MD & A

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”)
Peoples Gas System (“PGS”) – Gas Division of TEC	FPSC
New Mexico Gas Company, Inc. (“NMGC”)	New Mexico Public Regulation Commission (“NMPRC”)
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”)
Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”)	National Energy Board (“NEB”)
Equity Investment
NSP Maritime Link Inc. (“NSPML”)	UARB
Maritimes & Northeast Pipeline Limited Partnership and Maritimes & Northeast Pipeline LLC (“M&NP”)	NEB and FERC
Labrador Island Link Limited Partnership (“LIL”)	Newfoundland and Labrador Board of Commissioners of Public Utilities
St. Lucia Electricity Services Limited (“Lucelec”)	National Utility Regulatory Commission (“NURC”)

All amounts are in Canadian dollars (“CAD”), except for the Emera Florida and New Mexico, Emera Maine and Emera Caribbean 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.

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 which 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; capital market and liquidity risk; enterprise resource planning implementation risk; future dividend growth; timing and costs associated with certain capital projects; 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; commodity price risk; unanticipated maintenance and other expenditures; system operating and maintenance risk; project development and construction risk; derivative financial instruments and hedging; interest rate risk; 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

Emera is a geographically diverse energy and services company. The Company has investments in electricity generation, transmission and distribution, gas transmission and distribution, and utility services, predominantly within rate-regulated utilities supporting strong, consistent earnings and cash flow. Emera seeks to provide its customers with reliable, cost-effective and sustainable energy products and services, and provides regional energy solutions by connecting its assets, markets and partners in Canada, the United States and the Caribbean. For investors, Emera seeks to deliver long-term growth, and accordingly, the primary measures of performance are annual dividend growth, earnings per common share growth, adjusted earnings per common share growth (a non-GAAP measure described in the Non-GAAP Financial Measures section below) and total shareholder return. The Company targets eight per cent annual dividend growth through 2020.

Emera targets achieving 75 to 85 per cent of its adjusted net income from its rate-regulated utilities, which is reflective of the Company’s low risk profile; and a dividend payout ratio of 70 to 75 per cent of adjusted net income.

Energy markets worldwide, in particular across North America, are undergoing foundational changes that have created significant investment opportunities for companies with Emera’s experience and capabilities. Key trends contributing to these investment opportunities include: aging infrastructure, lower-cost natural gas, growing demand for new electric heating and cooling solutions, the requirement for large-scale transmission projects to deliver new energy sources to customers, and environmental concerns. These environmental concerns include a desire to reduce the emissions of carbon dioxide and other greenhouse gases and the potential effect of climate change, including changes in global and regional weather patterns, changes in the frequency and intensity of extreme weather events, and rising sea levels. At the core of Emera’s utilities strategy is identifying opportunities to invest in the transition from higher-carbon methods of electricity generation to lower-carbon alternatives, and the related transmission and distribution infrastructure to deliver that energy to market.

While it is still unclear whether economic volatility, government policy and lower fossil fuel prices will slow the pace of transformation, its impact on the sector continues to be felt in the form of mandated and

incented carbon reductions throughout eastern North America and in the Caribbean. As such, investment in wind, solar, and hydro generation, natural gas and new transmission infrastructure is likely to continue across the sector despite any cost differential with more carbon-intensive generating options. The capital spending requirements related to these investments will need to be managed within the context of overall energy pricing.

In Florida, the Company is evaluating a number of initiatives, including transmission and solar generation that would reduce carbon emissions. NSPI has invested in wind energy, biomass and hydroelectricity and is on track to meet a minimum 40 per cent renewable standard by 2020. In the Caribbean, Emera is similarly focused on introducing cleaner generation alternatives, with an emphasis on affordability and fuel cost stability for its customers.

Emera is investing in electricity transmission to deliver new renewable energy to market. Emera’s ownership in the Maritime Link Project will contribute to the transformation of the electricity market in the Atlantic provinces, enabling growth in the availability of clean, renewable energy for the region. In addition, the Atlantic provinces will benefit from enhanced connection to the northeastern United States, providing potential for excess renewable energy to be delivered throughout that region.

Emera Energy is a component of Emera’s business that is not rate-regulated. Formed in 2003, Emera Energy is a physical energy marketing and trading business, complemented by a portfolio of competitive electricity generation facilities. A substantial portion of Emera Energy’s activities are in northeast North America, and the business is supported by comprehensive infrastructure and market knowledge, a focus on customer service and robust risk management.

A collaborative approach to strategic partnerships, combined with the ability to find creative solutions to work within and across multiple jurisdictions, and experience dealing with complex projects and investment structures are fundamental to Emera’s strategy. The Company will continue to make investments in its regulated utilities to benefit customers and focus on providing rate stability. From time to time, Emera will make acquisitions, both regulated and unregulated, where the business or asset acquired aligns with Emera’s strategic initiatives and delivers shareholder value.

To ensure stability in the utilities’ net income and cash flows, Emera employs operating and governance models that focus on safety and operational excellence, constructive regulatory approaches, proactive stakeholder engagement and a customer focus through service reliability and rate stability.

Emera has grown its asset base to deliver on its strategic objectives. Over the last 10 years, Emera’s ability to raise the capital necessary to fund investments has been a strong enabler of the Company’s growth. In addition to access to debt and equity capital markets, cash flow from operations will continue to play a role in financing the Company’s future growth. Maintaining strong, investment grade credit ratings is an important component of Emera’s financing strategy.

The energy industry is seasonal in nature. Seasonal patterns and other weather events, including the number and severity of storms, can affect demand for energy and cost of service. Similarly, mark-to-market adjustments and foreign currency exchange can have a material impact on the financial results for a specific period. Results in any one quarter are not necessarily indicative of results in any other quarter, or for the year as a whole.

The effect of foreign currency exchange on Emera’s net income is noteworthy, as it is expected that approximately 70 per cent of Emera’s future adjusted net income will be derived from subsidiaries with a US functional currency. Emera‘s consolidated net income and cash flows will be impacted by movements in the US dollar relative to the Canadian dollar.

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;

· 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 included in Emera’s other income in 2016 related to the effect of TECO Energy, Inc. (“TECO Energy”) acquisition USD-denominated currency and forward contracts. These contracts were put in place to economically hedge the anticipated proceeds from the 2015 sale of $2.185 billion four per cent convertible unsecured subordinated debentures represented by instalment receipts (“the Debenture Offering” or “Debentures” or “Convertible Debentures”) for the TECO Energy acquisition.

Management believes excluding from 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 the ongoing operations of the business, and allows investors to better understand and evaluate the business. Management and the Board of Directors use this non-GAAP measure for evaluation of performance and incentive compensation.

Mark-to-market adjustments are further discussed in the Consolidated Financial Review section, Emera Energy and Corporate and Other.

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)		2017	2016
Net income attributable to common shareholders	$	312	$	44
After-tax mark-to-market gain (loss)	$	160	$	(76)
Adjusted net income attributable to common shareholders	$	152	$	120
Earnings per common share – basic	$	1.48	$	0.30
Adjusted earnings per common share – basic	$	0.72	$	0.81

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, make capital expenditures 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.

The Company’s EBITDA and Adjusted EBITDA may not be comparable to the EBITDA measures of other companies but in management’s view it appropriately reflects 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.

EBITDA and Adjusted EBITDA are discussed further in the Consolidated Financial Review, Emera Florida and New Mexico, NSPI, Emera Maine, Emera Caribbean, Emera Energy, and Corporate and Other sections.

The following is a reconciliation of reported net income attributable to common shareholders to EBITDA and Adjusted EBITDA.

