Exhibit 99.2
EMERA INCORPORATED
Unaudited Condensed Consolidated
Financial Statements
September 30, 2011 and 2010
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Emera Incorporated
Consolidated Statements of Income (Unaudited)
For the millions of Canadian dollars (except per share amounts) | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 (as adjusted – | 2011 | 2010 (as adjusted – | |||||||||||||
Operating revenues | ||||||||||||||||
Regulated | $453.8 | $332.9 | $1,429.3 | $1,053.9 | ||||||||||||
Non-regulated | 42.3 | 61.1 | 123.1 | 143.3 | ||||||||||||
Total operating revenues | 496.1 | 394.0 | 1,552.4 | 1,197.2 | ||||||||||||
Operating expenses | ||||||||||||||||
Regulated fuel for generation and purchased power | 209.8 | 147.2 | 651.4 | 476.8 | ||||||||||||
Regulated fuel adjustment (note 5) | (4.4) | (23.0) | (4.0) | (75.0) | ||||||||||||
Non-regulated fuel for generation and purchased power | 17.1 | 20.6 | 55.6 | 64.5 | ||||||||||||
Non-regulated direct costs | 15.2 | 22.6 | 40.5 | 46.1 | ||||||||||||
Operating, maintenance and general | 105.5 | 87.2 | 333.1 | 247.5 | ||||||||||||
Provincial, state, and municipal taxes | 12.2 | 11.8 | 36.7 | 35.5 | ||||||||||||
Depreciation and amortization | 64.8 | 48.1 | 176.3 | 143.7 | ||||||||||||
Total operating expenses | 420.2 | 314.5 | 1,289.6 | 939.1 | ||||||||||||
Income from operations | 75.9 | 79.5 | 262.8 | 258.1 | ||||||||||||
Income from equity investments | 5.2 | 5.7 | 17.3 | 13.6 | ||||||||||||
Other income (expenses), net (note 6) | 1.8 | 0.3 | 41.6 | 18.0 | ||||||||||||
Interest expense, net (note 7) | 40.3 | 36.1 | 122.1 | 111.5 | ||||||||||||
Income before provision for income taxes | 42.6 | 49.4 | 199.6 | 178.2 | ||||||||||||
Income tax expense (recovery) (note 8) | (5.7) | 4.0 | (10.4) | 2.5 | ||||||||||||
Net income from operations | 48.3 | 45.4 | 210.0 | 175.7 | ||||||||||||
Non-controlling interest in subsidiaries | 4.2 | 2.1 | 9.1 | 6.1 | ||||||||||||
Net income of Emera Incorporated | 44.1 | 43.3 | 200.9 | 169.6 | ||||||||||||
Preferred stock dividends | 3.3 | 3.0 | 6.6 | 3.0 | ||||||||||||
Net income attributable to common shareholders | $40.8 | $40.3 | $194.3 | $166.6 | ||||||||||||
Weighted average shares of common stock outstanding (in millions) | ||||||||||||||||
Basic | 122.6 | 114.3 | 120.4 | 114.0 | ||||||||||||
Diluted | 123.6 | 115.3 | 125.7 | 120.3 | ||||||||||||
Earnings per common share (note 17) | ||||||||||||||||
Basic | $0.33 | $0.35 | $1.61 | $1.46 | ||||||||||||
Diluted | $0.33 | $0.35 | $1.59 | $1.43 | ||||||||||||
Dividends per common share declared | $0.6625 | $0.6075 | $1.3125 | $1.1625 |
The accompanying notes are an integral part of these condensed financial statements.
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Emera Incorporated
Consolidated Balance Sheets (Unaudited)
As at millions of Canadian dollars | September 30 2011 | December 31 2010 (as adjusted – note 24) | ||||||
Assets | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $84.2 | $7.3 | ||||||
Restricted cash | 11.6 | 58.6 | ||||||
Receivables, net (note 9) | 413.4 | 392.9 | ||||||
Income taxes receivable | 15.9 | 44.3 | ||||||
Inventory (note 10) | 200.6 | 177.8 | ||||||
Deferred income taxes | 12.8 | 13.7 | ||||||
Derivative instruments (note 21) | 44.2 | 49.7 | ||||||
Regulatory assets | 127.5 | 90.5 | ||||||
Prepaid expenses | 27.7 | 9.5 | ||||||
Other current assets | 5.0 | 3.1 | ||||||
Total current assets | 942.9 | 847.4 | ||||||
Property, plant and equipment,net of accumulated depreciation of | 4,205.8 | 3,742.6 | ||||||
Other assets | ||||||||
Deferred income taxes | 27.3 | 31.1 | ||||||
Derivative instruments (note 21) | 68.7 | 36.0 | ||||||
Regulatory assets | 322.4 | 354.9 | ||||||
Net investment in direct financing lease | 489.6 | 491.5 | ||||||
Investments subject to significant influence (note 14) | 223.4 | 246.0 | ||||||
Available-for-sale investments (note 15) | 57.6 | 0.8 | ||||||
Goodwill | 198.1 | 167.4 | ||||||
Other | 243.6 | 171.8 | ||||||
Total other assets | 1,630.7 | 1,499.5 | ||||||
Total assets | $6,779.4 | $6,089.5 |
The accompanying notes are an integral part of these condensed financial statements.
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Emera Incorporated
Consolidated Balance Sheets (Unaudited) – Continued
As at millions of Canadian dollars | September 30 2011 | December 31 2010 (as adjusted – | ||||||
Liabilities and Equity | ||||||||
Current liabilities | ||||||||
Short-term debt | $184.2 | $81.7 | ||||||
Current portion of long-term debt | 16.9 | 10.6 | ||||||
Accounts payable | 335.0 | 293.9 | ||||||
Income taxes payable | 5.2 | 7.5 | ||||||
Deferred income taxes | 10.0 | 8.5 | ||||||
Derivative instruments (note 21) | 34.4 | 36.8 | ||||||
Regulatory liabilities | 42.6 | 55.0 | ||||||
Pension and post-retirement liabilities | 8.8 | 8.9 | ||||||
Other current liabilities (note 11) | 168.6 | 110.3 | ||||||
Total current liabilities | 805.7 | 613.2 | ||||||
Long-term liabilities | ||||||||
Long-term debt (note 12) | 3,147.1 | 3,118.5 | ||||||
Deferred income taxes | 243.9 | 168.5 | ||||||
Derivative instruments (note 21) | 26.1 | 28.9 | ||||||
Regulatory liabilities | 133.5 | 65.2 | ||||||
Asset retirement obligations | 89.4 | 141.8 | ||||||
Pension and post-retirement liabilities | 383.5 | 400.0 | ||||||
Other long-term liabilities | 23.2 | 22.0 | ||||||
Total long-term liabilities | 4,046.7 | 3,944.9 | ||||||
Commitments and contingencies(note 18) | ||||||||
Equity | ||||||||
Common stock, no par value, unlimited authorized shares, 122.23 million and 2010 – 114.62 million shares issued and outstanding (note 19) | 1,369.1 | 1,137.8 | ||||||
Preferred stock, unlimited authorized First Preferred Shares issuable in series, 6 million 4.40 percent Cumulative Five-Year Rate Reset First Preferred Shares Series A issued at $25 par value | 146.7 | 146.7 | ||||||
Contributed surplus | 3.5 | 3.2 | ||||||
Accumulated other comprehensive loss | (505.2) | (564.2) | ||||||
Retained earnings | 689.4 | 653.5 | ||||||
Total Emera Incorporated equity | 1,703.5 | 1,377.0 | ||||||
Non-controlling interest in subsidiaries | 223.5 | 154.4 | ||||||
Total equity | 1,927.0 | 1,531.4 | ||||||
Total liabilities and equity | $6,779.4 | $6,089.5 |
The accompanying notes are an integral part of these condensed financial statements.
Approved on behalf of the Board of Directors
Chairman | President and Chief Executive Officer |
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Emera Incorporated Consolidated Statements of Cash Flows (Unaudited)
For the millions of Canadian dollars | Nine months ended September 30 | |||||||
2011 | 2010 (as adjusted – note 24) | |||||||
Operating activities | ||||||||
Net income from operations of Emera Incorporated | $210.0 | $175.7 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depreciation and amortization | 187.2 | 155.4 | ||||||
Income from equity investments, net of dividends | (0.1) | 7.7 | ||||||
Allowance for equity funds used during construction | (9.1) | (8.5) | ||||||
Deferred income taxes, net | 6.5 | 7.7 | ||||||
Net change in pension and post-retirement, benefits | (2.6) | (11.1) | ||||||
Regulated fuel adjustment | (9.0) | (77.2) | ||||||
Net change in fair value of derivative instruments | 8.6 | 1.0 | ||||||
Net change in regulatory assets and liabilities | (11.6) | (13.6) | ||||||
Other operating activities, net | (44.3) | 6.6 | ||||||
Changes in non-cash working capital: | ||||||||
Receivables, net | 8.8 | (24.9) | ||||||
Income taxes receivable | 29.0 | (18.1) | ||||||
Inventory | (4.9) | 2.5 | ||||||
Prepaid expenses | (12.4) | (12.7) | ||||||
Other current assets | (1.0) | 1.5 | ||||||
Accounts payable | 1.1 | 40.7 | ||||||
Income taxes payable | (2.6) | (1.6) | ||||||
Other current liabilities | 8.1 | 6.9 | ||||||
Net cash provided by operating activities | 361.7 | 238.0 | ||||||
Investing activities | ||||||||
Additions to property, plant and equipment | (334.9) | (342.3) | ||||||
Acquisition, net of cash acquired | (35.1) | – | ||||||
Decrease in restricted cash | 61.2 | – | ||||||
Purchase of investments subject to significant influence, inclusive of acquisition costs (note 14) | (34.6) | (91.5) | ||||||
Allowance for borrowed funds used during construction | (8.1) | (7.6) | ||||||
Retirement spending, net of salvage | (6.0) | (1.9) | ||||||
Addition to investments in direct financing lease | (0.4) | (1.2) | ||||||
Purchase of subscription receipts | (98.9) | – | ||||||
Other investing activities | (5.8) | (13.9) | ||||||
Net cash used in investing activities | (462.6) | (458.4) | ||||||
Financing activities | ||||||||
Change in short-term debt, net | 98.2 | (56.6) | ||||||
Retirement of long-term debt | (10.3) | (104.7) | ||||||
Proceeds from long term-debt | – | 300.0 | ||||||
Net repayments under committed credit facilities | (19.6) | 46.2 | ||||||
Issuance of common stock, net of issuance costs | 228.4 | 23.7 | ||||||
Issuance of preferred stock | – | 145.2 | ||||||
Dividends on common stock | (116.3) | (93.3) | ||||||
Dividends on preferred stock | (5.0) | (3.0) | ||||||
Dividends paid by subsidiaries to non-controlling interest | (6.5) | (6.0) | ||||||
Other financing activities | 10.0 | (8.0) | ||||||
Net cash provided by financing activities | 178.9 | 243.5 | ||||||
Effect of exchange rate changes on cash and cash equivalents | (1.1) | 0.2 | ||||||
Net increase in cash and cash equivalents | 76.9 | 23.3 | ||||||
Cash and cash equivalents, beginning of period | 7.3 | 20.2 | ||||||
Cash and cash equivalents, end of period | $84.2 | $43.5 | ||||||
Cash and cash equivalents consists of: | ||||||||
Cash | $41.4 | $37.0 | ||||||
Short-term investments | 42.8 | 6.5 | ||||||
Cash and cash equivalents | $84.2 | $43.5 | ||||||
Supplemental disclosure of cash paid (received): | ||||||||
Interest | $120.6 | $104.8 | ||||||
Income and capital taxes | $(30.5) | $1.2 |
The accompanying notes are an integral part of these condensed financial statements.
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Emera Incorporated
Consolidated Statements of Comprehensive Income (Unaudited)
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 (as adjusted | 2011 | 2010 (as adjusted | |||||||||||||
Net income attributable to common shareholders | $40.8 | $40.3 | $194.3 | $166.6 | ||||||||||||
Other comprehensive income (loss), net of tax | ||||||||||||||||
Unrealized losses on cash flow hedges(1) | (9.4) | (0.9) | (6.8) | (5.9) | ||||||||||||
Hedging (gains) losses included in income(2) | (1.4) | 1.6 | (0.3) | 4.3 | ||||||||||||
Amortization of unrecognized pension and post-retirement benefit costs(3) | 6.0 | 3.1 | 17.2 | 7.8 | ||||||||||||
Unrealized loss on available-for-sale investment | (0.3) | (0.1) | (0.2) | (0.3) | ||||||||||||
Unrealized gain (loss) on translation of self-sustaining foreign operations | 77.6 | (19.0) | 49.1 | (8.9) | ||||||||||||
Other comprehensive income (loss)(4) | 72.5 | (15.3) | 59.0 | (3.0) | ||||||||||||
Comprehensive income attributable to common shareholders | $113.3 | $25.0 | $253.3 | $163.6 |
The accompanying notes are an integral part of these condensed financial statements.
1) | Net of tax recovery of $1.8 million (2010 – $2.6 million) for the three months ended September 30, 2011 and tax recovery of $1.7 million (2010 – $6.0 million) for the nine months ended September 30, 2011. |
2) | Net of tax recovery of $0.6 million (2010 – $1.1 million tax expense) for the three months ended September 30, 2011 and $1.0 million tax expense (2010 – $3.0 million) for the nine months ended September 30, 2011. |
3) | Net of tax recovery of $0.1 million (2010 – nil) for the three months ended September 30, 2011 and $0.5 million (2010 – $0.2 million) for the nine months ended September 30, 2011. |
4) | Net of tax recovery of $2.5 million (2010 – $1.5 million) for the three months ended September 30, 2011 and $1.2 million tax recovery (2010 – $3.2 million) for the nine months ended September 30, 2011. |
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Emera Incorporated
Consolidated Statements of Changes in Equity (Unaudited)
millions of Canadian dollars | Common Stock | Preferred Stock | Contributed Surplus | Accumulated Other Comprehensive Loss (“AOCL”) | Retained Earnings | Non- Controlling Interest | Total Equity | |||||||||||||||||||||
For the nine months ended September 30, 2011 |
| |||||||||||||||||||||||||||
Balance, December 31, 2010 (as adjusted – note 24) | $1,137.8 | $146.7 | $3.2 | $(564.2) | $653.5 | $154.4 | $1,531.4 | |||||||||||||||||||||
Net income of Emera Incorporated | – | – | – | – | 200.9 | 9.1 | 210.0 | |||||||||||||||||||||
Other comprehensive income, net of tax recovery $1.2 | – | – | – | 59.0 | – | – | 59.0 | |||||||||||||||||||||
Issuance of common stock, net of issuance costs | 196.0 | – | – | – | – | – | 196.0 | |||||||||||||||||||||
Additional investments | – | – | – | – | – | 66.5 | 66.5 | |||||||||||||||||||||
Cash dividends declared on preferred stock ($1.1000/share) | – | – | – | – | (6.6) | – | (6.6) | |||||||||||||||||||||
Cash dividends declared on common stock ($1.3125/share) | – | – | – | – | (158.4) | – | (158.4) | |||||||||||||||||||||
Dividends paid by subsidiaries to non-controlling interest | – | – | – | – | – | (0.5) | (0.5) | |||||||||||||||||||||
Common stock issued under purchase plan | 29.7 | – | – | – | – | – | 29.7 | |||||||||||||||||||||
Senior management stock options exercised | 4.7 | – | (0.3) | – | – | – | 4.4 | |||||||||||||||||||||
Stock option expense | – | – | 0.6 | – | – | – | 0.6 | |||||||||||||||||||||
Other stock-based compensation | 0.9 | – | – | – | – | – | 0.9 | |||||||||||||||||||||
Preferred dividends paid by subsidiaries to non-controlling interest | – | – | – | – | – | (6.0) | (6.0) | |||||||||||||||||||||
Balance, September 30, 2011 | $1,369.1 | $146.7 | $3.5 | $(505.2) | $689.4 | $223.5 | $1,927.0 | |||||||||||||||||||||
For the nine months ended September 30, 2010 (as adjusted – note 24) |
| |||||||||||||||||||||||||||
Balance, December 31, 2009 | $1,097.9 | – | $3.0 | $(426.2) | $594.8 | $164.3 | $1,433.8 | |||||||||||||||||||||
Net income of Emera Incorporated | – | – | – | – | 169.6 | 6.1 | 175.7 | |||||||||||||||||||||
Other comprehensive loss, net of tax recovery of $3.2 | – | – | – | (3.0) | – | – | (3.0) | |||||||||||||||||||||
Cash dividends declared on preferred stock ($0.4980/share) | – | – | – | – | (3.0) | (3.0) | ||||||||||||||||||||||
Cash dividends declared on common stock ($1.1625/share) | – | – | – | – | (132.0) | – | (132.0) | |||||||||||||||||||||
Common stock issued under purchase plan | 21.4 | – | – | – | – | – | 21.4 | |||||||||||||||||||||
Senior management stock options exercised | 2.0 | – | – | – | – | – | 2.0 | |||||||||||||||||||||
Stock option expense | – | – | 0.5 | – | – | – | 0.5 | |||||||||||||||||||||
Other stock-based compensation | 0.3 | – | – | – | – | – | 0.3 | |||||||||||||||||||||
Issuance of preferred shares | – | $146.7 | – | – | – | – | 146.7 | |||||||||||||||||||||
Preferred dividends paid by subsidiaries to non-controlling interest | – | – | – | – | – | (6.0) | (6.0) | |||||||||||||||||||||
Other | – | – | – | – | – | (2.0) | (2.0) | |||||||||||||||||||||
Balance, September 30, 2010 | $1,121.6 | $146.7 | $3.5 | $(429.2) | $629.4 | $162.4 | $1,634.4 |
The accompanying notes are an integral part of these condensed financial statements.
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Emera Incorporated
Notes to the Condensed Consolidated Financial Statements (Unaudited)
As at September 30, 2011
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 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 at September 30, 2011 included the following:
• | Nova Scotia Power Inc. (“NSPI”), a fully-integrated electric utility and the primary electricity supplier in Nova Scotia serving approximately 490,000 customers; |
• | Bangor Hydro Electric Company (“Bangor Hydro”) and Maine Public Service Company (“MPS”), (a wholly-owned subsidiary of Maine and Maritimes Corporation (“MAM”)), which together provide transmission and distribution services to approximately 156,000 customers in Maine; |
• | an 80.2 percent interest in Light & Power Holdings Ltd. (“LPH”), the parent of The Barbados Light & Power Company Limited (“BLPC”), the sole utility operator on the island of Barbados serving approximately 120,000 customers; |
• | an 80.4 percent direct and indirect interest in Grand Bahama Power Company Limited (“GBPC”), a vertically-integrated electric utility on Grand Bahama Island serving approximately 19,000 customers; and |
• | Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145 kilometre pipeline carrying 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”). |
Emera Incorporated and its subsidiaries (“Emera” or the “Company”) also own investments in other energy related companies, including:
• | Emera Energy Services, a physical energy business which purchases and sells natural gas and electricity and provides related energy asset management services; |
• | Bayside Power Limited Partnership (“Bayside”), a 260-megawatt (“MW”) electricity generating facility in Saint John, New Brunswick owned by Emera Energy Inc.; |
• | Emera Utility Services Inc. (“EUS”), a utility services contractor; |
• | a 50 percent joint venture in Bear Swamp Power Company LLC (“Bear Swamp”), a 600-MW pumped storage hydro-electric facility in northern Massachusetts; |
• | a 12.9 percent interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400 kilometer pipeline which transports natural gas from offshore Nova Scotia to markets in Maritime Canada and the northeastern United States; |
• | a 19.1 percent interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically-integrated electric utility on the Caribbean island of St. Lucia; |
• | a 49.999 percent interest in California Pacific Utilities Ventures, LLC, (“CPUV”); |
• | a 7.2 percent investment in Algonquin Power & Utilities Corp (“APUC”); |
• | a 37.7 percent investment in Atlantic Hydrogen Inc. (“AHI”); and |
• | other investments. |
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B. Basis of Presentation
Effective January 1, 2011, Emera changed the basis of presentation of its financial statements (including the application of rate-regulated accounting policies for Emera’s rate-regulated subsidiaries) from Canadian Generally Accepted Accounting Principles (“CGAAP”) to United States Generally Accepted Accounting Principles (“USGAAP”).
These unaudited condensed consolidated financial statements are prepared and presented in accordance with USGAAP and the rules and regulations of the United States Securities and Exchange Commission (“SEC”) for Quarterly Reports. These unaudited condensed consolidated financial statements do not contain all disclosures required by USGAAP for annual audited financial statements. Accordingly, they should be read in conjunction with Emera Incorporated’s annual consolidated financial statements as at and for the year ended December 31, 2010, which were prepared in accordance with CGAAP; and note 24 to these condensed consolidated financial statements, detailing the CGAAP to USGAAP transition and reconciliation information.
In the opinion of management, these unaudited condensed consolidated 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, 2011.
All dollar amounts are presented in Canadian dollars.
C. Principles of Consolidation
The unaudited condensed consolidated financial statements of Emera Incorporated include the accounts of Emera Incorporated and its majority-owned subsidiaries, and a variable interest entity where Emera is the primary beneficiary. 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.
Where Emera does not control an investment, but has significant influence over operating and financing policies of the investee, the investment is accounted for under the equity method. The cost method of accounting is used for investments where Emera does not have significant influence over the operating and financial policies of the investee.
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; Q1 and Q4 are typically the strongest periods, reflecting colder weather and fewer daylight hours in the winter season in northeast North America, where a substantial portion of Emera’s electricity business is located.
E. Use of Management Estimates
The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Management evaluates the Company’s estimates on an on-going 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, depreciation, 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”) and contingencies. Actual results may differ significantly from these estimates.
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F. Regulatory Matters
Regulatory accounting applies where rates are established by, or subject to approval by, an independent third party regulator; are designed to recover the costs of providing the regulated products or services; and it is reasonable to assume rates are set at levels such that the costs can be charged to and collected from customers.
Regulatory assets represent incurred costs that have been deferred because it is probable that they will be recovered through future rates or tolls collected from customers. Management believes that existing regulatory assets are probable of recovery either because the Company received specific approval from the appropriate regulator, or due to regulatory precedent set for similar circumstances. If management no longer considers it probable that an asset will be recovered, the deferred costs are charged to income.
Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for previous collections. If management no longer considers it probable that a liability will be settled, the related amount is recognized in income.
For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective regulator.
G. Foreign Currency Translation
Monetary assets and liabilities, denominated in foreign currencies, are converted to Canadian dollars at rates of exchange prevailing at the balance sheet date. The resulting differences between the translation at the original transaction date and the balance sheet date are included in income.
Assets and liabilities of self-sustaining foreign operations are translated using the exchange rates in effect at the balance sheet date and the results of operations at the average rates for the period. The resulting exchange gains and losses on the assets and liabilities are deferred on the balance sheet in AOCL.
H. Revenue Recognition
Operating revenues are recognized when electricity is delivered to customers or when products are delivered and services are rendered. Revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity are recognized at rates approved by the respective regulator and recorded based on meter readings and estimates, which occur on a systematic basis throughout a month. At the end of each month, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The accuracy of the unbilled revenue estimate is affected by energy demand, weather, line losses and changes in the composition of customer classes.
The Company records the net investment in a lease under the direct finance method, which consists of the sum of the minimum lease payments net of estimated executory costs and unearned income. The difference between the gross investment and the cost of the leased item for a direct financing lease is recorded as unearned income at the inception of the lease. The unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease.
Other revenues are recognized when services are performed or goods delivered.
I. Research and Development Costs
Research and development costs are expensed as incurred.
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J. Share-Based Compensation
The Company has several share-based compensation plans: a common share option plan for senior management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; and a performance share unit (“PSU”) plan. The Company accounts for its plans in accordance with the fair value based method of accounting for share-based compensation. Share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period using the graded vesting method.
