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 May, 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.

	EMERA INCORPORATED
Date: May 13, 2019	By:	\s\ Stephen D. Aftanas
		Name: Stephen D. Aftanas
		Title: Corporate Secretary

EXHIBIT INDEX

Exhibit No.	Description
99.1	Emera Incorporated Management’s Discussion and Analysis for the three month period ended March 31, 2019
99.2	Emera Incorporated Unaudited Condensed Consolidated Interim Financial Statements for the three month period ended March 31, 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 March 31, 2019
99.6	Emera Incorporated Media Release dated May 10, 2019

EX-99.1

Exhibit 99.1

Management’s Discussion & Analysis

As at May 9, 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 first quarter of 2019 relative to the same quarter in 2018; and its financial position as at March 31, 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 three months ended March 31, 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 and 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;

● 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 LLC; and

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

All comparative segment financial information for the three months ended March 31, 2018 has been restated with no impact to reported consolidated results.

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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”)	National Energy Board (“NEB”)
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”)	NEB 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.

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TABLE OF CONTENTS

Forward-looking Information	4
Introduction and Strategic Overview	4
Non-GAAP Financial Measures	6
Consolidated Financial Review	7
Significant Items Affecting Earnings	7
Consolidated Financial Highlights by Business Segment	7
Consolidated Income Statement Highlights	8
Business Overview and Outlook	11
Florida Electric Utility	11
Canadian Electric Utilities	12
Other Electric Utilities	13
Gas Utilities and Infrastructure	14
Other	14
Consolidated Balance Sheet Highlights	16
Developments	17
Outstanding Common Stock Data	18
Financial Highlights	18
Florida Electric Utility	18
Canadian Electric Utilities	20
Other Electric Utilities	23
Gas Utilities and Infrastructure	25
Other	27
Liquidity and Capital Resources	29
Consolidated Cash Flow Highlights	29
Contractual Obligations	31
Debt Management	32
Guarantees and Letters of Credit	32
Transactions with Related Parties	33
Risk Management and Financial Instruments	33
Disclosure and Internal Controls	35
Critical Accounting Estimates	36
Changes in Accounting Policies and Practices	36
Summary of Quarterly Results	37

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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”, “could”, “estimates”, “expects”, “intends”, “may”, “plans”, “projects”, “schedule”, “should”, “budget”, “forecast”, “might”, “will”, “would”, “targets” 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.

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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 $6.5 billion capital investment plan over the 2019 to 2021 period, including investing $1.4 billion ($1 billion USD) in Florida for the completion of Tampa Electric’s 600 megawatts (“MW”) of new solar generation and the modernization of the Big Bend Power Station. This planned capital investment is being funded primarily through internally generated cash flows, debt raised at the operating company level and select asset sales. Equity capital markets, including the issuance of common and preferred equity and the dividend reinvestment plan will continue to support the Company’s future capital investments. Maintaining investment-grade credit ratings is a key priority of management.

Emera has provided annual dividend growth guidance of four to five per cent through to 2021. 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 but not 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. Customers are looking for more choice, control and reliability. 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 new 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 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.

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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 the Other Electric Utilities and Other segments.

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	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2019		2018
Net income attributable to common shareholders	$	312	$	271
After-tax mark-to-market gain	$	88	$	69
Adjusted net income attributable to common shareholders	$	224	$	202
Earnings per common share – basic	$	1.32	$	1.17
Adjusted earnings per common share – basic	$	0.95	$	0.87

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 adjustments.

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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	Three months ended March 31
millions of Canadian dollars	2019		2018
Net income (1)	$	324	$	278
Interest expense, net		189		175
Income tax expense		82		65
Depreciation and amortization		224		223
EBITDA		819		741
Mark-to-market gain, excluding income tax and interest		126		100
Adjusted EBITDA	$	693	$	641

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

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Q1 Earnings

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

After-tax mark-to-market gains increased $19 million to $88 million in 2019 compared to $69 million in 2018, mainly due to changes in Emera Energy’s 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.

Consolidated Financial Highlights by Business Segment

For the	Three months ended March 31
millions of Canadian dollars	2019		2018
Adjusted Net Income
Florida Electric Utility	$	61	$	60
Canadian Electric Utilities		96		90
Other Electric Utilities		16		15
Gas Utilities and Infrastructure		67		53
Other		(16)		(16)
Adjusted net income attributable to common shareholders	$	224	$	202
After-tax mark-to-market gain		88		69
Net income attributable to common shareholders	$	312	$	271

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

For the	Three months ended
millions of Canadian dollars		March 31
Adjusted net income – 2018		$	202
Gas Utilities and Infrastructure			14
Gain on sale of property in Florida			10
Canadian Electric Utilities			6
Other variances			(8)
Adjusted net income – 2019		$	224

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

For the	Three months ended March 31
millions of Canadian dollars	2019		2018
Operating cash flow before changes in working capital	$	418	$	444
Change in working capital		(16)		(11)
Operating cash flow	$	402	$	433
Investing cash flow	$	298	$	(387)
Financing cash flow	$	(35)	$	(124)
As at	March 31		December 31
millions of Canadian dollars	2019		2018
Total assets	$	31,799	$	32,314
Total long-term debt (including current portion)	$	14,531	$	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 March 31				Variance
	2019		2018
Operating revenues	$	1,818	$	1,807	$	11
Operating expenses		1,276		1,317		41
Income from operations		542		490		52
Income from equity investments		40		37		3
Other income (expenses), net		13		(9)		22
Interest expense, net		189		175		(14)
Income tax expense		82		65		(17)
Net income		324		278		46
Net income attributable to common shareholders		312		271		41
After-tax mark-to-market gain		88		69		19
Adjusted net income attributable to common shareholders	$	224	$	202	$	22
Earnings per common share – basic	$	1.32	$	1.17	$	0.15
Earnings per common share – diluted	$	1.32	$	1.17	$	0.15
Adjusted earnings per common share – basic	$	0.95	$	0.87	$	0.08
Dividends per common share declared	$	0.5875	$	0.5650	$	0.0225
Adjusted EBITDA	$	693	$	641	$	52

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Operating Revenues

For the first quarter of 2019, operating revenues increased $11 million compared to the first quarter of 2018. Absent increased mark-to-market gains of $23 million, operating revenues decreased $12 million due to:

● $35 million decrease at Florida Electric Utility due to lower base rates, reflecting the impact of US tax reform, lower clause recoveries and unfavourable weather. These were partially offset by higher revenues related to in-service solar generation projects, customer growth and the impact of a weaker Canadian dollar; and

● $15 million decrease at Emera Energy due to lower marketing and trading margin reflecting less favourable market conditions relative to the first quarter of 2018.

These impacts were partially offset by increases of:

● $19 million at Canadian Electric Utilities as a result of increased sales volumes at NSPI due to weather and increased fuel related pricing, partially offset by the impact of the Maritime Link assessment; and

● $16 million at Gas Utilities and Infrastructure as a result of the impact of a weaker Canadian dollar, increased sales volumes due to colder weather in New Mexico and increased customers at PGS. These were partially offset by lower base rates reflecting the impact of US tax reform and less favourable weather at PGS.

Operating Expenses

For the first quarter of 2019, operating expenses decreased $41 million compared to the first quarter of 2018. Absent increased mark-to-market losses of $2 million, operating expenses decreased $43 million due to:

● $39 million decrease at Florida Electric Utility as a result of the change in generation mix and decreased operating, maintenance and general (“OM&G”) expenses due to the regulatory agreement to net storm costs and tax reform benefits in 2018. These were partially offset by the impact of a weaker Canadian dollar; and

● $14 million decrease in the Other segment primarily as a result of lower depreciation due to classification of New England Gas Generation (“NEGG’) as held for sale.

These impacts were partially offset by an increase of:

● $12 million at Canadian Electric Utilities, primarily due to increased fuel for generation and purchased power at NSPI as a result of increased commodity prices and sales volumes.

Other Income (Expenses), Net

The increase in other income (expenses), net for the first quarter in 2019, compared to the first quarter of 2018, was primarily due to the gain on sale of property in Florida.

Income Tax Expense

The increase in income tax expense for the first quarter of 2019 compared to the first quarter of 2018 was due to increased income before provision for income taxes.

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Net Income and Adjusted Net Income Attributable to Common Shareholders

For the first quarter of 2019, net income attributable to common shareholders was favourably impacted by the $19 million increase in after-tax mark-to-market gains primarily related to Emera Energy. Absent the favourable mark-to-market changes, adjusted net income attributable to common shareholders increased $22 million. The increase was due to higher contribution from the Gas Utilities and Infrastructure segment, higher contribution from Canadian Electric Utilities, specifically NSPI, 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 higher for the first quarter due to higher earnings as discussed above.

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 March 31				Year ended December 31
	2019		2018		2018
Weighted average CAD/USD exchange rate	$	1.33	$	1.26	$	1.30
Period end CAD/USD exchange rate	$	1.34	$	1.29	$	1.36

The weakening of the Canadian dollar increased earnings by $13 million and adjusted earnings by $8 million in Q1 2019 compared to Q1 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.

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

	Three months ended March 31
millions of US dollars	2019		2018
Florida Electric Utility	$	46	$	48
Other Electric Utilities		12		12
Gas Utilities and Infrastructure (1)		45		36
		103		96
Other segment (2)		(16)		(3)
Total (3)	$	87	$	93

(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

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;

● 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 2019, Tampa Electric sales volumes are expected to be consistent with 2018 which benefited from favourable weather.

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 April 9, 2019, Tampa Electric reached a proposed settlement agreement with consumer parties regarding eligibility of storm costs. If the settlement is approved by the FPSC, Tampa Electric will refund $12 million USD to customers in January 2020, resulting in minimal impact to earnings. A decision by the FPSC is anticipated in Q2 2019.

In 2019, capital expenditures in the Florida Electric Utility segment are expected to be approximately $1.0 billion USD (2018 - $940 million USD), including allowance for funds used during construction (“AFUDC”). Capital projects include supporting normal system reliability and growth, including investments in the modernization of the Big Bend Power Station, solar projects and advanced metering infrastructure (“AMI”). AFUDC will be earned on these projects during the construction periods.

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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 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 complete 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.

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 the 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. Recently, the proposed renewal of the Canada-Nova Scotia Equivalency Agreement was released for public comment on March 29, 2019, with comments due by May 29, 2019. NSPI expects the Equivalency Agreement to be finalized in 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 that extends to 2040 recognizing equivalent outcomes between federal and provincial environmental laws and regulations.

NSPI has completed registration under the Nova Scotia Cap-and-Trade Program Regulations and received its 2019 granted credits in April 2019. These 2019 credits 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.

