Exhibit 99.2
EMERA INC.
Unaudited Condensed Consolidated
Financial Statements
March 31, 2011 and 2010
Emera Inc.
Consolidated Statements of Income (Unaudited)
For the | Three months ended March 31 | |||||||
millions of Canadian dollars (except per share amounts) | 2011 | 2010 (as adjusted – note 22) | ||||||
Operating revenues | ||||||||
Regulated | $ | 507.5 | $ | 395.4 | ||||
Non-regulated | 47.1 | 43.1 | ||||||
Total operating revenues | 554.6 | 438.5 | ||||||
Operating expenses | ||||||||
Regulated fuel for generation and purchased power | 228.1 | 194.0 | ||||||
Regulated fuel adjustment (note 4) | (5.8 | ) | (39.4 | ) | ||||
Non-regulated fuel for generation and purchased power | 20.7 | 23.1 | ||||||
Non-regulated direct costs | 13.8 | 8.2 | ||||||
Operating, maintenance and general | 112.0 | 77.5 | ||||||
Provincial, state, and municipal taxes | 12.3 | 12.0 | ||||||
Depreciation and amortization | 55.9 | 47.3 | ||||||
Total operating expenses | 437.0 | 322.7 | ||||||
Income from operations | 117.6 | 115.8 | ||||||
Income from equity investments | 7.5 | 0.7 | ||||||
Other income (expenses), net (note 5) | 41.6 | (1.8 | ) | |||||
Interest expense, net (note 6) | 40.9 | 37.6 | ||||||
Income before provision for income taxes | 125.8 | 77.1 | ||||||
Income tax expense (recovery) (note 7) | (1.7 | ) | (2.5 | ) | ||||
Net income from operations | 127.5 | 79.6 | ||||||
Non-controlling interest in subsidiaries | 2.2 | 1.8 | ||||||
Net income of Emera Inc. | 125.3 | 77.8 | ||||||
Preferred stock dividends | 1.7 | — | ||||||
Net income attributable to common shareholders | $ | 123.6 | $ | 77.8 | ||||
Weighted average shares of common stock outstanding (in millions) | ||||||||
Basic | 116.4 | 113.6 | ||||||
Diluted | 121.8 | 120.0 | ||||||
Earnings per common share | ||||||||
Basic | $ | 1.06 | $ | 0.68 | ||||
Diluted | $ | 1.03 | $ | 0.67 | ||||
Dividends per common share declared | $ | 0.3250 | $ | 0.2725 | ||||
The accompanying notes are an integral part of these condensed financial statements.
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Emera Inc.
Consolidated Balance Sheets (Unaudited)
As at millions of Canadian dollars | March 31 2011 | December 31 2010 (as adjusted – note 22) | ||||||
Assets | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 80.1 | $ | 7.3 | ||||
Restricted cash | 15.8 | 58.6 | ||||||
Receivables, net (note 8) | 446.6 | 392.9 | ||||||
Income taxes receivable | 53.1 | 44.3 | ||||||
Inventory (note 9) | 168.9 | 177.8 | ||||||
Deferred income taxes | 13.0 | 13.7 | ||||||
Derivative instruments (note 19) | 44.5 | 49.7 | ||||||
Regulatory assets | 94.9 | 90.5 | ||||||
Prepaid expenses | 30.5 | 9.5 | ||||||
Other current assets | 4.2 | 3.1 | ||||||
Total current assets | 951.6 | 847.4 | ||||||
Property, plant and equipment,net of accumulated depreciation of $2,732.1 and $2,462.6, respectively | 4,031.5 | 3,742.6 | ||||||
Other assets | ||||||||
Deferred income taxes | 16.7 | 31.1 | ||||||
Derivative instruments (note 19) | 38.0 | 36.0 | ||||||
Regulatory assets | 366.0 | 354.9 | ||||||
Net investment in direct financing lease | 491.3 | 491.5 | ||||||
Investments subject to significant influence (note 12) | 215.9 | 246.0 | ||||||
Available-for-sale investment (note 13) | 49.1 | 0.8 | ||||||
Goodwill | 162.1 | 165.9 | ||||||
Other | 201.5 | 171.8 | ||||||
Total other assets | 1,540.6 | 1,498.0 | ||||||
Total assets | $ | 6,523.7 | $ | 6,088.0 | ||||
The accompanying notes are an integral part of these condensed financial statements.
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Emera Inc.
Consolidated Balance Sheets (Unaudited) – Continued
As at millions of Canadian dollars | March 31 2011 | December 31 2010 (as adjusted – note 22 ) | ||||||
Liabilities and Equity | ||||||||
Current liabilities | ||||||||
Short-term debt | $ | 367.7 | $ | 228.5 | ||||
Current portion of long-term debt | 13.3 | 10.6 | ||||||
Accounts payable | 286.4 | 293.9 | ||||||
Income taxes payable | 5.8 | 7.5 | ||||||
Deferred income taxes | 10.3 | 8.5 | ||||||
Derivative instruments (note 19) | 27.1 | 36.8 | ||||||
Regulatory liabilities | 53.8 | 55.0 | ||||||
Pension and post-retirement liabilities | 9.2 | 8.9 | ||||||
Other current liabilities (note 10) | 122.9 | 110.3 | ||||||
Total current liabilities | 896.5 | 760.0 | ||||||
Long-term liabilities | ||||||||
Long-term debt | 2,855.4 | 2,971.7 | ||||||
Deferred income taxes | 212.3 | 168.5 | ||||||
Derivative instruments (note 19) | 35.0 | 28.9 | ||||||
Regulatory liabilities | 93.2 | 65.2 | ||||||
Asset retirement obligations | 145.6 | 141.8 | ||||||
Pension and post-retirement liabilities | 393.2 | 400.0 | ||||||
Other long-term liabilities | 23.0 | 22.0 | ||||||
Total long-term liabilities | 3,757.7 | 3,798.1 | ||||||
Commitments and contingencies (note 16) | ||||||||
Equity | ||||||||
Common stock, no par value, unlimited authorized shares, 121.31 million and 2010 – 114.62 million shares issued and outstanding (note 17) | 1,343.6 | 1,137.8 | ||||||
Preferred stock, unlimited authorized number of 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 | 3.4 | 3.2 | ||||||
Accumulated other comprehensive loss | (578.0 | ) | (565.7 | ) | ||||
Retained earnings | 739.7 | 653.5 | ||||||
Total Emera Inc. equity | 1,655.4 | 1,375.5 | ||||||
Non-controlling interest in subsidiaries | 214.1 | 154.4 | ||||||
Total equity | 1,869.5 | 1,529.9 | ||||||
Total liabilities and equity | $ | 6,523.7 | $ | 6,088.0 | ||||
Approved on behalf of the Board of Directors
Chairman | President and Chief Executive Officer |
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Emera Inc. Consolidated Statements of Cash Flows (Unaudited)
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2011 | 2010 (as adjusted – note 22 ) | ||||||
Operating activities | ||||||||
Net income from operations of Emera Inc. | $ | 127.5 | $ | 79.6 | ||||
Adjustments to reconcile net income to net cash provided by operating activities | ||||||||
Depreciation and amortization | 55.9 | 47.3 | ||||||
Income from equity investments, net of dividends | (3.2 | ) | 6.5 | |||||
Allowance for equity funds used during construction | (2.4 | ) | (2.3 | ) | ||||
Deferred income taxes | 7.3 | 11.3 | ||||||
Net change in pension and post-retirement, benefits (obligations) | 0.7 | (1.8 | ) | |||||
Regulated fuel adjustment | (7.8 | ) | (39.7 | ) | ||||
Net changes in fair value of derivative instruments | (2.6 | ) | 2.6 | |||||
Net change in regulatory assets and liabilities | (2.9 | ) | (10.7 | ) | ||||
Other operating activities | (35.5 | ) | 12.2 | |||||
Changes in non-cash working capital | ||||||||
Receivables, net | (33.4 | ) | (41.9 | ) | ||||
Income taxes receivable | (8.8 | ) | (11.2 | ) | ||||
Inventory | 24.3 | 32.3 | ||||||
Prepaid expenses | (19.3 | ) | (20.5 | ) | ||||
Other current assets | (0.7 | ) | 1.5 | |||||
Accounts payable | (37.7 | ) | (60.5 | ) | ||||
Income taxes payable | (1.6 | ) | (2.1 | ) | ||||
Other current liabilities | 9.5 | (5.2 | ) | |||||
Net cash provided by (used in) operating activities | 69.3 | (2.6 | ) | |||||
Investing activities | ||||||||
Additions to property, plant and equipment | (66.0 | ) | (60.5 | ) | ||||
Acquisition, net of cash acquired | (35.1 | ) | — | |||||
Decrease in restricted cash | 54.1 | — | ||||||
Purchase of investments subject to significant influence (note 12) | (31.5 | ) | — | |||||
Allowance for borrowed funds used during construction | (2.3 | ) | (2.0 | ) | ||||
Retirement spending net of salvage | (2.7 | ) | (1.5 | ) | ||||
Transaction costs related mergers and acquisitions | (2.0 | ) | — | |||||
Other investing activities | (57.1 | ) | (4.3 | ) | ||||
Net cash used in investing activities | (142.6 | ) | (68.3 | ) | ||||
Financing activities | ||||||||
Short-term debt, net | (15.9 | ) | 86.5 | |||||
Retirement of long-term debt | (0.4 | ) | — | |||||
Issuance of common stock, net of issuance costs | 203.2 | 7.7 | ||||||
Dividends on common stock | (37.3 | ) | (30.8 | ) | ||||
Dividends on preferred stock | (1.7 | ) | — | |||||
Dividends paid by subsidiaries to non-controlling interest | (2.2 | ) | (2.7 | ) | ||||
Other financing activities | 0.1 | �� | (0.5 | ) | ||||
Net cash provided by financing activities | 145.8 | 60.2 | ||||||
Effect of exchange rate changes on cash and cash equivalents | 0.3 | 0.4 | ||||||
Net increase (decrease) in cash and cash equivalents | 72.8 | (10.3 | ) | |||||
Cash and cash equivalents, beginning of period | 7.3 | 20.2 | ||||||
Cash and cash equivalents, end of period | $ | 80.1 | $ | 9.9 | ||||
Cash and cash equivalents consists of: | ||||||||
Cash | $ | 46.3 | $ | 9.6 | ||||
Short-term investments | 33.8 | 0.3 | ||||||
Cash and cash equivalents | $ | 80.1 | $ | 9.9 | ||||
Supplemental disclosure of cash paid: | ||||||||
Interest | $ | 34.1 | $ | 31.0 | ||||
Income and capital taxes | $ | 3.1 | $ | 1.2 | ||||
The accompanying notes are an integral part of these condensed financial statements.
