EX-99.2

EX-99.2 3 d31622dex992.htm EX-99.2 EX-99.2

Exhibit 99.2

EMERA INCORPORATED

Unaudited Condensed Consolidated

Interim Financial Statements

June 30, 2020 and 2019

Emera Incorporated

Condensed Consolidated Statements of Income (Unaudited)


For the millions of Canadian dollars (except per share amounts)	Three months ended June 30				Six months ended June 30
	2020		2019		2020		2019

Operating revenues
Regulated electric	$	1,057	$	1,209	$	2,251	$	2,378
Regulated gas		207		234		538		586
Non-regulated		(95)		(65)		17		232
Total operating revenues (note 6)		1,169		1,378		2,806		3,196

Operating expenses
Regulated fuel for generation and purchased power		312		418		722		819
Regulated cost of natural gas		40		61		149		197
Non-regulated fuel for generation and purchased power		-		3		4		67
Operating, maintenance and general		334		343		712		709
Provincial, state and municipal taxes		78		85		162		170
Depreciation and amortization		216		228		447		452
Total operating expenses		980		1,138		2,196		2,414

Income from operations		189		240		610		782

Income from equity investments (note 7)		40		40		81		80

Other income (expenses), net (note 8)		24		6		587		19

Interest expense, net		173		185		357		374

Income before provision for income taxes		80		101		921		507

Income tax expense (recovery) (note 9)		(1)		(15)		305		67

Net income		81		116		616		440

Non-controlling interest in subsidiaries		-		1		1		2

Preferred stock dividends		23		12		34		23

Net income attributable to common shareholders	$	58	$	103	$	581	$	415
Weighted average shares of common stock outstanding (in millions) (note 11)
Basic		246.7		239.2		245.7		237.8
Diluted		248.0		239.8		247.0		238.4

Earnings per common share (note 11)
Basic	$	0.24	$	0.43	$	2.37	$	1.75
Diluted	$	0.23	$	0.43	$	2.35	$	1.74

Dividends per common share declared	$	1.2250	$	0.5875	$	1.8375	$	1.1750

The accompanying notes are an integral part of these condensed consolidated financial statements.

Emera Incorporated

Condensed Consolidated Statements of Comprehensive Income (Unaudited)


For the millions of Canadian dollars	Three months ended June 30				Six months ended June 30
	2020		2019		2020		2019

Net income	$	81	$	116	$	616	$	440

Other comprehensive income (loss), net of tax

Foreign currency translation adjustment (1)		(365)		(175)		396		(338)

Unrealized gains (losses) on net investment hedges (2) (3)		66		33		(75)		67

Cash flow hedges
Net derivative gains (losses)		1		1		(2)		3
Less: reclassification adjustment for losses (gains) included in income		1		-		2		2
Net effects of cash flow hedges		2		1		-		5

Net change in unrecognized pension and post-retirement benefit obligation (4)		3		4		(2)		8

Other comprehensive income (loss) (5)		(294)		(137)		319		(258)

Comprehensive income (loss)		(213)		(21)		935		182

Comprehensive income (loss) attributable to non-controlling interest		-		-		2		1

Comprehensive income (loss) of Emera Incorporated	$	(213)	$	(21)	$	933	$	181

The accompanying notes are an integral part of these condensed consolidated financial statements.

(1) Net of tax recovery of $7 million (2019 - nil) for the three months ended June 30, 2020 and tax expense of $6 million (2019 – nil) for the six months ended June 30, 2020.

(2) The Company has designated $1.2 billion United States dollar denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in United States dollar denominated operations.

(3) Net of tax expense of nil (2019 - nil) for the three months ended June 30, 2020 and tax recovery of $1 million (2019 – nil) for the six months ended June 30, 2020.

(4) Net of tax expense of nil (2019 - nil) for the three months ended June 30, 2020 and tax expense of nil (2019 – $1 million tax expense) for the six months ended June 30, 2020.

(5) Net of tax recovery of $7 million (2019 - nil) for the three months ended June 30, 2020 and tax expense of $5 million (2019 – $1 million tax expense) for the six months ended June 30, 2020.

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)


As at millions of Canadian dollars	June 30 2020		December 31 2019

Assets

Current assets
Cash and cash equivalents	$	285	$	222
Restricted cash (note 24)		53		51
Inventory		474		467
Derivative instruments (notes 13 and 14)		48		54
Regulatory assets (note 15)		133		121
Receivables and other current assets (note 17)		1,325		1,486
Assets held for sale (note 4)		-		85
		2,318		2,486

Property, plant and equipment, net of accumulated depreciation and amortization of $8,807 and $8,295, respectively		19,663		18,167

Other assets
Deferred income taxes		188		186
Derivative instruments (notes 13 and 14)		32		33
Regulatory assets (note 15)		1,426		1,431
Net investment in direct financing lease		469		473
Investments subject to significant influence (note 7)		1,342		1,312
Goodwill		6,122		5,835
Other long-term assets		319		300
Assets held for sale (note 4)		-		1,619
		9,898		11,189

Total assets	$	31,879	$	31,842

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited) – Continued


As at millions of Canadian dollars	June 30 2020		December 31 2019

Liabilities and Equity

Current liabilities
Short-term debt (note 19)	$	1,394	$	1,537
Current portion of long-term debt (note 20)		716		501
Accounts payable		996		1,118
Derivative instruments (notes 13 and 14)		184		268
Regulatory liabilities (note 15)		265		295
Other current liabilities		499		333
Liabilities associated with assets held for sale (note 4)		-		114

		4,054		4,166

Long-term liabilities
Long-term debt (note 20)		13,588		13,679
Deferred income taxes		1,585		1,285
Derivative instruments (notes 13 and 14)		87		102
Regulatory liabilities (note 15)		2,006		1,886
Pension and post-retirement liabilities (note 18)		458		460
Other long-term liabilities		837		764
Long-term liabilities associated with assets held for sale (note 4)		-		899
		18,561		19,075

Equity
Common stock (note 10)		6,435		6,216
Cumulative preferred stock (note 22)		1,004		1,004
Contributed surplus		78		78
Accumulated other comprehensive income (note 12)		413		95
Retained earnings		1,298		1,173
Total Emera Incorporated equity		9,228		8,566
Non-controlling interest in subsidiaries		36		35
Total equity		9,264		8,601

Total liabilities and equity	$	31,879	$	31,842

Commitments and contingencies (note 21)

The accompanying notes are an integral part of these condensed consolidated financial statements.

Approved on behalf of the Board of Directors


“M. Jacqueline Sheppard”		“Scott Balfour”

Chair of the Board		President and Chief Executive Officer

Emera Incorporated

Condensed Consolidated Statements of Cash Flows (Unaudited)


For the	Six months ended June 30
millions of Canadian dollars	2020		2019

Operating activities

Net income	$	616	$	440

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		457		457
Income from equity investments, net of dividends		(42)		(38)
Allowance for equity funds used during construction		(20)		(8)
Deferred income taxes, net		338		51
Net change in pension and post-retirement liabilities		(10)		(8)
Regulated fuel adjustment mechanism		(9)		(1)
Net change in fair value of derivative instruments		(108)		(148)
Net change in regulatory assets and liabilities		16		(5)
Net change in capitalized transportation capacity		134		40
Gain on sale (excluding transaction costs) and impairment charges		(578)		-
Other operating activities, net		22		(5)

Changes in non-cash working capital (note 23)		(75)		32

Net cash provided by operating activities		741		807

Investing activities

Proceeds from dispositions (note 4)		1,401		860

Additions to property, plant and equipment		(1,323)		(1,122)

Other investing activities		-		(2)

Net cash provided by (used in) investing activities		78		(264)

Financing activities
Change in short-term debt, net		79		162
Proceeds from short-term debt with maturities greater than 90 days		399		-
Repayment of short-term debt with maturities greater than 90 days		(688)		-
Proceeds from long-term debt, net of issuance costs		422		442
Retirement of long-term debt		(477)		(684)
Net repayments under committed credit facilities		(335)		(302)
Issuance of common stock, net of issuance costs		123		91
Dividends on common stock		(205)		(181)
Dividends on preferred stock		(23)		(23)
Other financing activities		(7)		(20)

Net cash used in financing activities		(712)		(515)

Effect of exchange rate changes on cash, cash equivalents, and restricted cash		(43)		(16)

Net increase in cash, cash equivalents, restricted cash and assets held for sale		64		12

Cash, cash equivalents, restricted cash and assets held for sale, beginning of period		274		372

Cash, cash equivalents, restricted cash and assets held for sale, end of period	$	338	$	384

Cash, cash equivalents, restricted cash and assets held for sale consists of:

Cash	$	281	$	325

Short-term investments		4		7

Restricted cash		53		51

Assets held for sale		-		1

Cash, cash equivalents, restricted cash, and assets held for sale	$	338	$	384

The accompanying notes are an integral part of these condensed consolidated financial statements.

Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)


millions of Canadian dollars	Common Stock		Preferred Stock		Contributed Surplus		Accumulated Other Comprehensive Income (Loss) (“AOCI”)		Retained Earnings		Non- Controlling Interest		Total Equity

For the three months ended June 30, 2020

Balance, March 31, 2020	$	6,340	$	1,004	$	78	$	707	$	1,540	$	36	$	9,705

Net income of Emera Incorporated		-		-		-		-		81		-		81

Other comprehensive income (loss), net of tax recovery of $7 million		-		-		-		(294)		-		-		(294)

Dividends declared on preferred stock (1)		-		-		-		-		(23)		-		(23)

Dividends declared on common stock ($1.2250/share)		-		-		-		-		(300)		-		(300)

Common stock issued under purchase plan		51		-		-		-		-		-		51

Issuance of common stock, net of after-tax issuance costs		41		-		-		-		-		-		41

Senior management stock options exercised		3		-		-		-		-		-		3

Balance, June 30, 2020	$	6,435	$	1,004	$	78	$	413	$	1,298	$	36	$	9,264



millions of Canadian dollars

For the six months ended June 30, 2020

Balance, December 31, 2019	$	6,216	$	1,004	$	78	$	95	$	1,173	$	35	$	8,601
Net income of Emera Incorporated		-		-		-		-		615		1		616

Other comprehensive income (loss), net of tax expense of $5 million		-		-		-		318		-		1		319

Dividends declared on preferred stock (2)		-		-		-		-		(34)		-		(34)

Dividends declared on common stock ($1.8375/share)		-		-		-		-		(449)		-		(449)

Common stock issued under purchase plan		99		-		-		-		-		-		99

Issuance of common stock, net of after-tax issuance costs		99		-		-		-		-		-		99

Senior management stock options exercised		20		-		(1)		-		-		-		19

Adoption of credit losses accounting standard (note 2)		-		-		-		-		(7)		-		(7)

Other		1		-		1		-		-		(1)		1

Balance, June 30, 2020	$	6,435	$	1,004	$	78	$	413	$	1,298	$	36	$	9,264

The accompanying notes are an integral part of these condensed consolidated financial statements.

