Exhibit 99.2
EMERA INCORPORATED
Unaudited Condensed Consolidated
Interim Financial Statements
March 31, 2018 and 2017
Emera Incorporated
Condensed Consolidated Statements of Income (Unaudited)
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars (except per share amounts) | 2018 | 2017 | ||||||
| Operating revenues | ||||||||
Regulated electric | $ 1,177 | $ 1,162 | ||||||
Regulated gas | 333 | 313 | ||||||
Non-regulated | 297 | 382 | ||||||
Total operating revenues | 1,807 | 1,857 | ||||||
| Operating expenses | ||||||||
Regulated fuel for generation and purchased power | 415 | 400 | ||||||
Regulated cost of natural gas | 138 | 126 | ||||||
Non-regulated fuel for generation and purchased power | 66 | 84 | ||||||
Non-regulated direct costs | 3 | 10 | ||||||
Operating, maintenance and general | 389 | 351 | ||||||
Provincial, state and municipal taxes | 83 | 81 | ||||||
Depreciation and amortization | 223 | 217 | ||||||
Total operating expenses | 1,317 | 1,269 | ||||||
| Income from operations | 490 | 588 | ||||||
| Income from equity investments (note 6) | 37 | 26 | ||||||
| Other income (expenses), net | (9) | (5) | ||||||
| Interest expense, net | 175 | 175 | ||||||
| Income before provision for income taxes | 343 | 434 | ||||||
| Income tax expense (recovery) (note 7) | 65 | 112 | ||||||
| Net income | 278 | 322 | ||||||
| Non-controlling interest in subsidiaries | - | 3 | ||||||
| Preferred stock dividends | 7 | 7 | ||||||
| Net income attributable to common shareholders | $ 271 | $ 312 | ||||||
| Weighted average shares of common stock outstanding (in millions)(note 9) | ||||||||
Basic | 231.0 | 211.6 | ||||||
Diluted | 231.5 | 212.2 | ||||||
| Earnings per common share (note 9) | ||||||||
Basic | $ 1.17 | $ 1.48 | ||||||
Diluted | $ 1.17 | $ 1.47 | ||||||
| Dividends per common share declared | $ 0.5650 | $ 0.5225 | ||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
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Emera Incorporated
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||
| Net income | $ | 278 | $ | 322 | ||||
| Other comprehensive income, net of tax | ||||||||
| Foreign currency translation adjustment | 185 | (48) | ||||||
| Unrealized gains (losses) on net investment hedges (1)(2) | (36) | 13 | ||||||
| Cash flow hedges | ||||||||
Net derivative gains | 1 | 2 | ||||||
Less: reclassification adjustment for gains included (3) in income | (5) | - | ||||||
Net effects of cash flow hedges | (4) | 2 | ||||||
| Unrealized gains (losses) onavailable-for-sale investment | ||||||||
Unrealized gain (loss) arising during the period | (1) | 3 | ||||||
Less: reclassification adjustment for (gains) recognized in income | (4) | (1) | ||||||
Net unrealized holding gains (losses) | (5) | 2 | ||||||
| Net change in unrecognized pension and post-retirement benefit obligation | 8 | 8 | ||||||
| Other comprehensive income (loss) (4) | 148 | (23) | ||||||
| Comprehensive income | 426 | 299 | ||||||
| Comprehensive income attributable tonon-controlling interest | 1 | 2 | ||||||
| Comprehensive Income of Emera Incorporated | $ | 425 | $ | 297 | ||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
1) Net of tax recovery of $6 million (2017 - nil) for the three months ended March 31, 2018.
2) 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.
3) Net of tax expense of $1 million (2017 - $1 million tax expense) for the three months ended March 31, 2018.
4) Net of tax recovery of $5 million (2017 - $1 million tax expense) for the three months ended March 31, 2018.
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Emera Incorporated
Condensed Consolidated Balance Sheets (Unaudited)
| As at | March 31 | December 31 | ||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||
| Assets | ||||||||
| Current assets | ||||||||
Cash and cash equivalents | $ | 367 | $ | 438 | ||||
Restricted cash | 68 | 65 | ||||||
Inventory | 404 | 418 | ||||||
Derivative instruments (notes 11 and 12) | 124 | 141 | ||||||
Regulatory assets (note 13) | 124 | 138 | ||||||
Receivables and other current assets | 1,240 | 1,326 | ||||||
| 2,327 | 2,526 | |||||||
| Property, plant and equipment,net of accumulated depreciation and amortization of $8,111 and $7,824, respectively | 17,480 | 16,995 | ||||||
| Other assets | ||||||||
Deferred income taxes (note 7) | 115 | 138 | ||||||
Derivative instruments (notes 11 and 12) | 73 | 112 | ||||||
Regulatory assets (note 13) | 1,278 | 1,238 | ||||||
Net investment in direct financing lease | 480 | 481 | ||||||
Investments subject to significant influence (note 6) | 1,283 | 1,215 | ||||||
Goodwill | 5,967 | 5,805 | ||||||
Other long-term assets | 284 | 261 | ||||||
| 9,480 | 9,250 | |||||||
| Total assets | $ | 29,287 | $ | 28,771 | ||||
| Liabilities and Equity | ||||||||
| Current liabilities | ||||||||
Short-term debt (note 16) | $ | 1,302 | $ | 1,241 | ||||
Current portion of long-term debt | 763 | 741 | ||||||
Accounts payable | 948 | 1,161 | ||||||
Derivative instruments (notes 11 and 12) | 159 | 227 | ||||||
Regulatory liabilities (note 13) | 228 | 226 | ||||||
Other current liabilities | 405 | 350 | ||||||
| 3,805 | 3,946 | |||||||
| Long-term liabilities | ||||||||
Long-term debt (note 17) | 13,375 | 13,140 | ||||||
Deferred income taxes (note 7) | 1,097 | 1,011 | ||||||
Derivative instruments (notes 11 and 12) | 85 | 83 | ||||||
Regulatory liabilities (note 13) | 2,252 | 2,242 | ||||||
Pension and post-retirement liabilities (note 15) | 560 | 559 | ||||||
Other long-term liabilities | 609 | 609 | ||||||
| 17,978 | 17,644 | |||||||
| Equity | ||||||||
Common stock (note 8) | 5,674 | 5,601 | ||||||
Cumulative preferred stock | 709 | 709 | ||||||
Contributed surplus | 84 | 76 | ||||||
Accumulated other comprehensive income (loss) (note 10) | (41) | (188) | ||||||
Retained earnings | 1,039 | 891 | ||||||
Total Emera Incorporated equity | 7,465 | 7,089 | ||||||
Non-controlling interest in subsidiaries | 39 | 92 | ||||||
Total equity | 7,504 | 7,181 | ||||||
| Total liabilities and equity | $ | 29,287 | $ | 28,771 | ||||
| Commitments and contingencies (note 18) | Approved on behalf of the Board of Directors | |||
| The accompanying notes are an integral part of these condensed consolidated financial statements. | “M. Jacqueline Sheppard” | “Scott Balfour” | ||
| Chair of the Board | President and Chief Executive Officer | |||
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Emera Incorporated
Condensed Consolidated Statements of Cash Flows (Unaudited)
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||
| Operating activities | ||||||||
| Net income | $ | 278 | $ | 322 | ||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depreciation and amortization | 227 | 218 | ||||||
Income from equity investments, net of dividends | (28) | (19) | ||||||
Allowance for equity funds used during construction | (2) | (3) | ||||||
Deferred income taxes, net | 54 | 101 | ||||||
Net change in pension and post-retirement liabilities | (3) | (8) | ||||||
Regulated fuel adjustment mechanism and fixed cost deferrals | 4 | 13 | ||||||
Net change in fair value of derivative instruments | (59) | (249) | ||||||
Net change in regulatory assets and liabilities | 17 | (38) | ||||||
Net change in capitalized transportation capacity | (39) | 20 | ||||||
Foreign exchange loss (gain) | (1) | - | ||||||
Other operating activities, net | (4) | (9) | ||||||
| Changes innon-cash working capital (note 19) | (11) | (182) | ||||||
| Net cash provided by operating activities | 433 | 166 | ||||||
| Investing activities | ||||||||
Additions to property, plant and equipment | (349) | (305) | ||||||
Net purchase of investments subject to significant influence, inclusive of acquisition costs | (40) | (69) | ||||||
Other investing activities | 2 | (7) | ||||||
| Net cash used in investing activities | (387) | (381) | ||||||
| Financing activities | ||||||||
Change in short-term debt, net | (103) | 53 | ||||||
Proceeds from short-term debt with maturities greater than 90 days | 129 | - | ||||||
Proceeds from long-term debt, net of issuance costs | 24 | 40 | ||||||
Retirement of long-term debt | (4) | (4) | ||||||
Net borrowings (repayments) under committed credit facilities | (58) | 56 | ||||||
Issuance of common stock, net of issuance costs | 3 | 3 | ||||||
Dividends on common stock | (82) | (69) | ||||||
Dividends on preferred stock | (7) | (7) | ||||||
Dividends paid by subsidiaries tonon-controlling interest | (1) | (2) | ||||||
Other financing activities | (25) | (4) | ||||||
| Net cash (used in) provided by financing activities | (124) | 66 | ||||||
| Effect of exchange rate changes on cash, cash equivalents, and restricted cash | 10 | (2) | ||||||
| Net decrease in cash, cash equivalents and restricted cash | (68) | (151) | ||||||
| Cash, cash equivalents and restricted cash, beginning of period | 503 | 491 | ||||||
| Cash, cash equivalents and restricted cash, end of period | $ | 435 | $ | 340 | ||||
| Cash, cash equivalents, and restricted cash consists of: | ||||||||
| Cash | $ | 235 | $ | 235 | ||||
| Short-term investments | 132 | 20 | ||||||
| Restricted cash | �� | 68 | 85 | |||||
| Cash, cash equivalents, and restricted cash | $ | 435 | $ | 340 | ||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
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Emera Incorporated
Condensed Consolidated Statements of Changes in Equity (Unaudited)
| millions of Canadian dollars | Common Stock | Preferred Stock | Contributed Surplus | Accumulated Other Comprehensive Income (“AOCI”) | Retained Earnings | Non- Controlling Interest | Total Equity | |||||||||||||||||||||
| For the three months ended March 31, 2018 | ||||||||||||||||||||||||||||
| Balance, December 31, 2017 | $ | 5,601 | $ | 709 | $ | 76 | $ | (188) | $ | 891 | $ | 92 | $ | 7,181 | ||||||||||||||
| Net income of Emera Incorporated | - | - | - | - | 278 | - | 278 | |||||||||||||||||||||
| Other comprehensive income, net of tax recovery of $5 million | - | - | - | 147 | - | 1 | 148 | |||||||||||||||||||||
