6-K

EMERA INCORPORATED

Date: November 13, 2019

/s/ Stephen D. Aftanas

Name: Stephen D. Aftanas

Title: Corporate Secretary

0001193125-19-290803.txt : 20191113 0001193125-19-290803.hdr.sgml : 20191113 20191113134209 ACCESSION NUMBER: 0001193125-19-290803 CONFORMED SUBMISSION TYPE: 6-K PUBLIC DOCUMENT COUNT: 9 CONFORMED PERIOD OF REPORT: 20191113 FILED AS OF DATE: 20191113 DATE AS OF CHANGE: 20191113 FILER: COMPANY DATA: COMPANY CONFORMED NAME: EMERA INC CENTRAL INDEX KEY: 0001127248 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 868143132 FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 6-K SEC ACT: 1934 Act SEC FILE NUMBER: 000-54516 FILM NUMBER: 191212965 BUSINESS ADDRESS: STREET 1: 1223 LOWER WATER ST., B-6TH FLOOR STREET 2: P.O. BOX 910 CITY: HALIFAX STATE: A5 ZIP: B3J 3S8 BUSINESS PHONE: 902-428-6494 MAIL ADDRESS: STREET 1: 1223 LOWER WATER ST., B-6TH FLOOR STREET 2: P.O. BOX 910 CITY: HALIFAX STATE: A5 ZIP: B3J 3S8 6-K 1 d805356d6k.htm 6-K 6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13a-16 OR 15d-16

UNDER THE SECURITIES EXCHANGE ACT OF 1934

For the month of November, 2019

Commission File Number: 000-54516

Emera Incorporated

(Exact name of registrant as specified in its charter)

5151 Terminal Road

Halifax NS B3J 1A1

Canada

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F ☐ Form 40-F ☑

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ☐

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ☐

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

EXHIBIT INDEX


Exhibit No.		Description

99.1		Emera Incorporated Management’s Discussion and Analysis for the three and nine month periods ended September 30, 2019
99.2		Emera Incorporated Unaudited Condensed Consolidated Interim Financial Statements for the three and nine month periods ended September 30, 2019
99.3		Form 52-109F2 Certification of Interim Filings by the Chief Executive Officer
99.4		Form 52-109F2 Certification of Interim Filings by the Chief Financial Officer
99.5		Emera Incorporated Earnings Coverage Ratio for the Twelve Months Ended September 30, 2019
99.6		Emera Incorporated Media Release dated November 8, 2019

EX-99.1 2 d805356dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

LOGO

Management’s Discussion & Analysis

As at November 7, 2019

Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its subsidiaries and investments (“Emera”) during the third quarter and year-to-date of 2019 relative to the same periods in 2018; and its financial position as at September 30, 2019 relative to December 31, 2018. Throughout this discussion, “Emera Incorporated”, “Emera” and “Company” refer to Emera Incorporated and all of its consolidated subsidiaries and investments.

This discussion and analysis should be read in conjunction with the Emera Incorporated unaudited condensed consolidated interim financial statements and supporting notes as at and for the nine months ended September 30, 2019; and the Emera Incorporated annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2018. Emera follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”).

Effective January 1, 2019, Emera has revised its reportable segments to align with strategic priorities and internal governance. These new reporting segments align with how the Company assesses financial performance and makes decisions about resource allocations. The five new reportable segments are:

●

Florida Electric Utility, which consists of Tampa Electric;

●

Canadian Electric Utilities, which includes Nova Scotia Power Inc. and Emera Newfoundland & Labrador Holdings Inc., a holding company with equity investments in NSP Maritime Link Inc. and Labrador-Island Link Limited Partnership;

●

Other Electric Utilities, which includes Emera Maine and Emera (Caribbean) Incorporated;

●

Gas Utilities and Infrastructure, which includes Peoples Gas System, New Mexico Gas Company, Inc., SeaCoast Gas Transmission, LLC; Emera Brunswick Pipeline Company Limited and an equity investment in Maritimes & Northeast Pipeline; and

●

Other, which includes Emera Energy, Emera Utility Services Inc. and corporate holding and financing companies.

All comparative segment financial information for the three and nine months ended September 30, 2018 has been restated with no impact to reported consolidated results.

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


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

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

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

TABLE OF CONTENTS


Forward-looking Information		4
Introduction and Strategic Overview		4
Non-GAAP Financial Measures		5
Consolidated Financial Review		7
Significant Items Affecting Earnings		7
Consolidated Financial Highlights by Business Segment		8
Consolidated Income Statement Highlights		9
Business Overview and Outlook		12
Florida Electric Utility		13
Canadian Electric Utilities		13
Other Electric Utilities		16
Gas Utilities and Infrastructure		16
Other		17
Consolidated Balance Sheet Highlights		18
Developments		20
Outstanding Common Stock Data		22
Financial Highlights		22
Florida Electric Utility		22
Canadian Electric Utilities		25
Other Electric Utilities		29
Gas Utilities and Infrastructure		31
Other		34
Liquidity and Capital Resources		36
Consolidated Cash Flow Highlights		36
Contractual Obligations		38
Debt Management		39
Credit Ratings		40
Guarantees and Letters of Credit		40
Transactions with Related Parties		41
Risk Management and Financial Instruments		41
Disclosure and Internal Controls		43
Critical Accounting Estimates		44
Changes in Accounting Policies and Practices		44
Summary of Quarterly Results		46

FORWARD-LOOKING INFORMATION

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

The forward-looking information is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors that could cause results or events to differ from current expectations are discussed in the “Business Overview and Outlook” section of the MD&A and may also include: regulatory risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; liquidity and capital market risk; pricing and timing of select asset sales; future dividend growth; timing and costs associated with certain capital investment; the expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology that could reduce demand for electricity; weather; unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk; counterparty credit risk; commercial relationship risk; disruption of fuel supply; country risks; environmental risks; foreign exchange; regulatory and government decisions, including changes to environmental, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology infrastructure and cybersecurity risks; market energy sales prices; labour relations; and availability of labour and management resources.

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

INTRODUCTION AND STRATEGIC OVERVIEW

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

Emera’s investment in rate-regulated businesses is concentrated in Florida and Nova Scotia. These jurisdictions provide generally stable regulatory and economic environments.

Emera’s portfolio of regulated utilities provides reliable earnings, cash flow and dividends. Earnings opportunities in regulated utilities are generally driven by the magnitude of net investment in the utility (known as “rate base”), and the amount of equity in the capital structure and the return on that equity (“ROE”) as approved through regulation. Earnings are also affected by sales volumes and operating expenses.

Emera has a $6.9 billion capital investment plan over the 2020-to-2022 period, including significant investments across the portfolio in renewable and cleaner generation, infrastructure modernization and customer-focused technologies. This planned capital investment is being funded primarily through internally generated cash flows and debt raised at the operating company level. Equity requirements in support of the Company’s capital investment plan will predominantly be funded in the equity capital markets through the dividend reinvestment plan and the issuance of common and preferred equity. Maintaining investment-grade credit ratings is a priority of management.

Emera has provided annual dividend growth guidance of four to five per cent through to 2022. The Company targets a long-term dividend payout ratio of 70 to 75 per cent, and while the payout ratio is likely to exceed that target in the forecast period, it is expected to return to that range over time.

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

Energy markets worldwide are facing significant change and Emera is well positioned to respond to shifting customer demands, complex regulatory environments and the trend towards de-carbonization. Renewable generation and battery storage are becoming both more affordable and efficient. Climate change and extreme weather are shaping how utilities operate and how they invest in infrastructure. There is also an overall need to replace aging infrastructure and further enhance reliability. Emera sees opportunity in these changes. Emera’s efforts to fund investments in renewable and technology assets with related fuel or operating cost savings balances the opportunity with managing rate pressure and affordability for customers.

For example, significant investments to facilitate the use of renewable and low-carbon energy include the recently completed Maritime Link in Atlantic Canada, the ongoing construction of solar generation at Tampa Electric, and the modernization of the Big Bend Power Station at Tampa Electric. Emera’s utilities are also investing in reliability projects and replacing aging infrastructure. All of these projects demonstrate Emera’s strategy of finding cleaner ways to meet the energy needs of its customers while keeping rates affordable.

Emera is committed to world-class safety, operational excellence, good governance, excellent customer service, reliability, being an employer of choice, and building constructive relationships with regulators, stakeholders and the communities where we operate.

NON-GAAP FINANCIAL MEASURES

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

Adjusted Net Income

Emera calculates an adjusted net income measure by excluding the effect of:

●

the mark-to-market adjustments related to Emera’s held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered;

●

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

●

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

●

the mark-to-market adjustments related to an interest rate swap in Brunswick Pipeline; and

●

the mark-to-market adjustments related to equity securities held in BLPC and Emera Reinsurance, a captive reinsurance company in the Other segment.

Management believes excluding from net income the effect of these mark-to-market valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows and ongoing operations of the business, and allows investors to better understand and evaluate the business. Management and the Board of Directors exclude these mark-to-market adjustments for evaluation of performance and incentive compensation.

Refer to the “Consolidated Financial Review” section and the “Financial Highlights” sections for Other Electric Utilities and Other segments, for further details on mark-to-market adjustments.

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


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

	2019		2018		2019		2018

Net income attributable to common shareholders	$	55	$	118	$	470	$	479

After-tax mark-to-market gain (loss)	$	(67)	$	(73)	$	(6)	$	(25)

Adjusted net income attributable to common shareholders	$	122	$	191	$	476	$	504

Earnings per common share – basic	$	0.23	$	0.51	$	1.97	$	2.06

Adjusted earnings per common share – basic	$	0.51	$	0.82	$	1.99	$	2.17

EBITDA and Adjusted EBITDA

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

Adjusted EBITDA is a non-GAAP financial measure used by Emera. Similar to adjusted net income calculations described above, this measure represents EBITDA absent the income effect of Emera’s mark-to-market and amortization adjustments discussed above.

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

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


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

	2019		2018		2019		2018

Net income (1)		$ 78		$ 141		$ 518		$ 516

Interest expense, net		183		176		557		527

Income tax expense (recovery)		(49)		(33)		18		29

Depreciation and amortization		226		236		678		687

EBITDA		438		520		1,771		1,759

Mark-to-market gain (loss), excluding income tax and interest		(96)		(105)		(11)		(36)

Adjusted EBITDA		$ 534		$ 625		$ 1,782		$ 1,795

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

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Earnings

2019

GBPC Hurricane Dorian Restoration

On September 1, 2019, Hurricane Dorian struck Grand Bahama Island as a Category 5 hurricane, causing significant damage across the island. Emera’s Q3 2019 earnings decreased by approximately $16 million ($0.07 per common share), compared to Q3 2018, as a result of the impact of the hurricane. GBPC’s earnings decreased by $7 million for the quarter due to reduced load as storm restoration efforts were underway. In addition, Emera recorded a corporate loss of $9 million in Q3 2019, in the Other segment, for the corporate share of the unrecoverable loss on GBPC’s facilities. Refer to the “Developments” section for further details on Hurricane Dorian.

Earnings Impact of After-Tax Mark-to-Market Gains and Losses

After-tax mark-to-market losses decreased $6 million to $67 million in Q3 2019, compared to $73 million in Q3 2018. Mainly related to Emera Energy, this decrease was due to changes in existing positions on gas contracts, partially offset by higher amortization of gas transportation assets in 2019. Year-to-date, after-tax mark-to-market losses decreased $19 million to $6 million in 2019, compared to $25 million for the same period in 2018. Mainly related to Emera Energy, this decrease was due to changes in existing positions on gas contracts and a larger reversal of mark-to-market losses in 2019, compared to 2018, partially offset by higher amortization of gas transportation assets in 2019.

2018

Florida State Tax Apportionment

In Q3 2018, Emera received approval from the Florida Department of Economic Opportunity to change its Florida state tax apportionment factors. This change resulted in the Company recording a tax benefit of approximately $23 million, or $0.10 per common share, as a result of the remeasurement of certain deferred tax balances.

Consolidated Financial Highlights by Business Segment


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

Adjusted net income	2019		2018		2019		2018

Florida Electric Utility	$	153	$	143	$	339	$	298

Canadian Electric Utilities		33		36		171		174

Other Electric Utilities		23		31		62		64

Gas Utilities and Infrastructure		25		15		132		93

Other		(112)		(34)		(228)		(125)

Adjusted net income attributable to common shareholders	$	122	$	191	$	476	$	504

After-tax mark-to-market gain (loss)		(67)		(73)		(6)		(25)

Net income attributable to common shareholders	$	55	$	118	$	470	$	479

The following table highlights significant changes in adjusted net income from 2018 to 2019.


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

Adjusted net income – 2018	$	191	$	504

Florida Electric Utility - increased earnings due to increased contribution from solar investments and customer growth		10		41

NMGC tax benefit related to change in treatment of net operating loss (“NOL”) carryforwards, and Q2 2019 recognition of tax reform benefits, of which $8 million relates to 2018		7		19

Gas Utilities and Infrastructure - increased earnings due to favourable weather in New Mexico in the first half of 2019, customer growth at PGS and lower depreciation and amortization at PGS		3		20

Gain on sale of property in Florida		-		10

Increased preferred stock dividends		(1)		(9)

Transaction costs related to the pending sale of Emera Maine		(2)		(6)

Impact of Hurricane Dorian related to GBPC. Refer to the “Significant Items Affecting Earnings” and “Developments” sections		(16)		(16)

Decreased earnings from Emera Energy Generation due to the sale of New England Gas Generating Facilities (“NEGG”) and Bayside generation facilities		(18)		(22)

Decreased earnings at Emera Energy Services		(20)		(43)

2018 recognition of Florida state tax apportionment benefit		(23)		(23)

Other variances		(9)		1

Adjusted net income – 2019	$	122	$	476

Refer to the “Financial Highlights” section for further details of reportable segment contributions.


For the millions of Canadian dollars	Nine months ended September 30

		2019		2018

Operating cash flow before changes in working capital	$	1,182	$	1,237

Change in working capital		128		156

Operating cash flow	$	1,310	$	1,393

Investing cash flow	$	(786)	$	(1,565)

Financing cash flow	$	(546)	$	121


As at millions of Canadian dollars	September 30 2019		December 31 2018

Total assets	$	31,565	$	32,314

Total long-term debt (including current portion)	$	14,377	$	15,411

Refer to the “Consolidated Cash Flow Highlights” section for further discussion of cash flow.

Consolidated Income Statement Highlights


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

	2019		2018					2019		2018

Operating revenues	$	1,299	$	1,495	$	(196	)	$	4,495	$	4,725	$	(230)

Operating expenses		1,117		1,257		140			3,531		3,758		227

Income from operations		182		238		(56	)		964		967		(3)

Income from equity investments		38		41		(3	)		118		121		(3)

Other income (expenses), net		(8)		5		(13	)		11		(16)		27

Interest expense, net		183		176		(7	)		557		527		(30)

Income tax expense (recovery)		(49)		(33)		16			18		29		11

Net income		78		141		(63	)		518		516		2

Net income attributable to common shareholders		55		118		(63	)		470		479		(9)

After-tax mark-to-market gain (loss)		(67)		(73)		6			(6)		(25)		19

Adjusted net income attributable to common shareholders	$	122	$	191	$	(69	)	$	476	$	504	$	(28)

Earnings per common share – basic	$	0.23	$	0.51	$	(0.28	)	$	1.97	$	2.06	$	(0.09)

Earnings per common share – diluted	$	0.23	$	0.50	$	(0.27	)	$	1.96	$	2.05	$	(0.09)

Adjusted earnings per common share – basic	$	0.51	$	0.82	$	(0.31	)	$	1.99	$	2.17	$	(0.18)

Dividends per common share declared	$	1.2000	$	1.1525	$	0.0475		$	2.3750	$	2.2825	$	0.0925



Adjusted EBITDA	$	534	$	625	$	(91	)	$	1,782	$	1,795	$	(13)

Operating Revenues

For the third quarter of 2019, operating revenues decreased $196 million compared to the third quarter in 2018. Absent decreased mark-to-market losses of $9 million, operating revenues decreased $205 million due to:

●

$106 million decrease in the Other segment due to the sale of NEGG;

●

$66 million decrease at Florida Electric Utility due to a reduction in base rates as a result of US tax reform and lower clause revenues;

●

$29 million decrease in marketing and trading margin at Emera Energy due to less favourable market conditions and higher fixed cost commitments for gas transportation and storage assets;

●

$14 million decrease at NSPI, mainly due to decreased industrial and commercial class sales volumes; and

●

$8 million decrease in Other Electric Utilities due to lower sales at GBPC as a result of the impact of Hurricane Dorian.

These impacts were partially offset by an increase of:

●

$29 million at Florida Electric Utility as a result of higher base revenues related to in-service of solar generation projects and the impact of a weaker Canadian dollar.

Year-to-date in 2019, operating revenues decreased $230 million compared to the same period in 2018. Absent decreased mark-to-market losses of $25 million, operating revenues decreased by $255 million due to:

●

$197 million decrease in the Other segment due to the sale of NEGG;

●

$153 million decrease at Florida Electric Utility due to lower base rates as a result of US tax reform and lower clause revenues;

●

$70 million decrease in marketing and trading margin at Emera Energy due to less favourable market conditions and higher fixed cost commitments for gas transportation and storage assets; and

●

$15 million decrease in PGS due to lower base rates to reflect the impact of tax reform, less favourable weather in Florida, lower off-system sales and lower clause-related revenues.

These impacts were partially offset by increases of:

●

$119 million at Florida Electric Utility as a result of a weaker Canadian dollar and higher base revenues related to in-service of solar generation projects and customer growth;

●

$45 million at Gas Utilities and Infrastructure as a result of NMGC’s recognition of tax reform benefits from January 1, 2018 to June 30, 2019, favourable weather in New Mexico, customer growth at PGS and the impact of a weaker Canadian dollar; and

●

$11 million at Canadian Electric Utilities as a result of increased sales volume at NSPI due to weather and increased fuel-related pricing, partially offset by the impact of the Maritime Link Assessment.

Operating Expenses

For the third quarter of 2019, operating expenses decreased $140 million compared to the third quarter of 2018 due to:

●

$75 million decrease in the Other segment primarily due to the sale of NEGG;

●

$51 million decrease at Florida Electric Utility as a result of decreased operating, maintenance and general (“OM&G”) expenses due to the regulatory agreement to net storm costs and tax reform benefits in 2018 and lower fuel costs; and

●

$28 million decrease at Canadian Electric Utilities primarily due to the timing of regulatory deferrals.

These impacts were partially offset by an increase of:

●

$28 million at Canadian Electric Utilities primarily due to higher storm costs as a result of the impact of post-tropical storm Dorian.

Year-to-date, operating expenses decreased $227 million compared to the same period of 2018. Absent increased mark-to-market gains of $6 million, operating expenses decreased $233 million due to:

●

$153 million decrease in the Other segment as a result of the sale of NEGG; and

●

$92 million decrease at Florida Electric Utility as a result of decreased OM&G expenses due to the regulatory agreement to net storm costs and tax reform benefits in 2018 and lower fuel costs.

These impacts were partially offset by an increase of:

●

$35 million at Canadian Electric Utilities primarily due to higher storm costs as a result of the impact of post-tropical storm Dorian.

Other Income (Expenses), Net

The decrease in other income (expenses), net for the third quarter was primarily due to the corporate loss recorded by Emera in Q3 2019 for the corporate share of the unrecoverable loss on GBPC facilities, as a result of the impact of Hurricane Dorian. Refer to the “Significant Items Affecting Earnings” and “Developments” sections. Year-to-date in 2019, the increase was due to lower non-service pension costs at NSPI and the gain on sale of property in Florida, partially offset by the impact of Hurricane Dorian.

Interest Expense

The increase in interest expense, net for the third quarter and year-to-date compared to 2018 was primarily due to higher borrowings at Florida Electric Utility and Canadian Electric Utilities and a weaker Canadian dollar.

Income Tax Expense (Recovery)

The decrease in income taxes for the third quarter in 2019, compared to the same period in 2018 was primarily due to decreased income before provision for income taxes, a change in treatment of NMGC net operating loss (“NOL”) carryforwards, increased deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities, and increased amortization of deferred income tax regulatory liabilities. This was partially offset by the remeasurement of certain deferred tax balances as a result of a change in Florida state tax apportionment factors in 2018, which resulted in recognition of a benefit in Q3 2018. Year-to-date in 2019, income taxes also decreased due to an increase in the proportion of income earned in foreign jurisdictions with lower tax rates.

Net Income and Adjusted Net Income Attributable to Common Shareholders

For the third quarter of 2019, net income attributable to common shareholders was favourably impacted by the $6 million decrease in after-tax mark-to-market losses, primarily related to Emera Energy. Absent the mark-to-market changes, adjusted net income attributable to common shareholders decreased $69 million. The decrease was due to lower contributions from Emera Energy, the 2018 recognition of Florida state tax apportionment benefits and the impact of Hurricane Dorian related to GBPC, partially offset by higher contributions from Florida Electric Utility and Gas Utilities and Infrastructure.

