Exhibit 99.2
EMERA INCORPORATED
Unaudited Condensed Consolidated
Financial Statements
March 31, 2012 and 2011
38
Emera Incorporated
Consolidated Statements of Income (Unaudited)
For the | Three months ended March 31 | |||||||
millions of Canadian dollars (except per share amounts) | 2012 | 2011 | ||||||
Operating revenues | ||||||||
Regulated | $ | 526.1 | $ | 507.5 | ||||
Non-regulated | 41.9 | 47.1 | ||||||
Total operating revenues | 568.0 | 554.6 | ||||||
Operating expenses | ||||||||
Regulated fuel for generation and purchased power | 218.1 | 229.5 | ||||||
Regulated fuel and fixed cost adjustments (note 4) | 11.1 | (5.8) | ||||||
Non-regulated fuel for generation and purchased power | 13.9 | 20.7 | ||||||
Non-regulated direct costs | 14.3 | 13.8 | ||||||
Operating, maintenance and general | 109.1 | 111.5 | ||||||
Provincial, state, and municipal taxes | 12.5 | 12.3 | ||||||
Depreciation and amortization | 63.0 | 55.0 | ||||||
Total operating expenses | 442.0 | 437.0 | ||||||
Income from operations | 126.0 | 117.6 | ||||||
Income from equity investments | 6.0 | 11.9 | ||||||
Other income (expenses), net (note 5) | 1.5 | 41.6 | ||||||
Interest expense, net (note 6) | 41.9 | 40.9 | ||||||
Income before provision for income taxes | 91.6 | 130.2 | ||||||
Income tax expense (recovery) (note 7) | 6.8 | 2.7 | ||||||
Net income | 84.8 | 127.5 | ||||||
Non-controlling interest in subsidiaries | 2.9 | 2.2 | ||||||
Net income of Emera Incorporated | 81.9 | 125.3 | ||||||
Preferred stock dividends | 1.7 | 1.7 | ||||||
Net income attributable to common shareholders | $ | 80.2 | $ | 123.6 | ||||
Weighted average shares of common stock outstanding (in millions) | ||||||||
Basic | 123.6 | 116.4 | ||||||
Diluted | 128.5 | 121.8 | ||||||
Earnings per common share (note 8) | ||||||||
Basic | $ | 0.65 | $ | 1.06 | ||||
Diluted | $ | 0.64 | $ | 1.03 | ||||
Dividends per common share declared | $ | 0.3375 | $ | 0.3250 |
The accompanying notes are an integral part of these condensed consolidated financial statements.
39
Emera Incorporated
Consolidated Statements of Comprehensive Income (Unaudited)
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2012 | 2011 | ||||||
Net income | $ | 84.8 | $ | 127.5 | ||||
Other comprehensive income (loss), net of tax | ||||||||
Unrealized gains (losses) on cash flow hedges (1) | (3.3 | ) | 3.3 | |||||
Hedging losses (gains) included in income (2) | - | 0.5 | ||||||
Net change in unrecognized pension and post-retirement benefit recovery (costs) (3) | 9.5 | 5.2 | ||||||
Unrealized gain (loss) on available-for-sale investment | 0.1 | - | ||||||
Unrealized gain (loss) on translation of self-sustaining foreign operations (4) | (20.6 | ) | (21.3) | |||||
Other comprehensive income (loss), net of tax (5) | (14.3 | ) | (12.3) | |||||
Comprehensive income (loss) | 70.5 | 115.2 | ||||||
Less: Comprehensive income (loss) attributable to non-controlling interest | 2.9 | 2.2 | ||||||
Preferred stock dividends | 1.7 | 1.7 | ||||||
Comprehensive income (loss) attributable to common shareholders | $ | 65.9 | $ | 111.3 |
The accompanying notes are an integral part of these condensed consolidated financial statements.
1) | Net of tax recovery of $2.8 million (2011 – $0.8 million tax expense) for the three months ended March 31, 2012. |
2) | Net of tax expense of $0.5 million (2011 – $0.7 million tax expense) for the three months ended March 31, 2012. |
3) | Net of tax expense of $1.3 million (2011 – $0.4 million tax recovery) for the three months ended March 31, 2012. |
4) | Net of tax expense/recovery of nil (2011 – nil tax expense/recovery) for the three months ended March 31, 2012. |
5) | Net of tax recovery of $1.0 million (2011 – $1.1 million tax expense) for the three months ended March 31, 2012. |
40
Emera Incorporated
Consolidated Balance Sheets (Unaudited)
As at millions of Canadian dollars | March 31 2012 | December 31 2011 | ||||||
Assets | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 109.0 | $ | 76.9 | ||||
Restricted cash | 11.0 | 14.0 | ||||||
Receivables, net (note 9) | 458.7 | 459.6 | ||||||
Income taxes receivable | 37.7 | 41.6 | ||||||
Inventory (note 10) | 189.6 | 198.8 | ||||||
Deferred income taxes | 14.5 | 14.0 | ||||||
Derivative instruments (note 15 and 16) | 23.0 | 27.3 | ||||||
Regulatory assets | 140.7 | 141.6 | ||||||
Prepaid expenses | 29.1 | 15.1 | ||||||
Other current assets | 5.7 | 4.4 | ||||||
Total current assets | 1,019.0 | 993.3 | ||||||
Property, plant and equipment,net of accumulated depreciation of | 4,320.4 | 4,294.4 | ||||||
Other assets | ||||||||
Deferred income taxes | 38.7 | 33.1 | ||||||
Derivative instruments (note 15 and 16) | 32.4 | 39.6 | ||||||
Regulatory assets | 338.7 | 312.2 | ||||||
Net investment in direct financing lease | 491.6 | 492.0 | ||||||
Investments subject to significant influence | 220.7 | 222.7 | ||||||
Available-for-sale investments (note 11) | 58.0 | 54.6 | ||||||
Goodwill | 194.3 | 197.7 | ||||||
Intangibles, net of accumulated amortization of $61.2 and $59.7, respectively | 100.7 | 100.7 | ||||||
Other | 150.2 | 183.3 | ||||||
Total other assets | 1,625.3 | 1,635.9 | ||||||
Total assets | $ | 6,964.7 | $ | 6,923.6 |
The accompanying notes are an integral part of these condensed consolidated financial statements.
41
Emera Incorporated
Consolidated Balance Sheets (Unaudited) – Continued
As at millions of Canadian dollars | March 31 2012 | December 31 2011 | ||||||
Liabilities and Equity | ||||||||
Current liabilities | ||||||||
Short-term debt | $ | 199.4 | $ | 210.3 | ||||
Current portion of long-term debt | 37.5 | 35.7 | ||||||
Accounts payable | 262.6 | 332.9 | ||||||
Income taxes payable | 1.1 | 1.9 | ||||||
Deferred income taxes | 11.7 | 10.9 | ||||||
Derivative instruments (note 15 and 16) | 56.6 | 50.1 | ||||||
Regulatory liabilities | 21.2 | 23.9 | ||||||
Pension and post-retirement liabilities (note 17) | 9.4 | 8.8 | ||||||
Other current liabilities (note 13) | 146.3 | 127.2 | ||||||
Total current liabilities | 745.8 | 801.7 | ||||||
Long-term liabilities | ||||||||
Long-term debt (note 14) | 3,316.8 | 3,273.5 | ||||||
Deferred income taxes | 260.6 | 228.6 | ||||||
Derivative instruments (note 15 and 16) | 34.0 | 38.7 | ||||||
Regulatory liabilities | 99.9 | 107.1 | ||||||
Asset retirement obligations | 99.0 | 99.9 | ||||||
Pension and post-retirement liabilities (note 17) | 522.4 | 530.8 | ||||||
Other long-term liabilities | 19.6 | 19.6 | ||||||
Total long-term liabilities | 4,352.3 | 4,298.2 | ||||||
Commitments and contingencies(note 18) | ||||||||
Equity | ||||||||
Common stock, no par value, unlimited shares authorized, 122.83 million and 123.49 million shares issued and outstanding, respectively (note 19) | 1,403.0 | 1,385.0 | ||||||
Cumulative preferred stock, Series A, par value $25 per share; unlimited shares authorized, 6 million shares issued and outstanding | 146.7 | 146.7 | ||||||
Contributed surplus | 3.2 | 3.3 | ||||||
Accumulated other comprehensive loss | (686.0 | ) | (671.7) | |||||
Retained earnings | 774.3 | 735.9 | ||||||
Total Emera Incorporated equity | 1,641.2 | 1,599.2 | ||||||
Non-controlling interest in subsidiaries | 225.4 | 224.5 | ||||||
Total equity | 1,866.6 | 1,823.7 | ||||||
Total liabilities and equity | $ | 6,964.7 | $ | 6,923.6 |
The accompanying notes are an integral part of these condensed consolidated financial statements.
Approved on behalf of the Board of Directors
Chairman | President and Chief Executive Officer |
42
Emera Incorporated
Consolidated Statements of Cash Flows (Unaudited)
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2012 | 2011 | ||||||
Operating activities | ||||||||
Net income | $ | 84.8 | $ | 127.5 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depreciation and amortization | 66.7 | 55.9 | ||||||
Income from equity investments, net of dividends | (1.5 | ) | (7.6) | |||||
Allowance for equity funds used during construction | (3.8 | ) | (2.4) | |||||
Deferred income taxes, net | 1.1 | 9.2 | ||||||
Net change in pension and post-retirement, obligations (benefits) | 4.4 | 0.7 | ||||||
Regulated fuel and fixed cost adjustments | 9.4 | (7.8) | ||||||
Net change in fair value of derivative instruments | (10.0 | ) | (2.6) | |||||
Net change in regulatory assets and liabilities | (6.9 | ) | (2.9) | |||||
Other operating activities, net | 2.9 | (33.0) | ||||||
Changes in non-cash working capital: | ||||||||
Receivables, net | (0.9 | ) | (33.4) | |||||
Income taxes receivable | 3.8 | (8.8) | ||||||
Inventory | 8.6 | 24.3 | ||||||
Prepaid expenses | (14.1 | ) | (19.3) | |||||
Other current assets | (0.7 | ) | (0.7) | |||||
Accounts payable | (67.8 | ) | (37.7) | |||||
Income taxes payable | (0.8 | ) | (1.6) | |||||
Other current liabilities | 19.8 | 9.5 | ||||||
Net cash provided by operating activities | 95.0 | 69.3 | ||||||
Investing activities | ||||||||
Additions to property, plant and equipment | (95.9 | ) | (66.0) | |||||
Acquisition, net of cash acquired | - | (35.1) | ||||||
Decrease in restricted cash | 2.8 | 54.1 | ||||||
Purchase of investments subject to significant influence, inclusive of acquisition costs | - | (33.5) | ||||||
Allowance for borrowed funds used during construction | (3.0 | ) | (2.3) | |||||
Retirement spending, net of salvage | (1.9 | ) | (2.7) | |||||
Other investing activities | 29.2 | (57.1) | ||||||
Net cash used in investing activities | (68.8 | ) | (142.6) | |||||
Financing activities | ||||||||
Change in short-term debt, net | (10.8 | ) | 48.2 | |||||
Retirement of long-term debt | (0.2 | ) | (0.4) | |||||
Proceeds from long term-debt | 365.6 | - | ||||||
Net repayments under committed credit facilities | (312.7 | ) | (64.1) | |||||
Issuance of common stock, net of issuance costs | 17.6 | 203.2 | ||||||
Dividends on common stock | (41.5 | ) | (37.3) | |||||
Dividends on preferred stock | (1.6 | ) | (1.7) | |||||
Dividends paid by subsidiaries to non-controlling interest | (2.0 | ) | (2.2) | |||||
Other financing activities | (7.1 | ) | 0.1 | |||||
Net cash provided by financing activities | 7.3 | 145.8 | ||||||
Effect of exchange rate changes on cash and cash equivalents | (1.4 | ) | 0.3 | |||||
Net increase in cash and cash equivalents | 32.1 | 72.8 | ||||||
Cash and cash equivalents, beginning of period | 76.9 | 7.3 | ||||||
Cash and cash equivalents, end of period | $ | 109.0 | $ | 80.1 | ||||
Cash and cash equivalents consists of: | ||||||||
Cash | $ | 78.1 | $ | 46.3 | ||||
Short-term investments | 30.9 | 33.8 | ||||||
Cash and cash equivalents | $ | 109.0 | $ | 80.1 | ||||
Supplemental disclosure of cash paid (received): | ||||||||
Interest | $ | 32.7 | $ | 34.1 | ||||
Income and capital taxes | $ | 3.2 | $ | 3.1 |
The accompanying notes are an integral part of these condensed consolidated financial statements.
