Exhibit 99.2

Management’s Discussion & Analysis

As at February 10, 2017

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 fourth quarter of 2016 relative to the same quarter in 2015; the full year of 2016 relative to 2015 and 2014; and its financial position as at December 31, 2016 relative to December 31, 2015. To enhance shareholders’ understanding, certain multi-year historical financial and statistical information is presented. Throughout this discussion, “Emera Incorporated”, “Emera” and “Company” refer to Emera Incorporated and all of its consolidated subsidiaries and investments. The Company’s activities are carried out through six business segments; Emera Florida and New Mexico, Nova Scotia Power Inc. (“NSPI”), Emera Maine, Emera Caribbean, Emera Energy and Corporate and Other.

This discussion and analysis should be read in conjunction with the Emera Incorporated annual audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2016. Emera follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”).

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 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”)
Peoples Gas System (“PGS”) – Gas Division of TEC	FPSC
New Mexico Gas Company, Inc. (“NMGC”)	New Mexico Public Regulation Commission (“NMPRC”)
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”)
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 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 Incorporated is a geographically diverse energy and services company, targeting eight per cent annual dividend growth through 2020. The Company invests in electricity generation, electricity transmission and distribution, gas transmission and distribution, and utility services. Emera provides regional energy solutions by connecting its assets, markets and partners in Canada, the United States and the Caribbean. Emera seeks to deliver long-term growth to investors and, accordingly, the primary measures of performance are annual dividend growth, earnings per common share growth, adjusted earnings per common share growth and total shareholder return. Below are Emera’s one, three and five year performance for these metrics:

For the	Year ended December 31, 2016
	1 year	3 year	5 year
Dividend per share compound annual growth rate	19.9%	12.2%	8.7%
Earnings per share compound annual growth rate	(51.1%)	(6.7%)	(7.7%)
Adjusted earnings per share compound annual growth rate (see Non-GAAP Financial Measures below)	22.6%	12.2%	6.7%
Emera annualized total shareholder return (1)	9.6%	18.3%	10.0%
S&P/TSX Capped Utilities Index annualized total shareholder return (2)	17.4%	9.3%	4.9%
(1) Total shareholder return combines share price appreciation and dividends per common share paid during the fiscal year to show the total return to the shareholder expressed as an annualized percentage, assuming dividends are reinvested each time they are paid.
(2) The S&P/TSX Capped Sector Indices provide liquid and tradable benchmarks for related derivative products of Canadian economic sectors. Constituents are selected from a stock pool of S&P/TSX Composite Index Stocks, and the relative weight of any single index constituent is capped at 25 per cent. The indices are based upon the Global Industry Classification Standards (GICS®). The S&P/TSX Capped Utilities Index imposes capped weights on the index constituents included in the S&P/TSX Composite that are classified in the GICS® utilities sector.

Regulated utilities are the foundation of Emera’s business, providing the Company with strong and consistent earnings. 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. In Florida and New Mexico 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.

Since its formation in 2003, Emera Energy has become an active participant in the northeastern United States electricity and natural gas markets. It has built a strong marketing, trading and asset management business, based on comprehensive market knowledge, focus on customer service and robust risk management. The integration and performance of three New England Gas Generating Facilities (“NEGG”) purchased in 2013 has contributed significantly to the success of Emera Energy.

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. Within this context, Emera is focused on growing shareholder value by identifying reliable and

affordable energy solutions, typically involving replacement of higher-carbon electricity generation with generation from cleaner sources, and the related transmission and distribution infrastructure to deliver that energy to market.

Emera has partnerships and relationships throughout the regions in which it operates and has established a diverse investment and operations profile that links its assets and capabilities in those regions. At the core of Emera’s strategy is the ability to leverage these particular linkages and adjacencies to create solutions for customers and investment opportunities for the Company.

The foundation of Emera’s strategy is its collaborative approach to strategic partnerships, its ability to find creative solutions to work within and across multiple jurisdictions, and its experience dealing with complex projects and investment structures. 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 targets achieving 75 to 85 per cent of its adjusted net income (a non-GAAP measure described in the section below) from rate-regulated subsidiaries, which generally contribute strong, predictable earnings and cash flows that fund dividends, reinvestment and are reflective of the Company’s risk tolerance. The Company is expected to achieve this adjusted net income target with the July 1, 2016 close of its acquisition of TECO Energy, Inc. (“TECO Energy”). The Company targets a dividend payout ratio of 70 to 75 per cent of adjusted net income.

Emera has grown its asset base to enable growth and 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. This was demonstrated in Emera’s financing of the TECO Energy acquisition. 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.

BUSINESS OVERVIEW

Energy markets across North America are affected by a number of trends that shape the environment in which energy and utility companies operate. Some of these trends are short-term or cyclical, while others evolve to have a significant long-term impact on businesses and stakeholders across the sector.

Among the key trends influencing Emera’s long-term strategy is the increasing expectation by customers and policy-makers for a permanent reduction in the carbon-equivalent levels of electricity generation. Advocacy for cleaner, renewable sources of electricity has become a defining trend in the industry globally, not just in the markets Emera serves. While it is still unclear whether economic volatility and lower fossil fuel prices will slow the pace of this 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 and hydro generation, and natural gas infrastructure, is likely to continue across the sector despite any cost differential with more carbon-intensive generating options.

The transformation in generation and fuel selection also has a significant impact on the requirement for new transmission infrastructure. In addition to the traditional issues of infrastructure life expectancy and changing technology, infrastructure renewal planning must now also consider the changing energy landscape. Gas extraction from the Marcellus Shale region of the United States, major new hydro developments in Newfoundland and Labrador, and development of new wind farms in northern New England and Atlantic Canada (to name a few) require significant new transmission infrastructure to bring this energy to market.

The capital spending requirements related to new infrastructure will need to be addressed in the context of the intense focus of customers and regulators on electricity pricing and affordability. Going forward, the ability of energy companies to achieve their growth objectives, environmental targets and other goals, will depend on their ability to address price and affordability.

As technology advances, so does availability and demand for affordable new mechanisms that allow consumers to have more control over their energy usage and for utilities to introduce more efficient energy solutions for their customers. This includes grid modernization or ‘smart grid’ advances that, when combined with in-home products such as heat pumps and electric thermal storage units, have the potential to significantly increase energy efficiency for consumers while allowing utilities to better manage peak load. Load is the total amount of electricity or gas delivered in order to meet energy-consumption demands of Emera’s customers. In addition, as with wind turbine technology, advancements in solar technology have significantly reduced solar generation costs, bringing them more in line with the cost of fossil fuel generation in some higher-cost jurisdictions. This gives rise to customer expectations that they will be able to benefit from options such as distributed generation. Continued and advancing development of energy storage technology will further transform and support the efficient and practical utilization of renewables and will facilitate the integration of more distributed generation.

These and other trends create opportunities and challenges for businesses, regulators, investors and other stakeholders within the energy sector, and are expected to drive increased regional cooperation and interconnection within the energy industry. Whether it is the need to transport natural gas and electricity from disparate regions to markets on the eastern seaboard, or the need to gain efficiencies by coordinating electricity generation and dispatch across multiple jurisdictions, inter-regional cooperation has emerged as an important trend.

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, as detailed below:

Non-GAAP measure	GAAP measure
Adjusted net income attributable to common shareholders or adjusted net income	Net income attributable to common shareholders
Adjusted earnings per common share – basic	Earnings per common share – basic
Adjusted contribution to consolidated net income	Contribution to consolidated net income
Adjusted income before provision for income taxes	Income before provision for income taxes
Adjusted contribution to consolidated earnings per common share – basic	Contribution to consolidated earnings per common share – basic
EBITDA	Net income
Adjusted EBITDA	Net income
Electric margin and gas margin	Income from operations

Adjusted Net Income

Emera calculates an adjusted net income measure by consistently 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 related to the effect of 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 Highlights section, Emera Energy – Review of 2016 and Corporate and Other – Review of 2016.

The following is a reconciliation of 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					Year ended
millions of Canadian dollars (except per share amounts)		December 31				December 31
		2016	2015			2016	2015		2014
Net income attributable to common shareholders	$	70	$	192	$	227	$	397	$	407
After-tax mark-to-market gain (loss)	$	(34)	$	105	$	(248)	$	67	$	88
Adjusted net income attributable to common shareholders	$	104	$	87	$	475	$	330	$	319
Earnings per common share – basic	$	0.34	$	1.31	$	1.33	$	2.72	$	2.84
Adjusted earnings per common share – basic	$	0.51	$	0.59	$	2.77	$	2.26	$	2.23

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, as previously discussed.

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 financial condition. 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.

EBITDA and Adjusted EBITDA Reconciliation

For the	Three months ended				Year ended
millions of Canadian dollars	December 31				December 31
		2016		2015		2016		2015		2014
Net income (1)	$	71	$	199	$	266	$	452	$	453
Interest expense, net		169		70		585		212		180
Income tax expense (recovery)		(6)		21		(22)		93		113
Depreciation and amortization		212		88		588		340		329
EBITDA		446		378		1,417		1,097		1,075
Mark-to-market gain (loss), excluding income tax and interest		(52)		119		(327)		66		129
Adjusted EBITDA	$	498	$	259	$	1,744	$	1,031	$	946
(1) Net income (loss) is income before Non-controlling interest in subsidiaries and Preferred stock dividends.

Electric Margin and Gas Margin

“Electric margin” and “Gas margin” are non-GAAP financial measure used to show the amounts that Emera’s regulated utilities retain to recover non-fuel and non-clause related costs. Prudently incurred fuel costs are recovered from customers, except at Domlec, where substantially all prudently incurred fuel costs are passed to customers through the fuel pass-through mechanism. In addition, prudently incurred clause related costs and returns are recovered from customers. Management believes measuring electric and gas margin shows the portion of these utilities’ revenues that directly contribute to Emera’s income as distinguished from the portion of revenues that are managed through fuel adjustment and other clause mechanisms, which have a minimal impact on income.

Emera Energy reports “Non-regulated electric margin” because the sales price of electricity and the cost of natural gas used to generate it are highly correlated. However, their absolute values can vary materially over time. Emera Energy believes that “Non-regulated electric margin”, as the net result, provides a meaningful measure of business performance in addition to the absolute values of sales and fuel expenses, which are also reported.

Electric margin and gas margin, as calculated by Emera, may not be comparable to the electric margin measures of other companies, but in management’s view appropriately reflects Emera’s specific condition. This measure is not intended to replace “Income from operations” which, as determined in accordance with GAAP, is an indicator of operating performance. Electric margin and Gas margin are discussed further in the Emera Florida and New Mexico – Electric and Gas Margin, the NSPI – Electric Margin, the Emera Caribbean – Electric Margin and the Emera Energy – Adjusted EBITDA sections.

Significant Items Affecting Earnings

2016

Acquisition Related Costs

Emera incurred after-tax costs related to its acquisition of TECO Energy (“the Acquisition”), including legal, banking and advisory, stipulation commitments, accelerated vesting of TECO Energy stock-based compensation, pre-closing financing, beneficial conversion feature discount noted below and foreign exchange costs totaling a $13 million benefit in Q4 2016 ($0.06 benefit per common share) and $166 million expense for the year ended December 31, 2016 ($0.97 per common share). Emera incurred after-tax costs of $30 million in Q4 2015 ($0.21 per common share) related to its then-pending acquisition of TECO Energy, including legal, advisory, and financing costs. For the year ended December 31, 2015, TECO Energy acquisition related costs were $53 million after-tax ($0.36 per common share). All acquisition costs have been recognized in the Corporate and Other segment.

Included below in “After-Tax-Mark-to-Market-Losses”, are the foreign currency earnings effect related to the Convertible Debentures USD cash balance and the associated forward contracts. These resulted in a mark-to-market after-tax loss of $114 million in 2016 recorded in “Other income (expenses), net (a mark-to-market after-tax gain of $98 million in 2015).

In Q3 2016 substantially all of Emera’s Convertible Debentures were converted to equity, and as a result, Emera recognized the difference between Emera’s closing share price on the issuance date of the Convertible Debentures and their exercise price (the “Beneficial Conversion Feature discount”) resulting in a cost of $62 million ($43 million after-tax or $0.24 per common share). This cost is included in the acquisition expense noted above.

After-Tax Mark-to-Market Losses

After-tax mark-to-market losses increased $139 million to a $34 million loss in Q4 2016 ($0.17 per common share) compared to $105 million gain in Q4 2015 ($0.71 per common share). Year-to-date losses increased $315 million to $248 million in 2016 ($1.45 per common share) compared to $67 million gain for the same period in 2015 ($0.46 per common share). The increased mark-to-market losses in the quarter and in the year ended December 31, 2016 relate to the effect of the Debenture Offering USD-denominated currency revaluation and forward contracts put in place to hedge the proceeds from the final instalment of the Debenture Offering. In addition, losses have increased due to changes in existing positions on Asset Management Agreements (“AMA”) and long-term natural gas contracts at Emera Energy.

At inception of an AMA contract, the unrealized mark-to-market adjustment on the commodity portion of the contract is offset fully by the value of a corresponding gas transportation asset. Subsequent changes in gas prices result in unrealized mark-to-market gains or losses recorded in earnings. The corresponding transportation assets are amortized evenly over the contract term. The difference between these items results in unrealized mark-to-market gains or losses in earnings but ultimately the mark-to-market adjustments and transportation assets reduce to zero at the end of the contract term.

Investment in APUC

On December 8, 2016, Emera completed the sale of 12.9 million common shares of Algonquin Power and Utilities Corp (“APUC”), representing approximately 4.7 per cent of APUC's issued and outstanding common shares for gross proceeds of $142 million. This sale resulted in a pre-tax loss of $12 million or $0.07 per common share (after-tax loss of $10 million or $0.06 per common share), which was recorded in "Other income (expenses), net" in Q4 2016. Emera no longer holds any interest in APUC.

On June 30, 2016, Emera exchanged 12.9 million APUC subscription receipts and dividend equivalents into 12.9 million APUC common shares. This conversion resulted in a pre-tax gain of $63 million or $0.42 per common share (after-tax gain of $53 million or $0.35 per common share), which was recorded in “Other income (expenses), net” in Q2 2016.

On May 24, 2016, Emera completed the sale of 50.1 million common shares of APUC, representing approximately 19.3 per cent of APUC's issued and outstanding common shares for gross proceeds of $544 million. This sale resulted in a pre-tax gain of $172 million or $1.15 per common share (after-tax gain of $146 million or $0.97 per common share), which was recorded in "Other income (expenses), net" in Q2 2016.

Gain on BLPC Self-Insurance Fund Regulatory Liability

BLPC maintains a Self-Insurance Fund (“SIF”) for the purpose of building an insurance fund to cover risk against damage and consequential loss to certain of BLPC’s generating, transmission and distribution systems. Third party risk advisors were engaged to support a detailed risk analysis, which was

completed to quantify the prudent assessment of the risk to BLPC’s transmission and distribution system from natural catastrophes.

In June 2016, BLPC secured support from the Government of Barbados and the Trustees of the SIF to reduce the contingency funding in the SIF to $29 million ($22 million USD). As a result, Emera recorded a pre-tax gain of $53 million ($41 million USD) or $0.35 per common share and an after-tax gain of $43 million ($34 million USD) or $0.29 per common share in “Other income (expenses), net”. In Q3 2016, Emera received a distribution of $65 million ($50 million USD) from the fund.

Emera Energy Recognition of State Fuel Taxes

Emera Energy recorded a $20 million pre-tax or $0.13 per common share ($12 million after-tax or $0.08 per common share) liability for state tax on natural gas sales made from November 2013 through March 2016. This included $4 million pre-tax ($2 million after-tax) related to Q1 2016. The recognition of this liability resulted in an increase to “Non-regulated fuel for generation and purchased power” in Q2 2016.

2015

After-Tax Mark-to-Market Gains

After-tax mark-to-market gains increased $32 million to $105 million in Q4 2015 compared to $73 million in Q4 2014; and decreased $20 million to $67 million for the year ended December 31, 2015 compared to $88 million in 2014. The increased mark-to-market gains in the quarter were primarily due to the effect of USD-denominated currency and forward contracts related to the then-pending TECO Energy acquisition. The increase was partially offset by changes in gas and power contract positions and amortization of transportation assets in Emera Energy. In addition, the reversal of 2013 mark-to-market losses in 2014 in Emera Energy was primarily responsible for the year-over-year decrease in after-tax mark-to-market gains.

Gain on Dilution of APUC Equity Investment

In December 2015, APUC closed a 14.355 million common share offering. As a result, Emera recorded a gain of $11 million (after-tax earnings of $9 million or $0.06 per common share) in “Income from Equity Investments”. The gain was a result of APUC’s share issuance price being higher than Emera’s pre-issuance average book value.

Barbados Light & Power Company Limited (“BLPC”) Restructuring Costs

BLPC recorded severance costs of $8 million ($6 million USD) relating to corporate restructuring, which was recorded in Operating, maintenance and general (“OM&G”) in Q2 2015. The after-tax effect on Emera’s Consolidated Net Income in Q2 2015, at Emera’s then 80.7 per cent ownership of ECI, was $5 million ($0.04 per common share).

Sale of Northeast Wind Partnership II, LLC (“NWP”) Equity Investment

On January 29, 2015, Emera completed the sale of its 49 per cent interest in NWP for $282 million ($223 million USD). This sale resulted in a pre-tax gain of $19 million or $0.13 per common share (after-tax gain of $12 million or $0.08 per common share), which was recorded in “Other income (expenses), net” in Q1 2015.

CONSOLIDATED FINANCIAL REVIEW

Below is a table highlighting significant changes between adjusted net income from 2015 to 2016.

For the	Three months ended		Year ended
millions of Canadian dollars	December 31		December 31
Adjusted net income – 2015	$	87	$	330
Emera Florida and New Mexico		63		172
Emera Caribbean		(6)		16
Emera Energy		(30)		(82)
NSPML and LIL AFUDC earnings		7		21
Acquisition and financing costs related to the acquisition of TECO Energy		43		(113)
TECO Energy post-acquisition financing costs		(44)		(93)
Gain (loss) on sale of APUC common shares		(10)		136
Gain on conversion of APUC subscription receipts and dividend equivalents to common shares of APUC		-		53
Gain on BLPC SIF regulatory liability		-		43
Emera Energy's recognition of fuel taxes for 2013 through March 2016		-		(12)
2015 gain on the sale of NWP		-		(12)
Other		(6)		16
Adjusted net income – 2016	$	104	$	475

Consolidated Financial Highlights

For the	Three months ended					Year ended
millions of Canadian dollars (except per share amounts)	December 31					December 31
		2016	2015			2016	2015		2014
Operating revenues	$	1,513	$	731	$	4,277	$	2,789	$	2,939
Income from operations		208		149		555		508		668
Net income attributable to common shareholders		70		192		227		397		407
After-tax mark-to-market gain (loss)		(34)		105		(248)		67		88
Adjusted net income attributable to common shareholders		104		87		475		330		319
Earnings per common share – basic	$	0.34	$	1.31	$	1.33	$	2.72	$	2.84
Earnings per common share – diluted	$	0.34	$	1.30	$	1.32	$	2.71	$	2.82
Adjusted earnings per common share – basic	$	0.51	$	0.59	$	2.77	$	2.26	$	2.23
Dividends per common share declared	$	-	$	-	$	1.9950	$	1.6625	$	1.4750

Adjusted EBITDA	$	498	$	259	$	1,744	$	1,031	$	946

For the	Three months ended					Year ended
millions of Canadian dollars (except per share amounts)		December 31				December 31
Operating Unit Contributions to Adjusted Net Income		2016	2015			2016	2015			2014
Emera Florida and New Mexico	$	63	$	-	$	172	$	-	$	-
NSPI		34		40		130		130		125
Emera Maine		11		5		47		45		42
Emera Caribbean		8		14		100		41		29
Emera Energy		5		35		24		130		98
Corporate and Other		(17)		(7)		2		(16)		25
Adjusted net income attributable to common shareholders	$	104	$	87	$	475	$	330	$	319
After-tax mark-to-market gain (loss)		(34)		105		(248)		67		88
Net income attributable to common shareholders	$	70	$	192	$	227	$	397	$	407

For the						Year ended
millions of Canadian dollars					December 31
						2016	2015		2014
Operating cash flow before changes in working capital					$	919	$	776	$	716
Change in working capital						134		(102)		46
Operating cash flow					$	1,053	$	674	$	762
Investing cash flow					$	(9,105)	$	(124)	$	(711)
Financing cash flow					$	7,448	$	221	$	58

As at					December 31
millions of Canadian dollars					2016		2015		2014
Working capital					$	301	$	600	$	357
Total assets (1)					$	29,221	$	12,039	$	9,853
Total long-term liabilities (1)					$	18,681	$	6,338	$	5,024
⁽¹⁾ These financial statements contain certain reclassifications of prior period amounts to be consistent with the current period presentation, with no effect on net income.

REVIEW OF 2016
Emera Consolidated Statements of Income

For the	Three months ended				Year ended
millions of Canadian dollars (except per share amounts)	December 31				December 31
		2016		2015		2016		2015		2014
Operating revenues – regulated electric	$	1,136	$	521	$	3,437	$	2,141	$	2,064
Operating revenues – regulated gas		282		13		499		52		49
Operating revenues – non-regulated		95		197		341		596		826
Total operating revenues		1,513		731		4,277		2,789		2,939
Regulated fuel for generation and purchased power		412		200		1,222		815		844
Regulated cost of natural gas		108		-		177		-		-
Regulated fuel adjustment mechanism and fixed cost deferrals		13		11		61		42		47
Non-regulated fuel for generation and purchased power		70		91		313		336		401
Non-regulated direct costs		22		4		29		19		31
Operating, maintenance and general		391		173		1,137		666		561
Provincial, state and municipal taxes		77		15		195		63		58
Depreciation and amortization		212		88		588		340		329
Total operating expenses		1,305		582		3,722		2,281		2,271
Income from operations		208		149		555		508		668
Income from equity investments		21		26		100		108		66
Other income (expenses), net		5		115		174		141		12
Interest expense, net		169		70		585		212		180
Income before provision for income taxes		65		220		244		545		566
Income tax expense (recovery)		(6)		21		(22)		93		113
Net income		71		199		266		452		453
Non-controlling interest in subsidiaries		1		7		11		25		20
Net income of Emera Incorporated		70		192		255		427		433
Preferred stock dividends		-		-		28		30		26
Net income attributable to common shareholders		70		192		227		397		407
After-tax mark-to-market gain (loss)		(34)		105		(248)		67		88
Adjusted net income attributable to common shareholders	$	104	$	87	$	475	$	330	$	319
Earnings per common share – basic	$	0.34	$	1.31	$	1.33	$	2.72	$	2.84
Earnings per common share – diluted	$	0.34	$	1.30	$	1.32	$	2.71	$	2.82
Adjusted earnings per common share – basic	$	0.51	$	0.59	$	2.77	$	2.26	$	2.23

Emera’s consolidated net income attributable to common shareholders decreased $122 million to $70 million in Q4 2016 compared to $192 million for the same period in 2015. For the year ended December 31, 2016, Emera’s consolidated net income attributable to common shareholders decreased $170 million to $227 million compared to $397 million in 2015.

Q4 Consolidated Income Statement Highlights

Operational Results

Income from operations increased $59 million to $208 million in Q4 2016 compared to $149 million in the same quarter in 2015 primarily due to the contribution of Emera Florida and New Mexico and lower acquisition costs compared to Q4 2015. These increases were partially offset by unfavourable mark-to-market changes of $60 million, decreased margin at the NEGG Facilities and Emera Energy’s decreased marketing and trading margin.

Details of operating revenues and operating expenses line item variances are described below:

Total operating revenues increased $782 million to $1,513 million in Q4 2016 compared to $731 million in Q4 2015 primarily due to:

· $881 million increase from Emera Florida and New Mexico;

· $78 million decrease from changes in mark-to-market impacts;

· $43 million decrease at the NEGG Facilities primarily due to lower hedged power prices.

Total operating expenses increased $723 million to $1,305 million in Q4 2016 compared to $582 million in Q4 2015, primarily due to the addition of expenses from Emera Florida and New Mexico, partially offset by decreased TECO Energy acquisition costs compared to Q4 2015.

Other income (expenses), net

Other income decreased $110 million to $5 million in Q4 2016 compared to $115 million in the same period in 2015. This was primarily due to mark-to-market gains on USD-denominated currency and forward contracts put in place to economically hedge the anticipated proceeds from the Debenture Offering for the pending TECO Energy acquisition in Q4 2015, and a $12 million pre-tax loss on the sale of APUC common shares in Q4 2016.

Interest expense, net

Interest expense, net increased $99 million in Q4 2016 to $169 million compared to $70 million in the same period in 2015, primarily due to financing related to the TECO Energy acquisition and interest expense from Emera Florida and New Mexico.

Income tax expense (recovery)

Income tax expense decreased $27 million to a $6 million recovery in Q4 2016 compared to a $21 million expense for the same period in 2015 primarily due to decreased income before provision for income taxes. This was partially offset by the non-deductible portion of mark-to-market losses on USD-denominated currency and forward contracts related to the TECO Energy acquisition in Q4 2015.

2016 Consolidated Income Statement and Operating Cash Flow Highlights

Operational Results

Income from operations increased $47 million to $555 million for the year ended December 31, 2016 compared to $508 million in 2015 primarily due to the contribution from Emera Florida and New Mexico. This is partially offset by higher mark-to-market losses of $144 million, increased costs related to the acquisition of TECO Energy, decreased margin at the NEGG Facilities, including recognizing a $20 million liability for state tax on natural gas sales made from November 2013 through March 2016, and Emera Energy’s decreased marketing and trading margin.

Total operating revenues increased $1,488 million to $4,277 million for the year ended December 31, 2016 compared to $2,789 million in the same period in 2015 primarily due to:

· $1,839 million increase from Emera Florida and New Mexico;

· $167 million decrease from changes in mark-to-market impacts;

· $84 million decrease at the New England Gas Generating Facilities primarily due to lower hedged power prices, partially offset by higher sales volumes as a result of fewer planned outage hours at the Bridgeport Facility in 2016;

· $61 million decrease at NSPI reflecting lower sales volumes due to weather and decreased fuel related electricity pricing;

· $27 million decrease in Emera Energy Services reflecting less favourable market conditions year-over-year, partially offset by higher Q1 2016 margin resulting from a stronger USD and growth in the volume of business.

Total operating expenses increased $1,441 million to $3,722 million for the year ended December 31, 2016 compared to $2,281 million in 2015. This was primarily due to the addition of expenses from Emera Florida and New Mexico and increased acquisition costs related to the TECO Energy acquisition, partially offset by decreased regulated fuel for generation and purchased power reflecting changes in commodity prices and lower sales volumes at NSPI, and changes in mark-to-market impacts in Emera Energy.

Other income (expenses), net

Other income increased $33 million to $174 million for the year ended December 31, 2016 compared to $141 million in the same period in 2015. This was primarily due to a $160 million pre-tax gain on the sale of 63 million common shares of APUC, a $63 million pre-tax gain on conversion of 12.9 million APUC subscription receipts and dividend equivalents, and a $53 million pre-tax gain on the BLPC SIF regulatory liability. This was partially offset by mark-to-market losses relating to the TECO Energy acquisition related USD-denominated currency and forward contracts and the 2015 gain on the sale of NWP.

Interest expense, net

Interest expense, net increased $373 million year-to-date in 2016 to $585 million compared to $212 million in 2015. This was primarily due to the new financing related to the TECO Energy acquisition, interest and the Beneficial Conversion Feature on the Convertible Debentures, as well as interest expense from Emera Florida and New Mexico.

Income tax expense (recovery)

Income tax expense decreased $115 million to a $22 million recovery for the year ended December 31, 2016 compared to a $93 million expense in 2015 primarily due to decreased income before provision for income taxes, the non-taxable portion of gains on APUC transactions and deferred income taxes on regulated income recorded as regulatory assets and liabilities. This was partially offset by the non-deductible portion of mark-to-market losses on USD-denominated currency and forward contracts related to the TECO Energy acquisition.

Net cash provided by operating activities

Net cash provided by operating activities in 2016 increased $379 million to $1,053 million compared to $674 million during the same period in 2015.

Cash from operations before changes in working capital increased by $143 million primarily due to the contribution from Emera Florida and New Mexico, partially offset by acquisition and financing costs related to the TECO Energy acquisition, and decreased margin at the NEGG Facilities.

Changes in working capital increased operating cash flows by $236 million primarily due to decreased fuel inventory and receivables as a result of lower sales at NSPI, favourable changes in cash collateral positions on derivative instruments at NSPI, the contribution from Emera Florida and New Mexico, and the timing of income tax payments at NSPI and Emera Energy Services.

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				Year ended
millions of US dollars		December 31				December 31
		2016		2015		2016		2015
Emera Florida and New Mexico	$	47	$	-	$	131	$	-
Emera Maine		9		4		36		36
Emera Caribbean		6		10		77		31
Emera Energy (1)		5		26		25		104
		67		40		269		171
Corporate and Other (2)		(29)		3		(59)		8
Total	$	38	$	43	$	210	$	179


Weighted average FX rate for period	$	1.32	$	1.33	$	1.32	$	1.27
(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.

OUTLOOK

The acquisition of TECO Energy has changed Emera’s business mix and enabled the Company to meet its strategic goal of having 75 to 85 per cent of its adjusted net income derived from regulated operations. The TECO Energy acquisition adds diversity to Emera’s operations, meets Emera’s strategic objective of expanding Emera’s operations to include gas distribution services, and expands Emera’s markets into higher growth regions. TECO Energy’s operations and opportunities align well with Emera’s strategy to invest in the transformation of electricity generation from higher to lower carbon intensity and providing cleaner and affordable energy solutions for customers. The addition of these regulated businesses may result in a material increase in earnings and cash flow as compared to the expected financial results prior to the acquisition.

Emera’s operations are affected by the US dollar relative to the Canadian dollar. The effect 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 in the future to a greater extent by movements in the US dollar relative to the Canadian dollar as a result of the TECO Energy acquisition.

Emera Florida and New Mexico

Emera Florida and New Mexico includes the following:

· TECO Energy, the parent company of the companies discussed below.

· TEC, which 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.

· PGS, a regulated gas distribution utility engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida.

· NMGC, a regulated gas distribution utility engaged in the purchase, transmission, distribution and sale of natural gas for residential, commercial and industrial customers in New Mexico.

· TECO Finance, a financing subsidiary of TECO Energy.