| Dividends declared on preferred stock (Series A: $0.15970/share, Series B: $0.17870/share, Series C: $0.25625/share, Series E: $0.28125/share and Series F: $0.265625/share) | - | - | - | - | (7) | - | (7) | |||||||||||||||||||||
| Dividends declared on common stock ($0.565/share) | - | - | - | - | (129) | - | (129) | |||||||||||||||||||||
| Common stock issued under purchase plan | 50 | - | - | - | - | - | 50 | |||||||||||||||||||||
| Acquisition ofnon-controlling interest of ICD Utilities Limited (“ICDU”) | 22 | - | 8 | - | - | (53) | (23) | |||||||||||||||||||||
| Other | 1 | - | - | - | 6 | (1) | 6 | |||||||||||||||||||||
| Balance, March 31, 2018 | $ | 5,674 | $ | 709 | $ | 84 | $ | (41) | $ | 1,039 | $ | 39 | $ | 7,504 | ||||||||||||||
| For the three months ended March 31, 2017 | ||||||||||||||||||||||||||||
| Balance, December 31, 2016 | $ | 4,738 | $ | 709 | $ | 75 | $ | 106 | $ | 1,076 | $ | 112 | $ | 6,816 | ||||||||||||||
| Net income of Emera Incorporated | - | - | - | - | 319 | 3 | 322 | |||||||||||||||||||||
| Other comprehensive income (loss), net of tax expense of $1 million | - | - | - | (23) | - | (1) | (24) | |||||||||||||||||||||
| Issuance of common stock, net ofafter-tax issuance costs | 3 | - | - | - | - | - | 3 | |||||||||||||||||||||
| Dividends declared on preferred stock (Series A: $0.15970/share, Series B: $0.14730/share, Series C: $0.25625/share, Series E: $0.28125/share and Series F: $0.265625/share) | - | - | - | - | (7) | - | (7) | |||||||||||||||||||||
| Dividends declared on common stock ($0.5225/share) | - | - | - | - | (110) | - | (110) | |||||||||||||||||||||
| Common stock issued under purchase plan | 43 | - | - | - | - | - | 43 | |||||||||||||||||||||
| Other | 1 | - | - | - | - | (2) | (1) | |||||||||||||||||||||
| Balance, March 31, 2017 | $ | 4,785 | $ | 709 | $ | 75 | $ | 83 | $ | 1,278 | $ | 112 | $ | 7,042 | ||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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Emera Incorporated
Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)
As at March 31, 2018 and 2017
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.
At March 31, 2018 Emera’s primary rate-regulated subsidiaries and investments included the following:
| • | Emera Florida and New Mexico represents TECO Energy, Inc. (“TECO Energy”), a holding company with regulated electric and gas utilities in Florida and New Mexico. TECO Energy’s holdings include: |
| • | Tampa Electric Company (“TEC”), which holds the Tampa Electric Division (“Tampa Electric”), a vertically integrated regulated electric utility, in West Central Florida and Peoples Gas System Division, (“PGS”) a regulated gas distribution utility operating across Florida; |
| • | New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility, serving New Mexico; and |
| • | TECO Finance, Inc. (“TECO Finance”), a financing subsidiary of TECO Energy. |
| • | Nova Scotia Power Inc. (“NSPI”), a fully integrated regulated electric utility and the primary electricity supplier in Nova Scotia; |
| • | Emera Maine, a regulated electric transmission and distribution utility, in the state of Maine; |
| • | Emera Caribbean represents Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities that includes: |
| • | The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated utility and sole provider of electricity on the island of Barbados; |
| • | Grand Bahama Power Company Limited (“GBPC”), a vertically integrated utility operating on Grand Bahama Island; |
| • | a 51.9 per cent interest in Dominica Electricity Services Ltd. (“Domlec”), an integrated utility on the island of Dominica; and |
| • | a 19.1 per cent indirect interest in St. Lucia Electricity Services Limited (“Lucelec”). |
| • | Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a145-kilometre pipeline deliveringre-gasified liquefied natural gas from Saint John, New Brunswick to the United States border under a25-year firm service agreement with Repsol Energy Canada, which expires in 2034; |
| • | Emera Newfoundland & Labrador Holdings Inc. (“ENL”), focused on two transmission investments related to the development of an 824 megawatt (“MW”) hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador, forecasted by Nalcor Energy to be generating first power in 2019 and full power in 2020. ENL’s two investments are: |
| • | a 100 per cent investment in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $1.56 billion transmission project, including two170-kilometresub-sea cables, connecting the island of Newfoundland and Nova Scotia. This project went in service on January 15, 2018; and |
| • | a 49.4 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. Nalcor Energy is forecasting that construction of the LIL will be completedmid-2018. |
| • | a 12.9 per cent interest in Maritimes & Northeast Pipeline (“M&NP”), a1,400-kilometre pipeline, which transports natural gas from offshore Nova Scotia to markets in Atlantic Canada and the northeastern United States. |
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At March 31, 2018 Emera’s investments in other energy-relatednon-regulated companies included 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; |
| • | Bridgeport Energy, Tiverton Power and Rumford Power (“New England Gas Generating Facilities” or “NEGG”), power plants in the northeastern United States; |
| • | Bayside Power Limited Partnership (“Bayside Power”), a power plant in Saint John, New Brunswick; |
| • | Brooklyn Power Corporation (“Brooklyn Energy”), a power plant in Brooklyn, Nova Scotia; and |
| • | a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a hydroelectric facility in northwestern Massachusetts. |
| • | Emera US Finance LP, a wholly owned financing subsidiary of Emera; |
| • | Emera Utility Services Inc., a utility services contractor primarily operating in Atlantic Canada; and |
| • | other investments. |
Basis of Presentation
These unaudited condensed consolidated interim financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). The significant accounting policies applied to these unaudited condensed consolidated interim financial statements are consistent with those disclosed in the audited consolidated financial statements as at and for the year ended December 31, 2017, except as described in note 2.
In the opinion of management, these unaudited condensed consolidated interim financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2018.
All dollar amounts are presented in Canadian dollars, unless otherwise indicated.
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.
Seasonal Nature of Operations
Interim results are not necessarily indicative of results for the full year, primarily due to seasonal factors. Electricity and gas sales, and related transmission and distribution, vary over the year. The first quarter provides strong earnings contributions due to a significant portion of the Company’s operations being in northeastern North America, where winter is the peak electricity usage season. The third quarter provides strong earnings contributions due to summer being the heaviest electric consumption season in Florida. Certain quarters may also be impacted by weather and the number and severity of storms.
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Revenue Recognition
Regulated electric revenue
Electric revenues 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 occur on a periodic, systematic basis. 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 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 occur on a periodic, systematic basis. 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.
Direct Finance Lease
The Company records the net investment in a lease under the direct finance method for Emera Brunswick Pipeline, which consists of the sum of the minimum lease payments and residual value net of estimated executory costs and unearned income. The difference between the gross investment and the cost of the leased item for a direct financing lease is recorded as unearned income at the inception of the lease. The unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Operating revenues – regulated gas” on the Consolidated Statements of Income.
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.
Othernon-regulated revenues are recorded when obligations under terms of a contract are satisfied.
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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.
Franchise Fees and Gross Receipts
Tampa Electric and PGS recover from customers certain costs incurred, on adollar-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 Statement of Income.
2. CHANGE IN ACCOUNTING POLICY
The new USGAAP accounting policies that are applicable to, and adopted by the Company in 2018, are described as follows:
Revenue from Contracts with Customers
On January 1, 2018, the Company adopted Accounting Standard Updates (“ASU”)2014-09, Revenue from Contracts with Customers and all the related amendments, which created a new, principle-based revenue recognition framework. The standard has been codified as Accounting Standards Codification (“ASC”) Topic 606. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled to. The guidance requires additional disclosures regarding the nature, amount, timing and uncertainty of revenue and related cash flows arising from contracts with customers. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017.
The Company adopted ASC 606 using the modified retrospective method. Results for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with historic accounting practices. The adoption of ASC 606 resulted in no adjustments to the Company’s opening retained earnings as of the adoption date or the Company’s Condensed Consolidated Income Statement for the three months ended March 31, 2018. The impact of the adoption of the new standard is expected to be immaterial to the Company’s net income on an ongoing basis.
Recognition and Measurement of Financial Assets and Financial Liabilities
On January 1, 2018, the Company adopted ASU2016-01,Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities and all the related amendments. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017.
