Emera 6K Current report | EMRAF 17 Nov 20

Exhibit 99.2

EMERA INCORPORATED

Unaudited Condensed Consolidated

Interim Financial Statements

September 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 September 30				Nine months ended September 30
	2020		2019		2020		2019

Operating revenues
Regulated electric	$	1,101	$	1,220	$	3,352	$	3,598
Regulated gas		192		199		730		785
Non-regulated		(130)		(120)		(113)		112
Total operating revenues (note 6)		1,163		1,299		3,969		4,495

Operating expenses
Regulated fuel for generation and purchased power		319		388		1,041		1,207
Regulated cost of natural gas		40		52		189		249
Non-regulated fuel for generation and purchased power		(1)		(4)		3		63
Operating, maintenance and general		334		367		1,046		1,076
Provincial, state and municipal taxes		81		88		243		258
Depreciation and amortization		217		226		664		678
Total operating expenses		990		1,117		3,186		3,531

Income from operations		173		182		783		964

Income from equity investments (note 7)		32		38		113		118

Other income (expenses), net (note 8)		21		(8)		608		11

Interest expense, net		163		183		520		557

Income before provision for income taxes		63		29		984		536

Income tax expense (recovery) (note 9)		(21)		(49)		284		18

Net income		84		78		700		518

Non-controlling interest in subsidiaries		-		1		1		3

Preferred stock dividends		-		22		34		45

Net income attributable to common shareholders	$	84	$	55	$	665	$	470

Weighted average shares of common stock outstanding (in millions) (note 11)
Basic		248.4		241.0		246.6		238.9
Diluted		248.7		242.4		247.0		240.3

Earnings per common share (note 11)
Basic	$	0.34	$	0.23	$	2.70	$	1.97
Diluted	$	0.34	$	0.23	$	2.69	$	1.96

Dividends per common share declared	$	-	$	1.2000	$	1.8375	$	2.3750

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 September 30				Nine months ended September 30
	2020		2019		2020		2019

Net income	$	84	$	78	$	700	$	518

Other comprehensive income (loss), net of tax

Foreign currency translation adjustment (1)		(189)		95		207		(243)

Unrealized gains (losses) on net investment hedges (2) (3)		34		(19)		(41)		48

Cash flow hedges
Net derivative gains (losses)		1		-		(1)		3
Less: reclassification adjustment for losses (gains) included in income		-		1		2		3
Net effects of cash flow hedges		1		1		1		6

Net change in unrecognized pension and post-retirement benefit obligation (4)		4		3		2		11

Other comprehensive income (loss) (5)		(150)		80		169		(178)

Comprehensive income (loss)		(66)		158		869		340

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

Comprehensive income (loss) of Emera Incorporated	$	(66)	$	157	$	867	$	338

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

(1) Net of tax recovery of $4 million (2019 - nil) for the three months ended September 30, 2020 and tax expense of $2 million (2019 – nil) for the nine months ended September 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 September 30, 2020 and tax recovery of $1 million (2019 – nil) for the nine months ended September 30, 2020.

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

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

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)


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

Assets

Current assets
Cash and cash equivalents	$	286	$	222
Restricted cash (note 24)		49		51
Inventory		475		467
Derivative instruments (notes 13 and 14)		61		54
Regulatory assets (note 15)		126		121
Receivables and other current assets (note 17)		1,313		1,486
Assets held for sale (note 4)		-		85
		2,310		2,486

Property, plant and equipment, net of accumulated depreciation and amortization of $8,846 and $8,295, respectively		19,764		18,167

Other assets
Deferred income taxes		238		186
Derivative instruments (notes 13 and 14)		28		33
Regulatory assets (note 15)		1,421		1,431
Net investment in direct financing lease		470		473
Investments subject to significant influence (note 7)		1,353		1,312
Goodwill		5,993		5,835
Other long-term assets		341		300
Assets held for sale (note 4)		-		1,619
		9,844		11,189

Total assets	$	31,918	$	31,842

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited) – Continued


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

Liabilities and Equity

Current liabilities
Short-term debt (note 19)	$	1,545	$	1,537
Current portion of long-term debt (note 20)		700		501
Accounts payable		1,094		1,118
Derivative instruments (notes 13 and 14)		331		268
Regulatory liabilities (note 15)		187		295
Other current liabilities		427		333
Liabilities associated with assets held for sale (note 4)		-		114

		4,284		4,166

Long-term liabilities
Long-term debt (note 20)		13,385		13,679
Deferred income taxes		1,639		1,285
Derivative instruments (notes 13 and 14)		105		102
Regulatory liabilities (note 15)		1,935		1,886
Pension and post-retirement liabilities (note 18)		434		460
Other long-term liabilities		833		764
Long-term liabilities associated with assets held for sale (note 4)		-		899
		18,331		19,075

Equity
Common stock (note 10)		6,541		6,216
Cumulative preferred stock (note 22)		1,004		1,004
Contributed surplus		78		78
Accumulated other comprehensive income (note 12)		263		95
Retained earnings		1,382		1,173
Total Emera Incorporated equity		9,268		8,566
Non-controlling interest in subsidiaries		35		35
Total equity		9,303		8,601

Total liabilities and equity	$	31,918	$	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	Nine months ended September 30
millions of Canadian dollars	2020		2019

Operating activities

Net income	$	700	$	518

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		678		684
Income from equity investments, net of dividends		(58)		(60)
Allowance for equity funds used during construction		(32)		(14)
Deferred income taxes, net		322		82
Net change in pension and post-retirement liabilities		(20)		(26)
Regulated fuel adjustment mechanism		(33)		(20)
Net change in fair value of derivative instruments		66		(51)
Net change in regulatory assets and liabilities		(53)		19
Net change in capitalized transportation capacity		69		42
Gain on sale (excluding transaction costs) and impairment charges		(578)		-
Other operating activities, net		40		8

