EX-99.3 4 d904641dex993.htm EX-99.3

Exhibit 99.3

EMERA INCORPORATED

Consolidated

Financial Statements

December 31, 2019 and 2018

75

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 and with the standards of the Public Company Accounting Oversight Board. Ernst & Young LLP has full and free access to the Audit Committee.

February 14, 2020

“Scott Balfour” |  | “Gregory Blunden”
President and Chief Executive Officer |  | Chief Financial Officer

76

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Emera Incorporated

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Emera Incorporated (the “Company“) as of December 31, 2019 and 2018, the related consolidated statements of income, consolidated statements of comprehensive income, consolidated statements of changes in equity and consolidated statements of cash flows for the years then ended, and the related notes and schedules (collectively referred to as the “consolidated financial statements“). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2019 and 2018, and the consolidated results of its operations and its consolidated cash flows for each of the two years in the period ended December 31, 2019, in conformity with United States generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company‘s management. Our responsibility is to express an opinion on the Company‘s consolidated financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

Chartered Professional Accountants

Licensed Public Accountants

We have served as the Company‘s auditor since 1998.

Halifax, Canada

February 14, 2020

77

Emera Incorporated

Consolidated Statements of Income

For the |  | Year ended December 31 |
millions of Canadian dollars (except per share amounts) |  | 2019 |  |  | 2018 |
Operating revenues |  |  |  |  |  |  |  |
Regulated electric |  | $ | 4,769 |  |  | $ | 4,852 |
Regulated gas |  |  | 1,081 |  |  |  | 1,044 |
Non-regulated |  |  | 261 |  |  |  | 628 |
Total operating revenues (note 6) |  |  | 6,111 |  |  |  | 6,524 |
Operating expenses |  |  |  |  |  |  |  |
Regulated fuel for generation and purchased power (notes 16 and 18) |  |  | 1,609 |  |  |  | 1,677 |
Regulated cost of natural gas |  |  | 350 |  |  |  | 388 |
Non-regulated fuel for generation and purchased power |  |  | 66 |  |  |  | 225 |
Operating, maintenance and general |  |  | 1,464 |  |  |  | 1,580 |
Provincial, state, and municipal taxes |  |  | 342 |  |  |  | 340 |
Depreciation and amortization |  |  | 903 |  |  |  | 916 |
GBPC impairment charge (note 21) |  |  | 34 |  |  |  | - |
Total operating expenses |  |  | 4,768 |  |  |  | 5,126 |
Income from operations |  |  | 1,343 |  |  |  | 1,398 |
Income from equity investments (note 7) |  |  | 154 |  |  |  | 154 |
Other income (expenses), net |  |  | 12 |  |  |  | (23) |
Interest expense, net |  |  | 738 |  |  |  | 713 |
Income before provision for income taxes |  |  | 771 |  |  |  | 816 |
Income tax expense (note 8) |  |  | 61 |  |  |  | 69 |
Net income |  |  | 710 |  |  |  | 747 |
Non-controlling interest in subsidiaries |  |  | 2 |  |  |  | 1 |
Preferred stock dividends |  |  | 45 |  |  |  | 36 |
Net income attributable to common shareholders |  | $ | 663 |  |  | $ | 710 |
Weighted average shares of common stock outstanding (in millions) (note 10) |  |  |  |  |  |  |  |
Basic |  |  | 240 |  |  |  | 233 |
Diluted |  |  | 240 |  |  |  | 234 |
Earnings per common share (note 10) |  |  |  |  |  |  |  |
Basic |  | $ | 2.76 |  |  | $ | 3.05 |
Diluted |  | $ | 2.76 |  |  | $ | 3.04 |
Dividends per common share declared |  | $ | 2.3750 |  |  | $ | 2.2825 |

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 |  | 2019 |  |  | 2018 |
Net income |  | $ | 710 |  |  | $ | 747 |
Other comprehensive income (loss), net of tax |  |  |  |  |  |  |  |
Foreign currency translation adjustment |  |  | (402) |  |  |  | 627 |
Unrealized gains (losses) on net investment hedges (1) (2) |  |  | 78 |  |  |  | (122) |
Cash flow hedges |  |  |  |  |  |  |  |
Net derivative gains (losses) |  |  | 3 |  |  |  | 2 |
Less: reclassification adjustment for losses (gains) included in income |  |  | 3 |  |  |  | (6) |
Net effects of cash flow hedges |  |  | 6 |  |  |  | (4) |
Unrealized gains on available-for-sale investment |  |  |  |  |  |  |  |
Unrealized gain (loss) arising during the period |  |  | - |  |  |  | - |
Less: reclassification adjustment for (gains) recognized in income |  |  | - |  |  |  | (4) |
Net unrealized holding gains (losses) |  |  | - |  |  |  | (4) |
Net change in unrecognized pension and post-retirement benefit obligation (3) |  |  | 74 |  |  |  | 9 |
Other comprehensive income (loss) (4) |  |  | (244) |  |  |  | 506 |
Comprehensive income (loss) |  |  | 466 |  |  |  | 1,253 |
Comprehensive income (loss) attributable to non-controlling interest |  |  | 1 |  |  |  | 4 |
Comprehensive Income (loss) of Emera Incorporated |  | $ | 465 |  |  | $ | 1,249 |

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

1) The Company has designated $1.2 billion United States dollar denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in United States dollar denominated operations.

2) Net of tax expense of $1 million (2018 - $9 million tax recovery) for the year ended December 31, 2019.

3) Net of tax expense of $9 million (2018 - $2 million tax recovery) for the year ended December 31, 2019.

4) Net of tax expense of $10 million (2018 - $11 million tax recovery) for the year ended December 31, 2019.

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Emera Incorporated

Consolidated Balance Sheets

As at |  | December 31 |  |  | December 31 |
millions of Canadian dollars |  | 2019 |  |  | 2018 |
Assets |  |  |  |  |  |  |  |
Current assets |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 222 |  |  | $ | 316 |
Restricted cash (note 31) |  |  | 51 |  |  |  | 56 |
Inventory (note 12) |  |  | 467 |  |  |  | 474 |
Derivative instruments (notes 13 and 14) |  |  | 54 |  |  |  | 148 |
Regulatory assets (note 15) |  |  | 121 |  |  |  | 165 |
Receivables and other current assets (note 17) |  |  | 1,486 |  |  |  | 1,620 |
Assets held for sale (note 4) |  |  | 85 |  |  |  | 53 |
|  |  | 2,486 |  |  |  | 2,832 |
Property, plant and equipment, net of accumulated depreciation and amortization of $8,295 and $8,567, respectively (note 19) |  |  | 18,167 |  |  |  | 18,712 |
Other assets |  |  |  |  |  |  |  |
Deferred income taxes |  |  | 186 |  |  |  | 175 |
Derivative instruments (notes 13 and 14) |  |  | 33 |  |  |  | 19 |
Regulatory assets (note 15) |  |  | 1,431 |  |  |  | 1,404 |
Net investment in direct financing lease (note 18) |  |  | 473 |  |  |  | 475 |
Investments subject to significant influence (note 7) |  |  | 1,312 |  |  |  | 1,316 |
Goodwill (note 21) |  |  | 5,835 |  |  |  | 6,313 |
Other long-term assets |  |  | 300 |  |  |  | 291 |
Assets held for sale (note 4) |  |  | 1,619 |  |  |  | 777 |
|  |  | 11,189 |  |  |  | 10,770 |
Total assets |  | $ | 31,842 |  |  | $ | 32,314 |

80

Emera Incorporated

Consolidated Balance Sheets – Continued

As at |  | December 31 |  |  | December 31 |
millions of Canadian dollars |  | 2019 |  |  | 2018 |
Liabilities and Equity |  |  |  |  |  |  |  |
Current liabilities |  |  |  |  |  |  |  |
Short-term debt (note 22) |  | $ | 1,537 |  |  | $ | 1,186 |
Current portion of long-term debt (note 24) |  |  | 501 |  |  |  | 1,119 |
Accounts payable |  |  | 1,118 |  |  |  | 1,289 |
Derivative instruments (notes 13 and 14) |  |  | 268 |  |  |  | 260 |
Regulatory liabilities (note 15) |  |  | 295 |  |  |  | 251 |
Other current liabilities (note 23) |  |  | 333 |  |  |  | 428 |
Liabilities associated with assets held for sale (note 4) |  |  | 114 |  |  |  | 20 |
|  |  | 4,166 |  |  |  | 4,553 |
Long-term liabilities |  |  |  |  |  |  |  |
Long-term debt (note 24) |  |  | 13,679 |  |  |  | 14,292 |
Deferred income taxes (note 8) |  |  | 1,285 |  |  |  | 1,320 |
Derivative instruments (notes 13 and 14) |  |  | 102 |  |  |  | 105 |
Regulatory liabilities (note 15) |  |  | 1,886 |  |  |  | 2,359 |
Pension and post-retirement liabilities (note 20) |  |  | 460 |  |  |  | 641 |
Other long-term liabilities (notes 7 and 25) |  |  | 764 |  |  |  | 684 |
Long-term liabilities associated with assets held for sale (note 4) |  |  | 899 |  |  |  | 2 |
|  |  | 19,075 |  |  |  | 19,403 |
Equity |  |  |  |  |  |  |  |
Common stock (note 9) |  |  | 6,216 |  |  |  | 5,816 |
Cumulative preferred stock (note 27) |  |  | 1,004 |  |  |  | 1,004 |
Contributed surplus |  |  | 78 |  |  |  | 84 |
Accumulated other comprehensive income (note 11) |  |  | 95 |  |  |  | 338 |
Retained earnings |  |  | 1,173 |  |  |  | 1,075 |
Total Emera Incorporated equity |  |  | 8,566 |  |  |  | 8,317 |
Non-controlling interest in subsidiaries (note 28) |  |  | 35 |  |  |  | 41 |
Total equity |  |  | 8,601 |  |  |  | 8,358 |
Total liabilities and equity |  | $ | 31,842 |  |  | $ | 32,314 |

Commitments and contingencies (note 26)

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

Approved on behalf of the Board of Directors

“M. Jacqueline Sheppard” |  | “Scott Balfour”
Chair of the Board |  | President and Chief Executive Officer

81

Emera Incorporated

Consolidated Statements of Cash Flows

For the |  | Year ended December 31 |
millions of Canadian dollars |  | 2019 |  |  | 2018 |
Operating activities |  |  |  |  |  |  |  |
Net income |  | $ | 710 |  |  | $ | 747 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 911 |  |  |  | 928 |
Income from equity investments, net of dividends |  |  | (83) |  |  |  | (75) |
Allowance for equity funds used during construction |  |  | (21) |  |  |  | (19) |
Deferred income taxes, net |  |  | 125 |  |  |  | 185 |
Net change in pension and post-retirement liabilities |  |  | (17) |  |  |  | 11 |
Regulated fuel adjustment mechanism |  |  | (46) |  |  |  | (16) |
Net change in fair value of derivative instruments |  |  | (39) |  |  |  | 55 |
Net change in regulatory assets and liabilities |  |  | 44 |  |  |  | 51 |
Net change in capitalized transportation capacity |  |  | (55) |  |  |  | (105) |
GBPC impairment charge (note 21) |  |  | 34 |  |  |  | - |
Other operating activities, net |  |  | 35 |  |  |  | 44 |
Changes in non-cash working capital (note 29) |  |  | (73) |  |  |  | (116) |
Net cash provided by operating activities |  |  | 1,525 |  |  |  | 1,690 |
Investing activities |  |  |  |  |  |  |  |
Additions to property, plant and equipment |  |  | (2,495) |  |  |  | (2,162) |
Net purchase of investments subject to significant influence, inclusive of acquisition costs |  |  | (3) |  |  |  | (49) |
Proceeds from dispositions (note 4) |  |  | 875 |  |  |  | - |
Other investing activities |  |  | 6 |  |  |  | 21 |
Net cash used in investing activities |  |  | (1,617) |  |  |  | (2,190) |
Financing activities |  |  |  |  |  |  |  |
Change in short-term debt, net |  |  | 413 |  |  |  | 99 |
Proceeds from short-term debt with maturities greater than 90 days |  |  | - |  |  |  | 129 |
Repayment of short-term debt with maturities greater than 90 days |  |  | - |  |  |  | (390) |
Proceeds from long-term debt, net of issuance costs |  |  | 1,066 |  |  |  | 1,055 |
Retirement of long-term debt |  |  | (1,103) |  |  |  | (757) |
Net borrowings (repayments) under committed credit facilities |  |  | (118) |  |  |  | 321 |
Issuance of common stock, net of issuance costs |  |  | 203 |  |  |  | 10 |
Issuance of preferred stock, net of issuance costs (note 27) |  |  | - |  |  |  | 291 |
Dividends on common stock |  |  | (378) |  |  |  | (346) |
Dividends on preferred stock |  |  | (45) |  |  |  | (36) |
Other financing activities |  |  | (24) |  |  |  | (32) |
Net cash provided by financing activities |  |  | 14 |  |  |  | 344 |
Effect of exchange rate changes on cash, cash equivalents, and restricted cash |  |  | (20) |  |  |  | 25 |
Net decrease in cash, cash equivalents, restricted cash and assets held for sale |  |  | (98) |  |  |  | (131) |
Cash, cash equivalents, and restricted cash, beginning of year |  |  | 372 |  |  |  | 503 |
Cash, cash equivalents, restricted cash and assets held for sale, end of year |  | $ | 274 |  |  | $ | 372 |
Cash, cash equivalents, restricted cash and assets held for sale consists of: |  |  |  |  |  |  |  |
Cash |  | $ | 222 |  |  | $ | 273 |
Short-term investments |  |  | - |  |  |  | 43 |
Restricted cash |  |  | 51 |  |  |  | 56 |
Assets held for sale |  |  | 1 |  |  |  | - |
Cash, cash equivalents, restricted cash and assets held for sale |  | $ | 274 |  |  | $ | 372 |

Supplementary Information to Consolidated Statements of Cash Flows (note 29)

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

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Emera Incorporated

Consolidated Statements of Changes in Equity

|  | Common Stock |  |  | Preferred Stock |  |  | Contributed Surplus |  |  | Accumulated Other Comprehensive Income (Loss) (1) |  |  | Retained Earnings |  |  | Non- Controlling Interest |  |  | Total Equity |
millions of Canadian dollars |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Balance, December 31, 2018 |  | $ | 5,816 |  |  | $ | 1,004 |  |  | $ | 84 |  |  | $ | 338 |  |  | $ | 1,075 |  |  | $ | 41 |  |  | $ | 8,358 |
Net income of Emera incorporated |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 708 |  |  |  | 2 |  |  |  | 710 |
Other comprehensive loss, net of tax expense of $10 million |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (243) |  |  |  | - |  |  |  | (1) |  |  |  | (244) |
Dividends declared on preferred stock (note 27) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (45) |  |  |  | - |  |  |  | (45) |
Dividends declared on common stock ($2.3750/share) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (565) |  |  |  | - |  |  |  | (565) |
Common stock issued under purchase plan |  |  | 195 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 195 |
Issuance of common stock, net of after-tax issuance costs |  |  | 99 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 99 |
Senior management stock options exercised |  |  | 104 |  |  |  | - |  |  |  | (7) |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 97 |
Issuance of preferred shares of GBPC, net of issuance costs (note 28) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 14 |  |  |  | 14 |
Redemption of preferred shares of GBPC (note 28) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (19) |  |  |  | (19) |
Other |  |  | 2 |  |  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | - |  |  |  | (2) |  |  |  | 1 |
Balance, December 31, 2019 |  | $ | 6,216 |  |  | $ | 1,004 |  |  | $ | 78 |  |  | $ | 95 |  |  | $ | 1,173 |  |  | $ | 35 |  |  | $ | 8,601 |
Balance, December 31, 2017 |  | $ | 5,601 |  |  | $ | 709 |  |  | $ | 76 |  |  | $ | (165) |  |  | $ | 891 |  |  | $ | 92 |  |  | $ | 7,204 |
Net income |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 746 |  |  |  | 1 |  |  |  | 747 |
Other comprehensive income, net of tax recovery of $11 million |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 503 |  |  |  | - |  |  |  | 3 |  |  |  | 506 |
Issuance of preferred stock, net of after-tax issuance costs |  |  | - |  |  |  | 295 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 295 |
Dividends declared on preferred stock (note 27) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (36) |  |  |  | - |  |  |  | (36) |
Dividends declared on common stock ($2.2825/share) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (528) |  |  |  | - |  |  |  | (528) |
Common stock issued under purchase plan |  |  | 191 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 191 |
Acquisition of non-controlling interest of ICD Utilities Limited (“ICDU”) |  |  | 22 |  |  |  | - |  |  |  | 6 |  |  |  | - |  |  |  | - |  |  |  | (53) |  |  |  | (25) |
Other |  |  | 2 |  |  |  | - |  |  |  | 2 |  |  |  | - |  |  |  | 2 |  |  |  | (2) |  |  |  | 4 |
Balance, December 31, 2018 |  | $ | 5,816 |  |  | $ | 1,004 |  |  | $ | 84 |  |  | $ | 338 |  |  | $ | 1,075 |  |  | $ | 41 |  |  | $ | 8,358 |

(1) Accumulated Other Comprehensive Income (Loss) (“AOCI”) (“AOCL”)

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, 2019 and 2018

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

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

Effective January 1, 2019, Emera revised its reportable segments to align with strategic priorities and internal governance. These new reporting segments align with how the Company assesses financial performance and makes decisions about resource allocations.

At December 31, 2019, Emera’s reportable segments include the following:

| ● |  | Florida Electric Utility, which consists of Tampa Electric, a vertically integrated regulated electric utility, serving approximately 779,000 customers in West Central Florida;

| ● |  | Canadian Electric Utilities which includes:

| ● |  | Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated electric utility and the primary electricity supplier in Nova Scotia, serving approximately 523,000 customers; and

| ● |  | Emera Newfoundland & Labrador Holdings Inc. (“ENL”), consisting of two transmission investments related to an 824 megawatt (“MW”) hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador being developed by Nalcor Energy and forecasted to be generating full power in the second half of 2020. ENL’s two investments are:

| ● |  | a 100 per cent investment in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $1.6 billion transmission project, including two 170-kilometre sub-sea cables, connecting the island of Newfoundland and Nova Scotia. This project went in service on January 15, 2018; and

| ● |  | a 49.5 per cent investment in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a $3.7 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Construction of the LIL has been completed and Nalcor recognized the first flow of energy from Labrador to Newfoundland in June 2018. Nalcor continues to work towards commissioning the LIL, which is forecasted to be in 2020.

| ● |  | Other Electric Utilities, which includes:

| ● |  | Emera Maine, a regulated electric transmission and distribution utility, serving approximately 159,000 customers in the state of Maine. On March 25, 2019, Emera announced an agreement to sell Emera Maine. The transaction is expected to close in early 2020, subject to approval of the Maine Public Utilities Commission (“MPUC”). Refer to note 4 for further details; and

| ● |  | Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities that include:

| ● |  | The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated electric utility on the island of Barbados, serving approximately 131,000 customers;

| ● |  | Grand Bahama Power Company Limited (“GBPC”), a vertically integrated regulated electric utility on Grand Bahama Island, serving approximately 18,000 customers. On September 1, 2019, Grand Bahama Island was struck by Hurricane Dorian, causing significant damage. Refer to note 15 and 21 for further details;

84

| ● |  | a 51.9 per cent interest in Dominica Electricity Services Ltd. (“Domlec”), a vertically integrated regulated electric utility on the island of Dominica, serving approximately 31,000 customers; and

| ● |  | a 19.1 per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia.

| ● |  | Gas Utilities and Infrastructure which includes:

| ● |  | Peoples Gas System (“PGS”), a regulated gas distribution utility, serving approximately 406,000 customers across Florida;

| ● |  | New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility, serving approximately 534,000 customers in New Mexico;

| ● |  | SeaCoast Gas Transmission, LLC (“SeaCoast”), a regulated intrastate natural gas transmission company offering services in Florida;

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

| ● |  | a 12.9 per cent interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400-kilometre pipeline, which transports natural gas throughout markets in Atlantic Canada and the northeastern United States.

At December 31, 2019, Emera’s investments in other energy-related non-regulated companies (included within the Other reportable segment) include the following:

| ● |  | Emera Energy, which consists of:

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

| ● |  | Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia; and

| ● |  | a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 600 MW pumped storage hydroelectric facility in northwestern 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 (“Emera Finance”) and TECO Finance, Inc. (“TECO Finance”), financing subsidiaries of Emera;

| ● |  | Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States; and

| ● |  | other investments.

In 2019, the Company completed the sale of assets previously included in the Other segment, including the sale of Emera Energy’s New England Gas Generating (“NEGG”) and Bayside facilities, and Emera Utility Services (“EUS”) equipment and inventory. Refer to note 4 for further details of these transactions.

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.

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

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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. Refer to note 31 for further details. 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 Company performs ongoing analysis to assess whether it holds any VIEs or whether any reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management reviews contractual and ownership arrangements such as leases, long-term purchase power agreements, tolling contracts, guarantees, jointly owned facilities and equity investments. 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.

Intercompany balances and intercompany 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 (“OM&G”), 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 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. The rates are designed to recover the costs of providing the regulated products or services and provide a reasonable rate of return on the equity invested or assets, as applicable (refer to note 15 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 foreign operations whose functional currency is not the Canadian dollar are translated using the exchange rates in effect at the balance sheet date and the results of operations at the average exchange rate in effect 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 denominated debt held in Canadian dollar 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 is recorded in Other Comprehensive Income (“OCI”).

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Revenue Recognition

Regulated Electric Revenue

Electric revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is when electricity is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the electricity. Electric revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity are recognized at rates approved by the respective regulator and recorded based on metered usage, which occurs on a periodic, systematic basis, generally monthly or bi-monthly. At the end of each reporting period, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of megawatt hour (“MWh”) delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy demand, weather, line losses and inter-period changes to customer classes.

Regulated Gas Revenue

Gas revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is when gas is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the gas. Gas revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the distribution and sale of gas are recognized at rates approved by the respective regulator and recorded based on metered usage, which occurs on a periodic, systematic basis, generally monthly. At the end of each reporting period, the gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of therms delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of usage, weather, and inter-period changes to customer classes.

Non-regulated Revenue

Marketing and trading margin is comprised of Emera Energy’s corresponding purchases and sales of natural gas and electricity, pipeline capacity costs and energy asset management revenues. Revenues are recorded when obligations under terms of a contract are satisfied and are presented on a net basis, reflecting the nature of the contractual relationships with customers and suppliers.

Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is when electricity is delivered to customers over time.

Capacity payments are recognized when obligations under the terms of a contract are satisfied, which is as the plants stand ready to deliver electricity to customers. Revenues related to capacity payments are recognized at rates determined through an auction process held annually, three years in advance, through the forward capacity market.

Other non-regulated revenues are recorded when obligations under terms of a contract are satisfied.

Other

Sales, value add, and other taxes, with the exception of gross receipts taxes discussed below, collected by the Company concurrent with revenue-producing activities are excluded from revenue.

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Leases

The Company determines whether a contract contains a lease at inception by evaluating if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.

Emera has leases with independent power producers and other utilities with annual requirements to purchase wind and hydro energy over varying contract lengths that are classified as finance leases. These finance leases are not recorded on the Company’s Consolidated Balance Sheets as payments associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease expense associated with these leases is recorded as “Regulated fuel for generation and purchased power” on the Consolidated Statements of Income.

Operating lease liabilities and right-of-use (“ROU”) assets are recognized on the Consolidated Balance Sheets based on the present value of the future minimum lease payments over the lease term at commencement date. As most of Emera’s leases do not provide an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as “Operating, maintenance and general” on the Consolidated Statements of Income.

Where the Company is the lessor, a lease is a sales-type lease if certain criteria are met and the arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual value guarantee, the lease is a direct financing lease.

For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and residual value (net of estimated executory costs and unearned income). The difference between the gross investment and the cost of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease.

For sales-type leases, the accounting is similar to the accounting for direct finance leases, however the difference between the fair value and the carrying value of the leased item is recorded at lease commencement rather than deferred over the term of the lease.

Emera has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component for all leases.

Franchise Fees and Gross Receipts

Tampa Electric and PGS 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 “Regulated electric” and “Regulated gas” 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 Statements of Income.

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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 costs, 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. For some of Emera’s rate regulated subsidiaries depreciation is calculated using the group remaining life method which is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property. The service lives of regulated assets require the appropriate regulatory approval.

Intangible assets, which are included in “Property, plant and equipment” 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 the asset in each category. For some of Emera’s rate regulated subsidiaries, amortization is calculated using the amortizable life method which is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above. The service lives of regulated intangible assets require 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 and is adjusted for the impact of foreign exchange. Under the applicable accounting guidance, goodwill is subject to an annual assessment for impairment at the reporting unit level. Refer to note 21 for further detail.

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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 reflect the amount of deferred income tax asset 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 Tampa Electric, PGS, NMGC and Emera Maine on regulated assets are deferred and amortized over the estimated service lives of the related properties, as required by 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. These regulated assets or liabilities are grossed up using the respective income tax rate to reflect the income tax associated with future revenues that are 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 classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively. Refer to note 8 for further details.

