Exhibit 99.2
EMERA INCORPORATED
Unaudited Condensed Consolidated
Interim Financial Statements
June 30, 2016 and 2015
1
Emera Incorporated
Condensed Consolidated Statements of Income (Unaudited)
For the | Three months ended | Six months ended | ||||||||||||||
millions of Canadian dollars (except per share amounts) | June 30 | June 30 | ||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Operating revenues | ||||||||||||||||
Regulated | $ | 493.1 | $ | 512.3 | $ | 1,079.7 | $ | 1,143.5 | ||||||||
Non-regulated | 6.3 | 14.6 | 296.7 | 271.9 | ||||||||||||
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Total operating revenues | 499.4 | 526.9 | 1,376.4 | 1,415.4 | ||||||||||||
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Operating expenses | ||||||||||||||||
Regulated fuel for generation and purchased power | 156.7 | 173.7 | 354.4 | 428.7 | ||||||||||||
Regulated fuel adjustment mechanism and fixed cost deferrals (note 5) | 24.0 | 22.7 | 41.6 | 15.5 | ||||||||||||
Non-regulated fuel for generation and purchased power | 69.5 | 37.3 | 179.3 | 187.7 | ||||||||||||
Non-regulated direct costs | 0.2 | 5.4 | 2.5 | 9.8 | ||||||||||||
Operating, maintenance and general | 147.3 | 151.7 | 323.0 | 306.8 | ||||||||||||
Provincial, state and municipal taxes | 16.5 | 15.7 | 32.9 | 31.6 | ||||||||||||
Depreciation and amortization | 84.5 | 84.3 | 172.0 | 167.1 | ||||||||||||
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Total operating expenses | 498.7 | 490.8 | 1,105.7 | 1,147.2 | ||||||||||||
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Income from operations | 0.7 | 36.1 | 270.7 | 268.2 | ||||||||||||
Income from equity investments (note 6) | 30.3 | 32.2 | 56.3 | 58.1 | ||||||||||||
Other income (expenses), net (note 7) | 294.2 | 0.7 | 155.0 | 22.6 | ||||||||||||
Interest expense, net (note 8) | 107.3 | 48.0 | 182.5 | 92.4 | ||||||||||||
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Income before provision for income taxes | 217.9 | 21.0 | 299.5 | 256.5 | ||||||||||||
Income tax expense (recovery) (note 9) | 1.1 | (1.4 | ) | 27.9 | 60.0 | |||||||||||
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Net income | 216.8 | 22.4 | 271.6 | 196.5 | ||||||||||||
Non-controlling interest in subsidiaries | 2.0 | 4.6 | 5.5 | 10.9 | ||||||||||||
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Net income of Emera Incorporated | 214.8 | 17.8 | 266.1 | 185.6 | ||||||||||||
Preferred stock dividends | 7.0 | 7.8 | 14.0 | 15.5 | ||||||||||||
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Net income attributable to common shareholders | $ | 207.8 | $ | 10.0 | $ | 252.1 | $ | 170.1 | ||||||||
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Weighted average shares of common stock outstanding (in millions) (note 10) | ||||||||||||||||
Basic | 149.7 | 145.4 | 149.2 | 145.2 | ||||||||||||
Diluted | 150.3 | 146.0 | 149.8 | 149.3 | ||||||||||||
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Earnings per common share (note 10) | ||||||||||||||||
Basic | $ | 1.39 | $ | 0.07 | $ | 1.69 | $ | 1.17 | ||||||||
Diluted | $ | 1.38 | $ | 0.07 | $ | 1.68 | $ | 1.16 | ||||||||
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Dividends per common share declared | $ | 0.4750 | $ | 0.4000 | $ | 0.9500 | $ | 0.7875 | ||||||||
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The accompanying notes are an integral part of these condensed consolidated financial statements.
2
Emera Incorporated
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
For the | Three months ended | Six months ended | ||||||||||||||
millions of Canadian dollars | June 30 | June 30 | ||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Net income | $ | 216.8 | $ | 22.4 | $ | 271.6 | $ | 196.5 | ||||||||
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Other comprehensive income (loss), net of tax | ||||||||||||||||
Foreign currency translation adjustment (1) | (17.5 | ) | (17.7 | ) | (179.0 | ) | 171.7 | |||||||||
Cash flow hedges | ||||||||||||||||
Net derivative gains (losses) (2) | 2.8 | 2.2 | 16.9 | (13.7 | ) | |||||||||||
Less: reclassification adjustment for losses (gains) included in income (3) | 2.6 | 2.0 | 3.5 | 0.9 | ||||||||||||
Net effects of cash flow hedges | 5.4 | 4.2 | 20.4 | (12.8 | ) | |||||||||||
Unrealized gains (losses) on available-for-sale investment | ||||||||||||||||
Unrealized gain (loss) arising during the period | (0.1 | ) | (0.9 | ) | 0.3 | (0.5 | ) | |||||||||
Net unrealized holding gains (losses) | (0.1 | ) | (0.9 | ) | 0.3 | (0.5 | ) | |||||||||
Net change in unrecognized pension and post-retirement benefit obligation (4) | 8.7 | 25.1 | 17.3 | 35.7 | ||||||||||||
Other equity method reclassification adjustment (5) | (45.7 | ) | — | (45.7 | ) | — | ||||||||||
Other comprehensive income (loss) (6) | (49.2 | ) | 10.7 | (186.7 | ) | 194.1 | ||||||||||
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Comprehensive income (loss) | 167.6 | 33.1 | 84.9 | 390.6 | ||||||||||||
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Comprehensive income (loss) attributable to non-controlling interest | 2.7 | 1.9 | (0.7 | ) | 21.4 | |||||||||||
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Comprehensive income (loss) of Emera Incorporated | $ | 164.9 | $ | 31.2 | $ | 85.6 | $ | 369.2 | ||||||||
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The accompanying notes are an integral part of these condensed consolidated financial statements.
1) | Net of tax recovery of $5.0 million (2015 - $3.7 million tax expense) for the three months ended June 30, 2016 and tax recovery of $3.2 million (2015 – $3.8 million tax expense) for the six months ended June 30, 2016. |
2) | Net of tax expense of $0.7 million (2015 - $0.4 million tax expense) for the three months ended June 30, 2016 and tax expense of $0.8 million (2015 – $0.6 million tax expense) for the six months ended June 30, 2016. |
3) | Net of tax expense of $0.5 million (2015 - $0.3 million tax expense) for the three months ended June 30, 2016 and tax recovery of $1.1 million (2015 – $1.9 million tax recovery) for the six months ended June 30, 2016. |
4) | Net of tax expense of nil (2015 - $8.5 million tax expense) for the three months ended June 30, 2016 and tax expense of nil (2015 – $9.1 million tax expense) for the six months ended June 30, 2016. |
5) | Net of tax recovery of $8.4 million (2015 - nil tax recovery) for the three months ended June 30, 2016 and tax recovery of $8.4 million (2015 - nil tax recovery) for the six months ended June 30, 2016. |
6) | Net of tax recovery of $12.2 million (2015 - $12.9 million tax expense) for the three months ended June 30, 2016 and tax recovery of $11.9 million (2015 - $11.6 million tax expense) for the six months ended June 30, 2016. |
3
Emera Incorporated
Condensed Consolidated Balance Sheets (Unaudited)
As at | June 30 | December 31 | ||||||
millions of Canadian dollars | 2016 | 2015 | ||||||
Assets | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 7,458.9 | $ | 1,073.4 | ||||
Restricted cash | 18.8 | 19.3 | ||||||
Investment securities (note 12) | 65.0 | — | ||||||
Instalment receipts receivable (note 23) | 1,457.4 | — | ||||||
Receivables, net (note 13) | 479.6 | 577.4 | ||||||
Income taxes receivable | 38.2 | 12.1 | ||||||
Inventory (note 14) | 265.8 | 314.3 | ||||||
Derivative instruments (notes 15 and 16) | 93.7 | 249.5 | ||||||
Regulatory assets (notes 5 and 17) | 52.3 | 94.2 | ||||||
Prepaid expenses | 45.3 | 18.3 | ||||||
Due from related parties (note 18) | 1.7 | 2.3 | ||||||
Other current assets (note 19) | 102.2 | 234.8 | ||||||
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Total current assets | 10,078.9 | 2,595.6 | ||||||
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Property, plant and equipment, net of accumulated depreciation of $3,773.8 and $3,732.4, respectively | 6,073.7 | 6,188.0 | ||||||
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Other assets | ||||||||
Income taxes receivable | 48.1 | 48.7 | ||||||
Deferred income taxes | 34.7 | 32.2 | ||||||
Derivative instruments (notes 15 and 16) | 119.8 | 167.6 | ||||||
Pension and post-retirement asset (note 20) | 8.6 | 8.7 | ||||||
Regulatory assets (notes 5 and 17) | 632.5 | 605.3 | ||||||
Net investment in direct financing lease | 477.7 | 480.1 | ||||||
Investments subject to significant influence (note 6) | 758.7 | 1,145.3 | ||||||
Investment securities (note 12) | 199.0 | 116.0 | ||||||
Goodwill | 248.3 | 264.1 | ||||||
Intangibles, net of accumulated amortization of $97.5 and $92.8, respectively | 206.8 | 191.9 | ||||||
Due from related parties (note 18) | 2.5 | 2.5 | ||||||
Other long-term assets | 99.4 | 104.0 | ||||||
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Total other assets | 2,836.1 | 3,166.4 | ||||||
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Total assets | $ | 18,988.7 | $ | 11,950.0 | ||||
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The accompanying notes are an integral part of these condensed consolidated financial statements.
4
Emera Incorporated
Condensed Consolidated Balance Sheets – (Unaudited) Continued
As at | June 30 | December 31 | ||||||
millions of Canadian dollars | 2016 | 2015 | ||||||
Liabilities and Equity | ||||||||
Current liabilities | ||||||||
Short-term debt | $ | 3.6 | $ | 15.9 | ||||
Current portion of long-term debt | 272.8 | 274.0 | ||||||
Accounts payable | 413.7 | 394.2 | ||||||
Income taxes payable | 20.4 | 8.1 | ||||||
Derivative instruments (notes 15 and 16) | 130.1 | 349.2 | ||||||
Regulatory liabilities (note 17) | 70.0 | 98.9 | ||||||
Pension and post-retirement liabilities (note 20) | 7.0 | 7.0 | ||||||
Due to related party (note 18) | 1.9 | 2.1 | ||||||
Other current liabilities (note 21) | 241.4 | 204.3 | ||||||
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Total current liabilities | 1,160.9 | 1,353.7 | ||||||
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Long-term liabilities | ||||||||
Long-term debt (note 22) | 9,605.8 | 3,734.6 | ||||||
Deferred income taxes | 810.9 | 761.7 | ||||||
Convertible debentures represented by instalment receipts (note 23) | 2,077.4 | 681.5 | ||||||
Derivative instruments (notes 15 and 16) | 72.0 | 96.1 | ||||||
Regulatory liabilities (note 17) | 224.5 | 271.7 | ||||||
Asset retirement obligations | 116.5 | 114.7 | ||||||
Pension and post-retirement liabilities (note 20) | 294.9 | 303.4 | ||||||
Other long-term liabilities (note 24) | 274.9 | 298.5 | ||||||
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Total long-term liabilities | 13,476.9 | 6,262.2 | ||||||
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Commitments and contingencies (note 25) | ||||||||
Equity | ||||||||
Common stock, no par value, unlimited shares authorized, 148.91 million and 147.21 million shares issued and outstanding, respectively (note 26) | 2,223.9 | 2,157.5 | ||||||
Cumulative preferred stock, Series A, B, C, E and F, par value $25 per share; unlimited shares authorized, 3.9 million, 2.1 million, 10 million, 5 million, and 8 million shares issued and outstanding, respectively | 709.5 | 709.5 | ||||||
Contributed surplus | 74.5 | �� | 28.8 | |||||
Accumulated other comprehensive income (loss) (note 11) | (48.1 | ) | 136.5 | |||||
Retained earnings | 1,284.5 | 1,167.8 | ||||||
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Total Emera Incorporated equity | 4,244.3 | 4,200.1 | ||||||
Non-controlling interest in subsidiaries (note 27) | 106.6 | 134.0 | ||||||
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Total equity | 4,350.9 | 4,334.1 | ||||||
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Total liabilities and equity | $ | 18,988.7 | $ | 11,950.0 | ||||
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The accompanying notes are an integral part of these condensed consolidated financial statements.
Approved on behalf of the Board of Directors
“M. Jacqueline Sheppard” | “Christopher G. Huskilson” | |
Chair of the Board | President and Chief Executive Officer |
5
Emera Incorporated
Condensed Consolidated Statements of Cash Flows (Unaudited)
For the | Six months ended June 30 | |||||||
millions of Canadian dollars | 2016 | 2015 | ||||||
Operating activities | ||||||||
Net income | $ | 271.6 | $ | 196.5 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depreciation and amortization | 178.7 | 172.8 | ||||||
Income from equity investments, net of dividends | (33.9 | ) | (17.8 | ) | ||||
Allowance for equity funds used during construction | (2.0 | ) | (1.8 | ) | ||||
Deferred income taxes, net | 4.7 | (0.3 | ) | |||||
Net change in pension and post-retirement liabilities | 13.8 | 18.0 | ||||||
Regulated fuel adjustment mechanism and fixed cost deferrals | 41.7 | 13.3 | ||||||
Net change in fair value of derivative instruments | (27.1 | ) | 31.8 | |||||
Net change in regulatory assets and liabilities | (4.4 | ) | 2.0 | |||||
Net change in capitalized transportation capacity | 117.6 | 40.1 | ||||||
Unrealized foreign exchange loss | 46.6 | — | ||||||
Gain on APUC sale of common shares and conversion of subscription receipts | (234.9 | ) | — | |||||
Other operating activities, net | (47.4 | ) | (19.5 | ) | ||||
Changes in non-cash working capital (note 28) | 150.7 | (85.3 | ) | |||||
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Net cash provided by operating activities | 475.7 | 349.8 | ||||||
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Investing activities | ||||||||
Additions to property, plant and equipment | (198.8 | ) | (165.1 | ) | ||||
Net purchase of investments subject to significant influence, inclusive of acquisition costs | (114.9 | ) | (7.9 | ) | ||||
Additions to intangible assets | (27.5 | ) | (24.7 | ) | ||||
Net proceeds on sale of investments subject to significant influence | 524.8 | 282.3 | ||||||
Other investing activities | (5.4 | ) | (20.9 | ) | ||||
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Net cash provided by investing activities | 178.2 | 63.7 | ||||||
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Financing activities | ||||||||
Change in short-term debt, net | (13.8 | ) | (270.5 | ) | ||||
Retirement of long-term debt | (8.4 | ) | (11.1 | ) | ||||
Proceeds from long-term debt, net of issuance costs | 6,236.2 | 425.0 | ||||||
Net borrowings (repayments) under committed credit facilities | (295.4 | ) | (512.7 | ) | ||||
Issuance of common stock, net of issuance costs | 18.0 | 4.4 | ||||||
Dividends on common stock | (96.6 | ) | (78.4 | ) | ||||
Dividends on preferred stock | (14.0 | ) | (15.5 | ) | ||||
Dividends paid by subsidiaries to non-controlling interest | (2.3 | ) | (6.5 | ) | ||||
Other financing activities | (13.9 | ) | (15.7 | ) | ||||
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Net cash provided by financing activities | 5,809.8 | (481.0 | ) | |||||
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Effect of exchange rate changes on cash and cash equivalents | (78.2 | ) | 23.1 | |||||
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Net increase (decrease) in cash and cash equivalents | 6,385.5 | (44.4 | ) | |||||
Cash and cash equivalents, beginning of period | 1,073.4 | 221.1 | ||||||
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Cash and cash equivalents, end of period | $ | 7,458.9 | $ | 176.7 | ||||
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Cash and cash equivalents consists of: | ||||||||
Cash | $ | 4,717.2 | $ | 107.4 | ||||
Short-term investments | 2,741.7 | 69.3 | ||||||
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Cash and cash equivalents | $ | 7,458.9 | $ | 176.7 | ||||
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The accompanying notes are an integral part of these condensed consolidated financial statements.
6
Emera Incorporated
Condensed Consolidated Statements of Changes in Equity (Unaudited)
Accumulated | ||||||||||||||||||||||||||||||||
Other | ||||||||||||||||||||||||||||||||
Comprehensive | Emera | Non- | ||||||||||||||||||||||||||||||
Common | Preferred | Contributed | Income (Loss) | Retained | Total | Controlling | Total | |||||||||||||||||||||||||
millions of Canadian dollars | Stock | Stock | Surplus | (“AOCI”) | Earnings | Equity | Interest | Equity | ||||||||||||||||||||||||
For the six months ended June 30, 2016 | ||||||||||||||||||||||||||||||||
Balance, December 31, 2015 | $ | 2,157.5 | $ | 709.5 | $ | 28.8 | $ | 136.5 | $ | 1,167.8 | $ | 4,200.1 | $ | 134.0 | $ | 4,334.1 | ||||||||||||||||
Net income of Emera Incorporated | — | — | — | — | 266.1 | 266.1 | 5.5 | 271.6 | ||||||||||||||||||||||||
Other comprehensive income (loss), net of tax recovery of $11.9 million | — | — | — | (180.6 | ) | — | (180.6 | ) | (6.2 | ) | (186.8 | ) | ||||||||||||||||||||
Dividends declared on preferred stock (Series A: $0.31940/share, Series B: $0.28180/share, Series C: $0.51250/share, Series E: $0.56250/share and Series F: $0.53125/share) | — | — | — | — | (14.0 | ) | (14.0 | ) | — | (14.0 | ) | |||||||||||||||||||||
Dividends declared on common stock ($0.9500/share) | — | — | — | — | (140.5 | ) | (140.5 | ) | — | (140.5 | ) | |||||||||||||||||||||
Common stock issued under purchase plan | 47.8 | — | — | — | — | 47.8 | — | 47.8 | ||||||||||||||||||||||||
Senior management stock options exercised | 15.2 | — | (1.1 | ) | — | — | 14.1 | — | 14.1 | |||||||||||||||||||||||
Stock option expense | — | — | 0.8 | — | — | 0.8 | — | 0.8 | ||||||||||||||||||||||||
Employee share purchase plan | 0.5 | — | — | — | — | 0.5 | — | 0.5 | ||||||||||||||||||||||||
Beneficial conversion feature, net of after-tax issuance costs | — | — | 43.0 | — | — | 43.0 | — | 43.0 | ||||||||||||||||||||||||
Preferred dividends paid and payable by subsidiaries to non-controlling interest | — | — | — | — | — | — | (1.8 | ) | (1.8 | ) | ||||||||||||||||||||||
Common dividends paid and payable by subsidiaries to non-controlling interest | — | — | — | — | — | — | (1.2 | ) | (1.2 | ) | ||||||||||||||||||||||
Acquisition of non-controlling interest of ECI | 2.9 | — | 7.1 | — | — | 10.0 | (23.7 | ) | (13.7 | ) | ||||||||||||||||||||||
Other | — | — | (4.1 | ) | (4.0 | ) | 5.1 | (3.0 | ) | — | (3.0 | ) | ||||||||||||||||||||
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Balance, June 30, 2016 | $ | 2,223.9 | $ | 709.5 | $ | 74.5 | $ | (48.1 | ) | $ | 1,284.5 | $ | 4,244.3 | $ | 106.6 | $ | 4,350.9 | |||||||||||||||
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The accompanying notes are an integral part of these condensed consolidated financial statements.