K. Employee Benefits
The costs of the Company’s pension and other post-employment benefit programs for employees are expensed over the periods during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-employment plans on the balance sheet and recognizes changes in funded status in the year the change occurs. The Company recognizes the unamortized gains and losses and past service costs in AOCL.
L. Earnings per Share
Basic earnings per share (“EPS”) is determined by dividing net income attributable to common shareholders by the weighted average number of common shares and DSUs outstanding during the period. Diluted EPS is computed by dividing net income attributable to common shareholders by the weighted average number of common shares and DSUs outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include Company contributions to the employee common share purchase plan, PSUs and the senior management stock option plan.
M. Cash and Cash Equivalents
Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition. The short-term investments of $42.8 million have an effective interest rate of 3.3 percent at September 30, 2011 (December 31, 2010 – nil short-term investments).
N. Receivables and Allowance for Doubtful Accounts
Customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date.
The Company is exposed to credit risk with respect to amounts receivable from customers. Credit risk assessments are conducted on all new customers and deposits are requested on any high risk accounts. The Company also maintains provisions for potential credit losses, which are assessed on a regular basis.
Management estimates uncollectible accounts receivable after considering historical loss experience and the characteristics of existing accounts. Provisions for losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible.
O. Inventory
Inventory, consisting of fuel and materials, is measured at the lower of cost or market. Cost is determined using the weighted average cost method. Fuel and materials are charged to inventory when purchased and then expensed or capitalized, as appropriate, using the weighted average cost method.
P. Property, Plant and Equipment
Property, plant and equipment are recorded at original cost, including allowance for funds used during construction (“AFUDC”) or capitalized interest, net of contributions received in aid of construction.
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The cost of additions, including betterments and replacements of units of property plant and equipment are included in “Property, plant and equipment”. When units of regulated property, plant and equipment are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation with no gain or loss reflected in income. Where a disposition of non-regulated property, plant and equipment occurs, gains and losses are included in income as the dispositions occur.
Normal maintenance projects are expensed as incurred. Planned major maintenance projects that do not increase the overall life of the related assets are expensed. When maintenance increases the life or value of the underlying asset, the cost is capitalized.
Q. Capitalization Policy
The cost of property, plant, and equipment represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, AROs and overhead directly attributable to the capital project. Overhead includes corporate costs such as finance, information technology and executive, along with other costs related to support functions, employee benefits, insurance, inventory, and fleet operating and maintenance.
R. Allowance for Funds Used During Construction
AFUDC represents the cost of financing regulated construction projects and is capitalized to the cost of property, plant and equipment. As approved by their respective regulator, NSPI, Bangor Hydro, MPS, GBPC and Brunswick Pipeline include an equity cost component in AFUDC in addition to a charge for borrowed funds. AFUDC is a non-cash item; cash is realized under the rate-making process over the service life of the related property, plant and equipment through future revenues resulting from a higher rate base and recovery of higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to “Interest expense, net”, while the equity component is included as a reduction to “Other income (expenses), net”. AFUDC is calculated using a weighted average cost of capital, as per the method of calculation approved by the respective regulator, and is compounded semi-annually. The annual AFUDC consisted of the following:
2011 | 2010 | |||||||
NSPI | 7.87% | 7.96% | ||||||
Bangor Hydro | 8.95% | 8.59% | ||||||
MPS | 8.89% | N/A | ||||||
GBPC | 10.00% | N/A |
S. Depreciation
Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each category. The service lives of regulated assets are determined based on formal depreciation studies and require the appropriate regulatory approval.
The estimated useful lives, in years, for each major category of property, plant and equipment consist of the following:
Generation | 15 to 131 | |||
Transmission | 10 to 83 | |||
Distribution | 11 to 75 | |||
General plant | 5 to 53 |
T. Intangible Assets
Intangible assets consist primarily of land rights and computer software with definite lives. Intangible assets are presented in “Other” as part of “Other assets” on the Balance Sheet. Amortization is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each category. The service lives of regulated assets are determined based on formal depreciation studies and require the appropriate regulatory approval.
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The estimated useful lives, in years, for each major category of intangibles with definite lives consist of the following:
Land rights | 50 to 143 | |||
Computer software | 3 to 10 |
U. Asset Impairment
Goodwill and Other Intangibles
Goodwill and other intangible assets with indefinite lives are not amortized, but are subject to an annual impairment test. Emera’s reporting units containing goodwill perform annual goodwill impairment tests during the fourth quarter of each year, and interim impairment tests are performed when impairment indicators are present. The carrying amount of the reporting unit’s goodwill is considered not recoverable if the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value.
Long-Lived Assets
Other long-lived assets require an impairment review when events or circumstances indicate that the carrying amount may not be recoverable. Emera bases its evaluation of other long-lived assets on the presence of impairment indicators such as the future economic benefit of the assets, any historical or future profitability measurements, and other external market conditions or factors.
Assets Held and Used:The carrying amount of assets held and used is considered not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value.
Assets Held for Sale:The carrying value of assets held for sale is considered not recoverable if it exceeds the fair value less the cost to sell. An impairment charge is recorded for any excess of the carrying value over the fair value less estimated costs to sell.
Cost and Equity Method Investments
The carrying value of investments accounted for under the cost and equity methods are assessed for impairment by comparing the fair values of these investments to their carrying values, if a fair value assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists and it is determined to be other-than-temporary, a charge is recognized equal to the amount the carrying value exceeds the investment’s fair value.
Financial Assets
The Company assesses at each balance sheet date whether there is objective evidence that a financial asset or a group of financial assets is impaired. In the case of equity securities classified as available-for-sale, a significant or prolonged decline in the fair value of the security below its cost is considered as an indicator that the securities are impaired. In the case of debt securities classified as available-for-sale, a breach of contract such as default or delinquency in interest or principal payments, or evidence of significant financial difficulty of the issuer is considered an indicator of impairment. If any such evidence exists for available-for-sale financial assets, the cumulative loss, measured as the difference between the acquisition cost and the current fair value, less any impairment loss on that financial asset previously recognized in income, is removed from AOCL and recognized on the Consolidated Statements of Income.
There were no material asset impairments for the three and nine months ended September 30, 2011 and 2010.
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V. Debt Financing Costs
The Company capitalizes the external costs of obtaining debt financing and includes them in “Other” as part of “Other assets” on the balance sheet. The deferred charge is amortized over the life of the related debt on an effective interest basis and included in “Interest expense, net”.
W. Income Taxes and Investment Tax Credits
Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in the financial statements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference between the carrying value of assets and liabilities on the balance sheet and their respective tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. Emera recognizes the effect of income tax positions only when it is more likely than not that they will be realized. If management subsequently determines that it is likely that some or all of a deferred income tax asset will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized.
Generally, investment tax credits are recorded as a reduction to income tax expense in the current or future periods to the extent that realization of such benefit is more likely than not. Investment tax credits earned by Bangor Hydro or MPS on regulated assets are deferred and amortized over the estimated service lives of the related properties, as required by United State tax laws and Maine regulatory practices.
Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively.
X. Asset Retirement Obligation
An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel.
An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation using the Company’s credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives, and governmental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. Accretion expense is included as part of “Depreciation and amortization”. Any accretion expense not yet approved by the regulator is deferred to a regulatory asset in “Property, plant and equipment” and included in the next depreciation study.
During Q2 2011, NSPI’s estimated future cash flows with respect to AROs were updated to reflect the results of a settlement agreement with stakeholders which was approved by the UARB, following the completion of a depreciation study. The changes resulted from a change in estimates of retirement dates and future decommissioning costs. The new accretion rates shall be effective January 1, 2012, pending approval of the 2012 proposed General Rate Application (“GRA”) settlement by the UARB.
Some transmission and distribution assets may have conditional AROs, which are required to be estimated and recorded as a liability. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Management monitors these obligations and a liability is recognized at fair value when an amount can be determined.
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Y. Derivatives and Hedging Activities
Emera’s risk management policies and procedures provide a framework through which management monitors various risk exposures. The risk management practices are overseen by the Board of Directors. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group which is independent of all operations.
The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange and interest rates using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, and coal, oil and gas futures, options, forwards, and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. These physical and financial contracts are classified as held-for-trading (“HFT”). Collectively these contracts are considered “derivatives”.
The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. Emera continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exception where the criteria are no longer met.
Derivatives qualify for hedge accounting if they meet stringent documentation requirements, and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the effective portion of the change in the fair value of derivatives is deferred to AOCL and recognized in income in the same period the related hedged item is realized. Any ineffective portion of the change in the fair value of the cash flow hedges is recognized in net income in the reporting period.
Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value, with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.
Derivatives entered into by NSPI that are documented as economic hedges, and for which the NPNS exception has not been taken, receive regulatory deferral as approved by the Nova Scotia Utility and Review Board (“UARB”). 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 when the derivatives settle. Management believes that any gains or losses resulting from settlement of these derivatives will be refunded to or collected from customers in future rates.
Derivatives that do not meet any of the above criteria are designated as HFT derivatives and are recorded on the balance sheet at fair value, with changes normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply.
Emera classifies gains and losses on derivatives as a component of fuel for generation and purchased power, other expenses, inventory and property, plant and equipment, depending on the nature of the item being economically hedged. Cash flows from derivative activities are presented in the same category as the item being hedged within operating or investing activities on the Consolidated Statements of Cash Flows.
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Z. Fair Value Measurement
The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exception (refer to notes 21 and 22). Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly arms-length transaction between market participants at the measurement date. Fair value measurements are required to reflect the assumptions that market participants would use in pricing an asset or liability based on the best available information including the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model. The Company uses a fair value hierarchy, based on the relative objectivity of the inputs used to measure fair value, with Level 1 representing the highest.
The three levels of the fair value hierarchy are defined as follows:
Level 1 Valuations – Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities.
Level 2 Valuations – 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 Valuations – 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.
AA. Variable Interest Entities
The Company performs ongoing analysis to assess whether it holds any variable interest entities (“VIEs”). To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly-owned facilities.
VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera is not deemed the primary beneficiary, the VIE is not recorded in the Company’s consolidated financial statements.
LPH 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. LPH holds a variable interest in the SIF for which it was determined that LPH was the primary beneficiary and, accordingly, the SIF must be consolidated by LPH. In its determination that LPH controls the SIF, management considered that in substance the activities of the SIF are being conducted on behalf of LPH’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because LPH, 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.
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NSPI holds a variable interest in Renewable Energy Services Ltd. (“RESL”), a VIE for which it was determined that NSPI was not the primary beneficiary since it does not have the controlling financial interest of RESL. NSPI has provided a $23.5 million guarantee with no set term for the indebtedness of RESL under a loan agreement between RESL and a third party lender, in support of which NSPI holds a security interest in all present and future assets of RESL. The guarantee arose in conjunction with NSPI’s participation in a wind energy project at Point Tupper, Nova Scotia, which is being operated by RESL. Under a purchased power agreement, NSPI purchases, at a fixed price, 100 percent of the power generated by the project. A default by RESL, under its loan agreement, would require NSPI to make payment under the guarantee. As at September 30, 2011, RESL’s indebtedness under the loan agreement was $22.2 million (December 31, 2010 – $23.1 million), and NSPI has not recorded a liability in relation to the guarantee.
Bangor Hydro holds a variable interest in Chester Static Var Compensator (“SVC”), a VIE for which it was determined that Bangor Hydro was not the primary beneficiary since it does not have the controlling financial interest of Chester SVC. A subsidiary of Bangor Hydro is a 50 percent general partner in Chester SVC, which owns electrical equipment that supports a major transmission line. A wholly-owned subsidiary of Central Maine Power Company owns the other 50 percent interest. Chester SVC is 100 percent debt financed and accordingly the partners have no equity interest; and the holders of the SVC notes are without recourse against the partners or their parent companies.
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.
Emera’s consolidated VIE is recorded as an “Available-for-sale investment”. The following table provides information about Emera’s consolidated and unconsolidated VIEs as at September 30, 2011 and 2010:
For the millions of Canadian dollars | Nine months ended September 30 | |||||||||||||||
2011 | 2010 | |||||||||||||||
Total assets | Maximum exposure to loss | Total assets | Maximum exposure to loss | |||||||||||||
Consolidated VIE | ||||||||||||||||
BLPC SIF Available-for-sale investment | $57.6 | $57.6 | – | – | ||||||||||||
Unconsolidated VIEs in which Emera has Variable Interests | ||||||||||||||||
RESL | – | 23.5 | – | $23.5 | ||||||||||||
Chester SVC | – | – | – | – |
BB. Available-for-sale Investments
Assets designated as Available-for-sale are non-derivative financial assets (equity and debt securities) intended to be held for an indefinite period of time, and may be sold in response to needs for liquidity or changes in interest rates, exchange rates or equity prices.
Regular purchases and sales of financial assets are recognized at fair value, including transaction costs, on the trade date, the date on which the Company commits to purchase or sell the asset; and subsequently carried at fair value based on current bid prices on the market. Unrealized gain and losses arising from changes in the fair value of available-for-sale assets are recognized in AOCL until the financial asset is sold, or otherwise disposed of, or until the financial investment is determined to be impaired, at which time the cumulative gain or loss will be included in income for the period.
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Interest on available-for-sale debt securities is calculated using the effective interest method and is recognized on the Consolidated Statements of Income in “Other income (expenses), net”. Dividends on available-for-sale equity securities are recognized on the Consolidated Statements of Income in “Other income (expenses), net”.
CC. Derivative Positions and 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”.
2. CHANGE IN ACCOUNTING POLICY
Emera tests goodwill impairment annually using a fair value approach.
In Q1 2011, the Company changed the date of its annual impairment test from March 31 to October 1. The change was made to more closely align the impairment testing date with the long-range planning and forecasting process. Emera believes the change in the annual impairment testing date did not delay, accelerate, or avoid an impairment charge and has determined this change in accounting policy is preferable under the circumstances and does not result in adjustments to the financial statements when applied retrospectively. During fiscal year 2010, the annual impairment test was performed as at December 31, 2010 for all entities except Bangor Hydro, which was performed in March 2011.
3. FUTURE ACCOUNTING PRONOUNCEMENTS
Intangibles – Goodwill and Other, Accounting Standards Update (“ASU”) Number (“No.”) 2011-08
In September 2011, The Financial Accounting Standards Board (“FASB”) issued an accounting standards update amending Accounting Standards Codification (“ASC”) 350 to simplify how entities test goodwill for impairment. The amendment permits an entity to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test. Under these amendments, an entity would not be required to calculate the fair value of a reporting unit unless the entity determines, based on the qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount. The amendments include a number of events and circumstances for an entity to consider in conducting the qualitative assessment. ASU No. 2011-08 is effective for annual and goodwill impairment tests performed for fiscal period beginning after December 15, 2011, with early adoption permitted. The Company has decided to adopt this standard early; the new approach will be used in its annual impairment testing as of October 1, 2011. Adoption of this standard is not expected to have a material impact on the financial statements.
Compensation – Retirement Benefits – Multiemployer Plans, ASU No. 2011-09
In September 2011, FASB issued an accounting standards update amending ASC 715-80 to address concerns from various users of financial statements on the lack of transparency about an employer’s participation in a multiemployer pension plan. The amendments require companies participating in multiemployer pension plans to disclose more information about their involvement in those plans. Retrospective application of the new disclosures will be required. ASU 2011-09 is effective for fiscal years ending after December 15, 2011. The adoption of this standard will increase disclosures related to the multiemployer pension plans in place at GBPC.
Other Comprehensive Income, ASU No. 2011-05
In June 2011, FASB issued an accounting standards update amending ASC 220 to improve the comparability, consistency and transparency of comprehensive income reporting. The guidance requires that items of net income, items of other comprehensive income and total comprehensive income be presented in one continuous statement or two separate but consecutive statements. Items that are reclassified from other comprehensive income to net income must be presented separately on the face of the financial statements. ASU No. 2011-05 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Retrospective application of the new disclosures will be required for comparative periods. The adoption of this update will change the order in which certain financial statements are presented and provide additional detail on those financial statements where applicable, but will not have any other impact to the financial statements.
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Fair Value Measurement, ASU No. 2011-04
In May 2011, FASB issued an accounting standards update amending ASC 820 to achieve common fair value measurement and disclosure requirements between U.S. GAAP and International Financial Reporting Standards (“IFRS”). The amendments clarify the intent concerning the application of existing requirements and include some instances where a particular principle or requirement for measuring fair value or disclosing information related to fair value measurements has changed. ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. Management is currently evaluating the impact that the adoption will have on our financial statements.
4. SEGMENT INFORMATION
The Company is required to disclose segment information based on management’s decision making process regarding the allocation of resources to segments, and measurement of segment performance. As at September 30, 2011, Emera has five reporting segments, specifically:
• | NSPI; |
• | Maine Utility Operations (Bangor Hydro and MPS); |
• | Caribbean Utility Operations (BLPC, GBPC and Lucelec); |
• | Brunswick Pipeline; and |
• | Other (Emera Energy Services, EUS, M&NP, other strategic investments, holding companies, and inter-segment eliminations). |
Bangor Hydro and MPS have been combined into Maine Utility Operations as the segments have similar economic characteristics. In Q4 2010, MPS was reported in “Other”. In previous years, the Company reported Caribbean Utility Operations in “Other” as these entities did not meet segment reporting requirements. Prior periods have been retrospectively restated to reflect the Maine Utility and Caribbean Utility Operations as segments.
millions of Canadian dollars | NSPI | Maine Utility Operations | Caribbean Utility Operations | Brunswick Pipeline | Other | Total | ||||||||||||||||||
For the three months ended September 30, 2011 | ||||||||||||||||||||||||
Operating revenues from external customers | $276.0 | $51.3 | $114.5 | $12.5 | $41.8 | $496.1 | ||||||||||||||||||
Inter-segment (expenses) revenues | (3.3) | (0.4) | (0.1) | (7.8) | 11.6 | – | ||||||||||||||||||
Net income (loss) attributable to common shareholders | 21.0 | 9.4 | 10.7 | 5.0 | (5.3) | 40.8 | ||||||||||||||||||
For the nine months ended September 30, 2011 | ||||||||||||||||||||||||
Operating revenues from external customers | 943.8 | 150.5 | 298.3 | 37.0 | 122.8 | 1,552.4 | ||||||||||||||||||
Inter-segment (expenses) revenues | (11.3) | (1.2) | (0.2) | (23.1) | 35.8 | – | ||||||||||||||||||
Net income attributable to common shareholders | 101.3 | 27.2 | 43.7 | 14.8 | 7.3 | 194.3 | ||||||||||||||||||
For the three months ended September 30, 2010 | ||||||||||||||||||||||||
Operating revenues from external customers | $272.2 | $48.6 | – | $12.1 | $61.1 | $394.0 | ||||||||||||||||||
Inter-segment (expenses) revenues | (19.5) | (0.5) | – | (7.6) | 27.6 | – | ||||||||||||||||||
Net income attributable to common shareholders | 18.6 | 11.5 | $2.8 | 5.9 | 1.5 | 40.3 | ||||||||||||||||||
For the nine months ended September 30, 2010 | ||||||||||||||||||||||||
Operating revenues from external customers | 888.2 | 129.0 | – | 36.9 | 143.1 | 1,197.2 | ||||||||||||||||||
Inter-segment (expenses) revenues | (38.8) | (1.3) | – | (23.4) | 63.5 | – | ||||||||||||||||||
Net income attributable to common shareholders | 99.3 | 24.1 | 27.5 | 14.6 | 1.1 | 166.6 |
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5. REGULATED FUEL ADJUSTMENT
NSPI
The regulated fuel adjustment related to the fuel adjustment mechanism (“FAM”) for NSPI includes the effect of fuel costs in both the current and two 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”. |
• | The recovery from (rebate to) customers of under (over) recovered costs from prior years. |
The regulated fuel adjustment consisted of the following:
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Under-recovery of current year fuel costs | $(10.3) | $(17.8) | $(24.5) | $(58.3) | ||||||||||||
Recovery from (rebate to) customers of prior years’ fuel costs | 5.9 | (5.2) | 20.5 | (16.7) | ||||||||||||
Regulated fuel adjustment | $(4.4) | $(23.0) | $(4.0) | $(75.0) |
The Company has recognized a deferred income tax expense related to the regulated fuel adjustment based on NSPI’s enacted statutory tax rate.
The FAM regulatory asset includes amounts recognized as a fuel adjustment, associated interest that is included in “Interest expense, net”, and the application of the deferral of tax benefits (see Regulatory Matters, note 13). The following table shows the balance sheet classification of the various components of the FAM balances:
As at millions of Canadian dollars | September 30 2011 | December 31 2010 | ||||||
Current regulatory asset | $54.0 | $27.2 | ||||||
Long-term regulatory asset | 33.4 | 65.7 | ||||||
Net FAM regulatory asset | $87.4 | $92.9 | ||||||
Current deferred income tax liability | $(16.8) | $(8.8) | ||||||
Long-term deferred income tax liability | (10.4) | (20.4) | ||||||
Net FAM deferred income tax liability | $(27.2) | $(29.2) |
BLPC
All BLPC fuel costs are passed to customers through the fuel clause adjustment (“fuel surcharge”). Fair Trading Commission, Barbados has approved the calculation of the fuel surcharge, which is adjusted on a monthly basis. BLPC has the ability to carryover an under-recovery to later months to smooth the fuel surcharge for customers.
GBPC
The current base tariff is calculated based on a price of $20 USD per barrel of oil. The amount by which actual fuel costs exceed $20 USD dollars per barrel is recovered or rebated through the fuel surcharge, which is adjusted on a monthly basis. The methodology for calculating the amount of the fuel surcharge has been approved by The Grand Bahama Port Authority (“GBPA”).
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6. OTHER INCOME (EXPENSES), NET
Other income (expenses), net consisted of the following:
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Gain on business acquisitions (note 16) | $0.3 | – | $28.3 | $22.5 | ||||||||||||
Gain on exchange of subscription receipts to common shares of APUC (1) | – | – | 15.1 | – | ||||||||||||
Allowance for equity funds used during construction | 3.8 | $3.8 | 9.1 | 8.5 | ||||||||||||
Amortization of defeasance costs | (3.0) | (3.0) | (9.1) | (9.1) | ||||||||||||
Foreign exchange (losses) gains | (3.7) | – | (3.5) | 0.4 | ||||||||||||
Foreign exchange losses recovered through the FAM | (1.6) | (2.2) | (4.3) | (5.9) | ||||||||||||
Recognition of regulatory asset in GBPC | 4.4 | – | 4.4 | – | ||||||||||||
Other | 1.6 | 1.7 | 1.6 | 1.6 | ||||||||||||
$1.8 | $0.3 | $41.6 | $18.0 |
(1) | Pursuant to an April 2009 subscription agreement with APUC, on January 1, 2011, Emera exchanged subscription receipts it acquired in 2009 into 8.523 million APUC common shares issued at $3.25 per share, resulting in a gain of $15.1 million (after-tax gain of $12.8 million). |
7. INTEREST EXPENSE, NET
Interest expense, net consisted of the following:
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Interest on long-term debt(1) | $39.8 | $37.1 | $119.2 | $106.8 | ||||||||||||
Interest on short-term debt | 3.6 | 2.9 | 11.1 | 6.9 | ||||||||||||
Allowance for borrowed funds used during construction | (3.4) | (3.6) | (8.1) | (7.6) | ||||||||||||
Interest revenue | (1.2) | (1.3) | (5.2) | (2.5) | ||||||||||||
Other | 1.5 | 1.0 | 5.1 | 7.9 | ||||||||||||
$40.3 | $36.1 | $122.1 | $111.5 |
(1) | Interest on long-term debt includes amortization of debt financing costs, premiums and discounts. |
8. INCOME TAXES
Income taxes for the three months ended September 30, 2011 were a recovery of $5.7 million (2010 – $4.0 million expense) and for the nine months ended September 30, 2011 were a recovery of $10.4 million (2010 – $2.5 million expense). Income taxes are lower for the three months ended September 30, 2011 compared to 2010 primarily due to decreased income before provision for income taxes, decreased regulatory amortization, a lower FAM regulatory asset and a lower statutory income tax rate. Income taxes were lower for the nine months ended September 30, 2011 compared to 2010 primarily due to decreased regulatory amortization, a lower FAM regulatory asset, and the non-taxable portion of a gain on APUC subscription receipts, partially offset by increased income before provision for income taxes at a lower statutory income tax rate.