Derivatives and Hedging Activities

The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange, interest rates and share prices 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, equity derivatives, 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 and financial instruments are considered derivatives.

The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty creditworthy. 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 change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Where the documentation or effectiveness requirements are not met any changes in fair value are recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.

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Derivatives entered into by 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. 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 any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. Tampa Electric and PGS have no derivatives related to hedging as a result of a Florida Public Service Commission approved five-year moratorium on hedging of natural gas purchases which ends on December 31, 2022.

Derivatives that do not meet any of the above criteria are designated as HFT, with changes in fair value 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, operating maintenance and general and 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 and other current assets” and obligations to return cash collateral are recognized in “Accounts payable”.

Cash, Cash Equivalents and Restricted Cash

Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition. There were no short-term investments at December 31, 2019 (2018 - $43 million with an effective interest rate of 2.0 per cent).

Receivables and Allowance for Doubtful Accounts

Utility 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.

The Company is exposed to credit risk with respect to amounts receivable from customers. Credit assessments may be conducted on new customers. Deposits are requested accounts as required. 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.

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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.

Asset Impairment

Long-Lived Assets

Emera assesses whether there has been an impairment of long-lived assets and intangibles when a triggering event occurs, such as a significant market disruption or sale of a business.

The review of long-lived assets for impairment involves comparing the undiscounted expected future cash flows to the carrying value of the asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset over its estimated fair value. The Company’s assumptions relating to future results of operations or other recoverable amounts are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. The Company’s expectations regarding uses and holding periods of assets are based on internal long-term budgets and projections, which give consideration to external factors and market forces, as of the end of each reporting period. The assumptions made are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities.

As a result of the damage caused by Hurricane Dorian, the Company completed an asset impairment analysis in Q4 2019. Property, plant and equipment and inventory with a book value of approximately $18 million USD was determined to be impaired and was reclassified as a regulatory asset. GBPC recorded an offsetting insurance receivable of $15 million USD against this regulatory asset. It is anticipated that the regulatory asset balance of $3 million USD remaining at December 31, 2019 will be recovered through insurance. Refer to note 15 for further details. No impairment was recorded in 2018.

Goodwill

Goodwill is not amortized, but is subject to an annual assessment for impairment at the reporting unit level. Reporting units are generally determined at the operating segment level or one level below the operating segment level. Reporting units with similar characteristics are grouped for the purpose of determining impairment, if any, of goodwill. Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. In performing a qualitative assessment management considers, among other factors, macroeconomic conditions, industry and market considerations and overall financial performance.

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If an entity performs the qualitative assessment and determines that it is more likely than not that its fair value is less than its carrying amount or if an entity chooses to bypass the qualitative assessment, a quantitative test is performed. The quantitative test 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, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. Management estimates the fair value of the reporting unit by using the income approach or a combination of the income and market approach. The income approach is applied using a discounted cash flow analysis which relies on management’s best estimate of the reporting units’ projected cash flows. The analysis 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 used 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. When using the market approach, management estimates fair value based on comparable companies and transactions within the utility industry. Significant assumptions used in estimating the fair value include discount and growth rates, rate case assumptions, valuation of Emera’s net operating loss (“NOL”), utility sector market performance and transactions, projected operating and capital cash flows and the fair value of debt. Adverse changes in assumptions described above could result in a future material impairment of the goodwill assigned to Emera’s reporting units with goodwill.

In Q4 2019, the Company performed quantitative impairment assessments at the reporting unit level. The quantitative assessments for Tampa Electric, PGS and NMGC concluded that the fair value of the reporting units exceeded their respective carrying amounts. However, it was determined that including the impacts of Hurricane Dorian, the fair value of GBPC did not exceed its carrying amount. As a result of this assessment, a goodwill impairment charge of $30 million was recorded in 2019 due to a decrease in expected future cash flows resulting from the impacts of Hurricane Dorian storm recovery and changes in the anticipated long term regulated capital structure of GBPC. No impairment was recorded in 2018. Refer to note 21 for further details.

Emera Maine’s assets and liabilities are classified as held for sale, including $148 million of goodwill, and are measured at the lower of their carrying value or fair value less costs to sell. The measurement did not result in a fair value adjustment and goodwill is not impaired. Refer to notes 4 and 21 for further details.

Equity Method Investments

The carrying value of investments accounted for under the equity method are assessed for impairment by comparing the fair value 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. No impairment of equity method investments was required for either 2018 or 2019.

Financial Assets

Equity investments, other than those accounted for under the equity method of accounting, are measured at fair value with changes in fair value recognized in the Consolidated Statements of Income. Equity investments that do not have readily determinable fair values are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or similar investments. No material impairment of financial assets was required for either 2018 or 2019.

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Asset Retirement Obligations

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

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. AROs are included in “Other long-term liabilities” and accretion expense is included as part of “Depreciation and amortization”. Any regulated accretion expense not yet approved by the regulator is recorded in “Property, plant and equipment” and included in the next depreciation study.

As at December 31, 2019 and 2018, some of the Company’s transmission and distribution assets may have conditional ARO’s which are not recognized in the consolidated financial statements as the fair value of these obligations could not be reasonably estimated, given there is insufficient information to do so. 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 in the period in which an amount can be determined.

Cost of Removal

Tampa Electric, PGS, NMGC and NSPI recognize non-ARO costs of removal (“COR”) as regulatory liabilities. The non-ARO costs of removal represent funds received from customers through depreciation rates to cover estimated future non-legally required cost of removal of property, plant and equipment upon retirement. The companies accrue for removal costs over the life of the related assets based on depreciation studies approved by their respective regulators. The costs are estimated based on historical experience and future expectations, including expected timing and estimated future cash outlays.

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; a performance share unit (“PSU”) plan; and a restricted share unit (“RSU”) 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. Stock-based compensation plans recognized as liabilities are initially 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. The components of net periodic benefit cost other than the service cost component are included in “Other income (expense), net” on the Consolidated Statements of Income.

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2. CHANGE IN ACCOUNTING POLICY

The new USGAAP accounting policies that are applicable to, and adopted by the Company in 2019, are described as follows:

Leases

On January 1, 2019, the Company adopted Accounting Standard Updates (“ASU”) 2016-02, Leases (Topic 842), including all related amendments, using the modified retrospective approach. The standard requires lessees to recognize leases on the balance sheet for all leases with a term of longer than twelve months and disclose key information about leasing arrangements.

As permitted by the optional transition method, Emera did not restate comparative financial information in the Company’s consolidated financial statements, did not reassess whether any expired or existing contracts contained leases and carried forward existing lease classifications. Additionally, the Company elected to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under the leasing guidance within ASC Topic 840. The Company elected to use hindsight to determine the lease term for existing leases and elected to not separate lease components from non-lease components for all lessee and lessor arrangements.

Emera has implemented additional processes and controls to facilitate the identification, tracking and reporting of potential leases based on the requirements of the standard. There were no updates to information technology systems as a result of implementation.

The Company’s adoption of this new standard resulted in right-of-use (“ROU”) assets and lease liabilities of approximately $58 million as of January 1, 2019. The ROU assets and lease liabilities were measured at the present value of remaining lease payments using the Company’s incremental borrowing rate.

There was no impact to opening retained earnings as at January 1, 2019 or the Company’s net income or cash flows for the year ended December 31, 2019 as a result of the adoption of the standard. There were no significant impacts to Emera’s accounting for lessor arrangements. Refer to note 18 of the consolidated financial statements for further detail.

Targeted Improvements to Accounting for Hedging Activities

On January 1, 2019, the Company adopted ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting recognition and presentation requirements in ASC Topic 815. This standard improves the transparency and understandability of information about an entity’s risk management activities by better aligning the entity’s financial reporting for hedging relationships with those risk management activities and simplifies the application of hedge accounting. The standard will make more financial and nonfinancial hedging strategies eligible for hedge accounting, amends the presentation and disclosure requirements for hedging activities and changes how entities assess hedge effectiveness. There was no impact on the consolidated financial statements as a result of the adoption of this standard.

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Cloud Computing

In August 2018, the Financial Accounting Standards Board (“FASB”) issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. The standard allows entities who are customers in hosting arrangements that are service contracts to apply the existing internal-use software guidance to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The guidance specifies classification for capitalizing implementation costs and related amortization expense within the financial statements and requires additional disclosures. The guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted and can be applied either retrospectively or prospectively. The Company early adopted the standard effective January 1, 2019 and elected to apply the guidance prospectively. There was no material impact on the consolidated financial statements as a result of the adoption of this standard.

3. FUTURE ACCOUNTING PRONOUNCEMENTS

The Company considers the applicability and impact of all ASUs issued by the FASB. The following updates have been issued by the 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 an insignificant impact on the 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. The Company adopted ASU 2016-13 effective January 1, 2020, with no significant changes to accounting and disclosure identified related to the adoption of the standard.

Simplifying the Accounting for Income Taxes

In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes. The standard simplifies the accounting for income taxes by eliminating certain exceptions to the guidance in ASC 740 related to the approach for intraperiod tax allocation, simplifies aspects of accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. The guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2020, with early adoption permitted. The standard will be applied on both a prospective and retrospective basis. The Company is currently evaluating the impact of adoption of the standard on its consolidated financial statements.

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4. DISPOSITIONS

Held for sale

Emera Maine

On March 25, 2019, Emera announced the sale of Emera Maine for a total enterprise value of approximately $1.3 billion USD including cash proceeds of $959 million USD, transferred debt and a working capital adjustment on close. The transaction is expected to close in early 2020, subject to the approval of the MPUC. All other required regulatory approvals have been received. A material gain on the sale is expected to be recognized in earnings at closing.

Emera Maine’s assets and liabilities are classified as held for sale and are measured at the lower of their carrying value or fair value less costs to sell. The measurement did not result in a fair value adjustment. The Company will continue to record depreciation on these assets, through the transaction closing date, as the depreciation continues to be reflected in customer rates and will be reflected in the carryover basis of the assets when sold. Depreciation and amortization of $39 million ($29 million USD) has been recorded on these assets from March 25, 2019, the date they were classified as held for sale to December 31, 2019.

Details of Emera Maine’s assets and liabilities classified as held for sale are as follows:

As at |  | December 31 |
millions of Canadian dollars |  | 2019 |
Regulatory assets |  | $ | 16 |
Receivables and other current assets |  |  | 69 |
Current assets held for sale |  |  | 85 |
Property, plant and equipment |  |  | 1,293 |
Goodwill |  |  | 148 |
Regulatory assets |  |  | 122 |
Other long-term assets |  |  | 56 |
Long-term assets held for sale |  |  | 1,619 |
Total assets held for sale |  | $ | 1,704 |
Regulatory liabilities |  | $ | 11 |
Accounts payable and other current liabilities |  |  | 103 |
Current liabilities associated with assets held for sale |  |  | 114 |
Long-term debt |  |  | 467 |
Deferred income taxes |  |  | 204 |
Regulatory liabilities |  |  | 145 |
Other long-term liabilities |  |  | 83 |
Long-term liabilities associated with assets held for sale |  |  | 899 |
Total liabilities associated with assets held for sale |  | $ | 1,013 |

Dispositions

New England Gas Generation

On March 29, 2019, Emera completed the sale of its three NEGG facilities for cash proceeds of $799 million ($598 million USD) including a working capital adjustment. The NEGG assets were classified as held for sale at December 31, 2018 and the Company ceased depreciation of these assets on November 27, 2018. The NEGG facilities were included within the Company’s Other reportable segment. The earnings impact of this sale transaction was immaterial.

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Details of NEGG’s assets and liabilities classified as held for sale at December 31, 2018 are as follows:

As at millions of Canadian dollars |  | December 31 2018 |
Receivables and other current assets |  | $ | 40 |
Inventory |  |  | 13 |
Current assets held for sale |  |  | 53 |
Property, plant and equipment |  |  | 777 |
Long-term assets held for sale |  |  | 777 |
Total assets held for sale |  | $ | 830 |
Accounts payable and other current liabilities |  | $ | 20 |
Current liabilities associated with assets held for sale |  |  | 20 |
Other long-term liabilities |  |  | 2 |
Long-term liabilities associated with assets held for sale |  |  | 2 |
Total liabilities associated with assets held for sale |  | $ | 22 |

Other

On March 5, 2019, the Company completed the sale of its Bayside facility for cash proceeds of $46 million. The Bayside facility was included within the Company’s Other reportable segment. The earnings impact of this sale transaction was immaterial.

On December 20, 2019, Emera completed the sale of EUS assets. EUS ceased operations on September 30, 2019, and there was no material impact on Emera’s balance sheet or earnings as a result of this transaction.

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5. SEGMENT INFORMATION

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

Effective January 1, 2019, Emera revised its reportable segments to align with strategic priorities and internal governance. These new reporting segments align with how the Company assesses financial performance and makes decisions about resource allocations. All comparative segment financial information has been restated with no impact to reported consolidated results.

The five new reportable segments are:

| ● |  | Florida Electric Utility;

| ● |  | Canadian Electric Utilities;

| ● |  | Other Electric Utilities;

| ● |  | Gas Utilities and Infrastructure; and

| ● |  | Other

millions of Canadian dollars |  | Florida Electric Utility |  |  | Canadian Electric Utilities |  |  | Other Electric Utilities |  |  | Gas Utilities and Infrastructure |  |  | Other |  |  | Inter- Segment Eliminations |  |  | Total |
For the year ended December 31, 2019 |
Operating revenues from external customers (1) |  | $ | 2,596 |  |  | $ | 1,429 |  |  | $ | 744 |  |  | $ | 1,097 |  |  | $ | 245 |  |  | $ | - |  |  | $ | 6,111 |
Inter-segment revenues (1) |  |  | 11 |  |  |  | 1 |  |  |  | - |  |  |  | 22 |  |  |  | 37 |  |  |  | (71) |  |  |  | - |
Total operating revenues |  |  | 2,607 |  |  |  | 1,430 |  |  |  | 744 |  |  |  | 1,119 |  |  |  | 282 |  |  |  | (71) |  |  |  | 6,111 |
AFUDC - debt and equity |  |  | 20 |  |  |  | 6 |  |  |  | 5 |  |  |  | 2 |  |  |  | - |  |  |  | - |  |  |  | 33 |
Depreciation and amortization |  |  | 445 |  |  |  | 231 |  |  |  | 107 |  |  |  | 109 |  |  |  | 11 |  |  |  | - |  |  |  | 903 |
Interest expense, net |  |  | 154 |  |  |  | 142 |  |  |  | 52 |  |  |  | 59 |  |  |  | 331 |  |  |  | - |  |  |  | 738 |
Internally allocated interest (2) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 14 |  |  |  | (14) |  |  |  | - |  |  |  | - |
Income from equity investments |  |  | - |  |  |  | 91 |  |  |  | 5 |  |  |  | 22 |  |  |  | 36 |  |  |  | - |  |  |  | 154 |
Income tax expense (recovery) |  |  | 79 |  |  |  | (10) |  |  |  | 11 |  |  |  | 48 |  |  |  | (67) |  |  |  | - |  |  |  | 61 |
Operating, maintenance and general (“OM&G”) |  |  | 554 |  |  |  | 313 |  |  |  | 195 |  |  |  | 319 |  |  |  | 130 |  |  |  | (47) |  |  |  | 1,464 |
GBPC impairment charge |  |  | - |  |  |  | - |  |  |  | 34 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 34 |
Net income (loss) attributable to common shareholders |  |  | 419 |  |  |  | 229 |  |  |  | 45 |  |  |  | 183 |  |  |  | (213) |  |  |  | - |  |  |  | 663 |
Capital expenditures |  |  | 1,393 |  |  |  | 384 |  |  |  | 195 |  |  |  | 448 |  |  |  | 63 |  |  |  | - |  |  |  | 2,483 |
As at December 31, 2019 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total assets |  |  | 16,214 |  |  |  | 6,717 |  |  |  | 3,069 |  |  |  | 5,489 |  |  |  | 1,459 |  |  |  | (1,106) | (3) |  |  | 31,842 |
Investments subject to significant influence |  |  | - |  |  |  | 1,133 |  |  |  | 41 |  |  |  | 138 |  |  |  | - |  |  |  | - |  |  |  | 1,312 |
Goodwill |  |  | 4,544 |  |  |  | - |  |  |  | 70 |  |  |  | 1,218 |  |  |  | 3 |  |  |  | - |  |  |  | 5,835 |

(1) All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes the elimination of these transactions would understate property, plant and equipment, OM&G expenses, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs.

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

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millions of Canadian dollars |  | Florida Electric Utility |  |  | Canadian Electric Utilities |  |  | Other Electric Utilities |  |  | Gas Utilities and Infrastructure |  |  | Other |  |  | Inter- Segment Eliminations |  |  | Total |
For the year ended December 31, 2018 |
Operating revenues from external customers (1) |  | $ | 2,670 |  |  | $ | 1,437 |  |  | $ | 745 |  |  | $ | 1,062 |  |  | $ | 610 |  |  | $ | - |  |  | $ | 6,524 |
Inter-segment revenues (1) |  |  | 9 |  |  |  | 3 |  |  |  | - |  |  |  | 36 |  |  |  | 51 |  |  |  | (99) |  |  |  | - |
Total operating revenues |  |  | 2,679 |  |  |  | 1,440 |  |  |  | 745 |  |  |  | 1,098 |  |  |  | 661 |  |  |  | (99) |  |  |  | 6,524 |
AFUDC - debt and equity |  |  | 20 |  |  |  | 6 |  |  |  | 3 |  |  |  | 1 |  |  |  | - |  |  |  | - |  |  |  | 30 |
Depreciation and amortization |  |  | 405 |  |  |  | 219 |  |  |  | 114 |  |  |  | 129 |  |  |  | 49 |  |  |  | - |  |  |  | 916 |
Interest expense, net |  |  | 132 |  |  |  | 139 |  |  |  | 48 |  |  |  | 55 |  |  |  | 339 |  |  |  | - |  |  |  | 713 |
Internally allocated interest (2) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 14 |  |  |  | (14) |  |  |  | - |  |  |  | - |
Income from equity investments |  |  | - |  |  |  | 87 |  |  |  | 6 |  |  |  | 22 |  |  |  | 39 |  |  |  | - |  |  |  | 154 |
Income tax expense (recovery) |  |  | 85 |  |  |  | 8 |  |  |  | 9 |  |  |  | 47 |  |  |  | (80) |  |  |  | - |  |  |  | 69 |
OM&G |  |  | 667 |  |  |  | 286 |  |  |  | 188 |  |  |  | 295 |  |  |  | 206 |  |  |  | (62) |  |  |  | 1,580 |
Net income (loss) attributable to common shareholders |  |  | 381 |  |  |  | 218 |  |  |  | 85 |  |  |  | 135 |  |  |  | (109) |  |  |  | - |  |  |  | 710 |
Capital expenditures |  |  | 1,217 |  |  |  | 345 |  |  |  | 187 |  |  |  | 330 |  |  |  | 72 |  |  |  | - |  |  |  | 2,151 |
As at December 31, 2018 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total assets |  |  | 15,997 |  |  |  | 6,275 |  |  |  | 3,094 |  |  |  | 5,404 |  |  |  | 2,653 |  |  |  | (1,109) | (3) |  |  | 32,314 |
Investments subject to significant influence |  |  | - |  |  |  | 1,079 |  |  |  | 77 |  |  |  | 155 |  |  |  | 5 |  |  |  | - |  |  |  | 1,316 |
Goodwill |  |  | 4,774 |  |  |  | - |  |  |  | 260 |  |  |  | 1,279 |  |  |  | - |  |  |  | - |  |  |  | 6,313 |

(1) All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes the elimination of these transactions would understate property, plant and equipment, OM&G expenses, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs.

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

Geographical Information

Revenues (1):

For the |  | Year ended December 31 |
millions of Canadian dollars |  | 2019 |  |  | 2018 |
Canada |  | $ | 1,497 |  |  | $ | 1,520 |
United States |  |  | 4,140 |  |  |  | 4,537 |
Barbados |  |  | 320 |  |  |  | 319 |
The Bahamas |  |  | 112 |  |  |  | 121 |
Dominica |  |  | 42 |  |  |  | 27 |
|  | $ | 6,111 |  |  | $ | 6,524 |
(1) Revenues are based on country of origin of the product or service sold. |  |  |  |  |  |  |  |
Property Plant and Equipment: |
As at millions of Canadian dollars |  | December 31 2019 |  |  | December 31 2018 |
Canada |  | $ | 4,248 |  |  | $ | 4,128 |
United States (1) |  |  | 13,095 |  |  |  | 13,739 |
Barbados |  |  | 462 |  |  |  | 446 |
The Bahamas |  |  | 282 |  |  |  | 315 |
Dominica |  |  | 80 |  |  |  | 84 |
|  | $ | 18,167 |  |  | $ | 18,712 |

(1) Excludes Emera Maine balances classified as held for sale as at December 31, 2019. Refer to note 4 for further details.

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6. REVENUE

The following disaggregates the Company’s revenue by major source:

millions of Canadian dollars |  | Florida Electric Utility |  |  | Canadian Electric Utilities |  |  | Other Electric Utilities |  |  | Gas Utilities and Infrastructure |  |  | Other |  |  | Inter- Segment Eliminations |  |  | Total |
For the year ended December 31, 2019 |
Regulated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Electric Revenue |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 1,387 |  |  | $ | 746 |  |  | $ | 276 |  |  | $ | - |  |  | $ | - |  |  | $ | - |  |  | $ | 2,409 |
Commercial |  |  | 745 |  |  |  | 400 |  |  |  | 339 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 1,484 |
Industrial |  |  | 207 |  |  |  | 210 |  |  |  | 44 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 461 |
Other electric and regulatory deferrals |  |  | 246 |  |  |  | 45 |  |  |  | 13 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 304 |
Other (1) |  |  | 22 |  |  |  | 29 |  |  |  | 72 |  |  |  | - |  |  |  | - |  |  |  | (12) |  |  |  | 111 |
Regulated electric revenue |  |  | 2,607 |  |  |  | 1,430 |  |  |  | 744 |  |  |  | - |  |  |  | - |  |  |  | (12) |  |  |  | 4,769 |
Gas Revenue |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 502 |  |  |  | - |  |  |  | - |  |  |  | 502 |
Commercial |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 298 |  |  |  | - |  |  |  | - |  |  |  | 298 |
Industrial |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 50 |  |  |  | - |  |  |  | - |  |  |  | 50 |
Finance income (2)(3) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 60 |  |  |  | - |  |  |  | - |  |  |  | 60 |
Other |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 193 |  |  |  | - |  |  |  | (22) |  |  |  | 171 |
Regulated gas revenue |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 1,103 |  |  |  | - |  |  |  | (22) |  |  |  | 1,081 |
Non-Regulated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Marketing and trading margin (4) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 31 |  |  |  | - |  |  |  | 31 |
Energy sales (4) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 80 |  |  |  | (12) |  |  |  | 68 |
Capacity |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 38 |  |  |  | - |  |  |  | 38 |
Other |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 16 |  |  |  | 31 |  |  |  | (25) |  |  |  | 22 |
Mark-to-market (3) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 102 |  |  |  | - |  |  |  | 102 |
Non-regulated revenue |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 16 |  |  |  | 282 |  |  |  | (37) |  |  |  | 261 |
Total operating revenues |  | $ | 2,607 |  |  | $ | 1,430 |  |  | $ | 744 |  |  | $ | 1,119 |  |  | $ | 282 |  |  | $ | (71) |  |  | $ | 6,111 |

(1) Other includes rental revenues, which do not represent revenue from contracts with customers.

(2) Revenue related to Brunswick Pipeline’s service agreement with Repsol Energy Canada.

(3) Revenue which does not represent revenues from contracts with customers.

(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers.