7
Emera Incorporated
Condensed Consolidated Statements of Changes in Equity (Unaudited) – Continued
Accumulated | ||||||||||||||||||||||||||||||||
Other | ||||||||||||||||||||||||||||||||
Comprehensive | Emera | Non- | ||||||||||||||||||||||||||||||
Common | Preferred | Contributed | Income | Retained | Total | Controlling | Total | |||||||||||||||||||||||||
millions of Canadian dollars | Stock | Stock | Surplus | (“AOCI”) | Earnings | Equity | Interest | Equity | ||||||||||||||||||||||||
For the six months ended June 30, 2015 | ||||||||||||||||||||||||||||||||
Balance, December 31, 2014 | $ | 2,016.4 | $ | 709.5 | $ | 8.8 | $ | (347.6 | ) | $ | 1,011.7 | $ | 3,398.8 | $ | 306.6 | $ | 3,705.4 | |||||||||||||||
Net income of Emera Incorporated | — | — | — | — | 185.6 | 185.6 | 10.9 | 196.5 | ||||||||||||||||||||||||
Other comprehensive income (loss), net of tax expense of $11.6 million | — | — | — | 183.6 | — | 183.6 | 10.5 | 194.1 | ||||||||||||||||||||||||
Dividends declared on preferred stock (Series A: $0.5500/share, Series C: $0.5125/share, Series E: $0.5625/share and Series F: $0.53125/share) | — | — | — | — | (15.5 | ) | (15.5 | ) | — | (15.5 | ) | |||||||||||||||||||||
Dividends declared on common stock ($0.7875/share) | — | — | — | — | (113.4 | ) | (113.4 | ) | — | (113.4 | ) | |||||||||||||||||||||
Dividends paid by subsidiaries to non-controlling interest | — | — | — | — | — | — | (1.3 | ) | (1.3 | ) | ||||||||||||||||||||||
Common stock issued under purchase plan | 38.4 | — | — | — | — | 38.4 | — | 38.4 | ||||||||||||||||||||||||
Senior management stock options exercised | 0.6 | — | — | — | — | 0.6 | — | 0.6 | ||||||||||||||||||||||||
Stock option expense | — | — | 0.7 | — | — | 0.7 | — | 0.7 | ||||||||||||||||||||||||
Other stock-based compensation | 0.5 | — | — | — | — | 0.5 | — | 0.5 | ||||||||||||||||||||||||
Preferred dividends paid by subsidiaries to non-controlling interest | — | — | — | — | — | — | (5.5 | ) | (5.5 | ) | ||||||||||||||||||||||
Other | — | — | — | — | — | — | (0.5 | ) | (0.5 | ) | ||||||||||||||||||||||
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Balance, June 30, 2015 | $ | 2,055.9 | $ | 709.5 | $ | 9.5 | $ | (164.0 | ) | $ | 1,068.4 | $ | 3,679.3 | $ | 320.7 | $ | 4,000.0 | |||||||||||||||
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The accompanying notes are an integral part of these condensed consolidated financial statements.
8
Emera Incorporated
Notes to the Condensed Consolidated Interim Financial Statements
As at June 30, 2016 and 2015
1. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
The significant accounting policies for both the regulated and non-regulated operations of Emera Incorporated are as follows:
A. | Nature of Operations |
Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation, transmission and distribution, gas transmission and utility energy services.
Emera’s primary rate-regulated subsidiaries and investments at June 30, 2016 included the following:
• | Nova Scotia Power Inc. (“NSPI”), which is a fully integrated electric utility and the primary electricity supplier in Nova Scotia, serving 507,000 customers; |
• | Emera Maine provides electric transmission and distribution services to 159,000 customers in the State of Maine in the United States; |
• | a 100.0 per cent interest (December 31, 2015 – 95.5 per cent) in Emera (Caribbean) Incorporated (“ECI”), the parent of The Barbados Light & Power Company Limited (“BLPC”), which is a vertically integrated utility and sole provider of electricity on the island of Barbados, serving 126,000 customers; a 51.9 per cent interest (December 31, 2015 – 49.6 per cent indirect interest) through ECI in Dominica Electricity Services Ltd. (“Domlec”), an integrated utility on the island of Dominica, serving 36,000 customers; and a 19.1 per cent indirect interest (December 31, 2015 – 18.2 per cent indirect interest) through ECI in St. Lucia Electricity Services Limited (“Lucelec”), which is a vertically integrated regulated electric utility in St. Lucia; |
• | a 50.0 per cent direct and 30.4 per cent indirect interest (through a 60.7 per cent interest in ICD Utilities Limited (“ICDU”)) in Grand Bahama Power Company Limited (“GBPC”), which is a vertically integrated utility and sole provider of electricity on Grand Bahama Island, serving 19,000 customers; |
• | Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), which is a 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick to the United States border under a 25-year firm service agreement with Repsol Energy Canada (“REC”), which expires in 2034; |
• | Emera Newfoundland & Labrador Holdings Inc. (“ENL”), focused on two transmission investments related to the development of an 824 megawatt (“MW”) hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador, scheduled to be generating first power in 2019 and full power in 2020. ENL’s two investments are: |
• | 100 per cent interest in NSP Maritime Link Inc. (“NSPML”), which is developing the Maritime Link Project, a $1.56 billion transmission project, including two 170-kilometre sub-sea cables, connecting the island of Newfoundland and Nova Scotia. This project is scheduled to go into service in Q4 2017; |
• | 60.5 per cent investment (December 31, 2015 – 55.1 per cent) in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a $3.4 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Emera’s percentage ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined on completion of the LIL and final costing of all transmission projects related to the Muskrat Falls development, including the LIL and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 per cent of the cost of all of these transmission developments. The investment in LIL is accounted for on the equity basis. This project is scheduled to go into service in Q2 2018. |
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• | a 12.9 per cent interest in Maritimes & Northeast Pipeline (“M&NP”), which is a 1,400-kilometre pipeline, which transports natural gas from offshore Nova Scotia to markets in Atlantic Canada and the northeastern United States. |
Emera Incorporated and its subsidiaries also own investments in other energy-related companies, including:
• | Emera Energy Inc. (“Emera Energy”), includes: |
• | Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services; |
• | Bridgeport Energy, Tiverton Power and Rumford Power (“New England Gas Generating Facilities”), comprising 1,090 MW of combined-cycle gas-fired electricity generating capacity in the northeastern United States; |
• | Bayside Power Limited Partnership (“Bayside Power”), which is a 290 MW electricity generating facility in Saint John, New Brunswick; |
• | Brooklyn Power Corporation (“Brooklyn Energy”), which is a 30 MW biomass co-generation merchant electricity facility in Brooklyn, Nova Scotia. Brooklyn Energy has a long-term purchase power agreement with NSPI; |
• | a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), which is a 600 MW pumped storage hydroelectric facility in northern Massachusetts. |
• | Emera Reinsurance Limited, which is a captive insurance company providing insurance and reinsurance to Emera and certain affiliates, to enable more cost efficient management of risk and deductible levels across Emera; |
• | Emera US Finance LP, a wholly owned financing subsidiary of Emera that issued multiple series of United States dollar denominated senior, unsecured notes for the purpose funding the acquisition of TECO Energy; |
• | Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States; |
• | Emera Utility Services Inc., which is a utility services contractor primarily operating in Atlantic Canada; |
• | a 4.7 per cent (December 31, 2015 – 19.6 per cent) investment in Algonquin Power & Utilities Corp. (“APUC”), which is a public company traded on the Toronto Stock Exchange under the symbol “AQN”; |
• | and other investments. |
TECO Energy Inc. Acquisition
On July 1, 2016, Emera acquired all of the outstanding common shares of TECO Energy Inc. (“TECO Energy”) – refer to Note 31 for further details.
B. | 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 annual audited financial statements of Emera Incorporated’s for the year ended December 31, 2015, except for adopted accounting policies described in note 1 (E) and 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 Incorporated. 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, 2016.
All dollar amounts are presented in Canadian dollars, unless otherwise indicated.
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C. | Use of Management Estimates |
The preparation of consolidated financial statements in accordance with United States generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. Significant estimates are included in unbilled revenue, allowance for doubtful accounts, inventory, valuation of derivative instruments, capitalized overhead, depreciation, asset removal costs, amortization, regulatory assets and regulatory liabilities (including the determination of the current portion), income taxes (including deferred income taxes), pension and post-retirement benefits, asset retirement obligations (“AROs”), goodwill impairment assessments, valuation of investments and contingencies. Actual results may differ significantly from these estimates.
D. | Seasonal Nature of Operations |
Interim results are not necessarily indicative of results for the full year, primarily due to seasonal factors. Electricity sales and related generation vary significantly over the year; the first quarter is typically the strongest period, reflecting colder weather and fewer daylight hours in the winter season in northeastern North America, where a substantial portion of Emera’s electricity business is located. Certain quarters may also be impacted by the number and severity of storms.
E. | Investment Securities |
Effective June 30, 2016, as a result of the sale of a portion of Emera’s investment in APUC, the Company began recording its investment in APUC as held-for-trading (“HFT”) investment securities. Unrealized gains and losses arising from changes in the fair value of HFT investment securities are recognized in the income statement each period. Dividends on HFT equity securities are recognized on the Consolidated Statements of Income in “Other income (expenses), net”.
2. | CHANGE IN ACCOUNTING POLICY |
The new USGAAP accounting policies that are applicable to, and were adopted by the Company, with no material impact on its consolidated financial statements in Q1 2016 and Q2 2016, are described as follows:
Consolidation
In February 2015, the FASB issued Accounting Standard Update (“ASU”) 2015-02,Consolidation,which changes the analysis a reporting entity must perform to determine whether it should consolidate certain types of legal entities. Some of the more notable amendments are (1) the identification of variable interests when fees are paid to a decision maker or service provider, (2) the variable interest entity (“VIE”) characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. All legal entities were subject to re-evaluation under the revised consolidation model.
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Interest – Imputation of Interest
In April 2015, the FASB issued ASU 2015-03,Interest – Imputation of Interest, which simplifies the presentation of debt issuance costs. The amendments require debt issuance costs be presented on the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts or premiums. The recognition and measurement guidance for debt issuance costs is not affected. The Company adopted this standard in Q1 2016 and December 31, 2015 balances have been retrospectively restated. This change resulted in $62.3 million of deferred financing costs, as at December 31, 2015, previously presented as other assets, being reclassified as a deduction from the carrying amount of the related long-term debt and “Convertible debentures represented by instalment receipts” on its Consolidated Balance Sheets.
In accordance with ASU 2015-15Interest: Imputation of Interest, the Company continues to present deferred issuance costs related to its revolving credit facilities and related instruments in “Other long-term assets” on its Consolidated Balance Sheets.
Compensation – Retirement Benefits
In April 2015, the FASB issued ASU 2015-04,Compensation – Retirement Benefits,which is part of FASB’s initiative to reduce complexity in accounting standards. This standard provides certain practical expedients for defined benefit pension or other post-retirement benefit plan measurement dates.
Intangibles – Goodwill and Other – Internal-Use Software
In April 2015, the FASB issued ASU 2015-05, Intangibles– Goodwill and Other– Internal-Use Software,which provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, the customer would account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer would account for the arrangement as a service contract. The guidance does not change GAAP for a customer’s accounting for service contracts.
Inventory – Simplifying the Measurement of Inventory
In July 2015, the FASB issued ASU 2015-11,Inventory –Simplifying the Measurement of Inventory. The amendments require an entity to measure inventory at the lower of cost or net realizable value, whereas previously, inventory was measured at the lower of cost or market. The Company early adopted in 2016 as permitted.
Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships
In March 2016, the FASB issued ASU 2016-05,Derivatives and Hedging Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships. The standard clarifies that a change in the counterparty to a derivative contract, in and of itself, does not require the de-designation of a hedging relationship provided that all other hedge accounting criteria continue to be met. The Company early adopted in 2016 as permitted.
Investments – Equity Method and Joint Ventures
In March 2016, the FASB issued ASU 2016-07,Investments – Equity Method and Joint Ventures, which is part of FASB’s initiative to reduce complexity in accounting standards. This standard eliminates the requirements of an investor to retroactively account for an investment under the equity method when an investment qualifies for equity method accounting. The Company early adopted in 2016 as permitted.
Compensation – Stock Compensation
In March 2016, the FASB issued ASU 2016-09,Compensation – Stock Compensation to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, accounting for forfeitures, classification of awards as either equity or liabilities and presentation on the statement of cash flows. The Company early adopted in 2016 as permitted.
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3. | FUTURE ACCOUNTING PRONOUNCEMENTS |
The Company considers the applicability and impact of all ASUs issued by FASB. The following updates have been issued by FASB, but have not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be either not applicable to the Company or are not expected to have a material impact on the consolidated financial statements.
Revenue from Contracts with Customers
In May 2014, the FASB issued ASU 2014-09,Revenue from Contracts with Customers, which creates a new, principle-based revenue recognition framework. The core principle is a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled to. The guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue arising from contracts with customers. The guidance will be effective beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. The Company will adopt this guidance effective January 1, 2018. The Company has developed an implementation plan and is continuing to evaluate the available adoption methods and the impact of adoption of this standard on its consolidated financial statements.
Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities
In January 2016, the FASB issued ASU 2016-01,Financial Instruments–Recognition and Measurement of Financial Assets and Financial Liabilities. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.
Leases (Topic 842)
In February 2016, the FASB issued ASU 2016-02,Leases. The standard increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for lease terms of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged. The guidance will require additional disclosures regarding key information about leasing arrangements. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018. Early adoption is permitted, and is required to be applied using a modified retrospective approach. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.
Measurement of Credit Losses on Financial Instruments
In June 2016, the FASB issued ASU 2016-13,Measurement of Credit Losses on Financial Instruments. The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures. The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators. This guidance will be effective beginning in 2020, with early adoption permitted in 2019, and will be applied using a modified retrospective approach. 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 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 at June 30, 2016, Emera has six reportable segments, specifically:
• | NSPI; |
• | Emera Maine; |
• | Emera Caribbean (ECI and its subsidiaries including BLPC, Domlec, GBPC, and an equity investment in Lucelec); |
• | Pipelines (Brunswick Pipeline and an equity investment in M&NP); |
• | Emera Energy (Emera Energy Services, New England Gas Generating Facilities, Bayside Power, Brooklyn Energy and an equity investment in Bear Swamp; and |
• | Corporate and Other (Emera Utility Services, ENL, Corporate, other strategic investments and holding companies). |
Inter- | ||||||||||||||||||||||||||||||||
Emera | Emera | Emera | Corporate | Segment | ||||||||||||||||||||||||||||
millions of Canadian dollars | NSPI | Maine | Caribbean | Pipelines | Energy | and Other | Eliminations | Total | ||||||||||||||||||||||||
For the three months ended June 30, 2016 | ||||||||||||||||||||||||||||||||
Operating revenues from external customers (1) | $ | 314.8 | $ | 65.6 | $ | 101.1 | $ | 12.2 | 5.2 | $ | 0.7 | $ | (0.5 | ) | $ | 499.1 | ||||||||||||||||
Inter-segment revenues (1) | — | — | — | — | 2.4 | 7.1 | (9.2 | ) | 0.3 | |||||||||||||||||||||||
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Total operating revenues | 314.8 | 65.6 | 101.1 | 12.2 | 7.6 | 7.8 | (9.7 | ) | 499.4 | |||||||||||||||||||||||
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Net income (loss) attributable to common shareholders | 28.4 | 9.7 | 58.1 | 8.5 | (63.5 | ) | 166.6 | — | 207.8 | |||||||||||||||||||||||
For the six months ended June 30, 2016 | ||||||||||||||||||||||||||||||||
Operating revenues from external customers (1) | 712.3 | 145.2 | 198.7 | 25.1 | 292.9 | 2.8 | (1.1 | ) | 1,375.9 | |||||||||||||||||||||||
Inter-segment revenues (1) | — | — | — | — | 5.7 | 13.4 | (18.6 | ) | 0.5 | |||||||||||||||||||||||
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Total operating revenues | 712.3 | 145.2 | 198.7 | 25.1 | 298.6 | 16.2 | (19.7 | ) | 1,376.4 | |||||||||||||||||||||||
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Net income attributable to common shareholders | 80.9 | 19.0 | 67.9 | 17.9 | 29.9 | 36.5 | — | 252.1 | ||||||||||||||||||||||||
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For the three months ended June 30, 2015 | ||||||||||||||||||||||||||||||||
Operating revenues from external customers (1) | $ | 327.4 | $ | 66.2 | $ | 106.7 | $ | 13.0 | 10.0 | $ | 4.5 | $ | (0.5 | ) | $ | 527.3 | ||||||||||||||||
Inter-segment revenues (1) | — | — | 2.5 | — | 2.6 | 4.6 | (10.1 | ) | (0.4 | ) | ||||||||||||||||||||||
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Total operating revenues | 327.4 | 66.2 | 109.2 | 13.0 | 12.6 | 9.1 | (10.6 | ) | 526.9 | |||||||||||||||||||||||
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Net income (loss) attributable to common shareholders | 16.9 | 13.7 | 4.8 | 7.9 | (33.2 | ) | (0.1 | ) | — | 10.0 | ||||||||||||||||||||||
For the six months ended June 30, 2015 | ||||||||||||||||||||||||||||||||
Operating revenues from external customers (1) | 773.9 | 135.4 | 209.7 | 26.1 | 264.3 | 7.7 | (1.1 | ) | 1,416.0 | |||||||||||||||||||||||
Inter-segment revenues (1) | — | — | 4.9 | — | 6.2 | 10.2 | (21.9 | ) | (0.6 | ) | ||||||||||||||||||||||
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Total operating revenues | 773.9 | 135.4 | 214.6 | 26.1 | 270.5 | 17.9 | (23.0 | ) | 1,415.4 | |||||||||||||||||||||||
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Net income attributable to common shareholders | 84.9 | 25.2 | 13.6 | 17.8 | 31.7 | (3.1 | ) | — | 170.1 | |||||||||||||||||||||||
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(1) | All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes that the elimination of these transactions would understate property, plant and equipment, operating, maintenance and general expenses, or regulated fuel for generation and purchased power. Inter-company transactions which have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments. |
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5. | REGULATED FUEL ADJUSTMENT MECHANISM AND FIXED COST DEFERRALS |
NSPI’s regulated fuel adjustment mechanism and fixed cost deferrals is recognized in the Consolidated Statement of Income and consisted of the following:
For the | Three months ended | Six months ended | ||||||||||||||
millions of Canadian dollars | June 30 | June 30 | ||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Regulated fuel adjustment mechanism (see chart below) | $ | 20.2 | $ | 20.8 | $ | 34.0 | $ | 15.4 | ||||||||
Application of non-fuel revenue | 3.8 | 10.6 | 7.6 | 17.6 | ||||||||||||
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Regulated fixed cost deferral related to 2015 demand side management | — | (8.7 | ) | — | (17.5 | ) | ||||||||||
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$ | 24.0 | $ | 22.7 | $ | 41.6 | $ | 15.5 | |||||||||
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Regulated Fuel Adjustment Mechanism
The regulated fuel adjustment mechanism (“FAM”) included in the Consolidated Statements of Income includes the effect of prudently incurred fuel for generation and purchased power and certain fuel related costs (“Fuel Costs”) in both the current and preceding years, specifically, and as detailed in the table below:
• | The difference between actual Fuel Costs and amounts recovered from customers in the current year. This amount, net of the incentive component, is deferred to a FAM regulatory asset in “Regulatory assets” or a FAM regulatory liability in “Regulatory liabilities” on the Consolidated Balance Sheets; and |
• | The recovery from (rebate to) customers of under (over) recovered Fuel Costs from prior years. |
The FAM is subject to an incentive, with NSPI retaining or absorbing 10 per cent of the over or under-recovered amount to a maximum of $5.0 million. The incentive was suspended for 2012 through 2015, as a result of an UARB approved settlement agreements and is in effect for 2016. The incentive is suspended as part of theElectricity Plan Implementation (2015) Act (the “Electricity Plan Act”) in 2017 to 2019.