(1) Series A; $0.31940/share, Series B; $0.35010/share, Series C; $0.59012/share, Series E; $0.56250/share, Series F; $0.525260/share and Series H; $0.61250/share

(2) Series A; $0.47910/share, Series B; $0.56910/share, Series C; $0.88518/share, Series E; $0.84375/share, Series F; $0.79089/share and Series H; $0.91875

Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)


millions of Canadian dollars	Common Stock		Preferred Stock		Contributed Surplus		Accumulated Other Comprehensive Income (Loss) (“AOCI”)		Retained Earnings		Non- Controlling Interest		Total Equity

For the three months ended June 30, 2019

Balance, March 31, 2019	$	5,899	$	1,004	$	82	$	217	$	1,249	$	40	$	8,491

Net income of Emera Incorporated		-		-		-		-		115		1		116

Other comprehensive income (loss), net of tax expense of nil		-		-		-		(136)		-		(1)		(137)

Dividends declared on preferred stock (1)		-		-		-		-		(12)		-		(12)

Dividends declared on common stock ($0.5875/share)		-		-		-		-		(140)		-		(140)

Issuance of preferred shares of GBPC, net of issuance costs												14		14

Redemption of preferred shares of GBPC												(19)		(19)

Common stock issued under purchase plan		50		-		-		-		-		-		50

Senior management stock options exercised		61		-		(3)		-		-		-		58

Balance, June 30, 2019	$	6,010	$	1,004	$	79	$	81	$	1,212	$	35	$	8,421


millions of Canadian dollars

For the six months ended June 30, 2019

Balance, December 31, 2018	$	5,816	$	1,004	$	84	$	338	$	1,075	$	41	$	8,358

Net income of Emera Incorporated		-		-		-		-		438		2		440

Other comprehensive income (loss), net of tax expense of $1 million		-		-		-		(257)		-		(1)		(258)

Dividends declared on preferred stock (2)		-		-		-		-		(23)		-		(23)

Dividends declared on common stock ($1.1750/share)		-		-		-		-		(278)		-		(278)

Issuance of preferred shares of GBPC, net of issuance costs												14		14

Redemption of preferred shares of GBPC												(19)		(19)

Common stock issued under purchase plan		101		-		-		-		-		-		101

Senior management stock option exercised		93		-		(5)		-		-		-		88

Other		-		-		-		-		-		(2)		(2)

Balance, June 30, 2019	$	6,010	$	1,004	$	79	$	81	$	1,212	$	35	$	8,421

The accompanying notes are an integral part of these condensed consolidated financial statements.

(1) Series A; $0.15970/share, Series B; $0.21150/share, Series C; $0.29506/share, Series E; $0.28125/share, Series F; $0.265625/share and Series H; $0.306250/share

(2) Series A; $0.31940/share, Series B; $0.43210/share, Series C; $0.59012/share, Series E; $0.56250/share, Series F; $0.53125/share and Series H; $0.61250/share

Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)

As at June 30, 2020 and 2019

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation, transmission and distribution, and gas transmission and distribution.

At June 30, 2020, Emera’s reportable segments include the following:

●

Florida Electric Utility, which consists of Tampa Electric, a vertically integrated regulated electric utility in West Central Florida.

●

Canadian Electric Utilities, which includes:

●

Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated electric utility and the primary electricity supplier in Nova Scotia; and

●

Emera Newfoundland & Labrador Holdings Inc. (“ENL”), consisting of two transmission investments related to an 824 megawatt (“MW”) hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador being developed by Nalcor Energy. ENL’s two investments are:

●

a 100 per cent investment in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $1.6 billion transmission project, including two 170-kilometre sub-sea cables, connecting the island of Newfoundland and Nova Scotia. This project went in service on January 15, 2018; and

●

a 49.2 per cent investment in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a $3.7 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Construction of the LIL has been completed and Nalcor recognized the first flow of energy from Labrador to Newfoundland in June 2018. Nalcor continues to work towards commissioning the LIL. In response to the COVID-19 pandemic, on March 17, 2020 Nalcor announced that it had paused construction activities at the Muskrat Falls site. Nalcor resumed work in May 2020 and is assessing the impact of the construction pause on its completion schedule. Refer to note 21 for further details.

●

Other Electric Utilities, which includes Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities that include:

●

The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated electric utility on the island of Barbados;

●

Grand Bahama Power Company Limited (“GBPC”), a vertically integrated regulated electric utility on Grand Bahama Island;

●

a 51.9 per cent interest in Dominica Electricity Services Ltd. (“Domlec”), a vertically integrated regulated electric utility on the island of Dominica; and

●

a 19.5 per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia.

On March 24, 2020, Emera completed the sale of Emera Maine which was previously included in the Other Electric Utilities segment. Refer to note 4 for further information.

●

Gas Utilities and Infrastructure, which includes:

●

Peoples Gas System (“PGS”), a regulated gas distribution utility operating across Florida;

●

New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility serving customers in New Mexico;

●

SeaCoast Gas Transmission, LLC (“SeaCoast”), a regulated intrastate natural gas transmission company offering services in Florida;

●

Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145-kilometre pipeline delivering re-gasified liquefied natural gas (“LNG”) from Saint John, New Brunswick to the United States border under a 25-year firm service agreement with Repsol Energy Canada, which expires in 2034; and

●

a 12.9 per cent interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400-kilometre pipeline, which transports natural gas throughout markets in Atlantic Canada and the northeastern United States.

At June 30, 2020, Emera’s investments in other energy-related non-regulated companies (included within the Other reportable segment) include the following:

●

Emera Energy, which consists of:

●

Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services;

●

Brooklyn Power Corporation (“Brooklyn Energy”), a power plant in Brooklyn, Nova Scotia; and

●

a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a pumped storage hydroelectric facility in northwestern Massachusetts.

●

Emera Reinsurance Limited, a captive insurance company providing insurance and reinsurance to Emera and certain affiliates, to enable more cost-efficient management of risk and deductible levels across Emera;

●

Emera US Finance LP (“Emera Finance”) and TECO Finance, Inc. (“TECO Finance”), financing subsidiaries of Emera;

●

Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States; and

●

other investments.

In 2019, the Company completed the sale of assets previously included in the Other segment, including the sale of Emera Energy’s New England Gas Generating (“NEGG”) and Bayside facilities, and Emera Utility Services equipment and inventory.

Basis of Presentation

These unaudited condensed consolidated interim financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). The significant accounting policies applied to these unaudited condensed consolidated interim financial statements are consistent with those disclosed in the audited consolidated financial statements as at and for the year ended December 31, 2019, except as described in note 2.

In the opinion of management, these unaudited condensed consolidated interim financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2020.

All dollar amounts are presented in Canadian dollars, unless otherwise indicated.

Use of Management 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, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, capitalized overhead and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current 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.

During the three months and six months ended June 30, 2020, the ongoing COVID-19 pandemic has affected all service territories in which Emera operates. Emera has experienced some reduced load and incremental operating expenses as a result of COVID-19. The impact varies by utility, however on a consolidated basis there has not been a material impact to consolidated net earnings to date, primarily due a favourable change to the mix of sales to residential customer classes. Favourable weather, in particular in Florida, has further reduced the consolidated impact. Emera’s utilities provide essential services and continue to operate and meet customer demand. Governments world-wide have implemented measures intended to address the pandemic. These measures include travel and transportation restrictions, quarantines, physical distancing, closures of commercial spaces and industrial facilities, shutdowns, shelter-in-place orders and other health measures. These measures are adversely impacting global, national and local economies. Global equity markets have experienced significant volatility and weakness. Governments and central banks are implementing measures designed to stabilize economic conditions. The pace and strength of economic recovery is uncertain and may vary among jurisdictions.

Management has analyzed the impact of the COVID-19 pandemic on its estimates and judgements and concluded that no material adjustments are required for the three months and six months ended June 30, 2020.

Goodwill Impairment Assessments

Management considered whether the potential impacts of the COVID-19 pandemic on future earnings required testing for goodwill impairment in Q2 2020 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, 2020.

As of June 30, 2020, $6.0 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, management does not expect the COVID-19 pandemic to have an impact on the goodwill associated with these reporting units.

As of June 30, 2020, $73 million of Emera’s goodwill was related to GBPC. The calculated goodwill for this reporting unit is more sensitive to changes in forecasted future earnings. Adverse impacts to earnings in the future as a result of COVID-19 could cause impairment, however, the impact of COVID-19 on future earnings cannot be reasonably determined or estimated at this time. No impairment has been recorded in the three months and six months ended June 30, 2020.

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, 2020, there are no indications of impairment of Emera’s long-lived assets. The impact of COVID-19 could cause the Company to impair long-lived assets in the future, however, 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.

Impairment charges of $3 million ($3 million after tax) and $25 million ($26 million after tax) were recognized on certain assets for the three months and six months ended June 30, 2020, respectively.

Pension and Other Post-Retirement Employee Benefits

The COVID-19 pandemic could impact key actuarial assumptions used to account for employee post-retirement benefits 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.

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, further potential government actions and future economic activity and energy usage. Actual results may differ significantly from these estimates.

Seasonal Nature of Operations

Interim results are not necessarily indicative of results for the full year, primarily due to seasonal factors. Electricity and gas sales, and related transmission and distribution, vary over the year. 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. Certain quarters may also be impacted by weather and the number and severity of storms. In 2020, quarterly results may also be affected by the impact of the COVID-19 pandemic.

Receivables and Allowance for Doubtful Accounts

Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date.

The Company is exposed to credit risk with respect to amounts receivable from customers. Credit assessments may be conducted on new customers. Deposits are requested on accounts as required. The Company also maintains provisions for potential credit losses, which are assessed on a regular basis.