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The standard requires investments in equity securities, except those accounted for under the equity method of accounting or those that result in consolidation, to be measured at fair value. The Company has elected to measure equity securities that do not have a readily determinable fair value at cost minus impairment (if any), plus or minus observable price changes resulting from transactions for the identical or a similar investment of the same issuer. The standard eliminates theavailable-for-sale classification for equity investments that recognized changes in the fair value as a component of other comprehensive income, resulting in all changes in fair value being recognized in net income. The increase in volatility of Other income (expense), net as a result of the remeasurement of equity investments is expected to be immaterial to the Company’s net income on an ongoing basis. A cumulative-effect adjustment of $4 million was made to retained earnings in the Condensed Consolidated Balance Sheet as of January 1, 2018.
Clarifying the Definition of a Business
In January 2017, the FASB issued ASU2017-01,Clarifying the Definition of a Business. The standard provides guidance to assist entities with evaluating when a set of transferred assets and activities is a business. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and is required to be applied prospectively. The Company adopted ASU2017-01 effective January 1, 2018. There was no impact on the consolidated financial statements as a result of the adoption of this standard
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost
In March 2017, the FASB issued ASU2017-07,Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The guidance requires the service cost component of defined benefit pension or other postretirement benefit plans to be reported in the same line items as other compensation costs. The other components of net benefit cost are required to be presented in the Consolidated Statements of Income outside of income from operations. Only the service cost component is eligible for capitalization as property, plant and equipment under this guidance. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The guidance is required to be applied retrospectively for presentation in the Consolidated Statements of Income and prospectively for the guidance limiting capitalization.
The Company adopted ASU2017-07 effective January 1, 2018 and March 31, 2017 balances have been retrospectively restated in the Consolidated Statements of Income. The amounts were determined by means of a practical expedient which allows the Company to use the amounts disclosed in its pension and other postretirement benefit plan note for the prior comparative periods as the estimation basis for applying the retrospective presentation requirements. This change resulted in $7 million of costs, previously presented within “Operating, maintenance and general”, being reclassified to “Other income (expense), net” in the Consolidated Statements of Income for the period ended March 31, 2017.
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3. FUTURE ACCOUNTING PRONOUNCEMENTS
The Company considers the applicability and impact of all ASUs issued by Financial Accounting Standards Board (the “FASB”). The ASUs that have been issued, but that are not yet effective, are consistent with those disclosed in the 2017 audited consolidated financial statements, with updates noted below.
Leases
In February 2016, the FASB issued ASU2016-02,Leases. The standard, codified as ASC Topic 842, increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months. Under the existing guidance, operating leases are not recorded as assets and liabilities on the balance sheet. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged. The guidance will require additional disclosures regarding key information about leasing arrangements. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018. Early adoption is permitted and is required to be applied using a modified retrospective approach. The Company will not early adopt the standard.
In January 2018, the FASB issued an amendment to ASC Topic 842 which permits companies to elect to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under existing lease guidance. The Company expects to elect this practical expedient. In November 2017, the FASB voted to amend ASC Topic 842 to allow companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. The amendment is expected to be finalized in Q2 2018. The Company expects to elect this practical expedient.
The Company expects that the standard will affect its financial position by increasing the assets and liabilities recorded relating to its operating leases, however, the ultimate impact of the new standard on the Company’s financial statements and disclosures has not yet been determined. In 2017, the Company developed and began execution of a project plan which included holding training sessions with key stakeholders throughout the organization and gathering detailed information on existing lease arrangements. Remaining activities to be performed include evaluating the available implementation alternatives, calculating the lease asset and liability balances associated with individual contractual arrangements and assessing the disclosure requirements. The Company continues to monitor FASB amendments to ASC Topic 842.
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income
In February 2018, the FASB issued ASUNo. 2018-02,Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The standard allows reclassification from accumulated other comprehensive income to retained earnings for certain tax effects resulting from the US Tax Cuts and Jobs Act that would otherwise be stranded in accumulated other comprehensive income. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018, with early adoption permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.
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4. SEGMENT INFORMATION
Emera manages its reportable segments separately due in part to their different geographical, operating and regulatory environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets as reported to the Company’s chief operating decision maker. Emera’s six reportable segments are Emera Florida and New Mexico, NSPI, Emera Maine, Emera Caribbean, Emera Energy and Corporate and Other (includes Emera Utility Services, ENL, Emera Brunswick Pipeline, Corporate, other strategic investments and holding companies).
| millions of Canadian dollars | Emera Florida and New Mexico | NSPI | Emera Maine | Emera Caribbean | Emera Energy | Corporate Other | Inter- Segment Eliminations | Total | ||||||||||||||||||||||||
| For the three months ended March 31, 2018 | ||||||||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 907 | $ | 423 | $ | 72 | $ | 101 | $ | 288 | $ | 16 | $ | - | $ | 1,807 | ||||||||||||||||
| Inter-segment revenues (1) | - | 1 | - | - | 4 | 7 | (12) | - | ||||||||||||||||||||||||
Total operating revenues | 907 | 424 | 72 | 101 | 292 | 23 | (12) | 1,807 | ||||||||||||||||||||||||
| Net income (loss) attributable to common shareholders | 90 | 65 | 10 | 4 | 125 | (23) | - | 271 | ||||||||||||||||||||||||
| For the three months ended March 31, 2017 | ||||||||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 889 | $ | 395 | $ | 79 | $ | 104 | $ | 366 | $ | 25 | $ | - | $ | 1,858 | ||||||||||||||||
| Inter-segment revenues (1) | - | 1 | - | - | 4 | 4 | (10) | (1) | ||||||||||||||||||||||||
Total operating revenues | 889 | 396 | 79 | 104 | 370 | 29 | (10) | 1,857 | ||||||||||||||||||||||||
| Net income (loss) attributable to common shareholders | 79 | 70 | 13 | 7 | 170 | (27) | - | 312 | ||||||||||||||||||||||||
(1) All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain transactions betweennon-regulated and regulated entities that have not been eliminated because management believes the elimination of these transactions would understate property, plant and equipment, operating, maintenance and general expenses, or regulated fuel for generation and purchased power. Inter-company transactions 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.
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5. REVENUE
The following disaggregates the Company’s revenue by major source:
| millions of Canadian dollars | Emera Florida and New Mexico | NSPI | Emera Maine | Emera Caribbean | Emera Energy | Corporate Other | Inter- Segment Eliminations | Total | ||||||||||||||||||||||||
| For the three months ended March 31, 2018 | ||||||||||||||||||||||||||||||||
| Regulated | ||||||||||||||||||||||||||||||||
| Electric Revenue | ||||||||||||||||||||||||||||||||
| Residential | $ | 290 | $ | 236 | $ | 27 | $ | 31 | $ | - | $ | - | $ | - | $ | 584 | ||||||||||||||||
| Commercial | 167 | 110 | 19 | 59 | - | - | - | 355 | ||||||||||||||||||||||||
| Industrial | 48 | 57 | 4 | 8 | - | - | - | 117 | ||||||||||||||||||||||||
| Other electric and regulatory deferrals | 73 | 14 | 3 | 1 | - | - | - | 91 | ||||||||||||||||||||||||
| Other (1) | 3 | 7 | 19 | 2 | - | - | (1) | 30 | ||||||||||||||||||||||||
Regulated electric revenue | 581 | 424 | 72 | 101 | - | - | (1) | 1,177 | ||||||||||||||||||||||||
| Gas Revenue | ||||||||||||||||||||||||||||||||
| Residential | 179 | - | - | - | - | - | - | 179 | ||||||||||||||||||||||||
| Commercial | 92 | - | - | - | - | - | - | 92 | ||||||||||||||||||||||||
| Industrial | 11 | - | - | - | - | - | - | 11 | ||||||||||||||||||||||||
| Finance income (2)(3) | - | - | - | - | - | 13 | - | 13 | ||||||||||||||||||||||||
| Other | 38 | - | - | - | - | - | - | 38 | ||||||||||||||||||||||||
Regulated gas revenue | 320 | - | - | - | - | 13 | - | 333 | ||||||||||||||||||||||||
| Non-Regulated | ||||||||||||||||||||||||||||||||
| Marketing and trading margin (4) | - | - | - | - | 69 | - | - | 69 | ||||||||||||||||||||||||
| Energy sales (4) | - | - | - | - | 95 | - | (4) | 91 | ||||||||||||||||||||||||
| Capacity | - | - | - | - | 27 | - | - | 27 | ||||||||||||||||||||||||
| Other | 6 | - | - | - | - | 10 | (7) | 9 | ||||||||||||||||||||||||
| Mark-to-market (3) | - | - | - | - | 101 | - | - | 101 | ||||||||||||||||||||||||
Non-regulated revenue | 6 | - | - | - | 292 | 10 | (11) | 297 | ||||||||||||||||||||||||
| Total operating revenues | $ | 907 | $ | 424 | $ | 72 | $ | 101 | $ | 292 | $ | 23 | $ | (12) | $ | 1,807 | ||||||||||||||||
(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 March 31, 2018, the aggregate amount of the transaction price allocated to remaining performance obligations was $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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6. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME
Investments subject to significant influence consisted of the following:
| Equity Income | Percentage | |||||||||||||||||||
| Carrying Value as at | For the three months ended | of | ||||||||||||||||||
| March 31 | December 31 | March 31 | Ownership | |||||||||||||||||
| millions of Canadian dollars | 2018 | 2017 | 2018 | 2017 | 2018 | |||||||||||||||
| NSPML (1) | $ | 558 | $ | 510 | $ | 15 | $ | 7 | 100.0 | |||||||||||
| LIL (1) | 502 | 492 | 10 | 9 | 49.4 | |||||||||||||||
| M&NP (2) | 157 | 156 | 6 | 6 | 12.9 | |||||||||||||||
| Lucelec (2) | 39 | 39 | - | 1 | 19.1 | |||||||||||||||
| Bear Swamp (3) | - | - | 4 | 3 | 50.0 | |||||||||||||||
| Other Investments | 27 | 18 | 2 | - | ||||||||||||||||
| $ | 1,283 | $ | 1,215 | $ | 37 | $ | 26 | |||||||||||||
(1) Emera indirectly owns 100 per cent of the LIL 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 completion of the LIL and final costing of all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Assets and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 per cent of the cost of all of these transmission developments.
