EX-99.1

EX-99.1 2 d442416dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

LOGO

Management’s Discussion & Analysis

As at August 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 second quarter and year-to-date in 2017 relative to the same periods in 2016; and its financial position as at June 30, 2017 relative to December 31, 2016. 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., Emera Maine, Emera Caribbean, Emera Energy and Corporate and Other.

This discussion and analysis should be read in conjunction with the Emera Incorporated unaudited condensed consolidated interim financial statements and supporting notes as at and for the six months ended June 30, 2017; and the Emera Incorporated annual MD&A and 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 and investments include:


Emera Rate-Regulated Subsidiary or Equity Investment		Accounting Policies Approved/Examined By
Subsidiary
Tampa Electric – Electric Division of Tampa Electric Company (“TEC”)		Florida Public Service Commission (“FPSC”) and the Federal Energy Regulatory Commission (“FERC”)
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.

TABLE OF CONTENTS


Forward-looking Information			3
Introduction and Strategic Overview			3
Non-GAAP Financial Measures			5
Consolidated Financial Review			6
Significant Items Affecting Earnings			6
Consolidated Financial Highlights			8
Consolidated Income Statement and Operating Cash Flow Highlights			9
Business Overview and Outlook			11
Emera Florida and New Mexico			11
NSPI			12
Emera Maine			13
Emera Caribbean			13
Emera Energy			14
Corporate and Other			14
Consolidated Balance Sheet Highlights			16
Developments			17
Outstanding Common Stock Data			17
Emera Florida and New Mexico			17
NSPI			21
Emera Maine			23
Emera Caribbean			25
Emera Energy			27
Corporate and Other			30
Liquidity and Capital Resources			31
Consolidated Cash Flow Highlights			31
Contractual Obligations			33
Debt Management			33
Guarantees and Letters of Credit			34
Risk Management and Financial Instruments			35
Disclosure and Internal Controls			37
Critical Accounting Estimates			38
Changes in Accounting Policies and Practices			38
Summary of Quarterly Results			40

FORWARD-LOOKING INFORMATION

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

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

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

INTRODUCTION AND STRATEGIC OVERVIEW

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

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

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

While it is still unclear whether economic volatility, government policy and lower fossil fuel prices will slow the pace of transformation, its impact on the sector continues to be felt in the form of mandated and incented carbon reductions throughout eastern North America and in the Caribbean. As such, investment in wind, solar, and hydro generation, natural gas and new transmission infrastructure is likely to continue across the sector despite any cost differential with more carbon-intensive generating options. The capital spending requirements related to these investments will need to be managed within the context of overall energy pricing.

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

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

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

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

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

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

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

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

NON-GAAP FINANCIAL MEASURES

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

Adjusted Net Income

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

•

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

•

the mark-to-market adjustments included in Emera’s equity income related to the business activities of Bear Swamp;

•

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

•

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

•

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

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

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

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


For the millions of Canadian dollars (except per share amounts)	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Net income attributable to common shareholders	$	101	$	208	$	413	$	252
After-tax mark-to-market gain (loss)	$	(16)	$	(30)	$	144	$	(106)
Adjusted net income attributable to common shareholders	$	117	$	238	$	269	$	358
Earnings per common share – basic	$	0.47	$	1.39	$	1.95	$	1.69
Adjusted earnings per common share – basic	$	0.55	$	1.59	$	1.27	$	2.40

EBITDA and Adjusted EBITDA

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

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

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

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

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


For the millions of Canadian dollars	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Net income (1)	$	110	$	217	$	432	$	272
Interest expense, net		178		107		353		182
Income tax expense		34		1		146		28
Depreciation and amortization		220		85		437		172
EBITDA		542		410		1,368		654
Mark-to-market gain (loss), excluding income tax and interest		(25)		(42)		207		(117)
Adjusted EBITDA	$	567	$	452	$	1,161	$	771

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

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Q2 Earnings

2017

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

After-tax mark-to-market losses decreased $14 million to $16 million in Q2 2017 compared to $30 million in Q2 2016 mainly due to changes in existing positions on long-term natural gas contracts at Emera Energy. Year to date, after-tax mark-to-market increased $250 million to a $144 million gain in 2017 compared to a $106 million loss for the same period in 2016. 2016 year-to-date included a $117 million loss resulting from the reversal of 2015 gains on USD-denominated currency and forward contracts related to the financing of the TECO Energy acquisition. Other factors contributing to the increase include changes in existing positions on long-term contracts at Emera Energy, and the reversal of 2016 mark-to-market losses at Emera Energy.

2016

Investment in Algonquin Power and Utilities Corp.

On May 24, 2016, Emera completed the sale of 50.1 million common shares of Algonquin Power and Utilities Corp. (“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.

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. These shares were sold on December 8, 2016. Emera no longer holds any interest in APUC.

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

In Q2 2016, 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, including $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 the period.

Acquisition Related Costs

Emera incurred after-tax costs of $42 million ($0.28 per common share) in Q2 2016 and $60 million year-to-date 2016 ($0.40 per common share) related to its acquisition of TECO Energy. All acquisition costs have been recognized in the Corporate and Other segment.

Consolidated Financial Highlights


For the millions of Canadian dollars (except per share amounts)	Three months ended June 30				Six months ended June 30
Adjusted Net Income	2017		2016		2017		2016
Emera Florida and New Mexico	$	103	$	-	$	182	$	-
NSPI		29		28		99		81
Emera Maine		12		10		25		19
Emera Caribbean		11		58		18		68
Emera Energy		(11)		(29)		(1)		19
Corporate and Other		(27)		171		(54)		171
Adjusted net income attributable to common shareholders	$	117	$	238	$	269	$	358
After-tax mark-to-market gain (loss)		(16)		(30)		144		(106)
Net income attributable to common shareholders	$	101	$	208	$	413	$	252

For the millions of Canadian dollars (except per share amounts)	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Operating revenues	$	1,469	$	499	$	3,326	$	1,376
Income from operations		291		1		872		271
Net income attributable to common shareholders		101		208		413		252
After-tax mark-to-market gain (loss)		(16)		(30)		144		(106)
Adjusted net income attributable to common shareholders	$	117	$	238	$	269	$	358
Earnings per common share – basic	$	0.47	$	1.39	$	1.95	$	1.69
Earnings per common share – diluted	$	0.47	$	1.38	$	1.94	$	1.68
Adjusted earnings per common share – basic	$	0.55	$	1.59	$	1.27	$	2.40
Dividends per common share declared	$	0.5225	$	0.4750	$	1.0450	$	0.9500

Adjusted EBITDA	$	567	$	452	$	1,161	$	771

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


For the millions of Canadian dollars	Three months ended June 30		Six months ended June 30
Adjusted net income – 2016	$	238	$	358
Emera Florida and New Mexico		103		182
2016 acquisition and financing costs related to the acquisition of TECO Energy		42		60
Emera Energy		6		(32)
2016 Emera Energy’s recognition of fuel taxes for 2013 to March 2016		12		12
NSPML and LIL AFUDC earnings		8		15
NSPI		1		18
2016 gain on BLPC SIF regulatory liability		(43)		(43)
TECO Energy post-acquisition financing costs		(45)		(90)
2016 gain on conversion of APUC subscription receipts and dividend equivalents to common shares of APUC		(53)		(53)
2016 gain on sale of APUC common shares		(146)		(146)
Other		(6)		(12)
Adjusted net income – 2017	$	117	$	269


For the millions of Canadian dollars	Six months ended June 30
	2017		2016
Operating cash flow before changes in working capital	$	703	$	325
Change in working capital		(222)		151
Operating cash flow	$	481	$	476
Investing cash flow	$	(888)	$	178
Financing cash flow	$	227	$	5,810


As at millions of Canadian dollars	June 30 2017		December 31 2016
Working capital	$	488	$	301
Total assets	$	28,584	$	29,221
Total long-term debt (including current portion)	$	14,617	$	14,744

Q2 Consolidated Income Statement Highlights

Operational Results

Income from operations increased $290 million to $291 million in Q2 2017 compared to $1 million in Q2 2016. Absent mark-to-market increases of $25 million, income from operations increased $265 million mainly due to the contribution of Emera Florida and New Mexico and increased contribution from Emera Energy.

Total operating revenues increased $970 million to $1,469 million in Q2 2017 compared to $499 million in Q2 2016. Absent mark-to-market increases of $35 million, operating revenues increased $935 million due to:

•

$946 million increase from Emera Florida and New Mexico;

•

$24 million decrease from New England Gas Generating Facilities (“NEGG”) reflecting an unplanned outage at the Bridgeport Facility.