The Company’s effective tax rate for the three months ended September 30, 2011 was a recovery of 13.4 percent and for the three months ended September 30, 2010 was an expense of 8.1 percent. The Company’s effective tax rate for the nine months ended September 30, 2011 was a recovery of 5.2 percent and for the nine months ended September 30, 2010 was an expense of 1.4 percent. The effective tax rates for the three and nine months ended September 30, 2011 and September 30, 2010 were lower than the 2011 and 2010 statutory income tax rates of 32.5 percent and 34.0 percent, respectively, primarily due to the effect of deferred income taxes on regulated income being deferred to regulatory assets and regulatory liabilities and therefore not impacting tax expense.
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9. RECEIVABLES, NET
Receivables, net consisted of the following:
As at millions of Canadian dollars | September 30 2011 | December 31 2010 | ||||||
Customer accounts receivable – billed | $290.6 | $250.8 | ||||||
Customer accounts receivable – unbilled | 109.8 | 126.4 | ||||||
Total customer accounts receivable | 400.4 | 377.2 | ||||||
Allowance for doubtful accounts | (8.0) | (6.6) | ||||||
Customer accounts receivable, net | 392.4 | 370.6 | ||||||
Other | 21.0 | 22.3 | ||||||
$413.4 | $392.9 |
10. INVENTORY
Inventory consisted of the following:
As at millions of Canadian dollars | September 30 2011 | December 31 2010 | ||||||
Fuel | $132.9 | $129.1 | ||||||
Materials | 67.7 | 48.7 | ||||||
$200.6 | $177.8 |
11. OTHER CURRENT LIABILITIES
Other current liabilities consisted of the following:
As at millions of Canadian dollars | September 30 2011 | December 31 2010 | ||||||
Accrued charges | $64.7 | $59.6 | ||||||
Accrued interest on long-term debt | 44.7 | 37.7 | ||||||
Sales taxes payable | 8.0 | 7.0 | ||||||
Dividends payable | 44.9 | 2.1 | ||||||
Other | 6.3 | 3.9 | ||||||
$168.6 | $110.3 |
12. | LONG-TERM DEBT |
In August 2011, Emera increased its committed syndicated revolving bank line of credit from $600 million to $700 million, and NSPI reduced its committed syndicated revolving bank line of credit from $600 million to $500 million. The maturity of both facilities was extended from June 2013 to June 2015.
13. REGULATORY MATTERS
NSPI
NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (the “Act”) and is subject to regulation under the Act by the UARB. The Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings held from time to time at NSPI’s or the UARB’s request.
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NSPI is regulated under a cost-of-service model, with rates set to recover prudently-incurred costs of providing electricity service to customers, and provide an appropriate return to investors. NSPI’s prescribed regulated return on equity (“ROE”) range for 2011 is 9.1 percent to 9.6 percent based on an actual regulated common equity component of up to 40 percent of average regulated capitalization. NSPI has a FAM, which enables NSPI to seek recovery of fuel costs through regularly scheduled rate adjustments. Differences between actual fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year. The FAM has an incentive component, whereby NSPI retains or absorbs 10 percent of the over or under recovered amount to a maximum of $5 million.
On May 13, 2011, NSPI filed a GRA with the UARB requesting an average 7.3 percent rate increase across all customer classes effective January 1, 2012. On September 19, 2011, prior to the commencement of the GRA hearing, NSPI and customer representatives announced a proposed settlement for 2012 electricity rates. If approved by the UARB, the settlement will result in an average rate increase of approximately 5.0 percent for all customers, effective January 1, 2012. Rates are proposed based on a 9.2 percent ROE, applied to a 37.5 percent common equity component. Due to the uncertainty in the pulp and paper industry, the proposed settlement defers any unrecovered 2012 non-fuel electric charges from NSPI’s two largest customers to be recovered beginning in 2013. A decision is expected during Q4 2011. NSPI’s last general rate hearing was settled by agreement with customer representatives on November 5, 2008 and the UARB approved an average 9.3 percent increase in customer rates effective January 1, 2009.
On December 23, 2010, the UARB granted NSPI approval to defer $14.5 million of tax benefits which arose in 2010 related to renewable energy projects. On July 21, 2011, the UARB approved an agreement NSPI reached with stakeholders to apply the deferral against the FAM regulatory asset effective January 1, 2011. The application of the deferral reduced the amount of the FAM balance outstanding with the reduction applied to the amount that would otherwise be recovered from customers in 2012.
On May 11, 2011, the UARB approved changes to NSPI’s depreciation rates following NSPI’s completion of a depreciation study and a settlement agreement with stakeholders. The overall impact on the average depreciation rate is immaterial. The new depreciation rates shall be effective January 1, 2012 pending approval of the 2012 proposed GRA settlement by the UARB.
On December 8, 2010, as part of the FAM regulatory process, the UARB approved NSPI’s setting of the 2011 base cost of fuel and the under-recovered fuel related costs from prior years. The UARB approved the recovery of the FAM balance as filed from customers over three years effective January 1, 2011, with 50 percent to be recovered in 2011, 30 percent in 2012 and 20 percent in 2013. The decision resulted in an average rate increase of approximately 4.5 percent for customers in 2011. Pursuant to the FAM Plan of Administration, NSPI is entitled to earn a return on the balance of fuel related costs.
Maine Utilities
Both Bangor Hydro and MPS’ core businesses are the transmission and distribution of electricity, with distribution operations and stranded cost recoveries regulated by the Maine Public Utilities Commission (“MPUC”). Each Company’s transmission operations are regulated by the Federal Energy Regulatory Commission (“FERC”). The rates for these three elements are established in distinct regulatory proceedings.
Distribution Operations
Both Bangor Hydro and MPS’ distribution businesses operate under a traditional cost-of-service regulatory structure.
Distribution rates are set based on an allowed ROE of 10.2 percent, on a common equity component of 50 percent. MPS has the ability to return to the MPUC to request new rates on January 1, 2012 or any time thereafter.
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Stranded Cost Recoveries
Pursuant to the Maine restructuring law, effective March 1, 2000, electric utilities in Maine are entitled to recover all prudently incurred stranded costs that resulted from the restructuring law that cannot reasonably be mitigated. Generally, the regulated rates to recover stranded costs are set every three years on a levelized basis and determined under a traditional cost of service approach.
Bangor Hydro
In May 2011, the MPUC approved an approximate 27 percent increase in Bangor Hydro’s stranded cost rates for the period of June 1, 2011 to February 28, 2014. The increased stranded cost revenues are offset, for the most part, by changes in regulatory amortizations, purchased power expense and resale of purchased power (“annual stranded costs”). The allowed ROE used in setting these new stranded cost rates is 7.35 percent, with a common equity component of 48 percent.
While the stranded cost revenue requirements differ throughout the period due to changes in annual stranded costs, the actual annual stranded cost revenues are the same during the period. To levelize the impact of the varying revenue requirements, cost or revenue deferrals are recorded as a regulatory asset or liability, and addressed in subsequent stranded cost rate proceedings, where customer rates are adjusted accordingly.
MPS
In March of 2010, the MPUC approved a settlement stipulation in which MPS’ stranded cost rates remained the same as in the previous three-year agreement. This revised two-year agreement, which expires on December 31, 2011, has an ROE of 9.6 percent for the first year and 8.6 percent for the second year and a common equity component of 50 percent. MPS uses its deferred fuel balance from an expired power purchase contract to levelize rates.
Transmission Operations
Bangor Hydro
Bangor Hydro’s local transmission rates are set annually on June 1, based upon a formula that utilizes prior year actual transmission investments and expenses, adjusted for current year forecasted transmission investments and expenses. The allowed ROE for these local transmission investments is 11.14 percent. The common equity component is based upon the prior calendar year actual average balances. On June 1, 2011, Bangor Hydro’s local transmission rates decreased by approximately 10 percent (2010 – increased 37 percent).
MPS
MPS transmission rates are set annually based on a formula through the Open Access Transmission Tariff (“OATT”). Rates derived from the previous calendar year results go into effect June 1 for wholesale customers and July 1 for retail customers. The allowed ROE for transmission operations is 10.5 percent, and is based on the actual prior calendar year common equity balances. The allowed ROE is determined by negotiation with customers in the formula change years of the OATT, which occur every three years. The last OATT formula change year was 2009. On June 1, 2011, MPS’ local transmission rates increased by 3 percent for wholesale customers (2010 – increased 63 percent) and by 4 percent for retail customers (2010 – increased by 64 percent) on July 1, 2011.
Regionally Funded Transmission Service
Bangor Hydro
Bangor Hydro’s bulk transmission assets are managed by the ISO-New England (“ISO”) as part of a region-wide pool of assets. Regional customers proportionally bear the cost of these pool transmission investments. The ISO manages the region’s bulk power generation and transmission systems and administers the open access transmission tariff.
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Bangor Hydro’s pool transmission investment recovery results from an annual formula rate filing made with the ISO each year and effective on June 1. This formula is based on prior year regionally funded transmission investments and expenses, adjusted for current year forecasted investments and expenses. The allowed ROE for these transmission investments ranges from 11.64 percent to 12.64 percent. The common equity component is based upon the prior calendar year average balances. On June 1, 2010, Bangor Hydro’s regional transmission revenue requirement increased by 22 percent; and on June 1, 2011, it increased by a further 9 percent.
MPS
MPS’ electric service territory is not interconnected to the New England bulk power system, and MPS is not a member of the ISO.
The Barbados Light & Power Company Limited
BLPC, a wholly-owned subsidiary of LPH, is the sole electric utility on the island of Barbados.
BLPC is subject to regulation under the Utilities Regulation (Procedural) Rules 2003 (“Rules”) by Fair Trading Commission, Barbados, an independent regulator. The Rules give the Fair Trading Commission, Barbados utility regulation functions which include establishing principles for arriving at rates to be charged, monitoring the rates charged to ensure compliance, and setting the maximum rates for regulated utility services. The government of Barbados has granted BLPC a franchise to produce, transmit and distribute electricity on the island until 2028.
BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and providing an appropriate return to investors. BLPC’s approved regulated return on assets for 2011 is 10 percent.
BLPC’s first rate adjustment since 1983 was approved in January 2010 and was effective March 1, 2010.
All BLPC fuel costs are passed to customers through the fuel surcharge. Fair Trading Commission, Barbados has approved the calculation of the fuel surcharge, which is adjusted on a monthly basis. BLPC has the ability to carryover an under-recovery to later months to smooth the fuel surcharge for customers.
Grand Bahama Power Company Limited
GBPC is the sole utility operator on Grand Bahama Island. GBPA regulates the utility and has granted GBPC a licensed, regulated and exclusive franchise to produce, transmit, and distribute electricity on the island until 2054. There is a fuel pass through mechanism and flexible tariff adjustment policy to ensure that costs are recovered and a reasonable return earned.
The current base fuel tariff is calculated based on a price of $20 USD per barrel of oil. The amount by which actual fuel costs exceed $20 USD dollars per barrel is recovered or rebated through the fuel surcharge, which is adjusted on a monthly basis. The methodology for calculating the amount of the fuel surcharge has been approved by GBPA.
On April 12, 2011, GBPA approved the recovery of the net costs of leasing temporary generation to meet peak demand for electricity as part of the fuel surcharge; and a 4.5 percent base tariff rate increase effective January 1, 2011. The collection from customers of the 4.5 base tariff increase will be deferred and recorded as a regulatory asset until the commission of the new 52-MW diesel generation unit scheduled to be on line mid-2012 at which time the regulatory asset will be amortized into earnings. GBPA also approved the amortization over a 5 year period of the remaining book value and reclamation costs of generation units that may be retired as a result of the commissioning of the new 52 MW diesel facility and a 2012 tariff rate increase to provide GPBC with a 10 percent return on rate base.
On July 14, 2011, GBPA approved the recovery of a $4.6 million USD asset impairment charge recorded in 2010. As a result, the charge was reversed through earnings in Q3, 2011, and instead recorded as a regulatory asset which will be amortized into income over a 25 year period commencing upon completion of the new generation facility referred to above.
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Brunswick Pipeline
Brunswick Pipeline is a 145-kilometre pipeline delivering natural gas from the Canaport Liquified Natural Gas (“LNG”) Terminal in Saint John, New Brunswick to the Maritimes and Northeast Pipeline. Brunswick Pipeline entered into a 25 year firm service agreement commencing in July 2009 with Repsol Energy Canada. The pipeline is considered a Group II pipeline regulated by the National Energy Board (“NEB”). The NEB Gas Transportation Tariff is filed by Brunswick Pipeline in compliance with the requirements of the NEB Act and sets forth the terms and conditions of the transportation rendered by Brunswick Pipeline.
14. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME
Investments subject to significant influence consisted of the following:
2011 | 2010 (as adjusted) | |||||||||||||||||||
millions of Canadian dollars | Percentage of Ownership | September 30 Carrying value | September 30 Equity income (loss) | December 31 Carrying | September 30 Equity income (loss) | |||||||||||||||
APUC(1) | 7.2 | $42.1 | $1.4 | – | – | |||||||||||||||
CPUV | 49.999 | 39.6 | 2.3 | – | – | |||||||||||||||
Bear Swamp | 50.0 | (17.7) | 6.6 | $(14.2) | $2.4 | |||||||||||||||
M&NP(1) | 12.9 | 125.3 | 6.3 | 118.8 | 6.3 | |||||||||||||||
LPH(2) | – | – | 0.7 | 111.7 | 3.4 | |||||||||||||||
Lucelec(1) | 19.1 | 26.7 | 1.4 | 25.0 | 1.6 | |||||||||||||||
AHI | 37.7 | 6.1 | (1.5) | 3.6 | (0.5) | |||||||||||||||
Maine Electric Power Company Inc. | 21.7 | 1.0 | 0.1 | 0.9 | – | |||||||||||||||
Maine Yankee Atomic Power Company (1) | 12.0 | 0.3 | – | 0.2 | – | |||||||||||||||
GBPC(2) | – | – | – | – | 0.4 | |||||||||||||||
$223.4 | $17.3 | $246.0 | $13.6 |
(1) | Although Emera’s ownership percentage of these entities is relatively low, it does have significant influence over the operating and financial decisions of these companies through board representation. Therefore, Emera records its investment in APUC and Maine Yankee Atomic Power Company, Lucelec and M&NP using the equity method. This is consistent with industry practice for similar investments with significant influence. |
(2) | Emera gained control of GBPC on December 22, 2010 and LPH on January 25, 2011; the above information does not include the earnings or the carrying value after acquiring control. |
15. AVAILABLE-FOR-SALE INVESTMENTS
The available-for-sale investments include investments in debt and equity securities held in trust on behalf of The Barbados Light & Power Company Limited Self Insurance Fund (“Self Insurance Fund”) for the purpose of building an insurance fund to cover risk against damage and consequential loss to certain of BLPC’s generating, transmissions and distribution systems. Emera has classified these investments as available-for-sale and have recorded all such investments at their market value as at September 30, 2011.
Available-for-sale financial assets include the following:
As at millions of Canadian dollars | September 30 2011 | December 31 2010 | ||||||
Common shares | $1.3 | $0.8 | ||||||
Mutual funds | 17.3 | – | ||||||
Corporate bonds, debentures, short and medium term notes | 31.0 | – | ||||||
Government bonds | 8.0 | – | ||||||
$57.6 | $0.8 |
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These available-for-sale financial investments include assets held in trust on behalf of the Self Insurance Fund that are not available to the Company for use in its operations.
As at millions of Canadian dollars | September 30 2011 | December 31 2010 | ||||||
Balance, beginning of the year | $0.8 | $1.0 | ||||||
Additions, due to acquisition | 54.8 | – | ||||||
Additions, net of foreign exchange loss | 28.8 | – | ||||||
Redemptions | (26.4) | – | ||||||
$58.0 | $1.0 | |||||||
Change in fair value | ||||||||
Gain recognized in regulatory liability | (0.2) | – | ||||||
Loss recognized in other comprehensive income during the period | (0.2) | (0.2) | ||||||
$(0.4) | $(0.2) | |||||||
Balance, end of the period | $57.6 | $0.8 |
There were no disposals or impairment provisions for available-for-sale investments for the year-to-date or for the year ended 2010.
As at September 30, 2011 the maturity profile of debt securities is as follows:
As at millions of Canadian dollars | September 30 2011 | December 31 2010 | ||||||
Maturity within 1 year | $15.3 | – | ||||||
Maturity in 1-5 years | 23.7 | – | ||||||
$39.0 | – |
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.
16. ACQUISITIONS
Light & Power Holdings Ltd.
On January 25, 2011, Emera acquired 7.2 million shares of LPH, the parent company of BLPC, a vertically-integrated utility and the sole provider of electricity on the island of Barbados until 2028, for total cash consideration of $92.6 million CAD ($92.8 million USD) to become the majority shareholder of LPH, with a total interest of 80.2 percent. This investment was made to increase Emera’s regulated transmission, distribution and generation portfolio.
Prior to this transaction, Emera owned 38.4 percent of LPH with a carrying value of $113.7 million CAD ($114.0 million USD). The fair value of Emera’s interest in LPH immediately prior to the acquisition date was $85.1 million CAD ($85.3 million USD).
The fair value of the assets of a regulated utility are generally deemed to equal book value (rate base) given the regulated utility’s earnings are a function of its rate base, as predetermined by the regulator. The purchase price was negotiated between arms-length parties. The differential between the two amounts resulted in Emera recording a gain on acquisition of $28.3 million, which Emera has recorded as a non-taxable gain in “Other income (expenses), net” on Emera’s Consolidated Statements of Income for the nine months ended September 30, 2011.
The valuation technique used to measure the acquisition-date fair value of the assets and liabilities of LPH was book value for regulated assets given the regulatory environment in which BLPC operates. Non-regulated assets were measured based on recent transactions. Accordingly, a third party valuation of assets was not performed. The purchase price allocation is adjusted, as necessary, typically up to one year after the acquisition closing date if further information regarding asset valuations and liabilities assumed arises.
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The total preliminary purchase price has been allocated to the fair value of assets and liabilities as follows:
millions of Canadian dollars | ||||
Cash and cash equivalents | $58.4 | |||
Restricted cash | 12.3 | |||
Receivables, net | 23.4 | |||
Income tax receivable | 0.2 | |||
Inventory | 16.3 | |||
Prepaid expenses | 2.9 | |||
Property, plant and equipment, net of accumulated depreciation of $232.1 | 292.0 | |||
Available-for-sale investments | 52.5 | |||
Other non-current assets | 1.6 | |||
Current portion of long-term debt | (7.5) | |||
Account payable | (33.7) | |||
Other current liabilities | (5.3) | |||
Long-term debt | (43.1) | |||
Deferred income taxes | (9.5) | |||
Regulatory liabilities | (62.7) | |||
Asset retirement obligation | (2.2) | |||
Other long-term liabilities | (2.5) | |||
Gain on business acquisition(1) | (28.3) | |||
Non-controlling interest | (57.9) | |||
Total purchase consideration | $206.9 |
(1) | The gain shown above represents the net effect of the gain on acquisition of $56.4 million net of a loss of $28.1 million on a business combination achieved in stages, which requires the revaluation of the existing interest to the implied value from the second investment at the date of acquiring control. The gain is included in “Other income (expenses) net” in the Consolidated Statements of Income. |
The Company has included operating revenues of $204.0 million and net income attributable to common shareholders of $8.7 million for BLPC in its consolidated net income attributable to common shareholders to date for fiscal 2011 related to the period subsequent to January 25, 2011.
The Company also incurred $1.9 million in acquisition-related costs of which $1.4 million was recorded in 2011. These costs are included in “Operating, maintenance and general expense” in the Consolidated Statements of Income.
Supplemental Pro Forma Data
The unaudited pro forma statement below gives effect to the acquisition of a controlling interest in BLPC as if the transaction had occurred at the beginning of 2010. This pro forma data is presented for informational purposes only and does not purport to be indicative of the results of future operations or of the results that would have occurred had the acquisition taken place at the beginning of 2010.
For the millions of Canadian dollars (except per share amounts) | Nine months ended September 30 | |||||||
2011 | 2010 | |||||||
Operating revenues | $1,569.7 | $1,392.4 | ||||||
Net income attributable to common shareholders | 194.6 | 175.7 | ||||||
Pro forma basic earnings per share | $1.62 | $1.54 | ||||||
Pro forma diluted earnings per share | $1.60 | $1.51 |
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Grand Bahama Power Company Limited
On December 22, 2010, Emera acquired 50 percent of the outstanding common shares of GBPC, an integrated utility and sole provider of electricity on Grand Bahama Island; and an additional 10.7 percent interest in ICD Utilities Limited (“ICDU”), owner of the remaining 50 percent interest in GBPC for total cash consideration of $81.6 million CAD ($82.0 million USD) giving Emera an 80.4 percent direct and indirect interest in GBPC. This investment was made to increase Emera’s regulated electricity, transmission and generation portfolio.
Prior to the transaction, Emera owned 50 percent of ICDU and indirectly through this ownership 25% of GBPC. This interest in ICDU had a carrying value of $39.2 million CDN ($39.4 million USD). The fair value of Emera’s interest in ICDU immediately prior to the acquisition date, was $36.8 million CDN ($37.0 million USD).
As a result of this transaction, the Company recorded a loss on a business acquisition achieved in stages related to the pre-existing investment of $2.4 million.
The purchase price allocation has not yet been finalized as the Company is in the process of completing an external valuation of tangible and intangible assets acquired. Therefore, the allocation of the purchase price has been estimated, and is subject to change. The valuation will be completed in 2011.
The total preliminary purchase price has been allocated to the fair value of assets and liabilities as follows:
millions of Canadian dollars | ||||
Receivables, net | $19.2 | |||
Inventory | 16.2 | |||
Prepaid expenses | 1.2 | |||
Other non-current assets | 0.5 | |||
Property, plant and equipment, net of accumulated depreciation of $96.0 | 153.4 | |||
Goodwill | 75.6 | |||
Short-term debt | (1.9) | |||
Current portion of long-term debt | (4.2) | |||
Account payable | (20.6) | |||
Other current liabilities | (3.5) | |||
Long-term debt | (83.1) | |||
Pension and post-retirement liabilities | (5.5) | |||
Non-controlling interest | (28.9) | |||
Total preliminary purchase consideration | $118.4 |
The goodwill that arose on the acquisition of GBPC is a result of expected operational efficiencies and synergies that Emera’s management believes it can bring to the operation of GBPC, as well as additional strategic opportunities in the region.
The Company has included operating revenues of $90.8 million and net income attributable to common shareholders of $4.9 million for GBPC in its consolidated net income attributable to common shareholders to date for fiscal 2011.
The Company also incurred $4.9 million in acquisition-related costs of which $6.1 million was expensed in 2010, offset with a recovery of $1.2 million recorded in 2011. These expenses are included in “Operating, maintenance and general expense” in the “Consolidated Statements of Income.”
Supplemental Pro Forma Data
The unaudited pro forma statement below gives effect to the acquisition of a controlling interest of GBPC as if the transaction had occurred at the beginning of 2010. This pro forma data is presented for informational purposes only and does not purport to be indicative of the results of future operations or of the results that would have occurred had the acquisition taken place at the beginning of 2010.
