSPML has deferred collection and recognition of $23 million in depreciation expense in 2021. On August 9, 2021, NSPML filed a final cost application with the UARB to recover capital costs associated with the Maritime Link and approval of NSPML’s 2022 assessment. In December 2021, NSPML obtained an interim decision from the UARB approving interim rates beginning January 1, 2022, until receipt of the UARB’s decision on the application. On February 9, 2022, the UARB issued its decision relating to the Maritime Link Project, approving NSPML’s requested rate base of approximately $1.8 billion less costs that would not otherwise have been recoverable if incurred by NSPI. For further information on the UARB decision, refer to the “Business Overview and Outlook – Canadian Electric Utilities” section. Any difference between the amounts included in the fuel stability plan and those approved by the UARB through the NSPML interim assessment application will be addressed through the FAM.

Other Electric Utilities

All amounts are reported in USD, unless otherwise stated.

On March 24, 2020, Emera completed the sale of Emera Maine. For further detail, refer to the “Significant Items Affecting Earnings” section.


		Three months ended				Year ended
For the		December 31				December 31
millions of US dollars (except per share amounts)		2021		2020		2021		2020

Operating revenues – regulated electric	$	98	$	79	$	355	$	354

Regulated fuel for generation and purchased power (1)	$	52	$	35	$	175	$	145

Contribution to consolidated adjusted net income	$	4	$	5	$	16	$	24

Contribution to consolidated adjusted net income – CAD	$	5	$	8	$	20	$	33

Equity securities MTM gain	$	2	$	2	$	1	$	2

Contribution to consolidated net income	$	6	$	7	$	17	$	26

Contribution to consolidated net income – CAD	$	7	$	10	$	21	$	35

Contribution to consolidated adjusted earnings per common share – basic – CAD	$	0.02	$	0.03	$	0.08	$	0.13

Contribution to consolidated earnings per common share – basic – CAD	$	0.03	$	0.04	$	0.08	$	0.14

Net income weighted average foreign exchange rate – CAD/USD	$	1.27	$	1.28	$	1.26	$	1.34

(1) Regulated fuel for generation and purchased power includes transmission pool expense for year ended December 31, 2020 related to Emera Maine.

Other Electric Utilities’ contribution to consolidated adjusted net income is summarized in the following table:


	Three months ended		Year ended
For the	December 31		December 31
millions of US dollars	2021	2020	2021	2020

BLPC	$ 6	$ 5	$ 11	$ 20

GBPC	-	3	8	5

Emera Maine	-	-	-	4

Other	(2)	(3)	(3)	(5)

Contribution to consolidated adjusted net income	$ 4	$ 5	$ 16	$ 24

Excluding the change in MTM, Other Electric Utilities CAD contribution to consolidated net income decreased $3 million to $5 million in Q4 2021, compared to $8 million in Q4 2020 and decreased $13 million to $20 million in 2021, compared to $33 million in 2020. Year-over-year, the decrease was due to the recognition of a previously deferred corporate income tax recovery at BLPC in Q1 2020 related to the enactment of a lower corporate income tax rate in December 2018 and the sale of Emera Maine in Q1 2020. These decreases were partially offset by higher income at GBPC and lower interest expense.

The foreign exchange rate had minimal impact for the three months December 31, 2021. For the year ended December 31, 2021, the strengthening of the CAD decreased earnings and adjusted earnings by $1 million.

Operating Revenues – Regulated Electric

Operating revenues increased $19 million to $98 million in Q4 2021, compared to $79 million in Q4 2020 and increased $1 million to $355 million in 2021, compared to $354 million in 2020. The increases in both periods were due to higher fuel revenue at BLPC due to higher fuel prices. Year-over-year, the increase was partially offset by the sale of Emera Maine.

Electric sales volumes were higher in Q4 2021 with 330 GWh compared to 313 GWh in Q4 2020. For the year ended December 31, 2021, electric sales volumes were higher with 1,262 GWh compared to 1,240 GWh in 2020.

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $17 million to $52 million in Q4 2021, compared to $35 million in Q4 2020 and increased $30 million to $175 million in 2021, compared to $145 million in 2020. The increases in both periods were due to higher fuel prices at BLPC. Year-over-year, the increase was partially offset by transmission pool expense at Emera Maine in 2020.

Regulatory Recovery Mechanisms

BLPC

BLPC is regulated by the FTC, an independent regulator. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on capital invested. BLPC’s fuel costs flow through a fuel pass-through mechanism which provides opportunity to recover all prudently incurred fuel costs from customers in a timely manner. The FTC approves the calculation of the fuel charge, which is adjusted on a monthly basis.

GBPC

GBPC is regulated by the GBPA. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on rate base. GBPC’s fuel costs flow through a fuel pass-through mechanism which provides the opportunity to recover all prudently incurred fuel costs from customers in a timely manner.

GBPC maintains insurance for its generation facilities. As with most utilities, its transmission and distribution networks are not covered by commercial insurance. In 2019, Hurricane Dorian restoration costs for GBPC transmission and distribution network assets were $15 million. In January 2020, the GBPA approved the deferral of these costs through a regulated asset with recovery through rates over a five-year period. Recovery of the asset began January 1, 2021.

As a result of Hurricane Matthew in 2016, a regulatory asset was established to recover associated restoration costs. In 2017, as part of the recovery of costs incurred as a result of Hurricane Matthew, the GBPA approved a fixed per kWh fuel charge and allowed the difference between this and the actual cost of fuel to be applied to the Hurricane Matthew regulatory asset. In September 2021, GBPC filed an application for rate review with the GBPA. As part of its decision issued January 14, 2022 and effective April 1, 2022, the GBPA approved the continued amortization of the remaining regulatory asset over the three year period ending December 31, 2024.

Domlec

Domlec is regulated by the IRC. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on rate base. Substantially all of Domlec fuel costs flow through a fuel pass-through mechanism which provides opportunity to recover prudently incurred fuel costs from customers in a timely manner.

Gas Utilities and Infrastructure

All amounts are reported in USD, unless otherwise stated.


		Three months ended				Year ended
For the		December 31				December 31
millions of US dollars (except per share amounts)		2021		2020		2021		2020

Operating revenues – regulated gas (1)	$	307	$	234	$	1,006	$	780

Operating revenues – non-regulated		2		3		12		12

Total operating revenue	$	309	$	237	$	1,018	$	792

Regulated cost of natural gas	$	139	$	80	$	375	$	221

Income from equity investments	$	4	$	4	$	16	$	14

Contribution to consolidated net income	$	44	$	35	$	157	$	122

Contribution to consolidated net income – CAD	$	55	$	45	$	198	$	162

Contribution to consolidated earnings per common share – basic – CAD	$	0.21	$	0.18	$	0.77	$	0.65

Net income weighted average foreign exchange rate – CAD/USD	$	1.26	$	1.30	$	1.26	$	1.33

(1) Operating revenues – regulated gas includes $12 million of finance income from Brunswick Pipeline (2020 - $11 million) for the three months ended December 31, 2021 and $46 million (2020 - $45 million) for the year ended December 31 2021; however, it is excluded from the gas revenues analysis below.

Gas Utilities and Infrastructure’s contribution to adjusted consolidated net income is summarized in the following table:


		Three months ended				Year ended
For the		December 31				December 31
millions of US dollars		2021		2020		2021		2020

PGS	$	17	$	13	$	77	$	52

NMGC		15		12		33		30

Other		12		10		47		40

Contribution to adjusted consolidated net income	$	44	$	35	$	157	$	122

Net Income

Highlights of the net income changes are summarized in the following table:


For the	Three months ended	Year ended
millions of US dollars	December 31	December 31

Contribution to consolidated net income – 2020	$ 35	$ 122

Increased gas operating revenues - see Operating Revenues - Regulated Gas below	73	226

Increased cost of natural gas sold - see Regulated Cost of Natural Gas below	(58)	(153)

Increased OM&G expenses year-over-year primarily due to higher labour and insurance costs at PGS and NMGC	2	(10)

Increased depreciation and amortization expense due to increased property, plant and equipment	(3)	(14)

Other	(5)	(14)

Contribution to consolidated net income – 2021	$ 44	$ 157

Gas Utilities and Infrastructure’s CAD contribution to consolidated net income increased $10 million in Q4 2021 to $55 million, compared to $45 million, in Q4 2020 and increased $36 million to $198 million compared to $162 million in 2020. The increases in both periods were due to higher base revenues at PGS as the result of a base rate increase effective January 1, 2021 and customer growth.

The impact of the change in the foreign exchange rate decreased CAD earnings for Q4 2021 and for the year ended December 31, 2021, by $1 million and $10 million respectively.

Operating Revenues – Regulated Gas

Gas Utilities and Infrastructure’s operating revenues increased $73 million to $307 million in Q4 2021, compared to $234 million in Q4 2020 and increased $226 million to $1,006 million in 2021, compared to $780 million in 2020. The increases in both periods were due to a base rate increase at PGS and NMGC effective January 1, 2021, customer growth at PGS, and higher purchased gas adjustment clause revenues at PGS and NMGC as a result of higher gas prices.

Gas revenues and sales volumes are summarized in the following tables by customer class:


Q4 Gas Revenues
millions of US dollars

		2021		2020

Residential	$	167	$	122

Commercial		87		63

Industrial (1)		15		11

Other (2)		26		27

Total (3)	$	295	$	223

(1) Industrial includes sales to power generation customers.

(2) Other includes off-system sales to other utilities and various other items.

(3) Excludes $12 million of finance income from Brunswick Pipeline (2020 – $11 million).


Annual Gas Revenues
millions of US dollars

		2021		2020

Residential	$	510	$	372

Commercial		301		207

Industrial (1)		53		41

Other (2)		96		115

Total (3)	$	960	$	735

(1) Industrial includes sales to power generation customers.

(2) Other includes off-system sales to other utilities and various other items.

(3) Excludes $46 million of finance income from Brunswick Pipeline (2020 – $45 million).


Q4 Gas Volumes
Therms (millions)

	2021		2020

Residential		120		132

Commercial		212		220

Industrial		327		388

Other		27		59

Total		686		799


Annual Gas Volumes
Therms (millions)

	2021		2020

Residential		405		405

Commercial		799		767

Industrial		1,434		1,586

Other		137		298

Total		2,775		3,056

Regulated Cost of Natural Gas

PGS and NMGC purchase gas from various suppliers depending on the needs of their customers. In Florida, gas is delivered to the PGS distribution system through interstate pipelines on which PGS has firm transportation capacity for delivery by PGS to its customers. NMGC’s natural gas is transported on major interstate pipelines and NMGC’s intrastate transmission and distribution system to customers.

In Florida, natural gas service is unbundled for non-residential customers and residential customers who use more than 1,999 therms annually and elect the option. In New Mexico, NMGC is required, if requested, to provide transportation-only services for all customer classes. Because the commodity portion of bundled sales is included in operating revenues, at the cost of the gas on a pass-through basis, there is no net earnings effect when a customer shifts to transportation-only sales.

Regulated cost of natural gas increased $59 million to $139 million in Q4 2021, compared to $80 million in Q4 2020 and increased $154 million to $375 million in 2021, compared to $221 million in 2020. The increases in both periods were due to higher gas prices at PGS and NMGC.

Gas sales by type are summarized in the following table:


Q4 Gas Volumes by Type
Therms (millions)

	2021	2020

System supply	177	197

Transportation	509	602

Total	686	799


Annual Gas Volumes by Type
Therms (millions)

	2021		2020

System supply		621		690

Transportation		2,154		2,366

Total		2,775		3,056

Regulatory Recovery Mechanisms

PGS

PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital.

Other Cost Recovery

Fuel Recovery Clause

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its purchased gas adjustment (“PGA”) clause. This clause is designed to recover actual costs incurred by PGS for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers. These charges may be adjusted monthly subject to a cap approved annually by the FPSC.

Other Cost Recovery Clauses

The FPSC annually approves cost-recovery rates for conservation costs including a return on capital invested incurred in developing and implementing energy conservation programs. PGS has a Cast Iron/Bare Steel Pipe Replacement clause to recover the cost of accelerating the replacement of cast iron and bare steel distribution lines in the PGS system. In February 2017, the FPSC approved expansion of the Cast Iron/Bare Steel clause to allow recovery of accelerated replacement of certain obsolete plastic pipe. PGS estimates that the majority of cast iron and bare steel pipe will be removed from its system by the end of 2022, with replacement of obsolete plastic pipe continuing until 2028 under the rider.

NMGC

NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital.