Total operating expenses increased $680 million to $1,178 million in Q2 2017 compared to $498 million in Q2 2016, primarily due to the addition of expenses from Emera Florida and New Mexico, partially offset by lower fuel expense at NEGG reflecting an unplanned outage at the Bridgeport Facility and the recognition of prior period state fuel taxes in Q2 2016.

Other income (expenses), net

Other income in Q2 2017 decreased $293 million to $1 million compared to $294 million in the same period in 2016. This was due to a $172 million gain on the 2016 sale of APUC common shares, a $63 million gain on the 2016 conversion of APUC subscription receipts and dividend equivalents into common shares, and a $53 million gain on the BLPC SIF regulatory liability in 2016.

Interest expense, net

Interest expense, net increased $71 million in Q2 2017 to $178 million compared to $107 million in the same period in 2016, due to interest expense from Emera Florida and New Mexico and interest on the permanent financing related to the TECO Energy acquisition, offset by the 2016 interest expense on the acquisition related Convertible Debentures.

Income tax expense

Income tax expense increased $33 million to $34 million in Q2 2017 compared to $1 million in Q2 2016 due to the non-taxable portion of gains on the 2016 APUC transactions and changes in the proportion of income earned in foreign jurisdictions. This was partially offset by decreased income before provision for income taxes.

Year-to-Date Consolidated Income Statement and Operating Cash Flow Highlights

Operational Results

Income from operations increased $601 million to $872 million year-to-date in 2017 compared to $271 million for the same period in 2016. Absent mark-to-market increases of $190 million, income from operations increased $411 million mainly due to the contribution of Emera Florida and New Mexico, partially offset by decreased contribution from Emera Energy.

Total operating revenues increased $1,950 million to $3,326 million year-to-date in 2017 compared to $1,376 million in 2016. Absent mark-to-market increases of $200 million, operating revenues increased $1,750 million due to:

•

$1,834 million increase from Emera Florida and New Mexico;

•

$100 million decrease at NEGG reflecting lower hedged power prices, decreased sales volumes driven by an unplanned outage at the Bridgeport facility and less favourable market conditions.

Total operating expenses increased $1,349 million to $2,454 million year-to-date in 2017 compared to $1,105 million for the same period in 2016. This was due to the addition of expenses from Emera Florida and New Mexico. This increase was partially offset by decreased fuel expense at NEGG due to lower hedged natural gas prices, decreased volumes reflecting an unplanned outage at the Bridgeport Facility and lower sales volumes and the recognition of prior period state fuel taxes in Q2 2016.

Other income (expenses), net

Other income decreased $152 million to $3 million year-to-date in 2017 compared to $155 million for the same period in 2016. This was due to a $172 million gain on the 2016 sale of APUC common shares, a $63 million gain on the 2016 conversion of APUC subscription receipts and dividend equivalents into common shares, and a $53 million gain on the BLPC SIF regulatory liability in 2016. These 2016 gains were partially offset by $117 million of mark-to-market losses in 2016 relating to the TECO Energy acquisition related USD-denominated currency and forward contracts.

Interest expense, net

Interest expense, net increased $171 million year-to-date in 2017 to $353 million compared to $182 million in 2016. This was due to interest expense from Emera Florida and New Mexico and the financing related to the TECO Energy acquisition.

Income tax expense

Income tax expense increased $118 million to $146 million year-to-date compared to $28 million for the same period in 2016 primarily due to increased income before provision for income taxes, the non-taxable portion of gains on the 2016 APUC transactions and changes in the proportion of income earned in foreign jurisdictions. This was partially offset by increased deferred income taxes on regulated income recorded as regulatory assets and liabilities and the non-deductible portion of foreign exchange and mark-to-market adjustments related to the TECO Energy acquisition in 2016.

Net cash provided by operating activities

Net cash provided by operating activities in 2017 increased $5 million to $481 million compared to $476 million during the same period in 2016 as explained below.

Cash from operations before changes in working capital increased by $378 million mainly due to the contribution from Emera Florida and New Mexico, partially offset by increased financing costs from long-term debt related to the TECO Energy acquisition and decreased margin from Emera Energy Services (“EES”) and NEGG.

Changes in working capital decreased operating cash flows by $373 million. This decrease is due to payments in 2017 related to significant year end accruals and refunds to customers in 2017 for fuel clause over-recoveries collected in 2016 at Emera Florida and New Mexico. In addition, the decrease is due to the timing of payments and changes in fuel inventory levels compared to 2016 at NSPI, changes in posted margin at EES, the recognition of prior period state fuel taxes at NEGG in 2016 and the impact of a weaker USD.

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, currency risks are managed through matching US denominated debt to finance US operations and the use of 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 net income is recorded in US dollar currency.


millions of US dollars	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Emera Florida and New Mexico	$	77	$	-	$	137	$	-
Emera Maine		9		7		19		14
Emera Caribbean		9		44		14		52
Emera Energy (1)		(1)		(14)		10		23
		94		37		180		89
Corporate and Other (2)		(29)		3		(58)		5
Total	$	65	$	40	$	122	$	94

FX rate for period	$	1.34	$	1.29	$	1.33	$	1.34

(1) Includes Emera Energy’s US dollar adjusted net income from EES, NEGG and Bear Swamp.

(2) Corporate and Other includes interest expense on US dollar denominated debt, net of interest income on an intercompany US dollar loan to Emera Energy.

BUSINESS OVERVIEW AND OUTLOOK

Emera Florida and New Mexico

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

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

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

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

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

NSPI

NSPI is a fully-integrated regulated electric utility. It is the primary electricity supplier in Nova Scotia, providing electricity generation, transmission and distribution services to customers. NSPI’s earnings are most directly impacted by the range of ROE and capital structure approved by the UARB, the prudent management and approved recovery of operating costs, load demand, weather, the approved recovery of regulatory deferrals and the timing and amount of capital spending.

NSPI anticipates earning within its allowed ROE range in 2017 and expects its earnings and rate base to generally be consistent with prior years.

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

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

Emera Maine

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

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

There are currently four pending complaints filed with the FERC to challenge the ISO-New England (“ISO-NE”) Open Access Transmission Tariff-allowed base ROE. On June 19, 2014, in connection with the first complaint, the FERC set the base ROE at 10.57 per cent and capped the total ROE, including the effect of incentive adders, at 11.74 per cent. On April 14, 2017, the U.S. Court of Appeals for the District of Columbia Circuit vacated this order. No changes in reserves have been made as a result of the Court of Appeals vacating the FERC Order, as the outcome is considered uncertain. There are no further updates since December 31, 2016 for the other pending complaints. For further discussion on the complaints, see note 19 to the condensed consolidated interim financial statements for the quarter ended June 30, 2017.

In 2017, Emera Maine expects to invest approximately $85 million USD (2016 – $69 million USD actual) primarily on transmission and distribution capital projects.

Emera Caribbean

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

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

Emera Caribbean’s 2017 earnings are expected to be less than prior years, excluding the impact of the Q2 2016 gain recognized on the Self-Insurance Fund regulatory liability. This is the 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.

On May 30, 2017, the Minister of Finance in Barbados delivered a new budget. Key measures include an increase in the National Social Responsibility Levy (NSRL) from two per cent to ten per cent and the introduction of a two per cent foreign exchange commission, both effective July 1, 2017. The NSRL is charged on all goods imported into Barbados and on domestically manufactured goods. The impact of these immaterial changes will be incorporated into BLPC’s cost of service.

Emera Caribbean plans to invest approximately $75 million USD in capital programs in 2017 (2016 - $65 million USD). Capital projects in 2017 include investment in energy storage, advanced metering infrastructure (“AMI”) and renewables.

Emera Energy

Emera Energy includes EES, a wholly owned physical energy marketing and trading business; EEG, a wholly owned portfolio of electricity generation facilities in New England and the Maritime provinces of Canada; and an equity investment in a 50.0 per cent joint venture ownership of Bear Swamp, a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts.

Emera Energy Services

EES, Emera Energy’s marketing and trading business, is generally dependent on market conditions. In particular, volatility in electricity and natural gas markets, which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 generally providing the greatest opportunity for earnings. Under normal market conditions, the business is generally expected to deliver adjusted net earnings of $15 to $30 million USD, with the opportunity for upside when market conditions present.

Emera Energy Generation

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

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

In 2017, Emera Energy expects to invest approximately $55 million (2016 – $39 million) in capital related to its generating assets in order to further improve reliability and enhance plant output capacity.

Corporate and Other

Corporate

Corporate encompasses certain corporate-wide functions including executive management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate business development, corporate governance, investor relations, risk management, insurance, acquisition-related costs and corporate human resource activities. It also includes interest revenue on intercompany financings recorded in “Intercompany revenue” and costs associated with corporate activities that are not directly allocated to the operations of Emera’s subsidiaries and investments.