(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 as a result of a $179 million distribution received in Q4 2015. Bear Swamp’s credit investment balance of $189 million (2017 - $188 million) is recorded in “Other long-term liabilities” on the Condensed Consolidated Balance Sheets.
Emera accounts for its variable interest investment in NSPML as an equity investment (note 20). NSPML’s consolidated summarized balance sheet is as follows:
| As at | March 31 | December 31 | ||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||
| Balance Sheet | ||||||||
| Current assets | $ | 154 | $ | 225 | ||||
| Property, plant and equipment | 1,707 | 1,720 | ||||||
| Non-current assets | 90 | 74 | ||||||
| Total assets | $ | 1,951 | $ | 2,019 | ||||
| Current liabilities | $ | 58 | $ | 180 | ||||
| Long-term debt | 1,287 | 1,287 | ||||||
| Non-current liabilities | 48 | 42 | ||||||
| Equity | 558 | 510 | ||||||
| Total liabilities and equity | $ | 1,951 | $ | 2,019 | ||||
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7. INCOME TAXES
The income tax provision differs from that computed using the statutory income tax rate for the following reasons:
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||
| Income before provision for income taxes | $ | 343 | $ | 434 | ||||
| Statutory income tax rate | 31% | 31% | ||||||
| Income taxes, at statutory income tax rate | 106 | 135 | ||||||
| Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities | (21) | (24) | ||||||
| Foreign tax rate variance | (10) | 8 | ||||||
| Amortization of deferred income tax regulatory liabilities | (8) | - | ||||||
| Other | (2) | (7) | ||||||
| Income tax expense (recovery) | $ | 65 | $ | 112 | ||||
| Effective income tax rate | 19% | 26% | ||||||
The statutory income tax rate of 31 per cent represents the combined Canadian federal and Nova Scotia and New Brunswick provincial corporate income tax rates, which are the relevant tax jurisdictions for Emera. The foreign tax rate variance reflects the reduction in the US federal corporate income tax rate.
On December 22, 2017, the US Tax Cuts and Jobs Act of 2017 (“the Act”) was signed into law enacting a broad range of legislative changes including a reduction of the US federal corporate income tax rate from 35 per cent to 21 per cent effective January 1, 2018, limitations on the deductibility of interest and 100 per cent expensing of qualified property. The Act provides an exemption to regulated electric and gas utilities from the limitations on the deductibility of interest and the 100 per cent expensing of qualified property.
The Company was required to revalue its US deferred income tax assets and liabilities based on the new 21 per cent tax rate at the date of enactment. The Company recognized an estimated $317 million income tax expense on December 31, 2017 as a result of the revaluation of its USnon-regulated net deferred income tax assets. The Company also reduced its US regulated net deferred income tax liabilities by an estimated $1.1 billion and recorded an equivalent regulatory liability since the benefit of lower US taxes is expected to be returned to customers over time as required by the Act or by order of the applicable regulator.
The Company provisionally revalued all of its US deferred tax assets and liabilities as of December 31, 2017, based on the rates they are expected to reverse at in the future, which is generally 21 per cent for US federal tax purposes. The December 31, 2017 balances of deferred tax assets and deferred tax liabilities that have been revalued are $1.3 billion and $1.8 billion, respectively. The Company continues to analyze certain aspects of the Act, including the valuation of refundable alternative minimum tax credits, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. Further adjustments, if any, will be recorded by the Company during the measurement period in 2018 as permitted by SEC Staff Accounting Bulletin 118, Income tax Accounting Implications of the Tax Cuts and Jobs Act. No measurement period adjustments have been recognized during the first quarter of 2018.
The following reflects the composition of taxes on income from continuing operations presented in the Condensed Consolidated Statements of Income:
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||
| Income tax expense (recovery) – current | $ | 11 | $ | 11 | ||||
| Income tax expense (recovery) – deferred | 54 | 101 | ||||||
| Income tax expense (recovery) | $ | 65 | $ | 112 | ||||
15
NSPI and the Canada Revenue Agency (“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.
Should NSPI be successful in defending its position, all payments including applicable interest will be refunded. If NSPI is unsuccessful in defending any portion of its position, the resulting taxes and applicable interest will be deducted from amounts previously paid, with the excess, if any, owing to CRA. The related tax deductions will be available in subsequent years. Should NSPI receive similar notices of reassessment for 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 and NSPI is disputing the reassessments through the CRA Appeal process. NSPI continues to assess its options to resolving the dispute however the outcome of the Appeal process is not determinable at this time.
8. COMMON STOCK
Authorized: Unlimited number ofnon-par value common shares.
| Issued and outstanding: | millions of shares | millions of Canadian dollars | ||||||
| Balance, December 31, 2017 | 228.77 | $ | 5,601 | |||||
| Conversion of Convertible Debentures (1) | 0.01 | - | ||||||
| Issuance of common stock (2) | 0.45 | 22 | ||||||
| Issued for cash under Purchase Plans at market rate | 1.27 | 53 | ||||||
| Discount on shares purchased under Dividend Reinvestment Plan | - | (2) | ||||||
| Options exercised under senior management share option plan | 0.02 | - | ||||||
| Balance, March 31, 2018 | 230.52 | $ | 5,674 | |||||
(1) As at March 31, 2018, a total of 52.15 million common shares of the Company were issued, representing conversion into common shares of more than 99.9 per cent of the Convertible Debentures.
(2) In Q1 2018, Emera issued 0.45 million common shares to facilitate the creation and issuance of 1.8 million depository receipts in connection with the ICDU share acquisition. The depository receipts are listed on the Bahamas International Securities Exchange.
9. EARNINGS PER SHARE
The following table reconciles the computation of basic and diluted earnings per share:
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars (except per share amounts) | 2018 | 2017 | ||||||
| Numerator | ||||||||
| Net income attributable to common shareholders | $ | 271.4 | $ | 312.4 | ||||
| Diluted numerator | 271.4 | 312.4 | ||||||
| Denominator | ||||||||
| Weighted average shares of common stock outstanding | 229.8 | 210.6 | ||||||
| Weighted average deferred share units outstanding | 1.2 | 1.0 | ||||||
| Weighted average shares of common stock outstanding – basic | 231.0 | 211.6 | ||||||
| Stock-based compensation | 0.4 | 0.5 | ||||||
| Convertible Debentures | 0.1 | 0.1 | ||||||
| Weighted average shares of common stock outstanding – diluted | 231.5 | 212.2 | ||||||
| Earnings per common share | ||||||||
| Basic | $ | 1.17 | $ | 1.48 | ||||
| Diluted | $ | 1.17 | $ | 1.47 | ||||
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10. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The components of accumulated other comprehensive income (loss), net of tax, 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 in available-for-sale investments | Net change in unrecognized pension and post-retirement benefit costs | Total AOCI | ||||||||||||||||||
| For the three months ended March 31, 2018 | ||||||||||||||||||||||||
| Balance, January 1, 2018 | $ | 29 | $ | 48 | $ | (3) | $ | 3 | $ | (265) | $ | (188) | ||||||||||||
| Other comprehensive income (loss) before reclassifications | 184 | (36) | 1 | (1) | - | 148 | ||||||||||||||||||
| Amounts reclassified from accumulated other comprehensive income loss (gain) | - | - | (5) | (4) | 8 | (1) | ||||||||||||||||||
| Net current period other comprehensive income (loss) | 184 | (36) | (4) | (5) | 8 | 147 | ||||||||||||||||||
| Balance, March 31, 2018 | $ | 213 | $ | 12 | $ | (7) | $ | (2) | $ | (257) | $ | (41) | ||||||||||||
| 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 in available-for-sale investments | Net change in unrecognized pension and post-retirement benefit costs | Total AOCI | ||||||||||||||||||
| For the three months ended March 31, 2017 | ||||||||||||||||||||||||
| Balance, January 1, 2017 | $ | 486 | $ | (49) | $ | (21) | $ | (1) | $ | (309) | $ | 106 | ||||||||||||
| Other comprehensive income (loss) before reclassifications | (48) | 13 | 2 | 3 | - | (30) | ||||||||||||||||||
| Amounts reclassified from accumulated other comprehensive income loss (gain) | - | - | - | (1) | 8 | 7 | ||||||||||||||||||
| Net current period other comprehensive income (loss) | (48) | 13 | 2 | 2 | 8 | (23) | ||||||||||||||||||
| Balance, March 31, 2017 | $ | 438 | $ | (36) | $ | (19) | $ | 1 | $ | (301) | $ | 83 | ||||||||||||
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The reclassifications out of accumulated other comprehensive income (loss) are as follows:
| For the | Three months ended March 31 | |||||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||||
Affected line item in the Consolidated Financial Statements | | Amounts reclassified from AOCI |
| |||||||
| Losses (gain) on derivatives recognized as cash flow hedges | ||||||||||
Power and gas swaps | Non-regulated fuel for generation and purchased power | $ | (4) | $ | (4) | |||||
Foreign exchange forwards | Operating revenue - regulated | (2) | 3 | |||||||
| Total before tax | (6) | (1) | ||||||||
| Income tax expense (recovery) | 1 | 1 | ||||||||
| Total net of tax | $ | (5) | $ | - | ||||||
| Net change inavailable-for-sale investments | ||||||||||
| Other income (expenses), net | $ | - | $ | (1) | ||||||
| Retained earnings (1) | (4) | - | ||||||||
| Total net of tax | $ | (4) | $ | (1) | ||||||
| Net change in unrecognized pension and post-retirement benefit costs | ||||||||||
Actuarial losses (gains) | OM&G | $ | 10 | $ | 10 | |||||
Past service costs (gains) | OM&G | (2) | (2) | |||||||
| Total net of tax | $ | 8 | $ | 8 | ||||||
| Total reclassifications out of AOCI, net of tax, for the period | $ | (1) | $ | 7 | ||||||
(1) Related to the adoption of ASU2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. Refer to note 2 Change in Accounting Policy.