Changes in non-cash working capital (note 23)		139		128

Net cash provided by operating activities		1,240		1,310

Investing activities

Proceeds from dispositions (note 4)		1,401		866

Additions to property, plant and equipment		(1,935)		(1,647)

Other investing activities		(2)		(5)

Net cash used in investing activities		(536)		(786)

Financing activities
Change in short-term debt, net		252		(188)
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		841
Retirement of long-term debt		(485)		(851)
Net repayments under committed credit facilities		(326)		(165)
Issuance of common stock, net of issuance costs		181		151
Dividends on common stock		(309)		(278)
Dividends on preferred stock		(33)		(34)
Other financing activities		(8)		(22)

Net cash used in financing activities		(595)		(546)

Effect of exchange rate changes on cash, cash equivalents, and restricted cash		(48)		(13)

Net increase (decrease) in cash, cash equivalents, restricted cash and assets held for sale		61		(35)

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	$	335	$	337

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

Cash	$	265	$	266

Short-term investments		21		7

Restricted cash		49		63

Assets held for sale		-		1

Cash, cash equivalents, restricted cash, and assets held for sale	$	335	$	337

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 September 30, 2020

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

Net income of Emera Incorporated		-		-		-		-		84		-		84

Other comprehensive income (loss), net of tax recovery of $4 million		-		-		-		(150)		-		-		(150)

Common stock issued under purchase plan		53		-		-		-		-		-		53

Issuance of common stock, net of after-tax issuance costs		52		-		-		-		-		-		52

Other		1		-		-		-		-		(1)		-

Balance, September 30, 2020	$	6,541	$	1,004	$	78	$	263	$	1,382	$	35	$	9,303

millions of Canadian dollars

For the nine months ended September 30, 2020

Balance, December 31, 2019	$	6,216	$	1,004	$	78	$	95	$	1,173	$	35	$	8,601

Net income of Emera Incorporated		-		-		-		-		699		1		700

Other comprehensive income (loss), net of tax expense of $1 million		-		-		-		168		-		1		169
Dividends declared on preferred stock (1)		-		-		-		-		(34)		-		(34)

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

Common stock issued under purchase plan		152		-		-		-		-		-		152

Issuance of common stock, net of after-tax issuance costs		151		-		-		-		-		-		151

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

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

Other		2		-		1		-		-		(2)		1

Balance, September 30, 2020	$	6,541	$	1,004	$	78	$	263	$	1,382	$	35	$	9,303

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

(1) 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 September 30, 2019

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

Net income of Emera Incorporated		-		-		-		-		77		1		78

Other comprehensive income (loss), net of tax expense of nil		-		-		-		80		-		-		80

Dividends declared on preferred stock (1)		-		-		-		-		(22)		-		(22)

Dividends declared on common stock ($1.2000/share)		-		-		-		-		(287)		-		(287)

Common stock issued under purchase plan		45		-		-		-		-		-		45

Issuance of common stock, net of after-tax issuance costs		49										-		49

Senior management stock options exercised		10		-		(1)		-		-		-		9

Other		1		-		-		-		-		(1)		-

Balance, September 30, 2019	$	6,115	$	1,004	$	78	$	161	$	980	$	35	$	8,373

millions of Canadian dollars

For the nine months ended September 30, 2019
Balance, December 31, 2018	$	5,816	$	1,004	$	84	$	338	$	1,075	$	41	$	8,358

Net income of Emera Incorporated		-		-		-		-		515		3		518

Other comprehensive income (loss), net of tax expense of $1 million		-		-		-		(177)		-		(1)		(178)

Dividends declared on preferred stock (2)		-		-		-		-		(45)		-		(45)

Dividends declared on common stock ($2.3750/share)		-		-		-		-		(565)		-		(565)

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		146		-		-		-		-		-		146

Issuance of common stock, net of after-tax issuance costs		49		-		-		-		-		-		49

Senior management stock option exercised		103		-		(6)		-		-		-		97

Other		1		-		-		-		-		(3)		(2)

Balance, September 30, 2019	$	6,115	$	1,004	$	78	$	161	$	980	$	35	$	8,373

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

(1) Series A; $0.31940/share, Series B; $0.44060/share, Series C; $0.59012/share, Series E; $0.56250/share, Series F; $0.53125/share and Series H; $0.61250/share

(2) Series A; $0.63880/share, Series B; $0.87270/share, Series C; $1.18024/share, Series E; $1.12500/share, Series F; $1.06250/share and Series H; $1.25500/share

Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)

As at September 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 September 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 48.7 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 continues to work toward project commissioning in 2021. 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 September 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 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, allowance for credit losses, 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 and nine months ended September 30, 2020, the ongoing COVID-19 pandemic has affected all service territories in which Emera operates. The pandemic has generally resulted in lower load and higher operating costs than what otherwise would have been experienced at the Company’s utilities. Some of Emera’s utilities have been impacted more than others. However, on a consolidated basis these unfavourable impacts have not had a material financial impact to net earnings to date primarily due to a favourable change to the mix of sales to residential customer classes. Lower commercial and industrial sales have been partially offset by increased sales to residential customers, which have a higher contribution to fixed cost recovery. 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. 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 and nine months ended September 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 Q3 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 September 30, 2020.

As of September 30, 2020, $5.9 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 September 30, 2020, $72 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 and nine months ended September 30, 2020 associated with this goodwill.

Long-Lived Assets Impairment Assessments

Management considered whether the potential impacts of the COVID-19 pandemic on undiscounted future cash flows could indicate that long-lived assets are not recoverable. As at September 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 $nil and $25 million ($26 million after tax) were recognized on certain assets for the three and nine months ended September 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 include the impact of the COVID-19 pandemic commencing in March 2020.

