EX-99.2 3 d349067dex992.htm AUDITED CONSOLIDATED FINANCIAL STATEMENTS

Exhibit 99.2

EMERA INCORPORATED

Consolidated

Financial Statements

December 31, 2016 and 2015

108

MANAGEMENT REPORT

Management's Responsibility for Financial Reporting

The accompanying consolidated financial statements of Emera Incorporated and the information in this annual report are the responsibility of management and have been approved by the Board of Directors (“Board”).

The consolidated financial statements have been prepared by management in accordance with United States Generally Accepted Accounting Principles. When alternative accounting methods exist, management has chosen those it considers most appropriate in the circumstances. In preparation of these consolidated financial statements, estimates are sometimes necessary when transactions affecting the current accounting period cannot be finalized with certainty until future periods. Management represents that such estimates, which have been properly reflected in the accompanying consolidated financial statements, are based on careful judgements and are within reasonable limits of materiality. Management has determined such amounts on a reasonable basis in order to ensure that the consolidated financial statements are presented fairly in all material respects. Management has prepared the financial information presented elsewhere in the annual report and has ensured that it is consistent with that in the consolidated financial statements.

Emera Incorporated maintains effective systems of internal accounting and administrative controls, consistent with reasonable cost. Such systems are designed to provide reasonable assurance that the financial information is reliable and accurate, and that Emera Incorporated's assets are appropriately accounted for and adequately safeguarded.

The Board is responsible for ensuring that management fulfils its responsibilities for financial reporting and is ultimately responsible for reviewing and approving the consolidated financial statements. The Board carries out this responsibility principally through its Audit Committee.

The Audit Committee is appointed by the Board, and its members are directors who are not officers or employees of Emera Incorporated. The Audit Committee meets periodically with management, as well as with the internal auditors and with the external auditors, to discuss internal controls over the financial reporting process, auditing matters and financial reporting issues, to satisfy itself that each party is properly discharging its responsibilities, and to review the annual report, the consolidated financial statements and the external auditors' report. The Audit Committee reports its findings to the Board for consideration when approving the consolidated financial statements for issuance to the shareholders. The Audit Committee also considers, for review by the Board and approval by the shareholders, the appointment of the external auditors.

The consolidated financial statements have been audited by Ernst & Young LLP, the external auditors, in accordance with Canadian Generally Accepted Auditing Standards. Ernst & Young LLP has full and free access to the Audit Committee.

February 10, 2017

“ Christopher Huskilson” “Gregory Blunden”

President and Chief Executive Officer President and Chief Executive Officer Chief Financial Officer

109

INDEPENDENT AUDITORS’ REPORT

To the Shareholders of Emera Incorporated

We have audited the accompanying consolidated financial statements of Emera Incorporated, which comprise the consolidated balance sheets as at December 31, 2016 and 2015, and the consolidated statements of income, comprehensive income, cash flows and changes in equity for the years then ended, and a summary of significant accounting policies and other explanatory information.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with United States generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditors consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Emera Incorporated as at December 31, 2016 and 2015, and its financial performance and its cash flows for the years then ended in accordance with United States generally accepted accounting principles.

Halifax, Canada “Ernst & Young LLP”

February 10, 2017 Chartered Professional Accountants

Licensed Public Accountants

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Emera Incorporated

# Consolidated Statements of Income

For the | Year ended December 31
millions of Canadian dollars (except per share amounts) |  | 2016 |  | 2015
Operating revenues |  |  |  |
Regulated electric | $ | 3,437 | $ | 2,141
Regulated gas |  | 499 |  | 52
Non-regulated |  | 341 |  | 596
Total operating revenues |  | 4,277 |  | 2,789
Operating expenses |  |  |  |
Regulated fuel for generation and purchased power |  | 1,222 |  | 815
Regulated cost of natural gas |  | 177 |  | -
Regulated fuel adjustment mechanism and fixed cost deferrals |  | 61 |  | 42
Non-regulated fuel for generation and purchased power |  | 313 |  | 336
Non-regulated direct costs |  | 29 |  | 19
Operating, maintenance and general |  | 1,137 |  | 666
Provincial, state, and municipal taxes |  | 195 |  | 63
Depreciation and amortization |  | 588 |  | 340
Total operating expenses |  | 3,722 |  | 2,281
Income from operations |  | 555 |  | 508
Income from equity investments (note 6) |  | 100 |  | 108
Other income (expenses), net (note 7) |  | 174 |  | 141
Interest expense, net (note 8) |  | 585 |  | 212
Income before provision for income taxes |  | 244 |  | 545
Income tax expense (recovery) (note 9) |  | (22) |  | 93
Net income |  | 266 |  | 452
Non-controlling interest in subsidiaries |  | 11 |  | 25
Net income of Emera Incorporated |  | 255 |  | 427
Preferred stock dividends |  | 28 |  | 30
Net income attributable to common shareholders | $ | 227 | $ | 397
Weighted average shares of common stock outstanding (in millions)(note 11) |  |  |  |
Basic |  | 171 |  | 146
Diluted |  | 172 |  | 146
Earnings per common share (note 11) |  |  |  |
Basic | $ | 1.33 | $ | 2.72
Diluted | $ | 1.32 | $ | 2.71
Dividends per common share declared | $ | 1.9950 | $ | 1.6625
The accompanying notes are an integral part of these consolidated financial statements.

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Emera Incorporated

# Consolidated Statements of Comprehensive Income

For the | Year ended December 31 |
millions of Canadian dollars |  | 2016 |  | 2015 |
Net income | $ | 266 | $ | 452 |
Other comprehensive income (loss), net of tax |  |  |  |  |
Foreign currency translation adjustment (1) |  | 32 |  | 435 |
Unrealized gains (losses) on net investment hedges (2) |  | (49) |  | - |
Cash flow hedges |  |  |  |  |
Net derivative gains (losses) (3) |  | 11 |  | (34) |
Less: reclassification adjustment for losses (gains) included in income (4) |  | 11 |  | 7 |
Net effects of cash flow hedges |  | 22 |  | (27) |
Unrealized gains on available-for-sale investment |  |  |  |  |
Unrealized gain (loss) arising during the period |  | 3 |  | (3) |
Less: reclassification adjustment for (gains) recognized in income |  | (4) |  | - |
Net unrealized holding gains (losses) |  | (1) |  | (3) |
Net change in unrecognized pension and post-retirement benefit obligation (5) |  | 12 |  | 107 |
Other equity method reclassification adjustment (6) |  | (46) |  | - |
Other comprehensive income (loss) (7) |  | (30) |  | 512 |
Comprehensive income (loss) |  | 236 |  | 964 |
Comprehensive income (loss) attributable to non-controlling interest |  | 8 |  | 53 |
Comprehensive Income of Emera Incorporated | $ | 228 | $ | 911 |
The accompanying notes are an integral part of these consolidated financial statements. |
1) Net of tax recovery of $3 million (2015 - $7 million tax expense) for the year ended December 31, 2016. |
2) The Company has designated $1.2 billion United States dollar dominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in United States dollar denominated operations. |
3) Net of tax expense of nil (2015 - $1 million tax expense) for the year ended December 31, 2016. |
4) Net of tax recovery of nil (2015 - $2 million tax recovery) for the year ended December 31, 2016. |
5) Net of tax expense of $3 million (2015 - $8 million tax expense) for the year ended December 31, 2016. |
6) Net of tax recovery of $9 million (2015 - nil) for the year ended December 31, 2016. |
7) Net of tax recovery of $9 million (2015 - $14 million tax expense) for the year ended December 31, 2016. |

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Emera Incorporated

# Consolidated Balance Sheets

As at | December 31 | December 31
millions of Canadian dollars |  | 2016 |  | 2015
Assets |  |  |  |
Current assets |  |  |  |
Cash and cash equivalents | $ | 404 | $ | 1,073
Restricted cash |  | 87 |  | 19
Receivables, net (note 13) |  | 1,014 |  | 578
Income taxes receivable (note 9) |  | 33 |  | 12
Inventory (note 14) |  | 472 |  | 314
Derivative instruments (notes 15 and 16) |  | 145 |  | 250
Regulatory assets (note 17) |  | 80 |  | 94
Prepayments and other current assets (note 19) |  | 276 |  | 256
Total current assets |  | 2,511 |  | 2,596
Property, plant and equipment, net of accumulated depreciation |  |  |  |
and amortization of $7,787 and $3,737, respectively (note 20) |  | 17,290 |  | 6,469
Other assets |  |  |  |
Income taxes receivable (note 9) |  | 48 |  | 49
Deferred income taxes (note 9) |  | 125 |  | 32
Derivative instruments (notes 15 and 16) |  | 131 |  | 168
Pension and post-retirement assets (note 21) |  | 9 |  | 9
Regulatory assets (note 17) |  | 1,242 |  | 605
Net investment in direct financing lease (note 22) |  | 488 |  | 480
Investments subject to significant influence (note 6) |  | 947 |  | 1,145
Investment securities |  | 48 |  | 116
Goodwill (note 23) |  | 6,213 |  | 264
Other long-term assets |  | 169 |  | 106
Total other assets |  | 9,420 |  | 2,974
Total assets | $ | 29,221 | $ | 12,039
The accompanying notes are an integral part of these consolidated financial statements.

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Emera Incorporated
Consolidated Balance Sheets – Continued
As at | December 31 | December 31
millions of Canadian dollars |  | 2016 |  | 2015
Liabilities and Equity |  |  |  |
Current liabilities |  |  |  |
Short-term debt (note 24) | $ | 961 | $ | 16
Current portion of long-term debt (note 26) |  | 476 |  | 274
Accounts payable |  | 1,242 |  | 394
Income taxes payable (note 9) |  | 19 |  | 8
Derivative instruments (notes 15 and 16) |  | 325 |  | 349
Regulatory liabilities (note 17) |  | 362 |  | 112
Pension and post-retirement liabilities (note 21) |  | 58 |  | 7
Other current liabilities (note 25) |  | 281 |  | 207
Total current liabilities |  | 3,724 |  | 1,367
Long-term liabilities |  |  |  |
Long-term debt (note 26) |  | 14,268 |  | 3,735
Deferred income taxes (note 9) |  | 1,672 |  | 762
Convertible debentures (2015 – represented by instalment receipts) (note 10) |  | 8 |  | 681
Derivative instruments (notes 15 and 16) |  | 150 |  | 96
Regulatory liabilities (note 17) |  | 1,277 |  | 353
Asset retirement obligations (note 27) |  | 170 |  | 109
Pension and post-retirement liabilities (note 21) |  | 669 |  | 303
Other long-term liabilities (note 6) |  | 467 |  | 299
Total long-term liabilities |  | 18,681 |  | 6,338
Commitments and contingencies (note 28) |  |  |  |
Equity |  |  |  |
Common stock (note 10) |  | 4,738 |  | 2,157
Cumulative preferred stock (note 29) |  | 709 |  | 709
Contributed surplus |  | 75 |  | 29
Accumulated other comprehensive income (note 12) |  | 106 |  | 137
Retained earnings |  | 1,076 |  | 1,168
Total Emera Incorporated equity |  | 6,704 |  | 4,200
Non-controlling interest in subsidiaries (note 30) |  | 112 |  | 134
Total equity |  | 6,816 |  | 4,334
Total liabilities and equity | $ | 29,221 | $ | 12,039
The accompanying notes are an integral part of these consolidated financial statements.

Approved on behalf of the Board of Directors

“M. Jacqueline Sheppard” “Christopher G. Huskilson”

Chair of the Board President and Chief Executive Officer

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Emera Incorporated
Consolidated Statements of Cash Flows
For the | Year ended December 31
millions of Canadian dollars |  | 2016 |  | 2015
Operating activities |  |  |  |
Net income | $ | 266 | $ | 452
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |
Depreciation and amortization |  | 593 |  | 352
Income from equity investments, net of dividends |  | (59) |  | (34)
Allowance for equity funds used during construction |  | (22) |  | (2)
Deferred income taxes, net |  | (67) |  | 20
Net change in pension and post-retirement liabilities |  | 13 |  | 37
Regulated fuel adjustment mechanism and fixed cost deferrals |  | 63 |  | 39
Net change in fair value of derivative instruments |  | 258 |  | 96
Net change in regulatory assets and liabilities |  | (25) |  | (6)
Net change in capitalized transportation capacity |  | 33 |  | (133)
Foreign exchange loss (gain) |  | 43 |  | (27)
Gain on APUC sale of common shares and conversion of subscription receipts (note 7) |  | (223) |  | -
Other operating activities, net |  | 46 |  | (18)
Changes in non-cash working capital (note 31) |  | 134 |  | (102)
Net cash provided by operating activities |  | 1,053 |  | 674
Investing activities |  |  |  |
Acquisition, net of cash acquired (note 4) |  | (8,409) |  | -
Additions to property, plant and equipment |  | (1,031) |  | (427)
Net purchase of investments subject to significant influence, inclusive of |  |  |  |
acquisition costs |  | (276) |  | (136)
Net proceeds on sale of investment subject to significant influence and held-for-trading common shares (note 6) |  | 665 |  | 282
Proceeds on distribution from investment subject to significant influence (note 6) |  | - |  | 179
Other investing activities |  | (54) |  | (22)
Net cash used in investing activities |  | (9,105) |  | (124)
Financing activities |  |  |  |
Change in short-term debt, net |  | 118 |  | (262)
Proceeds from long-term debt, net of issuance costs |  | 6,423 |  | 446
Proceeds from convertible debentures, net of issuance costs (2015 – represented by instalment receipts)(note 10) |  | 1,413 |  | 681
Retirement of long-term debt |  | (273) |  | (90)
Net borrowings (repayments) under committed credit facilities |  | (315) |  | (201)
Issuance of common stock, net of issuance costs |  | 354 |  | 9
Dividends on common stock |  | (221) |  | (162)
Dividends on preferred stock |  | (28) |  | (30)
Dividends paid by subsidiaries to non-controlling interest |  | (5) |  | (14)
Redemption of preferred shares by subsidiary |  | - |  | (135)
Other financing activities |  | (18) |  | (21)
Net cash provided by financing activities |  | 7,448 |  | 221
Effect of exchange rate changes on cash and cash equivalents |  | (65) |  | 81
Net (decrease) increase in cash and cash equivalents |  | (669) |  | 852
Cash and cash equivalents, beginning of year |  | 1,073 |  | 221
Cash and cash equivalents, end of year |  | 404 |  | 1,073
Cash and cash equivalents consists of: |  |  |  |
Cash |  | 221 |  | 996
Short-term investments |  | 183 |  | 77
Cash and cash equivalents |  | 404 |  | 1,073
Supplementary Information to Consolidated Statements of Cash Flows (note 31) |  |  |  |
The accompanying notes are an integral part of these consolidated financial statements.

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Emera Incorporated
Consolidated Statements of Changes in Equity
|  |  |  | Accumulated |  |  |
|  |  |  | Other |  | Emera | Non- |
| Common | Preferred | Contributed | Comprehensive | Retained | Total | Controlling | Total
millions of Canadian dollars | Stock | Stock | Surplus | Income (“AOCI”) | Earnings | Equity | Interest | Equity
2016
Balance, December 31, 2015 | $ | 2,157 | $ | 709 | $ | 29 | $ | 137 | $ | 1,168 | $ | 4,200 | $ | 134 | $ | 4,334
Net income of Emera Incorporated |  | - |  | - |  | - |  | - |  | 255 |  | 255 |  | 11 |  | 266
Other comprehensive income (loss), net of tax recovery of $9 million |  | - |  | - |  | - |  | (27) |  | - |  | (27) |  | (3) |  | (30)
Issuance of common stock, net of after-tax issuance costs |  | 2,450 |  | - |  | - |  | - |  | - |  | 2,450 |  | - |  | 2,450
Dividends declared on preferred stock (note 29) |  | - |  | - |  | - |  | - |  | (28) |  | (28) |  | - |  | (28)
Dividends declared on common stock ($1.9950/share) |  | - |  | - |  | - |  | - |  | (324) |  | (324) |  | - |  | (324)
Common stock issued under purchase plan |  | 110 |  | - |  | - |  | - |  | - |  | 110 |  | - |  | 110
Senior management stock options exercised |  | 17 |  | - |  | (1) |  | - |  | - |  | 16 |  | - |  | 16
Stock option expense |  | - |  | - |  | 2 |  | - |  | - |  | 2 |  | - |  | 2
Employee Share Purchase Plan |  | 1 |  | - |  | - |  | - |  | - |  | 1 |  | - |  | 1
Beneficial conversion feature, net of tax (note 8) |  | - |  | - |  | 43 |  | - |  | - |  | 43 |  | - |  | 43
Preferred dividends paid and payable by subsidiaries to non-controlling interests |  | - |  | - |  | - |  | - |  | - |  | - |  | (3) |  | (3)
Common dividends paid and payable by subsidiaries to non-controlling interest |  | - |  | - |  | - |  | - |  | - |  | - |  | (2) |  | (2)
Acquisition of non-controlling interest of ECI |  | 3 |  | - |  | 7 |  | - |  | - |  | 10 |  | (25) |  | (15)
Other |  | - |  | - |  | (5) |  | (4) |  | 5 |  | (4) |  | - |  | (4)
Balance, December 31, 2016 | $ | 4,738 | $ | 709 | $ | 75 | $ | 106 | $ | 1,076 | $ | 6,704 | $ | 112 | $ | 6,816
The accompanying notes are an integral part of these consolidated financial statements.

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Emera Incorporated
Consolidated Statements of Changes in Equity – Continued
|  |  |  | Accumulated |  |  |  |  |
|  |  |  | Other |  | Emera | Non- |
| Common | Preferred | Contributed | Comprehensive | Retained | Total | Controlling | Total
millions of Canadian dollars | Stock | Stock | Surplus | Income (“AOCI”) | Earnings | Equity | Interest | Equity
2015
Balance, December 31, 2014 | $ | 2,016 | $ | 709 | $ | 9 | $ | (347) | $ | 1,012 |  | 3,399 | $ | 306 | $ | 3,705
Net income of Emera Incorporated |  | - |  | - |  | - |  | - |  | 427 |  | 427 |  | 25 |  | 452
Other comprehensive income (loss), net of tax expense of $14 million |  | - |  | - |  | - |  | 484 |  | - |  | 484 |  | 28 |  | 512
Dividends declared on preferred stock (note 29) |  | - |  | - |  | - |  | - |  | (30) |  | (30) |  | - |  | (30)
Dividends declared on common stock ($1.6625/share) |  | - |  | - |  | - |  | - |  | (240) |  | (240) |  | - |  | (240)
Dividends paid by subsidiaries to non-controlling interest |  | - |  | - |  | - |  | - |  | - |  | - |  | (3) |  | (3)
Common stock issued under purchase plan |  | 84 |  | - |  | - |  | - |  | - |  | 84 |  | - |  | 84
Senior management stock options exercised |  | 2 |  | - |  | - |  | - |  | - |  | 2 |  | - |  | 2
Stock option expense |  | - |  | - |  | 1 |  | - |  | - |  | 1 |  | - |  | 1
Employee Share Purchase Plan |  | 1 |  | - |  | - |  | - |  | - |  | 1 |  | - |  | 1
Preferred dividends paid by subsidiaries to non-controlling interest |  | - |  | - |  | - |  | - |  | - |  | - |  | (12) |  | (12)
Redemption of preferred shares of subsidiary |  | - |  | - |  | - |  | - |  | - |  | - |  | (132) |  | (132)
Acquisition of non-controlling interest of ECI |  | 54 |  | - |  | 19 |  | - |  | - |  | 73 |  | (78) |  | (5)
Equity method investments |  | - |  | - |  | - |  | - |  | (1) |  | (1) |  | - |  | (1)
Balance, December 31, 2015 | $ | 2,157 | $ | 709 | $ | 29 | $ | 137 | $ | 1,168 |  | 4,200 | $ | 134 | $ | 4,334
The accompanying notes are an integral part of these consolidated financial statements.

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Emera Incorporated

Notes to the Consolidated Financial Statements

As at December 31, 2016 and 2015

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies for both the regulated and non-regulated operations of Emera Incorporated are as follows:

Nature of Operations

Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation, transmission and distribution, gas transmission and utility energy services.

Emera’s primary rate-regulated subsidiaries and investments at December 31, 2016 included the following:

· Emera Florida and New Mexico represents TECO Energy, Inc. (“TECO Energy”), a holding company with regulated electric and gas utilities in Florida and New Mexico, which was acquired on July 1, 2016. TECO Energy’s holdings includes:

· Tampa Electric Company (“TEC”), which holds the Tampa Electric Division (“Tampa Electric”), an integrated regulated electric utility, serving approximately 736,000 customers in West Central Florida and Peoples Gas System Division, (“PGS”) a regulated gas distribution utility, serving approximately 374,000 customers across Florida;

· New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility, serving approximately 522,000 customers across New Mexico;

· TECO Finance, Inc. (“TECO Finance”), a wholly owned financing subsidiary of TECO Energy.

· Nova Scotia Power Inc. (“NSPI”), a fully integrated electric utility and the primary electricity supplier in Nova Scotia, serving approximately 511,000 customers;

· Emera Maine provides electric transmission and distribution services to approximately 157,000 customers in the State of Maine in the United States;

· Emera (Caribbean) Incorporated (“ECI”) 100.0 per cent interest (December 31, 2015 – 95.5 per cent) includes:

· The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated utility and sole provider of electricity on the island of Barbados, serving approximately 126,000 customers;

· a 50.0 per cent direct and 30.4 per cent indirect interest (through a 60.7 per cent interest in ICD Utilities Limited (“ICDU”)) in Grand Bahama Power Company Limited (“GBPC”), a vertically integrated utility and sole provider of electricity on Grand Bahama Island, serving approximately 19,000 customers;

· a 51.9 per cent interest (December 31, 2015 – 49.6 per cent indirect interest) in Dominica Electricity Services Ltd. (“Domlec”), an integrated utility on the island of Dominica, serving approximately 36,000 customers;

· a 19.1 per cent indirect interest (December 31, 2015 – 18.2 per cent indirect interest) in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility in St. Lucia;

· Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick to the United States border under a 25-year firm service agreement with Repsol Energy Canada (“REC”), which expires in 2034;

· Emera Newfoundland & Labrador Holdings Inc. (“ENL”), focused on two transmission investments related to the development of an 824 megawatt (“MW”) hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador, scheduled to be generating first power in 2019 and full power in 2020. ENL’s two investments are:

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· a 100 per cent investment in NSP Maritime Link Inc. (“NSPML”), which is developing the Maritime Link Project, a $1.56 billion transmission project, including two 170-kilometre sub-sea cables, connecting the island of Newfoundland and Nova Scotia. This project is scheduled to be completed in Q4 2017 and then be in service by January 1, 2018;

· a 62.7 per cent investment (December 31, 2015 – 55.1 per cent) in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a $3.4 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Emera’s percentage ownership in LIL ‎is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined on completion of the LIL and final costing of all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Assets and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 per cent of the cost of all of these transmission developments. The investment in LIL is accounted for on the equity basis. Nalcor Energy has indicated that the project will be in service in Q2 2018.

· a 12.9 per cent interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400-kilometre pipeline, which transports natural gas from offshore Nova Scotia to markets in Atlantic Canada and the northeastern United States.

Emera also owns investments in other energy-related non-regulated companies, including:

· Emera Energy, includes:

· Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services;

· Bridgeport Energy, Tiverton Power and Rumford Power (“New England Gas Generating Facilities” (“NEGG”)), a 1,115 MW of combined-cycle gas-fired electricity generating capacity in the northeastern United States;

· Bayside Power Limited Partnership (“Bayside Power”), a 290 MW gas-fired combined cycle power plant in Saint John, New Brunswick;

· Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia. Brooklyn Energy has a long-term purchase power agreement with NSPI;

· a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 600 MW pumped storage hydroelectric facility in northern Massachusetts.

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

· Emera US Finance LP, a wholly owned financing subsidiary of Emera that issued multiple series of United States dollar denominated senior, unsecured notes for the purpose funding the acquisition of TECO Energy;

· Emera US Holdings Inc. (“EUSHI”), a wholly owned holding company for certain of Emera’s assets located in the United States;

· Emera Utility Services Inc., a utility services contractor primarily operating in Atlantic Canada;

· On December 8, 2016, Emera sold the Company’s remaining 4.7 per cent (December 31, 2015 – 19.6 per cent) investment in Algonquin Power & Utilities Corp. (“APUC”), a public company traded on the Toronto Stock Exchange under the symbol “AQN”;

· and other investments.

### Basis of Presentation

These consolidated financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). In the opinion of management, these consolidated financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera.

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All dollar amounts are presented in Canadian dollars, unless otherwise indicated.

### Principles of Consolidation

The consolidated financial statements of Emera include the accounts of Emera Incorporated, its majority-owned subsidiaries, and a variable interest entity (“VIE”) in which Emera is the primary beneficiary. Emera uses the equity method of accounting to record investments in which the Company has the ability to exercise significant influence, and for variable interest entities in which Emera is not the primary beneficiary. The consolidated financial statements include TECO Energy from the July 1, 2016 acquisition date through December 31, 2016.

Inter-company balances and inter-company transactions have been eliminated on consolidation, except for the net profit on certain transactions between certain non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-regulated operating revenues. An offset is recorded to property, plant and equipment, regulatory assets, regulated fuel for generation and purchased power, or operating, maintenance and general, depending on the nature of the transaction.

### Use of Management Estimates

The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements, and 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, with any adjustments recognized in income in the year they arise. Actual results may differ significantly from these estimates.

Regulatory Matters

Regulatory accounting applies where rates are established by, or subject to approval by, an independent third party regulator. They are designed to recover the costs of providing the regulated products or services; and it is reasonable to assume rates are set at levels such that the costs can be charged to and collected from customers (see note 17 for additional details).

### Foreign Currency Translation

Monetary assets and liabilities, denominated in foreign currencies, are converted to Canadian dollars at the rates of exchange prevailing at the balance sheet date. The resulting differences between the translation at the original transaction date and the balance sheet date are included in income.

Assets and liabilities of self-sustaining foreign operations are translated using the exchange rates in effect at the balance sheet date and the results of operations at the average rates for the period. The resulting exchange gains and losses on the assets and liabilities are deferred on the balance sheet in AOCI.

The Company designates certain United States dollar dominated debt held in Canadian functional currency companies as hedges of net investments in United States dollar denominated foreign operations. The change in the carrying amount of these investments, measured at the exchange rates in effect at the balance sheet date, and the effective portion of the hedge, is recorded in Other Comprehensive Income (“OCI”). Any ineffectiveness is reflected in current period earnings.

### Revenue Recognition

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Operating revenues are recognized when electricity or gas is delivered to customers or when products are delivered and services are rendered. Regulated revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity or gas is recognized at rates approved by the respective regulator and recorded based on meter readings and estimates, which occur on a systematic basis throughout a month. At the end of each month, the electricity or gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The accuracy of the unbilled revenue estimate is affected by energy demand, weather, line losses and changes in the composition of customer classes.

Non-regulated revenues are recorded when products have been delivered or services have been performed, the amount of revenue can be reliably measured and collectability is reasonably assured.

Revenues for energy marketing and trading operations are presented on a net basis, reflecting the nature of the contractual relationships with customers and suppliers.

The Company records the net investment in a lease under the direct finance method for Emera Brunswick Pipeline, which consists of the sum of the minimum lease payments and residual value net of estimated executory costs and unearned income. The difference between the gross investment and the cost of the leased item for a direct financing lease is recorded as unearned income at the inception of the lease. The unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Operating revenues – regulated gas” on the Consolidated Statements of Income.

Other revenues are recognized when services are performed or goods delivered.

### Property, Plant and Equipment

Property, plant and equipment are recorded at original cost, including allowance for funds used during construction (“AFUDC”) or capitalized interest, net of contributions received in aid of construction.

The cost of additions, including betterments and replacements of units of property, plant and equipment are included in “Property, plant and equipment”. When units of regulated property, plant and equipment are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no gain or loss reflected in income. Where a disposition of non-regulated property, plant and equipment occurs, gains and losses are included in income as the dispositions occur.

The cost of property, plant and equipment represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, asset retirement obligations (“ARO”) and overhead attributable to the capital project. Overhead includes corporate costs such as finance, information technology and executive, along with other costs related to support functions, employee benefits, insurance, procurement, and fleet operating and maintenance. Expenditures for project development are capitalized if they are expected to have a future economic benefit.

Normal maintenance projects are expensed as incurred. Planned major maintenance projects that do not increase the overall life of the related assets are expensed. When a major maintenance project increases the life or value of the underlying asset, the cost is capitalized.

Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each functional class of depreciable property. The service lives of regulated assets require the appropriate regulatory approval.

Intangible assets consist primarily of computer software, land rights and naming rights with definite lives. Amortization is determined by the straight-line method, based on the estimated remaining service lives of

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the asset in each category. The service lives of regulated intangible assets require the appropriate regulatory approval.

### Goodwill

Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated fair values of assets acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial cost less any write-down for impairment. Under the applicable accounting guidance, goodwill is subject to an annual assessment for impairment at the reporting unit level. See note 23 for further detail.

### Income Taxes and Investment Tax Credits

Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in the financial statements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference between the carrying value of assets and liabilities on the Consolidated Balance Sheets and their respective tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. Emera recognizes the effect of income tax positions only when it is more likely than not that they will be realized. Management reviews all readily available current and historical information, including forward-looking information, and the likelihood that deferred tax assets will be recovered from future taxable income is assessed and assumptions about the expected timing of the reversal of deferred tax assets and liabilities are made. If management subsequently determines that it is likely that some or all of a deferred income tax asset will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized.

Generally, investment tax credits are recorded as a reduction to income tax expense in the current or future periods to the extent that realization of such benefit is more likely than not. Investment tax credits earned by TECO Energy and Emera Maine on regulated assets are deferred and amortized over the estimated service lives of the related properties, as required by state regulatory practices.

Emera’s rate-regulated subsidiaries recognize regulatory assets or liabilities where the deferred income taxes are expected to be recovered from or returned to customers in future rates, unless specifically directed by a regulator to flow deferred income taxes through earnings.

Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively.

### Derivatives and Hedging Activities

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

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

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The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty creditworthy. Emera continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met.

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

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

Derivatives entered into by Tampa Electric, PGS, NMGC, NSPI and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at fair value on the balance sheet as derivative assets or liabilities. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes that any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates.

Derivatives that do not meet any of the above criteria are designated as HFT derivatives and are recorded on the balance sheet at fair value, with changes normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply.

Emera classifies gains and losses on derivatives as a component of fuel for generation and purchased power, other expenses, inventory and property, plant and equipment, depending on the nature of the item being economically hedged. Transportation capacity arising as a result of marketing and trading transactions is recognized as an asset in “Other” and amortized over the period of the transportation contract term. Cash flows from derivative activities are presented in the same category as the item being hedged within operating or investing activities on the Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on the Consolidated Statements of Cash Flows.

Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the fair value amounts of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables, net” and obligations to return cash collateral are recognized in “Accounts payable”.

### Cash and Cash Equivalents

Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition. Total short-term investments of $183 million have an effective interest rate of 0.6 per cent at December 31, 2016 (2015 – $78 million with an effective interest rate of 0.6 per cent).

### Receivables and Allowance for Doubtful Accounts

Customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date.

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The Company is exposed to credit risk with respect to amounts receivable from customers. Credit risk assessments are conducted on all new customers and deposits are requested on any high risk accounts. The Company also maintains provisions for potential credit losses, which are assessed on a regular basis.

Management estimates uncollectible accounts receivable after considering historical loss experience, customer deposits, current events and the characteristics of existing accounts. Provisions for losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible.

### Inventory

Fuel and materials inventories are valued using the weighted-average cost method. These inventories are carried at the lower of weighted-average cost or net realizable value, unless evidence indicates that the weighted-average cost will be recovered in future customer rates.

Emission credits inventory are measured using the first-in-first-out method. Emission credits inventory is recognized in inventory when purchased, or allocated by the respective government agency.

### Asset Impairment

Goodwill

Goodwill is not amortized, but is subject to an annual impairment test. Emera’s reporting units containing goodwill assess qualitative factors to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount during the fourth quarter of each year, and interim impairment tests are performed when impairment indicators are present. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount, the Company calculates the fair value of the reporting unit. The carrying amount of the reporting unit’s goodwill is considered not recoverable if the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value. See note 23 for further detail.

Cost and Equity Method Investments

The carrying value of investments accounted for under the cost and equity methods are assessed for impairment by comparing the fair values of these investments to their carrying values, if a fair value assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists and it is determined to be other-than-temporary, a charge is recognized in earnings equal to the amount the carrying value exceeds the investment’s fair value.

Financial Assets

The Company assesses at each balance sheet date whether there is objective evidence that a financial asset or a group of financial assets is impaired. In the case of equity securities classified as available-for-sale, an other than temporary decline in the fair value of the security below its cost is considered as an indicator that the securities are impaired. In the case of debt securities classified as available-for-sale, a breach of contract, such as default or delinquency in interest or principal payments, or evidence of significant financial difficulty of the issuer is considered an indicator of impairment. If any such evidence exists for available-for-sale financial assets, the cumulative loss, measured as the difference between the acquisition cost and the current fair value, less any impairment loss on that financial asset previously recognized in income, is removed from AOCI and recognized in the Consolidated Statements of Income.

### Asset Retirement Obligation s

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An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel.

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

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

### Variable Interest Entities

The Company performs ongoing analysis to assess whether it holds any VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly owned facilities.

VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses or the right to receive benefits of the entity that could potentially be significant to the entity. In circumstances where Emera is not deemed the primary beneficiary, the VIE is not consolidated in the Company’s consolidated financial statements.

### Franchise Fees and Gross Receipts

Tampa Electric and PGS are allowed to recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state and municipal taxes”.

NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the Consolidated Statement of Income.

### Stock-Based Compensation

The Company has several stock-based compensation plans: a common share option plan for senior management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; and a performance share unit (“PSU”) plan. The Company accounts for its plans in accordance with the fair value based method of accounting for stock-based compensation. Stock-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period using the graded vesting method.

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Stock-based compensation plans recognized as liabilities are measured at fair value and re-measured at fair value at each reporting date with the change in liability recognized in income.

### Employee Benefits

The costs of the Company’s pension and other post-retirement benefit programs for employees are expensed over the periods during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes changes in funded status in the year the change occurs. The Company recognizes the unamortized gains and losses and past service costs in AOCI or regulatory assets.

2. C HANGE IN ACCOUNTING POLICY

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

Consolidation

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

Interest – Imputation of Interest

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

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

Compensation – Retirement Benefits

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

Intangibles – Goodwill and Other – Internal-Use Software

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

Inventory – Simplifying the Measurement of Inventory

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

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

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

Investments – Equity Method and Joint Ventures

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

Compensation – Stock Compensation

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

3. FUTURE ACCOUNTING PRONOUNCEMENTS

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

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new, principle-based revenue recognition framework, which has been codified as ASC Topic 606. The FASB issued amendments to ASC Topic 606 during 2016 to clarify certain implementation guidance and to reflect narrow scope improvements and practical expedients. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled to. The guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue and related cash flows arising from contracts with customers. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and will allow for either full retrospective adoption or modified retrospective adoption. The Company will adopt this guidance effective January 1, 2018. The Company has implemented a project plan and is in the process of evaluating the impact of adoption of this standard on its consolidated financial statements and disclosures. This includes evaluating the available adoption methods, accounting for contributions in aid of construction and contract acquisition costs, the impact of collectability risk, unique contract characteristics in the Company’s non-regulated businesses and disclosure requirements. The Company is also monitoring the assessment of ASC Topic 606 by the AICPA Power and Utilities Revenue Recognition Task Force. The ultimate impact of the adoption of ASC Topic 606, and the method of adoption, has not yet been finalized.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. The standard provides guidance for the recognition,

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measurement, presentation and disclosure of financial assets and liabilities. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The Company is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Leases

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

Measurement of Credit Losses on Financial Instruments

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

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

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

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

Restricted Cash on the Statement of Cash Flows

In November 2016, the FASB issued ASU 2016-18, Restricted Cash on the Statement of Cash Flows. The standard will require the Company to show the changes in total cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. Transfers between cash and cash equivalents and restricted cash and restricted cash equivalents will no longer be presented in the statement of cash flows. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017, with early adoption permitted, and is required to be applied on a retrospective approach. The Company is currently evaluating the impact of adoption of this standard on its consolidated statement of cash flows.

Clarifying the Definition of a Business

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

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those periods, beginning after December 15, 2017, with early adoption permitted and is required to be applied prospectively.

Simplifying the Test for Goodwill Impairment

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

4. ACQUISITION

TECO ENERGY INC.

On July 1, 2016, Emera acquired all of the outstanding common shares of TECO Energy for $ 27.55 USD per common share. The net cash purchase price totaled $8.4 billion ($ 6.5 billion USD), with an aggregate purchase price of $13.9 billion ($ 10.7 billion USD), including the assumption of $5.5 billion ($ 4.2 billion USD) in US debt on closing. The net cash purchase price was financed through: (i) $728 million ($560 million USD) related to the first instalment of convertible debentures represented by instalment receipts issued in 2015, $ 1.56 billion ($1.2 billion USD) fixed-to-floating subordinated notes, $ 500 million ($384 million USD) in Canadian long-term debt and $ 4.2 billion ($3.25 billion USD) in US long-term senior unsecured notes; (ii) available cash on hand; and (iii) drawings of $1.4 billion ($1.1 billion USD) on the Company’s acquisition credit facility. Total proceeds of the debt, that were not otherwise required to complete the acquisition, have been used for general corporate purposes.

On August 2, 2016, the convertible debenture Final Instalment Date, Emera received the remaining two thirds of the convertible debenture instalments (note 10), for net proceeds of $1.4 billion. These funds were used to repay the Company’s acquisition credit facility.

TECO Energy is an energy-related holding company with regulated electric and gas utilities in Florida and New Mexico. TECO Energy’s holdings include Tampa Electric, an integrated regulated electric utility in West Central Florida, PGS, a regulated gas distribution utility serving customers across Florida, and NMGC, a regulated gas distribution utility in New Mexico.

The majority of TECO Energy’s operations are subject to the rate-setting authority of the Federal Energy Regulatory Commission (“FERC”), Florida Public Service Commission (“FPSC”), and New Mexico Public Regulation Commission (“NMPRC”), and are accounted for pursuant to USGAAP, including the accounting guidance for regulated operations. Except for unregulated long-term debt acquired and deferred taxes, preliminary fair values of tangible and intangible assets and liabilities subject to these rate-setting provisions approximate their carrying values due to the fact that a market participant would not expect to recover any more or less than their net carrying value. Accordingly, assets acquired and liabilities assumed and pro-forma financial information do not reflect any adjustments related to these amounts.

The Acquisition is accounted for in accordance with the acquisition method of accounting. The excess of purchase price over estimated fair values of assets acquired and liabilities assumed has been recognized as goodwill at the acquisition date of July 1, 2016. The goodwill reflects the value paid for access to regulated assets, net income and cash flows in growth markets, opportunities for adjacency growth, long-term potential for enhanced access to capital as a result of increased scale and business diversity, and an improved earnings risk profile. The goodwill recognized as part of this transaction is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to this goodwill.

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The following table summarizes the preliminary allocation of the purchase consideration to the assets and liabilities acquired as at July 1, 2016 based on their fair values, using the July 1, 2016 exchange rate of $1.00 USD = $1.3009 CAD. The allocation of the preliminary purchase consideration is considered preliminary due to the continued evaluation and analysis of deferred income taxes and the allocation of goodwill between reporting units.

millions of Canadian dollars
Purchase Consideration | $ | 8,447
Fair value assigned to net assets: |  |
Current assets (1) | $ | 619
Regulatory assets (including current portion) |  | 624
Property, plant and equipment, net |  | 10,023
Other long-term assets |  | 71
Current liabilities |  | (747)
Assumed long-term debt (including current portion) |  | (5,409)
Regulatory liabilities (including current portion) |  | (1,117)
Deferred income taxes |  | (800)
Pension and post-retirement liabilities (including current portion) |  | (480)
Other long-term liabilities |  | (146)
| $ | 2,638
Cash and cash equivalents |  | 38
Fair value of net assets acquired | $ | 2,676
Goodwill | $ | 5,771
(1) Includes accounts receivables with fair value of $334 million comprised of gross contract value of $337 million, and $3 million of contractual receivables not expected to be collected.

Goodwill has been preliminarily allocated to the TECO Energy reporting units and is subject to change as additional information is obtained through the purchase price allocation process.
millions of Canadian dollars |  |  |  |
Reporting Unit |  | Goodwill
Tampa Electric |  |  | $ | 4,552
PGS |  |  |  | 744
New Mexico Gas |  |  |  | 475
Goodwill |  |  | $ | 5,771

Goodwill is subject to an annual assessment for impairment at the reporting unit level. Adverse changes in assumptions could result in a material impairment of Emera’s goodwill (note 23).

Acquisition Related Expenses

Acquisition related expenses totaled $ 250 million ($166 million after-tax) and $76 million ($53 million after-tax) for the twelve months ended December 31, 2016 and 2015, respectively. These costs have been recognized in the Consolidated Statements of Income as follows:

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

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

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

Supplemental Pro Forma Data

The unaudited pro forma financial information below gives effect to the acquisition of TECO Energy as if the transaction had occurred at the beginning of 2015. This pro forma data is presented for information purposes only, and does not purport to be indicative of the results that would have occurred had the acquisition taken place at the beginning of 2015, nor is it indicative of the results that may be expected in future periods.

Pro forma net income attributable to common shareholders excludes all non-recurring acquisition-related expenses incurred by TECO Energy and Emera and includes adjustments for pro forma financing costs associated with the acquisition. In addition, net income from TECO Coal, a discontinued operation sold by TECO Energy in 2015 is excluded. After-tax adjustments increased pro forma net income attributable to common shareholders by $53 million for the twelve months ended December 31, 2016. The twelve months ended December 31, 2015 after-tax adjustments were a decrease of $ 35 million.

Adjustments to pro forma operating revenues resulted in an increase of $ 10 million for the year ended December 31, 2016, with no adjustment for 2015.

For the |  | Year ended
millions of Canadian dollars | December 31
|  | 2016 |  | 2015
Pro forma operating revenues | $ | 6,034 | $ | 6,297
Pro forma net income attributable to common shareholders | $ | 386 | $ | 584

5. SEGMENT INFORMATION

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Emera manages its reportable segments separately due in part to their different geographical, operating and regulatory environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets as reported to the Company’s chief operating decision maker.

As at December 31, 2016, Emera has six reportable segments, specifically:

· Emera Florida and New Mexico (includes TEC, consisting of two divisions: Tampa Electric and PGS, NMGC, their parent company TECO Energy, and TECO Finance, a wholly owned financing subsidiary of TECO Energy);

· NSPI;

· Emera Maine;

· Emera Caribbean (ECI and its subsidiaries including BLPC, Domlec, GBPC, and an equity investment in Lucelec);

· Emera Energy (Emera Energy Services, NEGG Facilities, Bayside Power, Brooklyn Energy and an equity investment in Bear Swamp); and

· Corporate and Other (Emera Utility Services, ENL, Emera Brunswick Pipeline, Corporate, other strategic investments and holding companies).

| Emera Florida |  |  |  |  |  |  | Corporate | Inter- |  |
| and New |  |  | Emera | Emera | Emera | and |  | segment |  |
millions of Canadian dollars | Mexico (2) | NSPI | Maine | Caribbean | Energy | Other | Eliminations | Total
For the year ended December 31, 2016
Operating revenues from external customers (1) | $ | 1,839 | $ | 1,356 | $ | 297 | $ | 419 | $ | 298 | $ | 69 | $ | (2) | $ | 4,276
Inter-segment revenues (1) |  | - |  | - |  | - |  | - |  | 11 |  | 24 |  | (34) |  | 1
Total operating revenues |  | 1,839 |  | 1,356 |  | 297 |  | 419 |  | 309 |  | 93 |  | (36) |  | 4,277
Allowance for funds used during construction - debt and equity |  | 28 |  | 6 |  | 1 |  | - |  | - |  | - |  | - |  | 35
Regulated fuel and fixed cost deferral adjustments |  | - |  | 61 |  | - |  | - |  | - |  | - |  | - |  | 61
Depreciation and amortization |  | 243 |  | 197 |  | 51 |  | 48 |  | 45 |  | 4 |  | - |  | 588
Interest expense (3) |  | 125 |  | 127 |  | 19 |  | 15 |  | 2 |  | 312 |  | - |  | 600
Interest revenue |  | - |  | - |  | - |  | - |  | 1 |  | 1 |  | - |  | 2
Internally allocated interest (4) |  | - |  | - |  | - |  | - |  | (24) |  | 24 |  | - |  | -
Income from equity investments |  | - |  | - |  | - |  | 3 |  | 11 |  | 86 |  | - |  | 100
Income tax expense (recovery) |  | 100 |  | 12 |  | 23 |  | 14 |  | (53) |  | (118) |  | - |  | (22)
Net income attributable to common shareholders |  | 172 |  | 130 |  | 47 |  | 100 |  | (110) |  | (112) |  | - |  | 227
Capital expenditures |  | 547 |  | 304 |  | 85 |  | 87 |  | 39 |  | 7 |  | - |  | 1,069
As at December 31, 2016 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total assets |  | 18,016 |  | 4,776 |  | 1,543 |  | 1,331 |  | 1,702 |  | 1,966 |  | (113) |  | 29,221
Investments subject to significant influence |  | - |  | - |  | 13 |  | 39 |  | - |  | 895 |  | - |  | 947
Goodwill |  | 5,957 |  | - |  | 154 |  | 102 |  | - |  | - |  | - |  | 6,213
(1) All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes that the elimination of these transactions would understate property, plant and equipment, operating, maintenance and general expenses, or regulated fuel for generation and purchased power. Inter-company transactions which have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments.
(2) Financial results of Emera Florida and New Mexico are from July 1, 2016, the date of the acquisition.
(3) Corporate and Other Interest expense has been reduced by amortization of $13 million related to the unregulated long-term debt fair market value adjustment recognized on the acquisition of TECO Energy.
(4) Segment net income is reported on a basis that includes internally allocated financing costs.

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| Emera Florida |  |  |  |  |  |  | Corporate | Inter- |  |
| and New |  |  | Emera | Emera | Emera | and |  | segment |  |
millions of Canadian dollars | Mexico (2) | NSPI | Maine | Caribbean | Energy | Other | Eliminations | Total
For the year ended December 31, 2015
Operating revenues from external customers (1) | $ | - | $ | 1,417 | $ | 284 | $ | 442 | $ | 578 | $ | 68 | $ | (2) | $ | 2,787
Inter-segment revenues (1) |  | - |  | - |  | - |  | 8 |  | 12 |  | 24 |  | (42) |  | 2
Total operating revenues |  | - |  | 1,417 |  | 284 |  | 450 |  | 590 |  | 92 |  | (44) |  | 2,789
Allowance for funds used during construction - debt and equity |  | - |  | 4 |  | 2 |  | - |  | - |  | - |  | - |  | 6
Regulated fuel and fixed cost deferral adjustments |  | - |  | 42 |  | - |  | - |  | - |  | - |  | - |  | 42
Depreciation and amortization |  | - |  | 206 |  | 47 |  | 44 |  | 41 |  | 2 |  | - |  | 340
Interest expense |  | - |  | 129 |  | 19 |  | 14 |  | 1 |  | 59 |  | - |  | 222
Interest revenue |  | - |  | 5 |  | - |  | - |  | 1 |  | - |  | - |  | 6
Internally allocated interest (3) |  | - |  | - |  | - |  | - |  | (18) |  | 18 |  | - |  | -
Income from equity investments |  | - |  | - |  | - |  | 3 |  | 21 |  | 84 |  | - |  | 108
Income tax expense (recovery) |  | - |  | 23 |  | 27 |  | 3 |  | 50 |  | (10) |  | - |  | 93
Net income attributable to common shareholders |  | - |  | 130 |  | 45 |  | 41 |  | 99 |  | 82 |  | - |  | 397
Capital expenditures |  | - |  | 271 |  | 65 |  | 44 |  | 98 |  | 9 |  | - |  | 487
As at December 31, 2015 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total assets |  | - |  | 4,721 |  | 1,558 |  | 1,403 |  | 1,919 |  | 2,663 |  | (225) |  | 12,039
Investments subject to significant influence |  | - |  | - |  | 12 |  | 39 |  | - |  | 1,094 |  | - |  | 1,145
Goodwill |  | - |  | - |  | 158 |  | 106 |  | - |  | - |  | - |  | 264
(1) All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes that the elimination of these transactions would understate property, plant and equipment, operating, maintenance and general expenses, or regulated fuel for generation and purchased power. Inter-company transactions which have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments.
(2) Financial results of Emera Florida and New Mexico are from July 1, 2016, the date of the acquisition.
(3) Segment net income is reported on a basis that includes internally allocated financing costs.

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Geographical Information
Revenues(1):
For the | Year ended December 31
millions of Canadian dollars |  | 2016 |  | 2015
Canada | $ | 1,510 | $ | 1,546
United States |  | 2,348 |  | 786
Barbados |  | 254 |  | 259
The Bahamas |  | 121 |  | 154
Dominica |  | 44 |  | 44
| $ | 4,277 | $ | 2,789
(1) Revenues are based on country of origin of the product or service sold |  |  |  |
Property Plant and Equipment:
As at | December 31 | December 31
millions of Canadian dollars | 2016 | 2015
Canada | $ | 3,791 | $ | 3,672
United States |  | 12,724 |  | 2,034
Barbados |  | 416 |  | 402
The Bahamas |  | 295 |  | 299
Dominica |  | 64 |  | 62
| $ | 17,290 | $ | 6,469

6. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME

134

Investments subject to significant influence consisted of the following:
|  |  |  |  | Equity Income | Percentage
| Carrying Value | For the year ended | of
millions of Canadian dollars | As at December 31 | December 31 | Ownership
|  | 2016 |  | 2015 |  | 2016 |  | 2015 | 2016
LIL (1) | $ | 400 | $ | 208 | $ | 24 | $ | 9 | 62.7
NSPML |  | 315 |  | 188 |  | 21 |  | 15 | 100.0
M&NP (2) |  | 175 |  | 189 |  | 23 |  | 23 | 12.9
Lucelec (2) |  | 39 |  | 39 |  | 3 |  | 3 | 19.1
APUC (3) |  | - |  | 504 |  | 18 |  | 37 | -
Bear Swamp (4) |  | - |  | - |  | 11 |  | 17 | 50.0
Other Investments |  | 18 |  | 17 |  | - |  | 4 |
| $ | 947 | $ | 1,145 | $ | 100 | $ | 108 |
(1) Emera indirectly owns 100 per cent of the Class B units, which comprises 24.9 per cent of the total units issued.
(2) Although Emera’s ownership percentage of these entities is relatively low, it is considered to have significant influence over the operating and financial decisions of these companies through Board representation. Therefore, Emera records its investment in these entities using the equity method. This is consistent with industry practice for similar investments with significant influence.
(3) On May 24, 2016, Emera completed the sale of 50.1 million common shares or 19.3 per cent of APUC's issued and outstanding common shares. This resulted in a pre-tax gain of $172 million (after-tax gain of $146 million), which was recorded in "Other income (expenses), net" in Q2 2016. On June 30, 2016, Emera exchanged 12.9 million of APUC subscription receipts and dividend equivalents into common shares. This resulted in a pre-tax gain of $63 million (after-tax gain of $53 million), which was recorded in "Other income (expenses), net" in Q2 2016. As a result of these transactions, Emera reclassified its investment in APUC from "Investments Subject to Significant Influence" to "Investment Securities" on the Consolidated Balance Sheets in Q2 2016, recorded at fair value. On December 8, 2016, Emera completed the sale of 12.9 million common shares or 4.7 per cent of APUC's issued and outstanding common shares. This sale resulted in a pre-tax loss of $12 million (after-tax loss of $10 million), which was recorded in "Other income (expenses), net" in Q4 2016. Emera no longer holds any interest in APUC.
(4) The investment balance in Bear Swamp is in a credit position primarily a result of a $179 million distribution received in Q4 2015. Bear Swamp's credit investment balance of $217 million (2015 - $225 million) is recorded in "Other long-term liabilities" on the Consolidated Balance Sheets.
Equity investments include a $14 million difference between the cost and the underlying fair value of the investees' assets as at the date of acquisition. The excess is attributable to goodwill.

Emera accounts for its variable interest investment in NSPML as an equity investment (note 33). NSPML's consolidated summarized balance sheets are illustrated as follows:
As at | December 31
millions of Canadian dollars | 2016 | 2015
Balance Sheets |  |  |  |
Current assets | $ | 439 | $ | 439
Property, plant and equipment |  | 1,132 |  | 648
Non-current assets |  | 276 |  | 554
Total assets | $ | 1,847 | $ | 1,641
Current liabilities | $ | 219 | $ | 130
Long-term debt |  | 1,288 |  | 1,288
Non-current liabilities |  | 25 |  | 35
Equity |  | 315 |  | 188
Total liabilities and equity | $ | 1,847 | $ | 1,641

7. OTHER INCOME (EXPENSES), NET

135

Other income (expenses), net consisted of the following: |  |  |  |
For the | Year ended December 31
millions of Canadian dollars |  | 2016 |  | 2015
Gain on sale of APUC common shares (note 6) | $ | 160 | $ | -
Gain on conversion of APUC subscription receipts and dividend equivalents to common shares of APUC (note 6) |  | 63 |  | -
Gain on BLPC Self-Insurance Fund ("SIF") regulatory liability (1) |  | 53 |  | -
Allowance for equity funds used during construction |  | 22 |  | 2
Foreign exchange (losses) gains and mark-to-market adjustments related to the TECO Energy acquisition (2) |  | (135) |  | 119
Gain on sale of NWP investment (3) |  | - |  | 19
Other |  | 11 |  | 1
| $ | 174 | $ | 141
(1) In June 2016, BLPC secured support from the Government of Barbados and the Trustees of the SIF to reduce the contingency funding in the SIF to $22 million USD. As a result, Emera reduced the SIF regulatory liability to $30 million ($22 million USD) and recorded a pre-tax gain of $53 million (after-tax gain of $43 million).
(2) Mark-to-market adjustments included in Emera’s other income related to the effect of TECO Energy convertible debenture related USD-denominated currency and forward contracts. These contracts were put in place to economically hedge the anticipated proceeds from the 2015 sale of $2.185 billion 4 per cent convertible unsecured subordinated debentures represented by instalment receipts (“the Debenture Offering” or “Debentures” or “Convertible Debentures”) for the TECO Energy acquisition.
(3) On January 25, 2015, Emera completed the sale of its 49 per cent interest in NWP. This resulted in a pre-tax gain of $19 million (after-tax gain of $12 million).

8. INTEREST EXPENSE, NET

Interest expense, net consisted of the following:
For the | Year ended December 31
millions of Canadian dollars |  | 2016 |  | 2015
Interest on debt | $ | 443 | $ | 193
Beneficial conversion feature (note 10) |  | 62 |  | -
Interest on Convertible Debentures (note 10) |  | 65 |  | 23
Interest on acquisition credit facility related to the TECO Energy acquisition (note 4) |  | 11 |  | -
Allowance for borrowed funds used during construction |  | (13) |  | (4)
Interest revenue |  | (2) |  | (6)
Other |  | 19 |  | 6
| $ | 585 | $ | 212

9. INCOME TAXES

136

The income tax provision, for the years ended December 31, differs from that computed using the statutory income tax rate for the following reasons:
millions of Canadian dollars | 2016 | 2015
Income before provision for income taxes | $ | 244 | $ | 545
Statutory income tax rate |  | 31% |  | 31%
Income taxes, at statutory income tax rates |  | 76 |  | 169
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities |  | (47) |  | (31)
Non-taxable portion of gains on APUC transactions |  | (34) |  | -
Non-deductible (non-taxable) portion of foreign exchange and mark-to-market adjustments related to the TECO Energy acquisition |  | 21 |  | (18)
Financing deductions |  | (17) |  | (10)
Tax effect of equity earnings |  | (10) |  | (11)
Manufacturing and investment allowances |  | (7) |  | (5)
Foreign tax rate variance |  | (5) |  | 2
Other |  | 1 |  | (3)
Income tax expense (recovery) | $ | (22) | $ | 93
Effective income tax rate |  | (9%) |  | 17%

The statutory income tax rate of 31 per cent represents the combined Canadian federal and Nova Scotia and New Brunswick provincial corporate income tax rates, which are the relevant tax jurisdictions for Emera.