Management estimates uncollectible 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. Provisions for losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible.

The potential future economic impact of COVID-19, in the service territories in which Emera operates, may impact the aging and collectability of customer receivables.

2. CHANGE IN ACCOUNTING POLICY

The new USGAAP accounting policies that are applicable to, and adopted by the Company in 2020, are described as follows:

Measurement of Credit Losses on Financial Instruments

The Company adopted Accounting Standard Update (“ASU”) 2016-13, Measurement of Credit Losses on Financial Instruments effective January 1, 2020. The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures. The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators. The adoption of the standard resulted in a $7 million decrease to retained earnings in the condensed consolidated financial statements as of January 1, 2020.

3. 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 2019 audited consolidated financial statements, with updates noted below.

Facilitation of the Effects of Reference Rate Reform on Financial Reporting

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The standard provides optional expedients and exceptions for applying USGAAP to contract modifications and hedging relationships that reference LIBOR or another rate that is expected to be discontinued. The guidance was effective as of the date of issuance and entities may elect to apply the guidance prospectively through December 31, 2022. The Company is currently evaluating the impact of adoption of the standard, if elected, on its consolidated financial statements.

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

In August 2020, the FASB issued 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). The standard reduces the number of accounting models 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. The guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2021. Early adoption is permitted, but no earlier than fiscal years beginning after December 15, 2020. The standard will be applied through either a modified retrospective method of transition or a fully retrospective method of transition. The Company is currently evaluating the impact of adoption of the standard on its consolidated financial statements.

4. DISPOSITIONS

On March 24, 2020, Emera completed the sale of Emera Maine for a total enterprise value of approximately $2.0 billion including cash proceeds of $1.4 billion, transferred debt and working capital adjustments. A gain on disposition of $585 million ($309 million after tax) net of transaction costs, was recognized in the Other segment and included in “Other income” on the Condensed Consolidated Statements of Income.

Emera Maine’s assets and liabilities were classified as held for sale at March 25, 2019. The Company continued recording depreciation on these assets through the transaction closing date, as the depreciation continued to be reflected in customer rates and was reflected in the carryover basis of the assets on completion of the sale. A total of $53 million of depreciation and amortization was recorded on these assets from March 25, 2019, the date they were classified as held for sale, until the date of the sale. $39 million of the $53 million was recorded in 2019. Emera Maine’s assets and liabilities were included in the Company’s Other Electric Utilities segment.

5. SEGMENT INFORMATION

Emera manages its reportable segments separately due in part to their different operating, regulatory and geographical environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets, as reported to the Company’s chief operating decision maker. Emera’s five reportable segments are Florida Electric Utility, Canadian Electric Utilities, Other Electric Utilities, Gas Utilities and Infrastructure, and Other.


millions of Canadian dollars	Florida Electric Utility		Canadian Electric Utilities		Other Electric Utilities		Gas Utilities and Infrastructure		Other		Inter- Segment Eliminations			Total

For the three months ended June 30, 2020

Operating revenues from external customers (1)	$	627	$	335	$	95	$	212	$	(100)	$	-		$	1,169

Inter-segment revenues (1)		1		-		-		2		6		(9)			-

Total operating revenues		628		335		95		214		(94)		(9)			1,169

Regulated fuel for generation and purchased power		130		146		37		-		-		(1)			312

Regulated cost of natural gas		-		-		-		40		-		-			40

Depreciation and amortization		112		58		16		28		2		-			216

Interest expense, net		39		35		7		15		76		1			173

Internally allocated interest (2)		-		-		-		4		(4)		-			-

Operating, maintenance and general (“OM&G”)		132		69		36		79		22		(4)			334

Gain on sale and impairment charges		-		-		-		-		(4)		-			(4)

Income tax expense (recovery)		28		4		-		8		(41)		-			(1)

Net income (loss) attributable to common shareholders		146		37		2		27		(154)		-			58

For the six months ended June 30, 2020

Operating revenues from external customers (1)		1,192		793		266		546		9		-			2,806

Inter-segment revenues (1)		3		-		-		5		10		(18)			-

Total operating revenues		1,195		793		266		551		19		(18)			2,806

Regulated fuel for generation and purchased power		272		350		104		-		-		(4)			722

Regulated cost of natural gas		-		-		-		149		-		-			149

Depreciation and amortization		228		116		44		55		4		-			447

Interest expense, net		79		70		20		30		158		-			357

Internally allocated interest (2)		-		-		-		7		(7)		-			-

OM&G		270		148		83		163		57		(9)			712

Gain on sale and impairment charges		-		-		-		-		560		-			560

Income tax expense (recovery)		42		12		(8)		30		229		-			305

Net income attributable to common shareholders		225		129		19		97		111		-			581

As at June 30, 2020

Total assets		17,592		6,769		1,470		5,991		1,175		(1,118)	⁽³⁾		31,879

(1) All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes the elimination of these transactions would understate property, plant and equipment, OM&G expenses, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs.

(3) Primarily relates to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.


millions of Canadian dollars	Florida Electric Utility		Canadian Electric Utilities		Other Electric Utilities		Gas Utilities and Infrastructure		Other		Inter- Segment Eliminations		Total
For the three months ended June 30, 2019
Operating revenues from external customers (1)	$	694	$	327	$	188	$	238	$	(70)	$	-	$	1,377
Inter-segment revenues (1)		3		-		-		5		11		(18)		1
Total operating revenues		697		327		188		243		(59)		(18)		1,378
Regulated fuel for generation and purchased power		209		143		71		-		-		(5)		418
Regulated cost of natural gas		-		-		-		61		-		-		61
Depreciation and amortization		113		57		29		27		2		-		228
Interest expense, net		38		37		13		15		82		-		185
Internally allocated interest (2)		-		-		-		4		(4)		-		-
OM&G		139		69		46		75		29		(15)		343
Income tax expense (recovery)		26		(7)		3		13		(50)		-		(15)
Net income (loss) attributable to common shareholders		125		42		23		40		(127)		-		103
For the six months ended June 30, 2019
Operating revenues from external customers (1)		1,239		769		370		594		224		-		3,196
Inter-segment revenues (1)		6		1		-		11		21		(39)		-
Total operating revenues		1,245		770		370		605		245		(39)		3,196
Regulated fuel for generation and purchased power		361		331		137		-		-		(10)		819
Regulated cost of natural gas		-		-		-		197		-		-		197
Depreciation and amortization		221		113		58		54		6		-		452
Interest expense, net		77		72		26		30		169		-		374
Internally allocated interest (2)		-		-		-		7		(7)		-		-
OM&G		272		142		95		154		74		(28)		709
Income tax expense (recovery)		39		1		6		34		(13)		-		67
Net income (loss) attributable to common shareholders		186		138		41		107		(57)		-		415
As at December 31, 2019
Total assets		16,214		6,717		3,069		5,489		1,459		(1,106)⁽³⁾		31,842

(2) Segment net income is reported on a basis that includes internally allocated financing costs.

(3) Primarily relates to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.

6. REVENUE

The following disaggregates the Company’s revenue by major source:


millions of Canadian dollars	Florida Electric Utility		Canadian Electric Utilities		Other Electric Utilities		Gas Utilities and Infrastructure		Other			Inter- Segment Eliminations			Total
For the three months ended June 30, 2020
Regulated
Electric Revenue
Residential	$	352	$	182	$	36	$	-	$	-		$	-		$	570
Commercial		168		90		46		-		-			-			304
Industrial		44		51		7		-		-			-			102
Other electric and regulatory deferrals		61		6		2		-		-			-			69
Other (1)		3		6		4		-		-			(1)			12
Regulated electric revenue		628		335		95		-		-			(1)			1,057
Gas Revenue
Residential		-		-		-		93		-			-			93
Commercial		-		-		-		50		-			-			50
Industrial		-		-		-		14		-			(1)			13
Finance income (2)(3)		-		-		-		15		-			-			15
Other		-		-		-		37		-			(1)			36
Regulated gas revenue		-		-		-		209		-			(2)			207
Non-Regulated
Marketing and trading margin (4)		-		-		-		-		(13)			-			(13)
Energy sales (4)		-		-		-		-		2			(4)			(2)
Other		-		-		-		5		4			-			9
Mark-to-market (3)		-		-		-		-		(87)			(2)			(89)
Non-regulated revenue		-		-		-		5		(94)			(6)			(95)
Total operating revenues	$	628	$	335	$	95	$	214	$		(94)	$		(9)	$	1,169
For the six months ended June 30, 2020
Regulated
Electric Revenue
Residential	$	627	$	446	$	97	$	-	$	-		$	-		$	1,170
Commercial		336		210		126		-		-			-			672
Industrial		94		107		19		-		-			-			220
Other electric and regulatory deferrals		129		17		5		-		-			-			151
Other (1)		9		13		19		-		-			(3)			38
Regulated electric revenue		1,195		793		266		-		-			(3)			2,251
Gas Revenue
Residential		-		-		-		261		-			-			261
Commercial		-		-		-		141		-			-			141
Industrial		-		-		-		27		-			(1)			26
Finance income (2)(3)		-		-		-		30		-			-			30
Other		-		-		-		84		-			(4)			80
Regulated gas revenue		-		-		-		543		-			(5)			538
Non-Regulated
Marketing and trading margin (4)		-		-		-		-		28			-			28
Energy sales (4)		-		-		-		-		6			(8)			(2)
Other		-		-		-		8		9			-			17
Mark-to-market (3)		-		-		-		-		(24)			(2)			(26)
Non-regulated revenue		-		-		-		8		19			(10)			17
Total operating revenues	$	1,195	$	793	$	266	$	551	$	19		$		(18)	$	2,806

(1) Other includes rental revenues, which do not represent revenue from contracts with customers.

(2) Revenue related to Brunswick Pipeline’s service agreement with Repsol Energy Canada.

(3) Revenue which does not represent revenues from contracts with customers.