11. DERIVATIVE INSTRUMENTS
The Company enters into futures, forwards, swaps and option contracts as part of its risk management strategy to limit exposure to:
| • | commodity price fluctuations related to the purchase and sale of commodities in the course of normal operations; |
| • | foreign exchange fluctuations on foreign currency denominated purchases and sales; and |
| • | interest rate fluctuations on debt securities. |
The Company also enters into physical contracts for energy commodities. Collectively, these contracts are considered “derivatives”. The Company accounts for derivatives under one of the following four approaches:
| 1. | Physical contracts that meet the normal purchases normal sales (“NPNS”) exemption are not recognized on the balance sheet; they are recognized in income when they settle. A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. The Company continually assesses contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exception if the criteria are no longer met. |
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| 2. | Derivatives that qualify for hedge accounting are recorded at fair value on the balance sheet. Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge the identified cash flow risk both at the inception and over the term of the derivative. Specifically for cash flow hedges, the effective portion of the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Any ineffective portion of the change in fair value from cash flow hedges is recognized in net income in the reporting period. |
| Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting. |
| 3. | Derivatives entered into by Tampa Electric, PGS, NMGC, NSPI, Emera Maine and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at fair value on the balance sheet as derivative assets or liabilities. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes that any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. |
| 4. | Derivatives that do not meet any of the above criteria are designated asheld-for-trading (“HFT”) derivatives and are recorded on the balance sheet at fair value, with changes normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply. |
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Derivative assets and liabilities relating to the foregoing categories consisted of the following:
| Derivative Assets | Derivative Liabilities | |||||||||||||||
| As at | March 31 | December 31 | March 31 | December 31 | ||||||||||||
| millions of Canadian dollars | 2018 | 2017 | 2018 | 2017 | ||||||||||||
| Cash flow hedges | ||||||||||||||||
| Power swaps | $ | 1 | $ | 5 | $ | 2 | $ | 2 | ||||||||
| Foreign exchange forwards | - | 2 | 3 | 5 | ||||||||||||
| 1 | 7 | 5 | 7 | |||||||||||||
| Regulatory deferral | ||||||||||||||||
| Commodity swaps and forwards | ||||||||||||||||
Coal purchases | 91 | 137 | 4 | 10 | ||||||||||||
Power purchases | 2 | 5 | 4 | 3 | ||||||||||||
Natural gas purchases and sales | 5 | 6 | 8 | 7 | ||||||||||||
Heavy fuel oil purchases | 14 | 15 | 4 | 4 | ||||||||||||
| Foreign exchange forwards | 32 | 32 | 3 | 4 | ||||||||||||
| Physical natural gas and biofuel energy purchases and sales | - | - | 2 | - | ||||||||||||
| 144 | 195 | 25 | 28 | |||||||||||||
| HFT derivatives | ||||||||||||||||
| Power swaps and physical contracts | 65 | 125 | 68 | 162 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts | 91 | 105 | 251 | 294 | ||||||||||||
| 156 | 230 | 319 | 456 | |||||||||||||
| Other derivatives | ||||||||||||||||
| Interest rate swap | 1 | 2 | - | - | ||||||||||||
| 1 | 2 | - | - | |||||||||||||
| Total gross current derivatives | 302 | 434 | 349 | 491 | ||||||||||||
| Impact of master netting agreements with intent to settle net or simultaneously | (105) | (181) | (105) | (181) | ||||||||||||
| 197 | 253 | 244 | 310 | |||||||||||||
| Current | 124 | 141 | 159 | 227 | ||||||||||||
| Long-term | 73 | 112 | 85 | 83 | ||||||||||||
| Total derivatives | $ | 197 | $ | 253 | $ | 244 | $ | 310 | ||||||||
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 Condensed Consolidated Balance Sheets, are summarized in the following table:
| Derivative Assets | Derivative Liabilities | |||||||||||||||
| As at | March 31 | December 31 | March 31 | December 31 | ||||||||||||
| millions of Canadian dollars | 2018 | 2017 | 2018 | 2017 | ||||||||||||
| Regulatory deferral | $ | 9 | $ | 14 | $ | 9 | $ | 14 | ||||||||
| HFT derivatives | 96 | 167 | 96 | 167 | ||||||||||||
| Total impact of master netting agreements with intent to settle net or simultaneously | $ | 105 | $ | 181 | $ | 105 | $ | 181 | ||||||||
Cash Flow Hedges
The Company enters into various derivatives designated as cash flow hedges. Emera enters into power swaps to limit Bear Swamp’s exposure to purchased power prices. The Company also enters into foreign exchange forwards to hedge the currency risk for revenue streams denominated in foreign currency for Brunswick Pipeline.
20
The amounts related to cash flow hedges recorded in income and AOCI consisted of the following:
| For the | Three months ended March 31 | |||||||||||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||||||||||
| Power Swaps | Foreign Exchange Forwards | Power Swaps | Foreign Exchange Forwards | |||||||||||||
| Realized gain (loss) innon-regulated fuel for generation and purchased power | 4 | - | 4 | - | ||||||||||||
| Realized gain (loss) in operating revenue – regulated | - | 2 | - | (3 | ) | |||||||||||
| Total gains (losses) in net income | $ | 4 | $ | 2 | $ | 4 | $ | (3 | ) | |||||||
| As at | March 31 | December 31 | ||||||||||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||||||||||
| Power Swaps | Foreign Exchange Forwards | Power Swaps | Foreign Exchange Forwards | |||||||||||||
| Total unrealized gain (loss) in AOCI – effective portion, net of tax | $ | (2) | $ | (3 | ) | $ | - | $ | (3 | ) | ||||||
The Company expects $2 million of unrealized loss currently in AOCI to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle.
As at March 31, 2018, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:
| millions | 2018 | 2019 | 2020 | 2021 | 2022 | |||||||||||||||
| Foreign exchange forwards (USD) sales | $ | 32 | $ | 30 | $ | 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 millions of Canadian dollars | Three months ended March 31, 2018 | |||||||||||
| Commodity swaps and forwards | Physical natural gas and biofuel energy purchases and sales | Foreign exchange forwards | ||||||||||
| Unrealized gain (loss) in regulatory assets | $ | (9) | $ | (2) | $ | 1 | ||||||
| Unrealized gain (loss) in regulatory liabilities | (20) | - | 6 | |||||||||
| Realized (gain) loss in regulatory liabilities | (2) | - | - | |||||||||
| Realized (gain) loss in inventory (1) | (13) | - | (5) | |||||||||
| Realized (gain) loss in regulated fuel for generation and purchased power (2) | (3) | - | (1) | |||||||||
| Total change in derivative instruments | $ | (47) | $ | (2) | $ | 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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For the millions of Canadian dollars | Three months ended March 31, 2017 | |||||||||||
| Commodity swaps and forwards | Physical natural gas and biofuel energy purchases and sales | Foreign exchange forwards | ||||||||||
| Unrealized gain (loss) in regulatory assets | $ | (20) | $ | (5) | $ | - | ||||||
| Unrealized gain (loss) in regulatory liabilities | - | 1 | (6) | |||||||||
| Realized (gain) loss in regulatory liabilities | (1) | - | - | |||||||||
| Realized (gain) loss in inventory (1) | (5) | - | (12) | |||||||||
| Realized (gain) loss in regulated fuel for generation and purchased power (2) | (2) | - | (5) | |||||||||
| Total change in derivative instruments | $ | (28) | $ | (4) | $ | (23) | ||||||
(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.
(2) Realized (gains) losses on derivative instruments settled and consumed in the period; hedging relationships that have been terminated or the hedged transaction is no longer probable.
Commodity Swaps and Forwards
As at March 31, 2018, 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:
| 2018 | 2019-2022 | |||||||
| millions | Purchases | Purchases | ||||||
| Coal (metric tonnes) | 1 | 1 | ||||||
| Natural Gas (Mmbtu) | 17 | 11 | ||||||
| Heavy fuel oil (bbls) | - | 1 | ||||||
Foreign Exchange Swaps and Forwards
As at March 31, 2018, the Company had the following notional volumes of foreign exchange swaps and forward contracts related to commodity contracts that are expected to settle as outlined below:
| 2018 | 2019-2020 | |||||||
| Foreign exchange contracts (millions of US dollars) | $ | 97 | $ | 156 | ||||
| Weighted average rate | 1.1017 | 1.2001 | ||||||
| % of USD requirements | 68% | 40% | ||||||
The Company reassesses foreign exchange forecasted periodically and will enter into additional hedges or unwind existing hedges, as required.
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Held-for-Trading Derivatives
In the ordinary course of its business, Emera enters into physical contracts for the purchase and sale of natural gas, as well as power and natural gas swaps, forwards and futures, to economically hedge those physical contracts. These derivatives are all considered HFT.