Year-to-date in 2019, net income attributable to common shareholders was favourably impacted by the $19 million decrease in after-tax mark-to-market losses primarily related to Emera Energy. Absent the favourable mark-to-market changes, adjusted net income attributable to common shareholders decreased $28 million. The decrease was due to lower contributions from Emera Energy, the 2018 recognition of Florida state tax apportionment benefits, the impact of Hurricane Dorian related to GBPC and increased preferred dividends. These were partially offset by higher contribution from Florida Electric Utility, the impact of a weaker Canadian dollar, NMGC’s recognition of tax reform benefits, increased contribution from the Gas Utilities and Infrastructure segment and a gain on sale of property in Florida.

Earnings and Adjusted Earnings per Common Share – Basic

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

Effect of Foreign Currency Translation

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

Earnings from Emera’s foreign operations are translated into Canadian dollars. In general, Emera’s earnings benefit from a weakening Canadian dollar and are adversely impacted by a strengthening Canadian dollar. The impact of foreign exchange in any period is driven by rate changes, the timing of earnings from foreign operations during the period, and the percentage of earnings from foreign operations in the period.

Results of foreign operations are translated at the weighted average rate of exchange and assets and liabilities of foreign operations are translated at period end rates. The relevant CAD/US exchange rates for 2019 and 2018 are as follows:


	Three months ended September 30				Nine months ended September 30				Year ended December 31

	2019		2018		2019		2018		2018

Weighted average CAD/USD exchange rate	$	1.32	$	1.31	$	1.33	$	1.29	$	1.30

Period end CAD/USD exchange rate	$	1.32	$	1.29	$	1.32	$	1.29	$	1.36

The weakening of the CAD had minimal impact on earnings and increased adjusted earnings by $1 million in Q3 2019, compared to Q3 2018. The weakening of the CAD increased earnings by $14 million and adjusted earnings by $13 million year-to-date in 2019, compared to the same period in 2018.

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

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


millions of US dollars	Three months ended September 30						Nine months ended September 30

	2019			2018			2019			2018

Florida Electric Utility	$	116		$	109		$	255		$	230

Other Electric Utilities		18			23			47			49

Gas Utilities and Infrastructure (1)		12			8			82			57

		146			140			384			336

Other segment (2)		(56	)		(20	)		(131	)		(55	)

Total (3)	$	90		$	120		$	253		$	281

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

(2) Includes Emera Energy’s US dollar adjusted net income from Emera Energy Services, NEGG and Bear Swamp and interest expense on Emera Inc.’s US dollar denominated debt.

(3) Amounts above do not include the impact of mark-to-market.

BUSINESS OVERVIEW AND OUTLOOK

The five new reportable segments are:

●

Florida Electric Utility;

●

Canadian Electric Utilities;

●

Other Electric Utilities;

●

Gas Utilities and Infrastructure; and

●

Other.

Florida Electric Utility

Florida Electric Utility consists of Tampa Electric, a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity, serving customers in West Central Florida.

Tampa Electric anticipates earning within its allowed ROE range in 2019 and expects rate base and earnings to be higher than prior years. Tampa Electric expects customer growth rates in 2019 to be consistent with 2018, reflective of economic growth in Florida. Assuming normal weather in the remainder of 2019, Tampa Electric sales volumes are expected to be consistent with 2018 which benefited from favourable weather in the second half of the year.

On October 17, 2019, the FPSC approved the tariffs on Tampa Electric’s third tranche of its Solar Base Rate Adjustment (“SoBRA”). This SOBRA tranche, effective January 1, 2020, represents 149 MW and $27 million USD annually in estimated revenue requirements. Tampa Electric expects to file its fourth SoBRA petition for the January 1, 2021 tranche in June 2020.

On October 3, 2019, the FPSC issued a rule to implement a storm protection 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. Subject to final approval of the FPSC rule, Tampa Electric expects to file a storm protection plan and associated rates with the FPSC in 2020.

In September 2017, Tampa Electric was impacted by Hurricane Irma and incurred restoration costs of approximately $102 million USD. On March 1, 2018, the FPSC approved a settlement agreement filed by Tampa Electric allowing the utility to net the amount of storm cost recovery against its return of estimated 2018 US tax reform benefits to customers. On May 21, 2019, the FPSC approved Tampa Electric’s settlement agreement with consumer parties regarding eligibility of these storm costs. As a result, Tampa Electric will refund $12 million USD to customers in January 2020, resulting in minimal impact to earnings.

In 2019, capital expenditures in the Florida Electric Utility segment are expected to be approximately $1.1 billion USD (2018 - $940 million USD), including allowance for funds used during construction (“AFUDC”). Capital projects include supporting system reliability and growth, including investments in the modernization of the Big Bend Power Station, which received final state approval on July 25, 2019, solar projects and advanced metering infrastructure (“AMI”). AFUDC will be earned on these projects during the construction periods.

Canadian Electric Utilities

Canadian Electric Utilities includes:

●

NSPI, a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity and the primary electricity supplier to customers in Nova Scotia; and

●

ENL, a holding company with equity investments in NSPML and LIL, two transmission investments related to the development of an 824 megawatt (“MW”) hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador.

●

The Maritime Link entered service on January 15, 2018 and provides for the transmission of energy between Newfoundland and Nova Scotia, as well as improved reliability and ancillary benefits, supporting the efficiency and reliability of energy in both provinces. The Maritime Link will transmit at greater capacity when the Lower Churchill hydroelectricity generation project is complete.

●

Construction of the LIL is complete and Nalcor Energy (“Nalcor”) recognized the first flow of energy from Labrador to Newfoundland in June 2018. Nalcor continues to work towards commissioning the LIL, which it forecasts to be operational in 2020.

NSPI

NSPI anticipates earning within its allowed ROE range in 2019 and expects modest rate base growth which will deliver a similar modest increase in earnings.

In September 2019, post-tropical storm Dorian struck Nova Scotia, with sustained hurricane force winds. The storm caused widespread damage to NSPI’s transmission and distribution systems. The total cost of the restoration is expected to be approximately $39 million. At September 30, 2019, $23 million of this estimated total cost was capitalized to property, plant and equipment, with the remaining $16 million charged to OM&G expense. There was no overall impact on NSPI earnings as NSPI’s increased storm costs were absorbed by some of the excess non-fuel revenues that were recorded to date in 2019. Any excess non-fuel revenues that are available at the end of the fiscal year will be returned to customers through the fuel adjustment mechanism (“FAM”). Refer to the “Developments” section for further details.

On June 27, 2019, NSPI filed an application for a three-year fuel stability plan with the UARB and on October 3, 2019, NSPI filed additional reply evidence in support of the application. If this application is approved, it will result in an annual rate increase averaging 1.9 per cent per year for the 2020 through 2022 period to recover fuel costs within the FAM. A regulatory hearing was held on October 15, 2019 with a decision on the application expected from the UARB by the end of 2019.

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

The Government of Canada has laws and regulations that would compel the closure of coal plants before the end of their economic life and at the latest by 2030. The Province of Nova Scotia has enacted laws and regulations that have been found to be equivalent to the federal regulations. The proposed renewal of the Canada-Nova Scotia Equivalency Agreement is expected to be finalized by the end of 2019. This agreement, as proposed, will allow NSPI to achieve compliance with federal greenhouse gas emissions regulations through 2029 by meeting provincial legislative and regulatory requirements as these requirements are deemed to be equivalent to the federal regulations. Efforts are now focused on the development of an Equivalency Agreement for 2030 and beyond recognizing equivalent outcomes between federal and provincial environmental laws and regulations.

On October 23, 2019, the Province of Nova Scotia introduced Bill 213, “The Sustainable Development Goals Act,” setting a goal of net-zero GHG emissions by 2050. It is currently before the legislature and is subject to proclamation. NSPI has and will continue to participate in any consultation process for this Bill.

NSPI has completed registration under the Nova Scotia Cap-and-Trade Program Regulations and received its 2019 granted emissions allowances in April 2019. These 2019 allowances will be used in 2019 or allocated to other years in the initial four-year compliance period of 2019 through 2022. NSPI anticipates that any prudently incurred costs required to comply with the Government of Canada’s Pan-Canadian Framework on Clean Growth and Climate Change, and the Nova Scotia Cap-and-Trade Program Regulations, will be recoverable from customers under NSPI’s regulatory framework.

In May 2019, Nova Scotia Environment advised NSPI that it intends to propose amendments to Nova Scotia’s Air Quality Regulations (the “Regulations”) respecting sulphur dioxide (“SO₂”) emissions which will lessen the reduction in the SO₂ emissions for the 2020 through 2022 fuel stability period. The Regulations have been driving a steady decrease in SO₂ emissions since 2005. The current Regulations call for another round of decreases starting in 2020 based on the assumption that Muskrat Falls would be online by 2020. Given the delay with Muskrat Falls, the provincial government is allowing NSPI near-term flexibility with emissions in order to avoid significant rate increases for Nova Scotians, while continuing Nova Scotia’s downward trend with SO₂ emissions. NSPI has incorporated the impact of these changes into the fuel stability plan application that was filed with the UARB on June 27, 2019.

NSPI continues to advance its “Coal to Clean” strategy. NSPI achieved carbon dioxide reductions of over 30 per cent from 2005 levels, exceeding the 21^st Conference of the Parties of the United Nations Framework Convention on Climate Change targets for a reduction of 30 per cent from 2005 levels by 2030. NSPI is on track to achieve reductions in carbon dioxide of over 55 per cent by 2030.

In 2019, NSPI expects to invest approximately $400 million (2018 - $348 million), including AFUDC, in capital projects to support system reliability and AMI.

ENL

Equity earnings from NSPML and LIL combined are expected to be modestly higher in 2019, compared to 2018. Both the NSPML and LIL investments are recorded as “Investments subject to significant influence” on Emera’s Condensed Consolidated Balance Sheets.

NSPML

Equity earnings contributions from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. The approved ROE is 9 per cent.

NSPML has UARB approval to collect $111 million from NSPI for the recovery of costs associated with the Maritime Link in 2019, which is currently included in NSPI rates. This payment is subject to a $10 million holdback. On June 14, 2019, NSPML filed an interim assessment application requesting recovery of 2020 costs of approximately $145 million from NSPI, subject to a $10 million holdback. NSPI has included the difference of $34 million in its proposed fuel stability plan filed with the UARB. A decision by the UARB is expected in Q4 2019.

In 2019, NSPML expects to invest approximately $35 million (2018 - $15 million) in capital.

LIL

Equity earnings from the LIL investment are based upon the book value of the equity investment and the approved ROE. Emera’s current equity investment is $568 million, and is forecasted to be $579 million by the end of 2019, comprised of $410 million in equity contribution and an estimated $169 million of accumulated equity earnings. Emera’s total equity contribution in the LIL, excluding accumulated equity earnings, is estimated to be approximately $600 million after all Lower Churchill projects, including Muskrat Falls, are completed. Nalcor is forecasting these projects to be completed in the second half of 2020.

Cash earnings and return of equity are forecasted by Nalcor to begin in Q4 2020 and until that point Emera will continue to record AFUDC earnings.

Other Electric Utilities

Other Electric Utilities includes:

●

Emera Maine, a regulated transmission and distribution electric utility in the State of Maine. On March 25, 2019, Emera announced an agreement to sell Emera Maine. The transaction is expected to close in late 2019, subject to MPUC approval. Refer to the “Developments” section for further details.

●

Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities, BLPC, a vertically integrated regulated electric utility on the island of Barbados, and GBPC, a vertically integrated regulated electric utility on Grand Bahama Island. ECI also holds:

●

a 51.9 per cent interest in Domlec, a vertically integrated regulated electric utility on the island of Dominica; and

●

a 19.1 per cent equity interest in Lucelec, a vertically integrated regulated electric utility on the island of St. Lucia.

Other Electric Utilities’ earnings are expected to decrease over the prior year due to lower earnings from ECI’s utilities as a result of the impact of Hurricane Dorian on GBPC, as discussed below, and modest growth in Emera Maine. The sale of Emera Maine is expected to occur in late 2019, resulting in approximately a year of earnings contribution for 2019. Emera Maine’s 2019 rate base is expected to grow modestly due to ongoing investment in transmission and distribution infrastructure, resulting in modest growth in earnings.

On September 1, 2019, Hurricane Dorian struck Grand Bahama Island causing significant damage across the island. GBPC sustained damage to its generation, transmission and distribution assets. Restoration efforts are well underway. GBPC has restored power to all customers who requested power and are able to receive it and as of September 30, 2019, power was restored to approximately 85 per cent of its customers. It is currently estimated that restoration costs for GBPC self-insured assets will be approximately $12 million USD. At September 30, 2019, approximately $8 million USD of self-insured storm restoration costs incurred to date were recorded as a regulatory asset with minimal impact to earnings. Management anticipates that recovery of these self-insured costs through a regulatory process is probable. The impact of Hurricane Dorian could adversely affect GBPC’s future earnings and impairment of its assets and goodwill will be assessed. The outcome of this assessment cannot be reasonably determined or estimated at this time, therefore no impairment was recorded in Q3 2019. The Company expects to complete its impairment analysis in Q4 2019. Refer to the “Developments” section for further details.

In 2019, capital expenditures in the Other Electric Utilities segment are expected to be approximately $160 million USD (2018 – $144 million USD). Emera Maine will invest primarily in transmission and distribution projects supporting normal system reliability. ECI’s utilities are forecasting capital investment in more efficient and cleaner sources of generation, including renewables and battery storage.

Gas Utilities and Infrastructure

Gas Utilities and Infrastructure includes:

●

PGS, a regulated gas distribution utility engaged in the purchase, distribution and sale of natural gas serving customers in Florida;

●

NMGC, a regulated gas distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving customers in New Mexico;

●

SeaCoast, a regulated intrastate natural gas transmission company offering services in Florida;

●

Brunswick Pipeline, a regulated 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick, to markets in the northeastern United States; and

●

Emera’s non-consolidated investment in M&NP.

Gas Utilities and Infrastructure earnings are anticipated to increase over the prior year. PGS anticipates earning within its allowed ROE range in 2019 and expects rate base and earnings to be higher than prior years. PGS expects customer growth rates in 2019 to be consistent with 2018, reflective of economic growth in Florida and the optimization of existing opportunities as the utility increases its market penetration in Florida. PGS sales volumes are expected to increase at a lower rate in 2019, as 2018 energy sales benefited from favourable weather. NMGC expects earnings and rate base to be higher than prior years due to tax reform benefits recorded in Q2 2019 and a change in the treatment of NOL carryforwards recorded in Q3 2019, both of which are discussed below; and colder weather throughout Q1 2019. Customer growth rates are expected to be consistent with 2018, reflecting expectations for housing starts and new connections.

On July 17, 2019, the NMPRC approved a rate increase for NMGC effective August 2019, and allowed NMGC to retain tax reform benefits realized from January 1, 2018 to the effective date of the new rates. The new rates are being phased in over two years and are expected to result in an annual revenue increase of approximately $3 million USD. The impact of the retention of the tax reform benefits resulted in an increase in earnings of $9 million USD in Q2 2019, of which $6 million USD relates to 2018. The NMPRC also approved the utility’s proposed weather adjustment mechanism. Beginning in August 2019, the NMPRC approved a change in the treatment of NOL carryforwards. As a result of this change, a tax benefit of approximately $5 million USD was recognized in Q3 2019.

In 2019, capital expenditures in the Gas Utilities and Infrastructure segment are expected to be approximately $340 million USD (2018 - $254 million USD), including AFUDC. PGS will make investments to expand its system and support customer growth. NMGC will complete planning phases of the Santa Fe Mainline Looping project in 2019, and will continue to invest in system improvements.

Other

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

Business operations in Other include:

●

Emera Energy, which consists of:

●

Emera Energy Services (“EES”), a wholly owned physical energy marketing and trading business;

●

Emera Energy Generation (“EEG”), a wholly owned portfolio of electricity generation facilities in New England and the Maritime provinces of Canada. In March 2019, Emera completed the sale of the NEGG and Bayside facilities. Refer to the “Developments” section for further details; and

●

an equity investment in a 50.0 per cent joint venture ownership of Bear Swamp, a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts.

●

Emera Utility Services (“EUS”), a utility services contractor primarily operating in Atlantic Canada. In Q2 2019, Emera entered into an agreement to sell its EUS equipment. The transaction is expected to close in late 2019. EUS ceased operations on September 30, 2019.

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

Earnings from EES are generally dependent on market conditions. In particular, volatility in electricity and natural gas markets, which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 generally providing the greatest opportunity for earnings. Under normal market conditions, the business is generally expected to deliver annual adjusted net earnings of $15 to $30 million USD ($45 to $70 million USD of margin), with the opportunity for upside when market conditions present. Based on results year-to-date, EES expects to fall short of the low end of its normal range for 2019 but maintain profitability.

The Other segment is expected to contribute positively to earnings in 2019 due to the sale of Emera Maine, with a material gain expected to be recognized in earnings at closing. Absent this gain, the adjusted net loss from the Other segment is expected to increase over the prior year, primarily due to lower contribution from EES, as discussed above; the sale of the NEGG facilities, resulting in only three months of earnings contribution in 2019; and higher corporate costs in 2019. Corporate costs are expected to be higher due to increased preferred dividend expense as a result of additional preferred shares issued in Q2 2018, the corporate share of the unrecoverable loss related to the impact of Hurricane Dorian on GBPC, and lower tax recoveries. Tax recoveries are expected to be lower as a result of the benefit recognized in Q3 2018 due to a change in Florida state tax apportionment factors, which resulted in remeasurement of certain deferred tax balances.

In 2019, capital expenditures in the Other segment are expected to be approximately $60 million (2018 - $75 million).

CONSOLIDATED BALANCE SHEET HIGHLIGHTS

Significant changes in the Condensed Consolidated Balance Sheets between December 31, 2018 and September 30, 2019 include:


millions of Canadian dollars	Total Increase (Decrease)	Increase (Decrease) due to Held for Sale classification (1)	Other Increase (Decrease)	Explanation of Other Increase (Decrease)

Assets

Regulatory assets (current and long-term)	$ (50)	(130)	$ 80	Increased due to deferred income tax regulatory asset and derivative instruments at NSPI, partially offset by the effect of a stronger CAD on the translation of Emera’s foreign affiliates.

Receivables and other assets (current and long-term)	(367)	(81)	(286)	Decreased due to lower commodity prices and lower cash collateral positions at Emera Energy, changes in corporate alternative minimum tax credit carryforwards and the effect of a stronger CAD on the translation of Emera’s foreign subsidiaries.

Assets held for sale (current and long-term), net of liabilities	(89)	719	(808)	Decreased due to completion of the sale of the NEGG facilities.

Property, plant and equipment, net of accumulated depreciation and amortization	(845)	(1,311)	466	Increased due to additions at Tampa Electric, PGS and NSPI partially offset by the effect of a stronger CAD on the translation of Emera’s foreign affiliates.

Goodwill	(334)	(151)	(183)	Decreased due to the effect of a stronger CAD on the translation of Emera’s foreign subsidiaries.


Liabilities and Equity

Short-term and long-term debt (including current portion)	(1,262)	(515)	(747)	Repayment of Emera US Finance LP USD note upon maturity, the effect of a stronger CAD on the translation of Emera’s foreign affiliates and repayments by NSPI and NMGC, partially offset by issuances at NSPI and Tampa Electric.

Accounts payable	(228)	(30)	(198)	Decreased due to the effect of a stronger CAD on the translation of Emera’s foreign subsidiaries, lower commodity prices at Emera Energy and lower cash collateral positions at NSPI and Emera Energy, partially offset by an increase at Tampa Electric due to timing of payments for solar and Big Bend modernization costs.

Deferred income tax liabilities, net of deferred income tax assets	(150)	(204)	54	Increased due to tax deductions in excess of accounting depreciation related to property, plant, and equipment, and net utilization of tax loss carryforwards, partially offset by increased income tax credits related to solar projects at Tampa Electric.

Regulatory liabilities (current and long-term)	(345)	(156)	(189)	Decreased primarily due to deferrals related to derivative instruments, fuel adjustment mechanism and cost of removal at NSPI, and the effect of a stronger CAD on the translation of Emera’s foreign affiliates.

Pension and post-retirement liabilities	(122)	(71)	(51)	Effect of a stronger CAD on the translation of Emera’s foreign affiliates.

Other liabilities (current and long-term)	311	(24)	335	Increased due to timing of Emera’s dividend payments and investment tax credits related to solar projects at Tampa Electric, partially offset by the effect of a stronger CAD on the translation of Emera’s foreign subsidiaries.