Receivables and Allowance for Credit Losses

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 credit losses related to accounts receivable after considering historical loss experience, customer deposits, current events, the characteristics of existing accounts and reasonable and supportable forecasts that affect the collectability of the reported amount. Provisions for credit 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, has impacted the aging of customer receivables resulting in higher allowances for credit losses related to 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 interim 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 implemented a project plan in Q2 2020 and has identified impacted financial instruments which primarily include debt and hedging contracts. The Company is in the process of 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.

Guaranteed Debt Securities Disclosure Requirements

In October 2020, the FASB issued ASU 2020-09, Debt (Topic 470): Amendments to SEC Paragraphs pursuant to SEC Release No. 33-10762. The change in the standard aligns with new SEC rules relating to changes to the disclosure requirements for certain registered debt securities that are guaranteed. The changes include simplifying and focusing the disclosure models, enhancing certain narrative disclosures and permitting the disclosures to be made outside of the financial statements. The guidance will be effective for annual reports filed for fiscal years ending after January 4, 2021, with early adoption permitted. The Company is currently evaluating the impact of adoption of the standard on its consolidated financial statements.

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 September 30, 2020

Operating revenues from external customers (1)	$	672	$	324	$	105	$	196	$	(134)	$	-		$	1,163

Inter-segment revenues (1)		2		-		-		1		1		(4)			-

Total operating revenues		674		324		105		197		(133)		(4)			1,163

Regulated fuel for generation and purchased power		135		143		44		-		-		(3)			319

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

Depreciation and amortization		115		59		13		28		2		-			217

Interest expense, net		37		35		6		13		72		-			163

Internally allocated interest (2)		-		-		-		3		(3)		-			-

Operating, maintenance and general (“OM&G”)		137		66		37		79		17		(2)			334

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

Income tax expense (recovery)		33		1		-		6		(61)		-			(21)

Net income (loss) attributable to common shareholders		175		35		6		20		(152)		-			84

For the nine months ended September 30, 2020

Operating revenues from external customers (1)		1,864		1,117		371		742		(125)		-			3,969

Inter-segment revenues (1)		5		-		-		6		11		(22)			-

Total operating revenues		1,869		1,117		371		748		(114)		(22)			3,969

Regulated fuel for generation and purchased power		407		493		148		-		-		(7)			1,041

Regulated cost of natural gas		-		-		-		189		-		-			189

Depreciation and amortization		343		175		57		83		6		-			664

Interest expense, net		116		105		26		43		230		-			520

Internally allocated interest (2)		-		-		-		10		(10)		-			-

OM&G		407		214		120		242		74		(11)			1,046

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

Income tax expense (recovery)		75		13		(8)		36		168		-			284

Net income (loss) attributable to common shareholders		400		164		25		117		(41)		-			665

As at September 30, 2020

Total assets		17,449		6,721		1,456		6,064		1,354		(1,126)	⁽³⁾		31,918

(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 September 30, 2019

Operating revenues from external customers (1)	$	735	$	296	$	189	$	203	$	(124)	$	-		$	1,299

Inter-segment revenues (1)		3		-		-		6		11		(20)			-

Total operating revenues		738		296		189		209		(113)		(20)			1,299

Regulated fuel for generation and purchased power		222		100		73		-		-		(7)			388

Regulated cost of natural gas		-		-		-		52		-		-			52

Depreciation and amortization		112		58		26		28		2		-			226

Interest expense, net		39		36		13		14		81		-			183

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

OM&G		136		88		46		81		29		(13)			367

Income tax expense (recovery)		26		(10)		4		(3)		(66)		-			(49)

Net income (loss) attributable to common shareholders		153		33		23		25		(179)		-			55

For the nine months ended September 30, 2019

Operating revenues from external customers (1)		1,974		1,065		559		797		100		-			4,495

Inter-segment revenues (1)		9		1		-		17		32		(59)			-

Total operating revenues		1,983		1,066		559		814		132		(59)			4,495

Regulated fuel for generation and purchased power		583		431		210		-		-		(17)			1,207

Regulated cost of natural gas		-		-		-		249		-		-			249

Depreciation and amortization		333		171		84		82		8		-			678

Interest expense, net		116		108		39		44		250		-			557

Internally allocated interest (2)		-		-		-		11		(11)		-			-

OM&G		408		230		141		235		103		(41)			1,076

Income tax expense (recovery)		65		(9)		10		31		(79)		-			18

Net income (loss) attributable to common shareholders		339		171		64		132		(236)		-			470

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 September 30, 2020
Regulated
Electric Revenue
Residential	$	404	$	161	$	41	$	-	$	-	$	-	$	606
Commercial		170		93		54		-		-		-		317
Industrial		41		57		6		-		-		-		104
Other electric and regulatory deferrals		54		7		3		-		-		-		64
Other (1)		5		6		1		-		-		(2)		10
Regulated electric revenue		674		324		105		-		-		(2)		1,101
Gas Revenue
Residential		-		-		-		77		-		-		77
Commercial		-		-		-		52		-		-		52
Industrial		-		-		-		13		-		-		13
Finance income (2)(3)		-		-		-		15		-		-		15
Other		-		-		-		36		-		(1)		35
Regulated gas revenue		-		-		-		193		-		(1)		192
Non-Regulated
Marketing and trading margin (4)		-		-		-		-		(12)		-		(12)
Energy sales (4)		-		-		-		-		6		(4)		2
Other		-		-		-		4		4		-		8
Mark-to-market (3)		-		-		-		-		(131)		3		(128)
Non-regulated revenue		-		-		-		4		(133)		(1)		(130)
Total operating revenues	$	674	$	324	$	105	$	197	$	(133)	$	(4)	$	1,163
For the nine months ended September 30, 2020
Regulated
Electric Revenue
Residential	$	1,031	$	607	$	138	$	-	$	-	$	-	$	1,776
Commercial		506		303		180		-		-		-		989
Industrial		135		164		25		-		-		-		324
Other electric and regulatory deferrals		183		24		8		-		-		-		215
Other (1)		14		19		20		-		-		(5)		48
Regulated electric revenue		1,869		1,117		371		-		-		(5)		3,352
Gas Revenue
Residential		-		-		-		338		-		-		338
Commercial		-		-		-		193		-		-		193
Industrial		-		-		-		40		-		(1)		39
Finance income (2)(3)		-		-		-		45		-		-		45
Other		-		-		-		120		-		(5)		115
Regulated gas revenue		-		-		-		736		-		(6)		730
Non-Regulated
Marketing and trading margin (4)		-		-		-		-		16		-		16
Energy sales (4)		-		-		-		-		12		(12)		-
Other		-		-		-		12		13		-		25
Mark-to-market (3)		-		-		-		-		(155)		1		(154)
Non-regulated revenue		-		-		-		12		(114)		(11)		(113)
Total operating revenues	$	1,869	$	1,117	$	371	$	748	$	(114)	$	(22)	$	3,969