43
Emera Incorporated
Consolidated Statements of Changes in Equity (Unaudited)
millions of Canadian dollars | Common Stock | Preferred Stock | Contributed Surplus | Accumulated Other Comprehensive Loss (“AOCL”) | Retained Earnings | Non- Controlling Interest | Total Equity | |||||||||||||||||||||
For the three months ended March 31, 2012 |
| |||||||||||||||||||||||||||
Balance, December 31, 2011 | $ | 1,385.0 | $ | 146.7 | $ | 3.3 | $ | (671.7 | ) | $ | 735.9 | $ | 224.5 | $ | 1,823.7 | |||||||||||||
Net income of Emera Incorporated | - | - | - | - | 81.9 | 2.9 | 84.8 | |||||||||||||||||||||
Other comprehensive income (loss), net of tax recovery of $1.0 million | - | - | - | (14.3 | ) | - | - | (14.3) | ||||||||||||||||||||
Cash dividends declared on preferred stock ($0.2750/share) | - | - | - | - | (1.7 | ) | - | (1.7) | ||||||||||||||||||||
Cash dividends declared on common stock ($0.3375/share) | - | - | - | - | (41.5 | ) | - | (41.5) | ||||||||||||||||||||
Dividends paid by subsidiaries to non-controlling interest | - | - | - | - | - | (0.2 | ) | (0.2) | ||||||||||||||||||||
Common stock issued under purchase plan | 11.5 | - | - | - | - | - | 11.5 | |||||||||||||||||||||
Senior management stock options exercised | 5.9 | - | (0.5 | ) | - | - | - | 5.4 | ||||||||||||||||||||
Stock option expense | - | - | 0.4 | - | - | - | 0.4 | |||||||||||||||||||||
Other stock-based compensation | 0.6 | - | - | - | (0.3 | ) | - | 0.3 | ||||||||||||||||||||
Preferred dividends paid by subsidiaries to non-controlling interest | - | - | - | - | - | (2.0 | ) | (2.0) | ||||||||||||||||||||
Other | - | - | - | - | - | 0.2 | 0.2 | |||||||||||||||||||||
Balance, March 31, 2012 | $ | 1,403.0 | $ | 146.7 | $ | 3.2 | $ | (686.0 | ) | $ | 774.3 | $ | 225.4 | $ | 1,866.6 | |||||||||||||
For the three months ended March 31, 2011 |
| |||||||||||||||||||||||||||
Balance, December 31, 2010 | $ | 1,137.8 | $ | 146.7 | $ | 3.2 | $ | (564.2 | ) | $ | 653.5 | $ | 154.4 | $ | 1,531.4 | |||||||||||||
Net income of Emera Incorporated | - | - | - | - | 125.3 | 2.2 | 127.5 | |||||||||||||||||||||
Other comprehensive income (loss), net of tax expense of $1.1 million | - | - | - | (12.3 | ) | - | - | (12.3) | ||||||||||||||||||||
Issuance of common stock, net of issuance costs | 196.0 | - | - | - | - | - | 196.0 | |||||||||||||||||||||
Additional Investment | - | - | - | - | - | 59.7 | 59.7 | |||||||||||||||||||||
Cash dividends declared on preferred stock ($0.2750/share) | - | - | - | - | (1.7 | ) | - | (1.7) | ||||||||||||||||||||
Cash dividends declared on common stock ($0.3250/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 | ||||||||||||||||||||
Preferred dividends paid by subsidiaries to non-controlling interest | - | - | - | - | - | (2.0 | ) | (2.0) | ||||||||||||||||||||
Balance, March 31, 2011 | $ | 1,343.6 | $ | 146.7 | $ | 3.4 | $ | (576.5 | ) | $ | 739.7 | $ | 214.1 | $ | 1,871.0 |
The accompanying notes are an integral part of these condensed consolidated financial statements.
44
Emera Incorporated
Notes to the Condensed Consolidated Financial Statements (Unaudited)
As at March 31, 2012 and 2011
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The significant accounting policies for both the regulated and non-regulated operations of Emera Incorporated are as follows:
A. Nature of Operations
Emera Incorporated is an energy and services company which invests in electricity generation, transmission and distribution, gas transmission and utility energy services.
Emera’s primary rate-regulated subsidiaries at March 31, 2012 included the following:
• | Nova Scotia Power Inc. (“NSPI”), a fully-integrated electric utility and the primary electricity supplier in Nova Scotia serving approximately 494,000 customers; |
• | Bangor Hydro Electric Company (“Bangor Hydro”) and Maine Public Service Company (“MPS”), which together provide transmission and distribution services to approximately 156,000 customers in Maine; |
• | an 80.0 percent interest in Light & Power Holdings Ltd. (“LPH”), the parent of The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated utility and sole provider of electricity on the island of Barbados serving approximately 123,000 customers; |
• | a 50.0 percent direct and 30.4 percent indirect interest (through ICD Utilities Limited (“ICDU”)) in Grand Bahama Power Company Limited (“GBPC”), a vertically-integrated utility and sole provider of electricity on Grand Bahama Island serving approximately 19,000 customers; and |
• | Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145 kilometer pipeline carrying re-gasified liquefied natural gas from Saint John, New Brunswick to the United States border under a 25 year firm service agreement with Repsol Energy Canada (“REC”). |
Emera Incorporated and its subsidiaries (“Emera” or the “Company”) also own investments in other energy related companies, including:
• | Emera Energy Services, a physical energy business which purchases and sells natural gas and electricity and provides related energy asset management services; |
• | Bayside Power Limited Partnership (“Bayside Power”), a 260-megawatt (“MW”) electricity generating facility in Saint John, New Brunswick ; |
• | Emera Utility Services Inc. (“EUS”), a utility services contractor operating in Atlantic Canada and the Bahamas; |
• | a 50 percent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 600-MW pumped storage hydro-electric facility in northern Massachusetts; |
• | Emera Newfoundland & Labrador Holdings Inc. (“ENL”), a development project focused on transmission investments related to the proposed 824-MW hydro-electric generating facility at Muskrat Falls in Labrador, scheduled to be in service in 2017; |
• | 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 15.3 percent indirect interest, through LPH, in St. Lucia Electricity Services Limited (“Lucelec”), a vertically-integrated regulated electric utility on the Caribbean island of St. Lucia; |
• | a 49.999 percent interest in California Pacific Utilities Ventures, LLC, (“CPUV”); |
• | a 5.8 percent investment in Algonquin Power & Utilities Corp (“APUC”); |
45
• | a 37.7 percent investment in Atlantic Hydrogen Inc. (“AHI”); and |
• | other investments. |
B. Basis of Presentation
These unaudited condensed consolidated financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). These unaudited condensed consolidated financial statements do not contain all disclosures required by USGAAP for annual audited financial statements. Accordingly, the financial statements should be read in conjunction with Emera Incorporated’s annual audited financial statements as at and for the year ended December 31, 2011.
In the opinion of management, these unaudited condensed consolidated financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera Incorporated. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2012.
All dollar amounts are presented in Canadian dollars, unless otherwise indicated.
C. Principles of Consolidation
The consolidated financial statements of Emera Incorporated include the accounts of Emera Incorporated and its majority-owned subsidiaries, and a variable interest entity where Emera is the primary beneficiary. All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes that the elimination of these transactions would understate property, plant and equipment, operating, maintenance and general expenses, or regulated fuel for generation and purchased power.
Where Emera does not control an investment, but has significant influence over operating and financing policies of the investee, the investment is accounted for under the equity method. The cost method of accounting is used for investments where Emera does not have significant influence over the operating and financial policies of the investee.
D. 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.
E. Seasonal Nature of Operations
Interim results are not necessarily indicative of results for the full year primarily due to seasonal factors. Electricity sales and related generation vary significantly over the year; Q1 and Q4 are typically the strongest periods, reflecting colder weather and fewer daylight hours in the winter season in northeast North America, where a substantial portion of Emera’s electricity business is located.
46
F. Regulatory Matters
Regulatory accounting applies where rates are established by, or subject to approval by, an independent third party regulator; are designed to recover the costs of providing the regulated products or services; and it is reasonable to assume rates are set at levels such that the costs can be charged to and collected from customers.
Regulatory assets represent incurred costs that have been deferred because it is probable that they will be recovered through future rates or tolls collected from customers. Management believes that existing regulatory assets are probable of recovery either because the Company received specific approval from the appropriate regulator, or due to regulatory precedent set for similar circumstances. If management no longer considers it probable that an asset will be recovered, the deferred costs are charged to income.
Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for previous collections. If management no longer considers it probable that a liability will be settled, the related amount is recognized in income.
For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective regulator.