Tampa Electric

With nearly $7.0 billion USD of assets and approximately 736,000 customers, at December 31, 2016, Tampa Electric owned 4,730 megawatts (“MW”) of generating capacity, of which 60 per cent was natural gas-fired, 35 per cent was conventional coal-fired and 5 per cent coal and petroleum coke (“petcoke”) using integrated gasification combined cycle technology. Tampa Electric owns 2,140 kilometres of transmission facilities and 18,370 kilometres of distribution facilities.

Tampa Electric is regulated by the FPSC under a cost-of-service model, with rates established to recover prudently incurred costs of providing electricity service to customers and to provide an appropriate return consistent with investments of comparable risk to investors. Tampa Electric’s target regulated return on equity (“ROE”) range is currently 9.25 per cent to 11.25 per cent, on an allowed equity capital structure of 54 per cent. Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services, and accounting practices.

Tampa Electric has a fuel-recovery clause, approved by the FPSC, allowing recovery of actual fuel costs from customers through annual fuel rate adjustments. Differences between prudently incurred fuel costs for generation and purchased power and certain fuel-related costs (“Fuel Costs”) and amounts recovered from customers through electricity rates are deferred to a fuel clause regulatory asset or liability and recovered from or returned to customers in a subsequent year. Tampa Electric has an environmental cost recovery clause which allows the company to earn a return on investments in new facilities to comply with new environmental regulations and to recover the costs to operate and maintain these facilities. Through its conservation cost recovery clause, Tampa Electric also offers its customers a comprehensive array of residential and commercial programs that have enabled the company to meet its required demand side management goals, reduce weather-sensitive peak demand and conserve energy.

Florida utilities must obtain franchises to operate in certain municipalities. Tampa Electric has franchise agreements with 13 incorporated municipalities within its retail service area. These agreements have various expiration dates ranging from September 2017 through August 2043; all are expected to be renewed under similar terms and conditions.

Peoples Gas System

With more than $1.1 billion USD of assets and approximately 374,000 customers, the PGS system includes approximately 19,950 kilometres of natural gas mains and 11,265 kilometres of service lines. Gas mains are distribution lines that serve as a common source of supply for more than one service line. Annual natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) is 1.9 billion therms.

PGS is regulated by the FPSC under a cost-of-service model, with rates established to recover prudently incurred costs of providing gas distribution service to customers, and to provide an appropriate return consistent with investments of comparable risk to investors. In December 2016, PGS entered into a settlement agreement with the Office of Public Counsel regarding its filed depreciation study. On February 7, 2017, the FPSC approved the settlement agreement. The settlement agreement resulted in a $16 million USD annual reduction to PGS’ depreciation expense beginning in 2016 and accelerated the amortization of PGS’ regulatory asset associated with the environmental liability for current and future remediation costs related to former Manufactured Gas Plant (“MGP”) sites. The settlement requires that at least $32 million USD of MGP amortization be expensed for the period 2016 through 2020 and of that at least $21 million USD to occur over 2016 and 2017. In 2016, PGS recorded $16 million USD of MGP amortization acceleration and as a result offset the $16 million USD reduction in 2016 depreciation expense. Absent any rate case filing, through 2020, the bottom of the allowed ROE range for PGS will be decreased 50 basis points to 9.25 per cent and the top of the range will remain unchanged at 11.75 per cent. The ROE of 10.75 per cent will continue to be used for the calculation of the return on investments for clauses. No change in customer rates resulted from this settlement agreement.

New Mexico Gas Company, Inc.

With over $0.8 billion USD of assets and approximately 522,000 customers, NMGC serves about 60 per cent of the state’s population in 23 of New Mexico’s 33 counties. NMGC’s system includes approximately 2,600 kilometres of transmission lines and 16,400 kilometres of mains. Annual natural gas throughput is approximately 775 million therms. NMGC’s largest concentration of customers (approximately 360,000) is in the region known as the Central Rio Grande Corridor, which includes the communities of Albuquerque, Belen, Rio Rancho and Santa Fe.

NMGC is regulated by the NMPRC under a cost-of-service model, with rates established to recover prudently incurred costs of providing gas distribution service to customers, and to provide an appropriate return consistent with investments of comparable risk to investors. NMGC’s rates were established in a 2012 rate case settlement and are frozen until December 31, 2017 per the June 2016 NMPRC order ( the “Order”) approving Emera’s acquisition of TECO Energy. Under the Order, NMGC will also provide customer credits of $4 million USD annually through June 30, 2018.

Emera Florida and New Mexico Outlook

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 of operating costs, the approved recovery of regulatory deferrals, 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 an additional 460 MW of generating capacity and invests in the related transmission system improvements needed to support the additional generation.

NMGC expects earnings to be consistent with prior years. Customer growth rates are expected to be slightly higher in 2017 than in 2016, reflecting expectations for housing starts and new connections. Assuming normal weather, sales growth is expected to be consistent with customer growth and costs will increase slightly.

In 2017, Emera Florida and New Mexico expects to invest approximately $645 million USD in capital projects compared to $795 million USD in 2016. The 2016 capital expenditures included approximately $135 million USD for the Polk Power Station conversion 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. The 2017 capital expenditures include projects to support normal system reliability and growth at Tampa Electric, PGS and NMGC. Tampa Electric includes 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 photo voltaic projects. PGS will make investments to expand the system and support customer growth, including high sales volume compressed natural gas fueling stations, and continue with replacement of 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 and is the primary electricity supplier in Nova Scotia, Canada. NSPI has $4.8 billion of assets and provides electricity generation, transmission and distribution services to approximately 511,000 customers. The Company owns 2,487 MW of generating capacity, of which approximately 43 per cent is coal-fired; 29 per cent is natural gas and/or oil; 19 per cent is hydro and wind; 7 per cent is petcoke and 2 per cent is biomass-fueled generation. In addition, NSPI has contracts to purchase renewable energy from independent power producers (“IPP”). These IPPs own 530 MW of capacity. This is expected to increase to 547 MW of capacity in 2017. IPP generation includes wind, tidal, biogas and biomass-fueled generation. NSPI owns approximately 5,000 kilometres of transmission facilities and 27,000 kilometres of distribution facilities.

NSPI is a public utility as defined in the Public Utilities Act (Nova Scotia) (“Act”) and is subject to regulation under the Act by the UARB. The Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings from time to time at its or the UARB’s request.

NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. NSPI’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 40 per cent.

NSPI has a Fuel Adjustment Mechanism (“FAM”), approved by the UARB, allowing NSPI to recover fluctuating fuel costs from customers through annual fuel rate adjustments. Differences between Fuel Costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year.

In December 2015, the UARB approved NSPI’s 2016 fuel rates and its recovery of prior period unrecovered Fuel Costs. The approved customer rates reset the base cost of fuel rates for 2016. In addition, they approved a $12 million recovery of prior years’ unrecovered Fuel Costs in 2016. This resulted in a combined average rate decrease for customers of approximately 1 per cent in 2016. The rates and recovery of these costs began on January 1, 2016.

On December 18, 2015, the Province enacted the Electricity Plan Implementation (2015) Act, (“Electricity Plan Act”), which required NSPI to file a three-year stability plan for Fuel Costs and a General Rate Application (“GRA”) for non-fuel costs if required by April 30, 2016. On March 7, 2016, NSPI announced that it would not file a GRA related to non-fuel electricity rates for the 2017 to 2019 period and NSPI filed the stability plan for Fuel Costs with the UARB for 2017 through 2019.

On July 19, 2016, the UARB approved a Consensus Agreement between NSPI and customer representatives related to the Rate Stability Plan for Fuel Costs for 2017 through 2019. Subsequently, certain customer representatives requested changes resulting in amended rates that were approved by the UARB on November 15, 2016 and results in an average annual rate increase of 1.5 per cent for each of these three years.

On December 12, 2016, the UARB approved the refund of over-recovered Fuel Costs in 2016 to customers. The over-recovered Fuel Costs balance at the end of 2016 will be refunded to customers through a one-time credit on their bills prior to April 30, 2017 and will be based on individual electricity usage in 2016. The balance to be refunded to customers is approximately $36 million.

Although the market in Nova Scotia is otherwise mature, the transformation of energy supply to lower emission sources has driven organic growth within NSPI as new investments have been made in renewable generation and system reliability projects.

Over the past several years, the requirement to reduce Nova Scotia’s reliance upon high carbon and greenhouse gas emitting sources of energy has resulted in NSPI making a significant investment in renewable energy sources and purchasing third party renewable energy. In December 2015, the Electricity Plan Act was enacted by the Province of Nova Scotia with a goal of providing rate stability and predictability for customers for the 2017 through 2019 period. In accordance with the Electricity Plan Act, NSPI filed a three-year stability plan for Fuel Costs in Q1 2016 with the UARB. NSPI also announced that it would not file a GRA for non-fuel costs for the 2017 through 2019 period. This was a result of NSPI continuing to work towards rate stability for customers through a focused effort on operating costs, productivity levels and service improvements.

In 2015, NSPI filed an application with the UARB for the approval of a market framework to enable independent renewable energy producers licensed by the UARB to sell directly to retail customers. The UARB issued a decision in 2016 approving the Company’s proposed framework. Potential retailers must apply to the UARB for approval of a license to sell low-impact renewable electricity generated in Nova Scotia. Licensed retailers who enter this retail market must pay tariffs to use NSPI’s systems for delivering their renewable energy, to ensure the supply of electricity to their customers and to ensure NSPI customers do not bear the cost of this new market.

NSPI is subject to environmental regulations as set by both the Province of Nova Scotia and the Government of Canada. The Company continues to work with officials at both of these levels of government to comply with these regulations in an integrated way, maximizing efficiency of emission control measures.

In November 2014, the Government of Canada and the Province of Nova Scotia entered into a Greenhouse gas (“GHG”) emission regulations equivalency agreement, which allows NSPI to achieve compliance with federal GHG emissions regulations by meeting provincial legislative and regulatory requirements as they are deemed to be equivalent.

In March 2016, Canada’s First Ministers issued the “Vancouver Declaration” on clean growth and climate change. First Ministers agreed to develop a Pan-Canadian Framework and implement it by early 2017. Four working groups, comprised of federal, provincial and territorial officials were established to provide recommendations and research to the Federal government. NSPI provided input into this process through the Nova Scotia government, the Government of Canada and directly to the working groups through the submission of a discussion paper.

In October 2016, the Government of Canada announced that the pan-Canadian framework would include a national price on carbon component, implemented by 2018 through either a carbon tax or a cap and trade system, applicable in each province except those which enact their own comparable carbon pricing mechanism by that time.

On November 21, 2016, the Government of Canada announced a second component of the plan would include an accelerated plan to phase out coal in Canada, to transition Canada's electricity system towards 90 per cent non-emitting generation sources by 2030.

On the same day the Province of Nova Scotia and the Government of Canada made two announcements regarding Nova Scotia’s participation in the Pan-Canadian plan:

Carbon pricing component

An agreement in principle covering the carbon component had been reached and will be governed on following principles:

· Nova Scotia will adopt a province-wide 2030 emissions reduction target equal or greater than Canada’s target of a 30 per cent reduction from 2005 levels by 2030;

· Nova Scotia will implement an agreed upon cap and trade system; and

· The Province of Nova Scotia and the Government of Canada will agree upon a methodology and scenarios for the modeling of projected greenhouse gas emissions to support the development of Nova Scotia’s cap and trade system.

Accelerated phase out of coal component

Nova Scotia and the Government of Canada will establish a new equivalency agreement that will enable the province to move directly from fossil fuels to clean energy sources and enable NSPI’s coal-fired plants to operate at some capacity beyond 2030.

On December 9, 2016 the Government of Canada and eight provinces (including Nova Scotia) signed the Pan Canadian Framework on Clean Growth and Climate Change. The Government of Canada has committed to ensuring that the provinces and territories have the flexibility to design their own policies and programs to meet emission-reduction targets, supported by federal investments in infrastructure, specific emission-reduction opportunities and clean technologies. Details under the agreements are expected to be finalized by the end of 2017. NSPI anticipates that any costs prudently incurred to achieve the legislated reductions would be recoverable from customers under NSPI’s regulatory framework. NSPI will continue to work with both the Province of Nova Scotia and the Government of Canada as the details of the agreements are finalized and to advance solutions that are in the best interest of customers.

The Government of Canada has indicated their intention to resume discussions regarding Base Level Industrial Emission Requirements (”BLIER”s) for sulphur dioxide and nitrogen dioxide and have outlined their intention to develop a Clean Energy Standard for natural gas and possibly diesel. The details of both processes are not yet known. NSPI will participate in these processes.

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, demand and generation load, weather, the approved recovery of regulatory deferrals 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.

In 2017, NSPI expects to invest approximately $398 million, including AFUDC, in capital projects compared to $309 million in 2015. This increase is primarily driven by increased spending on information technology projects and Maritime Link related Transmission projects.

Emera Maine

Emera Maine is a transmission and distribution (“T&D”) electric utility with assets of approximately $1.1 billion serving approximately 157,000 customers in the State of Maine in the United States. Effective January 1, 2014, Bangor Hydro Electric Company (“Bangor Hydro”) and Maine Public Service Company (“MPS”) merged, becoming Emera Maine.

Electricity generation is deregulated in Maine, and several suppliers compete to provide customers with the energy delivered through Emera Maine’s T&D networks. Emera Maine owns and operates approximately 1,800 kilometres of transmission facilities and 15,000 kilometres of distribution facilities.

Approximately 52 per cent of Emera Maine’s electric revenue represents distribution operations, 35 per cent is associated with local transmission operations and 13 per cent relates to stranded cost recoveries. The rates for each element are established in distinct regulatory proceedings.

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, load (including the effects of weather), and the timing and amount of capital expenditures.

Distribution Operations

Emera Maine’s distribution businesses operate under a traditional cost-of-service regulatory structure, and distribution rates are set by the MPUC. Prior to December 21, 2016 the ROE upon which rates are set was 9.55 per cent with a common equity component of 49 per cent. On December 21, 2016, Emera Maine’s distribution rates increased 3.75 per cent which was based on a 9 per cent ROE and a common equity component of 49 per cent.

Transmission Operations

There are two transmission districts in Emera Maine, corresponding to the service territories of the two pre-merger entities.

Bangor Hydro District

Local transmission rates for Bangor Hydro District (the franchise electric service territory associated with the former Bangor Hydro Electric Company in portions of the Maine counties of Penobscot, Hancock, Washington, Waldo, Piscataquis, and Aroostook) are regulated by the FERC and set annually on June 1, based on a formula utilizing prior year actual transmission investments, adjusted for current year forecasted transmission investments. The common equity component is based upon the prior calendar year actual average balances. On October 16, 2014, FERC issued an order in response to a challenge the ISO-New England (“ISO-NE”) Open Access Transmission Tariff base ROE compliant reducing the ROE from 11.14 per cent to 10.57 per cent for the period of October 1, 2011 to December 31, 2012 and set 10.57 per cent as the ROE rate effective October 16, 2014. The October 16, 2014 FERC order is currently under appeal in the DC Circuit Court and there are three additional pending complaints filed with the FERC to challenge the ISO-New England (“ISO-NE”) Open Access Transmission Tariff allowed base ROE.

Effective June 1, 2016, the average retail transmission rates for the Bangor Hydro District increased by approximately 2 per cent in connection with its annual transmission formula rate filing (2015 – increased by 21 per cent). The increase is associated primarily with the recovery of increased transmission plant in service and as a result the prior year tariff rate including a rate refund related to the aforementioned FERC ROE decision.

The Bangor Hydro District’s bulk transmission assets are managed by ISO-NE as part of a region-wide pool of assets. ISO-NE manages the region’s bulk power generation and transmission systems and administers the open access transmission tariff. Currently, the Bangor Hydro District along with all other participating transmission providers, recovers the full cost of service for its transmission assets from the customers of participating transmission providers in New England, based on a regional FERC approved formula that is updated June 1 each year. This formula is based on prior year regionally funded transmission investments, adjusted for current year forecasted investments. The participating transmission providers are also required to contribute to the cost of service of such transmission assets on a ratable basis according to the proportion of the total New England load that their customers represent. The common equity component is based upon the prior calendar year average balances. On October 16, 2014, FERC issued an order in response to a challenge the ISO-NE Open Access Transmission Tariff reducing Bangor Hydro District’s ROE for these transmission investments which ranged from 11.64 per cent up to 12.64 per cent to 11.07 per cent up to 11.74 per cent. There are currently three pending aforementioned complaints filed with FERC.

On June 1, 2016, Bangor District’s regionally recoverable transmission investments and expenses increased by 9 per cent (2015 – decreased by 6 per cent).

As at December 31, 2016, the Company had accrued $5 million pre-tax ($4 million USD) associated with the first two pending FERC ROE complaints (2015 – $7 million or $5 million USD). No reserve has been recorded for the third pending complaint as the outcome is considered uncertain. Refunds for the first FERC ROE complaint that FERC issued a ruling upon on October 16, 2014, were made to customers over a one-year period which began with the June 1, 2015 rate change and ended May 31, 2016 resulting in the reduction to the accrued reserve.

MPS District

Local transmission rates for MPS District’s (the franchise electric service territory associated with the former Maine Public Service Company in the Maine counties of Aroostook and a portion of Penobscot) are regulated by the FERC and are set annually on June 1 for wholesale and July 1 for retail customers, based on a formula utilizing prior year actual transmission investments and expenses, adjusted for current year forecasted investments. The current ROE for transmission operations is 10.2 per cent. The common equity component is based upon the prior calendar year actual average balances.

Effective June 1, 2016 the transmission rates for the MPS District increased by approximately 43 per cent for wholesale customers (2015 – decreased by 1 per cent) and on July 1, 2016 increased by 36 per cent for retail customers (2015 – decreased by 22 per cent) in connection with its annual transmission formula rate filing. Transmission rates in the MPS District for retail and wholesale customers can vary from year to year due to changes in the amount of export sales revenue received, the amount of transmission plant in service, the amount of operating cost to maintain the transmission system, and the approved ROE. The increase in the retail and wholesale transmission rates in 2016 is due to the increased investment of plant in service required to replace aging infrastructure. On April 1, 2015, as amended May 1, 2015, Emera Maine filed a revised Maine Public District (MPD) Open Access Transmission Tariff formula which was challenged by the Maine Customer Group and is currently subject to settlement discussions.

The MPS District electric service territory is not connected to the New England bulk power system and it is not a member of ISO-NE. As a result, MPS District is not a party to the previously discussed ROE complaints at the FERC.

Stranded Cost Recoveries

Stranded cost recoveries in Maine are set by the MPUC. Electric utilities are permitted to recover all prudently incurred stranded costs resulting from the restructuring of the industry in 2000 that could not be mitigated or that arose as a result of rate and accounting orders issued by the MPUC. Unlike transmission and distribution operational assets, which are generally sustained with new investment, the net stranded cost regulatory asset pool diminishes over time as elements are amortized through charges to income and recovered through rates. Generally, regulatory rates to recover stranded costs are set every three years, determined under a traditional cost-of-service approach and are fully recoverable. Each year on July 1, stranded cost rates are adjusted to reflect recovery of cost deferrals for the prior stranded costs rate year under the full recovery mechanism, as well as factor in any new stranded cost information.

Stranded cost recovery rates for Bangor Hydro District are set on a 5.9 per cent ROE, with a common equity component of 48 per cent. For MPS District, rates are set on a 6.75 per cent ROE with a common equity component of 48 per cent.

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.

Emera Maine expects to spend approximately $70 million USD (2016 – $69 million USD actual) in capital projects in 2017.

Emera Caribbean

Emera Caribbean includes the following consolidated and non-consolidated investments:

Consolidated Investments

· 100.0 per cent (December 31, 2015 – 95.5 per cent) investment in ECI and its wholly owned subsidiary BLPC, a vertically integrated utility that is the provider of electricity in Barbados. BLPC serves 126,000 customers and is regulated by the Fair Trading Commission, Barbados. BLPC owns 239 MW of oil-fired generation, 150 kilometres of transmission facilities and 2,800 kilometres of distribution facilities. BLPC’s approved regulated return on rate base for 2016 is 10.0 per cent. A fuel pass-through mechanism provides the opportunity to recover all fuel costs in a timely manner. On February 24, 2016, Emera completed the purchase of the remaining 4.5 per cent of common shares from minority shareholders of ECI.

· 50.0 per cent direct and 30.4 per cent indirect interest (through a 60.7 per cent interest in ICD Utilities Limited (“ICDU”)) in GBPC, which is a vertically integrated utility and a sole provider of electricity on Grand Bahama Island. GBPC serves 19,000 customers and is regulated by the GBPA. GBPC owns 98 MW of oil-fired generation, 138 kilometres of transmission facilities and 860 kilometres of distribution facilities. Effective February 1, 2016, the GBPA approved GBPC’s regulated return on rate base of 8.8 per cent applicable for the 2016 through 2018 period. A fuel pass-through mechanism provides the opportunity to recover all fuel costs in a timely manner. In December 2016, the GBPA approved the all-in rates for electricity (fuel and base rates) for the 2017 to 2021 periods to be held consistent with the 2016 rates. The approval includes the recovery of Hurricane Matthew related costs (as discussed below).

· 51.9 per cent (December 31, 2015 – 49.6 per cent indirect controlling interest), through ECI, in Domlec, an integrated utility on the island of Dominica. Domlec serves 36,000 customers and is regulated by the IRC. Domlec owns 20 MW of oil-fired generation, 7 MW of hydro production, 497 kilometres of transmission facilities and 716 kilometres of distribution facilities. Domlec’s approved allowable regulated return on rate base for 2016 is 15.0 per cent. A fuel pass-through mechanism provides the opportunity to recover substantially all fuel costs in a timely manner.

Equity Investment

· 19.1 per cent (December 31, 2015 – 18.2 per cent indirect interest), through ECI, in Lucelec, a vertically integrated regulated electric utility on the island of St. Lucia. Lucelec is regulated by the National Utility Regulatory Commission (NURC) which was established in 2016 to regulate utility services in St Lucia. Lucelec was previously regulated by the Government of St Lucia. The investment in Lucelec is accounted for on the equity basis.

On December 7, 2016, Emera sold its 50.0 per cent direct and 30.4 per cent indirect interest in GBPC to ECI. The transaction simplifies the Emera Caribbean reporting structure and allows the Caribbean to be managed from a single entity. It also allows for greater cooperation between the Caribbean utilities, including further sharing of skills and increased efficiencies that can result in benefits to customers.

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

The Barbados economy is predominantly driven by tourism and is forecasted to grow modestly in 2017. However, the April 2016 credit downgrades by Moody's (and more recently S&P in September 2016) of the long-term foreign and local currency sovereign ratings of Barbados, highlights the lack of market confidence that economic recovery will be sustained. The economy of Grand Bahama is generally correlated to the United States economy. On December 20, 2016, S&P lowered its foreign and local

currency sovereign credit ratings on The Commonwealth of The Bahamas. This downgrade was driven by weak economic growth and spending pressure in The Bahamas as a result Hurricane Matthew.

In October 2016, the island of Grand Bahama took a direct hit from Hurricane Matthew. Property damage on the island was extensive. GBPC’s generation and substation infrastructure weathered the storm well, however over 2,100 transmission and distribution poles and related conduit were damaged or destroyed, as were many connections to customer homes. Restoration efforts have been completed with the support of other Emera affiliates. Post hurricane load is down approximately 10 per cent as compared to normal expectations; however, management anticipates that demand will recover to pre-storm levels by 2018.

Emera Caribbean has recorded $28 million USD of restoration costs associated with Hurricane Matthew with no impact to net income. $21 million USD has been recorded as a regulated asset amortized over five years and $7 million USD recorded as property, plant and equipment depreciating at an average 27 years. Both assets are included in rate base. In December 2016, the GBPA has approved the full recovery of the storm restoration costs in this manner.

In addition, the GBPA approved that over a 5 year period, 2017 to 2021, the all-in rate for electricity (fuel and base rates) will be held at 2016 levels. This is achievable as the company’s fuel costs over this period are forecasted to decrease. Fuel costs are managed through a fuel hedging program which allows predictability of these costs. Any over recovery of fuel costs during this period will be applied to the Hurricane Matthew regulatory deferral, until such time as the deferral is recovered. Should GBPC recover funds in excess of the Hurricane Matthew regulatory deferral, the excess will be placed in a new storm reserve. If the Hurricane Matthew deferral is not fully recovered at the end of 5 years GBPC will have the opportunity to request recovery from customers in future rates.

With oil being the predominant fuel source for generation of electricity in the Caribbean, and with fuel costs directly passed through electricity rates to customers, any change in global fuel prices and resulting change in fuel costs will result in a similar change in customer rates and reported revenues. GBPC has implemented fuel hedging strategies to provide increased certainty to customers as to fuel costs and electricity rates. In support of reducing carbon emissions and exposure to carbon based fuel sources, BLPC recently commissioned a 10 megawatt solar facility in Barbados, which became operational in Q2 2016. Additional renewable energy generation investments are being explored.

Overall, Emera Caribbean 2017 earnings are expected to be slightly less than prior years, excluding the impact of the Q2 2016 gain recognized on the SIF 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 $109 million USD in capital programs in 2017 (2016 - $49 million USD actual). This increase is due to spending on renewable, advanced metering infrastructure and street lighting projects.

Emera Energy

Emera Energy includes the following:

· 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 with 1,435 megawatts (“MW”) of total capacity.

· Equity investment in a 50.0 per cent joint venture ownership of Bear Swamp, a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts. The investment in Bear Swamp is accounted for on an equity basis.

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.

Planned investment by the industry in gas transportation infrastructure within the northeast United States over the next few years could reduce the degree of volatility recently experienced in the market, all other things being equal.

In addition to capitalizing on volatility-driven market opportunities, Emera Energy Services expects to continue to grow organically by building market share through strong customer service, optimizing Emera Energy’s portfolio to build on power margin, and expanding its geographic reach to adjacent markets, including the Mid-Atlantic region.

The business is generally expected to deliver 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 performance are key success factors.

Adjusted earnings from Emera Energy’s generating assets in 2017 are expected to be higher than 2016, reflecting higher capacity prices (see table below) that come into effect mid-year 2017. Emera Energy expects this increase to be partially offset by lower market spark spreads and reduced hedging opportunities year-over-year.

Equity Investments

Bear Swamp’s adjusted earnings are expected to be higher in 2017 mainly due to higher capacity revenues and fewer planned maintenance outages as compared to 2016.

Capacity Payment

In addition to energy margins and ancillary revenue, the NEGG Facilities and Bear Swamp earn revenue from capacity payments through the forward capacity market (“FCM”), the annual reconfiguration capacity market and the monthly reconfiguration capacity market. Prices for the FCM, the largest of the components, are determined through an auction process held annually, three years in advance, thus providing revenue visibility to 2021, presuming the facilities continue to be available to support their capacity obligations. Details of pricing and estimated revenues are outlined in the table below for the NEGG Facilities, and Emera Energy’s 50.0 per cent interest in Bear Swamp.

Forward Capacity Auction (“FCA”) Year	Clearing Price in $/kW-month (in USD)	Approximate Estimated Annual Capacity Revenue (in USD) (1)
FCA7 (June 2016 to May 2017)	$3.15	$40 million
FCA8 (June 2017 to May 2018)	$7.025	$100 million
FCA9 (June 2018 to May 2019)	$9.55 and $11.08 (1)	$145 million
FCA 10 (June 2019 to May 2020)	$7.03	$106 million
FCA 11 (June 2020 to May 2021)	$5.297	$80 million

(1) $11.08 was awarded for the Southeast Massachusetts/Rhode Island zone only and, as such, applies only to Tiverton.

In 2017, Emera Energy expects to invest approximately $46 million (2016 – $39 million actual) in capital projects related to its generating assets in order to further improve reliability and increase plant 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, internal audit, 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 the following consolidated and non-consolidated investments:

Consolidated Investments

· Brunswick Pipeline is an NEB regulated, 145-kilometre pipeline that transports natural gas from Saint John, New Brunswick, to markets in the northeastern United States. The pipeline is contracted under a 25-year firm service agreement with Repsol Energy Canada that expires in 2034. The service agreement is accounted for as a direct financing lease.

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

· Emera Utility Services (“EUS”) is a utility services contractor primarily operating in Atlantic Canada.

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

· Emera US Finance LP is a wholly owned financing subsidiary of Emera.

Non-consolidated investments

· Emera’s 100 per cent investment in ENL, which holds investments in the following:

· Emera’s 100 per cent investment in NSPML, a $1.56 billion transmission project, including two 170-kilometre subsea cables, connecting the island of Newfoundland and Nova Scotia. The investment in NSPML is accounted for on the equity basis with equity earnings equal to the return on equity component of AFUDC, which will continue until the Maritime Link Project goes into service. This project is scheduled to be completed in Q4 2017 and go into service by January 1, 2018.

· Emera’s 62.7 per cent (December 31, 2015 - 55.1 per cent) investment in the partnership capital of LIL, a $3.4 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. 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 completion and 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. The investment in LIL is accounted for on the equity basis. Nalcor Energy has indicated that the project will be in service in Q2 2018.

· Emera’s 12.9 per cent investment in M&NP.

· On December 8, 2016 Emera sold the Company’s remaining 4.7 per cent (December 31, 2015 – 19.6 per cent) investment in APUC. APUC is a diversified generation, transmission and distribution utility traded on the Toronto Stock Exchange (“TSX”) under the symbol “AQN”. On May 24, 2016, Emera completed the sale of 50.1 million common shares of APUC, representing approximately 19.3 per cent of APUC's issued and outstanding common shares. On June 30, 2016, Emera exchanged 12.9 million APUC subscription receipts and dividend equivalents into 12.9 million APUC common shares. The resulting gains on the sale of the investment and conversion of subscription receipts and dividend equivalents into common shares are recorded in “Other income (expenses), net” on the Consolidated Statements of Income. APUC was accounted for on the equity basis, and Emera’s proportioned share of APUC’s earnings was included in the Consolidated Statements of Income until its partial sale on May 24, 2016. Since that time and up until the disposition on December 8, 2016, the common shares of APUC were included in Investment securities on the Consolidated Balance Sheets, with dividend income recorded in Other income (expenses), net on the Consolidated Statements of Income.

Corporate and Other includes corporate related costs which are dependent on the level of business development activity and acquisition related initiatives. This segment includes corporate financing costs, AFUDC earnings as a result of equity investments in the Maritime Link Project and the Labrador-Island Link, project-based construction services activity by Emera Utility Services and capital lease accounting treatment of the Emera Brunswick Pipeline, which yields declining earnings over the life of the asset. In 2015 this segment also included the equity earnings from the company’s investment in APUC.

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 APUC. This is partially offset by higher OM&G costs in 2016 related to the TECO Energy acquisition and lower forecasted 2017 interest costs as a result of permanent financing in place for the TECO Energy acquisition.