Other Cost Recovery

Fuel Recovery Clause

NMGC recovers gas supply costs through a purchased gas adjustment clause (“PGAC”). This clause recovers NMGC’s actual costs for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, transportation, distribution, and sale of natural gas to its customers.

On a monthly basis, NMGC can adjust charges based on next month’s expected cost of gas and any prior month under-recovery or over-recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish that continued use of the PGAC is reasonable and necessary. In December 2020, NMGC received approval of its PGAC Continuation Filing for the four-year period ending December 2024.

NMGC Winter Event Gas Cost Recovery

In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in an incremental $108 million for gas costs above what NMGC would normally have paid during this period. On June 15, 2021, the NMPRC approved the recovery over a period of 30 months beginning July 1, 2021. For more information, refer to the “Business Overview and Outlook – Gas Utilities and Infrastructure” section.

Weather Normalization Mechanism

In July 2019, the NMPRC approved changes to the company’s rate design to include a Weather Normalization Mechanism. This clause is designed to lower the variability of weather impacts during the October through April heating seasons. The Weather Normalization Mechanism allows customer rates and company revenue to be more predictable by partially removing the impact of warmer than usual or colder than usual weather. Weather-related revenue increases or decreases experienced from October to April are adjusted annually in October of the following heating season.

IMP Regulatory Asset

A portion of NMGC’s annual spend on infrastructure is for integrity management programs (“IMP”), or the replacement and update of legacy systems. These programs are driven both by NMGC integrity management plans and federal and state mandates. In December 2020, NMGC received approval through its rate case to defer costs through an IMP regulatory asset for certain of its IMP capital investments occurring between January 1, 2022 and December 31, 2023, and is seeking recovery of the regulatory asset in its rate case filed on December 13, 2021.

Other


		Three months ended				Year ended
For the	December 31				December 31
millions of Canadian dollars (except per share amounts)		2021		2020		2021		2020

Marketing and trading margin (1) (2)	$	39	$	22	$	102	$	38

Other non-regulated operating revenue		5		12		30		37

Total operating revenues – non-regulated	$	44	$	34	$	132	$	75

Income from equity investments	$	-	$	7	$	12	$	24

Contribution to consolidated adjusted net income (loss)	$	(44)	$	(23)	$	(198)	$	(252)

Gain on sale, net of tax and transaction costs (3)		-		-		-		309

Impairment charges, net of tax (4)		-		-		-		(26)

After-tax derivative MTM gain (loss) (5)		154		83		(214)		(12)

Contribution to consolidated net income (loss)	$	110	$	60	$	(412)	$	19

Contribution to consolidated adjusted earnings per common share – basic	$	(0.17)	$	(0.09)	$	(0.77)	$	(1.02)

Contribution to consolidated earnings per common share – basic	$	0.42	$	0.24	$	(1.60)	$	0.08

(1) Marketing and trading margin represents EES’s purchases and sales of natural gas and electricity, pipeline and storage capacity costs and energy asset management services’ revenues.

(2) Marketing and trading margin excludes a pre-tax MTM gain of $212 million in Q4 2021 (2020-$109 million gain) and a loss of $289 million for the year ended December 31,2021 (2020 – $46 million loss).

(3) Net of income tax expense of $276 million for the year ended December 31, 2020.

(4) Net of income tax expense of $1 million for the year ended December 31, 2020.

(5) Net of income tax expense of $63 million for the three months ended December 31, 2021 (2020 – $33 million expense) and $86 million recovery for the year ended December 31, 2021 (2020 – $8 million recovery)

Other’s contribution to consolidated adjusted net income is summarized in the following table:


	Three months ended				Year ended
For the	December 31				December 31
millions of Canadian dollars	2021		2020		2021		2020

Emera Energy	$	17	$	15	$	54	$	17

Corporate – see breakdown of adjusted contribution below		(57)		(32)		(231)		(255)

Emera Technologies		(4)		(5)		(17)		(12)

Other		-		(1)		(4)		(2)

Contribution to consolidated adjusted net income (loss)	$	(44)	$	(23)	$	(198)	$	(252)

MTM Adjustments

Emera Energy’s “Marketing and trading margin”, “Non-regulated fuel for generation and purchased power”, “Income from equity investments” and “Income tax expense (recovery)” are affected by MTM adjustments. Management believes excluding the effect of MTM valuations, and changes thereto, from income until settlement better matches the financial effect of these contracts with the underlying cash flows. Variance explanations of the MTM changes for this quarter and for the year are explained in the chart below.

Emera Energy has a number of asset management agreements (“AMA”) with counterparties, including local gas distribution utilities, power utilities and natural gas producers in North America. The AMAs involve Emera Energy buying or selling gas for a specific term, and the corresponding release of the counterparties’ gas transportation/storage capacity to Emera Energy. MTM adjustments on these AMAs arise on the price differential between the point where gas is sourced and where it is delivered. At inception, the MTM adjustment is offset fully by the value of the corresponding gas transportation asset, which is amortized over the term of the AMA contract.

Subsequent changes in gas price differentials, to the extent they are not offset by the accounting amortization of the gas transportation asset, will result in MTM gains or losses recorded in income. MTM adjustments may be substantial during the term of the contract, especially in the winter months of a contract when delivered volumes and market pricing are usually at peak levels. As a contract is realized, and volumes reduce, MTM volatility is expected to decrease. Ultimately, the gas transportation asset and the MTM adjustment reduce to zero at the end of the contract term. As the business grows, and AMA volumes increase, MTM volatility resulting in gains and losses may also increase.

Emera Corporate has foreign exchange forwards to manage the cash flow risk of forecasted USD cash inflows. Fluctuations in the foreign exchange rate result in MTM gains or losses recorded in income.

Net Income

Highlights of the net income changes are summarized in the following table:


For the		Three months ended		Year ended
millions of Canadian dollars	December 31		December 31

Contribution to consolidated net income (loss) – 2020	$	60	$	19

Increased marketing and trading margin - see Emera Energy below		17		64

Decreased interest expense in both periods due to the impact of a stronger CAD and lower interest rates. Year-over-year also decreased due to the repayment of corporate debt		6		35

Realized gain on hedges entered into to hedge foreign exchange earnings exposure		2		19

Revaluation of net deferred income tax assets and liabilities resulting from the enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020, including $2 million recovery related to MTM		-		11

TGH award, net of tax and legal costs		(36)		(36)

Decreased income tax recovery primarily due to decreased losses before provision for income taxes.		(7)		(39)

Increased MTM gains, net of tax, quarter-over-quarter, primarily due to settlements and changes in existing positions at Emera Energy. These were partially offset by higher amortization on gas transportation assets in Q4 2021 and the reversal of 2020 foreign exchange gains on cash flow hedges. Increased MTM losses, net of tax, year-over-year, primarily due to changes in existing positions and the reversal of 2020 foreign exchange gains on cash flow hedges.		71		(200)

2020 gain on sale and impairment charges, net of tax		-		(283)

Other		(3)		(2)

Contribution to consolidated net income (loss) – 2021	$	110	$	(412)

Emera Energy

EES derives revenue and earnings from the wholesale marketing and trading of natural gas, electricity and other energy-related commodities and derivatives within the Company’s risk tolerances, including those related to value-at-risk (“VaR”) and credit exposure. EES purchases and sells physical natural gas and electricity, the related transportation and transmission capacity rights, and provides energy asset management services. The primary market area for the natural gas and power marketing and trading business is northeastern North America, including the Marcellus and Utica shale supply areas. EES also participates in the Florida, US Gulf Coast and Midwest/Central Canadian natural gas markets. Its counterparties include electric and gas utilities, natural gas producers, electricity generators and other marketing and trading entities. EES operates in a competitive environment, and the business relies on knowledge of the region’s energy markets, understanding of pipeline and transmission infrastructure, a network of counterparty relationships and a focus on customer service. EES manages its commodity risk by limiting open positions, utilizing financial products to hedge purchases and sales, and investing in transportation capacity rights to enable movement across its portfolio.

Marketing and Trading

Excluding the impact of MTM gains, marketing and trading margin increased $17 million in Q4 2021, compared to Q4 2020, due to higher spot and forward natural gas prices and increased volatility, which created profitable opportunity for Emera Energy’s transportation and storage portfolio.

For the year ended December 31, 2021, marketing and trading margin, excluding the impact of MTM losses, increased $64 million compared to 2020. This increase reflected the mid-February extreme weather event across the South-Central US which sharply increased pricing and volatility in adjacent markets where Emera Energy has a presence, and on which the business was able to capitalize. In addition, Q3 and Q4 presented opportunity, with a surge in global liquefied natural gas (“LNG”) pricing in particular enhancing gas market pricing and volatility in key geographies.

Corporate

Corporate’s adjusted loss is summarized in the following table:


		Three months ended				Year ended
For the		December 31				December 31
millions of Canadian dollars		2021		2020		2021		2020

Operating expenses (1)	$	1	$	17	$	28	$	54

Interest expense		65		71		264		299

Income tax recovery		(18)		(24)		(75)		(102)

Preferred dividends		14		11		50		45

TGH award		-		(36)		-		(36)

Income tax expense associated with the revaluation of Corporate deferred income tax assets and liabilities due to the 2020 reduction in the Nova Scotia provincial corporate income tax rate		-		-		-		9

Other (2)		(5)		(7)		(36)		(14)

Corporate adjusted net loss	$	(57)	$	(32)	$	(231)	$	(255)

(1) Operating expenses include OM&G and depreciation. In Q4 2021, OM&G and depreciation were offset by a decrease in long-term incentive compensation. The value of long-term incentive compensation and related hedges are impacted by changes in Emera’s period end share price.

(2) Other includes realized foreign exchange gains on cash flow hedges to hedge foreign exchange earnings exposure, Q4 2021 includes a $5 million gain (2020 – $2 million gain) and year-ended December 31, 2021 gain of $18 million (2020 - $2 million loss).

LIQUIDITY AND CAPITAL RESOURCES

The Company generates internally sourced cash from its various regulated and non-regulated energy investments. Utility customer bases are diversified by both sales volumes and revenues among customer classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the business. Circumstances that could affect the Company’s ability to generate cash include general economic downturns in markets served by Emera, the loss of one or more large customers, regulatory decisions affecting customer rates and the recovery of regulatory assets and changes in environmental legislation. Emera’s subsidiaries are generally in a financial position to contribute cash dividends to Emera provided they do not breach their debt covenants, where applicable, after giving effect to the dividend payment, and maintain their credit metrics.

The ongoing COVID-19 pandemic, including government measures to address the pandemic, have resulted in economic slowdowns in all markets served by Emera. The pace and strength of economic recovery varies among jurisdictions. On a consolidated basis, COVID-19 has not had a material financial impact to net earnings in 2021 and is not expected to have a material financial impact in 2022. For further information on the potential future impacts of COVID on Emera and its businesses, refer to the “Business Overview and Outlook” section.

There have been no significant customer defaults to date and as of December 31, 2021. Adjustments to the allowance for credit losses have increased but have not had a material impact on earnings. The full impact of potential credit losses due to customer non-payment is not known at this time but is not expected to be material. The utilities are continuing to monitor customer accounts and are working with customers on payment arrangements.

Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing rate base investment, business acquisitions, greenfield development, dividends and debt servicing. Emera has a $8.4 billion capital investment plan over the 2022-to-2024 period (including a $240 million equity investment in the LIL in 2022) and the potential for additional capital investments of $1 billion over the same period. This plan includes significant rate base investments across the portfolio in renewable and cleaner generation, infrastructure modernization and customer-focused technologies. Capital investments at the regulated utilities are subject to regulatory approval. The extent of the future impact of COVID-19 on the profile of the Company’s capital investment plan cannot be predicted at this time. The Company has flexibility with respect to its capital investment plan and will continue to monitor current events and related impacts of COVID-19.

Emera plans to use cash from operations and debt raised at the utilities to support normal operations, repayment of existing debt, and capital requirements. Debt raised at certain of the Company’s utilities is subject to applicable regulatory approvals. Equity requirements in support of the Company’s capital investment plan are expected to be funded through the issuance of preferred equity and the issuance of common equity through Emera’s dividend reinvestment plan and ATM program.

Emera has credit facilities with varying maturities that cumulatively provide $3.8 billion of credit, with approximately $1.4 billion undrawn and available at December 31, 2021. The Company was holding a cash balance of $417 million at December 31, 2021. For further discussion, refer to the “Debt Management” section below. Refer to notes 23 and 25 in the consolidated financial statements for additional information regarding the credit facilities.