For the	Three months ended
millions of Canadian dollars	March 31
		2017		2016
Net income (1)	$	322	$	55
Interest expense, net		175		75
Income tax expense (recovery)		112		27
Depreciation and amortization		217		87
EBITDA		826		244
Mark-to-market gain (loss), excluding income tax and interest		232		(75)
Adjusted EBITDA	$	594	$	319
(1) Net income is income before Non-controlling interest in subsidiaries and Preferred stock dividends.

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Q1 Earnings

2017

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

After-tax mark-to-market gains increased $236 million to $160 million in 2017 compared to a $76 million loss for the same period in 2016. The increase is due to a $121 million loss in 2016 resulting from the reversal of 2015 gains on USD-denominated currency and forward contracts related to the financing of the TECO Energy acquisition, changes in existing positions on long-term contracts at Emera Energy, and the reversal of 2016 mark-to-market losses at Emera Energy.

2016

Earnings Impact of Acquisition Related Costs

Emera incurred after-tax interest costs of $18 million ($0.12 per common share) in Q1 2016 related to its acquisition of TECO Energy.

Consolidated Financial Highlights

For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)		2017	2016
Adjusted Net Income
Emera Florida and New Mexico	$	79	$	-
NSPI		70		53
Emera Maine		13		9
Emera Caribbean		7		10
Emera Energy		10		48
Corporate and Other		(27)		-
Adjusted net income attributable to common shareholders	$	152	$	120
After-tax mark-to-market gain (loss)		160		(76)
Net income attributable to common shareholders	$	312	$	44

For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)		2017	2016
Operating revenues	$	1,857	$	877
Income from operations		581		270
Net income attributable to common shareholders		312		44
After-tax mark-to-market gain (loss)		160		(76)
Adjusted net income attributable to common shareholders		152		120
Earnings per common share – basic	$	1.48	$	0.30
Earnings per common share – diluted	$	1.47	$	0.30
Adjusted earnings per common share – basic	$	0.72	$	0.81
Dividends per common share declared	$	0.5225	$	0.4750

Adjusted EBITDA	$	594	$	319

The following table highlights the significant changes in adjusted net income from 2016 to 2017.

For the	Three months ended
millions of Canadian dollars	March 31
Adjusted net income – 2016	$	120
Emera Florida and New Mexico		79
2016 acquisition and financing costs related to the acquisition of TECO Energy		18
NSPI		17
NSPML and LIL AFUDC earnings		7
Algonquin Power and Utilities Corp ("APUC") equity earnings – sold in 2016		(9)
Emera Energy		(38)
TECO Energy post-acquisition financing costs		(45)
Other		3
Adjusted net income – 2017	$	152

For the	Three months ended March 31
millions of Canadian dollars		2017		2016
Operating cash flow before changes in working capital	$	348	$	233
Change in working capital		(182)		(52)
Operating cash flow	$	166	$	181
Investing cash flow	$	(379)	$	(139)
Financing cash flow	$	66	$	(46)

As at	March 31		December 31
millions of Canadian dollars		2017	2016
Working capital	$	485	$	301
Total assets	$	28,946	$	29,221
Total long-term debt (including current portion)	$	14,741	$	14,744

Q1 Consolidated Income Statement and Operating Cash Flow Highlights

Operational Results

Income from operations increased $311 million to $581 million in Q1 2017 compared to $270 million in Q1 2016. Absent mark-to-market increases of $164 million, income from operations increased $147 million mainly due to the contribution of Emera Florida and New Mexico, partially offset by decreased contribution from Emera Energy.

Total operating revenues increased $980 million to $1,857 million in Q1 2017 compared to $877 million in Q1 2016. Absent mark-to-market increases of $166 million, operating revenues increased $814 million due to:

· $889 million contribution from Emera Florida and New Mexico;

· $76 million decrease at New England Gas Generating Facilities “NEGG” reflecting lower hedged power prices, decreased sales volumes and an unplanned outage at the Bridgeport Facility;

· $21 million decrease in marketing and trading margin at Emera Energy Services “EES” driven by less favourable market conditions, partially offset by growth in the volume of business.

Total operating expenses increased $669 million to $1,276 million in Q1 2017 compared to $607 million in Q1 2016. This was mainly due to the addition of expenses from Emera Florida and New Mexico, partially offset by lower fuel expense at NEGG reflecting lower hedged natural gas prices and decreased volumes.

Other income (expenses), net

Other income (expenses), net increased $141 million to $2 million in Q1 2017 compared to an expense of $139 million in Q1 2016. This was due to 2016 losses related to the translation of the USD cash balance and the effect of USD-denominated currency and forward contracts put into place to economically hedge anticipated proceeds from the TECO Energy related Debenture Offering financing.

Interest expense, net

Interest expense increased $100 million to $175 million in Q1 2017 compared to $75 million in Q1 2016 mainly due the financing related to the TECO Energy acquisition, and interest expense from Emera Florida and New Mexico.

Income tax expense

Income tax expense increased $85 million to $112 million in Q1 2017 compared to $27 million in Q1 2016 primarily due to increased income before provision for income taxes. This was partially offset by increased deferred income taxes on regulated income recorded as regulatory assets and liabilities and

the non-deductible portion of foreign exchange losses and mark-to-market adjustments related to the TECO Energy acquisition in 2016.

Net cash provided by operating activities

Net cash provided by operating activities in 2017 decreased $15 million to $166 million compared to $181 million during the same period in 2016.

Cash from operations before changes in working capital increased by $115 million mainly due to the contribution from Emera Florida and New Mexico, partially offset by decreased margin from EES and NEGG and increased financing costs from long-term debt related to the TECO Energy acquisition.

Changes in working capital decreased operating cash flows by $130 million due to the addition of Emera Florida and New Mexico and increased investment in working capital at NSPI as a result of the timing of payments for sales tax, unfavourable changes in fuel inventory levels compared to 2016 and changes in cash collateral requirements.

Effect of Foreign Currency Translation

Emera operates globally, 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, it 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.

Components of net income and adjusted net income are translated at the weighted average rate of exchange. The table below includes Emera’s significant segments whose contribution to adjusted earnings are recorded in US dollar currency.

		Three months ended
		March 31
millions of US dollars		2017		2016
Emera Florida and New Mexico	$	60	$	-
Emera Maine		10		7
Emera Caribbean		5		7
Emera Energy (1)		11		37
		86		51
Corporate and Other (2)		(29)	$	1
Total	$	57	$	52

Weighted average FX rate for period	$	1.32	$	1.38
(1) Includes Emera Energy’s US dollar adjusted net income from EES, NEGG and Bear Swamp.
(2) Corporate and Other includes interest expense on US dollar denominated debt, net of interest income on an intercompany US dollar loan to Emera Energy.

BUSINESS OVERVIEW AND OUTLOOK

Emera Florida and New Mexico

Emera Florida and New Mexico includes TECO Energy, the parent company of TEC, NMGC and TECO Finance. TEC consists of two divisions; Tampa Electric, a vertically-integrated regulated electric utility engaged in the generation, transmission and distribution of electricity serving customers in West Central Florida; and PGS, a regulated gas distribution utility engaged in the purchase, distribution and sale of

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

Emera Florida and New Mexico earnings are most directly impacted by the earned rate of return on equity and the capital structures approved by the FPSC and NMPRC, the prudent management and approved recovery of operating costs, the approved recovery of regulatory deferrals, sales volumes, and the timing and amount of capital expenditures.

The Florida utilities anticipate earning within their allowed ROE ranges in 2017 and expect rate base and earnings to be higher than prior years. Tampa Electric and PGS expect slightly higher customer growth rates in 2017 than those experienced in 2016, reflective of economic growth in Florida. Assuming normal weather, sales are expected to increase consistent with customer growth. In accordance with the 2013 settlement agreement approved by the FPSC, Tampa Electric increased base rates by $110 million USD on January 16, 2017, the commercial operation date of the Polk Power Station expansion project. This expansion project adds 460 MW of generating capacity and investment in related transmission system improvements needed to support the additional generation.