The following reflects the composition of taxes on income from continuing operations presented in the Consolidated Statements of Income for the years ended December 31:

millions of Canadian dollars | 2016 | 2015
Current income taxes |  |  |  |
Canada | $ | 13 | $ | 42
United States |  | 18 |  | 26
Other |  | 15 |  | 5
Deferred income taxes |  |  |  |
Canada | $ | (113) | $ | 11
United States |  | 151 |  | 14
Other |  | - |  | (1)
Operating loss carry forwards |  |  |  |
Canada |  | (2) |  | (4)
United States |  | (104) |  | -
Income tax expense (recovery) | $ | (22) | $ | 93
The following reflects the composition of income before provision for income taxes presented in the Consolidated Statements of Income for the years ended December 31:
millions of Canadian dollars | 2016 | 2015
Canada | $ | 71 | $ | 349
United States |  | 44 |  | 137
Other |  | 129 |  | 59
Income before provision for income taxes | $ | 244 | $ | 545

137

The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at December 31 consisted of the following:
millions of Canadian dollars | 2016 | 2015
Deferred income tax assets: |  |  |  |
Tax loss carry forwards | $ | 1,036 | $ | 72
Regulatory liabilities - cost of removal |  | 388 |  | 42
Tax credit carry forwards |  | 318 |  | 7
Derivative instruments |  | 173 |  | 204
Pension and post-retirement liabilities |  | 147 |  | 129
Regulatory liabilities – deferrals related to derivative instruments |  | 101 |  | 94
Asset retirement obligations |  | 47 |  | 47
Other |  | 355 |  | 136
Total deferred income tax assets before valuation allowance |  | 2,565 |  | 731
Valuation allowance |  | (58) |  | (18)
Total deferred income tax assets after valuation allowance | $ | 2,507 | $ | 713
Deferred income tax (liabilities): |  |  |  |
Property, plant and equipment | $ | (3,625) | $ | (960)
Derivative instruments |  | (202) |  | (264)
Net investment in direct financing lease |  | (103) |  | (89)
Other |  | (124) |  | (130)
Total deferred income tax liabilities | $ | (4,054) | $ | (1,443)
Consolidated Balance Sheets presentation: |  |  |  |
Long-term deferred income tax assets |  | 125 |  | 32
Long-term deferred income tax liabilities |  | (1,672) |  | (762)
Net deferred income tax liabilities | $ | (1,547) | $ | (730)

For regulated entities, to the extent deferred income taxes are expected to be recovered from or returned to customers in future rates, a regulatory asset or liability is recognized, unless specifically directed otherwise by a regulator. These amounts include a gross up to reflect the income tax associated with future revenues required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced revenues resulting from the realization of deferred income tax assets.

Emera’s gross net operating loss (“NOL”) carry forwards, capital loss carry forwards and tax credit carry forwards as at December 31, consisted of the following:

millions of Canadian dollars | 2016 | 2015
Canada |  |  |  |
NOL | $ | 199 | $ | 103
Capital loss |  | 77 |  | 84
United States |  |  |  |
Federal NOL | $ | 2,595 | $ | 48
State NOL |  | 1,183 |  | 225
Capital loss |  | 14 |  | 4
Tax credit |  | 318 |  | 30
Other |  |  |  |
NOL | $ | 22 | $ | 14

138

The following table summarizes as at December 31, 2016 the deferred tax assets associated with NOL, capital loss and tax credit carry forwards and the associated expiration periods, and the valuation allowances for amounts which Emera has determined that realization is uncertain:
| Deferred Tax | Valuation | Net Deferred | Expiration
millions of Canadian dollars | Asset | Allowance | Tax Asset | Period
Canada |  |  |  |  |  |  |
NOL | $ | 61 | $ | (27) | $ | 34 | 2026-2036
Capital loss |  | 16 |  | (16) |  | - | Indefinite
United States |  |  |  |  |  |  |
Federal NOL | $ | 908 | $ | - | $ | 908 | 2024-2036
State NOL |  | 45 |  | (1) |  | 44 | 2017-2036
Capital loss |  | 3 |  | (3) |  | - | 2018-2019
Tax credit |  | 318 |  | - |  | 318 | 2019-2036
Other |  |  |  |  |  |  |
NOL | $ | 3 | $ | (3) | $ | - | 2017-2023

Considering all evidence regarding the utilization of the Company’s deferred income tax assets, it has been determined that Emera is more likely than not to realize all recorded deferred income tax assets, except for the loss carry forwards noted above and unrealized capital losses on certain investments. A valuation allowance of $58 million has been recorded as at December 31, 2016 (2015 - $ 18 million) related to the loss carry forwards and investments.

The following table provides details of the change in unrecognized tax benefits for the years ended December 31 as follows:

millions of Canadian dollars | 2016 | 2015
Balance, January 1 | $ | 6 | $ | 5
Increases due to tax positions related to current year |  | 12 |  | -
Increases due to tax positions related to a prior year |  | - |  | 1
Balance, December 31 | $ | 18 | $ | 6

The total amount of unrecognized tax benefits as at December 31, 2016 was $18 million (2015 - $6 million), which would affect the effective tax rate if recognized. The total amount of accrued interest with respect to unrecognized tax benefits was $1 million (2015 - $1 million). No penalties have been accrued. The balance of unrecognized tax benefits could change in the next twelve months as a result of resolving Canada Revenue Agency (“CRA”) and Internal Revenue Service audits. A reasonable estimate of any change cannot be made at this time.

The Company intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, US and non-US income and withholding taxes for which deferred taxes might otherwise be required have not been provided for on a cumulative amount of temporary differences related to investments in foreign subsidiaries of approximately $667 million as at December 31, 2016 (2015 - $ 669 million). It is impractical to estimate the amount of income and withholding tax that might be payable if a reversal of temporary differences occurred.

Emera files a Canadian federal income tax return, which includes its Nova Scotia and New Brunswick provincial income tax. Emera’s subsidiaries file Canadian, US, Barbados, St. Lucia and Dominica income tax returns. As at December 31, 2016, the Company’s tax years still open to examination by taxing authorities include 2005 and subsequent years.

NSPI and the CRA are currently in a dispute with respect to the timing of certain tax deductions for NSPI’s 2006 through 2010 taxation years. The ultimate permissibility of the tax deductions is not in dispute; rather, it is the timing of those deductions. The cumulative net amount in dispute to date is $62 million, including interest. NSPI has prepaid $23 million of the amount in dispute, as required by CRA.

139

Should NSPI be successful in defending its position, all payments including applicable interest will be refunded. If NSPI is unsuccessful in defending any portion of its position, the resulting taxes and applicable interest will be deducted from amounts previously paid, with the excess, if any, owing to CRA. The related tax deductions will be available in subsequent years. Should NSPI receive similar notices of reassessment for the years not currently in dispute, further payments will be required; however, the ultimate permissibility of these deductions would be similarly not in dispute.

NSPI and its advisors believe that NSPI has reported its tax position appropriately and NSPI is disputing the reassessments through the CRA Appeal process. NSPI continues to assess its options to resolving the dispute however the outcome of the Appeal process is not determinable at this time.

10. COMMON STOCK

Authorized: Unlimited number of non-par value common shares. |  |  |  |  |  |
| 2016 |  | 2015
Issued and outstanding: | millions of shares | millions of Canadian dollars |  | millions of shares | millions of Canadian dollars
Balance, January 1 | 147.21 | $ | 2,157 |  | 143.78 | $ | 2,016
Conversion of Convertible Debentures | 51.99 |  | 2,115 |  | - |  | -
Issuance of common stock (1) | 7.69 |  | 338 |  | 1.25 |  | 54
Issued for cash under Purchase Plans at market rate | 2.51 |  | 115 |  | 2.10 |  | 88
Discount on shares purchased under Dividend Reinvestment Plan | - |  | (5) |  | - |  | (4)
Options exercised under senior management share option plan | 0.62 |  | 17 |  | 0.08 |  | 2
Stock-based compensation | - |  | 1 |  | - |  | 1
Balance, December 31 | 210.02 | $ | 4,738 |  | 147.21 | $ | 2,157
(1) In Q1 2016, Emera issued 0.06 million common shares to facilitate the creation and issuance of 0.2 million depositary receipts in connection with the ECI amalgamation transaction. The depositary receipts are listed on the Barbados Stock Exchange. In addition, Emera completed an offering of 7.63 million common shares in December 2016, at $45.25 per common share, for net proceeds of approximately $345 million. The net proceeds were $335 million after $10 million of issuance costs, net of taxes.

As at December 31, 2016, there were the following common shares reserved for issuance: 6.6 million (2015 – 7.3 million) under the senior management stock option plan, 1.5 million (2015 – 1.6 million) under the employee common share purchase plan and 7.9 million (2015 – 3.3 million) under the dividend reinvestment plan.

The issuance of common shares under the current or proposed common share compensation arrangements will not exceed 10 per cent of Emera's outstanding common shares. As at December 31, 2016, Emera is in compliance with this requirement.

Convertible Debentures

On September 28, 2015, to finance a portion of the acquisition of TECO Energy, Emera, through a direct wholly owned subsidiary (the “Selling Debentureholder”) completed the sale of $1.9 billion aggregate principal amount of 4.0 per cent convertible unsecured subordinated debentures, represented by instalment receipts. On October 2, 2015, in connection with the Debenture Offering, the underwriters fully exercised an over-allotment option and purchased an additional $285 million aggregate principal amount of Debentures at the Debenture Offering price. The sale of the additional Debentures brought the aggregate proceeds of the Debenture Offering to $2.185 billion.

The Debentures were sold on an instalment basis at a price of $1,000 per Debenture, of which

$333 (the “First Instalment”) was paid on closing of the Debenture Offerings on September 28, 2015 and

October 2, 2015, and the remaining $667 (the “Final Instalment”) was payable on August 2, 2016 (the “Final Instalment Date”). Prior to the Final Instalment Date, the Debentures were represented by

140

instalment receipts. The instalment receipts traded on the Toronto Stock Exchange (“TSX”) from September 28, 2015 to August 2, 2016 under the symbol “EMA.IR”. The Debentures will mature on September 29, 2025 and, as of the Final Instalment Date, bear interest at 0 per cent.

The proceeds of the first instalment and the over-allotment of the Debentures were $727.6 million ($681.4 million net of issue costs). The proceeds of the final instalment payment were $1.457 billion ($1.413 billion net of issue costs).

Final Instalment Notice was issued by Emera on June 29, 2016 with a payable date of August 2, 2016. At the option of the holders, each fully paid Debenture was convertible into common shares of Emera at any time after the Final Instalment Date, but prior to the earlier of maturity or redemption by the Company, at a conversion price of $41.85 per common share. This was a conversion rate of 23.8949 common shares per $1,000 principal amount of Debentures.

As the Final Instalment Date occurred prior to the first anniversary of the closing of the Debenture Offering, holders of the convertible debentures who paid the final instalment by August 2, 2016 received, in addition to the payment of accrued and unpaid interest, a make-whole payment. This represented the interest that would have accrued from the day following the Final Instalment Date up to and including

September 28, 2016. Recorded in the year ended December 31, 2016 is $65 million ($45 million after-tax) of interest expense related to the Convertible Debentures including the $21 million ($14 million after-tax) make-whole payment in Q2 2016 (note 8).

As at December 31, 2016, a total of 51.99 million common shares of the Company were issued, representing conversion into common shares of more than 99.6 per cent of the Convertible Debentures. After the Final Instalment Date of August 2, 2016, debentures not converted may be redeemed by Emera at a price equal to their principal amount. At maturity, Emera has the right to pay the principal amount due in common shares to the debenture holders that have not converted, which will be valued at 95 per cent of the weighted average trading price on the TSX for the 20 consecutive trading days ending five trading days preceding the maturity date.

11. EARNINGS PER SHARE

Basic earnings per share (“EPS”) is determined by dividing net income attributable to common shareholders by the weighted average number of common shares and DSUs outstanding during the period. Diluted EPS is computed by dividing net income attributable to common shareholders by the weighted average number of common shares and DSUs outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include Company contributions to the senior management stock option plan, convertible debentures and shares issued under the dividend reinvestment plan.

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The following table reconciles the computation of basic and diluted earnings per share:
For the |  | Year ended December 31
millions of Canadian dollars (except per share amounts) |  | 2016 |  | 2015
Numerator |  |  |  |
Net income attributable to common shareholders | $ | 227.2 | $ | 397.2
Convertible Debentures |  | 0.2 |  | -
Diluted numerator |  | 227.4 |  | 397.2
Denominator |  |  |  |
Weighted average shares of common stock outstanding |  | 170.4 |  | 144.9
Weighted average deferred share units outstanding |  | 1.0 |  | 0.9
Weighted average shares of common stock outstanding – basic |  | 171.4 |  | 145.8
Stock-based compensation |  | 0.6 |  | 0.6
Convertible Debentures |  | 0.2 |  | -
Weighted average shares of common stock outstanding – diluted |  | 172.2 |  | 146.4
Earnings per common share |  |  |  |
Basic | $ | 1.33 | $ | 2.72
Diluted | $ | 1.32 | $ | 2.71

12. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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The components of accumulated other comprehensive income are as follows:
millions of Canadian dollars | (Losses) gains on derivatives recognized as cash flow hedges | Net change in unrecognized pension and post-retirement benefit costs | Net change in net investment hedges | Net change on available-for-sale investments | Unrealized (loss) gain on translation of self-sustaining foreign operations | Total AOCI
For the year ended December 31, 2016
Balance, January 1, 2016 | $ | (35) | $ | (318) | $ | - | $ | - | $ | 490 | $ | 137
Other comprehensive income (loss) before reclassifications |  | 11 |  | - |  | (49) |  | 3 |  | 35 |  | -
Amounts reclassified from accumulated other comprehensive income loss |  | 11 |  | 12 |  | - |  | (4) |  | - |  | 19
Equity method reclassification adjustments |  | (8) |  | (3) |  | - |  | - |  | (35) |  | (46)
Net current period other comprehensive income (loss) |  | 14 |  | 9 |  | (49) |  | (1) |  | - |  | (27)
Other |  | - |  | - |  | - |  | - |  | (4) |  | (4)
Balance, December 31, 2016 | $ | (21) | $ | (309) | $ | (49) | $ | (1) | $ | 486 | $ | 106
millions of Canadian dollars | (Losses) gains on derivatives recognized as cash flow hedges | Net change in unrecognized pension and post-retirement benefit costs | Net change in net investment hedges | Net change on available-for-sale investments | Unrealized (loss) gain on translation of self-sustaining foreign operations | Total AOCI
For the year ended December 31, 2015
Balance, January 1, 2015 | $ | (8) | $ | (425) | $ | - | $ | 3 | $ | 82 | $ | (348)
Other comprehensive income (loss) before reclassifications |  | (34) |  | - |  | - |  | (3) |  | 408 |  | 371
Amounts reclassified from accumulated other comprehensive income loss (gain) |  | 7 |  | 107 |  | - |  | - |  | - |  | 114
Net current period other comprehensive income (loss) |  | (27) |  | 107 |  | - |  | (3) |  | 408 |  | 485
Balance, December 31, 2015 | $ | (35) | $ | (318) | $ | - | $ | - | $ | 490 | $ | 137

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The reclassifications out of accumulated other comprehensive income (loss) are as follows:
For the |  | Year ended December 31
millions of Canadian dollars |  |  | 2016 |  | 2015
| Affected line item in the Consolidated Statements of Income |  | Amounts reclassified from AOCI
Losses (gain) on derivatives recognized as cash flow hedges |  |  |  |  |
Power and gas swaps | Non-regulated fuel for generation and purchased power | $ | (2) | $ | (5)
Interest rate swaps | Income from equity investments |  | 1 |  | 1
Foreign exchange forwards | Operating revenue - regulated |  | 12 |  | 9
Total before tax |  |  | 11 |  | 5
| Income tax expense |  | - |  | 2
Total net of tax |  | $ | 11 | $ | 7
Net change in unrecognized pension and post-retirement benefit costs |  |  |  |  |
Actuarial losses (gains) | OM&G | $ | 41 | $ | 50
Past service costs (gains) | OM&G |  | (9) |  | (7)
Amounts reclassified into obligations | Pension and post-retirement benefits |  | (17) |  | 72
Total before tax |  |  | 15 |  | 115
| Income tax expense (recovery) |  | (3) |  | (8)
Total net of tax |  | $ | 12 | $ | 107
Net change in available-for-sale investments |  |  |  |  |
| Other income (expenses), net | $ | (4) | $ | -
Total before tax |  |  | (4) |  | -
| Income tax expense (recovery) |  | - |  | -
Total net of tax |  | $ | (4) | $ | -
Equity method reclassification adjustments |  |  |  |  |
| Investments subject to significant influence | $ | 54 | $ | -
Total before tax |  |  | 54 |  | -
| Income tax expense (recovery) |  | (8) |  | -
Total net of tax |  | $ | 46 | $ | -
Total reclassifications out of AOCI, net of tax, for the period |  | $ | 65 | $ | 114

13. RECEIVABLES, NET |  |  |  |
Receivables, net consisted of the following: |  |  |  |
As at | December 31 | December 31
millions of Canadian dollars |  | 2016 |  | 2015
Customer accounts receivable – billed | $ | 715 | $ | 406
Customer accounts receivable – unbilled |  | 270 |  | 144
Total customer accounts receivable |  | 985 |  | 550
Allowance for doubtful accounts |  | (13) |  | (12)
Customer accounts receivable, net |  | 972 |  | 538
Other |  | 42 |  | 40
| $ | 1,014 | $ | 578

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14. INVENTORY |  |  |  |
Inventory consisted of the following: |  |  |  |
As at | December 31 | December 31
millions of Canadian dollars |  | 2016 |  | 2015
Fuel | $ | 235 | $ | 185
Materials |  | 215 |  | 100
Emission credits (1) |  | 22 |  | 29
| $ | 472 | $ | 314
(1)The NEGG Facilities are subject to the Acid Rain Program for sulphur dioxide emissions and the Regional Greenhouse Gas Initiative ("RGGI") for carbon dioxide emissions. The emissions credits inventory balance represents the credits purchased to offset the other current liabilities and other long-term liabilities associated with these programs.

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15. DERIVATIVE INSTRUMENTS

The Company enters into futures, forwards, swaps and option contracts as part of its risk management strategy to limit exposure to:

· commodity price fluctuations related to the purchase and sale of commodities in the course of normal operations;

· foreign exchange fluctuations on foreign currency denominated purchases and sales; and

· interest rate fluctuations on debt securities.

The Company also enters into physical contracts for energy commodities. Collectively, these contracts are considered “derivatives”. The Company accounts for derivatives under one of the following four approaches:

1. Physical contracts that meet the normal purchases normal sales (“NPNS”) exemption are not recognized on the balance sheet; they are recognized in income when they settle. A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. The Company continually assesses contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exception if the criteria are no longer met.

2. Derivatives that qualify for hedge accounting are recorded at fair value on the balance sheet. Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge the identified cash flow risk both at the inception and over the term of the derivative. Specifically for cash flow hedges, the effective portion of the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Any ineffective portion of the change in fair value from cash flow hedges is recognized in net income in the reporting period.

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

4. Derivatives entered into by Tampa Electric, PGS, NMGC, NSPI and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at fair value on the balance sheet as derivative assets or liabilities. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes that any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates.

5. Derivatives that do not meet any of the above criteria are designated as HFT derivatives and are recorded on the balance sheet at fair value, with changes normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply.

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Derivative assets and liabilities relating to the foregoing categories consisted of the following:
|  | Derivative Assets |  | Derivative Liabilities
As at | December 31 | December 31 | December 31 | December 31
millions of Canadian dollars |  | 2016 |  | 2015 |  | 2016 |  | 2015
Current |  |  |  |  |  |  |  |
Cash flow hedges |  |  |  |  |  |  |  |
Power swaps | $ | 5 | $ | 8 | $ | 2 | $ | 1
Foreign exchange forwards |  | - |  | - |  | 12 |  | 14
|  | 5 |  | 8 |  | 14 |  | 15
Regulatory deferral |  |  |  |  |  |  |  |
Commodity swaps and forwards |  |  |  |  |  |  |  |
Coal purchases |  | 26 |  | - |  | 9 |  | 12
Power purchases |  | 3 |  | - |  | 1 |  | -
Natural gas purchases and sales |  | 28 |  | 2 |  | - |  | 1
Heavy fuel oil purchases |  | 6 |  | - |  | 4 |  | 20
Foreign exchange forwards |  | 56 |  | 85 |  | - |  | 10
Physical natural gas purchases and sales |  | - |  | 2 |  | - |  | -
|  | 119 |  | 89 |  | 14 |  | 43
HFT derivatives |  |  |  |  |  |  |  |
Power swaps and physical contracts |  | 33 |  | 151 |  | 44 |  | 119
Natural gas swaps, futures, forwards, physical contracts |  | 93 |  | 99 |  | 357 |  | 359
Foreign exchange options |  | - |  | - |  | - |  | 2
|  | 126 |  | 250 |  | 401 |  | 480
Other derivatives |  |  |  |  |  |  |  |
Foreign exchange forwards |  | - |  | 92 |  | 1 |  | -
|  | - |  | 92 |  | 1 |  | -
Total gross current derivatives |  | 250 |  | 439 |  | 430 |  | 538
Impact of master netting agreements with intent to settle net or simultaneously |  | (105) |  | (189) |  | (105) |  | (189)
Total current derivatives |  | 145 |  | 250 |  | 325 |  | 349
Long-term |  |  |  |  |  |  |  |
Cash flow hedges |  |  |  |  |  |  |  |
Power swaps |  | 5 |  | 12 |  | 3 |  | 4
Foreign exchange forwards |  | - |  | - |  | 10 |  | 27
|  | 5 |  | 12 |  | 13 |  | 31
Regulatory deferral |  |  |  |  |  |  |  |
Commodity swaps and forwards |  |  |  |  |  |  |  |
Coal purchases |  | 57 |  | - |  | - |  | 4
Power purchases |  | 4 |  | - |  | 3 |  | -
Natural gas purchases and sales |  | 5 |  | - |  | 2 |  | -
Heavy fuel oil purchases |  | 4 |  | - |  | 3 |  | 17
Foreign exchange forwards |  | 50 |  | 121 |  | - |  | -
|  | 120 |  | 121 |  | 8 |  | 21
HFT derivatives |  |  |  |  |  |  |  |
Power swaps and physical contracts |  | 14 |  | 13 |  | 27 |  | 28
Natural gas swaps, futures, forwards and physical contracts |  | 18 |  | 72 |  | 127 |  | 63
Foreign exchange options |  | - |  | 1 |  | - |  | 1
|  | 32 |  | 86 |  | 154 |  | 92
Other derivatives |  |  |  |  |  |  |  |
Interest rate swap |  | - |  | - |  | 1 |  | 3
|  | - |  | - |  | 1 |  | 3
Total gross long-term derivatives |  | 157 |  | 219 |  | 176 |  | 147
Impact of master netting agreements with intent to settle net or simultaneously |  | (26) |  | (51) |  | (26) |  | (51)
Total long-term derivatives |  | 131 |  | 168 |  | 150 |  | 96
Total derivatives | $ | 276 | $ | 418 | $ | 475 | $ | 445
Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.

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148

Details of master netting agreements, shown net on the Consolidated Balance Sheets, are summarized in the following table:
|  | Derivative Assets |  | Derivative Liabilities
As at | December 31 | December 31 | December 31 | December 31
millions of Canadian dollars |  | 2016 |  | 2015 |  | 2016 |  | 2015
Regulatory deferral | $ | 10 | $ | - | $ | 10 | $ | -
HFT derivatives |  | 121 |  | 240 |  | 121 |  | 240
Total impact of master netting agreements with intent to settle net or simultaneously | $ | 131 | $ | 240 | $ | 131 | $ | 240

Cash Flow Hedges

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

As previously noted, the effective portion of the change in fair value of these derivatives is included in AOCI, until the hedged transactions are recognized in income. The ineffective portion is recognized in income of the period. The amounts related to cash flow hedges recorded in income and AOCI consisted of the following:

For the | Year ended December 31
millions of Canadian dollars |  |  |  |  |  | 2016 |  |  |  |  |  | 2015
|  |  | Interest | Foreign |  |  | Interest | Foreign
Power | rate | exchange | Power | rate | exchange
swaps | swaps | forwards | swaps | swaps | forwards
Realized gain (loss) in non-regulated fuel for generation and purchased power |  | 2 |  | - |  | - |  | 5 |  | - |  | -
Realized gain (loss) in operating revenue – Regulated |  | - |  | - |  | (12) |  | - |  | - |  | (9)
Realized gain (loss) in income from equity investments |  | - |  | (1) |  | - |  | - |  | (1) |  | -
Total gains (losses) in Net income | $ | 2 | $ | (1) | $ | (12) | $ | 5 | $ | (1) | $ | (9)
As at | December 31
millions of Canadian dollars |  |  |  |  |  | 2016 |  |  |  |  |  | 2015
|  | Interest | Foreign |  | Interest | Foreign
Power | rate | exchange | Power | rate | exchange
swaps | swaps | forwards | swaps | swaps | forwards
Total unrealized gain (loss) in AOCI – effective portion, net of tax | $ | 2 | $ | - | $ | (22) | $ | 4 | $ | (1) | $ | (42)
The Company expects $14 million of unrealized losses currently in AOCI to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle.

As at December 31, 2016, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:
millions |  | 2017 |  | 2018 |  | 2019 |  | 2020
Foreign exchange forwards (USD) sales | $ | 53 | $ | 45 | $ | 30 | $ | 30
Foreign exchange forwards (EURO) purchases |  | 3 |  | - |  | - |  | -

Regulatory Deferral

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As previously noted, Tampa Electric, PGS, NMGC, NSPI and GBPC defer gains and losses on certain derivatives documented as economic hedges, including certain physical contracts that do not qualify for the NPNS exemption.

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

For the | Year ended December 31
millions of Canadian dollars |  |  |  |  |  | 2016 |  |  |  |  |  | 2015
| Commodity swaps and forwards | Physical natural gas purchases and sales | Foreign exchange forwards | Commodity swaps and forwards | Physical natural gas purchases and sales | Foreign exchange forwards
Unrealized gain (loss) in regulatory assets | $ | 40 | $ | - | $ | (2) | $ | (24) | $ | - | $ | (7)
Unrealized gain (loss) in regulatory liabilities |  | 101 |  | (1) |  | (30) |  | 1 |  | 9 |  | 173
Realized (gain) loss in regulatory assets |  | - |  | - |  | 12 |  | (3) |  | - |  | -
Realized (gain) loss in regulatory liabilities |  | - |  | - |  | (8) |  | - |  | - |  | -
Realized (gain) loss in property, plant and equipment |  | - |  | - |  | - |  | - |  | - |  | (1)
Realized (gain) loss in inventory (1) |  | 5 |  | - |  | (44) |  | 12 |  | - |  | (44)
Realized (gain) loss in regulated fuel for generation and purchased power (2) |  | 17 |  | (1) |  | (18) |  | (16) |  | (7) |  | (18)
Total change derivative instruments | $ | 163 | $ | (2) | $ | (90) | $ | (30) | $ | 2 | $ | 103
(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.
(2) Realized (gains) losses on derivative instruments settled and consumed in the period; hedging relationships that have been terminated or the hedged transaction is no longer probable.

#### Commodity Swaps and Forwards

As at December 31, 2016, the Company had the following notional volumes of commodity swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below:

| 2017 | 2018-2020
millions | Purchases | Purchases
Coal (metric tonnes) | - | 2
Natural Gas (Mmbtu) | 42 | 24
Heavy fuel oil (bbls) | - | 1

Foreign Exchange Swaps and Forwards

As at December 31, 2016, the Company had the following notional volumes of foreign exchange swaps and forward contracts related to commodity contracts that are expected to settle as outlined below:

| 2017 | 2018-2020
Fuel purchases exposure (millions of US dollars) | $ | 224 | $ | 240
Weighted average rate |  | 1.0722 |  | 1.1138
% of USD requirements |  | 120% |  | 44%
The Company reassesses foreign exchange forecasts periodically and will enter into additional hedges or unwind existing hedges, as required.