(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers.


millions of Canadian dollars	Florida Electric Utility		Canadian Electric Utilities		Other Electric Utilities		Gas Utilities and Infrastructure		Other			Inter- Segment Eliminations		Total
For the three months ended June 30, 2019
Regulated
Electric Revenue
Residential	$	348	$	165	$	65	$	-	$	-		$	-	$	578
Commercial		187		94		91		-		-			-		372
Industrial		56		53		11		-		-			-		120
Other electric and regulatory deferrals		100		8		4		-		-			-		112
Other (1)		6		7		17		-		-			(3)		27
Regulated electric revenue		697		327		188		-		-			(3)		1,209
Gas Revenue
Residential		-		-		-		93		-			-		93
Commercial		-		-		-		61		-			-		61
Industrial		-		-		-		13		-			-		13
Finance income (2)(3)		-		-		-		15		-			-		15
Other		-		-		-		57		-			(5)		52
Regulated gas revenue		-		-		-		239		-			(5)		234
Non-Regulated
Marketing and trading margin (4)		-		-		-		-		(28)			-		(28)
Energy sales (4)		-		-		-		-		2			(2)		-
Capacity		-		-		-		-		(2)			-		(2)
Other		-		-		-		4		8			(8)		4
Mark-to-market (3)		-		-		-		-		(39)			-		(39)
Non-regulated revenue		-		-		-		4		(59)			(10)		(65)
Total operating revenues	$	697	$	327	$	188	$	243	$		(59)		$ (18)	$	1,378
For the six months ended June 30, 2019
Regulated
Electric Revenue
Residential	$	622	$	417	$	133	$	-	$	-		$	-	$	1,172
Commercial		347		207		171		-		-			-		725
Industrial		102		108		23		-		-			-		233
Other electric and regulatory deferrals		162		24		7		-		-			-		193
Other (1)		12		14		36		-		-			(7)		55
Regulated electric revenue		1,245		770		370		-		-			(7)		2,378
Gas Revenue
Residential		-		-		-		282		-			-		282
Commercial		-		-		-		159		-			-		159
Industrial		-		-		-		25		-			-		25
Finance income (2)(3)		-		-		-		29		-			-		29
Other		-		-		-		102		-			(11)		91
Regulated gas revenue		-		-		-		597		-			(11)		586
Non-Regulated
Marketing and trading margin (4)		-		-		-		-		26			-		26
Energy sales (4)		-		-		-		-		80			(6)		74
Capacity		-		-		-		-		36			-		36
Other		-		-		-		8		18			(15)		11
Mark-to-market (3)		-		-		-		-		85			-		85
Non-regulated revenue		-		-		-		8		245			(21)		232
Total operating revenues	$	1,245	$	770	$	370	$	605	$	245			$ (39)	$	3,196

(1) Other includes rental revenues, which do not represent revenue from contracts with customers.

(2) Revenue related to Brunswick Pipeline’s service agreement with Repsol Energy Canada.

(3) Revenue which does not represent revenues from contracts with customers.

(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers.

Remaining Performance Obligations

Remaining performance obligations primarily represent gas transportation contracts, lighting contracts and long-term steam supply arrangements with fixed contract terms. As of June 30, 2020, the aggregate amount of the transaction price allocated to remaining performance obligations was $351 million (December 31, 2019 – $347 million). As allowed by the practical expedient in ASC 606, this amount excludes contracts with an original expected length of one year or less and variable amounts for which Emera recognizes revenue at the amount to which it has the right to invoice for services performed. Emera expects to recognize revenue for the remaining performance obligations through 2033.

7. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME


	Carrying Value as at				Equity Income for the three months ended June 30				Equity Income for the six months ended June 30				Percentage of Ownership
	June 30		December 31		Equity Income for the three months ended June 30				Equity Income for the six months ended June 30				Percentage of Ownership
millions of Canadian dollars	2020		2019		2020		2019		2020		2019		2020

LIL (1)	$	603	$	579	$	12	$	11	$	24	$	22		49.2

NSPML		558		554		12		12		27		26		100.0

M&NP (2)		137		138		4		6		9		12		12.9

Lucelec (2)		44		41		1		1		2		2		19.5

Bear Swamp (3)		-		-		11		10		19		18		50.0

	$	1,342	$	1,312	$	40	$	40	$	81	$	80

(1) Emera indirectly owns 100 per cent of the LIL Class B units, which comprises 24.9 per cent of the total units issued. Emera’s percentage ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon final costing of all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Assets and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 per cent of the cost of all of these transmission developments.

(2) Although Emera’s ownership percentage of these entities is relatively low, it is considered to have significant influence over the operating and financial decisions of these companies through Board representation. Therefore, Emera records its investment in these entities using the equity method.

(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $179 million distribution received in Q4 2015. Bear Swamp’s credit investment balance of $132 million (2019 - $137 million) is recorded in “Other long-term liabilities” on the Condensed Consolidated Balance Sheets.

Emera accounts for its variable interest investment in NSPML as an equity investment (note 24). NSPML’s consolidated summarized balance sheet is as follows:


As at	June 30		December 31
millions of Canadian dollars	2020		2019

Balance Sheet

Current assets	$	66	$	69

Property, plant and equipment		1,650		1,671

Regulatory assets		206		177

Non-current assets		32		32

Total assets	$	1,954	$	1,949

Current liabilities	$	60	$	23

Long-term debt		1,248		1,288

Non-current liabilities		88		84

Equity		558		554

Total liabilities and equity	$	1,954	$	1,949

8. OTHER INCOME (EXPENSES), NET


For the millions of Canadian dollars	Three months ended June 30					Six months ended June 30
	2020			2019		2020		2019

Gain on sale and impairment charges (1)	$	(4	)		-		560		-

Allowance for equity funds used during construction		11			4		20		8

Other		17			2		7		11

	$	24		$	6	$	587	$	19

(1) Refer to note 4 for further details related to the gain on sale of Maine

9. INCOME TAXES

The income tax provision differs from that computed using the enacted combined Canadian federal and provincial statutory income tax rate for the following reasons:


For the millions of Canadian dollars	Three months ended June 30				Six months ended June 30
	2020		2019		2020		2019

Income before provision for income taxes	$	80	$	101	$	921	$	507

Statutory income tax rate		29.5%		31%		29.5%		31%

Income taxes, at statutory income tax rate		24		31		272		157

Additional impact from the sale of Emera Maine		10		-		102		-

Amortization of deferred income tax regulatory liabilities		(11)		(11)		(27)		(16)

Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities		(6)		(13)		(27)		(34)

Foreign tax rate variance		(8)		(13)		(17)		(25)

Revaluation of deferred income taxes due to change in Nova Scotia tax rate		-		-		12		-

Tax effect of equity earnings		(4)		(4)		(8)		(9)

Other		(6)		(5)		(2)		(6)

Income tax expense (recovery)	$	(1)	$	(15)	$	305	$	67

Effective income tax rate		(1)%		(15)%		33%		13%

The increase in the effective income tax rate was primarily due to the sale of Emera Maine. Year-over-year, the increase was also due to lower deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities.

On March 10, 2020, Bill 243 of the Nova Scotia Financial Measures (2020) Act (“the Financial Measures Act”) was enacted, which included a reduction in the Nova Scotia provincial corporate income tax rate from 16 per cent to 14 per cent. As a result, the Company’s combined Canadian federal and provincial statutory income tax rate was reduced from 31 per cent to 29.5 per cent for 2020 and further reduced to 29 per cent for subsequent years.

As a result of the enactment of the Financial Measures Act in Q1 2020, the Company was required to revalue certain of its Canadian deferred income tax assets and liabilities based on the new tax rates. The Company recorded a reduction of $52 million to its net deferred income tax liabilities and an offsetting reduction to its net deferred income tax regulatory asset, as the benefit of lower net deferred income tax liabilities is expected to be returned to customers in future years. The Company also recognized a $12 million income tax expense in Q1 2020 as a result of the revaluation of certain net deferred income tax assets.

On March 25, 2020, Bill C-13, the Canadian COVID-19 Emergency Response Act (“the COVID-19 Act”) was enacted, guaranteeing rapid implementation and administration of measures to protect Canadians’ health and safety, and stabilize the economy. In addition, the Government of Canada announced the opportunity for businesses to defer certain tax payments. The Company does not anticipate any material impacts from the COVID-19 Act or the Government of Canada’s additional announcements.

On March 27, 2020, the United States Coronavirus Aid, Relief, and Economic Security (CARES) Act (“the CARES Act”) was signed into legislation. The CARES Act includes several business provisions including deferral of employer payroll taxes, an employee retention payroll tax credit, temporary changes to business interest expense disallowance rules, changes to net operating loss carryback and limitation rules and corporate alternative minimum tax (“AMT”) relief. Under the new AMT provisions, companies can accelerate the refund of AMT credit carryforwards. In Q1 2020, the Company reclassified $77 million of AMT credit carryforwards from deferred income tax assets to receivables and other current assets as it expects to receive the refund in 2020. The Company does not anticipate any other material impacts from the CARES Act.

10. COMMON STOCK

Authorized: Unlimited number of non-par value common shares.


Issued and outstanding:	millions of shares		millions of Canadian dollars

Balance, December 31, 2019		242.48		$ 6,216

Issuance of common stock (1)		1.73		99

Issued for cash under Purchase Plans at market rate		1.81		101

Discount on shares purchased under Dividend Reinvestment Plan		-		(2	)

Options exercised under senior management share option plan		0.42		20

Employee Share Purchase Plan		-		1

Balance, June 30, 2020		246.44		$ 6,435

(1) In Q2 2020, 745,121 common shares were issued under Emera’s at-the-market program (“ATM program”) at an average price of $55.33 per share for gross proceeds of $41.2 million ($40.7 million net of issuance costs). During the six months ended June 30, 2020, 1,728,103 common shares were issued under Emera’s at-the-market program (“ATM program”) at an average price of $57.87 per share for gross proceeds of $100 million ($98.7 million net of issuance costs). As at June 30, 2020, an aggregate gross sales limit of $400 million remains available for issuance under the ATM program.