Consolidated Cash Flow Highlights

Significant changes in the Consolidated Statements of Cash Flows between the years ended December 31, 2021 and 2020 include:


millions of Canadian dollars		2021		2020		$ Change

Cash, cash equivalents and restricted cash, beginning of period	$	254	$	274	$	(20)

Provided by (used in):
Operating cash flow before changes in working capital		1,337		1,420		(83)

Change in working capital		(152)		217		(369)

Operating activities	$	1,185	$	1,637	$	(452)

Investing activities		(2,332)		(1,224)		(1,108)

Financing activities		1,311		(372)		1,683

Effect of exchange rate changes on cash, cash equivalents and restricted cash		(1)		(61)		60

Cash, cash equivalents, and restricted cash, end of period	$	417	$	254	$	163

Cash Flow from Operating Activities

Net cash provided by operating activities decreased $452 million to $1,185 million for the year ended December 31, 2021, compared to $1,637 million in 2020.

Cash from operations before changes in working capital decreased $83 million in 2021. The decrease was primarily due to the deferral of gas costs at NMGC resulting from the February 2021 extreme cold weather event, higher under-recovery of clause-related costs primarily due to higher natural gas prices at Tampa Electric and PGS, the TGH award in 2020, and the sale of Emera Maine in Q1 2020. This was partially offset by increased marketing and trading margin at Emera Energy and higher base revenue at PGS.

Changes in working capital decreased operating cash flows by $369 million due to unfavourable changes in cash collateral positions at Emera Energy, increased fuel inventory at Emera Energy and NSPI, unfavourable changes in accounts receivable at Tampa Electric and NMGC, the receipt of a 2019 income tax refund at NSPI in 2020, and timing of accounts payable payments at NMGC and PGS. This was partially offset by favourable changes in cash collateral positions on derivative instruments at NSPI.

Cash Flow used in Investing Activities

Net cash used in investing activities increased $1,108 million to $2,332 million for the year ended December 31, 2021, compared to $1,224 million in 2020. The increase was due to the proceeds of $1.4 billion received on the sale of Emera Maine in 2020, partially offset by lower capital expenditures in 2021.

Capital expenditures for the year ended December 31, 2021, including AFUDC, were $2,420 million compared to $2,668 million in 2020. Details of the 2021 capital spend by segment are shown below:

•

$1,408 million - Florida Electric Utility (2020 – $1,415 million);

•

$374 million - Canadian Electric Utilities (2020 – $342 million);

•

$111 million - Other Electric Utilities (2020 – $149 million);

•

$522 million - Gas Utilities and Infrastructure (2020 – $758 million); and

•

$5 million - Other (2020 – $4 million).

Cash Flow from Financing Activities

Net cash provided by financing activities increased $1,683 million to $1,311 million for the year ended December 31, 2021, compared to cash used in financing activities of $372 million in 2020. The increase was due to net proceeds from the issuance of long-term debt at Tampa Electric, NMGC, PGS and GBPC in 2021, repayment of long-term debt at TECO Finance in 2020, lower net repayments of committed credit facilities at TECO Finance and Emera, and the issuance of preferred shares. This was partially offset by higher net repayments of short-term debt at TEC and net proceeds from long-term debt in 2020 at NSPI.

Working Capital

As at December 31, 2021, Emera’s cash and cash equivalents were $394 million (2020 – $220 million) and Emera’s investment in non-cash working capital was $491 million (2020 – $266 million). Of the cash and cash equivalents held at December 31, 2021, $194 million was held by Emera’s foreign subsidiaries (2020 – $197 million). A portion of these funds are invested in countries that have certain exchange controls, approvals, and processes for repatriation. Such funds are available to fund local operating and capital requirements unless repatriated.

Contractual Obligations

As at December 31, 2021, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:


millions of Canadian dollars	2022		2023		2024		2025		2026		Thereafter		Total

Long-term debt principal	$	462	$	590	$	827	$	504	$	3,479	$	8,914	$	14,776

Interest payment obligations (1)		611		592		580		561		481		6,589		9,414

Transportation (2)		563		437		372		323		297		2,627		4,619

Purchased power (3)		231		227		244		242		235		1,967		3,146

Fuel, gas supply and storage		694		104		45		40		25		–		908

Capital projects		359		93		3		1		1		–		457

Asset retirement obligations		8		7		2		2		1		395		415

Long-term service agreements (4)		49		66		47		32		26		83		303

Pension and post-retirement obligations (5)		32		38		33		33		33		168		337

Equity investment commitments (6)		240		–		–		–		–		–		240

Leases and other (7)		15		14		14		12		4		116		175

Demand side management		44		1		1		–		–		–		46

Long-term payable		5		5		–		–		–		–		10

	$	3,313	$	2,174	$	2,168	$	1,750	$	4,582	$	20,859	$	34,846

(1) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at December 31, 2021, including any expected required payment under associated swap agreements.

(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $142 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(3) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.

(4) Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management.

(5) The estimated contractual obligation is calculated as the current legislatively required contributions to the registered funded pension plans (excluding the possibility of wind-up), plus the estimated costs of further benefit accruals contracted under NSPI’s Collective Bargaining Agreement and estimated benefit payments related to other unfunded benefit plans.

(6) Emera has a commitment to make equity contributions to the LIL.

(7) Includes operating lease agreements for buildings, land, telecommunications services and rail cars, transmission rights and investment commitments.

NSPI has a contractual obligation to pay NSPML for the use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. As part of NSPI’s 2020 through 2022 fuel stability plan, rates have been set to include $164 million and $162 million for 2021 and 2022, respectively. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to UARB approval. Any difference between the amounts included in the NSPI fuel stability plan and those approved by the UARB through the NSPML interim assessment application will be addressed through the FAM. On August 9, 2021, NSPML filed a final capital cost application with the UARB seeking approval to recover capital costs associated with the Maritime Link and approval of NSPML’s 2022 assessment. In December 2021, NSPML obtained an interim decision from the UARB approving interim rates beginning January 1, 2022, until receipt of the UARB’s decision on the application. On February 9, 2022, the UARB issued its decision relating to the Maritime Link Project, approving NSPML’s requested rate base of approximately $1.8 billion less costs that would not otherwise have been recoverable if incurred by NSPI. For further information on the UARB decision, refer to the “Business Overview and Outlook – Canadian Electric Utilities” section.

Once Muskrat Falls and LIL have achieved full power, the commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations of the parties relating to the Maritime Link and LIL.

Emera has committed to obtain certain transmission rights for Nalcor, if requested, to enable it to transmit energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021, the date the NS Block commenced, and continuing for 50 years. As transmission rights are contracted, the obligations are included within “Leases and other” in the above table.

Forecasted Gross Consolidated Capital Expenditures

2022 forecasted gross consolidated capital expenditures are as follows:


millions of Canadian dollars		Florida Electric Utility		Canadian Electric Utilities		Other Electric Utilities		Gas Utilities and Infrastructure		Other		Total

Generation	$	352	$	170	$	47	$	–	$	–	$	569

New renewable generation		306		30		20		–		–		356

Transmission		80		150		2		–		–		232

Distribution		505		110		48		–		–		663

Gas transmission and distribution		–		–		–		562		–		562

Facilities, equipment, vehicles, and other		172		70		11		–		2		255

	$	1,415	$	530	$	128	$	562	$	2	$	2,637

Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to approximately $3.8 billion committed syndicated bank credit facilities in either CAD or USD per the table below.


millions of dollars	Maturity		Credit Facilities		Utilized		Undrawn and Available

Emera – Unsecured committed revolving credit facility		June 2026	$	900	$	493	$	407

TEC (in USD) – Unsecured committed revolving credit facility (1)		December 2026		800		246		554

NSPI – Unsecured committed revolving credit facility		December 2026		600		385		215

Emera – Unsecured non-revolving facility		December 2022		400		400		–

TEC (in USD) – Unsecured non-revolving facility (2)		December 2022		500		500		–

TECO Finance (in USD) – Unsecured committed revolving credit facility		December 2026		400		280		120

NMGC (in USD) – Unsecured committed revolving credit facility		December 2026		125		22		103

NMGC (in USD) – Unsecured non-revolving facility		September 2022		80		80		–

Other (in USD) – Unsecured committed revolving credit facilities		Various		34		20		14

(1) This facility is available for use by Tampa Electric and PGS. At December 31, 2021, $156 million USD was used by Tampa Electric and $90 million USD was used by PGS.

(2) This facility is available for use by Tampa Electric and PGS. At December 31, 2021, $400 million USD was used by Tampa Electric and $100 million USD was used by PGS.

Emera and its subsidiaries have certain financial and other covenants associated with their debt and credit facilities. Covenants are tested regularly, and the Company is in compliance with covenant requirements as at December 31, 2021. Emera’s significant covenant is listed below:


	Financial Covenant	Requirement	As at December 31, 2021

Emera
Syndicated credit facilities	Debt to capital ratio	Less than or equal to 0.70 to 1		0.57 : 1

Recent significant financing activities for Emera and its subsidiaries are discussed below by segment:

Florida Electric Utility

On December 17, 2021, TEC entered into a $500 million USD unsecured, non-revolving credit facility with a maturity date of December 16, 2022. The credit facility contains customary representations and warranties, events of default, financial and other covenants and bears interest based on either the London Inter-Bank Offered Rate (“LIBOR”), prime rate, or the federal funds rate, plus a margin.

On December 17, 2021, TEC amended and restated its $800 million USD revolving credit facility. The amendment extended the maturity date from March 22, 2023 to December 17, 2026. There were no other significant changes in commercial terms from the prior agreement.

On May 25, 2021, TEC established a commercial paper program. Amounts available under the commercial paper program may be borrowed, repaid and reborrowed with the aggregate amount of the notes outstanding at any time not to exceed $800 million USD. The full amount of commercial paper issued is backed by TEC’s credit facility and results in an equal amount of its credit facility being considered drawn and unavailable.

On May 15, 2021, TEC repaid its $278 million USD, 5.4 per cent notes upon maturity. The notes were repaid using existing credit facilities.

On March 18, 2021, TEC completed an issuance of $800 million USD senior notes. The issuance included $400 million USD senior notes that bear interest at a rate of 2.40 per cent with a maturity date of March 15, 2031 and $400 million USD senior notes that bear interest at a rate of 3.45 per cent with a maturity date of March 15, 2051.

As a result of the $800 million USD senior notes issuance discussed above, on March 23, 2021, TEC repaid its $300 million USD non-revolving term loan. TEC also repaid its $150 million USD accounts receivable collateralized borrowing facility and the agreement subsequently matured and terminated on March 22, 2021.

Canadian Electric Utilities

On December 3, 2021, NSPI amended its operating credit facility to extend the maturity from October 2024 to December 2026. There were no other significant changes in commercial terms from the prior agreement.

Other Electric

On December 16, 2021, GBPC entered into a $75 million USD 4.00 per cent term loan with a maturity date of December 31, 2026. Proceeds from this loan were used to repay existing, non-revolving term loans totaling $55 million USD and to fund operations.

Gas Utilities and Infrastructure

On December 17, 2021, NMGC amended and restated its $125 million USD revolving credit facility. The amendment extended the maturity date from March 22, 2023 to December 17, 2026. There were no other significant changes in commercial terms from the prior agreement.

On July 16, 2021, Brunswick Pipeline extended the maturity date of its $250 million credit facility from May 17, 2023 to June 30, 2025. There were no other significant changes in commercial terms from the prior agreement.

On March 25, 2021, NMGC entered into a $100 million USD unsecured, non-revolving credit facility with a maturity date of September 23, 2022. The credit facility contains customary representations and warranties, events of default, financial and other covenants and bears interest based on either the LIBOR, prime rate, or the federal funds rate, plus a margin. Proceeds from this issuance were used to pay for higher than normal gas costs as a result of the severe cold weather event in February 2021 (for more detail, refer to “Business Overview and Outlook – Gas Utilities and Infrastructure” section).

On February 5, 2021, NMGC completed an issuance of $220 million USD senior notes. The issuance included $70 million USD senior notes that bear interest at a rate of 2.26 per cent with a maturity date of February 5, 2031, $65 million USD senior notes that bear interest at a rate of 2.51 per cent and with a maturity date of February 5, 2036, and $85 million USD senior notes that bear interest at a rate of 3.34 per cent with a maturity date of February 5, 2051. Proceeds from this issuance were used to repay a $200 million USD note due in 2021, which was classified as long-term debt at December 31, 2020.