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Emera Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2011 | 2010 (as adjusted – note 21 ) | ||||||
Net income attributable to common shareholders | $ | 123.6 | $ | 77.8 | ||||
Other comprehensive income (loss), net of tax | ||||||||
Unrealized gains (losses) on cash flow hedges (net of tax of $0.7 and $(4.1)) | 3.3 | (5.3 | ) | |||||
Plus: | ||||||||
Hedging losses included in income (net of tax of $0.8 and $0.6) | 0.5 | 0.9 | ||||||
Amortization of unrecognized pension and post-retirement benefit costs (net of tax of $(0.1) and nil) | 5.2 | 3.2 | ||||||
Unrealized gain on available-for-sale investment | — | 0.1 | ||||||
Unrealized loss on translation of self-sustaining foreign operations | (21.3 | ) | (15.5 | ) | ||||
Other comprehensive loss, net of tax | (12.3 | ) | (16.6 | ) | ||||
Comprehensive income attributable to common shareholders | $ | 111.3 | $ | 61.2 | ||||
The accompanying notes are an integral part of these condensed financial statements.
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Emera Inc.
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 three months ended March 31, 2011 | ||||||||||||||||||||||||||||
Balance, December 31, 2010 (as adjusted – note 22) | $ | 1,137.8 | $ | 146.7 | $ | 3.2 | $ | (565.7 | ) | $ | 653.5 | $ | 154.4 | $ | 1,529.9 | |||||||||||||
Net income of Emera Inc. | — | — | — | — | 125.3 | 2.2 | 127.5 | |||||||||||||||||||||
Other comprehensive loss, net of tax | — | — | — | (12.3 | ) | — | — | (12.3 | ) | |||||||||||||||||||
Issuance of common stock, net of issuance costs | 196.0 | — | — | — | — | — | 196.0 | |||||||||||||||||||||
Additional investment in LPH | — | — | — | — | — | 59.7 | 59.7 | |||||||||||||||||||||
Cash dividends declared on preferred stock ($0.2750 per share) | — | — | — | — | (1.7 | ) | — | (1.7 | ) | |||||||||||||||||||
Cash dividends declared on common stock ($0.3250 per share) | — | — | — | — | (37.2 | ) | — | (37.2 | ) | |||||||||||||||||||
Dividends paid by subsidiaries to non-controlling interest | — | — | — | — | — | (0.2 | ) | (0.2 | ) | |||||||||||||||||||
Common stock issued under purchase plan | 9.0 | — | — | — | — | — | 9.0 | |||||||||||||||||||||
Senior management stock options exercised | 0.5 | — | — | — | — | — | 0.5 | |||||||||||||||||||||
Stock option expense | — | — | 0.2 | — | — | — | 0.2 | |||||||||||||||||||||
Other stock-based compensation | 0.3 | — | — | — | (0.2 | ) | — | 0.1 | ||||||||||||||||||||
Other | — | — | — | — | — | (2.0 | ) | (2.0 | ) | |||||||||||||||||||
Balance, March 31, 2011 | $ | 1,343.6 | $ | 146.7 | $ | 3.4 | $ | (578.0 | ) | $ | 739.7 | $ | 214.1 | $ | 1,869.5 | |||||||||||||
For the three months ended March 31, 2010 | ||||||||||||||||||||||||||||
Balance, December 31, 2009 (as adjusted – note 22) | $ | 1,097.9 | — | $ | 3.0 | $ | (426.2 | ) | $ | 594.8 | 164.3 | $ | 1,433.8 | |||||||||||||||
Net income of Emera Inc. | — | — | — | — | 77.8 | 1.8 | 79.6 | |||||||||||||||||||||
Other comprehensive loss, net of tax | — | — | — | (16.6 | ) | — | — | (16.6 | ) | |||||||||||||||||||
Cash dividends declared on common stock ($0.2725 per share) | — | — | — | — | (62.8 | ) | — | (62.8 | ) | |||||||||||||||||||
Dividends paid by subsidiaries to non-controlling interest | — | — | — | — | — | (0.7 | ) | (0.7 | ) | |||||||||||||||||||
Common stock issued under purchase plan | 7.4 | — | — | — | — | — | 7.4 | |||||||||||||||||||||
Senior management stock options exercised | 0.2 | — | — | — | — | — | 0.2 | |||||||||||||||||||||
Stock option expense | — | — | 0.2 | — | — | — | 0.2 | |||||||||||||||||||||
Other stock-based compensation | 0.1 | — | — | — | — | — | 0.1 | |||||||||||||||||||||
Other | — | — | — | — | — | (2.0 | ) | (2.0 | ) | |||||||||||||||||||
Balance, March 31, 2010 (as adjusted – note 22) | $ | 1,105.6 | — | $ | 3.2 | $ | (442.8 | ) | $ | 609.8 | $ | 163.4 | $ | 1,439.2 | ||||||||||||||
The accompanying notes are an integral part of these condensed financial statements.
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Emera Inc.
Notes to the Condensed Consolidated Financial Statements (Unaudited)
As at March 31, 2011
1. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
The significant accounting policies for both the regulated and non-regulated operations are as follows:
A. | Nature of Operations |
Emera Inc. is an energy and services company which invests in electricity generation, transmission and distribution as well as gas transmission and utility energy services. Emera’s primary rate-regulated subsidiaries at March 31, 2011 included the following utilities: 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”), the wholly-owned subsidiary of Maine and Maritimes Corporation (“MAM”), which together provide transmission and distribution services in Maine to approximately 154,000 customers; a 79.6 percent interest in Light and Power Holdings Ltd. (“LPH”), the parent of The Barbados Light & Power Company Limited (“BLPC”), the sole utility operator on the island of Barbados serving 120,000 customers; an 80.4 percent interest in Grand Bahama Power Company Limited (“GBPC”), a vertically-integrated electric utility on Grand Bahama Island serving 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.
Emera Inc. 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 electricity generating facility in Saint John, New Brunswick; Emera Utility Services , a utility services contractor; a 50/50 joint venture in Bear Swamp, a 600-megawatt 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 (“Lucelec”), a vertically-integrated electric utility on the Caribbean island of St. Lucia; ICD Utilities (ICDU”), a 49.999 percent interest in California Pacific Utilities Ventures, LLC, (“CPUV”), an 8.2 percent investment in Algonquin Power and Utilities Corp (“APUC”), a 26.1 percent investment in Atlantic Hydrogen Inc.(“AHI”), and other investments.
B. | Basis of Presentation |
These condensed consolidated financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”) and the rules and regulations of the United States Securities and Exchange Commission (“SEC”) for Quarterly Reports on Form 6-K. 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 Inc.’s annual consolidated financial statements as at and for the year ended December 31, 2010, which were prepared in accordance with Canadian Generally Accepted Accounting Principles (“CGAAP”), and note 22 to these condensed consolidated financial statements 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 Inc. 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.
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C. | Principles of Consolidation |
The consolidated financial statements of Emera Inc. include the accounts of Emera Inc. 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. Certain transactions between non-regulated and regulated entities have not been eliminated because management believes that the elimination of these entries 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 due primarily to seasonal factors. Electricity sales and related generation vary significantly over the year, with Q1 and Q4 typically being the strongest periods, reflecting colder weather and fewer daylight hours in the winter season.
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.
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 specific costs of the regulated products or services; and it is reasonable to assume are set at levels such that recovered 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 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.
The amortization of regulatory assets and liabilities is approved by the relevant regulator.
Emera recognizes regulatory assets or liabilities where the deferred income taxes are expected to be recovered from or returned to customers in future rates and tolls.
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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 and estimated executory costs less unearned income. The difference between the gross investment and the cost of the leased item for 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.
Any derivatives that are entered into as part of energy trading or energy marketing are recognized at fair market value.
Other revenues are recognized when services are performed or goods delivered.
I. | Sales Taxes |
Sales taxes are collected and remitted by the Company and accounted for on a net basis. Sales taxes are not reflected in the Consolidated Statements of Income.
J. | Research and Development Costs |
Research and development costs are expensed as incurred.
K. | 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.
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L. | 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 AOCI.
M. | 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.
N. | 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 $33.8 million have an effective interest rate of 3.03 percent at March 31, 2011 (2010 – nil short-term investments).
O. | Allowance for Doubtful Accounts |
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.
P. | 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.
Q. | Property, Plant and Equipment |
Property, plant and equipment are recorded at original cost, including allowance for funds used during construction (“AFUDC”), net of contributions received in aid of construction.
The cost of additions, including betterments and replacements of units of property plant and equipment are included in “Property, plant and equipment”. When units of regulated property, plant and equipment are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage proceeds, are charged to accumulated depreciation with no gain or loss reflected in operations. Where a disposition of non-regulated property, plant and equipment occurs, gains and losses are included in net 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.
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R. | Capitalization Policy |
The cost of property represents the original cost of materials, contracted services, direct labour, allowance for funds used during construction 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.
S. | Allowance for Funds Used During Construction |
AFUDC represents the cost of financing regulated construction projects with both borrowed and equity funds and is capitalized to the cost of property. As required by their respective regulator, NSPI, Bangor Hydro, MPS, GBPC and Brunswick Pipeline include an equity component in AFUDC. AFUDC is a non-cash item; cash is realized under the rate-making process over the service life of the related property through future revenues resulting from a higher rate base and 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 in “Other income (expenses), net”. AFUDC is calculated using a weighted average cost of capital as per the method of calculation approved by the regulators. AFUDC is compounded semi-annually. The average annual AFUDC rates for the years ended December 31, 2011 and 2010 were as follows:
2011 | 2010 | |||||||
NSPI | 7.87 | % | 7.96 | % | ||||
Bangor Hydro | 8.83 | % | 8.59 | % | ||||
MPS | 7.53 | % | N/A | |||||
GBPC | 7.07 | % | N/A |
T. | 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 are as follows:
Generation | 15 to 131 | |||
Transmission | 11 to 83 | |||
Distribution | 11 to 75 | |||
General plant | 5 to 53 |
U. | 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”. 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.
The estimated useful life in years for intangibles with definite lives is as follows:
Land rights | 50 to 143 | |||
Computer software | 3 to 10 |
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V. | Asset Impairment |
Goodwill and other intangible assets with indefinite lives are not amortized, but are subject to an annual impairment test. 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. 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.
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.
The carrying value of assets held for sale is 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. The carrying values of cost and equity method investments 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.
There were no material impairments for the quarters ended March 31, 2011 and March 31, 2010.
W. | 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”.
X. | 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 on the balance sheet and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. If management determines that it is more likely than not 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.
Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the more likely than not recognition threshold is satisfied and is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement.
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 tax laws and regulatory practices.
Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively.
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Y. | 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. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives, and governmental regulatory requirements. When the liability is initially recorded, 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.
Some of the 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.
Z. | Derivatives and Hedging Activities |
Emera enters into futures, forwards, swaps and option contracts as part of its risk management strategy to limit exposure to:
• | commodity price fluctuations related to the purchase and sales 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 uses derivatives to reduce normal operating and market risks. The Company’s primary objective in using derivatives is to reduce the impact of market price volatility. The risk management policies adopted by the Company provide a framework through which management monitors various risk exposures. The risk management plan has been approved 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 enters into derivatives when it intends to economically hedge cash flow risks. The Company formally documents the relationship, its risk management objective and strategy for undertaking the hedge, the hedging instrument and hedged transaction, and nature of the risk being hedged.