11. EARNINGS PER SHARE

The following table reconciles the computation of basic and diluted earnings per share:


For the	Three months ended June 30				Six months ended June 30
millions of Canadian dollars (except per share amounts)	2020		2019		2020		2019

Numerator

Net income attributable to common shareholders	$	58.0	$	103.5	$	581.1	$	415.3

Diluted numerator		58.0		103.5		581.1		415.3

Denominator

Weighted average shares of common stock outstanding		245.4		237.7		244.4		236.3

Weighted average deferred share units outstanding		1.3		1.5		1.3		1.5

Weighted average shares of common stock outstanding – basic		246.7		239.2		245.7		237.8

Stock-based compensation		0.4		0.5		0.4		0.5

Dividend reinvestment plan		0.9		-		0.9		-

Convertible Debentures		-		0.1		-		0.1

Weighted average shares of common stock outstanding – diluted		248.0		239.8		247.0		238.4

Earnings per common share

Basic	$	0.24	$	0.43	$	2.37	$	1.75

Diluted	$	0.23	$	0.43	$	2.35	$	1.74

12. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The components of accumulated other comprehensive income (loss), net of tax, are as follows:


millions of Canadian dollars	Unrealized (loss) gain on translation of self-sustaining foreign operations		Net change in net investment hedges		(Losses) gains on derivatives recognized as cash flow hedges		Net change in available- for-sale investments		Net change in unrecognized pension and post- retirement benefit costs		Total AOCI

For the six months ended June 30, 2020

Balance, January 1, 2020	$	253	$	4	$	(1)	$	(1)	$	(160)	$	95

Other comprehensive income (loss) before reclassifications		395		(75)		(2)		-		-		318

Amounts reclassified from accumulated other comprehensive income loss (gain)		-		-		2		-		(2)		-

Net current period other comprehensive income (loss)		395		(75)		-		-		(2)		318

Balance, June 30, 2020	$	648	$	(71)	$	(1)	$	(1)	$	(162)	$	413

For the six months ended June 30, 2019

Balance, January 1, 2019	$	654	$	(74)	$	(7)	$	(1)	$	(234)	$	338

Other comprehensive income (loss) before reclassifications		(337)		67		3		-		-		(267)

Amounts reclassified from accumulated other comprehensive income loss (gain)		-		-		2		-		8		10

Net current period other comprehensive income (loss)		(337)		67		5		-		8		(257)

Balance, June 30, 2019	$	317	$	(7)	$	(2)	$	(1)	$	(226)	$	81

The reclassifications out of accumulated other comprehensive income (loss) are as follows:


For the		Three months ended June 30				Six months ended June 30
millions of Canadian dollars		2020		2019		2020		2019
	Affected line item in the Consolidated Financial Statements		Amounts reclassified from AOCI

Losses (gain) on derivatives recognized as cash flow hedges
Foreign exchange forwards	Operating revenue – regulated	$	1	$	-	$	2	$	2

Total		$	1	$	-	$	2	$	2
Net change in unrecognized pension and post-retirement benefit costs
Actuarial losses (gains)	OM&G	$	3	$	4	$	6	$	9
Amounts reclassified into obligations	Pension and post-retirement liabilities		-		-		(8)		-

Total before tax			3		4		(2)		9

	Income tax expense (recovery)		-		-		-		(1)

Total net of tax		$	3	$	4	$	(2)	$	8

Total reclassifications out of AOCI, net of tax, for the period		$	4	$	4	$	-	$	10

13. DERIVATIVE INSTRUMENTS

The Company enters into futures, forwards, swaps and option contracts as part of its risk management strategy to limit exposure to:

●

commodity price fluctuations related to the purchase and sale of commodities in the course of normal operations;

●

foreign exchange fluctuations on foreign currency denominated purchases and sales;

●

interest rate fluctuations on debt securities; and

●

share price fluctuations on stock-based compensation.

The Company also enters into physical contracts for energy commodities. Collectively, these contracts are considered “derivatives”. The Company accounts for derivatives under one of the following four approaches:

Physical contracts that meet the normal purchases normal sales (“NPNS”) exemption are not recognized on the balance sheet; they are recognized in income when they settle. A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. The Company continually assesses contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exception if the criteria are no longer met.

Derivatives that qualify for hedge accounting are recorded at fair value on the balance sheet. Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge the identified cash flow risk both at the inception and over the term of the derivative. Specifically, for cash flow hedges, the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized.

Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.

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

Derivatives that do not meet any of the above criteria are designated as held-for-trading (“HFT”) derivatives and are recorded on the balance sheet at fair value, with changes normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply.

Derivative assets and liabilities relating to the foregoing categories consisted of the following:


	Derivative Assets				Derivative Liabilities
As at	June 30		December 31		June 30		December 31
millions of Canadian dollars	2020		2019		2020		2019
Cash flow hedges

Foreign exchange forwards	$	-	$	-	$	1	$	1

		-		-		1		1
Regulatory deferral

Commodity swaps and forwards
Coal purchases		9		8		33		39
Power purchases		12		23		45		36
Natural gas purchases and sales		5		2		5		5
Heavy fuel oil purchases		-		1		15		-

Foreign exchange forwards		11		2		1		6

		37		36		99		86

HFT derivatives

Power swaps and physical contracts		11		19		15		22

Natural gas swaps, futures, forwards, physical contracts		116		151		240		381

		127		170		255		403

Other derivatives

Equity derivatives		-		1		5		-

Foreign exchange forwards		9		-		4		-

		9		1		9		-

Total gross current derivatives		173		207		364		490

Impact of master netting agreements with intent to settle net or simultaneously		(93)		(120)		(93)		(120)

		80		87		271		370

Current		48		54		184		268

Long-term		32		33		87		102

Total derivatives	$	80	$	87	$	271	$	370

Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.

Details of master netting agreements, shown net on the Condensed Consolidated Balance Sheets, are summarized in the following table:


	Derivative Assets				Derivative Liabilities
As at	June 30		December 31		June 30		December 31
millions of Canadian dollars	2020		2019		2020		2019

Regulatory deferral	$	9	$	8	$	9	$	8

HFT derivatives		84		112		84		112
Total impact of master netting agreements with intent to settle net or simultaneously	$	93	$	120	$	93	$	120

Cash Flow Hedges

The Company has foreign exchange forwards to hedge the currency risk for revenue streams denominated in foreign currency for Brunswick Pipeline.

The amounts related to cash flow hedges recorded in income and AOCI consisted of the following:


	Three months ended				Six months ended
For the	June 30				June 30
millions of Canadian dollars	2020		2019		2020		2019

		Foreign Exchange Forwards				Foreign Exchange Forwards

Realized gain (loss) in operating revenue – regulated	$	(1)	$	-	$	(2)	$	(2)

Total gains (losses) in net income	$	(1)	$	-	$	(2)	$	(2)

As at millions of Canadian dollars	June 30 2020				December 31 2019

						Foreign Exchange Forwards

Total unrealized gain (loss) in AOCI – net of tax			$	(1)			$	(1)

The Company expects $1 million of unrealized losses currently in AOCI to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle.

As at June 30, 2020, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:



millions		2020

Foreign exchange forwards (USD) sales	$	12

Regulatory Deferral

The Company has recorded the following changes in realized and unrealized gains (losses) with respect to derivatives receiving regulatory deferral:


For the	Three months ended June 30
millions of Canadian dollars			2020				2019

		Commodity swaps and forwards		Foreign exchange forwards		Commodity swaps and forwards		Foreign exchange forwards

Unrealized gain (loss) in regulatory assets	$	24	$	(1)	$	(52)	$	(6)

Unrealized gain (loss) in regulatory liabilities		7		(20)		13		(3)

Realized (gain) loss in regulatory assets		1		-		-		-

Realized (gain) loss in regulatory liabilities		3		-		(1)		-

Realized (gain) loss in inventory (1)		3		(2)		(6)		(3)

Realized (gain) loss in regulated fuel for generation and purchased power (2)		7		(2)		-		(3)

Total change in derivative instruments	$	45	$	(25)	$	(46)	$	(15)

(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.

(2) 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.


For the	Six months ended June 30
millions of Canadian dollars			2020				2019
	Commodity swaps and forwards		Foreign exchange forwards		Commodity swaps and forwards		Foreign exchange forwards

Unrealized gain (loss) in regulatory assets	$	(50)	$	5	$	(46)	$	(7)

Unrealized gain (loss) in regulatory liabilities		(3)		15		(6)		(8)

Realized (gain) loss in regulatory assets		1		-		-		-

Realized (gain) loss in regulatory liabilities		10		-		4		-

Realized (gain) loss in inventory (1)		3		(3)		(24)		(8)

Realized (gain) loss in regulated fuel for generation and purchased power (2)		13		(3)		(2)		(5)

Total change in derivative instruments	$	(26)	$	14	$	(74)	$	(28)

(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.

(2) 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.

Commodity Swaps and Forwards

As at June 30, 2020, the Company had the following notional volumes of commodity swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below:



	2020	2021-2022

millions	Purchases	Purchases

Natural Gas (Mmbtu)	5	17

Power (MWh)	-	3

Heavy fuel oil (bbls)	-	1

Coal (metric tonnes)	-	1

Foreign Exchange Swaps and Forwards

As at June 30, 2020, the Company had the following notional volumes of foreign exchange swaps and forward contracts designated as regulated deferral that are expected to settle as outlined below:



		2020		2021-2022

Foreign exchange contracts (millions of US dollars)	$	78	$	259

Weighted average rate		1.3240		1.3381

% of USD requirements		67%		67%

The Company reassesses foreign exchange forecasted periodically and will enter into additional hedges or unwind existing hedges, as required.

Held-for-Trading Derivatives

In the ordinary course of its business, Emera enters into physical contracts for the purchase and sale of natural gas, as well as power and natural gas swaps, forwards and futures, to economically hedge those physical contracts. These derivatives are all considered HFT.

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


For the	Three months ended				Six months ended
millions of Canadian dollars	June 30				June 30
	2020		2019		2020		2019

Power swaps and physical contracts in non-regulated operating revenues	$	(1)	$	2	$	-	$	2

Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues		11		43		222		247

Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power		-		(3)		(4)		(5)

	$	10	$	42	$	218	$	244

As at June 30, 2020, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:


millions	2020		2021		2022		2023		2024

Natural gas purchases (Mmbtu)		338		151		56		41		26

Natural gas sales (Mmbtu)		316		102		13		4		2

Power purchases (MWh)		2		-		-		-		-

Power sales (MWh)		2		-		-		-		-

Other Derivatives

As at June 30, 2020, the Company had equity derivatives in place to manage the cash flow risk associated with forecasted future cash settlements of deferred compensation obligations and foreign exchange forwards in place to manage cash flow risk associated with forecasted US dollar cash inflows. The equity derivative hedges the return on 2.8 million shares and extends until December of 2020. The foreign exchange forwards have a combined notional amount of $215 million and expire in 2020 through 2021.