G. Allowance for Funds Used During Construction
Allowance for Funds Used During Construction (“AFUDC”) represents the cost of financing regulated construction projects and is capitalized to the cost of property, plant and equipment. As approved by their respective regulator, NSPI, Bangor Hydro, MPS, GBPC, and Brunswick Pipeline include an equity cost component in AFUDC in addition to a charge for borrowed funds. AFUDC is a non-cash item; cash is realized under the rate-making process over the service life of the related property, plant and equipment through future revenues resulting from a higher rate base and recovery of higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to “Interest expense, net”, while the equity component is included in “Other income (expenses), net”. AFUDC is calculated using a weighted average cost of capital, as per the method of calculation approved by the respective regulator, and is compounded semi-annually. The annual AFUDC consisted of the following:
2012 | 2011 | |||||||||||||
Total | Debt Component | Equity Component | Total | Debt Component | Equity Component | |||||||||
NSPI | 7.97% | 4.15% | 3.82% | 7.87% | 4.06% | 3.81% | ||||||||
Bangor Hydro | 8.87% | 2.55% | 6.32% | 9.00% | 2.60% | 6.40% | ||||||||
MPS | 8.89% | 2.87% | 6.02% | 7.42% | 2.37% | 5.05% | ||||||||
GBPC | 10.00% | 4.32% | 5.68% | 10.00% | 4.32% | 5.68% |
2. FUTURE ACCOUNTING PRONOUNCEMENTS
Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities, Accounting Standards Update (“ASU”) Number (“No.”) 2011-11
In December 2011, The Financial Accounting Standards Board (“FASB”) issued an accounting standards update which requires companies to disclose gross information and net information about both instruments and transactions eligible for offset in the statement of financial positions and instruments and transactions subject to an agreement similar to a master netting arrangement to
47
enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU No. 2011-11 is effective for fiscal years, and interim periods within those years, beginning on or after January 1, 2013 with required disclosures made retrospectively for all comparative periods presented. The Company is currently evaluating the impact that the adoption will have in the financial statements.
3. SEGMENT INFORMATION
Emera is an energy and services company which invests in electricity generation, transmission and distribution, gas transmission and utility energy services. Emera manages its reportable segments separately due to their different geographical, operating and regulatory environments. Segments are reported based on each subsidiary’s contribution of revenues, net income and total assets.
As at March 31, 2012, Emera has five reportable segments, specifically:
• | NSPI; |
• | Maine Utility Operations (Bangor Hydro and MPS); |
• | Caribbean Utility Operations (BLPC, GBPC and Lucelec); |
• | Brunswick Pipeline; and |
• | Other (Emera Energy Services, EUS, M&NP, other strategic investments, holding companies, and inter-segment eliminations). |
millions of Canadian dollars | NSPI | Maine Utility Operations | Caribbean Utility Operations | Brunswick Pipeline | Other and Eliminations | Total | ||||||||||||||||||
For the three months ended March 31, 2012 |
| |||||||||||||||||||||||
Operating revenues from external customers (1) | $ | 360.7 | $ | 51.2 | $ | 101.6 | $ | 12.4 | $ | 30.5 | $ | 556.4 | ||||||||||||
Inter-segment revenues (1) | 0.2 | - | - | - | 11.4 | 11.6 | ||||||||||||||||||
Total operating revenues | 360.9 | 51.2 | 101.6 | 12.4 | 41.9 | 568.0 | ||||||||||||||||||
Net income attributable to common shareholders | 59.6 | 8.5 | 3.9 | 4.8 | 3.4 | 80.2 | ||||||||||||||||||
For the three months ended March 31, 2011 |
| |||||||||||||||||||||||
Operating revenues from external customers (1) | $ | 368.6 | $ | 52.5 | $ | 73.6 | $ | 12.4 | $ | 43.2 | $ | 550.3 | ||||||||||||
Inter-segment revenues (1) | 0.2 | - | - | - | 4.1 | 4.3 | ||||||||||||||||||
Total operating revenues | 368.8 | 52.5 | 73.6 | 12.4 | 47.3 | 554.6 | ||||||||||||||||||
Net income attributable to common shareholders | 63.6 | 9.4 | 29.6 | 4.7 | 16.3 | 123.6 |
(1) All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes that the elimination of these transactions would understate property, plant and equipment, operating, maintenance and general expenses, or regulated fuel for generation and purchased power. Eliminated transactions are included in determining reportable segments.
4. REGULATED FUEL AND FIXED COST ADJUSTMENTS
Regulated fuel and fixed cost adjustments consisted of the following:
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2012 | 2011 | ||||||
Regulated Fuel Adjustment | $ | 22.1 | $ | (5.8) | ||||
Regulated Fixed Cost Adjustment | (11.0 | ) | - | |||||
$ | 11.1 | $ | (5.8) |
48
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, specifically, and as detailed in the table below:
• | The difference between actual fuel costs and amounts recovered from customers in the current year. This amount is deferred to a FAM regulatory asset in “Regulatory assets” or a FAM regulatory liability in “Regulatory liabilities”. |
• | The recovery from (rebate to) customers of over (under) recovered costs from prior years. |
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2012 | 2011 | ||||||
Over (Under) recovery of current year fuel costs | $ | �� 2.4 | $ | (14.0) | ||||
Recovery from (Rebate to) customers of prior years’ fuel costs | 19.7 | 8.2 | ||||||
Regulated fuel adjustment | $ | 22.1 | $ | (5.8) |
Since inception in 2009, the FAM was net of the incentive component, whereby NSPI retained or absorbed 10 percent of the over or under recovered amount to a maximum of $5 million. In November 2011, the UARB suspended the FAM incentive component for 2012 as part of the settlement agreement in the 2012 General Rate Application (“GRA”) Decision.
In December 2011, the UARB approved NSPI’s customer rates associated with the 2012 FAM adjustment related to the recovery of prior period fuel costs. The recovery of these costs began January 1, 2012. The approved customer rates seek to recover $69.0 million of prior years’ unrecovered fuel costs in 2012.
As at March 31, 2012, the FAM regulatory asset was $73.2 million (December 31, 2011 – $93.7 million) and is classified in “Regulatory assets” on the Consolidated Balance Sheets. The FAM regulatory asset includes amounts recognized as a fuel adjustment and associated interest that is included in “Interest expense, net” on the Consolidated Statements of Income.
NSPI has recognized a deferred income tax recovery related to the regulated fuel adjustment based on NSPI’s enacted statutory tax rate. As at March 31, 2012, NSPI’s deferred income tax liability related to the FAM was $22.7 million (December 31, 2011 – $29.0 million).
Regulated Fixed Cost Adjustment
The regulated fixed cost adjustment related to NSPI reflects the fixed cost recovery deferral (“FCR”) as approved in the 2012 GRA Decision by the UARB for fiscal 2012. The FCR is intended to address uncertainty associated with the operations of two large industrial customers currently experiencing financial challenges. In the event that actual sales to these customers are less than expected when rates were set, the resultant shortfall in contribution toward non-fuel expenses will be deferred for future recovery. The FCR is effective January 1, 2012, and the recovery from customers will be determined in Q4 2012 through a GRA or FAM proceeding.
As at March 31, 2012, the FCR was $11.1 million (December 31, 2011 – nil) and is classified in “Regulatory assets” on the Consolidated Balance Sheets. The FCR regulatory asset includes amounts recognized as a fixed cost adjustment and associated interest that is included in “Interest expense, net” on the Consolidated Statements of Income.
NSPI has recognized a deferred income tax expense related to the FCR based on NSPI’s enacted statutory tax rate. As at March 31, 2012, NSPI’s deferred income tax liability related to the FCR was $3.4 million (December 31, 2011 – nil).
49
5. OTHER INCOME (EXPENSES), NET
Other income (expenses), net consisted of the following:
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2012 | 2011 | ||||||
Gain on business acquisition (1) | $ | - | $ | 28.2 | ||||
Gain on exchange of subscription receipts to common shares of APUC (2) | - | 15.1 | ||||||
Allowance for equity funds used during construction | 3.8 | 2.4 | ||||||
Amortization of defeasance costs | (3.0 | ) | (3.0) | |||||
Foreign exchange gains (losses) | 0.2 | (0.4) | ||||||
Foreign exchange gains (losses) recovered through the FAM | (0.4 | ) | (1.3) | |||||
Other | 0.9 | 0.6 | ||||||
$ | 1.5 | $ | 41.6 |
(1) Emera’s interest in LPH was acquired in two tranches in Q2 2010 and Q1 2011 giving rise to non-taxable gains.
(2) 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 | 2012 | 2011 | ||||||
Interest on debt (1) | $ | 45.2 | $ | 43.7 | ||||
Allowance for borrowed funds used during construction | (3.0 | ) | (2.3) | |||||
Interest revenue | (2.0 | ) | (2.1) | |||||
Other | 1.7 | 1.6 | ||||||
$ | 41.9 | $ | 40.9 |
(1) Interest debt includes amortization of debt financing costs, premiums and discounts.
7. INCOME TAXES
Income tax expense for the three months ended March 31, 2012 was $6.8 million (2011 – $2.7 million). Income taxes are higher in 2012 compared to 2011 primarily due to decreased accelerated tax deductions related to property, plant and equipment, partially offset by increased tax deductions related to pension and a decrease to income before the provision of taxes.
The Company’s effective tax rate for the three months ended March 31, 2012 and March 31, 2011 was 7.4 percent and 2.1 percent, respectively. The effective tax rates for the three months ended March 31, 2012 and March 31, 2011 were lower than the 2012 and 2011 statutory income tax rates of 31.0 percent and 32.5 percent, respectively, primarily due to the effect of deferred income taxes on regulated income being deferred to regulatory assets and regulatory liabilities and therefore not affecting tax expense.
50
8. 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) | 2012 | 2011 | ||||||
Numerator | ||||||||
Net income attributable to common shareholders | $ | 80.2 | $ | 123.6 | ||||
Preferred stock dividends of subsidiary | 2.0 | 2.0 | ||||||
Diluted numerator | 82.2 | 125.6 | ||||||
Denominator | ||||||||
Weighted average shares of common stock outstanding | 123.0 | 115.9 | ||||||
Weighted average DSUs outstanding | 0.6 | 0.5 | ||||||
Weighted average shares of common stock outstanding – basic | 123.6 | 116.4 | ||||||
Effect of dilutive securities | 4.0 | 4.3 | ||||||
Stock-based compensation and employee common share purchase plan | 0.9 | 1.1 | ||||||
Weighted average shares of common stock outstanding – diluted | 128.5 | 121.8 | ||||||
Earnings per common share | ||||||||
Basic | $ | 0.65 | $ | 1.06 | ||||
Diluted (1) | $ | 0.64 | $ | 1.03 |
(1) The calculation of diluted earnings per share for the three months ended March 31, 2012 excluded the impact of nil (2011 – $0.2 million) of unexercised stock options that had an anti-dilutive effect.
9. RECEIVABLES, NET
Receivables, net consisted of the following:
As at | March 31 | December 31 | ||||||
millions of Canadian dollars | 2012 | 2011 | ||||||
Customer accounts receivable – billed | $ | 298.7 | $ | 310.7 | ||||
Customer accounts receivable – unbilled | 131.3 | 133.6 | ||||||
Total customer accounts receivable | 430.0 | 444.3 | ||||||
Allowance for doubtful accounts | (14.0 | ) | (12.8) | |||||
Customer accounts receivable, net | 416.0 | 431.5 | ||||||
Other | 42.7 | 28.1 | ||||||
$ | 458.7 | $ | 459.6 |
10. INVENTORY
Inventory consisted of the following:
As at | March 31 | December 31 | ||||||
millions of Canadian dollars | 2012 | 2011 | ||||||
Fuel | $ | 123.4 | $ | 134.6 | ||||
Materials | 66.2 | 64.2 | ||||||
$ | 189.6 | $ | 198.8 |
51
11. AVAILABLE-FOR-SALE INVESTMENTS
The available-for-sale investments consist primarily of investments in debt and equity securities held in trust on behalf of BLPC’s SIF for the purpose of building an insurance fund to cover risk against damage and consequential loss to certain of BLPC’s generating, transmissions and distribution systems. The SIF Fund assets are not available to the Company for use in its operations.