####

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#### Held-for-Trading Derivatives

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

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

For the | Year ended December 31
millions of Canadian dollars |  | 2016 |  | 2015
Power swaps and physical contracts in non-regulated operating revenues | $ | (1) | $ | 10
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues |  | 69 |  | 5
Natural gas swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power |  | (7) |  | (3)
Foreign exchange options in other income (expenses), net |  | (2) |  | (1)
| $ | 59 | $ | 11

As at December 31, 2016, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:

millions |  | 2017 |  | 2018 |  | 2019 |  | 2020 |  | 2021
Natural gas purchases (Mmbtu) |  | 270 |  | 69 |  | 54 |  | 45 |  | 45
Natural gas sales (Mmbtu) |  | 202 |  | 20 |  | 16 |  | 12 |  | 1
Power purchases (MWh) |  | 3 |  | - |  | - |  | - |  | -
Power sales (MWh) |  | 4 |  | - |  | - |  | - |  | -

Other Derivatives |  |  |  |  |  |  |  |
The Company has recognized the following realized and unrealized gains (losses) with respect to cash flow hedges which documentation requirements have not been met:
For the |  | Year ended December 31
millions of Canadian dollars |  |  |  | 2016 |  |  |  | 2015
|  | Interest |  | Foreign |  | Interest |  | Foreign
|  | rate |  | exchange | rate | exchange
| swaps |  | forwards | swaps | forwards
Realized gain (loss) in other income (expense) | $ | - | $ | (87) | $ | - | $ | -
Unrealized gain (loss) in other income (expense) |  | - |  | - |  | - |  | 92
Unrealized gain (loss) in interest expense, net |  | 2 |  | - |  | (3) |  | -
Total gains (losses) in net income | $ | 2 | $ | (87) | $ | (3) | $ | 92
As at December 31, 2016, the Company had interest rate swaps in place for the $250 million non-revolving term credit facility in Brunswick Pipeline for interest payments until the debt matures in 2019.
During the year ended December 31, 2016, $1,519 million in foreign exchange forwards and swaps that were used to partially hedge proceeds for the TECO Energy acquisition settled.

#### Credit Risk

The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures

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for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high risk accounts.

The Company assesses the potential for credit losses on a regular basis, and where appropriate, maintains provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability. The Company assesses credit risk internally for counterparties that are not rated.

As at December 31, 2016, the maximum exposure the Company has to credit risk is $1,019 million (2015 - $901 million), which includes accounts receivable net of collateral/deposits and assets related to derivatives.

It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, foreign exchange and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The total cash deposits/collateral on hand as at December 31, 2016 was $271 million (2015 - $94 million), which mitigates the Company’s maximum credit risk exposure. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company.

The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements (“ISDA”), North American Energy Standards Board agreements (“NAESB”) and, or Edison Electric Institute agreements. The Company believes that entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default.

As at December 31, 2016, the Company had $104 million (2015 - $83 million) in financial assets, considered to be past due, which have been outstanding for an average 69 days. The fair value of these financial assets is $91 million (2015 - $72 million), the difference of which is included in the allowance for doubtful accounts. These assets primarily relate to accounts receivable from electric and gas revenue.

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Concentration Risk |  |  |  |  |  |
The Company's concentrations of risk consisted of the following:
As at | December 31, 2016 | December 31, 2015
| millions of Canadian dollars | % of total exposure | millions of Canadian dollars | % of total exposure
Receivables, net |  |  |  |  |  |
Regulated utilities |  |  |  |  |  |
Residential | $ | 315 | 24% | $ | 189 | 20%
Commercial |  | 170 | 13% |  | 103 | 10%
Industrial |  | 38 | 3% |  | 29 | 3%
Other |  | 69 | 5% |  | 53 | 5%
|  | 592 | 45% |  | 374 | 38%
Trading group |  |  |  |  |  |
Credit rating of A- or above |  | 52 | 4% |  | 31 | 3%
Credit rating of BBB- to BBB+ |  | 60 | 5% |  | 22 | 2%
Not rated |  | 57 | 4% |  | 31 | 3%
|  | 169 | 13% |  | 84 | 8%
Other accounts receivable |  | 253 | 20% |  | 120 | 12%
|  | 1,014 | 78% |  | 578 | 58%
Derivative Instruments (current and long-term) |  |  |  |  |  |
Credit rating of A- or above |  | 252 | 20% |  | 340 | 34%
Credit rating of BBB- to BBB+ |  | 1 | 0% |  | 70 | 7%
Not rated |  | 23 | 2% |  | 8 | 1%
|  | 276 | 22% |  | 418 | 42%
| $ | 1,290 | 100% | $ | 996 | 100%

#### Cash Collateral

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

As at | December 31 | December 31
millions of Canadian dollars |  | 2016 |  | 2015
Cash collateral provided to others | $ | 91 | $ | 107
Cash collateral received from others |  | 52 |  | 29

Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain derivatives contain financial assurance provisions that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted in the senior unsecured debt to fall below investment grade, the counterparties to such derivatives could request ongoing full collateralization.

As at December 31, 2016, the total fair value of these derivatives, in a liability position, was $475 million (December 31, 2015 – $445 million). If the credit ratings of the Company were reduced below investment grade the full value of the net liability position could be required to be posted as collateral for these derivatives.

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16. FAIR VALUE MEASUREMENTS

The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exemption (see note 15), and uses a market approach to do so. The three levels of the fair value hierarchy are defined as follows:

Level 1 - Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities.

Level 2 - Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses.

Level 3 - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally-developed inputs. The primary reasons for a Level 3 classification are as follows:

· While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials.

· The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term.

· The valuations of certain transactions were based on internal models, although quoted prices were utilized in the valuations.

Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

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

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As at |  | December 31, 2016
millions of Canadian dollars |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Assets |  |  |  |  |  |  |  |
Cash flow hedges |  |  |  |  |  |  |  |
Power swaps | $ | 10 | $ | - | $ | - | $ | 10
|  | 10 |  | - |  | - |  | 10
Regulatory deferral |  |  |  |  |  |  |  |
Commodity swaps and forwards |  |  |  |  |  |  |  |
Coal purchases |  | - |  | 74 |  | - |  | 74
Power purchases |  | 7 |  | - |  | - |  | 7
Natural gas purchases and sales |  | 8 |  | 25 |  | - |  | 33
Heavy fuel oil purchases |  | 3 |  | 5 |  | 1 |  | 9
Foreign exchange forwards |  | - |  | 106 |  | - |  | 106
|  | 18 |  | 210 |  | 1 |  | 229
HFT derivatives |  |  |  |  |  |  |  |
Power swaps and physical contracts |  | (7) |  | 1 |  | - |  | (6)
Natural gas swaps, futures, forwards, physical contracts and related transportation |  | - |  | 4 |  | 39 |  | 43
|  | (7) |  | 5 |  | 39 |  | 37
Total assets |  | 21 |  | 215 |  | 40 |  | 276
Liabilities |  |  |  |  |  |  |  |
Cash flow hedges |  |  |  |  |  |  |  |
Power swaps |  | 4 |  | - |  | - |  | 4
Foreign exchange forwards |  | - |  | 23 |  | - |  | 23
|  | 4 |  | 23 |  | - |  | 27
Regulatory deferral |  |  |  |  |  |  |  |
Commodity swaps and forwards |  |  |  |  |  |  |  |
Power purchases |  | 4 |  | - |  | - |  | 4
Heavy fuel oil purchases |  | - |  | 6 |  | - |  | 6
Natural gas purchases and sales |  | 1 |  | 1 |  | - |  | 2
|  | 5 |  | 7 |  | - |  | 12
HFT derivatives |  |  |  |  |  |  |  |
Power swaps and physical contracts |  | 12 |  | 5 |  | - |  | 17
Natural gas swaps, futures, forwards and physical contracts |  | 4 |  | 24 |  | 389 |  | 417
|  | 16 |  | 29 |  | 389 |  | 434
Other derivatives |  |  |  |  |  |  |  |
Foreign exchange forwards |  | - |  | 1 |  | - |  | 1
Interest rate swap |  | - |  | 1 |  | - |  | 1
|  | - |  | 2 |  | - |  | 2
Total liabilities |  | 25 |  | 61 |  | 389 |  | 475
Net assets (liabilities) | $ | (4) | $ | 154 | $ | (349) | $ | (199)

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As at |  | December 31, 2015
millions of Canadian dollars |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Assets |  |  |  |  |  |  |  |
Cash flow hedges |  |  |  |  |  |  |  |
Power swaps | $ | 20 | $ | - | $ | - | $ | 20
|  | 20 |  | - |  | - |  | 20
Regulatory deferral |  |  |  |  |  |  |  |
Commodity swaps and forwards |  |  |  |  |  |  |  |
Coal purchases |  | - |  | 1 |  | - |  | 1
Foreign exchange forwards |  | - |  | 207 |  | - |  | 207
Physical natural gas purchases and sales |  | - |  | - |  | 2 |  | 2
|  | - |  | 208 |  | 2 |  | 210
HFT derivatives |  |  |  |  |  |  |  |
Power swaps and physical contracts |  | 38 |  | 1 |  | (8) |  | 31
Natural gas swaps, futures, forwards and physical contracts |  | - |  | 8 |  | 57 |  | 65
|  | 38 |  | 9 |  | 49 |  | 96
Other derivatives |  |  |  |  |  |  |  |
Foreign exchange forwards |  | - |  | 92 |  | - |  | 92
|  | - |  | 92 |  | - |  | 92
Total assets |  | 58 |  | 309 |  | 51 |  | 418
Liabilities |  |  |  |  |  |  |  |
Cash flow hedges |  |  |  |  |  |  |  |
Power swaps | $ | 5 | $ | - | $ | - | $ | 5
Foreign exchange forwards |  | - |  | 41 |  | - |  | 41
|  | 5 |  | 41 |  | - |  | 46
Regulatory deferral |  |  |  |  |  |  |  |
Commodity swaps and forwards |  |  |  |  |  |  |  |
Coal purchases |  | - |  | 16 |  | - |  | 16
Natural gas purchases and sales |  | 1 |  | - |  | - |  | 1
Heavy fuel oil purchases |  | - |  | 37 |  | - |  | 37
Foreign exchange forwards |  | - |  | 10 |  | - |  | 10
|  | 1 |  | 63 |  | - |  | 64
HFT derivatives |  |  |  |  |  |  |  |
Power swaps and physical contracts |  | 15 |  | - |  | (2) |  | 13
Foreign exchange options |  | - |  | 4 |  | - |  | 4
Natural gas swaps, futures, forwards and physical contracts |  | 14 |  | 22 |  | 279 |  | 315
|  | 29 |  | 26 |  | 277 |  | 332
Other derivatives |  |  |  |  |  |  |  |
Interest rate swaps |  | - |  | 3 |  | - |  | 3
|  | - |  | 3 |  | - |  | 3
Total liabilities |  | 35 |  | 133 |  | 277 |  | 445
Net assets (liabilities) | $ | 23 | $ | 176 | $ | (226) | $ | (27)

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The change in the fair value of the Level 3 financial assets for the year ended December 31, 2016 was as follows:
| Regulatory Deferral | Cash Flow Hedges and HFT Derivatives
millions of Canadian dollars | Oil Financial derivatives | Physical natural gas purchases and sales | Power | Natural gas | Total
Balance, January 1, 2016 | $ | - | $ | 2 | $ | (8) | $ | 57 | $ | 51
Increase (reduction) in benefit included in regulated fuel for generation and purchased power |  | - |  | (1) |  | - |  | - |  | (1)
Unrealized gains (losses) included in regulatory assets or liabilities |  | 3 |  | (1) |  | - |  | - |  | 2
Total realized and unrealized gains (losses) included in non-regulated operating revenues |  | - |  | - |  | 8 |  | (18) |  | (10)
Net transfers out of Level 3 |  | (2) |  | - |  | - |  | - |  | (2)
Balance, December 31, 2016 | $ | 1 | $ | - | $ | - | $ | 39 | $ | 40

The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2016 was as follows:
| Regulatory Deferral | Cash Flow Hedges and HFT Derivatives
millions of Canadian dollars | Oil Financial derivatives | Physical natural gas purchases and sales | Power | Natural gas | Total
Balance, January 1, 2016 | $ | - | $ | - | $ | (2) | $ | 279 | $ | 277
Total realized and unrealized gains (losses) included in non-regulated operating revenues |  | - |  | - |  | 2 |  | 110 |  | 112
Balance, December 31, 2016 | $ | - | $ | - | $ | - | $ | 389 | $ | 389

The Company evaluates the observable input of market data on a quarterly basis in order to determine if transfers between levels is appropriate. For the year ended December 31, 2016, transfers from Level 3 to Level 1 were a result of an increase in observable inputs.

Emera’s Enterprise Risk Management group is responsible for valuation policies, processes and the measurement of fair value. Fair value accounting rules provide a three level hierarchy that prioritizes the inputs used to measure fair value. When possible, determining fair value is based primarily on observable market inputs in active markets.

Contracts with quoted prices available in active markets and exchanges for identical assets or liabilities are classified as level 1 in the hierarchy. For those contracts whereby pricing inputs are either directly or indirectly observable through markets, exchanges or third party sources, but do not qualify as level 1, are classified as level 2 in the hierarchy. For a level 3 classification, the processes and methods of measurement for third-party pricing information and illiquid markets are developed with input and using the market knowledge of the trading operations within Emera and its affiliates.

Significant unobservable inputs used in the fair value measurement of Emera’s natural gas and power derivatives includes third-party-sourced pricing for instruments based on illiquid markets; internally developed correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid term markets. Where possible, Emera also sources multiple broker prices in an effort to evaluate and substantiate these unobservable inputs. Discount rates may include a risk premium for those long-term forward contracts with illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing similar industry practices and in discussion with industry peers. Significant

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increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement.

The following table outlines quantitative information about the significant unobservable inputs used in the fair value measurements categorized within Level 3 of the fair value hierarchy:

As at |  | December 31, 2016
millions of Canadian dollars |  | Fair Value | Valuation Technique | Unobservable Input | Range | Weighted average
Assets |  |  |  |  |  |
Regulatory deferral – Financial | $ | 1 | Modelled pricing | Third-party pricing | $69.64 | $69.64
oil derivatives |  |  |  | Probability of default | 0.80% | 0.80%
HFT derivatives – |  | 27 | Modelled pricing | Third-party pricing | $1.41 - $11.87 | $3.87
Natural gas swaps, |  |  |  | Probability of default | 0.00% - 0.07% | 0.01%
futures, forwards, |  |  |  | Discount rate | 0.00% - 0.32% | 0.05%
physical contracts |  | 12 | Modelled pricing | Third-party pricing | $1.83 - $11.87 | $6.16
and related transportation |  |  |  | Basis adjustment | (0.11)% - 0.64% | 0.39%
|  |  |  | Probability of default | 0.00% - 0.05% | 0.00%
|  |  |  | Discount rate | 0.00% - 0.10% | 0.00%
Total assets | $ | 40 |  |  |  |
Liabilities |  |  |  |  |  |
HFT derivatives – | $ | 386 | Modelled pricing | Third-party pricing | $1.55 - $11.87 | $6.26
Natural gas swaps, futures, |  |  |  | Own credit risk | 0.00% - 0.07% | 0.00%
forwards and physical contracts |  |  |  | Discount rate | 0.00% - 0.14% | 0.02%
|  | 3 | Modelled pricing | Third-party pricing | $1.83 - $11.87 | $5.93
|  |  |  | Basis adjustment | (0.11)% - 0.64% | 0.27%
|  |  |  | Own credit risk | 0.00% - 0.05% | 0.01%
|  |  |  | Discount rate | 0.00% - 0.10% | 0.01%
Total liabilities |  | 389 |  |  |  |
Net assets (liabilities) | $ | (349) |  |  |  |

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As at |  | December 31, 2015
millions of Canadian dollars |  | Fair Value | Valuation Technique | Unobservable Input | Range | Weighted average
Assets |  |  |  |  |  |
Regulatory deferral – Physical | $ | 2 | Modelled pricing | Third-party pricing | $5.15 - $6.21 | $5.72
natural gas purchases and sales |  |  |  | Probability of default | 0.01% | 0.01%
HFT derivatives – |  | (8) | Modelled pricing | Third-party pricing | $26.27 - $129.20 | $70.45
Power swaps and |  |  |  | Correlation factor | 0.98% - 1.00% | 0.99%
physical contracts |  |  |  | Probability of default | 0.00% - 0.02% | 0.00%
|  |  |  | Discount rate | 0.00% - 0.15% | 0.01%
|  | 54 | Modelled pricing | Third-party pricing | $1.13 - $9.12 | $3.26
|  |  |  | Probability of default | 0.00% - 0.10% | 0.01%
|  |  |  | Discount rate | 0.00% - 0.33% | 0.04%
|  | 3 | Modelled pricing | Third-party pricing | $1.25 - $15.74 | $6.19
|  |  |  | Basis adjustment | (0.06)% - 0.95% | 0.68%
|  |  |  | Probability of default | 0.00% - 0.09% | 0.00%
|  |  |  | Discount rate | 0.00% - 0.08% | 0.00%
Total assets | $ | 51 |  |  |  |
Liabilities |  |  |  |  |  |
HFT derivatives – | $ | (2) | Modelled pricing | Third-party pricing | $26.27 - $129.20 | $70.82
Power swaps and |  |  |  | Correlation factor | 0.98% - 1.00% | 0.99%
physical contracts |  |  |  | Own credit risk | 0.00% - 0.02% | 0.00%
|  |  |  | Discount rate | 0.00% - 0.15% | 0.01%
HFT derivatives – |  | 279 | Modelled pricing | Third-party pricing | $0.74 - $10.59 | $5.58
Natural gas swaps, |  |  |  | Probability of default | 0.00% - 0.03% | 0.00%
physical contracts |  |  |  | Discount rate | 0.00% - 0.12% | 0.01%
Total liabilities |  | 277 |  |  |  |
Net assets (liabilities) | $ | (226) |  |  |  |

The financial assets and liabilities included on the Consolidated Balance Sheets that are not measured at fair value consisted of the following: |  |
As at |  | December 31, 2016
millions of Canadian dollars |  | Carrying Amount |  | Fair Value |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Long-term debt (including current portion) | $ | 14,744 | $ | 15,723 | $ | 78 | $ | 14,843 | $ | 802 | $ | 15,723
As at |  | December 31, 2015
millions of Canadian dollars |  | Carrying Amount |  | Fair Value |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Long-term debt (including current portion) | $ | 4,009 | $ | 4,487 | $ | - | $ | 3,841 | $ | 646 | $ | 4,487

The fair values of long-term debt instruments, classified as level 1 in the fair value hierarchy, are valued using unadjusted quoted closing market prices that are traded in active markets.

Those classified as level 2 are valued either by using recent quoted market prices for the instrument where the instrument is not frequently traded, by using quoted closing market prices for similar issues that are frequently traded in an active market or by using quoted market prices and applying estimated credit spreads, provided by third-party pricing services, to the par value of the security.

Those classified as level 3 are valued by discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds with similar terms to maturity, plus a credit risk premium equal to that of issuers of similar credit quality.

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The Company has designated $1.2 billion United States dollar dominated Hybrid Notes as a hedge of the foreign currency exposure of its ne t investment in United States dollar denominated operations. A foreign currency loss of $49 million was recorded in Other Comprehensive Income for the twelve months ended December 31, 2016 (2015 – nil). There was no ineffectiveness for the twelve months ended December 31, 2016 (2015 – nil).

All other financial assets and liabilities, such as cash and cash equivalents, restricted cash, accounts receivable, short-term debt and accounts payable, are carried at cost. The carrying value approximates fair value due to the short-term nature of these financial instruments.

## 17. REGULATORY Assets and Liabilities

Regulatory assets represent incurred costs that have been deferred because it is probable that they will be recovered through future rates or tolls collected from customers. Management believes that existing regulatory assets are probable for recovery either because the Company received specific approval from the appropriate regulator, or due to regulatory precedent established for similar circumstances. If management no longer considers it probable that an asset will be recovered, the deferred costs are charged to income.

Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for previous collections. If management no longer considers it probable that a liability will be settled, the related amount is recognized in income.

For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective regulator.

####

#### Emera Florida and New Mexico

Tampa Electric and PGS are regulated separately by the FPSC. Tampa Electric is also subject to regulation by the FERC. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital.

NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to collect total revenues equal to their cost of providing service, plus an appropriate return on invested capital.

Base Rates - Tampa Electric

Tampa Electric’s target regulated return on equity (“ROE”) range is 9.25 per cent to 11.25 per cent. Based on a Stipulation and Settlement Agreement in 2013 Tampa Electric would receive a revenue increase of $ 110 million USD effective January 1, 2017 or the date Tampa Electric’s Polk Power Station goes into service, whichever is later. The expansion of Polk Power Station went into service on January 17, 2017. The agreement also provides that Tampa Electric’s allowed regulatory ROE would remain in place with a potential increase of the midpoint to 10.50 per cent from 10.25 per cent if U.S. Treasury bond yields exceed a specified threshold. This agreement provides that Tampa Electric cannot file for additional rate increases until 2017 (to be effective no sooner than January 1, 2018), unless its earned ROE were to fall below 9.25 per cent (or 9.5 per cent if the allowed ROE is increased as described above) before that time. If its earned ROE were to rise above 11.25 per cent (or 11.5 per cent if the allowed ROE is increased as described above) any party to the agreement other than Tampa Electric could seek a review of its base rates. Under the agreement, the allowed equity in the capital structure is 54 per cent from investor sources of capital.

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Base Rates - PGS

PGS’s base rates were based upon an ROE of 10.75 per cent, with a range between 9.75 per cent and 11.75 per cent.

In December 2016, PGS entered into a settlement agreement with the Office of Public Counsel (“OPC”) regarding its filed depreciation study. The settlement agreement resulted in new depreciation rates that reduce annual depreciation by $16 million USD in 2016 and accelerated the amortization of the regulated asset related to the Manufactured Gas Plant (“MGP”) environmental remediation costs. In addition, the bottom of the ROE range was decreased from 9.75 per cent to 9.25 per cent. The new bottom of the range will remain until the earlier of new base rates established in PGS’s next general rate proceeding or December 31, 2020. The top of the range will continue to be 11.75 per cent and the ROE of 10.75 per cent will continue to be used for the calculation of return on investment for clauses. On February 7, 2017 the FPSC approved the settlement agreement. No change in customer rates resulted from this agreement.

As part of the settlement, PGS and OPC agreed that at least $ 32 million USD of PGS’s regulatory asset associated with the environmental liability for current and future remediation costs related to former MGP sites will be amortized over the period 2016 through 2020. At least $21 million USD will be amortized over a two year recovery period beginning in 2016. In 2016, PGS recorded $16 million USD of this amortization.

Base Rates - NMGC

NMGC’s base rates were established in 2012 through a settlement agreement. As a condition of the 2016 NMPRC order (the “Order”) approving the acquisition of TECO Energy, NMGC will not seek an increase in base rates to be effective prior to December 31, 2017, and NMGC will continue to provide an annual bill reduction credit of $ 4 million USD through June 30, 2018.

#### NSPI

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

NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. NSPI’s target regulated ROE range for 2016 and 2015 was 8.75 per cent to 9.25 per cent based on an actual five quarter average regulated common equity component of up to 40 per cent. NSPI has a FAM, which enables it to seek recovery of Fuel Costs through regularly scheduled rate adjustments. Differences between actual Fuel Costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year.

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

On July 19, 2016, the UARB approved a Consensus Agreement between NSPI and customer representatives related to the Rate Stability Plan fuel costs for 2017 through 2019 which resulted in an

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average annual increase of 1.1 per cent for each of these three years. Subsequently, certain customer representatives requested changes resulting in amended rates that were approved by the UARB on November 15, 2016 and result in an average annual rate increase of 1.0 per cent for each of these three years.

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

On December 21, 2016, the UARB approved a settlement agreement between NSPI and customer representatives which resolved all issues related to the 2014 and 2015 FAM Audit and an issue that would impact future periods. As a result of this settlement agreement, NSPI agreed to forego $3 million of any incentive payment as a result of 2016 fuel costs savings achieved by the Company. NSPI achieved a $2.8 million incentive payment for 2016 and contributed that plus an additional $ 0.2 million to the benefit of customers.

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

FAM and fixed cost deferrals recognized in the 2016 and 2015 Consolidated Statement of Income consisted of the following:

For the |  | Year ended December 31
millions of Canadian dollars |  | 2016 |  | 2015
(Over) under recovery of current period Fuel costs | $ | 29 | $ | (24)
Recovery from customers of prior years’ Fuel costs |  | 12 |  | 56
Application of non-fuel revenues |  | 20 |  | 45
Regulated fixed cost deferral related to 2015 demand side management |  | - |  | (35)
Regulated fuel adjustment mechanism | $ | 61 | $ | 42

Emera Maine

Emera Maine’s core businesses are the transmission and distribution of electricity, with distribution operations and stranded cost recoveries regulated by the Maine Public Utilities Commission (“MPUC”). The transmission operations are regulated by the FERC. The rates for these three elements are established in distinct regulatory proceedings.

Distribution Operations

Emera Maine’s distribution businesses operate under a traditional cost-of-service regulatory structure, and distribution rates are set by the MPUC.

On December 21, 2016, Emera Maine’s distribution rates increased by 3.75 per cent, including the recovery, over five years, of approximately $4 million USD of costs associated with a major storm in Maine in 2014. Also, effective December 22, 2016 the allowed ROE became 9.00 per cent on a common equity component of 49 per cent.

Transmission Operations

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

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Bangor Hydro District

Bangor Hydro District (the franchise electric service territory associated with the former Bangor Hydro Electric Company in portions of the Maine counties of Penobscot, Hancock, Washington, Waldo, Piscataquis, and Aroostook) local transmission rates are regulated by the FERC and set annually on June 1, based on a formula utilizing prior year actual transmission investments, adjusted for current year forecasted transmission investments. Effective June 1, 2016, transmission rates for the Bangor Hydro district increased by approximately 2 per cent in connection with its annual transmission formula rate filing (2015 – increased by 21 per cent). The increase is associated primarily with the recovery of increased transmission plant in service and as a result of the prior year tariff rate including a rate refund related to the aforementioned FERC ROE decision.

Bangor Hydro District’s bulk transmission assets are managed by ISO-New England (“ISO-NE”) as part of a region-wide pool of assets. ISO-NE manages the region’s bulk power generation and transmission systems and administers the open access transmission tariff. Currently, the Bangor Hydro District, along with all other participating transmission providers, recovers the full cost of service for its transmission assets from the customers of participating transmission providers in New England, based on a regional FERC approved formula that is updated June 1 each year. This formula is based on prior year regionally funded transmission investments, adjusted for current year forecasted investments. The participating transmission providers are also required to contribute to the cost of service of such transmission assets on a ratable basis according to the proportion of the total New England load that their customers represent.

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

MPS District

MPS District (the franchise electric service territory associated with the former Maine Public Service Company in northern Maine) local transmission rates are regulated by the FERC and are set annually on June 1 for wholesale and July 1 for retail customers based on a formula utilizing prior year actual transmission investments and expenses, adjusted for current year forecasted investments. The current allowed ROE for transmission operations is 10.2 per cent. The common equity component is based upon the prior calendar year actual average balances. Effective June 1, 2016 the transmission rates for the Maine Public Service district increased by approximately 43 per cent for wholesale customers (2015 - decreased by 1 per cent) and on July 1, 2016 increased by 36 per cent for retail customers (2015 - decreased by 22 per cent) in connection with its annual transmission formula rate filing. These increases were primarily due to an increase in the recovery of increased transmission plant in service.

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

Stranded Cost Recoveries

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

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Bangor Hydro District

Bangor District’s net regulatory assets primarily include the costs associated with the restructuring of an above-market power purchase contract and deferrals associated with reconciling stranded costs. These net regulatory assets total approximately $11.4 million as at December 31, 2016 (2015 – $19.7 million) or 1.0 per cent of Emera Maine’s net asset base (2015 – 1.8 per cent).

The Bangor Hydro District is currently undergoing a stranded cost rate proceeding with the MPUC to set rates for the period March 1, 2017 to February 28, 2020.

While the stranded cost revenue requirements differ throughout the period due to changes in annual stranded costs, the actual annual stranded cost revenues are the same during the period. To stabilize the impact of the varying revenue requirements, cost or revenue deferrals are recorded as a regulatory asset or liability, and addressed in subsequent stranded cost rate proceedings, where customer rates are adjusted accordingly.

MPS District

Effective January 1, 2015, the stranded cost rates for the Maine Public Service district decreased by approximately 150 per cent. This was principally due to the flow-back to customers of certain benefits received by Emera Maine from Maine Yankee associated with litigation with the United States Department of Energy on nuclear waste disposal. The allowed ROE used in setting the new rates on January 1, 2015 was 6.75 per cent, with a common equity component of 48 per cent. On July 1, 2016, stranded cost rates further decreased by 7.6% to flow back over-collections associated with stranded cost reconciliation deferrals. The allowed ROE remained consistent with the January 1, 2015 rate change. The reduced stranded cost revenues are offset by reductions in expense and do not affect earnings. The Maine Public district is currently undergoing a stranded cost rate proceeding with the MPUC to set rates for the period March 1, 2017 to February 28, 2020.