All derivatives are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and normal sales (“NPNS”) exception. The Company’s physical contracts generally qualify 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 of the commodity, the Company intends to receive physical delivery, and the Company deems the counterparty creditworthy. Emera continually assesses physical contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption if the required criteria are no longer met.
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The Company enters into derivatives that are designated as cash flow hedges. Derivatives qualify for hedge accounting if the derivatives meet the 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. To the extent that cash flow hedges are effective, the unrealized gains and losses on the derivatives are recognized in AOCL, net of taxes. Amounts related to these cash flow hedges will be recognized in income when the hedged transactions are recognized in income, or if it probable that the hedged transaction will not occur. Any ineffective portion of the unrealized gains and losses related to derivatives that do not qualify for hedge accounting is recognized in income.
Derivatives entered into by NSPI that are documented as economic hedges, and for which the NPNS exception has not been taken may 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 unrealized gains and losses associated with these derivatives are deferred to a regulatory asset or liability. The gain or loss on these derivatives is recognized when the derivatives are settled. Management believes that any gains or losses resulting from settlement of these derivatives will be refunded or collected from customers in future rates.
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.
AA. | Fair Value Measurement |
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value measurement is required to reflect the assumptions that market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model. A fair value hierarchy exists that prioritizes the inputs used to measure fair value. The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exception (see notes 19 and 20).
The three levels of the fair value hierarchy are defined as follows:
The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurement) and the lowest priority to unobservable inputs (“Level 3” measurement).
Where possible the Company bases the fair valuation of its financial assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified as “Level 1”.
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 in active markets with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses. These valuations are classified as “Level 2”.
Finally, certain derivatives are classified as “Level 3” due to the use of unobservable or internally developed inputs. The primary reasons for a Level 3 classification are as follows:
• | While price curves may have been based on observable information, significant assumptions may have been made regarding seasonal or monthly shaping and locational basis differentials. |
• | Certain transactions were valued using pricing curves that extended beyond the quoted period. 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 external inputs were utilized in the valuations. |
Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
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BB. | Variable Interest Entities |
The Company performs an analysis on an on-going basis to assess whether the Company holds any variable interest entities (“VIEs”) that are required to be consolidated because the Company is determined to be the primary beneficiary. The analysis identifies the primary beneficiary of a VIE as the enterprise that has both of the following characteristics: the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and the obligation to absorb losses of the entity that could potentially be significant to the VIE. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly owned facilities. 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.
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 limited guarantee with no set term for the indebtedness of RESL under a loan agreement between RESL and a third party lender for a credit facility of $23.5 million. NSPI holds a security interest in all present and future assets of RESL. This 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 project agreement between RESL and NSPI. A default by RESL, under its loan agreement, would require NSPI to make payment under the guarantee. Under a purchased power agreement, NSPI purchases, at a fixed price, 100 percent of the power generated by the project. As at March 31, 2011, RESL indebtedness under the loan agreement was $22.8 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. In 1990, the Bangor Hydro formed Bangor Var Co. (“BVC”), whose sole function is to be a 50 percent general partner in Chester SVC, a partnership which owns a SVC, which is electrical equipment that supports a major transmission line. A wholly-owned subsidiary of Central Maine Power Company owns the other 50 percent interest in Chester SVC. Chester SVC financed the acquisition and construction of the SVC through the issuance of $33 million USD in principal amount of 10.48 percent senior notes due 2020, and up to $3.2 million USD in principal amount of additional notes due 2020 (collectively, the SVC notes). Since Chester SVC is 100 percent debt financed, BVC has no equity interest in Chester SVC. The holders of the SVC Notes are without recourse against the partners of their parent companies and may only look to Chester and to the collateral for payment. Certain New England utilities have agreed under a FERC approved contract to bear the cost of Chester, on a cost of service basis, which includes a return on and of all capital costs.
LPH has established a self-insurance fund (“SIF”) primarily for the purpose of building an insurance fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. In its determination that LPH controls the SIF, management considered that in substance, the activities of the SIF are being conducted on behalf of BLPC and that BLPC alone obtains the benefits from the SIF’s operations. Additionally, because LPH has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. As a result of controlling the SIF, the SIF must be consolidated by Emera. The SIF was established on December 31, 1998 in accordance with the Insurance Act – Insurance (Barbados Light & Power Company Limited) (Self Insurance Fund) Regulations 1998. The SIF was established for the purpose of building an insurance fund to cover risk against damage and consequential loss to certain generation, transmission and distribution systems.
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The following table provides information about Emera’s VIE as at March 31, 2011 and 2010, in which the Company has a significant variable interest and consolidates it under “Available-for-sale investment” as Emera is the primary beneficiary.
For the | Three months ended March 31 | |||||||||||||||
millions of Canadian dollars | 2011 | 2010 | ||||||||||||||
Total assets | Maximum exposure to loss | Total assets | Maximum exposure to loss | |||||||||||||
Unconsolidated VIE in which Emera has Variable Interests | ||||||||||||||||
RESL | — | $ | 23.5 | — | — | |||||||||||
Chester SVC | — | — | — | — | ||||||||||||
Consolidated VIE | ||||||||||||||||
Available-for-sale investment | $ | 49.1 | $ | 49.1 | — | — |
CC. | Available-for-sale investment |
Available-for-sale financial assets are designated in this category. They are non-derivatives 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 on the trade date, the date on which the Company commits to purchase or sell the asset. Available-for-sale assets are initially recognized at fair value which includes transaction costs and are 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 investments are recognized in AOCL until the financial investment 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.
Interest on available-for-sale securities is calculated using the effective interest method is recognized on the Consolidated Statements of Income in “Other income (expenses), net”. Dividends on available-for-sale equity instruments are recognized on the Consolidated Statements of Income in “Other income (expenses), net”.
Impairment of 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 as 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.
DD. | 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”.
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2. | CHANGE IN ACCOUNTING POLICY |
Emera tests goodwill impairment annually using a fair value approach.
In the first quarter of 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 principle 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. | 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 March 31, 2011, Emera has five reporting segments.
These segments include NSPI, Maine Utility Operations, Caribbean Utility Operations, Brunswick Pipeline and Other, which includes Emera Energy Services, Emera Utility Services and other strategic investments. 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”. Prior periods have been retrospectively restated to reflect Maine Utility Operations as a segment. Caribbean Utility Operations includes LPH, GBPC, ICDU and Lucelec. In previous years, the Company reported LPH, GBPC, ICDU and Lucelec in “Other” as they did not meet segment reporting requirements. Prior periods have been retrospectively restated to reflect Caribbean Utility Operations as a segment. “Other” also includes any holding companies, all other investments, and any inter-segment eliminations.
millions of Canadian dollars | NSPI | Maine Utility Operations | Caribbean Utility Operations | Brunswick Pipeline | Other | Total | ||||||||||||||||||
For the three months ended March 31, 2011 | ||||||||||||||||||||||||
Operating revenues from external customers | $ | 371.2 | $ | 52.5 | $ | 73.6 | $ | 12.4 | $ | 44.9 | $ | 554.6 | ||||||||||||
Inter-segment (expenses) revenues | (4.4 | ) | (0.4 | ) | (0.1 | ) | (7.6 | ) | 12.5 | — | ||||||||||||||
Net income attributable to common shareholders | 63.6 | 9.4 | 29.6 | 4.7 | 16.3 | 123.6 | ||||||||||||||||||
For the three months ended March 31, 2010 | ||||||||||||||||||||||||
Operating revenues from external customers | $ | 342.8 | $ | 40.5 | — | $ | 12.2 | $ | 43.0 | $ | 438.5 | |||||||||||||
Inter-segment (expenses) revenues | (3.7 | ) | (0.4 | ) | — | (7.6 | ) | 11.7 | — | |||||||||||||||
Net income attributable to common shareholders | 65.2 | 5.6 | $ | 0.2 | 6.1 | 0.7 | 77.8 |
4. | REGULATED FUEL ADJUSTMENT |
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. The difference between actual fuel costs and amounts recovered from customers in the current period is included in “Regulated fuel adjustment”. 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 fuel adjustment also includes the recovery from (rebate to) customers of under (over) recovered costs from prior years.
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The regulated fuel adjustment consisted of the following:
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2011 | 2010 | ||||||
Under recovery of current year fuel costs | $ | (14.0 | ) | $ | (33.0 | ) | ||
Recovery from (rebate to) customers from prior years | 8.2 | (6.4 | ) | |||||
Regulated fuel adjustment | $ | (5.8 | ) | $ | (39.4 | ) | ||
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 or liability includes amounts recognized as a fuel adjustment and associated interest that is included in “Interest expense, net”. As at March 31, 2011, NSPI’s current FAM regulatory asset was $36.4 million and long-term FAM regulatory asset was $64.3 million (December 31, 2010 – current FAM regulatory asset of $27.2 million and long-term FAM regulatory asset of $65.7 million), and current deferred income tax liability was $11.6 million and long-term deferred income tax liability was $19.9 million (December 31, 2010 – current deferred income tax liability of $8.8 million and long-term deferred income tax liability of $20.4 million).
5. | OTHER INCOME (EXPENSES), NET |
Other income (expenses), net consisted of the following:
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2011 | 2010 | ||||||
Gain on business acquisition (note 14) | $ | 28.0 | — | |||||
Gain on exchange of subscription receipts to common shares of APUC (1) | 15.1 | — | ||||||
Allowance for equity funds used during construction | 2.4 | $ | 2.3 | |||||
Amortization of defeasance costs | (3.0 | ) | (3.0 | ) | ||||
Foreign exchange loss | (0.4 | ) | — | |||||
Foreign exchange loss recovered through the FAM | (1.3 | ) | (2.8 | ) | ||||
Other | 0.8 | 1.7 | ||||||
$ | 41.6 | $ | (1.8 | ) | ||||
(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). |
6. | INTEREST EXPENSE, NET |
Interest expense, net consisted of the following:
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2011 | 2010 | ||||||
Interest on long-term debt | $ | 39.7 | $ | 34.3 | ||||
Interest on short-term debt | 4.0 | 2.2 | ||||||
Other | 1.6 | 3.5 | ||||||
Interest revenue | (2.1 | ) | (0.4 | ) | ||||
Allowance for borrowed funds used during construction | (2.3 | ) | (2.0 | ) | ||||
$ | 40.9 | $ | 37.6 | |||||
Interest on long-term debt includes amortization of debt financing costs, premiums and discounts.
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7. | INCOME TAXES |
The Company’s effective tax rate for the three months ended March 31, 2011 and March 31, 2010 was (1.4) percent and (3.2) percent respectively. The effective tax rate for the three months ended March 31, 2011 and March 31, 2010 was lower than the statutory income tax rate of 32.5 percent and 34 percent, respectively, primarily due to deferred income taxes on regulated income deferred to regulatory assets and regulatory liabilities.
Income taxes are higher in Q1 2011 compared to Q1 2010 primarily due to increased income before provision for income taxes offset by a non-taxable gain on acquisition of LPH and the non-taxable portion of a gain on APUC subscription receipts.