Other

On December 17, 2021, TECO Finance amended and restated its $400 million USD revolving credit facility. The amendment extended the maturity date from March 22, 2023 to December 17, 2026. There were no other significant changes in commercial terms from the prior agreement.

On December 3, 2021, Emera extended the maturity date of its $400 million non-revolving term loan from December 16, 2021 to December 16, 2022. There were no other significant changes in commercial terms from the prior agreement.

On July 23, 2021, Emera extended the maturity date of its $900 million unsecured committed revolving credit facility from June 30, 2024 to June 30, 2026. There were no other significant changes in commercial terms from the prior agreement.

On June 4, 2021, Emera US Finance LP completed an issuance of $750 million USD senior notes. The issuance included $450 million USD senior notes that bear interest at a rate of 2.64 per cent with a maturity date of June 15, 2031 and $300 million USD senior notes that bear interest at a rate of 0.83 per cent with a maturity date of June 15, 2024. The USD senior notes are guaranteed by Emera and Emera US Holdings Inc., a wholly owned Emera subsidiary.

From the $750 million USD senior notes issuance discussed above, on June 15, 2021, Emera US Finance LP repaid its previously outstanding $750 million USD senior notes on maturity.

Preferred Share Issuances

Credit Ratings

Emera and its subsidiaries have been assigned the following senior unsecured debt ratings:


	Fitch	S&P	Moody’s	DBRS

Emera Inc.	BBB (Stable)	BBB- (Stable)	Baa3 (Stable)	N/A

TECO Energy/TECO Finance	N/A	BBB- (Stable)	Baa1 (Positive)	N/A

TEC	A(Stable)	BBB+ (Stable)	A3 (Positive)	N/A

NMGC	BBB+ (Stable)	N/A	N/A	N/A

NSPI	N/A	BBB+ (Stable)	N/A	A (low) (Stable)

Guaranteed Debt

On June 4, 2021, Emera US Finance LP completed an issuance of $750 million USD senior notes. From the proceeds of the issuance, on June 15, 2021, Emera US Finance LP repaid its previously outstanding $750 million USD senior notes on maturity. As of December 31, 2021, the Company had $2.75 billion USD senior unsecured notes (“U.S. Notes”) outstanding.

The U.S. Notes are fully and unconditionally guaranteed, on a joint and several basis, by Emera and Emera US Holdings Inc. (in such capacity, the “Guarantor Subsidiaries”). Emera owns, directly or indirectly, all of the limited and general partnership interests in Emera US Finance LP. Other subsidiaries of the Company do not guarantee the U.S. Notes (such subsidiaries are referred to as the “Non-Guarantor Subsidiaries”), however Emera has unrestricted access to the assets of consolidated entities.

On January 1, 2021 the Company adopted ASU 2020-09, Debt (Topic 470): Amendments to SEC Paragraphs pursuant to SEC Release No 33-10762. In the release, the SEC adopted final rules that amend the financial disclosure requirements for subsidiary issuers and guarantors of registered debt securities under Rule 3-10 of Regulation S-X, permitting registrants to disclose summarized financial information for each subsidiary issuer and guarantor. These rules were codified in Rule 13-01 of Regulation S-X. In compliance thereof, the Company is including summarized financial information for Emera, Emera US Holdings Inc., and Emera US Finance LP (together, the “Obligor Group”), on a combined basis after transactions and balances between the combined entities have been eliminated. Investments in and equity earnings of the Non-Guarantor Subsidiaries have been excluded from the summarized financial information.

The Obligor Group was not determined using geographic, service line or other similar criteria, and as a result the summarized financial information include portions of Emera’s domestic and international operations. Accordingly, this basis of presentation is not intended to present Emera’s financial condition or results of operations for any purpose other than to comply with the specific requirements for guarantor reporting.

Summarized Statement of Income (loss)

The Company recognized income related to guaranteed debt under the following categories:


For the		Year ended December 31
millions of Canadian dollars		2021

Loss from operations		$ (21)

Net losses (1)		$ (86)

(1) Includes $222 million in interest and dividend income, net, from non-guarantor subsidiaries.

Summarized Balance Sheet

The Company has the following categories on the balance sheet related to guaranteed debt:


As at		December 31
millions of Canadian dollars		2021

Current assets (1)		$ 329

Goodwill		5,628

Other assets (2)		6,027

Total assets (3)		$ 11,984

Current liabilities (4)		$ 888

Long-term liabilities (5)		6,403

Total liabilities		$ 7,291

(1) Includes $140 million in amounts due from non-guarantor subsidiaries.

(2) Includes $5,749 million in amounts due from non-guarantor subsidiaries.

(3) Excludes investments in non-guarantor subsidiaries. Consolidated Emera total assets are $34,244 million.

(4) Includes $346 million due to non-guarantor subsidiaries.

(5) Includes $776 million due to non-guarantor subsidiaries.

Share Capital

Emera

As at December 31, 2021, Emera had 261.07 million (2020 – 251.43 million) common shares issued and outstanding. For the year ended December 31, 2021, 9.64 million common shares were issued (2020 – 8.95 million) for net proceeds of $537 million (2020 – $489 million).

As at December 31, 2021, Emera had 58 million preferred shares issued and outstanding (2020 – 41 million).

PENSION FUNDING

For funding purposes, Emera determines required contributions to its largest defined benefit pension plans based on smoothed asset values. This reduces volatility in the cash funding requirement as the impact of investment gains and losses are recognized over a three-year period. The cash required in 2022 for defined benefit pension plans is expected to be $41 million (2021 – $41 million). All pension plan contributions are tax deductible and will be funded with cash from operations.

Emera’s defined benefit pension plans employ a long-term strategic approach with respect to asset allocation, real return and risk. The underlying objective is to earn an appropriate return, given the Company’s goal of preserving capital within an acceptable level of risk for the pension fund investments.

To achieve the overall long-term asset allocation, pension assets are managed by external investment managers per the pension plan’s investment policy and governance framework. The asset allocation includes investments in the assets of Canadian and global equities, domestic and global bonds and short-term investments. Emera reviews investment manager performance on a regular basis and adjusts the plans’ asset mixes as needed in accordance with the pension plans’ investment policy.

Emera’s projected contributions to defined contribution pension plans, are $46 million for 2022 (2021 – $45 million).

Defined Benefit Pension Plan Summary


in millions of Canadian dollars

Plans by region	TECO Energy				NSPI		Caribbean		Total

Assets as at December 31, 2021		$	1,171	$	1,521	$	10	$	2,702

Accounting obligation at December 31, 2021		$	1,078	$	1,531	$	15	$	2,624

Accounting expense during fiscal 2021		$	13	$	9	$	1	$	23

OFF-BALANCE SHEET ARRANGEMENTS

Defeasance

Upon privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities that provide principal and interest streams to match the related defeased debt, which at December 31, 2021 totalled $200 million (2020 – $582 million). The securities are held in trust for an affiliate of the Province of Nova Scotia. Approximately 66 per cent of the defeasance portfolio consists of investments in the related debt, eliminating all risk associated with this portion of the portfolio; the remaining defeasance portfolio has a market value higher than the related debt, reducing the future risk of this portion of the portfolio.

Guarantees and Letters of Credit

Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December 31, 2021:

TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a gas transportation precedent agreement. The guarantee is for a maximum potential amount of $45 million USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the gas transportation precedent agreement termination date, which was on January 1, 2022. In the event that TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded below investment grade by Moody’s or S&P, TECO Energy would be required to provide its counterparty a letter of credit or cash deposit of $27 million USD.

Emera Inc. has issued a guarantee of up to $35 million USD relating to outstanding notes of GBPC. The guarantee for the notes will expire in May 2023.

NSPI has issued guarantees in the amount of $15 million USD on behalf of its subsidiary, NS Power Energy Marketing Incorporated (“NSPEMI”), to secure obligations under purchase agreements with third- party suppliers and $85 million USD related to a 15-year natural gas transportation commitment. NSPI has $118 million USD (2020 - $18 million USD) of guarantees outstanding with terms of varying lengths and will be renewed as required.

The Company has standby letters of credit and surety bonds in the amount of $148 million USD (December 31, 2020 - $55 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually as required.

Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The expiry date of this letter of credit was extended to June 2022. The amount committed as at December 31, 2021 was $64 million (December 31, 2020 - $63 million).

DIVIDEND PAYOUT RATIO

Emera has provided annual dividend growth guidance of four to five per cent through 2024.The Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent, and while the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to return to that range over time. Emera Incorporated’s common share dividends paid in 2021 were $2.5750 ($0.6375 in Q1, Q2, and Q3 and $0.6625 in Q4) per common share and $2.4750 ($0.6125 in Q1, Q2, and Q3 and $0.6375 in Q4) per common share for 2020, representing a dividend payout ratio of 129 per cent in 2021 (2020 – 65 per cent) and a dividend payout ratio of adjusted net income of 91 per cent in 2021 (2020 - 91 per cent).

On September 24, 2021, the Emera Board of Directors approved an increase in the annual common share dividend rate to $2.65 from $2.55. The first quarterly dividend payment at the increased rate was paid on November 15, 2021.

TRANSACTIONS WITH RELATED PARTIES

In the ordinary course of business, Emera provides energy and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. All material amounts are under normal interest and credit terms.

Significant transactions between Emera and its associated companies are as follows:

•

Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $149 million for the year ended December 31, 2021 (2020 - $139 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments. For further details, refer to the “Business Overview and Outlook - Canadian Electric Utilities - ENL” and “Contractual Obligations” sections.

•

Natural gas transportation capacity purchases from M&NP are reported in the Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $19 million for the year ended December 31, 2021 (2020 - $18 million).

There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Consolidated Balance Sheets as at December 31, 2021 and at December 31, 2020.

ENTERPRISE RISK AND RISK MANAGEMENT

Emera has a business-wide risk management process, overseen by its Enterprise Risk Management Committee and monitored by the Board of Directors, to ensure an effective, consistent and coherent approach to risk management. Certain risk management activities for Emera are overseen by the Enterprise Risk Management Committee to ensure such risks are appropriately assessed, monitored and subject to appropriate controls and, in the case of certain credit risks, controlled within predetermined financial risk tolerances established through approved policies.

The Board of Directors established a Risk and Sustainability Committee (“RSC”) in September 2021. The mandate of the RSC is to assist the Board in carrying out its risk and sustainability oversight responsibilities. The RSC’s mandate includes oversight of the Company’s Enterprise Risk Management framework, including the identification, assessment, monitoring and management of enterprise risks. It also includes oversight of the Company’s approach to sustainability and its performance relative to its sustainability objectives.

The Company’s financial risk management activities are focused on those areas that most significantly impact profitability, quality and consistency of income, and cash flow. Emera’s risk management focus extends to key operational risks including safety and environment, which represent core values of Emera. In this section, Emera describes the principal risks that management believes could materially affect its business, revenues, operating income, net income, net assets, liquidity or capital resources. The nature of risk is such that no list is comprehensive, and other risks may arise or risks not currently considered material may become material in the future.

Regulatory and Political Risk

The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of the recovery of costs and investments. Regulatory and political risk can include change in regulatory frameworks, shifts in government policy, and regulatory decisions.

As cost-of-service utilities with an obligation to serve customers, Emera’s utilities operate under formal regulatory frameworks, and must obtain regulatory approval to change or add rates and/or riders. Costs and investments can be recovered upon approval by the respective regulator as an adjustment to rates and/or riders, which normally requires a public hearing process or may be mandated by other governmental bodies. Emera also holds investments in entities in which it has significant influence, and which are subject to regulatory and political risk including NSPML, LIL, M&NP and Lucelec.

As a regulated Group II pipeline, the tolls of Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory approval process described above. In the absence of a complaint, the CER does not normally undertake a detailed examination of Brunswick Pipeline’s tolls, which are subject to a firm service agreement expiring in 2034, with Repsol Energy Canada (“REC”). The agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract.

Changes in government and shifts in government policy can impact the commercial and regulatory frameworks under which Emera and its subsidiaries operate. This includes initiatives regarding deregulation or restructuring of the energy industry. Deregulation or restructuring of the energy industry may result in increased competition and unrecovered costs that could adversely affect operations, net income and cash flows. State and local policies in some US jurisdictions have sought to prevent or limit the ability of utilities to provide customers the choice to use natural gas while in other jurisdictions policies have been adopted to prevent limitations on the use of natural gas. Changes in applicable state or local laws and regulations could adversely impact PGS and NMGC.