NSPI continues to advance its “Coal to Clean” strategy. To date, carbon dioxide reductions of over 30 per cent have been achieved, exceeding the 21^st Conference of the Parties of the United Nations Framework Convention on Climate Change target for a 30 per cent reduction from 2005 levels by 2030.

In 2019, NSPI expects to invest approximately $350 million (2018 - $348 million), including AFUDC, in capital projects to support system reliability and AMI.

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ENL

Equity earnings from NSPML and LIL 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.

In 2019, NSPML expects to invest approximately $25 million in capital related to construction close-out costs.

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 $545 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 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 regulatory approvals. 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:

● 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 anticipated to increase over the prior year. The sale of Emera Maine is expected to occur in late 2019, resulting in approximately a year of earnings contribution. 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. Earnings from ECI’s utilities in 2019 are expected to be consistent with 2018.

In 2019, capital expenditures in the Other Electric Utilities segment are expected to be approximately $190 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 new, efficient oil-based generation and renewable generation.

13

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. NMGC first quarter earnings in 2019 were higher than last year due to colder weather throughout the quarter. Customer growth rates are expected to be consistent with 2018, reflecting expectations for housing starts and new connections.

On February 26, 2018, NMGC filed a rate case, including the impact of tax reform. A decision by the NMPRC on the rate case and the refund of tax reform benefits realized from January 1, 2018 to the date rates are in effect is expected in Q2 2019.

In 2019, capital expenditures in the Gas Utilities and Infrastructure segment are expected to be approximately $360 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, a utility services contractor primarily operating in Atlantic Canada.

14

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 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.

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 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 2018, and lower tax recoveries due to the change in Florida state tax apportionment factors that resulted in the remeasurement of certain deferred tax balances in 2018.

In 2019, capital expenditures in the Other segment are expected to be approximately $50 million (2018 - $75 million).

15

CONSOLIDATED BALANCE SHEET HIGHLIGHTS

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

millions of Canadian dollars	Total Increase (Decrease)	Increase (Decrease) due to Emera Maine Held for Sale classification (1)	Other Increase (Decrease)	Explanation of Other Increase (Decrease)
Assets
Cash and cash equivalents	$ 663	$-	$ 663	Increased due to proceeds from the sale of the NEGG and Bayside facilities and cash from operations, partially offset by additions of property, plant and equipment and dividends on common stock.
Inventory	(75)	(8)	(67)	Decreased due to seasonal business trends at Emera Energy and settlement of emission credits at NEGG.
Regulatory assets (current and long-term)	(84)	(134)	50	Increased primarily due to deferred income tax regulatory asset at NSPI and an increase in solar investment tax credits at Tampa Electric.
Assets held for sale (current and long-term), net of liabilities	(98)	710	(808)	Decreased due to completion of the sale of the NEGG facilities.
Property, plant and equipment, net of accumulated depreciation and amortization	(1,346)	(1,288)	(58)	Decreased due to the impact of a stronger CAD on the translation of Emera’s foreign affiliates and the sale of the Bayside facility, partially offset by additions at the regulated utilities.
Goodwill	(282)	(152)	(130)	Decreased due to the effect of a stronger CAD on the translation of Emera’s foreign subsidiaries.
Receivables and other assets (current and long-term)	(150)	(85)	(65)	Decreased due to lower commodity prices and lower cash collateral positions at Emera Energy, partially offset by higher gas transportation assets at Emera Energy.
Liabilities and Equity
Short-term debt and long-term debt (including current portion)	(716)	(487)	(229)	Decreased due to the effect of a stronger CAD on the translation of Emera’s foreign affiliates and a repayment of Emera’s committed credit facilities. These were partially offset by increased borrowings under Tampa Electric’s committed credit facilities.
Accounts payable	(327)	(53)	(274)	Decreased due to timing of accounts payable payments at Tampa Electric, NSPI, and NMGC, lower cash collateral on derivative instruments at NSPI and lower commodity prices at Emera Energy.
Deferred income tax liabilities, net of deferred income tax assets	(221)	(199)	(22)	No significant change after removing impact of Emera Maine held for sale classification.
Derivative instruments (current and long-term)	(122)	-	(122)	Decreased due to the reversal of 2018 asset management agreements, partially offset by new contracts at Emera Energy.
Regulatory liabilities (current and long-term)	(230)	(165)	(65)	Decreased primarily due to the effect of a stronger CAD on the translation of Emera’s foreign affiliates and deferrals related to derivative instruments at NSPI.

16

Pension and post-retirement liabilities	(86)	(74)	(12)	No significant change after removing impact of Emera Maine held for sale classification.
Other liabilities (current and long-term)	127	(13)	140	Increased due to investment tax credits related to solar projects at Tampa Electric and timing of interest payments on long-term debt.
Common stock	83	-	83	Increased due to the dividend reinvestment plan and an increase in options exercised.
Accumulated other comprehensive income	(121)	-	(121)	Decreased due to the effect of a stronger CAD on the translation of Emera’s foreign subsidiaries.
Retained earnings	174	-	174	Increased due to net income in excess of dividends paid.

(1) On March 25, 2019, Emera announced the sale of Emera Maine. As at March 31, 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

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. Shareholder approval will be required for Emera to amend its 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 a working capital adjustment. On March 5, 2019, the Company sold its Bayside facility for cash proceeds of $46 million. The earnings impact of these sale transactions was immaterial. Proceeds from the sales will be used to support capital investment opportunities within Emera’s regulated utilities and to reduce corporate debt.

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 certain regulatory approvals and provisions of the Hart-Scott Rodino Antitrust Improvements Act. 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.

17

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
Issued for cash under Purchase Plans at market rate		1.16		53
Discount on shares purchased under Dividend Reinvestment Plan		-		(2	)
Options exercised under senior management stock option plan		0.90		32
Balance, March 31, 2019		236.18	$	5,899

As at May 6, 2019 the amount of issued and outstanding common shares was 237.2 million.

The weighted average shares of common stock outstanding – basic, which includes both issued and outstanding common stock and outstanding deferred share units, for the three months ended March 31, 2019 was 236.4 million (2018 – 231.0 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 March 31
	2019		2018
Operating revenues – regulated electric	$	412	$	461
Regulated fuel for generation and purchased power		115		141
Contribution to consolidated net income	$	46	$	48
Contribution to consolidated net income – CAD	$	61	$	60
Contribution to consolidated earnings per common share – basic - CAD	$	0.26	$	0.26
Net income weighted average foreign exchange rate – CAD/USD	$	1.33	$	1.25
EBITDA	$	166	$	160
EBITDA – CAD	$	221	$	202

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Net Income

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

For the millions of US dollars	Three months ended March 31
Contribution to consolidated net income – 2018		$          48
Decreased operating revenues - see Operating Revenues - Regulated Electric below		(49)
Decreased fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below		26
Decreased OM&G expenses due to Tampa Electric’s regulatory agreement to net 2018 tax reform benefits, and storm costs recorded through OM&G in 2018. Beginning in 2019, tax reform benefits are reflected in lower base rates		24
Increased depreciation and amortization due to increased property, plant and equipment		(5)
Increased other income as the result of higher AFUDC earnings due to the construction of solar projects		2
Contribution to consolidated net income – 2019		$          46

Florida Electric Utility’s CAD contribution to consolidated net income increased $1 million to $61 million in Q1 2019, compared to $60 million in Q1 2018. Revenues decreased due to a reduction in base rates as a result of tax reform and weather, partially offset by an increase in base rates related to the in-service of solar generation projects. This reduction in revenue was offset by lower OM&G expense in 2019 as the 2018 tax reform benefits were netted against storm costs recorded through OM&G expense in 2018, and the timing of generation outages.

The impact of the change in the foreign exchange rate increased Q1 2019 CAD earnings by $3 million.

Operating Revenues – Regulated Electric

Electric revenues decreased $49 million to $412 million in Q1 2019 compared to $461 million in Q1 2018 primarily due to lower base rates reflecting the impact of US tax reform (beginning January 1, 2019, as approved by the regulator, base rates at Tampa Electric were lowered by $103 million USD annually to reflect the impact of tax reform, resulting in a $22 million USD decrease in revenue in Q1 2019), lower clause recoveries and unfavourable weather. These decreases were partially offset by higher 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:

Q1 Electric Revenues millions of US dollars
		2019		2018
Residential	$	206	$	230
Commercial		120		132
Industrial		34		38
Other (1)		52		61
Total	$	412	$	461

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

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Q1 Electric Sales Volumes Gigawatt hours (“GWh”)
	2019		2018
Residential		1,939		2,021
Commercial		1,370		1,404
Industrial		462		473
Other		461		540
Total		4,232		4,438

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power decreased $26 million to $115 million in Q1 2019, compared to $141 million in Q1 2018, due to increased lower-cost natural gas usage, increased lower-cost solar usage and lower production volumes.

Q1 Production Volumes GWh
	2019		2018
Natural gas		3,768		3,445
Coal		308		635
Oil and petcoke		-		231
Solar		152		10
Purchased power		95		163
Total		4,323		4,484
Q1 Average Fuel Costs
US dollars		2019		2018
Dollars per Megawatt hour (“MWh”)	$	27	$	31

Average fuel cost per MWh decreased in Q1 2019, compared to Q1 2018, primarily due to increased lower-cost natural gas usage and increased lower-cost solar usage.

Canadian Electric Utilities

For the		Three months ended March 31
millions of Canadian dollars (except per share amounts)	2019		2018
Operating revenues – regulated electric	$	443	$	424
Regulated fuel for generation and purchased power (1)		192		175
Income from equity investments		25		25
Contribution to consolidated net income	$	96	$	90
Contribution to consolidated earnings per common share - basic	$	0.41	$	0.39
EBITDA	$	196	$	182

(1) Regulated fuel for generation and purchased power includes NSPI’s FAM and fixed cost deferrals on the Condensed Consolidated Income Statement, 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 March 31
	2019		2018
NSPI	$	71	$	65
Equity investment in NSPML		14		15
Equity investment in LIL		11		10
Contribution to consolidated net income	$	96	$	90

20

Net Income

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

For the millions of Canadian dollars	Three months ended March 31
Contribution to consolidated net income – 2018		$                     90
Increased operating revenues - see Operating Revenues – Regulated Electric below		19
Increased fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below		(17)
Decreased FAM and fixed cost deferrals due to current period under recovery of fuel costs partially offset by the higher application of excess non-fuel revenues		4
Decreased OM&G expenses primarily due to lower storm costs		4
Increased depreciation and amortization due to increased property, plant and equipment		(3)
Decreased other expenses, net primarily due to lower non-current service pension costs		4
Increased income tax expense primarily due to increased income before provision for income taxes		(4)
Other		(1)
Contribution to consolidated net income – 2019		$                     96

Canadian Electric Utilities’ contribution to consolidated net income increased in Q1 2019 due to a higher contribution from NSPI. This increase was a result of increased sales volume due to weather and decreased OM&G expenses, primarily a result of lower storm costs, partially offset by higher depreciation expense.