The Company has recognized the following realized and unrealized gains (losses) with respect to other derivatives:


For the				Three months ended June 30
millions of Canadian dollars				2020					2019

		Foreign Exchange Forwards			Equity Derivatives			Foreign Exchange Forwards		Equity Derivatives

Unrealized gain (loss) in operating, maintenance and general	$	-		$		(6)	$	-	$	9

Unrealized gain (loss) in other income (expense)		13			-			-		-

Realized gain (loss) in other income (expense)		(3	)					-		-

Total gains (losses) in net income	$	10		$		(6)	$	-	$	9


For the			Six months ended June 30
millions of Canadian dollars			2020				2019

		Foreign Exchange Forwards		Equity Derivatives		Foreign Exchange Forwards		Equity Derivatives

Unrealized gain (loss) in operating, maintenance and general	$	-	$	(7)	$	-	$	23

Unrealized gain (loss) in other income (expense)		4		-		-		-

Realized gain (loss) in other income (expense)		(4)		-		-		-

Total gains (losses) in net income	$	-	$	(7)	$	-	$	23

Credit Risk

The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high-risk accounts.

The Company assesses the potential for credit losses on a regular basis and, where appropriate, maintains provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability. The Company assesses credit risk internally for counterparties that are not rated.

It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, foreign exchange and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The Company also obtains cash deposits from electric customers. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company.

The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements (“ISDA”), North American Energy Standards Board agreements (“NAESB”) and, or Edison Electric Institute agreements. The Company believes that entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default.

As at June 30, 2020, the Company had $162 million (December 31, 2019 - $115 million) in financial assets considered to be past due, which have been outstanding for an average 70 days. The fair value of these financial assets is $144 million (December 31, 2019 - $106 million), the difference of which is included in the allowance for doubtful accounts. These assets primarily relate to accounts receivable from electric and gas revenue.

Cash Collateral

The Company’s cash collateral positions consisted of the following:


As at millions of Canadian dollars	June 30 2020		December 31 2019

Cash collateral provided to others	$	110	$	101

Cash collateral received from others		4		2

Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain derivatives contain financial assurance provisions that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted in the senior unsecured debt falling below investment grade, the counterparties to such derivatives could request ongoing full collateralization.

As at June 30, 2020, the total fair value of these derivatives, in a liability position, was $271 million (December 31, 2019 – $370 million). If the credit ratings of the Company were reduced below investment grade, the full value of the net liability position could be required to be posted as collateral for these derivatives.

14. FAIR VALUE MEASUREMENTS

The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exemption (see note 13), and uses a market approach to do so. The three levels of the fair value hierarchy are defined as follows:

Level 1 - Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities.

Level 2 - Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses.

Level 3 - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally developed inputs. The primary reasons for a Level 3 classification are as follows:

●

While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials.

●

The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term.

●

The valuations of certain transactions were based on internal models, although quoted prices were utilized in the valuations.

Derivative assets and liabilities are classified in their entirety, based on the lowest level of input that is significant to the fair value measurement.

The following tables set out the classification of the methodology used by the Company to fair value its derivatives:


As at	June 30, 2020
millions of Canadian dollars	Level 1		Level 2		Level 3		Total

Assets

Regulatory deferral

Commodity swaps and forwards
Power purchases	$	12	$	-	$	-	$	12
Natural gas purchases and sales		3		2		-		5

Foreign exchange forwards		-		11		-		11

		15		13		-		28

HFT derivatives

Power swaps and physical contracts		3		1		1		5

Natural gas swaps, futures, forwards, physical contracts and related transportation		-		27		11		38

		3		28		12		43

Other derivatives

Foreign exchange forwards		-		9		-		9

		-		9		-		9

Total assets		18		50		12		80

Liabilities

Cash flow hedges

Foreign exchange forwards		-		1		-		1

		-		1		-		1

Regulatory deferral

Commodity swaps and forwards
Coal purchases		-		24		-		24
Power purchases		45		-		-		45
Heavy fuel oil purchases		6		9		-		15
Natural gas purchases and sales		3		3		-		6

Foreign exchange forwards		-		1		-		1
		54		37		-		91

HFT derivatives

Power swaps and physical contracts		7		1		-		8

Natural gas swaps, futures, forwards and physical contracts		9		7		146		162

		16		8		146		170

Other derivatives

Foreign exchange forwards		-		4		-		4

Equity derivatives		5		-		-		5

		5		4		-		9

Total liabilities		75		50		146		271

Net assets (liabilities)	$	(57)	$	-	$	(134)	$	(191)


As at	December 31, 2019
millions of Canadian dollars	Level 1		Level 2		Level 3		Total
Assets
Regulatory deferral
Commodity swaps and forwards
Power purchases		23		-		-		23
Natural gas purchases and sales		-		2		-		2
Heavy fuel oil purchases		-		1		-		1

Foreign exchange forwards		-		2		-		2

		23		5		-		28
HFT derivatives
Power swaps and physical contracts		1		3		1		5

Natural gas swaps, futures, forwards, physical contracts and related transportation		(7)		46		14		53

		(6)		49		15		58
Other derivatives

Equity derivatives		1		-		-		1

		1		-		-		1
Total assets		18		54		15		87
Liabilities
Cash flow hedges

Foreign exchange forwards		-		1		-		1

		-		1		-		1
Regulatory deferral
Commodity swaps and forwards
Coal purchases		-		31		-		31
Power purchases		36		-		-		36
Natural gas purchased and sales		3		2		-		5

Foreign exchange forwards		-		6		-		6

		39		39		-		78
HFT derivatives
Power swaps and physical contracts		5		2		-		7

Natural gas swaps, futures, forwards and physical contracts		2		33		249		284

		7		35		249		291
Total liabilities		46		75		249		370
Net assets (liabilities)	$	(28)	$	(21)	$	(234)	$	(283)

The change in the fair value of the Level 3 financial assets for the three months ended June 30, 2020 was as follows:


	HFT Derivatives
millions of Canadian dollars	Power			Natural gas			Total

Balance, beginning of period	$	4		$	15		$	19

Total realized and unrealized losses included in non-regulated operating revenues		(1	)		(4	)		(5	)

Net transfers out of Level 3		(2	)		-			(2	)

Balance, June 30, 2020	$	1		$	11		$	12

The change in the fair value of the Level 3 financial liabilities for the three months ended June 30, 2020 was as follows:


	HFT Derivatives
millions of Canadian dollars	Power			Natural gas			Total

Balance, beginning of period	$	3		$	152		$	155

Total realized and unrealized losses included in non-regulated operating revenues		(2	)		(6	)		(8	)

Net transfers out of Level 3		(1	)		-			(1	)

Balance, June 30, 2020	$	-		$	146		$	146

The change in the fair value of the Level 3 financial assets for the six months ended June 30, 2020 was as follows:


	HFT Derivatives
millions of Canadian dollars	Power			Natural gas			Total

Balance, beginning of period	$	1		$	14		$	15

Total realized and unrealized gains (losses) included in non-regulated operating revenues		2			(3	)		(1	)

Net transfers out of Level 3		(2	)		-			(2	)

Balance, June 30, 2020	$	1		$	11		$	12

The change in the fair value of the Level 3 financial liabilities for the six months ended June 30, 2020 was as follows:


	HFT Derivatives
millions of Canadian dollars	Power			Natural gas			Total

Balance, beginning of period	$	-		$	249		$	249

Total realized and unrealized gains (losses) included in non-regulated operating revenues		1			(103	)		(102	)

Net transfers out of Level 3		(1	)		-			(1	)

Balance, June 30, 2020	$	-		$	146		$	146

The Company evaluates observable inputs of market data on a quarterly basis to determine if transfers between levels is appropriate. For the three and six months ended June 30, 2020, transfers out of Level 3 were a result of an increase in observable inputs.

Significant unobservable inputs used in the fair value measurement of Emera’s natural gas and power derivatives include third-party sourced pricing for instruments based on illiquid markets; internally developed correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid term markets. Discount rates may include a risk premium for those long-term forward contracts with illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing similar industry practices and in discussion with industry peers. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement.

The following table outlines quantitative information about the significant unobservable inputs used in the fair value measurements categorized within Level 3 of the fair value hierarchy:


As at	June 30, 2020
millions of Canadian dollars	Fair Value		Valuation Technique		Unobservable Input		Weighted Range average (1)

Assets

HFT derivatives –	$	1		Modelled pricing		Third-party pricing		$17.50-$62.90	$29.66

Power swaps and						Probability of default		0.02%-22.18%	9.25%

physical contracts						Discount rate		0.01%-0.87%	0.44%

HFT derivatives –		7		Modelled pricing		Third-party pricing		$1.10-$4.10	$2.03

Natural gas swaps, futures,						Probability of default		0.01%-28.01%	3.77%

forwards, physical contracts						Discount rate		0.00%-7.36%	0.29%

		4		Modelled pricing		Third-party pricing		$1.21-$8.28	$3.27

						Basis adjustment		$0.00-$1.27	$0.73

						Probability of default		0.34%-16.25%	6.81%

						Discount rate		0.00%-0.63%	0.25%

Total assets	$	12

Liabilities

HFT derivatives –		138		Modelled pricing		Third-party pricing		$1.10-$7.22	$3.60

Natural gas swaps, futures,						Own credit risk		0.14%-28.01%	5.43%

forwards and physical contracts						Discount rate		0.00%-7.73%	0.54%

		8		Modelled pricing		Third-party pricing		$0.77-$8.28	$3.37

						Basis adjustment		$0.00-$1.27	$0.62

						Own credit risk		0.34%-11.79%	3.03%

						Discount rate		0.00%-0.59%	0.24%

Total liabilities	$	146

Net assets (liabilities)	$	(134)

(1) Unobservable inputs were weighted by the relative fair value of the instruments

The financial liabilities included on the Condensed Consolidated Balance Sheets that are not measured at fair value consisted of long-term debt, as follows:



As at
millions of Canadian dollars	Carrying Amount		Fair Value		Level 1		Level 2		Level 3		Total

June 30, 2020	$	14,304	$	16,735	$	-	$	16,205	$	530	$	16,735

December 31, 2019	$	14,180	$	16,049	$	-	$	15,598	$	451	$	16,049

The Company has designated $1.2 billion United States dollar denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in United States dollar denominated operations. An after-tax foreign currency gain of $66 million was recorded in Other Comprehensive Income for the three months ended June 30, 2020 (2019 – $33 million gain after-tax). An after-tax foreign currency loss of $75 million was recorded in Other Comprehensive Income for the six months ended June 30, 2020 (2019 – $67 million gain after-tax).