The regulated fuel adjustment mechanism on the Consolidated Statements of Income consisted of the following:
For the | Three months ended | Six months ended | ||||||||||||||
millions of Canadian dollars | June 30 | June 30 | ||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Over (Under) recovery of current period Fuel Costs | $ | 17.4 | $ | 7.9 | $ | 27.4 | $ | (15.7 | ) | |||||||
Recovery from (rebate to) customers of prior years’ Fuel Costs | 2.8 | 12.9 | 6.6 | 31.1 | ||||||||||||
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Regulated fuel adjustment mechanism | $ | 20.2 | $ | 20.8 | $ | 34.0 | $ | 15.4 | ||||||||
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The deferred FAM amounts are recognized as a “Regulatory asset” or “Regulatory liability” on the Consolidated Balance Sheets. The FAM regulatory asset balance of $1.5 million and the FAM regulatory liability balance of $73.3 million is disclosed in note 17 and includes associated interest recorded as “Interest expense, net” on the Consolidated Statements of Income.
In December 2015, the UARB approved NSPI’s 2016 base cost of fuel and its recovery of prior period unrecovered fuel related costs. The approved customer rates reset the base cost of fuel rate for 2016 and seek to recover a total of $12.9 million of prior years’ unrecovered Fuel Costs in 2016. The rates and recovery of these costs began January 1, 2016.
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On December 18, 2015, theElectricity Plan Act was enacted by the Province of Nova Scotia. In accordance with theElectricity Plan Act, on March 7, 2016, NSPI filed with the UARB a three-year stability plan for Fuel Costs. On July 19, 2016, the UARB approved a consensus agreement between NSPI and customer representatives which resulted in an average annual increase of 1.1 per cent for 2017 through 2019. Differences between actual Fuel Costs and amounts recovered from customers through electricity rates during 2017 through 2019 will be deferred to a FAM regulatory asset or liability and recovered from or returned to customers after 2019. Difference between actual Fuel Costs and amounts recovered from customers during 2016 are being deferred to a FAM regulatory asset or liability and will be recovered from or returned to customers in the 2017 to 2019 period.
Pursuant to the FAM Plan of Administration, NSPI’s Fuel Costs are subject to independent audit. The audit for fiscal 2014 and 2015 is currently underway.
Application of Non-Fuel Revenues
TheElectricity Plan Act directed NSPI to apply any non-fuel revenues in excess of NSPI’s approved range of return in 2015 and 2016 to the FAM, which will be reserved to be applied in the 2017 to 2019 period. In addition, the financial benefit resulting from a change in the recognition of tax benefits for the South Canoe and Sable wind projects is to be reserved to be applied to the FAM and used in the 2017 to 2019 period. The exception to this direction is to apply a sufficient amount of non-fuel revenues to offset potential fuel related rate increases for certain customer classes in 2016 that would have been otherwise required, which totals $3.8 million.
For the three months ended June 30, 2016, NSPI applied $3.8 million (year-to-date $7.6 million) of non-fuel revenues to the FAM for the periods 2017 through 2019. This was as a result of applying the tax benefits associated with the South Canoe and Sable wind projects as directed by theElectricity Plan Act.
Fixed Cost Deferral Related to 2015 DSM
In April 2014, the Government of Nova Scotia announced new energy efficiency legislation to remove a previous charge for conservation and efficiency programs from power bills of Nova Scotia customers effective January 1, 2015. In addition, the legislation requires NSPI to purchase electricity efficiency and conservation activities (“Program Costs”) from EfficiencyOne, the provincially appointed franchisee to deliver energy efficiency programs to Nova Scotians. The Program Costs were set for 2015 at $35 million and have been deferred as a regulatory asset and are recoverable from customers over an eight-year period beginning in 2016. In August 2015, the UARB approved a budget of $102.0 million for the three year period of 2016 through 2018, which will be reduced by $7.1 million in 2017 as a result of underspend in 2015. The Electricity Plan Act has placed a cap of $34.0 million on the 2019 DSM spending. The 2016 annual DSM cost of $24.7 million will not be deferred and is charged to earnings.
The deferred DSM amounts from 2015 are recognized as a “Regulatory asset” on the Consolidated Balance Sheets. The DSM regulatory asset balance of $34.7 million (2015 - $36.4 million) is disclosed in Note 17 and includes associated interest that is recorded as “Interest expense, net” on the Consolidated Statements of Income.
For the | ||||
millions of Canadian dollars | 2016 | |||
DSM regulatory asset – Balance as at January 1 | $ | 36.4 | ||
Recovery of regulatory asset recorded as regulatory amortization | (3.0 | ) | ||
Interest on DSM balance | 1.3 | |||
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DSM regulatory asset – Balance as at June 30 | $ | 34.7 | ||
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6. | INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME |
Investments subject to significant influence consisted of the following:
Equity Income | Equity Income | |||||||||||||||||||||||||||
Carrying Value | for the | for the | Percentage | |||||||||||||||||||||||||
as at | three months ended | six months ended | of | |||||||||||||||||||||||||
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millions of Canadian dollars | 2016 | 2015 | 2016 | 2015 | 2016 | 2015 | 2016 | |||||||||||||||||||||
LIL (1) | $ | 283.5 | $ | 208.1 | $ | 5.6 | $ | 1.7 | $ | 10.3 | $ | 3.4 | 60.5 | |||||||||||||||
NSPML | 245.3 | 187.6 | 4.3 | 3.7 | 8.7 | 7.3 | 100.0 | |||||||||||||||||||||
M&NP | 175.5 | 188.7 | 5.1 | 4.8 | 11.0 | 10.7 | 12.9 | |||||||||||||||||||||
Lucelec | 37.0 | 39.4 | 0.8 | 0.8 | 1.4 | 1.4 | 19.1 | |||||||||||||||||||||
Maine Electric Power Company Inc. | 6.8 | 7.0 | 0.2 | 0.1 | 0.2 | 0.2 | 21.7 | |||||||||||||||||||||
Cape Sharp Tidal Venture Ltd. | 5.2 | 5.1 | — | — | — | — | 20.0 | |||||||||||||||||||||
Chester Static Var Compensator | 5.0 | 5.3 | — | — | — | — | 50.0 | |||||||||||||||||||||
Maine Yankee Atomic Power Company | 0.4 | 0.4 | — | — | — | — | 12.0 | |||||||||||||||||||||
APUC (2) (3) | — | 503.7 | 8.6 | 8.5 | 17.6 | 15.1 | 4.7 | |||||||||||||||||||||
Bear Swamp (4) | — | — | 5.7 | 12.6 | 7.1 | 15.7 | 50.0 | |||||||||||||||||||||
NWP | — | — | — | — | — | 4.3 | — | |||||||||||||||||||||
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| |||||||||||||||
$ | 758.7 | $ | 1,145.3 | $ | 30.3 | $ | 32.2 | $ | 56.3 | $ | 58.1 | |||||||||||||||||
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(1) | Emera indirectly owns 100 per cent of the Class B units, which comprises 24.9 per cent of the total units issued. Emera’s share of the total partnership capital is 60.5 per cent. |
(2) | On May 24, 2016, Emera completed the sale of 50.1 million common shares or 19.3 per cent of APUC’s issued and outstanding common shares. This resulted in a pre-tax gain of $172.1 million (after-tax gain of $145.5 million), which was recorded in “Other income (expenses), net” in Q2 2016. On June 30, 2016, Emera exchanged 12.9 million of APUC subscription receipts and dividend equivalents into common shares. This resulted in a pre-tax gain of $62.8 million (after-tax gain of $53.1 million), which was recorded in “Other income (expenses), net” in Q2 2016. As a result of these transactions, Emera reclassified its investment in APUC from “Investments Subject to Significant Influence” to “Investment Securities” on the Consolidated Balance Sheets as at June 30, 2016. |
(3) | Emera’s Strategic Investment Agreement with APUC and a ruling by the Maine Public Utilities (“MPUC”) limits Emera’s ownership in APUC to 25 per cent of APUC’s voting securities. The MPUC also stipulated Emera’s dollar investment in APUC cannot exceed 5 per cent of Emera’s total assets. As at June 30, 2016, Emera is in compliance with both of these requirements. |
(4) | Bear Swamp’s credit investment balance is recorded in “Other long-term liabilities” on the Consolidated Balance Sheets. |
Equity investments include a $13.2 million difference between the cost and the underlying fair value of the investees’ assets as at the date of acquisition. The excess is attributable to goodwill.
Emera accounts for its variable interest investment in NSPML as an equity investment (see note 29). NSPML’s consolidated summarized balance sheet is illustrated as follows:
As at | June 30 | December 31 | ||||||
millions of Canadian dollars | 2016 | 2015 | ||||||
Balance Sheet | ||||||||
Current assets | $ | 480.4 | $ | 438.7 | ||||
Property, plant and equipment | 861.7 | 647.7 | ||||||
Non-current assets | 408.7 | 565.6 | ||||||
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| |||||
Total assets | 1,750.8 | 1,652.0 | ||||||
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Current liabilities | 157.2 | 129.8 | ||||||
Non-current liabilities | 1,348.3 | 1,334.6 | ||||||
Equity | 245.3 | 187.6 | ||||||
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Total liabilities and equity | $ | 1,750.8 | $ | 1,652.0 | ||||
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17
7. | OTHER INCOME (EXPENSES), NET |
Other income (expenses), net consisted of the following:
For the | Three months ended | Six months ended | ||||||||||||||
millions of Canadian dollars | June 30 | June 30 | ||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Gain on sale of APUC common shares (note 6) | $ | 172.1 | $ | — | $ | 172.1 | $ | — | ||||||||
Gain on conversion of APUC subscription receipts and dividend equivalents to common shares of APUC (note 6) | 62.8 | — | 62.8 | — | ||||||||||||
Gain on BLPC Self-Insurance Fund (“SIF”) regulatory liability (1) | 53.1 | — | 53.1 | — | ||||||||||||
Allowance for equity funds used during construction | 1.1 | 1.5 | 2.0 | 1.8 | ||||||||||||
Investment income | 2.4 | 0.3 | 2.9 | 0.6 | ||||||||||||
Amortization of defeasance costs | (1.7 | ) | (1.7 | ) | (3.4 | ) | (3.4 | ) | ||||||||
Foreign exchange gains (losses) | (2.6 | ) | (0.4 | ) | (4.1 | ) | 1.5 | |||||||||
Foreign exchange gains (losses) and mark-to-market adjustments related to the TECO Energy acquisition (2) | 6.4 | — | (133.1 | ) | — | |||||||||||
Gain on sale of NWP investment (3) | — | — | — | 18.6 | ||||||||||||
Other | 0.6 | 1.0 | 2.7 | 3.5 | ||||||||||||
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$ | 294.2 | $ | 0.7 | $ | 155.0 | $ | 22.6 | |||||||||
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(1) | In June 2016, BLPC secured support from the Government of Barbados and the Trustees of the SIF to reduce the contingency funding in the SIF to $22.0 million USD. As a result, Emera reduced the SIF regulatory liability to $28.6 million and recorded a pre-tax gain of $53.1 million (after-tax gain of $43.4 million). |
(2) | Mark-to-market adjustments included in Emera’s other income related to the effect of TECO Energy convertible debenture related USD-denominated currency and forward contracts. These contracts were put in place to economically hedge the anticipated proceeds from the 2015 sale of $2.185 billion four per cent convertible unsecured subordinated debentures represented by instalment receipts (“the Debenture Offering” or “Debentures” or “Convertible Debentures”) for the TECO Energy acquisition. |
(3) | On January 25, 2015, Emera completed the sale of its 49 per cent interest in NWP. This resulted in a pre-tax gain of $18.6 million (after-tax gain of $11.5 million). |
8. | INTEREST EXPENSE, NET |
Interest expense, net consisted of the following:
For the | Three months ended | Six months ended | ||||||||||||||
millions of Canadian dollars | June 30 | June 30 | ||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Interest on debt | $ | 61.1 | $ | 48.8 | $ | 109.8 | $ | 96.1 | ||||||||
Interest on Convertible Debentures represented by instalment receipts (1) | 42.8 | — | 64.7 | — | ||||||||||||
Interest on bridge facility related to the TECO Energy acquisition | 3.3 | — | 7.8 | — | ||||||||||||
Allowance for borrowed funds used during construction | (0.9 | ) | (0.8 | ) | (1.6 | ) | (3.0 | ) | ||||||||
Interest revenue | (1.0 | ) | (1.8 | ) | (1.9 | ) | (3.9 | ) | ||||||||
Other | 2.0 | 1.8 | 3.7 | 3.2 | ||||||||||||
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$ | 107.3 | $ | 48.0 | $ | 182.5 | $ | 92.4 | |||||||||
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(1) | In 2015, Emera completed the sale of $2.185 billion four per cent convertible unsecured subordinated debentures represented by instalment receipts. In Q2 2016 these costs also include the accrual of a make-whole interest payment of $21.0 million. This item is payable to holders of the convertible debentures who paid the final instalment owing on the Debentures by August 2, 2016. |
18
9. | 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 | Six months ended | ||||||||||||||
millions of Canadian dollars | June 30 | June 30 | ||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Income before provision for income taxes | $ | 217.9 | $ | 21.0 | $ | 299.5 | $ | 256.5 | ||||||||
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Statutory income tax rate | 31.0 | % | 31.0 | % | 31.0 | % | 31.0 | % | ||||||||
Income taxes, at statutory income tax rate | 67.5 | 6.5 | 92.8 | 79.5 | ||||||||||||
Non-taxable portion of gains on APUC transactions | (36.4 | ) | — | (36.4 | ) | — | ||||||||||
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities | (13.4 | ) | (2.4 | ) | (26.5 | ) | (11.8 | ) | ||||||||
Non-deductible (taxable) portion of mark-to-market losses related to TECO Energy acquisition | (1.0 | ) | — | 20.6 | — | |||||||||||
Foreign tax rate variance | (14.3 | ) | 3.6 | (15.0 | ) | 6.6 | ||||||||||
Other | (1.3 | ) | (9.1 | ) | (7.6 | ) | (14.3 | ) | ||||||||
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Income tax expense (recovery) | $ | 1.1 | $ | (1.4 | ) | $ | 27.9 | $ | 60.0 | |||||||
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Effective income tax rate | 0.5 | % | (6.7 | )% | 9.3 | % | 23.4 | % | ||||||||
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The 2016 and 2015 statutory income tax rate of 31.0 per cent represents the combined Canadian federal and Nova Scotia provincial corporate income tax rates, which are the relevant tax jurisdictions for Emera.
The following reflects the composition of taxes on income from operations presented in the Condensed Consolidated Statements of Income:
For the | Three months ended | Six months ended | ||||||||||||||
millions of Canadian dollars | June 30 | June 30 | ||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Income tax expense (recovery) – current | $ | 5.3 | $ | 11.2 | $ | 23.3 | $ | 60.3 | ||||||||
Income tax expense (recovery) – deferred | (4.2 | ) | (12.6 | ) | 4.6 | (0.3 | ) | |||||||||
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Income tax expense (recovery) | $ | 1.1 | $ | (1.4 | ) | $ | 27.9 | $ | 60.0 | |||||||
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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 $62.3 million, including interest. NSPI has prepaid $22.7 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.
In Q2 2015, CRA commenced audit of NSPI’s 2011 through 2013 taxation years. Should NSPI receive notices of reassessment for those years, and should the 2014 and 2015 taxation years be similarly reassessed, further payments will be required; however, the ultimate permissibility of these deductions is similarly not in dispute.
NSPI and its advisors believe that NSPI has reported its tax position appropriately and NSPI is disputing the reassessments through the CRA Appeal process. The outcome of this process is not determinable at this time.