Emera’s rate-regulated subsidiaries are subject to regulatory processes. During public hearing processes, consultants and customer representatives scrutinize the costs, actions and plans of these rate-regulated companies, and their respective regulators determine whether to allow recovery and to adjust rates based upon the evidence and any contrary evidence from other parties. In some circumstances, other government bodies may influence the setting of rates. The subsidiaries manage this regulatory risk through transparent regulatory disclosure, ongoing stakeholder and government consultation and multi-party engagement on aspects such as utility operations, regulatory audits, rate filings and capital plans. The subsidiaries employ a collaborative regulatory approach through technical conferences and, where appropriate, negotiated settlements.

Global Climate Change Risk

The Company is subject to risks that may arise from the impacts of climate change. There is increasing public concern about climate change and growing support for reducing carbon dioxide emissions. Municipal, state, provincial and federal governments have been setting policies and enacting laws and regulations to deal with climate change impacts in a variety of ways, including decarbonization initiatives and promotion of cleaner energy and renewable energy generation of electricity. Refer to “Changes in Environmental Legislation” risk below. Insurance companies have begun to limit their exposure to coal-fired electricity generation and are evaluating the medium and long-term impacts of climate change which may result in fewer insurers, more restrictive coverage and increased premiums. Refer to the “Markets” section below and “Uninsured Risk”.

Climate change may lead to increased frequency and intensity of weather events and related impacts such as storms, ice storms, hurricanes, cyclones, heavy rainfall, extreme winds, wildfires, flooding and storm surge. The potential impacts of climate change, such as rising sea levels and larger storm surges from more intense hurricanes, can combine to produce even greater damage to coastal generation and other facilities. Climate change is also characterized by rising global temperatures. Increased air temperatures may bring increased frequency and severity of wildfires within the Company’s service territories. Refer to “Weather Risk” and “System Operating and Maintenance Risks”.

The Company has made significant investments to facilitate the use of renewable and lower-carbon energy including wind generation, the Maritime Link in Atlantic Canada, and in Florida, solar generation and the modernization of the Big Bend Power Station. Tampa Electric has taken significant steps to reduce overall emissions at its facilities as a result of its capital investment plan which has and will continue to reduce carbon dioxide emissions. In 2022, NSPI is on track to achieve reductions of carbon dioxide emissions of approximately 60 per cent from 2005 levels. NSPI expects to exceed the new Canadian target of 40-45 per cent reduction by 2030, as set out in the Canadian Net-Zero Emissions Accountability Act. Both the Government of Nova Scotia and the Government of Canada have enacted or introduced legislation that includes goals of net-zero GHG emissions by 2050. The Province of Nova Scotia has established targets with respect to the percentage of renewable energy in NSPI’s generation mix as well as the goal to phase out coal-fired electricity generation by 2030. Failure to meet such goals by 2030 could result in material fines, penalties, other sanctions and adverse reputational impacts. NSPI continues to work with both the provincial and federal governments on measures to seek to address their carbon reduction goals. Within Emera’s natural gas utilities, there are ongoing efforts to reduce methane and carbon dioxide emissions through replacement of aging infrastructure, more efficient operations, operational and supply chain optimization, and support of public policy initiatives that address the effects of climate change.

The Company’s long-term capital investment plan includes significant investment across the portfolio in renewable and cleaner generation, infrastructure modernization, storm hardening, energy storage and customer-focused technologies. All these initiatives contribute toward mitigating the potential impacts of climate change. The Company continues to engage with government, regulators, industry partners and stakeholders to share information and participate in the development of climate change related policies and initiatives.

Physical Impacts

The Company is subject to physical risks that arise, or may arise, from global climate change, including damage to operating assets from more frequent and intense weather events and from wildfires due to warming air temperatures and increasing drought conditions. Substantially all of the Company’s fossil fueled generation assets are located at or near coastal sites and, as such, are exposed to the separate and combined effects of rising sea levels and increasing storm intensity, including storm surges and flooding. Refer to “Weather Risk” for further information.

These risks are mitigated to an extent through features such as flood walls at certain plants and through the location of plants on higher ground. Planned investments in under-grounding parts of the electricity infrastructure contributes to risk mitigation, as does insurance coverage (for assets other than electricity transmission and distribution assets). In addition, implementation of regulatory mechanisms for recovery of costs, such as storm reserves and regulatory deferral accounts, help to smooth out the recovery of storm restoration costs over time.

Reputation

Failure to address issues related to climate change could affect Emera’s reputation with stakeholders, its ability to operate and grow, and the Company’s access to, and cost of, capital. Refer to “Liquidity and Capital Market Risk”. The Company seeks to mitigate this in part by moving away from higher-carbon generation in favour of lower-carbon generation and non-emitting renewable generation.

Markets

Changing carbon-related costs, policy and regulatory changes and shifts in supply and demand factors could lead to more expensive or more scarce products and services that are required by the Company in its operations. This could lead to supply shortages, delivery delays and the need to source alternate products and services. The Company seeks to mitigate these risks through close monitoring of such developments and adaptive changes to supply chain procurement strategies.

Given concerns regarding carbon-emitting generation, those assets and businesses may, over time, become difficult (or uneconomic) to insure in commercial insurance markets. In the short term, this may be mitigated through increased investment in engineered protection or alternative risk financing (such as funded self-insurance or regulatory structures, including storm reserves). Longer-term mitigation may be achieved through infrastructure siting decisions and further engineered protections. This risk is also mitigated through the continued transition away from high-carbon generation sources to sources with low or zero carbon dioxide emissions.

Policy

Government and regulatory initiatives, including greenhouse gas emissions standards, air emissions standards and generation mix standards, are being proposed and adopted in many jurisdictions in response to concerns regarding the effects of climate change. In some jurisdictions, government policy has included timelines for mandated shutdowns of coal generating facilities, percentage of electricity generation from renewables, carbon pricing, emissions limits and cap and trade mechanisms. Over the medium and longer terms, this could potentially lead to a significant portion of hydrocarbon infrastructure assets being subject to additional regulation and limitations in respect of GHG emissions and operations.

The Company is committed to compliance with all climate-related and environmental legislative and regulatory requirements. Such legislative and regulatory initiatives could adversely affect Emera’s operations and financial performance. Refer to “Regulatory and Political Risk” and “Changes in Environmental Legislation” risk. The Company seeks to mitigate these risks through active engagement with governments and regulators to pursue transition strategies that meet the needs of customers, stakeholders and the Company. This has included NSPI’s participation in negotiated equivalency agreements in Nova Scotia to provide for an affordable transition to lower-carbon generation. Equivalency agreements allow NSPI to achieve compliance with federal GHG emissions regulations by meeting provincial legislative and regulatory requirements as they are deemed to be equivalent.

Regulatory

Depending on the regulatory response to government legislation and regulations, the Company may be exposed to the risk of reduced recovery through rates in respect of the affected assets. Valuation impairments could result from such regulatory outcomes. Mitigation efforts in respect of these risks include active engagement with policy makers and regulators to find mechanisms to avoid such impacts while being responsive to customers’ and stakeholders’ objectives.

Legal

The Company could face litigation or regulatory action related to environmental harms from carbon dioxide emissions or climate change public disclosure issues. The Company addresses these risks through compliance with all relevant laws, emissions reduction strategies, and public disclosure of climate change risks.

Water Resources

For thermal plants requiring cooling water, reduced availability of water resulting from climate change could adversely impact operations or the costs of operations. The Company seeks ways to reduce and recycle water as it does in its Polk power plant in Florida, where recovered and treated wastewater is used in operations to reduce reliance on fresh water supplies in an area where water is not as abundant as in other markets.

The Company operates hydroelectric generation in certain of its markets. Such generation depends on availability of water and the hydrological profile of water sources. Changes in precipitation patterns, water temperatures and air temperatures could adversely affect the availability of water and consequently the amount of electricity that may be produced from such facilities. The Company is reinvesting in the efficiency of certain hydroelectric generation facilities to increase generation capacity and continues to monitor changing hydrology patterns. Such issues may also affect the availability of third-party owned hydroelectricity purchased power sources.

Weather Risk

The Company is subject to risks that arise or may arise from weather including seasonal variations impacting energy sales, more frequent and intense weather events, changing air temperatures, wildfires and extreme weather conditions associated with climate change. Refer to “Global Climate Change Risk”.

Fluctuations in the amount of electricity or natural gas used by customers can vary significantly in response to seasonal changes in weather and could impact the operations, results of operations, financial condition, and cash flows of the Company’s utilities. For example, electrical utilities operating in Atlantic Canada could see lower demand in winter months if temperatures are warmer than expected. Further, extreme weather conditions such as hurricanes and other severe weather conditions which may be associated with climate change could cause these seasonal fluctuations to be more pronounced. In the absence of a regulatory recovery mechanism for unanticipated costs, such events could influence the Company’s results of operations, financial conditions or cash flows.

Extreme weather events create a risk of physical damage to the Company’s assets. High winds can impact structures and cause widespread damage to transmission and distribution infrastructure, solar generation, and wind powered generation. Increased frequency and severity of weather events increases the likelihood that the duration of power outages and fuel supply disruptions could increase. Increased frequency and intensity of flooding and storm surge could adversely affect the operations of utilities and in particular generation assets.

Each of Emera’s regulated electric utilities have programs for storm hardening of transmission and distribution facilities to minimize damage, but there can be no assurance that these measures will fully mitigate the risk. This risk to transmission and distribution facilities is typically not insured, and as such the restoration cost is generally recovered through regulatory processes, either in advance through reserves or designated self-insurance funds, or after the fact through the establishment of regulatory assets. Recovery is not assured and is subject to prudency review. The risk to generation assets is, in part, mitigated through the design, siting, construction and maintenance of such facilities, regular risk assessments, engineered mitigation, emergency storm response plans, and insurance.

The risk of wildfires is addressed primarily through asset management programs for natural gas transmission and distribution operations, and vegetation management programs for electric transmission and distribution facilities. If it is found to be responsible for such a fire, the Company could suffer costs, losses and damages, all or some of which may not be recoverable through insurance, legal, regulatory cost recovery or other processes. If not recovered through these means, they could materially affect Emera’s business and financial results including its reputation with customers, regulators, governments and financial markets. Resulting costs could include fire suppression costs, regeneration, timber value, increased insurance costs and costs arising from damages and losses incurred by third parties.

Changes in Environmental Legislation

Emera is subject to regulation by federal, provincial, state, regional and local authorities regarding environmental matters, primarily related to its utility operations. This includes laws setting GHG emissions standards and air emissions standards. Emera is also subject to laws regarding waste management, wastewater discharges and aquatic and terrestrial habitats.

In 2019, NSPI completed registration under the Nova Scotia Cap-and-Trade Program Regulations. This provincial carbon pricing program meets the benchmark set by the Government of Canada. In the United States, air emissions, including GHG emissions, are regulated pursuant to the Clean Air Act. Individual states continue to develop or administer GHG reduction initiatives. Changes to GHG emissions standards and air emissions standards could adversely affect Emera’s operations and financial performance. Legislative or regulatory changes could influence decisions regarding early retirement of generation facilities and may result in stranded costs if the Company is not able to fully recover the costs and investment in the affected generation assets. Recovery is not assured and is subject to prudency review. Legislative or regulatory changes may curtail sales of natural gas to new customers, which could reduce future customer growth in Emera’s natural gas businesses. Stricter environmental laws and enforcement of such laws in the future could increase Emera’s exposure to additional liabilities and costs. These changes could also affect earnings and strategy by changing the nature and timing of capital investments.

In addition to imposing continuing compliance obligations, there are permit requirements, laws and regulations authorizing the imposition of penalties for non-compliance, including fines, injunctive relief, and other sanctions. The cost of complying with current and future environmental requirements is, and may be, material to Emera. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates, could have a material adverse effect on Emera. In addition, Emera’s business could be materially affected by changes in government policy, utility regulation, and environmental and other legislation that could occur in response to environmental and climate change concerns.

Emera manages its environmental risk by operating in a manner that is respectful and protective of the environment and in compliance with applicable legal requirements and Company policy. Emera has implemented this policy through the development and application of environmental management systems in its operating subsidiaries. Comprehensive audit programs are in place to regularly test compliance.

Cybersecurity Risk

Emera is exposed to potential risks related to cyberattacks and unauthorized access. The Company increasingly relies on information technology systems and network infrastructure to manage its business and safely operate its assets, including controls for interconnected systems of generation, distribution and transmission as well as financial, billing and other business systems. Emera also relies on third-party service providers to conduct business. As the Company operates critical infrastructure, it may be at greater risk of cyberattacks by third parties, which could include nation-state-controlled parties.