Other

Other includes consolidated investments in Brunswick Pipeline, Emera Reinsurance and Emera Utility Services. It also includes non-consolidated investments in NSPML (100 per cent investment), LIL (57.4 per cent investment) and M&NP (12.9 per cent investment). Investments in NSPML, LIL and M&NP are recorded as “Investments subject to significant influence” on Emera’s Condensed Consolidated Balance Sheets.

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

Corporate and Other, excluding ENL, expects to spend approximately $15 million on property, plant and equipment in 2017 (2016 - $7 million).

ENL

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

NSPML

Future earnings contribution from the Maritime Link Project will be affected by the amount and timing of capital expenditures for construction activities and the approved ROE, which will determine the component of costs to be funded by equity. The Maritime Link Project is accounted for in Emera’s financial statements as an equity investment (see note 5 of the Condensed Consolidated Interim Financial Statements). The Company’s earnings through the construction period are derived from AFUDC on Emera’s equity investment of 30 per cent of the project costs to maintain a 70 per cent to 30 per cent debt-to-equity ratio. As Maritime Link construction costs are incurred, Emera will contribute equity and then earn AFUDC on that contribution. Maritime Link forecasted cash equity contributions for 2017 are $165 million, with total equity contributions for the Project estimated to be $450 million.

LIL

Future earnings from the LIL investment are dependent on the amount and timing of additional equity investments and the approved ROE. Emera’s total 2017 cash equity contributions are forecasted to be $55 million, with the Company’s total equity contribution for the project estimated to be approximately $600 million.

Consolidated Balance Sheets Highlights

Significant changes in the condensed consolidated balance sheets between December 31, 2016 and June 30, 2017 include:


millions of Canadian dollars	Increase (Decrease)		Explanation
Assets
Cash and cash equivalents	$	(187)	Decreased primarily due to additions of property, plant and equipment, increased investment in LIL and NSPML and payment of common dividends. These decreases were partially offset by proceeds of long-term debt at GBPC, changes in short-term debt at Emera Florida and New Mexico, and changes in credit facilities.
Receivables, net		(91)	Decreased mainly due to lower commodity prices at Emera Energy and outages at EEG, seasonal trends of the business at Emera Florida and New Mexico, and the impact of a stronger CAD.
Derivative instruments (current and long-term)		(50)	Decreased primarily due to settlements of derivative instruments at Emera Energy and NSPI, unfavourable commodity hedges at NSPI, and lower natural gas swaps at Emera Florida and New Mexico.
Property, plant and equipment, net of accumulated depreciation		(221)	Decreased due to the effect of a stronger CAD on the translation of Emera’s foreign subsidiaries and depreciation, partially offset by additions at NSPI and Emera Florida and New Mexico.
Investments subject to significant influence		184	Increased mainly due to investment in NSPML and LIL.
Goodwill		(208)	Decreased due to the effect of stronger CAD on the translation of Emera’s foreign subsidiaries.
Prepayments and other assets (current and long-term)		(64)	Decreased due to amortization of transportation assets, partially offset by new Asset Management Agreements (“AMA”).
Liabilities and Equity
Accounts payable		(279)	Decreased primarily due to timing of payments of project expenditures and accruals, and lower commodity prices at Emera Energy.
Deferred income tax liabilities, net of deferred income tax assets		113	Increased primarily due to tax deductions in excess of accounting depreciation related to property, plant and equipment.
Derivative instruments (current and long-term)		(247)	Decreased due to the reversal of 2016 AMA MTM losses and changes in existing positions on long term natural gas contracts at Emera Energy.
Regulatory liabilities (current and long-term)		(172)	Decrease reflects lower deferred fuel clause at TEC and decreased regulated derivatives at NSPI, partially offset by an increased Fuel Adjustment Mechanism (“FAM”) regulatory liability and deferred income tax regulatory asset at NSPI.
Pension and post-retirement liabilities (current and long-term)		(66)	Decreased due to supplemental executive retirement plan and other post-retirement payments in Emera Florida and New Mexico.
Common stock		93	Increased due to issuance of common stock for the dividend reinvestment program.
Accumulated other comprehensive income		(152)	Decreased due to the effect of stronger CAD on the translation of Emera’s foreign subsidiaries.
Retained earnings		194	Increased due to net income in excess of dividends paid.

Developments

Appointments

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

OUTSTANDING COMMON STOCK DATA


Common stock Issued and outstanding:	millions of shares		millions of Canadian dollars
Balance, December 31, 2015		147.21	$	2,157
Conversion of Convertible Debentures		51.99		2,115
Issuance of common stock		7.69		338
Issued for cash under Purchase Plans at market rate		2.51		115
Discount on shares purchased under Dividend Reinvestment Plan		-		(5)
Options exercised under senior management stock option plan		0.62		17
Employee Share Purchase Plan		-		1
Balance, December 31, 2016		210.02	$	4,738
Conversion of Convertible Debentures (1)		0.13		5
Issued for cash under Purchase Plans at market rate		1.97		90
Discount on shares purchased under Dividend Reinvestment Plan		-		(4)
Options exercised under senior management stock option plan		0.04		1
Employee Share Purchase Plan		-		1
Balance, June 30, 2017		212.16	$	4,831

(1) During the six months ended June 30, 2017, 0.13 million common shares of Emera were issued relating to the conversion of the Convertible Debentures. As at June 30, 2017, a total of 52.12 million common shares of the Company were issued, representing conversion into common shares of more than 99.8% of the Convertible Debentures.

As at July 27, 2017 the amount of issued and outstanding common shares was 212.2 million.

The weighted average shares of common stock outstanding – basic, which includes both issued and outstanding common stock and outstanding deferred share units, for the three months ended June 30, 2017 was 212.8 million (2016 – 149.7 million) and for the six months ended June 30, 2017 was 212.2 million (2016 – 149.2 million).

EMERA FLORIDA AND NEW MEXICO

Financial Highlights

All amounts are reported in USD, unless otherwise stated.


For the millions of US dollars (except per share amounts)	Three months ended June 30		Six months ended June 30
	2017		2017
Operating revenues – regulated electric	$	541	$	982
Operating revenues – regulated gas		160		387
Operating revenues – non-regulated		2		6
Total operating revenues		703		1,375
Regulated fuel for generation and purchased power		172		310
Regulated cost of natural gas		56		151
Contribution to consolidated net income – USD	$	77	$	137
Contribution to consolidated net income – CAD		103		182
Contribution to consolidated earnings per common share – CAD	$	0.48	$	0.86
Net income weighted average foreign exchange rate – CAD/USD	$	1.34	$	1.33

EBITDA – USD	$	270	$	510
EBITDA – CAD	$	363	$	680

Net Income

Emera Florida and New Mexico’s contribution is summarized in the following table:


For the millions of US dollars	Three months ended June 30		Six months ended June 30
	2017		2017
Tampa Electric	$	76	$	119
PGS		10		24
NMGC		-		13
Other (1)		(9)		(19)
Contribution to consolidated net income	$	77	$	137

(1)	Other includes TECO Finance and administration costs.

Included below are comparisons of Emera Florida and New Mexico Q2 2017 quarterly results to the same period in 2016. Prior year data is for comparison purposes only, as the Emera acquisition was completed on July 1, 2016.

Tampa Electric’s net income increased $7 million to $76 million in Q2 2017 compared to $69 million for the same period in 2016 primarily due to higher base revenues related to completion of the Polk Power Station expansion project, warmer spring weather and customer growth. These were offset by increased depreciation and property tax expense, lower AFUDC earnings and income tax adjustments received in 2016, offsetting in Other. Year-to-date, Tampa Electric’s net income of $119 million was unchanged compared to the same period in 2016 due to unfavourable weather impacts on Q1 2017 results offsetting the favourable Q2 2017 results mentioned above.

On June 29, 2017, a tragic accident occurred during work being conducted at Tampa Electric’s Big Bend Power Station Unit Two, resulting in employee and contractor fatalities. Although the financial impact to Tampa Electric has not been fully determined, any such impact is expected to be substantially covered by insurance.

PGS’s net income increased $3 million to $10 million in Q2 2017 compared to $7 million for the same period in 2016 primarily due to higher sales to retail customers and lower depreciation expense as a result of the FPSC-approved 2016 depreciation study. PGS had increased retail therm sales due to customer growth and the strong Florida economy, including increased sales of compressed natural gas to vehicle fleets. Year-to-date, PGS’s net income increased $4 million to $24 million compared to $20 million for the same period in 2016 primarily due to the Q2 2017 explanation above, which were partially offset by unfavourable winter weather impacts on Q1 2017 results.