(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 September 30, 2019
Regulated
Electric Revenue
Residential	$	430	$	135	$	70	$	-	$	-	$	-	$	635
Commercial		212		91		85		-		-		-		388
Industrial		53		52		10		-		-		2		117
Other electric and regulatory deferrals		38		11		5		-		-		(2)		52
Other (1)		5		7		19		-		-		(3)		28
Regulated electric revenue		738		296		189		-		-		(3)		1,220
Gas Revenue
Residential		-		-		-		75		-		-		75
Commercial		-		-		-		59		-		-		59
Industrial		-		-		-		12		-		-		12
Finance income (2)(3)		-		-		-		15		-		-		15
Other		-		-		-		44		-		(6)		38
Regulated gas revenue		-		-		-		205		-		(6)		199
Non-Regulated
Marketing and trading margin (4)		-		-		-		-		(23)		-		(23)
Energy sales (4)		-		-		-		-		(2)		(1)		(3)
Capacity		-		-		-		-		2		-		2
Other		-		-		-		4		12		(10)		6
Mark-to-market (3)		-		-		-		-		(102)		-		(102)
Non-regulated revenue		-		-		-		4		(113)		(11)		(120)
Total operating revenues	$	738	$	296	$	189	$	209	$	(113)	$	(20)	$	1,299
For the nine months ended September 30, 2019
Regulated
Electric Revenue
Residential	$	1,052	$	552	$	203	$	-	$	-	$	-	$	1,807
Commercial		559		298		256		-		-		-		1,113
Industrial		155		160		33		-		-		2		350
Other electric and regulatory deferrals		200		35		12		-		-		(2)		245
Other (1)		17		21		55		-		-		(10)		83
Regulated electric revenue		1,983		1,066		559		-		-		(10)		3,598
Gas Revenue
Residential		-		-		-		357		-		-		357
Commercial		-		-		-		218		-		-		218
Industrial		-		-		-		37		-		-		37
Finance income (2)(3)		-		-		-		44		-		-		44
Other		-		-		-		146		-		(17)		129
Regulated gas revenue		-		-		-		802		-		(17)		785
Non-Regulated
Marketing and trading margin (4)		-		-		-		-		3		-		3
Energy sales (4)		-		-		-		-		78		(7)		71
Capacity		-		-		-		-		38		-		38
Other		-		-		-		12		30		(25)		17
Mark-to-market (3)		-		-		-		-		(17)		-		(17)
Non-regulated revenue		-		-		-		12		132		(32)		112
Total operating revenues	$	1,983	$	1,066	$	559	$	814	$	132	$	(59)	$	4,495

(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 September 30, 2020, the aggregate amount of the transaction price allocated to remaining performance obligations was $334 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


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

LIL (1)	$	615	$	579	$	13	$	11	$	37	$	33		48.7

NSPML		560		554		11		9		38		35		100.0

M&NP (2)		133		138		5		5		14		17		12.9

Lucelec (2)		45		41		1		-		3		2		19.5

Bear Swamp (3)		-		-		2		11		21		29		50.0

Other Investments		-		-		-		2		-		2

	$	1,353	$	1,312	$	32	$	38	$	113	$	118

(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 2015. Bear Swamp’s credit investment balance of $130 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	September 30		December 31
millions of Canadian dollars	2020		2019

Balance Sheet

Current assets	$	72	$	69

Property, plant and equipment		1,641		1,671

Regulatory assets		223		177

Non-current assets		32		32

Total assets	$	1,968	$	1,949

Current liabilities	$	66	$	23

Long-term debt		1,248		1,288

Non-current liabilities		94		84

Equity		560		554

Total liabilities and equity	$	1,968	$	1,949

8. OTHER INCOME (EXPENSES), NET


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

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

Allowance for equity funds used during construction		12		6		32		14

Other		9		(14)		16		(3)

	$	21	$	(8)	$	608	$	11

(1) Refer to note 4 for further details related to the gain on sale of Emera 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	Three months ended						Nine months ended
millions of Canadian dollars	September 30						September 30
	2020			2019			2020			2019

Income before provision for income taxes	$	63		$	29		$	984		$	536

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

Income taxes, at statutory income tax rate		18			9			290			166

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

Amortization of deferred income tax regulatory liabilities		(14)			(13)			(41)			(29)

Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities		(8)			(16)			(35)			(50)

Foreign tax rate variance		(10)			(15)			(27)			(40)

Tax effect of equity earnings		(4)			(3)			(12)			(12)

Change in treatment of NMGC net operating loss carryforwards		-			(7)			-			(7)

Other		(3)			(4)			7			(10)

Income tax expense (recovery)	$	(21)		$	(49)		$	284		$	18

Effective income tax rate		(33)	%		(169)	%		29	%		3	%

The year-over-year increase in the effective income tax rate was primarily due to the sale of Emera Maine. Quarter-over-quarter, the increase was due to increased income before provision for income taxes, decreased deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities and a change in treatment of NMGC net operating loss carryforwards in Q3 2019.