101

millions of Canadian dollars |  | Florida Electric Utility |  |  | Canadian Electric Utilities |  |  | Other Electric Utilities |  |  | Gas Utilities and Infrastructure |  |  | Other |  |  | Inter- Segment Eliminations |  |  | Total |
For the year ended December 31, 2018 |
Regulated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Electric Revenue |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 1,384 |  |  | $ | 731 |  |  | $ | 261 |  |  | $ | - |  |  | $ | - |  |  | $ | - |  |  | $ | 2,376 |
Commercial |  |  | 755 |  |  |  | 405 |  |  |  | 350 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 1,510 |
Industrial |  |  | 209 |  |  |  | 233 |  |  |  | 46 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 488 |
Other electric and regulatory deferrals |  |  | 312 |  |  |  | 43 |  |  |  | 16 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 371 |
Other (1) |  |  | 19 |  |  |  | 28 |  |  |  | 72 |  |  |  | - |  |  |  | - |  |  |  | (12) |  |  |  | 107 |
Regulated electric revenue |  |  | 2,679 |  |  |  | 1,440 |  |  |  | 745 |  |  |  | - |  |  |  | - |  |  |  | (12) |  |  |  | 4,852 |
Gas Revenue |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 492 |  |  |  | - |  |  |  | - |  |  |  | 492 |
Commercial |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 291 |  |  |  | - |  |  |  | - |  |  |  | 291 |
Industrial |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 49 |  |  |  | - |  |  |  | - |  |  |  | 49 |
Finance income (2)(3) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 57 |  |  |  | - |  |  |  | - |  |  |  | 57 |
Other |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 191 |  |  |  | - |  |  |  | (36) |  |  |  | 155 |
Regulated gas revenue |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 1,080 |  |  |  | - |  |  |  | (36) |  |  |  | 1,044 |
Non-Regulated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Marketing and trading margin (4) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 115 |  |  |  | - |  |  |  | 115 |
Energy sales (4) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 309 |  |  |  | (16) |  |  |  | 293 |
Capacity |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 136 |  |  |  | - |  |  |  | 136 |
Other |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 18 |  |  |  | 47 |  |  |  | (35) |  |  |  | 30 |
Mark-to-market (3) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 54 |  |  |  | - |  |  |  | 54 |
Non-regulated revenue |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 18 |  |  |  | 661 |  |  |  | (51) |  |  |  | 628 |
Total operating revenues |  | $ | 2,679 |  |  | $ | 1,440 |  |  | $ | 745 |  |  | $ | 1,098 |  |  | $ | 661 |  |  | $ | (99) |  |  | $ | 6,524 |

(1) Other includes rental revenues, which do not represent revenue from contracts with customers.

(2) Revenue related to Brunswick Pipeline’s service agreement with Repsol Energy Canada.

(3) Revenue which does not represent revenues from contracts with customers.

(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers.

Remaining Performance Obligations

Remaining performance obligations primarily represent gas transportation contracts, lighting contracts and long-term steam supply arrangements with fixed contract terms. As of December 31, 2019, the aggregate amount of the transaction price allocated to remaining performance obligations was $347 million (2018 – $370 million). As allowed by the practical expedient in ASC 606, this amount excludes contracts with an original expected length of one year or less and variable amounts for which Emera recognizes revenue at the amount to which it has the right to invoice for services performed. Emera expects to recognize revenue for the remaining performance obligations through 2033.

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7. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME

millions of Canadian dollars |  | Carrying Value As at December 31 |  |  | Equity Income For the year ended December 31 |  |  | Percentage of Ownership |
|  | 2019 |  |  | 2018 |  |  | 2019 |  |  | 2018 |  |  | 2019 |
LIL (1) |  | $ | 579 |  |  | $ | 534 |  |  | $ | 45 |  |  | $ | 42 |  |  |  | 49.5 |
NSPML |  |  | 554 |  |  |  | 545 |  |  |  | 46 |  |  |  | 45 |  |  |  | 100.0 |
M&NP (2) |  |  | 138 |  |  |  | 155 |  |  |  | 22 |  |  |  | 22 |  |  |  | 12.9 |
Lucelec (2) |  |  | 41 |  |  |  | 42 |  |  |  | 3 |  |  |  | 3 |  |  |  | 19.1 |
Bear Swamp (3) |  |  | - |  |  |  | - |  |  |  | 35 |  |  |  | 38 |  |  |  | 50.0 |
Other Investments |  |  | - |  |  |  | 40 |  |  |  | 3 |  |  |  | 4 |  |  |  |  |
|  | $ | 1,312 |  |  | $ | 1,316 |  |  | $ | 154 |  |  | $ | 154 |  |  |  |  |

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

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

(3) The investment balance in Bear Swamp is in a credit position, primarily a result of a $179 million distribution received in 2015. Bear Swamp’s credit investment balance of $137 million (2018 - $172 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 31). NSPML’s consolidated summarized balance sheets are illustrated as follows:

As at millions of Canadian dollars |  | 2019 |  |  | December 31 2018 |
Balance Sheets |  |  |  |  |  |  |  |
Current assets |  | $ | 69 |  |  | $ | 86 |
Property, plant and equipment |  |  | 1,671 |  |  |  | 1,690 |
Regulatory assets |  |  | 177 |  |  |  | 108 |
Non-current assets |  |  | 32 |  |  |  | 32 |
Total assets |  | $ | 1,949 |  |  | $ | 1,916 |
Current liabilities |  | $ | 23 |  |  | $ | 21 |
Long-term debt (1) |  |  | 1,288 |  |  |  | 1,288 |
Non-current liabilities |  |  | 84 |  |  |  | 62 |
Equity |  |  | 554 |  |  |  | 545 |
Total liabilities and equity |  | $ | 1,949 |  |  | $ | 1,916 |

(1) The project debt has been guaranteed by the Government of Canada.

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8. INCOME TAXES

The income tax provision, for the years ended December 31, differs from that computed using the enacted combined Canadian federal and Nova Scotia and New Brunswick provincial statutory income tax rate for the following reasons:

millions of Canadian dollars |  | 2019 |  |  | 2018 |
Income before provision for income taxes |  | $ | 771 |  |  | $ | 816 |
Statutory income tax rate |  |  | 31% |  |  |  | 31% |
Income taxes, at statutory income tax rate |  |  | 239 |  |  |  | 253 |
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities |  |  | (66) |  |  |  | (59) |
Foreign tax rate variance |  |  | (49) |  |  |  | (55) |
Amortization of deferred income tax regulatory liabilities |  |  | (36) |  |  |  | (37) |
Tax effect of equity earnings |  |  | (15) |  |  |  | (15) |
GBPC impairment charge |  |  | 11 |  |  |  | - |
Investment tax credits |  |  | (9) |  |  |  | (4) |
Change in treatment of NMGC net operating loss carryforwards |  |  | (7) |  |  |  | - |
Florida state tax apportionment adjustment |  |  | - |  |  |  | (23) |
Change in prior year unrecognized tax benefits at NSPI |  |  | - |  |  |  | 7 |
Other |  |  | (7) |  |  |  | 2 |
Income tax expense |  | $ | 61 |  |  | $ | 69 |
Effective income tax rate |  |  | 8% |  |  |  | 8% |
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 |  | 2019 |  |  | 2018 |
Current income taxes |  |  |  |  |  |  |  |
Canada |  | $ | (19) |  |  | $ | 3 |
United States |  |  | (46) |  |  |  | (121) |
Other |  |  | 1 |  |  |  | 2 |
Deferred income taxes |  |  |  |  |  |  |  |
Canada |  |  | 45 |  |  |  | 11 |
United States |  |  | 137 |  |  |  | 215 |
Other |  |  | - |  |  |  | (4) |
Investment tax credits |  |  |  |  |  |  |  |
United States |  |  | (9) |  |  |  | (4) |
Operating loss carryforwards |  |  |  |  |  |  |  |
Canada |  |  | (48) |  |  |  | (33) |
Income tax expense (recovery) |  | $ | 61 |  |  | $ | 69 |
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 |  | 2019 |  |  | 2018 |
Canada |  | $ | 98 |  |  | $ | 127 |
United States |  |  | 682 |  |  |  | 646 |
Other |  |  | (9) |  |  |  | 43 |
Income before provision for income taxes |  | $ | 771 |  |  | $ | 816 |

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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 |  | 2019 |  |  | 2018 |
Deferred income tax assets: |  |  |  |  |  |  |  |
Tax loss carryforwards |  | $ | 908 |  |  | $ | 917 |
Tax credit carryforwards |  |  | 311 |  |  |  | 269 |
Regulatory liabilities - cost of removal |  |  | 195 |  |  |  | 206 |
Derivative instruments |  |  | 145 |  |  |  | 90 |
Pension and post-retirement liabilities |  |  | 84 |  |  |  | 126 |
Other |  |  | 329 |  |  |  | 441 |
Total deferred income tax assets before valuation allowance |  |  | 1,972 |  |  |  | 2,049 |
Valuation allowance |  |  | (193) |  |  |  | (163) |
Total deferred income tax assets after valuation allowance |  | $ | 1,779 |  |  | $ | 1,886 |
Deferred income tax (liabilities): |  |  |  |  |  |  |  |
Property, plant and equipment |  | $ | (2,382) |  |  | $ | (2,591) |
Derivative instruments |  |  | (148) |  |  |  | (124) |
Other |  |  | (348) |  |  |  | (316) |
Total deferred income tax liabilities |  | $ | (2,878) |  |  | $ | (3,031) |
Consolidated Balance Sheets presentation: |  |  |  |  |  |  |  |
Long-term deferred income tax assets |  | $ | 186 |  |  | $ | 175 |
Long-term deferred income tax liabilities |  |  | (1,285) |  |  |  | (1,320) |
Net deferred income tax liabilities |  | $ | (1,099) |  |  | $ | (1,145) |

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 certain loss carryforwards and unrealized capital losses on investments. A valuation allowance of $193 million has been recorded as at December 31, 2019 (2018 - $163 million) related to the loss carryforwards and investments.

Emera’s net operating loss (“NOL”), capital loss and tax credit carryforwards and their expiration periods as at December 31, 2019 consisted of the following:

millions of Canadian dollars |  | Gross Tax Carryforwards |  |  | Unrecognized Amounts |  |  | Net Tax Carryforwards |  |  | Expiration Period |
Canada |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NOL |  | $ | 1,131 |  |  | $ | (554) |  |  | $ | 577 |  |  |  | 2027-2039 |
Capital loss |  |  | 80 |  |  |  | (80) |  |  |  | - |  |  |  | Indefinite |
United States |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Federal NOL |  | $ | 2,394 |  |  | $ | - |  |  | $ | 2,394 |  |  |  | 2024-2037 |
State NOL |  |  | 1,174 |  |  |  | - |  |  |  | 1,174 |  |  |  | 2024-2039 |
Tax credit |  |  | 311 |  |  |  | - |  |  |  | 311 |  |  |  | 2020-Indefinite |
Other |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NOL |  | $ | 38 |  |  | $ | (38) |  |  | $ | - |  |  |  | 2020-2026 |

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

millions of Canadian dollars |  | 2019 |  |  | 2018 |
Balance, January 1 |  | $ | 26 |  |  | $ | 19 |
Increases due to tax positions related to current year |  |  | 2 |  |  |  | - |
Increases due to tax positions related to a prior year |  |  | 1 |  |  |  | 8 |
Decreases due to tax positions related to a prior year |  |  | - |  |  |  | (1) |
Balance, December 31 |  | $ | 29 |  |  | $ | 26 |

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The total amount of unrecognized tax benefits as at December 31, 2019 was $29 million (2018 - $26 million), which would affect the effective tax rate if recognized. The total amount of accrued interest with respect to unrecognized tax benefits was $5 million (2018 - $4 million) with $1 million of interest expense recognized in the Consolidated Statements of Income (2018 - $3 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 $1.9 billion as at December 31, 2019 (2018 - $1.4 billion). 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, 2019, 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.

On November 29, 2019, NSPI filed a Notice of Appeal with the Tax Court of Canada with respect to its dispute. 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 be similarly reassessed by the CRA for 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 NSPI has reported its tax position appropriately. NSPI continues to assess its options to resolving the dispute; however, the outcome of the Appeal process is not determinable at this time.

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9. COMMON STOCK

Authorized: Unlimited number of non-par value common shares.

Issued and outstanding: |  | millions of shares |  |  | 2019 millions of Canadian dollars |  |  | millions of shares |  |  | 2018 millions of Canadian dollars |
Balance, December 31, 2018 |  |  | 234.12 |  |  | $ | 5,816 |  |  |  | 228.77 |  |  | $ | 5,601 |
Conversion of Convertible Debentures |  |  | 0.03 |  |  |  | 1 |  |  |  | 0.01 |  |  |  | - |
Issuance of common stock (1) |  |  | 1.77 |  |  |  | 99 |  |  |  | 0.45 |  |  |  | 22 |
Issued under Purchase Plans at market rate |  |  | 3.99 |  |  |  | 202 |  |  |  | 4.87 |  |  |  | 200 |
Discount on shares purchased under Dividend Reinvestment Plan |  |  | - |  |  |  | (7) |  |  |  | - |  |  |  | (9) |
Options exercised under senior management share option plan |  |  | 2.57 |  |  |  | 104 |  |  |  | 0.02 |  |  |  | 1 |
Employee Share Purchase Plan |  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | 1 |
Balance, December 31, 2019 |  |  | 242.48 |  |  | $ | 6,216 |  |  |  | 234.12 |  |  | $ | 5,816 |

(1) As at December 31, 2019 a total of 1.77 million common shares have been issued through Emera’s at-the-market equity program (“ATM Program”) at an average price of $56.56 per share for gross proceeds of $100 million ($98.7 million net of issuance costs).

On July 11, 2019, Emera established an ATM Program that allows the Company to issue up to $600 million of common shares to the public from time to time, at the Company’s discretion, at the prevailing market price. The ATM Program was established under a prospectus supplement to the Company’s short-form base shelf prospectus which expires on July 14, 2021. As at December 31, 2019, an aggregate gross sales limit of $500 million remains available for issuance under the ATM program.

As at December 31, 2019, the following common shares were reserved for issuance: 3.9 million (2018 – 6.5 million) under the senior management stock option plan, 0.9 million (2018 – 1 million) under the employee common share purchase plan and 8.8 million (2018 – 12.6 million) under the dividend reinvestment plan (“DRIP”).

The issuance of common shares under the common share compensation arrangements does not allow the plans to exceed 10 per cent of Emera’s outstanding common shares. As at December 31, 2019, Emera is in compliance with this requirement.

10. 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) |  | 2019 |  |  | 2018 |
Numerator |  |  |  |  |  |  |  |
Net income attributable to common shareholders |  | $ | 662.8 |  |  | $ | 709.6 |
Diluted numerator |  |  | 662.8 |  |  |  | 709.6 |
Denominator |  |  |  |  |  |  |  |
Weighted average shares of common stock outstanding |  |  | 238.5 |  |  |  | 231.7 |
Weighted average deferred share units outstanding |  |  | 1.4 |  |  |  | 1.3 |
Weighted average shares of common stock outstanding – basic |  |  | 239.9 |  |  |  | 233.0 |
Stock-based compensation |  |  | 0.6 |  |  |  | 0.4 |
Convertible Debentures |  |  | - |  |  |  | 0.1 |
Weighted average shares of common stock outstanding – diluted |  |  | 240.5 |  |  |  | 233.5 |
Earnings per common share |  |  |  |  |  |  |  |
Basic |  | $ | 2.76 |  |  | $ | 3.05 |
Diluted |  | $ | 2.76 |  |  | $ | 3.04 |

11. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The components of accumulated other comprehensive income are as follows:

millions of Canadian dollars |  | Unrealized (loss) gain on translation of self-sustaining foreign operations |  |  | Net change in net investment hedges |  |  | (Losses) gains on derivatives recognized as cash flow hedges |  |  | Net change on available-for- sale investments |  |  | Net change in unrecognized pension and post-retirement benefit costs |  |  | Total AOCI |
For the year ended December 31, 2019 |
Balance, January 1, 2019 |  | $ | 654 |  |  | $ | (74) |  |  | $ | (7) |  |  | $ | (1) |  |  | $ | (234) |  |  | $ | 338 |
Other comprehensive income (loss) before reclassifications |  |  | (401) |  |  |  | 78 |  |  |  | 3 |  |  |  | - |  |  |  | - |  |  |  | (320) |
Amounts reclassified from accumulated other comprehensive income loss (gain) |  |  | - |  |  |  | - |  |  |  | 3 |  |  |  | - |  |  |  | 74 |  |  |  | 77 |
Net current period other comprehensive income (loss) |  |  | (401) |  |  |  | 78 |  |  |  | 6 |  |  |  | - |  |  |  | 74 |  |  |  | (243) |
Balance, December 31, 2019 |  | $ | 253 |  |  | $ | 4 |  |  | $ | (1) |  |  | $ | (1) |  |  | $ | (160) |  |  | $ | 95 |
For the year ended December 31, 2018 |
Balance, January 1, 2018 (1) |  | $ | 30 |  |  | $ | 48 |  |  | $ | (3) |  |  | $ | 3 |  |  | $ | (243) |  |  | $ | (165) |
Other comprehensive income (loss) before reclassifications |  |  | 624 |  |  |  | (122) |  |  |  | 2 |  |  |  | - |  |  |  | - |  |  |  | 504 |
Amounts reclassified from accumulated other comprehensive income loss (gain) |  |  | - |  |  |  | - |  |  |  | (6) |  |  |  | (4) |  |  |  | 9 |  |  |  | (1) |
Net current period other comprehensive income (loss) |  |  | 624 |  |  |  | (122) |  |  |  | (4) |  |  |  | (4) |  |  |  | 9 |  |  |  | 503 |
Balance, December 31, 2018 |  | $ | 654 |  |  | $ | (74) |  |  | $ | (7) |  |  | $ | (1) |  |  | $ | (234) |  |  | $ | 338 |

(1) The January 1, 2018 balance of AOCI and Regulatory assets includes a prior period reclassification of $37 million in unrecognized pension and post-retirement benefit costs and $15 million in deferred taxes ($22 million, net of tax) to be consistent with current year presentation.

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

For the |  | Year ended December 31 |
millions of Canadian dollars |  |  |  | 2019 |  |  | 2018 |
Affected line item in the Consolidated Financial Statements |  |  |  |  |  |  |  |
Losses (gain) on derivatives recognized as cash flow hedges |  |  |  |  |  |  |  |
Foreign exchange forwards |  | Operating revenue - regulated |  | $ | 3 |  |  | $ | (5) |
Power and gas swaps |  | Non-regulated fuel for generation and purchased power |  |  | - |  |  |  | (1) |
Total before tax |  |  |  |  | 3 |  |  |  | (6) |
Total net of tax |  |  |  | $ | 3 |  |  | $ | (6) |
Net change in available-for-sale investments |  |  |  |  |  |  |  |
|  | Retained earnings (1) |  |  | - |  |  |  | (4) |
Total net of tax |  |  |  | $ | - |  |  | $ | (4) |
Net change in unrecognized pension and post-retirement benefit costs |  |  |  |  |  |  |  |
Actuarial losses (gains) |  | Operating, maintenance and general (“OM&G”) |  | $ | 17 |  |  | $ | 25 |
Past service costs (gains) |  | OM&G |  |  | (1) |  |  |  | (1) |
Amounts reclassified into obligations |  | Pension and post-retirement benefits |  |  | 39 |  |  |  | (17) |
Amounts reclassified into obligations |  | Regulatory assets |  |  | 28 |  |  |  | - |
Total before tax |  |  |  |  | 83 |  |  |  | 7 |
|  | Income tax recovery (expense) |  |  | (9) |  |  |  | 2 |
Total net of tax |  |  |  | $ | 74 |  |  | $ | 9 |
Total reclassifications out of AOCI, net of tax, for the period |  | $ | 77 |  |  | $ | (1) |

(1) Related to the adoption of ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. Refer to note 2 for additional detail.

12. INVENTORY

As at |  | December 31 |  |  | December 31 |
millions of Canadian dollars |  | 2019 |  |  | 2018 |
Fuel |  | $ | 232 |  |  | $ | 213 |
Materials |  |  | 235 |  |  |  | 241 |
Emission credits |  |  | - |  |  |  | 20 |
|  | $ | 467 |  |  | $ | 474 |

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13. DERIVATIVE INSTRUMENTS

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

|  | Derivative Assets |  |  | Derivative Liabilities |
As at millions of Canadian dollars |  | December 31 2019 |  |  | December 31 2018 |  |  | December 31 2019 |  |  | December 31 2018 |
Cash flow hedges |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Foreign exchange forwards |  | $ | - |  |  | $ | - |  |  | $ | 1 |  |  | $ | 5 |
|  |  | - |  |  |  | - |  |  |  | 1 |  |  |  | 5 |
Regulatory deferral |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity swaps and forwards |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Coal purchases |  |  | 8 |  |  |  | 71 |  |  |  | 39 |  |  |  | 1 |
Power purchases |  |  | 23 |  |  |  | 2 |  |  |  | 36 |  |  |  | 1 |
Natural gas purchases and sales |  |  | 2 |  |  |  | 2 |  |  |  | 5 |  |  |  | 4 |
Heavy fuel oil purchases |  |  | 1 |  |  |  | 1 |  |  |  | - |  |  |  | 1 |
Foreign exchange forwards |  |  | 2 |  |  |  | 29 |  |  |  | 6 |  |  |  | - |
|  |  | 36 |  |  |  | 105 |  |  |  | 86 |  |  |  | 7 |
HFT derivatives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Power swaps and physical contracts |  |  | 19 |  |  |  | 62 |  |  |  | 22 |  |  |  | 76 |
Natural gas swaps, futures, forwards, physical contracts |  |  | 151 |  |  |  | 125 |  |  |  | 381 |  |  |  | 403 |
|  |  | 170 |  |  |  | 187 |  |  |  | 403 |  |  |  | 479 |
Other derivatives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity derivatives and interest rate swaps |  |  | 1 |  |  |  | 1 |  |  |  | - |  |  |  | - |
|  |  | 1 |  |  |  | 1 |  |  |  | - |  |  |  | - |
Total gross current derivatives |  |  | 207 |  |  |  | 293 |  |  |  | 490 |  |  |  | 491 |
Impact of master netting agreements with intent to settle net or simultaneously |  |  | (120) |  |  |  | (126) |  |  |  | (120) |  |  |  | (126) |
|  |  | 87 |  |  |  | 167 |  |  |  | 370 |  |  |  | 365 |
Current |  |  | 54 |  |  |  | 148 |  |  |  | 268 |  |  |  | 260 |
Long-term |  |  | 33 |  |  |  | 19 |  |  |  | 102 |  |  |  | 105 |
Total derivatives |  | $ | 87 |  |  | $ | 167 |  |  | $ | 370 |  |  | $ | 365 |

Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.

Details of master netting agreements, shown net on the Consolidated Balance Sheets, are summarized in the following table:

|  | Derivative Assets |  |  | Derivative Liabilities |
As at millions of Canadian dollars |  | December 31 2019 |  |  | December 31 2018 |  |  | December 31 2019 |  |  | December 31 2018 |
Regulatory deferral |  | $ | 8 |  |  | $ | 1 |  |  | $ | 8 |  |  | $ | 1 |
HFT derivatives |  |  | 112 |  |  |  | 125 |  |  |  | 112 |  |  |  | 125 |
Total impact of master netting agreements with intent to settle net or simultaneously |  | $ | 120 |  |  | $ | 126 |  |  | $ | 120 |  |  | $ | 126 |

Cash Flow Hedges

The Company has foreign exchange forwards to hedge the currency risk for revenue streams denominated in foreign currency for Brunswick Pipeline.

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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 |  | 2019 |  |  |  |  |  | 2018 |
|  | Foreign exchange forwards |  |  | Power swaps |  |  | Foreign exchange forwards |
Realized gain (loss) in operating revenue – regulated |  |  | (3) |  |  |  | - |  |  |  | 5 |
Realized gain (loss) in non-regulated fuel for generation and purchased power |  |  | - |  |  |  | 1 |  |  |  | - |
Total gains (losses) in Net income |  | $ | (3) |  |  | $ | 1 |  |  | $ | 5 |
As at |  | December 31 |
millions of Canadian dollars |  | 2019 |  |  |  |  |  | 2018 |
|  | Foreign exchange forwards |  |  | Power swaps |  |  | Foreign exchange forwards |
Total unrealized gain (loss) in AOCI – effective portion, net of tax |  | $ | (1) |  |  | $ | (1) |  |  | $ | (6) |

The Company expects $1 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, 2019, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:

millions |  | 2020 |
Foreign exchange forwards (USD) sales |  | $ | 30 |

Regulatory Deferral

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 |  |  |  |  | 2019 |  |  |  |  |  | 2018 |
|  | Commodity swaps and forwards |  |  | Foreign exchange forwards |  |  | Commodity swaps and forwards |  |  | Foreign exchange forwards |
Unrealized gain (loss) in regulatory assets |  | $ | (89) |  |  | $ | (6) |  |  | $ | (34) |  |  | $ | 4 |
Unrealized gain (loss) in regulatory liabilities |  |  | 9 |  |  |  | (8) |  |  |  | 29 |  |  |  | 24 |
Realized (gain) loss in regulatory liabilities |  |  | (2) |  |  |  | - |  |  |  | (8) |  |  |  | - |
Realized (gain) loss in inventory (1) |  |  | (36) |  |  |  | (11) |  |  |  | (55) |  |  |  | (18) |
Realized (gain) loss in regulated fuel for generation and purchased power (2) |  |  | 3 |  |  |  | (8) |  |  |  | (2) |  |  |  | (9) |
Total change derivative instruments |  | $ | (115) |  |  | $ | (33) |  |  | $ | (70) |  |  | $ | 1 |

(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.

(2) Realized (gains) losses on derivative instruments settled and consumed in the period; hedging relationships that have been terminated or the hedged transaction is no longer probable.