Common stock	299	-	299	Increased due to the dividend reinvestment plan, increase in options exercised and shares issued under Emera’s at-the-market equity program (“ATM Program”).

Accumulated other comprehensive income	(177)	-	(177)	Decreased due to the effect of a stronger CAD on the translation of Emera’s foreign subsidiaries.

Retained earnings	(95)	-	(95)	Decreased due to dividends paid in excess of net income.

(1) On March 25, 2019, Emera announced the sale of Emera Maine. As at September 30, 2019, Emera Maine’s assets and liabilities were classified as held for sale. Refer to the “Developments” section and note 4 in the condensed consolidated financial statements for further details.

DEVELOPMENTS

Increase in Common Dividend

On September 27, 2019, Emera’s Board of Directors approved an increase in the annual common share dividend rate to $2.45 from $2.35. The first payment will be effective November 15, 2019. Emera extended its four to five per cent annual dividend growth rate target through to 2022.

Hurricane Dorian

In September 2019, Hurricane Dorian impacted GBPC, NSPI and Tampa Electric operations, as discussed below.

GBPC – On September 1, 2019, Dorian struck Grand Bahama Island as a Category 5 hurricane, with sustained winds of approximately 285 kilometres per hour. The hurricane stalled over the island for several days, causing significant damage to, or destruction of, homes and businesses served by GBPC. GBPC’s generation, transmission and distribution assets sustained damage, including the effect of flooding that resulted from storm surge and rain. All 19,000 of GBPC’s customers lost power following the storm. The Company’s restoration plan is well underway and by September 30, 2019, power was restored to all customers who were able to receive power, or approximately 16,000 customers.

GBPC maintains insurance for its generation facilities and, as with most utilities, its transmission and distribution networks are self-insured. It is currently estimated that restoration costs for GBPC self-insured assets will be approximately $12 million USD. At September 30, 2019, the Company incurred and recorded $8 million USD of this estimated cost. The $8 million USD was recorded as a regulatory asset as management anticipates that recovery of these prudently incurred costs through a regulatory process is probable. Management is working with GBPC’s insurance companies to assess the damage to its generation assets. It is anticipated that this damage will be covered by insurance, with the exception of $5 million USD, which is GBPC’s share of the insurance deductible, and which has not yet been recorded. In addition, Emera recorded a corporate loss of $9 million ($7 million USD) in Q3 2019, in the Other segment, for the corporate share of the unrecoverable loss on GBPC’s facilities.

At September 30, 2019, GBPC total assets were $465 million ($351 million USD), excluding goodwill, and $101 million ($76 million USD) of Emera’s goodwill was related to GBPC. The impact of Hurricane Dorian could adversely affect GBPC’s future earnings and impairment of some of its assets and goodwill could occur. The outcome cannot be reasonably determined or estimated at this time, therefore no impairment was recorded in Q3 2019. The Company expects to complete its impairment analysis in Q4 2019.

NSPI – On September 7, 2019, Dorian struck Nova Scotia with sustained hurricane force winds of over 100 kilometres per hour and peak gusts of approximately 155 kilometres per hour. The storm caused widespread damage to NSPI’s transmission and distribution system and, at the height of the storm, approximately 412,000 customers were affected. By September 10, 2019, power had been restored to 80 per cent of those affected, and all customers were restored by September 17, 2019. The total cost of the restoration is expected to be approximately $39 million. At September 30, 2019, $23 million of this estimated total cost was capitalized to property, plant and equipment, with the remaining $16 million charged to OM&G expense. There was no overall impact on NSPI earnings as NSPI’s increased storm costs were absorbed by some of the excess non-fuel revenues that were recorded to date in 2019. Any excess non-fuel revenues that are available at the end of the fiscal year will be returned to customers through the FAM.

Tampa Electric – In preparation for Hurricane Dorian, Tampa Electric incurred approximately $8 million USD in storm costs. There was no impact to Tampa Electric earnings as these costs were charged to Tampa Electric’s storm reserve regulatory liability. As of September 30, 2019, the storm reserve regulatory liability balance was $63 million ($48 million USD).

At-The-Market Equity Program

On July 11, 2019, Emera established an ATM Program that allows the Company to issue up to $600 million of common shares from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price. The ATM Program was established under a prospectus supplement to the Company’s short-form base shelf prospectus which expires on July 14, 2021. During Q3 2019, approximately 0.9 million common shares were issued under the ATM Program at an average price of $56.76 per share for gross proceeds of $50 million ($49.4 million net of issuance costs). As at September 30, 2019, an aggregate gross sales limit of $550 million remains available for issuance under the ATM program.

Removal of Legislative Restriction on Non-Canadian Resident Ownership of Emera Shares

On April 12, 2019, amendments to the Nova Scotia Power Privatization Act and the Nova Scotia Power Reorganization (1998) Act were enacted, removing the legislative restriction preventing non-Canadian residents from holding more than 25 per cent of Emera voting shares, in aggregate. On July 11, 2019, shareholders passed a special resolution to immediately amend the Company’s articles of association to remove this restriction.

Sale of Emera Energy’s New England Gas and Bayside Generating Facilities

On March 29, 2019, Emera completed the sale of its three NEGG facilities for cash proceeds of $799 million ($598 million USD), including working capital adjustments. On March 5, 2019, the Company sold its Bayside facility for cash proceeds of $46 million. An immaterial loss was recognized on these dispositions. Proceeds from the sales were used to reduce corporate debt and support capital investment opportunities within Emera’s regulated utilities.

Pending Sale of Emera Maine

On March 25, 2019, Emera announced the sale of Emera Maine for a total enterprise value of approximately $1.3 billion USD including cash proceeds of $959 million USD, transferred debt and a working capital adjustment on close. The transaction is expected to close in late 2019, subject to the approval of the MPUC. All other required regulatory approvals have been received.

A material gain on the sale is expected to be recognized in earnings at closing. Proceeds from the sale will be used to support capital investment opportunities within Emera’s regulated utilities and to reduce corporate debt.

Appointments

Executive

Effective October 21, 2019, Karen Hutt was appointed Executive Vice President, Strategy & Business Development for Emera. Most recently, Ms. Hutt was President and CEO of NSPI.

Effective October 21, 2019, Wayne O’Connor was appointed President and CEO of NSPI. Most recently, Mr. O’Connor was Executive Vice President, Strategy & Business Development, with Emera.

OUTSTANDING COMMON STOCK DATA


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

Balance, December 31, 2017		228.77		$ 5,601

Conversion of Convertible Debentures		0.01		-

Issuance of common stock		0.45		22

Issued for cash under Purchase Plans at market rate		4.87		200

Discount on shares purchased under Dividend Reinvestment Plan		-		(9)

Options exercised under senior management stock option plan		0.02		1

Employee Share Purchase Plan		-		1

Balance, December 31, 2018		234.12		$ 5,816

Conversion of Convertible Debentures		0.03		1

Issuance of common stock (1)		0.88		49

Issued for cash under Purchase Plans at market rate		3.04		153

Discount on shares purchased under Dividend Reinvestment Plan		-		(7)

Options exercised under senior management stock option plan		2.53		102

Employee Share Purchase Plan		-		1

Balance, September 30, 2019		240.60		$ 6,115

(1) As at September 30, 2019, a total of 0.88 million common shares have been issued through Emera’s at-the-market equity program (“ATM Program”) at an average price of $56.76 per share for gross proceeds of $50 million ($49.4 million net of issuance costs).

As at November 4, 2019, the amount of issued and outstanding common shares was 241.1 million.

The weighted average shares of common stock outstanding – basic, which includes both issued and outstanding common stock and outstanding deferred share units, for the three months ended September 30, 2019 was 241.0 million (2018 – 233.7 million) and for the nine months ended September 30, 2019 was 238.9 million (2018 – 232.4 million).

FINANCIAL HIGHLIGHTS

Florida Electric Utility

All amounts are reported in USD, unless otherwise stated.


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


	2019		2018		2019		2018

Operating revenues – regulated electric	$	559	$	593	$	1,492	$	1,565

Regulated fuel for generation and purchased power		168		190		439		482

Contribution to consolidated net income	$	116	$	109	$	255	$	230

Contribution to consolidated net income – CAD	$	153	$	143	$	339	$	298

Contribution to consolidated earnings per common share – basic – CAD	$	0.63	$	0.61	$	1.42	$	1.28

Net income weighted average foreign exchange rate – CAD/USD	$	1.32	$	1.29	$	1.33	$	1.26



EBITDA	$	249	$	237	$	641	$	590

EBITDA – CAD	$	331	$	311	$	853	$	762

Net Income

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


For the millions of US dollars	Three months ended September 30		Nine months ended September 30

Contribution to consolidated net income – 2018	$	109	$	230

Decreased operating revenues - see Operating Revenues - Regulated Electric below		(34)		(73)

Decreased fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below		22		43

Decreased OM&G expenses due to Tampa Electric’s regulatory agreement to net 2018 tax reform benefits with storm costs that were recorded through OM&G in 2018. Beginning in 2019, tax reform benefits are reflected in lower base rates		27		77

Increased depreciation and amortization due to increased property, plant and equipment		(7)		(18)

Increased interest expense in support of increased capital spending		(6)		(12)

Decreased other income as the result of lower AFUDC earnings due to a lower number of solar projects under construction in Q3 2019		(4)		-

Decreased income tax expense primarily due to increased amortization of deferred income tax regulatory liabilities resulting from tax reform, higher investment tax credits related to solar projects and a reduction in the Florida state corporate income tax rate		8		4

Other		1		4

Contribution to consolidated net income – 2019	$	116	$	255

Florida Electric Utility’s CAD contribution to consolidated net income increased $10 million in Q3 2019, compared to Q3 2018. Year-to-date, Florida Electric Utility’s CAD contribution to consolidated net income increased $41 million in 2019. Increases in both periods were due to higher base revenues related to the in-service of solar generation projects and customer growth. These increases were partially offset by higher depreciation expense and higher interest expense. The reduction in base rates due to tax reform was offset by lower OM&G expense in 2019, as the 2018 tax reform benefits were netted against the storm costs recorded through OM&G expense in 2018.

The impact of the change in the foreign exchange rate increased CAD earnings for the three and nine months ended September 30, 2019 by $2 million and $8 million respectively.

Operating Revenues – Regulated Electric

Beginning January 1, 2019, as approved by the FPSC, base rates at Tampa Electric were lowered by $103 million annually to reflect the impact of tax reform, resulting in a $27 million decrease in revenue in Q3 2019, and a $74 million decrease year-to-date.

Electric revenues decreased $34 million to $559 million in Q3 2019, compared to $593 million in Q3 2018. Year-to-date, electric revenues decreased $73 million to $1,492 million in 2019, compared to $1,565 million for the same period in 2018. The decreases in both periods were due to lower clause revenues, lower base rates as a result of US tax reform and less favourable weather, partially offset by higher base revenues related to in-service of solar generation projects, and customer growth.

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

Q3 Electric Revenues

millions of US dollars



	2019		2018

Residential	$	325	$	331

Commercial		160		163

Industrial		41		43

Other (1)		33		56

Total	$	559	$	593

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

YTD Electric Revenues

millions of US dollars



	2019		2018

Residential	$	792	$	802

Commercial		421		435

Industrial		117		121

Other (1)		162		207

Total	$	1,492	$	1,565

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

Q3 Electric Sales Volumes

Gigawatt hours (“GWh”)



	2019		2018

Residential		2,976		2,944

Commercial		1,791		1,791

Industrial		519		546

Other		548		579

Total		5,834		5,860

YTD Electric Sales Volumes

GWh



	2019		2018

Residential		7,281		7,098

Commercial		4,704		4,698

Industrial		1,520		1,524

Other		1,515		1,705

Total		15,020		15,025

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power decreased $22 million to $168 million in Q3 2019, compared to $190 million in Q3 2018. Year-to-date, regulated fuel for generation and purchased power decreased $43 million to $439 million in 2019, compared to $482 million in the same period in 2018. The decrease in both periods was due to increased use of lower-cost natural gas and increased solar generation.

Q3 Production Volumes

GWh



	2019		2018

Natural gas		5,006		4,698

Coal		219		775

Oil and petcoke		-		231

Solar		210		26

Purchased power		657		365

Total		6,092		6,095

YTD Production Volumes

GWh



	2019		2018

Natural gas		13,439		11,937

Coal		891		2,658

Oil and petcoke		-		472

Solar		587		50

Purchased power		1,080		727

Total		15,997		15,844

Q3 Average Fuel Costs



US dollars		2019		2018

Dollars per Megawatt hour (“MWh”)	$	28	$	31

YTD Average Fuel Costs



US dollars		2019		2018

Dollars per MWh	$	27	$	30

Average fuel cost per MWh decreased in Q3 2019 and year-to-date, compared to the same periods in 2018, primarily due to increased use of lower-cost natural gas and lower-cost solar generation.

Canadian Electric Utilities


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

		2019		2018		2019		2018

Operating revenues – regulated electric	$	296	$	310	$	1,066	$	1,055

Regulated fuel for generation and purchased power (1)		147		148		480		460

Income from equity investments		20		21		68		71

Contribution to consolidated net income	$	33	$	36	$	171	$	174

Contribution to consolidated earnings per common share – basic	$	0.14	$	0.15	$	0.72	$	0.75


EBITDA	$	117	$	125	$	441	$	444

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

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


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

		2019		2018		2019		2018

NSPI	$	13	$	15	$	103	$	103

Equity investment in NSPML		9		10		35		40

Equity investment in LIL		11		11		33		31

Contribution to consolidated net income	$	33	$	36	$	171	$	174

Net Income

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


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

Contribution to consolidated net income – 2018	$	36	$	174

(Decreased) increased operating revenues - see Operating Revenues – Regulated Electric below		(14)		11

Decreased (increased) fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below		1		(20)

Decreased FAM and fixed cost deferrals due to decreased excess non-fuel revenues in the quarter and increased under-recovery of fuel costs which includes the impact of the Maritime Link assessment in both periods		28		22

Increased OM&G expenses primarily due to higher storm costs mainly due to post-tropical storm Dorian and higher costs for vegetation management		(26)		(28)

Increased depreciation and amortization due to increased property, plant and equipment		(2)		(8)

Decrease in income from equity investments		(1)		(3)

Decreased other expenses, net primarily due to lower non-current service pension costs		5		16

Increased interest expense, net primarily due to increased long-term debt outstanding		(2)		(5)

Decreased income taxes primarily due to changes in federal tax legislation allowing for accelerated deduction of eligible property, plant and equipment, decreased non-deductible pension expense, tax benefits of capital investment related to Dorian and decreased income before provision for income taxes. These decreases were partially offset by lower tax deductions in excess of accounting depreciation related to property, plant and equipment		9		13

Other		(1)		(1)

Contribution to consolidated net income – 2019	$	33	$	171

Canadian Electric Utilities’ contribution to consolidated net income decreased in Q3 2019 due to lower contribution from NSPI. NSPI’s decrease was primarily due to decreased sales volume partially offset by lower income taxes and lower non-current pension costs. Canadian Electric Utilities’ year-to-date contribution was consistent with the same period in 2018.

Increased OM&G expenses at NSPI, related to Dorian storm restoration costs, had no overall impact on NSPI’s earnings in the quarter or year-to-date, as NSPI’s increased storm costs were absorbed by some of the excess non-fuel revenues that were recorded to date in 2019. Any excess non-fuel revenues that are available at the end of the fiscal year will be returned to customers through the FAM.

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

NSPI

Operating Revenues – Regulated Electric

Operating revenues decreased $14 million to $296 million in Q3 2019, compared to $310 million in Q3 2018 primarily due to decreased industrial and commercial class sales volume and decreased volume due to weather partially offset by increased fuel related electricity pricing in 2019. Year-to-date operating revenues increased $11 million to $1,066 million compared to $1,055 million for the same period in 2018 primarily due to increased sales volume due to weather, increased fuel-related electricity pricing in 2019 and increased residential class sales volume. This was partially offset by decreased industrial and commercial class sales volume and the impact of the Maritime Link assessment.

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

Q3 Electric Revenues

millions of Canadian dollars



	2019		2018

Residential	$	135	$	139

Commercial		91		95

Industrial		52		60

Other		11		9

Total	$	289	$	303

Q3 Electric Sales Volumes

GWh



	2019		2018

Residential		810		830

Commercial		707		739

Industrial		629		674

Other		72		63

Total		2,218		2,306

YTD Electric Revenues

millions of Canadian dollars



	2019		2018

Residential	$	552	$	532

Commercial		298		298

Industrial		160		171

Other		35		33

Total	$	1,045	$	1,034

YTD Electric Sales Volumes

GWh



	2019		2018

Residential		3,454		3,322

Commercial		2,305		2,303

Industrial		1,817		1,942

Other		272		247

Total		7,848		7,814

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power was consistent quarter-over-quarter. Year-to-date regulated fuel for generation and purchased power increased $20 million to $480 million compared to $460 million in the same period in 2018. The increase was primarily due to increased commodity prices, partially offset by change in generation mix.


Q3 Production Volumes
GWh

	2019		2018

Coal		918		962

Natural gas		451		514

Oil and petcoke		204		238

Purchased power – other		277		217

Total non-renewables		1,850		1,931

Wind and hydro		202		150

Purchased power – Independent Power Producers (“IPP”)		195		225

Purchased power – Community Feed-in Tariff program (“COMFIT”)		96		101

Biomass		14		47

Total renewables		507		523

Total production volumes		2,357		2,454


Q3 Average Fuel Costs

	2019		2018

Dollars per MWh		62		60


YTD Production Volumes
GWh

	2019		2018

Coal		3,551		3,464

Natural gas		1,047		1,152

Oil and petcoke		832		992

Purchased power – other		647		365

Total non-renewables		6,077		5,973

Wind and hydro		983		884

Purchased power – IPP		831		906

Purchased power – COMFIT		389		400

Biomass		59		129

Total renewables		2,262		2,319

Total production volumes		8,339		8,292


YTD Average Fuel Costs

	2019		2018

Dollars per MWh		58		55

Average fuel cost per MWh increased in Q3 2019 and year-to-date, compared to the same periods in 2018, primarily due to increased commodity pricing and the timing of the payments of the Maritime Link assessment. These increases were partially offset by a change in generation mix.

NSPI’s FAM regulatory liability balance decreased $20 million from $161 million at December 31, 2018 to $141 million at September 30, 2019, primarily due to under-recovery of current period fuel costs and a refund to customers of the 2018 Maritime Link assessment. This was partially offset by the recovery of the Maritime Link assessment in 2019 to be returned to customers as part of the assessment decision, demand side management costs to be returned to customers in subsequent years and interest on the FAM balance.

ENL

Income from Equity Investments in NSPML and LIL

Overall income from equity investments for both Q3 2019 and year-to-date were consistent with the same periods in 2018. Lower income from NSPML in both periods was due to timing of operational costs and lower interest revenues. Year-to-date, this decrease was partially offset by increased income from LIL, due to higher equity investment. In Q1 2018, NSPML began recording cash earnings and collecting UARB approved cash payments from NSPI.

Other Electric Utilities

All amounts are reported in USD, unless otherwise stated.

On March 25, 2019, Emera announced the sale of Emera Maine. The transaction is expected to close in late 2019, subject to MPUC approval. The Company will continue to record depreciation on these assets, through the transaction closing date, as the depreciation continues to be reflected in customer rates, and will be reflected in the carryover basis of the assets when sold. Refer to the “Developments” section for further details.


For the	Three months ended September 30				Nine months ended September 30
millions of US dollars (except per share amounts)	2019		2018		2019		2018

Operating revenues – regulated electric	$	144	$	157	$	421	$	434

Regulated fuel for generation and purchased power (1)		55		63		158		170

Adjusted contribution to consolidated net income	$	18	$	23	$	47	$	49

Adjusted contribution to consolidated net income – CAD	$	23	$	31	$	62	$	64

After-tax equity securities mark-to-market gain (loss)		-		1		2		(1)

Contribution to consolidated net income	$	18	$	24	$	49	$	48

Contribution to consolidated net income – CAD	$	23	$	31	$	64	$	62

Adjusted contribution to consolidated earnings per common share – basic – CAD	$	0.10	$	0.13	$	0.26	$	0.28

Contribution to consolidated earnings per common share – basic – CAD	$	0.10	$	0.13	$	0.27	$	0.27

Net income weighted average foreign exchange rate – CAD/USD	$	1.33	$	1.31	$	1.33	$	1.29



Adjusted EBITDA	$	52	$	60	$	149	$	153

Adjusted EBITDA – CAD	$	67	$	78	$	197	$	197

(1) Regulated fuel for generation and purchased power includes transmission pool expense.