NMGC’s net income of nil in Q2 2017 was unchanged compared to the same period in 2016. Year-to-date, NMGC’s net income decreased $2 million to $13 million compared to $15 million for the same period in 2016 primarily due to unfavourable weather impacts on Q1 2017 results.

Other net loss decreased $3 million to $9 million in Q2 2017 compared to $12 million for the same period in 2016 due to income tax adjustments in 2016. Year-to-date, other net loss increased $3 million to $19 million compared to $16 million for the same period in 2016 primarily as a result of a Q1 2016 non-recurring $5 million gain from an accounting rule change related to stock-based compensation.

Operating Revenues – Regulated Electric

Electric revenues increased $43 million to $ 541 million in Q2 2017 compared to $498 million in Q2 2016 primarily due to $30 million of higher base rate revenue related to completion of the Polk Power Station expansion in January 2017 and the pass through of higher fuel costs. Year-to-date, electric revenues increased $60 million to $ 982 million in 2017 compared to $922 million in 2016 primarily due to $50 million of higher base rate revenue related to the Polk Power Station expansion and the pass through of higher fuel costs.

Electric revenues are summarized in the following by customer class:


Electric Revenues millions of US dollars	Three months ended June 30		Six months ended June 30
	2017		2017
Residential	$	255	$	453
Commercial		149		280
Industrial		40		79
Other (1)		97		170
Total	$	541	$	982

(1) Other includes regulatory deferrals related to over-recovery of clause related costs.

Q2 Electric Sales Volumes

Gigawatt hours (“GWh”)

YTD Electric Sales Volumes

GWh

2017

2016*

2017

2016*

Residential

2,294

2,241

Residential

4,055

4,155

Commercial

1,636

1,565

Commercial

3,067

2,953

Industrial

505

479

Industrial

1,008

940

Other

416

447

Other

802

848

Total

4,851

4,732

Total

8,932

8,896

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

Operating Revenues – Regulated Gas

Gas revenues increased $8 million to $ 160 million in Q2 2017 compared to $152 million in Q2 2016 primarily due to revenues related to the pass through of higher natural gas commodity costs in New Mexico and customer growth in Florida. Year-to-date, gas revenues increased $3 million to $ 387 million in 2017 compared to $384 million in 2016 primarily due to higher commodity costs and customer growth being partially offset by impacts from unfavourable winter weather in both Florida and New Mexico.

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


Gas Revenues millions of US dollars	Three months ended June 30		Six months ended June 30
	2017		2016
Residential	$	72	$	200
Commercial		48		115
Industrial		9		17
Other (1)		31		55
Total	$	160	$	387

(1) Other includes regulatory deferrals related to over-recovery of clause related costs.

Q2 Gas Sales Volumes

Therms (millions)

YTD Gas Sales Volumes

Therms (millions)

2017

2016*

2017

2016*

Residential

197

214

Commercial

176

172

Commercial

399

412

Industrial

307

306

Industrial

606

619

Other

152

Total

601

620

Total

1,301

1,397

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

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

Electric Capacity

Regulated fuel for generation and purchased power increased $6 million to $172 million in Q2 2017 compared to $166 million in Q2 2016 and year-to-date increased $15 million to $310 million in 2017 compared to $295 million in 2016 due to higher natural gas and coal-fired generation offset by less purchased power.

Q2 Production Volumes

GWh

YTD Production Volumes

GWh

2017

2016*

2017

2016*

Natural gas (1)

3,489

2,777

Natural gas (1)

5,764

5,419

Coal

1,670

1,499

Coal

3,278

2,486

Oil and petcoke

241

154

Oil and petcoke

536

456

Solar

Purchased power, net (1) (2)

(35)

831

Purchased power (1)

1,218

Total production volumes

5,379

5,262

Total production volumes

9,642

9,581

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

(1) Natural gas production was higher and purchased power was lower due to completion of Polk Power Station expansion in January 2017 and expiration of a purchased power contract in December 2016.

(2) Sales for resale exceeded purchased power in Q2 2017.


Q2 Average Fuel Costs/Megawatt Hour (“MWh”) US dollars			YTD Average Fuel Costs/MWh US dollars
	2017			2017
Dollars per MWh	$	32	Dollars per MWh	$	32

Average fuel cost per MWh was $32 for both Q2 2017 and year-to-date 2017 compared to $32 in Q2 2016 and $31 in year-to-date 2016.

Cost of Natural Gas

Regulated cost of natural gas increased $6 million to $56 million in Q2 2017 compared to $50 million in Q2 2016 primarily due higher commodity costs. Year-to-date, regulated cost of natural gas increased $4 million to $151 million in 2017 compared to $147 million in 2016 primarily due to higher commodity costs partially offset by lower sales volumes due to unfavourable winter weather.

Gas sales by type are summarized in the following table:

Q2 Gas Sales Volumes by Type

Therms (millions)

YTD Gas Sales Volumes by Type

Therms (millions)

2017

2016*

2017

2016*

System Supply

130

152

System Supply

339

415

Transportation

471

468

Transportation

962

982

Total

601

620

Total

1,301

1,397

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

NSPI

Financial Highlights


For the millions of Canadian dollars (except per share amounts)	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Operating revenues – regulated electric	$	304	$	314	$	700	$	712
Regulated fuel for generation and purchased power (1)		98		100		237		242
Contribution to consolidated net income	$	29	$	28	$	99	$	81
Contribution to consolidated earnings per common share	$	0.14	$	0.19	$	0.47	$	0.54

EBITDA	$	112	$	111	$	269	$	251

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

Net Income

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


For the millions of Canadian dollars	Three months ended June 30		Six months ended June 30
Contribution to consolidated net income – 2016	$	28	$	81
Decreased operating revenues - see Operating Revenues - Regulated Electric below		(10)		(12)
Decreased fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below		2		5
Decreased fuel adjustment mechanism expense due to a rebate to customers of prior years’ over recovery of fuel costs partially offset by increased recovery of current year fuel costs		5		11
Decreased OM&G expenses primarily due to higher administrative overhead allocated to capital due to higher capital spending and lower pension expense; year-over-year also due to lower storm and maintenance costs		4		13
Decreased income tax expense primarily due to increased tax deductions in excess of accounting depreciation related to property, plant and equipment; year-over-year decrease partially offset by increased income before provision for income taxes		1		7
Other		(1)		(6)
Contribution to consolidated net income – 2017	$	29	$	99

Operating Revenues – Regulated Electric

Operating revenues decreased $10 million to $304 million in Q2 2017 compared to $314 million in Q2 2016 due to a $15 million one-time refund of 2016 fuel related revenues which was partially offset by a $6 million increase in fuel related electricity pricing.

Year-to-date, operating revenues decreased $12 million to $700 million in 2017 compared to $712 million in 2016. The one-time refund of 2016 fuel related revenues decreased revenues by $36 million, partially offset by a $13 million increase as a result of fuel related electricity pricing effective January 1, 2017 and a $9 million increase in residential sales volume due to colder weather and load growth.

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


Q2 Electric Revenues millions of Canadian dollars					YTD Electric Revenues millions of Canadian dollars
	2017		2016			2017		2016
Residential	$	147	$	156	Residential	$	375	$	379
Commercial		92		95	Commercial		195		204
Industrial		48		48	Industrial		94		96
Other		10		9	Other		21		21
Total	$	297	$	308	Total	$	685	$	700

Q2 Electric Sales Volumes GWh					YTD Electric Sales Volumes GWh
	2017		2016			2017		2016
Residential		959		967	Residential		2,470		2,398
Commercial		716		729	Commercial		1,567		1,569
Industrial		613		590	Industrial		1,214		1,168
Other		90		65	Other		186		144
Total		2,378		2,351	Total		5,437		5,279

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power decreased $2 million to $98 million in Q2 2017 compared to $100 million in Q2 2016 due to decreased commodity prices and increased hydro and wind production, partially offset by changes in generation mix and plant performance and increased sales volumes. Year-to-date, regulated fuel for generation and purchased power decreased $5 million to $237 million in 2017 compared to $242 million during the same period in 2016 due to decreased commodity prices, partially offset by increased sales volumes.

NSPI’s FAM regulatory liability balance has increased $33 million from $94 million at December 31, 2016 to $127 million at June 30, 2017 as a result of an over-recovery of current period fuel costs and the application of non-fuel revenues reduced by the refund to customers of prior years’ fuel costs.


