EX-99.1

Q2 Average Fuel Costs

US dollars

Dollars per Megawatt hour (“MWh”)

EX-99.1 2 d561918dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

LOGO

Management’s Discussion & Analysis

As at August 10, 2021

Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its subsidiaries and investments during the second quarter and year-to-date of 2021 relative to the same periods in 2020; and its financial position as at June 30, 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 unaudited condensed consolidated interim financial statements and supporting notes as at and for the three and six months ended June 30, 2021; and the Emera Incorporated annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2020. 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 June 30, 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		7
Consolidated Income Statement Highlights		9
Business Overview and Outlook		12
COVID-19 Pandemic		12
Florida Electric Utility		13
Canadian Electric Utilities		14
Other Electric Utilities		15
Gas Utilities and Infrastructure		16
Other		17
Consolidated Balance Sheet Highlights		18
Developments		19
Outstanding Stock Data		20
Financial Highlights		21
Florida Electric Utility		21
Canadian Electric Utilities		23
Other Electric Utilities		26
Gas Utilities and Infrastructure		27
Other		29
Liquidity and Capital Resources		31
Consolidated Cash Flow Highlights		32
Contractual Obligations		34
Debt Management		35
Guarantees and Letters of Credit		36
Transactions with Related Parties		37
Risk Management including Financial Instruments		37
Disclosure and Internal Controls		39
Critical Accounting Estimates		40
Changes in Accounting Policies and Practices		41
Future Accounting Pronouncements		41
Summary of Quarterly Results		42

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 investment; 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 gas and electric 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 $7.4 billion capital investment plan over the 2021-to-2023 period, and the potential for additional capital opportunities of $1.2 billion over the same period, results in a forecasted rate base growth of 7.5 per cent to 8.5 per cent through 2023. 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.

Emera has provided annual dividend growth guidance of four to five per cent through to 2022. The Company targets a long-term dividend payout ratio 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.

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 at Tampa Electric, and the modernization of the Big Bend Power Station at Tampa Electric. 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 achieve these goals and realize its net-zero vision while remaining focused on maintaining affordability, enhancing reliability, adopting emerging technologies and working constructively with policymakers, regulators, partners, investors, and Emera’s communities.

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

Emera calculates an 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:

●

the 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;

●

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

●

the amortization of transportation capacity recognized as a result of certain Emera Energy marketing and trading transactions;

●

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

●

the 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”, and the “Financial Highlights – Other” sections.

In 2020, the Company recognized a gain on the sale of Emera Maine. Management believes excluding this from net income better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business. For further details related to the sale of Emera Maine, refer to the “Significant Items Affecting Earnings” section. 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.

In 2020, the Company recognized certain non-cash impairment charges. Management believes excluding from net income the effect of these charges better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the Company. For further details, refer to the “Significant Items Affecting Earnings” and “Financial Highlights – Other” sections.

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


	Three months ended				Six months ended
For the	June 30				June 30
millions of Canadian dollars (except per share amounts)	2021		2020		2021		2020
Net income (loss) attributable to common shareholders	$	(17)	$	58	$	256	$ 581
Gain on sale, net of tax and transaction costs		-		(12)		-	309
Impairment charges, net of tax		-		(3)		-	(26)
After-tax MTM loss		(154)		(45)		(124)	(13)
Adjusted net income attributable to common shareholders	$	137	$	118	$	380	$ 311
Earnings (loss) per common share – basic	$	(0.07)	$	0.24	$	1.01	$ 2.37
Adjusted earnings per common share – basic	$	0.54	$	0.48	$	1.49	$ 1.27

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 (loss) 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 (loss) to EBITDA and Adjusted EBITDA:


	Three months ended				Six months ended
For the	June 30				June 30
millions of Canadian dollars	2021		2020		2021		2020
Net income (loss) (1)	$	(6)	$	81	$	279	$ 616
Interest expense, net		153		173		310	357
Income tax expense (recovery)		(55)		(1)		1	305
Depreciation and amortization		221		216		447	447
EBITDA		313		469		1,037	1,725
Gain on sale, net of transaction costs (excluding income tax)		-		(1)		-	585
Impairment charge, excluding income tax		-		(3)		-	(25)
MTM loss, excluding income tax		(216)		(65)		(173)	(20)
Adjusted EBITDA	$	529	$	538	$	1,210	$ 1,185

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

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Earnings

Earnings Impact of After-Tax MTM Losses

After-tax MTM losses increased $109 million to $154 million in Q2 2021, compared to $45 million in Q2 2020. Year-to-date, after-tax MTM losses increased $111 million to $124 million compared to $13 million for the same period in 2020. The increase in both periods is due to changes in existing positions at Emera Energy and increased foreign exchange losses on cash flow hedges, partially offset by lower amortization of gas transportation assets in 2021 at Emera Energy.

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). In Q1 2020, a gain on sale of $321 million after tax ($1.31 per common share), net of transaction costs, was recognized. In Q2 2020, an adjustment of $12 million after tax was recognized as a result of finalizing the gain calculation, such that the final year-to-date gain on sale was $309 million after tax ($1.26 per common share).

In addition, impairment charges of $3 million after tax in Q2 2020 and $26 million after tax year-to-date in 2020 were recognized on certain other assets.

Consolidated Financial Highlights by Business Segment


For the	Three months ended				Six months ended
millions of Canadian dollars	June 30				June 30
Adjusted net income	2021		2020		2021		2020
Florida Electric Utility	$	125	$	146	$	208	$ 225
Canadian Electric Utilities		44		37		132	129
Other Electric Utilities		-		(1)		7	19
Gas Utilities and Infrastructure		34		27		114	97
Other		(66)		(91)		(81)	(159)
Adjusted net income attributable to common shareholders	$	137	$	118	$	380	$ 311
Gain on sale, net of tax and transaction costs		-		(12)		-	309
Impairment charges, net of tax		-		(3)		-	(26)
After-tax MTM loss		(154)		(45)		(124)	(13)
Net income (loss) attributable to common shareholders	$	(17)	$	58	$	256	$ 581

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


For the	Three months ended		Six months ended
millions of Canadian dollars	June 30		June 30
Adjusted net income – 2020	$	118	$ 311
Operating Unit Performance
Increased earnings at Emera Energy Services (“EES”) due to favourable market conditions		7	24
Increased earnings at PGS due to higher base revenues as the result of a base rate increase on January 1, 2021 and customer growth		7	17
Decreased earnings at Tampa Electric due to the impact of a stronger CAD, higher depreciation and amortization reflecting increased capital investment, a 2020 regulatory settlement and increased operating, maintenance and general (“OM&G”) expenses. These decreases were partially offset by higher allowance for funds used during construction (“AFUDC”) earnings		(21)	(17)
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
Timing of preferred dividend declaration in Q2 2020		12	12
Decreased interest expense, pre-tax, due to the impact of a stronger CAD, repayment of corporate debt and lower interest rates		9	22
Decreased OM&G, pre-tax, year-over-year due to lower long-term compensation		(2)	14
Other Variances		7	(1)
Adjusted net income – 2021	$	137	$ 380

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


For the	Six months ended June 30
millions of Canadian dollars	2021		2020
Operating cash flow before changes in working capital	$	684	$ 816
Change in working capital		(53)	(75)
Operating cash flow	$	631	$741
Investing cash flow	$	(993)	$ 78
Financing cash flow	$	320	$ (712)

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


As at		June 30	December 31
millions of Canadian dollars		2021	2020
Total assets	$	31,362	$ 31,234
Total long-term debt (including current portion)	$	14,057	$ 13,721