The Barbados Light & Power Company Limited

BLPC is a vertically integrated utility and provider of electricity on the island of Barbados.

BLPC is subject to regulation under the Utilities Regulation (Procedural) Rules 2003 by the Fair Trading Commission (“The Rules”), Barbados, an independent regulator. The Rules give the Fair Trading Commission, Barbados utility regulation functions, which include establishing principles for arriving at rates to be charged, monitoring the rates charged to ensure compliance, and setting the maximum rates for regulated utility services. The government of Barbados has granted BLPC a franchise to generate, transmit and distribute electricity on the island until 2028.

BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. BLPC’s approved regulated return on rate base for 2016 and 2015 was 10 per cent.

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

Dominica Electricity Services Ltd

Domlec is an integrated utility on the island of Dominica and is regulated by the Independent Regulatory Commission, Dominica.

On October 7, 2013, the Independent Regulatory Commission, Dominica issued a Transmission, Distribution & Supply License and a Generation License, both of which came into effect on January 1,

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2014, for a period of 25 years. Domlec’s approved allowable regulated return on rate base for 2016 and 2015 was 15 per cent.

Domlec fuel costs are passed to customers through a fuel pass-through mechanism which provides the opportunity to recover substantially all fuel costs in a timely manner.

#### Grand Bahama Power Company Limited

GBPC is a vertically integrated utility and sole provider of electricity on Grand Bahama Island. The Grand Bahama Port Authority (“GBPA”) regulates the utility and has granted GBPC a licensed, regulated and exclusive franchise to produce, transmit and distribute electricity on the island until 2054. There is a fuel pass through mechanism and flexible tariff adjustment policy to ensure that fuel costs are recovered and a reasonable return earned. GBPC’s approved regulated return on rate base was 8.8 per cent for 2016 and 10 per cent for 2015.

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

In December 2016, the GBPA approved that over a five year period, 2017 to 2021, the all-in rate for electricity (fuel and base rates) will be held at 2016 levels. Any over-recovery of fuel costs during this period will be applied to the Hurricane Matthew regulatory deferral, until such time as the deferral is recovered. Should GBPC recover funds in excess of the Hurricane Matthew regulatory deferral, the excess will be placed in a new storm reserve. If balances remain within the Hurricane Matthew deferral at the end of five years, GBPC will have the opportunity to request recovery from customers in future rates.

#### Brunswick Pipeline

Brunswick Pipeline is a 145-kilometre pipeline delivering natural gas from the Canaport™ re-gasified liquefied natural gas (“LNG”) import terminal near Saint John, New Brunswick to markets in the northeastern United States. Brunswick Pipeline entered into a 25-year firm service agreement commencing in July 2009 with Repsol Energy Canada. The pipeline is considered a Group II pipeline regulated by the National Energy Board (“NEB”). The NEB Gas Transportation Tariff is filed by Brunswick Pipeline in compliance with the requirements of the NEB Act and sets forth the terms and conditions of the transportation rendered by Brunswick Pipeline.

Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following:

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As at |  | December 31 |  | December 31
millions of Canadian dollars |  | 2016 |  | 2015
Regulatory assets |  |  |  |
Deferred income tax regulatory assets | $ | 632 | $ | 431
Pension and post-retirement medical plan |  | 373 |  | 12
Environmental remediations |  | 49 |  | -
Unamortized defeasance costs |  | 39 |  | 46
2015 demand side management deferral |  | 32 |  | 36
GBPC Hurricane Matthew restoration |  | 28 |  | -
Stranded cost recovery |  | 27 |  | 28
Debt basis adjustment |  | 19 |  | -
Deferrals related to derivative instruments |  | 15 |  | 68
Cost-recovery clauses |  | 12 |  | -
Deferred bond refinancing costs |  | 9 |  | -
Regulated fuel adjustment mechanism |  | - |  | 14
Other |  | 87 |  | 64
| $ | 1,322 | $ | 699
Current | $ | 80 | $ | 94
Long-term |  | 1,242 |  | 605
Total regulatory assets | $ | 1,322 | $ | 699
Regulatory liabilities |  |  |  |
Accumulated reserve - cost of remova l |  | 990 |  | 94
Deferrals related to derivative instruments |  | 230 | $ | 210
Cost-recovery clauses |  | 153 |  | -
Regulated fuel adjustment mechanism |  | 94 |  | 42
Transmission and delivery storm reserve |  | 75 |  | -
Self-insurance fund (notes 7 and 33) |  | 30 |  | 87
Deferred income tax regulatory liabilities |  | 26 |  | 18
Bill reduction credit (note 4) |  | 10 |  | -
Other |  | 31 |  | 14
| $ | 1,639 | $ | 465
Current | $ | 362 | $ | 112
Long-term |  | 1,277 |  | 353
Total regulatory liabilities | $ | 1,639 | $ | 465

Deferred Income Tax Regulatory Asset and Liability

To the extent deferred income taxes are expected to be recovered from or returned to customers in future rates, a regulatory asset or liability is recognized, unless specifically directed otherwise by a regulator.

Pension and Post-Retirement Medical Plan

This asset is primarily related to the deferred costs of pension and postretirement benefits at Emera Florida and New Mexico. It is included in rate base and earns a rate of return as permitted by the FPSC or NMPRC, as applicable. It is amortized over the remaining service life of plan participants.

Environmental Remediation

This asset is primarily related to Peoples Gas costs associated with the environmental remediation at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement approved by the FPSC.

Unamortized Defeasance Costs

Upon privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities held in trust that provide the principal and interest streams to match the related defeased debt, which as

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at December 31, 2016, totaled $ 0.8 billion (2015 – $0.8 billion). The excess of the cost of defeasance investments over the face value of the related debt is deferred on the balance sheet and amortized over the life of the defeased debt as approved by the UARB.

2015 DSM Deferral

Effective January 1, 2015, NSPI must purchase electricity efficiency and conservation activities (“Program Costs”) from EfficiencyOne, the provincially appointed franchisee to deliver energy efficiency programs to Nova Scotians. The 2015 Program Costs were deferred to a regulatory asset and are recoverable from customers over an eight-year period which began in 2016. The UARB directed EffficiencyOne to review the financing options through which they would borrow the 2015 deferral amount from a commercial lender in order to repay NSPI the amount it expended on behalf of its customers in 2015. On December 2, 2016, EffficiencyOne secured the financing and advanced funds to NSPI to finance the 2015 DSM deferral. This was set up as a payable on the consolidated balance sheet, included in current and long-term other liabilities. As NSPI collects the associated amounts from customers over the next seven years, it will repay the balance to EfficiencyOne thereby reducing the liability. The 2016 annual DSM costs have not been deferred and have been charged to earnings.

Hurricane Matthew Restoration

This asset represents restoration costs incurred by GBPC associated with Hurricane Matthew. The asset is being amortized over five years and is included in rate base. The GBPA has approved full recovery of storm restoration costs.

Stranded Cost Recovery

Due to the decommissioning of a steam turbine in GBPC during 2012, the GBPA approved the recovery of a $21 million USD stranded cost through electricity rates; it is included in rate base for 2016 to 2018.

Debt Basis Adjustment

This asset represents the difference between the fair value and pre-merger carrying amounts for NMGC’s long-term debt on the date TECO Energy acquired NMGC. In accordance with purchase accounting standards, NMGC’s long-term debt was valued at fair value on the Consolidated Balance Sheets. In accordance with the stipulation agreement with the NMPRC, an offsetting regulatory asset was recorded in order to eliminate the effects of purchase accounting on rate payers. The asset does not earn a return and is not included in the regulatory capital structure. It is amortized over the term of the related debt instrument.

Deferrals Related to Derivative Instruments

Tampa Electric, PGS, NMGC, NSPI and GBPC defer changes in fair value of derivatives that are documented as economic hedges or that do not qualify for NPNS exemption, as a regulatory asset or liability. The realized gain or loss is recognized when the hedged item settles in fuel for generation and purchased power or inventory, depending on the nature of the item being economically hedged. Tampa Electric deferrals related to derivative instruments are recovered through cost-recovery mechanisms on a dollar-for-dollar basis in the year following the settlement of the derivative position.

Cost Recovery Clauses

These assets and liabilities are related to FPSC and NMPRC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position.

Deferred Bond Refinancing Costs

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This asset represents Tampa Electric and NMGC past costs associated with refinancing debt. It does not earn a return but is instead included in the capital structure, which is used in the calculation of the weighted average cost of capital used to determine revenue requirements. It is amortized over the term of the related debt instruments.

Fuel Adjustment Mechanism

Differences between actual Fuel Costs and amounts recovered from NSPI customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year. The 2016 FAM liability is recorded as a current FAM liability of $32 million, to be applied in 2017 and a long-term FAM liability of $62 million to be returned to customers during the 2018 through 2019 period as legislated.

Accumulated Reserve – Cost of Removal

This regulatory liability represents the non-ARO Cost of Removal (“COR”) in the accumulated reserve for depreciation of Tampa Electric and NSPI. AROs are costs for legally required removal of property, plant and equipment. Non-ARO COR represent estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as COR are incurred and increased as depreciation is recorded for existing assets and as new assets are put into service. Prior to July 1, 2016, NSPI presented COR as a deduction in the carrying value of property, plant and equipment as part of accumulated depreciation. The total amount reclassified as at December 31, 2015 was $94 million.

Transmission and Delivery Storm Reserve

The storm reserve is for hurricanes and other named storms that cause significant damage to Tampa Electric’s system. Tampa Electric can petition the FPSC to seek recovery of restoration costs over a 12-month period, or longer, as determined by the FPSC, as well as replenish its reserve to the current level. As a result of several named storms including Tropical Storm Colin, Hurricane Hermine and Hurricane Matthew, Tampa Electric incurred $11 million of storm costs in 2016 and 2015. On January 31, 2017, Tampa Electric petitioned the FPSC to seek full recovery of those costs as a surcharge to customers during the five month period ended December 31, 2017.

Bill Reduction Credit

This regulatory liability represents NMGC’s stipulation agreement included a commitment to provide an annual bill reduction credit to customers of $4 million USD per year through June 30, 2018, as part of Emera’s acquisition of TECO Energy.

18. RELATED PARTY TRANSACTIONS

In the ordinary course of business, Emera provides energy, construction and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Inter-company balances and inter-company transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities, as discussed in note 1. All material amounts are under normal interest and credit terms.

Significant transactions between Emera and its associated companies include natural gas transportation capacity revenues from M&NP reported in the Consolidated Statements of Income. Revenues from

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M&NP, reported in Operating revenues, Non-regulated, totaled $ 29 million for the year ended December 31, 2016 (2015 - $23 million).

There are no significant amounts between Emera and its associated companies reported on Emera’s Consolidated Balance Sheets as at December 31, 2016 and 2015.

19. PREPAYMENTS AND OTHER CURRENT ASSETS |  |  |  |
Prepayments and other current assets consisted of the following: |  |  |  |
As at | December 31 | December 31
millions of Canadian dollars |  | 2016 |  | 2015
Capitalized transportation capacity (1) | $ | 190 | $ | 223
Prepaid expenses |  | 57 |  | 18
Due from related parties |  | 16 |  | 2
Net investment in direct financing lease |  | 8 |  | 6
Other |  | 5 |  | 7
| $ | 276 | $ | 256
(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract.

20. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following regulated and non-regulated assets:
As at |  | December 31 | December 31
millions of Canadian dollars | Estimated useful life |  | 2016 |  | 2015
Generation | 3 to 131 | $ | 10,553 | $ | 4,957
Transmission | 28 to 77 |  | 2,799 |  | 1,603
Distribution | 11 to 80 |  | 5,715 |  | 2,503
Gas transmission and distribution | 10 to 85 |  | 2,895 |  | -
General plant and other | 3 to 50 |  | 1,711 |  | 932
Total cost |  |  | 23,673 |  | 9,995
Less: Accumulated depreciation |  |  | (7,787) |  | (3,737)
|  |  | 15,886 |  | 6,258
Construction work in progress |  |  | 1,404 |  | 211
Net book value |  | $ | 17,290 | $ | 6,469

21. EMPLOYEE BENEFIT PLANS

Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, Maine, Connecticut, Massachusetts, Rhode Island, New Mexico, Barbados, Dominica and Grand Bahama Island.

The acquisition of TECO Energy has added three defined benefit pension plans:

· TECO Energy Group Retirement Plan. An ongoing qualified pension plan covering all employees of TECO Energy, Inc. and its affiliates. This plan is a pension equity plan funded solely by employer contributions. There are no employee contributions to this plan.

· TECO Energy Group Supplemental Executive Retirement Plan. An unqualified supplemental executive retirement plan covering certain officers elected by the previous TECO Energy Board of Directors. This plan was historically unfunded, but was funded as a result of Emera’s acquisition of TECO Energy.

· TECO Energy Group Benefit Restoration Plan. An unfunded supplemental executive retirement plan effective January 1, 2016. The plan provides the benefits under the TECO Energy Group

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Retirement Plan formula that would otherwise be restricted as a result of the Internal Revenue Code.

In addition, there are two non-pension benefit plans:

· TECO Energy Post-retirement Health and Welfare Plan. This plan offers retirees under age 65 and their dependents a self-funded health reimbursement account (“HRA”) medical plan identical to that offered to active TECO Energy employees. Retirees over the age of 65 are enrolled in a Medicare Advantage plan.

· New Mexico Gas Company Retiree Medical Plan. This plan offers retirees under age 65 and their dependents a self-funded HRA medical plan identical to that offered to active TECO Energy employees. Retirees over age 65 and their dependents receive a fixed subsidy with which they can purchase additional coverage through a medical supplement program. Dental benefits are provided to retirees and spouses. Plan assets are held in a trust.

The net periodic costs below that relate to TECO Energy reflect purchase accounting at the acquisition date. In accordance with the Company’s accounting policies, unamortized gains and losses and past service costs are recognized in AOCI for TECO Energy’s unregulated companies and as regulatory assets for their regulated companies.

Benefit Obligation and Plan Assets

The changes in benefit obligation and plan assets, and the funded status for all plans were as follows:

For the | Year ended December 31
millions of Canadian dollars | 2016 | 2015
Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO") | Defined benefit pension plans | Non-pension benefit plans | Defined benefit pension plans | Non-pension benefit plans
Balance, January 1 | $ | 1,520 | $ | 88 | $ | 1,470 | $ | 102
Addition of TECO Energy, July 1, 2016 |  | 1,035 |  | 277 |  | - |  | -
Service cost |  | 35 |  | 4 |  | 22 |  | 3
Plan participant contributions |  | 8 |  | - |  | 8 |  | -
Interest cost |  | 79 |  | 9 |  | 59 |  | 4
Plan amendments |  | - |  | 2 |  | - |  | (27)
Benefits paid |  | (94) |  | (16) |  | (61) |  | (6)
Actuarial losses |  | (2) |  | (12) |  | (15) |  | 1
Foreign currency translation adjustment |  | 26 |  | 6 |  | 37 |  | 11
Balance, December 31 |  | 2,607 |  | 358 |  | 1,520 |  | 88
Change in plan assets |  |  |  |  |  |  |  |
Balance, January 1 |  | 1,300 |  | 6 |  | 1,205 |  | 5
Addition of TECO Energy, July 1, 2016 |  | 830 |  | 29 |  | - |  | -
Employer contributions |  | 49 |  | 17 |  | 23 |  | 6
Plan participant contributions |  | 8 |  | - |  | 8 |  | -
Benefits paid |  | (94) |  | (16) |  | (61) |  | (6)
Actual return on assets, net of expenses |  | 93 |  | 2 |  | 96 |  | -
Foreign currency translation adjustment |  | 22 |  | 1 |  | 29 |  | 1
Balance, December 31 |  | 2,208 |  | 39 |  | 1,300 |  | 6
Funded status, end of year | $ | (399) | $ | (319) | $ | (220) | $ | (82)

Plans with PBO/APBO in excess of plan assets

The aggregate financial position for all pension plans where the PBO or, for post-retirement benefit plans, the APBO exceeds the plan assets for the years ended December 31 is as follows:

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millions of Canadian dollars |  |  | 2016 | 2015
| Defined benefit pension plans | Non-pension benefit plans | Defined benefit pension plans | Non-pension benefit plans
PBO/APBO | $ | 2,579 | $ | 358 | $ | 1,489 | $ | 87
Fair value of plan assets |  | 2,171 |  | 39 |  | 1,261 |  | 5
Funded status | $ | (408) | $ | (319) | $ | (228) | $ | (82)

Plans with Accumulated Benefit Obligation (“ABO”) in excess of plan assets

The ABO for the defined benefit pension plans was $2,489 million as at December 31, 2016 (2015 – $1,427 million). The aggregate financial position for those plans with an ABO in excess of the plan assets for the years ended December 31 is as follows:

millions of Canadian dollars | 2016 | 2015
| Defined benefit pension plans | Defined benefit pension plans
ABO | $ | 2,462 | $ | 1,424
Fair value of plan assets |  | 2,171 |  | 1,261
Funded status | $ | (291) | $ | (163)

Balance Sheet

The amounts recognized in the Consolidated Balance Sheets consisted of the following:

As at |  |  |  |  |  | December 31
millions of Canadian dollars | 2016 | 2015
| Defined benefit pension plans | Non-pension benefit plans | Defined benefit pension plans | Non-pension benefit plans
Current liabilities | $ | (41) | $ | (17) | $ | (4) | $ | (3)
Long-term liabilities |  | (367) |  | (302) |  | (224) |  | (79)
Other asset (non-current) |  | 9 |  | - |  | 9 |  | -
Amount included in deferred tax asset |  | 16 |  | (1) |  | 19 |  | (3)
AOCL (AOCI) and regulatory assets after-tax adjustment |  | 620 |  | 45 |  | 330 |  | (9)
Net amount recognized at end of year | $ | 237 | $ | (275) | $ | 130 | $ | (94)

Amounts recognized in AOCI and Regulatory assets

Unamortized gains and losses and past service costs arising on post-retirement benefits are recorded in AOCI or regulatory assets. Unamortized net losses and past service costs as at the acquisition date for TECO Energy’s regulated companies were recorded as regulatory assets. The following table summarizes the change in AOCI and regulatory assets:

| Regulatory assets | Actuarial losses (gains) | Past service (gains) costs
millions of Canadian dollars
Defined Benefit Pension Plans |  |  |  |  |  |
Balance, January 1, 2016 | $ | - | $ | 353 | $ | (4)
Amortized in current period |  | (9) |  | (42) |  | 1
Current year addition to AOCL or regulatory assets |  | 318 |  | 19 |  | -
Balance, December 31, 2016 | $ | 309 | $ | 330 | $ | (3)
Non-pension benefits plans |  |  |  |  |  |
Balance, January 1, 2016 | $ | - | $ | 15 | $ | (27)
Amortized in current period |  | - |  | (2) |  | 8
Current year addition to AOCL (AOCI) or regulatory assets |  | 48 |  | 2 |  | -
Balance, December 31, 2016 | $ | 48 | $ | 15 | $ | (19)

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| 2016 | 2015
| Defined benefit pension plans | Non-pension benefit plans | Defined benefit pension plans | Non-pension benefit plans
Actuarial losses | $ | 330 | $ | 15 | $ | 353 | $ | 15
Past service (gains) |  | (3) |  | (19) |  | (4) |  | (27)
Regulatory assets |  | 309 |  | 48 |  | - |  | -
Total AOCL (AOCI) and regulatory assets on a pre-tax basis |  | 636 |  | 44 |  | 349 |  | (12)
Amount included in deferred tax asset |  | (16) |  | 1 |  | (19) |  | 3
Net amount in AOCL (AOCI) and regulatory assets after-tax adjustment | $ | 620 | $ | 45 | $ | 330 | $ | (9)

Benefit cost components

Emera's net periodic benefit cost included the following:

As at |  |  |  |  |  | Year ended December 31
millions of Canadian dollars | 2016 | 2015
| Defined benefit pension plans | Non-pension benefit plans | Defined benefit pension plans | Non-pension benefit plans
Service cost | $ | 35 | $ | 4 | $ | 22 | $ | 3
Interest cost |  | 79 |  | 9 |  | 59 |  | 3
Expected return on plan assets |  | (97) |  | (1) |  | (65) |  | -
Current year amortization of: |  |  |  |  |  |  |  |
Actuarial losses |  | 42 |  | 2 |  | 48 |  | 1
Past service costs (gains) |  | (1) |  | (8) |  | (1) |  | (6)
Regulatory assets (liability) |  | 9 |  | - |  | - |  | -
Total | $ | 67 | $ | 6 | $ | 63 | $ | 1

The expected return on plan assets is determined based on the market-related value of plan assets of $ 1,180 million as at January 1, 2016 and $859 million as at the acquisition date for TECO Energy (2015 – $1,089 million), adjusted for interest on certain cash flows during the year. The market-related value of assets for TECO Energy was reset to equal the market value of assets as at July 1, 2016. The market-related value of assets is based on a five-year smoothed asset value. Any investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized on a straight-line basis into the market-related value of assets over a five-year period.

Pension Plan Asset Allocations

Emera’s investment policy includes discussion regarding the investment philosophy, the level of risk which the Company is prepared to accept with respect to the investment of the Pension Funds, and the basis for measuring the performance of the assets. Central to the policy is the target asset allocation by major asset categories. The objective of the target asset allocation is to diversify risk and to achieve asset returns that meet or exceed the plan’s actuarial assumptions. The diversification of assets reduces the inherent risk in financial markets by requiring that assets be spread out amongst various asset classes. Within each asset class, a further diversification is undertaken through the investment in a broad basket of investment and non-investment grade securities. Emera’s target asset allocation is as follows:

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Canadian Pension Plans |  |  |  |
Asset Class | Target Range at Market
Short-term securities |  | 0% | to | 5%
Fixed income |  | 35% | to | 50%
Equities: |  |  |  |
Canadian |  | 12% | to | 22%
Non-Canadian |  | 36% | to | 50%

Non-Canadian Pension Plans |  |  |  |
Asset Class | Target Range at Market Weighted average
Short-term securities |  | 0% | to | 2%
Fixed income |  | 40% | to | 48%
Equities |  | 50% | to | 61%

Pension Plan assets are overseen by the respective Management Pension Committees in the sponsoring companies. All pension investments are in accordance with policies approved by the respective Board of Directors of each sponsoring company.

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

As at |  |  |  |  | December 31, 2016
millions of Canadian dollars | NAV | Level 1 | Level 2 | Total | Percentage
Cash and cash equivalents |  | - | $ | 31 |  | - | $ | 31 | 1 | %
Net in-transits |  | - |  | (42) |  | - |  | (42) | (2) | %
Equity Securities: |  |  |  |  |  |  |  |  |  |
Canadian equity |  |  |  | 192 |  |  |  | 192 | 9 | %
US equity |  | - |  | 303 |  | - |  | 303 | 14 | %
Other equity |  | - |  | 243 |  |  |  | 243 | 11 | %
Fixed income securities: |  |  |  |  |  |  |  |  |  |
Government |  | - |  | - | $ | 47 |  | 47 | 2 | %
Corporate |  | - |  | - |  | 53 |  | 53 | 2 | %
Other |  | - |  | 5 |  | 14 |  | 19 | 1 | %
Open-ended investments measured at NAV (1) | $ | 1,132 |  | - |  | - |  | 1,132 | 51 | %
Common collective trusts measured at NAV (2) |  | 230 |  | - |  | - |  | 230 | 11 | %
Total | $ | 1,362 | $ | 732 | $ | 114 | $ | 2,208 | 100 | %
(1) NAV investments are open-ended registered and non-registered mutual funds, collective investment trusts, or pooled funds. NAV’s are calculated daily and the funds honor subscription and redemption activity regularly.
(2) The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain funds invest primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The funds honor subscription and redemption activity regularly.

As at |  |  |  | December 31, 2015
millions of Canadian dollars |  | NAV | Level 1 | Total | Percentage
Cash and cash equivalents |  | - | $ | 12 | $ | 12 | 1 | %
Equity securities: |  |  |  |  |  |  |  |
Canadian equity |  | - |  | 190 |  | 190 | - | %
US equity |  | - |  | 240 |  | 240 | 18 | %
Other equity |  | - |  | 240 |  | 240 | 18 | %
Other investments measured at NAV | $ | 619 |  | - |  | 619 | 48 | %
Total | $ | 619 | $ | 682 | $ | 1,301 | 100 | %

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Refer to note 16 for more information on the fair value hierarchy and inputs used to measure fair value.

Canadian Post-Retirement Benefit Plans

There are no assets set aside to pay for the Canadian post-retirement benefit plans. As is common in Canada, post-retirement health benefits are paid from general accounts as required.

US Post-Retirement Benefit Plans

Emera’s US subsidiaries currently provide certain post-retirement health care and life insurance benefits for employees retiring after age 50 who meet eligibility requirements. Post-retirement benefit levels are substantially unrelated to salary. The company reserves the right to terminate or modify plans in whole or in part at any time.

Emera Maine provides retiree medical benefits to certain groups of employees. The Company's retiree medical expenses are incorporated into rate filings with its regulators and are recovered through its electric rates to customers.

TECO Energy and NMGC offers retirees under age 65 and their dependents a self-funded HRA medical plan identical to that offered to active TECO Energy employees. TECO Energy retirees over the age of 65 are enrolled in a Medicare Advantage plan. NMGC retirees over age 65 and their dependents receive a fixed subsidy with which they can purchase additional coverage through a medical supplement program. NMGC also provides dental benefits to retirees and spouses.

The target asset allocation for the Emera Maine Post-Retirement Benefits Plan is as follows:

Asset Class | Target Range at Market
Short-term securities |  | 10% | to | 50%
Fixed income |  | 0% | to | 40%
Equities: |  |  |  |
US |  | 30% | to | 60%
Non-US |  | 0% | to | 60%

The assets for the NMGC Post-Retirement Benefits Plan are invested in life insurance policies. The life insurance does not mirror any specific employee benefit. The plan can tap into the cash surrender value of the life insurance policies to generate cash to pay retiree medical costs. In addition, as the individuals covered by the life insurance die, the plan receives the life insurance proceeds (less any cash surrender value previously drawn upon) to cover retiree medical costs.

The fair values of investments as at December 31, 2016, for all Post-Retirement Benefit Plans by asset category, are as follows:

174

|  |  |  | December 31,2016
millions of Canadian dollars | NAV | Level 1 | Level 2 | Total | Percentage
Cash and cash equivalents |  | - | $ | 1 | $ | - | $ | 1 | 3 | %
Life insurance policies (1) |  | - |  | - |  | 33 |  | 33 | 85 | %
Other investments measured at NAV | $ | 5 |  | - |  | - |  | 5 | 12 | %
Total | $ | 5 | $ | 1 | $ | 33 | $ | 39 | 100 | %
(1) For valuation purposes, the life insurance policies held for the NMGC retiree medical plan are valued at the cash surrender value and are considered Level 2 assets
|  |  |  | December 31, 2015
millions of Canadian dollars | NAV | Level 1 | Level 2 | Total | Percentage
Cash and cash equivalents |  | - | $ | 1 | $ | - | $ | 1 | 20 | %
Other investments measured at NAV | $ | 4 |  | - |  | - |  | 4 | 80 | %
Total | $ | 4 | $ | 1 | $ | - | $ | 5 | 100 | %

Refer to Note 16 for more information on the fair value hierarchy and inputs used to measure fair value.

Investments in Emera

As at December 31, 2016 and 2015, the assets related to the pension funds and post-retirement benefit plans do not hold any material investments in Emera or its subsidiaries securities. However, as a significant portion of assets for the benefit plan are held in pooled assets, there may be indirect investments in these securities.