Q2 Production Volumes GWh					YTD Production Volumes GWh
	2017		2016			2017		2016
Coal		1,024		984	Coal		2,685		2,309
Natural gas		367		300	Natural gas		618		585
Oil and petcoke		227		351	Oil and petcoke		576		855
Purchased power – other		39		94	Purchased power – other		136		189
Total non-renewables		1,657		1,729	Total non-renewables		4,015		3,938
Wind and hydro – renewables		387		312	Wind and hydro – renewables		763		718
Purchased power – Independent Power Producers (“IPP”)		282		260	Purchased power – IPP		652		614
Purchased power – Community Feed-in Tariff program (“COMFIT”)		127		95	Purchased power – COMFIT		272		210
Biomass – renewables		37		36	Biomass – renewables		80		106
Total renewables		833		703	Total renewables		1,767		1,648
Total production volumes		2,490		2,432	Total production volumes		5,782		5,586

Q2 Average Fuel Costs					YTD Average Fuel Costs
	2017		2016			2017		2016
Dollars per MWh produced	$	39	$	41	Dollars per MWh produced	$	41	$	43

Average fuel costs decreased in Q2 2017 and year-to-date primarily due to favourable solid fuel pricing and increased hydro and wind production. Quarter-over-quarter this was partially offset by unfavourable generation mix.

EMERA MAINE

Financial Highlights

All amounts are reported in USD, unless otherwise stated.


For the millions of US dollars (except per share amounts)	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Operating revenues – regulated electric	$	54	$	51	$	114	$	109
Regulated fuel for generation and purchased power (1)		14		13		29		27
Contribution to consolidated net income – USD	$	9	$	7	$	19	$	14
Contribution to consolidated net income – CAD	$	12	$	10	$	25	$	19
Contribution to consolidated earnings per common share – CAD	$	0.06	$	0.06	$	0.12	$	0.13
Net income weighted average foreign exchange rate – CAD/USD	$	1.34	$	1.29	$	1.33	$	1.33
EBITDA – USD	$	27	$	24	$	57	$	49
EBITDA – CAD	$	37	$	32	$	76	$	65

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

Net Income

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


For the millions of US dollars	Three months ended June 30		Six months ended June 30
Contribution to consolidated net income – 2016	$	7	$	14
Increased operating revenues - regulated electric (see Operating Revenues - Regulated Electric Section below)		3		5
Decreased OM&G due to increased capitalized construction overheads as a result of higher capital spending and lower storm costs		-		5
Increased income tax expense due to increased income before provision for income taxes		(2)		(4)
Other		1		(1)
Contribution to consolidated net income – 2017	$	9	$	19

Emera Maine’s CAD contribution to consolidated net income increased $2 million to $12 million in Q2 2017 from $10 million in Q2 2016. Year-to-date, increased $6 million to $25 million in 2017 from $19 million during the same period in 2016. The foreign exchange rate had minimal impact for the three months and six months ended June 30, 2017.

Operating Revenues – Regulated Electric

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


Q2 Operating Revenues – Regulated Electric millions of US dollars					YTD Operating Revenues – Regulated Electric millions of US dollars
	2017		2016			2017		2016
Electric revenues	$	39	$	37	Electric revenues	$	83	$	79
Transmission pool revenues		13		12	Transmission pool revenues		25		23
Resale of purchased power		2		2	Resale of purchased power		6		7
Operating revenues – regulated electric	$	54	$	51	Operating revenues – regulated electric	$	114	$	109

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


Q2 Electric Revenues millions of US dollars					YTD Electric Revenues millions of US dollars
	2017		2016			2017		2016
Residential	$	19	$	17	Residential	$	41	$	38
Commercial		16		14	Commercial		31		29
Industrial		2		3	Industrial		6		6
Other (1)		2		3	Other (1)		5		6
Total	$	39	$	37	Total	$	83	$	79

1) Other revenue includes amounts recognized relating to FERC transmission rate refunds and other transmission revenue adjustments.

Electric revenues increased $2 million to $39 million in Q2 2017 compared to $37 million in Q2 2016. Year-to-date, electric revenues increased $4 million to $83 million in 2017 compared to $79 million during the same period in 2016 due to transmission and distribution rate changes and increased sales volumes.

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


Q2 Electric Sales Volumes GWh					YTD Electric Sales Volumes GWh
	2017		2016			2017		2016
Residential		184		176	Residential		407		394
Commercial		186		183	Commercial		381		381
Industrial		83		85	Industrial		165		166
Other		3		4	Other		7		8
Total		456		448	Total		960		949

Regulated Fuel for Generation and Purchased Power

Emera Maine’s regulated fuel for generation and purchased power increased $1 million to $14 million in Q2 2017 compared to $13 million in Q2 2016. Year-to-date, regulated fuel for generation and purchased power increased $2 million to $29 million in 2017 compared to $27 million during the same period in 2016.

EMERA CARIBBEAN

Financial Highlights

All amounts are reported in USD, unless otherwise stated.


For the millions of US dollars (except per share amounts)	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Operating revenues – regulated electric	$	84	$	78	$	163	$	149
Regulated fuel for generation and purchased power		36		30		72		57
Contribution to consolidated net income – USD	$	9	$	44	$	14	$	52
Contribution to consolidated net income – CAD	$	11	$	58	$	18	$	68
Contribution to consolidated earnings per common share – CAD	$	0.05	$	0.39	$	0.08	$	0.46
Net income weighted average foreign exchange rate – CAD/USD	$	1.35	$	1.29	$	1.34	$	1.30

EBITDA – USD	$	25	$	67	$	48	$	90
EBITDA – CAD	$	34	$	86	$	64	$	118

Net Income

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


For the millions of US dollars	Three months ended June 30		Six months ended June 30
Contribution to consolidated net income – 2016	$	44	$	52
Increased operating revenues - see Operating Revenues - Regulated Electric below		6		14
Increased regulated fuel for generation - see Regulated Fuel for Generation and Purchased Power below		(6)		(15)
Decreased other income mainly due to a pre-tax gain recognized on the SIF regulatory liability in the prior year		(41)		(41)
Decreased income tax expense primarily due to Q2 2016 pre-tax gain recognized on the BLPC SIF regulatory liability		7		7
Other		(1)		(3)
Contribution to consolidated net income – 2017	$	9	$	14

Emera Caribbean’s CAD contribution to consolidated net income decreased by $47 million to $11 million in Q2 2017 compared to $58 million in Q2 2016 and year-over-year decreased by $50 million to $18 million in 2017 compared to $68 million during the same period in 2016. The foreign exchange rate had minimal impact for the three and six months ended June 30, 2017.

Operating Revenues – Regulated Electric

Operating revenues increased $6 million to $84 million in Q2 2017 compared to $78 million in Q2 2016 due to an increase in fuel charge as a result of higher fuel prices at BLPC. Year-to-date, operating revenues increased $14 million to $163 million in 2017 compared to $149 million during the same period in 2016 due to an increase in fuel charge as a result of higher fuel prices in 2017 at BLPC, partially offset by lower sales volumes at GBPC due to the continued effect of Hurricane Matthew.

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


Q2 Electric Revenues millions of US dollars					YTD Electric Revenues millions of US dollars
	2017		2016			2017		2016
Residential	$	28	$	25	Residential	$	53	$	48
Commercial		48		45	Commercial		93		84
Industrial		5		6	Industrial		11		13
Other		2		2	Other		3		3
Total	$	83	$	78	Total	$	160	$	148

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


Q2 Electric Sales Volumes GWh					YTD Electric Sales Volumes GWh
	2017		2016			2017		2016
Residential		118		117	Residential		226		226
Commercial		194		195	Commercial		372		374
Industrial		21		24	Industrial		43		47
Other		4		5	Other		8		11
Total		337		341	Total		649		658

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $6 million to $36 million in Q2 2017 compared to $30 million in Q2 2016 and year-to-date increased $15 million to $72 million in 2017 compared to $57 million during the same period in 2016 primarily due to higher oil prices.


Q2 Production Volumes GWh					YTD Production Volumes GWh
	2017		2016			2017		2016
Oil		354		360	Oil		678		697
Hydro		10		9	Hydro		19		18
Solar		5		-	Solar		10		-
Total		369		369	Total		707		715


Q2 Average Fuel Costs/MWh					YTD Average Fuel Costs/MWh
US dollars	2017		2016		US dollars	2017		2016
Dollars per MWh	$	98	$	83	Dollars per MWh	$	102	$	80

The change in the average fuel costs in Q2 2017 compared to Q2 2016, and year-to-date in 2017 compared to the same periods in 2016 was the result of higher oil prices.