8. | RECEIVABLES, NET |
Receivables, net consisted of the following:
As at millions of Canadian dollars | March 31 2011 | December 31 2010 | ||||||
Customer accounts receivable – billed | $ | 287.1 | $ | 250.8 | ||||
Customer accounts receivable – unbilled | 141.5 | 126.4 | ||||||
Total customer accounts receivable | 428.6 | 377.2 | ||||||
Allowance for doubtful accounts | (7.1 | ) | (6.6 | ) | ||||
Customer accounts receivable, net | 421.5 | 370.6 | ||||||
Other | 25.1 | 22.3 | ||||||
$ | 446.6 | $ | 392.9 | |||||
9. | INVENTORY |
Inventory consisted of the following:
As at millions of Canadian dollars | March 31 2011 | December 31 2010 | ||||||
Fuel | $ | 107.3 | $ | 129.1 | ||||
Materials | 61.6 | 48.7 | ||||||
$ | 168.9 | $ | 177.8 | |||||
10. | OTHER CURRENT LIABILITIES |
Other current liabilities consisted of the following:
As at millions of Canadian dollars | March 31 2011 | December 31 2010 | ||||||
Accrued charges | $ | 61.9 | $ | 59.6 | ||||
Accrued interest on long-term debt | 46.5 | 37.7 | ||||||
Sales taxes payable | 9.4 | 7.0 | ||||||
Dividends payable | 2.0 | 2.1 | ||||||
Other | 3.1 | 3.9 | ||||||
$ | 122.9 | $ | 110.3 | |||||
11. | REGULATORY |
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 Nova Scotia Utility and Review Board (“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. The Company’s last general rate hearing was settled on November 5, 2008. The UARB approved an average 9.28 percent increase in customer rates at that time.
On December 23, 2010, the UARB granted NSPI approval to defer certain tax benefits related to renewable energy projects arising in 2010. Accordingly, effective December 31, 2010, NSPI recognized a deferral of $14.5 million through an increase in regulatory amortization. The UARB has convened a proceeding in 2011 to discuss how this deferral will be applied, and a decision is expected in Q2 2011.
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 prior year cost balance 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 unrecovered balance of fuel related costs.
On January 10, 2010, NSPI reached an agreement with stakeholders on its calculation of regulated ROE. The agreement, approved by the UARB, set as a condition that NSPI maintains an average actual equity to total capitalization, each as defined by the UARB, at a level of no higher than 40 percent beginning 2010 and until the next general rate case.
The UARB approved the implementation of a fuel adjustment mechanism in the Company’s 2009 General Rate Decision, effective January 1, 2009. The FAM is subject to a formula based incentive with NSPI retaining or absorbing the over- or under-recovered amount, less the difference between the incentive threshold and the base amount, to a maximum of $5 million.
Bangor Hydro
Bangor Hydro’s core business is the transmission and distribution of electricity. Bangor Hydro’s distribution operations and stranded cost recoveries are regulated by the Maine Public Utilities Commission (“MPUC”). The 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.
Bangor Hydro operates under a traditional cost-of-service regulatory structure.
Transmission rates are set by the FERC 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 transmission operations ranges from 11.14 percent for low voltage local transmission up to 12.64 percent for high voltage regionally-funded transmission developed as a result of the regional system plan.
In December 2007, the MPUC approved an increase of approximately 2 percent in distribution rates effective January 1, 2008. The allowed ROE used in setting these distribution rates was 10.2 percent, with a common equity component of 50 percent.
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In December 2007, the MPUC issued an order approving an approximate 39 percent reduction in stranded cost rates for the three-year period beginning March 1, 2008. The reduced stranded cost revenues are offset for the most part by decreased regulatory amortizations, decreased purchased power costs, and increased resale of purchased power. The allowed ROE used in setting the new stranded cost rates was 8.5 percent. Prior to that, stranded cost rates provided for an allowed ROE of 10 percent. On June 1, 2009, Bangor Hydro further reduced its stranded cost rates by approximately 15 percent to reflect an over-collection of certain stranded cost revenues and expenses under a full reconciliation rate mechanism.
Maine Public Service Company
MPS, a wholly owned subsidiary of MAM, is subject to the regulatory authority of MPUC and FERC. As a result of the rate-making process, the applications of accounting principles by the Company differ in certain respects from applications by non-regulated businesses.
MPS’ business consists of three primary components which are each governed by their own regulatory structure. The components are distribution, transmission and stranded costs.
MPS’ distribution business operates under the regulation of the MPUC and operates under a traditional cost-of-service regulatory structure.
The transmission business of MPS is primarily regulated by the FERC. Transmission rates are set annually through the Open Access Transmission Tariff (“OATT”). Rates derived from the previous calendar year’s 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 common equity. 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.
MPS also has the ability to recover stranded costs of regulatory assets.
Metering, billing and settlement services for power suppliers are provided directly by MPS within its service territory and MPS is permitted to recover all prudently incurred costs for these services.
In July 2006, the MPUC approved an increase of approximately 11 percent in distribution rates, effective July 15, 2006. The allowed ROE used in setting these distribution rates was 10.2 percent, with a common equity component of 50 percent. In the event that costs rise faster than revenues, MPS has the ability to return to the MPUC to request a further increase in rates on January 1, 2012 or any time thereafter.
The Barbados Light & Power Company Limited
BLPC, a wholly-owned subsidiary of LPH, is the sole utility operator on the island of Barbados. BLPC also operates a self-insurance fund.
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. Fair Trading Commission, Barbados has granted BLPC a licensed, regulated and exclusive 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.
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BLPC’s first rate adjustment since 1983 was approved in January 2010 and was effective March 1, 2010.
All BLPC fuel costs pass through 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
The Grand Bahama Port Authority 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 policies to ensure that costs are recovered and a reasonable return earned.
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.
Effective April 12, 2011, the Grand Bahama Port Authority approved as part of the fuel surcharge the recovery of the net cost for leasing temporary generation to meet peak demand for electricity a 4.5 percent base tariff rate increase effective January 1, 2011 and a 2012 tariff rate increase to provide GBPC with a 10 percent return on rate base.
Emera Brunswick Pipeline Company Ltd.
Brunswick Pipeline entered into a 25 year firm service agreement commencing on July 16, 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. Brunswick Pipeline meets the definition of a direct financing lease for accounting purposes.
12. | INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY EARNINGS |
Investments subject to significant influence consisted of the following:
2011 | 2010 | |||||||||||||||||||
millions of Canadian dollars | Percentage of Ownership | March 31 Carrying value | March 31 Equity income (loss) | December 31 Carrying value | March 31 Equity income (loss) | |||||||||||||||
APUC* | 8.2 | $ | 43.3 | $ | 0.5 | — | — | |||||||||||||
CPUV | 49.999 | 34.8 | 0.9 | — | — | |||||||||||||||
Bear Swamp | 50.0 | (9.4 | ) | 3.3 | $ | (14.2 | ) | $ | (1.6 | ) | ||||||||||
M&NP* | 12.9 | 118.0 | 2.1 | 118.8 | 2.2 | |||||||||||||||
LPH | — | — | 0.8 | 111.7 | — | |||||||||||||||
Lucelec* | 19.1 | 25.0 | 0.5 | 25.0 | 0.4 | |||||||||||||||
AHI | 26.1 | 3.1 | (0.6 | ) | 3.6 | |||||||||||||||
Maine Electric Power Company Inc. | 21.7 | 0.9 | — | 0.9 | — | |||||||||||||||
Maine Yankee Atomic Power Company* | 12.0 | 0.2 | — | 0.2 | — | |||||||||||||||
GBPC | — | — | — | — | (0.3 | ) | ||||||||||||||
$ | 215.9 | $ | 7.5 | $ | 246.0 | $ | 0.7 | |||||||||||||
(*) | 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 presentation. Therefore, Emera records its investment in APUC and Maine Yankee Atom Power Company, Lucelec, LPH and M&NP using the equity method. This is consistent with industry practice for similar joint-owned units. |
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13. | AVAILABLE-FOR-SALE INVESTMENT |
The available-for-sale investment include investments in debt and equity securities held in trust on behalf of The Barbados Light & Power Company Limited Self Insurance Fund for the purpose of building an insurance fund to cover risk against damage and consequential loss to certain generating, transmissions and distribution systems. Emera has classified these investments as available-for-sale and have recorded all such investments at their market value at March 31, 2011. These available-for-sale investments include common shares, mutual funds, corporate bonds, debentures, short- and medium-term notes and government bonds.
14. | ACQUISITIONS |
Light & Power Holdings Ltd.
On January 25, 2011, Emera acquired a further 41.6 percent of the outstanding common stock, to bring its total investment to 79.6%, in LPH, a publically held Barbados corporation for cash consideration of $92.0 million CAD ($92.2 million USD). LPH is the parent Company of BLPC. BLPC is a vertically-integrated utility and the sole provider of electricity on the island of Barbados until 2028. This investment was made to provide a platform on which to grow Emera’s regulated transmission, distribution and generation portfolio. Prior to the additional investment, Emera’s carrying value in LPH was $91.2 million CAD ($91.4 million USD).
The Company recorded a non-taxable gain for the three months ended March 31, 2011 of $28.0 million which was included in “Other income (expenses), net” in the “Consolidated Statements of Income”.
The Company recorded $2.0 million in acquisition-related costs of which $1.5 million was for the three months ended March 31, 2011 and included in “Operating, maintenance and general expense” in the “Consolidated Statements of Income”.
The valuation technique used to measure the acquisition-date fair value of the assets and liabilities of LPH subject to regulation was book value given the regulatory environment in which LPH operates.
The total purchase price has been allocated to the fair value of assets and liabilities. The allocation of the purchase price is as follows:
millions of Canadian dollars | ||||
Cash and cash equivalents | $ | 70.7 | ||
Receivables, net | 26.7 | |||
Inventory | 16.4 | |||
Property, plant and equipment, net of accumulated depreciation | 293.5 | |||
Financial investments available-for-sale | 52.5 | |||
Current liabilities | (35.4 | ) | ||
Other long-term liabilities | (68.2 | ) | ||
Regulatory liabilities | (62.7 | ) | ||
Gain on business acquisition(1) | (28.0 | ) | ||
Non-controlling interest | (59.8 | ) | ||
Total purchase consideration | $ | 205.7 | ||
(1) | The gain shown above represents the net effect of the gain on acquisition of $56.8 million net of a loss of $28.8 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 purchase price allocation has been finalized. A third party valuation of the assets was not performed because the fair value of the regulated assets are equal to their rate base since a regulated utility can only recover its cost or book value (rate base) plus a fair return.
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Supplemental Pro Forma Data
The unaudited pro forma statement below gives effect to the acquisition of the controlling interest of LPH 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 | Three months ended March 31 | |||||||
millions of Canadian dollars | 2011 | 2010 | ||||||
Operating revenues | $ | 620.2 | $ | 499.4 | ||||
Net income attributable to common shareholders | 123.9 | 79.2 | ||||||
Pro forma basic earnings per share | $ | 1.06 | $ | 0.70 | ||||
Pro forma diluted earnings per share | $ | 1.03 | $ | 0.68 | ||||
The Company has included operating revenues of $48.2 million and net income attributable to common shareholders of $1.4 million for LPH in its consolidated net income attributable to common shareholders for fiscal 2011 related to the period subsequent to January 25, 2011.