Cash Flows

The following table shows the expected cash flows for defined benefit pension and other post-retirement benefit plans:

millions of Canadian dollars | Defined benefit pension plans | Non-pension benefit plans
Expected employer contributions |  |  |  |
2017 | $ | 117 | $ | 25
Expected benefit payments |  |  |  |
2017 |  | 172 |  | 22
2018 |  | 140 |  | 23
2019 |  | 150 |  | 23
2020 |  | 156 |  | 24
2021 |  | 165 |  | 25
2022 – 2026 |  | 912 |  | 130

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Assumptions |  |  |  |  |  |  |  |
The following table shows the assumptions that have been used in accounting for defined benefit pension and other post-retirement benefit plans: |
| 2016 | 2015
(weighted average assumptions) | Defined benefit pension plans | Non-pension benefit plans | Defined benefit pension plans | Non-pension benefit plans
Benefit obligation – December 31: |  |  |  |  |  |  |  |
Discount rate | 3.96 | % | 4.18 | % | 4.02 | % | 4.04 | %
Rate of compensation increase | 2.82 | % | 2.54 | % | 3.07 | % | 3.50 | %
Health care trend - initial (next year) | - |  | 6.78 | % | - |  | 5.50 | %
- ultimate | - |  | 4.45 | % | - |  | 4.20 | %
- year ultimate reached | - |  | 2020 |  | - |  | 2020 |
Benefit cost for year ended December 31: |  |  |  |  |  |  |  |
Discount rate | 3.79 | % | 3.88 | % | 3.99 | % | 3.98 | %
Expected long-term return on plan assets | 6.33 | % | 4.43 |  | 5.91 | % | - |
Rate of compensation increase | 2.88 | % | 2.56 | % | 3.07 | % | 3.50 | %
Health care trend - initial (current year) | - |  | 6.76 | % | - |  | 5.90 | %
- ultimate | - |  | 4.45 | % | - |  | 4.30 | %
- year ultimate reached | - |  | 2020 |  | - |  | 2020 |
Figures shown are weighted averages. Actual assumptions used differ by plan.

The expected long-term rate of return on plan assets is based on historical and projected real rates of return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is determined. The asset return assumption is equal to the overall real rate of return assumption added to the inflation assumption, adjusted for assumed expenses to be paid from the plan.

The discount rate is based on high-quality long-term corporate bonds, with maturities matching the estimated cash flows from the pension plan

Sensitivity Analysis for Non-Pension Benefits Plans

The health care cost trend significantly influences the amounts presented for health care plans. An increase or decrease of one percentage point of the assumed health care cost trend would have had the following impact in 2016:

millions of Canadian dollars | Increase | Decrease
Service cost and interest cost | $ | 1 | $ | (1)
Accumulated post-retirement benefit obligation, December 31 |  | 20 |  | (17)

Sensitivity Analysis for Defined Benefit Pension Plans

The impact on the 2016 benefit cost of a 25 basis point change in the discount rate and asset return assumptions is as follows:

millions of Canadian dollars | Increase | Decrease
Discount rate assumption | $ | (7) | $ | 7
Asset rate assumption |  | (4) |  | 4

176

Amounts to be Amortized in the Next Fiscal Year
The following table shows the amounts from the AOCL and regulatory assets, which are expected to be recognized as part of the net periodic benefit cost in fiscal 2017:
|  | 2017
millions of Canadian dollars | Defined benefit pension plans | Non-pension benefit plans
Actuarial gains (losses) | $ | (53) | $ | (1)
Past service gains |  | 1 |  | 8
Regulatory assets |  | (16) |  | 3
Total | $ | (68) | $ | 10

Defined Contribution Plan

Emera also provides a defined contribution pension plan for certain employees. The Company’s contribution for the year ended December 31, 2016 was $17 million (2015 – $9 million), with the increase due to the acquisition of TECO Energy.

22. NET INVESTMENT IN DIRECT FINANCING LEASE

Emera’s net investment in direct financing lease primarily relates to Brunswick Pipeline. Brunswick Pipeline commenced service on July 16, 2009, transporting re-gasified LNG for Repsol Energy Canada under a 25-year firm service agreement. The agreement meets the definition of a direct financing capital lease for accounting purposes. The net investment in direct financing lease consists of the sum of the minimum lease payments and residual value net of estimated executory costs and unearned income. The unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease. Net investment in direct financing lease consists of the following:

As at | December 31 | December 31
millions of Canadian dollars |  | 2016 |  | 2015
Total minimum lease payments to be received | $ | 1,194 | $ | 1,202
Less: amounts representing estimated executory costs |  | (223) |  | (213)
Minimum lease payments receivable | $ | 971 | $ | 989
Estimated residual value of leased property (unguaranteed) |  | 183 |  | 183
Less: unearned finance lease income |  | (658) |  | (686)
Net investment in direct financing lease | $ | 496 | $ | 486
Principal due within one year (included in “Prepayments and other current assets”) |  | 8 |  | 6
Net investment in direct financing lease – long-term | $ | 488 | $ | 480

Future minimum lease payments to be received for the next five years:
For the | Year ended December 31
millions of Canadian dollars | 2017 | 2018 | 2019 | 2020 | 2021
Minimum lease payments to be received | $ | 65 | $ | 65 | $ | 65 | $ | 65 | $ | 65
Less: amounts representing estimated executory costs |  | (11) |  | (11) |  | (12) |  | (12) |  | (12)
Minimum lease payments receivable | $ | 54 | $ | 54 | $ | 53 | $ | 53 | $ | 53

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23. GOODWILL
The change in goodwill for the year ended December 31 is due to the following:
millions of Canadian dollars |  | 2016 |  | 2015
Balance, January 1 | $ | 264 | $ | 222
Acquisition of TECO Energy as at July 1, 2016 (note 4) |  | 5,771 |  | -
Impairment |  | - |  | -
Change in foreign exchange rate |  | 178 |  | 42
Balance, December 31 | $ | 6,213 | $ | 264

Goodwill on Emera’s balance sheet relates to the acquisitions of TECO Energy (see note 4), Emera Maine and GBPC. Goodwill is subject to an annual assessment for impairment at the reporting unit level. Reporting units are generally determined at the operating segment level or one level below the operating segment level. Emera’s reporting units with goodwill are Tampa Electric, PGS, New Mexico Gas, Emera Maine and GBPC.

Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. If an entity performs the qualitative assessment, but determines that it is more likely than not that its fair value is less than its carrying amount or if an entity bypasses the qualitative assessment, a quantitative two-step, fair value-based test is performed. The first step compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation accounting guidance in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. Emera reviews recorded goodwill at least annually (during the fourth quarter) for each reporting unit, with interim impairment tests performed when impairment indicators are present.

A qualitative assessment was performed for Emera Maine, concluding that the fair value of the reporting unit exceeded its carrying value, and as such, no quantitative assessment was performed. The fair value for GBPC was determined using a discounted cash flow analysis. The fair values for the reporting units acquired in the TECO Energy acquisition (Tampa Electric, PGS, New Mexico Gas) have been preliminarily determined using a weighted combination of a discounted cash flow analysis, a market multiple analysis, and a comparable transactions analysis. The discounted cash flow analysis relies on management’s best estimate of the reporting units’ projected cash flows. It includes an estimate of terminal values based on these expected cash flows using a methodology which derives a valuation using an assumed perpetual annuity based on the entity’s residual cash flows. The discount rate is a market participant rate based on a peer group of publicly traded comparable companies and represents the weighted average cost of capital of comparable companies. The market multiples analysis utilizes multiples of business enterprise value to earnings before interest, taxes, depreciation and amortization (“EBITDA”) of comparable public companies in estimating fair value. The comparable transaction analysis identified comparable company acquisitions within the industry and calculates the implied EBITDA multiple from the transaction, which is then applied to the last-twelve-months EBITDA of the subject company.

Significant assumptions used in estimating the fair value include discount and growth rates, valuation of NOLs, utility sector market performance and transactions, projected operating and capital cash flows and the calculation of the terminal value. In addition to this quantitative analysis, management performed a qualitative assessment in Q4 2016 to ensure that there were no changes in facts or circumstances from the July 1, 2016 acquisition date that would require additional fair value testing for the Tampa Electric, PGS, and New Mexico Gas reporting units.

178

The company determined the fair value of reporting units exceed their book value and related goodwill carrying amounts at December 31, 2016 and December 31, 2015, resulting in no impairment charge. Adverse changes in assumptions described above could result in a future material impairment of the goodwill assigned to Tampa Electric, PGS, New Mexico Gas, Emera Maine and GBPC.

## 24. SHORT-TERM DEBT

Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-revolving credit facilities and short-term notes. Short-term debt and the related weighted-average interest rates as at December 31 consisted of the following:

millions of Canadian dollars | 2016 | Weighted-average interest rate | 2015 | Weighted-average interest rate
TECO Energy/TECO Finance | $ |  |  |  |  |  |  |
Advances on revolving credit and term facilities |  | 685 | 1.74 | % |  | - | - | %
Tampa Electric Company |  |  |  |  |  |  |  |
Advances on accounts receivable and revolving credit facilities |  | 228 | 1.49 | % |  | - | - | %
NMGC |  |  |  |  |  |  |  |
Advances on revolving credit facilities |  | 35 | 1.71 | % |  | - | - | %
NSPI |  |  |  |  |  |  |  |
Bank indebtedness |  | 1 | 2.70 | % |  | 16 | 2.70 | %
GBPC |  |  |  |  |  |  |  |
Advances on revolving credit facilities |  | 12 | 5.75 | % |  | - | - | %
Short-term debt | $ | 961 |  |  | $ | 16 |  |

The Company’s total short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows:
millions of Canadian dollars | Maturity |  | 2016 |  | 2015
TECO Energy/TECO Finance - term credit facility | 2017 |  | 537 | $ | -
TECO Energy/TECO Finance - revolving credit facility | 2018 |  | 403 |  | -
Tampa Electric Company - revolving credit facility | 2018 |  | 436 |  | -
Tampa Electric Company - accounts receivable revolving credit facility | 2018 |  | 201 |  | -
NMGC - revolving credit facility | 2018 |  | 168 |  | -
GBPC - revolving credit facility | 2017 |  | 17 |  | 18
Total |  |  | 1,762 |  | 18
Less: |  |  |  |  |
Advances under revolving credit and term facilities |  |  | 960 |  | -
Letters of credit issued inside credit facilities |  |  | 3 |  | -
Total advances under available facilities |  |  | 963 |  | -
Available capacity under existing agreements |  | $ | 799 | $ | 18

The weighted average interest rate on outstanding short-term debt at December 31, 2016 was 1.73 per cent (2015 – 2.70 per cent).

Credit Facilities

TECO Energy/TECO Finance Term Credit Facility

TECO Energy has a $537 million ($400 million USD) bank credit facility maturing March 14, 2017. Interest rates on the borrowings are based on LIBOR plus a margin. TECO Finance expects to refinance the credit facility before maturity.

179

TECO Energy/TECO Finance Revolving Credit Facility

TECO Energy has a $403 million ($300 million USD) bank credit facility maturing December 17, 2018. Interest rates on the borrowings are based on LIBOR plus a margin.

TEC Credit Facility

TEC has a $436 million ($325 million USD) bank credit facility with a maturity date of December 17, 2018. Interest rates on the borrowings are based on LIBOR plus a margin.

TEC Accounts Receivable Facility

TEC has a $201 million ($150 million USD) accounts receivable collateralized borrowing facility with a maturity date of March 23, 2018. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates. TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding in the case of default. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet.

NMGC Credit Agreement

NMGC has a $168 million ($125 million USD) bank credit facility with a maturity date of December 17, 2018. Interest rates on the borrowings are based on one-month LIBOR plus a margin.

## 25. OTHER CURRENT LIABILITIES

Other current liabilities consisted of the following: |  |  |  |
As at | December 31 | December 31
millions of Canadian dollars |  | 2016 |  | 2015
Accrued charges | $ | 137 | $ | 130
Accrued interest on long-term debt |  | 96 |  | 44
Sales and other taxes payable |  | 16 |  | 4
Accrued interest on convertible debentures represented by instalment receipts (note 8) |  | - |  | 11
Emission credits obligations (1) |  | 10 |  | 6
Other |  | 22 |  | 12
| $ | 281 | $ | 207
(1) Throughout the three-year compliance period associated with the Regional Greenhouse Gas Initiative for carbon dioxide emissions, an obligation is recognized as gas is burned, measured at the cost to acquire credits for the related emissions. Emission credits are capitalized to inventory (note 14) when purchased and subsequently applied against the emission liabilities at the end of each compliance period.

26. L ONG-TERM DEBT

Emera’s long-term debt includes the issuances detailed below. Bonds, notes and debentures are at fixed interest rates and are unsecured unless noted below. Included are certain bankers’ acceptances and commercial paper where the Company has the intention and the unencumbered ability to refinance the obligations for a period greater than one year.

Long-term debt as at December 31, including the debt assumed on the acquisition of TECO Energy, consisted of the following:

180

millions of Canadian dollars | Weighted Average Interest Rate 2016 (1) | Weighted Average Interest Rate 2015 (1) | Maturity | 2016 | 2015 |
Emera |  |  |  |  |  |  |  |
Bankers acceptances, LIBOR loans | Variable | Variable | 2020 | $ | 30 | $ | 240 |
Unsecured fixed rate notes | 3.50% | 3.85% | 2019-2023 |  | 725 |  | 475 |
Fixed to floating subordinated notes (USD) (2) | 6.75% | - | 2076 |  | 1,611 |  | - |
|  |  |  | $ | 2,366 | $ | 715 |
Emera US Finance LP |  |  |  |  |  |  |  |
Unsecured senior notes (USD) (2) | 3.60% | - | 2019 - 2046 | $ | 4,364 | $ | - |
|  |  |  |  | 4,364 |  | - |
TECO Finance (3) |  |  |  |  |  |  |  |
Variable rate notes (USD) | Variable | - | 2018 | $ | 336 | $ | - |
Fixed rate notes and bonds (USD) | 5.86% |  | 2017 - 2020 |  | 805 |  | - |
|  |  |  | $ | 1,141 | $ | - |
Tampa Electric (4) |  |  |  |  |  |  |  |
Fixed rate notes and bonds (USD) | 4.90% | - | 2018 - 2045 | $ | 2,579 | $ | - |
|  |  |  | $ | 2,579 | $ | - |
PGS |  |  |  |  |  |  |  |
Fixed rate notes and bonds (USD) | 5.06% | - | 2018 - 2045 | $ | 351 | $ | - |
|  |  |  | $ | 351 | $ | - |
NMGC |  |  |  |  |  |  |  |
Fixed rate notes and bonds (USD) | 4.53% | - | 2021 - 2026 | $ | 363 | $ | - |
|  |  |  | $ | 363 | $ | - |
NMGI |  |  |  |  |  |  |  |
Fixed rate notes and bonds (USD) | 3.41% | - | 2019 - 2024 | $ | 269 | $ | - |
|  |  |  | $ | 269 | $ | - |
NSPI |  |  |  |  |  |  |  |
Commercial paper | Variable | Variable | 2020 | $ | 264 | $ | 369 |
Medium term fixed rate notes | 5.73% | 5.73% | 2019 - 2097 |  | 1,965 |  | 1,965 |
Fixed rate debenture | 9.75% | 9.75% | 2019 |  | 95 |  | 95 |
Capital lease obligations | 4.80% | 4.58% | 2019 |  | - |  | 1 |
|  |  |  | $ | 2,324 | $ | 2,430 |
Emera Maine |  |  |  |  |  |  |  |
LIBOR loans and demand loans | Variable | Variable | 2019 | $ | 32 | $ | 32 |
Secured fixed rate mortgage bonds (USD) | 9.74% | 9.74% | 2020-2022 |  | 67 |  | 69 |
Unsecured senior fixed rate notes (USD) | 4.28% | 4.31% | 2017-2044 |  | 281 |  | 296 |
|  |  |  | $ | 380 | $ | 397 |
EBP |  |  |  |  |  |  |  |
Senior secured credit facility | 3.08% | 3.08% | 2019 | $ | 248 | $ | 249 |
|  |  |  | $ | 248 | $ | 249 |
GBPC |  |  |  |  |  |  |  |
Unsecured amortizing fixed rate notes (USD) | 3.62% | 3.62% | 2021-2022 | $ | 63 | $ | 77 |
Unsecured senior notes (USD) | 7.07% | 7.07% | 2020-2023 |  | 67 |  | 68 |
|  |  |  | $ | 130 | $ | 145 |
BLPC & ECI |  |  |  |  |  |  |  |
Secured fixed rate senior notes (5) | 5.65% | 5.64% | 2020 - 2028 | $ | 81 | $ | 89 |
Secured senior notes (USD) (6) | Variable | - | 2021 |  | 201 |  | - |
|  |  |  | $ | 282 | $ | 89 |
Adjustments |  |  |  |  |  |  |  |
Fair market value adjustment - TECO Energy acquisition (7) |  |  |  | $ | 58 | $ | - |
Debt issuance costs |  |  |  |  | (111) |  | (16) |
Amount due within one year |  |  |  |  | (476) |  | (274) |
|  |  |  | $ | (529) | $ | (290) |
Long-Term Debt |  |  |  | $ | 14,268 | $ | 3,735 |
(1) Weighted average interest rate of fixed rate long-term debt. |
(2) See below for details on the long-term debt related to the acquisition of TECO Energy. |
(3) TECO Energy is a full and unconditional guarantor of TECO Finance’s securities, and no subsidiaries of TECO Energy guarantee TECO Finance’s securities. |
(4) A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture. |
(5) Notes are issued and payable in either USD, BBD or East Caribbean Dollar (XCD). |
(6) See below for details on the long-term debt issued by ECI in November, 2016. |
(7) On acquisition of TECO Energy, Emera recorded a fair market value adjustment on the unregulated long-term debt acquired. The fair market value adjustment is amortized over the remaining term of the debt. |

181

The Company’s total long-term revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows:
millions of Canadian dollars | Maturity |  | 2016 |  | 2015
Emera – revolving credit facility (1) | June 2020 | $ | 700 | $ | 700
NSPI - revolving credit facility (1) | October 2020 |  | 600 |  | 500
Emera Maine – revolving credit facility | September 2019 |  | 107 |  | 111
BLPC – revolving credit facility | 2017-2021 |  | 26 |  | 26
Total |  |  | 1,433 |  | 1,337
Less: |  |  |  |  |
Borrowings under credit facilities |  |  | 326 |  | 641
Letters of credit issued inside credit facilities |  |  | 37 |  | 33
Use of available facilities |  |  | 363 |  | 674
Available capacity under existing agreements |  | $ | 1,070 | $ | 663
(1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $50 million.

Debt Covenants

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. Emera’s significant covenants are listed below:

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

### Recent Financing Activity

Emera

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

Emera – TECO Energy Acquisition Related Capital Market Transactions

U.S. Notes

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

182

The U.S. Notes issued are as follows:

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

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

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

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

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

Hybrid Notes

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

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

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

Canadian Notes

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

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

NSPI

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

183

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

ECI

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

TECO Finance

On April 10, 2015, TECO Finance completed an offering of $250 million USD aggregate principal amount of floating rate notes due 2018 (“the 2018 Notes”), which are guaranteed by TECO Energy. The 2018 Notes were sold at par and mature on April 10, 2018. The 2018 Notes bear interest at a floating rate that is reset quarterly based on the three-month LIBOR plus 60 basis points. The 2018 Notes are not subject to redemption prior to maturity. The 2018 Notes are effectively subordinated to existing and future liabilities of TECO Energy’s subsidiaries to their respective creditors, and also are effectively subordinated to any secured debt that TECO Finance and TECO Energy incur to the extent of the value of the assets securing that indebtedness.

Tampa Electric

On May 20, 2015, TEC completed an offering of $250 million USD aggregate principal amount of 4.20 per cent notes due May 15, 2045.

Long-Term Debt Maturities

As at December 31, long-term debt maturities, including capital lease obligations, for each of the next five years and in aggregate thereafter are as follows:

millions of Canadian dollars | 2017 |  | 2018 |  | 2019 |  | 2020 |  | 2021 |  | Thereafter |  | Total
Emera | $ | - | $ | - | $ | 225 | $ | 30 | $ | - | $ | 2,111 | $ | 2,366
Emera US Finance LP |  | - |  | - |  | 671 |  | - |  | 1,007 |  | 2,686 |  | 4,364
TECO Energy |  | - |  | 409 |  | 67 |  | - |  | 643 |  | 2,443 |  | 3,562
TECO Finance |  | 403 |  | 335 |  | - |  | 403 |  | - |  | - |  | 1,141
NSPI |  | - |  | - |  | 95 |  | 264 |  | - |  | 1,965 |  | 2,324
Emera Maine |  | 33 |  | 6 |  | 32 |  | 40 |  | - |  | 269 |  | 380
EBP |  | - |  | - |  | 248 |  | - |  | - |  | - |  | 248
GBPC |  | 11 |  | 12 |  | 12 |  | 40 |  | 11 |  | 44 |  | 130
BLPC and ECI |  | 29 |  | 29 |  | 30 |  | 58 |  | 26 |  | 110 |  | 282
Total | $ | 476 | $ | 791 | $ | 1,380 | $ | 835 | $ | 1,687 | $ | 9,628 | $ | 14,797

27. ASSET RETIREMENT OBLIGATIONS

AROs mostly relate to the reclamation of land at the thermal, hydro and combustion turbine sites; and the disposal of polychlorinated biphenyls in transmission and distribution equipment and a pipeline site. Certain hydro, transmission and distribution assets may have additional ARO that cannot be measured as these assets are expected to be used for an indefinite period and, as a result, a reasonable estimate of the fair value of any related ARO cannot be made.

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The change in ARO for the years ended December 31 is as follows:
millions of Canadian dollars | 2016 | 2015
Balance, January 1 | $ | 109 | $ | 106
Additions (1) |  | 48 |  | -
Additions due to acquisition |  | 9 |  | -
Liabilities settled |  | (2) |  | (2)
Accretion included in depreciation expense |  | 7 |  | 8
Accretion deferred to regulatory asset (included in property, plant and equipment) |  | (2) |  | (8)
Other |  | 1 |  | 5
Balance, December 31 | $ | 170 | $ | 109
(1) Tampa Electric produces ash and other by-products known as coal combustion residuals ("CCRs") at its Big Bend and Polk power stations. The 2016 additions to ARO are to achieve compliance with the EPA's CCR rule, which contains design and operating standards for CCR management units. In 2016, the FPSC approved Tampa Electric's proposed CCR compliance program for cost recovery through the Environmental Cost Recovery Clause. However, additional petitions will be submitted for recovery of future project expenses based on engineering studies currently being performed.

As at December 31, 2016 and 2015, some of the Company’s transmission and distribution assets may have additional conditional ARO which are not recognized in the financial statements as the fair value of these obligations could not be reasonably estimated, given there is insufficient information to do so. Management will continue to monitor these obligations and a liability will be recognized in the period in which an amount becomes determinable.

28. COMMITMENTS AND CONTINGENCIES

A. Commitments

As at December 31, 2016, contractual commitments (excluding pensions and other post-retirement obligations, convertible debentures, long-term debt and AROs) 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 |
Purchased power (1) | $ | 253 | $ | 224 | $ | 206 | $ | 202 |  | 198 | $ | 2,272 | $ | 3,355 |
Fuel and gas supply |  | 475 |  | 161 |  | 109 |  | 28 |  | 22 |  | - |  | 795 |
Demand Side Management |  | 42 |  | 48 |  | 13 |  | - |  | - |  | - |  | 103 |
Transportation (2) |  | 496 |  | 392 |  | 310 |  | 280 |  | 196 |  | 1,622 |  | 3,296 |
Long-term service agreements (3) |  | 92 |  | 55 |  | 67 |  | 44 |  | 42 |  | 227 |  | 527 |
Capital projects |  | 133 |  | - |  | - |  | - |  | - |  | - |  | 133 |
Equity investment commitments (4) |  | 236 |  | - |  | - |  | 200 |  | - |  | - |  | 436 |
Leases and other (5) |  | 66 |  | 17 |  | 14 |  | 12 |  | 8 |  | 70 |  | 187 |
| $ | 1,793 | $ | 897 | $ | 719 | $ | 766 | $ | 466 | $ | 4,191 | $ | 8,832 |
(1) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths. |
(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. |
(3) 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. |
(4) Emera has a commitment in connection with the Federal Loan Guarantee ("FLG") to complete construction of the Maritime Link. Thirty per cent of the financing of this project will come from Emera as equity. Emera also has a commitment to make equity contributions to 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. |
(5) Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles. |

In connection with the acquisition of TECO Energy, Emera made certain commitments approved by the NMPRC. See note 4 for additional information.

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

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B. Legal Proceedings

Emera

Between September 16, 2015 and November 2, 2015, purported shareholders of TECO Energy filed 12 separate complaints styled as class action lawsuits in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida or the United States District Court for the Middle District of Florida (the “Merger Litigation”). Each complaint alleges, among other things, that the Board of Directors of TECO Energy breached its fiduciary duties in agreeing to the acquisition agreement and that Emera and/or Emera US Inc. aided and abetted such alleged breaches. The complaints sought to enjoin the merger pursuant to the acquisition agreement.

On November 17, 2015, TECO Energy, Emera, Emera US Inc. and the Board of Directors of TECO Energy entered into a memorandum of understanding with the shareholder plaintiffs to settle all of the Merger Litigation, subject to negotiation of a stipulation of settlement with the plaintiffs and to court approval. The memorandum of understanding provides for all claims against the defendants to be released in exchange for TECO Energy making certain additional disclosures to its shareholders related to the proposed merger, which have now been made.

On December 16, 2016, the judge entered an order and final judgement approving a stipulation of settlement negotiated by the parties, thereby concluding this matter.

Emera Florida and New Mexico

TECO Coal

TECO Coal was sold by TECO Energy on September 21, 2015 to Cambrian Coal Corporation (“Cambrian”), prior to Emera’s acquisition. On March 18, 2016, Cambrian delivered a notice of a purported claim to TECO Diversified. The claim asserted breach of certain representations, and fraud and willful misconduct in connection therewith, of the Securities Purchase Agreement dated September 21, 2015 by and between TECO Diversified and Cambrian related to the purchase of TECO Coal by Cambrian. While the outcome of such matter is uncertain, management does not believe that its ultimate resolution will have a material adverse effect on the Company’s results of operations, financial condition or cash flows.

TECO Guatemala Holdings (“TGH”)

On December 19, 2013, the International Centre for the Settlement of Investment Disputes (“ICSID”) Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, against the Republic of Guatemala (Guatemala) under the Dominican Republic Central America – United States Fee Trade Agreement, issued an award in the case (“the Award”). The ICSID Tribunal unanimously found in favor of TGH and awarded damages to TGH of approximately $21 million USD, plus interest from October 21, 2010 at a rate equal to the U.S. prime rate plus 2 per cent.

On April 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules.

On April 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the ICSID Tribunal’s determination of the amount of TGH’s damages.

On April 5, 2016, an ICSID ad hoc Committee issued a decision in favor of TGH in the annulment proceedings. In its decision, the ad hoc Committee unanimously dismissed Guatemala’s application for annulment of the award and upheld the original $21 million USD award, plus interest. In addition, the ad hoc Committee granted TGH’s application for partial annulment of the award, and ordered Guatemala to

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pay certain costs relating to the annulment proceedings. As a result, TGH had the right to resubmit its arbitration claim against Guatemala to seek additional damages (in addition to the previously awarded $21 million USD), as well as additional interest on the $21 million USD, and its full costs relating to the original arbitration and the new arbitration proceeding.

On September 23, 2016, TGH filed a request for resubmission to arbitration. On October 3, 2016, ICSID issued a notice of registration for TGH’s request for resubmission. TGH and Guatemala have each selected an arbitrator and ICSID has recently selected a President for the new tribunal. Results to date do not reflect any benefit.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a potentially responsible party (“PRP”) for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as at December 31, 2016, TEC has estimated its ultimate financial liability to be $ 43 million ($32 million USD), primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs. Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings. The FPSC has approved, as part of the PGS depreciation settlement as discussed in note 17, an agreement to accelerate the amortization of the regulated asset associated with this reserve.

Emera Maine

On September 30, 2011, a group including the Attorney General of Massachusetts, New England utilities commissions, state public advocates and end users filed a complaint with the FERC alleging that the 11.14 per cent base ROE under the ISO-New England (“ISO-NE”) Open Access Transmission Tariff (“OATT”) was unjust and unreasonable.

On June 19, 2014, the FERC issued an order in connection with this complaint that changed the methodology used to set the ROE and resulted in a lower base transmission ROE of 10.57 per cent and a lower total ROE (inclusive of incentive adders) of 11.74 per cent for the period of October 1, 2011 to December 31, 2012. The ROE was confirmed by FERC in two subsequent orders and has now been appealed to the U.S. Court of Appeals for the DC Circuit. The Court has decided to hold the appeal of this case in abeyance pending the outcome of the ENE Case and MA AG II Case discussed below.

On June 30, 2016, Emera Maine completed the processing of refunds to customers to reflect the 10.57 per cent ROE.