19
10. | EARNINGS PER SHARE |
The following table reconciles the computation of basic and diluted earnings per share:
For the | Three months ended | Six months ended | ||||||||||||||
millions of Canadian dollars (except per share amounts) | June 30 | June 30 | ||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Numerator | ||||||||||||||||
Net income attributable to common shareholders | $ | 207.8 | $ | 10.0 | $ | 252.1 | $ | 170.1 | ||||||||
Preferred stock dividends of subsidiary (1) | — | — | — | 3.8 | ||||||||||||
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Diluted numerator | 207.8 | 10.0 | 252.1 | 173.9 | ||||||||||||
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Denominator | ||||||||||||||||
Weighted average shares of common stock outstanding | 148.7 | 144.5 | 148.2 | 144.3 | ||||||||||||
Weighted average deferred share units outstanding | 1.0 | 0.9 | 1.0 | 0.9 | ||||||||||||
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Weighted average shares of common stock outstanding – basic | 149.7 | 145.4 | 149.2 | 145.2 | ||||||||||||
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Effect of dilutive preferred stock of a subsidiary (1) | — | — | — | 3.5 | ||||||||||||
Stock-based compensation | 0.6 | 0.6 | 0.6 | 0.6 | ||||||||||||
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Weighted average shares of common stock outstanding – diluted | 150.3 | 146.0 | 149.8 | 149.3 | ||||||||||||
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Earnings per common share | ||||||||||||||||
Basic | $ | 1.39 | $ | 0.07 | $ | 1.69 | $ | 1.17 | ||||||||
Diluted | $ | 1.38 | $ | 0.07 | $ | 1.68 | $ | 1.16 |
(1) | The calculation of diluted earnings per share for the three months ended June 30, 2016 excluded the impact of nil ( 2015 – $1.9 million) in preferred stock dividends of a subsidiary and nil ( 2015—3.5 million ) in potential common shares that has an anti-dilutive effect. |
Effect on EPS of Convertible Debentures
In June 2016, all regulatory approval contingencies associated with the acquisition of TECO Energy were resolved. As a result, final instalment notice was issued on June 29, 2016, with a final instalment payment date of August 2, 2016 (note 23). At the option of the debenture holders, provided that payment of the final instalment is made on August 2, 2016, each Debenture will be convertible in to common shares of Emera. This conversion can happen at any time after the Final Instalment Date, but prior to maturity or redemption by the Company. As a result, beginning August 2, 2016, assuming payment of the final instalment, approximately 52.2 million common shares will be included as a component of the Company’s diluted EPS.
As at August 3, 2016, approximately 50.5 million common shares of Emera were issued, representing conversion into common shares of approximately 97 per cent of the convertible debentures.
20
11. | ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) |
The components of accumulated other comprehensive income (loss), net of tax, are as follows:
millions of Canadian dollars | (Losses) gains on derivatives recognized as cash flow hedges | Net change in unrecognized pension and post-retirement benefit costs | Net change in available-for-sale investments | Unrealized (loss) gain on translation of self-sustaining foreign operations | Total AOCI | |||||||||||||||
For the six months ended June 30, 2016 | ||||||||||||||||||||
Balance, January 1, 2016 | $ | (35.1 | ) | $ | (317.6 | ) | $ | 0.3 | $ | 488.9 | $ | 136.5 | ||||||||
Other comprehensive income (loss) before reclassifications | 16.9 | 0.4 | 0.3 | (172.9 | ) | (155.3 | ) | |||||||||||||
Amounts reclassified from accumulated other comprehensive income loss (gain) | 3.5 | 16.9 | — | — | 20.4 | |||||||||||||||
Equity method reclassification adjustments | (7.5 | ) | (2.7 | ) | — | (35.5 | ) | (45.7 | ) | |||||||||||
Net current period other comprehensive income (loss) | 12.9 | 14.6 | 0.3 | (208.4 | ) | (180.6 | ) | |||||||||||||
Other | — | — | — | (4.0 | ) | (4.0 | ) | |||||||||||||
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Balance, June 30, 2016 | $ | (22.2 | ) | $ | (303.0 | ) | $ | 0.6 | $ | 276.5 | $ | (48.1 | ) | |||||||
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millions of Canadian dollars | (Losses) gains on derivatives recognized as cash flow hedges | Net change in unrecognized pension and post-retirement benefit costs | Net change in available-for-sale investments | Unrealized(loss) gain on translation of self-sustaining foreign operations | Total AOCI | |||||||||||||||
For the six months ended June 30, 2015 | ||||||||||||||||||||
Balance, January 1, 2015 | $ | (7.9 | ) | $ | (424.7 | ) | $ | 2.6 | $ | 82.4 | $ | (347.6 | ) | |||||||
Other comprehensive income (loss) before reclassifications | (13.7 | ) | — | (0.4 | ) | 161.1 | 147.0 | |||||||||||||
Amounts reclassified from accumulated other comprehensive income loss (gain) | 0.9 | 35.7 | — | — | 36.6 | |||||||||||||||
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Net current period other comprehensive income (loss) | (12.8 | ) | 35.7 | (0.4 | ) | 161.1 | 183.6 | |||||||||||||
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Balance, June 30, 2015 | $ | (20.7 | ) | $ | (389.0 | ) | $ | 2.2 | $ | 243.5 | $ | (164.0 | ) | |||||||
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21
The reclassifications out of accumulated other comprehensive income (loss) are as follows:
Three months ended | Six months ended | |||||||||||||||||
For the | June 30 | June 30 | ||||||||||||||||
millions of Canadian dollars | 2016 | 2015 | 2016 | 2015 | ||||||||||||||
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 | $ | 0.9 | $ | 0.6 | $ | (3.3 | ) | $ | (5.0 | ) | |||||||
Interest rate swaps | Income from equity investments | 0.3 | 0.1 | 0.6 | 0.3 | |||||||||||||
Foreign exchange forwards | Operating revenue – regulated | 1.9 | 1.6 | 5.1 | 3.7 | |||||||||||||
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Total before tax | 3.1 | 2.3 | 2.4 | (1.0 | ) | |||||||||||||
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Income tax expense (recovery) | (0.5 | ) | (0.3 | ) | 1.1 | 1.9 | ||||||||||||
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Total net of tax | $ | 2.6 | $ | 2.0 | $ | 3.5 | $ | 0.9 | ||||||||||
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Net change in unrecognized pension and post-retirement benefit costs | ||||||||||||||||||
Actuarial losses (gains) | OM&G | $ | 10.4 | $ | 12.2 | $ | 21.3 | $ | 24.1 | |||||||||
Past service costs (gains) | OM&G | (2.2 | ) | (2.1 | ) | (4.5 | ) | (2.8 | ) | |||||||||
Amounts reclassified into obligations | Pension and post-retirement liabilities | — | 23.5 | — | 23.5 | |||||||||||||
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Total before tax | 8.2 | 33.6 | 16.8 | 44.8 | ||||||||||||||
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Income tax expense (recovery) | 0.1 | (8.4 | ) | 0.1 | (9.1 | ) | ||||||||||||
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Total net of tax | $ | 8.3 | $ | 25.2 | $ | 16.9 | $ | 35.7 | ||||||||||
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Equity method reclassification adjustments | ||||||||||||||||||
Investments subject to significant influence | $ | 54.1 | $ | — | $ | 54.1 | $ | — | ||||||||||
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Total before tax | 54.1 | — | 54.1 | — | ||||||||||||||
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| |||||||||||
Deferred income taxes | (8.4 | ) | — | (8.4 | ) | — | ||||||||||||
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| |||||||||||
Total net of tax | $ | 45.7 | $ | — | $ | 45.7 | $ | — | ||||||||||
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| |||||||||||
Total reclassifications out of AOCI, net of tax, for the period | $ | 56.6 | $ | 27.2 | $ | 66.1 | $ | 36.6 | ||||||||||
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12. | INVESTMENT SECURITIES |
The Company has classified its investment securities as either available-for-sale or held-for-trading securities.
Available-for-sale securities
The available-for-sale securities of consist primarily of debt and equity investments held in trust on behalf of BLPC’s SIF for the purpose of building an insurance fund to cover risk against damage and consequential loss to certain of BLPC’s generating, transmission and distribution systems. Any withdrawal of SIF Fund assets by the Company would be subject to existing regulations.
Third party risk advisors were engaged to support a detailed risk analysis, which was completed to quantify the prudent assessment of the risk to BLPC’s transmission and distribution system from natural catastrophe. In June 2016 BLPC secured support from the Government of Barbados and the Trustees of the SIF to withdraw $65.0 million ($50.0 million USD) from the SIF (see note 7). The withdrawal is anticipated to be made in Q3 2016 and therefore Emera has reclassified $65.0 million ($50.0 million USD) available-for-sale investment securities from long-term to short-term.
In addition, these investment securities include available-for-sale debt and equity investments related to Emera Reinsurance Limited, for captive insurance purposes.
22
Held-for-trading securities
The held-for-trading securities include Emera’s 4.7 per cent investment in APUC (see note 6).
The investment securities discussed above are measured at fair value and classified in the fair value hierarchy as follows:
As at | June 30 | |||||||||||||||||||
millions of Canadian dollars | NAV (1) | Level 1 | Level 2 | Level 3 | 2016 | |||||||||||||||
Available-for-sale | ||||||||||||||||||||
Common shares | $ | — | $ | 16.2 | $ | — | $ | — | $ | 16.2 | ||||||||||
Corporate bonds, debentures, short and medium term notes | — | — | 40.5 | — | 40.5 | |||||||||||||||
Government bonds | — | — | 3.1 | — | 3.1 | |||||||||||||||
Other investments measured at NAV | 50.4 | — | — | — | 50.4 | |||||||||||||||
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$ | 50.4 | $ | 16.2 | 43.6 | $ | — | $ | 110.2 | ||||||||||||
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| |||||||||||
Held-for-trading | ||||||||||||||||||||
Common shares | — | 153.8 | — | — | 153.8 | |||||||||||||||
$ | — | $ | 153.8 | $ | — | $ | — | $ | 153.8 | |||||||||||
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| |||||||||||
Total investment securities | $ | 50.4 | $ | 170.0 | $ | 43.6 | $ | — | $ | 264.0 | ||||||||||
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| |||||||||||
As at | December 31 | |||||||||||||||||||
millions of Canadian dollars | NAV (1) | Level 1 | Level 2 | Level 3 | 2015 | |||||||||||||||
Available-for-sale | ||||||||||||||||||||
Common shares | $ | — | $ | 16.4 | $ | — | $ | — | $ | 16.4 | ||||||||||
Corporate bonds, debentures, short and medium term notes | — | — | 34.6 | — | 34.6 | |||||||||||||||
Government bonds | — | — | 11.7 | — | 11.7 | |||||||||||||||
Other investments measured at NAV | 53.3 | — | — | — | 53.3 | |||||||||||||||
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$ | 53.3 | $ | 16.4 | $ | 46.3 | $ | — | $ | 116.0 | |||||||||||
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Held-for-trading | ||||||||||||||||||||
Common shares | — | — | — | — | — | |||||||||||||||
$ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||
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| |||||||||||
Total investment securities | $ | 53.3 | $ | 16.4 | $ | 46.3 | $ | — | $ | 116.0 | ||||||||||
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(1) | Certain investments are permitted to be measured at fair value using the net asset value (“NAV”) per share under USGAAP accounting standards. |
The change in available-for-sale securities is as follows:
As at | June 30 | December 31 | ||||||
millions of Canadian dollars | 2016 | 2015 | ||||||
Balance, beginning of the year | $ | 116.0 | $ | 84.4 | ||||
Additions | 11.1 | 34.5 | ||||||
Disposals | (11.2 | ) | (16.5 | ) | ||||
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| |||||
$ | 115.9 | $ | 102.4 | |||||
|
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| |||||
Change in fair value | ||||||||
Gain (loss) recognized in other comprehensive income during the period | (5.7 | ) | 13.6 | |||||
$ | (5.7 | ) | $ | 13.6 | ||||
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|
| |||||
Balance, end of the period | $ | 110.2 | $ | 116.0 | ||||
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23
The change in held-for-trading securities is as follows:
As at | June 30 | December 31 | ||||||
millions of Canadian dollars | 2016 | 2015 | ||||||
Balance, beginning of the year | $ | — | $ | — | ||||
Additions (1) | 91.0 | — | ||||||
Unrealized (loss) gain recognized in income | 62.8 | — | ||||||
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Balance, end of the period | $ | 153.8 | $ | — | ||||
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(1) | Related to the reclassification of APUC common shares from “Investments Subject to Significant Influence” to “Investment Securities” as at June 30, 2016 (see note 6). |
There were no impairment provisions for available-for-sale or held-for-trading investment securities for the three or six months ended June 30, 2016 (2015 - nil).
The maturity profile of debt securities included in the available-for-sale securities is as follows:
As at | June 30 | December 31 | ||||||
millions of Canadian dollars | 2016 | 2015 | ||||||
Maturity within 1 year | $ | 8.1 | $ | 20.0 | ||||
Maturity in 1-5 years | 35.5 | 26.3 | ||||||
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$ | 43.6 | $ | 46.3 | |||||
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The maximum exposure to credit risk at the reporting date is the carrying value of the debt securities. None of these financial instruments are either past due or impaired.
13. | RECEIVABLES, NET |
Receivables, net consisted of the following:
As at | June 30 | December 31 | ||||||
millions of Canadian dollars | 2016 | 2015 | ||||||
Customer accounts receivable – billed | $ | 348.9 | $ | 406.3 | ||||
Customer accounts receivable – unbilled | 111.7 | 144.2 | ||||||
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Total customer accounts receivable | 460.6 | 550.5 | ||||||
Allowance for doubtful accounts | (12.2 | ) | (12.6 | ) | ||||
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Customer accounts receivable, net | 448.4 | 537.9 | ||||||
Other | 31.2 | 39.5 | ||||||
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$ | 479.6 | $ | 577.4 | |||||
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14. | INVENTORY |
Inventory consisted of the following:
As at | June 30 | December 31 | ||||||
millions of Canadian dollars | 2016 | 2015 | ||||||
Fuel | $ | 150.0 | $ | 185.3 | ||||
Materials | 94.8 | 100.4 | ||||||
Emission credits (1) | 21.0 | 28.6 | ||||||
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$ | 265.8 | $ | 314.3 | |||||
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(1) | The New England Gas Generating Facilities are subject to the Acid Rain Program for sulphur dioxide emissions and the Regional Greenhouse Gas Initiative (“RGGI”) for carbon dioxide emissions. The emissions credits inventory balance represents the credits purchased to offset the liabilities (notes 21 and 24) associated with these programs. |
24
15. | DERIVATIVE INSTRUMENTS |
The Company enters into futures, forwards, swaps and option contracts as part of its risk management strategy to limit exposure to:
• | commodity price fluctuations related to the purchase and sale of commodities in the course of normal operations; |
• | foreign exchange fluctuations on foreign currency denominated purchases and sales; and |
• | interest rate fluctuations on debt securities. |
The Company also enters into physical contracts for energy commodities. Collectively, these contracts are considered “derivatives”. The Company accounts for derivatives under one of the following four approaches:
1. | Physical contracts that meet the normal purchases normal sales (“NPNS”) exemption are not recognized on the balance sheet; they are recognized in income when they settle. A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. The Company continually assesses contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exception if the criteria are no longer met. |
2. | Derivatives that qualify for hedge accounting are recorded at fair value on the balance sheet. Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge the identified cash flow risk both at the inception and over the term of the derivative. Specifically for cash flow hedges, the effective portion of the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Any ineffective portion of the change in fair value from cash flow hedges is recognized in net income in the reporting period. |
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 NSPI and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at fair value on the balance sheet as derivative assets or liabilities. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes that any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. |
4. | Derivatives that do not meet any of the above criteria are designated as HFT derivatives and are recorded on the balance sheet at fair value, with changes normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply. |
25
Derivative assets and liabilities relating to the foregoing categories consisted of the following:
Derivative Assets | Derivative Liabilities | |||||||||||||||
As at | June 30 | December 31 | June 30 | December 31 | ||||||||||||
millions of Canadian dollars | 2016 | 2015 | 2016 | 2015 | ||||||||||||
Current | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power swaps | $ | 5.2 | $ | 7.9 | $ | 0.9 | $ | 0.5 | ||||||||
Foreign exchange forwards | 0.1 | — | 10.7 | 14.4 | ||||||||||||
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5.3 | 7.9 | 11.6 | 14.9 | |||||||||||||
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Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | 6.3 | — | 3.5 | 11.7 | ||||||||||||
Natural gas purchases and sales | 1.2 | 1.5 | 0.6 | 0.7 | ||||||||||||
Heavy fuel oil purchases | 1.8 | — | 10.0 | 20.5 | ||||||||||||
Foreign exchange forwards | 50.6 | 85.3 | 5.5 | 10.5 | ||||||||||||
Physical natural gas purchases and sales | 0.3 | 1.8 | — | — | ||||||||||||
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60.2 | 88.6 | 19.6 | 43.4 | |||||||||||||
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HFT derivatives | ||||||||||||||||
Power swaps and physical contracts | 33.8 | 150.8 | 38.7 | 118.5 | ||||||||||||
Natural gas swaps, futures, forwards, physical contracts | 69.4 | — | 125.2 | 358.8 | ||||||||||||
Foreign exchange options | 0.2 | 98.6 | 1.0 | 2.1 | ||||||||||||
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103.4 | 249.4 | 164.9 | 479.4 | |||||||||||||
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Other derivatives | ||||||||||||||||
Foreign exchange forwards | 3.5 | 92.1 | 12.7 | — | ||||||||||||
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3.5 | 92.1 | 12.7 | — | |||||||||||||
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Total gross current derivatives | 172.4 | 438.0 | 208.8 | 537.7 | ||||||||||||
Impact of master netting agreements with intent to settle net or simultaneously | (78.7 | ) | (188.5 | ) | (78.7 | ) | (188.5 | ) | ||||||||
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Total current derivatives | 93.7 | 249.5 | 130.1 | 349.2 | ||||||||||||
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Long-term | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power swaps | 5.7 | 11.6 | 3.2 | 4.1 | ||||||||||||
Foreign exchange forwards | 0.1 | 0.3 | 12.6 | 27.2 | ||||||||||||
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5.8 | 11.9 | 15.8 | 31.3 | |||||||||||||
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Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | 38.0 | — | — | 4.4 | ||||||||||||
Natural gas purchases and sales | 0.4 | — | 0.3 | — | ||||||||||||
Heavy fuel oil purchases | 3.5 | — | 8.0 | 16.6 | ||||||||||||
Foreign exchange forwards | 63.2 | 121.4 | — | — | ||||||||||||
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105.1 | 121.4 | 8.3 | 21.0 | |||||||||||||
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HFT derivatives | ||||||||||||||||
Power swaps and physical contracts | 15.2 | 12.9 | 24.7 | 28.2 | ||||||||||||
Natural gas swaps, futures, forwards and physical contracts | 23.3 | 72.3 | 49.8 | 62.6 | ||||||||||||
Foreign exchange options | 0.5 | 0.4 | 0.5 | 1.4 | ||||||||||||
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39.0 | 85.6 | 75.0 | 92.2 | |||||||||||||
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Other derivatives | ||||||||||||||||
Interest rate swap | — | — | 3.0 | 2.9 | ||||||||||||
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— | — | 3.0 | 2.9 | |||||||||||||
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Total gross long-term derivatives | 149.9 | 218.9 | 102.1 | 147.4 | ||||||||||||
Impact of master netting agreements with intent to settle net or simultaneously | (30.1 | ) | (51.3 | ) | (30.1 | ) | (51.3 | ) | ||||||||
Total long-term derivatives | 119.8 | 167.6 | 72.0 | 96.1 | ||||||||||||
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Total derivatives | $ | 213.5 | $ | 417.1 | $ | 202.1 | $ | 445.3 | ||||||||
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Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.