15. REGULATORY ASSETS AND LIABILITIES

A summary of the Company’s regulatory assets and liabilities is provided below. For a detailed description regarding the nature of the Company’s regulatory assets and liabilities, refer to note 15 in Emera’s 2019 annual audited consolidated financial statements.


As at millions of Canadian dollars	June 30 2020		December 31 2019
Regulatory assets
Deferred income tax regulatory assets	$	863	$	862
Pension and post-retirement medical plan		390		380
Deferrals related to derivative instruments		91		81
Storm restoration regulatory asset		41		38
Environmental remediations		29		26
Stranded cost recovery		28		27
Demand side management (“DSM”) deferral		17		19
Unamortized defeasance costs		16		19
Cost recovery clauses		9		13
Other		75		87
	$	1,559	$	1,552
Current	$	133	$	121
Long-term		1,426		1,431
Total regulatory assets	$	1,559	$	1,552

Regulatory liabilities
Deferred income tax regulatory liabilities	$	1,005	$	985
Accumulated reserve - cost of removal		929		891
Regulated fuel adjustment mechanism		106		115
Cost recovery clauses		99		53
Storm reserve		65		62
Self-insurance fund (note 24)		30		29
Deferrals related to derivative instruments		29		42
Other		8		4
	$	2,271	$	2,181
Current	$	265	$	295
Long-term		2,006		1,886
Total regulatory liabilities	$	2,271	$	2,181

Tampa Electric

On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan (“SPP”) Cost Recovery Clause. This new clause provides a process for Florida investor-owned utilities, including Tampa Electric, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Tampa Electric submitted its storm protection plan with the FPSC on April 10, 2020. On April 27, 2020, Tampa Electric submitted a settlement agreement with the FPSC which specified a $15 million USD base rate reduction for costs previously recovered in base rates related to SPP programs beginning January 1, 2021. On June 9, 2020, the FPSC approved this settlement agreement. On August 3, 2020, Tampa Electric submitted another settlement agreement to the FPSC for approval, including cost recovery of approximately $39 million USD in proposed storm protection project costs for 2020 and 2021. This cost recovery includes the $15 million USD of costs reduced from base rates. This settlement agreement was approved on August 10, 2020 and Tampa Electric’s cost recovery will begin in January 2021. Tampa Electric will file a new plan in 2022 to determine cost recovery in 2023, 2024, and 2025.

The June 9, 2020 settlement agreement approved by the FPSC disclosed above also included approval of Tampa Electric’s petition to eliminate its $16 million USD accumulated amortization reserve surplus for intangible software assets through a credit to amortization expense in 2020. As stipulated in the settlement, $8 million USD of this credit was recognized in Q2 2020 with the remaining $8 million USD to be recognized over the remainder of 2020.

On June 1, 2020, as part of its Big Bend Power Station modernization project, Tampa Electric retired Unit 1 components that will not be used in the modernized plant. At June 1, 2020, the balance sheet included $304 million ($223 million USD) and $123 million ($90 million USD) in property, plant and equipment and accumulated depreciation, respectively, related to Unit 1 components. In accordance with Tampa Electric’s 2017 settlement agreement approved by the FPSC, Tampa Electric will continue to account for its existing investment in Unit 1 in electric utility plant and depreciate the assets using the current depreciation rates until the FPSC approves Tampa Electric’s next depreciation and dismantlement study. In addition, Tampa Electric plans to retire Big Bend Unit 2 in 2021 early as part of the modernization project.

On April 28, 2020, the FPSC approved Tampa Electric’s request for a mid-course adjustment to its fuel and capacity charges due to a decline in expected fuel commodity and capacity costs in 2020. The adjustment was effective beginning with June 2020 customer bills.

BLPC

In December 2018, as a result of the enactment of the Income Tax Amendment Act in Barbados, BLPC was required to remeasure its deferred income tax liability at a new lower corporate income tax rate. At that time, BLPC deferred $6.9 million USD of the recovery, all of which was recognized in earnings in Q1 2020.

Grand Bahama Power Company

On September 1, 2019, Hurricane Dorian struck Grand Bahama Island causing significant damage across the island. In January 2020, the GBPA approved the recovery of approximately $15 million USD of restoration costs related to GBPC’s self-insured assets. As of June 30, 2020, $14 million USD of these costs were incurred, and recorded as a regulatory asset. Recovery of the regulatory asset, due to start on April 1, 2020, has been temporarily suspended as a result of the economic impacts of COVID-19 on Grand Bahama. This recovery is now expected to start on October 1, 2020.

16.

RELATED PARTY TRANSACTIONS

In the ordinary course of business, Emera provides energy, construction 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 $27 million for the three months ended June 30, 2020 (2019 - $27 million) and $55 million for the six months ended June 30, 2020 (2019 - $54 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.

●

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, 2020 (2019 - $16 million) and $11 million for the six months ended June 30, 2020 (2019 - $34 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, 2020 and at December 31, 2019.

17.

RECEIVABLES AND OTHER CURRENT ASSETS

Receivables and other current assets consisted of the following:


As at millions of Canadian dollars		June 30 2020		December 31 2019
Customer accounts receivable – billed	$	527	$	603
Customer accounts receivable – unbilled		239		265
Allowance for doubtful accounts		(19)		(9)
Capitalized transportation capacity (1)		145		272
Income tax receivable		156		118
Prepaid expenses		104		48
Other		173		189
	$	1,325	$	1,486

(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract.

18.

EMPLOYEE BENEFIT PLANS

Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, New Mexico, Barbados, Dominica and Grand Bahama Island. For details of the Company’s employee benefit plan, refer to note 20 in Emera’s 2019 annual audited consolidated financial statements. Refer to note 1 “Use of Management Estimates – Pension and Other Post-Retirement Employee Benefits”.

Emera’s net periodic benefit cost included the following:


For the millions of Canadian dollars		Three months ended June 30				Six months ended June 30
		2020		2019		2020		2019
Defined benefit pension plans
Service cost	$	12	$	12	$	24	$	24
Non-service cost
Interest cost		21		26		43		52
Expected return on plan assets		(36)		(38)		(73)		(75)
Current year amortization of:
Actuarial losses		3		4		7		8
Regulatory asset		7		5		14		10
Settlements and curtailments		-		1		-		1
Total non-service costs		(5)		(2)		(9)		(4)
Total defined benefit pension plans		7		10		15		20
Non-pension benefit plans
Service cost		1		1		2		2
Non-service cost
Interest cost		3		3		6		7
Expected return on plan assets		(1)		-		(1)		(1)
Current year amortization of:
Regulatory asset		-		(1)		-		(3)
Total non-service costs		2		2		5		3
Total non-pension benefit plans		3		3		7		5
Total defined benefit plans	$	10	$	13	$	22	$	25

Emera’s contributions related to these defined-benefit plans for the three months ended June 30, 2020 were $14 million (2019 – $18 million), and for the six months ended June 30, 2020 were $30 million (2019 – $34 million). Annual employer contributions to the defined benefit pension plans are estimated to be $39 million for 2020.

19. SHORT-TERM DEBT

Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-revolving credit facilities and short-term notes. For details regarding short-term debt refer to note 22 in Emera’s 2019 annual audited consolidated financial statements, and below for 2020 short-term debt financing activity.

Recent Significant Financing Activity by Segment

Florida Electric Utilities

On February 6, 2020, TEC entered into a $300 million USD non-revolving credit agreement with a maturity date of February 4, 2021. The credit agreement contains customary representations and warranties, events of default, financial and other covenants and bears interest at LIBOR, prime rate or the federal funds rate, plus a margin.

Other

On February 28, 2020, TECO Energy/Finance extended the maturity date of its $500 million USD credit facility from March 5, 2020 to July 3, 2020. There were no other significant changes in commercial terms from the prior agreement. Using funds from the sale of Emera Maine, on April 3, 2020, TECO Energy/Finance repaid $200 million USD of the term loan and the remaining $300 million USD was repaid on June 30, 2020.

20. LONG-TERM DEBT

For details regarding long-term debt, refer to note 24 in Emera’s 2019 annual audited consolidated financial statements, and below for 2020 long-term debt financing activity.

Recent Significant Financing Activity by Segment

Canadian Electric Utilities

On April 24, 2020, NSPI completed a $300 million 30-year unsecured notes issuance. The notes bear interest at a rate of 3.31 per cent and have a maturity date of April 25, 2050.

Other Electric Utilities

On May 20, 2020, GBPC entered into a $22 million USD non-revolving term loan with a maturity date of May 20, 2025. The loan bears interest at a rate of 90-day LIBOR plus a margin. On May 22, 2020, proceeds from this loan were used to repay $22 million USD senior notes upon maturity.

On May 20, 2020, GBPC entered into a $15 million BSD ($15 million USD) non-revolving term loan with a maturity date of May 20, 2025. The loan bears interest at a rate of 4.00 per cent.

On May 18, 2020, BLPC received an advance of $27 million BBD ($13 million USD) on a $110 million BBD ($55 million USD) non-revolving term loan. The loan bears interest at a rate of 2.05 per cent and has a 5-year term. At June 30, 2020, $67 million BBD ($33 million USD) was drawn against this facility.

Other

On March 13, 2020, TECO Finance repaid a $300 million USD note upon maturity. The note was repaid using existing credit facilities.

21. COMMITMENTS AND CONTINGENCIES

A.	Commitments

As at June 30, 2020, contractual commitments (excluding pensions and other post-retirement obligations, convertible debentures, long-term debt and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following:


millions of Canadian dollars	2020		2021		2022		2023		2024		Thereafter		Total

Purchased power (1)	$	142	$	217	$	218	$	216	$	219	$	1,905	$	2,917

Transportation (2)		296		430		379		316		283		2,673		4,377

Capital projects (3)		251		166		112		93		–		–		622

Fuel, gas supply and storage		274		217		41		6		1		–		539

Long-term service agreements (4)		52		23		23		21		29		70		218

Equity investment commitments (5)		–		240		–		–		–		–		240

Leases and other (6)		10		20		19		19		16		131		215

Demand side management		17		41		43		–		–		–		101

	$	1,042	$	1,354	$	835	$	671	$	548	$	4,779	$	9,229

(1) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths.

(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.