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For the millions of Canadian dollars (except per share amounts) | Nine months ended September 30 | |||||||
2011 | 2010 | |||||||
Operating revenues | $1,552.4 | $1,281.3 | ||||||
Net income attributable to common shareholders | 194.3 | 166.9 | ||||||
Pro forma basic earnings per share | $1.61 | $1.46 | ||||||
Pro forma diluted earnings per share | $1.59 | $1.44 |
Maine & Maritimes Corporation
On December 21, 2010, Emera acquired all of the outstanding common shares of MAM, a publically held United States corporation, and the parent company of MPS for cash consideration of $77.2 million CAD ($75.8 million USD). This investment was made to increase Emera’s transmission and distribution portfolio.
The valuation technique used to measure the acquisition-date fair value of the equity interest in MAM was book value given the regulatory environment in which MPS operates. Accordingly, a third party valuation of assets was not performed.
The purchase price allocation has not yet been finalized as the Company is in the process of completing a deferred tax review. Therefore, the allocation of the purchase price has been estimated, and is subject to change. The valuation will be completed in 2011.
The total preliminary purchase price has been allocated to the fair value of assets and liabilities as follows:
millions of Canadian dollars | ||||
Cash and cash equivalents | $0.6 | |||
Restricted cash | 0.2 | |||
Receivables, net | 8.3 | |||
Income taxes receivable | 1.2 | |||
Inventory | 1.1 | |||
Current regulatory assets | 9.9 | |||
Prepaid expenses | 0.9 | |||
Other current assets | 0.3 | |||
Property, plant and equipment, net of accumulated depreciation of $54.3 | 66.6 | |||
Non-current regulatory assets | 22.3 | |||
Investments subject to significant influence | 0.4 | |||
Goodwill | 31.3 | |||
Other non-current assets | 3.9 | |||
Short-term debt | (2.3) | |||
Current portion of long-term debt | (1.1) | |||
Account payable | (4.8) | |||
Regulatory liabilities – current | (0.5) | |||
Other current liabilities | (3.3) | |||
Long-term debt | (23.0) | |||
Deferred income taxes | (21.1) | |||
Derivative instruments | (3.6) | |||
Pension and post-retirement liabilities | (7.1) | |||
Other long-term liabilities | (3.0) | |||
Total purchase consideration | $77.2 |
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The goodwill that arose on the acquisition of MAM is a result of expected operational efficiencies and synergies that Emera’s management believes it can bring to the operation of MAM, as well as additional strategic opportunities in the region.
The Company has included operating revenues of $25.1 million and net income attributable to common shareholders of $1.6 million for MPS in its consolidated net income attributable to common shareholders to date for fiscal 2011.
The Company also incurred $4.7 million in acquisition-related costs which were expensed during 2010 and included in “Operating, maintenance and general expense” in the “Consolidated Statements of Income.”
Supplemental Pro Forma Data
The unaudited pro forma statement below gives effect to the acquisition of MPS as if the transaction had occurred at the beginning of 2010. This pro forma data is presented for informational purposes only and does not purport to be indicative of the results of future operations or of the results that would have occurred had the acquisition taken place at the beginning of 2010.
For the millions of Canadian dollars (except per share amounts) | Nine months ended September 30 | |||||||
2011 | 2010 | |||||||
Operating revenues | $1,552.4 | $1,223.30 | ||||||
Net income attributable to common shareholders | 194.3 | 166.1 | ||||||
Pro forma basic earnings per share | $1.61 | $1.46 | ||||||
Pro forma diluted earnings per share | $1.59 | $1.43 |
17. EARNINGS PER SHARE
The following table reconciles the computation of basic and diluted earnings per share:
For the millions of Canadian dollars (except per share amounts) | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Numerator | ||||||||||||||||
Net income attributable to common shareholders of Emera Incorporated | $40.8 | $40.3 | $194.3 | $166.6 | ||||||||||||
Preferred stock dividends of subsidiary | – | – | 6.0 | 6.0 | ||||||||||||
Diluted numerator | $40.8 | $40.3 | $200.3 | $172.6 | ||||||||||||
Denominator | ||||||||||||||||
Weighted average shares of common stock outstanding – basic | 122.1 | 113.8 | 119.9 | 113.5 | ||||||||||||
Weighted average DSUs outstanding | 0.5 | 0.5 | 0.5 | 0.5 | ||||||||||||
Weighted average shares of common stock outstanding – basic | 122.6 | 114.3 | 120.4 | 114.0 | ||||||||||||
Effect of dilutive securities | – | – | 4.3 | 5.4 | ||||||||||||
Stock-based compensation and employee common share purchase plan | 1.0 | 1.0 | 1.0 | 0.9 | ||||||||||||
Weighted average shares of common stock outstanding – diluted | 123.6 | 115.3 | 125.7 | 120.3 | ||||||||||||
Earnings per common share | ||||||||||||||||
Basic | $0.33 | $0.35 | $1.61 | $1.46 | ||||||||||||
Diluted(1) | $0.33 | $0.35 | $1.59 | $1.43 |
(1) | The calculation of diluted earnings per share for the three months ended September 30, 2011 excluded the impact of $2.0 million (2010 – $2 million) in preferred stock dividends of a subsidiary and 0.2 million (2010 – nil) of unexercised stock options that had an anti-dilutive effect. The calculation of diluted earnings per share for the nine months ended September 30, 2011 excluded 0.2 million (2010 – nil) of unexercised stock options that had an anti-dilutive effect. |
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18. COMMITMENTS AND CONTINGENCIES
A. Commitments
As at September 30, 2011, commitments (excluding pensions and other post-retirement benefits, long-term debt, and AROs) for each of the next five years and in aggregate thereafter consisted of the following:
millions of Canadian dollars | 2011 | 2012 | 2013 | 2014 | 2015 | Thereafter | Total | |||||||||||||||||||||
Purchased power(1) | $43.7 | $108.7 | $117.4 | $117.5 | $117.7 | $1,381.7 | $1,886.7 | |||||||||||||||||||||
Coal, biomass, oil and natural gas supply | 74.7 | 243.1 | 184.7 | 126.0 | 75.9 | 613.7 | 1,318.1 | |||||||||||||||||||||
Transportation(2) | 23.4 | 70.1 | 26.3 | 23.7 | 2.3 | 1.6 | 147.4 | |||||||||||||||||||||
Long-term service agreements(3) | 3.3 | 7.2 | 6.1 | 6.2 | 5.1 | 0.5 | 28.4 | |||||||||||||||||||||
Capital projects | 68.1 | 74.1 | 5.7 | – | 4.0 | – | 151.9 | |||||||||||||||||||||
Leases(4) | 1.1 | 1.4 | 0.6 | 0.6 | 0.6 | 1.5 | 5.8 | |||||||||||||||||||||
Other | 2.6 | 4.8 | 4.2 | 3.7 | 3.7 | 1.0 | 20.0 | |||||||||||||||||||||
Total | $216.9 | $509.4 | $345.0 | $277.7 | $209.3 | $2,000.0 | $3,558.3 |
(1) | Purchased power: annual requirement to purchase 100 percent of electricity production from independent power producers over varying contract lengths up to 25 years. |
(2) | Transportation: purchasing commitments for transportation of solid fuel and transportation capacity on M&NP. |
(3) | Long-term service agreements: outsourced management of the Company’s computer and communication infrastructure and maintenance of generation units. |
(4) | Leases: operating lease agreements for office space, land, telecommunications services, rail cars and vehicles. |
B. Legal Proceedings
A number of individuals who live in proximity to the Company’s Trenton generating station have filed a statement of claim for an unspecified amount against NSPI in respect of emissions from the operation of the plant for the period from 2001 forward. The plaintiffs claim unspecified damages as a result of interference with enjoyment of, or damage to, their property; and adverse health effects they allege were caused by such emissions. The Company has filed a defense to the claim. The outcome of this litigation, and therefore an estimate of any contingent loss, is not determinable.
In addition, Emera and its subsidiaries may, from time to time, be involved in legal proceedings, claims and litigations 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
NSPI
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.
Conformance with legislative and NSPI requirements are verified through a comprehensive environmental audit program. There were no significant environmental or regulatory compliance issues identified during the 2011 and 2010 audits.
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Climate Change and Air Emissions
Greenhouse Gas Emissions
NSPI has stabilized, and in recent years, reduced greenhouse gas emissions. This has been achieved by energy efficiency and conservation programs, increased use of natural gas, improved efficiency of converting natural gas to electricity and the addition of new renewable energy sources to the generation portfolio.
On August 19, 2011, Environment Canada announced proposed regulations for a new national carbon dioxide framework for the electricity sector in Canada. These proposed regulations would apply to new coal-fired electricity generation units and existing coal-fired electricity generation units once they have reached the end of their deemed economic life of forty-five years after commissioning. These proposed regulations will be effective July 1, 2015. Nova Scotia’s existing greenhouse gas regulations require reductions in NSPI’s emissions similar to those reflected in the federal framework. NSPI is reviewing the implications of this federal framework and its alignment with its current operating plans under existing Nova Scotia regulations.
Greenhouse gas emissions from NSPI facilities have been capped beginning in 2010 through to 2020. The 2010 to 2012 caps will be achieved by the continued success of energy efficiency and conservation programs and the addition of renewable energy to meet the provincial renewable energy standards. The regulations also include a transmission incentive compliance mechanism recognizing expenditures on transmission which facilitates additional renewable energy sources. Up to 3 percent of the annual cap can be offset in this way to 2019. Further, the 2010 to 2020 period years are combined to form multi-year compliance periods recognizing the variability in electricity supply sources and demand. It is anticipated that the 2013 through 2015 caps will be achieved by successful energy efficiency and conservation programs and adding renewable energy to meet the provincial 2013 renewable energy standards. Beyond 2014, reduced greenhouse gas emissions will be achieved through a combination of additional renewable energy, import of non-emitting energy, energy efficiency and conservation.
In April 2007, the province of Nova Scotia enacted an Act Respecting Environmental Goals and Sustainable Prosperity. Within this act, there is an objective to reduce provincial greenhouse gas emissions to 10 percent below 1990 levels by 2020. In January 2009, the Province released its 2009 Energy Strategy and Climate Change Action Plan. These documents provide the elements of the plan to achieve this objective. In August 2009, the Province enacted regulations to cap greenhouse gas emissions from the electricity sector in Nova Scotia.
Renewable Energy
On May 19, 2011 the Nova Scotia Government approved The Electricity Act (Amended) to facilitate the eligibility of energy from the Lower Churchill Project in Labrador as a resource for meeting Nova Scotia’s renewable electricity targets. The amendment requires regulations to be developed that increase the percentage of renewable energy in the generation mix from the planned 25 percent in 2015, to 40 percent by 2020.
On April 11, 2011, the Nova Scotia Government announced that the cap on the annual amount of new forest biomass that can be used to generate electricity will be lowered by 30 percent to 350,000 dry tonnes per year.
In January 2007, the Nova Scotia Government approved the Renewable Energy Standard Regulation (“RES”) to increase the percentage of renewable energy in the Province of Nova Scotia’s generation mix. In October 2009, the RES was amended. The target date for 5 percent of electricity to be supplied from post-2001 sources of renewable energy, owned by independent power producers, was extended to 2011 from 2010. The target for 2013, which requires an additional 5 percent of renewable energy, is unchanged.
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Mercury, Nitrogen Oxide and Sulphur Dioxide Emissions
In 2008, NSPI carried out extensive testing on mercury abatement technology in its coal power plants. A capital program to add sorbent injection to each of the seven pulverized fuel coal units was completed in 2010 at a cost of $17.3 million. This was put in place to address a change in the mercury emissions limit, moving from 168 kilograms (“kg”) per year to 65 kg per year beginning in 2010. In the fall of 2010, the Nova Scotia government amended the limits to allow 110 kg in 2010, 100 kg in 2011, 100 kg in 2012, 85 kg in 2013, 65 kg annually for the period 2014 through 2019 and 35 kg in 2020. Any mercury emission above 65 kg, between 2010 and 2013, must be offset by lower emissions in the 2014 to 2020 period.
NSPI has completed its capital program of retrofitting low nitrogen oxide combustion firing systems on six of its seven pulverized fuel coal units in early 2009 at a cost of $23.3 million. NSPI now meets the nitrogen oxide emission cap of 21,365 tonnes per year established by the Nova Scotia Government effective 2010. These investments, combined with the purchasing of compliance coal, allows NSPI to meet the provincial air quality regulations.
NSPI will meet ever-reducing sulphur dioxide emission cap requirements through the use of a blend of net lower sulphur content solid fuel.
Compared to historical levels, NSPI will have reduced mercury emissions by 60 percent effective 2014, nitrogen oxide by 40 percent effective 2009 and sulphur dioxide by 50 percent effective 2010.
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 electrical equipment on its system that do not meet the 2008 PCB Regulations Standard. NSPI is in the process of testing electrical equipment over a four year period. The project completion date had been extended to 2014.The cost of testing the electrical equipment, replacement of electrical equipment, the cost to install that electrical equipment and the cost of destroying PCB contaminated electrical equipment are capitalized.In addition, in response to the 2008 PCB Regulations Standard, there is a project to phase out the use of pole mount transformers before 2025. Currently, there is a capital program to destroy all confirmed PCB contaminated pole mount transformers taken out of service through attrition. The combined total cost of these projects is estimated to be $30.8 million and, as at September 30, 2011 approximately $6.0 million (December 31, 2010 – $5.4 million) has been spent to test, replace and remediate PCB contaminated electrical equipment and liquids in this effort to date.NSPI has recognized an ARO of $14.2 million as at September 30, 2011 (December 31, 2010 – $13.9 million) associated with the PCB phase-out program.
Bangor Hydro
In response to a Maine environmental regulation to phase out PCB transformers, Bangor Hydro has implemented a multi-year program to eliminate transformers on its system that do not meet the new State environmental guidelines. Bangor Hydro is in the final year of a four-year program. The cost of testing the transformers is expensed as incurred; replacement transformers and the cost to install those transformers are capitalized. The total cost of the program has been included in the sustaining capital and operating budgets for those years.
Maine Public Service
In response to a Maine environmental regulation to phase out PCB transformers, MPS has implemented a program to eliminate transformers on its system that do not meet the new State environmental guidelines. MPS is in the process of testing over distribution transformers over a ten-year period. The project completion date has been extended from 2010 to 2011. The cost of testing the transformers is expensed as incurred; replacement transformers and the cost to install those transformers are capitalized. As of September 30, 2011, all transformers have been remediated and are PCB-free in this effort; the total cost spent on this program as at September 30, 2011 was $3.0 million (December 31, 2010 – $2.8 million).
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The Barbados Light & Power Company Limited
BLPC implemented a Health Safety Environmental and Quality Management system in 2006 to assist in safeguarding the health and safety of its employees, contractors and customers while ensuring protection of the environment. The Company conducted an environmental impact assessment on its facilities and significant environmental aspects were identified and programs were developed.
D. Environmental Regulations
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 $63.0 million during 2011 and $437.8 million from 2012 through 2015. Amounts that have been committed to are included in “Capital projects” in the commitments table in note 18A. The estimated expenditures do not include costs related to possible changes in the environmental laws or regulations and enforcement policies may be enacted in response to issues such as climate change and other pollutant emissions.
E. 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.
Emera’s strategy includes acquisitions, exposing the Company to risks associated with acquisitions
The risks associated with Emera’s acquisition strategy include the availability of suitable acquisition candidates, obtaining the necessary regulatory approval for any acquisition and assimilating and integrating acquired companies into the Company. In addition, potential difficulties inherent in acquisitions may adversely affect the results of an acquisition. These include delays in implementation or unexpected costs or liabilities, as well as the risk of failing to realize operating benefits or synergies from completed transactions.
Emera mitigates these risks by following systematic procedures for integrating acquisitions, applying strict financial metrics to any potential acquisition and subjecting the process to close monitoring and review by the Board of Directors.
Regulatory risk
The Company’s rate-regulated subsidiaries are subject to risk in the recovery of costs and investments in a timely manner. The Company manages this risk through ongoing stakeholder consultation and engagement on aspects such as utility operations, rate filings and capital plans.
Changes in environmental legislation
The Company is subject to regulation by federal, provincial, state, regional, and local authorities with regard to environmental matters primarily related to its utility operations. Changes to climate change and air emissions standards could adversely affect utility operations.
Emera is committed to operating in a manner that is respectful and protective of the environment, and in full compliance with legal requirements and Company policy. Emera and its wholly-owned subsidiaries have implemented this policy through development and application of environmental management systems.
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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 Company enters into foreign exchange forward and swap contracts to limit exposure on foreign currency transactions such as fuel purchases and revenue streams.
Commercial relationships
NSPI
NSPI’s largest customer contributed approximately 7.9 percent (2010 – 9.1 percent) of NSPI’s electric revenues for the three months ended September 30, 2011 and 7.8 percent (2010 – 8.1 percent) for the nine months ended September 30, 2011. The five largest customers contributed approximately 16.3 percent (2010 – 17.2 percent) of NSPI’s electric revenues for the three months ended September 30, 2011 and 15.2 percent (2010 – 14.9 percent) for the nine months ended September 30, 2011. The loss of a major customer could have a material effect on NSPI’s operating revenues. NSPI continues to mitigate this risk through ongoing stakeholder consultation.
On September 9, 2011, NSPI’s largest customer was granted creditor protection under the Companies’ Creditors Arrangement Act (“CCAA”). This customer’s parent has commenced a voluntary case under Chapter 11 of the United States Bankruptcy Code as well. Accounts receivable as of September 30, 2011 were $12.3 million. No provision is required as the company expects recovery through set offs against amounts owing to the customer and post CCAA payments. The proposed 2012 GRA settlement, currently before the UARB, provides for any unrecovered non-fuel electric charges in 2012 related to this customer to be deferred and recovered beginning in 2013.
Brunswick Pipeline
Brunswick Pipeline has a 25 year firm service agreement with Repsol Energy Canada (“REC”). The pipeline was used solely in 2011 and 2010 to transport natural gas from the Canaport LNG terminal in Saint John, New Brunswick to the United States border for REC. The risk of non-payment is mitigated as Repsol YPF, S.A (“Repsol”), the parent company of REC, has provided Brunswick Pipeline with a guarantee for all RECs’ payment obligations under the firm service agreement. As at September 30, 2011, the net investment in direct financing lease with Repsol was $491.4 million. Repsol is rated investment grade BBB/Baa1; credit ratings and press releases are monitored on an ongoing basis. There is currently no allowance for credit losses related to this agreement.
Relationships with employees
Certain Emera employees are subject to collective labour agreements. Approximately 57 percent of the full time and term employees at NSPI, BLPC, GBPC, Bangor Hydro, EUS, and MPS are represented by a local union affiliated with the International Brotherhood of Electrical Workers. Emera seeks to manage this risk through ongoing discussions with local unions.
Weather risk
Shifts in weather patterns affect electric sales volumes and associated revenues. Extreme weather events generally result in increased operating costs associated with restoring power to customers. Emera responds to significant weather event related outages according to each subsidiary’s respective Emergency Services Restoration Plan.
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Interest rate risk
The Company utilizes a combination of fixed and variable 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.
F. Collaborative Arrangement
Bangor Hydro
Through Bangor Hydro, the Company is a party to a collaborative arrangement with National Grid Transmission Services Corporation to develop the Northeast Energy Link (“NEL”) Project. The cost of development activities, including acquisition of land in the transmission corridor and acquisition of necessary governmental and regulatory permits and approvals, are shared equally between the Company and National Grid. Bangor Hydro has deferred $2.4 million USD of costs associated with the NEL project as at September 30, 2011 (December 31, 2010 – $2.4 million USD), reported in the Consolidated Balance Sheets in “Other” as part of other assets.
G. Guarantees and Letters of Credit
Emera had the following guarantees and letter of credits as at September 30, 2011:
• | NSPI has provided a limited guarantee for the indebtedness of RESL. The guarantee is up to a maximum of $23.5 million. As at September 30, 2011, RESL’s indebtedness under the loan agreement was $22.2 million. NSPI holds a security interest in the present and future assets of RESL. For further information see note 1AA. |
• | Emera has provided a guarantee to the Long Island Power Authority (“LIPA”) on behalf of Bear Swamp for Bear Swamp’s long-term energy and capacity supply agreement (“PPA”) with LIPA, which expires on April 30, 2021. The guarantee is for 50 percent of the relevant obligations under the PPA up to a maximum of $18.6 million USD. As at September 30, 2011, the fair value of the PPA is positive. |
• | Emera has provided a guarantee to the Bank of Nova Scotia on behalf of Bear Swamp for Bear Swamp’s interest rate swaps entered into between Bear Swamp and the Bank of Nova Scotia which expires on May 9, 2012. The guarantee is for 50 percent of the relevant obligations up to a maximum of $1.0 million USD. As at September 30, 2011, the fair value of that agreement is positive. |
• | At the request of Emera and its subsidiaries, a financial institution has issued standby letters of credit in the amount of $9.9 million for the benefit of third parties that have extended credit to Emera and its subsidiaries. These letters of credit typically have a one year term and are renewed annually as required. |
• | A financial institution has issued a standby letter of credit in the amount of 1.2 million EURO to support NSPI’s operations. The letter of credit has a one year term and is renewed as required. The amount committed as at September 30, 2011 was $1.6 million. |
• | A financial institution has issued a standby letter of credit to secure obligations under an unfunded pension plan in NSPI. The letter of credit expires in June 2012 and is renewed annually. The amount committed as at September 30, 2011 was $22.5 million. |
• | A financial institution has issued a standby letter of credit to secure obligations under an unfunded pension plan in BHE. The letter of credit expires in October 2011 and is renewed annually. The amount committed as at September 30, 2011 was $2.2 million USD. |
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• | A financial institution has been issued direct pay letters of credit totaling $23.9 million USD to secure principal and interest payments related to Maine Public Utilities Financing Bank bonds issued on behalf of MPS, related to qualifying distribution assets. |
No liability has been recognized on the consolidated balance sheet related to any potential obligation under these guarantees and letters of credits.
19. COMMON STOCK
Authorized: Unlimited number of non-par value common shares.
Issued and outstanding:
| Millions of shares | Common Stock millions of Canadian dollars (adjusted) | ||||||
December 31, 2010 | 114.62 | $1,137.8 | ||||||
Issuance of common stock | 6.36 | 196.0 | ||||||
Issued for cash under purchase plans | 1.03 | 29.7 | ||||||
Options exercised under senior management share option plan | 0.22 | 4.7 | ||||||
Stock-based compensation | – | 0.9 | ||||||
September 30, 2011 | 122.23 | $1,369.1 |
In March 2011, Emera issued 6,359,500 common shares, which included the exercise of the over-allotment option of 829,500 common shares. The shares were issued at $31.70 per share for net proceeds after-tax and issuance costs of $196.0 million.
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, Maine, Barbados and Grand Bahama Island.
Emera acquired control of BLPC in January 2011, and therefore, it is not included in the December 31, 2010 comparative information.