Due to milder first quarter weather, NMGC expects 2017 earnings to be slightly below prior years. However, customer growth rates are expected to be slightly higher in 2017 than in 2016, reflecting expectations for housing starts and new connections. For the remainder of 2017, sales growth is expected to be consistent with customer growth and costs will increase slightly from prior years.

In 2017, Emera Florida and New Mexico expects to invest approximately $715 million USD, including allowance for funds used during construction (“AFUDC”), in capital projects compared to $795 million USD in 2016. The 2016 capital expenditures included approximately $135 million USD for the Polk Power Station expansion project and $35 million USD for the Florida utilities' new customer relationship management and billing system, both of which went into service in January 2017. In addition to capital projects to support normal system reliability and growth at the three utilities, capital projects at Tampa Electric include programs for transmission and distribution system storm hardening, distribution system modernization and automated metering equipment, transmission system reliability requirements and investments in utility scale solar photovoltaic projects. PGS will make investments to expand its system and support customer growth, including high sales volume compressed natural gas fueling stations, and continue with replacement of obsolete plastic, cast iron and bare steel pipe. NMGC will undertake a project relocating a portion of the gas pipeline feeding Taos, New Mexico, and will invest in a new customer relationship management and billing system.

NSPI

NSPI is a fully-integrated regulated electric utility. It is the primary electricity supplier in Nova Scotia, providing electricity generation, transmission and distribution services to customers. NSPI’s earnings are most directly impacted by the range of ROE and capital structure approved by the UARB; the prudent management and approved recovery of operating costs, the approved recovery of regulatory deferral, sales volumes, and the timing and amount of capital expenditures. NSPI anticipates earning within its allowed ROE range in 2017 and expects its earnings and rate base to generally be consistent with prior years.

The future earnings impact of the carbon emission reduction strategy being developed from the Pan-Canadian Framework on Clean Growth and Climate Change is unknown; however, NSPI anticipates that costs prudently incurred to achieve the legislated reductions would be recoverable from customers under NSPI’s regulatory framework. NSPI continues to work with both the Province of Nova Scotia and the Government of Canada as the details of the carbon emission reduction agreements are finalized and to advance solutions that are in the best interest of customers.

In 2017, NSPI expects to invest approximately $400 million, including AFUDC, in capital projects compared to $309 million in 2016. This increase is primarily driven by increased spending on information technology and transmission projects.

Emera Maine

Emera Maine is a transmission and distribution electric utility in the State of Maine. Emera Maine’s earnings are most directly impacted by the combined impacts of the range of rates of ROE and rate base approved by its regulators, the prudent management and approved recovery of operating costs, sales volumes, and the timing and amount of capital expenditures.

Emera Maine’s 2017 rate base is expected to grow modestly due to ongoing investment in transmission and distribution infrastructure, resulting in modest growth in earnings.

There are currently four pending complaints filed with the FERC to challenge the ISO-New England (“ISO-NE”) Open Access Transmission Tariff allowed base ROE. On June 19, 2014, in connection with the first complaint, the FERC set the base ROE at 10.57 per cent and capped the total ROE, including the effect of incentive adders, at 11.74 per cent. On April 14, 2017 the U.S. Court of Appeals for the District of Columbia Circuit vacated this order. No changes in reserves have been made as a result of the Court of Appeals vacating the FERC Order, as the outcome is considered uncertain. There are no further updates since December 31, 2016 for the other pending complaints. For further discussion on the complaints see note 19 to the condensed consolidated interim financial statements for the quarter ended March 31, 2017.

In 2017, Emera Maine expects to spend approximately $75 million USD (2016 – $69 million USD actual) in capital projects.

Emera Caribbean

Emera Caribbean includes Emera (Caribbean) Incorporated (“ECI”) and its wholly owned subsidiary BLPC, a vertically integrated utility that is the provider of electricity in Barbados; an 80.4 per cent interest in GBPC, a vertically integrated utility and the sole provider of electricity on Grand Bahama Island and a 51.9 per cent interest in Domlec, an integrated utility on the island of Dominica. In addition, Emera Caribbean includes a 19.1 equity interest in Lucelec, a vertically integrated regulated electric utility on the island of St. Lucia.

Earnings from Emera Caribbean are most directly impacted by the rates of return on rate base approved by their regulators, capital structure, prudent management and approved recovery of operating costs, sales volumes, and the timing and scale of capital expenditures.

Emera Caribbean’s 2017 earnings are expected to be slightly less than prior years, excluding the impact of the Q2 2016 gain recognized on the Self-Insurance Fund regulatory liability. This is a result of expected short term load decline in GBPC from Hurricane Matthew and higher interest charges in ECI on new debt issued in Q4 2016.

Emera Caribbean plans to invest approximately $95 million USD in capital programs in 2017 (2016 - $65 million USD actual). This increase is due to spending on renewable generation, advanced metering infrastructure and street lighting projects.

Emera Energy

Emera Energy includes Emera Energy Services, 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; 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 Energy Services

Emera Energy Services, Emera Energy’s marketing and trading business is 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, with the opportunity for upside when market conditions present.

Emera Energy Generation

Earnings from Emera Energy Generation’s assets are largely dependent on market conditions, in particular, the relative pricing of electricity and natural gas; and capacity pricing for the NEGG Facilities. Efficient operations of the fleet to ensure unit availability, cost management and effective commercial management are key success factors.

Adjusted earnings from Emera Energy’s generating assets in 2017 are expected to be in line with 2016. Higher capacity prices that come into effect mid-year 2017 are expected to be offset by lower realized spark spreads year-over-year, and to a lesser extent, the impact of an unplanned outage at the Bridgeport facility. The unit was taken offline for repair in mid-March, with an expected return to service in early June 2017.

In 2017, Emera Energy expects to invest approximately $45 million (2016 – $39 million actual) in capital related to its generating assets in order to further improve reliability and enhance plant output capacity.

Corporate and Other

Corporate

Corporate encompasses 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 related costs and corporate human resource activities. It also includes interest revenue on intercompany financings recorded in “Intercompany revenue” and costs associated with corporate activities that are not directly allocated to the operations of Emera’s subsidiaries and investments.

Other

Other includes consolidated investments in Brunswick Pipeline, Emera Reinsurance and Emera Utility Services. It also includes non-consolidated investments in NSPML (100 per cent investment), LIL (62.7 per cent investment) and M&NP (12.9 per cent). Investments in NSPML, LIL and M&NP are recorded as “Investments subject to significant influence” on Emera’s Condensed Consolidated Balance Sheets.

Corporate and Other’s contribution to consolidated adjusted net income is expected to be lower in 2017, primarily as the result of the 2016 gains associated with the sale of Emera’s investment in Algonquin Power and Utilities Corp (“APUC”). This is partially offset by higher Operating, maintenance and general (“OM&G”) costs in 2016 related to the TECO Energy acquisition. Interest costs will be higher in 2017 as a result of permanent financing in place for the TECO Energy acquisition.