Cyberattacks can reach the Company’s networks with access to critical assets and information via their interfaces with less critical internal networks or via the public internet. Cyberattacks can also occur via personnel with direct access to critical assets or trusted networks. An outbreak of infectious disease, a pandemic or a similar public health threat, such as COVID-19, may cause disruption in normal working patterns including wide scale “work from home” policies, which could increase cybersecurity risk as the quantity of both cyberattacks and network interfaces increases. Refer to the “Public Health Risk” section below. Methods used to attack critical assets could include general purpose or energy-sector-specific malware delivered via network transfer, removable media, viruses, attachments, or links in e-mails. The methods used by attackers are continuously evolving and can be difficult to predict and detect.

Despite security measures in place, that are described below, the Company’s systems, assets and information could experience security breaches that could cause system failures, disrupt operations, or adversely affect safety. Such breaches could compromise customer, employee-related or other information systems and could result in loss of service to customers or the unavailability, release, destruction, or misuse of critical, sensitive or confidential information. These breaches could also delay delivery or result in contamination or degradation of hydrocarbon products the Company transports, stores or distributes.

Should such cyberattacks or unauthorized accesses materialize, the Company could suffer costs, losses and damages all, or some of which, may not be recoverable through insurance, legal, regulatory cost recovery or other processes and could materially adversely affect Emera’s business and financial results including its reputation and standing with customers, regulators, governments and financial markets. Resulting costs could include, amongst others, response, recovery and remediation costs, increased protection or insurance costs and costs arising from damages and losses incurred by third parties. If any such security breaches occur, there is no assurance that they can be adequately addressed in a timely manner.

The Company seeks to manage these risks by aligning to a common set of cybersecurity standards, periodic security testing, program maturity objectives, strategy derived, in part, on the National Institute of Standards and Technology’s Cyber Security Framework, and employee communication and training. With respect to certain of its assets, the Company is required to comply with rules and standards relating to cybersecurity and information technology including, but not limited to, those mandated by bodies such as the North American Electric Reliability Corporation and Northeast Power Coordinating Council. The status of key elements of the Company’s cybersecurity program is reported to the Risk and Sustainability Committee.

Public Health Risk

An outbreak of infectious disease, a pandemic or a similar public health threat, such as the COVID-19 pandemic, or a fear of any of the foregoing, could adversely impact the Company, including causing operating, supply chain and project development delays and disruptions, labour shortages and shutdowns (including as a result of government regulation and prevention measures), which could have a negative impact on the Company’s operations.

Any adverse changes in general economic and market conditions arising as a result of a public health threat could negatively impact demand for electricity and natural gas, revenue, operating costs, timing and extent of capital expenditures, results of financing efforts, or credit risk and counterparty risk; which could result in a material adverse effect on the Company’s business. The Company maintains pandemic and business contingency plans in each of its operations to manage and help mitigate the impact of any such public health threat.

Energy Consumption Risk

Emera’s rate-regulated utilities are affected by demand for energy based on changing customer patterns due to fluctuations in a number of factors including general economic conditions, customers’ focus on energy efficiency, and advancements in new technologies, such as rooftop solar, electric vehicles and battery storage. Government policies promoting distributed generation, and new technology developments that enable those policies, have the potential to impact how electricity enters the system and how it is bought and sold. In addition, increases in distributed generation may impact demand resulting in lower load and revenues. These changes could negatively impact Emera’s operations, rate base, net earnings, and cash flows. The Company’s rate-regulated utilities are focused on understanding customer demand, energy efficiency, and government policy to ensure that the impact of these activities benefit customers, that they do not negatively impact the reliability of the energy service and that they are addressed through regulations.

Foreign Exchange Risk

The Company is exposed to foreign currency exchange rate changes. Emera operates internationally, with an increasing amount of the Company’s net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the Canadian dollar and, particularly, the US dollar, which could positively or adversely affect results.

Consistent with the Company’s risk management policies, Emera manages currency risks through matching US denominated debt to finance its US operations and may use foreign currency derivative instruments to hedge specific transactions and earnings exposure. The Company may enter foreign exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenue streams and capital expenditures, and on net income earned outside of Canada. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs, including foreign exchange.

The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries do not impact net income as they are reported in Accumulated Other Comprehensive Income (Loss) (“AOCI”) (“AOCL”).

Liquidity and Capital Market Risk

Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs could be financed through internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital markets. The Company reasonably expects liquidity sources to exceed capital needs.

Emera’s access to capital and cost of borrowing is subject to several risk factors, including financial market conditions, market disruptions and ratings assigned by credit rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan requires significant capital investments in property, plant and equipment and the risk associated with changes in interest rates could have an adverse effect on the cost of financing. The Company’s future access to capital and cost of borrowing may be impacted by various market disruptions. The inability to access cost-effective capital could have a material impact on Emera’s ability to fund its growth plan.

Emera is subject to financial risk associated with changes in its credit ratings. There are a number of factors that rating agencies evaluate to determine credit ratings, including the Company’s business and regulatory framework, the ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to climate change-related impacts, including increased frequency and severity of hurricanes and other severe weather events. A decrease in a credit rating could result in higher interest rates in future financings, increase borrowing costs under certain existing credit facilities, limit access to the commercial paper market or limit the availability of adequate credit support for subsidiary operations. For certain derivative instruments, if the credit ratings of the Company were reduced below investment grade, the full value of the net liability of these positions could be required to be posted as collateral. Emera manages these risks by actively monitoring and managing key financial metrics with the objective of sustaining investment grade credit ratings.

The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based compensation.

Interest Rate Risk

Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt.

For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates, such that regulatory ROE’s are likely to fall in times of reducing interest rates and rise in times of increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development and acquisition initiatives.

Project Development and Land Use Rights Risk

The Company’s capital plan includes significant investment in generation, infrastructure modernization, and customer-focused technologies. Any projects planned or currently in construction, particularly significant capital projects, may be subject to risks including, but not limited to, impact on costs from schedule delays, risk of cost overruns, ensuring compliance with operating and environmental requirements and other events within or beyond the Company’s control. The Company’s projects may also require approvals and permits at the federal, provincial, state, regional and local levels. There is no assurance that Emera will be able to obtain the necessary project approvals or applicable permits or receive regulatory approval to recover the costs in rates.

Some of the Company’s assets are located on land owned by third parties, including Indigenous Peoples, and may be subject to land claims. Present or future assets may be located on lands that have been used for traditional purposes and therefore subject to specific consultations, consents, or conditions for development or operation. If the Company’s rights to locate and operate its assets on any such lands are subject to expiry or become invalid, it may incur material costs to renew rights or obtain such rights. If reasonable terms for land-use rights cannot be negotiated, the Company may incur significant costs to remove and relocate its assets and restore the land. Additional costs incurred could cause projects to be uneconomical to proceed with.

Emera manages these project development and land use rights risks by deploying robust project and risk management approaches, led by teams with extensive experience in large projects. The Company consults with Indigenous Peoples in obtaining approvals, constructing, maintaining and operating such facilities, consistent with laws and public policy frameworks. Emera maintains relationships through on-going communications with stakeholders, including Indigenous Peoples, landowners and governments.

Counterparty Risk

Emera is exposed to risk related to its reliance on certain key partners, suppliers, and customers, any of which may endure financial challenges resulting from commodity price and market volatility, economic instability or adversity, adverse political or regulatory changes and other causes which may cause or contribute to such parties’ insolvency, bankruptcy, restructuring or default on their contractual obligations to Emera. Emera is also exposed to potential losses related to amounts receivable from customers, energy marketing collateral deposits and derivative assets due to a counterparty’s non-performance under an agreement. Counterparty creditworthiness and the ability of key partners, suppliers and customers to perform their contractual obligations may be affected by economic impacts related to COVID-19.

Emera manages this counterparty risk through due diligence and risk assessment processes prior to signing contracts, contractual rights and remedies, regulatory frameworks, and by monitoring significant developments with its customers, partners and suppliers. The Company also manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments may be conducted on new customers and counterparties, and deposits or collateral may be requested on certain accounts. Emera may also seek recovery of unpaid amounts or damages through applicable bankruptcy, insolvency or similar proceedings.

Country Risk

Earnings outside of Canada constituted 78 per cent of Emera’s earnings in 2021 (2020 – 73 per cent) with the majority from the US. Emera’s investments are currently in regions where political and economic risks are considered by the Company to be acceptable. Emera’s operations in some countries may be subject to changes in economic growth, restrictions on the repatriation of income or capital exchange controls, inflation, the effect of global health, safety and environmental matters, including climate change, or economic conditions and market conditions, and change in financial policy and availability of credit. The Company mitigates this risk through a rigorous approval process for investment, and by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available in all affiliates.

Commodity Price Risk

The Company’s utility fuel supply is subject to commodity price risk. In addition, Emera Energy is subject to commodity price risk through its portfolio of commodity contracts and arrangements.

The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks. The Company’s commercial arrangements, including the combination of supply and purchase agreements, asset management agreements, pipeline transportation agreements and financial hedging instruments are all used to manage and mitigate this risk. In addition, its credit policies, counterparty credit assessments, market and credit position reporting, and other risk management and reporting practices, are also used to manage and mitigate this risk.

Regulated Utilities

A large portion of the Company’s utility fuel supply comes from international suppliers and therefore may be exposed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk using financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable.

The majority of Emera’s regulated electric and gas utilities have adopted and implemented fuel adjustment mechanisms and purchased gas adjustment mechanisms respectively, which has further helped manage commodity price risk, as the regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred fuel and gas costs.

Emera Energy Marketing and Trading

Emera Energy has employed further measures to manage commodity risk. The majority of Emera Energy’s portfolio of electricity and gas marketing and trading contracts and, in particular, its natural gas asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or short commodity positions. However, the portfolio is subject to commodity price risk, particularly with respect to basis point differentials between relevant markets in the event of an operational issue or counterparty default.

To measure commodity price risk exposure, Emera Energy employs a number of controls and processes, including an estimated VaR analysis of its exposures. The VaR amount represents an estimate of the potential change in fair value that could occur from changes in Emera Energy’s portfolio or changes in market factors within a given confidence level, if an instrument or portfolio is held for a specified time period. The VaR calculation is used to quantify exposure to market risk associated with physical commodities, primarily natural gas and power positions.

Future Employee Benefit Plan Performance and Funding Risk

Emera subsidiaries have both defined benefit and defined contribution employee pension plans that cover their employees and retirees. All defined benefit plans are closed to new entrants, except for the TECO Energy Group Retirement Plan. The cost of providing these benefit plans varies depending on plan provisions, interest rates, investment performance and actuarial assumptions concerning the future. Actuarial assumptions include earnings on plan assets, discount rates (interest rates used to determine funding levels, contributions to the plans and the pension and post-retirement liabilities) and expectations around future salary growth, inflation and mortality. Two of the largest drivers of cost are investment performance and interest rates, which are affected by global financial and capital markets. Depending on future interest rates and actual versus expected investment performance, Emera could be required to make larger contributions in the future to fund these plans, which could affect Emera’s cash flows, financial condition and operations.

Each of Emera’s employee defined benefit pension plans are managed according to an approved investment policy and governance framework. Emera employs a long-term approach with respect to asset allocation and each investment policy outlines the level of risk which the Company is prepared to accept with respect to the investment of the pension funds in achieving both the Company’s fiduciary and financial objectives. Studies are routinely undertaken every three to five years with the objective that the plans’ asset allocations are appropriate for meeting Emera’s long-term pension objectives.

Labour Risk

Emera’s ability to deliver service to its customers and to execute its growth plan depends on attracting, developing and retaining a skilled workforce. Utilities are faced with demographic challenges related to trades, technical staff and engineers with an increasing number of employees expected to retire over the next several years. Failure to attract, develop and retain an appropriately qualified workforce could adversely affect the Company’s operations and financial results. Emera seeks to manage this risk through maintaining competitive compensation programs, a dedicated talent acquisition team, human resources programs and practices including ethics and diversity training, employee engagement surveys, succession planning for key positions and apprenticeship programs.

Approximately 33 per cent of Emera’s labour force is represented by unions and subject to collective labour agreements. The inability to maintain or negotiate future agreements on acceptable terms could result in higher labour costs and work disruptions, which could adversely affect service to customers and have an adverse effect on the Company’s earnings, cash flow and financial position. Emera seeks to manage this risk through ongoing discussions and working to maintain positive relationships with local unions. The Company maintains contingency plans in each of its operations to manage and reduce the effect of any potential labour disruption.