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. There have been no material impacts to Emera’s financial position 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 law. 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. As a result, in Q1 2020, the Company reclassified $77 million of AMT credit carryforwards from deferred income tax assets to receivables and other current assets. As at September 30, 2020, the Company had $145 million in receivables and other current assets related to refundable AMT credit carryforwards. This refund was received on October 22, 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) (2)		2.71		151

Issued for cash under Purchase Plans at market rate		2.82		155

Discount on shares purchased under Dividend Reinvestment Plan		-		(3)

Options exercised under senior management share option plan		0.42		20

Employee Share Purchase Plan		-		2

Balance, September 30, 2020		248.43	$	6,541

(1) In Q3 2019 and in the nine months ended September 30, 2019, 880,912 common shares were issued under Emera’s at-the-market program (“ATM program”) at an average price of $56.76 per share for gross proceeds of $50 million ($49 million net of issuance costs).

(2) In Q3 2020, 980,500 common shares were issued under Emera’s ATM program at an average price of $54.43 per share for gross proceeds of $53 million ($53 million net of issuance costs). During the nine months ended September 30, 2020, 2,708,603 common shares were issued under Emera’s ATM program at an average price of $56.62 per share for gross proceeds of $153 million ($151 million net of issuance costs). As at September 30, an aggregate gross sales limit of $347 million remains available for issuance under the ATM program.

As the Q3 2020 dividends were declared by the Board of Directors and recognized in Q2 2020, there were no common share dividends recognized in Q3 2020.

11. EARNINGS PER SHARE

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


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

Numerator

Net income attributable to common shareholders	$	84.3	$	55.0	$	665.4	$	470.3

Diluted numerator		84.3		55.0		665.4		470.3

Denominator

Weighted average shares of common stock outstanding		247.1		239.5		245.3		237.4

Weighted average deferred share units outstanding		1.3		1.5		1.3		1.5

Weighted average shares of common stock outstanding – basic		248.4		241.0		246.6		238.9

Stock-based compensation		0.3		0.6		0.4		0.6

Dividend reinvestment plan		-		0.8		-		0.8

Weighted average shares of common stock outstanding – diluted		248.7		242.4		247.0		240.3

Earnings per common share

Basic	$	0.34	$	0.23	$	2.70	$	1.97

Diluted	$	0.34	$	0.23	$	2.69	$	1.96

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 nine months ended September 30, 2020

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

Other comprehensive income (loss) before reclassifications		206		(41)		(1)		-		-		164

Amounts reclassified from accumulated other comprehensive income loss (gain)		-		-		2		-		2		4

Net current period other comprehensive income (loss)		206		(41)		1		-		2		168

Balance, September 30, 2020	$	459	$	(37)	$	-	$	(1)	$	(158)	$	263

For the nine months ended September 30, 2019

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

Other comprehensive income (loss) before reclassifications		(242)		48		3		-		-		(191)

Amounts reclassified from accumulated other comprehensive income loss (gain)		-		-		3		-		11		14

Net current period other comprehensive income (loss)		(242)		48		6		-		11		(177)

Balance, September 30, 2019	$	412	$	(26)	$	(1)	$	(1)	$	(223)	$	161

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


For the		Three months ended September 30				Nine months ended September 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	$	3

Total		$	-	$	1	$	2	$	3

Net change in unrecognized pension and post-retirement benefit costs
Actuarial losses (gains)	Other income (expenses), net	$	5	$	4	$	11	$	12
Past service costs (gains)	Other income (expenses), net		(1)		(1)		(1)		(1)
Amounts reclassified into obligations	Pension and post-retirement liabilities		-		1		(8)		1

Total before tax			4		4		2		12

	Income tax recovery		-		-		-		(1)

Total net of tax		$	4	$	4	$	2	$	11

Total reclassifications out of AOCI, net of tax, for the period		$	4	$	5	$	4	$	14

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	September 30		December 31		September 30		December 31
millions of Canadian dollars	2020		2019		2020		2019
Cash flow hedges

Foreign exchange forwards	$	-	$	-	$	-	$	1

		-		-		-		1
Regulatory deferral

Commodity swaps and forwards
Coal purchases		2		8		20		39
Power purchases		17		23		35		36
Natural gas purchases and sales		10		2		2		5
Heavy fuel oil purchases		1		1		12		-

Foreign exchange forwards		1		2		3		6

		31		36		72		86

HFT derivatives

Power swaps and physical contracts		11		19		11		22

Natural gas swaps, futures, forwards, physical contracts		108		151		422		381

		119		170		433		403

Other derivatives

Equity derivatives		-		1		2		-

Foreign exchange forwards		11		-		1		-

		11		1		3		-

Total gross current derivatives		161		207		508		490

Impact of master netting agreements with intent to settle net or simultaneously		(72)		(120)		(72)		(120)

		89		87		436		370

Current		61		54		331		268

Long-term		28		33		105		102

Total derivatives	$	89	$	87	$	436	$	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	September 30		December 31		September 30		December 31
millions of Canadian dollars	2020		2019		2020		2019

Regulatory deferral	$	4	$	8	$	4	$	8

HFT derivatives		68		112		68		112
Total impact of master netting agreements with intent to settle net or simultaneously	$	72	$	120	$	72	$	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:


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

		Foreign Exchange Forwards				Foreign Exchange Forwards

Realized (loss) in operating revenue – regulated	$	-	$	(1)	$	(2)	$	(3)

Total (losses) in net income	$	-	$	(1)	$	(2)	$	(3)

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

						Foreign Exchange Forwards

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

In Q3 2020, the Company reclassified $1 million of unrealized losses into net income due to the settlement of the underlying hedged transactions.