Grand Bahama Power Company Limited
On December 22, 2010, Emera acquired 50 percent of the outstanding common shares of Grand Bahama Power Company Limited (“GBPC”), an integrated utility and sole provider of electricity on Grand Bahama Island, and an additional 10.7 percent interest in ICDU, owner of the remaining 50 percent interest in GBPC. This investment was made to provide a platform on which to grow Emera’s regulated electricity, transmission and generation portfolio. Prior to December 22, 2010, the Company owned 50 percent of the outstanding common shares of ICDU, with a carrying value of $39.2 million. The fair value of GBPC and ICDU respectively immediately prior to the acquisition date was $147.4 million and $73.7 million.
Upon acquiring a further equity interest in GBPC and ICDU respectively, the Company recorded a loss on a business acquisition achieved in stages related to the pre-existing investment of $2.4 million.
Under the terms of the agreement, Emera purchased controlling interest in GBPC for the cash consideration of $81.6 million CAD ($82.0 million USD).
The Company incurred $5.4 million in acquisition-related costs of which $6.1 million was expensed in fiscal 2010 offset with a recovery of $0.7 million recorded for the three months ended March 31, 2011. These expenses are included in “Operating, maintenance and general expense” in the “Consolidated Statements of Income.”
The total preliminary purchase price has been allocated to the fair value of assets and liabilities. The allocation of the preliminary purchase price is as follows:
millions of Canadian dollars | ||||
Net working capital | $ | 7.2 | ||
Property, plant and equipment, net of accumulated depreciation | 174.7 | |||
Goodwill | 50.8 | |||
Long-term debt | (85.3 | ) | ||
Non-controlling interest | (28.9 | ) | ||
Total preliminary purchase consideration | $ | 118.5 | ||
The preliminary valuation technique used to measure the acquisition-date fair value of the equity interest in GBPC was book value given the regulatory environment in which GBPC operates. The purchase price allocation has not yet been finalized as the Company has not completed the valuation of property, plant and equipment in GBPC and, therefore, the allocation of the purchase price has been estimated, and is
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subject to change. Property, plant and equipment and goodwill values have not been finalized pending completion of an external valuation. The valuation will be completed in 2011.
Supplemental Pro Forma Data
The unaudited pro forma statement below gives effect to the acquisition of 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.
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2011 | 2010 | ||||||
Operating revenues | $ | 554.6 | $ | 461.6 | ||||
Net income attributable to common shareholders | 123.6 | 77.2 | ||||||
Pro forma basic earnings per share | $ | 1.06 | $ | 0.68 | ||||
Pro forma diluted earnings per share | $ | 1.03 | $ | 0.66 | ||||
The Company has included operating revenues of $25.4 million and net income attributable to common shareholders of nil for GBPC in its consolidated net income attributable to common shareholders for fiscal 2011.
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 Maine Public Service Company. Under the terms of the agreement, Emera purchased MAM for the cash consideration of $77.2 million CAD ($75.8 million USD). This investment was made to provide a platform on which to grow Emera’s transmission and distribution portfolio.
The Company incurred $4.7 million in acquisition-related costs which were expensed during 2010 and are included in “Operating, maintenance and general expense” in the “Consolidated Statements of Income.”
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.
The total purchase price has been allocated to the fair value of assets and liabilities. The allocation of the purchase price is as follows:
millions of Canadian dollars | ||||
Net working capital | $ | 1.3 | ||
Property, plant and equipment, net of accumulated depreciation | 69.4 | |||
Regulatory and other assets | 34.5 | |||
Goodwill | 31.2 | |||
Regulatory and other liabilities | (36.2 | ) | ||
Long-term debt | (23.0 | ) | ||
Total purchase consideration | $ | 77.2 | ||
The purchase price allocation has been finalized. A third party valuation of the assets was not performed because the fair value of the regulated assets are equal to their rate base since a regulated utility can only recover its cost or book value (rate base) plus a fair return.
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Supplemental Pro Forma Data
The unaudited pro forma statement below gives effect to the acquisition of MAM 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.
millions of Canadian dollars | 2011 | 2010 | ||||||
Operating revenues | $ | 554.6 | $ | 449.0 | ||||
Net income attributable to common shareholders | 123.6 | 78.5 | ||||||
Pro forma basic earnings per share | $ | 1.06 | $ | 0.69 | ||||
Pro forma diluted earnings per share | $ | 1.03 | $ | 0.67 | ||||
The Company has included operating revenues of $10.6 million and net income attributable to common shareholders of $2.0 million for MAM in its consolidated net income attributable to common shareholders for fiscal 2011.
15. | EARNINGS PER SHARE |
The following table reconciles the computation of basic and diluted earnings per share:
For the | Three months ended March 31 | |||||||
millions of Canadian dollars, except per share amounts | 2011 | 2010 | ||||||
Numerator | ||||||||
Net income attributable to common shareholders of Emera Inc. | $ | 123.6 | $ | 77.8 | ||||
Preferred stock dividends of subsidiary | 2.0 | 2.0 | ||||||
Diluted numerator | 125.6 | 79.8 | ||||||
Denominator | ||||||||
Weighted average shares of common stock outstanding – basic | 115.9 | 113.2 | ||||||
Weighted average DSUs outstanding | 0.5 | 0.4 | ||||||
Weighted average shares of common stock outstanding – basic | 116.4 | 113.6 | ||||||
Effect of dilutive securities | 4.3 | 5.6 | ||||||
Stock-based compensation and employee common share purchase plan | 1.1 | 0.8 | ||||||
Weighted average shares of common stock outstanding – diluted | 121.8 | 120.0 | ||||||
Earnings per common share | ||||||||
Basic | $ | 1.06 | $ | 0.68 | ||||
Diluted | $ | 1.03 | $ | 0.67 |
The calculation and diluted earnings per share for the three months ended March 31, 2011 and 2010, excluded 0.2 million and nil, respectively, unexercised stock options that had an anti-dilutive effect.
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16. | COMMITMENTS AND CONTINGENCIES |
A. | Commitments |
As at March 31, 2011, commitments (excluding pensions, long-term debt, and AROs) for each of the next five years and in aggregate thereafter were as follows:
millions of Canadian dollars | 2011 | 2012 | 2013 | 2014 | 2015 | Thereafter | ||||||||||||||||||
Purchased power | $ | 61.1 | $ | 82.9 | $ | 87.0 | $ | 86.6 | $ | 86.2 | $ | 1,077.6 | ||||||||||||
Coal, biomass, oil and natural gas supply | 192.9 | 251.1 | 171.5 | 111.3 | 82.2 | 613.7 | ||||||||||||||||||
Transportation | 62.9 | 70.0 | 26.2 | 23.7 | 2.4 | 0.5 | ||||||||||||||||||
Long-term service agreements | 8.0 | 5.8 | 5.2 | 5.2 | 4.7 | 0.5 | ||||||||||||||||||
Capital projects | 101.7 | 57.1 | 4.0 | — | — | — | ||||||||||||||||||
Leases | 3.2 | 2.1 | 1.0 | 0.6 | 0.6 | 1,429.0 | ||||||||||||||||||
Other | 2.1 | 2.0 | 1.7 | 1.0 | 1.0 | 1.0 |
• | Purchased power: annual requirement to purchase 100 percent of electricity production from independent power producers over varying contract lengths up to 25 years. |
• | Coal, biomass, oil and natural gas supply: purchasing commitments for the supply of coal, oil, natural gas and for the services and supply of biomass. |
• | Transportation: purchasing commitments for transportation of solid fuel and transportation capacity on M&NP. |
• | Long-term service agreements: consist of outsourced management of the Company’s computer infrastructure and maintenance of generation units. |
• | Capital projects: commitments to third parties to purchase goods and services related to capital projects. |
• | Leases: consists of operating lease agreements for office space, telecommunications services, rail cars and vehicles. |
• | Other: consists of other purchase commitments. |
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 committed to operating in a manner that is respectful and protective of the environment, and in full compliance with legal requirements and Company policy. NSPI has implemented this practice through development and application of environmental management systems (“EMS”) where risks are identified and managed proactively. In addition to programs for employees, the EMS procedures include planning, implementing and monitoring of contractors’ performance.
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The Company 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 the Company. 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 Company 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.
Climate Change and Air 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.
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.
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.
Greenhouse gas emissions from NSPI facilities are 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. The Canadian federal government has announced a proposed policy framework for greenhouse gas reductions from the coal generating units within the electricity sector. The proposed framework has a performance based standard to be achieved upon a coal fired generating unit reaching its 45 year anniversary. The first year of regulation would be 2015. The content and timing of the framework may be affected by the outcome of the May 2, 2011 federal election.
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Mercury
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.
Nitrogen Oxide and Sulphur Dioxide Emissions
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 Province of Nova Scotia effective 2010. These investments, combined with the purchasing of compliance coal, allows NSPI to meet the provincial air quality regulations. 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 is expensed as incurred; 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 $21.6 million and, as at March 31, 2011 and December 31, 2010, approximately $3.2 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 $14.5 million as at March 31, 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.
MPS
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. The total cost of the program is estimated to be $3.0 million and, as at March 31, 2011, $2.9 million has been spent to remediate approximately 99 percent of the transformers in this effort.
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D. | Environmental Remediation |
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 $61.0 million during 2011 and $618.0 million from 2012 to 2015. Amounts that have been committed to are included in “Capital projects” in the commitments table in note 16A. 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. | Risks and Uncertainties |
NSPI
Labour
NSPI had 1,680 full-time employees and 247 term employees as at March 31, 2011, of which approximately 51 percent were represented by a local union affiliated with the International Brotherhood of Electrical Workers. A collective bargaining agreement was entered into on August 1, 2007 and expires March 31, 2012.
Large Customer
NSPI has one large industrial customer that contributed to approximately 6.8 percent (2010 – 6.8 percent) of NSPI’s electric revenues for the quarter ending March 31, 2011. The five largest industrial customers contributed to approximately 10.1 percent (2010 – 10.2 percent) of NSPI’s electric revenues for the three months ending March 31, 2011.
Regulatory
The adoption and implementation of the FAM effective January 1, 2009 has helped NSPI manage the regulatory risk with respect to the timeliness and certainty of the full recovery of fuel costs.
Bangor Hydro
Labour
Bangor Hydro had 283 full-time employees at March 31, 2011, of which approximately 51 percent were represented by a local union affiliated with the International Brotherhood of Electrical Workers. A new collective bargaining agreement was entered into in July 2010 which will expire on June 30, 2015.
Brunswick Pipeline
Sole Customer
Brunswick Pipeline has a 25 year firm service agreement with Repsol Energy Canada. The pipeline was used solely in 2010 and 2011 to transport natural gas from the CanaportTM LNG terminal in Saint John, New Brunswick to the United States border for Repsol Energy Canada.