Information Technology Risk

Emera relies on various information technology systems to manage operations. This subjects Emera to inherent costs and risks associated with maintaining, upgrading, replacing and changing these systems. This includes impairment of its information technology, potential disruption of internal control systems, substantial capital expenditures, demands on management time and other risks of delays, difficulties in upgrading existing systems, transitioning to new systems or integrating new systems into its current systems. Emera’s digital transformation strategy, including investment in infrastructure modernization and customer focused technologies, is driving increased investment in information technology solutions, resulting in increased project risks associated with the implementation of these solutions.

Emera manages these information technology risks through IT asset lifecycle planning and management, governance, internal auditing and testing of systems, and executive oversight. Employees with extensive subject matter expertise assist in risk identification and mitigation, project management, implementation, change management and training. System resiliency, formal disaster recovery and backup processes, combined with critical incident response practices, ensure that continuity is maintained in the event of any disruptions.

Income Tax Risk

The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in Canada, the United States and the Caribbean. Any such changes could affect the Company’s future earnings, cash flows, and financial position. The value of Emera’s existing deferred tax assets and liabilities are determined by existing tax laws and could be negatively impacted by changes in laws. Emera monitors the status of existing tax laws to ensure that changes impacting the Company are appropriately reflected in the Company’s tax compliance filings and financial results.

System Operating and Maintenance Risks

The safe and reliable operation of electric generation and electric and natural gas transmission and distribution systems is critical to Emera’s operations. There are a variety of hazards and operational risks inherent in operating electric utilities and natural gas transmission and distribution pipelines. Electric generation, transmission and distribution operations can be impacted by risks such as mechanical failures, activities of third parties, damage to facilities, solar panels and infrastructure caused by hurricanes, storms, falling trees, lightning strikes, floods, fires and other natural disasters, and disruption of fuel supply chain caused by damage to, or cyber-attacks on, third party storage and pipeline facilities. Natural gas pipeline operations can also be impacted by risks such as leaks, explosions, mechanical failures, activities of third parties and damage to the pipelines facilities and equipment caused by hurricanes, storms, floods, fires and other natural disasters. Refer to “Global Climate Change Risk” and “Weather Risk”. Electric utility and natural gas transmission and distribution pipeline operation interruption could negatively affect revenue, earnings, and cash flows as well as customer and public confidence.

Emera manages these risks by investing in a highly skilled workforce, operating prudently, preventative maintenance, and making effective capital investments. Insurance, warranties, or recovery through regulatory mechanisms may not cover any or all these losses, which could adversely affect the Company’s results of operations and cash flows.

Uninsured Risk

Emera and its subsidiaries maintain insurance to cover accidental loss suffered to its facilities and to provide indemnity in the event of liability to third parties. This is consistent with Emera’s risk management policies. Certain facilities, in particular coal and other thermal generation, may, over time, become more difficult (or uneconomic) to insure as a result of the impact of global climate change. Refer to “Global Climate Change Risk – Markets”. There are certain elements of Emera’s operations which are not insured. These include a significant portion of its electric utilities’ transmission and distribution assets, as is customary in the industry. The cost of this coverage is not economically viable. In addition, Emera accepts deductibles and self-insured retentions under its various insurance policies. Insurance is subject to coverage limits as well as time sensitive claims discovery and reporting provisions and there can be no assurance that the types of liabilities or losses that may be incurred by the Company and its subsidiaries will be covered by insurance.

The occurrence of significant uninsured claims, claims in excess of the insurance coverage limits maintained by Emera and its subsidiaries, or claims that fall within a significant self-insured retention could have a material adverse effect on Emera’s results of operations, cash flows and financial position, if regulatory recovery is not available.

The Company mitigates its uninsured risk by ensuring that insurance limits align with risk exposures, and for uninsured assets and operations, that appropriate risk assessments and mitigation measures are in place. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs, including uninsured losses.

RISK MANAGEMENT INCLUDING FINANCIAL INSTRUMENTS

Emera’s risk management policies and procedures provide a framework through which management monitors various risk exposures. The risk management policies and practices are overseen by the Board of Directors. The Company has established a number of processes and practices to identify, monitor, report on and mitigate material risks to the Company. This includes establishment of the Enterprise Risk Management Committee, whose responsibilities include preparing an updated risk dashboard and heat map presented at regular meetings of the Board’s Risk and Sustainability Committee. Furthermore, a corporate team independent from operations is responsible for tracking and reporting on market and credit risks.

The Company manages exposure to normal operating and market risks relating to commodity prices, foreign exchange, interest rates and share prices through contractual protections with counterparties where practicable, and by using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. Collectively, these contracts and financial instruments are considered derivatives.

The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty creditworthy. The Company continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met.

Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Where the documentation or effectiveness requirements are not met, any changes in fair value are recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.

Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at fair value on the balance sheet as derivative assets or liabilities. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled in regulated fuel for generation and purchased power, inventory or property, plant and equipment, depending on the nature of the item being economically hedged. Management believes any gains or losses resulting from settlement of these derivatives will be refunded to or collected from customers in future rates. Tampa Electric and PGS have no derivatives related to hedging as a result of a FPSC approved five-year moratorium on hedging of natural gas purchases which ends on December 31, 2022. Tampa Electric’s moratorium on hedging of natural gas purchases will continue through December 31, 2024, as a result of Tampa Electric’s 2021 rate case settlement agreement.

Derivatives that do not meet any of the above criteria are designated as HFT and are recognized on the balance sheet at fair value. All gains or losses are recognized in net income of the period unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category when another accounting treatment applies.

Hedging Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to derivatives in valid hedging relationships:


As at	December 31			December 31
millions of Canadian dollars	2021			2020

Derivative instrument assets (current and other assets)		$	-		$	1

Net derivative instrument assets		$	-		$	1

Hedging Impact Recognized in Net Income

The Company recognized gains (losses) related to the effective portion of hedging relationships under the following categories:


For the	Year ended December 31
millions of Canadian dollars	2021		2020

Operating revenues – regulated	$	-		$	(2)

Non-regulated fuel for generation and purchased power		1			-

Effective net gains (losses)	$	1		$	(2)

The effective net losses reflected in the above table are offset in net income by the hedged item realized in the period.

Regulatory Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to derivatives receiving regulatory deferral:


As at	December 31			December 31
millions of Canadian dollars	2021			2020

Derivative instrument assets (current and other assets)		$	237		$	14

Regulatory assets (current and other assets)			23			65

Derivative instrument liabilities (current and long-term liabilities)			(20)			(62)

Regulatory liabilities (current and long-term liabilities)			(241)			(15)

Net asset (liability)		$	(1)		$	2

Regulatory Impact Recognized in Net Income

The Company recognized the following net gains (losses) related to derivatives receiving regulatory deferral as follows:


For the	Year ended December 31
millions of Canadian dollars	2021		2020

Regulated fuel for generation and purchased power (1)	$	34		$	(21)

Net gains (losses)	$	34		$	(21)

(1) Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships that have been terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized in “Regulated fuel for generation and purchased power” when the hedged item is consumed.

HFT Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to HFT derivatives:


As at	December 31			December 31
millions of Canadian dollars	2021			2020

Derivative instrument assets (current and other assets)		$	53		$	68

Derivative instrument liabilities (current and long-term liabilities)			(662)			(275)

Net derivative instrument liability		$	(609)		$	(207)

HFT Items Recognized in Net Income

The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives in net income:


For the	Year ended December 31
millions of Canadian dollars	2021		2020

Non-regulated operating revenues	$	(138)		$	204

Non-regulated fuel for generation and purchased power		-			(4)

Net gains (losses)	$	(138)		$	200

Other Derivatives Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to other derivatives:


As at	December 31			December 31
millions of Canadian dollars	2021			2020

Derivative instrument assets (current and other assets)		$	11		$	15

Derivative instrument liabilities (current and long-term liabilities)			-			(1)

Net derivative instrument assets		$	11		$	14

Other Derivatives Recognized in Net Income

The Company recognized in net income the following realized and unrealized gains (losses) related to other derivatives:


For the	Year ended December 31
millions of Canadian dollars	2021		2020

OM&G	$	26		$	(4)

Other income, net		3			13

Net gains	$	29		$	9

DISCLOSURE AND INTERNAL CONTROLS

Management is responsible for establishing and maintaining adequate disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”). The Company’s internal control framework is based on the criteria published in the Internal Control - Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations (“COSO”) of the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer, evaluated the design and effectiveness of the Company’s DC&P and ICFR as at December 31, 2021 to provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.

Management recognizes the inherent limitations in internal control systems, no matter how well designed. Control systems determined to be appropriately designed can only provide reasonable assurance with respect to the reliability of financial reporting and may not prevent or detect all misstatements.

There were no changes in the Company’s ICFR, during the year ended December 31, 2021, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

CRITICAL ACCOUNTING ESTIMATES

The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring the use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill, and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise.

Management has analyzed the impact of the COVID-19 pandemic on its estimates and assumptions and concluded that no material adjustments were required for the year ended December 31, 2021.

The extent of the future impact of COVID-19 on the Company’s financial results and business operations cannot be predicted at this time and will depend on future developments, including the duration and severity of the pandemic, timing and effectiveness of vaccinations, further potential government actions and future economic activity and energy usage. Actual results may differ significantly from these estimates.

Rate Regulation

The rate-regulated accounting policies of Emera’s rate-regulated subsidiaries and regulated equity investments are subject to examination and approval by their respective regulators and may differ from accounting policies for non-rate-regulated companies. These accounting policy differences occur when the regulators render their decisions on rate applications or other matters, and generally involve a difference in the timing of revenue and expense recognition. The accounting for these items is based on expectations of the future actions of the regulators. Assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered. The application of regulatory accounting guidance is a critical accounting policy as a change in these assumptions may result in a material impact on reported assets, liabilities and the results of operations.

The Company has recorded $2,566 million (2020 - $1,584 million) of regulatory assets and $2,055 million (2020 - $1,961 million) of regulatory liabilities as at December 31, 2021.

Accumulated Reserve – Cost of Removal

Tampa Electric, PGS, NMGC and NSPI recognize non-asset retirement obligation (“ARO”) costs of removal (“COR”) as regulatory liabilities. The non-ARO COR represent estimated funds received from customers through depreciation rates to cover future COR of property, plant and equipment upon retirement that are not legally required. The companies accrue for COR over the life of the related assets based on depreciation studies approved by their respective regulators. The costs are estimated based on historical experience and future expectations, including expected timing and estimated future cash outlays. The balance of the Accumulated reserve – COR within regulatory liabilities was $819 million at December 31, 2021 (2020 - $865 million).

Pension and Other Post-Retirement Employee Benefits

The Company provides post-retirement benefits to employees, including defined benefit pension plans. The cost of providing these benefits is dependent upon many factors that result from actual plan experience and assumptions of future expectations.

The accounting related to employee post-retirement benefits is a critical accounting estimate. Changes in the estimated benefit obligation, affected by employee demographics, including age, compensation levels, employment periods, contribution levels and earnings, could have a material impact on reported assets, liabilities, accumulated other comprehensive income and results of operations. Changes in key actuarial assumptions, including anticipated rates of return on plan assets and discount rates used in determining the accrued benefit obligation and benefit costs, could change annual funding requirements. This could have a significant impact on the Company’s annual earnings and cash requirements.

The pension plan assets are comprised primarily of equity and fixed income investments. Fluctuations in actual equity market returns and changes in interest rates may result in changes to pension costs in future periods.

The Company’s accounting policy is to amortize the net actuarial gain or loss, that exceeds 10 per cent of the greater of the projected benefit obligation / accumulated post-retirement benefit obligation (“PBO”) and the market-related value of assets, over active plan members’ average remaining service period. For the largest plans this is currently 9.2 years (9.0 years for 2021 benefit cost) for the Canadian plans and a weighted average of 11.1 years for the US plans). The Company’s use of smoothed asset values reduces volatility related to the amortization of actuarial investment experience. As a result, the main cause of volatility in reported pension cost is the discount rate used to determine the PBO.