NSPI

Operating Revenues – Regulated Electric

Operating revenues increased $19 million to $443 million in Q1 2019 compared to $424 million in Q1 2018. Revenues increased as a result of increased sales volume due to weather and increased fuel related electricity pricing in 2019. This was partially offset by the impact of the Maritime Link assessment.

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

Q1 Electric Revenues millions of Canadian dollars
	2019		2018
Residential	$	252	$	236
Commercial		113		110
Industrial		55		57
Other		16		14
Total	$	436	$	417
Q1 Electric Sales Volumes GWh
	2019		2018
Residential		1,621		1,518
Commercial		884		854
Industrial		597		624
Other		143		115
Total		3,245		3,111

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Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $17 million to $192 million in Q1 2019 compared to $175 million in Q1 2018 primarily due to increased commodity prices, increased sales volumes and due to the payment of the Maritime Link assessment.

Q1 Production Volumes GWh
	2019		2018
Coal		1,846		1,646
Oil and petcoke		315		456
Natural gas		244		161
Purchased power – other		141		88
Total non-renewables		2,546		2,351
Wind and hydro		371		385
Purchased power – IPP		370		386
Purchased power – Community Feed-in Tariff program		163		164
Biomass		15		40
Total renewables		919		975
Total production volumes		3,465		3,326
Q1 Average Fuel Costs
	2019		2018
Dollars per MWh	$	55	$	53

Average fuel cost per MWh increased in Q1 2019, compared to Q1 2018, primarily due to increased commodity pricing and timing of the Maritime Link Assessment, partially offset by a change in generation mix.

NSPI’s FAM regulatory liability balance decreased $4 million from $161 million at December 31, 2018 to $157 million at March 31, 2019 primarily due to a refund to customers of the 2018 Maritime Link assessment and under recovery of current period fuel costs. 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 and an increase in the application of excess non-fuel revenues.

ENL

Income from Equity Investments in NSPML and LIL

Q1 2019 income from equity investments was consistent with Q1 2018. In Q1 2018, NSPML began recording cash earnings and collecting UARB approved cash payments from NSPI.

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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 regulatory approvals. 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 March 31
millions of US dollars (except per share amounts)	2019		2018
Operating revenues – regulated electric		$            136	$	137
Regulated fuel for generation and purchased power (1)		49		54
Adjusted contribution to consolidated net income		$              12	$	12
Adjusted contribution to consolidated net income - CAD		$              16	$	15
After-tax equity securities mark-to-market gain (loss)		1		(1)
Contribution to consolidated net income		$              13	$	11
Contribution to consolidated net income – CAD		$              18	$	14
Adjusted contribution to consolidated earnings per common share – basic – CAD		$           0.07	$	0.06
Contribution to consolidated earnings per common share – basic – CAD		$           0.08	$	0.06
Net income weighted average foreign exchange rate – CAD/USD		$           1.33	$	1.26
Adjusted EBITDA		$              47	$	44
Adjusted EBITDA - CAD		$              62	$	56
(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 March 31
	2019		2018
Emera Maine		$                  8		$              8
ECI		4		4
Adjusted contribution to consolidated net income		$                12		$            12

Net Income

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

For the millions of US dollars	Three months ended March 31
Contribution to consolidated net income – 2018	$	11
Operating revenues - see Operating Revenues - Regulated Electric below		(1)
Regulated fuel for generation - see Regulated Fuel for Generation and Purchased Power below		5
Other		(2)
Contribution to consolidated net income – 2019	$	13

Excluding the change in mark-to-market, Other Electric Utilities CAD contribution to consolidated net income increased by $1 million to $16 million in Q1 2019, compared to $15 million in Q1 2018 due to increased contribution from ECI. ECI’s contribution increased primarily due to higher sales volumes at Domlec as a result of the completion of hurricane restoration in 2018 and higher industrial sales volumes at GBPC. The foreign exchange rate had minimal impact for the three months ended March 31, 2019.

23

Operating Revenues – Regulated Electric

Operating revenues decreased $1 million to $136 million in Q1 2019 compared to $137 million in Q1 2018, primarily due to a decrease in revenue at Emera Maine, partially offset by increased sales volumes at Domlec due to the completion of hurricane restoration in 2018. Emera Maine’s revenues decreased due to unfavourable transmission revenue adjustments and lower stranded cost revenue due to the expiration of a major purchased power contract in 2018, partially offset by increased load due to favourable weather and higher distribution and transmission rates in effect in Q1 2019.

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

Q1 Electric Revenues millions of USD
	2019		2018
Residential	$	51	$	47
Commercial		60		62
Industrial		9		9
Other (1)		16		19
Total	$	136	$	137

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

Q1 Electric Sales Volumes
GWh	2019		2018
Residential		339		328
Commercial		369		367
Industrial		112		102
Other		7		6
Total		827		803

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power decreased $5 million to $49 million in Q1 2019, compared to $54 million in Q1 2018 due to the expiration of a major purchased power contract at Emera Maine and lower oil prices at BLPC and GBPC, partially offset by increased volumes at Domlec.

Q1 Production Volumes GWh
	2019		2018
Oil		319		309
Hydro		4		4
Solar		5		4
Purchased power		8		6
Total		336		323

(1) Production volumes relate to ECI only.

Q1 Average Fuel Costs
US dollars	2019		2018
Dollars per MWh		$            116	$	124

(2) Average fuel costs relate to ECI only.

Average fuel cost per MWh decreased in Q1 2019, compared to Q1 2018, as a result of lower oil prices.

24

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 March 31
	2019		2018
Operating revenues – regulated gas (1)	$	269	$	269
Operating revenues – non-regulated		3		4
Total operating revenue		272		273
Regulated cost of natural gas		103		110
Income from equity investments		5		5
Contribution to consolidated net income	$	51	$	41
Contribution to consolidated net income – CAD	$	67	$	53
Contribution to consolidated earnings per common share – basic - CAD	$	0.28	$	0.23
Net income weighted average foreign exchange rate – CAD/USD	$	1.33	$	1.26
EBITDA	$	102	$	94
EBITDA – CAD	$	135	$	119

(1) Operating revenues – regulated gas includes $11 million of finance income from Brunswick Pipeline (2018 – $10 million), 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 March 31
	2019		2018
PGS	$	18	$	15
NMGC		23		17
Other		10		9
Contribution to consolidated net income	$	51	$	41

Net Income

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

For the millions of US dollars	Three months ended March 31
Contribution to consolidated net income – 2018	$	41
Gas operating revenues - see Operating Revenues - Regulated Gas below		-
Decreased cost of natural gas sold - see Regulated Cost of Natural Gas below		7
Decreased depreciation and amortization due to accelerated amortization of assets related to manufactured gas plant environmental remediation costs in 2018 at PGS and reduced PGS depreciation rates in 2019 related to the settlement agreement to net amortization of manufactured gas plant environmental regulatory asset and 2018 tax reform benefits		5
Other variances		(2)
Contribution to consolidated net income – 2019	$	51

Gas Utilities and Infrastructure CAD contribution to consolidated net income increased $14 million to $67 million in Q1 2019 compared to $53 million in Q1 2018. This increase was a result of favourable weather in New Mexico, customer growth in both utilities, lower depreciation and amortization in PGS, and lower OM&G expense in PGS as the 2018 tax reform benefits were recorded through OM&G expense in Q1 2018. These were partially offset by lower revenues in PGS due to tax reform.

The impact of the change in the foreign exchange rate increased Q1 2019 CAD earnings by $3 million compared to Q1 2018.

25

Operating Revenues – Regulated Gas

Q1 2019 operating revenues were consistent with Q1 2018. Revenues increased due to colder weather in New Mexico and increased customers. This was offset by the impact of lower PGS base rates (beginning January 1, 2019, as approved by the regulator, 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 Q1 2019), warmer Florida weather and lower commodity costs.

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

Q1 Gas Revenues
millions of US dollars
	2019		2018
Residential	$	142	$	142
Commercial		73		74
Industrial (1)		9		9
Other (2)		34		34
Total (3)	$	258	$	259

(1) Industrial includes sales to power generation customers.

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

(3) Excludes $11 million of finance income from Brunswick Pipeline (2018 – $10 million).

Q1 Gas Volumes
Therms (millions)
	2019		2018
Residential		175		156
Commercial		263		245
Industrial		337		317
Other		61		50
Total		836		768

Regulated Cost of Natural Gas

Regulated cost of natural gas decreased $7 million to $103 million in Q1 2019, compared to $110 million in Q1 2018, due to lower commodity costs in Florida and New Mexico.

Gas sales by type are summarized in the following table:    

Q1 Gas Volumes by Type
Therms (millions)
	2019		2018
System supply		268		247
Transportation		568		521
Total		836		768

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Other

For the		Three months ended March 31
millions of Canadian dollars (except per share amounts)	2019		2018
Marketing and trading margin (1) (2)	$	54	$	69
Electricity and capacity sales (3) (4)		116		122
Other non-regulated operating revenue		10		10
Total operating revenues – non-regulated		180		201
Intercompany revenue (5)		9		9
Non-regulated fuel for generation and purchased power (4)(6)		64		68
Income from equity investments		8		5
Interest expense, net		93		89
Adjusted contribution to consolidated net income (loss)	$	(16)	$	(16)
After-tax derivative mark-to-market gain	$	86	$	70
Contribution to consolidated net income	$	70	$	54
Adjusted contribution to consolidated earnings per common share – basic	$	(0.07)	$	(0.07)
Contribution to consolidated earnings per common share – basic	$	0.30	$	0.23
Adjusted EBITDA	$	90	$	92

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

(2) Marketing and trading margin excludes a pre-tax mark-to-market gain of $122 million for the quarter ended March 31, 2019 (2018 - $64 million gain).

(3) Electricity and capacity sales exclude a pre-tax mark-to-market gain of $2 million for the quarter ended March 31, 2019 (2018 - $37 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 loss of $2 million for the quarter ended March 31, 2019 (2018 - nil gain).