Emera has classified these investments as available-for-sale and recorded all such investments at their fair market value as at March 31, 2012.
Available-for-sale financial assets include the following:
As at millions of Canadian dollars | March 31 2012 | December 31 2011 | ||||||
Common shares | $ | 4.3 | $ | 1.3 | ||||
Mutual funds | 19.5 | 17.8 | ||||||
Corporate bonds, debentures, short and medium term notes | 26.6 | 27.7 | ||||||
Government bonds | 7.6 | 7.8 | ||||||
$ | 58.0 | $ | 54.6 |
The change in available-for-sale assets is as follows:
As at millions of Canadian dollars | March 31 2012 | December 31 2011 | ||||||
Balance, beginning of the year | $ | 54.6 | $ | 0.8 | ||||
Resulting from acquisitions | - | 53.5 | ||||||
Additions, net of foreign exchange loss | 3.9 | 36.5 | ||||||
Disposals | (0.5 | ) | (35.8) | |||||
$ | 58.0 | $ | 55.0 | |||||
Change in fair value | ||||||||
Loss (Gain) recognized in regulatory liability | 0.7 | (0.1) | ||||||
Gain (Loss) recognized in other comprehensive income during the period | (0.7 | ) | (0.3) | |||||
$ | - | $ | (0.4) | |||||
Balance, end of the period | $ | 58.0 | $ | 54.6 |
There were no impairment provisions for available-for-sale investments for the three months ended March 31 2012 or the year ended December 31, 2011.
The maturity profile of debt securities included in the available-for-for-sale assets is as follows:
As at millions of Canadian dollars | March 31 2012 | December 31 2011 | ||||||
Maturity within 1 year | $ | 10.4 | $ | 12.7 | ||||
Maturity in 1-5 years | 23.8 | 22.8 | ||||||
$ | 34.2 | $ | 35.5 |
The maximum exposure to credit risk at the reporting date is the carrying value of the debt securities. None of these financial instruments are either past due or impaired.
52
12. ACQUISITIONS
Light & Power Holdings Ltd.
On January 25, 2011, Emera acquired 7.2 million shares of LPH, the parent company of BLPC, a vertically-integrated utility and the sole provider of electricity on the island of Barbados with a franchise to produce, transmit and distribute electricity on the island until 2028, for total cash consideration of $92.6 million CAD ($92.8 million USD). As a result, Emera became the majority shareholder of LPH, with a total interest of 80.1 percent. This investment was made to increase Emera’s regulated transmission, distribution and generation portfolio.
Prior to this transaction, Emera owned 38.3 percent of LPH with a carrying value of $113.5 million CAD ($113.8 million USD). The fair value of Emera’s interest in LPH immediately prior to the acquisition date was $84.8 million CAD ($85.0 million USD).
The fair value of the assets of a regulated utility are generally deemed to equal book value (rate base) given the regulated utility’s earnings are a function of its rate base, as determined by the regulator. The purchase price was negotiated between arms-length parties. The differential between the two amounts resulted in Emera recording a gain on acquisition of $ 28.2 million, which Emera has recorded as a non-taxable gain in “Other income (expenses), net” on Emera’s Consolidated Statements of Income for the year ended December 31, 2011.
The valuation technique used to measure the acquisition-date fair value of the assets and liabilities of LPH was book value for regulated assets given the regulatory environment in which BLPC operates. Non-regulated assets were measured based on recent transactions. Accordingly, a third party valuation of assets and liabilities was not performed.
The purchase price allocation has been finalized. The total purchase price has been allocated to the fair value of assets and liabilities as follows:
millions of Canadian dollars | ||||
Cash and cash equivalents | $ | 58.4 | ||
Restricted cash | 12.3 | |||
Receivables, net | 23.4 | |||
Income tax receivable | 0.2 | |||
Inventory | 16.3 | |||
Prepaid expenses | 2.9 | |||
Property, plant and equipment | 292.0 | |||
Available-for-sale investments | 52.5 | |||
Other non-current assets | 1.6 | |||
Current portion of long-term debt | (7.5) | |||
Account payable | (33.7) | |||
Other current liabilities | (5.3) | |||
Long-term debt | (43.1) | |||
Deferred income taxes | (9.5) | |||
Regulatory liabilities | (62.7) | |||
ARO | (2.2) | |||
Other long-term liabilities | (2.5) | |||
Gain on business acquisition (1) | (28.2) | |||
Non-controlling interest | (58.2) | |||
Total purchase consideration | $ | 206.7 |
(1) The gain shown above represents the net effect of the gain on acquisition of $56.3 million net of a loss of $28.1 million on a business combination achieved in stages, which requires the revaluation of the existing interest to the implied value from the second investment at the date of acquiring control. The gain is included in “Other income (expenses) net” in the Consolidated Statements of Income.
53
The Company has included operating revenues of $282.4 million and net income attributable to common shareholders of $12.0 million for BLPC in its consolidated net income attributable to common shareholders for fiscal 2011 related to the period subsequent to January 25, 2011.
The Company also incurred $2.0 million in acquisition-related costs of which $0.5 million was recorded in 2010 and $1.5 million was recorded in 2011. These costs are included in “Operating, maintenance and general expense” in the Consolidated Statements of Income.
13. OTHER CURRENT LIABILITIES
Other current liabilities consisted of the following:
As at millions of Canadian dollars | March 31 2012 | December 31 2011 | ||||||
Accrued charges | $ | 62.8 | $ | 69.0 | ||||
Accrued interest on long-term debt | 49.8 | 38.0 | ||||||
Sales taxes payable | 24.1 | 12.8 | ||||||
Dividends payable | 2.0 | 2.0 | ||||||
Other | 7.6 | 5.4 | ||||||
$ | 146.3 | $ | 127.2 |
14. LONG-TERM DEBT
GBPC
On January 25, 2012, GBPC entered into an unsecured credit agreement with Scotiabank (Bahamas) Limited in the amount of $56.2 million USD. The proceeds of the credit agreement will be used to finance the construction of a 52-MW power plant on Grand Bahama Island. The credit agreement bears interest at a rate of the three month LIBOR rate plus 1.2 percent and is repayable in forty equal, consecutive quarterly installments over a ten year period. The payments commence at the earlier of six months after the completion of the construction of the power plant or January 31, 2013.
Bangor Hydro
On January 31, 2012, Bangor Hydro completed the issuance of an unsecured $70.0 million USD senior note. The Series 2012-A Senior Note bears interest at a rate of 3.61 percent per annum until January 31, 2022. The net proceeds of the note offering were used to repay borrowings under the revolving credit facility.
LPH
On February 9, 2012, LPH entered into a secured credit agreement with The Bank of Nova Scotia in the amount of USD $14.2 million. The proceeds of the credit agreement were used to partially finance the purchase of a 19.1 percent interest in Lucelec from a wholly-owned subsidiary of Emera. The credit agreement bears interest at a rate of the three month LIBOR plus 1.05 percent and is repayable in six equal, consecutive semi-annual installments over a three year period. The payments commence six months after the initial drawdown. LPH has provided a cash deposit of $14.2 million ($28.4 million Barbadian dollars) and an unlimited guarantee as security for the credit agreement.
NSPI
On March 6, 2012, NSPI completed the issuance of $250 million Series Y Medium-Term Notes. The Series Y Notes bear interest at a rate of 4.15 percent per annum until March 5, 2042. The net proceeds of the note offering were used to repay short-term borrowings and for general corporate purposes.
54
15. DERIVATIVE INSTRUMENTS
The Company enters into futures, forwards, swaps and option contracts as part of its risk management strategy to limit exposure to:
• | commodity price fluctuations related to the purchase and sale of commodities in the course of normal operations; |
• | foreign exchange fluctuations on foreign currency denominated purchases and sales; and |
• | interest rate fluctuations on debt securities. |
The Company also enters into physical contracts for energy commodities. Collectively, these contracts are considered “derivatives”. The Company accounts for derivatives under one of the following four approaches:
1. | Physical contracts that meet the normal purchases normal sales (“NPNS”) exception are not recognized on the balance sheet; they are recognized in income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. The Company continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exception if the criteria are no longer met. |
2. | Derivatives that qualify for hedge accounting are recorded at fair value on the balance sheet. Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge the identified cash flow risk both at the inception and over the term of the derivative. Specifically for cash flow hedges, the effective portion of the change in the fair value of derivatives is deferred to AOCL and recognized in income in the same period the related hedged item is realized. Any ineffective portion of the change in fair value from cash flow hedges is recognized in net income in the reporting period. |
Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.
3. | Derivatives entered into by NSPI, that are documented as economic hedges, and for which the NPNS exception has not been taken, receive regulatory deferral as approved by the UARB. These derivatives are recorded at fair value on the balance sheet as derivative assets or liabilities. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized when the derivatives settle. Management believes that any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates through the FAM. |
4. | Derivatives that do not meet any of the above criteria are designated as Held-for-trading (“HFT”) and are recognized on the balance sheet at fair value. All gains and losses are recognized in net income of the period. The Company has not elected to designate any derivatives to be included in the HFT category when another accounting treatment applies. |
55
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 2012 | December 31 2011 | March 31 2012 | December 31 2011 | ||||
Current | ||||||||
Cash flow hedges | ||||||||
Power & gas swaps | $ - | $ - | $ 6.4 | $ 8.1 | ||||
Foreign exchange forwards | 3.0 | 2.7 | 0.5 | 0.5 | ||||
3.0 | 2.7 | 6.9 | 8.6 | |||||
Regulatory deferral | ||||||||
Commodity swaps and forwards | ||||||||
Coal purchases | 5.2 | 5.4 | 0.1 | 0.1 | ||||
Natural gas purchases and sales | - | 0.7 | 39.0 | 33.5 | ||||
Foreign exchange forwards | 2.7 | 6.0 | 2.5 | - | ||||
Physical natural gas purchases and sales | 4.2 | 4.2 | 0.4 | 0.1 | ||||
12.1 | 16.3 | 42.0 | 33.7 | |||||
HFT derivatives | ||||||||
Power swaps and physical contracts | 2.5 | 1.4 | 1.8 | 1.2 | ||||
Natural gas swaps, futures, forwards and physical contracts | 7.2 | 10.9 | 7.7 | 10.6 | ||||
9.7 | 12.3 | 9.5 | 11.8 | |||||
Total gross current derivatives | 24.8 | 31.3 | 58.4 | 54.1 | ||||
Impact of master netting agreements with intent to settle net or simultaneously | (1.8) | (4.0) | (1.8) | (4.0) | ||||
Total current derivatives | 23.0 | 27.3 | 56.6 | 50.1 | ||||
Long-term | ||||||||
Cash flow hedges | ||||||||
Power swaps | 0.4 | 0.2 | 10.0 | 12.8 | ||||
Interest rate swaps | - | - | 5.7 | 6.2 | ||||
Foreign exchange forwards | 2.9 | 2.8 | 0.3 | 0.2 | ||||
3.3 | 3.0 | 16.0 | 19.2 | |||||
Regulatory deferral | ||||||||
Commodity swaps and forwards | ||||||||
Coal purchases | 5.3 | 6.7 | - | - | ||||
Natural gas purchases and sales | - | - | 5.2 | 5.1 | ||||
Foreign exchange forwards | 15.1 | 18.2 | 7.6 | 7.9 | ||||
Physical natural gas purchases and sales | 2.3 | 3.7 | - | - | ||||
22.7 | 28.6 | 12.8 | 13.0 | |||||
HFT derivatives | ||||||||
Power swaps and physical contracts | 0.9 | 0.9 | 0.6 | 0.8 | ||||
Natural gas swaps, futures, forwards and physical contracts | 7.0 | 6.8 | 6.1 | 5.4 | ||||
7.9 | 7.7 | 6.7 | 6.2 | |||||
Total gross long-term derivatives | 33.9 | 39.3 | 35.5 | 38.4 | ||||
Impact of master netting agreements with intent to settle net or simultaneously | (1.5) | 0.3 | (1.5) | 0.3 | ||||
Total long-term derivatives | 32.4 | 39.6 | 34.0 | 38.7 | ||||
Total derivatives | $ 55.4 | $ 66.9 | $ 90.6 | $ 88.8 |
Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.