The discount rate used to determine benefit costs is based on the yield of high quality long-term corporate bonds in each operating entity’s country and is determined with reference to bonds which have the same duration as the PBO as at January 1 of the fiscal year. The following table shows the discount rate for benefit cost purposes and the expected return on plan assets for each plan:

2021

2020

Discount rate for

benefit cost
purposes

Expected

return on

plan assets

Discount rate for

benefit cost purposes

Expected

return on

plan assets

TECO Energy Group Retirement Plan

2.38%

6.70%

3.22%

7.00

TECO Energy Group Supplemental Executive Retirement Plan (1)

1.84%

N/A

2.78%

N/A

TECO Energy Group Benefit Restoration Plan (1)

1.71%

N/A

2.81%

N/A

TECO Energy Post-retirement Health and Welfare Plan

2.47%

N/A

3.32%

N/A

New Mexico Gas Company Retiree Medical Plan

2.49%

4.00%

3.32%

3.25%

NSPI

2.59%, 2.85%

5.25%

3.13%, 3.21%

5.75%

GBPC Salaried

4.25%

6.00%

4.25%

6.00%

GBPC Union

5.65%

5.00%

(1) The discount rate and expected return on assets for benefit cost purposes is updated throughout the year as special events occur, such as settlements and curtailments.

Based on management’s estimate, the reported benefit cost for defined benefit and defined contribution plans was $85 million in 2021 (2020 - $87 million). The reported benefit cost is impacted by numerous assumptions, including the discount rate and asset return assumptions. A 0.25 per cent change in the discount rate and asset return assumptions would have had +/- impact on the 2021 benefit cost of $1 million and $3 million respectively (2020 - $6 million and $5 million).

Unbilled Revenue

Electric and gas revenues are billed on a systematic basis over a one or two-month period for NSPI and a one-month period for other Emera utilities. At the end of each month, the Company must make an estimate of energy delivered to customers since the date their meter was last read and determine related revenues earned but not yet billed. The unbilled revenue is estimated based on several factors, including current month’s generation, estimated customer usage by class, weather, line losses, inter-period changes to customer classes and applicable customer rates. Based on the extent of the estimates included in the determination of unbilled revenue, actual results may differ from the estimate. At December 31, 2021, unbilled revenues totalled $318 million (2020 – $286 million) on total regulated operating revenues of $5,926 million (2020 – $5,476 million).

Property, Plant and Equipment

Property, plant and equipment represents 59 per cent of total assets on the Company’s balance sheet. Included in “Property, plant and equipment” are the generation, transmission and distribution and other assets of the Company.

Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each category. The service lives of regulated property, plant and equipment are determined based on depreciation studies and require appropriate regulatory approval. Due to the magnitude of the Company’s property, plant and equipment, changes in estimated depreciation rates can have a material impact on depreciation expense and accumulated depreciation.

Depreciation expense was $877 million for the year ended December 31, 2021 (2020 – $860 million).

Goodwill Impairment Assessments

Goodwill is subject to an annual assessment for impairment at the reporting unit level with interim impairment tests performed when impairment indicators are present. Reporting units are generally determined at the operating segment level or one level below the operating segment level. Reporting units with similar characteristics are grouped for the purpose of determining impairment, if any, of goodwill. Application of the goodwill impairment test requires management judgment on significant assumptions and estimates. When assessing goodwill for impairment the Company has the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. Significant assumptions used in the qualitative assessment include macroeconomic conditions, industry and market considerations, and overall financial performance, among other factors.

If the Company performs the qualitative assessment and determines that it is more likely than not that its fair value is less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a quantitative test is performed. The quantitative test compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. Significant assumptions used in estimating the fair value include discount and growth rates, rate case assumptions, valuation of the reporting units’ net operating loss (“NOL”), utility sector market performance and transactions, projected operating and capital cash flows, and the fair value of debt. Adverse changes in assumptions could result in a future material impairment of the goodwill assigned to Emera’s reporting units with goodwill. As part of the goodwill impairment assessment, management considered potential impacts of the COVID-19 pandemic on future earnings of the reporting units.

As of December 31, 2021, the Company had goodwill with a total carrying amount of $5,696 million (December 31, 2020 – $5,720 million). This goodwill represents the excess of the acquisition purchase price for TECO Energy (Tampa Electric, PGS and NMGC reporting units) and GBPC over the fair values assigned to identifiable assets acquired and liabilities assumed. The change in the carrying value of goodwill from 2020 to 2021 was a result of changes to the Canadian dollar on the goodwill balances.

As of December 31, 2021, $5.6 billion of Emera’s goodwill was related to TECO Energy (Tampa Electric, PGS and NMGC reporting units). Qualitative assessments were performed for these reporting units given the significant excess of fair value over carrying amounts calculated during the last quantitative test in Q4 2019. Management concluded that it was more likely than not that the fair value of these reporting units exceeded their respective carrying amounts, including goodwill. As such, no quantitative testing was required.

As of December 31, 2021, $68 million of Emera’s goodwill was related to GBPC. In Q4 2021, the Company performed a quantitative impairment assessment for GBPC as this reporting unit is more sensitive to changes in assumptions due to limited excess of fair value over the carrying value. The assessment estimated that the fair value of the reporting unit exceeded its carrying value, including goodwill, by approximately 12 per cent. For further detail, refer to note 22 to the consolidated financial statements.

Long-Lived Assets Impairment Assessments

In accordance with accounting guidance for long-lived assets, the Company assesses whether there has been an impairment of long-lived assets and intangibles when a triggering event occurs, such as a significant market disruption or the sale of a business. The assessment involves comparing the undiscounted expected future cash flows, to the carrying value of the asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset over its estimated fair value.

The Company believes accounting estimates related to asset impairments are critical estimates, as they are highly susceptible to change and the impact of an impairment on reported assets and earnings could be material. Management is required to make assumptions based on expectations regarding the results of operations for significant/indefinite future periods and the current and expected market conditions in such periods. Markets can experience significant uncertainties. Estimates based on the Company’s assumptions relating to future results of operations or other recoverable amounts are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. The Company’s expectations regarding uses and holding periods of assets are based on internal long-term budgets and projections, which consider external factors and market forces, as of the end of each reporting period. Assumptions made by management are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities.

Management considered whether the potential impacts of the COVID-19 pandemic on undiscounted future cash flows could indicate that long-lived assets are not recoverable. As at December 31, 2021, there were no indications of impairment of Emera’s long-lived assets.

No impairment charges were recognized during the year ended December 31, 2021. In 2020, impairment charges of $25 million ($26 million after tax) were recognized on certain assets and recorded in “Impairment charge” on the Consolidated Income Statement.

Income Taxes

Income taxes are determined based on the expected tax treatment of transactions recorded in the consolidated financial statements. In determining income taxes, tax legislation is interpreted in a variety of jurisdictions, the likelihood that deferred tax assets will be recovered from future taxable income is assessed and assumptions about the expected timing of the reversal of deferred tax assets and liabilities are made. Uncertainty associated with application of tax statutes and regulations and the outcomes of tax audits and appeals, requires that judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income tax benefits that meet the “more likely than not” threshold may be recognized or continue to be recognized. Unrecognized tax benefits are evaluated quarterly and changes are recorded based on new information, including issuance of relevant guidance by the courts or tax authorities and developments occurring in examinations of the Company’s tax returns.

The Company believes the accounting estimates related to income taxes are critical estimates. The realization of deferred tax assets is dependent upon the generation of sufficient taxable income, both operating and capital, in future periods. A change in the estimated valuation allowance could have a material impact on reported assets and results of operations. Administrative actions of the tax authorities, changes in tax law or regulation, and the uncertainty associated with the application of tax statutes and regulations, could change the Company’s estimate of income taxes, including the potential for elimination or reduction of the Company’s ability to realize tax benefits and to utilize deferred tax assets.

Asset Retirement Obligations (“ARO”)

Measurement of the fair value of AROs requires the Company to make reasonable estimates concerning the method and timing of settlement associated with the legally obligated costs. There are uncertainties in estimating future asset-retirement costs due to potential events, such as changing legislation or regulations, and advances in remediation technologies. Emera has AROs associated with the remediation of generation, transmission, distribution and pipeline assets.

An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation using the Company’s credit-adjusted risk-free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives and governmental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. Accretion expense is included as part of “Depreciation and amortization expense”. Any accretion expense not yet approved by the regulator is recorded in “Property, plant and equipment” and included in the next depreciation study. Accordingly, changes to the ARO or cost recognition attributable to changes in the factors discussed above, should not impact the results of operations of the Company.

Some generation, transmission and distribution assets may have conditional AROs, which are required to be estimated and recorded as a liability. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Management monitors these obligations and a liability is recognized at fair value when an amount can be determined.

As at December 31, 2021, AROs recorded on the balance sheet were $174 million (2020 – $178 million). The Company estimates the undiscounted amount of cash flow required to settle the obligations is approximately $422 million (2020 - $432 million), which will be incurred between 2022 and 2061. The majority of these costs will be incurred between 2028 and 2050.

Financial Instruments

The Company is required to determine the fair value of all derivatives except those which qualify for the normal purchase, normal sale exception. Fair value is the price that would be received for the sale of an asset or paid to transfer a liability in an orderly arms-length transaction between market participants at the measurement date. Fair value measurements are required to reflect assumptions that market participants would use in pricing an asset or liability based on the best available information, including the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model.

Level Determinations and Classifications

The Company uses Level 1, 2, and 3 classifications in the fair value hierarchy. The fair value measurement of a financial instrument is included in only one of the three levels and is based on the lowest level input significant to the derivation of the fair value. Fair values are determined, directly or indirectly, using inputs that are observable for the asset or liability. Only in limited circumstances does the Company enter into commodity transactions involving non-standard features where market observable data is not available or have contract terms that extend beyond five years.

CHANGES IN ACCOUNTING POLICIES AND PRACTICES

The new USGAAP accounting policies that are applicable to, and adopted by the Company in 2021, are described as follows:

Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity

The Company adopted Accounting Standard Update (“ASU”) 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) effective January 1, 2021 using the modified retrospective approach. The standard simplifies the accounting for convertible debenture debt instruments and convertible preferred stock, in addition to amending disclosure requirements. The standard also updates guidance for the derivative scope exception for contracts in an entity’s own equity and the related earnings per share guidance. There was no material impact on the consolidated financial statements as a result of the adoption of this standard.

Guaranteed Debt Securities Disclosure Requirements

The Company adopted ASU 2020-09, Debt (Topic 470): Amendments to SEC Paragraphs pursuant to SEC Release No. 33-10762 effective December 31, 2021. The standard aligns with new SEC rules relating to changes to the disclosure requirements for certain registered debt securities that are guaranteed. The changes include simplifying and focusing the disclosure models, enhancing certain narrative disclosures and permitting the disclosures to be made outside of the financial statements. As a result of adopting this standard, the disclosures related to certain registered debt securities that are guaranteed were amended and removed from the consolidated financial statements and added to Management’s Discussion & Analysis.

Future Accounting Pronouncements

The Company considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board (“FASB”). The ASUs that have been issued by FASB, but are not yet effective, were assessed and determined to be either not applicable to the Company or have an insignificant impact on the consolidated financial statements.

SUMMARY OF QUARTERLY RESULTS


For the quarter ended millions of Canadian dollars		Q4		Q3			Q2			Q1		Q4		Q3		Q2		Q1
(except per share amounts)		2021		2021			2021			2021		2020		2020		2020		2020

Operating revenues	$	1,868	$	1,148		$	1,137		$	1,612	$	1,537	$	1,163	$	1,169	$	1,637

Net income attributable to common shareholders	$	324	$	(70	)	$	(17	)	$	273	$	273	$	84	$	58	$	523

Adjusted net income attributable to common shareholders	$	168	$	175		$	137		$	243	$	188	$	166	$	118	$	193

Earnings per common share – basic	$	1.24	$	(0.27	)	$	(0.07	)	$	1.08	$	1.09	$	0.34	$	0.24	$	2.14

Earnings per common share – diluted	$	1.20	$	(0.27	)	$	(0.07	)	$	1.08	$	1.08	$	0.34	$	0.23	$	2.13

Adjusted earnings per common share – basic	$	0.64	$	0.68		$	0.54		$	0.96	$	0.75	$	0.67	$	0.48	$	0.79

Quarterly operating revenues and adjusted net income attributable to common shareholders are affected by seasonality. The first quarter provides strong earnings contributions due to a significant portion of the Company’s operations being in northeastern North America, where winter is the peak electricity usage season. The third quarter provides strong earnings contributions due to summer being the heaviest electric consumption season in Florida. Seasonal and other weather patterns, as well as the number and severity of storms, can affect demand for energy and the cost of service. Quarterly results could also be affected by items outlined in the “Significant Items Affecting Earnings” section.