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

For the	Three months ended
millions of Canadian dollars	March 31
	2019		2018
Emera Energy	$	52	$	55
Corporate		(67)		(71)
Other		(1)		-
Adjusted contribution to consolidated net income (loss)	$	(16)	$	(16)

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Net Income    

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

For the	Three months ended
millions of Canadian dollars	March 31
Contribution to consolidated net income – 2018	$	54
Decreased marketing and trading margin - see Emera Energy - Marketing and Trading below		(15)
Decreased electricity and capacity sales net of non-regulated fuel for generation and purchased power - see Emera Energy - Generation below		(2)
Decreased depreciation due to NEGG held for sale classification		9
Increased income from equity investments due to increased capacity prices at Bear Swamp		3
Increased interest expense		(4)
Gain on sale of property in Florida, pre-tax		14
Increased preferred stock dividends due to the issuance of preferred shares in Q2 2018		(4)
Increased mark-to-market gain, net of tax, primarily due to changes in Emera Energy’s existing positions on gas contracts and a larger reversal of mark-to-market losses in 2019, partially offset by higher amortization of gas transportation assets in 2019		16
Other		(1)
Contribution to consolidated net income – 2019	$	70

Excluding the increase in mark-to-market gain, Other’s contribution to consolidated net income was consistent quarter-over-quarter, primarily due to the gain on sale of property in Florida offset by the decrease in marketing and trading margin.

Emera Energy

Marketing and Trading

Marketing and trading margin decreased $15 million to $54 million in Q1 2019 compared to $69 million in Q1 2018 due to less favourable market conditions relative to Q1 2018, when the impact of colder weather resulted in higher market prices and volatility that led to higher margins.

Generation

Emera Energy’s contribution from generation facilities decreased $2 million to $52 million in Q1 2019, compared to $54 million in Q1 2018. Capacity sales increased $11 million to $38 million in Q1 2019 from $27 million in Q1 2018, due to higher capacity prices that came into effect in New England in June 2018. This was offset by $13 million decrease in energy margin, reflecting less favourable short-term energy hedges, and lower energy sales volumes in New England due to less favourable market conditions in Q1 2019 compared to Q1 2018; and the sale of Bayside Power in Q1 2019.

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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 sufficient 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 expects to invest approximately $6.5 billion over the three-year period from 2019 to 2021 on rate base growth in the Company’s regulated utilities. Over 85 per cent of the investment is expected to be in Florida and Nova Scotia. 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, NEGG and other select asset sales, to support normal operations, repayment of existing debt and capital requirements. 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.

On May 9, 2019, Emera filed a short-form base shelf prospectus, under which the Company may issue common shares in an aggregate principal amount of up to $600 million during the 25 month life of the base shelf prospectus. No common shares have been issued to date under this base shelf prospectus.

At March 31, 2019, Emera had $146 million ($109 million USD) in receivables and other current assets related to the expected refund of alternative minimum tax credit carryforwards. The Company received this refund in April 2019.

Consolidated Cash Flow Highlights

Significant changes in the Condensed Consolidated Statements of Cash Flows between the three months ended March 31, 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		418		444		(26)
Change in working capital		(16)		(11)		(5)
Operating activities		402		433		(31)
Investing activities		298		(387)		685
Financing activities		(35)		(124)		89
Effect of exchange rate changes on cash, cash equivalents and restricted cash		(5)		10		(15)
Cash, cash equivalents and restricted cash, end of period	$	1,032	$	435	$	597

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Cash Flow from Operating Activities

Net cash provided by operating activities in Q1 2019 decreased $31 million to $402 million compared to $433 million for the same period in 2018.

Cash from operations before changes in working capital decreased $26 million due to lower marketing and trading margin at Emera Energy, lower margin at Bayside as a result of the sale in early March and various costs which are offset in working capital. These were partially offset by lower pension contributions, the billing of storm costs at Tampa Electric and higher margins at NMGC.

The changes in working capital overall were comparable quarter-over-quarter.

Cash Flow used in Investing Activities

Net cash provided by investing activities increased $685 million to $298 million for the three months ended March 31, 2019 compared to net cash used in financing activities of $387 million for the same period in 2018. In Q1 2019, Emera received proceeds of $861 million on disposition of the NEGG and Bayside facilities, and on sale of property in Florida. These proceeds were partially offset by an increase in capital expenditures.

Capital expenditures for the three months ended March 31, 2019, including AFUDC, were $561 million compared to $349 million for the same period in 2018. Details of the Q1 2019 capital spend by segment are shown below:

● $306 million - Florida Electric Utility (2018 – $161 million);

● $71 million - Canadian Electric Utilities (2018 – $71 million);

● $38 million - Other Electric Utilities (2018 – $30 million);

● $94 million - Gas Utilities and Infrastructure (2018 – $70 million); and

● $52 million - Other (2018 – $17 million).

Cash Flow from Financing Activities

Net cash used in financing activities decreased $89 million to $35 million for the three months ended March 31, 2019 compared to $124 million for the same period in 2018. The decrease was due to increased borrowings under Tampa Electric’s credit facilities, partially offset by net repayment of Emera’s committed credit facilities.

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Contractual Obligations

As at March 31, 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)	$	1,096	$	694	$	1,708	$	753	$	1,160	$	9,701	$	15,112
Interest payment obligations (2)(3)		614		639		589		542		518		6,780		9,682
Purchased power (4)(5)		200		206		211		212		215		2,094		3,138
Transportation (6)		429		371		235		196		158		1,388		2,777
Pension and post-retirement obligations (7)(8)		29		34		35		36		36		1,040		1,210
Capital projects (9)		405		144		47		9		3		8		616
Fuel, gas supply and storage		417		133		48		7		3		-		608
Asset retirement obligations		2		27		44		1		1		363		438
Long-term service agreements (10)(11)		35		42		29		26		20		113		265
Equity investment commitments (12)		-		-		190		-		-		-		190
Leases and other (13)		10		8		9		9		8		92		136
Demand side management		31		1		-		-		-		-		32
Long-term payable		3		5		5		5		5		-		23
Convertible debentures		-		-		-		-		-		2		2
	$	3,271	$	2,304	$	3,150	$	1,796	$	2,127	$	21,581	$	34,229

As noted below, Contractual Obligations at March 31, 2019 include contractual commitments related to Emera Maine. On completion of the sale of Emera Maine, 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 $488 million related to Emera Maine ($40 million in 2020; $120 million in 2022; $47 million in 2023 and $281 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 March 31, 2019, including any expected required payment under associated swap agreements.

(3) Includes $358 million related to Emera Maine ($14 million in 2019; $20 million in 2020; $18 million in 2021; $13 million in 2022; $13 million in 2023 and $280 million thereafter).

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

(5) Includes $154 million related to Emera Maine ($8 million in 2019; $11 million in 2020; $11 million in 2021; $11 million in 2022; $11 million in 2023 and $102 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 $94 million related to Emera Maine ($4 million in 2019; $7 million in 2020; $7 million in 2021; $7 million in 2022; $7 million in 2023 and $62 million thereafter).

(9) Includes $299 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 $38 million related to various long-term service agreements Emera Maine has entered into for IT maintenance and vegetation management ($13 million in 2019; $14 million in 2020; $5 million in 2021; $3 million in 2022; and $3 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.

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 and is subject to a holdback. After 2019, the timing and amounts payable to NSPML will be subject to regulatory filings with the UARB, with expected filings in 2019 and 2020.

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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 2020	$	900	$	205	$	695
TECO Finance, Inc. – in USD – Operating credit facilities	March 2020 - March 2022		900		650		250
NSPI – Operating credit facility	October 2023		600		545		55
TEC - in USD - credit facilities (1)	March 2021 - March 2022		475		313		162
NMGC – in USD – Operating credit facility	March 2022		125		44		81
Emera Maine – in USD – Operating credit facility	February 2023		80		38		42
Other - in USD - Operating credit facility	Various		32		17		15

(1) This facility is available for use by Tampa Electric and PGS. At March 31, 2019, Tampa Electric had utilized $269 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 March 31, 2019.

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

Canadian Electric Utilities

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.

Other

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.

Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2018 annual MD&A, with updates as noted below:

The Company has standby letters of credit and surety bonds in the amount of $58 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 December 2019. This letter of credit is renewed annually. The amount committed as of March 31, 2019 was $6 million USD (December 31, 2018 - $6 million USD).

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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 $27 million for the three months ended March 31, 2019 (2018 - $24 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 $18 million for the three months ended March 31, 2019 (2018 - $10 million).

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

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	March 31		December 31
millions of Canadian dollars	2019		2018
Derivative instrument liabilities (current and long-term liabilities)	$	(2)	$	(5)
Net derivative instrument assets (liabilities)	$	(2)	$	(5)

33

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	Three months ended March 31
millions of Canadian dollars	2019		2018
Operating revenues – regulated	$	(2)	$	2
Non-regulated fuel for generation and purchased power		-		4
Effective net gains (losses)	$	(2)	$	6

The effectiveness 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	March 31 2019		December 31 2018
Derivative instrument assets (current and other assets)	$	74	$	104
Regulatory assets (current and other assets)		17		6
Derivative instrument liabilities (current and long-term liabilities)		(17)		(6)
Regulatory liabilities (current and long-term liabilities)		(80)		(115)
Net asset (liability)	$	(6)	$	(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	Three months ended March 31
millions of Canadian dollars	2019		2018
Regulated fuel for generation and purchased power (1)		$                  4		$                  4
Net gains (losses)		$                  4		$                  4

(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	March 31 2019		December 31 2018
Derivative instrument assets (current and other assets)		$                39		$                62
Derivative instrument liabilities (current and long-term liabilities)		(224)		(354)
Net derivative instrument assets (liabilities)		$            (185)		$            (292)

34

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	Three months ended March 31
millions of Canadian dollars	2019		2018
Operating revenues – non-regulated		$              149		$            128
Non-regulated fuel for generation and purchased power		(2)		(2)
Net gains (losses)		$              147		$            126

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	March 31 2019		December 31 2018
Derivative instrument assets (current and other assets)	$	14	$	1
Net derivative instrument assets (liabilities)	$	14	$	1

For the three months ended March 31, 2019, the Company had unrealized gains on equity derivatives of $14 million (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 March 31, 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 March 31, 2019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

35

CRITICAL ACCOUNTING ESTIMATES

The preparation of consolidated financial statements in accordance with generally accepted accounting principles 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 months ended March 31, 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.

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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.

SUMMARY OF QUARTERLY RESULTS

For the quarter ended millions of dollars (except per share amounts)		Q1 2019		Q4 2018		Q3 2018		Q2 2018		Q1 2018		Q4 2017			Q3 2017		Q2 2017
Operating revenues	$	1,818	$	1,799	$	1,495	$	1,423	$	1,807	$	1,473		$	1,427	$	1,469
Net income (loss) attributable to common shareholders		312		231		118		90		271		(228	)		81		101
Adjusted net income attributable to common shareholders		224		167		191		111		202		137			118		117
Earnings per common share - basic		1.32		0.98		0.51		0.38		1.17		(1.06	)		0.38		0.47
Earnings per common share - diluted		1.32		0.98		0.50		0.38		1.17		(1.06	)		0.38		0.47
Adjusted earnings per common share - basic		0.95		0.71		0.82		0.48		0.87		0.64			0.55		0.55

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.