As at September 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	$	4

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 September 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	$	9		$	(2	)	$	(25	)	$	5

Unrealized gain (loss) in regulatory liabilities		11			(10	)		10			2

Realized gain in regulatory assets		(1	)		-			-			-

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

Realized (gain) loss in inventory (1)		3			-			(4	)		(1	)

Realized (gain) loss in regulated fuel for generation and purchased power (2)		8			-			1			(1	)

Total change in derivative instruments	$	33		$	(12	)	$	(21	)	$	5

(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	Nine months ended September 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	$	(41	)	$	3		$	(71	)	$	(2	)

Unrealized gain (loss) in regulatory liabilities		8			5			4			(6	)

Realized (loss) in regulatory liabilities		13			-			1			-

Realized (gain) loss in inventory (1)		6			(3	)		(28	)		(9	)

Realized (gain) loss in regulated fuel for generation and purchased power (2)		21			(3	)		(1	)		(6	)

Total change in derivative instruments	$	7		$	2		$	(95	)	$	(23	)

(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 September 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)	7	21

Power (MWh)	-	3

Heavy fuel oil (bbls)	-	1

Coal (metric tonnes)	-	1

Foreign Exchange Swaps and Forwards

As at September 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)	$	45	$	259

Weighted average rate		1.3377		1.3381

% of USD requirements		59%		61%

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						Nine months ended
millions of Canadian dollars	September 30						September 30
	2020			2019			2020			2019

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

Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues		(186	)		(67	)		36			180

Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power		1			1			(3	)		(4	)

	$	(186	)	$	(68	)	$	32		$	176

As at September 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)	168	240	57	41	26

Natural gas sales (Mmbtu)	192	280	50	9	1

Power purchases (MWh)	1	1	-	-	-

Power sales (MWh)	1	-	-	-	-

Other Derivatives

As at September 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 $209 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 September 30
millions of Canadian dollars				2020					2019

		Foreign Exchange Forwards			Equity Derivatives			Foreign Exchange Forwards		Equity Derivatives

Unrealized gain in operating, maintenance and general	$	-		$	4		$	-	$	11

Unrealized gain in other income (expense)		5			-			-		-

Total gains in net income	$	5		$	4		$	-	$	11

For the				Nine months ended September 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	$	-		$	(3	)	$	-	$	34

Unrealized gain in other income (expense)		9			-			-		-

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

Total gains (losses) in net income	$	5		$	(3	)	$	-	$	34

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 September 30, 2020, the Company had $146 million (December 31, 2019 - $115 million) in financial assets considered to be past due, which have been outstanding for an average 76 days. The fair value of these financial assets is $120 million (December 31, 2019 - $106 million), the difference of which is included in the allowance for credit losses. 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	September 30 2020		December 31 2019

Cash collateral provided to others	$	86	$	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 September 30, 2020, the total fair value of these derivatives, in a liability position, was $436 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	September 30, 2020
millions of Canadian dollars	Level 1			Level 2			Level 3			Total

Assets

Regulatory deferral

Commodity swaps and forwards
Power purchases	$	16		$	-		$	-		$	16
Natural gas purchases and sales		4			6			-			10

Foreign exchange forwards		-			1			-			1

		20			7			-			27

HFT derivatives

Power swaps and physical contracts		4			1			1			6

Natural gas swaps, futures, forwards, physical contracts and related transportation		2			28			15			45

		6			29			16			51

Other derivatives

Foreign exchange forwards		-			11			-			11

		-			11			-			11

Total assets		26			47			16			89

Liabilities

Regulatory deferral

Commodity swaps and forwards
Coal purchases		-			18			-			18
Power purchases		34			-			-			34
Heavy fuel oil purchases		5			6			-			11
Natural gas purchases and sales		-			2			-			2

Foreign exchange forwards		-			3			-			3

		39			29			-			68

HFT derivatives

Power swaps and physical contracts		4			1			1			6

Natural gas swaps, futures, forwards and physical contracts		3			29			327			359

		7			30			328			365

Other derivatives

Foreign exchange forwards		-			1			-			1

Equity derivatives		2			-			-			2

		2			1			-			3

Total liabilities		48			60			328			436

Net assets (liabilities)	$	(22	)	$	(13	)	$	(312	)	$	(347	)


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 September 30, 2020 was as follows:


	HFT Derivatives
millions of Canadian dollars	Power		Natural gas		Total

Balance, beginning of period	$	1	$	11	$	12

Total realized and unrealized gains included in non-regulated operating revenues		-		4		4

Balance, September 30, 2020	$	1	$	15	$	16

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

HFT Derivatives

millions of Canadian dollars

Power

Natural

gas

Total

Balance, beginning of period

146

Total realized and unrealized gains included in non-regulated operating revenues

181

182

Balance, September 30, 2020

327

328

The change in the fair value of the Level 3 financial assets for the nine months ended September 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 included in non-regulated operating revenues		2			1		3

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

Balance, September 30, 2020	$	1		$	15	$	16

The change in the fair value of the Level 3 financial liabilities for the nine months ended September 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 included in non-regulated operating revenues		2			78		80

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

Balance, September 30, 2020	$	1		$	327	$	328

The Company evaluates observable inputs of market data on a quarterly basis to determine if transfers between levels is appropriate. For the three months ended September 30, 2020, there were no transfers between levels. For the nine months ended September 30, 2020, transfers out of Level 3 in Q2 2020 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	September 30, 2020
millions of Canadian dollars	Fair Value			Valuation Technique		Unobservable Input		Range		Weighted average (1)