EMERA ENERGY

Financial Highlights


For the millions of Canadian dollars (except per share amounts)	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Marketing and trading margin (1)	$	(2)	$	(14)	$	24	$	33
Electricity sales (2)		41		77		155		257
Total operating revenues – non-regulated		39		63		179		290
Non-regulated fuel for generation and purchased power (3)		20		75		107		189
Adjusted contribution to consolidated net income (loss)	$	(11)	$	(29)	$	(1)	$	19
After-tax derivative mark-to-market gain (loss)	$	(17)	$	(34)	$	143	$	11
Contribution to consolidated net income (loss)	$	(28)	$	(63)	$	142	$	30
Adjusted contribution to consolidated earnings per common share – basic	$	(0.05)	$	(0.19)	$	-	$	0.13
Contribution to consolidated earnings per common share – basic	$	(0.13)	$	(0.42)	$	0.67	$	0.20

Adjusted EBITDA	$	1	$	(29)	$	32	$	59

(1) Marketing and trading margin excludes a pre-tax mark-to-market loss of $25 million in Q2 2017 (2016 - $60 million loss) and a gain of $212 million YTD in 2017 (2016 - $12 million gain).

(2) Electricity sales excludes a pre-tax mark-to-market gain of $4 million in Q2 2017 (2016 - $4 million gain) and a loss of $3 million YTD in 2017 (2016 - $4 million loss).

(3) Non-regulated fuel for generation and purchased power excludes a pre-tax mark-to-market loss of $5 million in Q2 2017 (2016 - $5 million gain) and a loss of $4 million YTD in 2017 (2016 - $8 million gain).


For the millions of Canadian dollars	Three months ended June 30		Six months ended June 30
Contribution to consolidated net income (loss) – 2016	$	(63)	$	30
Increased (decreased) marketing and trading margin quarter-over-quarter and year-over-year – See Marketing and Trading Margin below		12		(9)
Decreased electricity sales quarter-over-quarter mainly due to an unplanned outage at the Bridgeport Facility and a planned outage at Bayside Power. Year-over-year also due to lower hedged power prices and decreased sales volumes at NEGG driven by less favourable market conditions, partially offset by higher electricity prices at Bayside Power		(36)		(102)
Decreased non-regulated fuel for generation and purchased power quarter-over-quarter mainly due to the recognition of prior period state fuel taxes in Q2 2016, an unplanned outage at the Bridgeport Facility and a planned outage at Bayside Power in Q2 2017. Year-over-year also due to lower hedged natural gas prices and decreased volumes at NEGG driven by less favourable market conditions, partially offset by higher natural gas prices at Bayside Power		55		82
Decreased income tax recovery quarter-over-quarter mainly due to increased income before provision for income taxes. Year-over-year decreased income tax expense due to decreased income before provision for income taxes		(9)		11
Increased mark-to-market, net of tax quarter-over-quarter mainly due to changes in existing positions on long-term natural gas contracts. Year-over-year also due to the reversal of 2016 mark-to-market losses		17		132
Other		(4)		(2)
Contribution to consolidated net income (loss) – 2017	$	(28)	$	142

A portion of earnings are exposed to foreign exchange fluctuations, thereby affecting adjusted CAD contribution to net earnings. The impact of the change in USD/CAD exchange rate quarter-over-quarter decreased earnings in CAD by $1 million in Q2 2017 compared to Q2 2016. Year-to-date in 2017 the impact of the change in USD/CAD exchange rate decreased CAD earnings by $13 million compared to the same period in 2016.

Emera Energy Services

Adjusted EBITDA

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


For the millions of Canadian dollars	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Marketing and trading margin	$	(2)	$	(14)	$	24	$	33
OM&G		5		2		10		12
Other income (expenses), net		-		-		-		(4)
Adjusted EBITDA		$ (7)		$ (16)	$	14	$	17

Marketing and Trading Margin

Marketing and trading margin increased $12 million to $(2) million in Q2 2017 compared to $(14) million in Q2 2016. Overall market conditions were comparable quarter-over-quarter. The increase is mainly due to lower short-term fixed cost commitments for transportation, more valuable transportation positions in 2017 that provided optimization opportunities, and growth in the volume of business.

Year-to-date, marketing and trading margin decreased $9 million to $24 million in 2017 compared to $33 million during the same period in 2016. This decrease is mainly due to less favourable transportation capacity hedges in Q1 2017 and increased gas transportation infrastructure in the northeast United States which reduced volatility, partially offset by the Q2 2017 factors noted above.

Emera Energy Generation

Adjusted EBITDA

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


For the millions of Canadian dollars	Three months ended June 30
	New England					Maritime Canada						Total
	2017		2016			2017			2016			2017		2016
Energy sales	$	23	$	50		$	1		$	14		$	24	$	64
Capacity and other		16		13			1			-			17		13
Electricity revenue	$	39	$	63		$	2		$	14		$	41	$	77
Non-regulated fuel for generation and purchased power		18		59			2			13			20		72
Provincial, state and municipal taxes		2		1			-			-			2		1
OM&G		11		11			5			6			16		17
Adjusted EBITDA	$	8	$	(8	)	$	(5	)	$	(5	)	$	3	$	(13	)


For the millions of Canadian dollars	Six months ended June 30
	New England				Maritime Canada				Total
	2017		2016		2017		2016		2017		2016
Energy sales	$	88	$	189	$	39	$	42	$	127	$	231
Capacity and other		27		26		1		-		28		26
Electricity revenue	$	115	$	215	$	40	$	42	$	155	$	257
Non-regulated fuel for generation and purchased power		76		153		30		31		106		184
Provincial, state and municipal taxes		5		2		-		-		5		2
OM&G		20		20		10		12		30		32
Other income (expenses), net		-		-		-		1		-		1
Adjusted EBITDA	$	14	$	40	$	-	$	-	$	14	$	40

Adjusted EBITDA increased $16 million to $3 million in Q2 2017 from $(13) million in Q2 2016 mainly due to the recognition in Q2 2016 of $20 million in prior period state fuel taxes at NEGG. Absent this, adjusted EBITDA would have decreased $4 million in Q2 2017 compared to Q2 2016. This is due to the impact of an unplanned outage at the Bridgeport Facility which extended from mid-March 2017 to mid-June 2017, partially offset by higher capacity prices that came into effect for NEGG in June 2017.

Year-to-date, Adjusted EBITDA decreased $26 million to $14 million in 2017 from $40 million for the same period in 2016. Absent the $20 million in prior period state fuel taxes at NEGG, adjusted EBITDA would have decreased $46 million in 2017 compared to 2016. This is mainly due to lower realized energy margins in NEGG in Q1 2017, reflecting more favourable short-term energy hedges in 2016 compared to 2017 and lower energy sales volumes due to the unplanned outage at the Bridgeport Facility and less favourable market conditions.

Operating Statistics

For the

Three months ended June 30

Sales Volumes (GWh) (1)

Plant Availability (%) (2)

Net Capacity Factor (%) (3)

2017

2016

2017

2016

2017

2016

New England

461

1,318

53.1%

91.9%

18.9%

55.4%

Maritime Canada

431

27.8%

86.4%

3.7%

63.2%

Total

487

1,749

47.5%

90.6%

15.5%

57.1%

For the

Six months ended June 30

Sales Volumes (GWh) (1)

Plant Availability (%) (2)

Net Capacity Factor (%) (3)

2017

2016

2017

2016

2017

2016

New England

1,396

2,621

70.3%

94.0%

28.8%

55.1%

Maritime Canada

581

949

63.5%

91.1%

41.8%

69.6%

Total

1,977

3,570

68.8%

93.4%

31.7%

58.3%

(1) Sales volumes represent the actual electricity output of the plants.

(2) Plant availability represents the percentage of time in the period that the plant was available to generate power regardless of whether it was running. Effectively, it represents 100% availability reduced by planned and unplanned outages.

(3) Net capacity factor is the ratio of the utilization of an asset as compared to its maximum capability, within a particular time frame. It is generally a function of plant availability and plant economics vis-à-vis the market.

NEGG sales volumes, plant availability and net capacity factor were lower quarter-over-quarter mainly due to the impact of an unplanned outage at the Bridgeport Facility from mid-March 2017 to mid-June 2017. Year-to-date decrease also due to less favourable market conditions in Q1 2017 reducing opportunities for economic dispatch.

The Maritime Canada Facilities’ sales volumes, plant availability and net capacity factor were lower quarter-over-quarter and year-to-date due to a planned outage at the Bayside Facility in Q2 2017.