37

EX-99.2

Exhibit 99.2

EMERA INCORPORATED

Unaudited Condensed Consolidated

Interim Financial Statements

March 31, 2019 and 2018

38

Emera Incorporated

Condensed Consolidated Statements of Income (Unaudited)

For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2019		2018
Operating revenues
Regulated electric	$	1,169	$	1,177
Regulated gas		352		333
Non-regulated		297		297
Total operating revenues (note 6)		1,818		1,807
Operating expenses
Regulated fuel for generation and purchased power		401		415
Regulated cost of natural gas		136		138
Non-regulated fuel for generation and purchased power		64		66
Operating, maintenance and general		366		392
Provincial, state and municipal taxes		85		83
Depreciation and amortization		224		223
Total operating expenses		1,276		1,317
Income from operations		542		490
Income from equity investments (note 7)		40		37
Other income (expenses), net		13		(9)
Interest expense, net		189		175
Income before provision for income taxes		406		343
Income tax expense (note 8)		82		65
Net income		324		278
Non-controlling interest in subsidiaries		1		-
Preferred stock dividends		11		7
Net income attributable to common shareholders	$	312	$	271
Weighted average shares of common stock outstanding (in millions) (note 10)
Basic		236.4		231.0
Diluted		237.0		231.5
Earnings per common share (note 10)
Basic	$	1.32	$	1.17
Diluted	$	1.32	$	1.17
Dividends per common share declared	$	0.5875	$	0.5650
The accompanying notes are an integral part of these condensed consolidated financial statements.

39

Emera Incorporated

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

For the	Three months ended March 31
millions of Canadian dollars	2019		2018
Net income	$	324	$	278
Other comprehensive income, net of tax
Foreign currency translation adjustment		(163)		185
Unrealized gains (losses) on net investment hedges (1)(2)		34		(36)
Cash flow hedges
Net derivative gains		2		1
Less: reclassification adjustment for gains included (3) in income		2		(5)
Net effects of cash flow hedges		4		(4)
Unrealized gains (losses) on available-for-sale investment
Unrealized gain (loss) arising during the period		-		(1)
Less: reclassification adjustment for (gains) recognized in income		-		(4)
Net unrealized holding gains (losses)		-		(5)
Net change in unrecognized pension and post-retirement benefit obligation (4)		4		8
Other comprehensive income (loss) (5)		(121)		148
Comprehensive income		203		426
Comprehensive income attributable to non-controlling interest		1		1
Comprehensive Income of Emera Incorporated	$	202	$	425

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

1)  Net of tax expense of nil (2018 - $6 million recovery) for the three months ended March 31, 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 - $1 million tax recovery) for the three months ended March 31, 2019.

4)  Net of tax expense of $1 million (2018 - nil) for the three months ended March 31, 2019.

5)  Net of tax expense of $1 million (2018 - $7 million tax recovery) for the three months ended March 31, 2019.

40

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)

As at millions of Canadian dollars	March 31 2019		December 31 2018
Assets
Current assets
Cash and cash equivalents	$	979	$	316
Restricted cash		53		56
Inventory		399		474
Derivative instruments (notes 12 and 13)		107		148
Regulatory assets (note 14)		143		165
Receivables and other current assets		1,473		1,620
Assets held for sale (note 4)		89		53
		3,243		2,832
Property, plant and equipment, net of accumulated depreciation and amortization of $8,111 and $8,567, respectively		17,366		18,712
Other assets
Deferred income taxes		133		175
Derivative instruments (notes 12 and 13)		20		19
Regulatory assets (note 14)		1,342		1,404
Net investment in direct financing lease (note 16)		473		475
Investments subject to significant influence (note 7)		1,291		1,316
Goodwill		6,031		6,313
Other long-term assets		288		291
Assets held for sale (note 4)		1,612		777
		11,190		10,770
Total assets	$	31,799	$	32,314

41

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited) – Continued

As at millions of Canadian dollars	March 31 2019		December 31 2018
Liabilities and Equity
Current liabilities
Short-term debt (note 18)	$	1,350	$	1,186
Current portion of long-term debt		1,502		1,119
Accounts payable		962		1,289
Derivative instruments (notes 12 and 13)		172		260
Regulatory liabilities (note 14)		222		251
Other current liabilities		446		428
Liabilities associated with assets held for sale (note 4)		63		20
		4,717		4,553
Long-term liabilities
Long-term debt (note 19)		13,029		14,292
Deferred income taxes		1,057		1,320
Derivative instruments (notes 12 and 13)		71		105
Regulatory liabilities (note 14)		2,158		2,359
Pension and post-retirement liabilities (note 17)		555		641
Other long-term liabilities		793		684
Long-term liabilities associated with assets held for sale (note 4)		928		2
		18,591		19,403
Equity
Common stock (note 9)		5,899		5,816
Cumulative preferred stock		1,004		1,004
Contributed surplus		82		84
Accumulated other comprehensive income (loss) (note 11)		217		338
Retained earnings		1,249		1,075
Total Emera Incorporated equity		8,451		8,317
Non-controlling interest in subsidiaries		40		41
Total equity		8,491		8,358
Total liabilities and equity	$	31,799	$	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

42

Emera Incorporated    

Condensed Consolidated Statements of Cash Flows (Unaudited)

For the	Three months ended March 31
millions of Canadian dollars	2019		2018
Operating activities
Net income	$	324	$	278
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		228		227
Income from equity investments, net of dividends		(22)		(28)
Allowance for equity funds used during construction		(4)		(2)
Deferred income taxes, net		68		54
Net change in pension and post-retirement liabilities		(3)		(3)
Regulated fuel adjustment mechanism		(4)		4
Net change in fair value of derivative instruments		(114)		(59)
Net change in regulatory assets and liabilities		(7)		17
Net change in capitalized transportation capacity		(25)		(39)
Other operating activities, net		(23)		(5)
Changes in non-cash working capital (note 21)		(16)		(11)
Net cash provided by operating activities		402		433
Investing activities
Proceeds from dispositions (note 4)		861		-
Additions to property, plant and equipment		(557)		(349)
Net purchase of investments subject to significant influence, inclusive of acquisition costs		-		(40)
Other investing activities		(6)		2
Net cash provided by (used in) investing activities		298		(387)
Financing activities
Change in short-term debt, net		188		(103)
Proceeds from short-term debt with maturities greater than 90 days		-		129
Proceeds from long-term debt, net of issuance costs		-		24
Retirement of long-term debt		(9)		(4)
Net repayments under committed credit facilities		(142)		(58)
Issuance of common stock, net of issuance costs		32		3
Dividends on common stock		(90)		(82)
Dividends on preferred stock		(11)		(7)
Other financing activities		(3)		(26)
Net cash used in financing activities		(35)		(124)
Effect of exchange rate changes on cash, cash equivalents, and restricted cash		(5)		10
Net increase (decrease) in cash, cash equivalents and restricted cash		660		(68)
Cash, cash equivalents and restricted cash, beginning of period		372		503
Cash, cash equivalents and restricted cash, end of period	$	1,032	$	435
Cash, cash equivalents, and restricted cash consists of:
Cash	$	332	$	235
Short-term investments		647		132
Restricted cash		53		68
Cash, cash equivalents, and restricted cash	$	1,032	$	435

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

43

Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)

	Common Stock		Preferred Stock		Contributed Surplus		Accumulated Other Comprehensive Income (Loss) (“AOCI”)		Retained Earnings		Non- Controlling Interest		Total         Equity
millions of Canadian dollars
Balance, December 31, 2018	$	5,816	$	1,004	$	84	$	338	$	1,075	$	41	$	8,358
Net income of Emera Incorporated		-		-		-		-		323		1		324
Other comprehensive loss, net of tax expense of $1 million		-		-		-		(121)		-		-		(121)
Dividends declared on preferred stock (Series A: $0.1597/share, Series B: $0.2206/share, Series C: $0.29506/share, Series E: $0.28125/share, Series F: $0.265625/share and Series H: $0.30625/share)		-		-		-		-		(11)		-		(11)
Dividends declared on common stock ($0.5875/share)		-		-		-		-		(138)		-		(138)
Common stock issued under purchase plan		51		-		-		-		-		-		51
Senior management stock options exercised		32		-		(2)		-		-		-		30
Other		-		-		-		-		-		(2)		(2)
Balance, March 31, 2019	$	5,899	$	1,004	$	82	$	217	$	1,249	$	40	$	8,491
millions of Canadian dollars
Balance, December 31, 2017	$	5,601	$	709	$	76	$	(165)	$	891	$	92	$	7,204
Net income of Emera Incorporated		-		-		-		-		278		-		278
Other comprehensive income, net of tax recovery of $7 million		-		-		-		148		-		1		149
Dividends declared on preferred stock (Series A: $0.15970/share, Series B: $0.17870/share, Series C: $0.25625/share, Series E: $0.28125/share and Series F: $0.265625/share)		-		-		-		-		(7)		-		(7)
Dividends declared on common stock ($0.565/share)		-		-		-		-		(129)		-		(129)
Common stock issued under purchase plan		50		-		-		-		-		-		50
Acquisition of non-controlling interest of ICD Utilities (“ICDU”)		22		-		8		-		-		(53)		(23)
Other		1		-		-		-		6		(1)		6
Balance, March 31, 2018	$	5,674	$	709	$	84	$	(17)	$	1,039	$	39	$	7,528

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

44

Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)

As at March 31, 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.

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.

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 $1.56 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 complete 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 regulatory approvals. 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;

● 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.

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● 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 from offshore Nova Scotia to 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., a utility services contractor primarily operating in Atlantic Canada; 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.

46

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 are 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 is 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.

47

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

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 months ended March 31, 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.

48

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.

3. 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.

4. DISPOSITIONS

Held for sale

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 certain regulatory approvals and provisions of the Hart-Scott Rodino Antitrust Improvements Act. A material gain on the sale is expected to be recognized at closing.

As at March 31, 2019, Emera Maine’s assets and liabilities were classified as held for sale and were 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.

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

As at millions of Canadian dollars	March 31 2019
Regulatory assets	$	14
Receivables and other current assets		75
Current assets held for sale		89
Property, plant and equipment		1,288
Goodwill		152
Regulatory assets		120
Other long-term assets		52
Long-term assets held for sale		1,612
Total assets held for sale	$	1,701
Regulatory liabilities	$	10
Accounts payable and other current liabilities		53
Current liabilities associated with assets held for sale		63
Long-term debt		487
Deferred income taxes		199
Regulatory liabilities		155
Other long-term liabilities		87
Long-term liabilities associated with assets held for sale		928
Total liabilities associated with assets held for sale	$	991

Dispositions

On March 29, 2019, Emera completed the sale of its three NEGG facilities for cash proceeds of $799 million ($598 million USD) including a working capital adjustment. 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. The earnings impact of these sale transactions was immaterial.