26
Details of master netting agreements, shown net on the Consolidated Balance Sheets, are summarized in the following table:
Derivative Assets | Derivative Liabilities | |||||||||||||||
As at | June 30 | December 31 | June 30 | December 31 | ||||||||||||
millions of Canadian dollars | 2016 | 2015 | 2016 | 2015 | ||||||||||||
Regulatory deferral | $ | — | $ | 0.1 | $ | — | $ | 0.1 | ||||||||
HFT derivatives | 108.8 | 239.7 | 108.8 | 239.7 | ||||||||||||
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Total impact of master netting agreements with intent to settle net or simultaneously | $ | 108.8 | $ | 239.8 | $ | 108.8 | $ | 239.8 | ||||||||
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Cash Flow Hedges
The Company enters into various derivatives designated as cash flow hedges. Emera enters into power swaps to limit Bear Swamp’s exposure to purchased power prices. Emera also enters into interest rate swaps to fix Bear Swamp’s cost of debt. The Company also enters into foreign exchange forwards to hedge the currency risk for revenue streams denominated in foreign currency for Brunswick Pipeline.
As previously noted, the effective portion of the change in fair value of these derivatives is included in AOCI, until the hedged transactions are recognized in income. The ineffective portion is recognized in income of the period. The amounts related to cash flow hedges recorded in income and AOCI consisted of the following:
For the | Three months ended June 30 | |||||||||||||||||||||||
millions of Canadian dollars | 2016 | 2015 | ||||||||||||||||||||||
Interest | Foreign | Interest | Foreign | |||||||||||||||||||||
Power | Rate | Exchange | Power | Rate | Exchange | |||||||||||||||||||
Swaps | Swaps | Forwards | Swaps | Swaps | Forwards | |||||||||||||||||||
Unrealized gain (loss) in non-regulated fuel for generation and purchased power – ineffective portion | $ | 0.5 | $ | — | $ | — | $ | 0.3 | $ | — | $ | — | ||||||||||||
Realized gain (loss) in non-regulated fuel for generation and purchased power | (0.9 | ) | — | — | (0.6 | ) | — | — | ||||||||||||||||
Realized gain (loss) in operating revenue – regulated | — | — | (1.9 | ) | — | — | (1.6 | ) | ||||||||||||||||
Realized gain (loss) in income from equity investments | — | (0.3 | ) | — | — | �� | (0.1 | ) | — | |||||||||||||||
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Total gains (losses) in net income | $ | (0.4 | ) | $ | (0.3 | ) | $ | (1.9 | ) | $ | (0.3 | ) | $ | (0.1 | ) | $ | (1.6 | ) | ||||||
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For the | Six months ended June 30 | |||||||||||||||||||||||
millions of Canadian dollars | 2016 | 2015 | ||||||||||||||||||||||
Interest | Foreign | Interest | Foreign | |||||||||||||||||||||
Power | Rate | Exchange | Power | Rate | Exchange | |||||||||||||||||||
Swaps | Swaps | Forwards | Swaps | Swaps | Forwards | |||||||||||||||||||
Unrealized gain (loss) in non-regulated fuel for generation and purchased power – ineffective portion | $ | (0.5 | ) | $ | — | $ | — | $ | (0.3 | ) | $ | — | $ | — | ||||||||||
Realized gain (loss) in non-regulated fuel for generation and purchased power | 3.3 | — | — | 5.0 | — | — | ||||||||||||||||||
Realized gain (loss) in operating revenue – regulated | — | — | (5.1 | ) | — | — | (3.7 | ) | ||||||||||||||||
Realized gain (loss) in income from equity investments | — | (0.6 | ) | — | — | (0.3 | ) | — | ||||||||||||||||
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Total gains (losses) in net income | $ | 2.8 | $ | (0.6 | ) | $ | (5.1 | ) | $ | 4.7 | $ | (0.3 | ) | $ | (3.7 | ) | ||||||||
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27
As at | June 30 | December 31 | ||||||||||||||||||||||
millions of Canadian dollars | 2016 | 2015 | ||||||||||||||||||||||
Interest | Foreign | Interest | Foreign | |||||||||||||||||||||
Power | Rate | Exchange | Power | Rate | Exchange | |||||||||||||||||||
Swaps | Swaps | Forwards | Swaps | Swaps | Forwards | |||||||||||||||||||
Total unrealized gain (loss) in AOCI – effective portion, net of tax | $ | 1.4 | $ | (0.8 | ) | $ | (23.0 | ) | $ | 3.5 | $ | (1.1 | ) | $ | (41.7 | ) | ||||||||
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The Company expects $23.9 million of unrealized losses currently in AOCI to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle.
As at June 30, 2016, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:
millions | 2016 | 2017 | 2018 | 2019 | 2020 | |||||||||||||||
Power swaps (megawatt hours (“MWh”)) purchases | 0.1 | 0.3 | — | — | — | |||||||||||||||
Foreign exchange forwards (USD) sales | $ | 26.9 | $ | 53.4 | $ | 44.8 | $ | 30.0 | $ | 30.0 | ||||||||||
Foreign exchange forwards (EURO) purchases | — | 2.6 | — | — | — |
Regulatory Deferral
As previously noted, NSPI and GBPC defer gains and losses on certain derivatives documented as economic hedges, including certain physical contracts that do not qualify for the NPNS exemption.
The Company has recorded the following changes in realized and unrealized gains (losses) with respect to derivatives receiving regulatory deferral:
For the | Three months ended June 30 | |||||||||||||||||||||||
millions of Canadian dollars | 2016 | 2015 | ||||||||||||||||||||||
Commodity swaps and forwards | Physical natural gas purchases and sales | Foreign exchange forwards | Commodity swaps and forwards | Physical natural gas purchases and sales | Foreign exchange forwards | |||||||||||||||||||
Unrealized gain (loss) in regulatory assets | $ | 14.1 | $ | — | $ | (1.2 | ) | $ | (6.5 | ) | $ | — | $ | 0.3 | ||||||||||
Unrealized gain (loss) in regulatory liabilities | 47.8 | (0.2 | ) | 2.6 | — | 1.8 | (15.9 | ) | ||||||||||||||||
Realized (gain) loss in regulatory assets | (1.7 | ) | — | 3.3 | (0.3 | ) | — | — | ||||||||||||||||
Realized (gain) loss in regulatory liabilities | — | — | (2.3 | ) | — | — | ||||||||||||||||||
Realized (gain) loss in inventory (1) | 3.4 | — | (10.6 | ) | 1.7 | — | (8.3 | ) | ||||||||||||||||
Realized (gain) loss in regulated fuel for generation and purchased power (2) | 5.1 | (0.3 | ) | (4.1 | ) | 1.2 | (2.3 | ) | (4.5 | ) | ||||||||||||||
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Total change in derivative instruments | $ | 68.7 | $ | (0.5 | ) | $ | (12.3 | ) | $ | (3.9 | ) | $ | (0.5 | ) | $ | (28.4 | ) | |||||||
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(1) | Realized (gains) losses will be recognized in regulated 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. |
28
For the | Six months ended June 30 | |||||||||||||||||||||||
millions of Canadian dollars | 2016 | 2015 | ||||||||||||||||||||||
Commodity swaps and forwards | Physical natural gas purchases and sales | Foreign exchange forwards | Commodity swaps and forwards | Physical natural gas purchases and sales | Foreign exchange forwards | |||||||||||||||||||
Unrealized gain (loss) in regulatory assets | $ | 18.1 | $ | — | $ | 1.7 | $ | (21.8 | ) | $ | — | $ | (2.4 | ) | ||||||||||
Unrealized gain (loss) in regulatory liabilities | 48.7 | (1.2 | ) | (44.5 | ) | (0.1 | ) | 6.5 | 76.7 | |||||||||||||||
Realized (gain) loss in regulatory assets | — | — | 3.3 | 0.7 | — | — | ||||||||||||||||||
Realized (gain) loss in regulatory liabilities | — | — | (2.3 | ) | — | — | — | |||||||||||||||||
Realized (gain) loss in inventory (1) | 3.4 | — | (32.8 | ) | 3.4 | — | (19.7 | ) | ||||||||||||||||
Realized (gain) loss in property, plant and equipment | — | — | —�� | — | — | (1.0 | ) | |||||||||||||||||
Realized (gain) loss in regulated fuel for generation and purchased power (2) | 11.0 | (0.3 | ) | (13.3 | ) | (2.5 | ) | (2.4 | ) | (8.6 | ) | |||||||||||||
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Total change in derivative instruments | $ | 81.2 | $ | (1.5 | ) | $ | (87.9 | ) | $ | (20.3 | ) | $ | 4.1 | $ | 45.0 | |||||||||
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(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 June 30, 2016, the Company had the following notional volumes of commodity swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below:
2016 | 2017-2020 | |||||||
millions | Purchases | Purchases | ||||||
Coal (metric tonnes) | 0.2 | 2.6 | ||||||
Natural Gas (mmbtu) | 1.8 | 10.9 | ||||||
Heavy fuel oil (bbls) | 0.5 | 1.4 |
Foreign Exchange Swaps and Forwards
As at June 30, 2016, the Company had the following notional volumes of foreign exchange swaps and forward contracts related to commodity contracts that are expected to settle as outlined below:
2016 | 2017-2019 | |||||||
Fuel purchases exposure (millions of US dollars) | $ | 102.0 | $ | 461.8 | ||||
Weighted average rate | 1.0465 | 1.0931 | ||||||
% of USD requirements | 115 | % | 84 | % |
29
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 | Six months ended | ||||||||||||||
millions of Canadian dollars | June 30 | June 30 | ||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Power swaps and physical contracts in non-regulated operating revenues | $ | 2.6 | $ | 2.5 | $ | (2.9 | ) | $ | 4.0 | |||||||
Natural gas swaps, forwards, futures, physical contracts in non-regulated operating revenues | 32.7 | 18.6 | 260.6 | 111.1 | ||||||||||||
Natural gas swaps, forwards, futures and physical contracts in non-regulated fuel for purchased power | 0.8 | 0.6 | 1.7 | (1.2 | ) | |||||||||||
Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power | 3.7 | (4.7 | ) | 2.1 | (2.7 | ) | ||||||||||
Foreign exchange options in non-regulated operating revenue | (0.2 | ) | (0.6 | ) | (1.0 | ) | (0.6 | ) | ||||||||
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$ | 39.6 | $ | 16.4 | $ | 260.5 | $ | 110.6 | |||||||||
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As at June 30, 2016, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:
millions | 2016 | 2017 | 2018 | 2019 | 2020 | |||||||||||||||
Natural gas purchases (Mmbtu) | 154.2 | 103.4 | 68.1 | 57.2 | 47.9 | |||||||||||||||
Natural gas sales (Mmbtu) | 111.7 | 57.1 | 9.3 | 8.3 | 4.4 | |||||||||||||||
Power purchases (MWh) | 3.5 | 1.8 | 0.5 | 0.5 | 0.3 | |||||||||||||||
Power sales (MWh) | 1.1 | 0.7 | 0.3 | 0.3 | 0.3 | |||||||||||||||
Foreign exchange options (USD) | $ | 9.5 | $ | 12.5 | $ | 4.1 | — | — | ||||||||||||
Foreign exchange forwards (EURO) purchases | — | 0.2 | — | — | — |
30
Other Derivatives
The Company has recognized the following realized and unrealized gains (losses) with respect to cash flow hedges which documentation requirements have not been met:
For the | Three months ended June 30 | |||||||||||||||
millions of Canadian dollars | 2016 | 2015 | ||||||||||||||
Interest | Foreign | Interest | Foreign | |||||||||||||
rate | exchange | rate | exchange | |||||||||||||
swaps | forwards | swaps | forwards | |||||||||||||
Unrealized gain (loss) in other income (expense) | $ | — | $ | (6.5 | ) | $ | — | $ | — | |||||||
Unrealized gain (loss) in interest expense, net | 0.2 | — | (1.9 | ) | — | |||||||||||
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Total gains (losses) in net income | $ | 0.2 | $ | (6.5 | ) | $ | (1.9 | ) | $ | — | ||||||
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For the | Six months ended June 30 | |||||||||||||||
millions of Canadian dollars | 2016 | 2015 | ||||||||||||||
Interest | Foreign | Interest | Foreign | |||||||||||||
rate | exchange | rate | exchange | |||||||||||||
swaps | forwards | swaps | forwards | |||||||||||||
Unrealized gain (loss) in other income (expense) | $ | — | $ | (101.3 | ) | $ | — | $ | — | |||||||
Unrealized gain (loss) in interest expense, net | (0.1 | ) | — | (1.9 | ) | — | ||||||||||
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Total gains (losses) in net income | $ | (0.1 | ) | $ | (101.3 | ) | $ | (1.9 | ) | $ | — | |||||
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As at June 30, 2016, the Company had interest rate swaps in place for the $250 million non-revolving term credit facility in Brunswick Pipeline for interest payments until the debt matures in 2019.
As at June 30, 2016, the Company had a foreign exchange forwards in place for $1,121.7 million USD in 2016 to economically hedge the proceeds from the Debenture Offering for the TECO Energy acquisition.
As at June 30, 2016, the Company had a foreign exchange forward and an offsetting foreign exchange swap in place for $397.3 million USD relating to proceeds from the sale of APUC common shares that were used to partially finance the TECO Energy acquisition.
Credit Risk
The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high risk accounts.
The Company assesses the potential for credit losses on a regular basis, and where appropriate, recognizes 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.
31
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 June 30, 2016, the Company had $88.9 million (December 31, 2015—$83.2 million) in financial assets, considered to be past due, which have been outstanding for an average 75 days. The fair value of these financial assets is $77.9 million (December 31, 2015 - $71.5 million), the difference of which is included in the allowance for doubtful accounts. These assets primarily relate to accounts receivable from electric revenue.
Cash Collateral
Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the fair value amounts of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables, net” and obligations to return cash collateral are recognized in “Accounts payable”.
The Company’s cash collateral positions consisted of the following:
As at | June 30 | December 31 | ||||||
millions of Canadian dollars | 2016 | 2015 | ||||||
Cash collateral provided to others | $ | 58.2 | $ | 106.9 | ||||
Cash collateral received from others | 28.3 | 28.5 |
Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain derivatives contain financial assurance provisions that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted in the senior unsecured debt to fall below investment grade, the counterparties to such derivatives could request ongoing full collateralization.
As at June 30, 2016, the total fair value of these derivatives, in a liability position, was $202.1 million (December 31, 2015 – $445.3 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.
16. | FAIR VALUE MEASUREMENTS |
The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exemption (see note 15), and uses a market approach to do so. The three levels of the fair value hierarchy are defined as follows:
Level 1 - Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities.
32
Level 2 - Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses.
Level 3 - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally-developed inputs. The primary reasons for a Level 3 classification are as follows:
• | While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials. |
• | The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term. |
• | The valuations of certain transactions were based on internal models, although quoted prices were utilized in the valuations. |
Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
33
The following tables set out the classification of the methodology used by the Company to fair value its derivatives:
As at | June 30, 2016 | |||||||||||||||
millions of Canadian dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power swaps | $ | 10.9 | $ | — | $ | — | $ | 10.9 | ||||||||
Foreign exchange forwards | — | 0.2 | — | 0.2 | ||||||||||||
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| |||||||||
10.9 | 0.2 | — | 11.1 | |||||||||||||
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| |||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | — | 44.3 | — | 44.3 | ||||||||||||
Natural gas purchases and sales | 1.6 | — | — | 1.6 | ||||||||||||
Heavy fuel oil purchases | 2.1 | 2.8 | 0.4 | 5.3 | ||||||||||||
Foreign exchange forwards | — | 113.8 | — | 113.8 | ||||||||||||
Physical natural gas purchases and sales | — | — | 0.3 | 0.3 | ||||||||||||
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| |||||||||
3.7 | 160.9 | 0.7 | 165.3 | |||||||||||||
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| |||||||||
HFT derivatives | ||||||||||||||||
Power swaps and physical contracts | (2.8 | ) | 0.9 | 3.4 | 1.5 | |||||||||||
Foreign exchange options | — | 0.7 | — | 0.7 | ||||||||||||
Natural gas swaps, futures, forwards, physical contracts and related transportation | 1.0 | 9.5 | 20.9 | 31.4 | ||||||||||||
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| |||||||||
(1.8 | ) | 11.1 | 24.3 | 33.6 | ||||||||||||
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| |||||||||
Other derivatives | ||||||||||||||||
Foreign exchange forwards | — | 3.5 | — | 3.5 | ||||||||||||
— | 3.5 | — | 3.5 | |||||||||||||
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| |||||||||
Total assets | 12.8 | 175.7 | 25.0 | 213.5 | ||||||||||||
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| |||||||||
Liabilities | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power swaps | 4.0 | — | — | 4.0 | ||||||||||||
Foreign exchange forwards | — | 23.3 | — | 23.3 | ||||||||||||
4.0 | 23.3 | — | 27.3 | |||||||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | — | 3.5 | — | 3.5 | ||||||||||||
Heavy fuel oil purchases | — | 18.0 | — | 18.0 | ||||||||||||
Natural gas purchases and sales | 0.2 | 0.7 | — | 0.9 | ||||||||||||
Foreign exchange forwards | 5.5 | — | 5.5 | |||||||||||||
0.2 | 27.7 | — | 27.9 | |||||||||||||
HFT derivatives | ||||||||||||||||
Power swaps and physical contracts | 11.6 | 0.9 | 3.4 | 15.9 | ||||||||||||
Foreign exchange options | — | 1.5 | — | 1.5 | ||||||||||||
Natural gas swaps, futures, forwards and physical contracts | 24.0 | (13.3 | ) | 103.1 | 113.8 | |||||||||||
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| |||||||||
35.6 | (10.9 | ) | 106.5 | 131.2 | ||||||||||||
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| |||||||||
Other derivatives | ||||||||||||||||
Foreign exchange forwards | — | 12.7 | — | 12.7 | ||||||||||||
Interest rate swap | — | 3.0 | — | 3.0 | ||||||||||||
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| |||||||||
— | 15.7 | — | 15.7 | |||||||||||||
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| |||||||||
Total liabilities | 39.8 | 55.8 | 106.5 | 202.1 | ||||||||||||
|
|
|
|
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|
|
| |||||||||
Net assets (liabilities) | $ | (27.0 | ) | $ | 119.9 | $ | (81.5 | ) | $ | 11.4 | ||||||
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34
As at | December 31, 2015 | |||||||||||||||
millions of Canadian dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power swaps | $ | 19.5 | $ | — | $ | — | $ | 19.5 | ||||||||
Foreign exchange forwards | — | 0.3 | — | 0.3 | ||||||||||||
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| |||||||||
19.5 | 0.3 | — | 19.8 | |||||||||||||
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| |||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | — | 1.4 | — | 1.4 | ||||||||||||
Foreign exchange forwards | — | 206.7 | — | 206.7 | ||||||||||||
Physical natural gas purchases and sales | — | — | 1.8 | 1.8 | ||||||||||||
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— | 208.1 | 1.8 | 209.9 | |||||||||||||
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| |||||||||
HFT derivatives | ||||||||||||||||
Power swaps and physical contracts | 38.3 | — | (7.8 | ) | 30.5 | |||||||||||
Foreign exchange forwards | — | 0.4 | — | 0.4 | ||||||||||||
Natural gas swaps, futures, forwards and physical contracts | (0.3 | ) | 7.9 | 56.8 | 64.4 | |||||||||||
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38.0 | 8.3 | 49.0 | 95.3 | |||||||||||||
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Other derivatives | ||||||||||||||||
Foreign exchange forwards | — | 92.1 | — | 92.1 | ||||||||||||
— | 92.1 | — | 92.1 | |||||||||||||
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|
| |||||||||
Total assets | 57.5 | 308.8 | 50.8 | 417.1 | ||||||||||||
|
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| |||||||||
Liabilities | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power swaps | $ | 4.6 | $ | — | $ | — | $ | 4.6 | ||||||||
Foreign exchange forwards | — | 41.6 | — | 41.6 | ||||||||||||
4.6 | 41.6 | — | 46.2 | |||||||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | — | 16.1 | — | 16.1 | ||||||||||||
Natural gas purchases and sales | 0.6 | — | — | 0.6 | ||||||||||||
Heavy fuel oil purchases | — | 37.1 | — | 37.1 | ||||||||||||
Foreign exchange forwards | — | 10.5 | — | 10.5 | ||||||||||||
0.6 | 63.7 | — | 64.3 | |||||||||||||
HFT derivatives | ||||||||||||||||
Power swaps and physical contracts | 15.2 | — | (2.0 | ) | 13.2 | |||||||||||
Foreign exchange options | — | 3.5 | — | 3.5 | ||||||||||||
Natural gas swaps, futures, forwards and physical contracts | 14.4 | 22.0 | 278.8 | 315.2 | ||||||||||||
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| |||||||||
29.6 | 25.5 | 276.8 | 331.9 | |||||||||||||
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| |||||||||
Other derivatives | ||||||||||||||||
Interest rate swaps | — | 2.9 | — | 2.9 | ||||||||||||
— | 2.9 | — | 2.9 | |||||||||||||
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| |||||||||
Total liabilities | 34.8 | 133.7 | 276.8 | 445.3 | ||||||||||||
|
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|
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|
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|
| |||||||||
Net assets (liabilities) | $ | 22.7 | $ | 175.1 | $ | (226.0 | ) | $ | (28.2 | ) | ||||||
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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 six months ended June 30, 2016, there were no transfers between levels.