On December 27, 2012, a second group of consumer advocates, including Environment Northeast, filed a complaint with the FERC on similar grounds, arguing that the 11.14 per cent base ROE under the OATT was unjust and unreasonable (“the ENE Case”). This complaint applies to the period from January 1,

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2013 to March 31, 2014. On July 31, 2014, a group of state commissions, state public advocates and end users filed a third complaint with the FERC on similar grounds (“the MA AG II Case”) in relation to the period from July 31, 2014 to October 31, 2015. The ENE Case and MA AG II Case were subsequently consolidated by FERC into a single case.

On March 22, 2016, a FERC Administrative Law Judge (“ALJ”) issued a recommended decision to FERC with respect to the consolidated cases. The recommendation for the ENE Case was a 9.59 per cent base ROE, with a 10.42 per cent maximum ROE, and the recommendation for the MA AG II Case was a 10.90 per cent base ROE, with a 12.19 per cent maximum ROE. The ALJ’s recommended decision is not definitive and FERC has the ability to adjust the ALJ’s recommended decision. A decision by FERC is not expected until early 2017.

On April 29, 2016, an additional complaint was filed with FERC challenging the ROE under the ISO-NE transmission tariff. The complaint was filed by the Eastern Massachusetts Consumer-Owned Systems (“EMCOS”), a collection of thirteen municipal light departments, seeking to reduce the base ROE to 8.61 per cent and the maximum ROE to 11.24 per cent for the period April 29, 2016 to July 29, 2017.

Emera Maine has recorded a reserve of $5 million pre-tax ($ 4 million USD) (December 31, 2015 - $7 million or $ 5 million USD) for the ENE Case and MA AG II Case. The reserves recorded for these complaints have been recorded as “Regulatory Liabilities” on the Consolidated Balance Sheets and as a reduction to “Operating revenues – regulated electric” on the Consolidated Statements of Income. The reserve was calculated on a 10.57 per cent base and represents Emera Maine’s best estimate of the probable outcome. No update has been made to the reserve as a result of the ALJ recommendation as it is pending approval by the FERC and is considered uncertain until that time. No reserve has been made as a result of the EMCOS complaint, as the outcome is considered uncertain.

Other Legal Proceedings

Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company.

C. Environment

Emera’s activities are subject to a broad range of federal, provincial, state, regional and local laws and environmental regulations, designed to protect, restore and enhance the quality of the environment including air, water and solid waste. Emera estimates its environmental capital expenditures, excluding AFUDC, based upon present environmental laws and regulations. Amounts that have been committed to are included in “Capital projects” in the commitments table in note 28 A. The estimated expenditures do not include costs related to possible changes in the environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and other pollutant emissions.

Emera Florida and New Mexico

Tampa Electric operates fossil fuel burning power plants with air emissions regulated by the Clean Air Act and material Clean Water Act implications and impacts by federal and state legislative initiatives. Tampa Electric has achieved the emission-reduction levels called for in Phase I and Phase II of Clean Air Interstate Rule (“CAIR”) and these expenses were rate recoverable under the Florida environmental cost recovery clause (“ECRC”) as approved by the FPSC. Similarly, future expenses should be eligible for recovery upon petition by Tampa Electric and approval by the FPSC. On July 7, 2011, EPA released its final CAIR-replacement rule, called Cross-State Air Pollution Rule (“CSAPR”). An update to CSAPR was finalized on October 26, 2016 and will be implemented in 2017. Based on updated EPA modeling and favorable consideration of atmospheric dynamics, Florida is no longer subject to CSAPR requirements. However, Florida (including Tampa Electric power plants) could be subject to a future version of CSAPR

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as a result of an expected update triggered by compliance with the more stringent 2015 ozone standard or ongoing litigation related to current rule applicability.

NSPI

NSPI’s activities are subject to a broad range of federal, provincial, regional and local laws and environmental regulations, designed to protect, restore and enhance the quality of the environment including air, water and solid waste.

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

In March 2016, Canada’s First Ministers issued the “Vancouver Declaration” on clean growth and climate change. First Ministers agreed to develop a Pan-Canadian Framework and implement it by early 2017. Four working groups, comprised of federal, provincial and territorial officials were established to provide recommendations and research to the Federal government.

NSPI provided input into this process through the Nova Scotia government, the Government of Canada and directly to the working groups through the submission of a discussion paper.

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

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

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

Carbon pricing component

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

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

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

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

Accelerated phase out of coal component

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

On December 9, 2016, the Government of Canada and eight provinces (including Nova Scotia) signed the Pan Canadian Framework on Clean Growth and Climate Change. The Government of Canada has committed to ensuring that the provinces and territories have the flexibility to design their own policies and programs to meet emission-reduction targets, supported by federal investments in infrastructure, specific emission-reduction opportunities and clean technologies. Details under the agreements are expected to be finalized by the end of 2017. NSPI anticipates that any costs prudently incurred to

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achieve the legislated reductions would be recoverable from customers under NSPI’s regulatory framework. NSPI will continue to work with both the Province of Nova Scotia and the Government of Canada as the details of the agreements are finalized and to advance solutions that are in the best interest of customers.

The Government of Canada has indicated their intention to resume discussions regarding Base Level Industrial Emission Requirements (”BLIER”s) for sulphur dioxide and nitrogen dioxide and have outlined their intention to develop a Clean Energy Standard for natural gas and possibly diesel. The details of both processes are not yet known. NSPI will participate in these processes in 2017.

NSPI estimates its environmental capital expenditures, excluding AFUDC, based upon present environmental laws and regulations will be approximately $ 41 million during fiscal 2017 and are estimated to be $41 million from 2018 through 2021. Amounts that have been committed to are included in “Capital projects” in the commitments table in note 28 A.

Conformance with legislative and NSPI internal requirements is verified through a comprehensive environmental audit program. There were no significant environmental or regulatory compliance issues identified during the audits completed to December 31, 2016.

Polychlorinated Biphenyl Equipment

In response to the Canadian Environmental Protection Act 1999, 2008 Polychlorinated Biphenyl (“PCB”) Regulations to phase out electrical equipment and liquids containing PCBs, NSPI has implemented a program to eliminate transformers and other oil-filled electrical equipment on its system that fall under the 2008 PCB Regulations Standard by the end of 2025. This also includes PCB contaminated pole mounted transformers. The combined total cost of these projects is estimated to be $43 million and, as at December 31, 2016, approximately $ 28 million (December 31, 2015 – $20 million) has been spent to date. NSPI has recognized an ARO on the balance sheet of $11 million as at December 31, 2016 (December 31, 2015 – $15 million) associated with the PCB phase-out program.

Emera Energy Emissions

The NEGG Facilities are subject to the RGGI for carbon dioxide emissions and the Acid Rain Program for sulphur dioxide emissions. The NEGG Facilities emit approximately two million tons of carbon dioxide per year. The amount of sulphur dioxide emitted is not considered significant. Changes to these emissions programs could adversely impact financial and operational performance.

D. Principal Risks and Uncertainties

In this section, Emera describes some of the principal risks management believes could materially affect Emera’s business, revenues, operating income, net income, net assets or liquidity or capital resources in the near term. The nature of risk is such that no list can be comprehensive, and other risks may arise, or risks not currently considered material may become material in the future.

Sound risk management is an essential discipline for running the business efficiently and pursuing the Company’s strategy successfully. Emera has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach to risk management.

Regulatory and Political Risk

The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of the recovery of costs and investments. As cost-of-service utilities with an obligation to serve customers, Tampa Electric, PGS, NMGC, NSPI, Emera Maine, BLPC, GBPC, and Domlec must obtain regulatory approval to change electricity rates and/or riders from their respective regulators. Costs and investments can be recovered upon approval by the respective regulator as an adjustment to rates and/or riders, which normally requires a public hearing process or may be mandated by other

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governmental bodies. In addition, the commercial and regulatory frameworks under which Emera and its subsidiaries operate can be impacted by significant shifts in government policy (including shifts in policy which could occur as a result of climate change concerns) and changes in governments. Emera’s investments in entities in which it has significant influence and which are subject to regulatory risk include: NSPML, LIL, M&NP and Lucelec.

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

Weather and Climate Risk

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

Changes in Environmental Legislation

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

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

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

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

Foreign Exchange Risk

The Company is exposed to foreign currency exchange rate changes. Emera operates globally, with an increasing amount of the Company’s adjusted net income earned outside of Canada. As such, Emera is

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exposed to movements in exchange rates between the Canadian dollar and, particularly, the US dollar, which could positively or adversely affect results.

Consistent with the Company’s risk management policies, Emera manages currency risks through matching US denominated debt to finance its US operations and uses short-term foreign currency derivative instruments to hedge specific transactions. The Company enters into foreign exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenues streams, capital expenditures and capital projects. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs, including foreign exchange.

The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes, or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries are included in AOCI.

Capital Market and Liquidity Risk

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

Emera is subject to financial risk associated with changes in its credit ratings. There are a number of factors that rating agencies evaluate to determine credit ratings, including the company’s business and regulatory framework, the ability to recover costs and earn returns, diversification, leverage, and liquidity. A change to a credit rating as a result of changes in any of these items could result in higher interest rates in future financings, increase borrowing costs under certain existing credit facilities, limit access to the commercial paper market or limit the availability of adequate credit support for subsidiary operations.

Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs will be financed through internally generated cash flows, short-term credit facilities, and ongoing access to capital markets. The Company reasonably expects liquidity sources to exceed ordinary course capital needs.

Interest Rate Risk

Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter into interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt.

For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt costs are recovered from customers. While regulatory ROE will generally follow the direction of interest rates, such that regulatory ROE’s are likely to fall in times of reducing interest rates and raise in times of increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development and acquisition initiatives.

Commercial Relationships Risk

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

Commodity Price Risk

A large portion of the Company’s fuel supply comes from international suppliers and is subject to commodity price risk. The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks. Fuel contracts may be exposed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk through the use of financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable. In addition, the adoption and implementation of fuel adjustment mechanisms in its rate-regulated subsidiaries has further helped manage this risk, as the regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred fuel costs.

Income Tax Risk

The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in Canada, the United States and the Caribbean. Any such changes could affect the Company’s future earnings, cash flows, and financial position. The value of Emera’s existing deferred tax benefits are determined by existing tax laws and could be negatively impacted by changes in laws. “Comprehensive tax reform” remains a topic of discussion in the U.S. Congress. Such legislation could significantly alter the existing tax code, including a reduction in the corporate income tax rate. Although a reduction in the corporate income tax rate could result in lower future tax expense and tax payments, it would also reduce the value of the Company’s existing deferred tax assets and could result in a charge to earnings if written down. Emera monitors the status of existing tax laws to ensure that changes impacting the Company are appropriately reflected in the Company’s tax compliance filings and financial results.

E. Guarantees and Letters of Credit

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

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

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

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

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

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

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

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

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

Collaborative Arrangements

For the years ended December 31, 2016 and 2015, the Company has identified the following material collaborative arrangements:

Through NSPI, the Company is a participant in three wind energy projects in Nova Scotia. The percentage ownership of the wind project assets is based on the relative value of each party’s project assets by the total project assets. NSPI has power purchase arrangements to purchase the entire net output of the projects and, therefore, NSPI’s portion of the revenues are recorded net within regulated fuel for generation and purchased power. NSPI’s portion of operating expenses is recorded in operating, maintenance and general (“OM&G”) expenses. In 2016, NSPI recognized $18 million net expense (2015 - $10 million) in “Regulated fuel for generation and purchased power” and $5 million (2015 - $2 million) in “OM&G”.

29. CUMULATIVE PREFERRED STOCK

Authorized:
Unlimited number of First Preferred shares, issuable in series.
Unlimited number of Second Preferred shares, issuable in series.
|  |  |  |  |  |  |  | December 31, 2016 |  | December 31, 2015
Annual Dividend |  | Redemption |  | Issued and |  | Net |  | Issued and |  | Net
| Per Share |  | Price per share |  | Outstanding |  | Proceeds |  | Outstanding |  | Proceeds
Series A | $ | 0.6388 |  |  | $ | 25.00 |  | 3,864,636 |  | $ | 95 |  | 3,864,636 |  | $ | 95
Series B |  | Floating |  |  | $ | 25.00 |  | 2,135,364 |  | $ | 52 |  | 2,135,364 |  | $ | 52
Series C | $ | 1.0250 |  |  | $ | 25.00 |  | 10,000,000 |  | $ | 245 |  | 10,000,000 |  | $ | 245
Series E | $ | 1.1250 |  |  | $ | 26.00 |  | 5,000,000 |  | $ | 122 |  | 5,000,000 |  | $ | 122
Series F | $ | 1.0625 |  |  | $ | 25.00 |  | 8,000,000 |  | $ | 195 |  | 8,000,000 |  | $ | 195
Total |  |  |  |  | $ |  |  | 29,000,000 |  | $ | 709 |  | 29,000,000 |  | $ | 709

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On August 17, 2015, Emera announced that 2,135,364 of its 6,000,000 issues and outstanding Series A Shares were tendered for conversion, on a one-for-one basis into Cumulative Floating Rate First Preferred Shares, Series B (the “Series B Shares”). As a result of the conversion, Emera has 3,864,636 Series A Shares and 2,135,364 Series B Shares issued and outstanding. The 2016 dividends for the Series A and Series B shares were $0.6388 per share and $ 0.5724 respectively.

The First Preferred Shares, Series A, C and F are entitled to receive fixed cumulative cash dividends as and when declared by the Board of Directors of the Corporation in the amounts of $0.6388 , $1.025 and $ 1.0625 per share per annum, respectively for each year up to and excluding August 15, 2020, August 15, 2018, and February 15, 2020, respectively. As at August 15, 2020, August 15, 2018, and February 15, 2020, the holders of the First Preferred Shares Series A, C and F, respectively, are entitled to receive reset fixed cumulative cash dividends. The reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate of the First Preferred Shares, Series A, C and F, respectively, which is the sum of the five-year Government of Canada Bond-Yield on the application reset date plus 1.84 per cent, 2.65 per cent, and 2.63 per cent, respectively.

The First Preferred Shares, Series B, are entitled to receive floating rate cumulative cash dividends, as and when declared by the Board of Directors of the Corporation in the amount determined by multiplying $25.00 by the three month Government of Canada Treasury Bill rate plus 1.84 per cent.

The First Preferred Shares, Series E, are entitled to receive fixed rate cumulative cash dividends, as and when declared by the Board of Directors of the Corporation in the amount $1.1250 per share per annum.

The holders of First Preferred Shares, Series A, C and F will have the right, at their option, to convert their shares into an equal number of Cumulative Floating Rate First Preferred Shares, Series B, D, and G, of the Company, respectively, on August 15, 2020 August 15, 2018, and February 15, 2020, respectively, and every five years thereafter.

The holders of the First Preferred Shares, Series B will have the right, at their option, to convert their shares into an equal number of Series A shares of the Company on August 15, 2020 and every five years thereafter.

The Company has the right to redeem the outstanding Preferred Shares, Series A, C, and F shares without the consent of the holder on August 15, 2020, August 15, 2018, and February 15, 2020 respectively and on August 15, August 15 and February 15 respectively every five years thereafter for cash, in whole or in part at a price of $ 25.00 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption.

The Company has the right to redeem the outstanding Preferred Shares, Series B, Series D and Series G shares without the consent of the holder on August 15, 2020, August 15, 2023 and February 15, 2025 respectively and on August 15, August 15 and February 15 every five years thereafter for cash, in whole or in part at a price of $ 25.00 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption and $ 25.50 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on any other date after August 15, 2015, August 15, 2018 and February 15, 2020, respectively.

The Company has the right to redeem the outstanding First Preferred Shares, Series E on or after August 15, 2018 in whole or in part, at the Company’s option, by the payment in cash of $26.00 per Series E Preferred Share if redeemed prior to August 15, 2019; at $25.75 per Series E Preferred Share if redeemed on or after August 15, 2019, but prior to August 15, 2020; at $25.50 per Series E Preferred Share if redeemed on or after August 15, 2020, but prior to August 15, 2021; at $25.25 per Series E Preferred Share if redeemed on or after August 15, 2021, but prior to August 15, 2022; and at $ 25.00 per Series E Preferred Share if redeemed on or after August 15, 2022, in each case together with all accrued and unpaid dividends up to but excluding the date fixed for redemption.

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As the First Preferred Shares, Series A, B, C, E and F are neither redeemable at the option of the shareholder nor have a mandatory redemption date, they are classified as equity and the associated dividends will be deducted on the consolidated statements of earnings immediately before arriving at “Net earnings attributable to common shareholders” and will be shown on the consolidated statement of equity as a deduction from retained earnings.

The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary.

In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First Preferred Shares, the holders of the First Preferred Shares will be entitled to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at any such meeting.

30. NON-CONTROLLING INTEREST IN SUBSIDIARIES
Non-controlling interest in subsidiaries consisted of the following:
As at | December 31 | December 31
millions of Canadian dollars |  | 2016 |  | 2015
ICDU | $ | 53 | $ | 52
Preferred shares of GBPC |  | 34 |  | 34
Domlec |  | 25 |  | 23
ECI (1) |  | - |  | 25
| $ | 112 | $ | 134
(1) On December 17, 2015, an indirect wholly owned subsidiary of Emera acquired approximately 2.6 million ECI shares, increasing its ownership interest from 80.7 per cent to 95.5 per cent. On March 22, 2016, an indirect wholly-owned subsidiary of Emera acquired 0.7 million ECI shares (which owns 51.9 per cent share of Domlec), increasing Emera's ownership interest in ECI from 95.5 to 100 per cent.

Preferred shares of GBPC:
Authorized:
35,000 non-voting cumulative redeemable variable perpetual preferred shares
| 2016 | 2015
Issued and outstanding: | number of shares |  | millions of dollars | number of shares |  | millions of dollars
Outstanding as at December 31 | 35,000 | $ | 34 | 35,000 | $ | 34

GBPC Non–Voting Cumulative Variable Perpetual Preferred Stock:

The Preferred Stock is redeemable by GBPC, in whole at any time or in part from time to time, at $1,000 Bahamian per share plus accrued and unpaid dividends.

The Preferred Stock is entitled to a 7.25 per cent per annum fixed cumulative preferential dividend for years 2013 through 2016, 8.50 per cent per annum fixed cumulative preferential dividend for years 2017 through 2019 and 10.00 per cent per annum fixed cumulative preferential dividend after 2020, as and when declared by the Board of Directors, accruing from the date of issue.

The Preferred Shares rank behind all of GBPC’s current and future secured and unsecured debt with any of GBPC’s future preferred stock and ahead of all of GBPC’s current and future common stock.

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31. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS

For the | Year ended December 31
millions of Canadian dollars |  | 2016 |  | 2015
Changes in non-cash working capital: |  |  |  |
Receivables, net | $ | (104) | $ | (19)
Income taxes receivable |  | (23) |  | (22)
Inventory |  | 88 |  | (2)
Prepayments and other current assets |  | (18) |  | 9
Accounts payable and customer deposits |  | 162 |  | (45)
Income taxes payable |  | 14 |  | (32)
Other current liabilities |  | 15 |  | 9
Total non-cash working capital |  | 134 |  | (102)
Supplemental disclosure of cash paid (received): |  |  |  |
Interest | $ | 480 | $ | 196
Income taxes | $ | 57 | $ | 124
Supplemental disclosure of non-cash activities: |  |  |  |
Common share dividends reinvested | $ | 103 | $ | 78
Beneficial Conversion Feature of the convertible debentures | $ | 43 | $ | -

32. S TOCK-BASED COMPENSATION

EMPLOYEE COMMON SHARE PURCHASE PLAN AND COMMON SHAREHOLDERS DIVIDEND REINVESTMENT AND SHARE PURCHASE PLAN

Eligible employees may participate in Emera’s Employee Common Share Purchase Plan to which employees make cash contributions of a minimum of $25 to a maximum of $ 8,000 per year for the purpose of purchasing common shares of Emera. The Company also contributes to the plan a percentage of the employees’ contributions. If an employee contributes any amount up to $3,000 to employees plan account, the Company will contribute 20 per cent of that amount. When an employee contributes any amount over $3,000, up to the $8,000 maximum, the Company will contribute 10 per cent of that amount.

The plan allows the reinvestment of dividends. The maximum aggregate number of Emera common shares reserved for issuance under this plan is 4 million common shares.

The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan (“Dividend Reinvestment Plan”), which provides an opportunity for shareholders to reinvest dividends and for the purpose of purchasing common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividend.

Compensation cost for shares issued by Emera for the year ended December 31, 2016 under the Employee Common Share Purchase Plan was $1 million (2015 – $1 million) and is included in “Operating, maintenance and general” on the Consolidated Statements of Income.

STOCK-BASED COMPENSATION PLANS

Stock Option Plan

The Company has a stock option plan that grants options to senior management of the Company for a maximum term of ten years. The option price of the stock options is the closing market price of the stocks

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on the day before the option is granted. The maximum aggregate number of shares issuable under this plan is 11.7 million shares.

All options granted to date are exercisable on a graduated basis with up to 25 per cent of options exercisable on the first anniversary date and further 25 per cent increments on each of the second, third and fourth anniversaries of the grant. If an option is not exercised within ten years, it expires and the optionee loses all rights thereunder. The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted.

If, before the expiry of an option in accordance with its terms, the optionee ceases to be an eligible person due to retirement or termination for other than just cause, such option may, subject to the terms thereof and any other terms of the plan, be exercised at any time within the 24 months following the date the optionee retires, but in any case prior to the expiry of the option in accordance with its terms.

If, before the expiry of an option in accordance with its terms, the optionee ceases to be an eligible person due to employment termination for just cause, resignation or death, such option may, subject to the terms thereof and any other terms of the plan, be exercised at any time within the six months following the date the optionee is terminated, resigns or dies, as applicable, but in any case prior to the expiry of the option in accordance with its terms.

The Company uses the fair value based method to measure the compensation expense related to its stock-based compensation and recognizes the expense over the vesting period on a straight-line basis. The fair value of stock option awards granted was estimated on the date of grant using a Black-Scholes valuation model. The expected term of the option awards is calculated based on historical exercise behaviour and represents the period of time that options are expected to be outstanding. The risk-free interest rate is based on the Bank of Canada five-year government bond yields. The expected dividend yield incorporates current dividend rates as well as historical dividend increase patterns. Emera’s expected stock price volatility was estimated using its five-year historical volatility.

The following table shows the weighted average fair values per stock option along with the assumptions incorporated into the valuation models for options granted:

For the year ended December 31, | 2016 | 2015
Weighted average fair value per option | $ | 2.80 | $ | 2.66
Expected term |  | 5 years |  | 5 years
Risk-free interest rate |  | 0.66 | % |  | 0.73 | %
Expected dividend yield |  | 4.08 | % |  | 3.65 | %
Expected volatility |  | 15.45 | % |  | 14.58 | %

The following table summarizes information related to the stock options for 2016:

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| Total Options |  | Non-Vested Options(1)
| Number of Options | Weighted average exercise price per share |  | Number of Options | Weighted average grant date fair-value
Outstanding as at December 31, 2015 | 2,927,068 | $ | 33.07 |  | 1,453,486 | $ | 2.64
Granted | 615,100 |  | 46.19 |  | 615,100 |  | 2.80
Exercised | (622,168) |  | 25.65 |  | N/A |  | N/A
Forfeited | - |  | - |  | (548,461) |  | 2.68
Options outstanding December 31, 2016 | 2,920,000 | $ | 37.42 |  | 1,520,125 | $ | 2.69
Options exercisable December 31, 2016 (2)(3) | 1,399,875 | $ | 33.35 |  |  |  |
(1) As at December 31, 2016 there was $3 million of unrecognized compensation related to stock options not yet vested which is expected to be recognized over a weighted average period of approximately 2.4 years (2015 - $3 million, 2.3 years).
(2) As at December 31, 2016, the weighted average remaining term of vested options was 5.7 years with an aggregate intrinsic value of $17 million (2015 - 5.3 years, $21 million).
(3) As at December 31, 2016 the fair value of options that vested in the year was $2 million (2015 - $1 million).

Compensation cost recognized for stock options for the year ended December 31, 2016 was $2 million (2015 – $1 million), which is included in “Operating, maintenance and general” on the Consolidated Statements of Income.

As at December 31, 2016, cash received from option exercises was $16 million (2015 – $2 million). The total intrinsic value of options exercised for the year ended December 31, 2016 was $13 million (2015 – $1 million). The range of exercise prices for the options outstanding as at December 31, 2016 was $20.42 to $46.19 (2015 – $19.88 to $42.71).

Share Unit Plans

The Company has deferred share unit (“DSU”) and performance share unit (“PSU”) plans. The DSU and PSU liabilities are marked-to-market at the end of each period based on the common share price at the end of the period.

Deferred Share Unit Plans

Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one Emera common share. When a dividend is paid on Emera’s common shares, referred to as the Dividend Reinvestment Plan (“DRIP”), the Director’s DSU account is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common share at the time of redemption, pursuant to the plan. Following retirement or resignation from the board, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the average of Emera’s stock closing price during the ten trading days ending on the tenth trading day prior to the payment date.

Under the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their annual incentive award in the form of DSUs with the understanding, for participants who are subject to executive share ownership guidelines, a minimum of 50% of the value of their actual annual incentive award ( 25% in the first year of the program) will be payable in DSUs until the applicable guidelines are met.

When incentive awards are determined, the amount elected is converted to DSUs, which have a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s common shares, each participant’s DSU account is allocated additional DSUs equal in value to the dividends paid on an equivalent number of Emera common shares. Following termination of employment or retirement, and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited

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to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Payments are usually made in cash. At the sole discretion of the Management Resources and Compensation Committee (“MRCC”), payments may be made in the form of actual shares.

In addition, special DSU awards may be made from time to time by the MRCC to selected executives and senior management to recognize singular achievements or to achieve certain corporate objectives.

A summary of the activity related to employee and director DSUs for the year ended December 31, 2016 is presented in the following table:

| Employee DSU |  | Weighted Average Grant Date Fair Value | Director DSU |  | Weighted Average Grant Date Fair Value
Outstanding as at December 31, 2015 | 606,646 | $ | 26.27 | 362,750 | $ | 31.36
Granted including DRIP | 74,855 |  | 37.60 | 69,429 |  | 43.67
Exercised | (570) |  | 46.58 | (36,381) |  | 27.42
Outstanding and exercisable as at December 31, 2016 | 680,931 | $ | 27.50 | 395,798 | $ | 33.88

Compensation cost recognized for employee and director DSU for the year ended December 31, 2016 was $ 8 million (2015 – $8 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2016 were $3 million (2015 – $3 million); $nil was offset with regulatory assets and regulatory liabilities (2015 – $1 million).

Performance Share Unit Plan

Under the PSU plan, executive and senior employees are eligible for long-term incentives payable through the PSU plan. PSUs are granted annually for three-year overlapping performance cycles. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Dividend equivalents are awarded and are used to purchase additional PSUs, also referred to as DRIP. The PSU value varies according to the Emera common share market price and corporate performance.

PSUs vest at the end of the three-year cycle and will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and will be pro-rated in the case of retirement, disability or death.

A summary of the activity related to employee PSUs for the year ended December 31, 2016 is presented in the following table:

| Employee PSU |  | Weighted Average Grant Date Fair Value |  | Aggregate intrinsic value
Outstanding as at December 31, 2015 | 497,496 | $ | 34.50 | $ | 21.5
Granted including DRIP | 280,950 |  | 40.60 |  |
Exercised | (208,999) |  | 34.39 |  |
Forfeited | (8,567) |  | 37.54 |  |
Outstanding as at December 31, 2016 | 560,880 | $ | 37.55 | $ | 25.5

Compensation cost recognized for the PSU plan for the year ended December 31, 2016 was $11 million (2015 – $10 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2016 were $4 million (2015 – $3 million).

33. VARIABLE INTEREST ENTITIES

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The Company performs ongoing analysis to assess whether it holds any variable interest entities (“VIEs”). To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly owned facilities.

VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera is not deemed the primary beneficiary, the VIE is accounted for using the equity method.

For the years ended, December 31, 2016 and 2015, the Company has identified the following material VIEs:

Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have the controlling financial interest of NSPML. In Q2 2014, when the critical milestones were achieved, Nalcor Energy was deemed the beneficiary of the asset for financial reporting purposes as they have authority over the majority of the direct activities that are expected to most significantly impact the economic performance of the Maritime Link Project. Thus, Emera began recording the Maritime Link Project as an equity investment.

BLPC has established a Self-Insurance Fund primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, the activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s consolidated VIE in the SIF is recorded as an “Investment securities”, “Restricted cash” and “Regulatory liabilities”.

The Company has identified certain long-term purchase power agreements that meet the definition of variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.