(3) Includes $418 million of commitments related to Tampa Electric’s solar, Big Bend Power Station modernization and AMI projects.

(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) Emera has a commitment to make equity contributions to the Labrador Island Link Limited Partnership.

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

On March 17, 2020, Nalcor announced that it had paused construction activities at the Muskrat Falls site in response to the COVID-19 pandemic. As a result of the effects of COVID-19 on project execution, Nalcor declared force majeure under various project contracts, including formal notification to NSPML. Nalcor resumed work in May 2020 and is assessing the impact of the construction pause on its completion schedule.

NSPML expects to file a final cost assessment with the UARB upon commencement of the NS Block of energy from Muskrat Falls. On July 31, 2020, NSPML filed an interim assessment application with the UARB requesting recovery of 2021 costs of approximately $172 million from NSPI, with a decision expected in Q4 2020.

NSPI has a contractual obligation to pay NSPML for the use of the Maritime Link over approximately 37 years from its January 15, 2018 in-service date. The UARB approved payment for 2020 is $145 million subject to a $10 million holdback and as at June 30, 2020, $53 million has been paid. As part of NSPI’s 2020-2022 fuel stability plan, rates have been set to include the $145 million approved for 2020 and estimated amounts of $164 million and $162 million for 2021 and 2022, respectively. These estimated amounts are subject to review and approval by the UARB. The timing and amounts payable to NSPML for the remainder of the 37-year commitment period are dependent on regulatory filings with the UARB.

Emera has committed to obtain certain transmission rights for Nalcor Energy, if requested, to enable them to transmit energy which is not otherwise used in Newfoundland 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, and continuing for 50 years. As transmission rights are contracted, Emera includes the obligations within “Leases and other” in the above table.

B.	Legal Proceedings

TECO Guatemala Holdings (“TGH”)

In 2013, the International Centre for the Settlement of Investment Disputes (“ICSID”) Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, against the Republic of Guatemala (“Guatemala”) under the Dominican Republic Central America – United States Free Trade Agreement, issued an award in the case (“the Award”). The ICSID Tribunal unanimously found in favour of TGH and awarded damages to TGH of approximately $21 million USD, plus interest from October 21, 2010 at a rate equal to the U.S. prime rate plus two per cent. This award was upheld in subsequent annulment proceedings in 2016 and, in addition, TGH’s application for partial annulment of the award was granted, and Guatemala was ordered to pay certain costs relating to the annulment proceedings. As a result, TGH had the right to resubmit its arbitration claim against Guatemala to seek additional damages (in addition to the previously awarded $21 million USD), as well as additional interest on the $21 million USD, and its full costs relating to the original arbitration and the new arbitration proceeding.

On September 23, 2016, TGH filed a request for resubmission to arbitration. A new tribunal was constituted, and the matter was fully briefed. A hearing was held in March 2019. On May 13, 2020, the second tribunal awarded TGH additional damages and costs against Guatemala of more than $35 million USD plus interest.

In addition, TGH sued Guatemala in Washington, D.C. court to enforce the previously awarded $21 million USD owing. Guatemala’s motion to dismiss the enforcement action was denied. On October 1, 2019, the court granted TGH’s motion for summary judgment which will allow TGH to seek collection of the award plus interest when the order is final. Guatemala has appealed that decision. Results to date do not reflect any benefit.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party (“PRP”) for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as at June 30, 2020, TEC has estimated its financial liability to be $29 million ($21 million USD), primarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Condensed Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs. Other factors that could impact these estimates include additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in base rate proceedings.

Emera Maine

On March 24, 2020, the Company completed the sale of Emera Maine. Emera has no remaining obligations with respect to the legal proceedings previously disclosed in note 26 of Emera’s 2019 annual audited consolidated financial statements. No new or additional reserves were made in 2020 with respect to any of the four complaints filed with the Federal Energy Regulatory Commission.

Other Legal Proceedings

Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company.

C.	Principal Financial Risks and Uncertainties

Emera believes the following principal financial risks could materially affect the Company in the normal course of business. Risks associated with derivative instruments and fair value measurements are discussed in note 13 and note 14.

Sound risk management is an essential discipline for running the business efficiently and pursuing the Company’s strategy successfully. Emera has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach to risk management.

Public Health Risk

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

Any adverse changes in general economic and market conditions arising as a result of a public health threat could negatively impact demand for electricity and natural gas, revenue, operating costs, timing and extent of capital expenditures, results of financing efforts, or credit risk and counterparty risk; which could result in a material adverse effect on the Company’s business.

The extent of the evolving COVID-19 pandemic and its future impact on the Company is uncertain. The Company maintains pandemic and business contingency plans in each of its operations to manage and help mitigate the impact of any such public health threat. The Company’s top priority continues to be the health and safety of its customers and employees. In Q1 2020, Emera activated its company-wide pandemic and business continuity plans, including travel restrictions, directing employees to work remotely whenever possible, restricting access to operating facilities, physical distancing and implementing additional protocols (including the expanded use of personal protective equipment) for work within customers’ premises. The Company is monitoring recommendations by local and national public health authorities related to COVID-19 and is adjusting operational requirements as needed.

Foreign Exchange Risk

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

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

The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries do not impact net income as they are reported in AOCI.

Liquidity and Capital Market Risk

Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs will be financed through internally generated cash flows, select asset sales, short-term credit facilities, and ongoing access to capital markets. Cash flows generated from the sale of select assets are dependent on the market for the assets, acceptable pricing and the timing of the close of any sales. The Company reasonably expects liquidity sources to exceed capital needs.

Emera’s access to capital and cost of borrowing is subject to a number of risk factors including financial market conditions and ratings assigned by credit rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan requires significant capital investments in property, plant and equipment. Emera is subject to risk with changes in interest rates that could have an adverse effect on the cost of financing. Inability to access cost-effective capital could have a material impact on Emera’s ability to fund its growth plan. The Company’s future access to capital and cost of borrowing may be impacted by possible continued COVID-19 related market disruptions.

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

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

Interest Rate Risk

Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter into interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt. Future interest rates may be impacted by possible continued COVID-19 related market disruptions.

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

Commodity Price Risk

A large portion of the Company’s fuel supply comes from international suppliers and is subject to commodity price risk. The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks. Fuel contracts may be exposed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk through the use of financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable. In addition, the adoption and implementation of fuel adjustment mechanisms in its rate-regulated subsidiaries has further helped manage this risk, as the regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred fuel costs.

Income Tax Risk

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

D.	Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2019 audited annual consolidated financial statements, with updates as noted below:

The Company has standby letters of credit and surety bonds in the amount of $35 million USD (December 31, 2019 - $82 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually as required.

Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The expiry date of this letter of credit was extended to June 2021. The amount committed as at June 30, 2020 was $63 million (December 31, 2019 - $52 million).

On May 15, 2020, the Company issued a guarantee of up to $60 million USD relating to outstanding notes of GBPC. The guarantee was reduced to $35 million USD upon repayment of certain notes, by GBPC, on May 22, 2020.

22. CUMULATIVE PREFERRED STOCK

For details regarding cumulative preferred stock refer to note 27 in Emera’s 2019 annual audited financial statements, with updates as noted below:

On July 9, 2020, Emera announced that it would not redeem the currently outstanding Cumulative Rate Reset Preferred Shares, Series A (“Series A Shares”) or the Cumulative Floating Rate First Preferred Shares, Series B (“Series B Shares”) on August 15, 2020 (the “Conversion Date”). There are currently 3,864,636 Series A Shares and 2,135,364 Series B Shares outstanding.

On July 16, 2020, Emera announced a dividend rate of 2.182 per cent per annum on the Series A Shares during the five-year period commencing on August 15, 2020 and ending on (and inclusive of) August 14, 2025 ($0.1364 per Series A Share per quarter). Emera also announced a dividend rate of 2.021 per cent on the Series B Shares for the three-month period commencing on August 15, 2020 and ending on (and inclusive of) November 14, 2020 ($0.1274 per Series B Share for the quarter).

During the conversion period between July 16, 2020 and July 31, 2020, the holders of Series A Shares had the right, at their option to convert all or any of their Series A Shares, on a one-for-one basis, into Series B Shares and the holders of Series B Shares had the right, at their option to convert all or any of their Series B Shares, on a one-for-one basis, into Series A Shares. On the Conversion Date, Emera expects that there will be 4,866,814 Series A Shares and 1,133,186 Series B Shares outstanding.

23. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


For the	Six months ended June 30
millions of Canadian dollars	2020		2019
Changes in non-cash working capital:

Inventory	$	5	$	8

Receivables and other current assets		81		349

Accounts payable		(144)		(279)

Other current liabilities		(17)		(46)

Total non-cash working capital	$	(75)	$	32

Supplemental disclosure of non-cash activities:

Dividends payable	$	162	$	-

Common share dividends reinvested	$	93	$	96

Decrease (increase) in accrued capital expenditures	$	38	$	(10)

24. VARIABLE INTEREST ENTITIES

The Company performs ongoing analysis to assess whether it holds any Variable Interest Entities (“VIE”) or whether any reconsideration events have arisen with respect to existing VIE’s. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly owned facilities.

VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera has an investment in a VIE but is not deemed the primary beneficiary, the VIE is accounted for using the equity method.

Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have the controlling financial interest of NSPML. When the critical milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial reporting purposes as they have authority over the majority of the direct activities that are expected to most significantly impact the economic performance of Maritime Link. Thus, Emera began recording the Maritime Link as an equity investment.

BLPC has established a Self-Insurance Fund (“SIF”), primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, the activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s consolidated VIE in the SIF is recorded as “Other long-term assets”, “Restricted cash” and “Regulatory liabilities” on the Condensed Consolidated Balance Sheets. Amounts included in restricted cash represent the cash portion of funds required to be set aside for the BLPC SIF.

The Company has identified certain long-term purchase power agreements that meet the definition of variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.

The following table provides information about Emera’s portion of material unconsolidated VIEs:

As at

June 30, 2020

December 31, 2019

millions of Canadian dollars

Total
assets

Maximum
exposure to
loss

Total
assets

Maximum
exposure to
loss

Unconsolidated VIEs in which Emera has variable interests

NSPML (equity accounted)

558

554

25. COMPARATIVE INFORMATION

These financial statements contain certain reclassifications of prior period amounts to be consistent with the current period presentation, with no effect on net income.

26. SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through August 11, 2020, the date the financial statements were issued.