56
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 and capital projects denominated in foreign currency for Brunswick Pipeline and Bayside Power, respectively. 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 following table shows the amounts related to cash flow hedges recorded in AOCL and income for the period:
For the | Three months ended March 31 | Three months ended March 31 | ||||||||||||||||||||||
millions of Canadian dollars | 2012 | 2011 | ||||||||||||||||||||||
Power and Gas Swaps | Interest Rate Swaps | Foreign Exchange Forwards | Power and Gas Swaps | Interest Rate Swaps | Foreign Exchange Forwards | |||||||||||||||||||
Unrealized gain (loss) in non-regulated fuel and purchased power – ineffective portion | $ | (0.1 | ) | $ | - | $ | - | $ | (0.6 | ) | $ | - | $ | - | ||||||||||
Realized gain (loss) in non-regulated fuel and purchased power | (2.0 | ) | - | - | (1.0 | ) | - | - | ||||||||||||||||
Realized gain (loss) in regulated operating revenue | - | - | 0.8 | - | - | 0.8 | ||||||||||||||||||
Realized gain (loss) in other income, (expenses), net | - | - | (0.2 | ) | - | - | (0.1 | ) | ||||||||||||||||
Total gains (losses) in income | $ | (2.1 | ) | $ | - | $ | 0.6 | $ | (1.6 | ) | $ | - | $ | 0.7 | ||||||||||
Total unrealized gain (loss) in AOCL – effective portion, net of tax | $ | (4.9 | ) | $ | 0.1 | $ | 0.4 | $ | 1.0 | $ | 0.2 | $ | 1.6 |
The Company expects $8.6 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, 2012, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:
millions | 2012 | 2013 | 2014 | 2015 | 2016 | 2017 | ||||||||||||||||||
Power swaps (megawatt hours (“MWh”)) purchases | 0.3 | 0.3 | 0.3 | 0.3 | 0.3 | 0.3 | ||||||||||||||||||
Gas swaps (Mmbtu) purchases | 2.7 | - | - | - | - | - | ||||||||||||||||||
Foreign exchange forwards (EURO) purchases | 9.6 | - | - | 2.8 | - | - | ||||||||||||||||||
Foreign exchange forwards (USD) sales | $ | 40.6 | $ | 48.0 | $ | 15.0 | $ | 9.0 | $ | 6.0 | $ | - |
In addition, the Company has interest rate swaps on long-term debt of $13.6 million until 2021 and $9.0 million until 2025.
Regulatory Deferral
As previously noted, NSPI receives approval from the UARB for regulatory deferral of gains and losses on certain derivatives documented as economic hedges, including certain physical contracts that do not qualify for the NPNS exemption.
57
The Company has recorded the following realized and 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 2012 | March 31 2011 | March 31 2012 | March 31 2011 | ||||||||||||
Current | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | $ | - | $ | (1.0 | ) | $ | 0.3 | $ | (0.6) | |||||||
Natural gas purchases and sales | 5.7 | (8.8 | ) | 0.4 | (1.5) | |||||||||||
Heavy Fuel Oil (“HFO”) purchases | - | (1.3 | ) | - | 1.9 | |||||||||||
Foreign exchange forwards | 2.5 | 3.2 | 3.2 | 2.0 | ||||||||||||
Physical natural gas purchases and sales | 0.4 | 0.1 | - | (0.3) | ||||||||||||
Long-term | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | - | - | 1.4 | (2.9) | ||||||||||||
Natural gas purchases and sales | 0.1 | (1.5 | ) | - | (0.1) | |||||||||||
Foreign exchange forwards | (0.3 | ) | 10.5 | 3.1 | 2.2 | |||||||||||
Physical natural gas purchases and sales | - | - | 1.4 | 1.2 |
Regulatory Impact Recognized in Net Income
The Company recognized the following gains (losses) related to derivatives receiving regulatory deferral as follows:
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2012 | 2011 | ||||||
Regulated fuel for generation and purchased power | $ | (9.4 | ) | $ | (15.6) | |||
Net gains (losses) | $ | (9.4 | ) | $ | (15.6) |
Commodity Swaps and Forwards
As at March 31, 2012, the Company had the following notional volumes of outstanding commodity swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below:
2012 | 2013 | 2014 | ||||
millions | Purchases | Purchases | Purchases | |||
Coal (metric tonnes) | 0.4 | 0.3 | 0.1 | |||
Natural gas (Mmbtu) | 15.4 | 13.2 | 0.5 |
Foreign Exchange Swaps and Forwards
As at March 31, 2012, the Company had the following notional volumes of foreign exchange swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below:
2012 | 2013 | 2014 | 2015 | 2016 | ||||||||||||||||||
Fuel purchases exposure (millions of US dollars) | $ | 177.0 | $ | 212.0 | $ | 210.0 | $ | 210.0 | $ | 120.0 | ||||||||||||
Weighted average rate | 0.9923 | 1.0251 | 1.0106 | 1.0090 | 0.9814 | |||||||||||||||||
% of USD requirements | 73.8% | 70.4% | 66.0% | 66.0% | 37.7% |
58
Held-for-Trading Derivatives
In the ordinary course of its business, Emera enters into physical contracts for the purchase and sale of natural gas; and power and natural gas swaps, forwards, and futures to economically hedge those physical contracts. These derivatives are all considered HFT.
The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives:
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2012 | 2011 | ||||||
Power swaps and physical contracts in non-regulated operating revenues | $ | 0.1 | $ | (1.0) | ||||
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues | 4.9 | 7.6 | ||||||
Foreign exchange forwards in other income (expenses), net | - | 0.3 | ||||||
$ | 5.0 | $ | 6.9 |
As at March 31, 2012, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:
millions | 2012 | 2013 | 2014 | 2015 | 2016 | 2017 | ||||||||||||||||||
Natural gas purchases (Mmbtu) | 71.1 | 45.6 | 29.8 | 22.4 | 5.8 | 0.4 | ||||||||||||||||||
Natural gas sales (Mmbtu) | 37.4 | 20.4 | 7.3 | 1.8 | - | - | ||||||||||||||||||
Power purchases (MWh) | 0.5 | - | - | - | - | - | ||||||||||||||||||
Power sales (MWh) | 0.5 | - | - | - | - | - |
Credit Risk
The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits and derivative assets. Credit risk is the potential loss from counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties and deposits or collateral are requested on any high risk accounts.
The Company assesses the potential for credit losses on a regular basis, and where appropriate, maintains provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability. The Company assesses credit risk internally for counterparties that are not rated.
It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, foreign exchange and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The Company also obtains cash deposits from electric customers. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company.
59
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.
Cash Collateral
Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the fair value amounts of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables, net” and obligations to return cash collateral are recognized in “Accounts payable”.
The Company’s cash collateral positions consisted of the following:
As at millions of Canadian dollars | March 31 2012 | December 31 2011 | ||
Cash collateral provided to others | $ 46.1 | $ 71.6 | ||
Cash collateral received from others | 10.4 | 5.7 |
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 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, 2012, the total fair value of these derivatives, in a net liability position, is $ 90.6 million (December 31, 2011 – $ 88.8 million). If the credit ratings of the Company were reduced below investment grade the full value of the net liability position could be required to be posted as collateral for these derivatives.
16. FAIR VALUE MEASUREMENTS
The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exception (see note 15), and uses a market approach to do so. The three levels of the fair value hierarchy are defined as follows:
Level 1 Valuations – Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities.
Level 2 Valuations – Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses.