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

As at |  | December 31, 2016 |  | December 31, 2015
|  |  | Maximum |  |  | Maximum
millions of Canadian dollars |  | Total assets | exposure to loss |  | Total assets | exposure to loss
Unconsolidated VIEs in which Emera has variable interests |  |  |  |  |  |  |  |
NSPML (equity accounted) | $ | 315 | $ | 577 | $ | 188 | $ | 1,007

34. COMPARATIVE INFORMATION

These financial statements contain certain reclassifications of prior period amounts to be consistent with the current period presentation, with no effect on net income.

35. SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through February 10, 2017, the date the financial statements were issued.

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36. SUPPLEMENTAL FINANCIAL INFORMATION

On June 16, 2016, Emera US Finance LP, (in such capacity, the “Issuer”), issued $3.25 billion USD senior unsecured notes (“U.S. Notes”). The U.S Notes are fully and unconditionally guaranteed, on a joint and several basis, by Emera (in such capacity, the “Parent Company”) and EUSHI (in such capacity, the “Guarantor Subsidiaries”). Emera owns, directly or indirectly, all of the limited and general partnership interests in Emera US Finance LP.

The following consolidated financial statements present the results of operations, financial position and cash flows of the Parent Company, Subsidiary Issuer, Guarantor Subsidiaries and all other Non-guarantor Subsidiaries independently and on a consolidated basis.

Our guarantors were not determined using geographic, service line or other similar criteria, and as a result, the “Parent”, “Subsidiary Issuer”, “Guarantor Subsidiaries” and “Non-guarantor Subsidiaries” columns each include portions of our domestic and international operations. Accordingly, this basis of presentation is not intended to present our financial condition, results of operations or cash flows for any purpose other than to comply with the specific requirements for guarantor reporting.

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Emera Incorporated

# Consolidated Statements of Income

For the year ended December 31, 2016

|  | Parent | Subsidiary Issuer |  | Guarantor Subsidiaries | Non-guarantor Subsidiaries | Eliminations | Consolidated
millions of Canadian dollars |  |
Operating revenues |  |  |  |  |  |  |  |  |  |  |  |
Regulated electric | $ | - | $ | - | $ | 1,665 | $ | 1,774 | $ | (2) | $ | 3,437
Regulated gas |  | - |  | - |  | 451 |  | 48 |  | - |  | 499
Non-regulated |  | - |  | - |  | 378 |  | (4) |  | (33) |  | 341
Total operating revenues |  | - |  | - |  | 2,494 |  | 1,818 |  | (35) |  | 4,277
Operating expenses |  |  |  |  |  |  |  |  |  |  |  |
Regulated fuel for generation and purchased power |  | - |  | - |  | 560 |  | 662 |  | - |  | 1,222
Regulated cost of natural gas |  | - |  | - |  | 177 |  | - |  | - |  | 177
Regulated fuel adjustment mechanism and fixed cost deferrals |  | - |  | - |  | - |  | 61 |  | - |  | 61
Non-regulated fuel for generation and purchased power |  | - |  | - |  | 261 |  | 56 |  | (4) |  | 313
Non-regulated direct costs |  | - |  | - |  | - |  | 52 |  | (23) |  | 29
Operating, maintenance and general |  | 37 |  | - |  | 647 |  | 461 |  | (8) |  | 1,137
Provincial, state and municipal taxes |  | - |  | - |  | 152 |  | 43 |  | - |  | 195
Depreciation and amortization |  | 2 |  | - |  | 330 |  | 256 |  | - |  | 588
Total operating expenses |  | 39 |  | - |  | 2,127 |  | 1,591 |  | (35) |  | 3,722
Income (loss) from operations |  | (39) |  | - |  | 367 |  | 227 |  | - |  | 555
Income (loss) from equity investments in subsidiaries |  | 150 |  | - |  | - |  | - |  | (150) |  | -
Income from equity investments |  | 18 |  | - |  | - |  | 82 |  | - |  | 100
Intercompany income (expenses), net |  | 203 |  | 101 |  | (107) |  | (151) |  | (46) |  | -
Other income (expenses), net |  | 135 |  | - |  | 24 |  | 15 |  | - |  | 174
Interest expense, net |  | 226 |  | 85 |  | 127 |  | 147 |  | - |  | 585
Income (loss) before provision for income taxes |  | 241 |  | 16 |  | 157 |  | 26 |  | (196) |  | 244
Income tax expense (recovery) |  | (14) |  | 7 |  | 48 |  | (63) |  | - |  | (22)
Net income (loss) |  | 255 |  | 9 |  | 109 |  | 89 |  | (196) |  | 266
Non-controlling interest in subsidiaries |  | - |  | - |  | - |  | 7 |  | 4 |  | 11
Net income (loss) of Emera Incorporated |  | 255 |  | 9 |  | 109 |  | 82 |  | (200) |  | 255
Preferred stock dividends |  | 28 |  | - |  | 31 |  | 19 |  | (50) |  | 28
Net income (loss) attributable to common shareholders | $ | 227 | $ | 9 | $ | 78 | $ | 63 | $ | (150) | $ | 227
Comprehensive income (loss) of Emera Incorporated | $ | 228 | $ | 19 | $ | 205 | $ | 59 | $ | (283) | $ | 228

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Emera Incorporated

# Consolidated Statements of Income

For the year ended December 31, 2015

|  | Parent | Subsidiary Issuer |  | Guarantor Subsidiaries | Non-guarantor Subsidiaries | Eliminations | Consolidated
millions of Canadian dollars |  |
Operating revenues |  |  |  |  |  |  |  |  |  |  |  |
Regulated electric | $ | - | $ | - | $ | 283 | $ | 1,860 | $ | (2) | $ | 2,141
Regulated gas |  | - |  | - |  | - |  | 52 |  | - |  | 52
Non-regulated |  | - |  | - |  | 419 |  | 219 |  | (42) |  | 596
Total operating revenues |  | - |  | - |  | 702 |  | 2,131 |  | (44) |  | 2,789
Operating expenses |  |  |  |  |  |  |  |  |  |  |  |
Regulated fuel for generation and purchased power |  | - |  | - |  | 70 |  | 745 |  | - |  | 815
Regulated fuel adjustment mechanism and fixed cost deferrals |  | - |  | - |  | - |  | 42 |  | - |  | 42
Non-regulated fuel for generation and purchased power |  | - |  | - |  | 277 |  | 64 |  | (5) |  | 336
Non-regulated direct costs |  | - |  | - |  | - |  | 49 |  | (30) |  | 19
Operating, maintenance and general |  | 54 |  | - |  | 148 |  | 472 |  | (8) |  | 666
Provincial, state and municipal taxes |  | - |  | - |  | 21 |  | 42 |  | - |  | 63
Depreciation and amortization |  | 1 |  | - |  | 79 |  | 260 |  | - |  | 340
Total operating expenses |  | 55 |  | - |  | 595 |  | 1,674 |  | (43) |  | 2,281
Income (loss) from operations |  | (55) |  | - |  | 107 |  | 457 |  | (1) |  | 508
Income (loss) from equity investments in subsidiaries |  | 270 |  | - |  | - |  | - |  | (270) |  | -
Income from equity investments |  | 37 |  | - |  | 5 |  | 66 |  | - |  | 108
Intercompany income (expenses), net |  | 156 |  | - |  | - |  | 8 |  | (164) |  | -
Other income (expenses), net |  | 91 |  | - |  | 21 |  | 29 |  | - |  | 141
Interest expense, net |  | 46 |  | - |  | 28 |  | 272 |  | (134) |  | 212
Income (loss) before provision for income taxes |  | 453 |  | - |  | 105 |  | 288 |  | (301) |  | 545
Income tax expense (recovery) |  | 25 |  | - |  | 35 |  | 33 |  | - |  | 93
Net income (loss) |  | 428 |  | - |  | 70 |  | 255 |  | (301) |  | 452
Non-controlling interest in subsidiaries |  | - |  | - |  | - |  | 13 |  | 12 |  | 25
Net income (loss) of Emera Incorporated |  | 428 |  | - |  | 70 |  | 242 |  | (313) |  | 427
Preferred stock dividends |  | 30 |  | - |  | 15 |  | 26 |  | (41) |  | 30
Net income (loss) attributable to common shareholders | $ | 398 | $ | - | $ | 55 | $ | 216 | $ | (272) | $ | 397
Comprehensive income (loss) of Emera Incorporated | $ | 911 | $ | - | $ | 303 | $ | 452 | $ | (755) | $ | 911

204

Emera Incorporated

# Consolidated Balance Sheets

As at December 31, 2016

|  | Parent | Subsidiary Issuer |  | Guarantor Subsidiaries | Non-guarantor Subsidiaries | Eliminations | Consolidated
millions of Canadian dollars |  |
Assets |  |  |  |  |  |  |  |  |  |  |  |
Current assets |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents | $ | 200 | $ | 28 | $ | 48 | $ | 128 | $ | - | $ | 404
Restricted cash |  | - |  | - |  | 1 |  | 86 |  | - |  | 87
Receivables, net |  | 1 |  | - |  | 429 |  | 584 |  | - |  | 1,014
Intercompany receivables |  | 57 |  | 9 |  | 11 |  | 569 |  | (646) |  | -
Income taxes receivable |  | - |  | - |  | 5 |  | 28 |  | - |  | 33
Inventory |  | - |  | - |  | 273 |  | 199 |  | - |  | 472
Derivative instruments |  | 13 |  | - |  | 33 |  | 112 |  | (13) |  | 145
Regulatory assets |  | - |  | - |  | 54 |  | 26 |  | - |  | 80
Prepayments and other current assets |  | 2 |  | - |  | 44 |  | 230 |  | - |  | 276
Total current assets |  | 273 |  | 37 |  | 898 |  | 1,962 |  | (659) |  | 2,511
Property, plant and equipment, net of accumulated depreciation |  | 14 |  | - |  | 12,724 |  | 4,552 |  | - |  | 17,290
Other assets |  |  |  |  |  |  |  |  |  |  |  |
Income taxes receivable |  | - |  | - |  | - |  | 48 |  | - |  | 48
Deferred income taxes |  | 31 |  | - |  | 18 |  | 114 |  | (38) |  | 125
Derivative instruments |  | 12 |  | - |  | 2 |  | 129 |  | (12) |  | 131
Pension and post-retirement asset |  | - |  | - |  | - |  | 9 |  | - |  | 9
Regulatory assets |  | - |  | - |  | 647 |  | 595 |  | - |  | 1,242
Net investment in direct financing lease |  | - |  | - |  | 13 |  | 475 |  | - |  | 488
Investments in subsidiaries accounted for using the equity method |  | 8,349 |  | - |  | - |  | - |  | (8,349) |  | -
Investments subject to significant influence |  | 5 |  | - |  | 13 |  | 929 |  | - |  | 947
Investment securities |  | - |  | - |  | - |  | 48 |  | - |  | 48
Goodwill |  | - |  | - |  | 6,110 |  | 103 |  | - |  | 6,213
Intercompany notes receivable |  | 1,341 |  | 4,558 |  | 16 |  | 589 |  | (6,504) |  | -
Other investments - intercompany |  | - |  | - |  | - |  | 2,270 |  | (2,270) |  | -
Other long-term assets |  | 33 |  | - |  | 85 |  | 70 |  | (19) |  | 169
Total other assets |  | 9,771 |  | 4,558 |  | 6,904 |  | 5,379 |  | (17,192) |  | 9,420
Total assets | $ | 10,058 | $ | 4,595 | $ | 20,526 | $ | 11,893 | $ | (17,851) | $ | 29,221

205

Emera Incorporated
Consolidated Balance Sheets – Continued
As at December 31, 2016
|  | Parent | Subsidiary Issuer |  | Guarantor Subsidiaries | Non-guarantor Subsidiaries | Eliminations | Consolidated
millions of Canadian dollars |  |
Liabilities and Equity |  |  |  |  |  |  |  |  |  |  |  |
Current liabilities |  |  |  |  |  |  |  |  |  |  |  |
Short-term debt | $ | - | $ | - | $ | 948 | $ | 13 | $ | - | $ | 961
Current portion of long-term debt |  | - |  | - |  | 436 |  | 40 |  | - |  | 476
Accounts payable |  | 6 |  | - |  | 756 |  | 480 |  | - |  | 1,242
Intercompany payable |  | 534 |  | 6 |  | 81 |  | 25 |  | (646) |  | -
Income taxes payable |  | - |  | 6 |  | - |  | 13 |  | - |  | 19
Derivative instruments |  | 14 |  | - |  | 10 |  | 314 |  | (13) |  | 325
Regulatory liabilities |  | - |  | - |  | 225 |  | 137 |  | - |  | 362
Pension and post-retirement liabilities |  | - |  | - |  | 51 |  | 7 |  | - |  | 58
Other current liabilities |  | 54 |  | 7 |  | 79 |  | 141 |  | - |  | 281
Total current liabilities |  | 608 |  | 19 |  | 2,586 |  | 1,170 |  | (659) |  | 3,724
Long-term liabilities |  |  |  |  |  |  |  |  |  |  |  |
Long-term debt |  | 2,338 |  | 4,314 |  | 4,687 |  | 2,929 |  | - |  | 14,268
Intercompany long-term debt |  | 366 |  | - |  | 4,778 |  | 1,357 |  | (6,501) |  | -
Deferred income taxes |  | - |  | 1 |  | 1,193 |  | 516 |  | (38) |  | 1,672
Convertible debentures |  | 8 |  | - |  | - |  | - |  | - |  | 8
Derivative instruments |  | 12 |  | - |  | - |  | 150 |  | (12) |  | 150
Regulatory liabilities |  | - |  | - |  | 973 |  | 304 |  | - |  | 1,277
Asset retirement obligations |  | - |  | - |  | 61 |  | 109 |  | - |  | 170
Pension and post-retirement liabilities |  | 17 |  | - |  | 433 |  | 219 |  | - |  | 669
Other long-term liabilities |  | 5 |  | - |  | 213 |  | 268 |  | (19) |  | 467
Total long-term liabilities |  | 2,746 |  | 4,315 |  | 12,338 |  | 5,852 |  | (6,570) |  | 18,681
Equity |  |  |  |  |  |  |  |  |  |  |  |
Common stock |  | 4,738 |  | 242 |  | 4,177 |  | 3,997 |  | (8,416) |  | 4,738
Cumulative preferred stock |  | 709 |  | - |  | 620 |  | 271 |  | (891) |  | 709
Contributed surplus |  | 75 |  | - |  | 45 |  | 106 |  | (151) |  | 75
Accumulated other comprehensive income (loss) |  | 106 |  | 10 |  | 340 |  | (191) |  | (159) |  | 106
Retained earnings |  | 1,076 |  | 9 |  | 420 |  | 610 |  | (1,039) |  | 1,076
Total Emera Incorporated equity |  | 6,704 |  | 261 |  | 5,602 |  | 4,793 |  | (10,656) |  | 6,704
Non-controlling interest in subsidiaries |  | - |  | - |  | - |  | 78 |  | 34 |  | 112
Total equity |  | 6,704 |  | 261 |  | 5,602 |  | 4,871 |  | (10,622) |  | 6,816
Total liabilities and equity | $ | 10,058 | $ | 4,595 | $ | 20,526 | $ | 11,893 | $ | (17,851) | $ | 29,221

206

Emera Incorporated

# Consolidated Balance Sheets

As at December 31, 2015

|  | Parent | Subsidiary Issuer |  | Guarantor Subsidiaries | Non-guarantor Subsidiaries | Eliminations | Consolidated
millions of Canadian dollars |  |
Assets |  |  |  |  |  |  |  |  |  |  |  |
Current assets |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents | $ | - | $ | - | $ | 19 | $ | 1,068 | $ | (14) | $ | 1,073
Restricted cash |  | - |  | - |  | 1 |  | 18 |  | - |  | 19
Receivables, net |  | 2 |  | - |  | 70 |  | 506 |  | - |  | 578
Intercompany receivable |  | 102 |  | - |  | 51 |  | 95 |  | (248) |  | -
Income taxes receivable |  | - |  | - |  | 9 |  | 3 |  | - |  | 12
Inventory |  | - |  | - |  | 48 |  | 266 |  | - |  | 314
Derivative instruments |  | 109 |  | - |  | 46 |  | 112 |  | (17) |  | 250
Regulatory assets |  | - |  | - |  | 17 |  | 77 |  | - |  | 94
Prepayments and other current assets |  | 9 |  | - |  | 4 |  | 243 |  | - |  | 256
Total current assets |  | 222 |  | - |  | 265 |  | 2,388 |  | (279) |  | 2,596
Property, plant and equipment, net of accumulated depreciation |  | 15 |  | - |  | 2,035 |  | 4,419 |  | - |  | 6,469
Other assets |  |  |  |  |  |  |  |  |  |  |  |
Income taxes receivable |  | - |  | - |  | - |  | 49 |  | - |  | 49
Deferred income taxes |  | - |  | - |  | 47 |  | 19 |  | (34) |  | 32
Derivative instruments |  | 35 |  | - |  | - |  | 167 |  | (34) |  | 168
Pension and post-retirement assets |  | - |  | - |  | - |  | 9 |  | - |  | 9
Regulatory assets |  | - |  | - |  | 100 |  | 505 |  | - |  | 605
Net investment in direct financing lease |  | - |  | - |  | - |  | 480 |  | - |  | 480
Investments in subsidiaries accounted for using the equity method |  | 6,042 |  | - |  | - |  | - |  | (6,042) |  | -
Investments subject to significant influence |  | 509 |  | - |  | 12 |  | 624 |  | - |  | 1,145
Investment securities |  | - |  | - |  | - |  | 116 |  | - |  | 116
Goodwill |  | - |  | - |  | 158 |  | 106 |  | - |  | 264
Intercompany notes receivable |  | 3,051 |  | - |  | - |  | 2,754 |  | (5,805) |  | -
Other investments - intercompany |  | - |  | - |  | - |  | 98 |  | (98) |  | -
Other long-term assets |  | 16 |  | - |  | 13 |  | 77 |  | - |  | 106
Total other assets |  | 9,653 |  | - |  | 330 |  | 5,004 |  | (12,013) |  | 2,974
Total assets | $ | 9,890 | $ | - | $ | 2,630 | $ | 11,811 | $ | (12,292) | $ | 12,039

207

Emera Incorporated
Consolidated Balance Sheets – Continued
As at December 31, 2015
|  | Parent | Subsidiary Issuer |  | Guarantor Subsidiaries | Non-guarantor Subsidiaries | Eliminations | Consolidated
millions of Canadian dollars |  |
Liabilities and Equity |  |  |  |  |  |  |  |  |  |  |  |
Current liabilities |  |  |  |  |  |  |  |  |  |  |  |
Short-term debt | $ | 14 | $ | - | $ | - | $ | 16 | $ | (14) | $ | 16
Current portion of long-term debt |  | 250 |  | - |  | 6 |  | 18 |  | - |  | 274
Accounts payable |  | 17 |  | - |  | 76 |  | 301 |  | - |  | 394
Income taxes payable |  | - |  | - |  | - |  | 8 |  | - |  | 8
Intercompany payable |  | 52 |  | - |  | 92 |  | 77 |  | (221) |  | -
Derivative instruments |  | 17 |  | - |  | 36 |  | 313 |  | (17) |  | 349
Regulatory liabilities |  | - |  | - |  | 10 |  | 102 |  | - |  | 112
Pension and post-retirement liabilities |  | - |  | - |  | - |  | 7 |  | - |  | 7
Other current liabilities |  | 51 |  | - |  | 24 |  | 132 |  | - |  | 207
Total current liabilities |  | 401 |  | - |  | 244 |  | 974 |  | (252) |  | 1,367
Long-term liabilities |  |  |  |  |  |  |  |  |  |  |  |
Long-term debt |  | 464 |  | - |  | 389 |  | 2,882 |  | - |  | 3,735
Intercompany long-term debt |  | 2,631 |  | - |  | 120 |  | 3,072 |  | (5,823) |  | -
Deferred income taxes |  | 3 |  | - |  | 343 |  | 450 |  | (34) |  | 762
Convertible debentures (represented by installment receipts) |  | 2,139 |  | - |  | - |  | (1,458) |  | - |  | 681
Derivative instruments |  | 34 |  | - |  | - |  | 96 |  | (34) |  | 96
Regulatory liabilities |  | - |  | - |  | 12 |  | 341 |  | - |  | 353
Asset retirement obligations |  | - |  | - |  | - |  | 109 |  | - |  | 109
Pension and post-retirement liabilities |  | 13 |  | - |  | 93 |  | 197 |  | - |  | 303
Other long-term liabilities |  | 5 |  | - |  | 61 |  | 233 |  | - |  | 299
Total long-term liabilities |  | 5,289 |  | - |  | 1,018 |  | 5,922 |  | (5,891) |  | 6,338
Equity |  |  |  |  |  |  |  |  |  |  |  |
Common stock |  | 2,157 |  | - |  | 312 |  | 3,829 |  | (4,141) |  | 2,157
Cumulative preferred stock |  | 709 |  | - |  | 425 |  | 271 |  | (696) |  | 709
Contributed surplus |  | 29 |  | - |  | 45 |  | 133 |  | (178) |  | 29
Accumulated other comprehensive income (loss) |  | 137 |  | - |  | 245 |  | (169) |  | (76) |  | 137
Retained earnings |  | 1,168 |  | - |  | 341 |  | 751 |  | (1,092) |  | 1,168
Total Emera Incorporated equity |  | 4,200 |  | - |  | 1,368 |  | 4,815 |  | (6,183) |  | 4,200
Non-controlling interest in subsidiaries |  | - |  | - |  | - |  | 100 |  | 34 |  | 134
Total equity |  | 4,200 |  | - |  | 1,368 |  | 4,915 |  | (6,149) |  | 4,334
Total liabilities and equity | $ | 9,890 | $ | - | $ | 2,630 | $ | 11,811 | $ | (12,292) | $ | 12,039

208

Emera Incorporated |  |  |  |  |  |  |  |  |  |  |  |
Consolidated Statements of Cash Flows
For the year ended December 31, 2016
|  | Parent | Subsidiary Issuer |  | Guarantor Subsidiaries | Non-guarantor Subsidiaries | Eliminations | Consolidated
millions of Canadian dollars |  |
Net cash provided by (used in) by operating activities | $ | 265 | $ | 29 | $ | 481 | $ | 107 | $ | 171 | $ | 1,053
Investing activities |  |  |  |  |  |  |  |  |  |  |  |
Acquisitions, net of cash acquired |  | - |  | - |  | (8,409) |  | - |  | - |  | (8,409)
Additions to property, plant and equipment |  | (2) |  | - |  | (633) |  | (396) |  | - |  | (1,031)
Net purchase of investments subject to significant influence, inclusive of acquisition costs |  | - |  | - |  | - |  | (276) |  | - |  | (276)
Net proceeds on sale of investment subject to significant influence and held-for-trading common shares |  | 665 |  | - |  | - |  | - |  | - |  | 665
Other intercompany investing activities |  | (2,348) |  | (4,416) |  | (18) |  | (2,397) |  | 9,179 |  | -
Other investing activities |  | - |  | - |  | (42) |  | (12) |  | - |  | (54)
Net cash provided by (used in) investing activities |  | (1,685) |  | (4,416) |  | (9,102) |  | (3,081) |  | 9,179 |  | (9,105)
Financing activities |  |  |  |  |  |  |  |  |  |  |  |
Change in short-term debt, net |  | (14) |  | - |  | 122 |  | (4) |  | 14 |  | 118
Proceeds from long-term debt, net of issuance costs |  | 2,037 |  | 4,187 |  | 4,516 |  | 764 |  | (5,081) |  | 6,423
Proceeds from convertible debentures represented by instalment receipts, net of issuance costs |  | (44) |  | - |  | - |  | 1,457 |  | - |  | 1,413
Retirement of long-term debt |  | (250) |  | - |  | (6) |  | (36) |  | 19 |  | (273)
Net borrowings (repayments) under committed credit facilities |  | (210) |  | - |  | - |  | (99) |  | (6) |  | (315)
Issuance of common stock, net of issuance costs |  | 354 |  | 242 |  | 3,865 |  | 95 |  | (4,202) |  | 354
Issuance of preferred stock, net of issuance costs |  | - |  | - |  | 195 |  | - |  | (195) |  | -
Dividends on common stock |  | (221) |  | - |  | - |  | (254) |  | 254 |  | (221)
Dividends on preferred stock |  | (28) |  | - |  | (31) |  | (18) |  | 49 |  | (28)
Dividends paid by subsidiaries to non-controlling interest |  | - |  | - |  | - |  | (2) |  | (3) |  | (5)
Other financing activities |  | - |  | - |  | (18) |  | 185 |  | (185) |  | (18)
Net cash provided by (used in) financing activities |  | 1,624 |  | 4,429 |  | 8,643 |  | 2,088 |  | (9,336) |  | 7,448
Effect of exchange rate changes on cash and cash equivalents |  | (4) |  | (14) |  | 7 |  | (54) |  | - |  | (65)
Net increase (decrease) in cash and cash equivalents |  | 200 |  | 28 |  | 29 |  | (940) |  | 14 |  | (669)
Cash and cash equivalents, beginning of period |  | - |  | - |  | 19 |  | 1,068 |  | (14) |  | 1,073
Cash and cash equivalents, end of period | $ | 200 | $ | 28 | $ | 48 | $ | 128 | $ | - | $ | 404

209

Emera Incorporated |  |  |  |  |  |  |  |  |  |  |  |
Consolidated Statements of Cash Flows
For the year ended December 31, 2015
|  | Parent | Subsidiary Issuer |  | Guarantor Subsidiaries | Non-guarantor Subsidiaries | Eliminations | Consolidated
millions of Canadian dollars |  |
Net cash provided by (used in) operating activities | $ | 291 | $ | - | $ | 190 | $ | 364 | $ | (171) | $ | 674
Investing activities |  |  |  |  |  |  |  |  |  |  |  |
Additions to property, plant and equipment |  | (7) |  | - |  | (66) |  | (354) |  | - |  | (427)
Net purchase of investments subject to significant influence, inclusive of acquisition costs |  | (1) |  | - |  | (3) |  | (132) |  | - |  | (136)
Proceeds on sale of investment subject to significant influence |  | - |  | - |  | 282 |  | - |  | - |  | 282
Other intercompany investing activities |  | (2,453) |  | - |  | - |  | (29) |  | 2,482 |  | -
Other investing activities |  | (751) |  | - |  | (10) |  | (413) |  | 1,331 |  | 157
Net cash provided by (used in) investing activities |  | (3,212) |  | - |  | 203 |  | (928) |  | 3,813 |  | (124)
Financing activities |  |  |  |  |  |  |  |  |  |  |  |
Change in short-term debt, net |  | 4 |  | - |  | - |  | (262) |  | (4) |  | (262)
Proceeds from long-term debt, net of issuance costs |  | - |  | - |  | 29 |  | 1,465 |  | (1,048) |  | 446
Proceeds from convertible debentures represented by instalment receipts, net of issuance costs |  | 2,138 |  | - |  | - |  | (1,457) |  | - |  | 681
Retirement of long-term debt |  | - |  | - |  | (420) |  | (372) |  | 702 |  | (90)
Net borrowings (repayments) under committed credit facilities |  | (39) |  | - |  | (9) |  | (153) |  | - |  | (201)
Issuance of common stock, net of issuance costs |  | 9 |  | - |  | - |  | 2,390 |  | (2,390) |  | 9
Issuance of preferred stock, net of issuance costs |  | - |  | - |  | - |  | 6 |  | (6) |  | -
Dividends on common stock |  | (162) |  | - |  | - |  | (162) |  | 162 |  | (162)
Dividends on preferred stock |  | (30) |  | - |  | (15) |  | (25) |  | 40 |  | (30)
Dividends paid by subsidiaries to non-controlling interest |  | - |  | - |  | - |  | (3) |  | (11) |  | (14)
Other financing activities |  | 1,001 |  | - |  | (11) |  | (55) |  | (1,091) |  | (156)
Net cash provided by (used in) financing activities |  | 2,921 |  | - |  | (426) |  | 1,372 |  | (3,646) |  | 221
Effect of exchange rate changes on cash and cash equivalents |  | - |  | - |  | 14 |  | 67 |  | - |  | 81
Net increase (decrease) in cash and cash equivalents |  | - |  | - |  | (19) |  | 875 |  | (4) |  | 852
Cash and cash equivalents, beginning of period |  | - |  | - |  | 38 |  | 193 |  | (10) |  | 221
Cash and cash equivalents, end of period | $ | - | $ | - | $ | 19 | $ | 1,068 | $ | (14) | $ | 1,073

210