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

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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.

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. All comparative segment financial information has been restated with no impact to reported consolidated results.

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 March 31, 2019
Operating revenues from external customers (1)	$	545	$	442	$	182	$	356	$	294	$	-		$	1,819
Inter-segment revenues (1)		3		1		-		6		10		(21)			(1)
Total operating revenues		548		443		182		362		304		(21)			1,818
Net income attributable to common shareholders		61		96		18		67		70		-			312
As at March 31, 2019
Total assets		15,973		6,371		3,078		5,334		2,261		(1,218)	(2)		31,799
For the three months ended March 31, 2018
Operating revenues from external customers (1)	$	581	$	423	$	173	$	339	$	291	$	-		$	1,807
Inter-segment revenues (1)		2		1		-		7		11		(21)			-
Total operating revenues		583		424		173		346		302		(21)			1,807
Net income attributable to common shareholders		60		90		14		53		54		-			271
As at December 31, 2018
Total assets		15,997		6,275		3,094		5,404		2,653		(1,109)	(2)		32,314

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

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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 March 31, 2019
Regulated
Electric Revenue
Residential	$	274	$	252	$	68	$	-	$	-	$	-	$	594
Commercial		160		113		80		-		-		-		353
Industrial		46		55		12		-		-		-		113
Other electric and regulatory deferrals		62		16		3		-		-		-		81
Other (1)		6		7		19		-		-		(4)		28
Regulated electric revenue		548		443		182		-		-		(4)		1,169
Gas Revenue
Residential		-		-		-		189		-		-		189
Commercial		-		-		-		98		-		-		98
Industrial		-		-		-		12		-		-		12
Finance income (2)(3)		-		-		-		14		-		-		14
Other		-		-		-		45		-		(6)		39
Regulated gas revenue		-		-		-		358		-		(6)		352
Non-Regulated
Marketing and trading margin (4)		-		-		-		-		54		-		54
Energy sales (4)		-		-		-		-		78		(4)		74
Capacity		-		-		-		-		38		-		38
Other		-		-		-		4		10		(7)		7
Mark-to-market (3)		-		-		-		-		124		-		124
Non-regulated revenue		-		-		-		4		304		(11)		297
Total operating revenues	$	548	$	443	$	182	$	362	$	304	$	(21)	$	1,818

(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.

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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 March 31, 2018
Regulated
Electric Revenue
Residential	$	290	$	236	$	58	$	-	$	-	$	-	$	584
Commercial		167		110		78		-		-		-		355
Industrial		48		57		12		-		-		-		117
Other electric and regulatory deferrals		73		14		4		-		-		-		91
Other (1)		5		7		21		-		-		(3)		30
Regulated electric revenue		583		424		173		-		-		(3)		1,177
Gas Revenue
Residential		-		-		-		179		-		-		179
Commercial		-		-		-		92		-		-		92
Industrial		-		-		-		11		-		-		11
Finance income (2)(3)		-		-		-		13		-		-		13
Other		-		-		-		45		-		(7)		38
Regulated gas revenue		-		-		-		340		-		(7)		333
Non-Regulated
Marketing and trading margin (4)		-		-		-		-		69		-		69
Energy sales (4)		-		-		-		-		95		(4)		91
Capacity		-		-		-		-		27		-		27
Other		-		-		-		6		10		(7)		9
Mark-to-market (3)		-		-		-		-		101		-		101
Non-regulated revenue		-		-		-		6		302		(11)		297
Total operating revenues	$	583	$	424	$	173	$	346	$	302	$	(21)	$	1,807

(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 March 31, 2019, the aggregate amount of the transaction price allocated to remaining performance obligations was $357 million (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.

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7.  INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME

Investments subject to significant influence consisted of the following:

	Carrying Value as at				Equity Income For the three months ended				Percentage of
	March 31		December 31		March 31				Ownership
millions of Canadian dollars	2019		2018		2019		2018		2019
NSPML	$	549	$	545	$	14	$	15		100.0
LIL (1)		545		534		11		10		49.5
M&NP (2)		150		155		6		6		12.9
Lucelec (2)		42		42		1		-		19.1
Bear Swamp (3)		-		-		8		4		50.0
Other Investments		5		40		-		2
	$	1,291	$	1,316	$	40	$	37

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

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

(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $179 million distribution received in Q4 2015. Bear Swamp’s credit investment balance of $160 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 22). NSPML’s consolidated summarized balance sheet is as follows:

As at	March 31		December 31
millions of Canadian dollars	2019		2018
Balance Sheet
Current assets	$	110	$	86
Property, plant and equipment		1,682		1,690
Non-current assets		160		140
Total assets	$	1,952	$	1,916
Current liabilities	$	45	$	21
Long-term debt		1,288		1,288
Non-current liabilities		70		62
Equity		549		545
Total liabilities and equity	$	1,952	$	1,916

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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	Three months ended March 31
millions of Canadian dollars	2019		2018
Income before provision for income taxes	$	406	$	343
Statutory income tax rate		31%		31%
Income taxes, at statutory income tax rate		126		106
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities		(21)		(21)
Foreign tax rate variance		(12)		(10)
Amortization of deferred income tax regulatory liabilities		(9)		(8)
Other		(2)		(2)
Income tax expense (recovery)	$	82	$	65
Effective income tax rate		20%		19%

At March 31, 2019, Emera had $146 million ($109 million USD) in receivables and other current assets related to the expected refund of alternative minimum tax credit carryforwards. The Company received this refund in April 2019.

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
Issued for cash under Purchase Plans at market rate		1.16		53
Discount on shares purchased under Dividend Reinvestment Plan		-		(2	)
Options exercised under senior management share option plan		0.90		32
Balance, March 31, 2019		236.18		$          5,899

On May 9, 2019, Emera filed a short-form base shelf prospectus, under which the Company may issue common shares in an aggregate principal amount of up to $600 million during the 25 month life of the base shelf prospectus. No common shares have been issued to date under this base shelf prospectus.

10.  EARNINGS PER SHARE

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

For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2019		2018
Numerator
Net income attributable to common shareholders	$	311.8	$	271.4
Diluted numerator		311.8		271.4
Denominator
Weighted average shares of common stock outstanding		234.9		229.8
Weighted average deferred share units outstanding		1.5		1.2
Weighted average shares of common stock outstanding – basic		236.4		231.0
Stock-based compensation		0.5		0.4
Convertible Debentures		0.1		0.1
Weighted average shares of common stock outstanding – diluted		237.0		231.5
Earnings per common share
Basic	$	1.32	$	1.17
Diluted	$	1.32	$	1.17

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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 three months ended March 31, 2019
Balance, January 1, 2019	$	654	$	(74)	$	(7)	$	(1)	$	(234)	$	338
Other comprehensive income (loss) before reclassifications		(163)		34		2		-		-		(127)
Amounts reclassified from accumulated other comprehensive income loss (gain)		-		-		2		-		4		6
Net current period other comprehensive income (loss)		(163)		34		4		-		4		(121)
Balance, March 31, 2019	$	491	$	(40)	$	(3)	$	(1)	$	(230)	$	217
For the three months ended March 31, 2018
Balance, January 1, 2018 (1)	$	30	$	48	$	(3)	$	3	$	(243)	$	(165)
Other comprehensive income (loss) before reclassifications		185		(36)		1		(1)		-		149
Amounts reclassified from accumulated other comprehensive income loss (gain)		-		-		(5)		(4)		8		(1)
Net current period other comprehensive income (loss)		185		(36)		(4)		(5)		8		148
Balance, March 31, 2018	$	215	$	12	$	(7)	$	(2)	$	(235)	$	(17)

(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.

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

For the		Three months ended March 31
millions of Canadian dollars		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	$	2	$	(2)
Power and gas swaps	Non-regulated fuel for generation and purchased power		-		(4)
Total before tax			2		(6)
	Income tax recovery (expense)		-		1
Total net of tax		$	2	$	(5)
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	$	5	$	8
Past service costs (gains)	OM&G		-		-
Total before tax			5		8
	Income tax recovery (expense)		(1)		-
Total net of tax		$	4	$	8
Total reclassifications out of AOCI, net of tax, for the period		$	6	$	(1)

(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:

1. 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.

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2. 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.

3. 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.

4. 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.

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

	Derivative Assets				Derivative Liabilities
As at millions of Canadian dollars	March 31 2019		December 31 2018		March 31 2019		December 31 2018
Cash flow hedges
Foreign exchange forwards	$	-	$	-	$	2	$	5
		-		-		2		5
Regulatory deferral
Commodity swaps and forwards
Coal purchases		35		71		12		1
Power purchases		-		2		1		1
Natural gas purchases and sales		1		2		4		4
Heavy fuel oil purchases		23		1		1		1
Foreign exchange forwards		17		29		1		-
		76		105		19		7
HFT derivatives
Power swaps and physical contracts		19		62		26		76
Natural gas swaps, futures, forwards, physical contracts		77		125		255		403
		96		187		281		479
Other derivatives
Interest rate swap and equity derivatives		14		1		-		-
		14		1		-		-
Total gross current derivatives		186		293		302		491
Impact of master netting agreements with intent to settle net or simultaneously		(59)		(126)		(59)		(126)
		127		167		243		365
Current		107		148		172		260
Long-term		20		19		71		105
Total derivatives	$	127	$	167	$	243	$	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	March 31 2019		December 31 2018		March 31 2019		December 31 2018
Regulatory deferral	$	2	$	1	$	2	$	1
HFT derivatives		57		125		57		125
Total impact of master netting agreements with intent to settle net or simultaneously	$	59	$	126	$	59	$	126

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Cash Flow Hedges

The Company enters into various derivatives designated as cash flow hedges. Emera enters into power swaps to limit Bear Swamp’s exposure to purchased power prices. The Company also has foreign exchange forwards to hedge the currency risk for revenue streams denominated in foreign currency for Brunswick Pipeline.

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

For the	Three months ended March 31
millions of Canadian dollars					2019				2018
	Power Swaps		Interest Rate Swaps		Foreign Exchange Forwards		Power Swaps		Foreign Exchange Forwards
Realized gain (loss) in non-regulated fuel for generation and purchased power		-		-		-		4		-
Realized gain (loss) in operating revenue – regulated		-		-		(2)		-		2
Total gains (losses) in net income	$	-	$	-	$	(2)	$	4	$	2
As at	March 31								December 31
millions of Canadian dollars					2019				2018
	Power Swaps		Interest Rate Swaps		Foreign Exchange Forwards		Power Swaps		Foreign Exchange Forwards
Total unrealized gain (loss) in AOCI – effective portion, net of tax	$	(1)	$	1	$	(3)	$	(1)	$	(6)

The Company expects $2 million of unrealized loss currently in AOCI to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle.