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Commodity Swaps and Forwards

As at December 31, 2019, the Company had the following notional volumes of commodity swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below:

|  | 2020 |  |  | 2021-2022 |
millions |  | Purchases |  |  | Purchases |
Coal (metric tonnes) |  |  | - |  |  |  | 1 |
Natural Gas (Mmbtu) |  |  | 12 |  |  |  | 21 |
Heavy fuel oil (bbls) |  |  | - |  |  |  | 1 |
Power (MWh) |  |  | 1 |  |  |  | 3 |

Foreign Exchange Swaps and Forwards

As at December 31, 2019, the Company had the following notional volumes of foreign exchange swaps and forward contracts designated as regulated deferral that are expected to settle as outlined below:

|  | 2020 |  |  | 2021-2022 |
Foreign exchange contracts (millions of US dollars) |  | $ | 173 |  |  | $ | 148 |
Weighted average rate |  |  | 1.3148 |  |  |  | 1.3264 |
% of USD requirements |  |  | 85% |  |  |  | 39% |

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

Held-for-Trading Derivatives

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

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

For the |  | Year ended December 31 |
millions of Canadian dollars |  | 2019 |  |  | 2018 |
Power swaps and physical contracts in non-regulated operating revenues |  | $ | 1 |  |  | $ | (12) |
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues |  |  | 281 |  |  |  | 205 |
Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power |  |  | (6) |  |  |  | 2 |
|  | $ | 276 |  |  | $ | 195 |

As at December 31, 2019, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:

millions |  | 2020 |  |  | 2021 |  |  | 2022 |  |  | 2023 |  |  | 2024 |
Natural gas purchases (Mmbtu) |  |  | 424 |  |  |  | 84 |  |  |  | 56 |  |  |  | 41 |  |  |  | 26 |
Natural gas sales (Mmbtu) |  |  | 345 |  |  |  | 33 |  |  |  | 9 |  |  |  | 2 |  |  |  | 2 |
Power purchases (MWh) |  |  | 1 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Power sales (MWh) |  |  | 1 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |

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Other Derivatives

As at December 31, 2019, the Company had equity derivatives in place to manage the cash flow risk associated with forecasted future cash settlements of deferred compensation obligations. The equity derivative hedges the return on 2.8 million shares and extends until December of 2020.

For the |  | Year ended December 31 |
millions of Canadian dollars |  | 2019 |  |  | 2018 |
|  | Equity derivatives |  |  | Interest rate swaps |
Unrealized gain in operating, maintenance and general |  | $ | 1 |  |  | $ | - |
Unrealized gain (loss) in interest expense, net |  |  | - |  |  |  | (1) |
Realized gain in operating, maintenance and general |  |  | 27 |  |  |  | - |
Total gains (losses) in net income |  | $ | 28 |  |  | $ | (1) |

Credit Risk

The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high risk accounts.

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

As at December 31, 2019, the maximum exposure the Company has to credit risk is $860 million (2018 - $1,035 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, 2019 was $259 million (2018 - $346 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.

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As at December 31, 2019, the Company had $115 million (2018 - $118 million) in financial assets, considered to be past due, which have been outstanding for an average 71 days. The fair value of these financial assets is $106 million (2018 - $107 million), the difference of which is included in the allowance for doubtful accounts. These assets primarily relate to accounts receivable from electric and gas revenue.

Concentration Risk

The Company’s concentrations of risk consisted of the following:

As at |  | December 31, 2019 |  |  | December 31, 2018 |
|  | millions of Canadian dollars |  |  | % of total exposure |  |  | millions of Canadian dollars |  |  | % of total exposure |
Receivables, net |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Regulated utilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 344 |  |  |  | 31% |  |  | $ | 384 |  |  |  | 28% |
Commercial |  |  | 170 |  |  |  | 15% |  |  |  | 182 |  |  |  | 13% |
Industrial |  |  | 66 |  |  |  | 6% |  |  |  | 57 |  |  |  | 4% |
Other |  |  | 131 |  |  |  | 12% |  |  |  | 84 |  |  |  | 6% |
|  |  | 711 |  |  |  | 64% |  |  |  | 707 |  |  |  | 51% |
Trading group |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Credit rating of A- or above |  |  | 38 |  |  |  | 3% |  |  |  | 49 |  |  |  | 4% |
Credit rating of BBB- to BBB+ |  |  | 59 |  |  |  | 5% |  |  |  | 70 |  |  |  | 5% |
Credit rating of CCC- to CCC+ |  |  | - |  |  |  | 0% |  |  |  | 8 |  |  |  | 0% |
Not rated |  |  | 95 |  |  |  | 9% |  |  |  | 108 |  |  |  | 8% |
|  |  | 192 |  |  |  | 17% |  |  |  | 235 |  |  |  | 17% |
Other accounts receivable |  |  | 184 |  |  |  | 16% |  |  |  | 273 |  |  |  | 20% |
Classification as assets held for sale (1) |  |  | (55) |  |  |  | -5% |  |  |  | - |  |  |  | 0% |
|  |  | 1,032 |  |  |  | 92% |  |  |  | 1,215 |  |  |  | 88% |
Derivative Instruments (current and long-term) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Credit rating of A- or above |  |  | 47 |  |  |  | 4% |  |  |  | 130 |  |  |  | 9% |
Credit rating of BBB- to BBB+ |  |  | 8 |  |  |  | 1% |  |  |  | 9 |  |  |  | 1% |
Not rated |  |  | 32 |  |  |  | 3% |  |  |  | 28 |  |  |  | 2% |
|  |  | 87 |  |  |  | 8% |  |  |  | 167 |  |  |  | 12% |
|  | $ | 1,119 |  |  |  | 100% |  |  | $ | 1,382 |  |  |  | 100% |

(1) Emera Maine’s assets and liabilities are classified as held for sale. Refer to note 4 for further details.

Cash Collateral

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

As at |  | December 31 |  |  | December 31 |
millions of Canadian dollars |  | 2019 |  |  | 2018 |
Cash collateral provided to others |  | $ | 101 |  |  | $ | 103 |
Cash collateral received from others |  |  | 2 |  |  |  | 77 |

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

As at December 31, 2019, the total fair value of these derivatives, in a liability position, was $370 million (December 31, 2018 – $365 million). If the credit ratings of the Company were reduced below investment grade, the full value of the net liability position could be required to be posted as collateral for these derivatives.

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14. 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 1) and uses a market approach to do so. The three levels of the fair value hierarchy are defined as follows:

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

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

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

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

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

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

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

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

As at |  | December 31, 2019 |
millions of Canadian dollars |  | Level 1 |  |  | Level 2 |  |  | Level 3 |  |  | Total |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Regulatory deferral |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity swaps and forwards |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Power purchases |  |  | 23 |  |  |  | - |  |  |  | - |  |  |  | 23 |
Natural gas purchases and sales |  |  | - |  |  |  | 2 |  |  |  | - |  |  |  | 2 |
Heavy fuel oil purchases |  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | 1 |
Foreign exchange forwards |  |  | - |  |  |  | 2 |  |  |  | - |  |  |  | 2 |
|  |  | 23 |  |  |  | 5 |  |  |  | - |  |  |  | 28 |
HFT derivatives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Power swaps and physical contracts |  |  | 1 |  |  |  | 3 |  |  |  | 1 |  |  |  | 5 |
Natural gas swaps, futures, forwards, physical contracts and related transportation |  |  | (7) |  |  |  | 46 |  |  |  | 14 |  |  |  | 53 |
|  |  | (6) |  |  |  | 49 |  |  |  | 15 |  |  |  | 58 |
Other derivatives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity derivatives |  |  | 1 |  |  |  | - |  |  |  | - |  |  |  | 1 |
|  |  | 1 |  |  |  | - |  |  |  | - |  |  |  | 1 |
Total assets |  |  | 18 |  |  |  | 54 |  |  |  | 15 |  |  |  | 87 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash flow hedges |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Foreign exchange forwards |  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | 1 |
|  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | 1 |
Regulatory deferral |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity swaps and forwards |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Coal purchases |  |  | - |  |  |  | 31 |  |  |  | - |  |  |  | 31 |
Power purchases |  |  | 36 |  |  |  | - |  |  |  | - |  |  |  | 36 |
Natural gas purchases and sales |  |  | 3 |  |  |  | 2 |  |  |  | - |  |  |  | 5 |
Foreign exchange forwards |  |  | - |  |  |  | 6 |  |  |  | - |  |  |  | 6 |
|  |  | 39 |  |  |  | 39 |  |  |  | - |  |  |  | 78 |
HFT derivatives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Power swaps and physical contracts |  |  | 5 |  |  |  | 2 |  |  |  | - |  |  |  | 7 |
Natural gas swaps, futures, forwards and physical contracts |  |  | 2 |  |  |  | 33 |  |  |  | 249 |  |  |  | 284 |
|  |  | 7 |  |  |  | 35 |  |  |  | 249 |  |  |  | 291 |
Total liabilities |  |  | 46 |  |  |  | 75 |  |  |  | 249 |  |  |  | 370 |
Net assets (liabilities) |  | $ | (28) |  |  | $ | (21) |  |  | $ | (234) |  |  | $ | (283) |

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As at |  | December 31, 2018 |
millions of Canadian dollars |  | Level 1 |  |  | Level 2 |  |  | Level 3 |  |  | Total |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Regulatory deferral |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity swaps and forwards |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Coal purchases |  |  | - |  |  |  | 70 |  |  |  | - |  |  |  | 70 |
Power purchases |  |  | 2 |  |  |  | - |  |  |  | - |  |  |  | 2 |
Natural gas purchases and sales |  |  | - |  |  |  | 2 |  |  |  | - |  |  |  | 2 |
Heavy fuel oil purchases |  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | 1 |
Foreign exchange forwards |  |  | - |  |  |  | 29 |  |  |  | - |  |  |  | 29 |
|  |  | 2 |  |  |  | 102 |  |  |  | - |  |  |  | 104 |
HFT derivatives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Power swaps and physical contracts |  |  | 2 |  |  |  | 2 |  |  |  | 3 |  |  |  | 7 |
Natural gas swaps, futures, forwards, physical contracts and related transportation |  |  | 1 |  |  |  | 36 |  |  |  | 18 |  |  |  | 55 |
|  |  | 3 |  |  |  | 38 |  |  |  | 21 |  |  |  | 62 |
Other derivatives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate swap |  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | 1 |
|  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | 1 |
Total assets |  |  | 5 |  |  |  | 141 |  |  |  | 21 |  |  |  | 167 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash flow hedges |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Foreign exchange forwards |  |  | - |  |  |  | 5 |  |  |  | - |  |  |  | 5 |
|  |  | - |  |  |  | 5 |  |  |  | - |  |  |  | 5 |
Regulatory deferral |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity swaps and forwards |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Coal purchases |  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | 1 |
Power purchases |  |  | 1 |  |  |  | - |  |  |  | - |  |  |  | 1 |
Heavy fuel oil purchases |  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | 1 |
Natural gas purchases and sales |  |  | 3 |  |  |  | - |  |  |  | - |  |  |  | 3 |
|  |  | 4 |  |  |  | 2 |  |  |  | - |  |  |  | 6 |
HFT derivatives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Power swaps and physical contracts |  |  | 14 |  |  |  | 6 |  |  |  | 1 |  |  |  | 21 |
Natural gas swaps, futures, forwards and physical contracts |  |  | - |  |  |  | 28 |  |  |  | 305 |  |  |  | 333 |
|  |  | 14 |  |  |  | 34 |  |  |  | 306 |  |  |  | 354 |
Total liabilities |  |  | 18 |  |  |  | 41 |  |  |  | 306 |  |  |  | 365 |
Net assets (liabilities) |  | $ | (13) |  |  | $ | 100 |  |  | $ | (285) |  |  | $ | (198) |

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The change in the fair value of the Level 3 financial assets for the year ended December 31, 2019 was as follows:

|  | HFT Derivatives |
millions of Canadian dollars |  | Power |  |  | Natural gas |  |  | Total |
Balance, January 1, 2019 |  | $ | 3 |  |  | $ | 18 |  |  | $ | 21 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues |  |  | (2) |  |  |  | (4) |  |  |  | (6) |
Balance, December 31, 2019 |  | $ | 1 |  |  | $ | 14 |  |  | $ | 15 |

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

|  | HFT Derivatives |
millions of Canadian dollars |  | Power |  |  | Natural gas |  |  | Total |
Balance, January 1, 2019 |  | $ | 1 |  |  | $ | 305 |  |  | $ | 306 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues |  |  | (1) |  |  |  | (56) |  |  |  | (57) |
Balance, December 31, 2019 |  | $ | - |  |  | $ | 249 |  |  | $ | 249 |

The Company evaluates the observable inputs of market data on a quarterly basis in order to determine if transfers between levels is appropriate. For the year ended December 31, 2019, there were no transfers between levels.

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

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

As at |  | December 31, 2019 |
millions of Canadian dollars |  | Fair Value |  |  | Valuation Technique |  |  | Unobservable Input |  |  | Range |  |  | Weighted average |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
HFT derivatives – |  | $ | 1 |  |  |  | Modelled pricing |  |  |  | Third-party pricing |  |  |  | $21.40-$74.05 |  |  |  | $35.03 |
Power swaps and |  |  |  |  |  |  |  |  |  |  | Probability of default |  |  |  | 0.01%-1.14% |  |  |  | 0.21% |
physical contracts |  |  |  |  |  |  |  |  |  |  | Discount rate |  |  |  | 0.15%-6.65% |  |  |  | 2.78% |
HFT derivatives – |  |  | 9 |  |  |  | Modelled pricing |  |  |  | Third-party pricing |  |  |  | $1.63-$7.45 |  |  |  | $2.37 |
Natural gas swaps, futures, |  |  |  |  |  |  |  |  |  |  | Probability of default |  |  |  | 0.01%-2.31% |  |  |  | 0.09% |
forwards, physical contracts |  |  |  |  |  |  |  |  |  |  | Discount rate |  |  |  | 0.01%-20.93% |  |  |  | 1.55% |
|  |  | 5 |  |  |  | Modelled pricing |  |  |  | Third-party pricing |  |  |  | $1.33-$8.76 |  |  |  | $5.05 |
|  |  |  |  |  |  |  |  |  |  | Basis adjustment |  |  |  | $0.00-$1.31 |  |  |  | $0.76 |
|  |  |  |  |  |  |  |  |  |  | Probability of default |  |  |  | 0.01%-3.33% |  |  |  | 0.28% |
|  |  |  |  |  |  |  |  |  |  | Discount rate |  |  |  | 0.01%-4.71% |  |  |  | 0.91% |
Total assets |  | $ | 15 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
HFT derivatives – |  |  | 228 |  |  |  | Modelled pricing |  |  |  | Third-party pricing |  |  |  | $1.54-$7.45 |  |  |  | $4.07 |
Natural gas swaps, futures, |  |  |  |  |  |  |  |  |  |  | Own credit risk |  |  |  | 0.01%-2.31% |  |  |  | 0.12% |
forwards and physical contracts |  |  |  |  |  |  |  |  |  |  | Discount rate |  |  |  | 0.01%-18.63% |  |  |  | 1.89% |
|  |  | 21 |  |  |  | Modelled pricing |  |  |  | Third-party pricing |  |  |  | $1.36-$9.75 |  |  |  | $5.45 |
|  |  |  |  |  |  |  |  |  |  | Basis adjustment |  |  |  | $0.00-$1.31 |  |  |  | $0.91 |
|  |  |  |  |  |  |  |  |  |  | Own credit risk |  |  |  | 0.01%-3.33% |  |  |  | 0.06% |
|  |  |  |  |  |  |  |  |  |  | Discount rate |  |  |  | 0.01%-3.76% |  |  |  | 0.81% |
Total liabilities |  | $ | 249 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net assets (liabilities) |  | $ | (234) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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As at |  | December 31, 2018 |
millions of Canadian dollars |  | Fair Value |  |  | Valuation Technique |  |  | Unobservable Input |  |  | Range |  |  | Weighted average |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
HFT derivatives – |  | $ | 3 |  |  |  | Modelled pricing |  |  |  | Third-party pricing |  |  |  | $24.31 - $50.29 |  |  |  | $31.43 |
Power swaps and |  |  |  |  |  |  |  |  |  |  | Probability of default |  |  |  | 0.03% - 0.13% |  |  |  | 0.13% |
physical contracts |  |  |  |  |  |  |  |  |  |  | Discount rate |  |  |  | 0.03% - 2.19% |  |  |  | 1.45% |
|  |  |  |  |  |  |  |  |  |  | Correlation factor |  |  |  | 84.98% - 84.98% |  |  |  | 84.98% |
HFT derivatives – |  |  | 8 |  |  |  | Modelled pricing |  |  |  | Third-party pricing |  |  |  | $1.80 - $12.21 |  |  |  | $4.75 |
Natural gas swaps, |  |  |  |  |  |  |  |  |  |  | Probability of default |  |  |  | 0.01% - 2.94% |  |  |  | 0.24% |
futures, forwards, |  |  |  |  |  |  |  |  |  |  | Discount rate |  |  |  | 0.01% - 30.62% |  |  |  | 4.25% |
physical contracts |  |  | 10 |  |  |  | Modelled pricing |  |  |  | Third-party pricing |  |  |  | $1.95 - $12.90 |  |  |  | $8.68 |
and related transportation |  |  |  |  |  |  |  |  |  |  | Basis adjustment |  |  |  | $0.07 - $3.43 |  |  |  | $1.88 |
|  |  |  |  |  |  |  |  |  |  | Probability of default |  |  |  | 0.01% - 3.20% |  |  |  | 0.57% |
|  |  |  |  |  |  |  |  |  |  | Discount rate |  |  |  | 0.01% - 7.61% |  |  |  | 0.42% |
Total assets |  | $ | 21 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
HFT derivatives – |  |  | 1 |  |  |  | Modelled pricing |  |  |  | Third-party pricing |  |  |  | $20.80 - $50.29 |  |  |  | $26.38 |
Power swaps and |  |  |  |  |  |  |  |  |  |  | Correlation factor |  |  |  | 84.98% - 84.98% |  |  |  | 84.98% |
physical contracts |  |  |  |  |  |  |  |  |  |  | Probability of default |  |  |  | 0.08% - 0.29% |  |  |  | 0.15% |
|  |  |  |  |  |  |  |  |  |  | Discount rate |  |  |  | 0.03% - 2.99% |  |  |  | 1.65% |
HFT derivatives – |  |  | 286 |  |  |  | Modelled pricing |  |  |  | Third-party pricing |  |  |  | $1.48 - $12.90 |  |  |  | $5.75 |
Natural gas swaps, futures, |  |  |  |  |  |  |  |  |  |  | Own credit risk |  |  |  | 0.01% - 2.94% |  |  |  | 0.09% |
forwards and physical contracts |  |  |  |  |  |  |  |  |  |  | Discount rate |  |  |  | 0.01% - 11.96% |  |  |  | 2.35% |
|  |  | 19 |  |  |  | Modelled pricing |  |  |  | Third-party pricing |  |  |  | $2.15 - $13.18 |  |  |  | $7.54 |
|  |  |  |  |  |  |  |  |  |  | Basis adjustment |  |  |  | $0.07 - $3.43 |  |  |  | $2.67 |
|  |  |  |  |  |  |  |  |  |  | Own credit risk |  |  |  | 0.01% - 2.76% |  |  |  | 0.10% |
|  |  |  |  |  |  |  |  |  |  | Discount rate |  |  |  | 0.01% - 7.61% |  |  |  | 1.38% |
Total liabilities |  | $ | 306 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net assets (liabilities) |  | $ | (285) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

The financial liabilities included on the Consolidated Balance Sheets that are not measured at fair value consisted of long-term debt, as follows:

As at |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
millions of Canadian dollars |  | Carrying Amount |  |  | Fair Value |  |  | Level 1 |  |  | Level 2 |  |  | Level 3 |  |  | Total |
December 31, 2019 |  | $ | 14,180 |  |  | $ | 16,049 |  |  | $ | - |  |  | $ | 15,598 |  |  | $ | 451 |  |  | $ | 16,049 |
December 31, 2018 |  | $ | 15,411 |  |  | $ | 15,908 |  |  | $ | - |  |  | $ | 14,991 |  |  | $ | 917 |  |  | $ | 15,908 |

The Company has designated $1.2 billion United States dollar denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in United States dollar denominated operations. An after-tax foreign currency gain of $78 million was recorded in Other Comprehensive Income for the year ended December 31, 2019 (2018 – $122 million loss after-tax).

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15. REGULATORY ASSETS AND LIABILITIES

Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates or tolls collected from customers. Management believes existing regulatory assets are probable for recovery either because the Company received specific approval from the applicable 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.

Regulatory Assets and Liabilities

As at |  | December 31 |  |  | December 31 |
millions of Canadian dollars |  |  | 2019 | (1) |  |  | 2018 |
Regulatory assets |  |  |  |  |  |  |  |
Deferred income tax regulatory assets |  | $ | 862 |  |  | $ | 775 |
Pension and post-retirement medical plan |  |  | 380 |  |  |  | 453 |
Deferrals related to derivative instruments |  |  | 81 |  |  |  | 10 |
Storm restoration regulatory asset |  |  | 38 |  |  |  | 32 |
Stranded cost recovery |  |  | 27 |  |  |  | 28 |
Environmental remediations |  |  | 26 |  |  |  | 31 |
Demand side management (“DSM”) deferral |  |  | 19 |  |  |  | 24 |
Unamortized defeasance costs |  |  | 19 |  |  |  | 26 |
Cost recovery clauses |  |  | 13 |  |  |  | 75 |
Other |  |  | 87 |  |  |  | 115 |
|  | $ | 1,552 |  |  | $ | 1,569 |
Current |  | $ | 121 |  |  | $ | 165 |
Long-term |  |  | 1,431 |  |  |  | 1,404 |
Total regulatory assets |  | $ | 1,552 |  |  | $ | 1,569 |
Regulatory liabilities |  |  |  |  |  |  |  |
Deferred income tax regulatory liabilities |  |  | 985 |  |  |  | 1,218 |
Accumulated reserve - cost of removal |  |  | 891 |  |  |  | 955 |
Regulated fuel adjustment mechanism |  |  | 115 |  |  |  | 161 |
Storm reserve |  |  | 62 |  |  |  | 76 |
Cost recovery clauses |  |  | 53 |  |  |  | 30 |
Deferrals related to derivative instruments |  |  | 42 |  |  |  | 116 |
Self-insurance fund (note 31) |  |  | 29 |  |  |  | 30 |
Other |  |  | 4 |  |  |  | 24 |
|  | $ | 2,181 |  |  | $ | 2,610 |
Current |  | $ | 295 |  |  | $ | 251 |
Long-term |  |  | 1,886 |  |  |  | 2,359 |
Total regulatory liabilities |  | $ | 2,181 |  |  | $ | 2,610 |

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

Deferred Income Tax Regulatory Assets and Liabilities

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.

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Pension and Post-Retirement Medical Plan

This asset is primarily related to the deferred costs of pension and post-retirement benefits at Tampa Electric, PGS and NMGC. It is included in rate base and earns a rate of return as permitted by the FPSC, New Mexico Public Regulation Commission (“NMPRC”) and Maine Public Utilities Commission (“MPUC”), as applicable. It is amortized over the remaining service life of plan participants.

Deferrals Related to Derivative Instruments

This asset is primarily related to NSPI deferring 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 as approved by its regulator. The realized gain or loss is recognized when the hedged item settles in regulated fuel for generation and purchased power, inventory, operating, maintenance or general or property, plant and equipment, depending on the nature of the item being economically hedged.

Storm Restoration Regulatory Asset

This asset represents storm restoration costs, primarily incurred by GBPC. GBPC maintains insurance for its generation facilities and, as with most utilities, its transmission and distribution networks are self-insured. On September 1, 2019, Dorian struck Grand Bahama Island as a Category 5 hurricane, with sustained winds of approximately 285 kilometres per hour. The hurricane stalled over the island for several days, causing significant damage to, or destruction of, homes and businesses served by GBPC. GBPC’s generation, transmission and distribution assets sustained damage, including the effect of flooding that resulted from storm surge and rain.

It is currently estimated that restoration costs for GBPC self-insured assets will be approximately $15 million USD. In January 2020, the GBPA approved the recovery of these costs through rates over a five-year period. Approximately $12 million USD ($15 million CAD) of these estimated costs were incurred in 2019, and recorded as a regulatory asset.

Restoration costs associated with Hurricane Matthew in 2016 are being amortized over five years and included in rate base as approved by the Grand Bahama Port Authority (“GBPA”) for full recovery. The balance as at December 31, 2019 is $23 million.

Stranded Cost Recovery

Due to the decommissioning of a GBPC steam turbine in 2012, the GBPA approved the recovery of a $21 million USD stranded cost through electricity rates; it is included in rate base for 2019 and 2018 and is expected to be included in future years.

Environmental Remediations

This asset is primarily related to PGS costs associated with environmental remediation at Manufactured Gas Plant (“MGP”) 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.

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DSM Deferral

The UARB approved implementation of the 2015 DSM deferral set at $35 million for 2015 and recoverable from customers over an eight year period beginning in 2016.

The UARB directed EfficiencyOne to review financing options through which EfficiencyOne would borrow the 2015 deferral amount from a commercial lender in order to repay NSPI the amount it expended on behalf of its customers in 2015. In December 2016, EfficiencyOne secured financing and $31 million was advanced to NSPI to finance the 2015 DSM deferral. As NSPI collects the associated amounts from customers over the next six years, it will repay the balance to EfficiencyOne. This has been set up as a liability in “Other long-term liabilities” with the current portion of the liability included in “Other current liabilities” on the Consolidated Balance Sheets.