Other Electric Utilities’ adjusted contribution is summarized in the following table:

For the millions of US dollars	Three months ended September 30				Nine months ended September 30

	2019		2018		2019		2018

Emera Maine	$	11	$	12	$	28	$	25

ECI		7		11		19		24

Adjusted contribution to consolidated net income	$	18	$	23	$	47	$	49

Net Income

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


For the millions of US dollars	Three months ended September 30		Nine months ended September 30

Contribution to consolidated net income – 2018	$	24	$	48

Decreased operating revenues - see Operating Revenues - Regulated Electric below (1)		(7)		(7)

Decreased regulated fuel for generation - see Regulated Fuel for Generation and Purchased Power below (1)		5		9

Decreased OM&G, primarily due to higher capitalized overheads as a result of higher capital spending at Emera Maine (1)		-		3

Decreased earnings at GBPC due to Hurricane Dorian		(6)		(6)

Other		2		2

Contribution to consolidated net income – 2019	$	18	$	49

(1) Excludes the impact of Hurricane Dorian at GBPC

Excluding the change in mark-to-market, Other Electric Utilities CAD contribution to consolidated net income decreased $8 million in Q3 2019, compared to Q3 2018. Year-to-date, the CAD contribution decreased $2 million compared to 2018. ECI’s contribution decreased in both periods due to lower earnings in GBPC as a result of the impact of Hurricane Dorian in Q3 2019, partially offset by higher sales volumes at Domlec due to the completion of hurricane restoration in 2018. Emera Maine’s contribution increased year-to-date due to higher capitalized overheads.

The foreign exchange rate had minimal impact for the three months ended September 30, 2019 and year-to-date increased CAD earnings by $2 million.

Operating Revenues – Regulated Electric

Operating revenues decreased $13 million to $144 million in Q3 2019, compared to $157 million in Q3 2018. Year-to-date revenues decreased $13 million to $421 million compared to $434 million in the same period in 2018. The decreases in both periods were due to lower sales at GBPC as a result of the impact of Hurricane Dorian, lower fuel costs at ECI and lower load at Emera Maine driven by unfavourable weather in Q3 2019. These decreases were partially offset by increased sales volumes at Domlec reflecting the completion of hurricane restoration in 2018. The year-to-date decrease was also due to lower stranded cost rates, unfavourable transmission revenue adjustments and lower transmission pool revenue as a result of lower rates at Emera Maine.

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

Q3 Electric Revenues

millions of USD



	2019		2018

Residential	$	53	$	55

Commercial		64		75

Industrial		8		9

Other (1)		19		18

Total	$	144	$	157

(1) Other revenue includes amounts recognized relating to Emera Maine’s FERC transmission rate refunds and other transmission revenue adjustments.

Q3 Electric Sales Volumes



GWh	2019		2018

Residential		313		327

Commercial		381		398

Industrial		124		123

Other		5		7

Total		823		855

YTD Electric Revenues

millions of USD



	2019		2018

Residential	$	153	$	150

Commercial		193		202

Industrial		25		26

Other (1)		50		56

Total	$	421	$	434

(1) Other revenue includes amounts recognized relating to Emera Maine’s FERC transmission rate refunds and other transmission revenue adjustments.

YTD Electric Sales Volumes



GWh	2019		2018

Residential		951		942

Commercial		1,116		1,139

Industrial		344		328

Other		19		20

Total		2,430		2,429

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power decreased $8 million to $55 million in Q3 2019, compared to $63 million in Q3 2018. Year-to-date, regulated fuel for generation and purchased power decreased $12 million to $158 million compared to $170 million in the same period in 2018. The decreases in both periods were due to lower oil prices at ECI and lower generation at GBPC as a result of the impact of Hurricane Dorian. The year-to-date decrease was also due to the expiration of a major purchased power contract at Emera Maine, partially offset by increased volumes at Domlec.

Q3 Production Volumes

GWh



	2019		2018

Oil		344		355

Hydro		5		7

Solar		5		5

Purchased power		9		7

Total		363		374

Q3 Average Fuel Costs



US dollars	2019		2018

Dollars per MWh		124		142

(1) Production volumes and average fuel costs relate to ECI only.

YTD Production Volumes

GWh



	2019		2018

Oil		1,006		995

Hydro		15		17

Solar		14		13

Purchased power		25		19

Total		1,060		1,044

YTD Average Fuel Costs



US dollars	2019		2018

Dollars per MWh		121		132

Average fuel cost per MWh decreased in Q3 2019 and year-to-date, compared to the same periods in 2018, due to lower oil prices.

Gas Utilities and Infrastructure

All amounts are reported in USD, unless otherwise stated.


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

	2019		2018		2019		2018

Operating revenues – regulated gas (1)	$	156	$	162	$	604	$	602

Operating revenues – non-regulated		3		3		9		10

Total operating revenue	$	159	$	165	$	613	$	612

Regulated cost of natural gas		40		49		188		209

Income from equity investments		4		4		14		13

Contribution to consolidated net income	$	20	$	13	$	102	$	72

Contribution to consolidated net income – CAD	$	25	$	15	$	132	$	93

Contribution to consolidated earnings per common share – basic – CAD	$	0.10	$	0.06	$	0.55	$	0.40

Net income weighted average foreign exchange rate – CAD/USD	$	1.34	$	1.29	$	1.33	$	1.26


EBITDA	$	51	$	61	$	227	$	214

EBITDA – CAD	$	66	$	78	$	299	$	274

(1) Operating revenues – regulated gas includes $13 million of finance income from Brunswick Pipeline (2018 - $11 million) for the three months ended September 30, 2019 and $34 million (2018 - $31 million) for the nine months ended September 30, 2019, however, it is excluded from the gas revenues analysis below.

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


For the millions of US dollars	Three months ended September 30				Nine months ended September 30

	2019		2018		2019		2018

PGS	$	10	$	9	$	42	$	36

NMGC		(1)		(5)		31		10

Other		11		9		29		26

Contribution to consolidated net income	$	20	$	13	$	102	$	72

Net Income

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


For the millions of US dollars	Three months ended September 30		Nine months ended September 30

Contribution to consolidated net income – 2018	$	13	$	72

Decreased gas operating revenues net of recognition of tax reform benefits - see Operating Revenues - Regulated Gas below		(6)		(7)

Decreased cost of natural gas sold - see Regulated Cost of Natural Gas below		9		21

Increased OM&G expenses quarter-over-quarter due to PGS tax reform settlement. In Q3 2018, PGS reversed deferred tax reform related OM&G expense recorded through Q2 2018 and recorded amortization expense related to the regulatory asset associated with manufactured gas plant (“MGP”) environmental remediation costs. Year-over-year, OM&G expense also increased due to higher insurance and benefits expense in PGS and NMGC in 2019		(12)		(8)

Decreased depreciation and amortization due to accelerated amortization of assets related to MGP environmental remediation costs in 2018 at PGS and reduced PGS depreciation rates in 2019 related to the settlement agreement to net amortization of the MGP environmental regulatory asset and 2018 tax reform benefits		8		14

Recognition of tax benefit related to change in treatment of NOL carryforwards at NMGC		5		5

Recognition of tax reform benefits, net of tax, from January 2018 through June 2019 in NMGC, of which $6 million relates to 2018		-		9

Other		3		(4)

Contribution to consolidated net income – 2019	$	20	$	102

Gas Utilities and Infrastructure’s CAD contribution to consolidated net income increased $10 million compared to Q3 2018. Year-to-date, Gas Utilities and Infrastructure’s CAD contribution to consolidated net income increased $39 million compared to 2018. NMGC’s recognition of the tax benefit related to the change in treatment of NOL carryforwards resulted in a $7 million ($5 million USD) increase in net income for Q3 2019 and year-to-date. The year-to-date increase was also due to NMGC’s recognition of tax reform benefits from January 1, 2018 to June 30, 2019, which resulted in a $12 million ($9 million USD) increase in Q2 2019; customer growth at PGS; favourable weather in New Mexico; and lower depreciation and amortization in PGS.

The foreign exchange rate had minimal impact for the three months ended September 30, 2019 and year-to-date 2019 increased CAD earnings by $4 million.

Operating Revenues – Regulated Gas

Beginning January 1, 2019, as approved by the FPSC, base rates at PGS were lowered by $12 million USD annually to reflect the impact of tax reform, resulting in a $3 million USD decrease in revenue in Q3 2019 and a $8 million decrease year-to-date.

Gas Utilities and Infrastructure’s operating revenues decreased $6 million to $156 million in Q3 2019, compared to $162 million in Q3 2018. The decrease was the result of lower off-system sales at PGS and lower base rates at PGS reflecting the impact of tax reform, partially offset by customer growth in PGS and higher clause revenues in New Mexico.

Year-to-date operating revenues increased $2 million to $604 million compared to $602 million in the same period in 2018. The increase was the result of customer growth in PGS, favourable weather in New Mexico and the NMPRC’s approval of NMGC retaining tax reform benefits from January 1, 2018 to June 30, 2019. These increases were offset by unfavourable weather, lower off-system sales and lower base rates at PGS reflecting the impact of tax reform, and lower clause-related revenues at PGS and New Mexico due lower cost of natural gas sold.

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

Q3 Gas Revenues

millions of US dollars



	2019		2018

Residential	$	58	$	57

Commercial		43		42

Industrial (1)		9		10

Other (2)		33		42

Total (3)	$	143	$	151

(1)	Industrial includes sales to power generation customers.

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

(3)	Excludes $13 million of finance income from Brunswick Pipeline (2018 – $11 million).

YTD Gas Revenues

millions of US dollars



	2019		2018

Residential	$	270	$	265

Commercial		162		165

Industrial (1)		28		28

Other (2)		110		113

Total (3)	$	570	$	571

(1)	Industrial includes sales to power generation customers.

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

(3)	Excludes $34 million of finance income from Brunswick Pipeline (2018 – $31 million).

Q3 Gas Volumes

Therms (millions)



	2019		2018

Residential		35		34

Commercial		165		156

Industrial		386		367

Other		93		86

Total		679		643

YTD Gas Volumes

Therms (millions)



	2019		2018

Residential		275		248

Commercial		605		581

Industrial		1,106		999

Other		229		197

Total		2,215		2,025

Regulated Cost of Natural Gas

Regulated cost of natural gas decreased $9 million to $40 million in Q3 2019, compared to $49 million in Q3 2018. Year-to-date, regulated cost of natural gas decreased $21 million to $188 million in Q3 2019, compared to $209 million in the same period in 2018. The decrease in both periods was due to lower commodity costs in PGS, lower PGS off-system volume sales and lower commodity costs in New Mexico year-to-date.

Gas sales by type are summarized in the following table:

Q3 Gas Volumes by Type

Therms (millions)



	2019		2018

System supply		110		127

Transportation		569		516

Total		679		643

YTD Gas Volumes by Type

Therms (millions)



	2019		2018

System supply		519		503

Transportation		1,696		1,522

Total		2,215		2,025

Other


For the	Three months ended September 30				Nine months ended September 30
millions of Canadian dollars (except per share amounts)	2019		2018		2019		2018

Marketing and trading margin (1) (2)	$	(23)	$	6	$	3	$	73

Electricity and capacity sales (3) (4)		-		106		116		313

Other non-regulated operating revenue		12		13		30		35

Total operating revenues – non-regulated	$	(11)	$	125	$	149	$	421

Intercompany revenue (5)		4		10		17		29

Non-regulated fuel for generation and purchased power (4)(6)		-		54		66		170

Operating, maintenance and general		29		40		103		130

Depreciation and amortization		2		14		8		40

Income from equity investments		8		10		25		24

Interest expense, net		81		92		256		271

Adjusted contribution to consolidated net income (loss)	$	(112)	$	(34)	$	(228)	$	(125)

After-tax derivative mark-to-market gain (loss)	$	(67)	$	(73)	$	(8)	$	(23)

Contribution to consolidated net income (loss)	$	(179)	$	(107)	$	(236)	$	(148)

Adjusted contribution to consolidated earnings per common share – basic	$	(0.46)	$	(0.15)	$	(0.95)	$	(0.54)

Contribution to consolidated earnings per common share – basic	$	(0.74)	$	(0.46)	$	(0.99)	$	(0.64)


Adjusted EBITDA	$	(42)	$	45	$	7	$	148

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

(2) Marketing and trading margin excludes a pre-tax mark-to-market loss of $102 million in Q3 2019 (2018 - $108 million loss) and a loss of $19 million year-to-date (2018 – $71 million loss).

(3) Electricity and capacity sales exclude a pre-tax mark-to-market loss of nil in Q3 2019 (2018 - $3 million loss) and year-to-date gain of $2 million (2018 – $28 million gain).

(4) On March 29, 2019, Emera completed the sale of the NEGG facilities. Refer to the “Developments” section for further details.

(5) Intercompany revenue consists of interest from Brunswick Pipeline and M&NP.

(6) Non-regulated fuel for generation and purchased power excludes a pre-tax mark-to-market gain of $2 million in Q3 2019 (2018 - $2 million gain) and year-to-date $1 million loss (2018 – $5 million gain).

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


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

	2019		2018		2019		2018

Emera Energy	$	(14)	$	19	$	19	$	76

Corporate		(99)		(53)		(247)		(202)

Other		1		-		-		1

Adjusted contribution to consolidated net income (loss)	$	(112)	$	(34)	$	(228)	$	(125)

Net Income

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


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

Contribution to consolidated net income (loss) – 2018	$	(107)	$	(148)

Decreased marketing and trading margin - see Emera Energy below		(29)		(70)

Impact of sale of NEGG and Bayside Power, net of tax		(18)		(22)

Transaction costs related to the pending sale of Emera Maine		(2)		(6)

Decreased income tax recovery due to 2018 recognition of Florida state tax apportionment benefit		(23)		(23)

Increased income tax recovery primarily due to increased losses before provision for income taxes		8		19

Corporate share of the unrecoverable loss on GBPC facilities		(9)		(9)

Increased preferred stock dividends due to the issuance of preferred shares in Q2 2018		(1)		(9)

Gain on sale of property in Florida, pre-tax		-		14

Decreased mark-to-market loss, net of tax, quarter-over-quarter primarily due to change in existing positions on gas contracts, partially offset by higher amortization of gas transportation assets. Year-over-year decreased mark-to-market loss, net of tax, due to changes in existing positions on gas contracts and a larger reversal of mark-to-market losses in 2019, compared to 2018, partially offset by higher amortization of gas transportation assets in 2019		6		15

Other		(4)		3

Contribution to consolidated net income (loss) – 2019	$	(179)	$	(236)

Excluding the change in mark-to-market, Other’s contribution to consolidated net income decreased by $78 million for the quarter and $103 million year-to-date compared to the same periods in 2018. In both periods, the decrease was due to lower marketing and trading margin, the impact of the sale of NEGG and Bayside Power, the corporate share of the unrecoverable loss on GBPC’s facilities, decreased income tax recovery and higher preferred stock dividends. The year-to-date decrease was partially offset by the gain on sale of property in Florida.

Emera Energy

Marketing and trading margin decreased $29 million to $(23) million in Q3 2019, compared to $6 million in Q3 2018. Year-to-date margin decreased $70 million to $3 million in 2019, compared to $73 million for the same period in 2018. The decrease in both periods was due to less favourable market conditions, specifically lower natural gas prices and volatility and higher fixed cost commitments for gas transportation and storage assets in 2019, compared to 2018.

LIQUIDITY AND CAPITAL RESOURCES

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

Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing rate base investment, business acquisitions, greenfield development, dividends and debt servicing. Emera has a $6.9 billion capital investment plan over the 2020-to-2022 period, including significant rate base investments across the portfolio in renewable and cleaner generation, infrastructure modernization and customer-focused technologies. Capital expenditures at the regulated utilities are subject to regulatory approval. Emera plans to use cash from operations, debt raised at the utilities and proceeds from the Emera Maine sale, to support normal operations, repayment of existing debt and capital requirements. Debt raised at certain of the Company’s utilities is subject to applicable regulatory approvals. Equity requirements in support of the Company’s capital investment plan will predominantly be funded in the equity capital markets through the dividend reinvestment plan and the issuance of common and preferred equity. Emera has credit facilities with varying maturities that cumulatively provide $3.1 billion of credit. Refer to the “Debt Management” section for additional information regarding the credit facilities.

Consolidated Cash Flow Highlights

Significant changes in the Condensed Consolidated Statements of Cash Flows between the nine months ended September 30, 2019 and 2018 include:


millions of Canadian dollars	2019		2018		Change

Cash, cash equivalents and restricted cash, beginning of period	$	372	$	503	$	(131)

Provided by (used in):

Operating cash flow before change in working capital		1,182		1,237		(55)

Change in working capital		128		156		(28)

Operating activities		1,310		1,393		(83)

Investing activities		(786)		(1,565)		779

Financing activities		(546)		121		(667)

Effect of exchange rate changes on cash, cash equivalents, restricted cash and cash included in assets held for sale		(13)		11		(24)

Cash, cash equivalents, restricted cash and cash included in assets held for sale, end of period	$	337	$	463	$	(126)

Cash Flow from Operating Activities

Net cash provided by operating activities decreased $83 million to $1,310 million for the nine months ended September 30, 2019, compared to $1,393 million for the same period in 2018.

Cash from operations before changes in working capital decreased $55 million. The decrease was due to lower marketing and trading margin at EES and lower earnings from EEG as a result of the sale of NEGG and Bayside. These were partially offset by lower under-recovery from customers on clause related costs at Tampa Electric.

Changes in working capital decreased operating cash flows by $28 million. The decrease was due to unfavourable changes in cash collateral at NSPI and Emera Energy. These were partially offset by a refund of $146 million ($109 million USD) of alternative minimum tax credit carryforwards in April 2019 and favourable changes in accounts payable at Tampa Electric.

Cash Flow used in Investing Activities

Net cash used in investing activities decreased $779 million to $786 million for the nine months ended September 30, 2019, compared to $1,565 million for the same period in 2018. In 2019, Emera received proceeds of $866 million on dispositions, primarily from the sale of the NEGG and Bayside facilities. These proceeds were partially offset by an increase in capital expenditures.

Capital expenditures for the nine months ended September 30, 2019, including AFUDC, were $1,662 million compared to $1,556 million for the same period in 2018. Details of the 2019 capital spend by segment are shown below:

●

$919 million - Florida Electric Utility (2018 – $915 million);

●

$263 million - Canadian Electric Utilities (2018 – $251 million);

●

$127 million - Other Electric Utilities (2018 – $120 million);

●

$295 million - Gas Utilities and Infrastructure (2018 – $220 million); and

●

$58 million - Other (2018 – $50 million).

Cash Flow from Financing Activities

Net cash used in financing activities increased $667 million to $546 million for the nine months ended September 30, 2019, compared to net cash provided by financing activities of $121 million for the same period in 2018. The increase was due to repayment of corporate long-term debt, net repayment of committed credit facilities at Tampa Electric, a 2018 preferred share issuance and repayments at NSPI. These were partially offset by proceeds from the issuance of long-term debt at NSPI in 2019 and the 2018 repayment of debt at TECO Finance.

Contractual Obligations

As at September 30, 2019, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:


millions of Canadian dollars	2019		2020		2021		2022		2023		Thereafter		Total

Long-term debt principal (1)	$	249	$	548	$	1,686	$	547	$	1,168	$	10,800	$	14,998

Interest payment obligations (2)(3)		297		664		618		581		554		7,488		10,202

Purchased power (4)(5)		63		208		231		245		249		2,496		3,492

Transportation (6)		140		426		346		307		267		2,955		4,441

Pension and post-retirement obligations (7)(8)		9		34		34		35		36		1,030		1,178

Capital projects (9)		305		292		37		11		1		-		646

Fuel, gas supply and storage		196		440		104		4		1		-		745

Asset retirement obligations		2		9		44		1		1		362		419

Long-term service agreements (10)(11)		10		43		30		29		21		124		257

Equity investment commitments (12)		-		-		190		-		-		-		190

Leases and other (13)		10		16		17		16		10		126		195

Demand side management		12		31		37		39		-		-		119

Long-term payable		1		5		5		5		5		-		21

Convertible debentures		-		-		-		-		-		2		2

	$	1,294	$	2,716	$	3,379	$	1,820	$	2,313	$	25,383	$	36,905

As noted below, Contractual Obligations at September 30, 2019 include contractual commitments related to Emera Maine. On completion of the sale of Emera Maine, all of the remaining future obligations related to these contractual commitments will be transferred to the buyer. Refer to the “Developments” section for additional information.

(1) Includes $515 million related to Emera Maine ($40 million in 2020; $119 million in 2022; $79 million in 2023 and $277 million thereafter).

(2) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at September 30, 2019, including any expected required payment under associated swap agreements.

(3) Includes $345 million related to Emera Maine ($5 million in 2019; $20 million in 2020; $18 million in 2021; $13 million in 2022; $12 million in 2023 and $277 million thereafter).

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

(5) Includes $551 million related to Emera Maine ($4 million in 2019; $14 million in 2020; $25 million in 2021; $32 million in 2022; $32 million in 2023 and $444 million thereafter).