Net periodic costs prior to the effects of capitalization consisted of the following:
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Defined benefit pension plans | ||||||||||||||||
Service cost | $4.1 | $3.0 | $12.1 | $8.4 | ||||||||||||
Interest cost | 14.2 | 13.8 | 42.5 | 41.3 | ||||||||||||
Expected return on plan assets | (14.1) | (13.6) | (40.7) | (39.6) | ||||||||||||
Current year amortization of: | ||||||||||||||||
Actuarial losses | 6.1 | 2.6 | 18.3 | 7.8 | ||||||||||||
Foreign currency translation adjustment | – | 0.1 | – | 0.1 | ||||||||||||
Total defined benefit pension plans | 10.3 | 5.9 | 32.2 | 18.0 | ||||||||||||
Non-pension benefits plan | ||||||||||||||||
Service cost | 0.7 | 0.6 | 2.0 | 1.4 | ||||||||||||
Interest cost | 1.2 | 1.1 | 3.6 | 2.3 | ||||||||||||
Current year amortization of: | ||||||||||||||||
Actuarial losses | 0.4 | 0.2 | 1.2 | 0.3 | ||||||||||||
Past service gains | (0.4) | (0.4) | (1.1) | (0.7) | ||||||||||||
Total non-pension benefits plans | 1.9 | 1.5 | 5.7 | 3.3 | ||||||||||||
Total defined benefit plans | $12.2 | $7.4 | $37.9 | $21.3 |
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Emera’s contributions related to these defined-benefit plans for the three months ended September 30, 2011 were $10.9 million (2010 – $12.8 million), and for the nine months ended September 30, 2011 were $33.4 million (2010 – $32.8 million).
In addition, the Company contributions related to the defined contribution plan for the three months ended September 30, 2011 were $2.7 million (2010 – $0.5 million), and for the nine months ended September 30, 2011 were $5.6 million (2010 – $1.3 million).
21. DERIVATIVE INSTRUMENTS
The Company enters into futures, forwards, swaps and option contracts either 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 NPNS exception are not recognized on the balance sheet; they are recognized in income when they settle. The Company continually assesses contracts designated under the NPNS exception 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 AOCL 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, that are documented as economic hedges, and for which the NPNS exception has not been taken, receive regulatory deferral as approved by the UARB. 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 when the derivatives settle. Management believes that any gains or losses resulting from settlement of these derivatives 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 and are recognized on the balance sheet at fair value. All gains and losses are recognized 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 when another accounting treatment applies. |
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Derivative assets and liabilities relating to the foregoing categories consisted of the following:
Derivative Assets | Derivative Liabilities | |||||||||||||||
As at millions of Canadian dollars | September 30 2011 | December 31 2010 | September 30 2011 | December 31 2010 | ||||||||||||
Current | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power & gas swaps | $0.1 | – | $5.5 | $6.4 | ||||||||||||
Foreign exchange forwards | 0.8 | $2.4 | 0.1 | – | ||||||||||||
0.9 | 2.4 | 5.6 | 6.4 | |||||||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | 15.3 | 23.6 | 0.5 | 1.9 | ||||||||||||
Natural gas purchases and sales | 0.2 | 0.8 | 20.2 | 20.3 | ||||||||||||
Heavy fuel oil (“HFO”) purchases | – | 1.9 | – | 1.3 | ||||||||||||
Foreign exchange forwards | 15.2 | 2.1 | – | 1.2 | ||||||||||||
Physical natural gas purchases and sales | 4.0 | 4.3 | – | – | ||||||||||||
34.7 | 32.7 | 20.7 | 24.7 | |||||||||||||
HFT derivatives | ||||||||||||||||
Power swaps and physical contracts | 1.9 | 10.5 | 0.6 | 2.6 | ||||||||||||
Foreign exchange forwards | 0.1 | 1.4 | – | – | ||||||||||||
Natural gas swaps, futures, forwards and physical contracts | 8.7 | 7.6 | 9.6 | 8.0 | ||||||||||||
10.7 | 19.5 | 10.2 | 10.6 | |||||||||||||
Total gross current derivatives | 46.3 | 54.6 | 36.5 | 41.7 | ||||||||||||
Impact of master netting agreements with intent to settle net or simultaneously | (2.1) | (4.9) | (2.1) | (4.9) | ||||||||||||
Total current derivatives | 44.2 | 49.7 | 34.4 | 36.8 | ||||||||||||
Long-term | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power swaps | 1.4 | 0.5 | 8.4 | 8.3 | ||||||||||||
Interest rate swaps | – | – | 6.1 | 3.6 | ||||||||||||
Foreign exchange forwards | 0.6 | 4.1 | 0.4 | – | ||||||||||||
2.0 | 4.6 | 14.9 | 11.9 | |||||||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | 11.4 | 18.5 | – | – | ||||||||||||
Natural gas purchases and sales | – | 0.1 | 2.5 | 1.8 | ||||||||||||
Foreign exchange forwards | 41.8 | 2.2 | 1.9 | 9.4 | ||||||||||||
Physical natural gas purchases and sales | 5.0 | 8.1 | – | – | ||||||||||||
58.2 | 28.9 | 4.4 | 11.2 | |||||||||||||
HFT derivatives | ||||||||||||||||
Power swaps and physical contracts | 0.8 | 1.0 | 0.7 | 0.9 | ||||||||||||
Natural gas swaps, futures, forwards and physical contracts | 8.1 | 2.0 | 6.5 | 5.4 | ||||||||||||
8.9 | 3.0 | 7.2 | 6.3 | |||||||||||||
Total gross long-term derivatives | 69.1 | 36.5 | 26.5 | 29.4 | ||||||||||||
Impact of master netting agreements with intent to settle net or simultaneously | (0.4) | (0.5) | (0.4) | (0.5) | ||||||||||||
Total long-term derivatives | 68.7 | 36.0 | 26.1 | 28.9 | ||||||||||||
Total derivatives | $112.9 | $85.7 | $60.5 | $65.7 |
Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.
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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. The Company also enters into foreign exchange forwards to hedge the currency risk for revenue streams denominated in foreign currency for Brunswick Pipeline. Bayside has entered into swaps and futures to limit the exposure on natural gas prices. MPS entered into an interest rate swap to hedge the fluctuation in interest rates on long-term debt.
As previously noted, the effective portion of the change in fair value of these derivatives is included in AOCL, until the hedged transactions are recognized in income. The ineffective portion is recognized in income of the period. The table below shows the amounts related to cash flow hedges recorded in AOCL and income of the period.
For the | Three months ended September 30 | |||||||||||||||||||
millions of Canadian dollars | 2011 | 2010 | ||||||||||||||||||
Power and Gas Swaps | Interest Rate Swaps | Foreign Exchange Forwards | Power Swaps | Foreign Exchange Forwards | ||||||||||||||||
Unrealized loss in non-regulated fuel and purchased power – ineffective portion | $(0.1) | – | – | – | – | |||||||||||||||
Realized loss in non-regulated fuel and purchased power | (1.9) | – | – | $(2.2) | – | |||||||||||||||
Realized gain in regulated operating revenue | – | – | $0.8 | – | – | |||||||||||||||
Realized loss in other income, (expenses), net | – | – | (0.4) | – | – | |||||||||||||||
Total (losses) gains in income | $(2.0) | – | $0.4 | $(2.2) | – | |||||||||||||||
Total unrealized (loss) gain in AOCL – effective portion, net of tax | $(1.9) | $(3.3) | $(6.2) | $(3.8) | $2.9 |
For the | Nine months ended September 30 | |||||||||||||||||||
millions of Canadian dollars | 2011 | 2010 | ||||||||||||||||||
Power and Gas Swaps | Interest Rate Swaps | Foreign Exchange Forwards | Power Swaps | Foreign Exchange Forwards | ||||||||||||||||
Unrealized loss in non-regulated fuel and purchased power – ineffective portion | $(0.9) | – | – | – | – | |||||||||||||||
Realized loss in non-regulated fuel and purchased power | (4.7) | – | – | $(6.5) | – | |||||||||||||||
Realized gain in regulated operating revenue | – | – | $2.4 | – | – | |||||||||||||||
Realized loss in other income (expenses), net | – | – | (0.1) | – | – | |||||||||||||||
Total (losses) gains in income | $(5.6) | – | $2.3 | $(6.5) | – | |||||||||||||||
Total unrealized (loss) gain in AOCL – effective portion, net of tax | $(1.6) | $(3.6) | $(3.7) | $(8.7) | $2.8 |
The Company expects $4.7 million of unrealized losses currently in AOCL to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle.
As at September 30, 2011, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:
millions | 2011 | 2012 | 2013 | 2014 | 2015 | 2016 | ||||||||||||||||||
Power swaps (megawatt hours (“MWh”)) purchases | 0.1 | 0.3 | 0.3 | 0.3 | 0.3 | 0.3 | ||||||||||||||||||
Gas swaps (Mmbtu) purchases | 1.6 | – | – | – | – | – | ||||||||||||||||||
Foreign exchange forwards (USD) sales | $7.5 | $53.8 | $37.0 | $9.0 | $6.0 | – |
In addition, the Company has interest rate swaps on long-term debt of $13.2 million until 2021 and $8.8 million until 2025.
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Regulatory Deferral
As previously noted, NSPI received approval from the UARB for regulatory deferral of gains and losses on certain derivatives documented as economic hedges that do not qualify for hedge accounting, including certain physical contracts that do not qualify for the NPNS exemption. The Company has recorded the following unrealized gains (losses) with respect to derivatives receiving regulatory deferral:
Regulatory Assets | Regulatory Liabilities | |||||||||||||||
For the three months ended millions of Canadian dollars | September 30 2011 | September 30 2010 | September 30 2011 | September 30 2010 | ||||||||||||
Current | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | $0.3 | $(0.2) | $5.7 | $2.3 | ||||||||||||
Natural gas purchases and sales | 10.7 | 9.8 | 0.1 | 0.6 | ||||||||||||
HFO purchases | – | 0.2 | – | (0.4) | ||||||||||||
Foreign exchange forwards | (5.9) | (4.8) | (15.1) | 2.0 | ||||||||||||
Physical natural gas purchases and sales | (0.1) | (7.7) | 0.6 | (2.2) | ||||||||||||
Long-term | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | – | (2.1) | 5.0 | 3.7 | ||||||||||||
Natural gas purchases and sales | 2.1 | 1.2 | 0.1 | 0.1 | ||||||||||||
Foreign exchange forwards | (19.7) | 2.1 | (41.4) | 17.3 | ||||||||||||
Physical natural gas purchases and sales | – | – | 0.6 | (7.3) |
Regulatory Assets | Regulatory Liabilities | |||||||||||||||
For the nine months ended millions of Canadian dollars | September 30 2011 | September 30 2010 | September 30 2011 | September 30 2010 | ||||||||||||
Current | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | $(0.5) | $(8.0) | $7.4 | $1.5 | ||||||||||||
Natural gas purchases and sales | 0.5 | 7.9 | – | 0.1 | ||||||||||||
HFO purchases | (1.3) | (1.7) | 1.9 | 8.4 | ||||||||||||
Foreign exchange forwards | (1.6) | (18.8) | (13.2) | (4.7) | ||||||||||||
Physical natural gas purchases and sales | – | (3.1) | 0.4 | (3.6) | ||||||||||||
Long-term | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | – | (11.5) | 7.2 | (0.7) | ||||||||||||
Natural gas purchases and sales | 0.6 | 0.7 | 0.1 | – | ||||||||||||
HFO purchases | – | (1.3) | – | 2.0 | ||||||||||||
Foreign exchange forwards | (7.5) | (0.5) | (39.6) | 6.0 | ||||||||||||
Physical natural gas purchases and sales | – | – | 3.0 | (5.4) |
Regulatory Impact Recognized in Net Income
The Company recognized the following gains (losses) related to derivatives receiving regulatory deferral as follows:
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Other income (expenses), net | – | $1.5 | – | $0.5 | ||||||||||||
Regulated fuel for generation and purchased power | $(0.6) | (10.7) | $(17.5) | (55.9) | ||||||||||||
Net losses | $(0.6) | $(9.2) | $(17.5) | $(55.4) |
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Commodity Swaps and Forwards
As at September 30, 2011, the Company had the following notional volumes of outstanding commodity swaps and forwards related to purchases, designated for regulatory deferral that are expected to settle as outlined below:
2011 | 2012 | 2013 | 2014 | |||||||||||||
millions | Purchases | Purchases | Purchases | Purchases | ||||||||||||
Coal (metric tonnes) | 0.3 | 0.5 | 0.3 | 0.1 | ||||||||||||
Natural gas (Mmbtu) | 5.7 | 19.4 | 3.9 | – |
Foreign Exchange Swaps and Forwards
As at September 30, 2011, the Company had the following notional volumes of foreign exchange swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below:
2011 | 2012 | 2013 | 2014 | 2015 | 2016 | |||||||||||||||||||
Fuel purchases exposure (millions of US dollars) | $57.6 | $256.0 | $212.0 | $210.0 | $210.0 | $120.0 | ||||||||||||||||||
Weighted average rate | 0.9923 | 0.9912 | 1.0251 | 1.0106 | 1.0090 | 0.9814 | ||||||||||||||||||
% of USD requirements | 57.1% | 60.4% | 50.0% | 49.5% | 49.5% | 28.3% |
Held-for-Trading Derivatives
In the ordinary course of its business, Emera enters into physical contracts for the purchase and sale of natural gas; and 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 millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Power swaps and physical contracts in non-regulated operating revenues | $(5.0) | $7.7 | $(4.6) | $13.2 | ||||||||||||
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues | 4.7 | 2.0 | 14.6 | 1.8 | ||||||||||||
Foreign exchange forwards in other income (expenses), net | (0.6) | 1.8 | (0.3) | 1.8 | ||||||||||||
$(0.9) | $11.5 | $9.7 | $16.8 |
As at September 30, 2011, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:
millions | 2011 | 2012 | 2013 | 2014 | 2015 | 2016 | ||||||||||||||||||
Natural gas purchases (Mmbtu) | 24.5 | 60.1 | 37.0 | 29.8 | 22.4 | 5.8 | ||||||||||||||||||
Natural gas sales (Mmbtu) | 15.3 | 22.6 | 7.3 | 3.7 | 1.8 | – | ||||||||||||||||||
Power purchases (MWh) | – | 0.1 | – | – | – | – | ||||||||||||||||||
Power sales (MWh) | 0.2 | 0.1 | – | – | – | – | ||||||||||||||||||
Foreign exchange forwards (USD) | $4.5 | – | – | – | – | – |
Credit Risk
The Company is exposed to credit risk with counterparties to its derivatives. Credit risk is the potential loss resulting 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.
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It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as at September 30, 2011, substantially all of the counterparties with transaction amounts outstanding in the Company’s derivatives portfolio are rated “investment grade” by the major rating agencies. The Company assesses credit risk internally for counterparties that are not rated.
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.
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.
Cash Collateral
The Company’s cash collateral positions consisted of the following:
As at millions of Canadian dollars | September 30 2011 | December 31 2010 | ||||||
Cash collateral provided to others | $28.6 | $36.6 | ||||||
Cash collateral received from others | 4.7 | 3.0 |
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 of the Company’s derivatives contain financial assurance provisions that require collateral to be posted only 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 September 30, 2011, the total fair value of these derivatives, in a net liability position, is $60.5 million (December 31, 2010 – $65.7 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.
22. | FAIR VALUE MEASUREMENTS |
The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exception (see note 21), and uses a market approach to do so.
The three levels of the fair value hierarchy are defined as follows:
Level 1 Valuations – Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities.
Level 2 Valuations – 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.
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Level 3 Valuations – Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally-developed inputs. The primary reasons for a Level 3 classification are as follows:
• | While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials. |
• | The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term. |
• | The valuations of certain transactions were based on internal models, although quoted prices were utilized in the valuations. |
Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
The following tables set out the classification used by the Company to fair value its derivatives as at September 30, 2011 and December 31, 2010:
As at | September 30, 2011 | |||||||||||||||
millions of Canadian dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power and gas swaps | $1.5 | – | – | $1.5 | ||||||||||||
Foreign exchange forwards | – | $1.4 | – | 1.4 | ||||||||||||
1.5 | 1.4 | – | 2.9 | |||||||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | – | 26.6 | – | 26.6 | ||||||||||||
Natural gas purchases and sales | – | – | – | – | ||||||||||||
Foreign exchange forwards | – | 57.1 | – | 57.1 | ||||||||||||
Physical natural gas purchases and sales | – | – | $9.0 | 9.0 | ||||||||||||
– | 83.7 | 9.0 | 92.7 | |||||||||||||
HFT derivatives | ||||||||||||||||
Power swaps and physical contracts | – | – | 2.0 | 2.0 | ||||||||||||
Foreign exchange forwards | – | 0.1 | – | 0.1 | ||||||||||||
Natural gas swaps, futures, forwards and physical contracts | – | 11.8 | 3.4 | 15.2 | ||||||||||||
– | 11.9 | 5.4 | 17.3 | |||||||||||||
Total assets | 1.5 | 97.0 | 14.4 | 112.9 | ||||||||||||
Liabilities | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power and gas swaps | 13.9 | – | – | 13.9 | ||||||||||||
Foreign exchange forwards | – | 0.5 | – | 0.5 | ||||||||||||
Interest rate swaps | – | 6.1 | – | 6.1 | ||||||||||||
13.9 | 6.6 | – | 20.5 | |||||||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | – | 0.5 | – | 0.5 | ||||||||||||
Natural gas purchases and sales | 22.5 | – | – | 22.5 | ||||||||||||
Foreign exchange forwards | – | 1.9 | – | 1.9 | ||||||||||||
22.5 | 2.4 | – | 24.9 | |||||||||||||
HFT derivatives | ||||||||||||||||
Power swaps and physical contracts | – | – | 0.6 | 0.6 | ||||||||||||
Natural gas swaps, futures, forwards and physical contracts | 4.9 | 7.2 | 2.4 | 14.5 | ||||||||||||
4.9 | 7.2 | 3.0 | 15.1 | |||||||||||||
Total liabilities | 41.3 | 16.2 | 3.0 | 60.5 | ||||||||||||
Net (liabilities) assets | $(39.8) | $80.8 | $11.4 | $52.4 |
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As at | December 31, 2010 | |||||||||||||||
millions of Canadian dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power and gas swaps | $0.5 | – | – | $0.5 | ||||||||||||
Foreign exchange forwards | – | $6.5 | – | 6.5 | ||||||||||||
0.5 | 6.5 | – | 7.0 | |||||||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | – | 41.2 | – | 41.2 | ||||||||||||
Natural gas purchases and sales | 0.1 | – | – | 0.1 | ||||||||||||
HFO purchases | – | 1.9 | – | 1.9 | ||||||||||||
Foreign exchange forwards | – | 4.3 | – | 4.3 | ||||||||||||
Physical natural gas purchases and sales | – | – | $12.4 | 12.4 | ||||||||||||
0.1 | 47.4 | 12.4 | 59.9 | |||||||||||||
HFT derivatives | ||||||||||||||||
Power swaps and physical contracts | – | – | 9.0 | 9.0 | ||||||||||||
Foreign exchange forwards | – | 1.4 | – | 1.4 | ||||||||||||
Natural gas swaps, futures, forwards and physical contracts | 0.5 | 1.4 | 6.5 | 8.4 | ||||||||||||
0.5 | 2.8 | 15.5 | 18.8 | |||||||||||||
Total assets | 1.1 | 56.7 | 27.9 | 85.7 | ||||||||||||
Liabilities | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power and gas swaps | 14.7 | – | – | 14.7 | ||||||||||||
Interest rate swaps | – | 3.6 | – | 3.6 | ||||||||||||
14.7 | 3.6 | – | 18.3 | |||||||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | – | 1.0 | – | 1.0 | ||||||||||||
Natural gas purchases and sales | 21.3 | – | – | 21.3 | ||||||||||||
HFO purchases | – | 1.3 | – | 1.3 | ||||||||||||
Foreign exchange forwards | – | 10.6 | – | 10.6 | ||||||||||||
21.3 | 12.9 | – | 34.2 | |||||||||||||
HFT derivatives | ||||||||||||||||
Power swaps and physical contracts | – | – | 1.3 | 1.3 | ||||||||||||
Natural gas swaps, futures, forwards and physical contracts | 6.0 | 1.5 | 4.4 | 11.9 | ||||||||||||
6.0 | 1.5 | 5.7 | 13.2 | |||||||||||||
Total liabilities | 42.0 | 18.0 | 5.7 | 65.7 | ||||||||||||
Net (liabilities) assets | $(40.9) | $38.7 | $22.2 | $20.0 |
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The change in the fair value of the Level 3 financial assets for the three months ended September 30, 2011 was as follows:
Regulatory Deferral | Trading Derivatives | |||||||||||||||
millions of Canadian dollars | Physical natural gas purchases and sales | Power | Natural gas | Total | ||||||||||||
Balance, June 30 | $10.2 | $4.8 | $2.2 | $17.2 | ||||||||||||
Reduction in benefit included in regulated fuel for generation and purchased power | (1.1) | – | – | (1.1) | ||||||||||||
Unrealized losses included in regulatory assets or liabilities | (0.1) | – | – | (0.1) | ||||||||||||
Total realized and unrealized (losses) gains included in non-regulated operating revenues | – | (2.8) | 1.2 | (1.6) | ||||||||||||
Balance, September 30 | $9.0 | $2.0 | $3.4 | $14.4 |
The change in the fair value of the Level 3 financial liabilities for the three months ended September 30, 2011 was as follows:
Regulatory deferral | Trading derivatives | |||||||||||||||
millions of Canadian dollars | Physical natural gas purchases and sales | Power | Natural gas | Total | ||||||||||||
Balance, June 30 | – | $0.9 | $1.3 | $2.2 | ||||||||||||
Total realized and unrealized (losses) gains included in non-regulated operating revenues | – | (0.3) | 1.1 | 0.8 | ||||||||||||
Balance, September 30 | – | $0.6 | $2.4 | $3.0 |
The change in the fair value of the Level 3 financial assets for the nine months ended September 30, 2011 was as follows:
Regulatory Deferral | Trading Derivatives | |||||||||||||||
millions of Canadian dollars | Physical natural gas purchases and sales | Power | Natural gas | Total | ||||||||||||
Balance, January 1 | $12.4 | $9.0 | $6.5 | $27.9 | ||||||||||||
Reduction in benefit included in regulated fuel for generation and purchased power | (3.3) | – | – | (3.3) | ||||||||||||
Unrealized losses included in fuel for generation and purchased power | (0.1) | – | �� | (0.1) | ||||||||||||
Total realized and unrealized losses included in non-regulated operating revenues | – | (7.0) | (3.1) | (10.1) | ||||||||||||
Balance, September 30 | $9.0 | $2.0 | $3.4 | $14.4 |
The change in the fair value of the Level 3 financial liabilities for the nine months ended September 30, 2011 was as follows:
Regulatory deferral | Trading derivatives | |||||||||||||||
millions of Canadian dollars | Physical natural gas purchases and sales | Power | Natural gas | Total | ||||||||||||
Balance, January 1 | – | $1.3 | $4.4 | $5.7 | ||||||||||||
Benefit included in regulated fuel for generation and purchased power | $0.1 | – | – | 0.1 | ||||||||||||
Unrealized losses included in regulatory assets or liabilities | (0.1) | – | – | (0.1) | ||||||||||||
Total realized and unrealized gains included in non-regulated operating revenues | – | (0.7) | (2.0) | (2.7) | ||||||||||||
Balance, September 30 | – | $0.6 | $2.4 | $3.0 |
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The financial assets and liabilities included on the balance sheet that are not measured at fair value consisted of the following:
As at | September 30, 2011 | December 31, 2010 | ||||||||||||||
millions of Canadian dollars | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Long-term debt (including current portion) | $3,164.0 | $3,652.7 | $3,129.1 | $3,526.6 |
The fair values of long-term debt instruments 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, without considering the effect of third party credit enhancements.
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.
23. RELATED PARTY TRANSACTIONS
In the ordinary course of business, Emera purchased natural gas transportation capacity from M&NP, an investment under significant influence of the Company, totaling $11.3 million (2010 – $14.3 million) during the three months ended September 30, 2011, and $36.7 million (2010 – $42.3 million) for the nine months ended September 30, 2011. The amount is recognized in “Regulated fuel for generation and purchased power” or netted against energy marketing margin in “Non-regulated operating revenues” and is measured at the exchange amount. As at September 30, 2011, the amount payable to the related party was $3.5 million (December 31, 2010 – $3.9 million), and is under normal interest and credit terms.