Consolidated Income Statement Highlights


For the	Three months ended						Six months ended
millions of Canadian dollars	June 30						June 30
(except per share amounts)	2021		2020		Variance		2021		2020		Variance
Operating revenues	$	1,137	$	1,169	$	(32)	$	2,749	$	2,806	$	(57)
Operating expenses		1,107		983		(124)		2,282		2,221		(61)
Income from operations		30		186		(156)		467		585		(118)
Income from equity investments		37		40		(3)		78		81		(3)
Other income, net		25		27		(2)		45		612		(567)
Interest expense, net		153		173		20		310		357		47
Income tax expense (recovery)		(55)		(1)		54		1		305		304
Net income (loss)	$	(6)	$	81	$	(87)	$	279	$	616	$	(337)
Net income (loss) attributable to common shareholders	$	(17)	$	58	$	(75)	$	256	$	581	$	(325)
Gain on sale, net of tax and transaction costs		-		(12)		12		-		309		(309)
Impairment charges, net of tax		-		(3)		3		-		(26)		26
After-tax MTM loss		(154)		(45)		(109)		(124)		(13)		(111)
Adjusted net income attributable to common shareholders	$	137	$	118	$	19	$	380	$	311	$	69
Earnings (loss) per common share – basic	$	(0.07)	$	0.24	$	(0.31)	$	1.01	$	2.37	$	(1.36)
Earnings (loss) per common share – diluted	$	(0.07)	$	0.23	$	(0.30)	$	1.01	$	2.35	$	(1.34)
Adjusted earnings per common share – basic	$	0.54	$	0.48	$	0.06	$	1.49	$	1.27	$	0.22
Dividends per common share declared	$	0.6375	$	1.2250	$	(0.5875)	$	1.2750	$	1.8375	$	(0.5625)
Adjusted EBITDA	$	529	$	538	$	(9)	$	1,210	$	1,185	$	25

Operating Revenues

For the second quarter of 2021, operating revenues decreased $32 million compared to the second quarter in 2020. Absent increased MTM losses of $124 million, operating revenues increased $92 million due to:

●

$34 million increase in the Gas Utilities and Infrastructure segment 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. This increase was partially offset by the impact of a stronger CAD;

●

$25 million increase in the Florida Electric Utility segment due to higher fuel recovery clause revenue as a result of higher fuel costs, partially offset by the impact of a stronger CAD;

●

$13 million increase in the Other segment due to higher marketing and trading margin at EES primarily driven by favourable market conditions; and

●

$12 million increase in the Other Electric Utilities segment due to higher fuel revenue at BLPC as a result of higher oil prices.

Year-to-date in 2021, operating revenues decreased $57 million compared to the same period in 2020. Absent increased MTM losses of $144 million, operating revenues increased by $87 million due to:

●

$96 million increase in the Gas Utilities and Infrastructure segment 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. This increase was partially offset by the impact of a stronger CAD;

●

$39 million increase in the Other segment due to higher marketing and trading margin at EES primarily driven by favourable market conditions; and

●

$24 million increase in the Florida Electric Utility segment primarily due to higher fuel recovery clause revenue as a result of higher fuel costs, partially offset by the impact of a stronger CAD.

These impacts were partially offset by:

●

$59 million decrease in the Other Electric Utilities segment due to the sale of Emera Maine in Q1 2020.

Operating Expenses

For the second quarter of 2021, operating expenses increased $124 million compared to the second quarter of 2020. Absent the 2020 impairment charges of $3 million, operating expenses increased $127 million due to:

●

$62 million increase in the Florida Electric Utility segment due to higher natural gas prices, partially offset by the impact of a stronger CAD;

●

$29 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

●

$16 million increase in the Other Electric Utilities segment due to higher oil prices at BLPC.

Year-to-date in 2021, operating expenses increased $61 million compared to the same period of 2020. Absent the 2020 impairment charges of $26 million, operating expenses increased $87 million due to:

●

$78 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

●

$66 million increase in the Florida Electric Utility segment due to higher natural gas prices, partially offset by the impact of a stronger CAD.

These impacts were partially offset by:

●

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

Other Income, Net

Other income, net decreased year-to-date in 2021 compared to the same period in 2020 primarily due to the 2020 pre-tax gain on sale of Emera Maine.

Interest Expense, Net

Interest expense, net was lower for the second quarter and year-to-date 2021, compared to the same periods in 2020, due to the impact of a stronger CAD, the repayment of corporate debt and lower interest rates.

Income Tax Expense (Recovery)

The increase in income tax recovery for the second quarter in 2021, compared to the same period in 2020 , was primarily due to decreased income before provision for income taxes. The decrease in income tax expense year-to-date in 2021, compared to the same period in 2020, was primarily due to the gain on sale of Emera Maine.

Net Income and Adjusted Net Income Attributable to Common Shareholders

For the second quarter of 2021, the decrease in net income attributable to common shareholders compared to the same period in 2020, was unfavourably impacted by the $109 million increase in after-tax MTM losses primarily related to Emera Energy, favourably impacted by the $12 million adjustment to the after-tax gain on sale of Emera Maine in Q2 2020 and favourably impacted by the $3 million after-tax impairment charge in 2020. Absent the unfavourable MTM changes, the Q2 2020 adjustment to the gain on sale of Emera Maine and the 2020 impairment charges, adjusted net income attributable to common shareholders increased $19 million. The increase was primarily due to the timing of the preferred dividend declaration in Q2 2020, lower corporate interest expense, and increased earnings contributions from EES and PGS. These were partially offset by the impact of a stronger CAD and lower earnings contributions from Tampa Electric.

Year-to-date in 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 $111 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 attributable to common shareholders increased $69 million. The increase was primarily due to higher earnings contribution from EES and PGS, lower corporate interest expense, the 2020 revaluation of deferred taxes due to a reduction in the Nova Scotia corporate income tax rate, lower corporate OM&G, and the timing of preferred dividend declaration in Q2 2020. The increase was partially offset by the impact of a stronger CAD, the 2020 recognition of a corporate income tax recovery previously deferred as a regulatory liability in 2018 at BLPC, and lower earnings due to the sale of Emera Maine in Q1 2020.

Earnings and Adjusted Earnings per Common Share – Basic

Earnings per common share – basic was lower for the second quarter and year-to-date in 2021 due to the decreased earnings as discussed above and the impact of the increase in weighted average shares outstanding.

Adjusted earnings per common share was higher for the second quarter and year-to-date in 2021 due to increased adjusted earnings as discussed above, partially offset by the impact of the increase in the weighted average common 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 foreign exchange cash flow hedges entered 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				Six months ended				Year ended
	June 30				June 30				December 31
For the	2021		2020		2021		2020		2020
Weighted average CAD/USD exchange rate	$	1.25	$	1.39	$	1.27	$	1.37	$ 1.34
Period end CAD/USD exchange rate	$	1.24	$	1.36	$	1.24	$	1.36	$ 1.27

Strengthening of the CAD decreased the net loss by $2 million and decreased adjusted earnings by $11 million in Q2 2021 compared to Q2 2020. The strengthening of the CAD decreased earnings by $9 million and adjusted earnings by $20 million year-to-date in 2021, compared to the same period in 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				Six months ended
For the	June 30				June 30
millions of US dollars	2021		2020		2021		2020
Florida Electric Utility	$	102	$	106	$	167	$ 165
Other Electric Utilities		-		(1)		6	14
Gas Utilities and Infrastructure (1)		21		14		77	59
		123		119		250	238
Other segment (2)		(37)		(40)		(39)	(63)
Total	$	86	$	79	$	211	$ 175

(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

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 has not had a material financial impact to date on net earnings 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 2021. 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. For further information on the potential future impacts of COVID-19 on Emera and its businesses, refer to the “Business Overview and Outlook” and “Liquidity and Capital Resources” sections in the Company’s 2020 annual MD&A.

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 below, by segment, 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.

Due to continued growth in rate base, Tampa Electric anticipates earning near the bottom of the allowed ROE range in 2021. Tampa Electric sales volumes are expected to be similar to 2020, which benefited from weather that was warmer than in recent years. As a result, Tampa Electric anticipates earnings to be slightly lower than in 2020, which included the impact of a $16 million USD intangible software amortization credit due to a regulatory agreement approved by the FPSC in 2020. Tampa Electric expects customer growth rates in 2021 to be consistent with 2020, reflective of current expected economic growth in Florida.