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

(7) Defined benefit funding contractual obligations were determined based on funding requirements and assuming pension accruals cease as at December 31, 2018. Credited service and earnings are assumed to be crystallized as at December 31, 2018. The Company’s contractual obligations for post-retirement (non-pension) benefits assumes members must be age 55 or over (50 for TECO Energy) as at December 31, 2018 to be eligible. As the defined benefit pension plans currently undergo regular reviews to revise contribution requirements and members are still accruing service under the plans, actual future contributions to the plans will differ from the amounts shown.

(8) Includes $88 million related to Emera Maine ($1 million in 2019; $7 million in 2020; $7 million in 2021; $7 million in 2022; $7 million in 2023 and $59 million thereafter).

(9) Includes $356 million of commitments related to Tampa Electric’s solar and Big Bend Power Station modernization projects.

(10) 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.

(11) Includes $26 million related to various long-term service agreements Emera Maine has entered into for IT maintenance and vegetation management ($4 million in 2019; $14 million in 2020; $4 million in 2021; $2 million in 2022; and $2 million in 2023).

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

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

NSPI has a contractual obligation to pay NSPML for the use of the Maritime Link over approximately 37 years from its January 15, 2018 in-service date. The UARB approved payment for 2019 is $111 million, which is currently included in NSPI rates. This payment is subject to a $10 million holdback. On June 14, 2019, NSPML filed an interim assessment application requesting recovery of 2020 costs of approximately $145 million, subject to a $10 million holdback, with a decision expected in Q4 2019. NSPI has included the difference of $34 million in its proposed fuel stability plan filed with the UARB. After 2020, the timing and amounts payable to NSPML will be subject to 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 would 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 Nova Scotia Block, and continuing for 50 years. As transmission rights are contracted, Emera includes the obligations within “Leases and other” in the above table.

Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to approximately $3.1 billion committed syndicated revolving bank lines of credit in either CAD or USD per the table below.


millions of dollars	Maturity		Revolving Credit Facilities		Utilized		Undrawn and Available

Emera Inc. – Operating and acquisition credit facility		June 2024	$	900	$	432	$	468

TECO Finance, Inc. – in USD – Operating credit facilities		March 2020 - March 2022		900		500		400

NSPI – Operating credit facility		October 2023		600		270		330

TEC – in USD – credit facilities (1)		March 2021 - March 2022		475		137		338

NMGC – in USD – Operating credit facility		March 2022		125		73		52

Emera Maine – in USD – Operating credit facility		February 2023		80		62		18

Other – in USD – Operating credit facility		Various		32		11		21

(1) This facility is available for use by Tampa Electric and PGS. At September 30, 2019, Tampa Electric had utilized $93 million USD and PGS had utilized $44 million USD of the facility.

Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly and the Company is in compliance with covenant requirements as at September 30, 2019.

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

Florida Electric Utilities

On July 24, 2019, TEC completed a $300 million USD 30-year senior notes issuance. The notes bear interest at a rate of 3.625 per cent and have a maturity date of June 15, 2050.

Canadian Electric Utilities

On August 2, 2019, NSPI repaid a $95 million debenture upon maturity. The debenture was repaid using its operating credit facility.

On April 4, 2019, NSPI completed a $400 million Series AB 30-year medium term notes issuance. The notes bear interest at a rate of 3.57 per cent and have a maturity date of April 5, 2049.

Gas Utilities and Infrastructure

On July 31, 2019, New Mexico Gas Intermediate (“NMGI”) repaid a $50 million USD note upon maturity. The note was repaid using cash on hand.

On May 17, 2019, Emera Brunswick Pipeline amended the maturity date of its $250 million Credit Agreement from February 2022 to May 2023. There were no other material changes in commercial terms.

Other

On June 14, 2019, Emera US Finance LP repaid a $500 million USD note upon maturity. The note was repaid using short-term investments, temporarily held from the sale of the NEGG facilities.

On June 13, 2019, Emera extended the maturity date of its $900 million revolving credit facility from June 2020 to June 2024. There were no other significant changes in commercial terms from the prior agreement.

On March 7, 2019, TECO Energy/Finance extended the maturity date of its $500 million USD credit facility from March 8, 2019 to March 5, 2020. There were no other significant changes in commercial terms from the prior agreement.

Credit Ratings

On June 27, 2019, Moody’s Investor Services affirmed Emera’s Baa3 issuer and senior unsecured ratings and Emera US Finance LP’s Baa3 guaranteed senior unsecured rating and changed its ratings outlook to stable from negative.

On June 13, 2019, Fitch Ratings assigned ratings and outlook for Emera for the first time. Emera was assigned a BBB issuer default and senior unsecured rating with stable outlook. At the same time, Fitch Ratings assigned TEC an A- issuer default rating and an A senior unsecured rating with stable outlook.

Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2018 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, 2018 - $67 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 Reinsurance Limited has issued a standby letter of credit to secure obligations under reinsurance agreements. The expiry date of this letter of credit was extended to May 2020. This letter of credit is renewed annually. The amount committed as of September 30, 2019 was $4 million USD (December 31, 2018 - $6 million USD).

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 2020. The amount committed as at September 30, 2019 was $52 million (December 31, 2018 - $49 million).

TRANSACTIONS WITH RELATED PARTIES

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 $26 million for the three months ended September 30, 2019 (2018 - $25 million) and $80 million for the nine months ended September 30, 2019 (2018 - $76 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.

Refer to the “Business Overview and Outlook - Canadian Electric Utilities - ENL” and “Contractual Obligations” sections for further details.

●

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 $16 million for the three months ended September 30, 2019 (2018 - $6 million) and $50 million for the nine months ended September 30, 2019 (2018 - $22 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, 2019 and at December 31, 2018.

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

There have been no material changes in Emera’s risk management profile and practices from those disclosed in the Company’s 2018 annual MD&A, with the exception of the following update to labour risk:

Approximately 30 per cent of Emera’s employees are within the NSPI labour force and approximately 50 per cent of those employees are represented by the International Brotherhood of Electrical Workers Local 1928 (“IBEW”). NSPI and the IBEW reached a new collective agreement, ratified on August 23, 2019, for a four-year term ending on March 31, 2023. The previous collective agreement governing these employees expired on March 31, 2019.

Hedging Items Recognized on the Balance Sheets

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


As at millions of Canadian dollars	September 30 2019		December 31 2018

Derivative instrument liabilities (current and long-term liabilities)	$	(1)	$	(5)

Net derivative instrument assets (liabilities)	$	(1)	$	(5)

Hedging Impact Recognized in Net Income

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


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

	2019		2018		2019		2018

Operating revenues – regulated	$	(1)	$	1	$	(3)	$	5

Non-regulated fuel for generation and purchased power		-		(1)		-		2

Effective net gains (losses)	$	(1)	$	-	$	(3)	$	7

The effective net gains (losses) reflected in the above table would be offset in net income by the hedged item realized in the period.

Regulatory Items Recognized on the Balance Sheets

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


As at millions of Canadian dollars	September 30 2019		December 31 2018

Derivative instrument assets (current and other assets)	$	44	$	104

Regulatory assets (current and other assets)		65		6

Derivative instrument liabilities (current and long-term liabilities)		(65)		(6)

Regulatory liabilities (current and long-term liabilities)		(55)		(115)

Net asset (liability)	$	(11)	$	(11)

Regulatory Impact Recognized in Net Income

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


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

	2019		2018		2019		2018

Regulated fuel for generation and purchased power (1)	$	-	$	6	$	7	$	11

Net gains (losses)	$	-	$	6	$	7	$	11

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

HFT Items Recognized on the Balance Sheets

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


As at millions of Canadian dollars	September 30 2019		December 31 2018

Derivative instrument assets (current and other assets)	$	52	$	62

Derivative instrument liabilities (current and long-term liabilities)		(310)		(354)

Net derivative instrument assets (liabilities)	$	(258)	$	(292)

HFT Items Recognized in Net Income

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


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

	2019		2018		2019		2018

Operating revenue - non-regulated	$	(69)	$	(105)	$	180	$	44

Non-regulated fuel for purchased power		1		2		(4)		2

Net gains (losses)	$	(68)	$	(103)	$	176	$	46

Other Derivatives Recognized on the Balance Sheets

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


As at millions of Canadian dollars	September 30 2019		December 31 2018

Derivative instrument assets (current and other assets)	$	33	$	1

Net derivative instrument assets (liabilities)	$	33	$	1

Other Derivatives Recognized in Net Income

For the three months ended September 30, 2019, the Company had unrealized gains on equity derivatives of $11 million (2018 – nil) and $34 million for the nine months ended September 30, 2019 (2018- nil) recorded in Operating, maintenance and general expense in the Condensed Consolidated Statements of Income.

DISCLOSURE AND INTERNAL CONTROLS

Management is responsible for establishing and maintaining adequate disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”). The Company’s internal control framework is based on the criteria published in the Internal Control - Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations (“COSO”) of the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer, evaluated the design of the Company’s DC&P and ICFR as at September 30, 2019, to provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.

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

There were no changes in the Company’s ICFR during the quarter ended September 30, 2019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

CRITICAL ACCOUNTING ESTIMATES

The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. 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.

Significant areas requiring the use of management estimates relate to rate-regulated assets and liabilities, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, capitalized overhead and valuation of financial instruments. Actual results may differ significantly from these estimates. There were no material changes in the nature of the Company’s critical accounting estimates from those disclosed in the Company’s 2018 annual MD&A.

CHANGES IN ACCOUNTING POLICIES AND PRACTICES

The new USGAAP accounting policies that are applicable to, and adopted by the Company in 2019 are described as follows:

Leases

On January 1, 2019, the Company adopted Accounting Standard Updates (“ASU”) 2016-02, Leases (Topic 842), including all related amendments, using the modified retrospective approach. The standard requires lessees to recognize leases on the balance sheet for all leases with a term of longer than twelve months and disclose key information about leasing arrangements.

As permitted by the optional transition method, Emera did not restate comparative financial information in the Company’s condensed consolidated financial statements, did not reassess whether any expired or existing contracts contained leases and carried forward existing lease classifications. Additionally, the Company elected to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under the leasing guidance within ASC Topic 840. The Company elected to use hindsight to determine the lease term for existing leases and elected to not separate lease components from non-lease components for all lessee and lessor arrangements.

Emera has implemented additional processes and controls to facilitate the identification, tracking and reporting of potential leases based on the requirements of the standard. There were no updates to information technology systems as a result of implementation.

The Company’s adoption of this new standard resulted in right-of-use (“ROU”) assets and lease liabilities of approximately $58 million as of January 1, 2019. The ROU assets and lease liabilities were measured at the present value of remaining lease payments using the Company’s incremental borrowing rate.

There was no impact to opening retained earnings as at January 1, 2019 or the Company’s net income or cash flows for the three and nine months ended September 30, 2019 as a result of the adoption of the standard. There were no significant impacts to Emera’s accounting for lessor arrangements. Refer to note 16 of the financial statements for further detail.

Targeted Improvements to Accounting for Hedging Activities

On January 1, 2019, the Company adopted ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting recognition and presentation requirements in ASC Topic 815. This standard improves the transparency and understandability of information about an entity’s risk management activities by better aligning the entity’s financial reporting for hedging relationships with those risk management activities and simplifies the application of hedge accounting. The standard will make more financial and nonfinancial hedging strategies eligible for hedge accounting, amends the presentation and disclosure requirements for hedging activities and changes how entities assess hedge effectiveness. There was no impact on the condensed consolidated financial statements as a result of the adoption of this standard.

Cloud Computing

In August 2018, the Financial Accounting Standards Board (“FASB”) issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. The standard allows entities who are customers in hosting arrangements that are service contracts to apply the existing internal-use software guidance to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The guidance specifies classification for capitalizing implementation costs and related amortization expense within the financial statements and requires additional disclosures. The guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted and can be applied either retrospectively or prospectively. The Company early adopted the standard effective January 1, 2019 and elected to apply the guidance prospectively. There was no material impact on the condensed consolidated financial statements as a result of the adoption of this standard.

Future Accounting Pronouncements

The Company considers the applicability and impact of all ASUs issued by the FASB. The ASUs that have been issued, but that are not yet effective, are consistent with those disclosed in the Company’s 2018 audited consolidated financial statements, with updates noted below.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. 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. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019, and will be applied using a modified retrospective approach. Early adoption is permitted for annual reporting periods, including interim periods after December 15, 2018. The Company will not early adopt the standard. The Company does not expect a material impact on its consolidated financial statements as a result of adoption of the standard.

SUMMARY OF QUARTERLY RESULTS


For the quarter ended millions of Canadian dollars (except per share amounts)	Q3 2019		Q2 2019		Q1 2019		Q4 2018		Q3 2018		Q2 2018		Q1 2018		Q4 2017

Operating revenues	$	1,299	$	1,378	$	1,818	$	1,799	$	1,495	$	1,423	$	1,807	$	1,473

Net income (loss) attributable to common shareholders		55		103		312		231		118		90		271		(228)

Adjusted net income attributable to common shareholders		122		130		224		167		191		111		202		137

Earnings per common share – basic		0.23		0.43		1.32		0.98		0.51		0.38		1.17		(1.06)

Earnings per common share – diluted		0.23		0.43		1.32		0.98		0.50		0.38		1.17		(1.06)

Adjusted earnings per common share – basic		0.51		0.54		0.95		0.71		0.82		0.48		0.87		0.64

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

EX-99.2 3 d805356dex992.htm EX-99.2 EX-99.2

Exhibit 99.2

EMERA INCORPORATED

Unaudited Condensed Consolidated

Interim Financial Statements

September 30, 2019 and 2018

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

	2019		2018		2019		2018


Operating revenues
Regulated electric	$	1,220	$	1,289	$	3,598	$	3,624

Regulated gas		199		202		785		749

Non-regulated		(120)		4		112		352

Total operating revenues (note 6)		1,299		1,495		4,495		4,725


Operating expenses
Regulated fuel for generation and purchased power		388		448		1,207		1,250

Regulated cost of natural gas		52		65		249		267

Non-regulated fuel for generation and purchased power		(4)		49		63		159

Operating, maintenance and general		367		370		1,076		1,139

Provincial, state and municipal taxes		88		89		258		256

Depreciation and amortization		226		236		678		687

Total operating expenses		1,117		1,257		3,531		3,758

Income from operations		182		238		964		967


Income from equity investments (note 7)		38		41		118		121

Other income (expenses), net		(8)		5		11		(16)

Interest expense, net		183		176		557		527

Income before provision for income taxes		29		108		536		545


Income tax expense (recovery) (note 8)		(49)		(33)		18		29

Net income		78		141		518		516


Non-controlling interest in subsidiaries		1		1		3		1

Preferred stock dividends		22		22		45		36

Net income attributable to common shareholders	$	55	$	118	$	470	$	479


Weighted average shares of common stock outstanding (in millions) (note 10)

Basic		241.0		233.7		238.9		232.4

Diluted		242.4		235.2		240.3		233.9


Earnings per common share (note 10)
Basic	$	0.23	$	0.51	$	1.97	$	2.06

Diluted	$	0.23	$	0.50	$	1.96	$	2.05


Dividends per common share declared	$	1.2000	$	1.1525	$	2.3750	$	2.2825

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

	2019		2018		2019		2018

Net income	$	78	$	141	$	518	$	516

Other comprehensive income (loss), net of tax
Foreign currency translation adjustment		95		(126)		(243)		220

Unrealized gains (losses) on net investment hedges (1) (2)		(19)		25		48		(41)

Cash flow hedges

Net derivative gains (losses)		-		3		3		5

Less: reclassification adjustment for losses (gains) included in income (3)		1		-		3		(6)

Net effects of cash flow hedges		1		3		6		(1)

Unrealized gains (losses) on available-for-sale investment

Less: reclassification adjustment for (gains) losses recognized in income		-		-		-		(4)

Net unrealized holding gains (losses)		-		-		-		(4)

Net change in unrecognized pension and post-retirement benefit obligation (4)		3		7		11		26

Other comprehensive income (loss) (5)		80		(91)		(178)		200

Comprehensive income (loss)		158		50		340		716

Comprehensive income (loss) attributable to non-controlling interest		1		-		2		3

Comprehensive income (loss) of Emera Incorporated	$	157	$	50	$	338	$	713

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

(1) Net of tax expense of nil (2018 - $2 million tax expense) for the three months ended September 30, 2019 and tax expense of nil (2018 – $7 million tax recovery) for the nine months ended September 30, 2019.

(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 (2018 - nil) for the three months ended September 30, 2019 and tax expense of nil (2018 – $1 million tax recovery) for the nine months ended September 30, 2019.

(4) Net of tax expense of nil (2018 - nil) for the three months ended September 30, 2019 and tax expense of $1 million (2018 – $1 million tax expense) for the nine months ended September 30, 2019.

(5) Net of tax expense of nil (2018 - $2 million tax expense) for the three months ended September 30, 2019 and tax expense of $1 million (2018 – $7 million tax recovery) for the nine months ended September 30, 2019.

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)


As at millions of Canadian dollars	September 30 2019		December 31 2018

Assets
Current assets
Cash and cash equivalents	$	273	$	316

Restricted cash		63		56

Inventory		479		474

Derivative instruments (notes 12 and 13)		99		148

Regulatory assets (note 14)		123		165

Receivables and other current assets		1,246		1,620

Assets held for sale (note 4)		85		53

		2,368		2,832

Property, plant and equipment, net of accumulated depreciation and amortization of $8,345 and $8,567, respectively		17,867		18,712

Other assets
Deferred income taxes		218		175

Derivative instruments (notes 12 and 13)		30		19

Regulatory assets (note 14)		1,396		1,404

Net investment in direct financing lease (note 16)		474		475

Investments subject to significant influence (note 7)		1,301		1,316

Goodwill (note 14)		5,979		6,313

Other long-term assets		298		291

Assets held for sale (note 4)		1,634		777

		11,330		10,770

Total assets	$	31,565	$	32,314

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited) – Continued


As at millions of Canadian dollars	September 30 2019		December 31 2018

Liabilities and Equity
Current liabilities
Short-term debt (note 18)	$	958	$	1,186

Current portion of long-term debt		717		1,119

Accounts payable		1,061		1,289

Derivative instruments (notes 12 and 13)		275		260

Regulatory liabilities (note 14)		289		251

Other current liabilities		621		428

Liabilities associated with assets held for sale (note 4)		94		20

		4,015		4,553

Long-term liabilities
Long-term debt (note 19)		13,660		14,292

Deferred income taxes		1,213		1,320

Derivative instruments (notes 12 and 13)		101		105

Regulatory liabilities (note 14)		1,976		2,359

Pension and post-retirement liabilities (note 17)		519		641

Other long-term liabilities		802		684

Long-term liabilities associated with assets held for sale (note 4)		906		2

		19,177		19,403

Equity
Common stock (note 9)		6,115		5,816

Cumulative preferred stock		1,004		1,004

Contributed surplus		78		84

Accumulated other comprehensive income (note 11)		161		338

Retained earnings		980		1,075

Total Emera Incorporated equity		8,338		8,317

Non-controlling interest in subsidiaries (note 21)		35		41

Total equity		8,373		8,358

Total liabilities and equity	$	31,565	$	32,314

Commitments and contingencies (note 20)

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	2019		2018

Operating activities
Net income	$	518	$	516

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization		684		695

Income from equity investments, net of dividends		(60)		(64)

Allowance for equity funds used during construction		(14)		(14)

Deferred income taxes, net		82		8

Net change in pension and post-retirement liabilities		(26)		(1)

Regulated fuel adjustment mechanism		(20)		(10)

Net change in fair value of derivative instruments		(51)		122

Net change in regulatory assets and liabilities		19		64

Net change in capitalized transportation capacity		42		(79)

Other operating activities, net		8		-

Changes in non-cash working capital (note 22)		128		156

Net cash provided by operating activities		1,310		1,393

Investing activities
Proceeds from dispositions (note 4)		866		-

Additions to property, plant and equipment		(1,647)		(1,544)

Net purchase of investments subject to significant influence, inclusive of acquisition costs		(3)		(43)

Other investing activities		(2)		22

Net cash used in investing activities		(786)		(1,565)

Financing activities
Change in short-term debt, net		(188)		91

Proceeds from short-term debt with maturities greater than 90 days		-		129

Proceeds from long-term debt, net of issuance costs		841		488

Retirement of long-term debt		(851)		(728)

Net borrowings (repayments) under committed credit facilities		(165)		152

Issuance of common stock, net of issuance costs		151		8

Issuance of preferred stock, net of issuance costs		-		291

Dividends on common stock		(278)		(256)

Dividends on preferred stock		(34)		(24)

Other financing activities		(22)		(30)

Net cash (used in) provided by financing activities		(546)		121

Effect of exchange rate changes on cash, cash equivalents, and restricted cash		(13)		11

Net decrease in cash, cash equivalents, restricted cash and assets held for sale		(35)		(40)

Cash, cash equivalents, restricted cash and assets held for sale, beginning of period		372		503

Cash, cash equivalents, restricted cash and assets held for sale, end of period	$	337	$	463

Cash, cash equivalents, restricted cash, and assets held for sale consists of:
Cash	$	266	$	319

Short-term investments		7		74

Restricted cash		63		70

Assets held for sale		1		-



Cash, cash equivalents, restricted cash, and assets held for sale	$	337	$	463

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, 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 (note 21)		-		-		-		-		-		14		14

Redemption of preferred shares of GBPC (note 21)		-		-		-		-		-		(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 options 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; $1.22500

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, 2018

Balance, June 30, 2018		$ 5,724		$ 1,004		$ 82		$ 123		$ 997		$ 40		$ 7,970

Net income of Emera Incorporated		-		-		-		-		140		1		141

Other comprehensive income (loss), net of tax expense of $2 million		-		-		-		(90)		-		(1)		(91)

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

Dividends declared on common stock ($1.1525/share)		-		-		-		-		(268)		-		(268)

Common stock issued under purchase plan		43		-		-		-		-		-		43

Acquisition of non-controlling interest of ECI		-		-		1		-		-		-		1

Other		1		-		-		-		-		-		1

Balance, September 30, 2018		$ 5,768		$ 1,004		$ 83		$ 33		$ 847		$ 40		$ 7,775


millions of Canadian dollars

For the nine months ended September 30, 2018

Balance, December 31, 2017		$ 5,601		$ 709		$ 76		$ (165)		$ 891		$ 92		$ 7,204

Net income of Emera Incorporated		-		-		-		-		515		1		516

Other comprehensive income (loss), net of tax recovery of $7 million		-		-		-		198		-		2		200

Dividends declared on preferred stock (2)		-		-		-		-		(36)		-		(36)

Dividends declared on common stock ($2.2825/share)		-		-		-		-		(528)		-		(528)

Issuance of preferred shares, net of after-tax issuance costs		-		295		-		-		-		-		295

Common stock issued under purchase plan		143		-		-		-		-		-		143

Acquisition of non-controlling interest of ECI		22		-		6		-		-		(53)		(25)

Other		2		-		1		-		5		(2)		6

Balance, September 30, 2018		$ 5,768		$ 1,004		$ 83		$ 33		$ 847		$ 40		$ 7,775

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

(1) Series A; $0.31940/share, Series B; $0.39480/share, Series C; $0.55131/share, Series E; $0.56250/share, Series F; $0.53125/share, and Series H; $0.56132/share

(2) Series A; $0.63880/share, Series B; $0.75700/share, Series C; $1.06381/share, Series E; $1.12500/share, Series F; $1.06250/share and Series H; $0.56132/share

Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)

As at September 30, 2019 and 2018

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.