24. USGAAP TRANSITION
ADOPTION OF USGAAP
In February 2008, the Canadian Institute of Chartered Accountants (“CICA”) announced that CGAAP, for publically accountable enterprises, would be replaced by IFRS for fiscal years beginning on or after January 1, 2011. In Q4, 2009, due primarily to the continued uncertainty around the applicability of a rate-regulated accounting standard under IFRS, management reviewed the option of adopting USGAAP instead of IFRS. During Q1 2010, the Company’s Board of Directors approved the transition to USGAAP as recommended by management. The adoption of USGAAP has been made on a retrospective basis with restatement of prior periods’ financial statements to reflect USGAAP requirements in effect at that time.
For annual reporting purposes, the transition date to USGAAP is January 1, 2010, which is the commencement of the 2010 comparative period to the Company’s 2011 financial statements.
As a result of NSPI’s decision to transition to USGAAP, effective January 1, 2011 there was an amendment to NSPI’s regulated accounting policy for financial instruments and hedges which was approved by the UARB. The effects of this amendment were applied retrospectively, in accordance with that policy, without restatement of prior period income. The adjustments related to the amended accounting policy have been included with the adjustments as described further in this note.
82
Measurement, classification and disclosure differences arising out of the Company’s election to adopt USGAAP are presented below. With respect to measurement and classification differences, Section I “USGAAP differences”, presents quantitative reconciliations of balance sheets, income statements and statements of cash flows, previously presented in accordance with CGAAP, to the respective amounts and classifications under USGAAP, together with descriptions of the various significant measurement and classification differences arising from the adoption of USGAAP. Balance sheet reconciliations are presented as at January 1, 2010 and December 31, 2010, representing the commencement and ending dates of the comparative financial year to 2011. Income statement and statement of cash flow reconciliations are presented for the three, six and nine months ended March 31, 2010, June 30, 2010, and September 30, 2010, respectively and for the year ended December 31, 2010, which are periods that will be presented as comparatives to 2011 financial reporting.
In addition, USGAAP requires certain disclosures of financial information, significant to the Company, that are in addition to the required disclosure under CGAAP. This information, which is as at December 31, 2010, is presented in Section II “Additional disclosures required under USGAAP”.
Except as otherwise disclosed in this note, the change in basis of accounting from CGAAP to USGAAP did not materially impact accounting policies or disclosures. Reference should be made to the previously filed CGAAP financial statements as at and for the year ended December 31, 2010 for additional information on CGAAP accounting policies and practices.
The following table summarizes the increases (decreases) to total assets:
As at millions of Canadian dollars | Notes | January 1 2010 | December 31 2010 | |||||||||
Total assets – CGAAP | $5,284.5 | $6,329.1 | ||||||||||
Accounting for joint ventures | A | (76.4) | (75.4) | |||||||||
Offsetting | B | (0.9) | – | |||||||||
Income taxes | C | 17.2 | (136.4) | |||||||||
Hedging | F | 99.1 | 42.3 | |||||||||
Issue costs | G | 19.7 | 22.1 | |||||||||
Business combinations | J | (0.2) | 7.7 | |||||||||
Pension and other post-retirement benefits | K | (85.1) | (100.4) | |||||||||
Other | (0.3) | 0.5 | ||||||||||
Total transition adjustments | (26.9) | (239.6) | ||||||||||
Total assets – USGAAP | $5,257.6 | $6,089.5 |
The following table summarizes the increases (decreases) to total liabilities:
As at millions of Canadian dollars | Notes | January 1 2010 | December 31 2010 | |||||||||
Total liabilities – CGAAP | $3,746.5 | $4,534.8 | ||||||||||
Accounting for joint ventures | A | (76.5) | (75.9) | |||||||||
Offsetting | B | (0.9) | – | |||||||||
Income taxes | C | 17.0 | (131.2) | |||||||||
Hedging | F | 51.9 | 49.8 | |||||||||
Issue costs | G | 20.8 | 23.2 | |||||||||
Pension and other post-retirement benefits | K | 199.3 | 291.8 | |||||||||
Preferred stock of NSPI | P | (134.0) | (134.1) | |||||||||
Other | (0.3) | (0.3) | ||||||||||
Total transition adjustments | 77.3 | 23.3 | ||||||||||
Total liabilities – USGAAP | $3,823.8 | $4,558.1 |
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The following table summarizes the increases (decreases) to net income:
For the millions of Canadian dollars | 3 months ended March 31 2010 | 6 months ended June 30 2010 | 9 months ended September 30 2010 | Year ended December 31 2010 | ||||||||||||
Net income attributable to common shareholders – CGAAP | $77.1 | $106.7 | $151.5 | $191.1 | ||||||||||||
Note C – Income taxes | 1.2 | 1.0 | (3.9) | (5.0) | ||||||||||||
Note F – Hedging | (0.7) | (4.9) | (5.4) | (6.0) | ||||||||||||
Note J – Business combinations | – | 22.5 | 22.3 | 8.4 | ||||||||||||
Note K – Pension and other post-retirement benefits | 0.6 | 1.1 | 1.7 | 2.3 | ||||||||||||
Note P – Preferred stock of NSPI | – | 0.1 | 0.1 | 0.1 | ||||||||||||
Note R – Share-based compensation | (0.1) | (0.1) | (0.2) | (0.2) | ||||||||||||
Note S – Foreign currency translation | (0.4) | (0.4) | (0.1) | (0.3) | ||||||||||||
Other | 0.1 | 0.3 | 0.6 | 0.3 | ||||||||||||
Total transition adjustments | 0.7 | 19.6 | 15.1 | (0.4) | ||||||||||||
Net income attributable to common shareholders – USGAAP | $77.8 | $126.3 | $166.6 | $190.7 | ||||||||||||
Earnings per common share – basic – CGAAP | $0.68 | $0.94 | $1.33 | $1.68 | ||||||||||||
Effect of USGAAP transition | – | 0.17 | 0.13 | (0.01) | ||||||||||||
Earnings per common share – basic – USGAAP | $0.68 | $1.11 | $1.46 | $1.67 |
84
Section I. USGAAP differences
The reconciliations of the January 1, 2010 and December 31, 2010 Balance Sheets from CGAAP to USGAAP are as follows:
As at January 1, 2010 millions of Canadian dollars | Notes | CGAAP | Effect of transition to | USGAAP | ||||||||||||
Assets | ||||||||||||||||
Current assets | ||||||||||||||||
Cash and cash equivalents | A | $21.8 | $(1.6) | $20.2 | ||||||||||||
Restricted cash | A | 1.0 | (1.0) | – | ||||||||||||
Receivables, net | A, B | 413.1 | (4.8) | 408.3 | ||||||||||||
Income taxes receivable | 11.0 | – | 11.0 | |||||||||||||
Inventory | 174.5 | – | 174.5 | |||||||||||||
Deferred income taxes | C | 46.7 | (23.6) | 23.1 | ||||||||||||
Derivatives in a valid hedging relationship | D | 26.3 | (26.3) | – | ||||||||||||
Held-for-trading derivatives | D | 13.1 | (13.1) | – | ||||||||||||
Derivative instruments | D | – | 39.3 | 39.3 | ||||||||||||
Regulatory assets | E, F | – | 131.7 | 131.7 | ||||||||||||
Prepaid expenses | A | 7.4 | (0.2) | 7.2 | ||||||||||||
Other current assets | G, H | – | 3.2 | 3.2 | ||||||||||||
Total current assets | 714.9 | 103.6 | 818.5 | |||||||||||||
Property, plant and equipment | A, C, I, J | 2,933.7 | 170.5 | 3,104.2 | ||||||||||||
Construction work-in-progress | I | 220.2 | (220.2) | – | ||||||||||||
3,153.9 | (49.7) | 3,104.2 | ||||||||||||||
Other assets | ||||||||||||||||
Deferred income taxes | C | 4.4 | 61.8 | 66.2 | ||||||||||||
Derivatives in a valid hedging relationship | D | 30.9 | (30.9) | – | ||||||||||||
Held-for-trading derivatives | D | 30.7 | (30.7) | – | ||||||||||||
Derivative instruments | A, D | – | 45.4 | 45.4 | ||||||||||||
Regulatory assets | C, E, F, J, K | – | 278.8 | 278.8 | ||||||||||||
Net investment in direct financing lease | F | 476.9 | 3.2 | 480.1 | ||||||||||||
Investments subject to significant influence | A | 218.4 | (2.1) | 216.3 | ||||||||||||
Available-for-sale investment | M | 47.3 | (46.3) | 1.0 | ||||||||||||
Goodwill | 87.6 | – | 87.6 | |||||||||||||
Intangibles | L | 92.1 | (92.1) | – | ||||||||||||
Other | | A, C, E, G, H, K, L, M | | 427.4 | (267.9) | 159.5 | ||||||||||
Total other assets | 1,415.7 | (80.8) | 1,334.9 | |||||||||||||
Total assets | $5,284.5 | $(26.9) | $5,257.6 |
85
As at January 1, 2010 millions of Canadian dollars | Notes | CGAAP | Effect of transition to | USGAAP | ||||||||||||
Liabilities and Equity | ||||||||||||||||
Current liabilities | ||||||||||||||||
Short-term debt | $300.3 | – | $300.3 | |||||||||||||
Current portion of long-term debt | A | 108.1 | (1.6) | 106.5 | ||||||||||||
Accounts payable | A, B, N | – | 218.3 | 218.3 | ||||||||||||
Accounts payable and accrued charges | N | 305.9 | (305.9) | – | ||||||||||||
Income taxes payable | C | 9.3 | 1.2 | 10.5 | ||||||||||||
Dividends payable | O | 1.7 | (1.7) | – | ||||||||||||
Derivatives in a valid hedging relationship | D | 61.0 | (61.0) | – | ||||||||||||
Held-for-trading derivatives | D | 18.6 | (18.6) | – | ||||||||||||
Derivative instruments | A, D | – | 78.2 | 78.2 | ||||||||||||
Regulatory liabilities | C, E, F | – | 50.0 | 50.0 | ||||||||||||
Pension and post-retirement liabilities | K | – | 9.2 | 9.2 | ||||||||||||
Other current liabilities | C, H, N, O, P | – | 91.7 | 91.7 | ||||||||||||
Total current liabilities | 804.9 | 59.8 | 864.7 | |||||||||||||
Long-term liabilities | ||||||||||||||||
Long-term debt | A, G, P | 2,318.4 | (42.4) | 2,276.0 | ||||||||||||
Deferred income taxes | C, K | 194.1 | (67.9) | 126.2 | ||||||||||||
Derivatives in a valid hedging relationship | D | 25.7 | (25.7) | – | ||||||||||||
Held-for-trading derivatives | D | 15.8 | (15.8) | – | ||||||||||||
Derivative instruments | A, D | – | 35.5 | 35.5 | ||||||||||||
Regulatory liabilities | C, E, F | – | 91.5 | 91.5 | ||||||||||||
Asset retirement obligations | 104.5 | – | 104.5 | |||||||||||||
Pension and post-retirement liabilities | K | – | 292.4 | 292.4 | ||||||||||||
Other long-term liabilities | A, E, H, K | 148.1 | (115.1) | 33.0 | ||||||||||||
Preferred shares issued by a subsidiary | P | 135.0 | (135.0) | – | ||||||||||||
Total long-term liabilities | 2,941.6 | 17.5 | 2,959.1 | |||||||||||||
Non-controlling interest | Q | 32.1 | (32.1) | – | ||||||||||||
Equity | ||||||||||||||||
Common stock | R | 1,096.7 | 1.2 | 1,097.9 | ||||||||||||
Contributed surplus | R | 3.6 | (0.6) | 3.0 | ||||||||||||
Accumulated other comprehensive loss | A, C, F, K, S | (186.7) | (239.5) | (426.2) | ||||||||||||
Retained earnings | F, G, J, K, P, R, S | 592.3 | 2.5 | 594.8 | ||||||||||||
Total Emera Incorporated equity | 1,505.9 | (236.4) | 1,269.5 | |||||||||||||
Non-controlling interest in subsidiaries | P, Q | – | 164.3 | 164.3 | ||||||||||||
Total equity | 1,505.9 | (72.1) | 1,433.8 | |||||||||||||
Total liabilities and equity | $5,284.5 | $(26.9) | $5,257.6 |
86
As at December 31, 2010 millions of Canadian dollars | Notes | CGAAP | Effect of transition to | USGAAP | ||||||||||||
Assets | ||||||||||||||||
Current assets | ||||||||||||||||
Cash and cash equivalents | A | $9.4 | $(2.1) | $7.3 | ||||||||||||
Restricted cash | A | 59.6 | (1.0) | 58.6 | ||||||||||||
Receivables, net | A | 396.5 | (3.6) | 392.9 | ||||||||||||
Income taxes receivable | C | 50.7 | (6.4) | 44.3 | ||||||||||||
Inventory | 177.8 | – | 177.8 | |||||||||||||
Deferred income taxes | C | 28.2 | (14.5) | 13.7 | ||||||||||||
Derivatives in a valid hedging relationship | D | 28.4 | (28.4) | – | ||||||||||||
Held-for-trading derivatives | D | 22.1 | (22.1) | – | ||||||||||||
Derivative instruments | A, D | – | 49.7 | 49.7 | ||||||||||||
Regulatory assets | E, F | – | 90.5 | 90.5 | ||||||||||||
Prepaid expenses | A | 9.8 | (0.3) | 9.5 | ||||||||||||
Other current assets | G, H | – | 3.1 | 3.1 | ||||||||||||
Total current assets | 782.5 | 64.9 | 847.4 | |||||||||||||
Property, plant and equipment | A, C, I, J | 3,456.1 | 286.5 | 3,742.6 | ||||||||||||
Construction work-in-progress | I | 333.0 | (333.0) | – | ||||||||||||
3,789.1 | (46.5) | 3,742.6 | ||||||||||||||
Other assets | ||||||||||||||||
Deferred income taxes | C | 12.9 | 18.2 | 31.1 | ||||||||||||
Derivatives in a valid hedging relationship | D | 26.1 | (26.1) | – | ||||||||||||
Held-for-trading derivatives | D | 15.3 | (15.3) | – | ||||||||||||
Derivative instruments | A, D | – | 36.0 | 36.0 | ||||||||||||
Regulatory assets | C, E, F, K | – | 354.9 | 354.9 | ||||||||||||
Net investment in direct financing lease | F | 488.2 | 3.3 | 491.5 | ||||||||||||
Investments subject to significant influence | A, C, J | 238.9 | 7.1 | 246.0 | ||||||||||||
Available-for-sale investment | M | 47.0 | (46.2) | 0.8 | ||||||||||||
Goodwill | J, K | 178.9 | (11.5) | 167.4 | ||||||||||||
Intangibles | L | 98.1 | (98.1) | – | ||||||||||||
Other | A, C, E, G, H, J, K, L, M | 652.1 | (480.3) | 171.8 | ||||||||||||
Total other assets | 1,757.5 | (258.0) | 1,499.5 | |||||||||||||
Total assets | $6,329.1 | $(239.6) | $6,089.5 |
87
As at December 31, 2010 millions of Canadian dollars | Notes | CGAAP | Effect of transition to | USGAAP | ||||||||||||
Liabilities and Equity | ||||||||||||||||
Current liabilities | ||||||||||||||||
Short-term debt | G | $81.3 | $0.4 | $81.7 | ||||||||||||
Current portion of long-term debt | A | 12.7 | (2.1) | 10.6 | ||||||||||||
Accounts payable | A, N | – | 293.9 | 293.9 | ||||||||||||
Accounts payable and accrued charges | N | 399.6 | (399.6) | – | ||||||||||||
Income taxes payable | C | 8.4 | (0.9) | 7.5 | ||||||||||||
Deferred income taxes | C | – | 8.5 | 8.5 | ||||||||||||
Dividends payable | O | 1.8 | (1.8) | – | ||||||||||||
Derivatives in a valid hedging relationship | D | 8.6 | (8.6) | – | ||||||||||||
Held-for-trading derivatives | D | 31.1 | (31.1) | – | ||||||||||||
Derivative instruments | A, D | – | 36.8 | 36.8 | ||||||||||||
Regulatory liabilities | C, E, F | – | 55.0 | 55.0 | ||||||||||||
Pension and post-retirement liabilities | K | – | 8.9 | 8.9 | ||||||||||||
Other current liabilities | A, C, H, N, O, P | – | 110.3 | 110.3 | ||||||||||||
Total current liabilities | 543.5 | 69.7 | 613.2 | |||||||||||||
Long-term liabilities | ||||||||||||||||
Long-term debt | A, G, P | 3,153.7 | (35.2) | 3118.5 | ||||||||||||
Deferred income taxes | C, K | 359.8 | (191.3) | 168.5 | ||||||||||||
Derivatives in a valid hedging relationship | D | 21.3 | (21.3) | – | ||||||||||||
Held-for-trading derivatives | D | 18.0 | (18.0) | – | ||||||||||||
Derivative instruments | A, D | – | 28.9 | 28.9 | ||||||||||||
Regulatory liabilities | C, E, F | – | 65.2 | 65.2 | ||||||||||||
Asset retirement obligations | 141.8 | – | 141.8 | |||||||||||||
Pension and post-retirement liabilities | K | – | 400.0 | 400.0 | ||||||||||||
Other long-term liabilities | E, H, K | 161.7 | (139.7) | 22.0 | ||||||||||||
Preferred shares issued by a subsidiary | P | 135.0 | (135.0) | – | ||||||||||||
Total long-term liabilities | 3,991.3 | (46.4) | 3,944.9 | |||||||||||||
Non-controlling interest | Q | 20.7 | (20.7) | – | ||||||||||||
Equity | ||||||||||||||||
Common stock | R | 1,136.5 | 1.3 | 1,137.8 | ||||||||||||
Preferred stock | 146.7 | – | 146.7 | |||||||||||||
Contributed surplus | R | 3.7 | (0.5) | 3.2 | ||||||||||||
Accumulated other comprehensive loss | A, C, F, J, K, Q, S | (164.7) | (399.5) | (564.2) | ||||||||||||
Retained earnings | C, F, G, J, K, P, R, S | 651.4 | 2.1 | 653.5 | ||||||||||||
Total Emera Incorporated equity | 1,773.6 | (396.6) | 1,377.0 | |||||||||||||
Non-controlling interest in subsidiaries | P, Q | – | 154.4 | 154.4 | ||||||||||||
Total equity | 1,773.6 | (242.2) | 1,531.4 | |||||||||||||
Total liabilities and equity | $6,329.1 | $(239.6) | $6,089.5 |
88
The adjustments to January 1, 2010 and December 31, 2010 equity are as follows:
As at January 1, 2010 millions of Canadian | Common Stock | Contributed Surplus | Accumulated Income (Loss) | Retained Earnings | Non- controlling Interest in Subsidiaries | Total Equity
| ||||||||||||||||||
CGAAP | $1,096.7 | $3.6 | $(186.7) | $592.3 | – | $1,505.9 | ||||||||||||||||||
Note A – Accounting | – | – | 0.1 | – | – | 0.1 | ||||||||||||||||||
Note C – Income taxes | – | – | 0.2 | – | – | 0.2 | ||||||||||||||||||
Note F – Hedging | – | – | 36.6 | 10.6 | – | 47.2 | ||||||||||||||||||
Note G – Issue costs | – | – | – | (1.1) | – | (1.1) | ||||||||||||||||||
Note J – Business combinations | – | – | – | (0.2) | – | (0.2) | ||||||||||||||||||
Note K – Pension and | – | – | (277.6) | (6.8) | – | (284.4) | ||||||||||||||||||
Note P – Preferred | – | – | – | 1.8 | $132.2 | 134.0 | ||||||||||||||||||
Note Q – Non- | – | – | – | – | 32.1 | 32.1 | ||||||||||||||||||
Note R – Share-based compensation | 1.2 | (0.6) | – | (0.6) | – | – | ||||||||||||||||||
Note S – Foreign | – | – | 1.2 | (1.2) | – | – | ||||||||||||||||||
Total transition adjustments | 1.2 | (0.6) | (239.5) | 2.5 | 164.3 | (72.1) | ||||||||||||||||||
USGAAP | $1,097.9 | $3.0 | $(426.2) | $594.8 | $164.3 | $1,433.8 |
As at December 31, 2010 millions of Canadian | Common Stock | Preferred Stock | Contributed Surplus | Accumulated Other Comprehensive Income (Loss) | Retained Earnings | Non- controlling Interest in Subsidiaries | Total Equity | |||||||||||||||||||||
CGAAP | $1,136.5 | $146.7 | $3.7 | $(164.7) | $651.4 | – | $1,773.6 | |||||||||||||||||||||
Note A – Accounting | – | – | – | 0.5 | – | – | 0.5 | |||||||||||||||||||||
Note C – Income | – | – | – | 0.2 | (5.4) | – | (5.2) | |||||||||||||||||||||
Note F – Hedging | – | – | – | (12.1) | 4.6 | – | (7.5) | |||||||||||||||||||||
Note G – Issue costs | – | – | – | – | (1.1) | – | (1.1) | |||||||||||||||||||||
Note J – Business combinations | – | – | – | (0.5) | 8.2 | – | 7.7 | |||||||||||||||||||||
Note K – Pension and other post-retirement benefits | – | – | – | (387.9) | (4.3) | – | (392.2) | |||||||||||||||||||||
Note P – Preferred | – | – | – | – | 1.9 | $132.2 | 134.1 | |||||||||||||||||||||
Note Q – Non- | – | – | – | (1.5) | – | 22.2 | 20.7 | |||||||||||||||||||||
Note R – Share- | 1.3 | – | (0.5) | – | (0.8) | – | – | |||||||||||||||||||||
Note S – Foreign | – | – | – | 1.6 | (1.6) | – | – | |||||||||||||||||||||
Other | – | – | – | 0.2 | 0.6 | – | 0.8 | |||||||||||||||||||||
Total transition adjustments | 1.3 | – | (0.5) | (399.5) | 2.1 | 154.4 | (242.2) | |||||||||||||||||||||
USGAAP | $1,137.8 | $146.7 | $3.2 | $(564.2) | $653.5 | $154.4 | $1,531.4 |
89
The statements of income for the 2010 periods reconciled from CGAAP to USGAAP are as follows:
For the three months ended March 31, 2010 millions of Canadian dollars (except per share | Notes | CGAAP | Effect of transition to USGAAP | USGAAP | ||||||||||
Operating revenues | ||||||||||||||
Electric | T | $412.1 | $(412.1) | – | ||||||||||
Finance income from direct finance lease | T | 14.2 | (14.2) | – | ||||||||||
Other | T | 3.8 | (3.8) | – | ||||||||||
Regulated | F, T, U | – | 395.4 | $395.4 | ||||||||||
Non-regulated | A, T, U | – | 43.1 | 43.1 | ||||||||||
Total operating revenues | 430.1 | 8.4 | 438.5 | |||||||||||
Operating expenses | ||||||||||||||
Regulated fuel for generation and purchased power | U, V | 217.7 | (23.7) | 194.0 | ||||||||||
Regulated fuel adjustment | (39.4) | – | (39.4) | |||||||||||
Non-regulated fuel for generation and purchase power | A, V | – | 23.1 | 23.1 | ||||||||||
Non-regulated direct costs | U | – | 8.2 | 8.2 | ||||||||||
Operating, maintenance and general | A, K, R, U | 76.7 | 0.8 | 77.5 | ||||||||||
Provincial, state and municipal taxes | A | 12.4 | (0.4) | 12.0 | ||||||||||
Depreciation and amortization | A, C, X | 42.3 | 5.0 | 47.3 | ||||||||||
Regulatory amortization | X | 5.4 | (5.4) | – | ||||||||||
Total operating expenses | 315.1 | 7.6 | 322.7 | |||||||||||
Income from operations | 115.0 | 0.8 | 115.8 | |||||||||||
Income from equity investments | A | 2.3 | (1.6) | 0.7 | ||||||||||
Other income (expenses), net | A, F, S, T, U, W, Y | – | (1.8) | (1.8) | ||||||||||
Financing charges | P, W, Y | 43.2 | (43.2) | – | ||||||||||
Interest expense, net | A, C, U, W, Y | – | 37.6 | 37.6 | ||||||||||
Income before provision for income taxes | 74.1 | 3.0 | 77.1 | |||||||||||
Income tax expense (recovery) | A, C | (2.8) | 0.3 | (2.5) | ||||||||||
Net income from operations | 76.9 | 2.7 | 79.6 | |||||||||||
Non-controlling interest in subsidiaries | P | (0.2) | 2.0 | 1.8 | ||||||||||
Net income attributable to common shareholders | $77.1 | $0.7 | $77.8 | |||||||||||
Weighted average number of shares (in millions) | ||||||||||||||
Basic | 113.2 | 0.4 | 113.6 | |||||||||||
Diluted | 120.0 | – | 120.0 | |||||||||||