CORPORATE AND OTHER

Financial Highlights


For the millions of Canadian dollars	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Operating revenues – regulated gas		12		12		25		25
Non-regulated operating revenue		19		8		35		16
Total operating revenue	$	31	$	20	$	60	$	41
Intercompany revenue (1)		9		9		19		19
Income (loss) from equity investments		23		24		45		48
Interest expense, net (2)		73		71		146		110
Adjusted contribution to consolidated net income (loss)	$	(27)	$	171	$	(54)	$	171
After-tax mark-to-market gain (loss)		1		4		1		(117)
Contribution to consolidated net income (loss)	$	(26)	$	175	$	(53)	$	54
Adjusted contribution to consolidated earnings per common share – basic		(0.13)		1.14		(0.25)		1.15
Contribution to consolidated earnings per common share – basic	$	(0.12)	$	1.17	$	(0.25)	$	0.36

Adjusted EBITDA	$	28	$	261	$	59	$	297

(1) Intercompany revenue consists of interest from Brunswick Pipeline, M&NP and EEG.

(2) Interest expense, net excludes a pre-tax mark-to-market gain of $1 million in Q2 and year-to-date 2017 (2016 – nil).

Net Income

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


For the millions of Canadian dollars	Three months ended June 30		Six months ended June 30
Contribution to consolidated net income – 2016	$	175	$	54
Increased non-regulated operating revenue - see Operating Revenues below		11		19
Income from equity investments – see Income from Equity Investments below		(1)		(3)
2016 gain on sale of APUC common shares, pre-tax		(172)		(172)
2016 gain on conversion of APUC subscription receipts and dividend equivalents into APUC common shares, pre-tax		(63)		(63)
Increased interest expense - see Interest Expense below		(2)		(36)
Increased income tax recovery primarily due to decreased income before provision for income taxes, partially offset by the non-taxable portion of gains on APUC transactions in Q2 2016		36		48
After-tax mark-to-market loss in 2016 related to the adjustments from forward contracts economically hedging the debenture offering and the translation of the USD cash balance		(4)		117
Other		(6)		(17)
Contribution to consolidated net income (loss) – 2017	$	(26)	$	(53)

Operating Revenues

Operating revenues increased $11 million to $31 million in Q2 2017 compared to $20 million in Q2 2016. Year-to-date, operating revenues increased $19 million to $60 million in 2017 compared to $41 million in the same period in 2016 due to increased project activity in Emera Utility Services.

Income from Equity Investments

Income from equity investments are summarized in the following table:


For the millions of Canadian dollars	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
LIL	$	9	$	6	$	18	$	10
NSPML		9		4		16		9
M&NP		5		5		11		11
APUC - sold in 2016		-		9		-		18
Income from equity investments	$	23	$	24	$	45	$	48

Income from equity investments decreased $1 million to $23 million in Q2 2017 compared to $24 million in Q2 2016. Year-to-date, income from equity investments decreased $3 million to $45 million in 2017 compared to $48 million during the same period in 2016. These variances are a result of the sale of APUC in 2016, partially offset by higher earnings from the increased investment in NSPML and LIL.

Interest Expense

Interest expense increased $2 million to $73 million Q2 2017 compared to $71 million in Q2 2016 as a result of the interest on the permanent USD denominated debt for the acquisition offset by the interest on the convertible debentures related to the TECO Energy acquisition in 2016. Year-to-date, interest expense increased $36 million to $146 million in 2017 compared to $110 million for the same period in 2016 primarily due to financing related to the TECO Energy acquisition.

LIQUIDITY AND CAPITAL RESOURCES

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

Consolidated Cash Flow Highlights

Significant changes in the condensed consolidated statements of cash flows between the six months ended June 30, 2017 and 2016 include:


millions of Canadian dollars	2017		2016		$ Change
Cash and cash equivalents, beginning of period	$	404	$	1,073	$	(669)
Provided by (used in):
Operating cash flow before change in working capital		703		325		378
Change in working capital		(222)		151		(373)
Operating activities		481		476		5
Investing activities		(888)		178		(1,066)
Financing activities		227		5,810		(5,583)
Effect of exchange rate changes on cash and cash equivalents		(7)		(78)		71
Cash and cash equivalents, end of period	$	217	$	7,459	$	(7,242)

Cash Flow from Operating Activities

Refer to the Consolidated Income Statement and Operating Cash Flow Highlights earlier in the document for details.

Cash Flow Used In Investing Activities

Net cash used in investing activities increased $1,066 million to $888 million for the six months ended June 30, 2017 compared to cash provided by investing activities of $178 million in Q2 2016 due to an increase in capital spending and proceeds from the sale of APUC common shares in 2016.

Capital expenditures for the six months ended June 30, 2017, including AFUDC and net of proceeds from disposal of assets, were $728 million compared to $235 million during the same period in 2016. The increase was a result of the acquisition of TECO Energy and additional capital spending in NSPI, Emera Maine and Emera Energy, offset by a reduction in capital spend in Emera Caribbean. Details of the capital spend are shown below:

•

$434 million at Emera Florida and New Mexico;

•

$169 million at NSPI (2016 – $143 million);

•

$54 million at Emera Maine (2016 – $32 million);

•

$23 million at Emera Caribbean (2016 – $45 million);

•

$37 million at Emera Energy (2016 – $12 million);

•

$11 million in Corporate and Other (2016 – $3 million)

Cash Flow from Financing Activities

Net cash provided by financing activities decreased $5,583 million to $227 million for the six months ended June 30, 2017 compared to $5,810 million for the same period in 2016. The decrease was due to proceeds of the long-term debt issuance related to the acquisition of TECO Energy in 2016. This was partially offset by increased 2017 borrowings under committed credit facilities.

Contractual Obligations

As at June 30, 2017, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:


millions of Canadian dollars	2017		2018		2019		2020		2021		Thereafter		Total
Long-term debt	$	448	$	767	$	1,380	$	723	$	1,961	$	9,400	$	14,679
Interest payment obligations (1)		340		631		602		555		505		6,369		9,002
Purchased power (2)		136		230		222		210		206		2,338		3,342
Transportation (3)		265		406		300		273		190		1,571		3,005
Pension and post-retirement obligations (4)		66		47		48		49		51		863		1,124
Fuel and gas supply		344		230		120		47		39		-		780
Long-term service agreements (5)		61		64		63		30		40		213		471
Asset retirement obligations		2		2		1		2		43		390		440
Equity investment commitments (6)		220		25		-		190		-		-		435
Leases and other (7)		50		20		12		12		6		66		166
Capital projects		95		17		-		-		-		-		112
Demand side management		19		45		11		-		-		-		75
Long-term payable		2		4		5		5		5		10		31
Convertible debentures		-		-		-		-		-		4		4
	$ 2,048		$ 2,488		$ 2,764		$ 2,096		$ 3,046		$ 21,224		$ 33,666

(1) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at June 30, 2017, including any expected required payment under associated swap agreements.

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

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

(4) Defined benefit funding contractual obligations were determined based on funding requirements and assuming pension accruals cease as at December 31, 2016. Credited service and earnings are assumed to be crystallized as at December 31, 2016. The Company’s contractual obligations for post-retirement (non-pension) benefits assumes members must be age 55 or over (50 for TECO Energy) as at December 31, 2016 to be eligible. As the defined benefit pension plans currently undergoes regular reviews to revise contribution requirements and members are still accruing service under the plans, actual future contributions to the plans will differ from the amounts shown.

(5) Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management.

(6) Emera has a commitment in connection with the Federal Loan Guarantee to complete construction of the Maritime Link. Thirty per cent of the financing of this project will come from Emera as equity. Emera also has a commitment to make equity contributions to the Labrador Island Link Limited Partnership upon draw requests from the general partner. The amounts forecasted are a combination of equity investments for both projects and are subject to change in both timing and amounts as the projects advance through construction.

(7) Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles.

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

Debt Management

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


millions of dollars	Maturity	Revolving Credit Facilities		Utilized		Undrawn and Available
Emera – Operating and acquisition credit facility	June 2020 – Revolver	$	700	$	225	$	475
Emera Florida and New Mexico - in USD - credit facilities	March 2018 -March 2022		1,300		803		497
NSPI – Operating credit facility	October 2021 – Revolver		600		320		280
Emera Maine – in USD – Operating credit facility	September 2019 – Revolver		80		41		39
Other – in USD – Operating credit facilities	Various		32		-		32

Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly and the Company is in compliance with covenant requirements as at June 30, 2017.

NSPI

On June 28, 2017, NSPI amended its operating credit facility to extend the maturity from October 2020 to October 2021 and the debt to capitalization ratio from 0.65:1 to 0.70:1. All other terms of the agreement are the same.