Consolidated Balance Sheets Highlights

Significant changes in the condensed consolidated balance sheets between December 31, 2016 and March 31, 2017 include:

millions of Canadian dollars	Increase (Decrease)		Explanation
Assets
Cash and cash equivalents	$	(149)	Decreased primarily due to additions of property, plant and equipment at Emera Florida and New Mexico, increased investment in LIL and NSPML and payment of common dividends. These decreases were partially offset by proceeds of debt at GBPC and Emera Florida and New Mexico and changes in credit facilities.
Investments subject to significant influence		83	Increased due to investment in LIL and NSPML.
Liabilities and Equity
Accounts payable		(272)	Decreased mainly due to timing of payments of project expenditures and accruals, lower commodity prices at Emera Energy and payment of 2016 accrued acquisition related expenses.
Deferred income tax liabilities, net of deferred income tax assets		111	Increased primarily due to tax deductions in excess of accounting depreciation related to property, plant and equipment.
Derivative instruments (current and long-term)		(228)	Decreased due to the reversal of 2016 Asset Management Agreements (“AMA”) MTM losses and changes in existing positions on long-term natural gas contracts at Emera Energy.
Regulatory liabilities (current and long-term)		(83)	Decrease reflects lower deferred fuel clause at TEC and decreased regulated derivatives at NSPI.
Pension and post-retirement liabilities (current and long-term)		(59)	Decreased due to supplemental executive retirement plan and other post-retirement payments in Emera Florida and New Mexico.
Other liabilities (current and long-term)		58	Increase is driven by the timing of interest payments on the long-term debt at TEC, NSPI and Emera and the timing of sales tax payable at NSPI.
Retained earnings		202	Increased due to net income in excess of dividends paid.

Developments

Appointments

On March 29, 2017, Chris Huskilson provided notice of his intention to retire as Chief Executive Officer (“CEO”) in 2018. Concurrently, Emera’s Board of Directors announced it will appoint Scott Balfour, current Chief Operating Officer and former Chief Financial Officer, as CEO upon Mr. Huskilson’s retirement.

OUTSTANDING COMMON STOCK DATA

Common stock	millions of	millions of Canadian
Issued and outstanding:	shares	dollars
Balance, December 31, 2015	147.21		$	2,157
Conversion of Convertible Debentures	51.99			2,115
Issuance of common stock	7.69			338
Issued for cash under Purchase Plans at market rate	2.51			115
Discount on shares purchased under Dividend Reinvestment Plan	-			(5)
Options exercised under senior management stock option plan	0.62			17
Employee Share Purchase Plan	-			1
Balance, December 31, 2016	210.02		$	4,738
Conversion of Convertible Debentures (1)	0.08			3
Issued for cash under Purchase Plans at market rate	0.98			43
Options exercised under senior management stock option plan	0.03			1
Balance, March 31, 2017	211.11		$	4,785
(1) In Q1 2017, 0.08 million common shares of Emera were issued relating to the conversion of the Convertible Debentures. As at March 31, 2017, a total of 52.07 million common shares of the Company were issued, representing conversion into common shares of more than 99.7% of the Convertible Debentures.

As at April 27, 2017 the amount of issued and outstanding common shares was 211 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, 2017 was 212 million (2016 – 149 million).

EMERA FLORIDA AND NEW MEXICO

Financial Highlights

All amounts are reported in USD, unless otherwise stated.


For the	Three months ended
millions of US dollars (except per share amounts)	March 31
		2017
Operating revenues – regulated electric	$	441
Operating revenues – regulated gas		227
Operating revenues – non-regulated		4
Total operating revenues		672
Regulated fuel for generation and purchased power		138
Regulated cost of natural gas		95
Contribution to consolidated net income – USD	$	60
Contribution to consolidated net income – CAD	$	79
Contribution to consolidated earnings per common share – CAD	$	0.37
Net income weighted average foreign exchange rate – CAD/USD	$	1.32

EBITDA – USD	$	240
EBITDA – CAD	$	317

Net Income

The Emera Florida and New Mexico operating unit contribution for the three months ended March 31, 2017 is summarized in the following table:

For the	Three months ended
millions of US dollars	March 31
			2017
Tampa Electric		$	43
PGS			14
NMGC			13
Other (1)			(10)
Contribution to consolidated net income		$	60
(1) Other includes TECO Finance and administration costs.

Included below are Emera Florida and New Mexico’s Q1 2017 results compared to the same period in 2016. Prior year data is for comparison purposes only, as the Emera acquisition was completed on July 1, 2016.

Tampa Electric’s net income decreased $7 million to $43 million in Q1 2017 compared to $50 million for the same period in 2016 primarily due to lower energy sales and margin from milder weather in Q1 2017, higher OM&G due to transmission and distribution system maintenance and higher employee-benefit costs, and increased depreciation expense due to completion of the Polk Power Station expansion in January 2017 and from normal additions to facilities.

PGS’s net income increased $1 million to $14 million in Q1 2017 compared to $13 million for the same period in 2016 primarily due to lower depreciation expense as a result of the FPSC-approved 2016 depreciation study and lower compliance related costs than in 2016, partially offset by lower energy sales to residential and commercial customers due to the milder winter weather in 2017.

NMGC’s net income decreased $2 million to $13 million in Q1 2017 compared to $15 million for the same period in 2016 primarily due to lower gas margins from very mild winter weather throughout NMGC’s service territory.

In Q1 2017 Other had a net loss of $10 million compared to a net loss of $5 million in Q1 2016 as a result of a Q1 2016 non-recurring $5 million gain from an accounting rule change related to stock based compensation.

The Emera Florida and New Mexico CAD dollar contribution to consolidated net income was $79 million for the Q1 2017 period.

Operating Revenues – Regulated Electric

Electric revenues increased $18 million to $ 441 million in Q1 2017 compared to $423 million in Q1 2016 primarily due to $20 million of higher base rate revenues due to the completion of the Polk Power Station expansion in January 2017, which was partially offset by lower sales volumes from milder winter weather.

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

Q1 Electric Revenues
millions of US dollars
		2017
Residential	$	198
Commercial		131
Industrial		39
Other (1)		73
Total	$	441
(1) Other includes regulatory deferrals related to over-recovery of clause related costs.

Q1 Electric Sales Volumes
Gigawatt hours ("GWh")
	2017	2016*
Residential	1,761	1,915
Commercial	1,431	1,388
Industrial	504	461
Other	386	401
Total	4,082	4,165
*2016 data is for comparison purposes only. TECO Energy was acquired on July 1, 2016.

Operating Revenues – Regulated Gas

Gas revenues decreased $6 million to $ 227 million in Q1 2017 compared to $233 million in Q1 2016 primarily due to a decrease in sales volumes due to milder winter weather in both Florida and New Mexico. This was partially offset by greater revenues related to the pass through of higher natural gas commodity costs to system supply customers.

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

Q1 Gas Revenues
millions of US dollars
		2017
Residential	$	128
Commercial		67
Industrial		8
Other (1)		24
Total	$	227
(1) Other includes regulatory deferrals related to over-recovery of clause related costs.

Q1 Gas Sales Volumes
Therms (millions)
	2017	2016*
Residential	138	156
Commercial	223	240
Industrial	299	313
Other	40	68
Total	700	777
*2016 data is for comparison purposes only. TECO Energy was acquired on July 1, 2016.

Regulated Fuel for Generation, Purchased Power and Cost of Natural Gas

Electric Capacity

Regulated fuel for generation and purchased power increased $9 million to $138 million in Q1 2017 compared to $129 million in Q1 2016 primarily due to higher commodity fuel costs offset by lower sales volumes and less purchased power.

Q1 Production Volumes
GWh
	2017	2016*
Natural gas (1)	2,275	2,642
Coal	1,608	987
Oil and petcoke	295	302
Solar	9	1
Purchased power	76	387
Total production volumes	4,263	4,319
*2016 data is for comparison purposes only. TECO Energy was acquired on July 1, 2016.
(1) Natural gas production volumes in 2017 are lower due to higher natural gas commodity prices that has resulted in coal generating units dispatching more.

Q1 Average Fuel Costs/Megawatt hour ("MWh")
US dollars		2017
Dollars per MWh	$	32

Average fuel cost per MWh was $32 in 2017 compared to $30 in 2016. The increase in fuel cost per MWh was primarily due to higher natural gas pricing, which resulted a dispatch of higher cost coal generation.