Earnings per common share | ||||||||||||||
Basic | $0.68 | – | $0.68 | |||||||||||
Diluted | $0.66 | $0.01 | $0.67 | |||||||||||
Dividends per common share declared | $0.2725 | – | $0.2725 |
90
For the six months ended June 30, 2010 millions of Canadian dollars (except per share | Notes | CGAAP | Effect of transition to USGAAP | USGAAP | ||||||||||
Operating revenues | ||||||||||||||
Electric | T | $739.7 | $(739.7) | – | ||||||||||
Finance income from direct finance lease | T | 29.0 | (29.0) | – | ||||||||||
Other | T | 18.8 | (18.8) | – | ||||||||||
Regulated | F, T, U | – | 721.0 | $721.0 | ||||||||||
Non-regulated | A, T, U | – | 82.2 | 82.2 | ||||||||||
Total operating revenues | 787.5 | 15.7 | 803.2 | |||||||||||
Operating expenses | ||||||||||||||
Regulated fuel for generation and purchased power | U, V | 375.0 | (45.4) | 329.6 | ||||||||||
Regulated fuel adjustment | (52.0) | – | (52.0) | |||||||||||
Non-regulated fuel for generation and purchase power | A, V | – | 43.9 | 43.9 | ||||||||||
Non-regulated direct costs | U | – | 23.5 | 23.5 | ||||||||||
Operating, maintenance and general | A, K, R, U, W | 158.0 | 2.3 | 160.3 | ||||||||||
Provincial, state and municipal taxes | A | 24.5 | (0.8) | 23.7 | ||||||||||
Depreciation and amortization | A, C, X | 85.4 | 10.2 | 95.6 | ||||||||||
Regulatory amortization | X | 10.9 | (10.9) | – | ||||||||||
Total operating expenses | 601.8 | 22.8 | 624.6 | |||||||||||
Income from operations | 185.7 | (7.1) | 178.6 | |||||||||||
Income from equity investments | A, C | 6.2 | 1.7 | 7.9 | ||||||||||
Other income (expenses), net | F, J, S, T, U, W, Y | – | 17.7 | 17.7 | ||||||||||
Financing charges | P, W, Y | 84.3 | (84.3) | – | ||||||||||
Interest expense, net | A, C, P, U, W, Y | – | 75.4 | 75.4 | ||||||||||
Income before provision for income taxes | 107.6 | 21.2 | 128.8 | |||||||||||
Income tax expense (recovery) | A, C | 0.9 | (2.4) | (1.5) | ||||||||||
Net income from operations | 106.7 | 23.6 | 130.3 | |||||||||||
Non-controlling interest in subsidiaries | P | – | 4.0 | 4.0 | ||||||||||
Net income attributable to common shares | $106.7 | $19.6 | $126.3 | |||||||||||
Weighted average number of shares (in millions) | ||||||||||||||
Basic | 113.3 | 0.4 | 113.7 | |||||||||||
Diluted | 120.2 | (0.1) | 120.1 | |||||||||||
Earnings per common share | ||||||||||||||
Basic | $0.94 | $0.17 | $1.11 | |||||||||||
Diluted | $0.92 | $0.16 | $1.08 | |||||||||||
Dividends per common share declared | $0.5550 | – | $0.5550 |
91
For the nine months ended September 30, 2010 millions of Canadian dollars (except per share | Notes | CGAAP | Effect of transition to USGAAP | USGAAP | ||||||||||
Operating revenues | ||||||||||||||
Electric | T | $1,074.0 | $(1,074.0) | – | ||||||||||
Finance income from direct finance lease | T | 42.8 | (42.8) | – | ||||||||||
Other | T | 44.2 | (44.2) | – | ||||||||||
Regulated | F, T, U | – | 1,053.9 | $1,053.9 | ||||||||||
Non-regulated | A, T, U | – | 143.3 | 143.3 | ||||||||||
Total operating revenues | 1,161.0 | 36.2 | 1,197.2 | |||||||||||
Operating expenses | ||||||||||||||
Regulated fuel for generation and purchased power | U, V | 541.9 | (65.1) | 476.8 | ||||||||||
Regulated fuel adjustment | (75.0) | – | (75.0) | |||||||||||
Non-regulated fuel for generation and purchase power | A, V | – | 64.5 | 64.5 | ||||||||||
Non-regulated direct costs | U | – | 46.1 | 46.1 | ||||||||||
Operating, maintenance and general | A, K, R, U, W | 244.1 | 3.4 | 247.5 | ||||||||||
Provincial, state and municipal taxes | A | 36.8 | (1.3) | 35.5 | ||||||||||
Depreciation and amortization | A, C, X | 127.9 | 15.8 | 143.7 | ||||||||||
Regulatory amortization | X | 16.7 | (16.7) | – | ||||||||||
Total operating expenses | 892.4 | 46.7 | 939.1 | |||||||||||
Income from operations | 268.6 | (10.5) | 258.1 | |||||||||||
Income from equity investments | A, C | 11.3 | 2.3 | 13.6 | ||||||||||
Other income (expenses), net | F, J, S, T, U, W, Y | – | 18.0 | 18.0 | ||||||||||
Financing charges | P, W, Y | 124.6 | (124.6) | – | ||||||||||
Interest expense, net | A, C, P, U, W, Y | – | 111.5 | 111.5 | ||||||||||
Income before provision for income taxes | 155.3 | 22.9 | 178.2 | |||||||||||
Income tax expense (recovery) | A, C | 0.6 | 1.9 | 2.5 | ||||||||||
Net income from operations | 154.7 | 21.0 | 175.7 | |||||||||||
Non-controlling interest in subsidiaries | P | 0.1 | 6.0 | 6.1 | ||||||||||
Net income of Emera Incorporated | 154.6 | 15.0 | 169.6 | |||||||||||
Preferred stock dividends | C | 3.1 | (0.1) | 3.0 | ||||||||||
Net income attributable to common shareholders | $151.5 | $15.1 | $166.6 | |||||||||||
Weighted average number of shares (in millions) | ||||||||||||||
Basic | 113.5 | 0.5 | 114.0 | |||||||||||
Diluted | 120.2 | 0.1 | 120.3 | |||||||||||
Earnings per common share | ||||||||||||||
Basic | $1.33 | $0.13 | $1.46 | |||||||||||
Diluted | $1.31 | $0.12 | $1.43 | |||||||||||
Dividends per common share declared | $1.1625 | – | $1.1625 |
92
For the year ended December 31, 2010 millions of Canadian dollars (except per share amounts) | Notes | CGAAP | Effect of transition to USGAAP | USGAAP | ||||||||||||
Operating revenues | ||||||||||||||||
Electric | T | $1,436.1 | $(1,436.1) | – | ||||||||||||
Finance income from direct finance lease | T | 56.5 | (56.5) | – | ||||||||||||
Other | T | 61.1 | (61.1) | – | ||||||||||||
Regulated | F, T, U | – | 1,411.6 | $1,411.6 | ||||||||||||
Non-regulated | A, T, U | – | 194.5 | 194.5 | ||||||||||||
Total operating revenues | 1,553.7 | 52.4 | 1,606.1 | |||||||||||||
Operating expenses | ||||||||||||||||
Regulated fuel for generation and purchased power | U, V | 718.7 | (84.1) | 634.6 | ||||||||||||
Regulated fuel adjustment | (99.0) | – | (99.0) | |||||||||||||
Non-regulated fuel for generation and purchase power | A, V | – | 83.9 | 83.9 | ||||||||||||
Non-regulated direct costs | U | – | 62.3 | 62.3 | ||||||||||||
Operating, maintenance and general | | A, J, K, R, U, W | | 336.1 | 15.1 | 351.2 | ||||||||||
Provincial, state and municipal taxes | A | 49.1 | (1.7) | 47.4 | ||||||||||||
Depreciation and amortization | A, C, X | 173.6 | 39.9 | 213.5 | ||||||||||||
Regulatory amortization | X | 41.3 | (41.3) | – | ||||||||||||
Total operating expenses | 1,219.8 | 74.1 | 1,293.9 | |||||||||||||
Income from operations | 333.9 | (21.7) | 312.2 | |||||||||||||
Income from equity investments | A, C | 13.6 | 1.7 | 15.3 | ||||||||||||
Other income (expenses), net | | F, J, S, T, U, W, Y | | – | 12.5 | 12.5 | ||||||||||
Financing charges | P, W, Y | 168.4 | (168.4) | – | ||||||||||||
Interest expense, net | | A, C, P, U, W, Y | | – | 148.8 | 148.8 | ||||||||||
Income before provision for income taxes | 179.1 | 12.1 | 191.2 | |||||||||||||
Income tax expense (recovery) | A, C | (12.8) | 4.7 | (8.1) | ||||||||||||
Net income from operations | 191.9 | 7.4 | 199.3 | |||||||||||||
Non-controlling interest in subsidiaries | P | (2.3) | 7.9 | 5.6 | ||||||||||||
Net income of Emera Incorporated | 194.2 | (0.5) | 193.7 | |||||||||||||
Preferred stock dividends | C | 3.1 | (0.1) | 3.0 | ||||||||||||
Net income attributable to common shareholders | $191.1 | $(0.4) | $190.7 | |||||||||||||
Weighted average number of shares (in millions) | ||||||||||||||||
Basic | 113.7 | 0.5 | 114.2 | |||||||||||||
Diluted | 120.3 | 0.1 | 120.4 | |||||||||||||
Earnings per common share | ||||||||||||||||
Basic | $1.68 | $(0.1) | $1.67 | |||||||||||||
Diluted | $1.65 | – | $1.65 | |||||||||||||
Dividends per common share declared | $1.1625 | – | $1.1625 |
93
The consolidated statements of cash flows for the 2010 periods reconciled from CGAAP to USGAAP are as follows:
For the three months ended March 31, 2010 millions of Canadian dollars | Notes | CGAAP | Effect of transition to USGAAP | USGAAP | ||||||||||||
Net cash used in operating activities | A, P, R, Y | $(5.7) | $3.1 | $(2.6) | ||||||||||||
Net cash used in investing activities | A, Y | (66.7) | (1.6) | (68.3) | ||||||||||||
Net cash provided by financing activities | P, R | 62.3 | (2.1) | 60.2 | ||||||||||||
Effect of exchange rate changes on cash and cash equivalents | (0.2) | 0.6 | 0.4 | |||||||||||||
Net decrease in cash and cash equivalents | (10.3) | – | (10.3) | |||||||||||||
Cash and cash equivalents, beginning of period | A | 21.8 | (1.6) | 20.2 | ||||||||||||
Cash and cash equivalents, end of period | A | $11.5 | $(1.6) | $9.9 |
For the six months ended June 30, 2010 millions of Canadian dollars | Notes | CGAAP | Effect of transition to USGAAP | USGAAP | ||||||||||||
Net cash provided by operating activities | A, P, R, Y | $105.1 | $4.9 | $110.0 | ||||||||||||
Net cash used in investing activities | A, Y | (298.2) | (3.9) | (302.1) | ||||||||||||
Net cash provided by financing activities | A, P, R | 220.0 | (3.2) | 216.8 | ||||||||||||
Effect of exchange rate changes on cash and cash equivalents | 0.5 | (0.3) | 0.2 | |||||||||||||
Net increase (decrease) in cash and cash equivalents | 27.4 | (2.5) | 24.9 | |||||||||||||
Cash and cash equivalents, beginning of period | A | 21.8 | (1.6) | 20.2 | ||||||||||||
Cash and cash equivalents, end of period | A | $49.2 | $(4.1) | $45.1 |
For the nine months ended September 30, 2010 millions of Canadian dollars | Notes | CGAAP | Effect of transition to USGAAP | USGAAP | ||||||||||||
Net cash provided by operating activities | A, P, R, Y | $230.9 | $7.1 | $238.0 | ||||||||||||
Net cash used in investing activities | A, Y | (452.0) | (6.4) | (458.4) | ||||||||||||
Net cash provided by financing activities | A, P, R | 247.2 | (3.7) | 243.5 | ||||||||||||
Effect of exchange rate changes on cash and cash equivalents | (0.4) | 0.6 | 0.2 | |||||||||||||
Net increase (decrease) in cash and cash equivalents | 25.7 | (2.4) | 23.3 | |||||||||||||
Cash and cash equivalents, beginning of period | A | 21.8 | (1.6) | 20.2 | ||||||||||||
Cash and cash equivalents, end of period | A | $47.5 | $(4.0) | $43.5 |
For the year ended December 31, 2010 millions of Canadian dollars | Notes | CGAAP | Effect of transition to USGAAP | USGAAP | ||||||||||||
Net cash provided by operating activities | A, C, P, R, Y | $416.4 | $17.3 | $433.7 | ||||||||||||
Net cash used in investing activities | A, C, Y | (894.8) | (8.7) | (903.5) | ||||||||||||
Net cash provided by financing activities | A, P, R | 466.2 | (9.3) | 456.9 | ||||||||||||
Effect of exchange rate changes on cash and cash equivalents | (0.2) | 0.2 | – | |||||||||||||
Net decrease in cash and cash equivalents | (12.4) | (0.5) | (12.9) | |||||||||||||
Cash and cash equivalents, beginning of period | A | 21.8 | (1.6) | 20.2 | ||||||||||||
Cash and cash equivalents, end of period | A | $9.4 | $(2.1) | $7.3 |
94
NOTES TO THE TRANSITIONAL ADJUSTMENTS
Under USGAAP, the Company is (i) measuring certain assets, liabilities, revenues and expenses differently than it had been under CGAAP (see details on each measurement change below); and (ii) disclosing certain assets, liabilities, revenues and expenses on different lines in the financial statements than they had been under CGAAP (see details on each classification change below).
A. Accounting for joint ventures (measurement difference)
The Company exercises joint control over its investment in Bear Swamp with its third-party partner and therefore, proportionately consolidated the investment under CGAAP. Under the proportionate consolidation method the Company recognized its pro-rata share of the jointly controlled assets and liabilities of Bear Swamp in the Company’s balance sheet and recognized its pro-rata share of the revenues and expenses of Bear Swamp in the Company’s income statement.
Under USGAAP, the Company accounts for its investment in Bear Swamp using the equity method, whereby the amount of the investment is adjusted quarterly for the Company’s pro-rata share of Bear Swamp’s post-acquisition net income and reduced by the amount of any dividends received. The Company’s pro-rata share of Bear Swamp’s net income is recognized in “Income from equity investments”.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Current assets | ||||||||
Cash and cash equivalents | $(1.6) | $(2.1) | ||||||
Restricted cash | (1.0) | (1.0) | ||||||
Receivables, net | (3.9) | (3.2) | ||||||
Derivative instruments | – | (0.8) | ||||||
Prepaid expenses | (0.2) | (0.2) | ||||||
Property, plant and equipment | (51.0) | (48.1) | ||||||
Other assets | ||||||||
Derivative instruments | (16.1) | (5.3) | ||||||
Investments subject to significant influence | (2.0) | (14.3) | ||||||
Other | (0.6) | (0.4) | ||||||
Current liabilities | ||||||||
Current portion of long-term debt | (1.6) | (2.1) | ||||||
Accounts payable | (1.2) | (1.9) | ||||||
Derivative instruments | (1.4) | (2.9) | ||||||
Other current liabilities | – | (0.1) | ||||||
Long-term liabilities | ||||||||
Long-term debt | (63.8) | (58.5) | ||||||
Derivative instruments | (5.9) | (10.4) | ||||||
Other long-term liabilities | (2.6) | – | ||||||
Equity | ||||||||
Accumulated other comprehensive income (loss) | 0.1 | 0.5 |
95
For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended September 30 2010 | Year ended December 31 2010 | ||||||||||||
Non-regulated operating revenues | $(3.6) | $(15.6) | $(23.0) | $(28.1) | ||||||||||||
Non-regulated fuel for generation and purchased power | (4.6) | (9.0) | (13.0) | (17.2) | ||||||||||||
Operating, maintenance and general | (0.9) | (1.7) | (2.9) | (4.9) | ||||||||||||
Provincial, state and municipal taxes | (0.4) | (0.8) | (1.3) | (1.7) | ||||||||||||
Depreciation and amortization | (0.4) | (0.8) | (1.2) | (1.8) | ||||||||||||
Income from equity investments | (1.6) | 1.8 | 2.4 | 1.8 | ||||||||||||
Other income (expenses), net | (0.2) | – | – | – | ||||||||||||
Interest expense, net | (0.3) | (0.5) | (0.7) | (1.0) | ||||||||||||
Income tax expense (recovery) | 1.2 | (1.0) | (1.5) | 0.3 |
For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the effect on the Statements of Cash Flows is as follows:
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended September 30 2010 | Year ended December 31 2010 | ||||||||||||
Net cash provided by (used in) operating activities | $0.1 | $(3.2) | $(4.5) | $(0.4) | ||||||||||||
Net cash (used in) provided by investing activities | (0.1) | (0.2) | 0.1 | 1.5 | ||||||||||||
Net cash provided by (used in) financing activities | – | 0.9 | 1.5 | (1.6) | ||||||||||||
Cash and cash equivalents, beginning of period | (1.6) | (1.6) | (1.6) | (1.6) | ||||||||||||
Cash and cash equivalents, end of period | (1.6) | (4.1) | (4.5) | (2.1) |
B. Offsetting (measurement difference)
Certain items on the balance sheets are being offset where a legal right of setoff exists. Differences exist between CGAAP and USGAAP in defining what balances may be offset. As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Receivables, net | $(0.9) | – | ||||||
Accounts payable | (0.9) | – |
C. Income taxes (measurement difference)
In addition to the tax effects of other transition adjustments, the following are included in the income tax adjustments.
Investment tax credits (“ITCs”)
Under CGAAP, the Company recognizes ITCs as a reduction from the related expenditures where there is reasonable assurance of collection. Under USGAAP, the Company recognizes ITCs as a reduction of income tax expense in the current and future periods to the extent that realization of such benefit is more likely than not.
96
Tax rates
Under CGAAP, the Company measured income taxes using substantively enacted income tax rates. Under USGAAP, the Company uses enacted income tax rates. The Company recognized an income tax liability under USGAAP for the difference between the enacted tax rates and the substantively enacted tax rates for the Part VI.1 tax deduction related to preferred share dividends.
Uncertain tax positions
Under CGAAP, the Company recognized the benefit of an uncertain tax position when it was probable of being sustained.
Under USGAAP, the Company recognizes the benefit of an uncertain tax position only when it is more likely than not that such a position will be sustained by the taxing authorities based on the technical merits of the position. The current and deferred income tax impact is equal to the largest amount, considering possible settlement outcomes, that is greater than 50 percent likely of being realized upon settlement with the taxing authorities.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Current assets | ||||||||
Income taxes receivable | – | $(6.4) | ||||||
Deferred income taxes | $(23.6) | (14.5) | ||||||
Property, plant and equipment | 1.1 | 1.4 | ||||||
Other assets | ||||||||
Deferred income taxes | 61.7 | 17.9 | ||||||
Regulatory assets | (23.1) | (134.9) | ||||||
Investments subject to significant influence | – | (0.6) | ||||||
Other | 1.1 | 0.7 | ||||||
Current liabilities | ||||||||
Income taxes payable | 1.2 | (0.8) | ||||||
Deferred income taxes | – | 8.5 | ||||||
Regulatory liabilities | 6.7 | 4.1 | ||||||
Other current liabilities | 1.3 | 1.1 | ||||||
Long-term liabilities | ||||||||
Deferred income taxes | (53.6) | (176.5) | ||||||
Regulatory liabilities | 61.4 | 32.4 | ||||||
Equity | ||||||||
Accumulated other comprehensive income (loss) | 0.2 | 0.2 | ||||||
Retained earnings | – | (5.4) |
For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended September 30 2010 | Year ended December 31 2010 | ||||||||||||
Depreciation and amortization | $0.1 | $0.2 | $0.3 | $0.4 | ||||||||||||
Income from equity investments | – | (0.1) | (0.4) | (0.6) | ||||||||||||
Interest expense, net | (0.3) | (0.3) | (0.4) | (0.2) | ||||||||||||
Income tax expense (recovery) | (1.0) | (1.0) | 3.7 | 4.3 | ||||||||||||
Preferred stock dividends | – | – | (0.1) | (0.1) |
97
For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the effect on the Statements of Cash Flows is as follows:
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended September 30 2010 | Year ended December 31 2010 | ||||||||||||
Net cash provided by operating activities | – | – | – | $0.3 | ||||||||||||
Net cash used in investing activities | – | – | – | (0.3) |
D. Derivatives (classification change)
Under CGAAP, the Company was disclosing its derivatives in valid hedging relationships and held-for-trading derivatives as separate line items on the balance sheet. Under USGAAP, the Company has included these balances together in “Derivative instruments”.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Current assets | ||||||||
Derivative instruments | $39.4 | $50.5 | ||||||
Derivatives in a valid hedging relationship | (26.3) | (28.4) | ||||||
Held-for-trading derivatives | (13.1) | (22.1) | ||||||
Other assets | ||||||||
Derivative instruments | 61.6 | 41.4 | ||||||
Derivatives in a valid hedging relationship | (30.9) | (26.1) | ||||||
Held-for-trading derivatives | (30.7) | (15.3) | ||||||
Current liabilities | ||||||||
Derivative instruments | 79.6 | 39.7 | ||||||
Derivatives in a valid hedging relationship | (61.0) | (8.6) | ||||||
Held-for-trading derivatives | (18.6) | (31.1) | ||||||
Long-term liabilities | ||||||||
Derivative instruments | 41.5 | 39.3 | ||||||
Derivatives in a valid hedging relationship | (25.7) | (21.3) | ||||||
Held-for-trading derivatives | (15.8) | (18.0) |
E. Regulatory assets and liabilities (classification change)
Under CGAAP, the Company was disclosing its regulatory assets and liabilities in other assets and liabilities respectively. Under USGAAP, the Company discloses its regulatory assets and liabilities as separate line items on the balance sheet.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Current assets | ||||||||
Regulatory assets | $55.8 | $63.7 | ||||||
Other assets | ||||||||
Regulatory assets | 273.1 | 466.3 | ||||||
Other | (328.9) | (530.0) | ||||||
Current liabilities | ||||||||
Regulatory liabilities | 21.2 | 22.1 | ||||||
Long-term liabilities | ||||||||
Regulatory liabilities | 0.5 | 11.9 | ||||||
Other long-term liabilities | (21.7) | (34.0) |
98
F. Hedging (measurement change)
Brunswick Pipeline
Under CGAAP, cash flow hedging strategies of Brunswick Pipeline qualified for hedge accounting. Under USGAAP, the Company determined that certain cash flow hedging strategies did not qualify for hedge accounting primarily due to differences in effectiveness testing requirements. The Company changed its effectiveness testing for hedges put in place beginning January 1, 2010 and these hedges qualify for hedge accounting under USGAAP.