Emera Florida and New Mexico

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

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

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

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

GBPC

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

Guarantees and Letters of Credit

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

TECO Coal was sold on September 21, 2015 to Cambrian Coal Corporation (“Cambrian”). Pursuant to the sales agreement, Cambrian is obligated to file, in respect of each mining permit, applications in connection with the change of control with the appropriate governmental entities. As each application is approved, Cambrian is required to post a bond or other appropriate collateral in order to obtain the release of the corresponding bond secured by the TECO Energy indemnity for that permit. As at June 30, 2017, TECO Energy had remaining indemnified bonds totaling $9 million ($7 million USD).

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

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

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

Emera has standby letters of credit in the amount of $21 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.

Emera Inc. on behalf of NSPI has a standby letter of credit to secure obligations under an unfunded pension plan. The letter of credit expires in June 2018 and is renewed annually. The amount committed as at June 30, 2017 was $51 million.

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

There have been no material changes in Emera’s risk management profile and practices from those disclosed in the Company’s 2016 annual MD&A.

Hedging Items Recognized on the Balance Sheets

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


As at millions of Canadian dollars	June 30 2017		December 31 2016
Derivative instrument assets (current and other assets)	$	6	$	10
Derivative instrument liabilities (current and long-term liabilities)		(15)		(27)
Net derivative instrument assets (liabilities)	$	(9)	$	(17)

Hedging Impact Recognized in Net Income

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


For the millions of Canadian dollars	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Operating revenues – regulated	$	(3)	$	(2)	$	(6)	$	(5)
Non-regulated fuel for generation and purchased power		(1)		(1)		3		3
Income from equity investments		-		(1)		-		(1)
Effective net gains (losses)	$	(4)	$	(4)	$	(3)	$	(3)

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

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


For the millions of Canadian dollars	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Non-regulated fuel for generation and purchased power	$	-	$	1	$	-	$	-
Ineffective gains (losses)	$	-	$	1	$	-	$	-

Regulatory Items Recognized on the Balance Sheets

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


As at millions of Canadian dollars	June 30 2017		December 31 2016
Derivative instrument assets (current and other assets)	$	150	$	229
Regulatory assets (current and other assets)		19		11
Derivative instrument liabilities (current and long-term liabilities)		(20)		(12)
Regulatory liabilities (current and long-term liabilities)		(150)		(231)
Net asset (liability)	$	(1)	$	(3)

Regulatory Impact Recognized in Net Income

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


For the millions of Canadian dollars	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Regulated fuel for generation and purchased power (1)	$	6	$	(1)	$	13	$	2
Net gains (losses)	$	6	$	(1)	$	13	$	2

(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 or property plant and equipment will be recognized in “Regulated fuel for generation and purchased power” when the hedged item is consumed.

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

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


As at millions of Canadian dollars	June 30 2017		December 31 2016
Derivative instruments assets (current and other assets)	$	70	$	37
Derivative instruments liabilities (current and long-term liabilities)		(193)		(434)
Net derivative instrument assets (liabilities)	$	(123)	$	(397)

HFT Items Recognized in Net Income

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


For the millions of Canadian dollars	Three months ended June 30				Six months ended June 30
		2017		2016		2017		2016
Operating revenue - non-regulated	$	59	$	35	$	383	$	257
Non-regulated fuel for purchased power		5		5		7		4
Net gains (losses)	$	64	$	40	$	390	$	261

Other Derivatives Recognized on the Balance Sheets

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


As at millions of Canadian dollars	June 30 2017		December 31 2016
Derivative instrument liabilities (current and long-term liabilities)	$	-	$	(2)
Net derivative instrument assets (liabilities)	$	-	$	(2)

Other Derivatives Recognized in Net Income

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


For the millions of Canadian dollars	Three months ended June 30				Six months ended June 30
		2017		2016		2017		2016
Interest expense, net	$	1	$	-	$	1	$	-
Other income (expense)		-		(6)		-		(101)
Total gains (losses)	$	1	$	(6)	$	1	$	(101)

DISCLOSURE AND INTERNAL CONTROLS

Management is responsible for establishing and maintaining adequate disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”). The Company’s internal control framework is based on the criteria published in the Internal Control - Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations (“COSO”) of the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer, evaluated the design of the Company’s DC&P and ICFR as at June 30, 2017, to provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.

Change in ICFR

During the first quarter of 2017, TEC implemented an SAP developed Customer Relationship Management and Billing System as a process improvement initiative which replaced their legacy customer information system. TEC has made appropriate changes to internal controls and procedures, as is expected with a major system implementation.

Except as described above, there were no changes in the Company’s ICFR during the six months ended June 30, 2017, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

CRITICAL ACCOUNTING ESTIMATES

The preparation of consolidated financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current conditions and assumptions believed to be reasonable at the time the assumption is made.

Significant areas requiring the use of management estimates relate to rate-regulated assets and liabilities, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, capitalized overhead and valuation of financial instruments. Actual results may differ significantly from these estimates. There was no material change in the nature of the Company’s critical accounting estimates from those disclosed in the Company’s 2016 annual MD&A.

CHANGES IN ACCOUNTING POLICIES AND PRACTICES

Future Accounting Pronouncements

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

Revenue from Contracts with Customers

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

The Company implemented a revenue recognition project plan in 2016. In Q1 2017, the Company concluded that the accounting for contributions in aid of construction will be out of the scope of the new standard. In Q2 2017, the Company completed an analysis of material regulated revenue streams and collectability risk and has concluded that there will be no material changes on adoption of this standard. The Company will adopt the standard using the modified retrospective approach. Emera continues to evaluate the impact of this standard on unregulated revenue streams and financial statement disclosure requirements. The Company continues to monitor the assessment of ASC Topic 606 by the AICPA Power and Utilities Revenue Recognition Task Force for developments.

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 standard requires investments in equity securities, except those accounted for under the equity method of accounting or those that result in consolidation, to be measured at fair value. The Company will elect to measure equity securities that do not have a readily determinable fair value, at cost minus impairment (if any), plus or minus observable price changes resulting from transactions for the identical or a similar investment of the same issuer. The standard eliminates the available-for-sale classification for equity investments that recognized changes in the fair value as a component of other comprehensive income, resulting in all changes in fair value being recognized in net income. The increase in volatility of Other income (expense), net as a result of the remeasurement of equity investments is not expected to be significant. The Company will adopt this guidance effective January 1, 2018 with a cumulative-effect adjustment to the Consolidated Balance Sheet.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. The standard, codified as ASC Topic 842, increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged. The guidance will require additional disclosures regarding key information about leasing arrangements. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018. Early adoption is permitted, and is required to be applied using a modified retrospective approach. The Company is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

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

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The guidance requires the service cost component of defined benefit pension or other postretirement benefit plans to be reported in the same line items as other compensation costs. The other components of net benefit cost are required to be presented in the Consolidated Statements of Income outside of income from operations. Only the service cost component will be eligible for capitalization under this guidance. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The guidance is required to be applied retrospectively for presentation in the Consolidated Statements of Income and prospectively for the guidance limiting capitalization. The Company is currently evaluating the impact of the adoption of this standard on the consolidated financial statements, including the eligibility for capitalization of the other components of net benefit cost given the application of ASC 980 Regulated Operations. The Company will adopt this guidance effective January 1, 2018.

SUMMARY OF QUARTERLY RESULTS


For the quarter ended millions of Canadian dollars (except per share amounts)	Q2 2017		Q1 2017		Q4 2016		Q3 2016			Q2 2016		Q1 2016		Q4 2015		Q3 2015
Operating revenues	$	1,469	$	1,857	$	1,513	$	1,387		$	499	$	877	$	732	$	642
Net income (loss) attributable to common shareholders		101		312		70		(95	)		208		44		192		35
Adjusted net income attributable to common shareholders		117		152		104		14			238		120		87		23
Earnings per common share – basic		0.47		1.48		0.34		(0.52	)		1.39		0.30		1.31		0.24
Earnings per common share – diluted		0.47		1.47		0.34		(0.52	)		1.38		0.30		1.30		0.24
Adjusted earnings per common share – basic		0.55		0.72		0.51		0.08			1.59		0.81		0.59		0.16

Quarterly operating revenues and net income attributable to common shareholders are affected by seasonality. Historically, the first quarter has generally been the strongest because a significant portion of the Company’s operations are in northeastern North America, where winter is the peak electricity usage season. However, with the addition of Emera Florida and New Mexico, the third quarter will provide stronger earnings contributions due to summer being the heaviest electric consumption season in Florida. Seasonal and other weather patterns, as well as the number and severity of storms, can affect the demand for energy and the cost of service. Quarterly results could also be affected by items outlined in the Significant Items Affecting Earnings section and mark-to-market adjustments.