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 will not become effective until approved by the FPSC. The FPSC is expected to consider the matter by October 2021.

On July 19, 2021, Tampa Electric requested a mid-course adjustment of $83 million USD to its fuel and capacity charges, effective with September 2021 customer bills, due to an increase in fuel commodity and capacity costs in 2021. On August 3, 2021, the FPSC approved the request to recover the costs during the months of September through December 2021.

In 2021, capital investment in the Florida Electric Utility segment is expected to be approximately $1.2 billion USD (2020 - $1.0 billion USD), including AFUDC. Capital projects include solar investments, continuation of the modernization of the Big Bend Power Station, storm hardening investments and AMI.

Canadian Electric Utilities

Canadian Electric Utilities includes NSPI and Emera Newfoundland & Labrador Holdings Inc. (“ENL”). NSPI is a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity and is 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

NSPI anticipates earning near the low end of its allowed ROE range in 2021 and expects rate base and earnings to be higher than 2020. Assuming normal weather and a modest economic recovery from impacts of the COVID-19 pandemic in 2021, NSPI expects sales volumes to be higher than 2020.

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. With the forthcoming Nova Scotia block (“NS Block”), which is described below, NSPI is on track to meet the requirements of the program, where compliance is forecasted to be achieved through the granted emissions allowances, reduced emissions and credit purchases under the Cap-and-Trade Program. 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 will increase upon delivery of the NS Block of electricity transmitted through the Maritime Link from the Muskrat Falls hydroelectric project (“Muskrat Falls”). Nalcor Energy (“Nalcor”) has agreed to commence delivery of the NS Block by August 15, 2021 which 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. NSPI has the option of purchasing additional market-priced energy from Nalcor through the Energy Access Agreement. Pursuant to the agreement, Nalcor is obligated to offer NSPI a minimum average of 1.2 TWh of energy annually. Nalcor continues to work toward construction completion and final commissioning of the Lower Churchill projects (including Muskrat Falls and LIL) in the second half of 2021.

Under the provincially legislated Renewable Energy Regulations, 40 per cent of electric sales must be generated from renewable sources. 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 to 2022 period. NSPI expects to achieve this alternative compliance standard.

In 2021, capital investment for NSPI is expected to be approximately $395 million (2020 – $316 million), including AFUDC, primarily in capital projects required to support system reliability and hydroelectric infrastructure renewal projects.

ENL

Equity earnings from NSPML and LIL are expected to be higher in 2021, compared to 2020. Both the NSPML and LIL investments are recorded as “Investments subject to significant influence” on Emera’s Condensed 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 and provide for the transmission of energy between Newfoundland and Nova Scotia, improved reliability and ancillary benefits, supporting the efficiency and reliability of energy in both provinces. The Maritime Link will transmit at greater capacity when the Lower Churchill project is complete.

NSPML has 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 is subject to a holdback of up to $10 million that is dependent upon the timing of commencement of the NS Block and NSPML has deferred collection of $23 million in depreciation expense. Approximately $162 million is included in NSPI rates.

Two of four generators at Muskrat Falls are completed and available for service, the first in Q3 2020 and the second in Q2 2021. The third unit is expected to be completed in Q3 2021. Nalcor continues to work toward final project commissioning of Muskrat Falls and LIL in the second half of 2021. Nalcor has agreed to commence delivery of the NS Block by August 15, 2021 and the NS Block will be delivered over the next 35 years pursuant to the agreements. 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 requesting to set rates for 2022. A decision by the UARB is expected in early 2022.

In 2021, NSPML expects to invest approximately $10 million (2020 - $7 million) in capital.

LIL

ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and Nalcor continues to work toward final project commissioning in 2021.

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 $655 million, comprised of $410 million in equity contribution and $245 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, and until that point Emera will continue to record AFUDC earnings. Nalcor continues to work toward final project commissioning of the LIL in the second half of 2021.

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 was included in the Other Electric Utilities segment in Q1 2020.

Removing the Q1 2020 earnings contribution from Emera Maine and the Q1 2020 recognition of a $10 million previously deferred corporate income tax recovery, Other Electric Utilities’ earnings in 2021 are expected to increase over the prior year.

In Q1 2021, GBPC notified the GBPA of its intention to submit a Rate Plan proposal in 2021.

On November 6, 2020, BLPC notified the FTC that it plans to file a general rate review application with the FTC. This application is expected to be filed in the second half of 2021.

In 2021, capital investment in the Other Electric Utilities segment is expected to be approximately $120 million USD (2020 – $111 million USD including $14 million USD invested in Emera Maine projects), primarily in more efficient and cleaner sources of generation, including renewables and battery storage. BLPC expects to complete installation of a 33 MW diesel engine plant in the second half of 2021. This 33 MW plant is expected to increase efficiency and bridge BLPC’s transition to increased renewable sources of generation.

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 a 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.

Gas Utilities and Infrastructure earnings are anticipated to be higher in 2021 than 2020 primarily due to approved base rate increases for PGS and NMGC.

PGS anticipates earning within its allowed ROE range in 2021 and expects rate base and earnings to be higher than in 2020. PGS expects customer growth in 2021 to be higher than Florida’s population growth rates, reflecting expectations of continued strong housing demand in Florida and commercial activity trending back towards normal levels. PGS sales volumes are expected to increase above customer growth, as the COVID-19 pandemic impact on 2021 commercial energy sales is expected to be less than 2020. In January 2021, a base rate increase went into effect in accordance with the FPSC approved rate case settlement and is expected to result in a $34 million USD revenue increase.

NMGC’s application for new rates was approved in December 2020 and took effect in January 2021. The new rates result in an increase in revenue of approximately $5 million USD annually. NMGC anticipates earning at or near its authorized ROE in 2021 and expects rate base to be higher than 2020. NMGC expects customer growth rates to be consistent with historical trends.

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 2021, capital investment in the Gas Utilities and Infrastructure segment is expected to be approximately $430 million USD (2020 - $553 million USD), including AFUDC. PGS will make investments to expand its system and support customer growth. NMGC completed the Santa Fe Mainline Looping project in 2021 and will continue to invest in system improvements.

Other

The Other segment includes 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 600 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 recorded in “Intercompany revenue” 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 earnings of $15 to $30 million USD ($45 to $70 million USD of margin), with the opportunity for upside when market conditions present.

Absent the gain on the TECO Guatemala Holdings award in Q4 2020, the adjusted net loss from the Other segment is expected to be lower in 2021, primarily due to decreased interest expense, lower OM&G and higher earnings from EES. The decrease is expected to be partially offset by increased taxes due to a lower net loss and increased project spend in ETL.

In 2021, capital investment in the Other segment is expected to be approximately $5 million (2020 - $3 million).

CONSOLIDATED BALANCE SHEET HIGHLIGHTS

Significant changes in the Condensed Consolidated Balance Sheets between December 31, 2020 and June 30, 2021 include:


millions of Canadian dollars	Increase (Decrease)		Explanation
Assets
Derivative instruments (current and long-term)		$ 57	Increased due to higher commodity prices, partially offset by settlements of derivative instruments at NSPI
Regulatory assets (current and long-term)		140	Increased due to the NMGC winter event gas cost recovery, increased deferred income tax regulatory asset at NSPI and increased deferrals related to the fuel adjustment mechanism at NSPI. This increase was partially offset by deferrals related to derivative instruments at NSPI and the effect of a stronger CAD on the translation of Emera’s foreign affiliates
Property, plant and equipment, net of accumulated depreciation and amortization		103	Increased due to capital additions at Tampa Electric, PGS and NSPI, partially offset by the effect of a stronger CAD on the translation of Emera’s foreign affiliates
Goodwill		(152)	Decreased due to the effect of a stronger CAD on the translation of Emera’s foreign affiliates
Liabilities and Equity
Short-term debt and long-term debt (including current portion)		$ (66)	Decreased due to repayment of short-term debt at TEC, net repayments on committed credit facilities at Emera and NSPI and the effect of a stronger CAD on the translation of Emera’s foreign affiliates. The decrease was partially offset by net issuances of long-term debt at TEC and NMGC
Accounts payable		(87)	Decreased due to timing of payments at NMGC, PGS, NSPI, and the effect of a stronger CAD on the translation of Emera’s foreign affiliates. This decrease was partially offset by increased cash collateral positions on derivative instruments at NSPI
Derivative instruments (current and long-term)		91	Increased due to new contracts in 2021 and changes in existing positions, partially offset by reversal of 2020 contracts at Emera Energy
Common stock		252	Increased due to shares issued under Emera’s at-the-market equity program and the dividend reinvestment plan
Cumulative preferred stock		196	Increased due to issuance of preferred shares
Accumulated other comprehensive income		(183)	Decreased due to the effect of a stronger CAD on the translation of Emera’s foreign affiliates
Retained earnings		(64)	Decreased due to dividends paid in excess of net income