Assets

HFT derivatives – Power swaps and physical contracts	$	1			Modelled pricing		Third-party pricing		$17.94-$68.00		$31.62
							Probability of default		0.02%-30.40%		5.72%
							Discount rate		0.01%-0.81%		0.36%

		1			Modelled pricing		Third-party pricing		$26.40-$37.25		$30.11
							Probability of default		0.21%-0.65%		0.46%
							Discount rate		0.17%-0.48%		0.38%
							Correlation factor		100%-100%		100%

HFT derivatives – Natural gas swaps, futures, forwards, physical contracts		12			Modelled pricing		Third-party pricing		$0.91-$8.04		$2.88
							Probability of default		0.02%-10.11%		1.99%
							Discount rate		0.00%-8.11%		0.38%
		2			Modelled pricing		Third-party pricing		$1.33-$8.47		$3.48
							Basis adjustment		$0.00-$1.29		$0.67
							Probability of default		0.07%-17.73%		5.88%
							Discount rate		0.00%-0.55%		0.21%

Total assets	$	16

Liabilities

HFT derivatives – Power swaps and physical contracts	$	1			Modelled pricing		Third-party pricing		$1.13-$68.00		$44.82
							Own credit risk		0.02%-30.40%		2.65%
							Discount rate		0.01%-0.81%		0.30%
		1			Modelled pricing		Third-party pricing		$15.21-$66.95		$60.26
							Own credit risk		0.02%-0.65%		0.42%
							Discount rate		0.01%-0.51%		0.31%
							Correlation factor		100%-100%		100%

HFT derivatives – Natural gas swaps, futures, forwards and physical contracts		311			Modelled pricing		Third-party pricing		$0.66-$8.04		$4.86
							Own credit risk		0.0.2%-10.11%		0.49%
							Discount rate		0.00%-7.15%		0.35%
		15			Modelled pricing		Third-party pricing		$0.71-$9.33		$4.42
							Basis adjustment		$0.00-$1.29		$0.42
							Own credit risk		0.16%-13.09%		0.62%
							Discount rate		0.00%-0.75%		0.22%

Total liabilities	$	328

Net assets (liabilities)	$	(312	)

(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

September 30, 2020	$	14,085	$	16,669	$	-	$	16,160	$	509	$	16,669

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 $34 million was recorded in Other Comprehensive Income for the three months ended September 30, 2020 (2019 – $19 million loss after-tax). An after-tax foreign currency loss of $41 million was recorded in Other Comprehensive Income for the nine months ended September 30, 2020 (2019 – $48 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	September 30 2020		December 31 2019
Regulatory assets
Deferred income tax regulatory assets	$	873	$	862
Pension and post-retirement medical plan		377		380
Deferrals related to derivative instruments		68		81
Storm restoration regulatory asset		43		38
Cost recovery clauses		31		13
Environmental remediations		29		26
Stranded cost recovery		28		27
Demand side management (“DSM”) deferral		16		19
Unamortized defeasance costs		14		19
Other		68		87
	$	1,547	$	1,552
Current	$	126	$	121
Long-term		1,421		1,431
Total regulatory assets	$	1,547	$	1,552

Regulatory liabilities
Deferred income tax regulatory liabilities	$	962	$	985
Accumulated reserve - cost of removal		908		891
Regulated fuel adjustment mechanism		82		115
Storm reserve		64		62
Cost recovery clauses		47		53
Self-insurance fund (note 24)		29		29
Deferrals related to derivative instruments		26		42
Other		4		4
	$	2,122	$	2,181
Current	$	187	$	295
Long-term		1,935		1,886
Total regulatory liabilities	$	2,122	$	2,181

Tampa Electric

Base Rates

On July 31, 2020, TEC filed its fourth and final solar base rate adjustments (“SoBRAs”) petition along with supporting tariffs representing 46 MW and $8 million USD annually in estimated revenues. On November 3, 2020, the FPSC approved the tariffs on this SoBRAs filing and TEC will begin receiving these revenues in January 2021.

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

Storm Protection Cost Recovery Clause and Settlement Agreement

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 SPP program costs previously recovered in base rates 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 removed from base rates. This settlement agreement was approved on August 10, 2020 and Tampa Electric’s cost recovery will begin January 2021. The current approved plan will apply for the years 2020, 2021 and 2022, and 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, Tampa Electric recognized $4 million USD of this credit in Q3 2020 and $12 million USD year-to-date, with the remaining $4 million USD to be recognized in Q4 2020.

Big Bend Modernization Project

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.

Mid-Course Adjustment to Fuel Recovery

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.

PGS

On October 22, 2020, PGS filed a settlement agreement for approval with the FPSC. The settlement agreement allows for an increase in base rates of $58 million USD annually effective January 2021. The $58 million USD increase includes $24 million USD previously recovered through the cast iron and bare steel replacement rider. The settlement agreement includes an allowed regulatory ROE range of 8.90 per cent to 11.00 per cent with a 9.90 per cent midpoint (2020 - 9.25 per cent to 11.75 per cent with a 10.75 per cent midpoint). The settlement agreement provides PGS with the ability to reverse a total of $34 million USD of accumulated depreciation through 2023 and sets new depreciation rates going into effect January 1, 2021. These depreciation rates are comparatively consistent with PGS’ current overall average depreciation rate. Under the agreement base rates are frozen from January 1, 2021 to December 31, 2023, unless its earned ROE falls below 8.90 per cent before that time, with an allowed equity capital structure of 54.7 per cent. The settlement agreement further addresses tax rate changes. PGS will quantify the future impact of decreases in tax rates on net operating income through a reduction in base revenues within 120 days of when such tax change becomes law. If tax legislation results in a tax rate increase, PGS can establish a regulatory asset to neutralize the impact of the increase in income tax rate to be addressed in PGS’ next base rate proceeding. A decision from the FPSC is expected in 2020.