35
The change in the fair value of the Level 3 financial assets for the three months ended June 30, 2016 was as follows:
Regulatory Deferral | HFT Derivatives | |||||||||||||||||||
millions of Canadian dollars | Physical natural gas purchases and sales | Heavy fuel oil purchases | Power Swaps | Natural gas | Total | |||||||||||||||
Balance, beginning of period | $ | 0.8 | $ | — | $ | 4.8 | $ | 20.5 | $ | 26.1 | ||||||||||
Increase (reduction) in benefit included in regulated fuel for generation and purchased power | (0.3 | ) | — | — | — | (0.3 | ) | |||||||||||||
Unrealized gains (losses) included in regulatory assets or liabilities | (0.2 | ) | 0.4 | — | — | 0.2 | ||||||||||||||
Total realized and unrealized gains (losses) included in non-regulated operating revenues | — | — | (1.4 | ) | 0.4 | (1.0 | ) | |||||||||||||
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| |||||||||||
Balance, June 30, 2016 | $ | 0.3 | $ | 0.4 | $ | 3.4 | $ | 20.9 | $ | 25.0 | ||||||||||
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The change in the fair value of the Level 3 financial liabilities for the three months ended June 30, 2016 was as follows:
HFT Derivatives | ||||||||||||
millions of Canadian dollars | Power | Natural gas | Total | |||||||||
Balance, beginning of period | $ | 4.6 | $ | 96.0 | $ | 100.6 | ||||||
Total realized and unrealized gains (losses) included in non-regulated operating revenues | (1.2 | ) | 7.1 | 5.9 | ||||||||
|
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| |||||||
Balance, June 30, 2016 | $ | 3.4 | $ | 103.1 | $ | 106.5 | ||||||
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The change in the fair value of the Level 3 financial assets for the six months ended June 30, 2016 was as follows:
Regulatory Deferral | HFT Derivatives | |||||||||||||||||||
millions of Canadian dollars | Physical natural gas purchases and sales | Heavy fuel oil purchases | Power | Natural gas | Total | |||||||||||||||
Balance, beginning of period | $ | 1.8 | $ | — | $ | (7.8 | ) | $ | 56.8 | $ | 50.8 | |||||||||
Increase (reduction) in benefit included in regulated fuel for generation and purchased power | (0.3 | ) | — | — | — | (0.3 | ) | |||||||||||||
Unrealized gains (losses) included in regulatory assets or liabilities | (1.2 | ) | 0.4 | — | — | (0.8 | ) | |||||||||||||
Total realized and unrealized gains (losses) included in non-regulated operating revenues | — | — | 11.2 | (35.9 | ) | (24.7 | ) | |||||||||||||
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| |||||||||||
Balance, June 30, 2016 | $ | 0.3 | $ | 0.4 | $ | 3.4 | $ | 20.9 | $ | 25.0 | ||||||||||
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The change in the fair value of the Level 3 financial liabilities for the six months ended June 30, 2016 was as follows:
HFT Derivatives | ||||||||||||
millions of Canadian dollars | Power | Natural gas | Total | |||||||||
Balance, beginning of period | $ | (2.0 | ) | $ | 278.8 | $ | 276.8 | |||||
Total realized and unrealized gains (losses) included in non-regulated operating revenues | 5.4 | (175.7 | ) | (170.3 | ) | |||||||
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| |||||||
Balance, June 30, 2016 | $ | 3.4 | $ | 103.1 | $ | 106.5 | ||||||
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36
Emera’s Enterprise Risk Management group is responsible for valuation policies, processes and the measurement of fair value. Fair value accounting rules provide a three level hierarchy that prioritizes the inputs used to measure fair value. When possible, determining fair value is based primarily on observable market inputs in active markets.
Contracts with quoted prices available in active markets and exchanges for identical assets or liabilities are classified as level 1 in the hierarchy. For those contracts whereby pricing inputs are either directly or indirectly observable through markets, exchanges or third party sources, but do not qualify as level 1, are classified as level 2 in the hierarchy. For a level 3 classification, the processes and methods of measurement for third-party pricing information and illiquid markets are developed with input and using the market knowledge of the trading operations within Emera and its affiliates.
Significant unobservable inputs used in the fair value measurement of Emera’s natural gas and power derivatives includes third-party-sourced pricing for instruments based on illiquid markets; internally developed correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid term markets. Where possible, Emera also sources multiple broker prices in an effort to evaluate and substantiate these unobservable inputs. Discount rates may include a risk premium for those long-term forward contracts with illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing similar industry practices and in discussion with industry peers. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement.
37
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:
June 30, 2016 | ||||||||||||||||||
As at millions of Canadian dollars | Fair Value | Valuation Technique | Unobservable Input | Range | Weighted average | |||||||||||||
Assets | ||||||||||||||||||
Regulatory deferral – Physical natural gas purchases and sales | $ | 0.3 | Modelled pricing | Third-party pricing | $ | 4.75 - $4.94 | $ | 4.87 | ||||||||||
Probability of default | 0.01 | % | 0.01 | % | ||||||||||||||
Regulatory deferral – Financial heavy fuel oil purchases | 0.4 | Modelled pricing | Third-party pricing | $ | 52.63 - $53.02 | $ | 52.82 | |||||||||||
Probability of default | 0.03 | % | 0.03 | % | ||||||||||||||
HFT derivatives – Power swaps and physical contracts | 3.4 | Modelled pricing | Third-party pricing | $ | 22.00 - $82.13 | $ | 38.00 | |||||||||||
Probability of default | 0.00% - 0.02 | % | — | |||||||||||||||
Discount rate | 0.02% - 0.09 | % | 0.03 | % | ||||||||||||||
HFT derivatives – Natural gas swaps, futures, forwards, physical contracts and related transportation | 14.5 | Modelled pricing | Third-party pricing | $ | 1.80 - $9.27 | $ | 3.25 | |||||||||||
Probability of default | 0.00% - 0.03 | % | 0.00 | % | ||||||||||||||
Discount rate | 0.00% - 0.23 | % | 0.03 | % | ||||||||||||||
6.4 | Modelled pricing | Third-party pricing | $ | 1.80 - $9.18 | $ | 3.34 | ||||||||||||
Basis adjustment | -0.12% -0.65 | % | 0.35 | % | ||||||||||||||
Probability of default | 0.00% - 0.01 | % | 0.00 | % | ||||||||||||||
Discount rate | 0.00% - 0.06 | % | 0.00 | % | ||||||||||||||
|
| |||||||||||||||||
Total assets | 25.0 | |||||||||||||||||
|
| |||||||||||||||||
Liabilities | ||||||||||||||||||
HFT derivatives – Power swaps and physical contracts | $ | 3.3 | Modelled pricing | Third-party pricing | $ | 22.00 - $82.13 | $ | 38.05 | ||||||||||
Own credit risk | 0.00% - 0.01 | % | 0.01 | % | ||||||||||||||
Discount rate | 0.02% - 0.09 | % | 0.03 | % | ||||||||||||||
0.1 | Modelled pricing | Third-party pricing | $ | 21.28 - $43.95 | $ | 32.18 | ||||||||||||
Correlation factor | 1.00% - $1.01 | % | 1.01 | % | ||||||||||||||
Own credit risk | 0.00% - 0.00 | % | 0.00 | % | ||||||||||||||
Discount rate | 0.00% - 0.01 | % | 0.01 | % | ||||||||||||||
HFT derivatives – Natural gas swaps, futures, forwards and physical contracts | 77.0 | Modelled pricing | Third-party pricing | $ | 1.48 - $9.27 | $ | 3.75 | |||||||||||
Own credit risk | 0.00% - 0.09 | % | 0.00 | % | ||||||||||||||
Discount rate | 0.00% - 0.07 | % | 0.01 | % | ||||||||||||||
26.1 | Modelled pricing | Third-party pricing | $ | 1.63 - $9.11 | $ | 3.18 | ||||||||||||
Basis adjustment | -0.12% - 0.65 | % | 0.09 | % | ||||||||||||||
Probability of default | 0.00% - 0.07 | % | 0.00 | % | ||||||||||||||
Discount rate | 0.00% - 0.06 | % | 0.01 | % | ||||||||||||||
|
| |||||||||||||||||
Total liabilities | 106.5 | |||||||||||||||||
|
| |||||||||||||||||
Net assets (liabilities) | $ | (81.5 | ) | |||||||||||||||
|
|
The financial assets and liabilities included on the Consolidated Balance Sheets that are not measured at fair value consisted of the following:
June 30, 2016 | ||||||||||||||||||||||||
As at millions of Canadian dollars | Carrying Amount | Fair Value | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||
Long-term debt (including current portion) | $ | 9,878.6 | $ | 10,775.4 | $ | — | $ | 10,160.1 | $ | 615.3 | $ | 10,775.4 | ||||||||||||
December 31, 2015 | ||||||||||||||||||||||||
As at millions of Canadian dollars | Carrying Amount | Fair Value | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||
Long-term debt (including current portion) | $ | 4,008.6 | $ | 4,486.7 | $ | — | $ | 3,841.3 | $ | 645.4 | $ | 4,486.7 |
The fair values of long-term debt instruments, classified as level 2 in the fair value hierarchy, are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturity.
38
The fair values of long-term debt instruments, classified as level 3 in the fair value hierarchy, are determined by discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds with similar terms to maturity, plus a credit risk premium equal to that of issuers of similar credit quality.
All other financial assets and liabilities, such as cash and cash equivalents, restricted cash, accounts receivable, short-term debt and accounts payable, are carried at cost. The carrying value approximates fair value due to the short-term nature of these financial instruments.
17. | REGULATORY ASSETS AND LIABILITIES |
A summary of the Company’s regulatory assets and liabilities is provided below. For a detailed description of the nature of the Company’s regulatory assets and liabilities, refer to Note 17 in Emera’s 2015 annual audited consolidated financial statements.
As at | June 30 | December 31 | ||||||
millions of Canadian dollars | 2016 | 2015 | ||||||
Regulatory assets | ||||||||
Deferred income tax regulatory assets | $ | 485.1 | $ | 431.3 | ||||
Unamortized defeasance costs | 42.4 | 45.7 | ||||||
2015 Demand side management deferral (note 5) | 34.7 | 36.4 | ||||||
Deferrals related to derivative instruments | 27.9 | 67.7 | ||||||
Stranded cost recovery | 27.2 | 28.5 | ||||||
Pension and post-retirement medical plan | 10.6 | 11.9 | ||||||
Hydro-Quebec obligation | 6.9 | 7.6 | ||||||
2014 Maine storms | 5.9 | 6.1 | ||||||
Asset impairment recovery | 5.1 | 5.5 | ||||||
Purchased power contracts | 4.4 | 5.9 | ||||||
Stranded cost revenue & purchase power reconciliation deferrals | 3.7 | 6.1 | ||||||
Regulated fuel adjustment mechanism (note 5) | 1.5 | 13.7 | ||||||
Other | 29.4 | 33.1 | ||||||
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| |||||
$ | 684.8 | $ | 699.5 | |||||
|
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|
| |||||
Current | $ | 52.3 | $ | 94.2 | ||||
Long-term | 632.5 | 605.3 | ||||||
|
|
|
| |||||
Total regulatory assets | $ | 684.8 | $ | 699.5 | ||||
|
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|
| |||||
Regulatory liabilities | ||||||||
Deferrals related to derivative instruments | $ | 164.9 | $ | 209.9 | ||||
Regulated fuel adjustment mechanism (note 5) | 73.3 | 42.0 | ||||||
Self-Insurance Fund (notes 7 and 12) | 28.6 | 86.8 | ||||||
Deferred income tax regulatory liabilities | 16.1 | 17.6 | ||||||
Other | 11.6 | 14.3 | ||||||
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$ | 294.5 | $ | 370.6 | |||||
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Current | $ | 70.0 | $ | 98.9 | ||||
Long-term | 224.5 | 271.7 | ||||||
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Total regulatory liabilities | $ | 294.5 | $ | 370.6 | ||||
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18. | RELATED PARTY TRANSACTIONS |
In the ordinary course of business, Emera provides energy, construction and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Inter-company balances and inter-company transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-regulated operating revenues, with an offset to property, plant and equipment, regulated fuel for generation and purchased power, or operating, maintenance and general, depending on the nature of the transaction. Below are transactions between Emera and its associated companies reported in the Consolidated Statements of Income:
For the | Three months ended | Six months ended | ||||||||||||||||||
millions of Canadian dollars | June 30 | June 30 | ||||||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||||||
Nature of Service | Presentation | |||||||||||||||||||
Sales: | ||||||||||||||||||||
APUC subsidiary (1) | Net sale of natural gas and transportation | Operating revenue –non-regulated | $ | 0.4 | $ | — | $ | 2.4 | $ | 1.7 | ||||||||||
Purchases: | ||||||||||||||||||||
M&NP | Natural gas transportation capacity | Regulated fuel for generation and purchased power | 1.0 | 1.8 | 1.3 | 2.0 | ||||||||||||||
M&NP | Natural gas transportation capacity | Operating revenue –non-regulated | (6.9 | ) | (5.0 | ) | (15.0 | ) | (11.3 | ) |
(1) | APUC subsidiary related party transactions includes transactions until May 24, 2016, when APUC ceased being a related party. |
Operating revenue – non-regulated includes intercompany profit relating to the sale of natural gas, sale of power, construction, operations management and engineering services, and hedging services to rate-regulated subsidiaries of Emera totaling $0.3 million for the three months ended June 30, 2016 (2015 – $(0.4) million) and $0.5 million for the six months ended June 30, 2016 (2015 – $(0.6) million).
Amounts reported on Emera’s Consolidated Balance Sheets due (to) from its equity investments are summarized in the following table:
As at | June 30 | December 31 | ||||||
millions of Canadian dollars | 2016 | 2015 | ||||||
Due from related parties: | ||||||||
NSPML – current | $ | 1.7 | $ | 1.6 | ||||
Subsidiary of APUC – current | — | 0.7 | ||||||
M&NP – loan receivable – long-term | 2.5 | 2.5 | ||||||
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Due to related parties: | ||||||||
M&NP – current | 1.9 | 2.1 | ||||||
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Net due from (to) related parties | $ | 2.3 | $ | 2.7 | ||||
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All amounts are under normal interest and credit terms, except for a loan receivable from M&NP bearing interest at 1 per cent per annum maturing on November 30, 2019.
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19. | OTHER CURRENT ASSETS |
Other current assets consisted of the following:
As at millions of Canadian dollars | June 30 2016 | December 31 2015 | ||||||
Net investment in direct financing lease | $ | 5.1 | $ | 5.4 | ||||
Dividend receivable | 1.8 | 6.7 | ||||||
Capitalized transportation capacity (1) | 95.3 | 222.7 | ||||||
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$ | 102.2 | $ | 234.8 | |||||
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(1) | Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract. |
20. | EMPLOYEE BENEFIT PLANS |
Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees; and plans providing non-pension benefits for its retirees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Maine, Connecticut, Massachusetts, Rhode Island, Barbados, Dominica and Grand Bahama Island.