The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives:
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||
| Power swaps and physical contracts innon-regulated operating revenues | $ | (9) | $ | 1 | ||||
| Natural gas swaps, forwards, futures and physical contracts innon-regulated operating revenues | 137 | 323 | ||||||
| Natural gas swaps, forwards, futures and physical contracts innon-regulated fuel for generation and purchased power | - | 3 | ||||||
| Power swaps, forwards, futures and physical contracts innon-regulated fuel for generation and purchased power | (2) | (1) | ||||||
| $ | 126 | $ | 326 | |||||
As at March 31, 2018, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:
| millions | 2018 | 2019 | 2020 | 2021 | 2022 | |||||||||||||||
| Natural gas purchases (Mmbtu) | 328 | 162 | 74 | 50 | 41 | |||||||||||||||
| Natural gas sales (Mmbtu) | 232 | 77 | 22 | 8 | 2 | |||||||||||||||
| Power purchases (MWh) | 4 | 3 | - | - | - | |||||||||||||||
| Power sales (MWh) | 5 | 3 | - | - | - | |||||||||||||||
| Foreign exchange options (USD) | $ | 3 | $ | - | $ | - | $ | - | $ | - | ||||||||||
Other Derivatives
The Company has realized and unrealized gains (losses) with respect to cash flow hedges for which documentation requirements have not been met of nil for the three months ended March 31, 2018 (2017 – nil)
As at March 31, 2018 the Company had interest rate swaps in place for the $250 millionnon-revolving term credit facility in Brunswick Pipeline for interest payments until the debt matures in 2019.
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’snon-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.
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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 Company also obtains cash deposits from electric customers. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company.
The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements (“ISDA”), North American Energy Standards Board agreements (“NAESB”) and, or Edison Electric Institute agreements. The Company believes that entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral,non-performance and default.
As at March 31, 2018, the Company had $136 million (December 31, 2017 - $90 million) in financial assets considered to be past due, which have been outstanding for an average 68 days. The fair value of these financial assets is $123 million (December 31, 2017 - $78 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.
Cash Collateral
The Company’s cash collateral positions consisted of the following:
| As at | March 31 | December 31 | ||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||
| Cash collateral provided to others | $ | 75 | $ | 119 | ||||
| Cash collateral received from others | 64 | 99 | ||||||
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 March 31, 2018, the total fair value of these derivatives, in a liability position, was $244 million (December 31, 2017 – $310 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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12. 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 11), 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 fromover-the-counter clearing houses.
Level 3 - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally-developed inputs. The primary reasons for a Level 3 classification are as follows:
| • | While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials. |
| • | The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term. |
| • | The valuations of certain transactions were based on internal models, although quoted prices were utilized in the valuations. |
Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
The following tables set out the classification of the methodology used by the Company to fair value its derivatives:
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| As at | March 31, 2018 | |||||||||||||||
| millions of Canadian dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Assets | ||||||||||||||||
| Cash flow hedges | ||||||||||||||||
| Power swaps | $ | 1 | $ | - | $ | - | $ | 1 | ||||||||
| 1 | - | - | 1 | |||||||||||||
| Regulatory deferral | ||||||||||||||||
| Commodity swaps and forwards | ||||||||||||||||
Coal purchases | - | 87 | - | 87 | ||||||||||||
Power purchases | 2 | - | - | 2 | ||||||||||||
Natural gas purchases and sales | - | 3 | - | 3 | ||||||||||||
Heavy fuel oil purchases | 5 | 6 | - | 11 | ||||||||||||
| Foreign exchange forwards | - | 32 | - | 32 | ||||||||||||
| 7 | 128 | - | 135 | |||||||||||||
| HFT derivatives | ||||||||||||||||
| Power swaps and physical contracts | 8 | 1 | 3 | 12 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts and related transportation | (1) | 28 | 21 | 48 | ||||||||||||
| 7 | 29 | 24 | 60 | |||||||||||||
| Other derivatives | ||||||||||||||||
| Interest rate swap | - | 1 | - | 1 | ||||||||||||
| - | 1 | - | 1 | |||||||||||||
| Total assets | 15 | 158 | 24 | 197 | ||||||||||||
| Liabilities | ||||||||||||||||
| Cash flow hedges | ||||||||||||||||
| Power swaps | 2 | - | - | 2 | ||||||||||||
| Foreign exchange forwards | - | 3 | - | 3 | ||||||||||||
| 2 | 3 | - | 5 | |||||||||||||
| Regulatory deferral | ||||||||||||||||
| Commodity swaps and forwards | ||||||||||||||||
Power purchases | 4 | - | - | 4 | ||||||||||||
Heavy fuel oil purchases | 1 | - | 1 | |||||||||||||
Natural gas purchases and sales | 4 | 2 | - | 6 | ||||||||||||
| Foreign exchange forwards | - | 3 | - | 3 | ||||||||||||
| Physical natural gas and biofuel energy purchases and sales | - | 2 | - | 2 | ||||||||||||
| 8 | 8 | - | 16 | |||||||||||||
| HFT derivatives | ||||||||||||||||
| Power swaps and physical contracts | 12 | 1 | 3 | 16 | ||||||||||||
| Natural gas swaps, futures, forwards and physical contracts | 1 | 26 | 180 | 207 | ||||||||||||
| 13 | 27 | 183 | 223 | |||||||||||||
| Total liabilities | 23 | 38 | 183 | 244 | ||||||||||||
| Net assets (liabilities) | $ | (8) | $ | 120 | $ | (159) | $ | (47) | ||||||||
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| As at | December 31, 2017 | |||||||||||||||
| millions of Canadian dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Assets | ||||||||||||||||
| Cash flow hedges | ||||||||||||||||
| Power swaps | $ | 5 | $ | - | $ | - | $ | 5 | ||||||||
| Foreign exchange forwards | - | 2 | - | 2 | ||||||||||||
| 5 | 2 | - | 7 | |||||||||||||
| Regulatory deferral | ||||||||||||||||
| Commodity swaps and forwards | ||||||||||||||||
Coal purchases | - | 127 | - | 127 | ||||||||||||
Power purchases | 5 | - | - | 5 | ||||||||||||
Natural gas purchases and sales | - | 5 | - | 5 | ||||||||||||
Heavy fuel oil purchases | 4 | 8 | - | 12 | ||||||||||||
| Foreign exchange forwards | - | 32 | - | 32 | ||||||||||||
| 9 | 172 | - | 181 | |||||||||||||
| HFT derivatives | ||||||||||||||||
| Power swaps and physical contracts | - | 3 | 9 | 12 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts and related transportation | - | 26 | 25 | 51 | ||||||||||||
| - | 29 | 34 | 63 | |||||||||||||
| Other derivatives | ||||||||||||||||
| Interest rate swap | - | 2 | - | 2 | ||||||||||||
| - | 2 | - | 2 | |||||||||||||
| Total assets | 14 | 205 | 34 | 253 | ||||||||||||
| Liabilities | ||||||||||||||||
| Cash flow hedges | ||||||||||||||||
| Power swaps | 2 | - | - | 2 | ||||||||||||
| Foreign exchange forwards | - | 5 | - | 5 | ||||||||||||
| 2 | 5 | - | 7 | |||||||||||||
| Regulatory deferral | ||||||||||||||||
| Power purchases | 3 | - | - | 3 | ||||||||||||
| Natural gas purchased and sales | 5 | 1 | - | 6 | ||||||||||||
| Foreign exchange forwards | - | 4 | - | 4 | ||||||||||||
| 8 | 5 | - | 13 | |||||||||||||
| HFT derivatives | ||||||||||||||||
| Power swaps and physical contracts | 49 | 5 | (4) | 50 | ||||||||||||
| Natural gas swaps, futures, forwards and physical contracts | 6 | 47 | 187 | 240 | ||||||||||||
| 55 | 52 | 183 | 290 | |||||||||||||
| Total liabilities | 65 | 62 | 183 | 310 | ||||||||||||
| Net assets (liabilities) | $ | (51) | $ | 143 | $ | (149) | $ | (57) | ||||||||
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The change in the fair value of the Level 3 financial assets for the three months ended March 31, 2018 was as follows:
| HFT Derivatives | ||||||||||||
| millions of Canadian dollars | Power | Natural gas | Total | |||||||||
| Balance, January 1, 2018 | $ | 9 | $ | 25 | $ | 34 | ||||||
| Total realized and unrealized gains (losses) included innon-regulated operating revenues | (6) | (4) | (10) | |||||||||
| Balance, March 31, 2018 | $ | 3 | $ | 21 | $ | 24 | ||||||
The change in the fair value of the Level 3 financial liabilities for the three months ended March 31, 2018 was as follows:
| HFT Derivatives | ||||||||||||
| millions of Canadian dollars | Power | Natural gas | Total | |||||||||
| Balance, January 1, 2018 | $ | (4 | ) | $ | 187 | $ | 183 | |||||
| Total realized and unrealized gains (losses) included innon-regulated operating revenues | 7 | (7 | ) | - | ||||||||
| Balance, March 31, 2018 | $ | 3 | $ | 180 | $ | 183 | ||||||
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 three months ended March 31, 2018, 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 | March 31, 2018 | |||||||||||||||||||
| millions of Canadian dollars | Fair Value | Valuation Technique | Unobservable Input | Range | Weighted average | |||||||||||||||
| Assets | ||||||||||||||||||||
| HFT derivatives – | $ | 3 | Modelled pricing | Third-party pricing | $28.05-$38.46 | $36.43 | ||||||||||||||
| Power swaps and | Probability of default | 0.13%-0.29% | 0.21% | |||||||||||||||||
| physical contracts | Discount rate | 0.59%-3.90% | 2.34% | |||||||||||||||||