Level 3 Valuations – Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally-developed inputs. The primary reasons for a Level 3 classification are as follows:
• | While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials. |
60
• | The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term. |
• | The valuations of certain transactions were based on internal models, although quoted prices were utilized in the valuations. |
Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
The following tables set out the classification of the methodology used by the Company to fair value its derivatives:
As at | March 31, 2012 | |||||||||||||||
millions of Canadian dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power and gas swaps | $ | �� 0.4 | $ | - | $ | - | $ | 0.4 | ||||||||
Foreign exchange forwards | - | 5.9 | - | 5.9 | ||||||||||||
0.4 | 5.9 | - | 6.3 | |||||||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | - | 10.5 | - | 10.5 | ||||||||||||
Foreign exchange forwards | - | 17.8 | - | 17.8 | ||||||||||||
Physical natural gas purchases and sales | - | - | 6.4 | 6.4 | ||||||||||||
- | 28.3 | 6.4 | 34.7 | |||||||||||||
HFT derivatives | ||||||||||||||||
Power swaps and physical contracts | - | - | 2.4 | 2.4 | ||||||||||||
Natural gas swaps, futures, forwards and physical contracts | - | 9.8 | 2.2 | 12.0 | ||||||||||||
- | 9.8 | 4.6 | 14.4 | |||||||||||||
Total assets | 0.4 | 44.0 | 11.0 | 55.4 | ||||||||||||
Liabilities | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power and gas swaps | 16.4 | - | - | 16.4 | ||||||||||||
Foreign exchange forwards | - | 0.8 | - | 0.8 | ||||||||||||
Interest rate swaps | - | 5.7 | - | 5.7 | ||||||||||||
16.4 | 6.5 | - | 22.9 | |||||||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Natural gas purchases and sales | 44.2 | - | - | 44.2 | ||||||||||||
Foreign exchange forwards | - | 10.1 | - | 10.1 | ||||||||||||
Physical natural gas purchases and sales | - | - | 0.4 | 0.4 | ||||||||||||
44.2 | 10.1 | 0.4 | 54.7 | |||||||||||||
HFT derivatives | ||||||||||||||||
Power swaps and physical contracts | 0.2 | - | 1.3 | 1.5 | ||||||||||||
Natural gas swaps, futures, forwards and physical contracts | 3.0 | 7.6 | 0.9 | 11.5 | ||||||||||||
3.2 | 7.6 | 2.2 | 13.0 | |||||||||||||
Total liabilities | 63.8 | 24.2 | 2.6 | 90.6 | ||||||||||||
Net assets (liabilities) | $ | (63.4 | ) | $ | 19.8 | $ | 8.4 | $ | (35.2) |
61
As at | December 31, 2011 | |||||||||||||||
millions of Canadian dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power and gas swaps | $ | 0.2 | $ | - | $ | - | $ | 0.2 | ||||||||
Foreign exchange forwards | - | 5.5 | - | 5.5 | ||||||||||||
0.2 | 5.5 | - | 5.7 | |||||||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Coal purchases | - | 12.1 | - | 12.1 | ||||||||||||
Natural gas purchases and sales | (0.4) | 0.7 | - | 0.3 | ||||||||||||
HFO purchases | - | 24.2 | - | 24.2 | ||||||||||||
Physical natural gas purchases and sales | - | - | 7.9 | 7.9 | ||||||||||||
(0.4) | 37.0 | 7.9 | 44.5 | |||||||||||||
HFT derivatives | ||||||||||||||||
Power swaps and physical contracts | 0.3 | - | 1.6 | 1.9 | ||||||||||||
Natural gas swaps, futures, forwards and physical contracts | - | 10.4 | 4.4 | 14.8 | ||||||||||||
0.3 | 10.4 | 6.0 | 16.7 | |||||||||||||
Total assets | 0.1 | 52.9 | 13.9 | 66.9 | ||||||||||||
As at | December 31, 2011 | |||||||||||||||
millions of Canadian dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Liabilities | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Power and gas swaps | $ | 20.9 | $ | - | $ | - | $ | 20.9 | ||||||||
Foreign exchange forwards | - | 0.7 | - | 0.7 | ||||||||||||
Interest rate swaps | - | 6.2 | - | 6.2 | ||||||||||||
20.9 | 6.9 | - | 27.8 | |||||||||||||
Regulatory deferral | ||||||||||||||||
Commodity swaps and forwards | ||||||||||||||||
Natural gas purchases and sales | 38.3 | - | - | 38.3 | ||||||||||||
Foreign exchange forwards | - | 7.9 | - | 7.9 | ||||||||||||
Physical natural gas purchases and sales | - | - | 0.1 | 0.1 | ||||||||||||
38.3 | 7.9 | 0.1 | 46.3 | |||||||||||||
HFT derivatives | ||||||||||||||||
Power swaps and physical contracts | 0.3 | - | 1.3 | 1.6 | ||||||||||||
Natural gas swaps, futures, forwards and physical contracts | 2.7 | 7.3 | 3.1 | 13.1 | ||||||||||||
3.0 | 7.3 | 4.4 | 14.7 | |||||||||||||
Total liabilities | 62.2 | 22.1 | 4.5 | 88.8 | ||||||||||||
Net assets (liabilities) | $ | (62.1) | $ | 30.8 | $ | 9.4 | $ | (21.9) |
62
The change in the fair value of the Level 3 financial assets for the three months ended March 31 was as follows:
Regulatory Deferral | Trading Derivatives | |||||||||||||||
millions of Canadian dollars | Physical natural gas purchases and sales | Power | Natural gas | Total | ||||||||||||
Balance, January 1 | $ | 7.9 | $ | 1.6 | $ | 4.4 | $ | 13.9 | ||||||||
Increase (Reduction) in benefit included in regulated fuel for generation and purchased power | (0.8 | ) | - | - | (0.8) | |||||||||||
Unrealized gains (losses) included in regulatory assets or liabilities | (0.7 | ) | - | - | (0.7) | |||||||||||
Total realized and unrealized gains (losses) included in non-regulated operating revenues | - | 0.8 | (2.2 | ) | (1.4) | |||||||||||
Balance, March 31 | $ | 6.4 | $ | 2.4 | $ | 2.2 | $ | 11.0 |
The change in the fair value of the Level 3 financial liabilities for the three months ended March 31 was as follows:
Regulatory deferral | Trading derivatives | |||||||||||||||
millions of Canadian dollars | Physical natural gas purchases and sales | Power | Natural gas | Total | ||||||||||||
Balance, January 1 | $ | 0.1 | $ | 1.3 | $ | 3.1 | $ | 4.5 | ||||||||
Increase (Reduction) in benefit included in regulated fuel for generation and purchased power | (0.1 | ) | - | - | (0.1) | |||||||||||
Unrealized gains (losses) included in regulatory assets or liabilities | 0.4 | - | - | 0.4 | ||||||||||||
Total realized and unrealized gains (losses) included in non-regulated operating revenues | - | - | (2.2 | ) | (2.2) | |||||||||||
Balance, March 31 | $ | 0.4 | $ | 1.3 | $ | 0.9 | $ | 2.6 |
The significant unobservable inputs used in the fair value measurement of Emera’s natural gas and power derivatives includes third-party-sourced-pricing for instruments based on illiquid markets; internally developed correlation factors and basis differentials; probabilities of default; and discount rates. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement.
63
The following table outlines quantitative information about the significant unobservable inputs used in the fair value measurements categorized within Level 3 of the fair value hierarchy:
As at | March 31, 2012 | |||||||||||||||
millions of Canadian dollars | Fair Value | Valuation Technique | Unobservable Input | Range | Weighted average | |||||||||||
Assets | ||||||||||||||||
Regulatory deferral – Physical | $ | 6.4 | Modeled pricing | Third-party pricing | $2.32 - $6.95 | $3.91 | ||||||||||
natural gas purchases and sales | Probability of default | 0.07% - 0.64% | 0.23% | |||||||||||||
HFT derivatives – | 1.3 | Modeled pricing | Third-party pricing | $23.70 - $51.72 | $33.23 | |||||||||||
Power swaps and | Probability of default | 0.14% - 0.17% | 0.15% | |||||||||||||
physical contracts | Discount rate | 0.00% - 2.68% | 0.32% | |||||||||||||
1.1 | Modeled pricing | Third-party pricing | $18.8 - $50.68 | $32.85 | ||||||||||||
Correlation factor | 0.96% - 1.00% | 0.98% | ||||||||||||||
Probability of default | 0.17% - 0.52% | 0.17% | ||||||||||||||
Discount rate | 0.00% - 2.68% | 0.74% | ||||||||||||||
HFT derivatives – | 1.2 | Modeled pricing | Third-party pricing | $2.32 - $4.31 | $3.10 | |||||||||||
Natural gas swaps, | Probability of default | 0.05% - 26.72% | 1.19% | |||||||||||||
futures, forwards and | Discount rate | 0.00% - 0.80% | 0.09% | |||||||||||||
physical contracts | 1.0 | Modeled pricing | Third-party pricing | $2.10 - $5.29 | $2.67 | |||||||||||
Basis adjustment | (0.06%) - 0.36% | (0.03%) | ||||||||||||||
Probability of default | 0.09% - 1.17% | 0.61% | ||||||||||||||
Discount rate | 0.00% - 1.15% | 0.13% | ||||||||||||||
Total assets | 11.0 | |||||||||||||||
Liabilities | ||||||||||||||||
Regulatory deferral – Physical | 0.4 | Modeled pricing | Third-party pricing | $2.32 - $2.64 | $2.52 | |||||||||||
natural gas purchases and sales | Own credit risk | - | 0.17% | |||||||||||||
HFT derivatives – | 1.3 | Modeled pricing | Third-party pricing | $23.70 - $51.72 | $33.25 | |||||||||||
Power swaps and | Own credit risk | - | 0.17% | |||||||||||||
physical contracts | Discount rate | 0.00% - 2.68% | 0.32% | |||||||||||||
HFT derivatives – | 0.6 | Modeled pricing | Third-party pricing | $2.42 - $7.00 | $5.13 | |||||||||||
Natural gas swaps, | Own credit risk | - | 0.17% | |||||||||||||
futures, forwards and | Discount rate | 0.00% - 2.30% | 0.37% | |||||||||||||
physical contracts | 0.3 | Modeled pricing | Third-party pricing | $2.10 - $3.31 | $2.54 | |||||||||||
Basis adjustment | (0.06%) - 0.36% | (0.05%) | ||||||||||||||
Own credit risk | - | 0.17% | ||||||||||||||
Discount rate | 0.00% - 1.15% | 0.11% | ||||||||||||||
Total liabilities | 2.6 | |||||||||||||||
Net assets (liabilities) | $ | 8.4 |
64
The financial assets and liabilities included on the Consolidated Balance Sheets that are not measured at fair value consisted of the following:
As at | March 31, 2012 | December 31, 2011 | ||||||||||||||
millions of Canadian dollars | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Long-term debt (including current portion) | $ | 3,354.3 | $ | 3,939.2 | $ | 3,309.2 | $ | 3,935.0 |
The fair values of long-term debt instruments, classified as level 3 in the fair value hierarchy, are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturity, 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.
17. 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 | 2012 | 2011 | ||
Defined benefit pension plans | ||||
Service cost | $ 4.5 | $ 4.1 | ||
Interest cost | 14.2 | 14.2 | ||
Expected return on plan assets | (14.5) | (12.6) | ||
Current year amortization of: | ||||
Actuarial losses (gains) | 8.1 | 6.1 | ||
Special termination benefits | 1.6 | - | ||
Total defined benefit pension plans | 13.9 | 11.8 | ||
Non-pension benefits plan | ||||
Service cost | 0.7 | 0.7 | ||
Interest cost | 1.2 | 1.2 | ||
Current year amortization of: | ||||
Actuarial losses (gains) | 0.6 | 0.4 | ||
Past service costs (gains) | (0.4) | (0.4) | ||
Special termination benefits | 0.6 | - | ||
Total non-pension benefits plans | 2.7 | 1.9 | ||
Total defined benefit plans | $ 16.6 | $ 13.7 |
Emera’s contributions related to these defined benefit plans for the three months ended March 31, 2012 were $13.8 million (2011 – $12.4 million). In addition, the Company contributions related to the defined contribution plan for the three months ended March 31, 2012 were $0.7 million (2011 - $0.8 million).