Cost of Natural Gas

Regulated cost of natural gas decreased $2 million to $95 million in Q1 2017 compared to $97 million in Q1 2016 primarily due to lower sales volumes driven by milder winter weather.

Gas sales by type are summarized in the following table:

Q1 Gas Sales Volumes by Type
Therms (millions)	2017	2016*
System supply	209	263
Transportation	491	514
Total	700	777
*2016 data is for comparison purposes only. TECO Energy was acquired on July 1, 2016.

NSPI

Financial Highlights


For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)		2017		2016
Operating revenues – regulated electric	$	396	$	398
Regulated fuel for generation and purchased power (1)		139		142
Contribution to consolidated net income	$	70	$	53
Contribution to consolidated earnings per common share	$	0.33	$	0.36

EBITDA	$	157	$	140
(1) Regulated fuel for generation and purchased power includes affiliate transactions and proceeds from the sale of natural gas.

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 – 2016	$	53
Decreased operating revenues - see Operating Revenues – Regulated Electric below		(2)
Decreased regulated fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below		3
Decreased fuel adjustment mechanism expense due to rebate to customers of prior years' over recovery of fuel costs partially offset by increased recovery of current year fuel costs		6
Decreased OM&G expenses primarily due to lower storm and maintenance costs		9
Increased depreciation and amortization due to increased property, plant and equipment		(5)
Decreased income tax expense primarily due to increased tax deductions in excess of accounting depreciation related to property, plant and equipment, partially offset by increased income before provision for income taxes		6
Contribution to consolidated net income – 2017	$	70

Operating Revenues – Regulated Electric

Operating revenues decreased $2 million to $396 million in Q1 2017 compared to $398 million in Q1 2016. The refund of 2016 over-recovered fuel costs decreased revenues by $21 million, partially offset by a $10 million increase in residential sales volume due to colder weather and load growth and $7 million increase as a result of fuel related electricity pricing effective January 1, 2017.

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

Q1 Electric Revenues
millions of Canadian dollars
		2017		2016
Residential	$	228	$	224
Commercial		103		109
Industrial		46		48
Other		11		11
Total	$	388	$	392

Q1 Electric Sales Volumes
GWh
	2017	2016
Residential	1,511	1,431
Commercial	851	840
Industrial	601	578
Other	96	79
Total	3,059	2,928

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power decreased $3 million to $139 million in Q1 2017 compared to $142 million in Q1 2016 due to change in generation mix and plant performance and decreased commodity prices, partially offset by increased sales volumes, changes in solid fuel commodity mix and decreased hydro production.

NSPI’s FAM regulatory liability balance has increased $12 million from $94 million at December 31, 2016 to $106 million at March 31, 2017 as a result of an over-recovery of current period fuel costs, the application of non-fuel revenues and interest on the FAM balance reduced by the refund to customers of prior years’ fuel costs.

Q1 Production Volumes
GWh
		2017		2016
Coal		1,661		1,325
Natural gas		251		285
Oil and petcoke		349		504
Purchased power – other		97		95
Total non-renewables		2,358		2,209
Wind and hydro – renewables		376		406
Purchased power – IPP		370		354
Purchased power – Community Feed-in Tariff program		145		115
Biomass – renewables		43		70
Total renewables		934		945
Total production volumes		3,292		3,154

Q1 Average Fuel Costs
		2017		2016
Dollars per MWh produced	$	42	$	45

Average unit fuel costs decreased in Q1 2017 compared to Q1 2016 primarily due to favourable generation mix towards lower cost fuel, including the transition to economic dispatch of biomass generation compared to must run in the prior year. Also contributing to the decrease was improved plant performance combined with favourable solid fuel pricing, partially offset by decreased NSPI owned hydro generation and increased generation costs associated with the Nova Scotia Community Feed-in Tariff program.

EMERA MAINE

Financial Highlights

All amounts are reported in USD, unless otherwise stated.

For the	Three months ended March 31
millions of US dollars (except per share amounts)		2017		2016
Operating revenues – regulated electric	$	60	$	58
Regulated fuel for generation and purchased power (1)		15		14
Contribution to consolidated net income – USD	$	10	$	7
Contribution to consolidated net income – CAD	$	13	$	9
Contribution to consolidated earnings per common share – CAD	$	0.06	$	0.06
Net income weighted average foreign exchange rate – CAD/USD	$	1.32	$	1.37

EBITDA – USD	$	30	$	25
EBITDA – CAD	$	39	$	33
(1) Regulated fuel generation and purchased power includes transmission pool expense.

Net Income

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

For the	Three months ended
millions of US dollars	March 31
Contribution to consolidated net income – 2016	$	7
Increased operating revenues - see Operating Revenues - Regulated Electric below		2
Decreased OM&G primarily due to increased capitalized construction overheads as a result of higher capital spending and lower storm costs		5
Increased income tax expense primarily due to increased income before provision for income taxes		(2)
Other		(2)
Contribution to consolidated net income – 2017	$	10

Emera Maine’s CAD contribution to consolidated net income increased by $4 million to $13 million in Q1 2017 compared to $9 million in Q1 2016. The foreign exchange rate had minimal impact for the three months ended March 31, 2017.

Operating Revenues – Regulated Electric

Emera Maine's operating revenues – regulated electric include sales of electricity and other services as summarized in the following table:

For the	Three months ended March 31
millions of US dollars		2017		2016
Electric revenues	$	44	$	42
Transmission pool revenues		12		12
Resale of purchased power		4		4
Operating revenues – regulated electric	$	60	$	58

Electric revenues increased $2 million to $44 million in Q1 2017 compared to $42 million in Q1 2016 due to transmission and distribution rate changes.

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

Q1 Electric Revenues
millions of US dollars
		2017		2016
Residential	$	22	$	21
Commercial		15		15
Industrial		4		3
Other (1)		3		3
Total	$	44	$	42
(1) Other revenue includes amounts recognized relating to FERC transmission rate refunds and other transmission revenue adjustments.

Electric sales volume are summarized in the following tables by customer class:

Q1 Electric Sales Volumes
GWh	2017	2016
Residential	223	218
Commercial	195	198
Industrial	82	81
Other	4	4
Total	504	501

Regulated Fuel for Generation and Purchased Power

Emera Maine’s regulated fuel for generation and purchased power increased $1 million to $15 million in Q1 2017 compared to $14 million in Q1 2016.

EMERA CARIBBEAN

Financial Highlights

All amounts are reported in USD, unless otherwise stated.

For the		Three months ended March 31
millions of US dollars (except per share amounts)		2017		2016
Operating revenues – regulated electric	$	79	$	71
Regulated fuel for generation and purchased power		36		27
Contribution to consolidated net income – USD	$	5	$	7
Contribution to consolidated net income – CAD	$	7	$	10
Contribution to consolidated earnings per common share – CAD	$	0.03	$	0.07
Net income weighted average foreign exchange rate – CAD/USD	$	1.33	$	1.38

EBITDA – USD	$	23	$	23
EBITDA – CAD	$	30	$	32

Net Income

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


For the	Three months ended
millions of US dollars		March 31
Contribution to consolidated net income – 2016	$	7
Increased operating revenues - see Operating Revenues - Regulated Electric below		8
Increased regulated fuel for generation - see Regulated Fuel for Generation and Purchased Power below		(9)
Other		(1)
Contribution to consolidated net income – 2017	$	5

Emera Caribbean’s CAD contribution to consolidated net income decreased by $3 million to $7 million in Q1 2017 compared to $10 million in Q1 2016. The foreign exchange rate had minimal impact for the three months ended March 31, 2017.