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 and forecasted to be generating first power in 2019 and full power in 2020. ENL’s two investments are:

●

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

●

a 49.5 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, which it forecasts to be operational in 2020.

●

Other Electric Utilities, which includes:

●

Emera Maine, a regulated electric transmission and distribution utility, in the state of Maine. On March 25, 2019, Emera announced an agreement to sell Emera Maine. The transaction is expected to close in late 2019, subject to approval of the Maine Public Utilities Commission (“MPUC”). Refer to note 4 for further details; and

●

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. On September 1, 2019, Grand Bahama Island was struck by Hurricane Dorian, causing significant damage. Refer to note 14 for further details;

●

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

●

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.

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;

●

Bridgeport Energy, Tiverton Power and Rumford Power (“New England Gas Generating Facilities” or “NEGG”), power plants in the northeastern United States. On March 29, 2019, Emera completed the sale of the NEGG facilities. Refer to note 4 for further details;

●

Bayside Power Limited Partnership (“Bayside Power”), a power plant in Saint John, New Brunswick. On March 5, 2019, the Company sold the Bayside facility. Refer to note 4 for further details;

●

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

●

Emera Utility Services Inc. (“EUS”), a utility services contractor primarily operating in Atlantic Canada. In Q2 2019, Emera entered into an agreement to sell its EUS equipment. The transaction is expected to close in late 2019. EUS ceased operations on September 30, 2019; and

●

other investments.

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, 2018, 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, 2019.

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. 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. 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.

Leases

The Company determines whether a contract contains a lease at inception by evaluating if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.

Emera has leases with independent power producers and other utilities with annual requirements to purchase wind and hydro energy over varying contract lengths that are classified as finance leases. These finance leases are not recorded on the Company’s Condensed Consolidated Balance Sheets as payments associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease expense associated with these leases is recorded as “Regulated fuel for generation and purchased power” on the Condensed Consolidated Statements of Income.

Operating lease liabilities and right-of-use (“ROU”) assets are recognized on the Condensed Consolidated Balance Sheets based on the present value of the future minimum lease payments over the lease term at commencement date. As most of Emera’s leases do not provide an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as “Operating, maintenance and general” on the Condensed Consolidated Statements of Income.

Where the Company is the lessor, a lease is a sales-type lease if certain criteria are met and the arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual value guarantee, the lease is a direct financing lease.

For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and residual value (net of estimated executory costs and unearned income). The difference between the gross investment and the cost of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease.

For sales-type leases, the accounting is similar to the accounting for direct finance leases, however the difference between the fair value and the carrying value of the leased item is recorded at lease commencement rather than deferred over the term of the lease.

Emera has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component for all leases.

2. CHANGE IN ACCOUNTING POLICY

The new USGAAP accounting policies that are applicable to, and adopted by the Company in 2019 are described as follows:

Leases

Targeted Improvements to Accounting for Hedging Activities

Cloud Computing

3. FUTURE ACCOUNTING PRONOUNCEMENTS

Measurement of Credit Losses on Financial Instruments

4. DISPOSITIONS

Held for sale

Emera Maine

Emera Maine’s assets and liabilities are classified as held for sale and are measured at the lower of their carrying value or fair value less costs to sell. The measurement did not result in a fair value adjustment. The Company will continue to record depreciation on these assets, through the transaction closing date, as the depreciation continues to be reflected in customer rates, and will be reflected in the carryover basis of the assets when sold. Depreciation and amortization of $26 million ($20 million USD) has been recorded on these assets from March 25, 2019, the date they were classified as held for sale to September 30, 2019.

Other

As at September 30, 2019, an immaterial amount of EUS assets were classified as held for sale as the Company has entered into an agreement to sell these assets. This transaction is expected to close in late 2019. EUS ceased operations on September 30, 2019.

Details of the assets and liabilities classified as held for sale are as follows:


As at millions of Canadian dollars	September 30 2019

Regulatory assets	$	12

Receivables and other current assets		73

Current assets held for sale		85

Property, plant and equipment		1,311

Goodwill		151

Regulatory assets		118

Other long-term assets		54

Long-term assets held for sale		1,634

Total assets held for sale	$	1,719


Regulatory liabilities	$	10

Accounts payable and other current liabilities		84

Current liabilities associated with assets held for sale		94

Long-term debt		475

Deferred income taxes		204

Regulatory liabilities		146

Other long-term liabilities		81

Long-term liabilities associated with assets held for sale		906

Total liabilities associated with assets held for sale	$	1,000

Dispositions

On March 29, 2019, Emera completed the sale of its three NEGG facilities for cash proceeds of $799 million ($598 million USD) including working capital adjustments. The NEGG assets were classified as held for sale at December 31, 2018 and the Company ceased depreciation of these assets on November 27, 2018. On March 5, 2019, the Company completed the sale of its Bayside facility for cash proceeds of $46 million. The NEGG and Bayside facilities were included within the Company’s Other reportable segment. An immaterial loss was recognized on these dispositions.

Details of NEGG’s assets and liabilities classified as held for sale at December 31, 2018 are as follows:


As at millions of Canadian dollars	December 31 2018

Receivables and other current assets	$	40

Inventory		13

Current assets held for sale		53

Property, plant and equipment		777

Long-term assets held for sale		777

Total assets held for sale	$	830


Accounts payable and other current liabilities	$	20

Current liabilities associated with assets held for sale		20

Other long-term liabilities		2

Long-term liabilities associated with assets held for sale		2

Total liabilities associated with assets held for sale	$	22

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.

The five new 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, 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

Depreciation and amortization		112		58		26		28		2		-			226

Interest expense, net		39		36		13		14		81		-			183

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

Operating, maintenance and general (“OM&G”)		136		88		46		81		29		(13)			367

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

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

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

As at September 30, 2019
Total assets		16,265		6,526		3,116		5,398		1,419		(1,159)	⁽³⁾		31,565

(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, 2018
Operating revenues from external customers (1)	$	773	$	310	$	206	$	206	$	-	$	-		$	1,495

Inter-segment revenues (1)		2		-		-		10		14		(26)			-

Total operating revenues		775		310		206		216		14		(26)			1,495

Depreciation and amortization		101		56		28		37		14		-			236

Interest expense, net		30		34		12		14		86		-			176

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

OM&G		171		64		44		65		40		(14)			370

Net income (loss) attributable to common shareholders		143		36		31		15		(107)		-			118

For the nine months ended September 30, 2018
Operating revenues from external customers (1)		2,011		1,053		561		761		339		-			4,725

Inter-segment revenues (1)		6		2		-		23		39		(70)			-

Total operating revenues		2,017		1,055		561		784		378		(70)			4,725

Depreciation and amortization		299		163		88		97		40		-			687

Interest expense, net		96		103		35		40		253		-			527

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

OM&G		496		204		139		217		130		(47)			1,139

Net income (loss) attributable to common shareholders		298		174		62		93		(148)		-			479

As at December 31, 2018 Total assets		15,997		6,275		3,094		5,404		2,653		(1,109)	⁽³⁾		^32,314

(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, 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

(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 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.


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, 2018
Regulated
Electric Revenue

Residential	$	431	$	139	$	71	$	-	$	-	$	-	$	641

Commercial		213		95		97		-		-		-		405

Industrial		55		60		14		-		-		-		129

Other electric and regulatory deferrals		69		9		4		-		-		-		82

Other (1)		7		7		20		-		-		(2)		32

Regulated electric revenue		775		310		206		-		-		(2)		1,289

Gas Revenue

Residential		-		-		-		74		-		-		74

Commercial		-		-		-		56		-		-		56

Industrial		-		-		-		12		-		-		12

Finance income (2)(3)		-		-		-		15		-		-		15

Other		-		-		-		55		-		(10)		45

Regulated gas revenue		-		-		-		212		-		(10)		202

Non-Regulated
Marketing and trading margin (4)		-		-		-		-		6		-		6

Energy sales (4)		-		-		-		-		67		(5)		62

Capacity		-		-		-		-		39		-		39

Other		-		-		-		4		13		(9)		8

Mark-to-market (3)		-		-		-		-		(111)		-		(111)

Non-regulated revenue		-		-		-		4		14		(14)		4

Total operating revenues	$	775	$	310	$	206	$	216	$	14	$	(26)	$	1,495


For the nine months ended September 30, 2018
Regulated
Electric Revenue

Residential	$	1,034	$	532	$	192	$	-	$	-	$	-	$	1,758

Commercial		561		298		261		-		-		-		1,120

Industrial		155		171		35		-		-		-		361

Other electric and regulatory deferrals		251		33		17		-		-		-		301

Other (1)		16		21		55		-		-		(8)		84

Regulated electric revenue		2,017		1,055		560		-		-		(8)		3,624

Gas Revenue

Residential		-		-		-		339		-		-		339

Commercial		-		-		-		211		-		-		211

Industrial		-		-		-		36		-		-		36

Finance income (2)(3)		-		-		-		41		-		-		41

Other		-		-		-		145		-		(23)		122

Regulated gas revenue		-		-		-		772		-		(23)		749

Non-Regulated
Marketing and trading margin (4)		-		-		-		-		73		-		73

Energy sales (4)		-		-		-		-		217		(12)		205

Capacity		-		-		-		-		96		-		96

Other		-		-		1		12		35		(27)		21

Mark-to-market (3)		-		-		-		-		(43)		-		(43)

Non-regulated revenue		-		-		1		12		378		(39)		352

Total operating revenues	$	2,017	$	1,055	$	561	$	784	$	378	$	(70)	$	4,725

(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, 2019, the aggregate amount of the transaction price allocated to remaining performance obligations was $341 million (December 31, 2018 – $370 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

Investments subject to significant influence consisted of the following:


	September 30		Carrying Value as at December 31		Equity Income for the three months ended September 30				Equity Income for the nine months ended September 30				Percentage of Ownership

millions of Canadian dollars	2019		2018		2019		2018		2019		2018		2019

LIL(1)	$	568	$	534	$	11	$	11	$	33	$	31		49.5

NSPML		548		545		9		10		35		40		100.0

M&NP (2)		144		155		5		4		17		17		12.9

Lucelec (2)		41		42		-		1		2		2		19.1

Bear Swamp (3)		-		-		11		13		29		27		50.0

Other Investments		-		40		2		2		2		4

	$	1,301	$	1,316	$	38	$	41	$	118	$	121

(1) Emera indirectly owns 100 per cent of the Class B units, which comprises 24.9 per cent of the total of 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 $145 million (2018 - $172 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 23). NSPML’s consolidated summarized balance sheet is illustrated as follows:


As at millions of Canadian dollars	September 30 2019		December 31 2018

Balance Sheet
Current assets	$	95	$	86

Property, plant and equipment		1,678		1,690

Non-current assets		192		140

Total assets	$	1,965	$	1,916

Current liabilities	$	50	$	21

Long-term debt		1,288		1,288

Non-current liabilities		79		62

Equity		548		545

Total liabilities and equity	$	1,965	$	1,916

8. INCOME TAXES

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


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

	2019		2018		2019		2018

Income before provision for income taxes	$	29	$	108	$	536	$	545

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

Income taxes, at statutory income tax rate		9		34		166		169

Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities		(16)		(10)		(50)		(41)

Foreign tax rate variance		(15)		(17)		(40)		(34)

Amortization of deferred income tax regulatory liabilities		(13)		(7)		(29)		(24)

Tax effect of equity earnings		(3)		(3)		(12)		(13)

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

Florida state tax apportionment adjustment		-		(23)		-		(23)

Other		(4)		(7)		(10)		(5)

Income tax expense (recovery)	$	(49)	$	(33)	$	18	$	29

Effective income tax rate		(169)%		(31)%		3%		5%

In Q3 2018, Emera received approval from the Florida Department of Economic Opportunity to change its Florida state tax apportionment factors. This change resulted in the Company recording a tax benefit of approximately $23 million in 2018 as a result of the remeasurement of certain deferred tax balances.

9. COMMON STOCK

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


Issued and outstanding:	millions of shares		millions of Canadian dollars

Balance, December 31, 2018		234.12	$	5,816

Conversion of Convertible Debentures		0.03		1

Issuance of common stock (1)		0.88		49

Issued for cash under Purchase Plans at market rate		3.04		153

Discount on shares purchased under Dividend Reinvestment Plan		-		(7	)

Options exercised under senior management share option plan		2.53		102

Employee Share Purchase Plan		-		1

Balance, September 30, 2019		240.60	$	6,115

On July 11, 2019, Emera established an ATM Program that allows the Company to issue up to $600 million of common shares to the public from time to time, at the Company’s discretion, at the prevailing market price. The ATM Program was established under a prospectus supplement to the Company’s short-form base shelf prospectus which expires on July 14, 2021. As at September 30, 2019, an aggregate gross sales limit of $550 million remains available for issuance under the ATM program.

10. EARNINGS PER SHARE

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


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

	2019		2018		2019		2018

Numerator
Net income attributable to common shareholders	$	55.0	$	118.1	$	470.3	$	479.0

Diluted numerator		55.0		118.1		470.3		479.0

Denominator
Weighted average shares of common stock outstanding		239.5		232.4		237.4		231.1

Weighted average deferred share units outstanding		1.5		1.3		1.5		1.3

Weighted average shares of common stock outstanding – basic		241.0		233.7		238.9		232.4

Stock-based compensation		0.6		0.3		0.6		0.3

Dividend reinvestment plan		0.8		1.1		0.8		1.1

Convertible Debentures		-		0.1		-		0.1

Weighted average shares of common stock outstanding – diluted		242.4		235.2		240.3		233.9

Earnings per common share
Basic	$	0.23	$	0.51	$	1.97	$	2.06

Diluted	$	0.23	$	0.50	$	1.96	$	2.05

11. 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, 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


For the nine months ended September 30, 2018

Balance, January 1, 2018 (1)	$	30	$	48	$	(3)	$	3	$	(243)	$	(165)

Other comprehensive income (loss) before reclassifications		218		(41)		5		-		-		182

Amounts reclassified from accumulated other comprehensive income loss (gain)		-		-		(6)		(4)		26		16

Net current period other comprehensive income (loss)		218		(41)		(1)		(4)		26		198

Balance, September 30, 2018	$	248	$	7	$	(4)	$	(1)	$	(217)	$	33

(1) The January 1, 2018 balance of AOCI and Regulatory Assets includes a prior period reclassification of $37 million in unrecognized pension and post-retirement benefit costs and $15 million in deferred taxes ($22 million, net of tax) to be consistent with current year presentation.

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		2019		2018			2019		2018

	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	$	(1	)	$	3	$	(5)

Power and gas swaps	Non-regulated fuel for generation and purchased power		-		1			-		(2)

Total before tax			1		-			3		(7)

	Income tax expense (recovery)		-		-			-		1

Total net of tax		$	1	$	-		$	3	$	(6)

Net change in available-for-sale investments

	Retained earnings (1)		-		-			-	$	(4)

Total net of tax			-		-			-	$	(4)

Net change in unrecognized pension and post-retirement benefit costs
Actuarial losses (gains)	OM&G	$	4	$	8		$	12	$	28

Past service costs (gains)	OM&G		(1)		(1)			(1)		(1)

Amounts reclassified into obligations	Pension and post-retirement liabilities		1		-			1		-

Total before tax			4		7			12		27

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

Total net of tax		$	4	$	7		$	11	$	26

Total reclassifications out of AOCI, net of tax, for the period		$	5	$	7		$	14	$	16

(1) Related to the adoption of ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities.

12. 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, Emera Maine, 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 millions of Canadian dollars	September 30 2019		December 31 2018		September 30 2019		December 31 2018

Cash flow hedges
Foreign exchange forwards	$	-	$	-	$	1	$	5

		-		-		1		5

Regulatory deferral
Commodity swaps and forwards
Coal purchases		11		71		23		1

Power purchases		22		2		28		1

Natural gas purchases and sales		5		2		8		4

Heavy fuel oil purchases		4		1		10		1

Foreign exchange forwards		8		29		2		-

		50		105		71		7

HFT derivatives
Power swaps and physical contracts		15		62		16		76

Natural gas swaps, futures, forwards, physical contracts		116		125		373		403

		131		187		389		479

Other derivatives
Equity derivatives and interest rate swaps		33		1		-		-

		33		1		-		-

Total gross current derivatives		214		293		461		491

Impact of master netting agreements with intent to settle net or simultaneously		(85)		(126)		(85)		(126)

		129		167		376		365

Current		99		148		275		260

Long-term		30		19		101		105

Total derivatives	$	129	$	167	$	376	$	365

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 millions of Canadian dollars	September 30 2019		December 31 2018		September 30 2019		December 31 2018

Regulatory deferral	$	6	$	1	$	6	$	1

HFT derivatives		79		125		79		125

Total impact of master netting agreements with intent to settle net or simultaneously	$	85	$	126	$	85	$	126

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 millions of Canadian dollars	2019		Three months ended September 30 2018

	Foreign Exchange Forwards		Power Swaps			Foreign Exchange Forwards

Realized gain (loss) in non-regulated fuel for generation and purchased power	$	-	$	(1	)	$	-

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

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


For the millions of Canadian dollars	2019		Nine months ended September 30 2018

	Foreign Exchange Forwards		Power Swaps			Foreign Exchange Forwards

Realized gain (loss) in non-regulated fuel for generation and purchased power	$	-	$	2		$	-

Realized gain (loss) in operating revenue – regulated		(3)		-			5

Total gains (losses) in net income	$	(3)	$	2		$	5


As at millions of Canadian dollars	September 30 2019					December 31 2018

	Foreign Exchange Forwards		Power Swaps			Foreign Exchange Forwards

Total unrealized gain (loss) in AOCI – net of tax	$	(1)	$	(1)		$	(6)

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

As at September 30, 2019, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:


millions	2019		2020

Foreign exchange forwards (USD) sales	$	3	$	30

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	2019					2018

	Commodity swaps and forwards			Foreign exchange forwards		Commodity swaps and forwards			Physical natural gas and biofuel energy purchases and sales		Foreign exchange forwards

Unrealized gain (loss) in regulatory assets	$	(25	)	$	5	$	(8	)	$	-	$	(1)

Unrealized gain (loss) in regulatory liabilities		10			2		35			-		(4)

Realized (gain) loss in regulatory liabilities		(3)			-		2			-		-

Realized (gain) loss in inventory (1)		(4)			(1)		(18)			-		(3)

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

Total change in derivative instruments	$	(21	)	$	5	$	8		$	-	$	(11)

(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	2019				2018

	Commodity swaps and forwards		Foreign exchange forwards		Commodity swaps and forwards		Physical natural gas and biofuel energy purchases and sales		Foreign exchange forwards

Unrealized gain (loss) in regulatory assets	$	(71)	$	(2)	$	(16)	$	(1)	$	2

Unrealized gain (loss) in regulatory liabilities		4		(6)		76		-		10

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

Realized (gain) loss in inventory (1)		(28)		(9)		(43)		-		(14)

Realized (gain) loss in regulated fuel for generation and purchased power (2)		(1)		(6)		(5)		-		(6)

Total change in derivative instruments	$	(95)	$	(23)	$	9	$	(1)	$	(8)

(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, 2019, 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:


	2019		2020-2022

millions	Purchases		Purchases

Coal (metric tonnes)		-		1

Natural Gas (Mmbtu)		8		23

Heavy fuel oil (bbls)		1		2

Power (MWh)		-		3

Foreign Exchange Swaps and Forwards

As at September 30, 2019, the Company had the following notional volumes of foreign exchange swaps and forward contracts related to commodity contracts that are expected to settle as outlined below:


	2019		2020-2022

Foreign exchange contracts (millions of US dollars)	$	43	$	276

Weighted average rate		1.2172		1.3199

% of USD requirements		88%		39%

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 millions of Canadian dollars	Three months ended September 30				Nine months ended September 30

	2019		2018		2019		2018

Power swaps and physical contracts in non-regulated operating revenues	$	(2)	$	(1)	$	-	$	(11)

Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues		(67)		(104)		180		55

Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power		1		2		(4)		2

	$	(68)	$	(103)	$	176	$	46

As at September 30, 2019, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:


millions	2019		2020		2021		2022		2023

Natural gas purchases (Mmbtu)		255		167		76		56		41

Natural gas sales (Mmbtu)		224		100		19		7		2

Power purchases (MWh)		2		-		-		-		-

Power sales (MWh)		2		-		-		-		-

Other Derivatives

As at September 30, 2019, the Company had equity derivatives in place to manage the cash flow risk associated with forecasted future cash settlements of deferred compensation obligations. The equity derivative hedges the return on 2.3 million shares and extends until March of 2020.