F. | Collaborative Arrangement |
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 terms of the arrangement were established in a Memorandum of Understanding, executed on March 14, 2008. 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 Emera, through its subsidiary Bangor Hydro Electric Company and National Grid. Bangor Hydro has deferred $2.3 million USD of costs associated with the NEL project as at March 31, 2011, reported in the Consolidated Balance Sheets within “Other” as part of other assets.
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G. | Guarantees and Letters of Credit |
As part of normal business, Emera enters into various guarantees providing financial or performance assurance to third parties. These guarantees are entered into primarily to support or enhance their creditworthiness, thereby facilitating the extension of sufficient credit to accomplish the Company’s intended commercial purposes.
Emera had the following guarantees:
• | At the request of Emera and its subsidiaries, a financial institution has issued standby letters of credit in the amount of $10.69 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. These amounts are not reflected on the consolidated Balance Sheets. |
• | Standby letters of credit in the amount of $21.0 million for Supplemental Executive Retirement Plans are not reflected on the consolidated Balance Sheets. |
• | At the request of MPS, 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. In addition to these letters of credit, MPS issued first and second mortgage bonds totaling $23.9 million USD to secure MPS’ obligation under the letters of credit. |
• | NSPI has provided a limited guarantee for the indebtedness of RESL. The guarantee is up to a maximum of $23.5 million. As at March 31, 2011 RESL’s indebtedness under the loan agreement was $22.0 million. NSPI holds a first ranking security interest in the assets of RESL and all future assets of the project owned by RESL. For further information see note 1BB. |
No liability has been recognized related to any potential obligation under these guarantees.
As permitted under applicable law, each of Emera and its affiliates has agreements that indemnify the Company’s Officers and Directors for certain events or occurrences while the Officer or Director is, or was serving, at such Company’s request in such capacity. The term of the indemnification period is for the Officer’s or Director’s lifetime. The maximum potential amount of future payments that could be required under these indemnification agreements is unlimited; however, Emera has Officer and Director insurance and other insurance coverages which help limit exposure and enable recovery of a portion of any future amounts paid. As a result of the insurance coverage, Emera believes the estimated fair value of these indemnification agreements is minimal. Accordingly, no liability was recorded for these agreements as at March 31, 2011 or December 31, 2010.
17. | COMMON STOCK |
Authorized:Unlimited number of non-par value common shares.
Issued and outstanding: | millions of shares | Common Stock Capital millions of Canadian dollars | ||||||
December 31, 2010 | 114.62 | $ | 1,137.8 | |||||
Issuance of common stock | 6.36 | 196.0 | ||||||
Issued for cash under purchase plans | 0.31 | 9.0 | ||||||
Options exercised under senior management share option plan | 0.02 | 0.5 | ||||||
Stock-based compensation | — | 0.3 | ||||||
March 31, 2011 | 121.31 | $ | 1,343.6 | |||||
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.
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18. | 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.
Net periodic costs prior to the effects of capitalization consisted of the following:
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2011 | 2010 | ||||||
Defined benefit pension plans | ||||||||
Service cost | $ | 4.1 | $ | 2.7 | ||||
Interest cost | 14.2 | 13.8 | ||||||
Expected return on plan assets | (12.6 | ) | (12.4 | ) | ||||
Current year amortization of: | ||||||||
Actuarial losses | 6.1 | 2.6 | ||||||
Total defined benefit pension plans | 11.8 | 6.7 | ||||||
Non-pension benefits plan | ||||||||
Service cost | 0.7 | 0.4 | ||||||
Interest cost | 1.2 | 0.6 | ||||||
Current year amortization of: | ||||||||
Actuarial losses (gains) | 0.4 | (0.1 | ) | |||||
Past service (gains) costs | (0.4 | ) | 0.1 | |||||
Total non-pension benefits plans | 1.9 | 1.0 | ||||||
Total defined benefit plans | $ | 13.7 | $ | 7.7 | ||||
Emera’s contributions related to these defined-benefit plans for the three months ended March 31, 2011 were $12.4 million (2010 – $9.0 million).
In addition, the Company contributions related to the defined contribution plan for the three months ended March 31, 2011 were $0.8 million (2010 – $0.4 million).
19. | 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 recognized when settled. 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 of the commodity, the Company intends to receive physical delivery, and the Company deems the counterparty creditworthy. The Company continually assesses physical contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exception if the criteria are no longer met. For greater certainty, NPNS contracts are not recognized at fair value on the balance sheet. |
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2. | Derivatives that do not meet the requirements of NPNS are recorded at fair value on the balance sheet. Derivatives qualify for hedge accounting if the derivatives meet the 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. The effective portion of the unrealized gains and losses of qualifying cash flow hedges are recognized in other comprehensive income, net of income taxes. Amounts related to these cash flow hedges will be recognized in income when the hedged transactions are recognized in income, or if it is probable that the hedged transaction will not occur. Any ineffective portion of the unrealized gains and losses of qualifying cash flow hedges are recognized in income of the period. Unrealized gains and losses related to derivatives that do not qualify for hedge accounting are also recognized in income. |
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 unrealized gains and losses associated with these derivatives are deferred to a regulatory asset or liability. The gain or loss on these derivatives is recognized when the derivatives are settled. 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 entered into by Emera Energy Services as part of its energy marketing business are recognized on the balance sheet at fair value. All gains and losses are recognized in income. |
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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 | March 31 2011 | December 31 2010 | March 31 2011 | December 31 2010 | ||||||||||||
Current | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power swaps | — | — | $ | 5.4 | $ | 6.4 | ||||||||||
Foreign exchange forwards | $ | 3.3 | $ | 2.4 | — | — | ||||||||||
3.3 | 2.4 | 5.4 | 6.4 | |||||||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | 23.4 | 23.6 | 0.1 | 1.9 | ||||||||||||
Natural gas purchases and sales | 1.5 | 0.8 | 10.6 | 20.3 | ||||||||||||
Heavy fuel oil (“HFO”) purchases | — | 1.9 | — | 1.3 | ||||||||||||
Foreign exchange forwards | 0.1 | 2.1 | 4.8 | 1.2 | ||||||||||||
Physical natural gas purchases and sales | 4.6 | 4.3 | 0.1 | — | ||||||||||||
29.6 | 32.7 | 15.6 | 24.7 | |||||||||||||
Trading derivatives | ||||||||||||||||
Power swaps and physical contracts | 7.1 | 10.5 | 1.2 | 2.6 | ||||||||||||
Foreign exchange forwards | 1.4 | 1.4 | — | — | ||||||||||||
Natural gas swaps, futures, forwards and physical contracts | 6.0 | 7.6 | 7.8 | 8.0 | ||||||||||||
14.5 | 19.5 | 9.0 | 10.6 | |||||||||||||
Total gross current derivatives | 47.4 | 54.6 | 30.0 | 41.7 | ||||||||||||
Impact of master netting agreements with intent to settle net or simultaneously | (2.9 | ) | (4.9 | ) | (2.9 | ) | (4.9 | ) | ||||||||
Total current derivatives | 44.5 | 49.7 | 27.1 | 36.8 | ||||||||||||
Long-term | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power swaps | 1.1 | 0.5 | 6.9 | 8.3 | ||||||||||||
Interest rate swaps | — | — | 3.4 | 3.6 | ||||||||||||
Foreign exchange forwards | 4.7 | 4.1 | — | — | ||||||||||||
5.8 | 4.6 | 10.3 | 11.9 | |||||||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | 21.4 | 18.5 | — | — | ||||||||||||
Natural gas purchases and sales | 0.2 | 0.1 | 0.4 | 1.8 | ||||||||||||
Foreign exchange forwards | — | 2.2 | 19.8 | 9.4 | ||||||||||||
Physical natural gas purchases and sales | 6.8 | 8.1 | — | — | ||||||||||||
28.4 | 28.9 | 20.2 | 11.2 | |||||||||||||
Trading derivatives | ||||||||||||||||
Power swaps and physical contracts | 0.9 | 1.0 | 0.8 | 0.9 | ||||||||||||
Natural gas swaps, futures, forwards and physical contracts | 3.2 | 2.0 | 4.0 | 5.4 | ||||||||||||
4.1 | 3.0 | 4.8 | 6.3 | |||||||||||||
Total gross long-term derivatives | 38.3 | 36.5 | 35.3 | 29.4 | ||||||||||||
Impact of master netting agreements with intent to settle net or simultaneously | (0.3 | ) | (0.5 | ) | (0.3 | ) | (0.5 | ) | ||||||||
Total long-term derivatives | 38.0 | 36.0 | 35.0 | 28.9 | ||||||||||||
Total derivatives | $ | 82.5 | $ | 85.7 | $ | 62.1 | $ | 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. 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 March 31 | |||||||||||||||||||
millions of Canadian dollars | 2011 | 2010 | ||||||||||||||||||
Power Swaps | Interest Rate Swaps | Foreign Exchange Forwards | Power Swaps | Foreign Exchange Forwards | ||||||||||||||||
Unrealized gain (loss) in AOCL – effective portion | $ | 1.0 | $ | 0.2 | $ | 2.3 | $ | (5.9 | ) | $ | 0.6 | |||||||||
Total gains (losses) in AOCL | 1.0 | 0.2 | $ | 2.3 | (5.9 | ) | $ | 0.6 | ||||||||||||
Unrealized loss in non-regulated fuel and purchased power – ineffective portion | (0.6 | ) | — | — | — | — | ||||||||||||||
Realized loss in non-regulated fuel and purchased power | (1.0 | ) | — | — | (1.9 | ) | — | |||||||||||||
Realized gain in regulated operating revenue | — | — | 0.6 | — | — | |||||||||||||||
Realized gain (loss) in other income (expenses), net | — | — | 0.1 | — | — | |||||||||||||||
Total (losses) gains in income | $ | (1.6 | ) | — | $ | 0.7 | $ | (1.9 | ) | — | ||||||||||
The Company expects $3.9 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 March 31, 2011, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:
2011 | 2012 | 2013 | 2014 | 2015 | ||||||||||||||||||||||||||||||||
millions | Sales | Sales | Purchases | Sales | Purchases | Sales | Purchases | Sales | Purchases | |||||||||||||||||||||||||||
Power swaps (megawatt hours (“MWh”) | — | — | 0.3 | — | 0.3 | — | 0.3 | — | 0.3 | |||||||||||||||||||||||||||
Foreign exchange forwards (USD) | 25.0 | 36.0 | — | 18.0 | — | 3.0 | — | 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 receives approval from the UARB for regulatory deferral of certain derivatives documented as economic hedges, 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 | March 31 2011 | March 31 2010 | March 31 2011 | March 31 2010 | ||||||||||||
Current | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | $ | (1.0 | ) | $ | 0.2 | $ | (0.6 | ) | $ | 0.3 | ||||||
Natural gas purchases and sales | (8.8 | ) | 1.5 | (1.5 | ) | (0.2 | ) | |||||||||
HFO purchases | (1.3 | ) | (1.4 | ) | 1.9 | 7.6 | ||||||||||
Foreign exchange forwards | 3.2 | (0.3 | ) | 2.0 | (0.3 | ) | ||||||||||
Physical natural gas purchases and sales | 0.1 | 13.9 | (0.3 | ) | (0.8 | ) | ||||||||||
Long-term | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | — | 0.4 | (2.9 | ) | 2.3 | |||||||||||
Natural gas purchases and sales | (1.5 | ) | 0.8 | (0.1 | ) | (0.1 | ) | |||||||||
HFO purchases | — | (1.3 | ) | — | 2.0 | |||||||||||
Foreign exchange forwards | 10.5 | 2.1 | 2.2 | 9.4 | ||||||||||||
Physical natural gas purchases and sales | — | 0.1 | 1.2 | 1.1 |
Commodity Swaps and Forwards
As at March 31, 2011, the Company had the following notional volumes of outstanding commodity swaps and forwards related to purchases, designated for regulatory approval that are expected to settle as outlined below:
millions of Canadian dollars | 2011 | 2012 | 2013 | 2014 | ||||||||||||
Coal swaps (metric tonnes) | 0.9 | 0.5 | 0.3 | 0.1 | ||||||||||||
Natural gas swaps and forwards (Mmbtu) | 20.2 | 10.4 | 0.5 | — |
Foreign Exchange Forwards
As at March 31, 2011, the Company had the following notional volumes of foreign exchange forwards that are expected to settle as outlined below:
millions of Canadian dollars | 2011 | 2012 | 2013 | 2014 | 2015 | |||||||||||||||
Fuel purchases exposure | $ | 140.2 | $ | 226.0 | $ | 130.0 | $ | 128.0 | $ | 127.0 | ||||||||||
Weighted average rate | 0.9917 | 0.9947 | 1.0617 | 1.0319 | 1.0281 | |||||||||||||||
% of USD requirements | 46.6% | 53.3% | 30.7% | 30.2% | 30.0% |
Trading Derivatives
In the ordinary course of its business, Emera Energy Services enters into physical contracts for the purchase and sale of natural gas; and power and nature gas swaps, forwards, and futures to economically hedge those physical contracts. These derivatives are all considered held for trading.