65
18. COMMITMENTS AND CONTINGENCIES
A. | Commitments |
As at March 31, 2012, commitments (excluding pensions and other post-retirement benefits, long-term debt, and AROs) for each of the next five years and in aggregate thereafter consisted of the following:
millions of Canadian dollars | 2012 | 2013 | 2014 | 2015 | 2016 | Thereafter | Total | |||||||||||||||||||||
Purchased power (1) | $ | 85.5 | $ | 108.8 | $ | 109.0 | $ | 117.3 | $ | 117.5 | $ | 1,343.2 | $ | 1,881.3 | ||||||||||||||
Coal, biomass, oil and natural gas supply | 153.6 | 139.6 | 103.8 | 58.6 | 22.4 | 599.9 | $ | 1,077.9 | ||||||||||||||||||||
Transportation (2) | 54.5 | 31.3 | 28.8 | 16.3 | 2.2 | 2.7 | $ | 135.8 | ||||||||||||||||||||
Long-term service agreements (3) | 10.5 | 11.5 | 6.4 | 5.0 | 0.5 | 0.5 | $ | 34.4 | ||||||||||||||||||||
Capital projects | 57.1 | 3.5 | 0.6 | 3.9 | - | - | $ | 65.1 | ||||||||||||||||||||
Leases (4) | 2.3 | 3.2 | 3.3 | 3.2 | 2.8 | 16.0 | $ | 30.8 | ||||||||||||||||||||
Other | 4.7 | 3.5 | 3.3 | 3.2 | 1.3 | 1.0 | $ | 17.0 | ||||||||||||||||||||
Total | $ | 368.2 | $ | 301.4 | $ | 255.2 | $ | 207.5 | $ | 146.7 | $ | 1,963.3 | $ | 3,242.3 |
(1) | Purchased power: annual requirement to purchase 100 percent of electricity production from independent power producers. |
(2) | Transportation: purchasing commitments for transportation of solid fuel and transportation capacity on various pipelines. |
(3) | Long-term service agreements: outsourced management of the Company’s computer and communication infrastructure, vegetation management and maintenance of certain generating equipment. |
(4) | Leases: operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles. |
B. | Legal Proceedings |
A number of individuals who live in proximity to the NSPI’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. NSPI has filed a defense to the claim. The outcome of this litigation, and therefore an estimate of any contingent loss, is not determinable.
On October 31, 2011, MF Global Holding Ltd., the parent company of MF Global Inc. (“MFG”), a futures commission merchant used by Emera Energy Services (“Emera Energy”) for natural gas and electricity futures filed for Chapter 11 bankruptcy. Emera Energy was able to transfer its open future positions to other brokers; however $5.46 million USD of its posted margin was frozen with MFG and Emera Energy was unable to transfer these funds. Legal proceedings related to the bankruptcy have been initiated and are expected to involve cross-border insolvency proceedings as a result of MFG’s global affiliates. Although management expects to recover the majority of the frozen funds, a provision has been recognized and the net amount has been reclassified to “Other long-term assets”. The outcome of the bankruptcy proceedings is currently 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 |
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
66
AFUDC, based upon present environmental laws and regulations will be approximately $60.6 million during 2012 and are estimated to be $273.3 million from 2013 through 2016. Amounts that have been committed to are included in “Capital projects” in the commitments table in note 18A. The estimated expenditures do not include costs related to possible changes in the environmental laws or regulations and enforcement policies may be enacted in response to issues such as climate change and other pollutant emissions.
NSPI
NSPI is subject to regulation by federal, provincial and municipal authorities with regard to environmental matters primarily through its utility operations. In addition to imposing continuing compliance obligations, there are laws, regulations and permits authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is material to NSPI. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on NSPI.
Conformance with legislative and NSPI requirements are verified through a comprehensive environmental audit program. There were no significant environmental or regulatory compliance issues identified during the audits to date.
Climate Change and Air Emissions
Greenhouse Gas Emissions
NSPI has stabilized, and in recent years, reduced greenhouse gas emissions. This has been achieved by energy efficiency and conservation programs, increased use of natural gas and the addition of new renewable energy sources to the generation portfolio.
Greenhouse gas emissions from NSPI facilities have been capped beginning in 2010 through to 2020. The regulations allow for multi-year compliance periods recognizing the variability in electricity supply sources and demand. Over the decade, the caps will be achieved by a combination of additional renewable generation, import of non-emitting energy, and energy efficiency and conservation.
In 2011, Environment Canada announced proposed regulations for a new national carbon dioxide framework for the electricity sector in Canada. These proposed regulations would apply to new coal-fired electricity generation units; and existing coal-fired electricity generation units that have reached the end of their deemed economic life of forty-five years after commissioning. These proposed regulations will be effective July 1, 2015. Nova Scotia’s existing greenhouse gas regulations require reductions in NSPI’s emissions similar to those reflected in the federal framework.
On March 19, 2012, Environment Canada and the Nova Scotia Environment Department announced they are working toward an equivalency agreement on coal-fired electricity greenhouse gas regulations to avoid duplication of efforts to control greenhouse gas emissions. In the equivalency agreement, provincial regulations would take precedence over federal regulations, provided provincial regulations achieve an equivalent emissions outcome.
Nova Scotia’s existing greenhouse gas regulations require reductions of 25 percent in greenhouse gas emission in the electricity sector by 2020. The Province of Nova Scotia plans to develop additional more stringent milestones between 2020 and 2030 to match the federal targets. Discussions are underway for the 2020 to 2030 period to ensure consistency with the proposed federal regulations. NSPI is reviewing the implications of this federal framework and its alignment with its current operating plans under existing Nova Scotia regulations.
67
Renewable Energy
The Province of Nova Scotia has established targets with respect to the percentage of renewable energy in NSPI’s generation mix. 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 at a total of 20 percent renewable energy including NSPI owned and pre-2001 sources.
On May 19, 2011 the Nova Scotia Government approved The Electricity Act (Amended) to facilitate the eligibility of energy from the Lower Churchill Project in Labrador as a resource for meeting Nova Scotia’s renewable electricity targets. The amendment requires regulations to be developed that increase the percentage of renewable energy in the generation mix from the planned 25 percent in 2015, to 40 percent by 2020.
Mercury, Nitrogen Oxide and Sulphur Dioxide Emissions
NSPI completed a capital program to add sorbent injection to each of the seven pulverized fuel coal units in 2010 at a cost of $17.3 million. This was put in place to address planned reductions in mercury emissions limits, which are set out in the following table:
Year | Mercury Emissions Limit (kg) | |
2009 | 168 | |
2010 | 110 | |
2011 – 2012 | 100 | |
2013 | 85 | |
2014 – 2019 | 65 | |
2020 | 35 |
Any mercury emission above 65 kg, between 2010 and 2013, must be offset by lower emissions in the 2014 to 2020 period.
NSPI completed its capital program of retrofitting low nitrogen oxide combustion firing systems on six of its seven pulverized fuel coal units in early 2009 at a cost of $23.3 million. NSPI now meets the nitrogen oxide emission cap of 21,365 tonnes per year established by the Nova Scotia Government effective 2010. These investments, combined with the purchasing of low sulfur coal, allow NSPI to meet the provincial air quality regulations.
NSPI is committed to meeting ever-reducing sulphur dioxide emission cap requirements through the use of a blend of net lower sulphur content solid fuel.
Compared to historical levels, NSPI will have reduced mercury emissions by 60 percent effective 2014, nitrogen oxide by 40 percent effective 2009 and sulphur dioxide by 50 percent effective 2010.
Poly Chlorinated Bi-Phenol Transformers
In response to the Canadian Environmental Protection Act 1999, 2008 Poly Chlorinated Bi-Phenol (“PCB”) Regulations to phase out electrical equipment and liquids containing PCBs, NSPI has implemented a program to eliminate transformers and other oil filled electrical equipment on its system that do not meet the 2008 PCB Regulations Standard by 2014. In addition, there is a project to phase out the use of pole mount transformers before 2025 including a capital program to destroy all confirmed PCB contaminated pole mount transformers taken out of service through attrition. The
68
combined total cost of these projects is estimated to be $35.0 million and, as at March 31, 2012, approximately $8.1 million (December 31, 2011 – $7.8 million) has been spent to date.NSPI has recognized an ARO of $18.8 million as at March 31, 2012 (December 31, 2011 – $20.6 million) associated with the PCB phase-out program.
Maine Utilities
Poly Chlorinated Bi-Phenol Transformers
In response to a Maine environmental regulation to phase out PCB transformers, the Maine Utilities implemented multi-year programs to eliminate transformers on their systems that do not meet the new State environmental guidelines. The Maine Utilities completed their programs in 2011. The cost of testing the transformers is expensed as incurred; replacement transformers and the cost to install those transformers are capitalized. As of December 31, 2011 all transformers were remediated and are PCB-free in this effort; the total cumulative expenditures associated with the Maine Utilities’ programs was $4.4 million.
Caribbean Utilities
The Caribbean utilities have implemented a Health Safety Environmental and Management system to assist in safeguarding the health and safety of employees, contractors and customers while ensuring protection of the environment.
D. | Principal Risks and Uncertainties |
In this section, Emera describes some of the principal risks management believes could materially affect Emera’s business, revenues, operating income, net income, net asset or liquidity or capital resources. The nature of risk is such that no list can be comprehensive, and other risks may arise or risks not currently considered material may become material in the future.
Sound risk management is an essential discipline for running the business efficiently and pursuing the Company’s strategy successfully. Emera has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach.
Regulatory Risk
The Company’s rate-regulated subsidiaries are subject to risk in the recovery of costs and investments in a timely manner. The Company manages this regulatory risk through transparent regulatory disclosure, ongoing stakeholder consultation and multi-party engagement on aspects such as utility operations, rate filings and capital plans.
Changes in Environmental Legislation
The Company is subject to regulation by federal, provincial, state, regional, and local authorities with regard to environmental matters primarily related to its utility operations. Changes to climate change and air emissions standards could adversely affect utility operations.
Emera is committed to operating in a manner that is respectful and protective of the environment, and in full compliance with legal requirements and Company policy. Emera and its wholly-owned subsidiaries have implemented this policy through development and application of environmental management systems.
69
Commodity Prices and Foreign Exchange Rate Fluctuations
A substantial amount of the Company’s fuel supply comes from international suppliers and is subject to commodity price risk. Fuel contracts may be exposed to broader global conditions which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk through the use of financial hedging instruments and physical contracts. In addition, the adoption and implementation of FAMs in certain subsidiaries has further helped manage this risk.
The Company enters into foreign exchange forward and swap contracts to limit exposure on foreign currency transactions such as fuel purchases and USD revenue streams.
Acquisition Risk
The risks associated with Emera’s acquisition strategy include the availability of suitable acquisition candidates, obtaining the necessary regulatory approval for any acquisition and assimilating and integrating acquired companies into the Company. In addition, potential difficulties inherent in acquisitions may adversely affect the results of an acquisition. These include delays in implementation or unexpected costs or liabilities, as well as the risk of failing to realize operating benefits or synergies from completed transactions.
Emera mitigates these risks by following systematic procedures for integrating acquisitions, applying strict financial metrics to any potential acquisition and subjecting the process to close monitoring and review by the Board of Directors.
Commercial relationships
NSPI
For the three months ended March 31, 2012, NSPI’s five largest customers contributed approximately 6.5 percent (2011 – 13.1 percent) of electric revenues. The loss of a large customer could have a material effect on NSPI’s operating revenues. NSPI works to mitigate this risk through operational adjustments and cost management as well as the regulatory process.