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, 2019, the Company had $136 million (December 31, 2018 - $118 million) in financial assets considered to be past due, which have been outstanding for an average 72 days. The fair value of these financial assets is $124 million (December 31, 2018 - $107 million), the difference of which is included in the allowance for doubtful accounts. These assets primarily relate to accounts receivable from electric and gas revenue.

Cash Collateral

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


As at millions of Canadian dollars	September 30 2019		December 31 2018

Cash collateral provided to others	$	91	$	103

Cash collateral received from others		7		77

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, 2019, the total fair value of these derivatives, in a liability position, was $376 million (December 31, 2018 – $365 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.

13. 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 12), 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, 2019

millions of Canadian dollars	Level 1		Level 2		Level 3		Total

Assets

Regulatory deferral
Commodity swaps and forwards
Coal purchases	$	-	$	8	$	-	$	8

Power purchases		21		-		-		21

Natural gas purchases and sales		-		4		-		4

Heavy fuel oil purchases		3		-		-		3

Foreign exchange forwards		-		8		-		8

		24		20		-		44

HFT derivatives
Power swaps and physical contracts		4		-		1		5

Natural gas swaps, futures, forwards, physical contracts and related transportation		(3)		34		16		47

		1		34		17		52

Other derivatives

Equity derivatives and interest rate swap		33		-		-		33

		33		-		-		33

Total assets		58		54		17		129

Liabilities
Cash flow hedges

Foreign exchange forwards		-		1		-		1

		-		1		-		1

Regulatory deferral
Commodity swaps and forwards
Coal purchases		-		20		-		20

Power purchases		27		-		-		27

Heavy fuel oil purchases		2		8		-		10

Natural gas purchases and sales		4		2		-		6

Foreign exchange forwards		-		2		-		2

		33		32		-		65

HFT derivatives
Power swaps and physical contracts		5		-		1		6

Natural gas swaps, futures, forwards and physical contracts		6		23		275		304

		11		23		276		310

Total liabilities		44		56		276		376

Net assets (liabilities)	$	14	$	(2)	$	(259)	$	(247)


As at	December 31, 2018

millions of Canadian dollars	Level 1		Level 2		Level 3		Total

Assets

Regulatory deferral
Commodity swaps and forwards
Coal purchases	$	-	$	70	$	-	$	70

Power purchases		2		-		-		2

Natural gas purchases and sales		-		2		-		2

Heavy fuel oil purchases		-		1		-		1

Foreign exchange forwards		-		29		-		29

		2		102		-		104

HFT derivatives
Power swaps and physical contracts		2		2		3		7

Natural gas swaps, futures, forwards, physical contracts and related transportation		1		36		18		55

		3		38		21		62

Other derivatives
Interest rate swap		-		1		-		1

		-		1		-		1

Total assets		5		141		21		167

Liabilities
Cash flow hedges
Foreign exchange forwards		-		5		-		5

		-		5		-		5

Regulatory deferral
Commodity swaps and forwards
Coal purchases		-		1		-		1

Power purchases		1		-		-		1

Heavy fuel oil purchases		-		1		-		1

Natural gas purchases and sales		3		-		-		3

		4		2		-		6

HFT derivatives
Power swaps and physical contracts		14		6		1		21

Natural gas swaps, futures, forwards and physical contracts		-		28		305		333

		14		34		306		354

Total liabilities		18		41		306		365

Net assets (liabilities)	$	(13)	$	100	$	(285)	$	(198)

The change in the fair value of the Level 3 financial assets for the three months ended September 30, 2019 was as follows:


	HFT Derivatives
millions of Canadian dollars	Power		Natural gas		Total

Balance, beginning of period	$	3	$	17	$	20

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

Balance, September 30, 2019	$	1	$	16	$	17

The change in the fair value of the Level 3 financial liabilities for the three months ended September 30, 2019 was as follows:


	HFT Derivatives
millions of Canadian dollars	Power		Natural gas		Total

Balance, beginning of period	$	1	$	176	$	177

Total realized and unrealized gains (losses) included in non-regulated operating revenues		-		99		99

Balance, September 30, 2019	$	1	$	275	$	276

The change in the fair value of the Level 3 financial assets for the nine months ended September 30, 2019 was as follows:


	HFT Derivatives
millions of Canadian dollars	Power		Natural gas		Total

Balance, beginning of period	$	3	$	18	$	21

Total realized and unrealized gains (losses) included in non-regulated operating revenues		(2)		(2)		(4)

Balance, September 30, 2019	$	1	$	16	$	17

The change in the fair value of the Level 3 financial liabilities for the nine months ended September 30, 2019 was as follows:

HFT Derivatives

millions of Canadian dollars

Power

Natural

gas

Total

Balance, beginning of period

305

306

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

(30)

Balance, September 30, 2019

275

276

The Company evaluates the observable inputs of market data on a quarterly basis in order to determine if transfers between levels is appropriate. For the three and nine months ended September 30, 2019, there were no transfers between levels.

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. Where possible, Emera also sources multiple broker prices in an effort to evaluate and substantiate these unobservable inputs. 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, 2019

millions of Canadian dollars

Fair
Value

Valuation

Technique

Unobservable Input

Range

Weighted
average

Assets

HFT derivatives –

Modelled pricing

Third-party pricing

$21.72 - $79.95

$34.12

Power swaps and

Probability of default

0.01% - 1.14%

0.25%

physical contracts

Discount rate

0.02% - 6.30%

2.94%

HFT derivatives –

Modelled pricing

Third-party pricing

$1.26 - $9.61

$3.04

Natural gas swaps, futures,

Probability of default

0.01% - 5.71%

0.22%

forwards, physical contracts

Discount rate

0.01% - 17.88%

2.19%

Modelled pricing

Third-party pricing

$1.66 - $10.92

$5.38

Basis adjustment

$0.07 - $1.30

$0.78

Probability of default

0.01% - 7.72%

0.40%

Discount rate

0.01% - 4.72%

1.19%

Total assets

Liabilities

HFT derivatives –

Modelled pricing

Third-party pricing

$18.70 - $25.52

$24.16

Power swaps and

Correlation factor

92.2% - 92.2%

92.20%

physical contracts

Probability of default

0.01% - 0.01%

0.01%

Discount rate

0.00% - 0.00%

0.00%

HFT derivatives –

247

Modelled pricing

Third-party pricing

$1.28 - $9.61

$4.68

Natural gas swaps, futures,

Own credit risk

0.01% - 2.31%

0.12%

forwards and physical contracts

Discount rate

0.01% - 15.96%

2.18%

Modelled pricing

Third-party pricing

$1.24 - $10.92

$7.06

Basis adjustment

$0.07 - $1.30

$1.08

Probability of default

0.01% - 7.72%

0.06%

Discount rate

0.01% - 4.61%

1.21%

Total liabilities

276

Net assets (liabilities)

(259)

The financial assets and liabilities included on the Condensed Consolidated Balance Sheets that are not measured at fair value consisted of the following:


As at

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

September 30, 2019	$	14,377	$	16,361	$	-	$	15,879	$	482	$	16,361

December 31, 2018	$	15,411	$	15,908	$	-	$	14,991	$	917	$	15,908

The Company has designated $1.2 billion USD denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in USD denominated operations. An after-tax foreign currency loss of $19 million was recorded in “Other Comprehensive Income – Unrealized gains (losses) on net investment hedges” for the three months ended September 30, 2019 (2018 – $25 million gain after-tax). An after-tax foreign currency gain of $48 million was recorded in Other Comprehensive Income for the nine months ended September 30, 2019 (2018 - $41 million after-tax foreign currency loss).

14. 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 14 in Emera’s 2018 annual audited consolidated financial statements.


As at millions of Canadian dollars		September 30 2019	(1)		December 31 2018

Regulatory assets
Deferred income tax regulatory assets	$	823		$	775

Pension and post-retirement medical plan		378			453

Deferrals related to derivative instruments		65			10

Cost-recovery clauses		38			75

Storm restoration regulatory asset		38			32

Environmental remediation		35			31

Stranded cost recovery		27			28

Unamortized defeasance costs		20			26

Demand side management deferral		21			24

Other		74			115

	$	1,519		$	1,569

Current	$	123		$	165

Long-term		1,396			1,404

Total regulatory assets	$	1,519		$	1,569


Regulatory liabilities

Deferred income tax regulatory liabilities	$	1,024		$	1,218

Accumulated reserve - cost of removal		910			955

Regulated fuel adjustment mechanism		141			161

Storm reserve		63			76

Deferrals related to derivative instruments		52			116

Cost-recovery clauses		42			30

Self-Insurance fund (note 23)		29			30

Other		4			24

	$	2,265		$	2,610

Current	$	289		$	251

Long-term		1,976			2,359

Total regulatory liabilities	$	2,265		$	2,610

(1) On March 25, 2019, Emera announced the sale of Emera Maine. As at September 30, 2019, Emera Maine’s assets and liabilities were classified as held for sale. Refer to note 4 for further details.

Grand Bahama Power Company

On September 1, 2019, Dorian struck Grand Bahama Island as a Category 5 hurricane, with sustained winds of approximately 285 kilometres per hour. The hurricane stalled over the island for several days, causing significant damage to, or destruction of, homes and businesses served by GBPC. GBPC’s generation, transmission and distribution assets sustained damage, including the effect of flooding that resulted from storm surge and rain. All 19,000 of GBPC’s customers lost power following the storm. The Company’s restoration plan is well underway and by September 30, 2019, power was restored to all customers who were able to receive power, or approximately 16,000 customers.

GBPC maintains insurance for its generation facilities and, as with most utilities, its transmission and distribution networks are self-insured. It is currently estimated that restoration costs for GBPC self-insured assets will be approximately $12 million USD. At September 30, 2019, the Company incurred and recorded $11 million ($8 million USD) of this estimated cost. The $11 million was recorded as a regulatory asset as management anticipates that recovery of these prudently incurred costs through a regulatory process is probable. Management is working with GBPC’s insurance companies to assess the damage to its generation assets. It is anticipated that this damage will be covered by insurance with the exception of $5 million USD, which is GBPC’s share of the insurance deductible, and which has not yet been recorded.

At September 30, 2019, GBPC total assets, excluding goodwill, were $465 million ($351 million USD) and $101 million ($76 million USD) of Emera’s goodwill was related to GBPC. The impact of Hurricane Dorian could adversely affect GBPC’s future earnings and impairment of some of its assets and goodwill could occur. The outcome cannot be reasonably determined or estimated at this time, therefore no impairment has been recorded in Q3 2019. The Company expects to complete its impairment analysis in Q4 2019.

NSPI

On September 7, 2019, post-tropical storm Dorian struck Nova Scotia, with sustained hurricane force winds causing widespread damage to NSPI’s transmission and distribution system. The total cost of the restoration is expected to be approximately $39 million. At September 30, 2019, $23 million of this estimated total cost was capitalized to property, plant and equipment, with the remaining $16 million charged to OM&G expense. There was no overall impact on NSPI earnings as NSPI’s increased storm costs were absorbed by some of the excess non-fuel revenues that were recorded to date in 2019. Any excess non-fuel revenues that are available at the end of the fiscal year will be returned to customers through the fuel adjustment mechanism.

Tampa Electric

In Q3 2019, Tampa Electric incurred approximately $11 million ($8 million USD) in costs related to Hurricane Dorian. These costs were charged against the utility’s storm reserve regulatory liability.

NMGC

On July 17, 2019, the NMPRC approved a rate increase for NMGC effective August 2019, and allowed NMGC to retain tax reform benefits realized from January 1, 2018 to the effective date of the new rates. The new rates are being phased in over two years and are expected to result in an annual revenue increase of approximately $3 million USD. The deferred income tax regulatory liability of $11 million ($8 million USD) recorded at December 31, 2018 to reflect 2018 tax benefits was recognized in revenue in Q2 2019. The NMPRC also approved the utility’s proposed weather adjustment mechanism. Beginning in August 2019, the NMPRC approved a change in the treatment of net operating loss carryforwards. As a result of this change, a tax benefit of approximately $7 million ($5 million USD) was recognized in earnings in Q3 2019.

15. RELATED PARTY TRANSACTIONS

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

●

16. LEASES

Lessee

The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera’s leases have remaining lease terms of 1 year to 67 years, some of which include options to extend the leases for up to 65 years. These options are included as part of the lease term when it is considered reasonably certain that they will be exercised.


As at millions of Canadian dollars	Classification		September 30 2019

Right-of-use asset		Other long-term assets	$	66

Lease liabilities

Current		Other current liabilities		4

Long-term		Other long-term liabilities		62

Total lease liabilities			$	66

The Company has recorded lease expense of $30 million and $116 million for the three and nine months ended September 30, 2019, respectively, of which $28 million for the third quarter and $111 million for the nine months ended September 30, 2019, relates to variable costs for power generation facility finance leases.

As at September 30, 2019, future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter are as follows:


millions of Canadian dollars	2019		2020		2021		2022		2023		Thereafter		Total

Minimum lease payments	$	3	$	7	$	7	$	7	$	7	$	109	$	140

Less imputed interest														(74)

Total	$	3	$	7	$	7	$	7	$	7	$	109	$	66

Additional information related to Emera’s leases is as follows:


For the	Nine months ended September 30, 2019

Cash paid for amounts included in the measurement of lease liabilities:

Operating cash flows for operating leases (millions of Canadian dollars)	$	5

Right-of-use assets obtained in exchange for lease obligations:

Operating leases (millions of Canadian dollars)	$	15

Weighted average remaining lease term (years)		39

Weighted average discount rate - operating leases		4.05%

Lessor

The Company’s net investment in direct finance and sales-type leases relate to Brunswick Pipeline, compressed natural gas (“CNG”) stations and heat pumps.

Direct finance and sales-type lease unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Operating revenues – Regulated gas” and “Other income (expenses), net” on the Condensed Consolidated Statements of Income.

The Company manages its risk associated with the residual value of the Brunswick Pipeline lease through proper routine maintenance of the asset.

Customers have the option to purchase CNG station assets at any time after year five of the agreements, which is in 2021, by paying a make-whole payment at the date of the purchase based on a targeted internal rate of return or may take possession of the CNG station asset at the end of the lease term for no cost. Customers have the option to purchase heat pumps at the end of the lease term for a nominal fee.

The net investment in direct finance and sales-type leases consisted of the following:


As at millions of Canadian dollars	September 30 2019

Total minimum lease payment to be received	$	1,066

Less: amounts representing estimated executory costs		(192)

Minimum lease payments receivable	$	874

Estimated residual value of leased property (unguaranteed)		183

Less: unearned finance lease income		(532)

Net investment in direct finance and sales-type leases	$	525

Principal due within one year (included in “Receivables and other current assets”)		18

Net investment in sales-type leases - long-term (included in “Other long-term assets”)		33

Net Investment in direct finance leases - long-term	$	474

As at September 30, 2019, future minimum lease payments to be received for each of the next five years and in aggregate thereafter are as follows:


millions of Canadian dollars	2019		2020		2021		2022		2023		Thereafter		Total

Minimum lease payments to be received	$	19	$	72	$	71	$	70	$	69	$	765	$	1,066

Less: executory costs														(192)

Minimum lease payments receivable	$	19	$	72	$	71	$	70	$	69	$	765	$	874

17. 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, Maine, New Mexico, Barbados, Dominica and Grand Bahama Island. For details of the Company’s employee benefit plan, refer to note 19 in Emera’s 2018 annual audited consolidated financial statements.

Emera’s net periodic benefit cost included the following:


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

	2019		2018		2019		2018

Defined benefit pension plans
Service cost	$	12	$	13	$	36	$	38

Non-service cost

Interest cost		26		24		78		71

Expected return on plan assets		(37)		(34)		(112)		(103)

Current year amortization of:
Actuarial losses		4		8		12		28

Past service gains		(1)		(1)		(1)		(1)

Regulated asset		5		7		15		19

Settlements and curtailments		-		-		1		1

Total non-service costs		(3)		4		(7)		15

Total defined benefit pension plans		9		17		29		53

Non-pension benefit plans

Service cost		1		1		3		4

Non-service cost

Interest cost		4		4		11		10

Expected return on plan assets		-		(1)		(1)		(2)

Current year amortization of:
Regulated asset		(2)		(1)		(5)		(2)

Total non-service costs		2		2		5		6

Total non-pension benefit plans		3		3		8		10

Total defined benefit plans	$	12	$	20	$	37	$	63

Emera’s total contributions related to these defined benefit pension plans and non-pension benefit plans for the three months ended September 30, 2019 were $29 million (2018 – $13 million), and for the nine months ended September 30, 2019 were $63 million (2018 – $67 million). Annual employer contributions for the defined benefit pension plans only, are estimated to be $53 million for 2019.

18. 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 2018 annual audited consolidated financial statements, and below for 2019 short-term debt financing activity.

Recent Financing Activity by Segment

Other

19. LONG-TERM DEBT

For details regarding long-term debt, refer to note 24 in Emera’s 2018 annual audited consolidated financial statements, and below for significant long-term debt financing activity in 2019.

Recent Financing Activity by Segment

Florida Electric Utilities

On July 24, 2019, Tampa Electric Company (“TEC”) completed a $300 million USD 30-year senior notes issuance. The notes bear interest at a rate of 3.625 per cent and have a maturity date of June 15, 2050.

Canadian Electric Utilities

On August 2, 2019, NSPI repaid a $95 million debenture upon maturity. The debenture was repaid using its operating credit facility.

On April 4, 2019, NSPI completed a $400 million Series AB 30-year medium term notes issuance. The notes bear interest at a rate of 3.57 per cent and have a maturity date of April 5, 2049.

Gas Utilities and Infrastructure

On July 31, 2019, New Mexico Gas Intermediate (“NMGI”) repaid a $50 million USD note upon maturity. The note was repaid using cash on hand.

On May 17, 2019, Emera Brunswick Pipeline amended the maturity date of its $250 million Credit Agreement from February 2022 to May 2023. There were no other material changes in commercial terms.

Other

On June 14, 2019, Emera US Finance LP repaid a $500 million USD note upon maturity. The note was repaid using proceeds from the sale of the NEGG facilities.