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The Company has recognized the following realized and unrealized gains (losses) with respect to held-for-trading derivatives:
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2011 | 2010 | ||||||
Power swaps and physical contracts in non-regulated operating revenues | $ | (1.0 | ) | $ | 8.3 | |||
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues | 7.6 | (3.6 | ) | |||||
Foreign exchange forwards in other income (expenses), net | — | (0.7 | ) | |||||
$ | 6.6 | $ | 4.0 | |||||
As at March 31, 2011, the Company had the following notional volumes of outstanding held-for-trading derivatives that are considered held-for-trading that are expected to settle as outlined below:
millions | 2011 | 2012 | 2013 | 2014 | 2015 | 2016 | ||||||||||||||||||
Natural gas purchases (Mmbtu) | 77.7 | 36.8 | 28.8 | 24.3 | 22.0 | 16.6 | ||||||||||||||||||
Natural gas sales (Mmbtu) | 40.7 | 17.5 | 6.9 | 3.3 | 1.5 | 0.4 | ||||||||||||||||||
Power purchases (MWh) | 1.4 | — | — | — | — | — | ||||||||||||||||||
Power sales (MWh) | 2.2 | — | — | — | — | — | ||||||||||||||||||
Foreign exchange forwards (USD) | 13.5 | — | — | — | — | — |
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.
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 of March 31, 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.
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Cash Collateral
The Company’s cash collateral positions consisted of the following:
As at millions of Canadian dollars | March 31 2011 | December 31 2010 | ||||||
Cash collateral provided to others | $ | 33.0 | $ | 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 March 31, 2011, the total fair value of these derivatives in a net liability position is $62.1 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.
20. | 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 19) and uses a market approach. Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices for identical assets and in active markets. These valuations are classified as “Level 1”.
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 in active markets with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses. These valuations are classified as “Level 2”.
Finally, certain derivatives are classified as “Level 3” due to the significance of unobservable or internally developed inputs. The primary reasons for a Level 3 classification are as follows:
• | While price curves may have been based on observable information, significant assumptions may have been made regarding seasonal or monthly shaping and locational basis differentials. |
• | Certain transactions were valued using pricing curves that extended beyond the quoted period. 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 external inputs were utilized in the valuations. |
Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
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The following tables set out the classification of the methodology used by the Company to fair value its derivatives at March 31, 2011 and December 31, 2010:
As at | March 31, 2011 | |||||||||||||||
millions of Canadian dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power swaps | $ | 1.1 | — | — | $ | 1.1 | ||||||||||
Foreign exchange forwards | — | $ | 8.0 | — | 8.0 | |||||||||||
1.1 | 8.0 | — | 9.01 | |||||||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | 44.7 | — | — | 44.7 | ||||||||||||
Natural gas purchases and sales | 1.7 | — | — | 1.7 | ||||||||||||
Foreign exchange forwards | — | 0.1 | — | 0.1 | ||||||||||||
Physical natural gas purchases and sales | — | — | $ | 11.4 | 11.4 | |||||||||||
46.4 | 0.1 | 11.4 | 57.9 | |||||||||||||
Trading derivatives | ||||||||||||||||
Power swaps and physical contracts | — | — | 6.8 | 6.8 | ||||||||||||
Foreign exchange forwards | — | 1.4 | — | 1.4 | ||||||||||||
Natural gas swaps, futures, forwards and physical contracts | — | 5.3 | 2.0 | 7.3 | ||||||||||||
— | 6.7 | 8.8 | 15.5 | |||||||||||||
Total assets | 47.5 | 14.8 | 20.2 | 82.5 | ||||||||||||
Liabilities | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power swaps | 12.3 | — | — | 12.3 | ||||||||||||
Interest rate swaps | — | 3.4 | — | 3.4 | ||||||||||||
12.3 | 3.4 | — | 15.7 | |||||||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Natural gas purchases and sales | 11.0 | — | — | 11.0 | ||||||||||||
Foreign exchange forwards | — | 24.6 | — | 24.6 | ||||||||||||
Physical natural gas purchases and sales | — | — | 0.1 | 0.1 | ||||||||||||
11.0 | 24.6 | 0.1 | 35.7 | |||||||||||||
Trading derivatives | ||||||||||||||||
Power swaps and physical contracts | — | — | 0.8 | 0.8 | ||||||||||||
Natural gas swaps, futures, forwards and physical contracts | 5.8 | 2.5 | 1.6 | 9.9 | ||||||||||||
5.8 | 2.5 | 2.4 | 10.7 | |||||||||||||
Total liabilities | 29.1 | 30.5 | 2.5 | 62.1 | ||||||||||||
Net assets (liabilities) | $ | 18.4 | $ | (15.7 | ) | $ | 17.7 | $ | 20.4 | |||||||
40
As at | December 31, 2010 | |||||||||||||||
millions of Canadian dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power swaps | $ | 0.5 | — | — | $ | 0.5 | ||||||||||
Foreign exchange forwards | — | $ | 6.5 | — | $ | 6.5 | ||||||||||
0.5 | 6.5 | — | 7.0 | |||||||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps | ||||||||||||||||
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 | |||||||||||
41.3 | 6.2 | 12.4 | 59.9 | |||||||||||||
Trading 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 | 18.4 | |||||||||||||
Total assets | 42.3 | 15.5 | 27.9 | 85.7 | ||||||||||||
Liabilities | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power swaps | 14.7 | — | — | 14.7 | ||||||||||||
Interest rate swaps | — | 3.6 | — | 3.6 | ||||||||||||
14.7 | 3.6 | — | 18.3 | |||||||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps | ||||||||||||||||
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 | ||||||||||||
22.3 | 11.9 | — | 34.2 | |||||||||||||
Trading 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 | 43.0 | 17.0 | 5.7 | 65.7 | ||||||||||||
Net assets (liabilities) | $ | (0.7 | ) | $ | (1.5 | ) | $ | 22.2 | $ | 20.0 | ||||||
The change in the fair value of the Level 3 financial assets for the three months ended March 31, 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 | ||||||||
Benefit included in regulated fuel for generation and purchased power | (1.2 | ) | — | — | (1.2 | ) | ||||||||||
Unrealized gains included in regulatory assets or liabilities | 0.2 | — | — | 0.2 | ||||||||||||
Total realized and unrealized losses included in non-regulated operating revenues | — | (2.2 | ) | (4.5 | ) | (6.7 | ) | |||||||||
Balance, March 31 | $ | 11.4 | $ | 6.8 | $ | 2.0 | $ | 20.2 | ||||||||
41
The change in the fair value of the Level 3 financial liabilities for the three months ended March 31, 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 | |||||||||
Unrealized losses included in regulatory assets or liabilities | $ | 0.1 | — | — | 0.1 | |||||||||||
Total realized and unrealized gains included in non-regulated operating revenues | — | (0.5 | ) | (2.8 | ) | (3.3 | ) | |||||||||
Balance, March 31 | $ | 0.1 | $ | 0.8 | $ | 1.6 | $ | 2.5 | ||||||||
The financial assets and liabilities included on the balance sheet that are not measured at fair value consisted of the following:
As at | March 31, 2011 | December 31, 2010 | ||||||||||||||
millions of Canadian dollars | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Long-term debt | $ | 2,868.7 | $ | 3,192.4 | $ | 2,982.3 | $ | 3,379.8 |
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.
21. | RELATED PARTY TRANSACTIONS |
In the normal course of business, Emera purchased natural gas transportation capacity totaling $12.9 million (2010 – $13.5 million) during the three months ended March 31, 2011, from M&NP, an investment under significant influence of the Company. 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 March 31, 2011, the amount payable to the related party was $3.9 million (December 31, 2010 – $3.9 million), and is under normal interest and credit terms.
22. | 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 International Financial Reporting Standards (“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.
42
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.