DEVELOPMENTS

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. The Settlement Agreement will not become effective until approved by the FPSC. The FPSC is expected to consider the matter by October 2021. For further information on the Settlement Agreement, refer to the “Business Overview and Outlook – Florida Electric Utility” section.

Delivery of NS Block

Nalcor has agreed to commence delivery of the NS Block by August 15, 2021 which will be delivered over the next 35 years pursuant to the agreements. 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 requesting to set rates for 2022. A decision by the UARB is expected in early 2022. For further information on the NS Block, refer to the “Business Overview and Outlook – Canadian Electric Utilities” and “Contractual Obligations” sections.

Preferred Shares

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 August 10, 2021, Gil C. Quiniones joined the Emera Board of Directors. Mr. Quiniones is the President and Chief Executive Officer of the New York Power Authority, the largest state public power organization in the United States, operating 16 generating facilities and more than 2,200 kilometres of transmission lines.

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)		2.34	128
Issued for cash under Purchase Plans at market rate		2.29	121
Discount on shares purchased under Dividend Reinvestment Plan		-	(2)
Options exercised under senior management stock option plan		0.05	2
Employee Share Purchase Plan		-	3
Balance, June 30, 2021		256.11	$ 6,957

(1) In 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 Q2 2021, 1,396,926 common shares were issued under Emera’s ATM program at an average price of $56.95 per share for gross proceeds of $80 million ($78 million net of issuance costs). For the six months ended June 30, 2021, 2,337,026 common shares were issued under Emera’s ATM program at an average price of $55.59 per share for gross proceeds of $130 million ($128 million net of issuance costs). As at June 30, 2021, an aggregate gross sales limit of $115 million remained available for issuance under the ATM program. Emera’s ATM program automatically terminated on July 14, 2021. Refer to below for more information.

As at August 6, 2021 the amount of issued and outstanding common shares was 256.5 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 June 30, 2021 was 255.8 million (2020 – 246.7 million) and for the six months ended June 30, 2021 was 254.6 million (2020 – 245.7 million).

ATM Equity Program

Emera’s ATM Program automatically terminated on July 14, 2021 with the expiry of the Company’s short-form base shelf prospectus dated June 14, 2019. Emera intends to establish a new ATM Program during Q3 2021.

FINANCIAL HIGHLIGHTS

Florida Electric Utility

All amounts are reported in USD, unless otherwise stated.


	Three months ended				Six months ended
For the	June 30				June 30
millions of US dollars (except per share amounts)	2021		2020		2021		2020
Operating revenues – regulated electric	$	532	$	454	$	979	$ 875
Regulated fuel for generation and purchased power	$	156	$	93	$	284	$ 199
Contribution to consolidated net income	$	102	$	106	$	167	$ 165
Contribution to consolidated net income – CAD	$	125	$	146	$	208	$ 225
Contribution to consolidated earnings per common share – basic – CAD	$	0.49	$	0.59	$	0.82	$ 0.92
Net income weighted average foreign exchange rate – CAD/USD	$	1.22	$	1.38	$	1.24	$ 1.37
EBITDA	$	240	$	236	$	437	$ 420
EBITDA – CAD	$	293	$	326	$	544	$ 574

Net Income

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


For the	Three months ended		Six months ended
millions of US dollars	June 30		June 30
Contribution to consolidated net income – 2020	$	106	$ 165
Increased operating revenues - see Operating Revenues - Regulated Electric below		78	104
Increased fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below		(63)	(85)
Increased OM&G expenses due to higher clause-related expenses and employee benefit costs in Q2 2021 partially offset by timing of planned maintenance outages quarter-over-quarter and lower labour and employee benefit costs in Q1 2021		(12)	(2)
Increased depreciation and amortization due to increased property, plant and equipment and a 2020 regulatory settlement		(12)	(19)
Increased AFUDC earnings due to the Big Bend Power Station modernization and solar projects		3	7
Other		2	(3)
Contribution to consolidated net income – 2021	$	102	$ 167

Florida Electric Utility’s CAD contribution to consolidated net income decreased $21 million to $125 million in Q2 2021, compared to $146 million in Q2 2020. Year-to-date in 2021, the CAD contribution to consolidated net income decreased $17 million to $208 million compared to $225 million for the same period in 2020. Decreases in both periods were due to the impact of the strengthening CAD, higher depreciation and amortization expense reflecting increased capital investment and a 2020 regulatory settlement, and higher OM&G expense. These decreases were partially offset by higher AFUDC earnings.

The impact of the strengthening Canadian dollar decreased CAD earnings for the three and six months ended June 30, 2021 by $16 million and $21 million, respectively.

Operating Revenues – Regulated Electric

Electric revenues increased $78 million to $532 million in Q2 2021, compared to $454 million in Q2 2020. Year-to-date in 2021, electric revenues increased $104 million to $979 million, compared to $875 million for the same period in 2020. Increases in both periods were due to higher fuel recovery clause revenue as a result of higher fuel costs.

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


Q2 Electric Revenues
millions of US dollars
	2021		2020
Residential	$	276	$ 254
Commercial		144	121
Industrial		42	32
Other (1)		70	47
Total	$	532	$ 454
(1) Other includes sales to public authorities, off-system sales to other utilities, unbilled revenues and regulatory deferrals related to clauses.


YTD Electric Revenues
millions of US dollars
	2021		2020
Residential	$	508	$ 459
Commercial		270	246
Industrial		79	69
Other (1)		122	101
Total	$	979	$ 875
(1) Other includes sales to public authorities, off-system sales to other utilities, unbilled revenues and regulatory deferrals related to clauses.


Q2 Electric Sales Volumes (1)
Gigawatt hours (“GWh”)
	2021		2020
Residential		2,472	2,518
Commercial		1,525	1,431
Industrial		541	452
Other		494	450
Total		5,032	4,851
(1) Electric sales volumes are calculated based on billed hours only. GWh related to unbilled revenues are excluded.


YTD Electric Sales Volumes (1)
GWh
	2021	2020
Residential	4,525	4,398
Commercial	2,850	2,804
Industrial	1,015	949
Other	939	916
Total	9,329	9,067
(1) Electric sales volumes are calculated based on billed hours only. GWh related to unbilled revenues are excluded.

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $63 million to $156 million in Q2 2021, compared to $93 million in Q2 2020 and year-to-date, increased $85 million to $284 million in 2021, compared to $199 million in the same period in 2020. The increase in both periods was primarily due to increased natural gas prices.


Q2 Production Volumes
GWh
	2021		2020
Natural gas		4,075	4,150
Purchased power		695	820
Coal		351	78
Solar		395	350
Total		5,516	5,398


YTD Production Volumes
GWh
	2021	2020
Natural gas	7,482	8,255
Purchased power	1,035	856
Coal	757	259
Solar	681	584
Total	9,955	9,954

Average fuel cost per MWh increased in Q2 2021 and year-to-date compared to the same periods in 2020, primarily due to increased natural gas prices.