Corporate and Other, excluding ENL as discussed below, expects to spend approximately $13 million on property, plant and equipment in 2017 (2016 - $7 million actual).

ENL

NSP Maritime Link Inc. (“NSPML”)

Through its subsidiary, NSP Maritime Link Inc., ENL had invested at December 31, 2016, $1.18 billion of equity, debt and working capital, including $132 million of AFUDC, in the development of the Maritime Link Project. Project to date, ENL has invested $315 million in equity, comprised of $261 million in equity contributed and $54 million of accumulated retained earnings, with the remaining being funded with working capital and debt. The debt has been guaranteed by the Government of Canada. AFUDC on invested equity is being capitalized at an annual rate of 9 per cent.

ENL’s future earnings contribution from the Maritime Link Project will be affected by the amount and timing of capital expenditures for construction activities, which will determine the component of costs to be funded by equity. Proceeds from the federally guaranteed debt financing (completed in 2014) were used to fund project costs until the debt to equity ratio reached 70 to 30 per cent, respectively, which occurred in Q4 2015. From that point forward, project costs are being funded with debt and equity at a 70 to 30 per cent ratio, with equity contributions of $106 million made in 2016.

In February 2015, ENL entered into a contract with Abengoa S.A., a global Spanish energy company, for the transmission line construction on the Maritime Link Project. Abengoa S.A. has been under ongoing global creditor protection proceedings that hampered the company’s ability to perform its work. As a result of Abengoa’s failure to perform, NSPML notified Abengoa that it was in default of its contract. NSPML has terminated its contract with Abengoa.

In July 2016 NSPML announced EUS-Rokstad, a joint venture between EUS and Rokstad Power, would complete construction of the high voltage direct current components of the transmission line. As part of the agreement entered into with NSPML, EUS has responsibility for approximately 50 kilometres of transmission line in Nova Scotia and Rokstad has responsibility for approximately 140 kilometres of transmission line on the island of Newfoundland. EUS and Rokstad Power are jointly and severally liable for completion of the project.

Maritime Link Project forecasted equity contributions for 2017 are $181 million, resulting in total equity contributions for the Project estimated to be $442 million.

Labrador Island Link (“LIL”)

ENL is a limited partner with Nalcor Energy in LIL, with project costs currently estimated at $3.4 billion. As at December 31, 2016, ENL had invested $400 million, comprised of $355 million in equity and $45 million of accumulated equity earnings in LIL. Equity earnings are recorded based on an annual rate of 8.5 per cent of the equity invested (8.8 per cent prior to July 1, 2016). The ROE is approved by the Newfoundland and Labrador Board of Commissioners of Public Utilities (“NLPUB”). Future earnings are dependent on the amount and timing of additional equity investments and the approved ROE. Total equity contributions for LIL in 2016 are $168 million.

LIL 2017 equity contributions by Emera are forecasted to be $55 million. The total equity contribution by Emera for the project is estimated to be approximately $600 million.

Both the NSPML and LIL investments are recorded as “Investments subject to significant influence” on Emera’s Consolidated Balance Sheets.

Throughout construction of both ML and LIL, equity earnings in ENL are a result of AFUDC on the related projects. Therefore, 2017 equity earnings contribution from ENL will be higher in 2017 than 2016 as a result of Emera’s continued equity contribution while under construction resulting in higher equity levels and therefore higher AFUDC earnings.

Consolidated Balance Sheets Highlights

Significant changes in the consolidated balance sheets between December 31, 2015 and December 31, 2016 include:

			Increase (Decrease) Due to		Other
			Emera Florida		Increase
millions of Canadian dollars	Total		and New Mexico		(Decrease)		Explanation of Other Increase/Decrease
Assets
Cash and cash equivalents	$	(669)	$	37	$	(706)	Decreased primarily due to the cash paid for the acquisition of TECO Energy
Receivables, net		436		350		86	Increased primarily due to higher commodity prices and increased volumes at Emera Energy
Income taxes receivable, net of income taxes payable (current and long-term)		9		(23)		32	Increased primarily due to expected recovery of prior year income taxes at Emera Energy
Inventory		158		233		(75)	Decreased primarily due to lower fuel inventory volumes as a result of consumption and lower commodity pricing at NSPI
Derivative instruments (current and long-term)		(142)		22		(164)	Decreased primarily due to settlement and change in gas and power contracts at Emera Energy and mark-to-market adjustment on foreign exchange forward contract in Emera Corporate
Regulatory assets (current and long-term)		623		590		33	Increased primarily due to the regulatory offset to deferred income taxes at Brunswick Pipeline and ENL
Property, plant and equipment, net of accumulated depreciation		10,821		10,728		93	Increased primarily due to the favourable effect of a stronger CAD on the translation of Emera's foreign subsidiaries, increased capital expenditures at NSPI, partially offset by depreciation
Investments subject to significant influence		(198)		-		(198)	Decreased primarily due to the sale of APUC common shares, partially offset by increased investment in LIL and NSPML. See discussion under "Significant Items Affecting Earnings"
Investment securities (current and long-term)		(68)		-		(68)	Decreased primarily due to the withdrawal of investments in the SIF
Goodwill		5,949		-		5,949	Increased due to the TECO Energy acquisition
Other assets (current and long-term)		84		108		(24)	Decreased primarily due to lower initial value of AMA's and the amortization of transportation assets
Liabilities and Equity
Short-term debt and long-term debt (including current portion)		11,680		5,635		6,045	Increased primarily due to the issuance of long-term debt related to the TECO Energy acquisition and issuance of debt in the Caribbean
Accounts payable		848		692		156	Increased primarily due to higher commodity prices at Emera Energy and increased cash collateral position on derivative instruments at NSPI
Deferred income tax liabilities, net of deferred income tax assets		817		905		(88)	Decreased primarily due to additional tax losses and the change in derivative instruments
Convertible debentures		(673)		-		(673)	Decreased due to the conversion of the majority of the convertible debentures related to the TECO Energy acquisition into common shares
Derivative instruments (current and long-term)		30		-		30	Increased primarily due to changes in existing positions on AMA's and long-term natural gas contracts, partially offset by settlements of natural gas and power contracts at Emera Energy and commodity contracts at NSPI and GBPC
Regulatory liabilities (current and long-term)		1,174		1,173		1	The increase in NSPI's regulatory liability due to the increase in the FAM regulatory liability was partially offset by the reduction of SIF BLPC regulatory liability
Pension and post-retirement liabilities (current and long-term)		417		396		21	Increased primarily due to a reduction in the discount rate at NSPI
Other liabilities (current and long-term)		244		218		26	Increased primarily due to the timing of interest payments on the long-term debt related to the TECO Energy acquisition
Common stock		2,581		-		2,581	Increased primarily due to the conversion of the convertible debentures into common shares, the Q4 2016 issuance of 7.6 million common shares, and issuance of common stock for the dividend reinvestment program
Contributed surplus		46		-		46	Increased primarily due to the beneficial conversion feature discount on the convertible debentures related to the TECO Energy acquisition
Accumulated other comprehensive income		(31)		99		(130)	Decreased primarily due to the effect of a stronger CAD on the translation of Emera's foreign subsidiaries and the adjustment to AOCI due to the sale of APUC common shares
Retained earnings		(92)		172		(264)	Decreased due to dividends paid in excess of net income
Non-controlling interest in subsidiaries		(22)		-		(22)	Decreased due to increased ownership by Emera in ECI

Developments

Conversion of Convertible Debentures

As at December 31, 2016, 52 million common shares of Emera were issued relating to the conversion of the Convertible Debentures, representing conversion into common shares of 99.6 per cent of the outstanding convertible debentures.

Increase in Common Dividend

On July 4, 2016, Emera’s Board of Directors announced an increase in the annual common share dividend rate from $1.90 to $2.09. The first payment was effective August 15, 2016. Emera also extended its eight per cent annual dividend growth target from 2019 to 2020.

Acquisition of TECO Energy

On July 1, 2016, Emera acquired all of the outstanding common shares of TECO Energy for $27.55 USD per common share. The net cash purchase price totaled $8.4 billion ($6.5 billion USD), with an aggregate purchase price of $13.9 billion ($10.7 billion USD), including the assumption on closing of $5.5 billion ($4.2 billion USD) in US debt. The net cash purchase price was financed through: (i) $728 million ($560

million USD) related to the first instalment of convertible debentures represented by instalment receipts issued in 2015, $1.56 billion ($1.2 billion USD) fixed-to-floating subordinated notes, $500 million in Canadian long-term debt and $4.2 billion ($3.25 billion USD) in US long-term senior unsecured notes; (ii) available cash on hand; and (iii) drawings of $1.4 billion ($1.1 billion USD) on the Company’s acquisition credit facility. Total proceeds of the debt, not otherwise required to complete the Acquisition, have been used for general corporate purposes.

On August 2, 2016, the Convertible Debentures Final Instalment Date, Emera obtained the remaining two- thirds of the Convertible Debentures instalment. The net proceeds were $1.4 billion and were used to repay the Company’s acquisition credit facility.

For further information on the acquisition of TECO Energy refer to the “Outlook”, “Outlook – Emera Florida and New Mexico” and the “Emera Florida and New Mexico” segment section of this MD&A.

Investment in APUC

On May 24, 2016, Emera completed the sale of 19.3 per cent of APUC's issued and outstanding common shares. Proceeds of the sale were used in support of Emera's general financing requirements, including the purchase of TECO Energy. On June 30, 2016, Emera converted 12.9 million subscription receipts and dividend equivalents into 12.9 million APUC common shares. On December 8, 2016, Emera completed the sale of the remaining 12.9 million common shares. Emera no longer holds any interest in APUC.

ECI Amalgamation

On February 24, 2016, the common shareholders of ECI approved an amalgamation transaction, which resulted in a wholly owned subsidiary of Emera purchasing all common shares of ECI. Prior to this, Emera held 95.5 per cent of ECI’s common shares.

To effect the amalgamation, all issued and outstanding common shares of ECI were converted to Class A redeemable preferred shares. In Q1 2016, the Class A redeemable preferred shares of ECI not owned were redeemed. Minority ECI shareholders could elect to receive $23.26 ($33.30 Barbadian dollars (“BBD”)) in cash per common share (“Cash Offer”) or 2.1 Depositary Receipts (“DR”) per common share, with each DR representing one quarter of a common share of Emera (“DR Offer”); or a combination of the two offers. The total consideration paid to redeem the minority interest was $15 million ($23 million BBD), consisting of $14 million of the Cash Offer ($22 million BBD) and $1 million of the DR Offer ($1 million BBD). The amalgamated entity retained the name Emera (Caribbean) Incorporated.

Recent Financing Activity

Emera

On December 16, 2016, Emera completed an offering of 6,630,000 common shares, at $45.25 per common share. On December 21, 2016, underwriters fully exercised an over-allotment option of 994,500 common shares, at $45.25 per common share. The aggregate gross and net proceeds from the offering, including the over-allotment, were $345 million and $335 million respectively. The proceeds of the offering were used for general corporate purposes.

On December 13, 2016, Emera's Series H $250 million 2.96% medium-term notes matured and were repaid.

Emera – TECO Energy Acquisition Related Capital Market Transactions

U.S. Notes

On June 16, 2016, Emera US Finance LP, a limited partnership financing subsidiary, wholly owned directly and indirectly by Emera, completed the issuance of $3.25 billion USD senior unsecured notes (“U.S. Notes”) by way of private placement. The U.S. Notes were sold only to “qualified institutional buyers” under Rule 144A of the United States Securities Act of 1933, as amended (the “Securities Act”) and to non-U.S. persons under Regulation S of the Securities Act and were not offered for sale in Canada. The U.S. Notes are guaranteed by Emera and Emera US Holdings Inc., a wholly owned Emera subsidiary. The U.S. Notes bear interest semi-annually, in arrears, on June 15 and December 15 of each year, commencing on December 15, 2016. The U.S. Notes will not be listed on a securities exchange.

The U.S. Notes issued are as follows:

$500 million USD three year, 2.15 per cent Notes due 2019

$750 million USD five year 2.70 per cent Notes due 2021

$750 million USD ten year 3.55 per cent Notes due 2026

$1.25 billion USD thirty year 4.75 per cent Notes due 2046

In connection with the initial issuance of the U.S. Notes, Emera US Finance LP entered into a registration rights agreement with the initial purchasers of the U.S. Notes in which it undertook to offer to exchange the U.S. Notes for new notes, in an equal principal amount and under the same terms, registered under the Securities Act. On December 15, 2016, a registration statement on Form F-10/Form S-4 was declared effective by the United States Securities and Exchange Commission (the “SEC”). On January 17, 2017 the new notes were issued.

Hybrid Notes

On June 16, 2016, Emera completed the issuance of $1.2 billion USD unsecured, fixed-to-floating subordinated notes (“Hybrid Notes”). The Hybrid Notes were issued pursuant to a prospectus filed with the Nova Scotia Securities Commission (the “NSSC”) and a corresponding registration statement filed with the SEC under the United States / Canada Multijurisdictional Disclosure System. The Hybrid Notes will mature on June 15, 2076. Emera will pay interest on the Hybrid Notes at a fixed rate of 6.75 per cent per year in equal semi-annual instalments on June 15 and December 15 of each year until June 15, 2026. Beginning on June 15, 2026, and on every quarter thereafter that the Hybrid Notes are outstanding until their maturity on June 15, 2076 (the “Interest Reset Date”), the interest rate on the Hybrid Notes will be reset. The Hybrid Notes are not currently listed and Emera does not intend to list them on any securities exchange or include them on any automated quotation system.

Beginning on June 15, 2026, and on every Interest Reset Date until June 15, 2046, the Hybrid Notes will be reset at an interest rate of the three month LIBOR plus 5.44 per cent, payable in arrears. Beginning on June 15, 2046, and on every Interest Reset Date until June 15, 2076, the Hybrid Notes will be reset at an interest rate of the three-month LIBOR plus 6.19 per cent, payable in arrears.

Emera may elect, at its sole option, to defer the interest payable on the Hybrid Notes on one or more occasions for up to five consecutive years. Deferred interest will accrue, compounding on each subsequent interest payment date, until paid. Additionally, on or after June 15, 2026, Emera may, at its option, redeem the Hybrid Notes, at a redemption price equal to 100 per cent of the principal amount, together with accrued and unpaid interest.

Canadian Notes

On June 16, 2016, Emera completed the issuance of $500 million senior unsecured notes (“Canadian Notes”). The Canadian Notes were issued with a seven-year term to maturity and bear interest at a rate of 2.90 per cent. The notes will bear interest semi-annually in arrears on June 16 and December 16 of each year, commencing on December 16, 2016. The Canadian Notes will not be listed on a securities exchange.

The proceeds of the U.S. Notes, Hybrid Notes and Canadian Notes offerings were used to partially finance the purchase price for the Acquisition. Proceeds of the offerings, not otherwise required to complete the Acquisition, have been used for general corporate purposes.

NSPI

On April 28, 2016, NSPI increased its committed syndicated revolving bank line of credit to $600 million from $500 million. The increase will support ongoing business requirements and general corporate purposes.

On May 27, 2016, NSPI increased its commercial paper program to $500 million from $400 million, of which the full amount outstanding is backed by NSPI’s operating credit facility referred to above. The amount of commercial paper issued results in an equal amount of its operating credit facility being considered drawn and unavailable.

ECI

On November 29, 2016, ECI completed a senior, secured floating rate, non-revolving term loan of $150 million USD. The loan is for a five year term and matures on November 29, 2021. Interest is due semi-annually and is based on 6 month LIBOR plus 4.08 per cent weighted average.

Appointments

Board of Directors

Effective September 1, 2016, John Ramil joined the Emera Board of Directors. Mr. Ramil was President and Chief Executive Officer (“CEO”) of TECO Energy until his retirement on August 31, 2016.

Executive

Effective December 1, 2016, Archie Collins was appointed President and Chief Executive Officer of GBPC. Mr. Collins is also President and Chief Operating Officer of ECI.

Effective November 18, 2016, Scott Balfour was appointed as Chief Operating Officer of Emera. In addition to his responsibilities for Emera’s Northeast and Caribbean operations, Mr. Balfour will be responsible for providing senior executive direction for Emera’s affiliates in Florida and New Mexico and corporate functions including Human Resources, Stakeholder Relations and Strategic Planning.

Effective September 1, 2016, Rob Bennett, was appointed President and Chief Executive Officer of TECO Energy.

Effective September 1, 2016, in addition to his current role of Chief Financial Officer, Emera, Greg Blunden was appointed as TECO Energy’s and TEC’s Senior Vice President – Finance and Accounting and Chief Financial Officer (Chief Accounting Officer).

Effective September 1, 2016, Sarah MacDonald has been appointed to President of TECO Services Inc., TECO Energy’s centralized service company.

Effective August 1, 2016, Bob Hanf was appointed Executive Vice President, Stakeholder Relations and Regulatory Affairs for Emera. Most recently, he was President and CEO of NSPI.

Effective August 1, 2016, Karen Hutt was appointed President and CEO of NSPI. Previously, Ms. Hutt was Vice President, Mergers and Acquisitions, with Emera.

OUTSTANDING COMMON STOCK DATA

Common stock	millions of	millions of Canadian
Issued and outstanding:	shares	dollars
December 31, 2014	143.78		$	2,016
Issuance of common stock	1.25			54
Issued for cash under Purchase Plans at market rate	2.10			88
Discount on shares purchased under Dividend Reinvestment Plan	-			(4)
Options exercised under senior management stock option plan	0.08			2
Employee Share Purchase Plan	-			1
December 31, 2015	147.21		$	2,157
Conversion of Convertible Debentures (1)	51.99			2,115
Issuance of common stock (2)	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
December 31, 2016	210.02		$	4,738
(1) In 2016, 51.99 million common shares of Emera were issued relating to the conversion of the Convertible Debentures, representing conversion into common shares of 99.6 per cent.
(2) In Q1 2016, Emera issued 0.06 million common shares to facilitate the creation and issuance of 0.2 million depositary receipts in connection with the ECI amalgamation transaction. The depositary receipts are listed on the Barbados Stock Exchange. In addition, Emera completed an offering of 7.63 million common shares in December 2016, at $45.25 per common share, for net proceeds of approximately $345 million. The net proceeds were $335 million after $10 million of issuance costs, net of taxes.


As at January 30, 2017 the amount of issued and outstanding common shares was 210.1 million.

The weighted average shares of common stock outstanding – basic, which includes both issued and outstanding common stock and outstanding deferred share units, for the three months ended December 31, 2016 was 204 million (2015 – 147 million). The weighted average shares of common stock outstanding – basic for the year ended December 31, 2016 was 171 million (2015 – 146 million).

EMERA FLORIDA AND NEW MEXICO

All amounts are reported in USD, unless otherwise stated.

Review of 2016
Emera Florida and New Mexico Net Income

For the	Three months ended			Year ended
millions of US dollars (except per share amounts)		December 31			December 31*
			2016			2016
Operating revenues – regulated electric		$	454		$	1,039
Operating revenues – regulated gas			202			349
Operating revenues – non-regulated			4			7
Total operating revenues			660			1,395
Regulated fuel for generation and purchased power			159			371
Regulated cost of natural gas			80			133
Operating, maintenance and general			176			335
Provincial, state and municipal taxes			45			96
Depreciation and amortization			92			184
Total operating expenses			552			1,119
Income from operations			108			276
Other income (expenses), net			9			17
Interest expense, net			43			87
Income before provision for income taxes			74			206
Income tax expense (recovery)			27			75
Contribution to consolidated net income – USD		$	47		$	131
Contribution to consolidated net income – CAD			63			172
Contribution to consolidated earnings per common share – CAD		$	0.31		$	1.00
Net income weighted average foreign exchange rate – CAD/USD		$	1.34		$	1.31

EBITDA – USD		$	209		$	477
EBITDA – CAD		$	279		$	629
* Financial results of Emera Florida and New Mexico are from July 1, 2016. For additional information on the acquisition of TECO Energy, refer to the “Developments” section of this MD&A.

The Emera Florida and New Mexico USD contribution to consolidated net income was $47 million in Q4 2016. For the year ended December 31, 2016, the Emera Florida and New Mexico USD contribution to consolidated net income was $131 million. This reflects results since July 1, 2016, which is the date of the acquisition by Emera.

The Emera Florida and New Mexico operating unit contribution to consolidated net income for the three months and year ended December 31, 2016 is summarized in the following table:

For the	Three months ended			Year ended
millions of US dollars	December 31			December 31*
			2016			2016
Tampa Electric		$	38		$	126
PGS			9			15
NMGC			10			9
Other (1)			(10)			(19)
Contribution to consolidated net income		$	47		$	131
* Financial results of Emera Florida and New Mexico are from July 1, 2016. For additional information on the acquisition of TECO Energy, refer to the “Developments” section of this MD&A.
(1) Other includes TECO Finance and administration costs.

Included below are Emera Florida and New Mexico’s Q4 and year ended 2016 results compared to the same period in 2015. Prior year data is for comparison purposes only, as the Emera acquisition was completed on July 1, 2016. The year ended period reflects the six months ended December 31, 2016.

Tampa Electric’s net income decreased $5 million to $38 million in Q4 2016 compared to $43 million for the same period in 2015 primarily due to lower energy sales and margin from milder weather in Q4 2016, higher OM&G due to timing and increased depreciation expense resulting from normal additions to facilities to reliably serve customers. For the six-month year ended 2016 period, Tampa Electric’s net income increased $1 million to $126 million compared to $125 million in 2015 primarily due to higher energy sales and increased AFUDC on the Polk Power Station expansion project, which were partially offset by higher OM&G due to the same factors as the quarter. The higher energy sales and margin in the six month period were primarily due to the warmer weather in Q3 2016 and 1.6 per cent customer growth.

PGS’s net income increased $2 million to $9 million in Q4 2016 compared to $7 million for the same period in 2015 primarily due to higher residential and commercial sales volumes being offset by slightly higher OM&G. PGS had increased energy sales and margin due to 2.7 per cent customer growth, which included higher volume commercial customers. For the six-month year ended 2016 period, PGS’s net income increased $2 million to $15 million compared to $13 million in 2015 due to the same factors as the quarter.

NMGC’s net income decreased $3 million to $10 million in Q4 2016 compared to $13 million for the same period in 2015 primarily due to lower energy sales from milder weather resulting in lower margin. For the six-month year ended 2016 period, NMGC’s net income decreased $1 million to $9 million compared to $10 million in 2015 primarily due to lower margin resulting from the same factors as Q4, which was partially offset by lower interest expense on short term debt and increased AFUDC related to reliability improvement projects.

Other net loss of $10 million in Q4 2016 and $19 million in the six-month year ended 2016 period was essentially unchanged compared to the same periods in 2015.

The Emera Florida and New Mexico CAD dollar contribution to consolidated net income was $63 million and $172 million for the Q4 2016 and six-month year ended 2016 period, respectively.

Operating Revenues – Regulated

Emera Florida and New Mexico's operating revenues - regulated include sales of electricity, gas and other services as summarized in the following table:

Q4 Operating Revenues – Regulated			Six-Month Year Ended Operating Revenues – Regulated*
millions of US dollars			millions of US dollars
		2016			2016
Electric revenues - regulated (1)	$	454	Electric revenues - regulated (1)	$	1,039
Gas revenues - regulated (1)		202	Gas revenues - regulated (1)		349
Operating revenues – regulated	$	656	Operating revenues – regulated	$	1,388
*Financial results of Emera Florida and New Mexico are from July 1, 2016. For additional information on the acquisition of TECO Energy, refer to the “Developments” section of this MD&A.
(1) Electric and gas regulated revenues include regulatory deferrals related to over-recovery of fuel and clause related costs, if any. Under recoveries are included in the related expense.

Electric and Gas Revenues

Electric and gas sales volumes are primarily driven by general economic conditions, population and weather. Residential and commercial electricity and gas sales are seasonal. In Florida, Q3 is the strongest period for electricity sales, reflecting warmer weather and cooling demand. In New Mexico and Florida, Q1 is the strongest period for gas sales due to colder weather and heating demand.

Emera Florida and New Mexico’s residential load generally comprises individual homes, apartments and condominiums. Commercial customers include small retail operations, large office and commercial complexes, universities and hospitals. Industrial customers include manufacturing facilities and other large volume operations. The gas utilities’ industrial customers include manufacturing facilities and other large volume operations. Other sales volumes consist primarily of off-system sales to other utilities and revenues from street lighting.

Q4 Electric Sales Volumes

Six-Month Year Ended Electric Sales Volumes

GWh

2016

2015*

2014*

2016

2015*

2014*

Residential

2,072

2,146

1,965

Residential

5,032

4,875

4,744

Commercial

1,543

1,587

1,489

Commercial

3,357

3,341

3,262

Industrial

491

486

441

Industrial

990

930

924

Other

457

461

452

Other

960

935

946

Total

4,563

4,680

4,347

Total

10,339

10,081

9,876

*2015 and 2014 data is for comparison purposes only. TECO Energy was acquired on July 1, 2016.

Q4 Gas Sales Volumes

Six-Month Year Ended Gas Sales Volumes

Therms (millions)

2016

2015*

2014*

2016

2015*

2014*

Residential

116

126

123

Residential

151

160

158

Commercial

204

210

205

Commercial

354

356

347

Industrial (1)

289

309

260

Industrial (1)

617

612

553

Other

147

120

Total

665

710

620

Total

1,269

1,248

1,134

*2015 and 2014 data is for comparison purposes only. TECO Energy was acquired on July 1, 2016.

(1) Industrial gas sales include on-system power generation customers.

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

Q4 Electric Revenues			Six-Month Year Ended Electric Revenues*
millions of US dollars			millions of US dollars
		2016			2016
Residential	$	235	Residential	$	566
Commercial		146	Commercial		313
Industrial		41	Industrial		83
Other (1)		32	Other (1)		77
Total	$	454	Total	$	1,039
(1) Other includes regulatory deferrals related to over-recovery of clause related costs.			*Financial results of Emera Florida and New Mexico are from July 1, 2016. For additional information on the acquisition of TECO Energy, refer to the “Developments” section of this MD&A.
			(1) Other includes regulatory deferrals related to over-recovery of clause related costs.

Electric revenues decreased $20 million to $ 454 million in Q4 2016 compared to $474 million in Q4 2015 primarily due to lower sales volumes from milder weather. For the six-month year ended 2016 period, electric revenues increased $5 million to $1,039 million compared to $1,034 million in the same period in 2015 primarily due to higher sales volumes from warmer weather during the summer months.

Q4 Gas Revenues			Six-Month Year Ended Gas Revenues*
millions of US dollars			millions of US dollars
		2016			2016
Residential	$	106	Residential	$	162
Commercial		57	Commercial		99
Industrial		7	Industrial		13
Other (1)		32	Other (1)		75
Total	$	202	Total	$	349
(1) Other includes regulatory deferrals related to over-recovery of clause related costs.			*Financial results of TECO Energy are from July 1, 2016. For additional information on the acquisition of TECO Energy, refer to the “Developments” section of this MD&A.
			(1) Other includes regulatory deferrals related to over-recovery of clause related costs.

Gas revenues increased $3 million to $202 million in Q4 2016 compared to $199 million in Q4 2015 with consistent revenues by customer class. For the six-month year ended 2016 period, gas revenues increased $19 million to $349 million compared to $330 million in the same period in 2015 primarily due to the increase in off-system sales in Florida.

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

Electric Capacity

Tampa Electric is required to maintain a generating capacity greater than firm peak demand. The total Tampa Electric-owned generation capacity is approximately 4,730 MW, which is supplemented by 488 MW contracted with other regulated utilities and independent power producers in Florida. Tampa Electric meets the planning criteria for reserve capacity established by the FPSC, which is a 20% reserve margin over firm peak demand.

Tampa Electric’s 460 MW Polk Power Station expansion project went into commercial operation on January 16, 2017.

Q4 Production Volumes
GWh
	2016	2015*	2014*
Natural gas (1)	1,958	2,175	1,284
Coal	1,872	2,079	2,764
Oil and petcoke	220	269	268
Purchased power	492	238	29
Total production volumes	4,542	4,761	4,345
*2015 and 2014 data is for comparison purposes only. TECO Energy was acquired on July 1, 2016.
(1) Natural gas production volumes in 2016 are lower due to outages related to the Polk conversion project.


Six-Month Year Ended Production Volumes
GWh
	2016	2015*	2014*
Natural gas (1)	4,451	5,248	3,507
Coal	4,281	4,065	5,719
Oil and petcoke	516	533	563
Purchased power	1,338	615	275
Total production volumes	10,586	10,461	10,064
*2015 and 2014 data is for comparison purposes only. TECO Energy was acquired on July 1, 2016. Year ended data reflects Q3 and Q4 periods.
(1) Natural gas production volumes in 2016 are lower due to outages related to the Polk conversion project.

Q4 Average Fuel Costs/MWh
US dollars		2016
Dollars per MWh	$	35

Six-Month Year Ended Average Fuel Costs/MWh*
US dollars		2016
Dollars per MWh	$	35
*Financial results of Emera Florida and New Mexico are from July 1, 2016. For additional information on the acquisition of TECO Energy, refer to the “Developments” section of this MD&A.

Q4 and year ended average fuel cost per MWh was $35 for both periods in 2016 and 2015. The 2014 average fuel cost per MWh were $42 and $40 for Q4 and the six-month year ended period, respectively. The reduction is primarily due to lower natural gas pricing in 2016 and 2015 compared to 2014.

Tampa Electric’s Fuel Costs are affected by commodity prices and generation mix that is largely dependent on economic dispatch of the generating fleet, bringing the lowest cost options on stream first (after renewable energy from solar arrays), such that the incremental cost of production increases as sales volumes increase. Generation mix may also be affected by plant outages, plant performance, availability of lower priced short-term purchased power, availability of renewable solar generation, and compliance with environmental standards and regulations.

Historically, coal and petcoke have the lowest per unit fuel cost, with natural gas being the next lowest. However, recent declines in natural gas prices and better overall thermal efficiencies have at times resulted in natural gas generation dispatching before coal and petcoke units.

Regulated fuel for generation and purchased power decreased $7 million to $159 million in Q4 2016 compared to $166 million in Q4 2015 primarily due to lower sales volumes, which was partially offset by an increase in purchased power costs to cover outages related to the Polk Power Station expansion project. For the six-month year ended 2016 period, regulated fuel for generation and purchased power increased $3 million to $371 million compared to $368 million for the same 2015 period primarily due to higher sales volumes experienced during the summer months compared to Q3 2015.