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 | ) | (101.9 | ) | |||||||
Other | (0.3 | ) | 0.5 | |||||||||
Total transition adjustments | (26.9 | ) | (241.1 | ) | ||||||||
Total assets – USGAAP | $ | 5,257.6 | $ | 6,088.0 | ||||||||
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 | ||||||||
43
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 | ||||||||
44
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 | 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 | |||||||||
45
As at January 1, 2010 millions of Canadian dollars | Notes | CGAAP | Effect of transition to USGAAP | 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, 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 Inc. 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 | |||||||||
46
As at December 31, 2010 millions of Canadian dollars | Notes | CGAAP | Effect of transition to USGAAP | 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 | 178.9 | (13.0 | ) | 165.9 | |||||||||||
Intangibles | L | 98.1 | (98.1 | ) | — | |||||||||||
Other | C, E, G, H, J, K, L, M | 652.1 | (480.3 | ) | 171.8 | |||||||||||
Total other assets | 1,757.5 | (259.5 | ) | 1,498.0 | ||||||||||||
Total assets | $ | 6,329.1 | $ | (241.1 | ) | $ | 6,088.0 | |||||||||
47
As at December 31, 2010 millions of Canadian dollars | Notes | CGAAP | Effect of transition to USGAAP | USGAAP | ||||||||||||
Liabilities and Equity | ||||||||||||||||
Current liabilities | ||||||||||||||||
Short-term debt | G | $ | 228.1 | $ | 0.4 | $ | 228.5 | |||||||||
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 | 690.3 | 69.7 | 760.0 | |||||||||||||
Long-term liabilities | ||||||||||||||||
Long-term debt | A, G, P | 3,006.9 | (35.2 | ) | 2,971.7 | |||||||||||
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 | 3,844.5 | (46.4 | ) | 3,798.1 | ||||||||||||
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 | ) | (401.0 | ) | (565.7 | ) | |||||||||
Retained earnings | C, F, G, J, K, P, R, S | 651.4 | 2.1 | 653.5 | ||||||||||||
Total Emera Inc. equity | 1,773.6 | (398.1 | ) | 1,375.5 | ||||||||||||
Non-controlling interest in subsidiaries | P, Q | — | 154.4 | 154.4 | ||||||||||||
Total equity | 1,773.6 | (243.7 | ) | 1,529.9 | ||||||||||||
Total liabilities and equity | $ | 6,329.1 | $ | (241.1 | ) | $ | 6,088.0 | |||||||||
48
The adjustments to January 1, 2010 and December 31, 2010 equity are as follows:
As at January 1, 2010 Millions of Canadian dollars | Common Stock | Contributed Surplus | Accumulated Other Comprehensive 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 for joint ventures | — | — | 0.1 | — | — | 0.2 | ||||||||||||||||||
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 other post-retirement benefits | — | — | (277.6 | ) | (6.8 | ) | — | (284.4 | ) | |||||||||||||||
Note P – Preferred stock of NSPI | — | — | — | 1.8 | $ | 132.2 | 134.0 | |||||||||||||||||
Note Q – Non-controlling interest in subsidiaries | — | — | — | — | 32.1 | 32.1 | ||||||||||||||||||
Note R – Share-based compensation | 1.2 | (0.6 | ) | — | (0.6 | ) | — | — | ||||||||||||||||
Note S – Foreign currency translation | — | — | 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 dollars | 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 for joint ventures | — | — | — | 0.5 | — | — | 0.5 | |||||||||||||||||||||
Note C – Income taxes | — | — | — | 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 | — | — | — | (389.4 | ) | (4.3 | ) | — | (393.7 | ) | ||||||||||||||||||
Note P – Preferred stock of NSPI | — | — | — | — | 1.9 | $ | 132.2 | 134.1 | ||||||||||||||||||||
Note Q – Non-controlling interest in subsidiaries | — | — | — | (1.5 | ) | — | 22.2 | 20.7 | ||||||||||||||||||||
Note R – Share-based compensation | 1.3 | — | (0.5 | ) | — | (0.8 | ) | — | — | |||||||||||||||||||
Note S – Foreign currency translation | — | — | — | 1.6 | (1.6 | ) | — | — | ||||||||||||||||||||
Other | — | — | — | 0.2 | 0.6 | — | 0.8 | |||||||||||||||||||||
Total transition adjustments | 1.3 | — | (0.5 | ) | (401.0 | ) | 2.1 | 154.4 | (243.7 | ) | ||||||||||||||||||
USGAAP | $ | 1,137.8 | $ | 146.7 | $ | 3.2 | $ | (565.7 | ) | $ | 653.5 | $ | 154.4 | $ | 1,529.9 | |||||||||||||
49
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 earnings 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 | |||||||||||
50
For the six months ended June 30, 2010 millions of Canadian dollars (except earnings 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 | — | 82.1 | 82.1 | ||||||||||||
Total operating revenues | 787.5 | 15.6 | 803.1 | |||||||||||||
Operating expenses | ||||||||||||||||
Regulated fuel for generation and purchased power | U, V | 375.0 | (45.3 | ) | 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 | 22.9 | 624.6 | |||||||||||||
Income from operations | 185.7 | (7.3 | ) | 178.5 | ||||||||||||
Income from equity investments | A, C | 6.2 | 1.7 | 7.9 | ||||||||||||
Other income (expenses), net | | F, J, S, T, U, W, Y | | — | 17.8 | 17.8 | ||||||||||
Financing charges | P, W, Y | 84.3 | (84.3 | ) | — | |||||||||||
Interest expense, net |
| A, C, P, U, W, Y |
| — | 75.3 | 75.3 | ||||||||||
Income before provision for income taxes | 107.6 | 21.2 | 128.9 | |||||||||||||
Income tax expense (recovery) | A, C | 0.9 | (2.3 | ) | (1.4 | ) | ||||||||||
Net income from operations | 106.7 | 23.5 | 130.3 | |||||||||||||
Non-controlling interest in subsidiaries | P | — | 4.0 | 4.0 | ||||||||||||
Net income attributable to common shares | $ | 106.7 | $ | 19.5 | $ | 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 | |||||||||||
51
For the nine months ended September 30, 2010 millions of Canadian dollars (except earnings 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 Inc. | 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 | |||||||||||
52
For the year ended December 31, 2010 millions of Canadian dollars | 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 Inc. | 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 | $ | 1.16 | — | $ | 1.16 | |||||||||||
53
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 | A, 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 increase (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 | $ | 7.8 | $ | 112.9 | |||||||||
Net cash used in investing activities | A, Y | (298.2 | ) | (4.1 | ) | (302.3 | ) | |||||||||
Net cash provided by financing activities | A, P, R | 220.0 | (5.6 | ) | 214.4 | |||||||||||
Effect of exchange rate changes on cash and cash equivalents | 0.5 | (0.6 | ) | (0.1 | ) | |||||||||||
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 | $ | 13.7 | $ | 244.6 | |||||||||
Net cash used in investing activities | A, Y | (452.0 | ) | (8.0 | ) | (460.0 | ) | |||||||||
Net cash provided by financing activities | A, P, R | 247.2 | (7.5 | ) | 239.7 | |||||||||||
Effect of exchange rate changes on cash and cash equivalents | (0.4 | ) | (0.6 | ) | (1.0 | ) | ||||||||||
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 increase (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 | ||||||||
54
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 |
55
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 June 30 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 March 31 2010 | 6 months ended June 30 2010 | 9 months ended September 30 2010 | Year ended December 31 2010 | ||||||||||||
Net cash provided by (used in) operating activities | $ | 0.1 | $ | (1.0 | ) | $ | (0.7 | ) | $ | (0.4 | ) | |||||
Net cash (used in) provided by investing activities | (0.1 | ) | 0.1 | (0.1 | ) | 1.5 | ||||||||||
Net cash used in financing activities | — | (1.6 | ) | (1.6 | ) | (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 | ) | (4.0 | ) | (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.
56
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 March 31 2010 | 6 months ended June 30 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 | ) |
57
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 March 31 2010 | 6 months ended June 30 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 | ) |
58
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 March 31 2010 | 6 months ended June 30 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.
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 | ) |
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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 | ) |
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.
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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 | ||||||
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 March 31 2010 | 6 months ended June 30 2010 | 9 months ended September 30 2010 | Year ended December 31 2010 | ||||||||||||
Operating, maintenance and general | — | — | — | $ | 11.3 |
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 | ) |
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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 March 31 2010 | 6 months ended June 30 2010 | 9 months ended September 30 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 March 31 2010 | 6 months ended June 30 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 “Accumulated other comprehensive loss (“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 | ) | ||||
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 | ) | (389.4 | ) | ||||
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 March 31 2010 | 6 months ended June 30 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 March 31 2010 | 6 months ended June 30 2010 | 9 months ended September 30 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 March 31 2010 | 6 months ended June 30 2010 | 9 months ended September 30 2010 | Year ended December 31 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 March 31 2010 | 6 months ended June 30 2010 | 9 months ended September 30 2010 | Year ended December 31 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 March 31 2010 | 6 months ended June 30 2010 | 9 months ended September 30 2010 | Year ended December 31 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 March 31 2010 | 6 months ended June 30 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 March 31 2010 | 6 months ended June 30 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 March 31 2010 | 6 months ended June 30 2010 | 9 months ended September 30 2010 | Year ended December 31 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 March 31 2010 | 6 months ended June 30 2010 | 9 months ended September 30 2010 | Year ended December 31 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 March 31 2010 | 6 months ended June 30 2010 | 9 months ended September 30 2010 | Year ended December 31 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 June 30 2010 | 9 months ended September 30 2010 | Year ended December 31 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 March 31 2010 | 6 months ended June 30 2010 | 9 months ended September 30 2010 | Year ended December 31 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 | ) |
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 March 31 2010 | 6 months ended June 30 2010 | 9 months ended September 30 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 | ) |
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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 | ||||
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 | ) | |||
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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 | ||||
The total amount of unrecognized tax benefits as of 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 of 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.
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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.
23. | SUBSEQUENT EVENTS |
Sale of CPUV to APUC
On April 29, 2011 APUC and Emera entered into a strategic investment agreement (“SIA”) which establishes how APUC and Emera will work together to pursue specific strategic investments of mutual benefit. The SIA outlines “areas of pursuit” for each of APUC and Emera. For APUC, these include investment opportunities relating to unregulated renewable generation, small electric utilities and gas distribution utilities. For Emera, these include investment opportunities related to regulated renewable projects within its service territories and large electric utilities.
Consistent with the framework established by the SIA, Emera has agreed to sell its 49.999 percent direct ownership in CPUV to APUC, subject to California regulatory approval. As consideration, Emera will receive 8.211 million APUC shares in two tranches. Approximately half of the shares will be issued following regulatory approval of the CPUV ownership transfer and the balance of the shares will be issued following completion of California Pacific’s first rate case which is expected to be completed in the first half of 2012. The company paid $31.5 million for its 49.999% interest in CPUV on January 1, 2011. The financial effect on the company will be impacted by changes in the share price of APUC at the time the transaction is finalized and ultimately, by the growth and financial performance of APUC.
Northeast Wind
APUC and Emera announced, on April 30, 2011, their intention to form a partnership with First Wind Holdings LLC (“First Wind”) for its northeastern assets. First Wind’s northeastern assets are comprised of a 370 megawatt (“MW”) portfolio of wind energy projects in northeastern United States, including five operating projects and two projects near operation. These assets will become part of an operating company of which First Wind will own 51 percent. Emera and APUC intend to create a separate joint venture (“Northeast Wind”), which will own 49 percent of the operating company. Emera will own 75 percent of Northeast Wind and APUC will own the balance. Northeast Wind will invest a total of $333 million USD to acquire the 49 percent ownership of the operating company; this includes a $150 million USD loan to the operating company. Emera will finance the transaction through existing credit facilities subject to lender approval.
In addition to its ownership interest in the operating company, First Wind will serve as its managing partner and continue to operate the projects.
The transaction requires certain state, federal regulatory approvals, among others, and is expected to close by the end of the year.
APUC’s financing plans for the Northeast Wind transaction include an agreement with Emera for Emera to acquire $37 million of subscription receipts in APUC at a price of $5.37 per share. This transaction, along with the sale of CPUV to APUC described above, provides Emera with the opportunity to increase its ownership interest in APUC up to 25 percent, subject to APUC shareholder approval.
Emera’s total investment in the Northeast Wind transaction will be approximately $287 million.
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