Canadian Electric Utilities


	Three months ended				Six months ended
For the	June 30				June 30
millions of Canadian dollars (except per share amounts)	2021		2020		2021		2020
Operating revenues – regulated electric	$	341	$	335	$	784	$ 793
Regulated fuel for generation and purchased power (1)	$	173	$	146	$	385	$ 340
Income from equity investments	$	27	$	24	$	53	$ 51
Contribution to consolidated net income	$	44	$	37	$	132	$ 129
Contribution to consolidated earnings per common share – basic	$	0.17	$	0.15	$	0.52	$ 0.53
EBITDA	$	141	$	134	$	331	$ 327

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

Canadian Electric Utilities’ contribution is summarized in the following table:


	Three months ended				Six months ended
For the	June 30				June 30
millions of Canadian dollars	2021		2020		2021		2020
NSPI	$	18	$	13	$	80	$ 78
Equity investment in NSPML		14		12		27	27
Equity investment in LIL		12		12		25	24
Contribution to consolidated net income	$	44	$	37	$	132	$ 129

Net Income

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


For the	Three months ended			Six months ended
millions of Canadian dollars	June 30			June 30
Contribution to consolidated net income – 2020	$	37		$ 129
Increased (decreased) operating revenues - see Operating Revenues – Regulated Electric below		6		(9)
Increased fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below		(27	)	(45)
Decreased FAM 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		26		55
Increased depreciation and amortization due to increased property, plant and equipment		(4	)	(7)
Increased income from equity investments		3		2
Increased other income primarily due to lower amortization of defeasance costs and favourable changes in foreign exchange		2		3
Other		1		4
Contribution to consolidated net income – 2021	$	44		$ 132

Canadian Electric Utilities’ contribution to consolidated net income increased $7 million to $44 million in Q2 2021, compared to $37 million in Q2 2020 and year-to-date increased $3 million to $132 million compared to $129 million in 2020. Increases in both periods were primarily driven by higher contribution from NSPI. This was a result of lower FAM and fixed cost deferrals. These increases were partially offset by lower Maritime Link assessment included in revenue compared to 2020 and higher depreciation and amortization due to increased property plant and equipment.

NSPI

Operating Revenues – Regulated Electric

Operating revenues increased $6 million to $341 million in Q2 2021, compared to $335 million in Q2 2020 due to increased customer driven sales volumes and fuel-related pricing, partially offset by weather driven impacts on sales volumes and lower Maritime Link assessment included in revenue compared to 2020.

Year-to-date in 2021, operating revenues decreased $9 million to $784 million compared to $793 million for the same period in 2020 due to lower Maritime Link assessment included in revenue and weather driven impacts on sales volumes, partially offset by increased customer driven sales volumes and fuel-relating pricing.

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


Q2 Electric Revenues
millions of Canadian dollars
	2021		2020
Residential	$	175	$ 182
Commercial		92	90
Industrial		59	51
Other		7	6
Total	$	333	$ 329


YTD Electric Revenues
millions of Canadian dollars
	2021		2020
Residential	$	434	$ 446
Commercial		206	210
Industrial		115	107
Other		14	17
Total	$	769	$ 780


Q2 Electric Sales Volumes
GWh
	2021		2020
Residential		1,010	1,035
Commercial		650	621
Industrial		626	510
Other		35	36
Total		2,321	2,202


YTD Electric Sales Volumes
GWh
	2021		2020
Residential		2,559	2,595
Commercial		1,472	1,481
Industrial		1,198	1,098
Other		78	112
Total		5,307	5,286

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $27 million to $173 million in Q2 2021, compared to $146 million in Q2 2020, and year-to-date increased $45 million to $385 million, compared to $340 million in the same period in 2020. Increases in both periods were due to changes in generation mix and higher Maritime Link assessment costs. Year-over-year, higher commodity prices also contributed to the increase.


Q2 Production Volumes
GWh
	2021		2020
Coal		767	549
Natural gas		498	552
Purchased power – other		352	195
Petcoke		-	262
Oil		6	2
Total non-renewables		1,623	1,560
Purchased power – Independent Power Producers (“IPP”)		314	309
Wind and hydro		335	319
Purchased power – Community Feed-in Tariff program (“COMFIT”)		139	146
Biomass		32	30
Total renewables		820	804
Total production volumes		2,443	2,364
Q2 Average Fuel Costs
		2021	2020
Dollars per MWh	$	71	$ 62


YTD Production Volumes
GWh
	2021		2020
Coal		2,421	2,144
Natural gas		811	1,026
Purchased power – other		491	314
Petcoke		206	534
Oil		57	12
Total non-renewables		3,986	4,030
Purchased power – IPP		675	644
Wind and hydro		640	660
Purchased power – COMFIT		290	293
Biomass		69	41
Total renewables		1,674	1,638
Total production volumes		5,660	5,668
YTD Average Fuel Costs
		2021	2020
Dollars per MWh	$	68	$ 60

Average fuel cost per MWh increased in Q2 2021 and year-to-date, compared to the same periods in 2020. This was primarily due to changes in generation mix driven by emissions constraints, with increased generation from lower carbon intensity sources such as IPP, import, and biomass generation offsetting decreased generation from solid fuel, and natural gas. Higher Maritime Link assessment costs also contributed to a higher average fuel cost. Increased commodity prices contributed to a higher average fuel cost year-over-year.

NSPI’s FAM regulatory balance increased $45 million from a regulatory liability of $21 million at December 31, 2020 to a regulatory asset of $24 million at June 30, 2021 primarily due to under-recovery of current period fuel costs.

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				Six months ended
For the	June 30				June 30
millions of US dollars (except per share amounts)	2021		2020		2021		2020
Operating revenues – regulated electric	$	87	$	69	$	161	$ 196
Regulated fuel for generation and purchased power (1)	$	44	$	27	$	77	$ 77
Adjusted contribution to consolidated net income (loss)	$	-	$	(1)	$	6	$ 14
Adjusted contribution to consolidated net income (loss) – CAD	$	-	$	(1)	$	7	$ 19
After-tax equity securities MTM income (loss)	$	(1)	$	2	$	(1)	$ -
Contribution to consolidated net income (loss)	$	(1)	$	1	$	5	$ 14
Contribution to consolidated net income (loss) – CAD	$	(1)	$	2	$	6	$ 19
Adjusted contribution to consolidated earnings per common share – basic – CAD	$	-	$	-	$	0.03	$ 0.08
Contribution to consolidated earnings per common share – basic – CAD	$	-	$	0.01	$	0.02	$ 0.08
Net income weighted average foreign exchange rate – CAD/USD	$	1.31	$	1.39	$	1.25	$ 1.37
Adjusted EBITDA	$	17	$	16	$	39	$ 56
Adjusted EBITDA – CAD	$	21	$	22	$	49	$ 76
(1) Regulated fuel for generation and purchased power includes transmission pool expense in 2020 related to Emera Maine Other Electric Utilities’ adjusted contribution is summarized in the following table:
	Three months ended				Six months ended
For the	June 30				June 30
millions of US dollars	2021		2020		2021		2020
BLPC	$	-	$	2	$	2	$ 13
GBPC		-		-		5	1
Emera Maine		-		-		-	4
Other		-		(3)		(1)	(4)
Adjusted contribution to consolidated net income (loss)	$	-	$	(1)	$	6	$ 14

Excluding the change in MTM, Other Electric Utilities CAD contribution to consolidated net income in Q2 2021 was consistent with Q2 2020. Year-to-date, the CAD contribution decreased $12 million to $7 million, compared to $19 million, for the same period in 2020. The sale of Emera Maine decreased earnings by $6 million. BLPC’s contribution decreased due to the recognition of a $10 million previously deferred corporate income tax recovery in Q1 2020 related to the enactment of a lower corporate income tax rate in December 2018. These decreases were partially offset by recognition of insurance proceeds and higher other income at GBPC, and lower interest costs.

The foreign exchange rate had minimal impact for the three months ended June 30. Year-to-date, the strengthening of the CAD decreased earnings and adjusted earnings by $1 million.