Cost of Natural Gas

Emera Florida and New Mexico’s gas utilities, PGS and NMGC, purchase gas from various suppliers depending on the needs of its customers. In Florida, the gas is delivered to the PGS distribution system through three interstate pipelines on which PGS has firm transportation capacity for delivery by PGS to its customers. NMGC’s service territory is situated between two large natural gas production basins (the San Juan Basin in northwest New Mexico and the Permian Basin located in the southeast New Mexico). Natural gas is transported from these production basins on major interstate pipelines and NMGC’s intrastate transmission system to customers using NMGC’s distribution system.

In Florida, natural gas service is unbundled for non-residential customers and residential customers that use more than 1,999 therms annually that elect this option, affording these customers the opportunity to purchase gas from any provider. In New Mexico, NMGC is required to provide transportation-only services for all customer classes if requested. The net result of unbundling is a shift from bundled transportation and commodity sales to transportation-only sales. Because the commodity portion of bundled sales is included in operating revenues at the cost of the gas on a pass-through basis, there is no net earnings affect when a customer shifts to transportation-only sales.

Gas sales by type are summarized in the following tables:

Q4 Gas Sales Volumes by Type

Six-Month Year Ended Gas Sales Volumes by Type

Therms (millions)

2016

2015*

2014*

Therms (millions)

2016

2015*

2014*

System Supply

198

222

185

System Supply

329

317

271

Transportation

467

488

435

Transportation

940

931

863

Total

665

710

620

Total

1,269

1,248

1,134

*2015 and 2014 data is for comparison purposes only. TECO Energy was acquired on July 1, 2016.

Gas sales volumes in Q4 2016 were lower than Q4 2015 primarily due to milder weather in New Mexico affecting heating load and lower power generation sales in Florida. For the six-month year ended 2016 period, gas sales volumes increased compared to the same period in 2015 primarily due to customer growth and higher off-system sales in Florida.

Regulatory Recovery Mechanisms

Tampa Electric

Fuel Recovery Clause

Tampa Electric has a fuel recovery clause that is approved by the FPSC, allowing it to recover fluctuating fuel expenses from customers through annual fuel rate adjustments. Differences between actual Fuel Costs and amounts recovered from customers through electricity rates in a year are deferred to a fuel clause regulatory asset or liability and recovered from or returned to customers in a subsequent year.

Other Cost Recovery Clauses

The FPSC annually approves cost-recovery rates for purchased power, capacity, environmental and conservation costs including a return on capital invested. Differences between the prudently incurred clause-recoverable costs and amounts recovered from customers through electricity rates in a year are deferred to a corresponding regulatory asset or liability and recovered from or returned to customers in a subsequent year. In November 2016, the FPSC approved cost-recovery rates for fuel and purchased power, capacity, environmental and conservation costs for 2017.

PGS

Fuel Recovery Clause

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its purchased gas adjustment (“PGA”) clause. This clause is designed to recover the costs incurred by PGS for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers. These charges may be adjusted monthly based on a cap approved annually by the FPSC.

Other Cost Recovery Clauses

The FPSC annually approves cost-recovery rates for conservation costs including a return on capital invested incurred in developing and implementing energy conservation programs. In 2012, the FPSC approved a Cast Iron/Bare Steel Pipe Replacement clause to recover the cost of accelerating the replacement of cast iron and bare steel distribution lines in the PGS system. The FPSC approved PGS’ request to accelerate the replacement program of approximately 5 per cent, or 800 kilometres, of the PGS system at a cost of approximately $80 million USD over a 10-year period. As part of the depreciation study settlement agreement approved by the FPSC in February 2017, the Cast Iron/Bare Steel clause was expanded to allow recovery of accelerated replacement of certain obsolete plastic pipe.

NMGC

Fuel Recovery Clause

NMGC recovers gas supply costs through a purchased gas adjustment clause (“PGAC”). This clause recovers NMGC’s actual costs for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers.

On a monthly basis, NMGC can adjust the charges based on next month’s expected cost of gas and any prior month under-recovery or over-recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish that the continued use of the PGAC is reasonable and necessary. In December 2016, NMGC received approval of its PGAC Continuation Filing for the four-year period ending December 2020.

Electric and Gas Revenue Margin

Emera Florida and New Mexico’s utilities distinguish revenues related to various regulated clauses from revenues related primarily to the recovery of non-fuel costs (“base rates”). Electric and gas margin (“margin”) and net income are derived primarily by base rates and the return on Florida utility assets associated with approved cost recovery clauses. Fuel and other non-fuel cost recovery clauses do not have a material effect on margin, as substantially all costs are recovered from customers. However the clauses do include a return on capital invested related to these clauses.

Customer classes contribute differently to base rate revenue, with residential and commercial customers contributing more on a dollar per MWh and per therm basis than industrial customers. Residential and commercial load is primarily affected by changes in weather and economic conditions, while industrial load is primarily affected by economic conditions.

Regulated operating revenues are shown separately by those recovered through base rates and those recovered by various fuel and non-fuel recovery clauses and are outlined below for the three months ended and six months ended December 31, 2016:

For the					Three months ended
millions of US dollars						December 31
		Electric		Gas		Total
Electric and gas revenues – base rate	$	230	$	106	$	336
Fuel electric and gas revenues (1)		162		81		243
Other non-fuel cost recovery clause revenues (1)		28		5		33
Other operating revenues		12		5		17
Gross receipts tax and franchise fees revenues (2)		22		5		27
Regulated operating revenues	$	454	$	202	$	656
(1) Includes return on FPSC approved clause recoverable assets and incentive on generation fleet performance.
(2) Gross receipts and franchise fees for Tampa Electric and PGS are collected from customers on a dollar-for-dollar basis. As a result, they are included in Regulated revenues and as an offsetting expense in "Provincial, state and municipal taxes" on the Consolidated Statements of Income.

For the					Year ended
millions of US dollars						December 31*
		Electric		Gas		Total
Electric and gas revenues – base rate	$	529	$	184	$	713
Fuel electric and gas revenues (1)		377		136		513
Other non-fuel cost recovery clause revenues (1)		58		10		68
Other operating revenues		25		9		34
Gross receipts tax and franchise fees revenues (2)		50		10		60
Regulated operating revenues	$	1,039	$	349	$	1,388
*Financial results of Emera Florida and New Mexico are from July 1, 2016. For additional information on the acquisition of TECO Energy, refer to the “Developments” section of this MD&A.
(1) Includes return on FPSC approved clause recoverable assets and incentive on generation fleet performance.
(2) Gross receipts and franchise fees for Tampa Electric and PGS are collected from customers on a dollar-for-dollar basis. As a result, they are included in Regulated revenues and as an offsetting expense in "Provincial, state and municipal taxes" on the Consolidated Statements of Income.


Electric margin for the three months and year ended December 31, 2016 is summarized in the following table:

For the	Three months ended		Year ended
millions of US dollars	December 31		December 31*
		2016			2016
Electric base rate revenue	$	230		$	529
Other electric non-fuel cost recovery clause revenues		28			58
Less: Other electric non-fuel clause costs, net of deferrals		(19)			(40)
Electric fuel clause revenue		162			377
Less: Electric fuel clause costs, net of deferrals		(161)			(375)
Electric margin	$	240		$	549
*Financial results of Emera Florida and New Mexico are from July 1, 2016. For additional information on the acquisition of TECO Energy, refer to the “Developments” section of this MD&A.

Electric margin decreased $9 million to $240 million in Q4 2016 compared to $249 million in Q4 2015 primarily due to decreased sales volumes reflecting milder weather. For the six-month year ended 2016 period, electric margin increased $7 million to $549 million compared to $542 million in the same period in 2015 primarily due to the higher energy sales from warmer weather in Q3 2016 that were partially offset by the Q4 2016 items discussed above.

Gas margin for the three months and year ended December 31, 2016 are summarized in the following table:

For the	Three months ended		Year ended
millions of US dollars	December 31		December 31*
		2016		2016
Gas base rate revenue	$	106	$	184
Other gas non-fuel cost recovery clause revenues		5		10
Less: Other gas clause recoverable costs, net of deferrals		(4)		(8)
Gas fuel clause revenue		81		136
Less: Gas fuel clause cost, net of deferrals		(80)		(134)
Gas margin	$	108	$	188
*Financial results of Emera Florida and New Mexico are from July 1, 2016. For additional information on the acquisition of TECO Energy, refer to the “Developments” section of this MD&A.

Gas margin was unchanged in Q4 2016 compared to Q4 2015 as decreases in NMGC gas margin due to milder weather were offset by increases in PGS’ margin due to strong customer growth in Florida. For the six-month year ended 2016 period, gas margin increased $3 million to $188 million in 2016 compared to $185 million in 2015 primarily due to customer growth in Florida, which was partially offset by the milder weather in New Mexico.

Income Taxes

The Florida utilities are subject to corporate income tax at the statutory rate of 39 per cent (combined US federal and Florida state income tax rate). NMGC is subject to corporate income tax at the statutory rate of 39 per cent (combined US federal and New Mexico state income tax rate). Emera Florida and New Mexico’s effective tax rate for the three months and six months ended December 31, 2016 was 36 per cent for both periods, which was lower than the statutory rates primarily due to non-taxable AFUDC-equity at Tampa Electric.

Non-GAAP Measure

Electric and Gas Margin Reconciliation

“Electric and gas margin” is a non-GAAP financial measure used to show the amounts that Tampa Electric, PGS and NMGC retain to recover their non-clause costs. Effectively, all prudently incurred clause recoverable costs are recovered through the fuel clauses or various other regulatory clause mechanisms approved by the FPSC and NMPRC. Electric and gas margin associated with non-fuel recovery clauses are essentially the return on assets employed, as all other clause related costs are fully recovered.

The companies’ electric and gas margin may not be comparable to other companies’ electric or gas margin measures, but in management’s view appropriately reflects the utilities’ regulatory framework. This measure is not intended to replace “Income from operations” which, as determined in accordance with GAAP, is an indicator of operating performance. Electric and gas margin was discussed in the Financial Review Electric and Gas Margin section above.

	Three months ended
	December 31
	2016
For the		Electric		Gas
millions of US dollars		Margin		Margin		Total
Income from operations	$	72	$	36	$	108
Less:
Operating revenues – non-regulated		-		4		4
Fuel electric and gas revenues		162		81		243
Other clause revenues		28		5		33
Other operating revenues		12		5		17
Gross receipts tax and franchise fees revenues		22		5		27
Add back:
Regulated fuel for generation and purchased power		159		-		159
Cost of natural gas sold		-		80		80
Operating, maintenance and general –non-clause related		120		56		176
Provincial, state and municipal taxes		35		10		45
Depreciation and amortization – non-clause related		68		24		92
Non-base rate margin contribution (1)		10		2		12
Electric and gas margin	$	240	$	108	$	348
(1) Includes return on FPSC approved clause recoverable assets and incentive on generation fleet performance – see electric and gas margin discussion above for details of the contributions.

	Year ended
	December 31
	2016*
For the		Electric		Gas
millions of US dollars		Margin		Margin		Total
Income from operations	$	226	$	50	$	276
Less:
Operating revenues – non-regulated		-		7		7
Fuel electric and gas revenues		377		136		513
Other clause revenues		58		10		68
Other operating revenues		25		9		34
Gross receipts tax and franchise fees revenues		50		10		60
Add back:
Regulated fuel for generation and purchased power		371		-		371
Cost of natural gas sold		-		133		133
Operating, maintenance and general –non-clause related		231		104		335
Provincial, state and municipal taxes		76		20		96
Depreciation and amortization – non-clause related		135		49		184
Non-base rate margin contribution (1)		20		4		24
Electric and gas margin	$	549	$	188	$	737
*Financial results of Emera Florida and New Mexico are from July 1, 2016. For additional information on the acquisition of TECO Energy, refer to the “Developments” section of this MD&A.
(1) Includes return on FPSC approved clause recoverable assets and incentive on generation fleet performance – see electric and gas margin discussion above for details of the contributions.

NSPI

Review of 2016
NSPI Net Income

For the	Three months ended				Year ended
millions of Canadian dollars (except per share amounts)	December 31				December 31
		2016		2015		2016		2015		2014
Operating revenues – regulated	$	352	$	338	$	1,356	$	1,417	$	1,348
Regulated fuel for generation and purchased power (1)		136		133		490		543		512
Regulated fuel adjustment mechanism and fixed cost deferrals		13		11		61		42		47
Operating, maintenance and general		76		66		299		298		273
Provincial grants and taxes (2)		10		9		39		38		38
Depreciation and amortization		49		52		197		206		204
Total operating expenses		284		271		1,086		1,127		1,074
Income from operations		68		67		270		290		274
Other expenses, net (3)		1		-		4		6		5
Interest expense, net		31		31		124		122		116
Income before provision for income taxes		36		36		142		162		153
Income tax expense (recovery)		2		(7)		12		23		20
Net income of Nova Scotia Power Inc.		34		43		130		139		133
Preferred stock dividends (4)		-		3		-		9		8
Contribution to consolidated net income	$	34	$	40	$	130	$	130	$	125
Contribution to consolidated earnings per common share	$	0.17	$	0.27	$	0.76	$	0.89	$	0.87

EBITDA	$	116	$	119	$	463	$	490	$	473
(1) Regulated fuel for generation and purchased power includes affiliate transactions and proceeds from the sale of natural gas.
(2) Provincial grants and taxes are included in "Provincial state and municipal taxes" on the Consolidated Statements of Income.
(3) Other expenses, net is included in "Other income (expenses), net" on the Consolidated Statements of Income.
(4) Preferred stock dividends are included in "Non-controlling interest in subsidiaries" on the Consolidated Statements of Income. In Q4 2015, NSPI redeemed its preferred shares.

NSPI’s contribution to consolidated net income decreased $6 million to $34 million in Q4 2016 compared to $40 million in Q4 2015. For the year ended December 31, 2016, NSPI’s contribution to consolidated net income was consistent with 2015.

Highlights of the changes are summarized in the following table:

For the	Three months ended		Year ended
millions of Canadian dollars	December 31		December 31
Contribution to consolidated net income – 2014			$	125
Increased electric margin primarily due to increased residential load, largely due to weather and a FAM audit disallowance included in 2014				13
Increased fixed cost deferrals primarily due to the new demand side management ("DSM") regulatory deferral commencing in 2015, partially offset by an increase in the amount of non-fuel revenues deferred compared to 2014				31
Increased OM&G primarily due to increased DSM program costs as a result of legislation, effective January 1, 2015, requiring NSPI to purchase electricity efficiency and conservation activities and higher pension costs, partially offset by lower storm costs				(25)
Increased interest expense, net primarily due to lower interest revenues related to FAM and fixed cost deferrals and higher debt levels				(6)
Increased income tax expense primarily due to increased income before provision for income taxes				(3)
Other				(5)
Contribution to consolidated net income – 2015	$	40	$	130
Increased (decreased) electric margin (see Electric Margin section below for explanation)		5		(18)
Decreased fixed cost deferrals primarily due to 2015 DSM regulatory deferral, partially offset by a reduction in the amount of non-fuel revenues deferred		(2)		(10)
Increased OM&G quarter-over-quarter primarily due to higher storm costs and timing of planned plant maintenance, partially offset by lower pension expense; year-over-year primarily due to higher storm costs and investment in cost saving initiatives, partially offset by lower pension expense		(13)		(11)
Decreased DSM program costs		3		10
Decreased depreciation and amortization primarily due to lower regulatory amortization as a result of a deferral from 2012 being fully amortized in 2015, partially offset by increased depreciation associated with increased property, plant and equipment		3		9
Increased income tax expense quarter-over-quarter primarily due to a 2015 legislated change by the Province of Nova Scotia to the deferred tax treatment of the South Canoe and Sable wind farms resulting in prior period deferred income taxes recorded through earnings being recorded as regulatory assets in Q4 2015; year-over-year decrease primarily due to decreased income before provision for income taxes and increased accelerated tax deductions related to property, plant and equipment		(9)		11
Decreased preferred stock dividends due to redemption of the preferred stock in Q4 2015		3		9
Other		4		-
Contribution to consolidated net income – 2016	$	34	$	130

Operating Revenues – Regulated Electric

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

For the	Three months ended				Year ended
millions of Canadian dollars	December 31				December 31
	2016		2015			2016	2015		2014
Electric revenues	$	343	$	333	$	1,327	$	1,389	$	1,319
Other revenues		9		5		29		28		29
Operating revenues – regulated electric	$	352	$	338	$	1,356	$	1,417	$	1,348

Electric Revenues

NSPI’s electric revenue is affected by rates approved by the UARB and electric sales volumes.

Electric sales volume is primarily driven by general economic conditions, population, weather and DSM activities. Residential and commercial electricity sales are seasonal, with Q1 being the strongest period, reflecting colder weather and fewer daylight hours in the winter season.

NSPI’s residential load generally comprises individual homes, apartments and condominiums. Commercial customers include small retail operations, large office and commercial complexes, universities and hospitals. Industrial customers include manufacturing facilities and other large volume operations. Other electric revenues consist primarily of sales to municipal electric utilities and revenues from street lighting.

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

Q4 Electric Sales Volumes				Annual Electric Sales Volumes
Gigawatt hours ("GWh")				GWh
	2016	2015	2014		2016	2015	2014
Residential	1,143	1,075	1,083	Residential	4,318	4,484	4,370
Commercial	764	757	767	Commercial	3,062	3,134	3,092
Industrial	632	592	630	Industrial	2,445	2,457	2,513
Other	80	82	75	Other	293	337	312
Total	2,619	2,506	2,555	Total	10,118	10,412	10,287

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

Q4 Electric Revenues							Annual Electric Revenues
millions of Canadian dollars							millions of Canadian dollars
		2016		2015		2014			2016		2015		2014
Residential	$	181	$	171	$	165	Residential	$	689	$	716	$	669
Commercial		101		100		97	Commercial		399		410		387
Industrial		51		51		50	Industrial		197		214		214
Other		10		11		12	Other		42		49		49
Total	$	343	$	333	$	324	Total	$	1,327	$	1,389	$	1,319

Electric revenues increased $10 million to $343 million in Q4 2016 compared to $333 million in Q4 2015. For the year ended December 31, 2016 , electric revenues decreased $62 million to $1,327 million compared to $1,389 million in the same period in 2015. Highlights of the changes are summarized in the following table:

For the	Three months ended		Year ended
millions of Canadian dollars	December 31		December 31
Electric revenues – 2014			$	1,319
Increased fuel related electricity pricing effective January 1, 2015				56
Increased commercial and residential sales volumes primarily due to weather and load growth				20
Decreased industrial sales volume				(5)
Other				(1)
Electric revenues – 2015	$	333	$	1,389
Decreased fuel related electricity pricing effective January 1, 2016		(3)		(12)
Increased residential sales volume quarter-over-quarter primarily due to favourable weather increasing load; decreased residential sales volume year-over-year primarily due to unfavourable weather in Q1		11		(21)
Increased (decreased) commercial sales volume		2		(6)
Increased (decreased) industrial sales volume		2		(16)
Other		(2)		(7)
Electric revenues – 2016	$	343	$	1,327

Regulated Fuel for Generation and Purchased Power

Capacity

To ensure reliability of service, NSPI must maintain a generating capacity greater than firm peak demand. The total NSPI-owned generation capacity is 2,487 MW, which is supplemented by 530 MW contracted with IPPs and Community Feed-In Tariff (“COMFIT”) participants. NSPI meets the planning criteria for reserve capacity established by the Maritime Control Area and the Northeast Power Coordinating Council.

NSPI facilities continue to rank among the best in Canada on performance indicators. The high availability and capability of low cost thermal generating stations provide lower-cost energy to customers. In 2016, thermal plant availability was 86 per cent compared to 88 per cent in 2015. NSPI’s four-year average for thermal plant availability is 86 per cent. Availability is in line with industry comparisons. NSPI continues to derive good performance from its thermal plants despite the challenges of increased renewable integration, flexible utilization, and risks associated with an aging fleet.

Q4 Production Volumes							Annual Production Volumes
GWh							GWh
		2016		2015		2014			2016		2015		2014
Coal		1,380		1,186		1,433	Coal		4,810		4,869		5,255
Natural gas		281		354		186	Natural gas		1,244		1,302		1,468
Oil and petcoke		391		356		353	Oil and petcoke		1,499		1,760		1,507
Purchased power – other		129		121		126	Purchased power – other		430		428		353
Total non-renewables		2,181		2,017		2,098	Total non-renewables		7,983		8,359		8,583
Wind and hydro – renewables		230		228		391	Wind and hydro – renewables		1,081		1,275		1,357
Purchased power – IPP		314		330		243	Purchased power – IPP		1,147		1,009		825
Purchased power – COMFIT		110		104		12	Purchased power – COMFIT		414		280		24
Biomass – renewables		52		63		62	Biomass – renewables		214		206		258
Total renewables		706		725		708	Total renewables		2,856		2,770		2,464
Total production volumes		2,887		2,742		2,806	Total production volumes		10,839		11,129		11,047

Q4 Average Fuel Costs							Annual Average Fuel Costs
		2016		2015		2014			2016		2015		2014
Dollars per megawatt hour ("MWh") produced	$	47	$	48	$	45	Dollars per MWh produced	$	45	$	49	$	46

Average unit Fuel Costs is consistent in Q4 2016 compared to Q4 2015. Year-over-year, average unit Fuel Costs decreased in 2016 compared to 2015, primarily due to favorable commodity pricing, combined with the transition to economic dispatch of biomass generation compared to must run in 2015. These cost savings are partially offset by increased generation costs associated with the COMFIT program and IPP purchases and decreased NSPI-owned hydro generation.

NSPI’s Fuel Costs are affected by commodity prices and generation mix which is largely dependent on economic dispatch of the generating fleet, bringing the lowest cost options on stream first after renewable energy from IPPs including COMFIT participants, for which NSPI has power purchase agreements in place. This results in the incremental cost of production generally increasing as sales volumes

increase. Generation mix may also be affected by plant outages, availability of renewable generation, plant performance and compliance with environmental standards and regulations.

NSPI-owned regulated hydro and wind have no fuel cost component. After hydro and wind, historically, petcoke and coal have the lowest per unit fuel cost, with natural gas being the next lowest. However, declines in natural gas prices and better overall thermal efficiencies have at times resulted in natural gas dispatching before petcoke and coal units. Oil, biomass and purchased power have the next lowest fuel cost, depending on the relative pricing of each.

The generation mix is transforming with the addition of new non-dispatchable renewable energy sources such as wind, including IPP and COMFIT, which typically have a higher cost per MWh than NSPI-owned generation or other purchased power sources.

Regulated fuel for generation and purchased power increased $3 million to $136 million in Q4 2016 compared to $133 million in Q4 2015. For the year ended December 31, 2016, regulated fuel for generation and purchased power decreased $53 million to $490 million compared to $543 million in 2015. Highlights of the changes are summarized in the following table:

For the	Three months ended		Year ended
millions of Canadian dollars	December 31		December 31
Regulated fuel for generation and purchased power – 2014			$	512
Decreased commodity prices				(38)
Changes in generation mix and plant performance				51
Increased sales volumes				11
Decreased hydro and NSPI-owned wind production				3
Other				4
Regulated fuel for generation and purchased power – 2015	$	133	$	543
Change in commodity prices		1		(47)
Changes in sales volumes		7		(15)
Decrease in hydro production		-		9
Other		(5)		-
Regulated fuel for generation and purchased power – 2016	$	136	$	490

Regulated Fuel Adjustment Mechanism and Fixed Cost Deferrals

Regulated Fuel Adjustment Mechanism and FAM Regulatory Deferral

NSPI has a Regulated FAM which enables it to seek recovery of Fuel Costs through regularly scheduled rate adjustments. Differences between actual Fuel Costs and amounts recovered from customers through electricity rates in a given year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year.

The FAM is subject to an incentive with NSPI retaining or absorbing 10 per cent of the over or under-recovered Fuel Cost amount to a maximum of $5 million. The incentive was suspended for 2012 through 2015 as a result of UARB approved settlement agreements and is in effect for 2016. The incentive is suspended as part of the Electricity Plan Act in 2017 through 2019. For 2016, a FAM incentive of $2.8 million was achieved by NSPI and will be returned to the benefit of customers through a settlement agreement related to the 2014 and 2015 FAM audit, as discussed below.

Pursuant to the FAM Plan of Administration, NSPI’s Fuel Costs are subject to independent audit. On August 12, 2016, the FAM audit results relating to the fiscal 2014 and 2015 audit were publically released and recommended one disallowance in the amount of $1 million. This amount related to a specific long-term contract that had also been disallowed following previous FAM audits. On December 21, 2016 the UARB approved a settlement agreement between NSPI and customer representatives which resolved all issues related to the 2014 and 2015 FAM Audit, including all future issues related to the contract that had previously been disallowed. As a result of the settlement agreement, NSPI agreed to forego $3 million of

any FAM incentive payment resulting from 2016 Fuel Costs savings it achieved. NSPI achieved a $2.8 million incentive for 2016 and contributed that amount plus an additional $0.2 million to the benefit of customers.

In December 2015, the UARB approved NSPI’s 2016 fuel rates and its recovery of prior period unrecovered Fuel Costs. The approved customer rates reset the base cost of fuel rates for 2016. In addition, $12 million was approved to be recovered related to prior years’ unrecovered Fuel Costs. This resulted in a combined average rate decrease for customers of approximately 1 per cent in 2016. The rates and recovery of these costs began on January 1, 2016.

The impact of the FAM included in the Consolidated Statements of Income include the effect of Fuel Costs in both the current and preceding years and are detailed below:

· The difference between actual Fuel Costs and amounts recovered from customers in the current year. This amount, net of the incentive component, is deferred to a FAM regulatory asset in “Regulatory assets” or a FAM regulatory liability in “Regulatory liabilities” on the Consolidated Balance Sheets; and

· The recovery from (rebate to) customers of under (over) recovered Fuel Costs from prior years.

The FAM regulatory asset (liability) includes amounts recognized as FAM and associated interest that is included in “Interest expense, net” on the Consolidated Statements of Income. Details of the FAM regulatory asset (liability), classified in “Regulatory assets” or “Regulatory liabilities” on the Consolidated Balance Sheets, are summarized in the following table:

millions of Canadian dollars		2016		2015
FAM regulatory asset (liability) – Balance as at January 1	$	(28)	$	48
(Over) under recovery of current year Fuel Costs		(29)		24
Recovery from customers of prior years’ Fuel Costs		(12)		(56)
Excess non-fuel revenues		(5)		(27)
Benefit of tax treatment on South Canoe and Sable wind farms		(15)		(18)
Interest on FAM balance		(5)		1
FAM regulatory asset (liability) – Balance as at December 31	$	(94)	$	(28)

As at December 31, 2016, NSPI applied $15 million of the tax benefits associated with the South Canoe and Sable wind projects to the FAM, as directed by the Electricity Plan Act. In addition, NSPI will refund $5 million of excess non fuel revenue to customers as part of the one-time credit of approximately $36 million in 2017.

2015 DSM Deferral

Effective January 1, 2015, NSPI must purchase electricity efficiency and conservation activities (“Program Costs”) from EfficiencyOne, the provincially appointed franchisee to deliver energy efficiency programs to Nova Scotians. The 2015 Program Costs of $35 million were deferred to a regulatory asset and are recoverable from customers over an eight-year period which began in 2016. The UARB directed EfficiencyOne to review the financing options through which EfficiencyOne would borrow the 2015 deferral amount from a commercial lender in order to repay NSPI the amount it expended on behalf of its customers in 2015. On December 2, 2016, EfficiencyOne secured the financing and $31 million was advanced to NSPI to finance the 2015 DSM deferral. As NSPI collects the associated amounts from customers over the next seven years, it will repay the balance to EfficiencyOne. This advance has been set up as a liability in “Other long-term liabilities” with the current portion of the liability included in “Other current liabilities” on the Consolidated Balance Sheets.

In August 2015, the UARB approved a budget for EfficiencyOne of $102 million for the three year period of 2016 through 2018, which will be reduced by $7 million in 2017 as a result of underspend by EfficiencyOne in 2015. The Electricity Plan Act has placed a cap of $34 million on 2019 DSM spending.

The DSM regulatory asset includes amounts recognized as DSM and associated interest that is included in “Interest expense, net” on the Consolidated Statements of Income.

Details of the DSM regulatory asset, classified in “Regulatory assets” on the Consolidated Balance Sheets, are summarized in the following table:

millions of Canadian dollars		2016		2015
DSM regulatory asset – Balance as at January 1	$	36	$	-
Current period Program Costs deferred		-		35
Recovery of regulatory asset recorded as regulatory amortization		(6)		-
Interest on DSM balance		2		1
DSM regulatory asset – Balance as at December 31	$	32	$	36

The DSM regulatory asset is largely offset by a liability of $31 million to EfficiencyOne.

Electric Revenue and Margin

NSPI distinguishes electric revenues related to the recovery of Fuel Costs (“fuel electric revenues”) from revenues related to the recovery of non-fuel costs (“non-fuel electric revenues”) because the FAM effectively seeks to recover all prudently incurred Fuel Costs. Consequently, Fuel Costs and fuel electric revenues do not have a material effect on NSPI’s electric margin or net income, with the exception of the incentive component of the FAM. The incentive component is where NSPI retains or absorbs 10 per cent of the over or under recovered amount to a maximum of $5 million.

Electric margin is influenced primarily by revenues relating to non-fuel costs. NSPI’s customer classes contribute differently to its non-fuel electric revenues, with residential and commercial customers contributing more than industrial customers under current rates. Accordingly, changes in residential and commercial load, largely due to the effects of weather, general economic conditions and DSM have the largest effect on non-fuel electric revenues and electric margin. Changes in industrial load, which are generally due to economic conditions and DSM, have less of an effect on non-fuel electric revenues than would a similar volume change in residential and commercial load.

The addition of new generation facilities to meet legislated greenhouse gas emission reductions and renewable generation requirements and other capital investments are among the drivers increasing NSPI’s fixed costs.

Operating revenues are summarized in the following table:

For the	Three months ended				Year ended
millions of Canadian dollars	December 31				December 31
	2016		2015		2016		2015		2014
Fuel electric revenues – current year	$	135	$	122	$	518	$	518	$	512
Fuel electric revenues – recovery of preceding years		3		14		12		56		-
Non-fuel electric revenues		205		197		797		815		807
Other revenues		9		5		29		28		29
Operating revenues	$	352	$	338	$	1,356	$	1,417	$	1,348

Electric margin is summarized in the following table:

Fuel electric revenues – current year	$	135	$	122	$	518	$	518	$	512
Fuel electric revenues – recovery of preceding years		3		14		12		56		-
Total fuel electric revenues		138		136		530		574		512
Regulated fuel for generation and purchased power		(136)		(133)		(490)		(543)		(512)
Regulated fuel adjustment mechanism		(5)		(5)		(41)		(32)		(6)
Fuel-related foreign exchange gain (loss) (1)		-		2		1		1		1
Net fuel revenue (expense)(2)		(3)		-		-		-		(5)
Non-fuel electric revenues		205		197		797		815		807
Electric margin	$	202	$	197	$	797	$	815	$	802
(1) As reported in "Other income (expenses), net", on the Consolidated Statements of Income.
(2) The net fuel expense for the three months ended December 31, 2016 is a result of the FAM audit settlement as discussed above.