As at March 31, 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	$	21	$	30

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Regulatory Deferral

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

For the millions of Canadian dollars	Three months ended March 31, 2019
	Commodity swaps and forwards		Physical natural gas and biofuel energy purchases and sales		Foreign exchange forwards
Unrealized gain (loss) in regulatory assets	$	6	$	-	$	(1)
Unrealized gain (loss) in regulatory liabilities		(19)		-		(5)
Realized (gain) loss in regulatory assets		5		-		-
Realized (gain) loss in regulatory liabilities		-		-		-
Realized (gain) loss in inventory (1)		(18)		-		(5)
Realized (gain) loss in regulated fuel for generation and purchased power (2)		(2)		-		(2)
Total change in derivative instruments	$	(28)	$	-	$	(13)
(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 millions of Canadian dollars	Three months ended March 31, 2018
	Commodity swaps and forwards		Physical natural gas and biofuel energy purchases and sales		Foreign exchange forwards
Unrealized gain (loss) in regulatory assets	$	(9)	$	(2)	$	1
Unrealized gain (loss) in regulatory liabilities		(20)		-		6
Realized (gain) loss in regulatory liabilities		(2)		-		-
Realized (gain) loss in inventory (1)		(13)		-		(5)
Realized (gain) loss in regulated fuel for generation and purchased power (2)		(3)		-		(1)
Total change in derivative instruments	$	(47)	$	(2)	$	1
(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 March 31, 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		1
Natural Gas (Mmbtu)		8		3
Heavy fuel oil (bbls)		-		1

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Foreign Exchange Swaps and Forwards

As at March 31, 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
Foreign exchange contracts (millions of US dollars)	$	147	$	111
Weighted average rate		1.2408		1.3027
% of USD requirements		76%		45%

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

Held-for-Trading Derivatives

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

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

For the	Three months ended March 31
millions of Canadian dollars	2019		2018
Power swaps and physical contracts in non-regulated operating revenues	$	(3)	$	(9)
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues		152		137
Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power		(2)		(2)
	$	147	$	126

As at March 31, 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)		299		118		71		51		41
Natural gas sales (Mmbtu)		267		58		9		2		-
Power purchases (MWh)		3		-		-		-		-
Power sales (MWh)		2		-		-		-		-

Other Derivatives

As at March 31, 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.

For the three months ended March 31, 2019, the Company had unrealized gains on equity derivatives of $14 million (2018 – nil) recorded in Operating, maintenance and general expense in the Condensed Consolidated Statements of Income.

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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 March 31, 2019, the Company had $125 million (December 31, 2018 - $118 million) in financial assets considered to be past due, which have been outstanding for an average 76 days. The fair value of these financial assets is $113 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.

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Cash Collateral

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

As at	March 31		December 31
millions of Canadian dollars	2019		2018
Cash collateral provided to others		$            16		$            103
Cash collateral received from others		19		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 March 31, 2019, the total fair value of these derivatives, in a liability position, was $243 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.

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

As at	March 31, 2019
millions of Canadian dollars	Level 1		Level 2		Level 3		Total
Assets
Regulatory deferral
Commodity swaps and forwards
Coal purchases	$	-	$	34	$	-	$	34
Natural gas purchases and sales		-		1		-		1
Heavy fuel oil purchases		4		18		-		22
Foreign exchange forwards		-		17		-		17
		4		70		-		74
HFT derivatives
Power swaps and physical contracts		2		-		2		4
Natural gas swaps, futures, forwards, physical contracts and related transportation		2		19		14		35
		4		19		16		39
Other derivatives
Equity derivatives and interest rate swap		14		-		-		14
		14		-		-		14
Total assets		22		89		16		127
Liabilities
Cash flow hedges
Foreign exchange forwards		-		2		-		2
		-		2		-		2
Regulatory deferral
Commodity swaps and forwards
Coal purchases		-		11		-		11
Power purchases		1		-		-		1
Natural gas purchases and sales		3		1		-		4
Foreign exchange forwards		-		1		-		1
		4		13		-		17
HFT derivatives
Power swaps and physical contracts		8		2		1		11
Natural gas swaps, futures, forwards and physical contracts		(3)		7		209		213
		5		9		210		224
Total liabilities		9		24		210		243
Net assets (liabilities)	$	13	$	65	$	(194)	$	(116)

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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 March 31, 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		(1)		(4)		(5)
Balance, March 31, 2019	$	2	$	14	$	16

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The change in the fair value of the Level 3 financial liabilities for the three months ended March 31, 2019 was as follows:

	HFT Derivatives
millions of Canadian dollars	Power		Natural gas		Total
Balance, beginning of period	$	1	$	305	$	306
Total realized and unrealized gains (losses) included in non-regulated operating revenues		-		(96)		(96)
Balance, March 31, 2019	$	1	$	209	$	210

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 months ended March 31, 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.

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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	March 31, 2019
millions of Canadian dollars	Fair Value		Valuation Technique	Unobservable Input	Range	Weighted average
Assets
HFT derivatives –	$	1	Modelled pricing	Third-party pricing	$23.15 - $88.25		$41.20
Power swaps and				Probability of default	0.02% - 2.43%		0.60%
physical contracts				Discount rate	0.22% - 10.43%		4.68%
		1	Modelled pricing	Third-party pricing	$23.43 - $32.42		$30.19
				Probability of default	0.13% - 0.13%		0.13%
				Discount rate	0.38% - 1.27%		0.95%
				Correlation factor	85.41% - 85.41%		85.41%
HFT derivatives –		9	Modelled pricing	Third-party pricing	$1.98 - $5.58		$3.12
Natural gas swaps, futures,				Probability of default	0.01% - 4.32%		0.34%
forwards, physical contracts				Discount rate	0.02% - 27.22%		4.28%
		5	Modelled pricing	Third-party pricing	$2.09 - $11.68		$5.23
				Basis adjustment	$0.10 - $3.33		$2.45
				Probability of default	0.01% - 1.77%		0.15%
				Discount rate	0.02% - 6.29%		0.83%
Total assets	$	16
Liabilities
HFT derivatives –	$	1	Modelled pricing	Third-party pricing	$21.36 - $26.89		$22.35
Power swaps and				Probability of default	0.13% - 0.13%		0.13%
physical contracts				Discount rate	0.12% - 1.96%		1.20%
				Correlation factor	85.41% - 85.41%		85.41%
HFT derivatives –		197	Modelled pricing	Third-party pricing	$1.53 - $11.19		$4.95
Natural gas swaps, futures,				Own credit risk	0.02% - 0.58%		0.08%
forwards and physical contracts				Discount rate	0.02% - 10.08%		2.90%
		12	Modelled pricing	Third-party pricing	$2.12 - $11.78		$5.70
				Basis adjustment	$0.10 - $3.33		$2.49
				Own credit risk	0.02% - 2.67%		0.07%
				Discount rate	0.02% - 6.29%		1.10%
Total liabilities	$	210
Net assets (liabilities)	$	(194)

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
March 31, 2019	$	14,531	$	15,493	$	-	$	15,050	$	443	$	15,493
December 31, 2018	$	15,411	$	15,908	$	-	$	14,991	$	917	$	15,908

The Company has designated $1.2 billion United States dollar denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in United States dollar denominated operations. An after-tax foreign currency gain of $34 million was recorded in “Other Comprehensive Income – Unrealized gains (losses) on net investment hedges” for the three months ended March 31, 2019 (2018 – $36 million loss after-tax).

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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	March 31 2019		(1)	December 31 2018
Regulatory assets
Deferred income tax regulatory assets	$	773		$	775
Pension and post-retirement medical plan		390			453
Cost-recovery clauses		85			75
Environmental remediation		31			31
Stranded cost recovery		28			28
Hurricane Matthew restoration		27			28
Unamortized defeasance costs		24			26
Demand side management deferral		23			24
Deferrals related to derivative instruments		18			10
Storm reserve		4			4
Other		82			115
	$	1,485		$	1,569
Current	$	143		$	165
Long-term		1,342			1,404
Total regulatory assets	$	1,485		$	1,569
Regulatory liabilities
Deferred income tax regulatory liabilities	$	1,068		$	1,218
Accumulated reserve - cost of removal		937			955
Regulated fuel adjustment mechanism		157			161
Deferrals related to derivative instruments		81			116
Storm reserve		75			76
Self-Insurance fund (note 22)		29			30
Cost-recovery clauses		28			30
Other		5			24
	$	2,380		$	2,610
Current	$	222		$	251
Long-term		2,158			2,359
Total regulatory liabilities	$	2,380		$	2,610

(1) On March 25, 2019, Emera announced the sale of Emera Maine. As at March 31, 2019, Emera Maine’s assets and liabilities were classified as held for sale. Refer to note 4 for further details.

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15.  RELATED PARTY TRANSACTIONS

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

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

● Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $27 million for the three months ended March 31, 2019 (2018 - $24 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments.

● Natural gas transportation capacity purchases from M&NP are reported in the Condensed Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $18 million for the three months ended March 31, 2019 (2018 - $10 million).

There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at March 31, 2019 and at December 31, 2018.

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	March 31 2019
Right-of-use asset	Other long-term assets	$	54
Lease liabilities
Current	Other current liabilities		4
Long-term	Other long-term liabilities		50
Total lease liabilities		$	54

The Company has recorded lease expense of $52 million for the three months ended March 31, 2019, of which $49 million relates to variable costs for power generation facility finance leases.

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	$	5	$	6	$	6	$	6	$	5	$	87	$	115
Less imputed interest														(61)
Total	$	5	$	6	$	6	$	6	$	5	$	87	$	54

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Additional information related to Emera’s leases are as follows:

For the	Three months ended March 31 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases (millions of Canadian dollars)		$                        2
Weighted average remaining lease term (years)		42
Weighted average discount rate- operating leases		3.98%

Lessor

The Company’s net investment in direct finance and sales-type leases relate to Brunswick Pipeline, 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 (expense), net” on the Condensed Consolidated Statements of Income.

The Company manages its risk associated with the residual value of the Brunswick Pipeline lease by monitoring the creditworthiness of the counterparty on a regular basis, maintaining a guarantee with the parent company of the counterparty, and through proper routine maintenance of the asset.

Customers have the option to purchase CNG station assets at any time after 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.