Operating Revenues – Regulated Electric

Operating revenues increased $18 million to $87 million in Q2 2021, compared to $69 million in Q2 2020 due to increased fuel revenue at BLPC due to higher oil prices. Year-to-date in 2021, revenues decreased $35 million to $161 million compared to $196 million in the same period in 2020. The decrease year-over-year was a result of the sale of Emera Maine, partially offset by higher fuel revenue at BLPC due to higher oil prices.

Electric sales volumes were 306 GWh in Q2 2021 compared to 290 GWh in Q2 2020. Year-to-date, electric sales volumes were 595 GWh compared to 601 GWh for the same period in 2020.

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $17 million to $44 million in Q2 2021, compared to $27 million in Q2 2020 due to higher oil prices at BLPC. Year-to-date in 2021, regulated fuel for generation and purchased power was $77 million, consistent with the same period in 2020, due to higher oil prices at BLPC offset by transmission pool expense at Emera Maine in 2020.

Gas Utilities and Infrastructure

All amounts are reported in USD, unless otherwise stated.


	Three months ended				Six months ended
For the	June 30				June 30
millions of US dollars (except per share amounts)	2021		2020		2021		2020
Operating revenues – regulated gas (1)	$	198	$	150	$	510	$ 400
Operating revenues – non-regulated		4		3		7	6
Total operating revenue	$	202	$	153	$	517	$ 406
Regulated cost of natural gas	$	55	$	30	$	179	$ 111
Income from equity investments	$	4	$	4	$	8	$ 7
Contribution to consolidated net income	$	28	$	18	$	91	$ 71
Contribution to consolidated net income – CAD	$	34	$	27	$	114	$ 97
Contribution to consolidated earnings per common share – basic – CAD	$	0.13	$	0.11	$	0.45	$ 0.39
Net income weighted average foreign exchange rate – CAD/USD	$	1.23	$	1.39	$	1.26	$ 1.35
EBITDA	$	74	$	58	$	192	$ 161
EBITDA – CAD	$	91	$	82	$	241	$ 219

(1) Operating revenues – regulated gas includes $12 million of finance income from Brunswick Pipeline (2020 - $11 million) for the three months ended June 30, 2021 and $23 million (2020 - $22 million) for the six months ended June 30, 2021; however, it is excluded from the gas revenues analysis below.

Gas Utilities and Infrastructure’s contribution is summarized in the following table:


	Three months ended				Six months ended
For the	June 30				June 30
millions of US dollars	2021		2020		2021		2020
PGS	$	19	$	11	$	46	$ 29
NMGC		(2)		-		22	23
Other		11		7		23	19
Contribution to consolidated net income	$	28	$	18	$	91	$ 71

Net Income

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


For the	Three months ended		Six months ended
millions of US dollars	June 30		June 30
Contribution to consolidated net income – 2020	$	18	$ 71
Increased gas operating revenues - see Operating Revenues - Regulated Gas below		48	110
Increased cost of natural gas sold - See Regulated Cost of Natural Gas below		(25)	(68)
Increased depreciation and amortization expense due to increased property, plant and equipment		(4)	(7)
Increased OM&G expense due to higher labour costs at PGS and NMGC		(6)	(8)
Other		(3)	(7)
Contribution to consolidated net income – 2021	$	28	$ 91

Gas Utilities and Infrastructure’s CAD contribution to consolidated net income increased $7 million to $34 million in Q2 2021, compared to $27 million in Q2 2020 and year-to-date increased $17 million to $114 million, compared to $97 million in 2020. The increase in both periods was due to PGS’s higher base revenues as the result of a base rate increase and customer growth.

The impact of the change in the foreign exchange rate decreased CAD earnings for the three months ended June 30, 2021 and year-to-date 2021 by $4 million and $8 million respectively.

Operating Revenues – Regulated Gas

Gas Utilities and Infrastructure’s operating revenues increased $48 million to $198 million in Q2 2021, compared to $150 million in Q2 2020 and year-to-date increased $110 million to $510 million, compared to $400 million in the same period in 2020. The increase in both periods was 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:


Q2 Gas Revenues
millions of US dollars
	2021		2020
Residential	$	90	$ 67
Commercial		63	37
Industrial (1)		13	10
Other (2)		20	25
Total (3)	$	186	$ 139
(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).


YTD Gas Revenues
millions of US dollars
	2021		2020
Residential	$	262	$ 193
Commercial		153	104
Industrial (1)		25	20
Other (2)		47	61
Total (3)	$	487	$ 378
(1) Industrial includes sales to power generation customers.
(2) Other includes off-system sales to other utilities and various other items.
(3) Excludes $23 million of finance income from Brunswick Pipeline (2020 – $22 million).


Q2 Gas Volumes
Therms (millions)
	2021		2020
Residential		59	63
Commercial		181	146
Industrial		356	394
Other		40	74
Total		636	677


YTD Gas Volumes
Therms (millions)
	2021		2020
Residential		247	235
Commercial		423	397
Industrial		723	781
Other		87	171
Total		1,480	1,584

Regulated Cost of Natural Gas

Regulated cost of natural gas increased $25 million to $55 million in Q2 2021, compared to $30 million in Q2 2020 and year-to-date increased $68 million to $179 million in Q2 2021, compared to $111 million in the same period in 2020. The increase in both periods was due to higher gas prices at PGS and NMGC.

Gas sales by type are summarized in the following table:


Q2 Gas Volumes by Type
Therms (millions)
	2021		2020
System supply		100	126
Transportation		536	551
Total		636	677


YTD Gas Volumes by Type
Therms (millions)
	2021		2020
System supply		366	401
Transportation		1,114	1,183
Total		1,480	1,584

Other


	Three months ended				Six months ended
For the	June 30				June 30
millions of Canadian dollars (except per share amounts)	2021		2020		2021		2020
Marketing and trading margin (1) (2)	$	-	$	(13)	$	67	$	28
Other non-regulated operating revenue		9		6		17		15
Total operating revenues – non-regulated	$	9	$	(7)	$	84	$	43
Income from equity investments	$	4	$	8	$	11	$	17
Adjusted contribution to consolidated net income (loss)	$	(66)	$	(91)	$	(81)	$	(159)
Gain on sale, net of tax and transaction costs		-		(12)		-		309
Impairment charges, net of tax		-		(3)		-		(26)
After-tax derivative MTM loss		(153)		(48)		(123)		(13)
Contribution to consolidated net income (loss)	$	(219)	$	(154)	$	(204)	$	111
Adjusted contribution to consolidated earnings per common share – basic	$	(0.26)	$	(0.37)	$	(0.32)	$	(0.65)
Contribution to consolidated earnings per common share – basic	$	(0.86)	$	(0.62)	$	(0.80)	$	0.45
Adjusted EBITDA	$	(11)	$	(20)	$	54	$	(3)

(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 loss of $205 million in Q2 2021 (2020 - $87 million loss) and a loss of $167 million year-to-date (2020 – $24 million loss).

Other’s adjusted contribution is summarized in the following table:


	Three months ended				Six months ended
For the	June 30				June 30
millions of Canadian dollars	2021		2020		2021		2020
Emera Energy	$	(1)	$	(7)	$	42	$ 14
Corporate – see breakdown of adjusted contribution below		(61)		(82)		(115)	(169)
Emera Technologies		(3)		(2)		(6)	(4)
Other		(1)		-		(2)	-
Adjusted contribution to consolidated net income (loss)	$	(66)	$	(91)	$	(81)	$ (159)

Net Income

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


For the	Three months ended		Six months ended
millions of Canadian dollars	June 30		June 30
Contribution to consolidated net income (loss) – 2020	$	(154)	$ 111
Increased marketing and trading margin - see Emera Energy		13	39
Increased OM&G quarter-over-quarter primarily due to increased long-term compensation. Decreased OM&G year-over-year primarily due to lower long-term compensation		(2)	14
Realized foreign exchange gain on cash flow hedges to hedge foreign exchange earnings exposure		8	13
Decreased interest expense due to the impact of a stronger CAD, the repayment of debt and lower interest rates		9	22
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
Decreased income tax recovery primarily due to decreased losses before provision for income taxes		(7)	(28)
Decreased preferred stock dividends primarily due to timing		12	12
2020 gain on sale and impairment charges, net of tax		15	(283)
Increased MTM loss, net of tax, in both periods primarily due to changes in existing positions and increased foreign exchange losses on cash flow hedges, partially offset by lower amortization of gas transportation assets in 2021		(105)	(108)
Other		(8)	(7)
Contribution to consolidated net income (loss) – 2021	$	(219)	$ (204)

Emera Energy

Marketing and trading margin increased $13 million to nil in Q2 2021, compared to a loss of $13 million in Q2 2020 due to the favourable impact of weather in several key market areas, which resulted in higher market prices and volatility that led to higher natural gas margins.