NSPI’s electric margin increased $5 million to $202 million in Q4 2016 compared to $197 million in Q4 2015 primarily due to increased residential sales reflecting colder weather partially offset by NSPI foregoing $3 million of the FAM incentive as a result of the FAM audit settlement agreement. NSPI’s electric margin for the year ended December 31, 2016 decreased $18 million to $797 million compared to $815 million in 2015 primarily due to decreased residential and commercial sales reflecting unfavorable weather in Q1 2016.

Q4 Average Electric Margin							Annual Average Electric Margin
		2016		2015		2014			2016		2015		2014
Dollars per MWh	$	77	$	78	$	77	Dollars per MWh	$	79	$	78	$	78

NSPI’s electric margin per MWh is consistent quarter-over-quarter and year-over-year.

Provincial Grants and Taxes

NSPI pays annual grants to the Province of Nova Scotia in lieu of municipal taxation other than deed transfer tax.

Income Taxes

In 2016 and 2015, NSPI was subject to corporate income tax at the statutory rate of 31 per cent (combined federal and provincial income tax rate). In 2015, NSPI was subject to Part VI.1 tax relating to preferred stock dividends at the statutory rate of 40 per cent. NSPI also received a reduction in its corporate income tax otherwise payable related to the Part VI.1 tax deduction of 43 per cent of preferred stock dividends.

Non-GAAP Measure

Electric Margin Reconciliation

“Electric margin” is a non-GAAP financial measure used to show the amounts that NSPI retains to recover its non-fuel costs, as effectively all prudently incurred Fuel Costs are recovered through the FAM. NSPI’s electric margin may not be comparable to other companies’ electric margin measures, but in management’s view appropriately reflects NSPI’s regulatory framework. This measure is not intended to replace “Income from operations” which, as determined in accordance with USGAAP, is an indicator of operating performance. Electric margin was discussed in the Financial Review Electric Revenue and Margin section above.

For the	Three months ended				Year ended
millions of Canadian dollars	December 31				December 31
		2016		2015		2016		2015		2014
Income from operations	$	68	$	67	$	270	$	290	$	274
Less:
Fuel electric revenues – current and preceding years		138		136		530		574		512
FAM audit disallowance		-		-		-		-		5
Other revenues		9		5		29		28		29
Add back:
Regulated fuel for generation and purchased power		136		133		490		543		512
Operating, maintenance and general		76		66		299		298		273
Property, state and municipal taxes		10		9		39		38		38
Depreciation and amortization		49		52		197		206		204
Regulated fuel adjustment mechanism and fixed cost deferrals		13		11		61		42		47
Other fuel related costs		(3)		-		-		-		-
Electric margin	$	202	$	197	$	797	$	815	$	802

EMERA MAINE

All amounts are reported in USD, unless otherwise stated.

Review of 2016
Emera Maine Net Income

For the	Three months ended				For the year ended
millions of USD (except per share amounts)	December 31				December 31
		2016		2015		2016		2015		2014
Operating revenues – regulated electric	$	55	$	52	$	223	$	221	$	219
Operating revenues – non-regulated		1		-		1		1		-
Total operating revenues		56		52		224		222		219
Regulated fuel for generation and purchased power		6		7		28		29		30
Transmission pool expense (1)		6		6		26		25		24
Operating, maintenance and general		12		14		51		49		47
Provincial, state and municipal taxes		3		3		13		13		11
Depreciation and amortization		12		10		39		37		43
Total operating expenses		39		40		157		153		155
Income from operations		17		12		67		69		64
Other income (expenses), net		(1)		(2)		1		1		4
Interest expense, net		3		3		14		13		12
Income before provision for income taxes		13		7		54		57		56
Income tax expense (recovery)		4		3		18		21		18
Contribution to consolidated net income – USD	$	9	$	4	$	36	$	36	$	38
Contribution to consolidated net income – CAD	$	11	$	5	$	47	$	45	$	42
Contribution to consolidated earnings per common share – CAD	$	0.05	$	0.03	$	0.27	$	0.31	$	0.29
Net income weighted average foreign exchange rate – CAD/USD	$	1.34	$	1.33	$	1.32	$	1.27	$	1.10

EBITDA – USD	$	28	$	20	$	107	$	107	$	111
EBITDA – CAD	$	37	$	27	$	141	$	136	$	123
(1) Transmission pool expense is included in “Regulated fuel for generation and purchased power” on the Consolidated Statements of Income.

Emera Maine’s USD contribution to consolidated net income increased by $5 million to $9 million in Q4 2016 compared to $4 million in Q4 2015. For the year ended December 31, 2016, Emera Maine’s USD contribution to consolidated net income was flat at $36 million compared to $36 million in 2015. Highlights of the USD net income changes are summarized in the following table:

For the	Three months ended		Year ended
millions of US dollars	December 31		December 31
Contribution to consolidated net income – 2014			$	38
(Decreased) increased operating revenues – see Operating Revenues – Regulated Electric section below				3
Increased OM&G primarily due to decreased capitalized construction overheads, partially offset by changes in pension and retiree medical expenses				(2)
Decreased depreciation and amortization due to lower depreciation rates as a result of a 2014 depreciation study and lower regulatory amortization				7
Decreased other income primarily due to AFUDC adjustments recognized as a result of a FERC audit				(4)
Increased income tax expense primarily due to decrease in regulatory amortization and AFUDC adjustments recorded as a result of a FERC audit				(3)
Other				(3)
Contribution to consolidated net income – 2015	$	4	$	36
Increased operating revenues – see Operating Revenues – Regulated Electric section below		3		2
Decreased OM&G quarter-over-quarter primarily due to increased capitalized construction overheads, partially offset by losses recognized on disallowed and abandoned plant. Increased OM&G year-over-year primarily due to increased major storm and regulatory expenses as well as losses recognized on disallowed and abandoned plant, partially offset by increased capitalized construction overheads		2		(2)
Increased income tax expense quarter-over-quarter primarily due to increased income before provision for income taxes, year-over-year decrease primarily due to AFUDC adjustments recorded as a result of a FERC audit in 2015		(1)		3
Other		1		(3)
Contribution to consolidated net income – 2016	$	9	$	36

Emera Maine’s CAD contribution to consolidated net income increased by $6 million to $11 million in Q4 2016 from $5 million in Q4 2015. For the year ended December 31, 2016, Emera Maine’s CAD contribution to consolidated net income increased by $2 million to $47 million from $45 million in 2015. The foreign exchange rate had no impact for the three months ended December 31, 2016. The impact of a stronger USD increased CAD earnings by $2 million for the year ended December 31, 2016.

Operating Revenues – Regulated Electric

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

Q4 Operating Revenues – Regulated Electric							Annual Operating Revenues – Regulated Electric
millions of US dollars							millions of US dollars
	2016		2015		2014			2016		2015		2014
Electric revenues	$	40	$	38	$	41	Electric revenues	$	160	$	160	$	157
Transmission pool revenues		12		11		11	Transmission pool revenues		51		49		49
Resale of purchased power		3		3		3	Resale of purchased power		12		12		13
Operating revenues – regulated electric	$	55	$	52	$	55	Operating revenues – regulated electric	$	223	$	221	$	219

Electric Revenues

Electric sales volume is primarily driven by general economic conditions, population and weather. Electric sales pricing in Maine is regulated, and therefore can change in accordance with regulatory decisions.

Q4 Electric Sales Volumes				Annual Electric Sales Volumes
GWh	2016	2015	2014	GWh	2016	2015	2014
Residential	202	199	203	Residential	790	802	805
Commercial	192	192	193	Commercial	776	777	788
Industrial	85	94	104	Industrial	352	427	426
Other	2	3	4	Other	13	14	15
Total	481	488	504	Total	1,931	2,020	2,034

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

Q4 Electric Revenues							Annual Electric Revenues
millions of US dollars							millions of US dollars
		2016		2015		2014			2016		2015		2014
Residential	$	20	$	19	$	20	Residential	$	77	$	76	$	76
Commercial		15		15		14	Commercial		60		58		57
Industrial		3		3		2	Industrial		13		14		14
Other (1)		2		1		5	Other (1)		10		12		10
Total	$	40	$	38	$	41	Total	$	160	$	160	$	157
(1) Other revenue includes amounts recognized relating to FERC transmission rate refunds and other transmission revenue adjustments.

Electric revenues increased $2 million to $40 million in Q4 2016 compared to $38 million in Q4 2015. For the year ended December 31, 2016, electric revenues were flat at $160 million. Highlights of the changes are summarized in the following table:

For the	Three months ended		Year ended
millions of US dollars	December 31		December 31
Electric revenues – 2014			$	157
Decreased sales volumes primarily due to weather				(1)
Increased primarily due to rate changes				4
Increased due to FERC transmission rate refund				6
Decreased due to transmission revenue adjustments				(6)
Electric revenues – 2015	$	38	$	160
Decreased sales volumes primarily due to loss of load associated with closing two large industrial customers in December 2015 and the impact of weather		(1)		(4)
Increased primarily due to transmission rate changes		1		5
Decreased due to FERC transmission rate refund		(1)		-
Increased (decreased) due to transmission revenue adjustments		3		(1)
Electric revenues – 2016	$	40	$	160

Q4 Electric Revenue / MWh							Annual Average Electric Revenue / MWh
		2016		2015		2014			2016		2015		2014
Dollars per MWh	$	83	$	78	$	81	Dollars per MWh	$	83	$	79	$	77

The increase in the average electric revenue per MWh in Q4 2016 compared to Q4 2015 and the year ended 2016 compared to 2015 reflects increased transmission rates offset by transmission revenue adjustments.

Transmission Pool Revenues and Expenses

Transmission pool revenues are recorded in “Operating revenues – regulated electric” and transmission pool expenses are recorded in “Regulated fuel for generation and purchased power” in the Consolidated Statements of Income.

Transmission pool revenues and expenses are summarized in the following table:

For the	Three months ended				Year ended
millions of US dollars	December 31				December 31
		2016		2015		2016		2015		2014
Transmission pool revenues	$	12	$	11	$	51	$	49	$	49
Transmission pool expenses		6		6		26		25		24
Net transmission pool revenues	$	6	$	5	$	25	$	24	$	25

Emera Maine’s net transmission pool revenues increased slightly in the quarter and year ended due to changes in the level of investment in regionally funded transmission assets and the impacts of weather in the New England region.

Resale of Purchased Power and Regulated Fuel for Generation and Purchased Power

Emera Maine has several above-market power purchase contracts with generators in its Bangor District service territory. The power purchased under these arrangements is resold at market rates significantly below the contract rates. The difference between the cost of the power purchased under these arrangements and the revenue collected is recovered through stranded cost rates under a full reconciliation rate mechanism.

Resale of purchased power was flat at $3 million in Q4 2016 compared to $3 million in Q4 2015, and for the year ended December 31, 2016 at $12 million compared to $12 million in 2015.

Income Taxes

Emera Maine is subject to corporate income tax at the statutory rate of 41 per cent (combined US federal and state income tax rate).

EMERA CARIBBEAN

All amounts are reported in USD, unless otherwise stated.

Review of 2016
Emera Caribbean Net Income

For the	Three months ended				Year ended
millions of USD (except per share amounts)	December 31				December 31
		2016		2015		2016		2015		2014
Operating revenues – regulated electric	$	78	$	84	$	316	$	346	$	432
Operating revenues – non-regulated		-		-		-		6		8
Total operating revenues		78		84		316		352		440
Regulated fuel for generation and purchased power		36		37		130		158		248
Non-regulated direct costs		-		-		-		6		7
Operating, maintenance and general		24		24		89		102		107
Property taxes (1)		-		-		2		1		2
Depreciation and amortization		9		9		37		35		33
Total operating expenses		69		70		258		302		397
Income from operations		9		14		58		50		43
Income from equity investment		-		1		2		2		2
Other income (expenses), net		1		2		47		5		6
Interest expense, net		3		3		11		11		11
Income before provision for income taxes		7		14		96		46		40
Income tax expense (recovery)		1		1		11		2		3
Net income		6		13		85		44		37
Non-controlling interest in subsidiaries		-		3		5		10		8
Preferred stock dividends (2)		-		-		3		3		3
Contribution to consolidated net income – USD	$	6	$	10	$	77	$	31	$	26
Contribution to consolidated net income – CAD	$	8	$	14	$	100	$	41	$	29
Contribution to consolidated earnings per common share – CAD	$	0.04	$	0.10	$	0.58	$	0.28	$	0.19
Net income weighted average foreign exchange rate – CAD/USD	$	1.34	$	1.33	$	1.31	$	1.29	$	1.10

EBITDA – USD	$	19	$	26	$	144	$	92	$	84
EBITDA – CAD	$	25	$	34	$	189	$	118	$	93
(1) Included in "Provincial, state and municipal taxes" on the Consolidated Statements of Income.
(2) Preferred stock dividends are included in "Non-controlling interest in subsidiaries" on the Consolidated Statements of Income.

Emera Caribbean’s USD contribution to consolidated net income decreased by $4 million to $6 million in Q4 2016 compared to $10 million in Q4 2015. For the year ended December 31, 2016, Emera Caribbean’s USD contribution to consolidated net income increased by $46 million to $77 million compared to $31 million in 2015. Highlights of the net income changes are summarized in the following table:

For the	Three months ended		Year ended
millions of US dollars	December 31		December 31
Contribution to consolidated net income – 2014			$	26
Increased Electric Margin – see Electric Margin section				4
Decreased OM&G primarily due to lower pension expense, savings and timing of maintenance costs, and restructuring payroll savings at BLPC, lower outage costs at GBPC, and the reversal of Domlec regulatory costs; year-over-year restructuring costs at BLPC offset the decreased OM&G				5
Increased non-controlling interest due to increased earnings from ECI, GBPC and Domlec				(2)
Other				(2)
Contribution to consolidated net income – 2015	$	10	$	31
Decreased Electric Margin – see Electric Margin section		(4)		(1)
Decreased OM&G year-over-year primarily due to operational cost savings at GBPC and BLPC		-		13
Increased other income year-over-year primarily due to Q2 pre-tax gain recognized on the BLPC SIF regulatory liability (see details below)		(1)		42
Increased income tax expense year-over-year primarily due to the gain recognized on the BLPC SIF regulatory liability		-		(9)
Other		1		1
Contribution to consolidated net income – 2016	$	6	$	77

In June 2016, BLPC secured support from the Government of Barbados and the Trustees of the SIF to reduce the contingency funding in the SIF to $22 million USD. As a result, Emera recorded a pre-tax gain of $41 million USD and an after-tax gain of $34 million USD. Absent this gain, the Emera Caribbean contribution to the consolidated net income for the year ended 2016 was $43 million USD ($57 million CAD).

In October 2016, the island of Grand Bahama took a direct hit from Hurricane Matthew. GBPC’s generation and substation infrastructure weathered the storm well, however over 2,100 transmission and distribution poles and related conduit were damaged or destroyed, as were many connections to customer homes. Restoration efforts have been completed. Emera Caribbean has recorded $28 million USD of restoration costs associated with Hurricane Matthew with no impact to net income as $21 million USD was recorded as a regulated asset amortized over five years and $7 million USD recorded as property, plant and equipment depreciating at an average 27 years. GBPC’s regulator has approved the full recovery of the storm restoration costs in this manner.

Emera Caribbean’s CAD contribution to consolidated net income decreased by $6 million to $8 million in Q4 2016 compared to $14 million in Q4 2015. For the year ended December 31, 2016, Emera Caribbean’s CAD contribution to consolidated net income increased by $59 million to $100 million in 2016 compared to $41 million in 2015. The foreign exchange rate had no impact for the three months ended 2016. The impact of a stronger USD year-over-year increased CAD earnings by $2 million in 2016 compared to 2015.

Operating Revenues – Regulated Electric

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

Q4 Operating Revenues – Regulated							Annual Operating Revenues – Regulated
millions of US dollars							millions of US dollars
		2016		2015		2014			2016		2015		2014
Electric revenues – base rates	$	42	$	47	$	45	Electric revenues – base rates	$	185	$	187	$	183
Fuel charge		36		36		59	Fuel charge		128		155		245
Total electric revenues		78		83		104	Total electric revenues		313		342		428
Other revenues		-		1		1	Other revenues		3		4		4
Operating revenues – regulated electric	$	78	$	84	$	105	Operating revenues – regulated electric	$	316	$	346	$	432

Electric Revenues

Electric sales volume is primarily driven by general economic conditions, population and weather. Residential and commercial electricity sales are seasonal, with Q3 being the strongest period, reflecting warmer weather.

Q4 Electric Sales Volumes				Annual Electric Sales Volumes
GWh				GWh
	2016	2015	2014		2016	2015	2014
Residential	110	115	111	Residential	465	453	440
Commercial	185	197	189	Commercial	766	764	751
Industrial	17	25	26	Industrial	89	104	102
Other	3	7	7	Other	19	24	26
Total	315	344	333	Total	1,339	1,345	1,319

Electric volumes decreased in Q4 2016 compared to Q4 2015 as a result of the direct hit the island of Grand Bahama took from Hurricane Matthew in October 2016. Year-to-date electric volumes remained consistent period over period with the lower Q4 volumes at GBPC being offset by higher volumes at BLPC as a result of warmer weather.

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

Q4 Electric Revenues							Annual Electric Revenues
millions of US dollars							millions of US dollars
		2016		2015		2014			2016		2015		2014
Residential	$	26	$	27	$	34	Residential	$	104	$	111	$	143
Commercial		46		48		61	Commercial		179		195		251
Industrial		5		7		7	Industrial		24		30		27
Other		1		1		2	Other		6		6		7
Total	$	78	$	83	$	104	Total	$	313	$	342	$	428

Electric revenues decreased $5 million to $78 million in Q4 2016 compared to $83 million in Q4 2015. For the year ended December 31, 2016, electric revenues decreased $29 million to $313 million compared to $342 million in 2015. Highlights of the changes are summarized in the following table:

For the	Three months ended		Year ended
millions of US dollars	December 31		December 31
Electric revenues – 2014			$	428
Decreased fuel charge primarily due to lower fuel prices				(90)
Increased due to higher sales volumes at BLPC and GBPC primarily due to weather				4
Electric revenues – 2015	$	83	$	342
Decreased year-over-year fuel charge primarily due to lower fuel prices		-		(27)
Decreased quarter-over-quarter primarily due to lower sales volumes at GBPC due to the impact of Hurricane Matthew, year-over-year decrease due to lower sales volumes at GBPC due to the impact of Hurricane Matthew partially offset by higher sales volumes at BLPC due to warmer weather		(5)		(2)
Electric revenues – 2016	$	78	$	313

Q4 Average Electric Revenue/MWh							Annual Average Electric Revenue/MWh
		2016		2015		2014			2016		2015		2014
Dollars per MWh	$	248	$	241	$	314	Dollars per MWh	$	234	$	254	$	324

The change in average electric revenues per MWh in Q4 2016 compared to Q4 2015 was the result of increased fuel charge at BLPC due to higher fuel prices in the quarter being offset by a decrease in fuel charge at GBPC. The change year-to-date 2016 compared to the same period in 2015 was mainly due to the decrease in fuel prices.

Electric Revenue and Margin

Emera Caribbean distinguishes revenues related to the recovery of fuel costs through the fuel charge from revenues related primarily to the recovery of non-fuel costs (“base rates”). Emera Caribbean’s electric margin and net income are influenced primarily by base rates, whereas the fuel charge and fuel costs do not have a material effect on electric margin or net income. Emera Caribbean’s customer classes contribute differently to the Company’s base rate revenue, with residential and commercial customers contributing more than industrial customers. Residential and commercial load is primarily affected by changes in weather and economic conditions, while industrial load is primarily affected by economic conditions.

Electric margin is summarized in the following table:

For the	Three months ended				Year ended
millions of US dollars	December 31				December 31
		2016		2015		2016		2015		2014
Operating revenues – regulated	$	78	$	84	$	316	$	346	$	432
Less: Other revenues		-		(1)		(3)		(4)		(4)
Total electric revenues		78		83		313		342		428

Total electric revenues are broken down as follows:
Electric revenues – base rate	$	42	$	47	$	185	$	187	$	183
Fuel charge		36		36		128		155		245
Total electric revenues		78		83		313		342		428
Regulated fuel for generation and purchased power		36		37		130		158		248
Regulatory amortization (1)		1		1		3		3		3
Electric margin	$	41	$	45	$	180	$	181	$	177
(1) Included in "Depreciation and amortization" on the Consolidated Statements of Income.

Emera Caribbean’s electric margin decreased $4 million to $41 million in Q4 2016 compared to $45 million in Q4 2015 due to lower sales volumes at GBPC due to the direct hit the island of Grand Bahamas took from Hurricane Matthew in October 2016. For the year ended December 31, 2016, electric margin

decreased $1 million to $180 million compared to $181 million in 2015 mainly due to lower sales volumes at GBPC due to the impact of Hurricane Matthew, partially offset by higher sales volumes at BLPC due to warmer weather.

Q4 Average Electric Margin / MWh							Annual Average Electric Margin / MWh
		2016		2015		2014			2016		2015		2014
Dollars per MWh	$	130	$	131	$	132	Dollars per MWh	$	134	$	135	$	134

Electric margin for the quarter and year-to-date is consistent with prior periods.

Regulated Fuel for Generation and Purchased Power

Q4 Production Volumes							Annual Production Volumes
GWh							GWh
		2016		2015		2014			2016		2015		2014
Oil		337		369		349	Oil		1,417		1,441		1,397
Hydro		9		6		8	Hydro		36		25		31
Solar		4		-		-	Solar		9		-		-
Total		350		375		357	Total		1,462		1,466		1,428


Q4 Average Fuel Costs/MWh							Annual Average Fuel Costs/MWh
		2016		2015		2014			2016		2015		2014
Dollars per MWh	$	103	$	99	$	168	Dollars per MWh	$	89	$	108	$	173

The change in average fuel costs in Q4 2016 compared to Q4 2015 and for the year ended December 31, 2016 compared to the same period in 2015 is a result of the change in commodity prices.

Regulated fuel for generation and purchased power decreased $1 million to $36 million in Q4 2016 compared to $37 million in Q4 2015 primarily due to higher commodity prices offset by lower production volumes at GBPC due to Hurricane Matthew. For the year ended December 31, 2016, regulated fuel for generation and purchased power decreased $28 million to $130 million compared to $158 million in 2015 primarily due to lower commodity prices.

Regulatory Recovery Mechanisms

BLPC

BLPC’s fuel costs flow through a fuel pass-through mechanism which provides the opportunity to recover all prudent fuel costs from customers in a timely manner. The Barbados Fair Trading Commission has approved the calculation of the fuel charge, which is adjusted on a monthly basis.

GBPC

GBPC’s fuel costs flow through a fuel pass-through mechanism which provides the opportunity to recover all prudent fuel costs from customers in a timely manner. In December 2016, the GBPA approved holding the all-in (fuel and base) rates consistent with 2016 levels for five years (2017-2021). See the Emera Caribbean Outlook section for additional details.

As a component of its regulatory agreement GBPC has an Earnings Share Mechanism to allow for earnings on rate base to be deferred to a regulatory asset or liability at the rate of 50 per cent of amounts below a 7.8 per cent return on rate base and 50 per cent of amounts above 9.8 per cent return on rate base respectively.

Domlec

Substantially all of Domlec fuel costs flow through a fuel pass-through mechanism which provides the opportunity to recover prudent fuel costs from customers in a timely manner.

Income Taxes

Emera Caribbean is subject to corporate income tax at the following statutory rates:

· ECI is subject to corporate income tax at the statutory rate of 25 per cent;

· BLPC is subject to corporate income tax at the statutory rate of 15 per cent;

· GBPC is not subject to corporate income tax;

· Domlec is subject to corporate income tax at the statutory rate of 25 per cent; and

· Lucelec is subject to corporate income tax at the statutory rate of 30 per cent.

Non-GAAP Measure

Electric Margin Reconciliation

“Electric margin” is a non-GAAP financial measure used to show the amounts that BLPC, GBPC and Domlec retain to recover their non-fuel costs, as substantially all prudently incurred fuel costs are recovered from customers.

The companies’ electric margin may not be comparable to electric margin measures of other companies, but in management’s view appropriately reflects Emera’s specific condition. Management believes measuring electric margin shows the portion of revenues managed through fuel adjustment mechanism, which have a minimal impact on income. This measure is not intended to replace “Income from operations” which, as determined in accordance with GAAP, is an indicator of operating performance.

For the	Three months ended				Year ended
millions of US dollars	December 31				December 31
		2016		2015		2016		2015		2014
Income from operations	$	9	$	14	$	58	$	50	$	43
less:
Operating revenues – non-regulated		-		-		-		6		8
Other revenue		-		1		3		4		4
Add back:
Non-regulated direct costs		-		-		-		6		7
Operating, maintenance and general		24		24		89		102		107
Property taxes		-		-		2		1		2
Depreciation and amortization (1)		8		8		34		32		30
Electric margin	$	41	$	45	$	180	$	181	$	177
(1) Depreciation and amortization excludes $1 million of regulatory amortization in Q4 2016 (2015 – $1 million) and $3 million for the year ended December 31, 2016 (2015 – $3 million)

EMERA ENERGY

Review of 2016
Emera Energy Adjusted Contribution to Consolidated Net Income

For the	Three months ended				Year ended
millions of Canadian dollars (except per share amounts)	December 31				December 31
		2016		2015		2016		2015		2014
Marketing and trading margin (1)	$	23	$	38	$	58	$	85	$	117
Electricity sales (2)		109		143		460		546		521
Total operating revenues – non-regulated		132		181		518		631		638
Non-regulated fuel for generation and purchased power (3)		84		87		334		335		385
Operating, maintenance and general		23		25		87		80		79
Provincial, state and municipal taxes		3		2		10		6		5
Depreciation and amortization		13		11		45		41		38
Total operating expenses		123		125		476		462		507
Adjusted income (loss) from operations		9		56		42		169		131
Income from equity investments (4)		2		3		13		26		12
Other income (expenses), net		1		1		(1)		25		3
Interest expense, net		6		6		24		19		6
Adjusted income (loss) before provision for income taxes		6		54		30		201		140
Income tax expense (recovery) (5)		1		19		6		71		42
Adjusted contribution to consolidated net income (loss)	$	5	$	35	$	24	$	130	$	98
After-tax derivative mark-to-market gain (loss)	$	(36)	$	5	$	(134)	$	(31)	$	88
Contribution to consolidated net income	$	(31)	$	40	$	(110)	$	99	$	186
Adjusted contribution to consolidated earnings per common share – basic	$	0.02	$	0.24	$	0.14	$	0.89	$	0.68
Contribution to consolidated earnings per common share – basic	$	(0.15)	$	0.27	$	(0.64)	$	0.68	$	1.30

Adjusted EBITDA	$	25	$	71	$	99	$	261	$	184
(1) Marketing and trading margin excludes a pre-tax mark-to-market loss of $64 million in Q4 2016 (2015 - $37 million gain) and a loss of $203 million for the year ended December 31, 2016 (2015 - $2 million loss)
(2) Electricity sales exclude a pre-tax mark-to-market gain (loss) of nil in Q4 2016 (2015 - $22 million loss) and a loss of $7 million for the year ended December 31, 2016 (2015 - $39 million loss)
(3) Non-regulated fuel for generation and purchased power excludes a pre-tax mark-to-market gain of $13 million in Q4 2016 (2015 – $5 million loss) and a gain of $18 million for the year ended December 31, 2016 (2015 - $6 million loss)
(4) Income from equity investments excludes a pre-tax mark-to-market loss of $1 million in Q4 2016 (2015 - $10 million loss) and a loss of $1 million for the year ended December 31, 2016 (2015 - $6 million loss)
(5) Income tax expense (recovery) excludes a $16 million recovery relating to mark-to-market losses in Q4 2016 (2015 - $5 million recovery) and $59 million recovery relating to mark-to-market losses for the year ended December 31, 2016 (2015 - $22 million recovery)

Mark-to-Market Adjustments

Emera Energy’s “Marketing and trading margin”, “Electricity sales”, “Non-regulated fuel for generation and purchased power”, “Income from equity investments” and “Income tax expense (recovery)” are affected by mark-to-market (“MTM”) adjustments. The Emera Energy table above shows these amounts net of MTM adjustments and details these adjustments in footnotes to the table. Management believes excluding the effect of MTM valuations, and changes thereto, from income until settlement better matches the financial effect of these contracts with the underlying cash flows. Variance explanations of the MTM charges for this quarter and YTD are explained in the chart below.

Emera Energy has a number of AMAs with counterparties, including local gas distribution utilities, power utilities, and natural gas producers in the northeast. The AMAs involve Emera Energy buying or selling gas for a specific term, and the corresponding release of the counterparties’ gas transportation/storage

capacity to Emera Energy. MTM adjustments on these AMAs arise on the price differential between the point where gas is sourced and where it is delivered. At inception, the MTM adjustment is offset fully by the value of the corresponding gas transportation asset, which is amortized over the term of the AMA contract.

Subsequent changes in gas price differentials, to the extent they are not offset by the accounting amortization of the gas transportation asset, will result in MTM gains or losses recorded in income. MTM adjustments may be substantial during the term of the contract, especially in the winter months of a contract when delivered volumes and market volatility are usually at peak levels. As a contract is realized, and volumes reduce, MTM volatility is expected to decrease. Ultimately, the gas transportation asset and the MTM adjustment reduce to zero at the end of the contract term. As the business grows, and AMA volumes increase, MTM volatility resulting in gains and losses may also increase.

For the quarter, Emera Energy’s contribution to consolidated net income decreased by $71 million to a loss of $(31) million in Q4 2016 compared to $40 million in Q4 2015. Adjusted for after-tax derivative mark-to-market and the amortization of transportation capacity, Emera Energy’s adjusted contribution to consolidated net income decreased by $30 million to $5 million in Q4 2016 compared to $35 million in Q4 2015.

For the year ended December 31, 2016, Emera Energy’s contribution to consolidated net income decreased $209 million to a loss of $(110) million in 2016 compared to $99 million during the same period in 2015. Adjusted for after-tax derivative mark-to-market and the amortization of transportation capacity, Emera Energy’s adjusted contribution to consolidated net income decreased by $106 million to $24 million in 2016 compared to $130 million during the same period in 2015.