Operating Revenues – Regulated Electric

Operating revenues increased $8 million to $79 million in Q1 2017 compared to $71 million in Q1 2016 due to increased fuel charge as a result of higher fuel prices in 2017 at BLPC, partially offset by lower sales volumes at GBPC due to the impact of Hurricane Matthew.

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

Q1 Electric Revenues
millions of US dollars
		2017		2016
Residential	$	25	$	23
Commercial		45		39
Industrial		6		7
Other		1		1
Total	$	77	$	70

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

Q1 Electric Sales Volumes
GWh
	2017	2016
Residential	108	109
Commercial	178	179
Industrial	22	23
Other	4	6
Total	312	317

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $9 million to $36 million in Q1 2017 compared to $27 million in Q1 2016 due to higher oil prices.

Q1 Production Volumes
GWh
	2017	2016
Oil	324	337
Hydro	9	9
Solar	5	-
Total	338	346

Q1 Average Fuel Costs/MWh
US dollars		2017		2016
Dollars per MWh	$	107	$	77

The change in average fuel costs in Q1 2017 compared to Q1 2016 was the result of higher oil prices.

EMERA ENERGY

Financial Highlights

For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)		2017		2016
Marketing and trading margin (1)	$	26	$	47
Electricity sales (2)		114		180
Total operating revenues – non-regulated		140		227
Non-regulated fuel for generation and purchased power (3)		87		114
Adjusted contribution to consolidated net income	$	10	$	48
After-tax derivative mark-to-market gain	$	160	$	45
Contribution to consolidated net income	$	170	$	93
Adjusted contribution to consolidated earnings per common share – basic	$	0.05	$	0.32
Contribution to consolidated earnings per common share – basic	$	0.80	$	0.63

Adjusted EBITDA	$	31	$	88
(1) Marketing and trading margin excludes a pre-tax mark-to-market gain of $237 million for the quarter ended March 31, 2017 (2016 - $72 million gain).
(2) Electricity sales exclude a pre-tax mark-to-market loss of $7 million for the quarter ended March 31, 2017 (2016 - $8 million loss).
(3) Non-regulated fuel for generation and purchased power excludes a pre-tax mark-to-market gain of $1 million for the quarter ended March 31, 2017 (2016 - $3 million gain).

For the	Three months ended
millions of Canadian dollars	March 31
Contribution to consolidated net income – 2016	$	93
Decreased marketing and trading margin – See Marketing and Trading Margin below		(21)
Decreased electricity sales mainly due to lower hedged power prices and decreased sales volumes at the NEGG Facilities driven by less favourable market conditions, an unplanned outage at the Bridgeport Facility, and a weaker USD; partially offset by higher electricity prices at Bayside Power.		(66)
Decreased non-regulated fuel for generation and purchased power mainly due to lower hedged natural gas prices and decreased volumes at the NEGG Facilities driven by less favourable market conditions, the unplanned outage at the Bridgeport Facility, and a weaker USD; partially offset by higher natural gas prices at Bayside Power.		27
Decreased income tax expense mainly due to decreased income before provision for income taxes.		20
Increased mark-to-market, net of tax mainly due to changes in existing positions on long-term natural gas and AMA contracts, and the reversal of 2016 mark-to-market losses.		115
Other		2
Contribution to consolidated net income – 2017	$	170

A portion of earnings are exposed to foreign exchange fluctuations, thereby affecting adjusted CAD contribution to net earnings. The impact of a weaker USD, quarter-over-quarter, decreased CAD earnings by $12 million in Q1 2017 compared to Q1 2016, mainly related to after-tax derivative mark-to-market gains.

Emera Energy Services
Adjusted EBITDA

Adjusted EBITDA for Emera Energy Services is summarized in the following table:

For the
millions of Canadian dollars	Three months ended March 31
	2017		2016
Marketing and trading margin	$	26	$	47
OM&G		5		10
Other income (expenses), net		-		(4)
Adjusted EBITDA	$	21	$	33

Marketing and Trading Margin

Marketing and trading margin decreased $21 million to $26 million in Q1 2017 compared to $47 million in Q1 2016. This decrease is mainly due to weaker market conditions, specifically reduced volatility driven by warmer winter weather, less favourable capacity hedges and increased gas transportation infrastructure within the northeast United States, partially offset by growth in the volume of business.

Emera Energy Generation

Adjusted EBITDA

Adjusted EBITDA for Emera Energy Generation is summarized in the following table:

For the		Three months ended March 31
	New England				Maritime Canada				Total
millions of Canadian dollars	2017		2016		2017		2016		2017		2016
Energy sales	$	65	$	139	$	38	$	28	$	103	$	167
Capacity and other		11		13		-		-		11		13
Electricity revenue	$	76	$	152	$	38	$	28	$	114	$	180
Non-regulated fuel for generation and purchased power		58		94		28		18		86		112
Provincial, state and municipal taxes		3		1		-		-		3		1
OM&G		9		9		5		6		14		15
Other income (expenses), net		-		-		-		1		-		1
Adjusted EBITDA	$	6	$	48	$	5	$	5	$	11	$	53

Adjusted EBITDA decreased $42 million to $11 million in Q1 2017 from $53 million in Q1 2016, mainly due to lower realized energy margins in the NEGG Facilities, reflecting more favourable short-term economic hedges in Q1 2016 compared to Q1 2017. Energy sales volumes were also lower due to less favourable market conditions, and to a lesser extent, the unplanned outage at the Bridgeport Facility.

The Maritime Canada Facilities’ adjusted EBITDA was consistent quarter-over-quarter.

Operating Statistics

For the	Three months ended March 31
	Sales Volumes (GWh) (1)		Plant Availability (%) (2)				Net Capacity Factor (%) (3)
	2017	2016	2017		2016		2017		2016
New England	935	1,303	87.7	%	96.1	%	38.8	%	54.7	%
Maritime Canada	555	518	99.6	%	95.8	%	80.3	%	75.9	%
Total	1,490	1,821	90.3	%	96.0	%	48.3	%	59.3	%
(1) Sales volumes represent the actual electricity output of the plants.
(2) Plant availability represents the percentage of time in the period that the plant was available to generate power regardless of whether it was running. Effectively, it represents 100% availability reduced by planned and unplanned outages.
(3) Net capacity factor is the ratio of the utilization of an asset as compared to its maximum capability, within a particular time frame. It is generally a function of plant availability and plant economics vis-à-vis the market.

The NEGG Facilities sales volumes, plant availability and net capacity factor were lower quarter-over-quarter mainly due to less favourable market conditions reducing opportunities for economic dispatch and the impact of an unplanned outage at the Bridgeport Facility in mid-March 2017.

The Maritime Canada Facilities’ sales volumes, plant availability and net capacity factor were up quarter-over-quarter mainly due to fewer unplanned outage hours at Bayside Power in Q1 2017 compared to Q1 2016.

CORPORATE AND OTHER

Financial Highlights

For the	Three months ended March 31
millions of Canadian dollars		2017		2016
Operating revenues – regulated gas	$	13	$	13
Non-regulated operating revenue		16		8
Total operating revenue		29		21
Intercompany revenue (1)		10		10
Income from equity investments		22		24
Interest expense		73		39
Adjusted contribution to consolidated net income		(27)		-
After-tax mark-to-market gain (loss)		-		(121)
Contribution to consolidated net income		(27)		(121)
Adjusted contribution to consolidated earnings per common share – basic		(0.13)		-
Contribution to consolidated earnings per common share – basic	$	(0.13)	$	(0.81)

Adjusted EBITDA	$	31	$	36
(1) Intercompany revenue consists of interest from Brunswick Pipeline, M&NP and EEG.