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 at December 31, 2019, totalled $740 million (2018 – $759 million). 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 permitted by the Nova Scotia Utility and Review Board (“UARB”).

Cost Recovery Clauses

These assets and liabilities are related to Tampa Electric, PGS and NMGC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year.

Accumulated Reserve – Cost of Removal (“COR”)

This regulatory liability represents the non-ARO COR reserve in Tampa Electric, PGS, NMGC 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.

Regulated Fuel Adjustment Mechanism

This regulated liability is the difference between actual fuel costs and amounts recovered from NSPI customers through electricity rates in a given year, and deferred to a fuel adjustment mechanism (“FAM”) regulatory asset or liability and recovered from or returned to customers in a subsequent year. For the years 2017 to 2019, differences between actual fuel costs and fuel revenues recovered from customers will be recovered or returned to customers after 2019, as required under the Electricity Plan Implementation (2015) Act, (“Electricity Plan Act”). As approved on December 6, 2019 as part of NSPI’s three-year fuel stability plan, differences between actual fuel costs and fuel revenues recovered from customers for the years 2020 to 2022, will be recovered or returned to customers after 2022.

Storm Reserve

The storm reserve is for hurricanes and other named storms that cause significant damage to Tampa Electric and PGS systems. As allowed by the FPSC, if the charges to the storm reserve exceed the storm liability, the excess is to be carried as a regulatory asset. Tampa Electric and PGS 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 the reserve. In September 2019, Tampa Electric incurred approximately $8 million USD in storm restoration preparation costs for Hurricane Dorian. These costs were charged to the storm reserve regulatory liability.

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Regulatory Environments

Florida Electric Utility

Tampa Electric is regulated by the FPSC. Tampa Electric is also subject to regulation by the Federal Energy Regulatory Commission (“FERC”). The FPSC sets rates at a level that allows utilities such as Tampa Electric to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital.

Tampa Electric’s approved regulated return on equity (“ROE”) range for 2019 and 2018 is 9.25 per cent to 11.25 per cent based on an allowed equity capital structure of 54 per cent. An ROE of 10.25 per cent is used for the calculation of the return on investments for clauses.

Tampa Electric has a fuel recovery clause approved by the FPSC, allowing the opportunity to recover fluctuating fuel expenses from customers through annual fuel rate adjustments. The FPSC annually approves cost-recovery rates for purchased power, capacity, environmental and conservation costs including a return on capital invested. Differences between the prudently incurred fuel costs and the cost-recovery rates and amounts recovered from customers through electricity rates in a year are deferred to a regulatory asset or liability and recovered from or returned to customers in a subsequent year.

As of December 31, 2019, Tampa Electric has invested approximately $820 million USD in 600 MW of utility-scale solar photovoltaic projects, which are recoverable through FPSC-approved solar base rate adjustments (“SoBRAs”). Tampa Electric expects to invest an additional $30 million USD in these projects through 2021. AFUDC is being earned on these projects during construction. The FPSC has approved SoBRAs representing a total of 554 MW or $96 million USD annually in estimated revenue requirements for in-service projects. Tampa Electric expects to file its final SoBRA petition for the January 1, 2021 tranche in 2020.

On December 10, 2019, the FPSC approved Tampa Electric’s petition to reduce base rates and charges reflecting reduction of the state income tax from 5.5 per cent to 4.46 per cent retroactive from January 1, 2019. The base rate reduction of approximately $5 million USD due to customers is subject to true-up, and the actual rate reduction may vary from year to year.

On October 3, 2019, the FPSC issued a rule to implement a storm protection cost recovery clause. This new clause provides a process for Florida investor-owned utilities, including Tampa Electric, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Subject to final approval of the FPSC rule, Tampa Electric expects to file a storm protection plan with the FPSC in Q2 2020.

On August 20, 2018, the FPSC approved a reduction in base rates of $103 million USD annually beginning in 2019 as a result of lower tax expense due to 2018 US tax reform benefits. On April 9, 2019, Tampa Electric reached a settlement agreement with consumer parties regarding eligible storm costs as a result of Hurricane Irma in 2017, which was approved by the FPSC on May 21, 2019. As a result, Tampa Electric refunded $12 million USD to customers in January 2020, resulting in minimal impact to the Consolidated Statements of Income.

Canadian Electric Utilities

NSPI

NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (the “Public Utilities Act”) and is subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval.

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NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers and provide an appropriate return to investors. NSPI’s approved regulated ROE range for 2019 and 2018 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.

The Electricity Plan Act, was enacted by the Province of Nova Scotia in December 2015, with a goal of providing rate stability and predictability for customers for the 2017 through 2019 period. In March 2016, in accordance with the Electricity Plan Act, NSPI announced that it would not file a General Rate Application (“GRA”) for non-fuel electricity rates for the 2017 through 2019 period. The UARB approved NSPI’s three-year fuel stability plan for 2017 through 2019, which resulted in an average annual overall rate increase of 1.5 per cent to recover fuel costs for each of these three years.

On December 6, 2019, the UARB approved NSPI’s three-year fuel stability plan which results in an average annual overall rate increase of 1.5 per cent to recover fuel costs for the period of 2020 through 2022. For the years 2020 to 2022, differences between actual fuel costs and fuel revenues recovered from customers will be recovered from or returned to customers after 2022. The decision further directed that annual excess non-fuel revenues above NSPI’s approved range of ROE are to be applied to the FAM.

In September 2017, the UARB approved NSPI’s interim assessment payment to NSP Maritime Link Inc. (“NSPML”) of the costs associated with the Maritime Link when it is in service. The UARB approved annual payment for 2019 is $111 million and as of December 31, 2019, $101 million of that has been paid. The payments are subject to a holdback of $10 million pending UARB agreement that a minimum of $10 million in benefits from the Maritime Link are realized for NSPI customers. If the $10 million in benefits is realized, the UARB will direct NSPI to pay the $10 million to NSPML for that year. If not realized, then the UARB will direct NSPI to pay to NSPML only that portion that is realized and the balance will be refunded to customers through NSPI’s FAM. As of December 31, 2019, NSPI has recorded a $6 million holdback payable to NSPML.

In response to the delayed timing of energy delivery from the Muskrat Falls project, the approved interim assessment payments of $110 million and $111 million for 2018 and 2019 respectively, reflect a $53 million reduction in NSPML’s assessment in each of 2018 and 2019, related to depreciation and amortization expenses. As these amounts are included in NSPI’s 2017 through 2019 fuel rates and were recovered from customers, NSPI is providing a credit to customers, including interest, as the payments from NSPI to NSPML are not required in those years. In 2018, $17 million was refunded and in 2019, a further $35 million was refunded. The UARB decision to reduce the assessment payable to NSPML in 2018 and 2019 results in the Company recording amounts collected from customers as a FAM regulatory liability, with no material impact on earnings.

The UARB’s decision to approve NSPI’s 2020 through 2022 Fuel Stability Plan outlined the treatment of the reduced 2019 NSPML assessment of $52 million plus interest. The reduced assessment will be refunded to most customers through a reduction incorporated into their 2020 through 2022 rates and the remaining customers will receive a one-time on bill credit in 2020.The credit to customers will be approximately $40 million plus interest in 2020, with the remaining $12 million plus interest to be returned to customers subsequent to 2022.

On November 27, 2019, the UARB approved the 2020 interim cost assessment recovery from NSPI for costs associated with the Maritime Link of $145 million, subject to a holdback of up to $10 million. Refer to the NSPML section below for further details.

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Pursuant to the FAM Plan of Administration, NSPI’s fuel costs are subject to independent audit. In July 2018, the FAM audit results relating to fiscal 2016 and 2017 were publicly released. A UARB regulatory process is in progress with a hearing held on January 13, 2020.

NSPML

Equity earnings contributions from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. NSPML’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 30 per cent.

On November 27, 2019, the UARB approved NSPML’s interim assessment for recovery of 2020 Maritime Link costs from NSPI of approximately $145 million (2019 - $111 million). The total recovery of $145 million includes approximately $115 million of operating and maintenance, debt financing and equity financing costs, and approximately $30 million for depreciation and amortization of financing costs. This payment is subject to a holdback of up to $10 million. Recovery of the $115 million of operating and maintenance, debt financing and equity financing costs began on January 1, 2020. Beginning June 1, 2020, recovery of the $30 million of depreciation and amortization of financing costs will be included in NSPI customer rates, with payment of this recovery to NSPML to begin on the earlier of the confirmation of delivery of the Nova Scotia block (“NS Block”) of electricity transmitted through the Maritime Link from the Muskrat Falls hydroelectric facility, and November 1, 2020. NSPML expects to file a final cost assessment with the UARB in 2020.

Other Electric Utilities

Emera Maine

Emera Maine’s distribution operations and stranded cost recoveries are regulated by the MPUC. The transmission operations are regulated by the FERC. Rates for these are established in distinct regulatory proceedings. US tax reform benefits, resulting from the lower tax rate, were reflected in distribution and transmission rates effective July 1, 2018, with other components being deferred to be addressed in future 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. In June 2018, the MPUC approved a 5.3 per cent distribution rate increase. This increase was effective July 1, 2018 and is based on a 9.35 per cent ROE and a common equity component of 49 per cent. Prior to July 1, 2018, the allowed ROE was 9.0 per cent, on a common equity component of 49 per cent.

Transmission Operations

Emera Maine’s transmission operations are split between two districts; Bangor Hydro District and Maine Public Service (“MPS”). Bangor Hydro District 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. The allowed ROE for Bangor Hydro District local transmission operations for 2019 and 2018 is 10.57 per cent. Bangor Hydro District’s bulk transmission assets are managed by ISO-New England (“ISO-NE”) as part of a region-wide pool of assets. The allowed ROE range for Bangor Hydro bulk transmission assets is 11.07 to 11.74 per cent for 2019 and 2018.

MPS District 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. The current allowed ROE for transmission operations is 9.6 per cent (2018 – 9.6 per cent).

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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.

The Barbados Light & Power Company Limited

BLPC is regulated by the Fair Trading Commission, an independent regulator, under the Utilities Regulation (Procedural) Rules 2003. The Government of Barbados has granted BLPC a franchise to generate, transmit and distribute electricity on the island until 2028. In 2019, the Government of Barbados passed legislation amending the number of licenses required for the supply of electricity from a single integrated license which currently exists to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. BLPC is negotiating the terms of the new licenses under the amended legislation.

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 was 10 per cent for 2019 and 2018.

All BLPC fuel costs are passed to customers through the fuel pass-through mechanism which provides opportunity to recover all fuel costs in a timely manner. The approved calculation of the fuel charge is adjusted monthly and reported to the regulator.

In December 2018, the Government of Barbados signed the Income Tax Amendment Act into law. This legislation which is effective January 1, 2019, created a new corporate income tax rate schedule and eliminated certain tax credits. At the date of enactment, BLPC was required to remeasure its deferred income tax liability at the new lower corporate income tax rate, resulting in recognition of an income tax recovery of $9.6 million USD of which $6.9 million USD was deferred as a regulatory liability.

Grand Bahama Power Company Limited

GBPC is regulated by the GBPA. The GBPA 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 tariff review policy with new rates submitted every three years. GBPC’s approved regulated return on rate base was 8.5 per cent for 2019 (2018 - 8.5 per cent). In December 2018, the GBPA approved GBPC’s regulated return on rate base of 8.44 per cent for 2019.

In December 2016, the GBPA approved that the all-in rate for electricity (fuel and base rates) would be held at 2016 levels over the five-year period from 2017 through 2021. 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.

Dominica Electricity Services Ltd

Domlec 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, 2014, for a period of 25 years. Domlec’s approved allowable regulated return on rate base was 15 per cent for 2019 and 2018.

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

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Gas Utilities and Infrastructure

PGS

PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital.

The approved ROE range for PGS is 9.25 per cent to 11.75 per cent, based on an allowed equity capital structure of 54.7 per cent. An ROE of 10.75 per cent is used for the calculation of return on investments for clauses.

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

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

On September 12, 2018, the FPSC approved a settlement agreement filed by PGS authorizing the utility to amortize $11 million USD of its MGP environmental regulatory asset and net it against its estimated 2018 tax reform benefits. Beginning in January 2019, PGS reduced its base rates by $12 million USD to reflect the impact of tax reform and reduce depreciation rates by $10 million USD in accordance with the settlement agreement.

PGS is permitted to initiate a general base rate proceeding during 2020 regardless of its earned ROE at the time, provided the new rates do not become effective before January 1, 2021. On February 7, 2020, PGS notified the FPSC that it is planning to file a new base rate proceeding in April 2020 for new rates effective January 2021.

NMGC

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

The approved ROE for NMGC is 9.1 per cent, on an allowed equity capital structure of 52 per cent.

NMGC recovers gas supply costs through a purchased gas adjustment clause (“PGAC”). This clause recovers NMGC’s actual costs for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers. On a monthly basis, NMGC can adjust the charges based on the next month’s expected cost of gas and any prior month under-recovery or over-recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish that the continued use of the PGAC is reasonable and necessary. In December 2016, NMGC received approval of its PGAC Continuation Filing for the four-year period ending December 2020.

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On July 17, 2019, the NMPRC approved a rate increase for NMGC effective August 2019, and allowed NMGC to retain tax reform benefits realized from January 1, 2018 to the effective date of the new rates. The new rates are being phased in over two years and are expected to result in an annual revenue increase of approximately $3 million USD. The deferred income tax regulatory liability of $11 million ($8 million USD) recorded at December 31, 2018 to reflect deferred tax benefits was recognized in revenue in Q2 2019. The NMPRC also approved the utility’s weather adjustment mechanism. Beginning in August 2019, the NMPRC approved a change in the treatment of net operating loss carryforwards. As a result of this change, a tax benefit of approximately $7 million ($5 million USD) was recognized in earnings in Q3 2019.

On December 23, 2019, NMGC filed a future year rate case on December 23, 2019 for new rates effective January 2021. The proposed new rates reflect the recovery of capital investment in pipelines and related infrastructure. The estimated annual incremental revenue requirement is approximately $13 million USD. A decision from the NMPRC is expected in late 2020.

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 Canada Energy Board (“CER”). The CER Gas Transportation Tariff is filed by Brunswick Pipeline in compliance with the requirements of the CER Act and sets forth the terms and conditions of the transportation rendered by Brunswick Pipeline.

16. RELATED PARTY TRANSACTIONS

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

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

● |  | Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $107 million for the year ended December 31, 2019 (2018 - $97 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments.

● |  | Natural gas transportation capacity purchases from M&NP are reported in the Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $63 million for the year ended December 31, 2019 (2018- $29 million).

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

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17. RECEIVABLES AND OTHER CURRENT ASSETS

Receivables and other current assets consisted of the following:

As at |  | December 31 |  |  | December 31 |
millions of Canadian dollars |  | 2019 |  |  | 2018 |
Customer accounts receivable – billed |  | $ | 704 |  |  | $ | 844 |
Customer accounts receivable – unbilled |  |  | 265 |  |  |  | 296 |
Allowance for doubtful accounts |  |  | (9) |  |  |  | (11) |
Other receivables |  |  | 72 |  |  |  | 86 |
Capitalized transportation capacity (1) |  |  | 272 |  |  |  | 179 |
Income tax receivable |  |  | 118 |  |  |  | 175 |
Prepaid expenses |  |  | 48 |  |  |  | 42 |
Net investment in direct financing lease (note 18) |  |  | 9 |  |  |  | 9 |
Other current assets |  |  | 7 |  |  |  | - |
|  | $ | 1,486 |  |  | $ | 1,620 |

(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.

18. LEASES

Lessee

The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera’s leases have remaining lease terms of 1 year to 66 years, some of which include options to extend the leases for up to 65 years. These options are included as part of the lease term when it is considered reasonably certain that they will be exercised.

As at |  |  |  |  |  | December 31 |
millions of Canadian dollars |  |  |  | Classification |  | 2019 |
Right-of-use asset |  |  |  | Other long-term assets |  | $ | 64 |
Lease liabilities |  |  |  |  |  |  |  |
Current |  |  |  | Other current liabilities |  |  | 5 |
Long-term |  |  |  | Other long-term liabilities |  |  | 61 |
Total lease liabilities |  |  |  |  |  | $ | 66 |

The Company has recorded lease expense of $172 million for the year ended December 31, 2019, of which $156 million relates to variable costs for power generation facility finance leases, recorded in “Regulated fuel for generation and purchased power” in the consolidated statements of income.

Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter are as follows:

millions of Canadian dollars |  | 2020 |  |  | 2021 |  |  | 2022 |  |  | 2023 |  |  | 2024 |  |  | Thereafter |  |  | Total |
Minimum lease payments |  | $ | 8 |  |  | $ | 8 |  |  | $ | 7 |  |  | $ | 6 |  |  | $ | 5 |  |  | $ | 102 |  |  | $ | 136 |
Less imputed interest |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (70) |
Total |  | $ | 8 |  |  | $ | 8 |  |  | $ | 7 |  |  | $ | 6 |  |  | $ | 5 |  |  | $ | 102 |  |  | $ | 66 |

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

|  | Year ended December 31 |
For the |  | 2019 |
Cash paid for amounts included in the measurement of lease liabilities: |  |  |  |
Operating cash flows for operating leases (millions of Canadian dollars) |  | $ | 7 |
Right-of-use assets obtained in exchange for lease obligations: |  |  |  |
Operating leases (millions of Canadian dollars) |  | $ | 16 |
Weighted average remaining lease term (years) |  |  | 39 |
Weighted average discount rate- operating leases |  |  | 4.07% |

Lessor

The Company’s net investment in direct finance and sales-type leases relate to Brunswick Pipeline, compressed natural gas (“CNG”) stations and heat pumps.

Direct finance and sales-type lease unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Operating revenues – regulated gas” and “Other income (expense), net” on the Consolidated Statements of Income.

The Company manages its risk associated with the residual value of the Brunswick Pipeline lease through proper routine maintenance of the asset.

Customers have the option to purchase CNG station assets at any time after 2021 by paying a make-whole payment at the date of the purchase based on a targeted internal rate of return or may take possession of the CNG station asset at the end of the lease term for no cost. Customers have the option to purchase heat pumps at the end of the lease term for a nominal fee.

Net investment in direct finance and sales-type leases consist of the following(1):

As at |  | December 31 |
millions of Canadian dollars |  | 2019 |
Total minimum lease payment to be received |  | $ | 1,066 |
Less: amounts representing estimated executory costs |  |  | (189) |
Minimum lease payments receivable |  | $ | 877 |
Estimated residual value of leased property (unguaranteed) |  |  | 183 |
Less: unearned finance lease income |  |  | (532) |
Net investment in direct finance and sales-type leases |  | $ | 528 |
Principal due within one year (included in “Receivables and other current assets”) |  |  | 17 |
Net investment in sales-type leases - long-term (included in “Other long-term assets”) |  |  | 38 |
Net Investment in direct finance leases - long-term |  | $ | 473 |

(1) The net investment in direct finance lease balance as of December 31, 2018, primarily related to New Brunswick Pipeline, consisted of net minimum lease payments receivable of $865 million less an unguaranteed residual value of $183 million and unearned finance income of $564 million.

As at December 31, 2019, future minimum lease payments to be received for each of the next five years and in aggregate thereafter are as follows:

millions of Canadian dollars |  | 2020 |  |  | 2021 |  |  | 2022 |  |  | 2023 |  |  | 2024 |  |  | Thereafter |  |  | Total |
Minimum lease payments to be received |  | $ | 76 |  |  | $ | 74 |  |  | $ | 73 |  |  | $ | 73 |  |  | $ | 74 |  |  | $ | 696 |  |  | $ | 1,066 |
Less: executory costs |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (189) |
Minimum lease payments receivable |  | $ | 76 |  |  | $ | 74 |  |  | $ | 73 |  |  | $ | 73 |  |  | $ | 74 |  |  | $ | 696 |  |  | $ | 877 |

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19. 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 |  | 2019 (1) |  |  | 2018 |
Generation (2) |  | 3 to 131 |  | $ | 11,181 |  |  | $ | 11,092 |
Transmission |  | 11 to 80 |  |  | 2,318 |  |  |  | 3,047 |
Distribution |  | 4 to 80 |  |  | 5,820 |  |  |  | 6,348 |
Gas transmission and distribution |  | 7 to 85 |  |  | 3,546 |  |  |  | 3,398 |
General plant and other |  | 2 to 60 |  |  | 2,006 |  |  |  | 2,158 |
Total cost |  |  |  |  | 24,871 |  |  |  | 26,043 |
Less: Accumulated depreciation (2) |  |  |  |  | (8,295) |  |  |  | (8,567) |
|  |  |  |  | 16,576 |  |  |  | 17,476 |
Construction work in progress |  |  |  |  | 1,591 |  |  |  | 1,236 |
Net book value |  |  |  | $ | 18,167 |  |  | $ | 18,712 |

(1) Excludes Emera Maine balances classified as held for sale as at December 31, 2019. Refer to the note 4 for further details.

(2) On March 29, 2019, the Company sold its NEGG facilities. As of December 31, 2018, the Company classified these assets as held for sale on the Consolidated Balance Sheets. Refer to note 4 for additional information.

20. EMPLOYEE BENEFIT PLANS

Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, Maine, New Mexico, Barbados, Dominica and Grand Bahama Island. On March 25, 2019, Emera announced the sale of Emera Maine. As at December 31, 2019, Emera Maine’s assets and liabilities, including balances related to benefit plans, were classified as held for sale. Refer to note 4 for further details.