| Correlation factor | 91.78%-91.78% | 91.78% | ||||||||||||||||||
| HFT derivatives – | 14 | Modelled pricing | Third-party pricing | $2.06-$4.38 | $3.15 | |||||||||||||||
| Natural gas swaps, futures, | Probability of default | 0.01%-5.86% | 0.61% | |||||||||||||||||
| forwards, physical contracts | Discount rate | 0.02%-32.28% | 7.78% | |||||||||||||||||
| 7 | Modelled pricing | Third-party pricing | $2.03-$10.60 | $3.73 | ||||||||||||||||
| Basis adjustment | $0.08-$0.80 | $0.49 | ||||||||||||||||||
| Probability of default | 0.01%-1.85% | 0.14% | ||||||||||||||||||
| Discount rate | 0.02%-9.7% | 1.35% | ||||||||||||||||||
| Total assets | $ | 24 | ||||||||||||||||||
| Liabilities | ||||||||||||||||||||
| HFT derivatives – | $ | 1 | Modelled pricing | Third-party pricing | $28.45-$86.30 | $38.70 | ||||||||||||||
| Power swaps and | Own credit risk | 0.04%-1.29% | 0.26% | |||||||||||||||||
| physical contracts | Discount rate | 0.17%-14.67% | 3.90% | |||||||||||||||||
| 2 | Modelled pricing | Third-party pricing | $24.09-$29.49 | $26.03 | ||||||||||||||||
| Probability of default | 0.13%-0.29% | 0.21% | ||||||||||||||||||
| Discount rate | 0.17%-4.51% | 2.35% | ||||||||||||||||||
| Correlation factor | 91.78%-91.78% | 91.78% | ||||||||||||||||||
| HFT derivatives – | 137 | Modelled pricing | Third-party pricing | $1.86-$9.90 | $3.34 | |||||||||||||||
| Natural gas swaps, futures, | Own credit risk | 0.02%-1.08% | 0.16% | |||||||||||||||||
| forwards and physical contracts | Discount rate | 0.01%-14.26% | 3.81% | |||||||||||||||||
| 43 | Modelled pricing | Third-party pricing | $2.14-$10.61 | $7.50 | ||||||||||||||||
| Basis adjustment | $0.08-$0.80 | $0.54 | ||||||||||||||||||
| Own credit risk | 0.01%-5.57% | 0.09% | ||||||||||||||||||
| Discount rate | 0.02%-9.70% | 1.96% | ||||||||||||||||||
| Total liabilities | $ | 183 | ||||||||||||||||||
| Net assets (liabilities) | $ | (159) | ||||||||||||||||||
The financial assets and liabilities included on the Condensed Consolidated Balance Sheets that are not measured at fair value consisted of the following:
| As at | ||||||||||||||||||||||||
| millions of Canadian dollars | Carrying Amount | Fair Value | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||
| March 31, 2018 | $ | 14,138 | $ | 15,061 | $ | 71 | $ | 14,176 | $ | 814 | $ | 15,061 | ||||||||||||
| December 31, 2017 | $ | 13,881 | $ | 15,217 | $ | 69 | $ | 14,346 | $ | 802 | $ | 15,217 | ||||||||||||
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. Anafter-tax foreign currency loss of $36 million was recorded in Other Comprehensive Income for the three months ended March 31, 2018 (2017 – $13 million gainafter-tax). There was no ineffectiveness for the three months ended March 31, 2018 (2017 – nil).
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13. REGULATORY ASSETS AND LIABILITIES
A summary of the Company’s regulatory assets and liabilities is provided below. For a detailed description regarding the nature of the Company’s regulatory assets and liabilities, refer to note 16 in Emera’s 2017 annual audited consolidated financial statements.
| As at | March 31 | December 31 | ||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||
| Regulatory assets | ||||||||
| Deferred income tax regulatory assets | $ | 706 | $ | 667 | ||||
| Pension and post-retirement medical plan | 349 | 345 | ||||||
| Storm Reserve | 59 | 59 | ||||||
| Environmental remediation | 37 | 41 | ||||||
| Unamortized defeasance costs | 30 | 32 | ||||||
| 2015 demand side management deferral | 27 | 28 | ||||||
| GBPC Hurricane Matthew restoration | 26 | 28 | ||||||
| Stranded cost recovery | 26 | 25 | ||||||
| Deferrals related to derivative instruments | 15 | 15 | ||||||
| Debt basis adjustment | 13 | 13 | ||||||
| Cost-recovery clauses | 9 | 17 | ||||||
| Deferred bond refinancing costs | 7 | 7 | ||||||
| Other | 98 | 99 | ||||||
| $ | 1,402 | $ | 1,376 | |||||
| Current | $ | 124 | $ | 138 | ||||
| Long-term | 1,278 | 1,238 | ||||||
| Total regulatory assets | $ | 1,402 | $ | 1,376 | ||||
| Regulatory liabilities | ||||||||
| Deferred income tax regulatory liabilities | $ | 1,139 | $ | 1,116 | ||||
| Accumulated reserve - cost of removal | 916 | 894 | ||||||
| Deferrals related to derivative instruments | 139 | 182 | ||||||
| NSPI Regulated fuel adjustment mechanism | 181 | 177 | ||||||
| Cost-recovery clauses | 37 | 51 | ||||||
| Self-Insurance fund (note 20) | 28 | 28 | ||||||
| Tax reform and storm settlement | 24 | - | ||||||
| Other | 16 | 20 | ||||||
| $ | 2,480 | $ | 2,468 | |||||
| Current | $ | 228 | $ | 226 | ||||
| Long-term | 2,252 | 2,242 | ||||||
| Total regulatory liabilities | $ | 2,480 | $ | 2,468 | ||||
Tax Reform and Storm Settlement
On March 1, 2018, the FPSC approved a settlement agreement filed by Tampa Electric that authorizes the utility to net the estimated amount of storm cost recovery against its return of estimated 2018 tax reform benefits to customers. As a result, in Q1 2018, Tampa Electric recorded OM&G expense and a regulatory liability of $24 million in order to offset tax reform benefits in the first quarter. This deferral was recorded as a result of deferring the impact of the first quarter as the effective date of the agreement is April 1, 2018. The regulatory liability will be amortized over the remainder of 2018 as a credit against the recognition of storm expense, beginning on April 1, 2018. Tampa Electric’s final storm costs subject to netting and final impact of tax reform on base rates will be determined in separate regulatory proceedings. Any difference will be trued up and recovered from or returned to customers in 2019. Beginning in January 2019, Tampa Electric will reflect the full amount of tax reform in its base rates, provided the FPSC’s determinations have been finalized. Hearings on the tax reform impacts for all state utilities are tentatively scheduled for the second half of 2018.
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14. 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 tonon-related parties. Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions betweennon-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:
| • | Transactions between NSPI and NSPML related to the Maritime Link Interim Assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in Operating expenses, Regulated fuel for generation and purchased power, totalling $24 million for the three months ended March 31, 2018 (2017 – nil). NSPML is considered an equity investment and therefore, the corresponding revenue is reflected in Income from equity investments. |
| • | Natural gas transportation capacity revenues from M&NP are reported in the Condensed Consolidated Statements of Income. Revenues from M&NP, reported in Operating revenue -non-regulated, totalled $10 million for the three months ended March 31, 2018 (2017 - $10 million). |
There are no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at March 31, 2018 and December 31, 2017.
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15. 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 providesnon-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, Maine, Connecticut, Massachusetts, Rhode Island, New Mexico, Barbados, Dominica and Grand Bahama Island. For details of the Company’s employee benefit plan, refer to note 20 in Emera’s 2017 annual audited consolidated financial statements.
Emera’s net periodic benefit cost included the following:
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||
| Defined benefit pension plans | ||||||||
| Service cost | $ | 12 | $ | 12 | ||||
| Non-service cost | ||||||||
Interest cost | 24 | 25 | ||||||
Expected return on plan assets | (35) | (33) | ||||||
Current year amortization of: | ||||||||
Actuarial losses (gains) | 9 | 9 | ||||||
Regulatory asset | 5 | 4 | ||||||
Special termination benefits | 1 | - | ||||||
| Totalnon-service costs | 4 | 5 | ||||||
| Total defined benefit pension plans | 16 | 17 | ||||||
| Non-pension benefits plan | ||||||||
| Service cost | 1 | 1 | ||||||
| Non-service cost | ||||||||
Interest cost | 3 | 4 | ||||||
Expected return on plan assets | (1) | (1) | ||||||
Current year amortization of: | ||||||||
Actuarial losses (gains) | 1 | 1 | ||||||
Past service costs (gains) | (2) | (2) | ||||||
Regulatory asset | 1 | - | ||||||
| Totalnon-service costs | 2 | 2 | ||||||
| Totalnon-pension benefits plans | 3 | 3 | ||||||
| Total defined benefit plans | $ | 19 | $ | 20 | ||||
Emera’s contributions related to these defined-benefit plans for the three months ended March 31, 2018 were $27 million (2017 - $68 million). Annual employer contributions for the defined benefit pension plans are estimated to be $50 million for 2018.
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16. SHORT-TERM DEBT
Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving andnon-revolving credit facilities and short-term notes. For details regarding short-term debt refer to note 23 in Emera’s 2017 annual audited consolidated financial statements, and below for 2018 short-term debt financing activity.
Recent financing activities
TECO Energy/TECO Finance revolving credit facility
On March 7, 2018, TECO Energy increased its $300 million USD revolving credit facility by $100 million USD to $400 million USD. There were no other changes in commercial terms.
TECO Energy/TECO Finance term credit facility
On March 7, 2018, TECO Energy increased its $400 million USD term bank credit facility by $100 million USD to $500 million USD, and extended the maturity date from March 8, 2018 to March 8, 2019. There were no other changes in commercial terms.