Year-to-date, margin increased $39 million to $67 million in 2021, compared to $28 million for the same period in 2020. In addition to the Q2 2021 differential noted above, 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, such that the business was able to capitalize. The Northeast, though seasonally cold, was largely insulated from the weather event, but still provided steady opportunity throughout Q1.

Corporate

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


	Three months ended				Six months ended
For the	June 30				June 30
millions of Canadian dollars	2021		2020		2021		2020
Operating expenses (1)	$	17	$	15	$	17	$ 31
Interest expense		66		75		134	156
Income tax expense (recovery)		(21)		(26)		(39)	(59)
Preferred dividends		11		23		22	34
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)		(12)		(5)		(19)	(2)
Corporate adjusted net loss	$	(61)	$	(82)	$	(115)	$ (169)

(1) Operating expenses include OM&G and depreciation.

(2) Other includes realized foreign exchange gains on cash flow hedges to hedge foreign exchange earnings exposure, Q2 2021 includes a $5 million gain (2020- $3 million loss) and year-to-date gain of $9 million (2020 - $4 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 is uncertain and may vary among jurisdictions. For further information on the potential future impacts of COVID on Emera and its businesses, refer to the “Business Overview and Outlook” and “Liquidity and Capital Resources” sections in the Company’s 2020 annual MD&A.

On a consolidated basis, COVID-19 has not had a material financial impact to net earnings to date in 2021 and is not expected to have a material financial impact in 2021. For further discussion, refer to the “Business Overview and Outlook – COVID-19 Pandemic” section. To date, there have been no significant customer defaults and as of June 30, 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 $7.4 billion capital investment plan over the 2021-to-2023 period and the potential for additional capital opportunities of $1.2 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 at-the-market program.

Emera has credit facilities with varying maturities that cumulatively provide $3.4 billion of credit, with approximately $1.8 billion undrawn and available at June 30, 2021. The Company was holding a cash balance of $207 million at June 30, 2021. For further discussion, refer to the “Debt Management” section below. Refer to notes 19 and 20 in the condensed consolidated interim financial statements for additional information regarding the credit facilities.

Consolidated Cash Flow Highlights

Significant changes in the Condensed Consolidated Statements of Cash Flows between the six months ended June 30, 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 change in working capital		684		816	(132)
Change in working capital		(53)		(75)	22
Operating activities	$	631	$	741	$ (110)
Investing activities		(993)		78	(1,071)
Financing activities		320		(712)	1,032
Effect of exchange rate changes on cash, cash equivalents, and restricted cash		(5)		(43)	38
Cash, cash equivalents, and restricted cash, end of period	$	207	$	338	$ (131)

Cash Flow from Operating Activities

Net cash provided by operating activities decreased $110 million to $631 million for the six months ended June 30, 2021, compared to $741 million for the same period in 2020.

Cash from operations before changes in working capital decreased $132 million. 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 at Tampa Electric and the sale of Emera Maine in Q1 2020. This was partially offset by increased marketing and trading margin at Emera Energy.

Changes in working capital increased operating cash flows by $22 million due to favourable changes in cash collateral positions on derivative instruments at NSPI. This was partially offset by the receipt of a 2019 income tax refund at NSPI in 2020, timing of accounts payable payments at NMGC, unfavourable changes in cash collateral positions at Emera Energy and unfavourable changes in accounts receivable at NMGC.

Cash Flow from Investing Activities

Net cash used in investing activities increased $1,071 million to $993 million for the six months ended June 30, 2021, compared to cash provided by investing activities of $78 million for the same period 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 six months ended June 30, 2021, including AFUDC, were $1,026 million compared to $1,343 million for the same period in 2020. Details of the 2021 capital spend by segment are shown below:

●

$560 million - Florida Electric Utility (2020 – $711 million);

●

$156 million - Canadian Electric Utilities (2020 – $176 million);

●

$51 million - Other Electric Utilities (2020 – $93 million);

●

$257 million - Gas Utilities and Infrastructure (2020 – $361 million); and

●

$2 million - Other (2020 – $2 million).

Cash Flow from Financing Activities

Net cash provided by financing activities increased $1,032 million to $320 million for the six months ended June 30, 2021, compared to cash used in financing activities of $712 million for the same period in 2020. The increase was due to net proceeds from the issuance of long-term debt at Tampa Electric, NMGC and PGS 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.

Contractual Obligations

As at June 30, 2021, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:


millions of Canadian dollars	2021		2022		2023		2024		2025		Thereafter		Total
Long-term debt principal	$	131	$	512	$	801	$	625	$	226	$	11,881	$ 14,176
Interest payment obligations (1)		301		592		570		555		536		6,949	9,503
Transportation (2)		301		427		352		309		276		2,656	4,321
Purchased power (3)		148		219		218		236		233		2,139	3,193
Fuel, gas supply and storage		362		187		45		42		37		22	695
Capital projects		430		121		91		-		-		-	642
Asset retirement obligations		9		2		7		2		2		389	411
Long-term service agreements (4)		57		65		70		50		35		116	393
Pension and post-retirement obligations (5)		15		37		31		32		31		185	331
Equity investment commitments (6)		-		240		-		-		-		-	240
Leases and other (7)		10		16		16		15		8		118	183
Demand side management		19		45		-		-		-		-	64
Long-term payable		2		5		5		-		-		-	12
	$	1,785	$	2,468	$	2,206	$	1,866	$	1,384	$	24,455	$ 34,164

(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 June 30, 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 $141 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.

The UARB approved assessment for 2021 is approximately $172 million. This is subject to a holdback of up to $10 million, that is dependent upon the timing of commencement of the NS Block and NSPML has deferred collection of $23 million in depreciation expense. Nalcor has agreed to commence delivery of the NS Block by August 15, 2021 and the NS Block will be delivered over the next 35 years pursuant to the agreements with Nalcor. 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 requesting to set rates for 2022.

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 2020-2022 fuel stability plan, rates have been set to include $164 million and $162 million for 2021 and 2022, respectively. 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. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are dependent on regulatory filings with the UARB.

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. This energy could be transmitted from Nova Scotia to New England energy markets beginning at first commercial power of the Muskrat Falls hydroelectric generating facility and related transmission assets when Nalcor commences delivery of the NS Block by August 15, 2021, and continuing for 50 years. As transmission rights are contracted, the obligations are included within “Leases and other” in the above table.

Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to approximately $3.4 billion committed syndicated bank lines of credit in either CAD or USD, per the table below.


							Undrawn
			Credit				and
millions of dollars	Maturity		Facilities		Utilized		Available
Emera – Unsecured committed revolving credit facility		June 2024	$	900	$	174	$ 726
TEC (in USD) – Unsecured committed revolving credit facility (1)		March 2023		800		411	389
NSPI – Unsecured committed revolving credit facility		October 2024		600		231	369
Emera – Unsecured non-revolving facility		December 2021		400		400	-
TECO Finance (in USD) – Unsecured committed revolving credit facility		March 2023		400		232	168
NMGC (in USD) – Unsecured committed revolving credit facility		March 2023		125		9	116
NMGC (in USD) - Unsecured non-revolving facility		September 2022		100		100	-
Other (in USD) – Unsecured committed revolving credit facilities		Various		35		23	12

(1) This facility is available for use by Tampa Electric and PGS. At June 30, 2021, $312 million USD was used by Tampa Electric and $99 million USD was used by PGS.

Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly and the Company is in compliance with covenant requirements as at June 30, 2021.

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

Florida Electric Utility

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.

Gas Utilities and Infrastructure

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 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.

As a result of 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 issuance

Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2020 annual MD&A, with updates as noted below:

The Company has standby letters of credit and surety bonds in the amount of $49 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.

NSPI has issued guarantees in the amount of $28 million USD (December 31, 2020 - $18 million USD) on behalf of its subsidiary, NS Power Energy Marketing Incorporated, to secure obligations under purchase agreements with third-party suppliers. The guarantees have terms of varying lengths and will be renewed as required.

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 Condensed Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $36 million for the three months ended June 30, 2021 (2020 - $27 million) and $64 million for the six months ended June 30, 2021 (2020 - $55 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 Condensed Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $3 million for the three months ended June 30, 2021 (2020 - $3 million) and $10 million for the six months ended June 30, 2021 (2020 - $11 million).

There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at June 30, 2021 and at December 31, 2020.

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

There have been no material changes in Emera’s risk management profile and practices from those disclosed in the Company’s 2020 annual MD&A.

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	June 30		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:


	Three months ended				Six months ended
For the	June 30				June 30
millions of Canadian dollars	2021		2020		2021		2020
Operating revenues – regulated	$	-	$	(1)	$	-	$ (2)
Effective net losses	$	-	$	(1)	$	-	$ (2)

The effective net losses reflected in the above table would be 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	June 30		December 31
millions of Canadian dollars	2021		2020
Derivative instrument assets (current and other assets)	$	92	$ 14
Regulatory assets (current and other assets)		40	65
Derivative instrument liabilities (current and long-term liabilities)		(40)	(62)
Regulatory liabilities (current and long-term liabilities)		(95)	(15)
Net (liability) asset	$	(3)	$ 2

Regulatory Impact Recognized in Net Income

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


	Three months ended				Six months ended
For the	June 30				June 30
millions of Canadian dollars	2021		2020		2021		2020
Regulated fuel for generation and purchased power (1)	$	(7)	$	(5)	$	(4)	$ (10)
Net losses	$	(7)	$	(5)	$	(4)	$ (10)

(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	June 30		December 31
millions of Canadian dollars	2021		2020
Derivative instrument assets (current and other assets)	$	49	$ 68
Derivative instrument liabilities (current and long-term liabilities)		(389)	(275)
Net derivative instrument liability	$	(340)	$ (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:


	Three months ended				Six months ended
For the	June 30				June 30
millions of Canadian dollars	2021		2020		2021		2020
Operating revenue - non-regulated	$	(120)	$	10	$	9	$ 222
Non-regulated fuel for purchased power		-		-		1	(4)
Net gains (losses)	$	(120)	$	10	$	10	$ 218

Other Derivatives Recognized on the Balance Sheets

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


As at	June 30		December 31
millions of Canadian dollars	2021		2020
Derivative instrument assets (current and other assets)	$	14	$ 15
Derivative instrument liabilities (current and long-term liabilities)		-	(1)
Net derivative instrument assets	$	14	$ 14

Other Derivatives Recognized in Net Income

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


	Three months ended				Six months ended
For the	June 30				June 30
millions of Canadian dollars	2021		2020		2021		2020
OM&G	$	1	$	(6)	$	6	$ (7)
Other income, net		2		10		3	-
Total gains (losses)	$	3	$	4	$	9	$ (7)

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. 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 of the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer, evaluated the design of the Company’s DC&P and ICFR as at June 30, 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 quarter ended June 30, 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, allowance for credit losses, 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 three and six months ended June 30, 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.

Goodwill Impairment Assessments

Management considered whether the potential impacts of the COVID-19 pandemic on future earnings required testing for goodwill impairment in Q2 2021 and determined that it is more likely than not that the fair value of reporting units that include goodwill exceeded their respective carrying amounts as of June 30, 2021.

As of June 30, 2021, $5.5 billion of Emera’s goodwill was related to TECO Energy (Tampa Electric, PGS and NMGC reporting units). Given the significant excess of fair value over carrying amounts calculated for these reporting units as of the last quantitative test performed in Q4 2019, and the results of the qualitative assessment performed in Q4 2020, management does not expect the COVID-19 pandemic to have an impact on the goodwill associated with these reporting units.

As of June 30, 2021, $66.5 million of Emera’s goodwill was related to GBPC. In Q4 2020, the Company performed a quantitative impairment assessment for GBPC as this reporting unit is more sensitive to changes in forecasted future earnings due to limited excess of fair value over the carrying value. As part of the assessment management considered potential impacts of the COVID-19 pandemic on the future earnings of the reporting unit. Adverse changes in significant assumptions could result in a future impairment. No adverse changes in significant assumptions were identified in Q2 2021 and no impairment has been recorded for the three and six months ended June 30, 2021 associated with this goodwill.

Long-Lived Assets Impairment Assessments

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 June 30, 2021, there are no indications of impairment of Emera’s long-lived assets. There is currently no indication that future cash flows would be impacted to a point where the Company’s long-lived assets would not be recoverable.

No impairment charges were recognized for the three and six months ended June 30, 2021. Impairment charges of $3 million ($3 million after tax) and $25 million ($26 million after tax) were recognized on certain assets for the three and six months ended June 30, 2020, respectively.

Receivables and Allowance for Credit Losses

Management estimates credit losses related to accounts receivable after considering historical loss experience, customer deposits, current events, the characteristics of existing accounts and reasonable and supportable forecasts that affect the collectability of the reported amount. The economic impact of COVID-19, in the service territories where Emera operates, has impacted the aging of customer receivables resulting in higher allowances for credit losses related to customer receivables, however it has not had a material impact on earnings.

Pension and Other Post-Retirement Employee Benefits

The COVID-19 pandemic could impact key actuarial assumptions used to account for employee post-retirement benefits as a result of changes in the market. These changes could impact assumptions including the anticipated rates of return on plan assets and discount rates used in determining the accrued benefit obligation, benefit costs and annual pension funding requirements. Fluctuations in actual equity market returns and changes in interest rates as a result of the COVID-19 pandemic may also result in changes to pension costs and funding in future periods.

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.

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, but are not yet effective, are consistent with those disclosed in the Company’s 2020 audited consolidated financial statements, with updates noted below.

Guaranteed Debt Securities Disclosure Requirements

In October 2020, the FASB issued ASU 2020-09, Debt (Topic 470): Amendments to SEC Paragraphs pursuant to SEC Release No. 33-10762. The change in 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. The guidance will be effective for annual reports filed for fiscal years ending after January 4, 2021, with early adoption permitted. The Company is currently evaluating the impact of adoption of the standard on its consolidated financial statements.

SUMMARY OF QUARTERLY RESULTS


For the quarter ended millions of Canadian dollars	Q2		Q1		Q4		Q3		Q2		Q1		Q4		Q3
(except per share amounts)	2021		2021		2020		2020		2020		2020		2019		2019
Operating revenues	$	1,137	$	1,612	$	1,537	$	1,163	$	1,169	$	1,637	$	1,616	$ 1,299
Net income (loss) attributable to common shareholders		(17)		273		273		84		58		523		193	55
Adjusted net income attributable to common shareholders		137		243		188		166		118		193		145	122
Earnings (loss) per common share – basic		(0.07)		1.08		1.09		0.34		0.24		2.14		0.79	0.23
Earnings (loss) per common share – diluted		(0.07)		1.08		1.08		0.34		0.23		2.13		0.80	0.23
Adjusted earnings per common share – basic		0.54		0.96		0.75		0.67		0.48		0.79		0.60	0.51

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.