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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 |  | 2019 |  |  | 2018 |
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 |  | $ | 2,650 |  |  | $ | 350 |  |  | $ | 2,683 |  |  | $ | 356 |
Service cost |  |  | 47 |  |  |  | 4 |  |  |  | 51 |  |  |  | 6 |
Plan participant contributions |  |  | 8 |  |  |  | 5 |  |  |  | 8 |  |  |  | 5 |
Interest cost |  |  | 102 |  |  |  | 14 |  |  |  | 95 |  |  |  | 13 |
Benefits paid |  |  | (130) |  |  |  | (23) |  |  |  | (143) |  |  |  | (33) |
Actuarial (gains) losses |  |  | 231 |  |  |  | 19 |  |  |  | (133) |  |  |  | (25) |
Settlements and curtailments |  |  | (20) |  |  |  | - |  |  |  | (18) |  |  |  | - |
Foreign currency translation adjustment |  |  | (66) |  |  |  | (16) |  |  |  | 107 |  |  |  | 28 |
Balance, December 31 |  |  | 2,822 |  |  |  | 353 |  |  |  | 2,650 |  |  |  | 350 |
Change in plan assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Balance, January 1 |  |  | 2,300 |  |  |  | 49 |  |  |  | 2,408 |  |  |  | 45 |
Employer contributions |  |  | 52 |  |  |  | 19 |  |  |  | 51 |  |  |  | 31 |
Plan participant contributions |  |  | 8 |  |  |  | 5 |  |  |  | 8 |  |  |  | 5 |
Benefits paid |  |  | (130) |  |  |  | (23) |  |  |  | (143) |  |  |  | (33) |
Actual return on assets, net of expenses |  |  | 424 |  |  |  | 7 |  |  |  | (105) |  |  |  | (3) |
Settlements and curtailments |  |  | (7) |  |  |  | - |  |  |  | (18) |  |  |  | - |
Foreign currency translation adjustment |  |  | (54) |  |  |  | (1) |  |  |  | 99 |  |  |  | 4 |
Balance, December 31 |  |  | 2,593 |  |  |  | 56 |  |  |  | 2,300 |  |  |  | 49 |
Funded status, end of year |  | $ | (229) |  |  | $ | (297) |  |  | $ | (350) |  |  | $ | (301) |

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:

millions of Canadian dollars |  |  |  |  | 2019 |  |  | 2018 |
|  | Defined benefit pension plans |  |  | Non-pension benefit plans |  |  | Defined benefit pension plans |  |  | Non-pension benefit plans |
PBO/APBO |  | $ | 2,797 |  |  | $ | 323 |  |  | $ | 2,623 |  |  | $ | 318 |
Fair value of plan assets |  |  | 2,557 |  |  |  | 7 |  |  |  | 2,264 |  |  |  | 6 |
Funded status |  | $ | (240) |  |  | $ | (316) |  |  | $ | (359) |  |  | $ | (312) |

Plans with Accumulated Benefit Obligation (“ABO”) in Excess of Plan Assets

The ABO for the defined benefit pension plans was $2,687 million as at December 31, 2019 (2018 – $2,527 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 |  | 2019 |  |  | 2018 |
|  | Defined benefit pension plans |  |  | Defined benefit pension plans |
ABO |  | $ | 2,665 |  |  | $ | 2,504 |
Fair value of plan assets |  |  | 2,557 |  |  |  | 2,264 |
Funded status |  | $ | (108) |  |  | $ | (240) |

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Balance Sheet

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

As at |  | December 31 |  |  | December 31 |
millions of Canadian dollars |  | 2019 |  |  | 2018 |
|  | Defined benefit pension plans |  |  | Non-pension benefit plans |  |  | Defined benefit pension plans |  |  | Non-pension benefit plans |
Other current liabilities |  | $ | (4) |  |  | $ | (18) |  |  | $ | (12) |  |  | $ | (19) |
Long-term liabilities |  |  | (206) |  |  |  | (254) |  |  |  | (347) |  |  |  | (294) |
Long-term liabilities associated with assets held for sale (1) |  |  | (30) |  |  |  | (44) |  |  |  | - |  |  |  | - |
Other long-term assets |  |  | 11 |  |  |  | 19 |  |  |  | 9 |  |  |  | 11 |
Amount included in deferred income tax |  |  | (7) |  |  |  | 1 |  |  |  | 5 |  |  |  | (2) |
AOCI, net of tax and regulatory assets |  |  | 524 |  |  |  | 72 |  |  |  | 628 |  |  |  | 60 |
Net amount recognized |  | $ | 288 |  |  | $ | (224) |  |  | $ | 283 |  |  | $ | (244) |

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

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. As at December 31, 2019, regulatory asset balances related to Emera Maine have been reclassified as assets held for sale. The following table summarizes the change in AOCI and regulatory assets:

millions of Canadian dollars |  | Regulatory assets |  |  | Actuarial (gains) losses |  |  | Past service (gains) costs |
Defined Benefit Pension Plans |  |  |  |  |  |  |  |  |  |  |  |
Balance, January 1, 2019 |  | $ | 389 |  |  | $ | 246 |  |  | $ | (2) |
Amortized in current period |  |  | (20) |  |  |  | (17) |  |  |  | 1 |
Current year addition to AOCI or regulatory assets |  |  | 6 |  |  |  | (69) |  |  |  | - |
Change in foreign exchange rate |  |  | (17) |  |  |  | - |  |  |  | - |
Balance, December 31, 2019 |  | $ | 358 |  |  | $ | 160 |  |  | $ | (1) |
Non-pension benefits plans |  |  |  |  |  |  |  |  |  |  |  |
Balance, January 1, 2019 |  | $ | 65 |  |  | $ | (7) |  |  | $ | - |
Amortized in current period |  |  | 5 |  |  |  | - |  |  |  | - |
Current year addition to AOCI or regulatory assets |  |  | 11 |  |  |  | 2 |  |  |  | - |
Change in foreign exchange rate |  |  | (3) |  |  |  | - |  |  |  | - |
Balance, December 31, 2019 |  | $ | 78 |  |  | $ | (5) |  |  | $ | - |

|  |  | 2019 |  |  |  | 2018 |
|  | Defined benefit pension plans |  |  | Non-pension benefit plans |  |  | Defined benefit pension plans |  |  | Non-pension benefit plans |
Actuarial losses (gains) |  | $ | 160 |  |  | $ | (5) |  |  | $ | 246 |  |  | $ | (7) |
Past service (gains) costs |  |  | (1) |  |  |  | - |  |  |  | (2) |  |  |  | - |
Regulatory assets |  |  | 358 |  |  |  | 78 |  |  |  | 389 |  |  |  | 65 |
Total AOCI and regulatory assets before deferred income taxes |  |  | 517 |  |  |  | 73 |  |  |  | 633 |  |  |  | 58 |
Amount included in deferred income tax assets |  |  | 7 |  |  |  | (1) |  |  |  | (5) |  |  |  | 2 |
Net amount in AOCI and regulatory assets |  | $ | 524 |  |  | $ | 72 |  |  | $ | 628 |  |  | $ | 60 |

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Benefit Cost Components

Emera’s net periodic benefit cost included the following:

As at millions of Canadian dollars |  |  |  |  | 2019 |  |  | Year ended December 31 2018 |
|  | Defined benefit pension plans |  |  | Non-pension benefit plans |  |  | Defined benefit pension plans |  |  | Non-pension benefit plans |
Service cost |  | $ | 47 |  |  | $ | 4 |  |  | $ | 51 |  |  | $ | 6 |
Interest cost |  |  | 102 |  |  |  | 14 |  |  |  | 95 |  |  |  | 13 |
Expected return on plan assets |  |  | (147) |  |  |  | (2) |  |  |  | (138) |  |  |  | (2) |
Current year amortization of: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Actuarial losses |  |  | 16 |  |  |  | - |  |  |  | 33 |  |  |  | (1) |
Past service costs (gains) |  |  | (1) |  |  |  | - |  |  |  | (1) |  |  |  | - |
Regulatory assets (liability) |  |  | 20 |  |  |  | (5) |  |  |  | 26 |  |  |  | (2) |
Settlement, curtailments |  |  | 1 |  |  |  | - |  |  |  | 4 |  |  |  | - |
Total |  | $ | 38 |  |  | $ | 11 |  |  | $ | 70 |  |  | $ | 14 |

The expected return on plan assets is determined based on the market-related value of plan assets of $2,401 million as at January 1, 2019 (2018 – $2,223 million), adjusted for interest on certain cash flows during the year. 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:

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 |  |  | 30% |  |  |  | to |  |  |  | 55% |

Non-Canadian Pension Plans

Asset Class |  | Target Range at Market Weighted average |
Fixed income |  |  | 40% |  |  |  | to |  |  |  | 45% |
Equities |  |  | 55% |  |  |  | to |  |  |  | 60% |

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.

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

millions of Canadian dollars |  | NAV |  |  | Level 1 |  |  | Level 2 |  |  | Total |  |  | Percentage |
|  |  |  |  |  |  |  | December 31, 2019 |
Cash and cash equivalents |  | $ | - |  |  | $ | 44 |  |  | $ | - |  |  | $ | 44 |  |  |  | 2% |
Net in-transits |  |  | - |  |  |  | (48) |  |  |  | - |  |  |  | (48) |  |  |  | -2% |
Equity Securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Canadian equity |  |  | - |  |  |  | 210 |  |  |  | - |  |  |  | 210 |  |  |  | 8% |
US equity |  |  | - |  |  |  | 388 |  |  |  | - |  |  |  | 388 |  |  |  | 15% |
Other equity |  |  | - |  |  |  | 176 |  |  |  | - |  |  |  | 176 |  |  |  | 7% |
Fixed income securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Government |  |  | - |  |  |  | - |  |  |  | 93 |  |  |  | 93 |  |  |  | 3% |
Corporate |  |  | - |  |  |  | - |  |  |  | 126 |  |  |  | 126 |  |  |  | 5% |
Other |  |  | - |  |  |  | 5 |  |  |  | 9 |  |  |  | 14 |  |  |  | -% |
Mutual funds |  |  | - |  |  |  | 199 |  |  |  | - |  |  |  | 199 |  |  |  | 8% |
Other |  |  | - |  |  |  | (5) |  |  |  | 1 |  |  |  | (4) |  |  |  | -% |
Open-ended investments measured at NAV (1) |  |  | 860 |  |  |  | - |  |  |  | - |  |  |  | 860 |  |  |  | 33% |
Common collective trusts measured at NAV (2) |  |  | 535 |  |  |  | - |  |  |  | - |  |  |  | 535 |  |  |  | 21% |
Total |  | $ | 1,395 |  |  | $ | 969 |  |  | $ | 229 |  |  | $ | 2,593 |  |  |  | 100% |
|  |  |  |  | December 31, 2018 |
Cash and cash equivalents |  | $ | - |  |  | $ | 30 |  |  | $ | - |  |  | $ | 30 |  |  |  | 1% |
Net in-transits |  |  | - |  |  |  | (56) |  |  |  | - |  |  |  | (56) |  |  |  | -2% |
Equity securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Canadian equity |  |  | - |  |  |  | 191 |  |  |  | - |  |  |  | 191 |  |  |  | 8% |
US equity |  |  | - |  |  |  | 330 |  |  |  | - |  |  |  | 330 |  |  |  | 14% |
Other equity |  |  | - |  |  |  | 157 |  |  |  | - |  |  |  | 157 |  |  |  | 7% |
Fixed Income securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Government |  |  | - |  |  |  | - |  |  |  | 119 |  |  |  | 119 |  |  |  | 5% |
Corporate |  |  | - |  |  |  | - |  |  |  | 108 |  |  |  | 108 |  |  |  | 5% |
Other |  |  | - |  |  |  | 4 |  |  |  | 3 |  |  |  | 7 |  |  |  | - |
Mutual funds |  |  | - |  |  |  | 132 |  |  |  | - |  |  |  | 132 |  |  |  | 6% |
Other |  |  | - |  |  |  | 8 |  |  |  | 4 |  |  |  | 12 |  |  |  | 1% |
Open-ended investments measured at NAV (1) |  |  | 820 |  |  |  | - |  |  |  | - |  |  |  | 820 |  |  |  | 36% |
Common collective trusts measured at NAV (2) |  |  | 450 |  |  |  | - |  |  |  | - |  |  |  | 450 |  |  |  | 19% |
Total |  | $ | 1,270 |  |  | $ | 796 |  |  | $ | 234 |  |  | $ | 2,300 |  |  |  | 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.

Refer to note 14 for more information on the fair value hierarchy and inputs used to measure fair value.

Post-Retirement Benefit Plans

There are no assets set aside to pay for most of the Company’s post-retirement benefit plans. As is common practice, post-retirement health benefits are paid from general accounts as required. The primary exceptions to this are the NMGC Retiree Medical Plan, which is fully funded, and the Emera Maine post-retirement benefits plans, which are partially-funded.

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Investments in Emera

As at December 31, 2019 and 2018, 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 (1) |  |  | Non-pension benefit plans (2) |
Expected employer contributions |  |  |  |  |  |  |  |
2020 |  | $ | 44 |  |  | $ | 21 |
Expected benefit payments |  |  |  |  |  |  |  |
2020 |  |  | 143 |  |  |  | 23 |
2021 |  |  | 154 |  |  |  | 23 |
2022 |  |  | 158 |  |  |  | 23 |
2023 |  |  | 165 |  |  |  | 23 |
2024 |  |  | 173 |  |  |  | 23 |
2025 – 2029 |  |  | 959 |  |  |  | 115 |

(1) Includes expected employer contributions related to Emera Maine of $3 million in 2020; and expected benefit payments related to Emera Maine of $10 million in 2020; $10 million in 2021; $11 million in 2022; $11 million in 2023; $12 million in 2024 and $62 million in 2025-2029.

(2) Includes expected employer contributions related to Emera Maine of $3 million in 2020; and expected benefit payments related to Emera Maine of $3 million in 2020; $3 million in 2021; $3 million in 2022; $3 million in 2023; $4 million in 2024 and $17 million in 2025-2029.

Assumptions

The following table shows the assumptions that have been used in accounting for defined benefit pension and other post-retirement benefit plans:

|  | 2019 |  |  | 2018 |
(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 - past service |  |  | 3.17 % |  |  |  | 3.27 % |  |  |  | 4.05 % |  |  |  | 4.30 % |
Discount rate - future service |  |  | 3.21 % |  |  |  | 3.28 % |  |  |  | 4.05 % |  |  |  | 4.30% |
Rate of compensation increase |  |  | 3.32 % |  |  |  | 3.70 % |  |  |  | 3.30 % |  |  |  | 3.67 % |
Health care trend - initial (next year) |  |  | - |  |  |  | 6.15 % |  |  |  | - |  |  |  | 6.39 % |
- ultimate |  |  | - |  |  |  | 4.38 % |  |  |  | - |  |  |  | 4.45 % |
- year ultimate reached |  |  | - |  |  |  | 2038 |  |  |  | - |  |  |  | 2035 |
Benefit cost for year ended December 31: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Discount rate - past and future service |  |  | 4.05 % |  |  |  | 4.30 % |  |  |  | 3.55 % |  |  |  | 3.65 % |
Expected long-term return on plan assets |  |  | 6.50 % |  |  |  | 2.81 % |  |  |  | 6.38 % |  |  |  | 3.73 % |
Rate of compensation increase |  |  | 3.30 % |  |  |  | 3.67 % |  |  |  | 3.12 % |  |  |  | 3.28 % |
Health care trend - initial (current year) |  |  | - |  |  |  | 6.39 % |  |  |  | - |  |  |  | 6.65 % |
- ultimate |  |  | - |  |  |  | 4.45 % |  |  |  | - |  |  |  | 4.45 % |
- year ultimate reached |  |  | - |  |  |  | 2035 |  |  |  | - |  |  |  | 2036 |

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.

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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 2019:

millions of Canadian dollars |  | Increase |  |  | Decrease |
Service cost and interest cost |  | $ | 1 |  |  | $ | (1) |
Accumulated post-retirement benefit obligation, December 31 |  |  | 16 |  |  |  | (14) |

Sensitivity Analysis for Defined Benefit Pension Plans

The impact on the 2019 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 |  | $ | (9) |  |  | $ | 9 |
Asset rate assumption |  |  | (6) |  |  |  | 6 |

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 2020:

millions of Canadian dollars |  | Defined benefit pension plans |  |  | Non-pension benefit plans |
Actuarial gains (losses) |  | $ | (14) |  |  | $ | - |
Past service gains |  |  | (1) |  |  |  | - |
Regulatory assets |  |  | (29) |  |  |  | (1) |
Total |  | $ | (44) |  |  | $ | (1) |

Defined Contribution Plan

Emera also provides a defined contribution pension plan for certain employees. The Company’s contribution for the year ended December 31, 2019 was $34 million (2018 – $31 million).

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21. GOODWILL

The change in goodwill for the year ended December 31 is due to the following:

millions of Canadian dollars |  | 2019 |  |  | 2018 |
Balance, January 1 |  | $ | 6,313 |  |  | $ | 5,805 |
Additions |  |  | 3 |  |  |  | - |
GBPC impairment charge |  |  | (30) |  |  |  | - |
Classified as assets held for sale (1) |  |  | (148) |  |  |  | - |
Change in foreign exchange rate |  |  | (303) |  |  |  | 508 |
Balance, December 31 |  | $ | 5,835 |  |  | $ | 6,313 |

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

Goodwill is subject to an annual assessment for impairment at the reporting unit level. The goodwill on Emera’s Balance Sheets at December 31, 2019, relates to TECO Energy, Emera Maine and GBPC. Emera’s reporting units with goodwill are Tampa Electric, PGS, New Mexico Gas, Emera Maine and GBPC.

In 2019, Emera elected to bypass a qualitative assessment and performed a quantitative impairment assessment for Tampa Electric, PGS and New Mexico Gas, respectively, using a combination of the income and market approach. The Company concluded that the fair value of the reporting units exceeded their respective carrying values and, as such, no impairment charges were recognized.

Goodwill on Emera’s Consolidated Balance Sheets at December 31, 2018, included $104 million related to GBPC. In 2019, Emera elected to bypass a qualitative assessment and performed a quantitative impairment assessment for GBPC using an income approach. This assessment concluded that the fair value of the reporting unit was below its carrying value, including goodwill. Certain assumptions used in determining the fair value of the reporting unit in the 2019 impairment test changed from those used in prior years, including a decrease in expected future cash flows due to the impacts of Hurricane Dorian storm recovery and changes in the anticipated long term regulated capital structure of GBPC.

As a result, Emera recognized an impairment charge of $30 million in 2019 based on the excess of GBPC’s carrying amount over its fair value. This non-cash charge is included in “GBPC impairment charge” in the Consolidated Statements of Income. $70 million in goodwill continues to be related to GBPC as at December 31, 2019.

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22. 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 |  | 2019 |  |  | Weighted average interest rate |  |  | 2018 |  |  | Weighted average interest rate |
TECO Finance |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Advances on revolving credit and term facilities |  | $ | 656 |  |  |  | 2.39 % |  |  | $ | 805 |  |  |  | 3.43 % |
Tampa Electric Company (“TEC”) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Advances on accounts receivable and revolving credit facilities |  |  | 452 |  |  |  | 2.56 % |  |  |  | 302 |  |  |  | 3.10 % |
Emera Inc. |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Non-revolving term facility |  |  | 399 |  |  |  | 2.69 % |  |  |  |  |  |  |  |  |
Bank indebtedness |  |  | 6 |  |  |  | - % |  |  |  | - |  |  |  | - % |
GBPC |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Advances on revolving credit facilities |  |  | 10 |  |  |  | 5.25 % |  |  |  | - |  |  |  | - % |
NMGC |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Advances on revolving credit facilities |  |  | 8 |  |  |  | 2.70 % |  |  |  | 79 |  |  |  | 3.40 % |
NSPI |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Bank indebtedness |  |  | 6 |  |  |  | - % |  |  |  | - |  |  |  | - % |
Short-term debt |  | $ | 1,537 |  |  |  |  |  |  | $ | 1,186 |  |  |  |  |

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 |  |  | 2019 |  |  | 2018 |
TECO Energy/TECO Finance - term credit facility |  |  | 2020 |  |  | $ | 649 |  |  | $ | 682 |
TECO Energy/TECO Finance - revolving credit facility |  |  | 2022 |  |  |  | 520 |  |  |  | 546 |
Tampa Electric Company - revolving credit facility |  |  | 2022 |  |  |  | 520 |  |  |  | 443 |
Emera Inc. - non-revolving term facility |  |  | 2020 |  |  |  | 400 |  |  |  | - |
Tampa Electric Company - accounts receivable revolving credit facility |  |  | 2021 |  |  |  | 195 |  |  |  | 205 |
NMGC - revolving credit facility |  |  | 2022 |  |  |  | 162 |  |  |  | 171 |
GBPC - revolving credit facility |  |  | on demand |  |  |  | 17 |  |  |  | 18 |
Total |  |  |  |  |  |  | 2,463 |  |  |  | 2,065 |
Less: |  |  |  |  |  |  |  |  |  |  |  |
Advances under revolving credit and term facilities |  |  |  |  |  |  | 1,525 |  |  |  | 1,186 |
Letters of credit issued within the credit facilities |  |  |  |  |  |  | 3 |  |  |  | 3 |
Total advances under available facilities |  |  |  |  |  |  | 1,528 |  |  |  | 1,189 |
Available capacity under existing agreements |  |  |  |  |  | $ | 935 |  |  | $ | 876 |

The weighted average interest rate on outstanding short-term debt at December 31, 2019 was 2.54 per cent (2018 – 3.34 per cent).

Recent Significant Financing Activities by Segment

Florida Electric Utilities

On February 6, 2020, TEC entered into a $300 million USD non-revolving credit agreement with a maturity date of February 4, 2021. The credit agreement contains customary representations and warranties, events of default, financial and other covenants and bears interest at LIBOR, prime rate or the federal funds rate, plus a margin.

On December 19, 2019, TEC increased its $325 million USD revolving credit facility by $75 million USD to $400 million USD. There were no other changes in commercial terms.

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Other

On December 16, 2019, Emera entered into a $400 million non-revolving credit agreement with a maturity date of December 15, 2020. The credit agreement contains customary representations and warranties, events of default, financial and other covenants and bears interest at Bankers Acceptance rates or prime rate advances, plus a margin.

On March 7, 2019, TECO Energy/Finance extended the maturity date of its $500 million USD credit facility from March 8, 2019 to March 5, 2020. There were no other significant changes in commercial terms from the prior agreement.

23. OTHER CURRENT LIABILITIES

As at |  | December 31 |  |  | December 31 |
millions of Canadian dollars |  | 2019 |  |  | 2018 |
Accrued charges |  | $ | 147 |  |  | $ | 154 |
Accrued interest on long-term debt |  |  | 77 |  |  |  | 93 |
Pension and post-retirement liabilities (note 20) |  |  | 22 |  |  |  | 31 |
Sales and other taxes payable |  |  | 13 |  |  |  | 9 |
Income tax payable |  |  | 1 |  |  |  | 6 |
Other |  |  | 73 |  |  |  | 135 |
|  | $ | 333 |  |  | $ | 428 |

24. LONG-TERM DEBT

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.

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Long-term debt as at December 31 consisted of the following:

|  | Weighted average interest rate (1) |  |  |  |  |  |  |  |  |
millions of Canadian dollars |  | 2019 |  |  | 2018 |  | Maturity |  |  | 2019 |  |  | 2018 |
Emera |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Bankers acceptances, LIBOR loans |  |  | Variable |  |  | Variable |  |  | 2024 |  |  | $ | 437 |  |  | $ | 339 |
Unsecured fixed rate notes |  |  | 2.90 | % |  | 3.50% |  |  | 2023 |  |  |  | 500 |  |  |  | 725 |
Fixed to floating subordinated notes (USD) |  |  | 6.75 | % |  | 6.75% |  |  | 2076 |  |  |  | 1,559 |  |  |  | 1,637 |
|  |  |  |  |  |  |  |  |  |  |  | $ | 2,496 |  |  | $ | 2,701 |
Emera Finance |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Unsecured senior notes (USD) |  |  | 3.86 | % |  | 3.60% |  |  | 2021 - 2046 |  |  | $ | 3,572 |  |  | $ | 4,434 |
TECO Finance (2) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed rate notes and bonds (USD) |  |  | 5.15 | % |  | 5.15% |  |  | 2020 |  |  |  | 390 |  |  |  | 409 |
Tampa Electric (3) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed rate notes and bonds (USD) |  |  | 4.53 | % |  | 4.64% |  |  | 2021 - 2050 |  |  | $ | 3,334 |  |  | $ | 3,126 |
PGS |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed rate notes and bonds (USD) |  |  | 4.58 | % |  | 4.66% |  |  | 2021 - 2050 |  |  | $ | 437 |  |  | $ | 425 |
NMGC |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed rate notes and bonds (USD) |  |  | 4.30 | % |  | 4.53% |  |  | 2021 - 2049 |  |  | $ | 474 |  |  | $ | 368 |
NMGI |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed rate notes and bonds (USD) |  |  | 3.64 | % |  | 3.41% |  |  | 2024 |  |  | $ | 195 |  |  | $ | 273 |
NSPI |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Discount notes |  |  | Variable |  |  | Variable |  |  | 2024 |  |  | $ | 308 |  |  | $ | 516 |
Medium term fixed rate notes |  |  | 5.37 | % |  | 5.73% |  |  | 2025 - 2097 |  |  |  | 2,365 |  |  |  | 1,965 |
Fixed rate debenture |  |  | - |  |  | 9.75% |  |  | - |  |  |  | - |  |  |  | 95 |
|  |  |  |  |  |  |  |  |  |  |  | $ | 2,673 |  |  | $ | 2,576 |
Emera Maine |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
LIBOR loans and demand loans |  |  | Variable |  |  | Variable |  |  | 2023 |  |  | $ | 11 |  |  | $ | 28 |
Secured fixed rate mortgage bonds (USD) |  |  | 9.74 | % |  | 9.74% |  |  | 2020 - 2022 |  |  |  | 65 |  |  |  | 68 |
Unsecured senior fixed rate notes (USD) |  |  | 4.15 | % |  | 4.23% |  |  | 2022 - 2049 |  |  |  | 442 |  |  |  | 382 |
|  |  |  |  |  |  |  |  |  |  |  | $ | 518 |  |  | $ | 478 |
EBP |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Senior secured credit facility |  |  | Variable |  |  | 3.08% |  |  | 2023 |  |  | $ | 248 |  |  | $ | 248 |
ECI |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Secured senior notes (USD) |  |  | Variable |  |  | Variable |  |  | 2021 |  |  | $ | 130 |  |  | $ | 159 |
Amortizing fixed rate notes (USD) |  |  | 3.89 | % |  | 3.83% |  |  | 2021 - 2022 |  |  | $ | 122 |  |  | $ | 114 |
Secured fixed rate senior notes (4) |  |  | 4.84 | % |  | 5.51% |  |  | 2020 - 2035 |  |  | $ | 218 |  |  | $ | 191 |
|  |  |  |  |  |  |  |  |  |  |  | $ | 470 |  |  | $ | 464 |
Adjustments |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fair market value adjustment - TECO Energy acquisition (5) |  |  |  |  |  |  |  |  |  |  |  | $ | 8 |  |  | $ | 22 |
Debt issuance costs |  |  |  |  |  |  |  |  |  |  |  |  | (119) |  |  |  | (113) |
Classification as liabilities held for sale (6) |  |  |  |  |  |  |  |  |  |  |  |  | (516) |  |  |  | - |
Amount due within one year (7) |  |  |  |  |  |  |  |  |  |  |  |  | (501) |  |  |  | (1,119) |
|  |  |  |  |  |  |  |  |  |  |  | $ | (1,128) |  |  | $ | (1,210) |
Long-Term Debt |  |  |  |  |  |  |  |  |  |  |  | $ | 13,679 |  |  | $ | 14,292 |

(1) Weighted average interest rate of fixed rate long-term debt.

(2) TECO Energy is a full and unconditional guarantor of TECO Finance’s securities, and no subsidiaries of TECO Energy guarantee TECO Finance’s securities.

(3) 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.

(4) Notes are issued and payable in either USD, BBD or East Caribbean Dollar (XCD).

(5) 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.

(6) Emera Maine’s assets and liabilities are classified as held for sale. Refer to note 4 for further details.

(7) Excludes Emera Maine amounts which are classified as current liabilities associated with assets held for sale.