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

For the	Three months ended		Year ended
millions of Canadian dollars	December 31		December 31
Contribution to consolidated net income – 2014			$	186
Decreased marketing and trading margin reflects sustained high pricing and volatility in several of Emera Energy's markets in Q1 2014, largely the result of cold weather and a stronger USD in 2015				(32)
Increased electricity sales primarily due to a stronger USD and reduced planned outage work at Bridgeport in 2015, partially offset by lower power prices				25
Decreased non-regulated fuel for generation and purchased power is primarily due to lower commodity fuel prices, partially offset by a stronger USD and reduced planned outage work at Bridgeport in 2015				50
Increased income from equity investments primarily due to the resupply of the contracted power sales in Bear Swamp in 2015 that were not delivered in 2014 due to transmission line outages, NWP losses recorded in 2014 and the strengthening USD				14
Increased other income (expenses) primarily due to a gain on the sale of NWP				22
Increased interest expense, net primarily due to an intercompany loan with Corporate and Other put in place in Q2 2015				(13)
Increased income tax expense primarily due to increased income before provision for income taxes, changes in the proportion of income earned in higher tax rate foreign jurisdiction and a stronger USD				(29)
Decreased mark-to-market, net of tax, primarily due to changes in gas and power contract positions, amortization of transportation assets and the reversal of 2013 mark-to-market losses in 2014				(119)
Other				(5)
Contribution to consolidated net income – 2015	$	40	$	99
Decreased marketing and trading margin - See Marketing and Trading Margin section below		(15)		(27)
Decreased electricity revenues quarter-over-quarter primarily due to lower hedged power prices at the NEGG Facilities, partially offset by higher power prices at Bayside Power. Year-over-year also due to lower market power prices at the NEGG Facilities, partially offset by higher sales volumes as a result of fewer planned outage hours at the Bridgeport Facility in 2016 and a stronger USD		(34)		(86)
Decreased non-regulated fuel for generation and purchased power quarter-over-quarter primarily due to lower hedged commodity prices at the NEGG Facilities, offset by the expiry of a favourable gas contract at Bayside Power in 2016. Year-over-year also offset by the recognition of $20 million in state fuel taxes for 2013 through March 2016, fewer planned outage hours at the Bridgeport Facility in 2016, and a stronger USD		3		1
Decreased income from equity investments – see Equity Investments section below		(1)		(13)
Decreased other income (expenses), net year-over-year primarily due to a one-time gain on the sale of NWP in 2015 and foreign exchange losses in marketing and trading due to the impact of strengthening CAD on CAD liabilities		-		(26)
Decreased income tax expense primarily due to decreased income before provision for income taxes		18		65
Decreased mark-to-market, net of tax quarter-over-quarter primarily due to changes in existing positions on AMA's and amortization of gas transportation assets; year-over-year also due to changes in existing positions on long-term natural gas contracts		(41)		(103)
Other		(1)		(20)
Contribution to consolidated net income – 2016	$	(31)	$	(110)

A significant portion of Emera Energy earnings are exposed to foreign exchange fluctuations thereby affecting CAD dollar contribution to net earnings. Quarter-over-quarter in 2016 the impact of the USD decreased the loss in CAD dollars by $1 million compared to the same period in 2015. Year-to-date in 2016 the impact of the USD decreased the loss in CAD dollars by $13 million compared to the same period in 2015.

Energy Services

Emera Energy Services (“EES”) derives revenue and earnings from the wholesale marketing and trading of natural gas, electricity and other energy-related commodities and derivatives within the Company’s risk tolerances, including those related to value-at-risk (“VaR”) and credit exposure. EES purchases and sells physical natural gas and related transportation capacity rights and provides related energy asset management services. EES is also responsible for commercial management of electricity production and fuel procurement for Emera Energy Generation’s fleet. Established in 2002, Emera Energy’s marketing and trading business currently has approximately 90 employees engaged in commercial activities and related back office, legal and other support functions. The primary market for the marketing and trading business is northeastern North America, including the Marcellus shale gas region, the US Gulf Coast and Central Canada. Its counterparties include electric and gas utilities, natural gas producers, electricity generators and other marketing and trading entities. Marketing and trading operates in a competitive environment, and its business relies on knowledge of the region’s energy markets, understanding of pipeline infrastructure, a network of counterparty relationships and a focus on customer service. Emera Energy manages its commodity risk by limiting open positions, utilizing financial products to hedge purchases and sales, and investing in transportation capacity rights to enable movement across its portfolio.

Adjusted EBITDA

Adjusted EBITDA for Emera Energy's marketing and trading business is summarized in the following table:

For the	Three months ended				Year ended
millions of Canadian dollars	December 31				December 31
	2016		2015		2016		2015		2014
Marketing and trading margin	$	23	$	38	$	58	$	85	$	117
OM&G		7		8		22		21		25
Other income (expenses), net		1		1		(3)		5		3
Adjusted EBITDA	$	17	$	31	$	33	$	69	$	95

Marketing and Trading Margin

Marketing and trading margin is comprised of Emera Energy’s corresponding purchases and sales of natural gas and electricity, pipeline capacity costs and energy asset management services’ revenues.

Marketing and trading margin decreased $15 million to $23 million in Q4 2016 compared to $38 million in Q4 2015. Marketing and trading had more transportation capacity in Q4 2015 compared to Q4 2016, and had hedged that Q4 2015 capacity at favorable values.

For the year ended December 31, 2016, marketing and trading margin decreased $27 million to $58 million compared to $85 million in 2015. Higher Q1 2016 margin resulting from a stronger USD and growth in the volume of business was fully offset by the impact of less favorable market conditions and capacity hedges for the remainder of the year.

Generation

Emera Energy wholly owns and operates a portfolio of high efficiency, non-utility electricity generating facilities in northeast North America.

Information regarding Emera Energy’s wholly owned generation facilities is summarized in the following table:

Wholly Owned Generation Facilities	Location	Capacity (MW)	Commissioning/ In-Service Date	Fuel	Description
New England
Bridgeport (1)	Connecticut	560	1999	Natural gas	Selling electricity and capacity to ISO-NE
Tiverton (2)	Rhode Island	290	2000	Natural gas	Selling electricity and capacity to ISO-NE
Rumford	Maine	265	2000	Natural gas	Selling electricity and capacity to ISO-NE
Total New England		1,115
Maritime Canada
Bayside	New Brunswick	290	2001	Natural gas	Long-term power purchase agreement ("PPA") November - March; Selling electricity to Maritimes and ISO-NE for remainder of year
Brooklyn	Nova Scotia	30	1996	Biomass	Long-term PPA
Total Maritime Canada		320
Total EEG		1,435
(1) In Q2 2015, an upgrade at Bridgeport increased its nameplate capacity from 540 MW to 560 MW.
(2) In Q4 2016, an upgrade at Tiverton increased its nameplate capacity from 265 MW to 290 MW.

Emera Energy has approximately 115 employees in its generation business. For the portion of output not committed under PPAs, Emera Energy’s generation facilities sell into price-based competitive markets and earn revenues through the physical delivery of power and ancillary services, such as load regulation. The NEGG Facilities also participate in the regional capacity market and are compensated for being available to provide power. The electricity generation business in the northeast is seasonal. Winter and summer are generally the strongest periods, reflecting colder weather and fewer daylight hours in the winter season, and cooling load in the summer.

Emera Energy Generation

Adjusted EBITDA

Adjusted EBITDA is summarized in the following tables:

For the		Three months ended December 31
	New England				Maritime Canada				Total
millions of Canadian dollars	2016		2015		2016		2015		2016		2015
Energy sales	$	70	$	111	$	29	$	20	$	99	$	131
Capacity and other		10		12		-		-		10		12
Electricity sales	$	80	$	123	$	29	$	20	$	109	$	143
Non-regulated fuel for generation and purchased power		61		73		22		11		83		84
Non-regulated electric margin		19		50		7		9		26		59
Provincial, state and municipal taxes		3		1		1		-		4		1
Operating, maintenance and general		11		12		4		5		15		17
Other income (expenses), net		1		-		-		-		1		-
Adjusted EBITDA	$	6	$	37	$	2	$	4	$	8	$	41



For the		Year ended December 31
	New England						Maritime Canada						Total
millions of Canadian dollars	2016		2015		2014		2016		2015		2014		2016		2015		2014
Energy sales	$	327	$	414	$	366	$	86	$	88	$	109	$	413	$	502	$	475
Capacity and other		47		44		46		-		-		-		47		44		46
Electricity sales	$	374	$	458	$	412	$	86	$	88	$	109	$	460	$	546	$	521
Non-regulated fuel for generation and purchased power		261		277		312		65		52		73		326		329		385
Non-regulated electric margin		113		181		100		21		36		36		134		217		136
Provincial, state and municipal taxes		8		5		5		1		1		1		9		6		6
OM&G		42		38		30		21		18		21		63		56		51
Other income (expenses), net		1		2		-		1		(1)		-		2		1		-
Adjusted EBITDA	$	64	$	140	$	65	$	-	$	16	$	14	$	64	$	156	$	79

Adjusted EBITDA decreased $33 million to $8 million in Q4 2016 from $41 million in Q4 2015; and year-to-date decreased $92 million to $64 million in 2016 from $156 million for the same period in 2015.

The NEGG Facilities adjusted EBITDA decreased $31 million quarter-over-quarter primarily due to very favourable short-term economic hedges in Q4 2015 compared to Q4 2016 and increased property tax expense at the Bridgeport Facility in Q4 2016. For the year ended December 31, 2016 the NEGG Facilities adjusted EBITDA decreased $76 million. This decrease includes a $20 million charge to cost of fuel to recognize fuel taxes for 2013 through March 2016. Absent this, the NEGG Facilities adjusted EBITDA would have been $84 million, a decrease of $56 million year-over-year. This decrease reflects very favourable short-term economic hedges in 2015, primarily in Q1 and Q4 compared to the same period in 2016, partially offset by the stronger USD and fewer planned outage hours in 2016.

The Maritime Canada Facilities saw an increased cost of gas at Bayside Power, reflecting the expiry of a long-term favourable gas contract, and its replacement at market rates, which was the primary contributor to a $2 million decrease in adjusted EBITDA quarter-over-quarter; and a $16 million decrease year-over-year.

Operating Statistics

For the	Three months ended December 31
	Sales Volumes (GWh) (1)		Plant Availability (%) (2)				Net Capacity Factor (%) (3)
	2016	2015	2016		2015		2016		2015
New England	1,264	1,194	88.8	%	89.5	%	51.7	%	49.7	%
Maritime Canada	420	417	85.5	%	95.1	%	61.0	%	60.5	%
Total	1,684	1,611	88.1	%	90.8	%	53.8	%	52.1	%

For the	Year ended December 31
	Sales Volumes (GWh) (1)		Plant Availability (%) (2)				Net Capacity Factor (%) (3)
	2016	2015	2016		2015		2016		2015
New England	5,221	4,777	90.9	%	94.5	%	54.3	%	50.5	%
Maritime Canada	1,713	1,699	86.7	%	92.7	%	62.4	%	61.9	%
Total	6,934	6,476	90.0	%	94.1	%	56.1	%	53.0	%
(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.

Sales volumes, plant availability and net capacity factor were consistent quarter-over-quarter. Year-over-year sales volume and net capacity factor increase at the NEGG Facilities was primarily due to fewer planned outage hours in the first half of 2016 and an upgrade at the Bridgeport Energy Facility, completed in Q2 2015. The Maritime Canada Facilities sales volumes and net capacity factor were consistent with the prior year.

The NEGG Facilities sell into price based competitive markets. The primary reason the overall capacity factor is lower as compared to the Maritime Canada Facilities is because the Rumford Plant, in particular, generally operates with a capacity factor of approximately 20 per cent, reflecting current electricity and gas supply price dynamics in its markets.

Equity Investments

Information regarding Emera Energy's equity investment in the Bear Swamp generation facility is summarized below:

Investment in Generation Facility	Ownership	Location	Capacity (MW)	Fuel	Description
New England
Bear Swamp	50 per cent	Massachusetts	600	Hydro	Long-term PPA and selling electricity and capacity to ISO-NE

Adjusted income from equity investments

Adjusted income from equity investments is summarized in the following table:

For the	Three months ended				Year ended
millions of Canadian dollars	December 31				December 31
		2016		2015		2016		2015		2014
Bear Swamp	$	2	$	3	$	13	$	24	$	19
NWP		-		-		-		2		(7)
Adjusted income from equity investments	$	2	$	3	$	13	$	26	$	12

Adjusted Income from equity investments decreased $1 million to $2 million in Q4 2016 compared to $3 million in Q4 2015. For the year ended December 31, 2016, adjusted income from equity investments decreased $13 million to $13 million compared to $26 million in 2015. This is primarily due to a resupply

of contracted power sales in Bear Swamp in Q3 2015 that were not delivered in 2014 due to transmission line outages and higher interest costs at Bear Swamp as a result of its Q4 2015 refinancing.

Other Income

Income Taxes

Emera Energy is subject to corporate income tax at the statutory rate ranging from 39 to 42 per cent (combined US federal and state income tax rate) on its US sourced income and ranging from 29 to 31 per cent (combined Canadian federal and provincial income tax rate) on its Canada sourced income.

New England Gas Generating Facilities is subject to corporate income tax at the statutory rate ranging from 35 to 41 per cent (combined US federal and state income tax rate).

Brooklyn Energy is subject to corporate income tax at the statutory rate of 31 per cent (combined Canadian federal and provincial income tax rate).

Bear Swamp Refinancing

On October 8, 2015, Bear Swamp refinanced its $125 million USD bank debt that was due to mature in 2017 and issued $400 million USD in senior secured 10-year bonds, with $375 million USD at fixed rate of 4.89 per cent and $25 million USD at a floating rate of LIBOR plus 2.70 per cent. The proceeds of this financing were used to repay existing debt and provide working capital to the joint venture, with the remainder shared equally between Emera and its joint venture partner. After fees and expenses, Emera received a $179 million ($137 million USD) non-taxable distribution in Q4 2015.

CORPORATE AND OTHER

Review of 2016
Corporate and Other

For the	Three months ended				Year ended
millions of Canadian dollars	December 31				December 31
		2016		2015		2016		2015		2014
Intercompany revenue (1)	$	10	$	10	$	39	$	34	$	26
Operating revenues – regulated gas		12		13		38		52		49
Non-regulated operating revenue		28		10		55		40		49
Non-regulated direct costs		27		9		52		42		47
Operating, maintenance and general		9		33		133		105		47
Depreciation and amortization		1		1		4		2		3
Total operating expenses		37		43		189		149		97
Income (loss) from operations		13		(10)		(57)		(23)		27
Income (loss) from equity earnings		20		31		86		84		65
Other income (expenses), net (2)		(9)		(5)		229		(4)		4
Interest expense (3)		76		35		328		71		57
Adjusted income (loss) before provision for income taxes		(52)		(19)		(70)		(14)		39
Income tax expense (recovery) (4)		(35)		(12)		(100)		(28)		(12)
Preferred stock dividends		-		-		28		30		26
Adjusted contribution to consolidated net income	$	(17)	$	(7)	$	2	$	(16)	$	25
After-tax mark-to-market gain (loss)		2		100		(114)		98		-
Contribution to consolidated net income	$	(15)	$	93	$	(112)	$	82	$	25
Adjusted contribution to consolidated earnings per common share – basic	$	(0.08)	$	(0.05)	$	0.01	$	(0.11)	$	0.17
Contribution to consolidated earnings per common share – basic	$	(0.07)	$	0.63	$	(0.65)	$	0.56	$	0.17

Adjusted EBITDA	$	25	$	17	$	262	$	59	$	99
(1) Intercompany revenue consists of interest from EEG.
(2) Other income (expenses) net, excludes a pre-tax mark-to-market gain/loss of nil in Q4 2016 (2015 – $119 million gain) and a loss of $134 million for the year ended December 31, 2016 (2015 – $119 million gain).
(3) Interest expense excludes a pre-tax mark-to-market gain of $2 million in Q4 2016 (2015 – nil) and a gain of $2 million for the year ended December 31, 2016 (2015 – $4 million loss)
(4) Income tax expense (recovery), excludes a nil expense relating to mark-to-market gains in Q4 2016 (2015 – $19 million expense) and an $18 million recovery relating to mark-to-market losses for the year ended December 31, 2016 (2015 – $17 million expense).

Mark-to-Market Adjustments

The after-tax mark-to-market loss of $114 million for the year ended December 31, 2016 (2015 – gain of $98 million) primarily relates to the effect of the Debenture Offering USD-denominated currency revaluation and forward contracts put in place to hedge the proceeds from the final instalment of the Debenture Offering.

“Other income (expenses), net” and “Income tax expense (recovery)” are affected by the mark-to-market adjustments discussed above. Corporate and Other’s table above shows these amounts net of mark-to-market adjustments and details the adjustments in the footnotes.

Corporate and Other’s contribution to consolidated net income decreased by $108 million to a loss of $(15) million in Q4 2016 compared to earnings of $93 million in Q4 2015. For the year ended December 31, 2016, Corporate and Other’s contribution to consolidated net income decreased $194 million to a loss of $(112) million compared to earnings of $82 million in 2015. Highlights of the income changes are summarized in the following table:

For the	Three months ended		Year ended
millions of Canadian dollars	December 31		December 31
Contribution to consolidated net income – 2014			$	25
Increased intercompany revenue due to the issuance of a loan to Emera Energy Generation, partially offset by the repayment of an intercompany loan from Brunswick Pipeline		-		8
Acquisition costs related to the TECO Energy acquisition				(52)
Decreased OM&G primarily due to lower performance-based compensation and lower business development costs not related to the TECO Energy acquisition				(6)
Income from equity investments – see Income from Equity Investments section below				20
Decreased other income due to the reclassification of APUC subscription receipts, losses incurred in Emera Reinsurance from Tropical Storm Erika and the recognition of NSPML as an equity investment in Q2 2014				(8)
Increased interest expense primarily due to interest on convertible debentures represented by installment receipts, partially offset by maturity of long-term debt in Q4 2014				(15)
Decreased income tax expense primarily due to decreased income before provision for income taxes				16
Increased preferred stock dividends primarily due to issuance of preferred shares in Q2 2014				(4)
After-tax mark-to-market gain (loss) – see After-Tax Mark-to-Market Gain (Loss) section below				98
Contribution to consolidated net income – 2015	$	93	$	82
Decreased operating revenue - regulated gas primarily as a result of accruing bill credits for NMGC customers as a result of the stipulation agreement on the closing of the TECO Energy acquisition		-		(10)
Increased intercompany revenue due to the issuance of a loan to Emera Energy Generation		-		5
Decreased acquisition costs quarter-over-quarter due to higher TECO Energy acquisition costs in Q4 2015. Increased costs year-over-year due to higher TECO Energy acquisition costs in 2016		20		(37)
Decreased OM&G quarter-over-quarter primarily due to increase in recoveries from affiliates with the addition of Florida and New Mexico; year-over-year includes lower non TECO Energy related business development costs		3		9
Income from equity investments – see Income from Equity Investments section below		(11)		2
Gain on sale of APUC common shares, pre-tax		(12)		160
Gain on conversion of APUC subscription receipts and dividend equivalents into APUC common shares, pre-tax		-		63
Decreased interest expense quarter-over-quarter primarily due to no interest on convertible debentures in Q4 2016 and amortization of the fair market value debt adjustment related to the TECO Energy acquisition, Increased year-over-year also includes Beneficial Conversion Feature recognized on conversion of the Convertible Debentures, higher interest on Convertible Debentures, and interest on bridge facility related to the acquisition of TECO Energy		30		(111)
Post-acquisition interest on financing related to the TECO Energy acquisition, pre-tax		(71)		(146)
Increased income tax recovery primarily due to decreased income before provision for income taxes and deferred income taxes on regulated income recorded as regulatory assets and liabilities: year-over-year increase also due to the non- taxable portion of gains on APUC transactions		23		72
After-tax mark-to-market (loss) – see After-Tax Mark-to-Market Gain (Loss) section below		(98)		(212)
Other		8		11
Contribution to consolidated net income – 2016	$	(15)	$	(112)

TECO Energy Acquisition Related Costs

Highlights of the TECO Energy related acquisition costs are summarized in the following table:


For the		Three months ended				Year ended
millions of Canadian dollars		December 31				December 31
		2016		2015		2016		2015		2014
Operating revenues – regulated gas	$	-	$	-	$	(10)	$	-	$	-
Operating, maintenance, and general		1		21		89		52		-
Interest expense, net		-		23		148		24		-
Other income (expenses), net		-		-		(3)		-		-
Income tax expense (recovery)		(14)		(14)		(84)		(23)		-
Acquisition related costs	$	(13)	$	30	$	166	$	53	$	-

As part of the acquisition the Company has agreed to fund certain commitments in New Mexico. These commitments include contributions relating to economic development, donations, construction of an enlarged pipeline to the New Mexico/Mexico border, establishment of a matching fund to extend gas infrastructure in New Mexico and an annual customer bill reduction credit through June 30, 2018. For the year ended December 31, 2016, Emera recognized $10 million in “Operating revenues - Regulated gas” and $30 million in “Operating, maintenance, and general” associated with these commitments for a total of $40 million ($23 million after-tax).

In addition to the New Mexico commitments, operating, maintenance, and general expenses includes acquisition related legal, accounting, banking and advisory fees and the accelerated vesting of outstanding stock-based compensation awards. Other income (expenses), net includes foreign exchange gains on acquisition related transactions. Interest expense, net includes interest incurred on the convertible debentures represented by instalment receipts and the acquisition credit facility issued for the purpose of financing the TECO Energy acquisition. In addition, it includes interest for the period between the issuance date and the acquisition date on acquisition-related debt and the Beneficial Conversion Feature discount expensed on conversion of the convertible debentures.

After-Tax Mark-to-Market Gain (Loss)

The foreign currency earnings impact related to the translation of the TECO Energy acquisition related convertible debenture USD denominated cash balance and the mark-to-market adjustments from forward contracts from economically hedging the Debenture Offering are recorded as a mark-to-market adjustment to net income. Pre-tax losses in 2016 of $134 million for the year ($114 million after-tax loss) are recorded in “Other income (expenses), net” on the Consolidated Statements of Income. These losses offset a pre-tax mark-to-market gain of $119 million ($101 million after-tax gain) recorded in Q4 2015. The after-tax mark-to-market gain (loss) is summarized in the following table:

For the		Three months ended				Year ended
millions of Canadian dollars		December 31				December 31
		2016		2015		2016		2015		2014
Foreign exchange on TECO Energy acquisition related USD cash	$	-	$	27	$	(42)	$	27	$	-
Mark-to-market adjustment on interest rate hedges in EBP		2		-		2		(4)		-
Mark-to-market adjustment on USD forward contracts associated with the TECO Energy acquisition		-		92		(92)		92		-
Income tax expense (recovery)		-		(19)		18		(17)		-
After-tax mark-to-market gain (loss)	$	2	$	100	$	(114)	$	98	$	-

Income from Equity Investments

Income from equity investments are summarized in the following table:

For the		Three months ended				Year ended
millions of Canadian dollars		December 31				December 31
		2016		2015		2016		2015		2014
APUC	$	-	$	18	$	18	$	37	$	30
M&NP		6		6		23		23		18
NSPML		6		4		21		15		10
LIL		8		3		24		9		7
Income from equity investments	$	20	$	31	$	86	$	84	$	65

Income from equity investments decreased $11 million to $20 million in Q4 2016 compared to $31 million in Q4 2015. For the year ended December 31, 2016, income from equity investments increased $2 million to $86 million compared to $84 million in 2015. Highlights of the income changes are summarized in the following table:

For the	Three months ended		Year ended
millions of Canadian dollars	December 31		December 31
Income from equity investments – 2014			$	65
APUC – Due to higher equity earnings in 2015, the reclassification of APUC subscription receipts in 2015, partially offset by lower dilution on APUC share issuances in 2015 compared to dilutions related to share issuances in 2014				7
M&NP				5
NSPML – Due to the recognition of the AFUDC earnings of NSPML as income from equity investment				5
LIL – Increase in investment				2
Income from equity investments – 2015	$	31	$	84
APUC – Due to divestiture of shares		(18)		(19)
NSPML – Increase in equity investment		2		6
LIL – Increase in equity investment		5		15
Income from equity investments – 2016	$	20	$	86

Emera has invested $1.18 billion as at December 31, 2016 of equity, debt and working capital, including $132 million of AFUDC, in the development of the Maritime Link Project. Project to date, Emera has invested a $315 million in equity, comprised of $261 million in equity contributed and $54 million of accumulated retained earnings, with the remaining being funded with working capital and debt. The debt has been guaranteed by the Government of Canada. AFUDC on invested equity is being capitalized at an annual rate of 9 per cent. Proceeds from the federally guaranteed debt financing completed in April 2014 will be used to fund project costs until the Project's debt to equity ratio reaches 70 per cent to 30 per cent respectively in Q4 2015. From that point forward, project costs are being funded with debt and equity at a 70 per cent to 30 per cent ratio, with equity contributions of $106 million in 2016.

Emera has invested $400 million in the LIL as at December 31, 2016, which is comprised of $355 million in equity contributed and $45 million of accumulated equity earnings. Equity earnings are recorded based on an annual rate of 8.5 per cent of the equity invested (8.8 per cent prior to July 1, 2016). The rate is approved by the Newfoundland and Labrador Board of Commissioners of Public Utilities.

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 statements of cash flows between the years ended December 31, 2016 and 2015 include:

Year ended December 31
millions of Canadian dollars		2016		2015	$ Change
Cash and cash equivalents, beginning of period	$	1,073	$	221	$	852
Provided by (used in):
Operating cash flow before changes in working capital		919		776		143
Change in working capital		134		(102)		236
Operating activities		1,053		674		379
Investing activities		(9,105)		(124)		(8,981)
Financing activities		7,448		221		7,227
Effect of exchange rate changes on cash and cash equivalents		(65)		81		(146)
Cash and cash equivalents, end of period	$	404	$	1,073	$	(669)

Cash Flow from Operating Activities

Refer to Consolidated Income Statement Highlights for details.

Cash Flow Used in Investing Activities

Net cash used in investing activities increased $8,981 million to $9,105 million for the year ended December 31, 2016 compared to $124 million for the year ended December 31, 2015. The increase was primarily due to the acquisition of TECO Energy, proceeds from the sale of NWP in 2015, increased capital spending as a result of the acquisition of TECO Energy and increased investment in NSPML and LIL in 2016. This was partially offset by proceeds from the sale of APUC common shares in 2016.

Capital expenditures, including AFUDC and net of proceeds from disposal of assets, for the year ended December 31, 2016 were $1,102 million compared to $436 million in 2015. The increase is a result of the acquisition of TECO Energy, additional capital spending in NSPI and Emera Maine and the investment in a solar facility in Emera Caribbean. Details of the capital spend are shown below:

· $573 million at Emera Florida and New Mexico

· $309 million at NSPI (2015 - $274 million);

· $86 million at Emera Maine (2015 - $66 million);

· $87 million at Emera Caribbean (2015 - $44 million);

· $39 million at Emera Energy (2015 - $42 million);

· $8 million at Corporate and Other (2015 – $10 million)

Cash Flow from Financing Activities

Net cash provided by financing activities increased $7,227 million to $7,448 million for the year ended December 31, 2016 compared to $221 million in December 31, 2015. The increase was primarily due to the proceeds of the long-term debt issuance and convertible debentures related to the acquisition of TECO Energy, proceeds from the long-term debt issuance at ECI, issuance of equity at Emera in Q4 2016 and higher repayment of debt in 2015. This was partially offset by the 2015 proceeds of the long-term debt issuance by Brunswick Pipeline, redemption of NSPI preferred shares in 2015 and increased

2016 dividends on common stock. The majority of the net cash provided by financing activities was used to finance the TECO Energy acquisition.

Working Capital

As at December 31, 2016, Emera’s cash and cash equivalents were $404 million (2015 – $1,073 million) and Emera’s investment in non-cash working capital was $301 million (2015 – $600 million). Of the $1,073 million of cash and cash equivalents held at December 31, 2015, $728 million was from the proceeds from the convertible debentures for the TECO Energy acquisition and were held in USD. Of the $404 million cash and cash equivalents held at December 31, 2016, $267 million is held by Emera’s foreign subsidiaries (2015 – $373 million). A portion of these funds are invested in countries that have certain exchange controls, required approvals, and processes for repatriation. Such funds remain available to fund local operating and capital requirements unless repatriated.

Emera’s future liquidity and capital needs will be predominately for working capital requirements and capital expenditures in support of growth throughout the businesses, as well as acquisitions, dividends and debt servicing. In addition to using cash generated from operating activities, Emera uses available cash and credit facility borrowings to support normal operations and capital requirements. Emera may reduce short-term borrowings with cash from operations, long-term borrowings, or equity contributions. Emera has credit facilities with varying maturities that cumulatively provide $3.2 billion of credit (see note 24 and note 26 to the 2016 Annual Emera Consolidated Financial Statements for additional information regarding the credit facilities). Emera believes that its liquidity is adequate given its expected operating cash flows, capital expenditures, and related financing plans.

Contractual Obligations

As at December 31, 2016, 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	$	476	$	791	$	1,380	$	835	$	1,687	$	9,628	$	14,797
Purchased power (1)		253		224		206		202		198		2,272		3,355
Fuel and gas supply		475		161		109		28		22		-		795
DSM		42		48		13		-		-		-		103
Pension and post-retirement obligations (2)		133		47		48		49		51		863		1,191
Asset retirement obligations		2		1		1		1		46		396		447
Interest payment obligations (3)		686		641		611		565		515		6,524		9,542
Long-term payable		4		4		4		5		5		9		31
Convertible debentures represented by instalment receipts		-		-		-		-		-		9		9
Transportation (4)		496		392		310		280		196		1,622		3,296
Long-term service agreements (5)		92		55		67		44		42		227		527
Capital projects		133		-		-		-		-		-		133
Equity investment commitments (6)		236		-		-		200		-		-		436
Leases and other (7)		66		17		14		12		8		70		187
	$	3,094	$	2,381	$	2,763	$	2,221	$	2,770	$	21,620	$	34,849
(1) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths.
(2) 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.
(3) 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 December 31, 2016, including any expected required payment under associated swap agreements.
(4) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.
(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 ("FLG") 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 LIL 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 amount as the projects advance through construction.
(7) Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles.

In connection with the acquisition of TECO Energy, Emera made certain commitments approved by the NMPRC. Refer to note 4 of the Company's annual audited financial statements for additional information.

Beginning in 2018, NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over 35 years. The timing and amount of future payments could change based on UARB approval and 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.