TEC accounts receivable revolving credit facility
On March 23, 2018, TEC extended the maturity date of its $150 million USD accounts receivable collateralized borrowing facility from March 23, 2018 to March 22, 2021. There were no other changes in commercial terms.
17. LONG-TERM DEBT
For details regarding long-term debt refer to note 25 in Emera’s 2017 annual audited consolidated financial statements, and below for 2018 long-term debt financing activity.
Recent financing activities
ECI
On January 12, 2018, a wholly owned indirect subsidiary of ECI entered into a five year $18 million Bahamian dollar loan agreement with an interest rate of 4.00 per cent and maturity date of January 12, 2023.
TECO Energy/TECO Finance
On April 10, 2018, TECO Energy/Finance repaid a $250 million USD note upon maturity. The note was repaid using funds from existing credit facilities and cash on hand.
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18. COMMITMENTS AND CONTINGENCIES
A. Commitments
As at March 31, 2018, 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 | 2018 | 2019 | 2020 | 2021 | 2022 | Thereafter | Total | |||||||||||||||||||||
| Purchased power (1) | $ | 177 | $ | 219 | $ | 216 | $ | 212 | $ | 210 | $ | 2,227 | $ | 3,261 | ||||||||||||||
| Transportation (2) | 385 | 326 | 281 | 195 | 184 | 1,493 | 2,864 | |||||||||||||||||||||
| Capital projects | 577 | 202 | 31 | 12 | - | - | 822 | |||||||||||||||||||||
| Fuel and gas supply | 377 | 185 | 51 | 41 | 4 | - | 658 | |||||||||||||||||||||
| Long-term service agreements (3) | 54 | 81 | 36 | 35 | 41 | 195 | 442 | |||||||||||||||||||||
| Equity investment commitments (4) | 20 | 5 | 190 | - | - | - | 215 | |||||||||||||||||||||
| Leases and other (5) | 42 | 14 | 12 | 8 | 7 | 66 | 149 | |||||||||||||||||||||
| Demand side management | 42 | 28 | 18 | 18 | 18 | - | 124 | |||||||||||||||||||||
| $ | 1,674 | $ | 1,060 | $ | 835 | $ | 521 | $ | 464 | $ | 3,981 | $ | 8,535 | |||||||||||||||
(1) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths.
(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.
(3) Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management.
(4) Emera has a commitment under the Federal Loan Guarantee to complete construction of the Maritime Link. The project has been placed in service and remaining costs relate to construction close out. Emera also has a commitment to make equity contributions to the Labrador Island Link Limited Partnership. The amounts forecasted are a combination of investments in both projects.
(5) Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles.
NSPI has a contractual obligation to pay NSPML for the use of the Maritime Link over approximately 37 years. The UARB has approved NSPI to pay NSPML approximately $110 million and $111 million in 2018 and 2019, respectively. After 2019, the timing and amounts payable to NSPML will be subject to a regulatory filing with the UARB which will be filed no later than 2019.
B. Legal Proceedings
Emera Florida and New Mexico
TECO Coal
TECO Coal was sold by TECO Energy on September 21, 2015 to Cambrian Coal Corporation (“Cambrian”), prior to Emera’s acquisition of TECO Energy. On March 18, 2016, Cambrian delivered a notice of a purported claim to TECO Diversified. The claim asserted breach of certain representations, and fraud and willful misconduct in connection therewith, of the Securities Purchase Agreement dated September 21, 2015 by and between TECO Diversified and Cambrian related to the purchase of TECO Coal by Cambrian. On March 7, 2018, TECO Diversified and Cambrian reached a global settlement agreement on mutually acceptable terms and conditions, having no material adverse effect on TECO Diversified.
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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. On October 3, 2016, ICSID issued a notice of registration for TGH’s request for resubmission. A new tribunal has been constituted and it issued its first procedural order. TGH’s memorial was filed on September 1, 2017. Guatemala’s counter-memorial was filed on February 2, 2018. In addition, TGH has sued Guatemala in Washington, D.C. court to enforce the $21 million USD due and owing. 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 March 31, 2018, TEC has estimated its ultimate financial liability to be $36 million ($28 million USD), primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Condensed Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.
The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.
In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs. Factors that could impact these estimates include the ability of other PRPs to pay theirpro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings. The FPSC has approved, as part of the PGS depreciation settlement, an agreement to accelerate the amortization of the regulated asset associated with this reserve.
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Emera Maine
From 2011 to 2016, four separate complaints have been filed with the FERC to challenge theISO-New England Open Access Transmission Tariff-allowed base ROE. Complaint I, filed by a group including the Attorney General of Massachusetts, New England utilities commissions, state public advocates and end users, has been remanded to the FERC by the US Court of Appeals for further proceedings. A decision by the FERC is expected in 2018. No reserve has been made with respect to Complaint I due to uncertainty. Complaints II and III (theso-called “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. A decision on these cases is expected in 2018. Emera Maine has recorded a reserve of $4 million USD for the ENE and MA AG II Cases. These reserves have been recorded as “Regulatory liabilities” on the Condensed Consolidated Balance Sheets and as a reduction to “Operating revenues – regulated electric” on the Condensed 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 is likely to be appealed to the FERC. If so, a final decision is expected in 2018. No reserve has been made in relation to Complaint IV due to the uncertainty of the final outcome.
Other Legal Proceedings
Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company.
C. Principal Financial Risks and Uncertainties
In this section, Emera describes some of the principal financial risks management believes could materially affect the Company in the normal course of business. Risks associated with derivative instruments and fair value measurements are discussed further in note 11 and note 12.
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 globally, with an increasing amount of the Company’s adjusted net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the Canadian dollar and, particularly, the US dollar, which could positively or adversely affect results.
Consistent with the Company’s risk management policies, Emera manages currency risks through matching US denominated debt to finance its US operations and uses short-term foreign currency derivative instruments to hedge specific transactions. The Company enters into foreign exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenues streams, capital expenditures and projects. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs, including foreign exchange.
The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes, or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries are included in AOCI.
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Capital Market and Liquidity Risk
Emera’s operations and projects in development require significant capital investments in property, plant and equipment. Consequently, Emera is an active participant in the debt and equity markets. Any disruption in capital markets could have a material impact on Emera’s ability to fund its operations. Capital markets are global in nature and are affected by numerous events throughout the world economy. Capital market disruptions could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions.
Emera is subject to financial risk associated with changes in its credit ratings. There are a number of factors that rating agencies evaluate to determine credit ratings, including the company’s business and regulatory framework, the ability to recover costs and earn returns, diversification, leverage, and liquidity. A change to a credit rating as a result of changes in any of these items could result in higher interest rates in future financings, increase borrowing costs under certain existing credit facilities, limit access to the commercial paper market or limit the availability of adequate credit support for subsidiary operations.
Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs will be financed through internally generated cash flows, short-term credit facilities, and ongoing access to capital markets. The Company reasonably expects liquidity sources to exceed ordinary course capital needs.
Interest Rate Risk
Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter into interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt.
For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt costs are recovered from customers. While regulatory ROE will generally follow the direction of interest rates, such that regulatory ROE’s are likely to fall in times of reducing interest rates and 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.
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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. US tax reform legislation was enacted on December 22, 2017. The Company continues to analyze certain aspects of the Act and some of the specific details have yet to be clarified. 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’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2017 audited annual consolidated financial statements, with updates as noted below.
TECO Coal was sold on September 21, 2015 to Cambrian Coal Corporation (“Cambrian”). Pursuant to the sales agreement, Cambrian was obligated to file, in respect of each mining permit, applications in connection with the change of control with the appropriate governmental entities. As each application was approved, Cambrian was required to post a bond or other appropriate collateral in order to obtain the release of the corresponding bond secured by the TECO Energy indemnity for that permit. As at March 31, 2018, TECO Energy had remaining indemnified bonds totaling $5 million ($4 million USD). In April 2018, all of the TECO Coal bonds were released and returned.
Emera has standby letters of credit in the amount of $37 million USD to third parties that have extended credit to Emera and its subsidiaries. These letters of credit typically have aone-year term and are renewed annually as required.
19. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars | 2018 | 2017 | ||||||
| Changes innon-cash working capital: | ||||||||
Receivables, net | $ | 166 | $ | 11 | ||||
Income taxes receivable | 9 | (5) | ||||||
Inventory | 21 | 27 | ||||||
Prepayments and other current assets | (24) | (27) | ||||||
Accounts payable | (230) | (236) | ||||||
Income taxes payable | 4 | (1) | ||||||
Other current liabilities | 43 | 49 | ||||||
| Totalnon-cash working capital | $ | (11) | $ | (182) | ||||
| Supplemental disclosure ofnon-cash activities: | ||||||||
| Common share dividends reinvested | $ | 47 | $ | 40 | ||||
| Issuance of depository receipts | $ | 22 | $ | - | ||||
20. VARIABLE INTEREST ENTITIES
The Company performs ongoing analysis to assess whether it holds any Variable Interest Entities (“VIE”). To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly-owned facilities.
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VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera is not deemed the primary beneficiary, the VIE is accounted for using the equity method.
Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have the controlling financial interest of NSPML. In Q2 2014, when the critical milestones were achieved, Nalcor Energy was deemed the beneficiary of the asset for financial reporting purposes as they have authority over the majority of the direct activities that are expected to most significantly impact the economic performance of Maritime Link. Thus, Emera began recording 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 an “Other long-term assets”, “Restricted cash” and “Regulatory liabilities” on the Condensed 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 | March 31, 2018 | December 31, 2017 | ||||||||||||||
| 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) | $ | 558 | $ | 70 | $ | 510 | $ | 67 | ||||||||
21. 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.
22. SUBSEQUENT EVENTS
These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through May 10, 2018, the date the financial statements were issued.
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