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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 |  |  | 2019 |  |  | 2018 |
Emera – revolving credit facility (1) |  |  | June 2024 |  |  | $ | 900 |  |  | $ | 900 |
NSPI - revolving credit facility (1) |  |  | October 2024 |  |  |  | 600 |  |  |  | 600 |
Emera Maine – revolving credit facility |  |  | February 2023 |  |  |  | 104 |  |  |  | 109 |
BLPC – revolving credit facility |  |  | 2020-2032 |  |  |  | 25 |  |  |  | 26 |
Total |  |  |  |  |  |  | 1,629 |  |  |  | 1,635 |
Less: |  |  |  |  |  |  |  |  |  |  |  |
Borrowings under credit facilities |  |  |  |  |  |  | 771 |  |  |  | 899 |
Letters of credit issued inside credit facilities |  |  |  |  |  |  | 65 |  |  |  | 77 |
Use of available facilities |  |  |  |  |  |  | 836 |  |  |  | 976 |
Available capacity under existing agreements |  |  |  |  |  | $ | 793 |  |  | $ | 659 |

(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, 2019
Emera |  |  |  |  |  |
Syndicated credit facilities |  | Debt to capital ratio |  | Less than or equal to 0.70 to 1 |  | 0.59 : 1

Recent Significant Financing Activity by Segment

Florida Electric Utilities

On July 24, 2019, TEC completed a $300 million USD 30-year senior notes issuance. The notes bear interest at a rate of 3.625 per cent and have a maturity date of June 15, 2050.

Canadian Electric Utilities

On November 25, 2019, NSPI amended its operating credit facility to extend the maturity from October 2023 to October 2024. All other terms of the agreement are the same.

On August 2, 2019, NSPI repaid a $95 million debenture upon maturity. The debenture was repaid using its operating credit facility.

On April 4, 2019, NSPI completed a $400 million Series AB 30-year medium term notes issuance. The notes bear interest at a rate of 3.57 per cent and have a maturity date of April 5, 2049.

Gas Utilities and Infrastructure

On December 19, 2019, NMGC completed a $80 million USD 30-year unsecured note issuance. The notes bear interest at a rate of 3.72 per cent and have a maturity date of December 15, 2049.

On December 19, 2019, NMGC completed a $15 million USD 15-year unsecured note issuance. The notes bear interest at a rate of 3.24 per cent and have a maturity date of December 15, 2034.

On July 31, 2019, New Mexico Gas Intermediate (“NMGI”) repaid a $50 million USD note upon maturity. The note was repaid using cash on hand.

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On May 17, 2019, Emera Brunswick Pipeline amended the maturity date of its $250 million Credit Agreement from February 2022 to May 2023. There were no other material changes in commercial terms.

Other Electric Utilities

On December 10, 2019, Emera Maine completed a securities issuance for $60 million USD senior unsecured notes. The 30-year notes bear interest at a rate of 3.79 per cent and will mature on December 10, 2049.

Other

On December 2, 2019, Emera’s Series G $225 million 4.83 per cent medium-term notes matured and were repaid. The notes were repaid using existing credit facilities.

On June 14, 2019, Emera Finance repaid a $500 million USD note upon maturity. The note was repaid using proceeds from the sale of the NEGG facilities.

On June 13, 2019, Emera extended the maturity date of its $900 million revolving credit facility from June 2020 to June 2024. There were no other significant changes in commercial terms from the prior agreement.

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 |  | 2020 |  |  | 2021 |  |  | 2022 |  |  | 2023 |  |  | 2024 |  |  | Thereafter |  |  | Total |
Emera |  | $ | - |  |  | $ | - |  |  | $ | - |  |  | $ | 500 |  |  | $ | 437 |  |  | $ | 1,559 |  |  | $ | 2,496 |
Emera US Finance LP |  |  | - |  |  |  | 974 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 2,598 |  |  |  | 3,572 |
TECO Finance |  |  | 390 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 390 |
Tampa Electric |  |  | - |  |  |  | 301 |  |  |  | 292 |  |  |  | - |  |  |  | - |  |  |  | 2,741 |  |  |  | 3,334 |
PGS |  |  | - |  |  |  | 61 |  |  |  | 32 |  |  |  | - |  |  |  | - |  |  |  | 344 |  |  |  | 437 |
NMGC |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 195 |  |  |  | - |  |  |  | 195 |
NMGI |  |  | - |  |  |  | 260 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 214 |  |  |  | 474 |
NSPI |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 308 |  |  |  | 2,365 |  |  |  | 2,673 |
Emera Maine (1) |  |  | 49 |  |  |  | - |  |  |  | 107 |  |  |  | 11 |  |  |  | - |  |  |  | 351 |  |  |  | 518 |
EBP |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 248 |  |  |  | - |  |  |  | - |  |  |  | 248 |
ECI |  |  | 111 |  |  |  | 69 |  |  |  | 81 |  |  |  | 72 |  |  |  | 47 |  |  |  | 90 |  |  |  | 470 |
Total |  | $ | 550 |  |  | $ | 1,665 |  |  | $ | 512 |  |  | $ | 831 |  |  | $ | 987 |  |  | $ | 10,262 |  |  | $ | 14,807 |

(1) Classified as held for sale.

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25. ASSET RETIREMENT OBLIGATIONS

AROs mostly relate to 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 AROs 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.

The change in ARO for the years ended December 31 is as follows:

millions of Canadian dollars |  | 2019 |  |  | 2018 |
Balance, January 1 |  | $ | 205 |  |  | $ | 172 |
Additions (1) |  |  | - |  |  |  | 25 |
Liabilities settled (1) |  |  | (25) |  |  |  | (2) |
Accretion included in depreciation expense |  |  | 7 |  |  |  | 6 |
Other |  |  | 3 |  |  |  | (1) |
Change in foreign exchange rate |  |  | (5) |  |  |  | 5 |
Balance, December 31 |  | $ | 185 |  |  | $ | 205 |

(1) Tampa Electric produces ash and other by-products, collectively known as CCR’s, at its Big Bend and Polk power stations. The increase in ARO in 2018 was to achieve compliance with the US Environmental Protection Agency’s CCR rule due to the closure of a CCR management facility that began in 2018. The closure was completed in 2019.

26. COMMITMENTS AND CONTINGENCIES

A. | Commitments

As at December 31, 2019, contractual commitments (excluding pensions and other post-retirement obligations, convertible debentures, long-term debt and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following:

millions of Canadian dollars |  | 2020 |  |  | 2021 |  |  | 2022 |  |  | 2023 |  |  | 2024 |  |  | Thereafter |  |  | Total |
Purchased power (1)(2) |  | $ | 210 |  |  | $ | 233 |  |  | $ | 237 |  |  | $ | 246 |  |  | $ | 249 |  |  | $ | 2,228 |  |  | $ | 3,403 |
Transportation (3) |  |  | 514 |  |  |  | 398 |  |  |  | 340 |  |  |  | 281 |  |  |  | 264 |  |  |  | 2,720 |  |  |  | 4,517 |
Capital projects (4) |  |  | 411 |  |  |  | 109 |  |  |  | 103 |  |  |  | 86 |  |  |  | - |  |  |  | - |  |  |  | 709 |
Fuel, gas supply and storage |  |  | 466 |  |  |  | 133 |  |  |  | 22 |  |  |  | 1 |  |  |  | - |  |  |  | - |  |  |  | 622 |
Long-term service agreements (5)(6) |  |  | 52 |  |  |  | 37 |  |  |  | 36 |  |  |  | 27 |  |  |  | 26 |  |  |  | 100 |  |  |  | 278 |
Equity investment commitments (7) |  |  | 240 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 240 |
Leases and other (8) |  |  | 19 |  |  |  | 19 |  |  |  | 18 |  |  |  | 17 |  |  |  | 8 |  |  |  | 118 |  |  |  | 199 |
Demand side management |  |  | 38 |  |  |  | 41 |  |  |  | 43 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 122 |
|  | $ | 1,950 |  |  | $ | 970 |  |  | $ | 799 |  |  | $ | 658 |  |  | $ | 547 |  |  | $ | 5,166 |  |  | $ | 10,090 |

As noted below, contractual obligations at December 31, 2019 include amounts related to Emera Maine. On completion of the sale of Emera Maine, all of the remaining future contractual obligations will be transferred to the buyer. Refer to note 4 for additional information.

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

(2) Includes $520 million related to Emera Maine ($13 million in 2020; $23 million in 2021; $27 million in 2022; $31 million in 2023; $31 million in 2024 and $395 million thereafter).

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

(4) Includes $345 million of commitments related to Tampa Electric’s solar and Big Bend Power Station modernization projects.

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

(6) Includes $44 million related to various long-term service agreements Emera Maine has entered into for IT maintenance and vegetation management ($19 million in 2020; $9 million in 2021; $8 million in 2022; and $8 million in 2023).

(7) Emera has a commitment to make equity contributions to the Labrador Island Link Limited Partnership.

(8) Includes operating lease agreements for buildings, land, telecommunications services and rail cars, transmission rights and investment commitments.

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NSPI has a contractual obligation to pay NSPML for the use of the Maritime Link over approximately 37 years from its January 15, 2018 in-service date. The UARB approved payment for 2019 was $111 million subject to a $10 million holdback and as at December 31, 2019, $101 million has been paid. The UARB approved payment for 2020 is $145 million, subject to a holdback of up to $10 million. As part of NSPI’s 2020-2022 fuel stability plan, rates have been set to include the $145 million approved for 2020 and estimated amounts of $164 million and $162 million for 2021 and 2022, respectively. These estimated amounts are subject to review and approval by the UARB. The timing and amounts payable to NSPML for the remainder of the 37-year commitment period are dependent on regulatory filings with the UARB.

Emera has committed to obtain certain transmission rights for Nalcor Energy, if requested, to enable them to transmit energy which is not otherwise used in Newfoundland or Nova Scotia. This energy would be transmitted from Nova Scotia to New England energy markets beginning at first commercial power of the Muskrat Falls hydroelectric generating facility and related transmission assets when Nalcor commences delivery of the NS Block, and continuing for 50 years. As transmission rights are contracted, Emera includes the obligations within “Leases and other” in the above table.

B. | Legal Proceedings

TECO Guatemala Holdings (“TGH”)

In 2013, the International Centre for the Settlement of Investment Disputes (“ICSID”) Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, against the Republic of Guatemala (“Guatemala”) under the Dominican Republic Central America – United States Free Trade Agreement, issued an award in the case (“the Award”). The ICSID Tribunal unanimously found in favour of TGH and awarded damages to TGH of approximately $21 million USD, plus interest from October 21, 2010 at a rate equal to the U.S. prime rate plus two per cent. This award was upheld in subsequent annulment proceedings in 2016 and, in addition, TGH’s application for partial annulment of the award was granted, and Guatemala was ordered to pay certain costs relating to the annulment proceedings. As a result, TGH had the right to resubmit its arbitration claim against Guatemala to seek additional damages (in addition to the previously awarded $21 million USD), as well as additional interest on the $21 million USD, and its full costs relating to the original arbitration and the new arbitration proceeding.

On September 23, 2016, TGH filed a request for resubmission to arbitration. A new tribunal was constituted, and the matter was fully briefed. A hearing was held in March 2019 and a decision is expected from the tribunal in 2020. In addition, TGH sued Guatemala in Washington, D.C. court to enforce the $21 million USD owing. Guatemala’s motion to dismiss the enforcement action was denied. On October 1, 2019, the court granted TGH’s motion for summary judgment which will allow TGH to seek collection of the award plus interest when the order is final. Guatemala has appealed that decision. Results to date do not reflect any benefit.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party (“PRP”) for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as at December 31, 2019, TEC has estimated its financial liability to be $27 million ($21 million USD), primarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the 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.

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In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs. Other factors that could impact these estimates include additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in base rate proceedings.

Emera Maine

From 2011 to 2016, four separate complaints were filed with the FERC to challenge the base return on equity (“ROE”) under the ISO-New England (“ISO-NE”) Open Access Transmission Tariff (“OATT”).

| ● |  | Complaint I, filed by a group including the Attorney General of Massachusetts, New England utilities commissions, state public advocates and end users, was remanded to the FERC by the US Court of Appeals in 2017 for further proceedings. No reserve has been made with respect to Complaint I due to uncertainty of the outcome.

| ● |  | Complaints II and III (the “ENE” and “MA AG II” cases), brought by a group of consumer advocates and by a group of state commissions, state public advocates and end users respectively, have been joined together and are presently pending before the FERC. Emera Maine has recorded a reserve of approximately $4 million USD for these cases. These reserves have been recorded as “Regulatory liabilities” on the Consolidated Balance Sheets and as a reduction to “Operating revenues – regulated electric” on the Consolidated Statements of Income. The reserve was calculated based on Emera Maine’s best estimate of the probable outcome.

| ● |  | Complaint IV was filed by the Eastern Massachusetts Consumer Owned Systems (“EMCOS”). On March 27, 2018, a FERC Administrative Law Judge issued an Initial Decision concluding that the currently filed base ROE of 10.57 per cent, which with incentive adders may reach a maximum ROE of 11.74 per cent, is not unjust and unreasonable. This decision was appealed to the FERC. No reserve has been made in relation to Complaint IV due to the uncertainty of the final outcome.

On October 16, 2018, the FERC issued an order that addressed all four complaint proceedings. The FERC order proposed a new methodology to set ROEs. Based on the new methodology, the FERC’s preliminary finding was a 10.41 per cent base ROE for the ISO-NE OATT. The FERC has permitted parties to comment on the new methodology and its application to the four pending complaint proceedings. No new or additional reserves have been made with respect to any of the four pending complaints due to uncertainty.

On November 21, 2019, the FERC approved an order affecting transmission ROEs in the Midcontinent ISO region (MISO) that alters the Commission’s methodology for analyzing the base return on equity component of a jurisdictional public utility’s rates. The methodology applied in the MISO case may be applied by the FERC in the pending ISO NE cases. No date for a decision has been made yet, but the FERC is expected to rule on these three outstanding ISO-NE cases in 2020. Additionally, both the MISO case, and a decision in the ISO-NE cases, will be subject to further appeal rights and, if appealed, a final decision would be unlikely to occur before Q4 2020. Therefore, no change in Emera Maine’s accrual related to ROE complaints has been made as a result of the MISO decision.

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.

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C. | Principal Financial Risks and Uncertainties

Emera believes the following principal financial risks could materially affect the Company in the normal course of business. Risks associated with derivative instruments and fair value measurements are discussed in note 13 and note 14.

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

Foreign Exchange Risk

The Company is exposed to foreign currency exchange rate changes. Emera operates internationally, with an increasing amount of the Company’s adjusted net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the Canadian dollar and, particularly, the US dollar, which could positively or adversely affect results.

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

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

Liquidity and Capital Market Risk

Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs will be financed through internally generated cash flows, select asset sales, short-term credit facilities, and ongoing access to capital markets. Cash flows generated from the sale of select assets are dependent on the market for the assets, acceptable pricing and the timing of the close of any sales. The Company reasonably expects liquidity sources to exceed capital needs.

Emera’s access to capital and cost of borrowing is subject to a number of risk factors including financial market conditions and ratings assigned by credit rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan requires significant capital investments in property, plant and equipment. Emera is subject to risk with changes in interest rates that could have an adverse effect on the cost of financing. Inability to access cost-effective capital could have a material impact on Emera’s ability to fund its growth plan.

Emera is subject to financial risk associated with changes in its credit ratings. There are a number of factors that rating agencies evaluate to determine credit ratings, including the Company’s business and regulatory framework, the ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to climate change-related impacts, including increased frequency and severity of hurricanes and other sever weather events. A decrease in a credit rating could result in higher interest rates in future financings, increase borrowing costs under certain existing credit facilities, limit access to the commercial paper market or limit the availability of adequate credit support for subsidiary operations. Emera manages this risk by actively monitoring and managing key financial metrics with the objective of sustaining investment grade credit ratings.

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The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based compensation, preferred share units and deferred share units.

Interest Rate Risk

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

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

Commodity Price Risk

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

Income Tax Risk

The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in Canada, the United States and the Caribbean. Any such changes could affect the Company’s future earnings, cash flows, and financial position. The value of Emera’s existing deferred tax assets and liabilities are determined by existing tax laws and could be negatively impacted by changes in laws. Emera monitors the status of existing tax laws to ensure that changes impacting the Company are appropriately reflected in the Company’s tax compliance filings and financial results.

D. | Guarantees and Letters of Credit

Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December 31, 2019:

TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a gas transportation precedent agreement. The guarantee is for a maximum potential amount of $45 million USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the gas transportation precedent agreement termination date, which is expected to terminate on January 1, 2022. In the event that TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded below investment grade by Moody’s or S&P, TECO Energy would be required to provide its counterparty a letter of credit or cash deposit of $27 million USD.

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The Company has standby letters of credit and surety bonds in the amount of $82 million USD (December 31, 2018 - $67 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually as required.

Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The letter of credit expires in June 2020 and is renewed annually. The amount committed as at December 31, 2019 was $52 million (December 31, 2018 - $49 million).

Collaborative Arrangements

For the years ended December 31, 2019 and 2018, 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 OM&G expenses. In 2019, NSPI recognized $19 million net expense (2018 - $19 million) in “Regulated fuel for generation and purchased power” and $3 million (2018 - $2 million) in OM&G.

27. CUMULATIVE PREFERRED STOCK

Authorized:

Unlimited number of First Preferred shares, issuable in series.

Unlimited number of Second Preferred shares, issuable in series.

|  |  |  |  |  |  |  | December 31, 2019 |  |  | December 31, 2018 |
|  | Annual Dividend Per Share |  |  | Redemption Price per share |  |  | Issued and Outstanding |  |  | Net Proceeds |  |  | Issued and Outstanding |  |  | Net 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 |  | $ | 1.1802 |  |  | $ | 25.00 |  |  |  | 10,000,000 |  |  | $ | 245 |  |  |  | 10,000,000 |  |  | $ | 245 |
Series E |  | $ | 1.1250 |  |  | $ | 25.75 |  |  |  | 5,000,000 |  |  | $ | 122 |  |  |  | 5,000,000 |  |  | $ | 122 |
Series F |  | $ | 1.0625 |  |  | $ | 25.00 |  |  |  | 8,000,000 |  |  | $ | 195 |  |  |  | 8,000,000 |  |  | $ | 195 |
Series H |  | $ | 1.2250 |  |  | $ | 25.00 |  |  |  | 12,000,000 |  |  | $ | 295 |  |  |  | 12,000,000 |  |  | $ | 295 |
Total |  |  |  |  |  |  |  |  |  |  | 41,000,000 |  |  | $ | 1,004 |  |  |  | 41,000,000 |  |  | $ | 1,004 |

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Characteristics of the First Preferred Shares:

First Preferred Shares (1)(2) |  | Initial Yield (%) |  |  | Current Annual Dividend ($) |  |  | Minimum Reset Dividend Yield (%) |  |  | Earliest Redemption and/or Conversion Option Date |  |  | Redemption Value ($) |  |  | Right to Convert on a one for one basis |
Fixed rate reset (3)(4) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Series A |  |  | 4.400 |  |  |  | 0.6388 |  |  |  | 1.84 |  |  |  | August 15, 2020 |  |  |  | 25.00 |  |  |  | Series B |
Series C (5) |  |  | 4.100 |  |  |  | 1.1802 |  |  |  | 2.65 |  |  |  | August 15, 2023 |  |  |  | 25.00 |  |  |  | Series D |
Series F (6) |  |  | 4.250 |  |  |  | 1.0625 |  |  |  | 2.63 |  |  |  | February 15, 2020 |  |  |  | 25.00 |  |  |  | Series G |
Minimum rate reset (3)(4) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Series B |  |  | 2.393 |  |  |  | Floating |  |  |  | 1.84 |  |  |  | August 15, 2020 |  |  |  | 25.00 |  |  |  | Series A |
Series H |  |  | 4.900 |  |  |  | 1.2250 |  |  |  | 4.90 |  |  |  | August 15, 2023 |  |  |  | 25.00 |  |  |  | Series I |
Perpetual fixed rate |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Series E (7) |  |  | 4.500 |  |  |  | 1.1250 |  |  |  |  |  |  |  |  |  |  |  | 25.75 |  |  |  |  |

(1) Holders are entitled to receive fixed or floating cumulative cash dividends when declared by the Board of Directors of the Corporation.

(2) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First Preferred Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but excluding the dates fixed for redemption.

(3) On the redemption and/or conversion option date the reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed or floating dividend rate, which for Series A, C, F and H is the sum of the five-year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield (Series H annual reset rate must be a minimum of 4.90 per cent) and for Series B equals the Government of Treasury Bill Rate on the applicable reset date, plus 1.84 per cent.

(4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their Shares into an equal number of Cumulative Redeemable First Preferred Shares of a specified series. The Company has the right to redeem the outstanding Preferred Shares, Series D, Series G and Series I shares without the consent of the holder 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, 2023, February 15, 2020 and August 15, 2023, respectively. The reset dividend yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus 2.54 per cent.

(5) The annual fixed dividend per share for First Preferred Shares, Series C was reset from $1.0250 to $1.1802 for the five-year period from and including August 15, 2018.

(6) On January 7, 2020, Emera announced it would not redeem the 8,000,000 Cumulative Rate Reset First Preferred Shares, Series F Shares. The holders of the Series F Shares have the right, at their option, to convert all or any of their Series F Shares, on a one-for-one basis, into Cumulative Floating Rate First Preferred Shares, Series G of the Company on February 15, 2020, or to continue to hold their Series F Shares. On February 6, 2020, Emera announced that, after having taken into account all conversion notices received from holders, no First Preferred Shares, Series F Shares would be converted into Cumulative Floating Rate First Preferred Shares, Series G Shares.

(7) First Preferred Shares, Series E are redeemable at $25.75 to August 15, 2020, decreasing $0.25 each year until August 15, 2022 and $25.00 per share thereafter.

First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory redemption date. They are classified as equity and the associated dividends is deducted on the Consolidated Statements of Income before arriving at “Net earnings attributable to common shareholders” and is 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, for only so long as the dividends remain in arrears, 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.

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28. NON-CONTROLLING INTEREST IN SUBSIDIARIES

As at millions of Canadian dollars |  | December 31 2019 |  |  | December 31 2018 |
Preferred shares of GBPC |  | $ | 14 |  |  | $ | 19 |
Domlec |  |  | 21 |  |  |  | 22 |
|  | $ | 35 |  |  | $ | 41 |

Preferred shares of GBPC:

Authorized:

10,000 non-voting cumulative redeemable variable perpetual preferred shares.

|  | 2019 |  |  | 2018 |
Issued and outstanding: |  | number of shares |  |  | millions of dollars |  |  | number of shares |  |  | millions of dollars |
Outstanding as at December 31 |  |  | 10,000 |  |  | $ | 14 |  |  |  | 20,000 |  |  | $ | 19 |

GBPC Non–Voting Cumulative Variable Perpetual Preferred Stock:

In June 2019, GBPC redeemed all outstanding preferred shares, replacing them with $10 million USD debt at 4 per cent and $10 million USD preferred shares at 6 per cent. The new preferred shares are redeemable by GBPC after June 17, 2021, at $1,000 Bahamian per share plus accrued and unpaid dividends and are entitled to a 6.0 per cent per annum fixed cumulative preferential dividend to be paid semi-annually, with the first payment scheduled for January 2020.

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

29. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS

For the |  | Year ended December 31 |
millions of Canadian dollars |  | 2019 |  |  | 2018 |
Changes in non-cash working capital: |  |  |  |  |  |  |  |
Inventory |  | $ | (19) |  |  | $ | (44) |
Receivables and other current assets |  |  | 154 |  |  |  | (144) |
Accounts payable |  |  | (137) |  |  |  | 59 |
Other current liabilities |  |  | (71) |  |  |  | 13 |
Total non-cash working capital |  | $ | (73) |  |  | $ | (116) |
Supplemental disclosure of cash paid (received): |  |  |  |  |  |  |  |
Interest |  | $ | 750 |  |  | $ | 696 |
Income taxes |  | $ | (107) |  |  | $ | 33 |
Supplemental disclosure of non-cash activities: |  |  |  |  |  |  |  |
Common share dividends reinvested |  | $ | 187 |  |  | $ | 181 |
Increase in accrued capital expenditures |  | $ | 33 |  |  | $ | 50 |
Issuance of depository receipts |  | $ | - |  |  | $ | 22 |

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30. STOCK-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. As of December 31, 2019, the plan allows employees to 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 the employee’s 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. As at December 31, 2019, Emera is in compliance with this requirement.

Compensation cost for shares issued by Emera for the year ended December 31, 2019 under the Employee Common Share Purchase Plan was $1 million (2018 – $1 million) and is included in “OM&G” on the Consolidated Statements of Income.

In November 2019, Emera’s Board of Directors approved changes to the ECSPP which are expected to be effective in 2020. These changes include increasing the maximum employee cash contribution to $20,000 and changing the Company’s matching contribution to 20 per cent of the employees’ contributions. In addition, the Company match on dividends that exists within the current ECSPP plan will be discontinued.