Forecasted Gross Consolidated Capital Expenditures

2017 forecasted gross consolidated capital expenditures are as follows:

millions of Canadian dollars	Emera Florida and New Mexico		NSPI		Emera Maine		Emera Caribbean		Emera Energy		Corporate and Other		Total
Generation	$	153	$	106	$	-	$	19	$	44	$	-	$	322
New renewable generation		13		-		4		44		2		-		63
Transmission		39		91		45		18		-		-		193
Distribution		233		84		29		52		-		-		398
Gas transmission and distribution		283		-		-				-		-		283
Facilities, equipment, vehicles, and other		119		117		14		10		-		13		273
	$	840	$	398	$	92	$	143	$	46	$	13	$	1,532

Debt Management

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

As at December 31, 2016, the Company's total credit facilities, outstanding borrowings and available capacity were as follows:
			Revolving				Undrawn
			Credit				and
millions of dollars	Maturity		Facilities		Utilized		Available
Emera – Operating and acquisition credit facility	June 2020 – Revolver	$	700	$	63	$	637
Emera Florida and New Mexico - in USD - credit facilities	March 2017 - December 2018		1,300		708		592
NSPI – Operating credit facility	October 2020 – Revolver		600		265		335
Emera Maine – in USD – Operating credit facility	September 2019 – Revolver		80		26		54
Other – in USD – Operating credit facilities	Various		32		9		23

For the purpose of bridge financing for the acquisition of TECO Energy, on September 4, 2015, the Company secured an aggregate of $6.5 billion USD non-revolving term credit facilities (“Acquisition Credit Facilities”) from a syndicate of banks. The non-revolving term credit facilities were comprised of a $4.3 billion USD debt bridge facility, repayable in full on the first anniversary following its advance, and a $2.2 billion USD equity bridge facility repayable in full on the first anniversary following its advance.

On October 16, 2015, Emera permanently reduced the USD bridge facilities in the amount of $588.3 million USD and on June 16, 2016, Emera further reduced the USD bridge facilities by $4.8 billion. On August 2, 2016, the Convertible Debentures Final Instalment Date, Emera obtained the remaining two- thirds of the Convertible Debentures instalment. The net proceeds were $1.4 billion and were used to fully repay the Company’s acquisition credit facility.

Emera’s future liquidity and capital needs will be predominately for working capital requirements and capital expenditures in support of growth throughout the businesses, potential new acquisitions, dividends and debt servicing. These liquidity and capital needs will be financed through internally generated cash flows, short-term credit facilities, and ongoing access to capital markets.

Emera and its subsidiaries recent financing activity is discussed in the Developments section of this MD&A, including the most recent capital markets transactions relating to the TECO Energy Acquisition.

Credit Ratings

Emera and its subsidiaries have been assigned the following senior unsecured debt ratings:

	S&P	Moody's	Fitch	DBRS
Emera Inc.	BBB (Negative)	Baa3 (Stable)	N/A	N/A
TECO Energy/TECO Finance	BBB (Negative)	Baa2 (Stable)	BBB (Stable)	N/A
TEC	BBB+ (Negative)	A3 (Stable)	A- (Stable)	N/A
NMGC	BBB+ (Negative)	N/A	N/A	N/A
NSPI	BBB+ (Negative)	N/A	N/A	A (low) (Stable)

Emera

In June 2016, as a result of the TECO Energy acquisition outlined in the Developments section of this MD&A, Moody’s Investor Services assigned the following new credit ratings to Emera:

Issuer		Baa3 (Stable Outlook)
Senior Unsecured		Baa3
Subordinate		Ba2

Emera Florida and New Mexico

On July 6, 2016, Moody’s downgraded the credit ratings of TECO Energy and TECO Finance to Baa2 from Baa1 and the issuer rating and senior unsecured ratings of TEC to A3 from A2. Moody’s described the ratings outlook for the companies as stable.

On July 1, 2016, following the Merger with Emera, S&P affirmed the issuer credit ratings of TECO Energy and the senior unsecured debt ratings of its subsidiaries, TECO Finance, TEC and NMGC, and maintained the ratings outlook at negative.

On October 9, 2015, Fitch Ratings affirmed the issuer default ratings of TECO Energy at BBB and TEC at BBB+ and affirmed the senior unsecured debt rating of its subsidiaries, TECO Finance and TEC. Fitch Ratings also described the ratings outlook as stable.

NSPI

On December 13, 2016, DBRS affirmed all ratings on NSPI.

On May 25, 2016, S&P affirmed all ratings on NSPI

Emera Maine, BLPC, Domlec and GBPC have no public debt, and accordingly have no requirement for public credit ratings. These utilities’ credit facilities provide adequate access to capital to support current operations and a base level of capital expenditures. For additional capital needs, these utilities expect to have sufficient access to competitively priced financing in the unsecured or secured debt markets.

A credit rating is not a recommendation to buy, hold or sell securities and may be subject to revision or withdrawal at any time by the assigned rating agency. Our access to capital markets and cost of financing are influenced by the ratings of our securities. A downgrade, if any, in any rating may affect our ability to borrow and may increase financing costs, which may decrease earnings.

Emera and its subsidiaries have certain financial and other covenants associated with their debt and credit facilities. Covenants are tested regularly and the Company is in compliance with covenant requirements. Emera’s significant covenant is listed below:

			As at
	Financial Covenant	Requirement	December 31, 2016
Emera
Syndicated credit facilities	Debt to capital ratio	Less than or equal to 0.70 to 1	0.62:1

Share Capital

Emera

As at December 31, 2016, Emera had 210.02 million (2015 – 147.21 million) common shares issued and outstanding. For the year ended December 31, 2016, 10.82 million common shares were issued (2015 – 3.43 million) for net proceeds of $466 million (2015 – $141 million).

On December 16, 2016, Emera completed an offering of 6,630,000 common shares, at $45.25 per common share. On December 21, 2016, underwriters fully exercised an over-allotment option of 994,500 common shares, at $45.25 per common share. The aggregate gross and net proceeds from the offering, including the over-allotment, were $345 million and $335 million, respectively. The proceeds of the offering were used for general corporate purposes.

As at December 31, 2016, Emera had 29 million preferred shares issued and outstanding (2015 – 29 million).

PENSION FUNDING

For funding purposes, Emera determines required contributions to its largest defined benefit pension plans based on smoothed asset values. This reduces volatility in the cash funding requirement as the impact of investment gains and losses are recognized over a three-year period. The cash required in 2017 for defined benefit pension plans is expected to be $117 million (2016 – $49 million). All pension plan contributions are tax deductible and will be funded with cash from operations.

Emera’s defined benefit pension plans employ a long-term strategic approach with respect to asset allocation, real return and risk. The underlying objective is to earn an appropriate return, given the Company’s goal of preserving capital within an acceptable level of risk for the pension fund investments.

To achieve the overall long-term asset allocation, pension assets are managed by external investment managers per the pension plan’s investment policy and governance framework. The asset allocation includes investments in the assets of Canadian and global equities, domestic and global bonds and short-term investments. Emera reviews investment manager performance on a regular basis and adjusts the plans’ asset mixes as needed in accordance with the pension plans’ investment policy.

Emera’s projected contributions to defined contribution pension plans are $27 million for 2017 (2016 – $17 million actual).

Defined Benefit Pension Plan Summary
As at December 31, 2016
in millions of Canadian dollars
Plans by region	TECO Energy Pension Plans		NSPI Pension Plans		Emera Maine Pension Plans		Caribbean Plans		Total
Assets as at December 31, 2016	$	872	$	1,161	$	165	$	10	$	2,208
Accounting obligation at December 31, 2016		1,033		1,354		207		13		2,607
Accounting expense during fiscal 2016	$	12	$	48	$	7	$	-	$	67

OFF-BALANCE SHEET ARRANGEMENTS

Defeasance

Upon privatization of the former provincially owned Nova Scotia Power Corporation (“NSPC”) in 1992, NSPI became responsible for managing a portfolio of defeasance securities that provide principal and interest streams to match the related defeased debt, which at December 31, 2016 totaled $753 million (2015 – $765 million). The securities are held in trust for Nova Scotia Power Finance Corporation (“NSPFC”), an affiliate of the Province of Nova Scotia. Approximately 80 per cent of the defeasance portfolio consists of investments in the related debt, eliminating all risk associated with this portion of the portfolio; the remaining defeasance portfolio has a market value higher than the related debt, reducing the future risk of this portion of the portfolio.

Under the privatization agreements, NSPI administers the defeasance cash flows and obligations pursuant to a Management and Administration Agreement. The NSPFC bank accounts are included in NSPI’s pool of bank accounts under a mirror netting agreement and therefore, from time to time, if any cash accumulates in the NSPFC bank account it is available until that cash is required to service the defeased NSPC debt.

Guarantees and Letters of Credit

Emera had significant guarantees and letters of credit on behalf of third parties outstanding as discussed below. These are not included within the Consolidated Balance Sheets as at December 31, 2016:

Emera has provided a completion guarantee to the Government of Canada, whereby it has guaranteed the performance of the obligations of NSPML to cause the completion of the Maritime Link Project, subject to certain conditions set out in that guarantee. The cost of those obligations is estimated to be $1.577 billion, which reduces in the ordinary course as project costs are paid. The current exposure as at December 31, 2016 is $577 million.

TECO Coal was sold on September 21, 2015 to Cambrian Coal Corporation (“Cambrian”). Pursuant to the sales agreement, Cambrian is obligated to file applications required in connection with the change of control with the appropriate governmental entities. Once the applicable governmental agency deems each application to be acceptable, Cambrian is obligated to post a bond or other appropriate collateral necessary to obtain the release of the corresponding bond secured by the TECO Energy indemnity for that permit. Until the bonds secured by TECO Energy's indemnity are released, TECO Energy's indemnity will remain effective. As a result of the sale in September 2015, the letters of indemnity guaranteed $124 million ($95 million USD).

TECO Energy has remaining letters of indemnity related to TECO Coal, which totaled $80 million ($59 million USD) at December 31, 2016. As of that date Cambrian had posted approximately $54 million ($40 million USD) of additional reclamation bonds to replace corresponding reclamation bonds supported by TECO Energy’s indemnity. TECO Energy’s indemnity obligations in respect of such bonds will not be released until the applicable State department processes the applicable permit transfers and releases such bonds. These letters of indemnity guarantee payments to certain surety companies that issued

reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal's mining operations. Payments to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder, TECO Coal, does not pay the surety.

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.

NSPI has a standby letter of credit to secure obligations under an unfunded pension plan in NSPI. The letter of credit expires in June 2017 and is renewed annually. The amount committed as at December 31, 2016 was $47 million.

Emera has standby letters of credit in the amount of $24 million USD for the benefit of secured parties in connection with a refinancing of the Bear Swamp joint venture and also to third parties that have extended credit to Emera and its subsidiaries. These letters of credit typically have a one-year term and are renewed annually as required.

DIVIDEND PAYOUT RATIO

Emera targets a dividend payout ratio of 70 to 75 per cent of adjusted net income. Emera Incorporated’s common share dividends paid in 2016 were $1.9950 ($0.4750 in Q1 and Q2 and $0.5225 in Q3 and Q4) per common share and $1.6625 ($0.3875 in Q1, $0.4000 in Q2 and Q3 and $0.4750 in Q4) per common share for 2015, representing a payout ratio of 68.2 per cent of adjusted net income in 2016 and 72.8 per cent for 2015. The decrease in the payout ratio is primarily due to a large increase in adjusted net income in 2016 as a result of the net gain realized on the sale of APUC.

ENTERPRISE RISK AND RISK MANAGEMENT

Emera has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach to risk management. Certain risk management activities for Emera are overseen by the Enterprise Risk Management Committee to ensure such risks are appropriately assessed, monitored and controlled within predetermined risk tolerances established through approved policies.

The Company’s risk management activities are focused on those areas that most significantly impact profitability, quality of income and cash flow. In this section, Emera describes these principal risks that management believes could materially affect its business, revenues, operating income, net income, net assets, or liquidity or capital resources. The nature of risk is such that no list is comprehensive, and other risks may arise or risks not currently considered material may become material in the future.

Regulatory and Political Risk

The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of the recovery of costs and investments. As cost-of-service utilities with an obligation to serve customers, Tampa Electric, PGS, NMGC, NSPI, Emera Maine, BLPC, GBPC, and Domlec must obtain regulatory approval to change electricity rates and/or riders from their respective regulators. Costs

and investments can be recovered upon approval by the respective regulator as an adjustment to rates and/or riders, which normally requires a public hearing process or may be mandated by other governmental bodies. In addition, the commercial and regulatory frameworks under which Emera and its subsidiaries operate can be impacted by significant shifts in government policy (including shifts in policy which could occur as a result of climate change concerns) and changes in governments. Emera’s investments in entities in which it has significant influence and which are subject to regulatory risk include: NSPML, LIL, M&NP and Lucelec.

During public hearing processes, consultants and customer representatives scrutinize the costs, actions and plans of these rate regulated companies and their respective regulators determine whether to allow recovery and to adjust rates based upon the evidence and any contrary evidence from other parties. In some circumstances, other government bodies may influence the setting of rates. The subsidiaries manage this regulatory risk through transparent regulatory disclosure, ongoing stakeholder and government consultation and multi-party engagement on aspects such as utility operations, fuel-related audits, rate filings and capital plans. The subsidiaries employ a collaborative regulatory approach through technical conferences and, where appropriate, negotiated settlements.

Brunswick Pipeline has a 25-year firm service agreement, expiring in 2034, with Repsol Energy Canada (“REC”). This firm service agreement was filed with the NEB, and provides for predetermined toll increases after the fifth and fifteenth year of the contract. As a regulated Group II pipeline, the tolls of Brunswick Pipeline are regulated by the NEB on a complaint basis. Brunswick Pipeline is required to make copies of tariffs and supporting financial information readily available to interested persons. Persons who cannot resolve traffic, toll and tariff issues with Brunswick Pipeline may file a complaint with the NEB. In the absence of a complaint, the NEB does not normally undertake a detailed examination of Brunswick Pipeline’s tolls.

Weather and Climate Risk

Shifts in weather patterns affect energy sales and associated revenues and costs. Extreme weather events generally result in increased operating costs associated with restoring service to customers as a result of unplanned outages. Emera responds to outages which occur as a result of significant weather events according to each subsidiary’s respective emergency services restoration plan.

Changes in Environmental Legislation

Emera is subject to regulation by federal, provincial, state, regional and local authorities with regard to environmental matters; primarily related to its utility operations. This includes laws setting GHG emissions standards and air emissions standards. Emera is also subject to laws regarding the generation, storage, transportation, use and disposal of hazardous substances and materials.

In addition to imposing continuing compliance obligations, there are permit requirements, laws and regulations authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is, and may be, material to Emera. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on Emera. In addition, Emera’s business could be materially affected by changes in government policy, utility regulation, and environmental and other legislation that could occur in response to environmental and climate change concerns.

New emission reductions requirements for the utilities sector are being established by governments in Canada and the United States. Changes to GHG emissions standards and air emissions standards could adversely affect Emera’s operations and financial performance. Stricter environmental laws and enforcement of such laws in the future could increase Emera’s exposure to additional liabilities and costs. These changes could also affect earnings and strategy by changing the nature and timing of capital investments.

Emera manages its environmental risk by operating in a manner that is respectful and protective of the environment and with the objective of achieving full compliance with applicable laws, legislation and company policies and standards. Emera has implemented this policy through the development and application of environmental management systems in its operating subsidiaries. Comprehensive audit programs are also in place to regularly test compliance with such laws, policies and standards.

Cybersecurity Risk

Emera’s reliance on information technology systems and network infrastructure to manage its business, including controls for interconnected systems of generation, distribution and transmission, exposes the Company to potential risks related to cybersecurity attack. Attacks can occur over the Internet, through malware, viruses, attachments to e-mails, through persons inside of the organization or through persons with access to systems outside of the organization. A cybersecurity attack could disrupt operations, cause loss of important data or compromise customer, employee-related or other critical information or systems, or otherwise adversely affect Emera’s business and financial results and condition.

Despite security measures in place, the Company’s systems, assets and information could experience security breaches that could cause system failures, disrupt operations, adversely affect safety, result in loss of service to customers and release of sensitive or confidential information. Should such cybersecurity risks materialize, the Company could suffer costs, losses and damage, all or some of which may not be recoverable through legal, regulatory or other processes. The Company seeks to manage this risk by maintaining a cybersecurity strategy, based on the National Institute of Standards and Technology Cyber Security Framework, to both comply with relevant regulation and sustain industry best-practice governance and capability.

Energy Consumption Risk

Typical of utilities, Emera’s rate-regulated subsidiaries are affected by demand for energy in the areas in which it operates based upon fluctuations in general economic conditions, such as changes in employment levels, personal disposable income, energy prices and housing starts. Customers’ focus on energy efficiency also results in changes in energy consumption. Government policies promoting distributed generation and new technology developments enabling those policies, particularly with rooftop solar, have the potential to impact how electricity enters the system and how it is bought and sold. This could negatively impact operations, net earnings and cash flows.

Energy costs and clean energy options have increased demand for products enabling the consumers’ ability to self-generate. The Company’s rate-regulated subsidiaries are actively involved in all aspects of customer demand, energy efficiency and government policy to ensure that the impact of these activities benefits customers, are not detrimental to the reliability of the energy service the subsidiary provides, and are accommodated through regulations. Additionally, the Company is monitoring the evolution of distributed generation and technology through its strategic initiatives.

Foreign Exchange Risk

The Company is exposed to foreign currency exchange rate changes. 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, Emera 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. The Company enters into foreign exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenues streams, capital expenditures and capital projects. 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 are included in accumulated other comprehensive income (loss) (“AOCI”).

In 2016, approximately 35 per cent of Emera’s adjusted net income was derived from subsidiaries with a US dollar functional currency. As such, Emera’s earnings are subject to fluctuations in the Canadian dollar to US dollar exchange rate. The operations of TECO Energy are conducted in US dollars, thus Emera’s consolidated net income and cash flows are impacted to a greater extent than before the acquisition, by movements in the US dollar relative to the Canadian dollar. The July 1, 2016 acquisition of TECO Energy is expected to increase the percentage of Emera’s adjusted net income to approximately 70 per cent going forward. In particular, decreases in the value of the US dollar versus the Canadian dollar, could negatively impact the Company’s net income as it is reported in Canadian dollars.

Capital Market and Liquidity Risk

Emera’s operations and projects in development require significant capital investments in property, plant and equipment. Consequently, Emera is an active participant in the debt and equity markets. After giving effect to the TECO Energy acquisition, Emera now has total debt of approximately $15 billion. Any disruption in capital markets could have a material impact on Emera’s ability to fund its operations. Capital markets are global in nature and are affected by numerous events throughout the world economy. Capital market disruptions could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions.

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 change to a credit rating as a result of changes in any of these items 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.

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, short-term credit facilities, and ongoing access to capital markets. The Company reasonably expects liquidity sources to exceed ordinary course capital needs.

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. While 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 raise 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.

Project Development and Construction Risk

ENL’s investment in the development of the Maritime Link Project has risks commensurate with any large construction project. Risks related to large projects can include, but are not limited to, impact on costs from schedule delays, risk of cost overruns, and ensuring compliance with operating and environmental requirements. Emera deploys robust project and risk management approaches, led by teams with extensive experience in large projects. Specific to the Maritime Link, there are significant contractual terms in place protecting Emera and ENL from any exposure to cost overruns to either of Nalcor’s projects and with specific provisions for Nalcor sharing in cost overruns of the Maritime Link Project.

Emera Energy Marketing and Trading

The majority of Emera’s portfolio of electricity and gas marketing and trading contracts, and in particular its natural gas asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or short commodity positions. However, the portfolio is subject to commodity price risk, particularly with respect to basis point differentials between relevant markets, in the event of an operational issue or counterparty default.

To measure commodity price risk exposure, Emera employs a number of controls and process, including an estimated value-at-risk (“VaR”) analysis of its exposures. The VaR amount represents an estimate of the potential change in fair value that could occur from changes in market factors within a given confidence level, if an instrument or portfolio is held for a specified time period. The VaR calculation is used to quantify exposure to market risk associated with physical commodities, primarily natural gas and power positions. The Company’s commercial arrangements, including the combination of supply and purchase agreements, asset management agreements, pipeline transportation agreements and financial hedging instruments, as well as its credit policies, counterparty credit assessments, market and credit position reporting, and other risk management and reporting practices, are all used to manage and mitigate this risk.

Emera Energy Electricity Sales and Non-Regulated Fuel for Generation and Purchased Power

Emera Energy’s natural gas fired plants in the northeastern United States, operating as merchant facilities, are susceptible to the volatility of the New England electricity market and natural gas prices. Market electricity prices are dependent upon a number of factors, including the projected supply and demand of electricity, natural gas prices, the price of other materials used to generate electricity, the cost of complying with applicable environmental and other regulatory requirements and weather conditions. A material change in any one of these factors can materially affect the profitability of the facilities. The Company takes a strategic approach to hedging the volatility of pricing risk in these markets. When market prices are favourable, the Company will typically enter into hedging instruments that effectively fix the price of natural gas and electricity.

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.

Country Risk

Operating revenues outside of Canada constituted 65 per cent (55 per cent from the US and 10 per cent from the Caribbean) of Emera’s total operating revenues in 2016 (2015 – 45 per cent, with 28 per cent from the US and 17 per cent from the Caribbean). Emera’s investments are currently in regions where

the political and economic risk levels are considered by the Company to be acceptable. Emera’s operations in some countries may be subject to changes in the rate of economic growth, restrictions on the repatriation of income or capital exchange controls, inflation, the effect of global health, safety and environmental matters or economic conditions and market conditions, and change in financial policy and availability of credit. The Company mitigates this risk through a rigorous approval process for investment, and by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available in all affiliates.

Commercial Relationships Risk

The Company is exposed to commercial relationships risk in respect of its reliance on certain key partners, suppliers and customers. The Company manages its commercial relationships risk by monitoring credit risk, as discussed above in Credit Risk, and monitoring of significant developments with its customers, partners and suppliers.

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.

Future Employee Benefit Plan Performance and Funding Risk

Certain Emera subsidiaries have both defined benefit and defined contribution employee benefit plans that cover their employees and retirees. All defined benefit plans are closed to new entrants, with the exception of the TECO Energy Group Retirement Plan. The cost of providing these benefit plans varies depending on the plan provisions, interest rates, investment performance and actuarial assumptions concerning the future. Actuarial assumptions include earnings on plan assets, discount rates (interest rates used to determine funding levels, contributions to the plans and the pension and post-retirement liabilities) and expectations around future salary growth, inflation and mortality. Two of the largest drivers of cost are investment performance and interest rates, which are affected by global financial and capital markets. Depending on future interest rates and actual versus expected investment performance, Emera could be required to make larger contributions in the future to fund these plans, which could affect Emera’s cash flows, financial condition and operations.

Each of Emera’s employee defined benefit pension plans are managed according to an approved investment policy and governance framework. Emera employs a long-term approach with respect to asset allocation and each investment policy outlines the level of risk which the Company is prepared to accept with respect to the investment of the pension funds in achieving both the Company’s fiduciary and financial objectives. Studies are routinely undertaken every 3 to 5 years with the objective that the plans’ asset allocations are appropriate for meeting Emera’s long term pension objectives.

Labour Risk

Certain Emera employees are subject to collective labour agreements. Approximately 39 per cent of the full-time and term employees within the Emera labour force are represented by unions.

As at December 31, 2016, approximately 10 per cent of the entire labour force is covered by collective labour agreements that will expire within the next 12 months. Emera seeks to manage this risk through

ongoing discussions with local unions. The Company maintains contingency plans in each of its operations to manage and reduce the effect of any potential labor disruption.

Information Technology Risk

Emera relies on various information technology systems to manage operations. This subjects Emera to inherent costs and risks associated with maintaining, upgrading, replacing and changing these systems. This includes impairment of its information technology, potential disruption of internal control systems, substantial capital expenditures, demands on management time and other risks of delays, difficulties in upgrading existing systems, transitioning to new systems or integrating new systems into its current systems.

Emera manages this risk through regular IT asset lifecycle management, dedicated project teams, executive oversight and appropriate governance structures and strong project management practices. Employees with extensive subject matter expertise assist in planning, project management, implementation and training. Formal back up and critical incident response practices ensure that continuity is maintained in the event of any disruptions or incidents.

Enterprise Resource Planning (“ERP”) Implementation Risk

Certain Emera affiliates are in the process of updating their financial information systems through the implementation of an integrated ERP system. There are risks associated with this project, and the Company has adopted a detailed plan to address the risks inherent in the implementation process. The implementation of an ERP system will require the investment of significant financial and human resources. Disruptions, delays or deficiencies in the design and implementation of the new ERP system could affect Emera’s ability to monitor its business, pay its suppliers and prepare its financial statements accurately and on a timely basis. Emera manages this risk through a dedicated project team, with executive oversight and a detailed governance structure. Consultants, with extensive ERP expertise, have and will continue to assist in planning, design, project management, implementation and training. The expected implementation date is in late 2017.

System Operating and Maintenance Risks

The safe and reliable operation of electric generation and electric and natural gas transmission and distribution systems is critical to Emera’s operations. There are a variety of hazards and operational risks inherent in operating electric utilities and natural gas transmission and distribution pipelines. Electric generation, transmission and distribution operations can be impacted by risks such as mechanical failures, activities of third parties, damage to facilities and infrastructure caused by hurricanes, storms, falling trees, lightning strikes, floods, fires and other natural disasters. Natural gas pipeline operations can be impacted by risks such as leaks, explosions, mechanical failures, activities of third parties and damage to the pipelines facilities and equipment caused by hurricanes, storms, floods, fires and other natural disasters. Electric utility and natural gas transmission and distribution pipeline operation interruption could negatively affect revenue, earnings, and cash flows as well as customer and public confidence. Emera manages these risks by investing in a highly skilled workforce, operating prudently, preventative maintenance and making effective capital investments. Insurance, warranties, or recovery through regulatory mechanisms may not cover any or all of these losses, which could adversely affect the Company’s results of operations and cash flows.

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 benefits are determined by existing tax laws and could be negatively impacted by changes in laws. “Comprehensive tax reform” remains a topic of discussion in the U.S. Congress. Such legislation could significantly alter the existing tax code, including a reduction in the corporate income tax rate. Although a reduction in the

corporate income tax rate could result in lower future tax expense and tax payments, it would also reduce the value of the Company’s existing deferred tax assets and could result in a charge to earnings if written down. 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.

Uninsured Risk

Emera and its subsidiaries maintain insurance to cover accidental loss suffered to its facilities, and to provide indemnity in the event of liability to third parties. This is consistent with Emera’s risk management policies. There are certain elements of Emera’s operations which are not insured. These include a significant portion of its electric utilities’ transmission and distribution assets, as is customary in the industry. The cost of this coverage is not economically viable. In addition, Emera accepts deductibles and self-insured retentions under its various insurance policies. Insurance is subject to coverage limits as well as time sensitive claims discovery and reporting provisions and there can be no assurance that the types of liabilities or losses that may be incurred by the Company and its subsidiaries will be covered by insurance.

The occurrence of significant uninsured claims, claims in excess of the insurance coverage limits maintained by Emera and its subsidiaries or claims that fall within a significant self-insured retention could have a material adverse effect on Emera’s results of operations, cash flows and financial position, if regulatory recovery is not available. A limited portion of Emera’s property and casualty insurance is placed with a wholly owned captive insurance company. If a loss is suffered by the captive insurer, it is not able to recover that loss other than through future premiums.

The Company mitigates its uninsured risk by ensuring that insurance limits align with risk exposures, and for uninsured assets and operations, that appropriate risk assessments and mitigation measures are in place. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs, including uninsured losses.

RISK MANAGEMENT INCLUDING FINANCIAL INSTRUMENTS

Emera’s risk management policies and procedures provide a framework through which management monitors various risk exposures. The risk management policies and practices are overseen by the Board of Directors. The Company has established a number of processes and practices to identify, monitor, report on and mitigate material risks to the Company. This includes establishment of the Enterprise Risk Management Committee, whose responsibilities include preparing and updating a “Risk Dashboard” for the Board of Directors on a quarterly basis. Furthermore, a corporate team independent from operations is responsible for tracking and reporting on market and credit risks.

The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange and interest rates through contractual protections with counterparties where practicable, as well as by using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. Collectively, these contracts and financial instruments are considered “derivatives”.

The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception 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 creditworthy. The Company continually assesses contracts designated under the NPNS

exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met.

Derivatives qualify for hedge accounting if they meet stringent documentation requirements, and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the effective portion of 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. Any ineffective portion of the change in the fair value of the cash flow hedges is recognized in net income in the reporting period.

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

Derivatives entered into by Tampa Electric, PGS, NMGC, NSPI 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 realized gain or loss is recognized when the hedged item settles in regulated fuel for generation and purchased power, inventory or property, plant and equipment, depending on the nature of the item being economically hedged. Management believes that any gains or losses resulting from settlement of these derivatives be refunded to or collected from customers in future rates.

Derivatives that do not meet any of the above criteria are designated as HFT and are recognized on the balance sheet at fair value. All gains or losses are recognized 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 when another accounting treatment applies.

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	December 31		December 31
millions of Canadian dollars		2016		2015
Derivative instrument assets (current and other assets)	$	10	$	20
Derivative instrument liabilities (current and long-term liabilities)		(27)		(46)
Net derivative instrument assets (liabilities)	$	(17)	$	(26)

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		Year ended
millions of Canadian dollars		December 31
		2016		2015
Operating revenues – regulated	$	(12)	$	(9)
Non-regulated fuel for generation and purchased power		2		5
Income from equity investments		(1)		(1)
Effective net gains (losses)	$	(11)	$	(5)

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

Regulatory Items Recognized on the Balance Sheets

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

As at	December 31		December 31
millions of Canadian dollars		2016		2015
Derivative instrument assets (current and other assets)	$	229	$	210
Regulatory assets (current and other assets)		11		64
Derivative instrument liabilities (current and long-term liabilities)		(12)		(64)
Regulatory liabilities (current and long-term liabilities)		(231)		(210)
Net asset (liability)	$	(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	Year ended December 31
millions of Canadian dollars		2016		2015
Regulated fuel for generation and purchased power (1)	$	2	$	41
Net gains (losses)	$	2	$	41
(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 Items Recognized on the Balance Sheets

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

As at	December 31		December 31
millions of Canadian dollars		2016		2015
Derivative instruments assets (current and other assets)	$	37	$	96
Derivative instruments liabilities (current and long-term liabilities)		(434)		(332)
Net derivative instrument assets (liabilities)	$	(397)	$	(236)

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		Year ended
millions of Canadian dollars	December 31
		2016		2015
Non-regulated operating revenues	$	68	$	15
Non-regulated fuel for generation and purchased power		(7)		(3)
Other income (expenses), net		(2)		(1)
Net gains (losses)	$	59	$	11

Other Derivatives Recognized on the Balance Sheets

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

As at	December 31		December 31
millions of Canadian dollars	2016		2015
Derivative instrument assets (current and other assets)	$	-	$	92
Derivative instrument liabilities (current and long-term liabilities)		(2)		(3)
Net derivative instrument assets (liabilities)	$	(2)	$	89

Other Derivatives Recognized in Net Income

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

For the		Year ended
millions of Canadian dollars		December 31
		2016		2015
Other income (expense)	$	(87)	$	92
Interest expense, net		2		(3)
Total gains (losses)	$	(85)	$	89

DISCLOSURE AND INTERNAL CONTROLS

The Company, under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, has designed as at December 31, 2016, disclosure controls and procedures (“DC&P”) and internal controls over financial reporting (“ICFR”) as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”).