Net periodic costs prior to the effects of capitalization consisted of the following:
For the millions of Canadian dollars | Three months ended June 30 | Six months ended June 30 | ||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Defined benefit pension plans | ||||||||||||||||
Service cost | $ | 5.4 | $ | 5.5 | $ | 10.9 | $ | 11.0 | ||||||||
Interest cost | 15.0 | 14.6 | 30.1 | 29.2 | ||||||||||||
Expected return on plan assets | (16.6 | ) | (16.1 | ) | (33.4 | ) | (32.1 | ) | ||||||||
Current year amortization of: | ||||||||||||||||
Actuarial losses (gains) | 10.4 | 11.8 | 20.9 | 23.6 | ||||||||||||
Past service costs (gains) | (0.2 | ) | (0.2 | ) | (0.4 | ) | (0.4 | ) | ||||||||
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Total defined benefit pension plans | 14.0 | 15.6 | 28.1 | 31.3 | ||||||||||||
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Non-pension benefits plan | ||||||||||||||||
Service cost | 0.7 | 0.7 | 1.4 | 1.5 | ||||||||||||
Interest cost | 0.8 | 0.8 | 1.7 | 1.8 | ||||||||||||
Expected return on plan assets | (0.1 | ) | (0.1 | ) | (0.2 | ) | (0.1 | ) | ||||||||
Current year amortization of: | ||||||||||||||||
Actuarial losses (gains) | 0.5 | 0.4 | 1.0 | 0.7 | ||||||||||||
Past service costs (gains) | (2.0 | ) | (1.9 | ) | (4.1 | ) | (2.4 | ) | ||||||||
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Total non-pension benefits plans | (0.1 | ) | (0.1 | ) | (0.2 | ) | 1.5 | |||||||||
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Total defined benefit plans | $ | 13.9 | $ | 15.5 | $ | 27.9 | $ | 32.8 | ||||||||
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21. | OTHER CURRENT LIABILITIES |
Other current liabilities consisted of the following:
As at millions of Canadian dollars | June 30 2016 | December 31 2015 | ||||||
Accrued charges | $ | 112.4 | $ | 130.1 | ||||
Accrued interest on long-term debt | 51.9 | 44.1 | ||||||
Sales and other taxes payable | 29.3 | 4.2 | ||||||
Accrued interest on convertible debentures represented by instalment receipts (note 8) | 37.1 | 11.2 | ||||||
Emission credits obligations (1) | 3.7 | 6.3 | ||||||
Other | 7.0 | 8.4 | ||||||
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$ | 241.4 | $ | 204.3 | |||||
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(1) | Throughout the three-year compliance period associated with the Regional Greenhouse Gas Initiative for carbon dioxide emissions, an obligation is recognized as gas is burned, measured at the cost to acquire credits for the related emissions. Emission credits are capitalized to inventory (note 14) when purchased and subsequently applied against the emission liabilities at the end of each compliance period. |
22. | LONG-TERM DEBT |
U.S. Notes
On June 16, 2016, Emera US Finance LP, a limited partnership financing subsidiary, wholly owned directly and indirectly by Emera, completed the issuance of $3.25 billion USD senior unsecured notes (“U.S. Notes”). The U.S. Notes are guaranteed by Emera and Emera US Holdings Inc., a wholly owned Emera subsidiary. The U.S. notes bear interest semi-annually, in arrears, on June 15 and December 15 of each year, commencing on December 15, 2016. The U.S. notes will not be listed on a securities exchange. The U.S. notes issued are described below:
$500,000,000 USD three year, 2.15 per cent Notes due 2019
$750,000,000 USD five year 2.70 per cent Notes due 2021
$750,000,000 USD ten year 3.55 per cent Notes due 2026
$1,250,000,000 USD 30 year 4.75 per cent Notes due 2046
Hybrid Notes
On June 16, 2016, Emera completed the issuance of $1.2 billion USD unsecured, fixed-to-floating subordinated notes (“Hybrid Notes”). The Hybrid Notes will mature on June 15, 2076. Emera will pay interest on the Hybrid Notes at a fixed rate of 6.75 per cent per year in equal semi-annual instalments on June 15 and December 15 of each year until June 15, 2026. Starting on June 15, 2026, and on every quarter thereafter that the Hybrid Notes are outstanding until their maturity on June 15, 2076 (the “Interest Reset Date”), the interest rate on the Hybrid Notes will be reset.
Beginning on June 15, 2026, and on every Interest Reset Date until June 15, 2046, the Hybrid Notes will be reset at an interest rate of the three month LIBOR plus 5.44 per cent, payable in arrears. Beginning on June 15, 2046, and on every Interest Reset Date until June 15, 2076, the Hybrid Notes will be reset at an interest rate of the three-month LIBOR plus 6.19 per cent, payable in arrears.
Emera may elect, at its sole option, to defer the interest payable on the Hybrid Notes on one or more occasions for up to five consecutive years. Deferred interest will accrue, compounding on each subsequent interest payment date, until paid. Additionally, on or after June 15, 2026, Emera may, at its option, redeem the Hybrid Notes, at a redemption price equal to 100 per cent of the principal amount, together with accrued and unpaid interest.
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Canadian Notes
On June 16, 2016, Emera completed the issuance of $500 million senior unsecured notes (“Canadian Notes”). The Canadian Notes were issued with a seven-year term to maturity and bear interest at a rate of 2.90 per cent. The notes will bear interest semi-annually in arrears on June 16 and December 16 of each year, commencing on December 16, 2016. The Canadian Notes will not be listed on a securities exchange.
The proceeds of the U.S. Notes, Hybrid Notes and Canadian Notes offerings were used to partially finance the purchase price for the Acquisition. Proceeds of the offerings, not otherwise required to complete the Acquisition, have been used for general corporate purposes.
As at June 30, 2016, the carrying value of the U.S., Hybrid, and Canadian Notes issued amounted to $6,210 million, and was recorded in “Long-term debt” on the Consolidated Balance Sheets.
NSPI
On April 28, 2016, NSPI increased its committed syndicated revolving bank line of credit to $600 million from $500 million. The increase will support ongoing business requirements and general corporate purposes.
On May 27, 2016, NSPI increased its commercial paper program to $500 million from $400 million, of which the full amount outstanding is backed by NSPI’s operating credit facility referred to above. The amount of commercial paper issued results in an equal amount of its operating credit facility being considered drawn and unavailable.
23. | CONVERTIBLE DEBENTURES REPRESENTED BY INSTALMENT RECEIPTS |
On September 28, 2015, to finance a portion of the acquisition of TECO Energy, Emera, through a direct wholly owned subsidiary (the “Selling Debentureholder”) completed the sale of $1.9 billion aggregate principal amount of 4.0 per cent convertible unsecured subordinated debentures, represented by instalment receipts. On October 2, 2015, in connection with the Debenture Offering, the underwriters fully exercised an over-allotment option and purchased an additional $285 million aggregate principal amount of Debentures at the Debenture Offering price. The sale of the additional Debentures brought the aggregate proceeds of the Debenture Offering to $2.185 billion.
The Debentures were sold on an instalment basis at a price of $1,000 per Debenture, of which $333 (the “First Instalment”) was paid on closing of the Debenture Offerings on September 28, 2015 and October 2, 2015, and the remaining $667 (the “Final Instalment”) is payable on August 2, 2016 (the “Final Instalment Date”). Prior to the Final Instalment Date, the Debentures were represented by instalment receipts. The instalment receipts traded on the Toronto Stock Exchange (“TSX”) from September 28, 2015 to August 2, 2016 under the symbol “EMA.IR”.
The proceeds of the first instalment and the over-allotment of the Debentures were $727.6 million ($681.4 million net of issue costs) and the proceeds of the final instalment payment were $1.457 billion ($1.414 billion net of issue costs), which were used to finance, directly and indirectly, the acquisition of TECO Energy (note 31).
The Debentures are not listed on the TSX and will mature on September 29, 2025. They bear interest at an annual rate of 4 per cent per $1,000 principal amount of Debentures until and including the Final Instalment Date, after which the interest rate is 0 per cent. At the option of the holders, each fully paid Debenture is convertible into common shares of Emera at any time after the Final Instalment Date, but prior to the earlier of maturity or redemption by the Company, at a conversion price of $41.85 per common share. This is a conversion rate of 23.8949 common shares per $1,000 principal amount of Debentures.
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Final Instalment Notice, Interest and Make Whole Payment
Final Instalment Notice was issued by Emera on June 29, 2016 with a payable date of August 2, 2016. As a result, the Company recorded a $1.457 billion short term receivable from the debenture holders and a corresponding increase in the long-term Convertible Debentures liability in Q2 2016.
As the Final Instalment Date will occur prior to the first anniversary of the closing of the Debenture Offering, holders of the convertible debentures who pay the final instalment by August 2, 2016 will receive, in addition to the payment of accrued and unpaid interest, a make-whole payment, representing the interest that would have accrued from the day following the Final Instalment Date up to and including September 28, 2016. Recorded in the three months ended June 30, 2016 is $42.8 million ($29.5 million after-tax) in interest expense, including the $21.0 million ($14.5 million after-tax) make-whole payment, associated with the Debentures. For the six months ending June 30, 2016 Emera recorded $64.7 million ($44.6 million after-tax) of interest expense related to the Convertible Debentures (note 8).
Beneficial Conversion Feature
The Company recognized the difference between Emera’s closing share price on the issuance date of the Debentures and their exercise price (the “Beneficial Conversion Feature discount”) in June 2016 when the regulatory approval contingencies associated with the Acquisition were resolved. This non-cash discount is netted against the Convertible Debentures liability, with a corresponding offset to Contributed Surplus. The Beneficial Conversion Feature discount was $62.3 million ($42.9 million after-tax) as at June 30, 2016.
Until the Debentures are converted to equity, the Beneficial Conversion Feature discount will be amortized as a component of Interest expense, net over the remaining term of the Debentures. Emera recognized interest expense associated with amortizing the Beneficial Conversion Feature of $0.1 million in the three month period ended June 30, 2016. When the Convertible Debentures are converted to common equity, the remaining unamortized Beneficial Conversion Feature discount will be expensed, in its entirety, as component of Interest expense, net. This is expected to occur in Q3 2016.
Conversion of Convertible Debentures
As at August 3, 2016, approximately 50.5 million common shares of Emera were issued, representing conversion into common shares of approximately 97 per cent of the convertible debentures. After the Final Instalment Date of August 2, 2016, debentures not converted may be redeemed by Emera at a price equal to their principal amount. At maturity, Emera has the right to pay the principal amount due in common shares to the debenture holders that have not converted, which will be valued at 95 per cent of the weighted average trading price on the TSX for the 20 consecutive trading days ending five trading days preceding the maturity date.
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24. | OTHER LONG-TERM LIABILITIES |
Other long-term liabilities consisted of the following:
As at millions of Canadian dollars | June 30 2016 | December 31 2015 | ||||||
Funds received in excess of equity investment (1) | $ | 207.9 | $ | 225.0 | ||||
Long-term service agreements | 30.4 | 37.7 | ||||||
Emission credits obligations (2) | 9.6 | 6.3 | ||||||
Other | 27.0 | 29.5 | ||||||
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$ | 274.9 | $ | 298.5 | |||||
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(1) | Emera has a 50 per cent investment in Bear Swamp. The investment balance in Bear Swamp is in a credit position primarily a result of a $178.7 million distribution received in Q4 2015. |
(2) | Throughout the three-year compliance period associated with the Regional Greenhouse Gas Initiative (“RGGI”) for carbon dioxide emissions, an obligation is recognized as gas is burned, measured at the cost to acquire credits for the related emissions. Emission credits are capitalized to inventory (note 14) when purchased and subsequently applied against the emission liabilities at the end of each compliance period. |
25. | COMMITMENTS AND CONTINGENCIES |
A. | Commitments |
As at June 30, 2016, contractual commitments (excluding pensions and other post-retirement obligations, convertible debentures represented by instalment receipts, long-term debt and AROs) for each of the next five years and in aggregate thereafter consisted of the following:
millions of Canadian dollars | 2016 | 2017 | 2018 | 2019 | 2020 | Thereafter | Total | |||||||||||||||||||||
Purchased power (1) | $ | 113.0 | $ | 231.4 | $ | 205.7 | $ | 200.4 | 197.1 | $ | 2,423.5 | $ | 3,371.1 | |||||||||||||||
Solid fuel supply | 81.1 | 93.3 | 23.9 | 13.4 | — | — | 211.7 | |||||||||||||||||||||
DSM | 14.9 | 26.9 | 34.9 | — | — | — | 76.7 | |||||||||||||||||||||
Transportation (2) | 119.6 | 122.4 | 78.2 | 42.7 | 44.4 | 88.6 | 495.9 | |||||||||||||||||||||
Long-term service agreements (3) | 38.3 | 51.7 | 36.8 | 58.0 | 22.4 | 226.1 | 433.3 | |||||||||||||||||||||
Capital projects | 57.8 | 7.6 | — | — | — | — | 65.4 | |||||||||||||||||||||
Equity investment commitments (4) | 350.0 | 376.9 | — | — | — | — | 726.9 | |||||||||||||||||||||
Leases and other (5) | 6.6 | 21.8 | 9.3 | 8.7 | 7.3 | 16.5 | 70.2 | |||||||||||||||||||||
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$ | 781.3 | $ | 932.0 | $ | 388.8 | $ | 323.2 | $ | 271.2 | $ | 2,754.7 | $ | 5,451.2 | |||||||||||||||
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(1) | Annual requirement to purchase 20 to 100 per cent of electricity production from independent power producers over varying contract lengths up to 25 years. |
(2) | Purchasing commitments for transportation of solid fuel and transportation capacity on various pipelines. |
(3) | Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management. |
(4) | Emera has a commitment in connection with the Federal Loan Guarantee (“FLG”) to complete construction of the Maritime Link. Thirty per cent of the financing of this project will come from Emera as equity. Emera also has a commitment to make equity contributions to the Labrador Island Link Limited Partnership upon draw requests from the general partner. The amounts forecasted are a combination of equity investments for both projects and are subject to change in both timing and amounts as the projects advance through construction. |
(5) | Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles. |
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B. | Legal Proceedings |
Emera
Between September 16, 2015 and November 2, 2015, purported shareholders of TECO Energy filed 12 separate complaints styled as class action lawsuits in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida or the United States District Court for the Middle District of Florida (the “Merger Litigation”). Each complaint alleges, among other things, that the Board of Directors of TECO Energy breached its fiduciary duties in agreeing to the acquisition agreement and that Emera and/or Emera US Inc. aided and abetted such alleged breaches. The complaints sought to enjoin the merger pursuant to the acquisition agreement.
On November 17, 2015, TECO Energy, Emera, Emera US Inc. and the Board of Directors of TECO Energy entered into a memorandum of understanding with the shareholder plaintiffs to settle all of the Merger Litigation, subject to negotiation of a stipulation of settlement with the plaintiffs and to court approval. The memorandum of understanding provides for all claims against the defendants to be released in exchange for TECO Energy making certain additional disclosures to its shareholders related to the proposed merger, which have now been made. The parties are expected to enter into a stipulation of settlement in August 2016, which will be filed with the court for approval.
There is no assurance that the parties will ultimately enter into a stipulation of settlement or that the court will approve such settlement. While the outcome of the proceeding is uncertain, management does not believe that its ultimate resolution will have a material adverse effect on Emera’s results of operations, financial condition or cash flows.
Emera Maine
On September 30, 2011, a group including the Attorney General of Massachusetts, New England utilities commissions, state public advocates and end users filed a complaint with the Federal Energy Regulatory Commission (“FERC”) alleging that the 11.14 per cent base return on equity (“ROE”) under the ISO-New England (“ISO-NE”) Open Access Transmission Tariff (“OATT”) was unjust and unreasonable.
On June 19, 2014, the FERC issued an order in connection with this complaint that changed the methodology used to set the ROE and resulted in a lower base transmission ROE of 10.57 per cent and a lower total ROE (inclusive of incentive adders) of 11.74 per cent for the period of October 1, 2011 to December 31, 2012. The ROE was confirmed by FERC in two subsequent orders and has now been appealed to the U.S. Court of Appeals for the DC Circuit. The Court has decided to hold the appeal of this case in abeyance pending the outcome of the ENE Case and MA AG II Case discussed below.
On June 30, 2016, Emera Maine completed the processing of refunds to customers to reflect the 10.57 per cent ROE.
On December 27, 2012, a second group of consumer advocates, including Environment Northeast, filed a complaint with the FERC on similar grounds, arguing that the 11.14 per cent base ROE under the OATT was unjust and unreasonable (“the ENE Case”). This complaint applies to the period from January 1, 2013 to March 31, 2014. On July 31, 2014, a group of state commissions, state public advocates and end users filed a third complaint with the FERC on similar grounds (“the MA AG II Case”) in relation to the period from July 31, 2014 to October 31, 2015. The ENE Case and MA AG II Case were subsequently consolidated by FERC into a single case.
On March 22, 2016, a FERC Administrative Law Judge (“ALJ”) issued a recommended decision to FERC with respect to the consolidated cases. The recommendation for the ENE Case was a 9.59 per cent base ROE, with a 10.42 per cent maximum ROE, and the recommendation for the MA AG II Case was a 10.90 per cent base ROE, with a 12.19 per cent maximum ROE. The ALJ’s recommended decision is not definitive and FERC has the ability to adjust the ALJ’s recommended decision. A decision by FERC is not expected until Q4 2016.
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On April 29, 2016, an additional complaint was filed with FERC challenging the ROE under the ISO-NE transmission tariff. The complaint was filed by the Eastern Massachusetts Consumer-Owned Systems (“EMCOS”), a collection of thirteen municipal light departments, seeking to reduce the base ROE to 8.61 per cent and the maximum ROE to 11.24 per cent for the period April 29, 2016 to July 29, 2017.
Emera Maine has recorded a reserve of $5.1 million pre-tax ($3.9 million USD) (December 31, 2015—$6.9 million or $5.0 million USD) for the ENE Case and MA AG II Case. The reserves recorded for these complaints have been recorded as a component of Regulatory Liabilities on the Consolidated Balance Sheets, and the charges to earnings have been a reduction to Operating revenues—regulated on the Consolidated Statements of Income. The reserve was calculated on a 10.57 per cent base and represents Emera Maine’s best estimate of the probable outcome. No update has been made to the reserve as a result of the ALJ recommendation as it is pending approval by the FERC and is considered uncertain until that time. No reserve has been made as a result of the EMCOS complaint, as the outcome is considered uncertain.
Other Legal Proceedings
Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company.
C. | Environment |
Emera’s activities are subject to a broad range of federal, provincial, state, regional and local laws and environmental regulations, designed to protect, restore and enhance the quality of the environment including air, water and solid waste. Emera estimates its environmental capital expenditures, excluding AFUDC, based upon present environmental laws and regulations will be approximately $24.7 million during fiscal 2016 and are estimated to be $63.7 million from 2017 through 2020. Amounts that have been committed to are included in “Capital projects” in the commitments table in note 25A. The estimated expenditures do not include costs related to possible changes in the environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and other pollutant emissions.