The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan (“Dividend Reinvestment Plan”) or (“DRIP”), which provides an opportunity for shareholders to reinvest dividends and purchase 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 dividends. In 2019, the discount was changed from 5 per cent to 2 per cent effective with the dividend payment of August 15, 2019.

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 on the day before the option is granted. The maximum aggregate number of shares issuable under this plan is 11.7 million shares. As at December 31, 2019, Emera is in compliance with this requirement.

Stock options vest in 25 per cent increments on the first, second, third and fourth anniversaries of the date 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.

Unless a stock option has expired, vested options may be exercised within the 24 months following the option holders date of retirement or termination for other than just cause, and within six months following the date of termination for just cause, resignation or death. If stock options are not exercised within such time, they expire.

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The Company uses the Black-Scholes valuation model to estimate the compensation expense related to its stock-based compensation and recognizes the expense over the vesting period on a straight-line basis.

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:

|  | 2019 |  |  | 2018 |
Weighted average fair value per option |  | $ | 2.41 |  |  | $ | 1.70 |
Expected term (1) |  |  | 6 years |  |  |  | 6 years |
Risk-free interest rate (2) |  |  | 1.82% |  |  |  | 2.13% |
Expected dividend yield (3) |  |  | 5.10% |  |  |  | 5.69% |
Expected volatility (4) |  |  | 14.32% |  |  |  | 13.71% |

(1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period of time that the options are expected to be outstanding.

(2) Based on the Bank of Canada five-year government bond yields.

(3) Incorporates current dividend rates and historical dividend increase patterns.

(4) Estimated using the five-year historical volatility.

The following table summarizes stock option information for 2019:

|  | 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, 2018 |  |  | 4,225,575 |  |  | $ | 39.56 |  |  |  | 1,679,325 |  |  | $ | 2.22 |
Granted |  |  | 651,400 |  |  |  | 46.39 |  |  |  | 651,400 |  |  |  | 2.41 |
Exercised |  |  | (2,568,625) |  |  |  | 37.90 |  |  |  | N/A |  |  |  | N/A |
Vested |  |  | N/A |  |  |  | N/A |  |  |  | (759,900) |  |  |  | 2.37 |
Forfeited |  |  | (21,800) |  |  |  | 46.39 |  |  |  | (21,800) |  |  |  | 2.41 |
Expired |  |  | N/A |  |  |  | N/A |  |  |  | N/A |  |  |  | N/A |
Options outstanding December 31, 2019 |  |  | 2,286,550 |  |  | $ | 43.31 |  |  |  | 1,549,025 |  |  | $ | 2.22 |
Options exercisable December 31, 2019 (2)(3) |  |  | 737,525 |  |  | $ | 41.43 |  |  |  |  |  |  |  |  |

(1) As at December 31, 2019, there was $2 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 (2018 - $2 million, 2.2 years).

(2) As at December 31, 2019, the weighted average remaining term of vested options was 5.5 years with an aggregate intrinsic value of $11 million (2018 - 5.1 years, $18 million).

(3) As at December 31, 2019, the fair value of options that vested in the year was $2 million (2018 - $2 million).

Compensation cost recognized for stock options for the year ended December 31, 2019 was $1 million (2018 – $1 million), which is included in “OM&G” on the Consolidated Statements of Income.

As at December 31, 2019, cash received from option exercises was $97 million (2018 – $1 million). The total intrinsic value of options exercised for the year ended December 31, 2019 was $32 million (2018 – $1 million). The range of exercise prices for the options outstanding as at December 31, 2019 was $32.06 to $46.39 (2018 – $21.99 to $46.19).

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Share Unit Plans

The Company has DSU, PSU and RSU plans and the 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, 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 Emera’s closing common share price on the date DSUs are redeemed.

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 per cent of the value of their actual annual incentive award (25 per cent 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 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, 2019 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, 2018 |  |  | 837,109 |  |  | $ | 29.54 |  |  |  | 563,521 |  |  | $ | 37.07 |
Granted including DRIP |  |  | 120,098 |  |  |  | 39.05 |  |  |  | 104,293 |  |  |  | 42.25 |
Exercised |  |  | (252,610) |  |  |  | 19.68 |  |  |  | (136,360) |  |  |  | 29.76 |
Outstanding and exercisable as at December 31, 2019 |  |  | 704,597 |  |  | $ | 34.69 |  |  |  | 531,454 |  |  | $ | 39.96 |

Compensation cost recognized for employee and director DSU for the year ended December 31, 2019 was $24 million (2018 – ($2 million)). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2019 were $7 million (2018 – $1 million). The aggregate intrinsic value of the outstanding shares for the year ended December 31, 2019 for employees was $40 million (2018 - $37 million). The aggregate intrinsic value of the outstanding shares for the year ended December 31, 2019 for directors was $30 million (2018 - $25 million).

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Performance Share Unit Plan

Under the PSU plan, certain 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, resulting in a cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional PSUs. 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 may be pro-rated in certain departure scenarios.

A summary of the activity related to employee PSUs for the year ended December 31, 2019 is presented in the following table:

|  | Employee PSU |  |  | Weighted Average Grant Date Fair Value |  |  | Aggregate intrinsic value |
Outstanding as at December 31, 2018 |  |  | 1,127,114 |  |  | $ | 46.02 |  |  | $ | 56.9 |
Granted including DRIP |  |  | 545,008 |  |  |  | 43.15 |  |  |  |  |
Exercised |  |  | (140,754) |  |  |  | 43.00 |  |  |  |  |
Forfeited |  |  | (150,268) |  |  |  | 44.41 |  |  |  |  |
Outstanding as at December 31, 2019 |  |  | 1,381,100 |  |  | $ | 45.37 |  |  | $ | 88.1 |

Compensation cost recognized for the PSU plan for the year ended December 31, 2019 was $34 million (2018 – $14 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2019 were $9 million (2018 – $4 million).

Restricted Share Unit Plan

In November 2019, a new RSU plan was approved by Emera’s Board of Directors, with grants to begin in 2020. Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the RSU plan. RSUs are granted annually for three-year overlapping cycles, resulting in a cash payment. RSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional RSUs. The RSU value varies according to the Emera common share market price.

RSUs 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 may be pro-rated in certain departure scenarios.

31. VARIABLE INTEREST ENTITIES

The Company performs ongoing analysis to assess whether it holds any Variable Interest Entities (“VIE”) or whether any reconsideration events have arisen with respect to existing 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 has an investment in a VIE but is not deemed the primary beneficiary, the VIE is accounted for using the equity method.

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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. When the critical milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial reporting purposes as it has authority over the majority of the direct activities that are expected to most significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the Maritime Link as an equity investment.

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

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

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

As at |  | December 31, 2019 |  |  | December 31, 2018 |
millions of Canadian dollars |  | Total assets |  |  | Maximum exposure to loss |  |  | Total assets |  |  | Maximum exposure to loss |
Unconsolidated VIEs in which Emera has variable interests |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NSPML (equity accounted) |  | $ | 554 |  |  | $ | 23 |  |  | $ | 545 |  |  | $ | 51 |

32. 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.

33. SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through February 14, 2020, the date the financial statements were issued.

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34. 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 Emera US Holdings Inc. (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 condensed 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.

Emera Incorporated

Condensed Consolidated Statements of Income

millions of Canadian dollars |  | Parent |  |  | Subsidiary Issuer |  |  | Guarantor Subsidiaries |  |  | Non-guarantor Subsidiaries |  |  | Eliminations |  |  | Consolidated |
For the year ended December 31, 2019 |
Operating revenues |  | $ | - |  |  | $ | - |  |  | $ | 4,125 |  |  | $ | 2,029 |  |  | $ | (43) |  |  | $ | 6,111 |
Operating expenses |  |  | 31 |  |  |  | - |  |  |  | 3,084 |  |  |  | 1,695 |  |  |  | (42) |  |  |  | 4,768 |
Income (loss) from equity investments and subsidiaries |  |  | 753 |  |  |  | - |  |  |  | 2 |  |  |  | 151 |  |  |  | (752) |  |  |  | 154 |
Other income (expenses), net |  |  | 21 |  |  |  | - |  |  |  | 22 |  |  |  | (11) |  |  |  | (20) |  |  |  | 12 |
Interest expense, net (1) |  |  | 75 |  |  |  | (40) |  |  |  | 481 |  |  |  | 222 |  |  |  | - |  |  |  | 738 |
Income (loss) before provision for income taxes |  |  | 668 |  |  |  | 40 |  |  |  | 584 |  |  |  | 252 |  |  |  | (773) |  |  |  | 771 |
Income tax expense (recovery) |  |  | (40) |  |  |  | 11 |  |  |  | 60 |  |  |  | 30 |  |  |  | - |  |  |  | 61 |
Net income (loss) |  |  | 708 |  |  |  | 29 |  |  |  | 524 |  |  |  | 222 |  |  |  | (773) |  |  |  | 710 |
Non-controlling interest in subsidiaries |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 2 |  |  |  | 2 |
Preferred stock dividends |  |  | 45 |  |  |  | - |  |  |  | 19 |  |  |  | 3 |  |  |  | (22) |  |  |  | 45 |
Net income (loss) attributable to common shareholders |  | $ | 663 |  |  | $ | 29 |  |  | $ | 505 |  |  | $ | 219 |  |  | $ | (753) |  |  | $ | 663 |
Comprehensive income (loss) of Emera Incorporated |  | $ | 465 |  |  | $ | 14 |  |  | $ | 102 |  |  | $ | 205 |  |  | $ | (321) |  |  | $ | 465 |
For the year ended December 31, 2018 |
Operating revenues |  | $ | - |  |  | $ | - |  |  | $ | 4,432 |  |  | $ | 2,146 |  |  | $ | (54) |  |  | $ | 6,524 |
Operating expenses |  |  | 45 |  |  |  | - |  |  |  | 3,468 |  |  |  | 1,665 |  |  |  | (52) |  |  |  | 5,126 |
Income (loss) from equity investments and subsidiaries |  |  | 801 |  |  |  | - |  |  |  | 3 |  |  |  | 150 |  |  |  | (800) |  |  |  | 154 |
Other income (expenses), net |  |  | 22 |  |  |  | - |  |  |  | 20 |  |  |  | (27) |  |  |  | (38) |  |  |  | (23) |
Interest expense, net (1) |  |  | 79 |  |  |  | (40) |  |  |  | 456 |  |  |  | 218 |  |  |  | - |  |  |  | 713 |
Income (loss) before provision for income taxes |  |  | 699 |  |  |  | 40 |  |  |  | 531 |  |  |  | 386 |  |  |  | (840) |  |  |  | 816 |
Income tax expense (recovery) |  |  | (47) |  |  |  | 9 |  |  |  | 64 |  |  |  | 43 |  |  |  | - |  |  |  | 69 |
Net income (loss) |  |  | 746 |  |  |  | 31 |  |  |  | 467 |  |  |  | 343 |  |  |  | (840) |  |  |  | 747 |
Non-controlling interest in subsidiaries |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (1) |  |  |  | 2 |  |  |  | 1 |
Preferred stock dividends |  |  | 36 |  |  |  | - |  |  |  | 38 |  |  |  | 4 |  |  |  | (42) |  |  |  | 36 |
Net income (loss) attributable to common shareholders |  | $ | 710 |  |  | $ | 31 |  |  | $ | 429 |  |  | $ | 340 |  |  | $ | (800) |  |  | $ | 710 |
Comprehensive income (loss) of Emera Incorporated |  | $ | 1,249 |  |  | $ | 56 |  |  | $ | 973 |  |  | $ | 439 |  |  | $ | (1,468) |  |  | $ | 1,249 |

(1) Interest expense is net of interest revenue.

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Emera Incorporated

Condensed Consolidated Balance Sheets

millions of Canadian dollars |  | Parent |  |  | Subsidiary Issuer |  |  | Guarantor Subsidiaries |  |  | Non-guarantor Subsidiaries |  |  | Eliminations |  |  | Consolidated |
As at December 31, 2019 |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current assets |  | $ | 96 |  |  | $ | 27 |  |  |  | 1,486 |  |  | $ | 1,171 |  |  | $ | (294 | ) |  | $ | 2,486 |
Property, plant and equipment |  |  | 23 |  |  |  | - |  |  |  | 13,099 |  |  |  | 5,040 |  |  |  | 5 |  |  |  | 18,167 |
Other assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Regulatory assets |  |  | - |  |  |  | - |  |  |  | 519 |  |  |  | 912 |  |  |  | - |  |  |  | 1,431 |
Goodwill |  |  | 3 |  |  |  | - |  |  |  | 5,762 |  |  |  | 70 |  |  |  | - |  |  |  | 5,835 |
Other long-term assets |  |  | 11,994 |  |  |  | 3,856 |  |  |  | 1,739 |  |  |  | 3,289 |  |  |  | (16,955 | ) |  |  | 3,923 |
Total other assets |  |  | 11,997 |  |  |  | 3,856 |  |  |  | 8,020 |  |  |  | 4,271 |  |  |  | (16,955 | ) |  |  | 11,189 |
Total assets |  | $ | 12,116 |  |  | $ | 3,883 |  |  | $ | 22,605 |  |  | $ | 10,482 |  |  | $ | (17,244 | ) |  | $ | 31,842 |
Liabilities and Equity |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current liabilities |  | $ | 542 |  |  | $ | 12 |  |  | $ | 3,699 |  |  | $ | 992 |  |  | $ | (1,079 | ) |  | $ | 4,166 |
Long-term liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term debt |  |  | 2,978 |  |  |  | 3,534 |  |  |  | 8,829 |  |  |  | 4,547 |  |  |  | (6,209 | ) |  |  | 13,679 |
Deferred income taxes |  |  | - |  |  |  | 3 |  |  |  | 515 |  |  |  | 767 |  |  |  | - |  |  |  | 1,285 |
Regulatory liabilities |  |  | - |  |  |  | - |  |  |  | 1,793 |  |  |  | 93 |  |  |  | - |  |  |  | 1,886 |
Other long-term liabilities |  |  | 38 |  |  |  | - |  |  |  | 1,697 |  |  |  | 511 |  |  |  | (21 | ) |  |  | 2,225 |
Total long-term liabilities |  |  | 3,016 |  |  |  | 3,537 |  |  |  | 12,834 |  |  |  | 5,918 |  |  |  | (6,230 | ) |  |  | 19,075 |
Total Emera Incorporated equity |  |  | 8,558 |  |  |  | 334 |  |  |  | 6,072 |  |  |  | 3,551 |  |  |  | (9,949 | ) |  |  | 8,566 |
Non-controlling interest in subsidiaries |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 21 |  |  |  | 14 |  |  |  | 35 |
Total equity |  |  | 8,558 |  |  |  | 334 |  |  |  | 6,072 |  |  |  | 3,572 |  |  |  | (9,935 | ) |  |  | 8,601 |
Total liabilities and equity |  | $ | 12,116 |  |  | $ | 3,883 |  |  | $ | 22,605 |  |  | $ | 10,482 |  |  | $ | (17,244 | ) |  | $ | 31,842 |
As at December 31, 2018 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current assets |  | $ | 146 |  |  | $ | 67 |  |  |  | 1,767 |  |  | $ | 1,096 |  |  | $ | (244 | ) |  | $ | 2,832 |
Property, plant and equipment |  |  | 24 |  |  |  | - |  |  |  | 13,745 |  |  |  | 4,946 |  |  |  | (3 | ) |  |  | 18,712 |
Other assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Regulatory assets |  |  | - |  |  |  | - |  |  |  | 645 |  |  |  | 759 |  |  |  | - |  |  |  | 1,404 |
Goodwill |  |  | - |  |  |  | - |  |  |  | 6,208 |  |  |  | 105 |  |  |  | - |  |  |  | 6,313 |
Other long-term assets |  |  | 11,457 |  |  |  | 4,660 |  |  |  | 971 |  |  |  | 3,200 |  |  |  | (17,235 | ) |  |  | 3,053 |
Total other assets |  |  | 11,457 |  |  |  | 4,660 |  |  |  | 7,824 |  |  |  | 4,064 |  |  |  | (17,235 | ) |  |  | 10,770 |
Total assets |  | $ | 11,627 |  |  | $ | 4,727 |  |  | $ | 23,336 |  |  | $ | 10,106 |  |  | $ | (17,482 | ) |  | $ | 32,314 |
Liabilities and Equity |
Current liabilities |  | $ | 368 |  |  | $ | 695 |  |  | $ | 2,829 |  |  | $ | 926 |  |  | $ | (265 | ) |  | $ | 4,553 |
Long-term liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term debt |  |  | 2,906 |  |  |  | 3,709 |  |  |  | 10,243 |  |  |  | 4,428 |  |  |  | (6,994 | ) |  |  | 14,292 |
Deferred income taxes |  |  | - |  |  |  | 3 |  |  |  | 668 |  |  |  | 643 |  |  |  | 6 |  |  |  | 1,320 |
Regulatory liabilities |  |  | - |  |  |  | - |  |  |  | 2,118 |  |  |  | 241 |  |  |  | - |  |  |  | 2,359 |
Other long-term liabilities |  |  | 36 |  |  |  | - |  |  |  | 874 |  |  |  | 543 |  |  |  | (21 | ) |  |  | 1,432 |
Total long-term liabilities |  |  | 2,942 |  |  |  | 3,712 |  |  |  | 13,903 |  |  |  | 5,855 |  |  |  | (7,009 | ) |  |  | 19,403 |
Total Emera Incorporated equity |  |  | 8,317 |  |  |  | 320 |  |  |  | 6,604 |  |  |  | 3,303 |  |  |  | (10,227 | ) |  |  | 8,317 |
Non-controlling interest in subsidiaries |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 22 |  |  |  | 19 |  |  |  | 41 |
Total equity |  |  | 8,317 |  |  |  | 320 |  |  |  | 6,604 |  |  |  | 3,325 |  |  |  | (10,208 | ) |  |  | 8,358 |
Total liabilities and equity |  | $ | 11,627 |  |  | $ | 4,727 |  |  | $ | 23,336 |  |  | $ | 10,106 |  |  | $ | (17,482 | ) |  | $ | 32,314 |

159

Emera Incorporated

Condensed Consolidated Statements of Cash Flows

millions of Canadian dollars |  | Parent |  |  | Subsidiary Issuer |  |  | Guarantor Subsidiaries |  |  | Non-guarantor Subsidiaries |  |  | Eliminations |  |  | Consolidated |
As at December 31, 2019 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net cash provided by (used in) by operating activities |  | $ | 133 |  |  | $ | 33 |  |  | $ | 1,100 |  |  | $ | 279 |  |  | $ | (20 | ) |  | $ | 1,525 |
Investing activities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Additions to property, plant and equipment |  |  | (2 | ) |  |  | - |  |  |  | (1,973 | ) |  |  | (520 | ) |  |  | - |  |  |  | (2,495 | )
Net purchase of investments subject to significant influence |  |  | - |  |  |  | - |  |  |  | (3 | ) |  |  | - |  |  |  | - |  |  |  | (3 | )
Proceeds on disposal of assets |  |  | - |  |  |  | - |  |  |  | 818 |  |  |  | 57 |  |  |  | - |  |  |  | 875 |
Other investing activities |  |  | (402 | ) |  |  | 595 |  |  |  | 774 |  |  |  | (1 | ) |  |  | (960 | ) |  |  | 6 |
Net cash provided by (used in) investing activities |  |  | (404 | ) |  |  | 595 |  |  |  | (384 | ) |  |  | (464 | ) |  |  | (960 | ) |  |  | (1,617 | )
Financing activities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Change in short-term debt, net |  |  | 399 |  |  |  | - |  |  |  | (9 | ) |  |  | 23 |  |  |  | - |  |  |  | 413 |
Proceeds from long-term debt |  |  | - |  |  |  | - |  |  |  | (6 | ) |  |  | 552 |  |  |  | 520 |  |  |  | 1,066 |
Retirement of long-term debt |  |  | (225 | ) |  |  | (664 | ) |  |  | (65 | ) |  |  | (166 | ) |  |  | 17 |  |  |  | (1,103 | )
Net borrowings (repayments) under committed credit facilities |  |  | 146 |  |  |  | - |  |  |  | (11 | ) |  |  | (225 | ) |  |  | (28 | ) |  |  | (118 | )
Issuance of common and preferred stock |  |  | 203 |  |  |  | - |  |  |  | (620 | ) |  |  | 58 |  |  |  | 562 |  |  |  | 203 |
Dividends paid |  |  | (423 | ) |  |  | - |  |  |  | (19 | ) |  |  | (138 | ) |  |  | 157 |  |  |  | (423 | )
Other financing activities |  |  | (1 | ) |  |  | - |  |  |  | 138 |  |  |  | 87 |  |  |  | (248 | ) |  |  | (24 | )
Net cash provided by (used in) financing activities |  |  | 99 |  |  |  | (664 | ) |  |  | (592 | ) |  |  | 191 |  |  |  | 980 |  |  |  | 14 |
Effect of exchange rate changes on cash, cash equivalents, restricted cash and assets held for sale |  |  | 147 |  |  |  | (3 | ) |  |  | (141 | ) |  |  | (23 | ) |  |  | - |  |  |  | (20 | )
Net increase (decrease) in cash, cash equivalents, restricted cash and assets held for sale |  |  | (25 | ) |  |  | (39 | ) |  |  | (17 | ) |  |  | (17 | ) |  |  | - |  |  |  | (98 | )
Cash, cash equivalents, and restricted cash, beginning of year |  |  | 20 |  |  |  | 58 |  |  |  | 104 |  |  |  | 190 |  |  |  | - |  |  |  | 372 |
Cash, cash equivalents, restricted cash and assets held for sale, end of year |  | $ | (5 | ) |  | $ | 19 |  |  | $ | 87 |  |  | $ | 173 |  |  | $ | - |  |  | $ | 274 |

160

Emera Incorporated

Condensed Consolidated Statements of Cash Flows (Continued)

millions of Canadian dollars |  | Parent |  |  | Subsidiary Issuer |  |  | Guarantor Subsidiaries |  |  | Non-guarantor Subsidiaries |  |  | Eliminations |  |  | Consolidated |
As at December 31, 2018 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net cash provided by (used in) operating activities |  | $ | 191 |  |  | $ | 35 |  |  | $ | 1,266 |  |  | $ | 465 |  |  | $ | (267 | ) |  | $ | 1,690 |
Investing activities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Additions to property, plant and equipment |  |  | (9 | ) |  |  | - |  |  |  | (1,687 | ) |  |  | (466 | ) |  |  | - |  |  |  | (2,162 | )
Net purchase of investments subject to significant influence |  |  | - |  |  |  | - |  |  |  | (16 | ) |  |  | (33 | ) |  |  | - |  |  |  | (49 | )
Other investing activities |  |  | (489 | ) |  |  | - |  |  |  | 3 |  |  |  | (65 | ) |  |  | 572 |  |  |  | 21 |
Net cash provided by (used in) investing activities |  |  | (498 | ) |  |  | - |  |  |  | (1,700 | ) |  |  | (564 | ) |  |  | 572 |  |  |  | (2,190 | )
Financing activities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Change in short-term debt, net |  |  | - |  |  |  | - |  |  |  | (162 | ) |  |  | - |  |  |  | - |  |  |  | (162 | )
Proceeds from long-term debt |  |  | - |  |  |  | - |  |  |  | 1,174 |  |  |  | 75 |  |  |  | (194 | ) |  |  | 1,055 |
Retirement of long-term debt |  |  | - |  |  |  | - |  |  |  | (716 | ) |  |  | (41 | ) |  |  | - |  |  |  | (757 | )
Net borrowings (repayments) under committed credit facilities |  |  | 136 |  |  |  | - |  |  |  | (103 | ) |  |  | 178 |  |  |  | 110 |  |  |  | 321 |
Issuance of common and preferred stock |  |  | 301 |  |  |  | - |  |  |  | 319 |  |  |  | 127 |  |  |  | (446 | ) |  |  | 301 |
Dividends paid |  |  | (382 | ) |  |  | - |  |  |  | (37 | ) |  |  | (311 | ) |  |  | 348 |  |  |  | (382 | )
Other financing activities |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 91 |  |  |  | (123 | ) |  |  | (32 | )
Net cash provided by (used in) financing activities |  |  | 55 |  |  |  | - |  |  |  | 475 |  |  |  | 119 |  |  |  | (305 | ) |  |  | 344 |
Effect of exchange rate changes on cash, cash equivalents and restricted cash |  |  | (4 | ) |  |  | 2 |  |  |  | 9 |  |  |  | 18 |  |  |  | - |  |  |  | 25 |
Net increase (decrease) in cash, cash equivalents, and restricted cash |  |  | (256 | ) |  |  | 37 |  |  |  | 50 |  |  |  | 38 |  |  |  | - |  |  |  | (131 | )
Cash, cash equivalents and restricted cash, beginning of year |  |  | 276 |  |  |  | 21 |  |  |  | 54 |  |  |  | 152 |  |  |  | - |  |  |  | 503 |
Cash, cash equivalents and restricted cash, end of year |  | $ | 20 |  |  | $ | 58 |  |  | $ | 104 |  |  | $ | 190 |  |  | $ | - |  |  | $ | 372 |

161