Net Income

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

For the	Three months ended
millions of Canadian dollars	March 31
Contribution to consolidated net income – 2016	$	(121)
Increased non-regulated operating revenue - see Operating Revenues below		8
Income from equity investments - see Income from Equity Investments below		2
Increased interest expense - see Interest Expense below		(34)
After-tax mark-to-market gain (loss) in 2016 related to the translation of the USD cash balance and the mark-to-market adjustments from forward contracts economically hedging the Debenture Offering		121
Other		(3)
Contribution to consolidated net income – 2017	$	(27)

Operating Revenues

Operating revenues increased $8 to $29 million in Q1 2017 compared to $21 million in Q1 2016 due to increased project activity in Emera Utility Services.

Income from Equity Investments

Income from equity investments are summarized in the following table:

For the		Three months ended
millions of Canadian dollars		March 31
		2017		2016
LIL	$	9	$	5
NSPML		7		4
M&NP		6		6
APUC – sold in 2016		-		9
Income from equity investments	$	22	$	24

Income from equity investments decreased $2 million to $22 million in Q1 2017 compared to $24 million in Q1 2016 as a result of the sale of APUC in 2016, partially offset by higher earnings from the investment in NSPML and LIL.

Interest Expense

Interest expense increased $34 million to $73 million in Q1 2017 compared to $39 million in Q1 2016 primarily due to financing related to the TECO Energy acquisition.

Liquidity and Capital Resources

The Company generates cash primarily through its investments in various regulated and non-regulated energy related entities and investments. Utility customer bases are diversified by both sales volumes and revenues among customer classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the business. Circumstances that could affect the Company’s ability to generate 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. Emera’s subsidiaries maintain solid credit metrics and 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.

Consolidated Cash Flow Highlights

Significant changes in the condensed consolidated statements of cash flows between the three months ended March 31, 2017 and 2016 include:
		2017
millions of Canadian dollars		2017	2016			$ Change
Cash and cash equivalents, beginning of period	$	404	$	1,073	$	(669)
Provided by (used in):
Operating cash flow before change in working capital		348		233		115
Change in working capital		(182)		(52)		(130)
Operating activities		166		181		(15)
Investing activities		(379)		(139)		(240)
Financing activities		66		(46)		112
Effect of exchange rate changes on cash and cash equivalents		(2)		(69)		67
Cash and cash equivalents, end of period	$	255	$	1,000	$	(745)

Cash Flow from Operating Activities

Refer to the Q1 Consolidated Income Statement and Operating Cash Flow Highlights for details.

Cash Flow Used In Investing Activities

Net cash used in investing activities increased $240 million to $379 million for the three months ended March 31, 2017 compared to $139 million in Q1 2016 due to an increase in capital spending.

Capital expenditures for the three months ended March 31, 2017, including AFUDC and net of proceeds from disposal of assets, were $305 million compared to $87 million during the same period in 2016. The increase was a result of the acquisition of TECO Energy and additional capital spending in NSPI and Emera Maine offset by a reduction in capital spend in Emera Caribbean. Details of the capital spend are shown below:

· $205 million at Emera Florida and New Mexico;

· $60 million at NSPI (2016 – $48 million);

· $18 million at Emera Maine (2016 – $9 million);

· $9 million at Emera Caribbean (2016 – $22 million);

· $11 million at Emera Energy (2016 – $6 million);

· $2 million in Corporate and Other (2016 – $2 million)

Cash Flow from Financing Activities

Net cash provided by financing activities increased $112 million to $66 million for the three months ended March 31, 2017 compared to cash flow used in financing activities of $46 million for the same period in 2016. The increase was due to proceeds from the issuance of long-term debt at GBPC, the issuance of short-term debt at Emera Florida and New Mexico and higher repayment of debt in 2016. This was partially offset by increased 2017 dividends on common stock.

Contractual Obligations

As at March 31, 2017, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:

millions of Canadian dollars	2017		2018		2019		2020		2021		Thereafter		Total
Long-term debt	$	469	$	787	$	1,392	$	881	$	1,686	$	9,584	$	14,799
Interest payment obligations (1)		615		640		609		563		512		6,485		9,424
Purchased power (2)		194		225		206		203		200		2,306		3,334
Transportation (3)		450		409		308		280		196		1,620		3,263
Pension and post-retirement obligations (4)		100		47		48		49		51		863		1,158
Fuel and gas supply		552		212		115		32		27		-		938
Long-term service agreements (5)		81		64		64		31		41		218		499
Asset retirement obligations		2		2		2		2		44		390		442
Equity investment commitments (6)		235		-		-		190		-		-		425
Leases and other (7)		59		16		13		11		8		69		176
Capital projects		125		1		-		-		-		-		126
Demand side management		28		48		13		-		-		-		89
Long-term payable		3		4		5		5		5		10		32
Convertible debentures		-		-		-		-		-		6		6
	$	2,913	$	2,455	$	2,775	$	2,247	$	2,770	$	21,551	$	34,711
(1) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at March 31, 2017, including any expected required payment under associated swap agreements.
(2) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths.
(3) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.
(4) Defined benefit funding contractual obligations were determined based on funding requirements and assuming pension accruals cease as at December 31, 2016. Credited service and earnings are assumed to be crystallized as at December 31, 2016. 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, 2016 to be eligible. As the defined benefit pension plans currently undergoes 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.
(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) Emera has a commitment in connection with the Federal Loan Guarantee to complete construction of the Maritime Link. Thirty per cent of the financing of this project will come from Emera as equity. Emera also has a commitment to make equity contributions to the Labrador Island Link Limited Partnership upon draw requests from the general partner. The amounts forecasted are a combination of equity investments for both projects and are subject to change in both timing and amounts as the projects advance through construction.
(7) Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles.

NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 35 years. The timing and amounts payable to NSP Maritime Link Inc. and NSPI’s future rate recoveries are dependent upon the in-service date of the Maritime Link, UARB decisions and the final costing of the Maritime Link after construction is complete. This transaction will be accounted for as a related party transaction in accordance with the Company’s accounting policies. The Company accounts for NSPML as an equity investment.

Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to approximately $2.7 billion committed syndicated revolving bank lines of credit in either CAD or USD per the table below.

			Revolving				Undrawn
			Credit				and
millions of dollars	Maturity		Facilities		Utilized		Available
Emera – Operating and acquisition credit facility	June 2020 – Revolver	$	700	$	64	$	636
Emera Florida and New Mexico - in USD - credit facilities	March 2018 - March 2022		1,300		758		542
NSPI – Operating credit facility	October 2020 – Revolver		600		302		298
Emera Maine – in USD – Operating credit facility	September 2019 – Revolver		80		37		43
Other – in USD – Operating credit facilities	Various		32		-		32

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, 2017.

Emera Florida and New Mexico

On March 8, 2017, TECO Energy/Finance extended the maturity date of its $400 million USD term bank credit facility from March 14, 2017 to March 8, 2018 with no significant change in commercial terms from the prior agreement.

On March 22, 2017, TECO Energy/Finance extended the maturity date of its $300 million USD bank credit facility from December 17, 2018 to March 22, 2022 with no significant change in commercial terms from the prior agreement.

On March 22, 2017, TEC extended the maturity date of its $325 million USD bank credit facility from December 17, 2018 to March 22, 2022, and reduced the existing letter of credit facility to $50 million USD from $200 million USD. There were no other significant changes in commercial terms from the prior agreement.

On March 22, 2017, NMGC extended the maturity date of its $125 USD million bank credit facility from December 17, 2018 to March 22, 2022 with no significant change in commercial terms from the prior agreement.

GBPC

On March 21, 2017, GBPC amended its loan agreement with the addition of two non-revolving term credit facilities and no significant change in commercial terms from the prior agreement. The combined total of these new facilities is for up to $45 million USD. At March 31, 2017 a total of $30 million USD was drawn against the new facilities.

Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2016 annual MD&A, with the exception of the items noted below.

TECO Coal was sold on September 21, 2015 to Cambrian Coal Corporation (“Cambrian”). Pursuant to the sales agreement, Cambrian is obligated to file, in respect of each mining permit, applications in connection with the change of control with the appropriate governmental entities. As each application is approved, Cambrian is required to post a bond or other appropriate collateral in order to obtain the release of the corresponding bond secured by the TECO Energy indemnity for that permit. As at March 31, 2017, TECO Energy had remaining indemnified bonds totaling $40 million ($30 million USD) and, of that remaining exposure, Cambrian had posted approximately $31 million ($23 million USD) of additional replacement bonds. Once the corresponding TECO Energy indemnified bonds have been released, TECO Energy’s exposure would be reduced by that amount.

The amounts outlined above represent the maximum theoretical amounts that TECO Energy would be required to pay to the surety companies.

The company is working with Cambrian on the process to replace the remaining bonds. Pursuant to the securities purchase agreement, Cambrian has the obligation to indemnify and hold TECO Energy harmless from any losses incurred that arise out of the coal mining permits during the period commencing on the closing date through the date all permit approvals are obtained.

Emera has a standby letter of credit in the amount of $21 million to guarantee the performance of the obligations of the EUS-Rokstad joint venture. The letter of credit expires in August 2017. EUS-Rokstad is a joint venture between EUS and Rokstad Power, formed for the purpose of constructing the high voltage direct current components of NSPML’s transmission line. Rokstad Power has issued a separate letter of credit to Emera for their portion of the work to be performed under the contract. EUS and Rokstad Power are jointly and severally liable for completion of the project.

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 2016 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		2017		2016
Derivative instrument assets (current and other assets)	$	6	$	10
Derivative instrument liabilities (current and long-term liabilities)		(21)		(27)
Net derivative instrument assets (liabilities)	$	(15)	$	(17)

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		2017		2016
Operating revenues – regulated	$	(3)	$	(3)
Non-regulated fuel for generation and purchased power		4		4
Effective net gains (losses)	$	1	$	1

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

The Company recognized in net income the following gains (losses) related to the ineffective portion of hedging relationships under the following categories:

For the	Three months ended March 31
millions of Canadian dollars		2017		2016
Non-regulated fuel for generation and purchased power	$	-	$	(1)
Ineffective gains (losses)	$	-	$	(1)

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	March 31		December 31
millions of Canadian dollars		2017		2016
Derivative instrument assets (current and other assets)	$	181	$	229
Regulatory assets (current and other assets)		19		11
Derivative instrument liabilities (current and long-term liabilities)		(20)		(12)
Regulatory liabilities (current and long-term liabilities)		(181)		(231)
Net asset (liability)	$	(1)	$	(3)

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		2017		2016
Regulated fuel for generation and purchased power (1)	$	7	$	3
Net gains (losses)	$	7	$	3
(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.

Held-for-trading ("HFT") Items Recognized on the Balance Sheets

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

As at	March 31		December 31
millions of Canadian dollars		2017		2016
Derivative instruments assets (current and other assets)	$	65	$	37
Derivative instruments liabilities (current and long-term liabilities)		(205)		(434)
Net derivative instrument assets (liabilities)	$	(140)	$	(397)

Held-for-trading 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		2017		2016
Operating revenues – non-regulated	$	324	$	222
Non-regulated fuel for generation and purchased power		2		(1)
Net gains (losses)	$	326	$	221

Other Derivatives Recognized on the Balance Sheets

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

As at	March 31		December 31
millions of Canadian dollars	2017		2016
Derivative instrument liabilities (current and long-term liabilities)		(1)		(2)
Net derivative instrument assets (liabilities)	$	(1)	$	(2)

Other Derivatives Recognized in Net Income

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

For the		Three months ended
millions of Canadian dollars		March 31
		2017		2016
Other income (expense)	$	-	$	(95)
Total gains (losses)	$	-	$	(95)

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, 2017, to provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.

Change in ICFR

There were no changes in the Company’s ICFR during the quarter ended March 31, 2017, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over

financial reporting, except for TEC’s implementation of an SAP developed Customer Relationship Management and Billing System as a process improvement initiative which replaced their legacy customer information system. TEC has made appropriate changes to internal controls and procedures, as is expected with a major system implementation.

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 2016 annual MD&A.

CHANGES IN ACCOUNTING POLICIES AND PRACTICES

Future Accounting Pronouncements

The Company considers the applicability and impact of all Accounting Standard Updates (“ASU”) issued by Financial Accounting Standards Board (the "FASB"). The ASUs that have been issued, but that are not yet effective, are consistent with those disclosed in the 2016 audited consolidated financial statements, with the exception of the items noted below.

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new, principle-based revenue recognition framework, which has been codified as Accounting Standards Codification (“ASC”) Topic 606. The FASB issued amendments to ASC Topic 606 during 2016 to clarify certain implementation guidance and to reflect narrow scope improvements and practical expedients. The guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue and related cash flows arising from contracts with customers. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and will allow for either full retrospective adoption or modified retrospective adoption. The Company will adopt this guidance effective January 1, 2018.

The Company implemented a project plan in 2016, and is in the process of reviewing material revenue streams in line with this plan, with conclusions on the impact on the streams expected in Q2 and Q3 2017. In addition, the Company is evaluating the available adoption methods, the impact of collectability risk, and disclosure requirements. In Q1 2017, the Company has concluded that the accounting for contributions in aid of construction will be out of the scope of the new standard. The Company continues to monitor the assessment of ASC Topic 606 by the AICPA Power and Utilities Revenue Recognition Task Force.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. The standard, codified as ASC Topic 842, increases transparency and comparability among organizations by recognizing lease assets and liabilities

on the balance sheet for leases with terms of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged. The guidance will require additional disclosures regarding key information about leasing arrangements. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018. Early adoption is permitted, and is required to be applied using a modified retrospective approach. The Company is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, the FASB issued ASU 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The guidance requires the service cost component of defined benefit pension or other postretirement benefit plans to be reported in the same line items as other compensation costs. The other components of net benefit cost are required to be presented in the Consolidated Statements of Income outside of income from operations. Only the service cost component will be eligible for capitalization. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The guidance is required to be applied retrospectively for presentation in the Consolidated Statements of Income and prospectively for the guidance limiting capitalization. The Company is currently evaluating the impact of the adoption of this standard on its consolidated financial statements.

SUMMARY OF QUARTERLY RESULTS

For the quarter ended
millions of dollars		Q1		Q4		Q3		Q2		Q1		Q4		Q3		Q2
(except per share amounts)		2017		2016		2016		2016		2016		2015		2015		2015
Operating revenues	$	1,857	$	1,513	$	1,387	$	500	$	877	$	732	$	642	$	527
Net income attributable to common shareholders		312		70		(95)		208		44		192		35		10
Adjusted net income attributable to common shareholders		152		104		14		237		120		87		23		48
Earnings per common share – basic		1.48		0.34		(0.52)		1.39		0.30		1.31		0.24		0.07
Earnings per common share – diluted		1.47		0.34		(0.52)		1.38		0.30		1.30		0.24		0.07
Adjusted earnings per common share – basic		0.72		0.51		0.08		1.59		0.81		0.59		0.16		0.33

Quarterly operating revenues and net income attributable to common shareholders are affected by seasonality. Historically, the first quarter has generally been the strongest because a significant portion of the Company’s operations are in northeastern North America, where winter is the peak electricity usage season. However, with the addition of Emera Florida and New Mexico, the third quarter will provide stronger 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 and mark-to-market adjustments.