20. COMMITMENTS AND CONTINGENCIES

A. Commitments

As at September 30, 2019, 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	2019		2020		2021		2022		2023		Thereafter		Total

Purchased power (1)(2)	$	63	$	208	$	231	$	245	$	249	$	2,496	$	3,492

Transportation (3)		140		426		346		307		267		2,955		4,441

Capital projects (4)		305		292		37		11		1		-		646

Fuel, gas supply and storage		196		440		104		4		1		-		745

Long-term service agreements (5)(6)		10		43		30		29		21		124		257

Equity investment commitments (7)		-		-		190		-		-		-		190

Leases and other (8)		10		16		17		16		10		126		195

Demand side management		12		31		37		39		-		-		119

	$	736	$	1,456	$	992	$	651	$	549	$	5,701	$	10,085

As noted below, contractual obligations at September 30, 2019 include contractual obligations related to Emera Maine. On completion of the sale of Emera Maine, all of the remaining future contractual obligations will be transferred to the buyer. Refer to note 4 for additional information.

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

(2) Includes $551 million related to Emera Maine ($4 million in 2019; $14 million in 2020; $25 million in 2021; $32 million in 2022; $32 million in 2023 and $444 million thereafter).

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

(4) Includes $356 million of commitments related to Tampa Electric’s solar and Big Bend Power Station modernization projects.

(5) 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.

(6) Includes $26 million related to various long-term service agreements Emera Maine has entered into for IT maintenance and vegetation management ($4 million in 2019; $14 million in 2020; $4 million in 2021; $2 million in 2022; and $2 million in 2023).

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

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

B. Legal Proceedings

TECO Guatemala Holdings (“TGH”)

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

On September 23, 2016, TGH filed a request for resubmission to arbitration. A new tribunal was constituted, and the matter has been fully briefed. A hearing was held in March 2019 and a decision is expected from the tribunal in 2020. In addition, TGH has sued Guatemala in Washington, D.C. court to enforce the $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. 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, 2019, TEC has estimated its financial liability to be $37 million ($28 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

From 2011 to 2016, four separate complaints were filed with the Federal Energy Regulatory Commission (“FERC”) to challenge the base return on equity (“ROE”) under the ISO-New England (“ISO-NE”) Open Access Transmission Tariff (“OATT”).

●

Complaint I, filed by a group including the Attorney General of Massachusetts, New England utilities commissions, state public advocates and end users, was remanded to the FERC by the US Court of Appeals in 2017 for further proceedings. No reserve has been made with respect to Complaint I due to uncertainty of the outcome.

●

Complaints II and III (the “ENE” and “MA AG II” cases), brought by a group of consumer advocates and by a group of state commissions, state public advocates and end users respectively, have been joined together and are presently pending before the FERC. Emera Maine has recorded a reserve of approximately $4 million USD for these cases. These reserves have been recorded as “Regulatory liabilities” on the Condensed Consolidated Balance Sheets and as a reduction to “Operating revenues – regulated electric” on the Condensed Consolidated Statements of Income. The reserve was calculated based on Emera Maine’s best estimate of the probable outcome.

●

Complaint IV was filed by the Eastern Massachusetts Consumer Owned Systems (“EMCOS”). On March 27, 2018, a FERC Administrative Law Judge issued an Initial Decision concluding that the currently-filed base ROE of 10.57 per cent, which with incentive adders may reach a maximum ROE of 11.74 per cent, is not unjust and unreasonable. This decision was appealed to the FERC. No reserve has been made in relation to Complaint IV due to the uncertainty of the final outcome.

On October 16, 2018, the FERC issued an order that addressed all four complaint proceedings. The FERC order proposed a new methodology to set ROEs. Based on the new methodology, the FERC’s preliminary finding was a 10.41 per cent base ROE for the ISO-NE OATT. The FERC has permitted parties to comment on the new methodology and its application to the four pending complaint proceedings. No new or additional reserves have been made with respect to any of the four pending complaints due to uncertainty.

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 12 and note 13.

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.

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 uses foreign currency derivative instruments to hedge specific transactions. 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. 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.

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, and liquidity. 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.

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 2018 audited annual consolidated financial statements, with updates as noted below:

21. NON-CONTROLLING INTEREST IN SUBSIDIARIES

Non-controlling interest in subsidiaries consisted of the following:


As at millions of Canadian dollars	September 30 2019		December 31 2018

Preferred shares of GBPC (1)	$	14	$	19

Domlec		21		22

	$	35	$	41

(1) In June 2019, GBPC redeemed all outstanding preferred shares, replacing them with $10 million USD debt at 4 per cent and $10 million USD preferred shares at 6 per cent. The new preferred shares are redeemable by GBPC after June 17, 2021, at $1,000 Bahamian per share plus accrued and unpaid dividends and are entitled to a 6.0 per cent per annum fixed cumulative preferential dividend to be paid semi-annually, with the first payment scheduled for January 2020.

22. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


For the	Nine months ended September 30
millions of Canadian dollars	2019		2018

Changes in non-cash working capital: Inventory	$	(28)	$	(4	)

Receivables and other current assets		317		203

Accounts payable		(211)		(54)

Other current liabilities		50		11

Total non-cash working capital	$	128	$	156


Supplemental disclosure of non-cash activities:

Dividends payable	$	159	$	148

Common share dividends reinvested	$	140	$	135

Change in accrued capital expenditures	$	(14)	$	(33)

Issuance of depository receipts	$	-	$	22

23. VARIABLE INTEREST ENTITIES

The Company performs ongoing analysis to assess whether it holds any Variable Interest Entities (“VIE”). 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 it has authority over the majority of the direct activities that are expected to most significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the Maritime Link as an equity investment.

BLPC has established a Self-Insurance Fund (“SIF”), primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, the activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s consolidated VIE in the SIF is recorded as an “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, 2019

December 31, 2018

Maximum

Maximum

millions of Canadian dollars

Total
assets

exposure to
loss

Total
assets

exposure to
loss

Unconsolidated VIEs in which Emera has variable interests

NSPML (equity accounted)

548

545

24. 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.

25. SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through November 7, 2019, the date the financial statements were issued.

EX-99.3 4 d805356dex993.htm EX-99.3 EX-99.3

Exhibit 99.3

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

I, Scott Balfour, President and Chief Executive Officer of Emera Incorporated, certify the following:

1. Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Emera Incorporated (the “issuer”) for the interim period ended September 30, 2019.

2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

4. Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

5. Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

ii.

information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control-Integrated Framework.

5.2 ICFR – material weakness relating to design: N/A

5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A

the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and ICFR to exclude controls, policies and procedures of:

a proportionately consolidated entity in which the issuer has an interest;

ii.

a special purpose entity in which the issuer has an interest; or

iii.

a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim filings; and

summary financial information about the proportionately consolidated entity, special purpose entity or business that the issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements.

6. Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2019 and ended on September 30, 2019 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: November 7, 2019

“Scott Balfour”

Scott Balfour

President and Chief Executive Officer

EX-99.4 5 d805356dex994.htm EX-99.4 EX-99.4

Exhibit 99.4

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

I, Greg Blunden, Chief Financial Officer of Emera Incorporated, certify the following:

designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

ii.

5.2 ICFR – material weakness relating to design: N/A

5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A

the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and ICFR to exclude controls, policies and procedures of:

a proportionately consolidated entity in which the issuer has an interest;

ii.

a special purpose entity in which the issuer has an interest; or

iii.

a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim filings; and

Date: November 7, 2019


“Greg Blunden”



Greg Blunden Chief Financial Officer

EX-99.5 6 d805356dex995.htm EX-99.5 EX-99.5

Exhibit 99.5

Emera Incorporated

Earnings Coverage Ratio

Pursuant to Section 8.4 of National Instrument 44-102, this updated calculation of the earnings coverage ratio is filed as an exhibit to the unaudited condensed consolidated financial statements of Emera Incorporated (“Emera”) for the nine months ended September 30, 2019.

The following earnings coverage ratio is calculated on a consolidated basis for the twelve-month period ended September 30, 2019.


		Twelve months ended September 30, 2019
Earnings Coverage ⁽¹⁾		1.89

⁽¹⁾ Earnings coverage is equal to consolidated net income attributable to common shareholders plus: income taxes, interest on debt, amortization of debt financing costs, allowance for funds used during construction and preferred share dividends declared during the period together with undeclared preferred share dividends, if any, divided by the sum of interest on debt, amortization of debt financing costs, allowance for funds used during construction, capitalized interest and preferred dividends grossed up to a before-tax equivalent using an effective tax rate of 30.1 per cent.

Emera’s dividend requirements on all of its preferred shares, grossed up to a before-tax equivalent using an effective income tax rate of 30.1 per cent, amounted to $65 million for the twelve months ended September 30, 2019. Emera’s interest requirements for the twelve months ended September 30, 2019 amounted to $751 million. Emera’s consolidated income before interest and income tax for the twelve months ended September 30, 2019 was $1,546 million, which is 1.89 times Emera’s aggregate preferred dividends and interest requirements for this period.

EX-99.6 7 d805356dex996.htm EX-99.6 EX-99.6

Exhibit 99.6

LOGO

Emera Reports 2019 Third Quarter Financial Results

HALIFAX, Nova Scotia -- Today Emera (TSX: EMA) announced financial results for the third quarter of 2019.

Q3 2019 and Year-to-Date Highlights:

Reported Net Income

●

Q3 2019 reported net income was $55 million, or $0.23 per common share, compared with net income of $118 million, or $0.51 per common share, in Q3 2018.

●

Year-to-date reported net income was $470 million, or $1.97 per common share, compared with net income of $479 million, or $2.06 per common share, in the 2018 period.

Adjusted Net Income ⁽¹⁾

●

Q3 2019 adjusted net income was $122 million, or $0.51 per common share, compared with $191 million, or $0.82 per common share, in Q3 2018.

●

Year-to-date adjusted net income was $476 million, or $1.99 per common share, compared with $504 million, or $2.17 per common share, in the 2018 period.

Significant Items Affecting Reported and Adjusted Net Income

●

Q3 2018 included $23 million of earnings related to a change in Florida state tax apportionment factors.

●

Q3 2019 earnings were $18 million lower than Q3 2018 from the sale of the New England Gas Generation (“NEGG”) and Bayside facilities in Q1 2019. Year-to-date contributions from these assets were $22 million lower than 2018.

●

Q3 2019 included $16 million of impacts from Hurricane Dorian related to Grand Bahama Power Company (“GBPC”).

Cash Flow

●

Year-to-date operating cash flow, before changes in working capital, decreased by $55 million to $1,182 million, compared with $1,237 million in the 2018 period.

⁽¹⁾See “Non-GAAP Measures” noted below.

“Our results for the quarter were affected by weak marketing and trading conditions, the sale of the merchant gas plants, and the impact of Hurricane Dorian on our operations,” said Scott Balfour, President and CEO. “However, our continuing regulated businesses remain strong and are performing very well. These businesses delivered growth in adjusted earnings of 4% for the quarter and 12% year-to-date. Moreover, our forecasted growth in rate base of over 7% through 2022 is expected to continue to drive solid earnings and cash flow over the long-term.”

LOGO

Financial Highlights:


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

	2019		2018		2019		2018

Net income attributable to common shareholders	$	55	$	118	$	470	$	479
After-tax mark-to-market gain (loss)		(67)		(73)		(6)		(25)

Adjusted net income attributable to common shareholders⁽¹⁾⁽²⁾	$	122	$	191	$	476	$	504



Earnings per common share – basic	$	0.23	$	0.51	$	1.97	$	2.06
Adjusted earnings per common share – basic ⁽¹⁾⁽²⁾	$	0.51	$	0.82	$	1.99	$	2.17



Weighted average shares of common stock outstanding - basic (millions of shares)		241		234		239		232

⁽¹⁾ See “Non-GAAP Measures” noted below

⁽²⁾ Adjusted net income and adjusted earnings per common share exclude the effect of mark-to-market adjustments

After-tax mark-to-market losses decreased $6 million to $67 million in Q3 2019 compared to $73 million in Q3 2018. This decrease, mainly related to Emera Energy, was due to changes in existing positions on gas contracts, partially offset by higher amortization of gas transportation assets in 2019. Year-to-date, after-tax mark-to-market losses decreased $19 million to $6 million in 2019 compared to $25 million for the same period in 2018. This decrease, mainly related to Emera Energy, was due to changes in existing positions on gas contracts and a larger reversal of mark-to-market losses in 2019, compared to 2018, partially offset by higher amortization of gas transportation assets in 2019.

The weakening of the CAD had minimal impact on earnings and adjusted earnings increased by $1 million in Q3 2019 compared to Q3 2018. The weakening of the CAD increased earnings by $14 million and adjusted earnings by $13 million year-to-date in 2019 compared to the same period in 2018.

LOGO

Consolidated Financial Review:

The following table highlights significant changes in adjusted net income from 2018 to 2019 in the second quarter and year-to-date periods.


For the millions of Canadian dollars	Three months ended September 30		Nine months ended September 30
Adjusted net income – 2018 ⁽¹⁾⁽²⁾	$	191	$	504
Florida Electric Utility - increased earnings due to increased contribution from solar and customer growth		10		41
New Mexico Gas Company, Inc. (“NMGC”) tax benefit related to change in treatment of net operating loss (“NOL”) carryforwards and Q2 2019 recognition of tax reform benefits, of which $8 million relates to 2018		7		19
Gas Utilities and Infrastructure - increased earnings due to favourable weather in New Mexico in the first half of 2019, customer growth at Peoples Gas System (“PGS”) and lower depreciation and amortization at PGS		3		20
Gain on sale of property in Florida		-		10
Increased preferred stock dividends		(1)		(9)
Transaction costs related to the pending sale of Emera Maine		(2)		(6)
Impact of Hurricane Dorian related to GBPC		(16)		(16)
Decreased earnings from Emera Energy Generation due to the sale of NEGG and Bayside generation facilities		(18)		(22)
Decreased earnings at Emera Energy Services		(20)		(43)
2018 recognition of Florida state tax apportionment benefit		(23)		(23)
Other variances		(9)		1
Adjusted net income – 2019 ⁽¹⁾⁽²⁾	$	122	$	476

⁽¹⁾

See “Non-GAAP Measures” noted below

⁽²⁾

Excludes the effect of mark-to-market adjustments

LOGO

Segmented Results:

Effective January 1, 2019, Emera revised its reportable segments to align with strategic priorities and internal governance. Emera reports its results in five operating segments: Florida Electric Utility, Canadian Electric Utilities, Other Electric Utilities, Gas Utilities and Infrastructure and Other.


For the	Three months ended September 30				Nine Months ended September 30
millions of Canadian dollars (except per share amounts)		2019		2018		2019		2018
Adjusted net income⁽¹⁾
Florida Electric Utility	$	153	$	143	$	339	$	298
Canadian Electric Utilities		33		36		171		174
Other Electric Utilities ⁽²⁾		23		31		62		64
Gas Utilities and Infrastructure		25		15		132		93
Other ⁽²⁾		(112)		(34)		(228)		(125)
Adjusted net income ⁽¹⁾	$	122	$	191	$	476	$	504
After-tax mark-to-market gain (loss)		(67)		(73)		(6)		(25)
Net income attributable to common shareholders	$	55	$	118	$	470	$	479

EPS (basic)	$	0.23	$	0.51	$	1.97	$	2.06

Adjusted EPS (basic) ⁽¹⁾⁽²⁾	$	0.51	$	0.82	$	1.99	$	2.17

⁽¹⁾

See “Non-GAAP Measures” noted below.

⁽²⁾

Excludes the effect of mark-to-market adjustments.

Florida Electric Utility’s CAD net income increased by $10 million to $153 million in Q3 2019, compared to $143 million in Q3 2018. Year-to-date, Florida Electric Utility’s CAD net income increased by $41 million to $339 million, compared to $298 million in 2018. Increases in both periods were due to higher base revenues related to the in-service of solar generation projects and customer growth, partially offset by higher depreciation and interest expenses.

Canadian Electric Utilities’ net income decreased by $3 million to $33 million, compared to $36 million in Q3 2018. Year-to-date, Canadian Utilities’ net income was $171 million, compared to $174 million in the 2018 period.

Other Electric Utilities’ CAD net income, adjusted to exclude mark-to-market, decreased by $8 million to $23 million in Q3 2019, compared to $31 million in Q3 2018. Year-to-date, Other Electric Utilities’ CAD net income, adjusted to exclude mark-to-market, decreased by $2 million to $62 million, compared to $64 million in 2018. Decreases in both periods were primarily due to lower earnings in GBPC as a result of the impact of Hurricane Dorian in Q3 2019. The year-to-date decrease was partially offset by higher sales volumes at Domlec due to the completion of hurricane restoration in 2018 and higher capitalized overheads at Emera Maine.

Gas Utilities and Infrastructure’s CAD net income increased by $10 million to $25 million in Q3 2019, compared to $15 million in Q3 2018. Year-to-date, Gas Utilities and Infrastructure’s CAD net income increased by $39 million to $132 million, compared to $93 million in 2018. NMGC’s recognition of the tax benefit related to the change in treatment of NOL carryforwards resulted in a $7 million ($5 million USD) increase in net income for Q3 2019 and year-to-date. The year-to-date increase was also due to NMGC’s recognition of tax reform benefits from January 1, 2018 to June 30, 2019, which resulted in a $12 million ($9 million USD) increase in Q2 2019; customer growth and lower depreciation and amortization at PGS; and favourable weather and the optimization of pipeline capacity in New Mexico.

LOGO

Other’s net loss, adjusted to exclude mark-to-market, increased by $78 million to $112 million in Q3 2019, compared to $34 million in Q3 2018. Year-to-date, Other’s net loss, adjusted to exclude mark-to-market, increased by $103 million to $228 million, compared to $125 million in 2018. The quarterly and year-to-date increases were primarily due to lower marketing and trading margin, lower earnings resulting from the sale of the New England gas portfolio in Q1 2019, decreased income tax recovery and a $9 million after-tax expense associated with Hurricane Dorian. Higher preferred stock dividends and costs related to asset divestitures, partially offset by the gain on sale of property in Florida, also contributed to the year to date increase.

Non-GAAP Measures

Emera uses financial measures that do not have standardized meaning under USGAAP and may not be comparable to similar measures presented by other entities. Emera calculates the non-GAAP measures by adjusting certain GAAP and non-GAAP measures for specific items the Company believes are significant, but not reflective of underlying operations in the period. Refer to the Non-GAAP Financial Measures section of our Management’s Discussion and Analysis (“MD&A”) for further discussion of these items.

Forward Looking Information

This news release contains forward-looking information within the meaning of applicable securities laws. By its nature, forward-looking information requires Emera to make assumptions and is subject to inherent risks and uncertainties. These statements reflect Emera management’s current beliefs and are based on information currently available to Emera management. There is a risk that predictions, forecasts, conclusions and projections that constitute forward-looking information will not prove to be accurate, that Emera’s assumptions may not be correct and that actual results may differ materially from such forward-looking information. Additional detailed information about these assumptions, risks and uncertainties is included in Emera’s securities regulatory filings, including under the heading “Business Risks and Risk Management” in Emera’s annual Management’s Discussion and Analysis, and under the heading “Principal Risks and Uncertainties” in the notes to Emera’s annual and interim financial statements, which can be found on SEDAR at www.sedar.com.

Teleconference Call

The company will be hosting a teleconference today, November 8, 2019 at 9:30 a.m. Atlantic (8:30 a.m. Eastern) to discuss the Q3 2019 financial results.

Analysts and other interested parties in North America are invited to participate by dialing 1-866-521-4909. International parties are invited to participate by dialing 1-647-427-2311. Participants should dial in at least 10 minutes prior to the start of the call. No passcode is required.

A live and archived audio webcast of the teleconference will be available on the Company’s website, www.emera.com. A replay of the teleconference will be available two hours after the conclusion of the call until December 9, 2019, by dialing 1-800-585-8367 and entering passcode 5146398.

LOGO

About Emera

Emera Inc. is a geographically diverse energy and services company headquartered in Halifax, Nova Scotia, with approximately $32 billion in assets and 2018 revenues of more than $6.5 billion. The company primarily invests in regulated electricity generation and electricity and gas transmission and distribution with a strategic focus on transformation from high carbon to low carbon energy sources. Emera has investments throughout North America, and in four Caribbean countries. Emera’s common and preferred shares are listed on the Toronto Stock Exchange and trade respectively under the symbol EMA, EMA.PR.A, EMA.PR.B, EMA.PR.C, EMA.PR.E, EMA.PR.F and EMA.PR.H. Depositary receipts representing common shares of Emera are listed on the Barbados Stock Exchange under the symbol EMABDR and on The Bahamas International Securities Exchange under the symbol EMAB. Additional Information can be accessed at www.emera.com or at www.sedar.com.

Emera Inc.

Investor Relations:

Ken McOnie, VP, Investor Relations and Treasurer

902-428-6945

ken.mconie@emera.com

Erin Power, Manager, Investor Relations

902-428-6760

erin.power@emera.com

Media:

902-222-2683

media@emera.com

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