The Chief Executive Officer and Chief Financial Officer have caused to be evaluated under their supervision, with the assistance of Company employees, the effectiveness of the Company’s DC&P and ICFR, and based on that evaluation, have concluded DC&P and ICFR were effective as at December 31, 2016.

There have been no changes in Emera or its consolidated subsidiaries’ ICFR during the period beginning on January 1, 2016 and ending on December 31, 2016, which have materially affected or are reasonably likely to materially affect ICFR except as outlined below.

Limitation on Scope of Design

NI 52-109 permits a business that the issuer acquires not more than 365 days before the issuer’s financial year-end to be excluded from its scope of certifications. The Company has limited the scope of design of DC&P and ICFR to exclude controls, policies and procedures relating to TECO Energy

(including its holdings Tampa Electric, PGS and NMGC) which was acquired on July 1, 2016 (refer to note 5 of the Company’s annual audited consolidated financial statements for segmented financial information). Tampa Electric Company, an affiliate of TECO Energy, continues to annually evaluate the effectiveness of its DC&P quarterly, and ICFR, in accordance with the Sarbanes Oxley Act of 2002.

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 (“ARO”), capitalized overhead and valuation of financial instruments. Actual results may differ significantly from these estimates.

Rate Regulation

The rate-regulated accounting policies of Tampa Electric, PGS, NMGC, NSPI, Emera Maine, BLPC, Domlec, GBPC, and Brunswick Pipeline may differ from accounting policies for non-rate-regulated companies, which are subject to examination and approval by their respective regulators. These accounting policy differences occur when the regulators render their decisions on rate applications or other matters, and generally involve a difference in the timing of revenue and expense recognition. The accounting for these items is based on the expectation of the future actions of the regulators. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered.

As required by their respective regulators, Tampa Electric, PGS, NMGC and NSPI recognize non-ARO costs of removal as regulatory liabilities. The non-ARO costs of removal represent estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment upon retirement. The companies accrue for removal costs over the life of the related assets based on depreciation studies approved by their respective regulators. The costs are estimated based on historical experience and future expectations, including expected timing and estimated future cash outlays. The application of regulatory accounting guidance is a critical accounting policy since a change in these assumptions may result in a material impact on reported assets, liabilities and the results of operations.

Emera has recorded $1,322 million (2015 - $699 million) of regulatory assets and $1,639 million (2015 - $465 million) of regulatory liabilities as at December 31, 2016.

Pension and Other Post-Retirement Employee Benefits

The Company provides post-retirement benefits to employees, including defined benefit pension plans. The cost of providing these benefits is dependent upon many factors that result from actual plan experience and assumptions of future experience.

The Company believes that the accounting related to employee post-retirement benefits is a critical accounting estimate. Changes in the estimated benefit obligation, affected by employee demographics, including age, compensation levels, employment periods, contribution levels and earnings could have a

material impact on reported assets, liabilities, accumulated other comprehensive income and results of operations. Changes in key actuarial assumptions, including anticipated rates of return on plan assets and discount rates used in determining the accrued benefit obligation and benefit costs could change the annual pension funding requirements. This could have a significant impact on the Company’s annual cash requirements.

The pension plan assets are comprised primarily of equity and fixed income investments. Fluctuations in actual equity market returns and changes in interest rates may result in increased or decreased pension costs in future periods.

Emera’s accounting policy is to amortize the net actuarial gain or loss, which exceeds 10 per cent of the greater of the projected benefit obligation / accumulated post-retirement benefit obligation (“PBO”) and the market-related value of assets, over active plan members’ average remaining service period, which is currently 8.5 years. Emera’s use of smoothed asset values further reduces the volatility related to the amortization of actuarial investment experience. As a result, the main cause of volatility in reported pension cost is the discount rate used to determine the PBO.

The discount rate used to determine benefit costs is based on the yield of high quality long-term corporate bonds in each operating entity’s country and is determined with reference to bonds which have the same duration as the PBO as at January 1 of the fiscal year. The following table shows the discount rate for benefit cost purposes and the expected return on plan assets for each plan:


	2016				2015
	Discount rate for benefit cost purposes		Expected return on plan assets			Discount rate for benefit cost purposes		Expected return on plan assets
TECO Energy Group Retirement Plan	3.72	%	7.00	%
TECO Energy Group Supplemental Executive Retirement Plan	2.64	%	N/A
TECO Energy Group Benefit Restoration Plan	3.12	%	N/A
TECO Energy Postretirement Health and Welfare Plan	3.85	%	N/A
New Mexico Gas Company Retiree Medical Plan	3.85	%	5.75	%
NSPI (1)	4.00	%	5.75	%		4.00	%	5.75	%
Bangor Hydro (2)	4.25	%	6.75	%		3.91	%	7.50	%
MPS (2)	4.10	%	6.75	%		3.77	%	7.50	%
GBPC	4.75	%	6.00	%		4.75	%	6.00	%

(1) Prior to December 31, 2016, the discount rate for NSPI was rounded to the nearest 25 basis points. Effective December 31, 2016 the discount rate for NSPI will be unrounded.

(2) Effective January 1, 2014, Bangor Hydro Electric Company and Maine Public Service Company merged to become Emera Maine.

Based on management’s estimate, the reported benefit cost for defined benefit and defined contribution plans is $90 million in 2016. The reported benefit cost is impacted by numerous assumptions, including the discount rate and asset return assumptions.

The following shows the impact on 2016 benefit cost of a 25 basis point change (0.25 per cent) in the discount rate and asset return assumptions:

	0.25% Increase		0.25% Decrease
millions of dollars	2016	2015	2016	2015
Discount rate assumption	$(7)	$(5)	$7	$5
Asset return assumption	$(4)	$(3)	$4	$3

Unbilled Revenue

Electric revenues are billed on a systematic basis over a one or two-month period for NSPI and a one-month period for Tampa Electric, PGS, NMGC, Emera Maine, BLPC, GBPC and Domlec. At the end of each month, the Company must make an estimate of energy delivered to customers since the date their meter was last read and of related revenues earned but not yet billed. The unbilled revenue is estimated based on several factors, including current month’s generation, estimated customer usage by class, weather, line losses and applicable customer rates. EUS includes an estimate of work completed under contracts but not yet billed at the end of each month. Based on the extent of the estimates included in the determination of unbilled revenue, actual results may differ from the estimate. As at December 31, 2016, unbilled revenues amount to $270 million (2015 – $144 million) on a base of annual operating revenues of $4,277 million (2015 – $2,789 million).

Property, Plant and Equipment

Property, plant and equipment represents 59 per cent of total assets on the Company’s balance sheet. Included in “Property, plant and equipment” are the generation, transmission and distribution and other assets of the Company. Due to the magnitude of the Company’s property, plant and equipment, changes in estimated depreciation rates can have a material impact on depreciation expense.

Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each category. The service lives of regulated property, plant and equipment are determined based on formal depreciation studies and require the appropriate regulatory approval.

Depreciation expense was $560 million for the year ended December 31, 2016 (2015 – $296 million).

Goodwill Impairment Assessments

Goodwill is subject to an annual assessment for impairment at the reporting unit level. Reporting units are generally determined at the operating segment level or one level below the operating segment level. Reporting units with similar characteristics are grouped for the purpose of determining impairment, if any, of goodwill. Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. If an entity performs the qualitative assessment, but determines that it is more likely than not that its fair value is less than its carrying amount or if an entity bypasses the qualitative assessment, a quantitative two-step, fair value-based test is performed. The first step compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation accounting guidance in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense.

Application of the goodwill impairment test requires management judgment. Significant assumptions used in these fair value analyses include discount and growth rates, rate case assumptions, valuation of net operating losses, utility sector market performance and transactions, projected operating and capital cash flows for the relevant business and the fair value of debt. In applying the second step (when required), management must estimate the fair value of specific assets and liabilities of the reporting unit.

At December 31, 2016, the Company had goodwill with a total carrying amount of $6,213 million (December 31, 2015 – $264 million), representing the excess of the acquisition purchase price for TECO Energy, Emera Maine and GBPC over the fair values assigned to individual assets acquired and liabilities assumed. As a result of the acquisition of TECO Energy on July 1, 2016, additional goodwill of $5,771 million was recognized by the Company.

Determining the fair market value of goodwill is susceptible to changes from period to period as assumptions about future cash flows are required. Adverse regulatory actions, such as significant

reductions in the allowed ROE at Tampa Electric, PGS, NMGC, Emera Maine or GBPC could negatively impact goodwill in the future. In addition, changes in significant assumptions, including growth rates, utility sector market performance and transactions, projected operating and capital cash flows from the affiliates businesses, could also negatively impact goodwill in the future.

No impairment provisions with respect to goodwill were required for either 2016 or 2015.

Long-Lived Assets Impairment Assessments

In accordance with accounting guidance for long-lived assets, the Company assesses whether there has been an impairment of long-lived assets and certain intangibles held and used when such indicators exist. The Company reviews all long-lived assets in the last quarter of each year to ensure that any gradual change over the year and the seasonality of the markets are considered when determining which assets require an impairment analysis. However, in the case of a triggering event, such as a significant market disruption or sale of a business, the values of related long-lived assets are reviewed.

The Company believes accounting estimates related to asset impairments are critical estimates for the following reasons: 1) the estimates are highly susceptible to change, as management is required to make assumptions based on expectations of the results of operations for significant/indefinite future periods and/or the current market conditions in such periods; 2) markets can experience significant uncertainties; 3) the estimates are based on the ongoing expectations of management regarding probable future uses and holding periods of assets; and 4) the impact of an impairment on reported assets and earnings could be material. The Company’s assumptions relating to future results of operations or other recoverable amounts are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. The Company’s expectations regarding uses and holding periods of assets are based on internal long-term budgets and projections, which give consideration to external factors and market forces, as of the end of each reporting period. The assumptions made are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities.

No impairment provisions with respect to long-lived assets were required for either 2016 or 2015.

Income Taxes

Income taxes are determined based on the expected tax treatment of transactions recorded in the consolidated financial statements. In determining income taxes, tax legislation is interpreted in a variety of jurisdictions, the likelihood that deferred tax assets will be recovered from future taxable income is assessed and assumptions about the expected timing of the reversal of deferred tax assets and liabilities are made. Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals requires judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income tax benefits that meet the “more likely than not” threshold may be recognized or continue to be recognized. Unrecognized tax benefits are re-evaluated quarterly and changes are recorded based on new information, including the issuance of relevant guidance by the courts or tax authorities and developments occurring in the examinations of the Company’s tax returns.

The Company believes that the accounting estimate related to income taxes is a critical estimate for the following reasons: 1) realization of deferred tax assets is dependent upon the generation of sufficient taxable income, both operating and capital, in future periods; 2) a change in the estimated valuation allowance could have a material impact on reported assets and results of operations; and 3) administrative actions of the tax authorities’ changes in tax law or regulation, and the uncertainty associated with the application of tax statutes and regulations could change our estimate of income taxes, including the potential for elimination or reduction of our ability to realize tax benefits and to utilize deferred tax assets.

Asset Retirement Obligations

An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. The measurement of the fair value of AROs requires the Company to make reasonable estimates concerning the method and timing of settlement associated with the legally obligated costs. There are also uncertainties in estimating future asset-retirement costs due to potential events, such as changing legislation or regulations and advances in remediation technologies.

An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation using the Company’s credit-adjusted risk free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives and governmental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. Accretion expense is included as part of “Depreciation and amortization”. Any accretion expense not yet approved by the regulator is deferred to a regulatory asset in “Property, plant and equipment” and included in the next depreciation study. Accordingly, changes to the ARO or cost recognition attributable to changes in the factors discussed above, should not impact the results of operations of the Company.

Some transmission and distribution assets may have conditional AROs, which are required to be estimated and recorded as a liability. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Management monitors these obligations and a liability is recognized at fair value when an amount can be determined.

The key assumptions used to determine the ARO are as follows:

Asset	Credit-adjusted risk-free rate		Estimated undiscounted future obligation (millions of dollars)		Expected settlement date (number of years)
	2016	2015	2016	2015	2016	2015
Thermal	4.4 – 5.3%	5.1 – 5.3%	$265	$143	11 – 27	17 – 28
Hydro	5.1 – 5.3%	5.1 – 5.3%	128	128	14 – 45	16 – 46
Wind	5.2%	5.2%	27	27	12 – 19	13 – 20
Combustion turbines	5.1 – 5.3%	5.1 – 5.3%	8	8	7 – 29	1 – 30
Transmission & distribution	4.1 – 5.8%	4.3 – 5.8%	13	22	1 – 33	1 – 10
Pipeline	3.8 – 4.4%	3.8%	19	18	8 – 17.5	18.5
			$460	$346

As at December 31, 2016, the AROs recorded on the balance sheet were $170 million (2015 – $109 million). The Company estimates the undiscounted amount of cash flow required to settle the obligations is approximately $455 million, which will be incurred between 2017 and 2061. The majority of these costs will be incurred between 2028 and 2050.

Capitalized Overhead

As required by their respective regulators, Tampa Electric, PGS, NMGC, NSPI, Emera Maine, GBPC, BLPC and Domlec capitalize overhead costs that are not directly attributable to specific utility assets, but to the overall capital expenditure program. The methodology for the calculation of capitalized overhead is approved by their respective regulator. For the year ended December 31, 2016, $111 million of overhead costs (2015 – $72 million) were capitalized to capital assets. Any change in the methodology for the calculation and allocation of overhead costs could have a material impact on the amounts recognized as expenses versus assets.

Financial Instruments

Emera is required to determine the fair value of all derivatives except those which qualify for the normal purchase, normal sale exception. Fair value is the price that would be received for the sale of an asset or paid to transfer a liability in an orderly arms-length transaction between market participants at the measurement date. Fair value measurements are required to reflect the assumptions that market participants would use in pricing an asset or liability based on the best available information, including the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model.

Level Determinations and Classifications

Emera uses the Level 1, 2, 3 and NAV classifications in the fair value hierarchy. The fair value measurement of a financial instrument is included in only one of the three levels and is based on the lowest level input significant to the derivation of the fair value. Fair values are determined, directly or indirectly, using inputs that are unobservable for the asset or liability. In limited circumstances, Emera may enter into commodity transactions involving non-standard features where market observable data is not available, or contracts with terms that extend beyond five years.

CHANGES IN ACCOUNTING POLICIES AND PRACTICES

The new USGAAP accounting policies that are applicable to, and were adopted by the Company in 2016, with no material impact on its consolidated financial statements, are described as follows:

Consolidation

In February 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2015-02, Consolidation, which changes the analysis a reporting entity must perform to determine whether it should consolidate certain types of legal entities. Some of the more notable amendments are (1) the identification of variable interests when fees are paid to a decision maker or service provider, (2) the variable interest entity characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. All legal entities were subject to re-evaluation under the revised consolidation model.

Interest – Imputation of Interest

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest, which simplifies the presentation of debt issuance costs. The amendments require debt issuance costs be presented on the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts or premiums. The recognition and measurement guidance for debt issuance costs is not affected. The Company adopted this standard in Q1 2016 and December 31, 2015 balances have been retrospectively restated. This change resulted in $62 million of debt issuance costs, as at December 31, 2015, previously presented as “Other long-term assets”, being reclassified as a deduction from the carrying amount of the related long-term debt and “Convertible debentures” on its Consolidated Balance Sheets.

In accordance with ASU 2015-15 Interest: Imputation of Interest, the Company continues to present debt issuance costs related to its revolving credit facilities and related instruments in “Other long-term assets” on its Consolidated Balance Sheets.

Compensation – Retirement Benefits

In April 2015, the FASB issued ASU 2015-04, Compensation – Retirement Benefits, which is part of FASB’s initiative to reduce complexity in accounting standards. This standard provides certain practical expedients for defined benefit pension or other post-retirement benefit plan measurement dates.

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Intangibles – Goodwill and Other – Internal-Use Software

In April 2015, the FASB issued ASU 2015-05, Intangibles – Goodwill and Other – Internal-Use Software, which provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, the customer would account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer would account for the arrangement as a service contract. The guidance does not change USGAAP for a customer’s accounting for service contracts.

Inventory – Simplifying the Measurement of Inventory

In July 2015, the FASB issued ASU 2015-11, Inventory – Simplifying the Measurement of Inventory. The amendments require an entity to measure inventory at the lower of cost or net realizable value, whereas previously, inventory was measured at the lower of cost or market. The Company early adopted in 2016, as permitted.

Derivatives and Hedging – Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships

In March 2016, the FASB issued ASU 2016-05, Derivatives and Hedging Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships. The standard clarifies that a change in the counterparty to a derivative contract, in and of itself, does not require the de-designation of a hedging relationship provided that all other hedge accounting criteria continue to be met. The Company early adopted in 2016, as permitted.

Investments – Equity Method and Joint Ventures

In March 2016, the FASB issued ASU 2016-07, Investments – Equity Method and Joint Ventures, which is part of FASB’s initiative to reduce complexity in accounting standards. This standard eliminates the requirements of an investor to retroactively account for an investment under the equity method when an investment qualifies for equity method accounting. The Company early adopted in 2016, as permitted.

Compensation – Stock Compensation

In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, accounting for forfeitures, classification of awards as either equity or liabilities and presentation on the statement of cash flows. The Company early adopted in 2016, as permitted.

Future Accounting Pronouncements

The Company considers the applicability and impact of all ASUs issued by FASB. The following updates have been issued by FASB, but have not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be either not applicable to the Company or have minimal impact on the consolidated financial statements.

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 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 core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled to. 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 has implemented a project plan and is in the process

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of evaluating the impact of adoption of this standard on its consolidated financial statements and disclosures. This includes evaluating the available adoption methods, accounting for contributions in aid of construction and contract acquisition costs, the impact of collectability risk, unique contract characteristics in the Company’s non-regulated businesses and disclosure requirements. The Company is also monitoring the assessment of ASC Topic 606 by the AICPA Power and Utilities Revenue Recognition Task Force. The ultimate impact of the adoption of ASC Topic 606, and the method of adoption, has not yet been finalized.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The Company is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

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.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures. The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators.

This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted for annual reporting periods, including interim periods after December 15, 2018 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows. The standard provides guidance regarding the classification of certain cash receipts and cash payments on the statement of cash flows, where specific guidance is provided for issues not previously addressed. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017, with early adoption permitted, and is required to be applied on a retrospective approach. The Company is currently evaluating the impact of adoption of this standard on its consolidated statement of cash flows.

Restricted Cash on the Statement of Cash Flows

In November 2016, the FASB issued ASU 2016-18, Restricted Cash on the Statement of Cash Flows. The standard will require the Company to show the changes in total cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. Transfers between cash and cash

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equivalents and restricted cash and restricted cash equivalents will no longer be presented in the statement of cash flows. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017, with early adoption permitted, and is required to be applied on a retrospective approach. The Company is currently evaluating the impact of adoption of this standard on its consolidated statement of cash flows.

Clarifying the Definition of a Business

In January 2017, the FASB issued ASU 2017-01, Clarifying the Definition of a Business. The standard provides guidance to assist entities with evaluating when a set of transferred assets and activities is a business. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017, with early adoption permitted and is required to be applied prospectively.

Simplifying the Test for Goodwill Impairment

In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment. The standard provides guidance to simplify the subsequent measurement of goodwill by eliminating the second step of the quantitative test. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. The guidance is required to be applied prospectively.

SUMMARY OF QUARTERLY RESULTS


For the quarter ended		Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
millions of dollars (except per share amounts)		2016		2016		2016		2016		2015		2015		2015		2015
Operating revenues	$	1,513	$	1,387	$	500	$	877	$	732	$	642	$	527	$	888
Net income attributable to common shareholders		70		(95)		208		44		192		35		10		160
Adjusted net income attributable to common shareholders		104		14		237		120		87		23		48		172
Earnings per common share – basic		0.34		(0.52)		1.39		0.30		1.31		0.24		0.07		1.10
Earnings per common share – diluted		0.34		(0.52)		1.38		0.30		1.30		0.24		0.07		1.09
Adjusted earnings per common share – basic		0.51		0.08		1.59		0.81		0.59		0.16		0.33		1.18

Quarterly operating revenues and net income attributable to common shareholders are affected by seasonality. Historically, the first quarter is generally 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 the summer being the heaviest electric consumption season in Florida. As the energy industry is seasonal in nature for companies like Emera, 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 be affected by items outlined in the Significant Items section and mark-to-market adjustments.

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OPERATING STATISTICS
FIVE-YEAR SUMMARY

Year ended December 31	2016	2015	2014	2013	2012
Electric energy sales (GWh)
Residential	10,605	5,740	5,616	5,624	5,372
Commercial	14,895	11,154	10,989	7,157	6,175
Industrial	3,876	2,984	2,971	3,067	2,679
Other	1,284	374	385	358	371
Total electric energy sales	30,660	20,252	19,961	16,206	14,597
Sources of energy (GWh)
Thermal – coal	9,091	4,869	5,255	5,489	4,998
– oil and petcoke	3,393	3,164	2,938	3,026	2,580
– natural gas	12,630	7,782	7,692	3,686	3,726
Biomass	270	272	320	167	-
Hydro	856	1,041	1,129	1,003	828
Wind	270	259	258	261	256
Purchases	5,641	4,142	3,693	3,528	3,210
Total generation and purchases	32,151	21,529	21,285	17,160	15,598
Losses and internal use	1,491	1,277	1,324	954	1,001
Total electric energy sold	30,660	20,252	19,961	16,206	14,597
Gas sales (Therms) Millions
Residential	151	-	-	-	-
Commercial	354	-	-	-	-
Industrial	617	-	-	-	-
Other	147	-	-	-	-
Total gas sales	1,269	-	-	-	-
Gas sales by sales type (Therms)
System supply	329	-	-	-	-
Transportation	940	-	-	-	-
Total gas sales by sales type	1,269	-	-	-	-
Electric customers
Residential	1,404,316	747,629	742,110	738,444	702,738
Commercial	156,748	85,480	82,076	83,612	79,613
Industrial	6,006	2,628	2,637	2,711	2,521
Other	17,886	9,432	10,421	10,510	20,230
Total electric customers	1,584,956	845,169	837,244	835,277	805,102
Gas customers
Residential	818,870	-	-	-	-
Commercial	75,271	-	-	-	-
Industrial	80	-	-	-	-
Other	1,693	-	-	-	-
Total gas customers	895,914	-	-	-	-
Capacity
Emera-owned generating nameplate capacity (MW)
Coal fired	2,727	1,072	1,072	1,072	1,072
Petcoke fired	408	171	171	171	171
Dual fired	350	350	350	350	350
Gas turbines	4,688	1,819	1,799	1,796	747
Biomass	90	90	90	90	-
Hydroelectric	400	402	402	402	395
Wind turbines	180	82	82	82	82
Diesel	135	241	241	245	231
Solar	10	-	-	-	-
Steam	40	40	40	40	40
Comfit	139	-	-	-	-
Independent power producers	893	593	370	308	300
	10,060	4,860	4,617	4,556	3,388
Total number of employees	7,442	3,454	3,530	3,558	3,374
km of transmission lines	12,199	7,504	7,215	7,224	6,803
km of distribution lines	63,865	46,162	44,811	44,771	39,590
km of Gas mains	36,350	-	-	-	-
km of Gas service lines	11,265	-	-	-	-

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REGULATED		Employee	Peak demand	Energy sales	Total assets		Rate base		Income		Allowable ROE		Allowable ROE
ELECTRIC	Customers	count	(MW)	(GWh)	(billions)		(billions)		(millions)		2016		2015
Tampa Electric (1)	736,047	2,039	4,131	10,339	$	9.4	$	7.8	$	164	9.25-11.25	%	-	%
NSPI	510,522	1,819	2111	10,118		4.8		3.7		130	8.75-9.25		8.75-9.25
Emera Maine	156,648	403	387	1,931		1.5		1.0		47	10.5		10.3
BLPC (2)	126,372	326	157	944		0.5		0.5		91	10.0		10.0
GBPC(2)	19,176	186	67	295		0.4		0.3		20	8.8		10.0
Domlec (2)	36,184	198	18	99		0.1		0.1		6	15.0		15.0
(1) Financial results of TECO Energy are from July 1, 2016.
(2) These subsidiaries use return on rate base, as opposed to ROE.


REGULATED		Employee	Max volume day	Gas sales volume	Total assets		Rate base		Income		Allowable ROE		Allowable ROE
GAS	Customers	count	(MMcf)	(Millions of Therms)	(billions)		(billions)		(millions)		2016		2015
PGS (1)	374,076	539	543	918	$	1.6	$	1.1	$	20.0	9.25-11.75	%	-	%
NMGC (1)	521,838	688	437	351		1.1		0.7		12.0	10.0		-
(1) Financial results of TECO Energy are from July 1, 2016.

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FIVE-YEAR FINANCIAL SUMMARY

For the year ended December 31		2016		2015		2014		2013		2012
millions of Canadian dollars

Consolidated Statements of Income
Operating Revenues	$	4,277	$	2,789	$	2,939	$	2,230	$	2,059
Operating expenses
Regulated fuel for generation and purchased power		1,222		815		844		868		811
Regulated cost of natural gas		177		-		-		-		-
Regulated fuel and fixed cost adjustments		61		42		47		(41)		10
Non-regulated fuel for generation and purchased power		313		336		401		90		44
Non-regulated direct costs		29		19		31		52		57
Operating, maintenance and general		1,137		666		561		505		463
Provincial, state and municipal taxes		195		63		58		51		49
Depreciation and amortization		588		340		329		298		278
Income from operations		555		508		668		407		347
Income from equity investments and Other income (expenses), net		274		249		78		64		53
Interest expense, net		585		212		180		172		167
Income before provision for income taxes		244		545		566		299		233
Income tax expense (recovery)		(22)		93		113		44		(13)
Net income		266		452		453		255		246
Non-controlling interest in subsidiaries		11		25		20		19		14
Net income of Emera Incorporated		255		427		433		236		232
Preferred stock dividends		28		30		26		19		11
Net income attributable to common shareholders		227		397		407		217		221
After-tax mark-to-market gain (loss)		(248)		67		88		(42)		(10)
Adjusted net income attributable to common shareholders		475		330		319		259		231
Adjusted EBITDA		1,744		1,031		946		830		693

Balance Sheet Information
Current assets (1)		2,511		2,596		1,411		1,152		940
Property, plant and equipment, net of accumulated depreciation		17,290		6,469		5,744		5,446		4,605
Other assets
Income taxes receivable		48		49		29		28		-
Deferred income taxes (1)		125		32		58		68		29
Derivative instruments		131		168		92		61		23
Pension and post-retirement asset		9		9		6		1		-
Regulatory assets		1,242		605		487		558		376
Net investment in direct financing lease		488		480		484		487		490
Investments subject to significant influence (2)		947		1,145		1,028		739		537
Investment securities		48		116		84		74		142
Goodwill		6,213		264		222		207		194
Other long-term assets		169		106		208		56		200
Total assets		29,221		12,039		9,853		8,877		7,536

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FIVE-YEAR FINANCIAL SUMMARY (continued)

For the year ended December 31		2016		2015		2014		2013		2012
millions of Canadian dollars

Current liabilities		3,724		1,367		1,124		1,530		952
Long-term liabilities
Long-term debt		14,268		3,735		3,660		3,364		3,257
Deferred income taxes (1)		1,672		762		613		548		312
Convertible debentures (2015 – represented by instalment receipts)		8		681		-		-		-
Derivative instruments		150		96		77		27		22
Regulatory liabilities		1,277		353		159		119		93
Asset retirement obligations		170		109		106		99		95
Pension and post-retirement liabilities		669		303		361		256		506
Other long-term liabilities (2)		467		299		48		37		21
Equity
Common stock		4,738		2,157		2,016		1,703		1,644
Cumulative preferred stock		709		709		709		514		391
Contributed surplus		75		29		9		4		3
Accumulated other comprehensive income (loss)		106		137		(347)		(430)		(776)
Retained earnings		1,076		1,168		1,012		817		788
Total Emera Incorporated equity		6,704		4,200		3,399		2,608		2,050
Non-controlling interest in subsidiaries		112		134		306		289		228
Total equity		6,816		4,334		3,705		2,897		2,278
Total liabilities and equity		29,221		12,039		9,853		8,877		7,536

Statements of Cash Flow Information
Cash provided by operating activities		1,053		674		763		564		398
Cash used in investing activities		(9,105)		(124)		(711)		(922)		(919)
Cash provided by (used in) financing activities		7,448		221		58		362		534

Financial ratios ($ per share)
Earnings per share – basic	$	1.33	$	2.72	$	2.84	$	1.64	$	1.77
Adjusted earnings per share – basic	$	2.77	$	2.26	$	2.23	$	1.96	$	1.85
(1) Emera early adopted ASU 2015-17 Income Taxes – Balance Sheet Classification of Deferred Taxes, which simplifies the presentation of deferred income taxes effective Q4 2015. The December 31, 2014 and 2015 periods have been restated
(2) As at December 31, 2015 and 2014, the negative investment balance for Bear Swamp has been reclassified to "Other long-term liabilities" on the Consolidated Balance Sheets. The 2014 and 2015 carrying values have been restated.

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Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	7th grade Bad

Emera (EMRAF) 40-F2016 FY Annual report (Canada)

Content analysis

Management’s Discussion & Analysis

Introduction and Strategic Overview

Non-GAAP Financial Measures

Adjusted Net Income

EBITDA and Adjusted EBITDA

Electric Margin and Gas Margin

Significant Items Affecting Earnings

Developments

Recent Financing Activity

Appointments

NSPI

Electric Revenues

EMERA MAINE

Transmission Pool Revenues and Expenses

DIVIDEND PAYOUT RATIO