As a result of disqualifying cash flow hedges in place prior to 2010, Brunswick Pipeline must recognize changes in fair value on these derivatives in net income of the period, rather than deferring the changes to accumulated other comprehensive income. In addition, because of the change in effectiveness testing effective January 1, 2010, Brunswick Pipeline must measure and recognize any ineffectiveness of its hedging strategies in net income of the period.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Net investment in direct financing lease | $3.2 | $3.2 | ||||||
Accumulated other comprehensive income (loss) | (7.4) | (1.4) | ||||||
Retained earnings | 10.6 | 4.6 |
For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended September 30 2010 | Year ended December 31 2010 | ||||||||||||
Regulated operating revenues | $(2.0) | $(4.2) | $(5.9) | $(7.4) | ||||||||||||
Other income (expenses), net | 1.3 | (0.7) | 0.5 | 1.4 |
Nova Scotia Power
In addition to the above, effective for 2011, NSPI implemented an amended hedge accounting policy which was approved by the UARB. The amended policy resulted from stakeholder requests to simplify the accounting for derivatives used to manage risk and to alleviate any USGAAP issues which would result in increased income volatility. The amended policy is applied retrospectively with restatement of prior periods with the exception of prior period income, and requires regulatory deferral for commodity, foreign exchange and interest derivatives documented as economic hedges and for physical contracts that do not qualify for the NPNS exception under USGAAP.
99
As a result of the amended accounting policy, NSPI receives regulatory deferral for any changes in fair value on derivatives documented as economic hedges. As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Current assets | ||||||||
Regulatory assets | $75.9 | $26.9 | ||||||
Other assets | ||||||||
Regulatory assets | 20.0 | 12.2 | ||||||
Current liabilities | ||||||||
Regulatory liabilities | 22.1 | 28.6 | ||||||
Long-term liabilities | ||||||||
Regulatory liabilities | 29.8 | 21.2 | ||||||
Equity | ||||||||
Accumulated other comprehensive income (loss) | 44.0 | (10.7) |
G. Issue costs
Classification change
Under CGAAP, debt financing costs, premiums and discounts were netted against long-term debt. Under USGAAP, debt financing costs are included in “Other” as part of “Other assets”.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Other current assets | $1.8 | $1.0 | ||||||
Other, included in other assets | 16.8 | 20.0 | ||||||
Short-term debt | – | 0.4 | ||||||
Long-term debt | 18.6 | 20.6 |
Measurement Change
Under CGAAP, the straight-line method of amortizing debt financing costs, premiums and discounts was used to approximate the effective interest method. Under USGAAP, the straight-line method is not appropriate so the effective interest method has been adopted.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Other, included in other assets | $1.1 | $1.1 | ||||||
Long-term debt | 2.2 | 2.2 | ||||||
Retained earnings | (1.1) | (1.1) |
100
H. Current other assets and liabilities (classification change)
Under CGAAP, the Company was disclosing its other assets and liabilities on the balance sheet as long-term. Under USGAAP, the Company has included the current portion of these balances in “Other current assets” and “Other current liabilities”.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Other current assets | $1.5 | $2.1 | ||||||
Other, included in other assets | (1.5) | (2.1) | ||||||
Other current liabilities | 2.8 | 3.9 | ||||||
Other long-term liabilities | (2.8) | (3.9) |
I. Construction work-in-progress (classification change)
Under CGAAP, the Company was disclosing its construction work-in-progress (“CWIP”) as a separate line item on the balance sheet. Under USGAAP, the Company has included this balance in “Property, plant and equipment” and will disclose its CWIP balance annually in the notes to the December 31 financial statements.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Property, plant and equipment | $220.2 | $333.0 | ||||||
Construction work-in-progress | (220.2) | (333.0) |
J. Business combinations (measurement change)
Acquisition-related transaction costs
Under CGAAP, acquisition-related transaction costs were capitalized and included in the allocation of the purchase price to the acquired assets and liabilities. Under USGAAP, acquisition-related transaction costs are expensed in the period incurred, beginning with transactions completed on or after January 1, 2009.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Property, plant and equipment | $(0.2) | $(0.2) | ||||||
Other, included in other assets | – | (0.5) | ||||||
Goodwill | – | (10.7) | ||||||
Accumulated other comprehensive income (loss) | – | 0.1 | ||||||
Retained earnings | (0.2) | (11.5) |
For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended September 30 2010 | Year ended December 31 2010 | ||||||||||||
Operating, maintenance and general | – | – | – | $11.3 |
101
Business combinations achieved in stages
Under CGAAP, for business combinations achieved in stages, the acquirer does not re-measure its previously held equity interest in an acquired company. Under USGAAP, the acquirer re-measures the previously held equity interest at the acquisition-date fair value and recognizes the resulting gain or loss, if any, in income.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Property, plant and equipment | $0.4 | – | ||||||
Regulatory assets | (0.4) | – | ||||||
Goodwill | – | $(2.4) | ||||||
Retained earnings | – | (2.4) |
For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended 2010 | Year ended December 31 2010 | ||||||||||||
Other income (expenses), net | – | – | – | $(2.4) |
Negative goodwill
Under CGAAP, where the net assets in a business combination exceed the purchase price, sometimes referred to as “negative goodwill”, the excess should be eliminated, to the extent possible, by allocating the negative goodwill as a pro rata reduction of the amounts that otherwise would be assigned to certain of the acquired assets. Under USGAAP, the negative goodwill gives rise to an extraordinary gain which is recognized in income.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Investments subject to significant influence | – | $21.5 | ||||||
Accumulated other comprehensive income (loss) | – | (0.6) | ||||||
Retained earnings | – | 22.1 |
For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended September 30 2010 | Year ended December 31 2010 | ||||||||||||
Other income (expenses), net | – | $22.5 | $22.3 | $22.1 |
K. Pension and other post-retirement benefits (measurement change)
Under CGAAP, the Company disclosed, but did not recognize, its unamortized gains and losses, its past service costs, and its unamortized transitional obligation associated with pension and other post-retirement benefits. Under USGAAP, the Company has recognized its unfunded pension obligation as a liability; the unamortized gains and losses and past service costs are recognized in AOCL; and the unamortized transitional obligation previously determined under CGAAP is recognized in “Retained earnings”.
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As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Other assets | ||||||||
Regulatory assets | $9.2 | $11.6 | ||||||
Other | (94.3) | (113.5) | ||||||
Goodwill | – | 1.5 | ||||||
Current liabilities | ||||||||
Pension and post-retirement liabilities | 9.2 | 8.9 | ||||||
Long-term liabilities | ||||||||
Deferred income taxes | (14.3) | (14.7) | ||||||
Pension and post-retirement liabilities | 292.4 | 400.0 | ||||||
Other long-term liabilities | (88.0) | (102.4) | ||||||
Equity | ||||||||
Accumulated other comprehensive income (loss) | (277.6) | (387.9) | ||||||
Retained earnings | (6.8) | (4.3) |
For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended September 30 2010 | Year ended December 31 2010 | ||||||||||||
Operating, maintenance and general | $(0.6) | $(1.1) | $(1.7) | $(2.3) |
L. Intangibles (classification change)
Under CGAAP, the Company was disclosing its intangibles as a separate line item on the balance sheet. Under USGAAP, the Company has included this balance in “Other” as part of “Other assets”.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Other, included in other assets | $92.1 | $98.2 | ||||||
Intangibles | (92.1) | (98.2) |
M. Investments (measurement change)
Under CGAAP, certain investments of the Company were classified as an available-for-sale investment and measured at cost as the investments are not actively traded in an open market. Under USGAAP, investments measured at cost because they do not trade in an active market are not included in “Available-for-sale investment” therefore the Company has included these investments in “Other assets”.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Other, included in other assets | $46.3 | 46.2 | ||||||
Available-for-sale investment | (46.3) | (46.2) |
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N. Accounts payable (classification change)
Under CGAAP, trade and non-trade payables were recognized in accounts payable and accrued charges. Under USGAAP, trade payables are recognized in “Accounts payable” and non-trade payables are recognized in “Other current liabilities”.
As at January 1 and December 31, 2010, the effect the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Accounts payable | $220.4 | $296.5 | ||||||
Accounts payable and accrued charges | (305.9) | (399.6) | ||||||
Other current liabilities | 85.5 | 103.1 |
O. Dividends payable (classification change)
Under CGAAP, the Company was disclosing dividends payable as a separate line item on the balance sheet. Under USGAAP, the Company has included this balance in “Other current liabilities”.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Dividends payable | $(1.7) | $(1.8) | ||||||
Other current liabilities | 1.7 | 1.8 |
P. Preferred stock of Nova Scotia Power Inc. (measurement change)
Under CGAAP, NSPI’s preferred stock was classified as a liability; preferred stock dividends were classified as an expense in the income statement and were accrued monthly; and issuance costs were deferred on the balance sheet as a deferred financing charge and amortized to income over the life of the preferred stock.
Under USGAAP, NSPI’s preferred stock is classified as equity in “Non-controlling interest” as the preferred stock does not meet the USGAAP definition of a liability; preferred stock dividends are deducted from retained earnings and are accrued as declared; and issuance costs are netted against the preferred stock on the balance sheet and are not amortized.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Other current liabilities | $0.3 | $0.3 | ||||||
Long-term debt | 0.7 | 0.6 | ||||||
Preferred shares issued by a subsidiary | (135.0) | (135.0) | ||||||
Retained earnings | 1.8 | 1.9 | ||||||
Non-controlling interest in subsidiaries | 132.2 | 132.2 |
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For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended 2010 | Year ended December 31 2010 | ||||||||||||
Financing charges | $(2.0) | $(4.0) | $(6.0) | $(8.0) | ||||||||||||
Interest expense, net | – | (0.1) | (0.1) | (0.1) | ||||||||||||
Non-controlling interest in subsidiaries | 2.0 | 4.0 | 6.0 | 8.0 |
For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the effect on the Statements of Cash Flows is as follows:
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended 2010 | Year ended 2010 | ||||||||||||
Net cash provided by operating activities | $2.0 | $4.0 | $6.0 | $8.0 | ||||||||||||
Net cash used in financing activities | (2.0) | (4.0) | (6.0) | (8.0) |
Q. Non-controlling interest in subsidiaries (classification change)
Under CGAAP, non-controlling interest in subsidiaries (“NCI”) is classified outside shareholders’ equity, after liabilities. Under USGAAP, NCI is included in total equity.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Non-controlling interest | $(32.1) | $(20.7) | ||||||
Accumulated other comprehensive income (loss) | – | (1.5) | ||||||
Non-controlling interest in subsidiaries | 32.1 | 22.2 |
R. Share-based compensation (measurement change)
Employee Common Share Purchase Plan
Under CGAAP, the Company was recognizing the amount of its contribution in excess of 5 percent of the average market price of the shares. Under USGAAP, the Company’s employee common share purchase plan is considered compensatory and the Company’s contribution to the plan should be recognized.
Senior Management Stock Option Plan
Under CGAAP, the Company was amortizing the compensation cost associated with its stock option over two years, the average vesting period of the four awards. Under USGAAP, the Company has chosen to amortize the compensation cost over four years, the vesting period of the entire award.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Common stock | $1.2 | $1.3 | ||||||
Contributed surplus | (0.6) | (0.5) | ||||||
Retained earnings | (0.6) | (0.8) |
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For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is as reflected in the following increases (decreases):
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended 2010 | Year ended 2010 | ||||||||||||
Operating, maintenance and general | $0.1 | $0.1 | $0.2 | $0.2 |
For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the effect on the Statements of Cash Flows results is as follows:
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended 2010 | Year ended 2010 | ||||||||||||
Net cash used in operating activities | $(0.1) | $(0.1) | $(0.2) | $(0.2) | ||||||||||||
Net cash provided by financing activities | 0.1 | 0.1 | 0.2 | 0.2 |
S. Foreign currency translation (measurement change)
Under CGAAP, the Company’s Canadian division of Emera Energy Services had a Canadian functional currency. Monetary assets and liabilities denominated in a foreign currency were converted to Canadian dollars at rates of exchange prevailing at the balance sheet date. The effect of periodic changes in exchange rates were charged to income.
Under USGAAP, the Company has determined that Emera Energy Services has a US functional currency. Asset and liabilities are translated using the exchange rates in effect at the balance sheet date and the results of operations at the average rates for the periods. The resulting exchange gains (losses) on the assets and liabilities are deferred and included in accumulated other comprehensive income.
As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):
As at millions of Canadian dollars | January 1 2010 | December 31 2010 | ||||||
Accumulated other comprehensive income | $1.2 | $1.6 | ||||||
Retained earnings | (1.2) | (1.6) |
For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended September 30 2010 | Year ended December 31 2010 | ||||||||||||
Other income (expenses), net | $(0.4) | $(0.4) | $(0.1) | $(0.3) |
T. Revenue (classification change)
Under CGAAP, revenue was recognized in electric revenue, finance income from direct finance lease and other revenue. Under USGAAP, revenue is recognized in regulated operating revenues, non-regulated operating revenue income and other income (expense), net.
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For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended September 20 2010 | Year ended December 31 2010 | ||||||||||||
Electric revenue | $(412.1) | $(739.7) | $(1,074.0) | $(1,436.1) | ||||||||||||
Finance income from direct finance lease | (14.2) | (29.0) | (42.8) | (56.5) | ||||||||||||
Other revenue | (3.8) | (18.8) | (44.2) | (61.1) | ||||||||||||
Regulated operating revenues | 391.2 | 712.8 | 1,040.1 | 1,391.9 | ||||||||||||
Non-regulated operating revenues | 38.6 | 74.2 | 119.9 | 159.9 | ||||||||||||
Other income (expense), net | 0.3 | 0.5 | 1.0 | 1.9 |
U. Netting of certain revenues and expenses (measurement change)
Under CGAAP, the Company was netting certain revenues and expenses in its statements of income. Under USGAAP, revenues are classified on a gross or net basis depending on whether the Company is acting as the principal or an agent in the transaction. The adoption of USGAAP has resulted in certain revenue transactions disclosed on a net basis under CGAAP to be presented on a gross basis under USGAAP.
For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended 2010 | Year ended 2010 | ||||||||||||
Regulated operating revenues | $6.2 | $12.5 | $19.8 | $27.2 | ||||||||||||
Non-regulated operating revenues | 8.1 | 23.5 | 46.4 | 62.6 | ||||||||||||
Regulated fuel for generation and purchased power | 3.9 | 7.6 | 12.5 | 17.0 | ||||||||||||
Non-regulated direct costs | 8.2 | 23.5 | 46.1 | 62.3 | ||||||||||||
Operating, maintenance and general | 2.2 | 4.9 | 7.6 | 10.5 | ||||||||||||
Other income (expenses), net | 0.1 | 0.2 | 0.2 | 0.3 | ||||||||||||
Interest expense, net | 0.1 | 0.2 | 0.2 | 0.3 |
V. Fuel for generation and purchased power (classification change)
Under CGAAP, all fuel for generation and purchased power was recognized as such. Under USGAAP, regulated and non-regulated fuel for generation and purchased power are recognized separately.
For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended 2010 | Year ended 2010 | ||||||||||||
Regulated fuel for generation and purchased power | $(27.7) | $(52.9) | $(77.5) | $(101.1) | ||||||||||||
Non-regulated fuel for generation and purchased power | 27.7 | 52.9 | 77.5 | 101.1 |
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W. Interest expense (classification change)
Under CGAAP, interest expense, amortization of defeasance costs, and foreign exchange gains and losses were included in financing charges. Under USGAAP, interest expense is disclosed in a separate line item and amortization of defeasance costs and foreign exchange gains and losses are included in “Other income (expense), net”.
For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended 2010 | Year ended 2010 | ||||||||||||
Operating, maintenance and general | – | $0.1 | $0.1 | $0.2 | ||||||||||||
Other income (expenses), net | $(5.6) | (9.9) | (16.6) | (26.0) | ||||||||||||
Financing charges | (45.8) | (90.0) | (136.8) | (186.5) | ||||||||||||
Interest expense, net | 40.2 | 80.0 | 120.1 | 160.3 |
X. Regulatory amortization (classification change)
Under CGAAP, regulatory amortization was disclosed as a separate line item. Under USGAAP, regulatory amortization is included in “Depreciation and amortization”.
For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):
For the millions of Canadian dollars | 3 months ended March 31 2010 | 6 months ended 2010 | 9 months ended 2010 | Year ended 2010 | ||||||||||||
Depreciation and amortization | $5.4 | $10.9 | $16.7 | $41.3 | ||||||||||||
Regulatory amortization | (5.4) | (10.9) | (16.7) | (41.3) |
Y. Allowance for funds used during construction (classification change)
Under CGAAP, AFUDC was included in financing charges. Under USGAAP, allowance for equity funds used during construction is included in “Other income (expenses), net” and allowance for borrowed funds used during construction is netted against “Interest expense, net”.
For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended 2010 | Year ended 2010 | ||||||||||||
Other income (expenses), net | $2.6 | $5.7 | $10.6 | $15.6 | ||||||||||||
Financing charges | 4.6 | 9.7 | 18.2 | 26.0 | ||||||||||||
Interest expense, net | (2.0) | (4.0) | (7.6) | (10.4) |
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For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the effect on the Statements of Cash Flows is as follows:
For the millions of Canadian dollars | 3 months ended 2010 | 6 months ended 2010 | 9 months ended 2010 | Year ended December 31 2010 | ||||||||||||
Net cash provided by operating activities | $2.0 | $4.0 | $7.6 | $10.4 | ||||||||||||
Net cash provided by investing activities | (2.0) | (4.0) | (7.6) | (10.4) |
Section II. Additional disclosures required under USGAAP
The following represents select disclosures required for annual financial statements prepared in accordance with USGAAP that are not otherwise found in these interim financial statements or in the Company’s December 31, 2010 consolidated financial statements prepared in accordance with CGAAP.
Pension and other post-retirement benefits
The change in projected benefit obligation, plan assets, and funded status for all plans for the year ended December 31, 2010 was as follows:
millions of Canadian dollars | Defined benefit pension plans | Non-pension benefits plans | ||||||
Reconciliation of projected benefit obligation | ||||||||
Balance, January 1, 2010 | $898.1 | $83.4 | ||||||
Service cost | 11.3 | 2.4 | ||||||
Plan participant contributions | 5.7 | 0.2 | ||||||
Interest cost | 56.6 | 4.7 | ||||||
Plan amendments | (1.0) | – | ||||||
Benefits paid | (44.5) | (6.2) | ||||||
Actuarial losses | 128.0 | 6.2 | ||||||
Foreign currency translation adjustment | (5.9) | (2.5) | ||||||
Balance, December 31, 2010 | $1,048.3 | $88.2 | ||||||
Reconciliation of plan assets | ||||||||
Balance, January 1, 2010 | $663.3 | $3.3 | ||||||
Employer contributions | 39.9 | 5.8 | ||||||
Plan participant contributions | 5.7 | 0.2 | ||||||
Benefits paid | (44.5) | (6.2) | ||||||
Actual return on assets, net of expenses | 63.6 | 0.3 | ||||||
Foreign currency translation adjustment | (3.8) | – | ||||||
Balance, December 31, 2010 | $724.2 | $3.4 | ||||||
Funded status, December 31, 2010 | $(324.1) | $(84.8) |
Amounts reflected in the above table that have not yet been recognized in Emera’s net periodic benefit cost, and are included in “Accumulated other comprehensive loss”, as of December 31, 2010 were as follows:
millions of Canadian dollars | Defined benefit pension plans | Non-pension benefits plans | ||||||
Actuarial losses | $402.3 | $21.9 | ||||||
Past service gains | 0.4 | 12.8 | ||||||
Total AOCL, pre-tax | 401.9 | 9.1 | ||||||
Less: amount included in deferred income tax asset | 13.1 | 2.4 | ||||||
Amount in AOCL, after-tax | $388.8 | $6.7 |
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Amounts from the above tables recognized in the Balance Sheet as at December 31, 2010 were as follows:
millions of Canadian dollars | Defined benefit pension plans | Non-pension benefits plans | ||||||
Current liability | $(3.9) | $(5.0) | ||||||
Long-term liability | (320.2) | (79.8) | ||||||
Amount included in deferred income tax asset | 13.1 | 2.4 | ||||||
Amount included in AOCL, after-tax | 388.8 | 6.7 | ||||||
Net asset (liability) recognized | $77.8 | $(75.7) |
The Accumulated Benefit Obligation (“ABO”) for the defined benefit pension plans was $992.1 million as at December 31, 2010. The aggregate financial position for all plans with an ABO in excess of plan assets, as at December 31, 2010, is as follows:
millions of Canadian dollars | Defined benefit pension plans | |||
Accumulated benefit obligation | $980.5 | |||
Fair value of plan assets | 718.3 | |||
Funded status | $(262.2) |
Income taxes
The deferred income tax assets and liabilities as at December 31, 2010 consisted of the following:
millions of Canadian dollars | Current | Long-term | ||||||
Deferred income tax assets: | ||||||||
Property, plant and equipment | – | $(182.3) | ||||||
Regulatory assets (deferral of FAM) | – | (20.4) | ||||||
Regulatory assets (unamortized defeasance costs) | – | (17.8) | ||||||
Intangibles | – | 23.9 | ||||||
Asset retirement obligations | – | 62.4 | ||||||
Pension and post-retirement liabilities | – | 143.2 | ||||||
Derivatives | $2.3 | (1.8) | ||||||
Tax loss carry forwards | 7.6 | 26.0 | ||||||
Other | 4.5 | 10.7 | ||||||
Total deferred income tax assets before valuation allowance | 14.4 | 43.9 | ||||||
Valuation allowance | (0.7) | (12.8) | ||||||
Total deferred income tax assets after valuation allowance | $13.7 | $31.1 |
millions of Canadian dollars | Current | Long-term | ||||||
Deferred income tax liabilities: | ||||||||
Property, plant and equipment | – | $171.6 | ||||||
Regulatory assets (deferral of FAM) | $8.9 | – | ||||||
Regulatory assets (unamortized defeasance costs) | 1.4 | – | ||||||
Net investment in direct finance lease | – | 32.9 | ||||||
Intangibles | – | (3.4) | ||||||
Asset retirement obligations | – | (0.8) | ||||||
Derivatives | 3.9 | (0.2) | ||||||
Pension and post-retirement liabilities | (4.0) | (25.9) | ||||||
Tax loss carry forwards | – | (21.3) | ||||||
Other | (2.3) | 15.2 | ||||||
Total deferred income tax liabilities before valuation allowance | 7.9 | 168.1 | ||||||
Valuation allowance | 0.6 | 0.4 | ||||||
Total deferred income tax liabilities after valuation allowance | $8.5 | $168.5 |
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The total amount of unrecognized tax benefits as at December 31, 2010 was $11.9 million of which $11.1 million would favourably affect the effective tax rate, if recognized. Interest of $1.3 million has been accrued related to unrecognized tax benefits as at December 31, 2010. No penalties have been accrued. During the next twelve months, it is reasonably possible that $3.4 million of unrecognized tax benefits may be recognized due to statute expirations or settlement agreements with taxing authorities.
As at December 31, 2010, the Company’s tax years still open to examination by taxing authorities include 2006 and subsequent years. With few exceptions, the Company is no longer subject to examination for years prior to 2006. The major exception is for transactions involving non-arm’s length non-residents, which are open to examination by taxing authorities for 2003 and subsequent years.
The Company intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, US and non-US income and withholding taxes for which deferred taxes might otherwise be required have not been provided for on a cumulative amount of temporary differences related to investments in foreign subsidiaries of approximately $190.6 million as of December 31, 2010. It is impractical to estimate the amount of income and withholding tax that might be payable if a reversal of temporary differences occurred.
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