Net investment in direct finance and sales-type leases consist of the following:

As at millions of Canadian dollars	March 31 2019
Total minimum lease payment to be received	$	1,090
Less: amounts representing estimated executory costs		(197)
Minimum lease payments receivable	$	893
Estimated residual value of leased property (unguaranteed)		183
Less: unearned finance lease income		(554)
Net investment in direct finance and sales-type leases	$	522
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”)		31
Net Investment in direct finance leases-long-term	$	473

As at March 31, 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	$	58	$	70	$	69	$	68	$	68	$	757	$	1,090
Less: executory costs														(197)
Minimum lease payments receivable	$	58	$	70	$	69	$	68	$	68	$	757	$	893

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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	Three months ended March 31
millions of Canadian dollars	2019		2018
Defined benefit pension plans
Service cost	$	12	$	12
Non-service cost
Interest cost		26		24
Expected return on plan assets		(37)		(35)
Current year amortization of:
Actuarial losses		5		8
Regulatory asset		4		6
Special termination benefits		-		1
Total non-service costs		(2)		4
Total defined benefit pension plans		10		16
Non-pension benefits plan
Service cost		1		1
Non-service cost
Interest cost		4		3
Expected return on plan assets		(1)		(1)
Current year amortization of:
Regulatory asset		(2)		-
Total non-service costs		1		2
Total non-pension benefits plans		2		3
Total defined benefit plans	$	12	$	19

Emera’s contributions related to these defined-benefit plans for the three months ended March 31, 2019 were $16 million (2018 - $27 million). Annual employer contributions for the defined benefit pension plans 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

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.

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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 2019 long-term debt financing activity.

Recent Financing Activity by Segment

Canadian Electric Utilities

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.

20.  COMMITMENTS AND CONTINGENCIES

A. Commitments

As at March 31, 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)	$	200	$	206	$	211	$	212	$	215	$	2,094	$	3,138
Transportation (3)		429		371		235		196		158		1,388		2,777
Capital projects (4)		405		144		47		9		3		8		616
Fuel, gas supply and storage		417		133		48		7		3		-		608
Long-term service agreements (5)(6)		35		42		29		26		20		113		265
Equity investment commitments (7)		-		-		190		-		-		-		190
Leases and other (8)		10		8		9		9		8		92		136
Demand side management		31		1		-		-		-		-		32
	$	1,527	$	905	$	769	$	459	$	407	$	3,695	$	7,762

As noted below, contractual obligations at March 31, 2019 include contractual obligations related to Emera Maine. On completion of the sale of Emera Maine, 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 $154 million related to Emera Maine ($8 million in 2019; $11 million in 2020; $11 million in 2021; $11 million in 2022; $11 million in 2023 and $102 million thereafter).

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

(4)  Includes $299 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 $38 million related to various long-term service agreements Emera Maine has entered into for IT maintenance and vegetation management ($13 million in 2019; $14 million in 2020; $5 million in 2021; $3 million in 2022; and $3 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.

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 and is subject to a holdback. After 2019, the timing and amounts payable to NSPML will be subject to a regulatory filing with the UARB, with expected filings in 2019 and 2020.

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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. The parties are in the process of filing motions on the matter. Results to date do not reflect any benefit.

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company (“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 March 31, 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 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.

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● 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.

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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.

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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:

The Company has standby letters of credit and surety bonds in the amount of $58 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 December 2019. This letter of credit is renewed annually. The amount committed as of March 31, 2019 was $6 million USD (December 31, 2018 - $6 million USD).

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21. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the	Three months ended March 31
millions of Canadian dollars	2019		2018
Changes in non-cash working capital:
Inventory	$	57	$	21
Receivables and other current assets		151		151
Accounts payable		(265)		(230)
Other current liabilities		41		47
Total non-cash working capital	$	(16)	$	(11)
Supplemental disclosure of non-cash activities:
Common share dividends reinvested	$	48	$	47
Change in accrued capital expenditures	$	18	$	4
Issuance of depository receipts	$	-	$	22

22.  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. In Q2 2014, when the critical milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial reporting purposes as they have authority over the majority of the direct activities that are expected to most significantly impact the economic performance of Maritime Link. Thus, Emera began recording 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.

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

As at	March 31, 2019				December 31, 2018
millions of Canadian dollars	Total     assets		Maximum exposure to loss		Total     assets		Maximum exposure to loss
Unconsolidated VIEs in which Emera has variable interests
NSPML (equity accounted)	$	549	$	48	$	545	$	51

23.  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.

24.  SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through May 9, 2019, the date the financial statements were issued.

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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 March 31, 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

A. designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

i. 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

B. 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

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:

i. 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

b. 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 January 1, 2019 and ended on March 31, 2019 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: May 9, 2019

“Scott Balfour”

Scott Balfour

President and Chief Executive Officer            

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:

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 March 31, 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

A. designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

i. 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

B. 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

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:

i. 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

b. 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 January 1, 2019 and ended on March 31, 2019 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: May 9, 2019

“Greg Blunden”

Greg Blunden

Chief Financial Officer

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 three months ended March 31, 2019.

The following earnings coverage ratio is calculated on a consolidated basis for the twelve-month period ended March 31, 2019.

	Twelve months ended March 31, 2019
Earnings Coverage (1)	2.02

⁽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 29.8 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 29.8 per cent, amounted to $58 million for the twelve months ended March 31, 2018. Emera’s interest requirements for the twelve months ended March 31, 2019 amounted to $736 million. Emera’s consolidated income before interest and income tax for the twelve months ended March 31, 2019 was $1,604 million, which is 2.02 times Emera’s aggregate preferred dividends and interest requirements for this period.

EX-99.6

Exhibit 99.6

Emera Reports 2019 First Quarter Financial Results

HALIFAX, Nova Scotia -- Today Emera (TSX: EMA) announced financial results for the first quarter of 2019.

Q1 2019 Highlights:

Reported Net Income

● Q1 2019 reported net income was $312 million, compared with net income of $271 million in Q1 2018

● Q1 2019 reported earnings per common share were $1.32, compared with $1.17 per common share in Q1 2018

Adjusted Net Income ⁽¹⁾

● Q1 2019 adjusted net income was $224 million, compared with $202 million in Q1 2018

● Q1 2019 adjusted earnings per common share were $0.95, compared with $0.87 in Q1 2018

Cash Flow

● Operating cash flow, before changes in working capital, decreased by $26 million to $418 million in Q1 2019, compared with $444 million in Q1 2018

DRIP Discount

● Discount offered on the reinvestment of cash dividends under the dividend reinvestment plan (the “DRIP”) reduced from five per cent to two per cent

⁽¹⁾ See “Non-GAAP Measures” noted below.

“Our business continued to perform well during the first quarter, delivering strong financial results while making measurable progress on our strategic objectives,” said Scott Balfour, President and CEO. “With the recent close of our New England Gas Generation transaction and the announced sale of Emera Maine, we are well positioned to focus on our robust capital investment profile.”

Financial Highlights:

For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2019		2018
Net income attributable to common shareholders	$	312	$	271
After-tax mark-to-market gain (loss)		88	$	69
Adjusted net income attributable to common shareholders (1)(2)	$	224	$	202
Earnings per common share – basic	$	1.32	$	1.17
Adjusted earnings per common share – basic (1)(2)	$	0.95	$	0.87
Weighted average shares of common stock outstanding - basic (millions of shares)		236		231

⁽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 gains increased $19 million to $88 million in 2019 compared to $69 million in 2018, mainly due to changes in Emera Energy’s 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.

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The weaker Canadian dollar increased earnings by $13 million and adjusted earnings by $8 million in Q1 2019 compared to Q1 2018.

Consolidated Financial Review:

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

For the millions of Canadian dollars	Three months ended March 31
Adjusted net income – 2018 (1)(2)	$	202
Gas Utilities and Infrastructure		14
Gain on sale of property in Florida		10
Canadian Electric Utilities		6
Other Variances		(8)
Adjusted net income – 2019 (1)(2)	$	224

⁽¹⁾ See “Non-GAAP Measures” noted below

⁽²⁾ Excludes the effect of mark-to-market adjustments

Segmented Results:

Effective January 1, 2019, Emera has 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 March 31
millions of Canadian dollars (except per share amounts)	2019		2018
Adjusted net income (1)
Florida Electric Utility	$	61	$	60
Canadian Electric Utilities		96		90
Other Electric Utilities (2)		16		15
Gas Utilities and Infrastructure		67		53
Other (2)		(16)		(16)
Adjusted net income (1)	$	224	$	202
After-tax mark-to-market gain (loss)		88		69
Net income attributable to common shareholders	$	312	$	271
EPS (basic)	$	1.32	$	1.17
Adjusted EPS (basic) (1)(2)	$	0.95	$	0.87

⁽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 $1 million to $61 million in Q1 2019, compared to $60 million in Q1 2018. This increase was due to higher revenues related to the in-service solar generation projects, lower OM&G due to the timing of generation outages and a weaker Canadian dollar, partially offset by lower revenues due to less favourable weather.

Canadian Electric Utilities’ net income increased by $6 million to $96 million, compared to $90 million in Q1 2019. The increase was due to higher sales volume due to weather and lower OM&G, primarily a result of lower storm costs, at Nova Scotia Power Inc.

Other Electric Utilities’ CAD net income, adjusted to exclude mark-to-market, increased by $1 million to $16 million in Q1 2019, compared to $15 million in Q1 2018.

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Gas Utilities and Infrastructure’s CAD net income increased by $14 million to $67 million in Q1 2019, compared to $53 million in Q1 2018. This increase was due to favourable weather conditions and the optimization of pipeline capacity at New Mexico Gas Company, lower depreciation and amortization at Peoples Gas and customer growth at both utilities.

Other’s net loss, adjusted to exclude mark-to-market, in Q1 2019 was $16 million, consistent with Q1 2018. Adjusted earnings from Emera Energy were $52 million, a decrease of $3 million from Q1 2018. Also in Q1 2019 was a $2 million loss associated with the sales of the New England Gas Generation portfolio and Bayside and a $10 million gain from the sale of a property in Florida.

Discount on Reinvested Dividends:

Emera also announced today a change from five per cent to two per cent of the applicable discount from the average market price for common shares purchased in connection with the reinvestment of cash dividends under its DRIP. The revision aligns the Company’s discount rate with industry peers and offers value for those shareholders electing to participate in the DRIP. For common shareholders who have elected participation in the DRIP, reinvestment of their dividends will occur at the new discount beginning on the next dividend declaration date. Additional information regarding Emera’s DRIP is available on its website at www.emera.com.

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, Friday, May 10, 2019 at 9:30 a.m. Atlantic (8:30 a.m. Eastern) to discuss the Q1 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 pass code is required.

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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 June 11, 2019, by dialing 1-800-585-8367 and entering pass code 9045319.

Annual General Meeting

Emera will hold its Annual General Meeting on Wednesday, May 15, 2019 at 2:00 p.m. Atlantic (1:00 p.m. Eastern) at the Halifax Convention Centre, Argyle Suite, Level 2, 1650 Argyle Street, Halifax, Nova Scotia.

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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