A large customer was granted creditor protection under the Companies’ Creditors Arrangement Act (“CCAA”), and suspended operations in September 2011. NSPI is working to recover an outstanding balance of $11.6 million through the CCAA claims process, including a claim for set-off against amounts owing from NSPI to the customer that exceeds the amount receivable. The 2012 GRA Decision, approved by the UARB, provided for a FCR adjustment which allows NSPI to defer any unrecovered contribution toward non-fuel expenses in 2012 related to this customer. The recovery period will be determined through a GRA or FAM proceeding in Q4 2012.
Brunswick Pipeline
Brunswick Pipeline has a 25 year firm service agreement with Repsol Energy Canada (“REC”). The pipeline was used solely in 2012 and 2011 to transport natural gas from the Canaport LNG terminal in Saint John, New Brunswick to the United States border for REC. The risk of non-payment is mitigated as Repsol YPF, S.A (“Repsol”), the parent company of REC, has provided Brunswick Pipeline with a guarantee for all RECs’ payment obligations under the firm service agreement. As at March 31, 2012 the net investment in direct financing lease with Repsol was $493.4 million. Credit ratings and other company information are monitored on an ongoing basis. On March 14, 2012, Moody’s downgraded Repsol to Baa2 from Baa1; and on April 19, 2012, Standard & Poor’s downgraded Repsol to BBB- from BBB, with a negative outlook. The rating agency actions have had no impact on the operations of the Canaport facility, nor REC’s ability to meet its obligations under the firm service agreement.
70
Bayside Power
Bayside Power sells all of its power during the winter months, November through March, to NB Power in accordance with a long-term purchase power agreement (“PPA”). Revenue from this PPA contributed 100.0 percent (2011 – 100.0 percent) to Bayside Power’s electric revenues for the three months ended March 31, 2012. The PPA expires March 31, 2021, with an option to renew for an additional five year term, provided both parties consent to the renewal.
Labour Risk
Certain Emera employees are subject to collective labour agreements. Approximately 53 percent of the full-time and term employees at NSPI, BLPC, GBPC, Bangor Hydro, EUS, and MPS are represented by local unions. Approximately 40 percent of the labour force is covered by collective labour agreements that have or will expire within the next twelve months. Where collective labour agreements have expired, negotiations for new agreements have commenced and are ongoing. Emera seeks to manage this risk through ongoing discussions with local unions.
Weather Risk
Shifts in weather patterns affect electric sales volumes and associated revenues. Extreme weather events generally result in increased operating costs associated with restoring power to customers. Emera responds to significant weather event related outages according to each subsidiary’s respective Emergency Services Restoration Plan.
Interest Rate Risk
The Company utilizes a combination of fixed and variable rate debt financing for operations and capital expenditures resulting in an exposure to interest rate risk. The Company seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long term debt or enter into interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt.
E. | Collaborative Arrangement |
Bangor Hydro
Through Bangor Hydro, the Company is a party to a collaborative arrangement with National Grid Transmission Services Corporation to develop the Northeast Energy Link (“NEL”) Project. The cost of development activities, including acquisition of land in the transmission corridor and acquisition of necessary governmental and regulatory permits and approvals, are shared equally between the Company and National Grid. Bangor Hydro has deferred $2.5 million USD of costs associated with the NEL project as at March 31, 2012 (December 31, 2011 – $2.5 million USD), reported in the Consolidated Balance Sheets in “Other” as part of other assets.
F. | Guarantees and Letters of Credit |
Emera had the following guarantees and letter of credits as at March 31, 2012:
• | NSPI has provided a limited guarantee for the indebtedness of Renewable Energy Services Ltd. (“RESL”). The guarantee is up to a maximum of $23.5 million. As at March 31, 2012, RESL’s indebtedness under the loan agreement was $21.6 million. NSPI holds a security interest in the present and future assets of RESL. For further information see note 21. |
71
• | Emera has provided a guarantee to the Long Island Power Authority (“LIPA”) on behalf of Bear Swamp for Bear Swamp’s long-term energy and capacity supply agreement (“PPA”) with LIPA, which expires on April 30, 2021. The guarantee is for 50 percent of the relevant obligations under the PPA up to a maximum of $18.6 million USD. As at March 31, 2012, the fair value of the PPA was positive. |
• | Emera has provided a guarantee to the Bank of Nova Scotia on behalf of Bear Swamp for Bear Swamp’s interest rate swaps entered into between Bear Swamp and the Bank of Nova Scotia which expires on May 9, 2012. The guarantee is for 50 percent of the relevant obligations up to a maximum of $1.0 million USD. In the event Emera was required to make a payment to the Bank of Nova Scotia under this guarantee, the guarantee provides that Emera is able to seek recovery from Bear Swamp’s creditors after Bear Swamp has paid its debts in full. As at March 31, 2012, the fair value of that agreement was positive. |
• | At the request of Emera and its subsidiaries, a financial institution has issued standby letters of credit in the amount of $10.5 million for the benefit of third parties that have extended credit to Emera and its subsidiaries. These letters of credit typically have a one year term and are renewed annually as required. |
• | A financial institution has issued a standby letter of credit to secure obligations under an unfunded pension plan in NSPI. The letter of credit expires in June 2012 and is renewed annually. The amount committed as at March 31, 2012 was $22.5 million. |
• | A financial institution has issued a standby letter of credit to secure obligations under an unfunded pension plan in Bangor Hydro. The letter is renewed annually in October. The amount committed as at March 31, 2012 was $2.2 million USD. |
• | A financial institution has issued a standby letter of credit in connection with a precedent transmission line agreement between Bangor Hydro and two other parties. The letter of credit expires in December 2012. The amount committed as at March 31, 2012 was $1.75 million USD. |
• | A financial institution has been issued direct pay letters of credit totaling $23.9 million USD to secure principal and interest payments related to Maine Public Utilities Financing Bank bonds issued on behalf of MPS, related to qualifying distribution assets. |
No liability has been recognized on the consolidated balance sheet related to any potential obligation under these guarantees and letters of credits.
19. COMMON STOCK
Authorized: Unlimited number of non-par value common shares.
Issued and outstanding: | millions of shares | millions of Canadian dollars | ||
Balance, December 31, 2011 | 122.83 | $ 1,385.0 | ||
Issued for cash under Purchase Plans at market rate | 0.36 | 12.0 | ||
Discount on shares purchased under Dividend Reinvestment Plan | - | (0.5) | ||
Options exercised under senior management share option plan | 0.30 | 5.9 | ||
Stock-based compensation | - | 0.6 | ||
Balance, March 31, 2012 | 123.49 | $ 1,403.0 |
72
20. RELATED PARTY TRANSACTIONS
MN&P
In the ordinary course of business, Emera purchased natural gas transportation capacity from M&NP, an investment under significant influence of the Company, totaling $7.6 million (2011 – $12.9 million) for the three months ended March 31, 2012. 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, 2012, the amount payable to the related party was $2.5 million (December 31, 2011 – $3.3 million), and is under normal interest and credit terms.
Lucelec
On January 31, 2012, a wholly-owned subsidiary of Emera sold its 19.1 percent interest in Lucelec to LPH at book value, a subsidiary owned 80.0 percent by Emera, for $26.2 million ($29.1 million USD) effective January 1, 2012.
APUC
As at March 31, 2012 subscription receipts received and promissory notes issued to APUC were $98.8 million (December 31, 2011 – $135.8 million) included in “Other” assets and “Long-term debt” respectively on Emera’s Consolidated Balance Sheets.
On January 27, 2012, APUC announced it would not be proceeding with its investment to partner with Emera and First Wind Holdings LLC to own 370 MW of wind energy in the northeastern United States. In connection with this transaction, Emera had purchased 6.9 million subscription receipts for $5.37 each on July 29, 2011. With APUC’s subsequent withdrawal from the First Wind investment in Q1 2012, both the subscription receipts and related promissory note were cancelled.
21. VARIABLE INTEREST ENTITIES
The Company performs ongoing analysis to assess whether it holds any variable interest entities (“VIEs”). To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly-owned facilities.
VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera is not deemed the primary beneficiary, the VIE is not recorded in the Company’s consolidated financial statements.
LPH has established a self-insurance fund (“SIF”) primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. LPH holds a variable interest in the SIF for which it was determined that LPH was the primary beneficiary and, accordingly, the SIF must be consolidated by LPH. In its determination that LPH controls the SIF, management considered that in substance the activities of the SIF are being conducted on behalf of LPH’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because LPH, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF.
73
NSPI holds a variable interest in RESL, a VIE for which it was determined that NSPI was not the primary beneficiary since it does not have the controlling financial interest of RESL. NSPI has provided a $23.5 million guarantee with no set term for the indebtedness of RESL under a loan agreement between RESL and a third party lender, in support of which NSPI holds a security interest in all present and future assets of RESL. The guarantee arose in conjunction with NSPI’s participation in a wind energy project at Point Tupper, Nova Scotia, which is being operated by RESL. Under a purchased power agreement, NSPI purchases, at a fixed price, 100 percent of the power generated by the project. A default by RESL, under its loan agreement, would require NSPI to make payment under the guarantee. As at March 31, 2012, RESL’s indebtedness under the loan agreement was $21.6 million (December 31, 2011 – $21.9 million), and NSPI has not recorded a liability in relation to the guarantee.
Bangor Hydro holds a variable interest in Chester Static Var Compensator (“SVC”), a VIE for which it was determined that Bangor Hydro was not the primary beneficiary since it does not have the controlling financial interest of Chester SVC. A subsidiary of Bangor Hydro is a 50 percent general partner in Chester SVC, which owns electrical equipment that supports a major transmission line. A wholly-owned subsidiary of Central Maine Power Company owns the other 50 percent interest. Chester SVC is 100 percent debt financed and accordingly the partners have no equity interest; and the holders of the SVC notes are without recourse against the partners or their parent companies.
The Company has identified certain long-term purchase power agreements that could be defined as variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.
Emera’s consolidated VIE is recorded as an “Available-for-sale investment”. The following table provides information about Emera’s consolidated and unconsolidated VIEs:
As at | March 31, 2012 | December 31, 2011 | ||||||
millions of Canadian dollars | Total assets | Maximum exposure to loss | Total assets | Maximum exposure to loss | ||||
Consolidated VIE | ||||||||
BLPC SIF Available-for-sale investment | $ 57.4 | $ 57.4 | $ 54.1 | $ 54.1 | ||||
Unconsolidated VIEs in which Emera has Variable Interests | ||||||||
RESL | - | 23.5 | - | 23.5 | ||||
Chester SVC | - | - | - | - |
For the three months ended March 31, 2012, the Company has not identified any new VIEs.
22. COMPARATIVE INFORMATION
Effective Q1, 2012, the Company reclassified partnership income tax expense of $0.4 million previously recorded as a reduction in “Income from equity investments” to “Income tax expense (recovery)” in the Consolidated Statements of Income. Prior year comparatives have also been retrospectively reclassified, with $4.4 million previously recorded as a reduction in “Income from equity investments” in Q1, 2011 reclassified to “Income tax expense (recovery)” in the Consolidated Statements of Income.
74