NSPI is subject to regulation by federal, provincial and municipal authorities with regard to environmental matters, primarily through its utility operations. In addition to imposing continuing compliance obligations, there are laws, regulations and permits authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is material to NSPI. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on NSPI.
In March 2016, the Prime Minister met with provincial premiers to begin the development of a pan-Canadian plan to reduce greenhouse gases and issued, theVancouver Declaration. NSPI is providing input to the process both through the Province and through submission of a discussion paper to the relevant working committee. The outcome is considered uncertain.
In June 2016, the Federal government announced a formal review process for several Acts and processes including the Canadian Environmental Assessment Act (“CEAA”) and process, the National Energy Board (“NEB”) processes, the Fisheries Act and the Navigation Protection Act. The Company will participate in the consultation process.
Conformance with legislative and NSPI internal requirements is verified through a comprehensive environmental audit program. There were no significant environmental or regulatory compliance issues identified during the audits completed to June 30, 2016.
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Poly Chlorinated Bi-Phenol Transformers
In response to the Canadian Environmental Protection Act 1999, 2008 Poly Chlorinated Bi-Phenol (“PCB”) Regulations to phase out electrical equipment and liquids containing PCBs, NSPI has implemented a program to eliminate transformers and other oil-filled electrical equipment on its system that do not meet the 2008 PCB Regulations Standard by the end of 2025. This also includes PCB contaminated pole mounted transformers. The combined total cost of these projects is estimated to be $40.1 million and, as at June 30, 2016, approximately $24.3 million (December 31, 2015 – $19.7 million) has been spent to date. NSPI has recognized an ARO of $14.6 million as at June 30, 2016 (December 31, 2015 – $15.0 million) associated with the PCB phase-out program.
Emera Energy Emissions
The New England Gas Generating Facilities are subject to the Regional Greenhouse Gas Initiative (“RGGI”) for carbon dioxide emissions and the Acid Rain Program for sulphur dioxide emissions. The New England Gas Generating Facilities emit approximately two million tons of carbon dioxide per year. The amount of sulphur dioxide emitted is not considered significant. Changes to these emissions programs could adversely impact financial and operational performance.
D. | Principal Risks and Uncertainties |
In this section, Emera describes some of the principal risks management believes could materially affect Emera’s business, revenues, operating income, net income, net asset or liquidity or capital resources. The nature of risk is such that no list can be comprehensive, and other risks may arise, or risks not currently considered material may become material in the future.
Sound risk management is an essential discipline for running the business efficiently and pursuing the Company’s strategy successfully. Emera has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach.
Regulatory and Political Risk
The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of the recovery of costs and investments in a timely manner. As cost-of-service utilities with an obligation to serve, NSPI, Emera Maine, BLPC, GBPC and Domlec must obtain regulatory approval to change electricity rates and/or riders from their respective regulators. Costs and investments can be recovered upon the respective regulator’s approval of the recovery in adjustments to rates and/or riders, which normally requires a public hearing process or may be mandated by other governmental bodies. In addition, the commercial and regulatory frameworks under which Emera and its subsidiaries operate can be impacted by significant shifts in government policy and changes in governments. Emera has certain investments subject to significant influence that are subject to regulatory risk and include: APUC, M&NP, NSPML, LIL and Lucelec.
During public hearing processes, consultants and customer representatives scrutinize the costs, actions and plans of these subsidiaries and their respective regulators determine whether to allow recovery and to adjust rates based upon the subsidiaries’ evidence and any contrary evidence from other parties. In some circumstances, other government bodies may influence the setting of rates. The subsidiaries manage this regulatory risk through transparent regulatory disclosure, ongoing stakeholder and government consultation and multi-party engagement on aspects such as utility operations, fuel-related audits, rate filings and capital plans. The subsidiaries employ a collaborative regulatory approach through technical conferences and, where appropriate, negotiated settlements.
On April 13, 2016, in association with a distribution rate application, the MPUC ordered an audit of Emera Maine’s implementation of its new customer information system and customer service performance, including billing and reliability. The audit report is expected to be released in Q3 2016.
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Changes in Environmental Legislation
Emera is subject to regulation by federal, provincial, state, regional and local authorities with regard to environmental matters; primarily related to its utility operations. This includes laws setting greenhouse gas emissions standards and air emissions standards. Emera is also subject to laws regarding the generation, storage, transportation, use and disposal of hazardous substances and materials.
In addition to imposing continuing compliance obligations, there are permit requirements, laws and regulations authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is, and may be, material to Emera. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on Emera.
New emission reductions requirements for the utilities sector are being established by governments in Canada and the United States. Changes to greenhouse gas emissions standards and air emissions standards could adversely affect Emera’s operations and financial performance. Stricter environmental laws and enforcement of such laws in the future could increase Emera’s exposure to additional liabilities and costs. These changes could also affect earnings and strategy by changing the nature and timing of capital investments.
Emera manages its environmental risk by operating in a manner that is respectful and protective of the environment and with the objective of achieving full compliance with applicable laws, legislation and company policies and standards. Emera has implemented this policy through the development and application of environmental management systems in its operating subsidiaries. Comprehensive audit programs are also in place to regularly test compliance with such laws, policies and standards.
Commercial Relationships
The Company is exposed to commercial relationship risk in respect of its reliance on certain key partners, supplies and customers. The company manages its commercial relationship risk by monitoring credit risk, and monitoring of significant developments with its customers, partners and suppliers.
ENL
Emera and Nalcor Energy executed agreements pertaining to the development and transmission of hydroelectric power from Muskrat Falls in Labrador to the island of Newfoundland, the Province of Nova Scotia and through to New England. In exchange for the Company’s investment in the Maritime Link Project, estimated to be approximately $1.56 billion, Nalcor has agreed to provide 20 per cent of the output of the Muskrat Falls generating station.
Interest Rate Risk
The Company utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. The Company 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 the Company’s regulated subsidiaries, the cost of debt is generally passed through to ratepayers. While regulatory ROE rates will generally and indirectly follow the direction of interest rates, regulatory ROE’s are likely to fall in times of reducing interest rates and raise in times of increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development initiatives.
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Commodity Prices and Foreign Exchange Rate Fluctuations
A substantial amount of the Company’s fuel supply comes from international suppliers and is subject to commodity price risk. 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. In addition, the adoption and implementation of FAMs in certain subsidiaries has further helped manage this risk. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs.
The Company enters into foreign exchange forward and swap contracts to limit exposure on foreign currency transactions such as fuel purchases and USD revenue streams.
The cash consideration for the TECO Energy acquisition was required to be paid in US dollars, a portion of which was raised in Canadian dollars. As a result, increases in the value of the US dollar versus the Canadian dollar could have increased the purchase price translated in Canadian dollars and thereby increased the Canadian dollars required to fund the USD purchase price for the acquisition.
To mitigate this risk, the proceeds of the first instalment of the Debenture Offering were invested in short-term US dollar investment grade securities.
In addition, during October 2015, Emera entered into foreign exchange forward contracts to economically hedge an amount equal to the anticipated proceeds from the final instalment of the Debenture Offering of the TECO Energy acquisition of $1.457 billion. These foreign exchange forward contracts are economic hedges and do not qualify for hedge accounting. Therefore, all mark-to-market gains and losses will be recognized in net income for the period.
The operations of TECO Energy are conducted in US dollars. Following the acquisition, the consolidated net income of Emera will be impacted to a greater extent by movements in the US dollar relative to the Canadian dollar.
E. | Guarantees and Letters of Credit |
There were no material changes in Emera’s guarantees and letters of credit since December 31, 2015.
26. | COMMON STOCK |
Authorized: Unlimited number of non-par value common shares.
Issued and outstanding: | millions of shares | millions of Canadian dollars | ||||||
Balance, December 31, 2015 | 147.21 | $ | 2,157.5 | |||||
Issuance of common stock (1) | 0.06 | 2.9 | ||||||
Issued for cash under Purchase Plans at market rate | 1.10 | 50.2 | ||||||
Discount on shares purchased under Dividend Reinvestment Plan | — | (2.3 | ) | |||||
Options exercised under senior management share option plan | 0.54 | 15.1 | ||||||
Stock-based compensation | — | 0.5 | ||||||
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Balance, June 30, 2016 (2) | 148.91 | $ | 2,223.9 | |||||
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(1) | In Q1 2016, Emera issued 0.06 million common shares to facilitate the creation and issuance of 0.2 million depositary receipts in connection with the ECI amalgamation transaction. The depositary receipts are listed on the Barbados Stock Exchange. |
(2) | As at August 3, 2016, approximately 50.5 million common shares of Emera were issued, representing conversion into common shares of approximately 97 per cent of the convertible debentures (see note 23). |
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27. | NON-CONTROLLING INTEREST IN SUBSIDIARIES |
Non-controlling interest in subsidiaries consisted of the following:
As at millions of Canadian dollars | June 30 2016 | December 31 2015 | ||||||
ICDU | $ | 49.9 | $ | 51.8 | ||||
Preferred shares of GBPC | 33.5 | 33.5 | ||||||
Domlec (1) | 22.8 | 48.3 | ||||||
Preferred shares of Emera Maine | 0.4 | 0.4 | ||||||
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$ | 106.6 | $ | 134.0 | |||||
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(1) | On March 22, 2016, an indirect wholly-owned subsidiary of Emera acquired 0.7 million ECI shares, increasing Emera’s ownership interest from 95.5 to 100 per cent. |
28. | SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS |
For the | Six months ended June 30 | |||||||
millions of Canadian dollars | 2016 | 2015 | ||||||
Changes in non-cash working capital: | ||||||||
Receivables, net | $ | 77.6 | $ | 80.5 | ||||
Income taxes receivable | (28.6 | ) | (15.6 | ) | ||||
Inventory | 43.2 | 8.5 | ||||||
Prepaid expenses | (28.2 | ) | (23.3 | ) | ||||
Due from related party | (0.2 | ) | 2.1 | |||||
Other current assets | 4.9 | (0.9 | ) | |||||
Accounts payable | 38.7 | (93.4 | ) | |||||
Income taxes payable | 15.8 | (15.2 | ) | |||||
Other current liabilities | 27.5 | (28.0 | ) | |||||
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Total non-cash working capital | 150.7 | (85.3 | ) | |||||
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Supplemental disclosure of non-cash activities: | ||||||||
Common share dividends reinvested | $ | 43.9 | $ | 35.0 | ||||
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29. | VARIABLE INTEREST ENTITIES |
The Company performs ongoing analysis to assess whether it holds any VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly-owned facilities.
VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera is not deemed the primary beneficiary, the VIE is accounted for using the equity method.
For the three and six months ended June 30, 2016, the Company has identified the following significant VIEs:
Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have the controlling financial interest of NSPML. In Q2 2014, critical milestones were achieved and Nalcor Energy was deemed the beneficiary of the asset for financial reporting purposes, as they have authority over the majority of the direct activities that are expected to most significantly impact the economic performance of the Maritime Link Project. Thus, Emera records the Maritime Link Project as an equity investment.
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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 (notes 12 and 17). Emera’s consolidated VIE in the SIF is recorded as an “Investment securities” and “Restricted cash”.
The Company has identified certain long-term purchase power agreements that could be defined as 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 significant unconsolidated VIEs:
As at | June 30, 2016 | December 31, 2015 | ||||||||||||||
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) | 245.3 | 818.0 | 187.6 | 1,007.0 |
30. | 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.
31. | ACQUISITION |
TECO ENERGY INC.
On July 1, 2016, Emera acquired all of the outstanding common shares of TECO Energy Inc. for $27.55 USD per common share. The net cash purchase price totaled $8.4 billion ($6.5 billion USD), with an aggregate purchase price of $13.9 billion ($10.7 billion USD), including the assumption of $5.5 billion ($4.2 billion USD) in US debt facilities on closing. The net cash purchase price was financed through: (i) $728 million ($560 million USD) related to the first instalment of convertible debentures represented by instalment receipts issued in 2015, $1.56 billion ($1.2 billion USD) fixed-to-floating subordinated notes, $500 million ($384 million USD) in Canadian long-term debit and $4.2 billion ($3.25 billion USD) in US long-term senior unsecured notes; (ii) available cash on hand; and (iii) drawings of $1.4 billion ($1.1 billion USD) on the Company’s acquisition credit facility. Total proceeds of the debt, that were not otherwise required to complete the Acquisition, have been used for general corporate purposes.
On August 2, 2016, the convertible debenture Final Instalment Date, Emera obtained the remaining two thirds of the convertible debenture instalments, net proceeds of which were $1.4 billion. These funds were used to fully repay the Company’s acquisition credit facility.
TECO Energy Inc. is an energy-related holding company with regulated electric and gas utilities in Florida and New Mexico. TECO Energy’s holdings include Tampa Electric, an integrated regulated electric utility which serves approximately 730,000 customers in West Central Florida, Peoples Gas System, a regulated gas distribution utility which serves more than 370,000 customers across Florida, and New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility which serves more than 520,000 customers across New Mexico.
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The majority of TECO Energy’s operations are subject to the rate-setting authority of the FERC, Florida Public Service Commission (“FPSC”), and New Mexico Public Regulation Commission (“NMPRC”), and are accounted for pursuant to USGAAP, including the accounting guidance for regulated operations. Except for unregulated long-term debt acquired and deferred taxes, preliminary fair values of tangible and intangible assets and liabilities subject to these rate-setting provisions approximate their carrying values. Accordingly, assets acquired and liabilities assumed and pro-forma financial information do not reflect any net adjustments related to these amounts.
The Acquisition is accounted for in accordance with the acquisition method of accounting. The excess of purchase price over estimated fair values of assets acquired and liabilities assumed will be recognized as goodwill at the acquisition date of July 1, 2016. The goodwill reflects the value paid primarily for access to regulated assets, net income and cash flows in growth markets with constructive regulatory environments, opportunities for adjacency growth, long-term potential for enhanced access to capital as a result of increased scale and business diversity, and an improved earnings risk profile. Allocation of goodwill to the reporting units is not complete as at August 8, 2016. The goodwill recognized as part of this transaction is not deductible for income tax purposes, and as such, no deferred taxes will be recorded related to this transactions goodwill.
The following table summarizes the preliminary allocation of the purchase consideration to the assets and liabilities acquired as at July 1, 2016 based on their fair values, using the July 1, 2016 exchange rate of $1.00 USD = $1.3009 CAD.
millions of Canadian dollars | ||||
Purchase Consideration | $ | 8,447 | ||
Fair value assigned to net assets: | ||||
Current assets (1) | $ | 613 | ||
Regulatory assets (including current portion) | 624 | |||
Property, plant and equipment, net | 9,983 | |||
Other long-term assets | 111 | |||
Current liabilities | (794 | ) | ||
Assumed long-term debt (including current portion) | (5,409 | ) | ||
Regulatory liabilities (including current portion) | (1,111 | ) | ||
Deferred income taxes | (768 | ) | ||
Other long-term liabilities | (580 | ) | ||
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$ | 2,669 | |||
Cash and cash equivalents | 38 | |||
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Fair value of net assets acquired | $ | 2,707 | ||
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Goodwill | $ | 5,740 | ||
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(1) | Includes accounts receivables with fair value of $334 million, gross contract value of $337 million, and $3 million of contractual receivables not expected to be collected. |
Acquisition Related Expenses
Acquisition related expenses totaled $67.4 million ($42.0 million after-tax) and $93.0 million ($59.5 million after-tax) for the three and six months ended June 30, 2016 (2015 – nil). These costs have been recognized in the Consolidated Statements of Income as follows:
For the millions of Canadian dollars | Three months ended June 30 | Six months ended June 30 | ||||||
2016 | 2016 | |||||||
Operating, maintenance and general | $ | 7.4 | $ | 7.5 | ||||
Interest expense, net | 60.0 | 85.5 | ||||||
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Income tax expense (recovery) | (25.4 | ) | (33.5 | ) | ||||
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Acquisition related expenses | $ | 42.0 | $ | 59.5 | ||||
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Operating, maintenance, and general expenses are attributable to acquisition related legal, accounting, banking and advisory fees. Interest expense, net relates to interest incurred on both the convertible debentures represented by instalment receipts and the acquisition credit facility issued for the purpose of financing the TECO Energy acquisition.
Emera will incur additional acquisition related operating, maintenance and general expenses in Q3 2016, including approximately $65.0 million related to the accelerated vesting of outstanding stock-based compensation awards, advisory and legal fees.
Other Contractual Obligations
In connection with the acquisition of TECO Energy by Emera, Emera and NMGC have made certain commitments approved by the NMPRC. NMGC agreed, among other things, to fund, at shareholder expense, economic development projects, make charitable contributions, provide funding to enterprises engaged in economic and business development in New Mexico, apply annual bill reduction credits through June 30, 2018, to construct an enlarged pipeline from NMGC’s current system to the New Mexico/Mexico border, and establish a matching fund to extend its natural gas infrastructure to currently unserved areas in New Mexico. A total of $39.5 million or $24.0 million after-tax ($30.4 million USD or $18.5 million USD after-tax) associated with these commitments will be recorded in the third quarter of 2016.
Supplemental Pro Forma Data
The unaudited pro forma financial information below gives effect to the acquisition of TECO Energy as if the transaction had occurred at the beginning of 2016. This pro forma data is presented for information purposes only, and does not purport to be indicative of the results that would have occurred had the acquisition taken place at the beginning of 2016, nor is it indicative of the results that may be expected in future periods.
Pro forma net income attributable to common shareholders excludes all non-recurring acquisition-related expenses incurred by TECO Energy and Emera Inc., adjustments for pro forma financing costs associated with the acquisition, and the exclusion of net income from TECO Coal, a discontinued operation sold by TECO Energy in 2015. Total after-tax adjustments made to the pro forma net income attributable to common shareholders were $70.0 million and $41.0 million, respectively, for the three and six months ended June 30, 2016, and $17.0 million and $(19.0) million, respectively, for the three and six months ended June 30, 2015. Pro forma operating revenues have not been adjusted, as there are no acquisition related revenue adjustments required for the three and six months periods ended June 30, 2016 and June 30, 2015.
For the millions of Canadian dollars | Three months ended June 30 | Six months ended June 30 | ||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Pro forma operating revenues | $ | 1,340 | $ | 1,364 | $ | 3,123 | $ | 3,112 | ||||||||
Pro forma net income attributable to common shareholders | $ | 285 | $ | 42 | $ | 398 | $ | 237 |
32. | SUBSEQUENT EVENTS |
As at August 3, 2016, approximately 50.5 million common shares of Emera were issued, representing conversion into common shares of approximately 97 per cent of the Convertible Debentures. Refer to note 23 for further details.
On July 1, 2016, Emera acquired all of the outstanding common shares of TECO Energy Inc. Refer to note 31 for further details.
These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through August 8, 2016, the date the financial statements were issued.
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