NMGC

On December 23, 2019, NMGC filed a future year rate case for new rates effective January 2021. On August 25, 2020, NMGC filed a settlement agreement with the NMPRC and, on October 20, 2020, a hearing in front of the Hearing Examiner was held. The proposed new rates reflect the recovery of capital investment in pipelines and related infrastructure and would be expected to result in an increase in revenue of approximately $5 million USD annually. A decision from the NMPRC is expected in 2020.

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 September 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 January 1, 2021.

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 September 30, 2020 (2019 - $26 million) and $82 million for the nine months ended September 30, 2020 (2019 - $80 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 $2 million for the three months ended September 30, 2020 (2019 - $16 million) and $13 million for the nine months ended September 30, 2020 (2019-$50 million).

There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at September 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	September 30 2020		December 31 2019
Customer accounts receivable – billed	$	550	$	603
Customer accounts receivable – unbilled		228		265
Allowance for credit losses		(26)		(9)
Capitalized transportation capacity (1)		181		272
Income tax receivable (2)		153		118
Prepaid expenses		79		48
Other		148		189
	$	1,313	$	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.

(2) At September 30, 2020, includes $145 million related to refundable AMT credit carryforwards. The Company received this refund on October 22, 2020.

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	Three months ended				Nine months ended
millions of Canadian dollars	September 30				September 30
		2020		2019		2020		2019
Defined benefit pension plans
Service cost	$	11	$	12	$	35	$	36
Non-service cost
Interest cost		21		26		64		78
Expected return on plan assets		(34)		(37)		(107)		(112)
Current year amortization of:
Actuarial losses		4		4		11		12
Past service gains		(1)		(1)		(1)		(1)
Regulatory asset		6		5		20		15
Settlements and curtailments		-		-		-		1
Total non-service costs		(4)		(3)		(13)		(7)
Total defined benefit pension plans		7		9		22		29
Non-pension benefit plans
Service cost		1		1		3		3
Non-service cost
Interest cost		2		4		8		11
Expected return on plan assets		-		-		(1)		(1)
Current year amortization of:
Regulatory asset		-		(2)		-		(5)
Total non-service costs		2		2		7		5
Total non-pension benefit plans		3		3		10		8
Total defined benefit plans	$	10	$	12	$	32	$	37

Emera’s pension and non-pension contributions related to these defined-benefit plans for the three months ended September 30, 2020 were $20 million (2019 – $29 million), and for the nine months ended September 30, 2020 were $50 million (2019 – $63 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.

At September 30, 2020, BLPC had drawn $67 million BBD ($33 million USD) against 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.

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 September 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)	$	74	$	218	$	218	$	216	$	219	$	2,024	$	2,969

Transportation (2)		157		467		396		337		307		3,028		4,692

Capital projects (3)		222		195		104		91		-		-		612

Fuel, gas supply and storage		177		240		44		6		1		-		468

Long-term service agreements (4)		13		30		30		27		25		96		221

Equity investment commitments (5)		-		-		240		-		-		-		240

Leases and other (6)		4		19		18		18		16		128		203

Demand side management		8		42		43		-		-		-		93

	$	655	$	1,211	$	1,093	$	695	$	568	$	5,276	$	9,498

(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 $422 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. Nalcor achieved first power on the first of four generators at Muskrat Falls on September 22, 2020 and continues to work toward project commissioning in 2021.

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, resulting in an additional $27 million to be collected from NSPI. A decision from the UARB is 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 September 30, 2020, $79 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 amounts of $164 million and $162 million for 2021 and 2022, respectively. Any difference between the amounts included in the NSPI fuel stability plan and those approved by the UARB through the NSPML interim assessment application will be addressed through the FAM. The timing and amounts payable to NSPML for the remainder of the 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.

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.

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. TGH subsequently requested a reconsideration of the interest quantum awarded. On October 16, 2020, the tribunal granted TGH’s request for additional interest. The additional amount is approximately $2 million USD. Guatemala now has until February 13, 2021 to seek annulment of this second award. The total of the two awards, with interest, is approximately $96 million USD. 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 September 30, 2020, TEC has estimated its financial liability to be $28 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 or future 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 or future 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 $54 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 September 30, 2020 was $63 million (December 31, 2019 - $52 million).

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

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:

As the Q3 2020 dividends were declared by the Board of Directors and recognized in Q2 2020, there were no preferred share dividends recognized in Q3 2020.

On July 9, 2020, Emera announced it would not redeem the 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 17, 2020, Emera announced 128,610 of its 3,864,636 issued and outstanding Series A Shares were tendered for conversion into Series B Shares and 1,130,788 of its 2,135,364 issued and outstanding Series B Shares were tendered for conversion into Series A Shares, all on a one-for-one basis. As a result of the conversion, Emera has 4,866,814 Series A Shares and 1,133,186 Series B Shares issued and 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 which commenced on August 15, 2020 and ends 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 which commenced on August 15, 2020 and ends on (and inclusive of) November 14, 2020 ($0.1274 per Series B Share for the quarter).

23. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


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

Inventory	$	(3)	$	(28)

Receivables and other current assets		115		317

Accounts payable		(42)		(211)

Other current liabilities		69		50

Total non-cash working capital	$	139	$	128

Supplemental disclosure of non-cash activities:

Dividends payable (1)	$	-	$	159

Common share dividends reinvested	$	140	$	140

Decrease in accrued capital expenditures	$	23	$	14

(1) The Board of Directors declaration of the Q4 2020 dividends occurred in October, compared to September in 2019. As a result, there are no common or preferred dividends payable at September 30, 2020.

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 VIEs. 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 records 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

September 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)

560

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 November 12, 2020, the date the financial statements were issued.

Emera (EMRAF) 6-KCurrent report (foreign)