Exhibit 99.1
Management’s Discussion & Analysis
As at May 11, 2012
Management’s Discussion and Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its primary subsidiaries and investments (“Emera”) during the first quarter of 2012 relative to 2011; and its financial position as at March 31, 2012 relative to December 31, 2011. To enhance shareholders’ understanding, certain multi-year historical financial and statistical information is presented. Throughout this discussion, “Emera Incorporated”, “Emera” and “Company” refer to Emera Incorporated and all of its consolidated subsidiaries and investments.
This discussion and analysis should be read in conjunction with the Emera Incorporated unaudited condensed consolidated financial statements and supporting notes as at and for the three months ended March 31, 2012; and the Emera Incorporated annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2011. Emera follows United States Generally Accepted Accounting Principles (“USGAAP”).
The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s non rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities, revenue and expenses. Emera’s rate-regulated subsidiaries include:
Emera Rate-Regulated Subsidiary | Accounting Policies Approved/Examined By | |
Nova Scotia Power Inc. (“NSPI”) | Nova Scotia Utility and Review Board (“UARB”) | |
Bangor Hydro Electric Company (“Bangor Hydro”) | Maine Public Utilities Commission (“MPUC”) and the Federal Energy Regulatory Commission (“FERC”) | |
Maine Public Service Company (“MPS”) | MPUC and FERC | |
Barbados Light & Power Company Limited (“BLPC”) | Fair Trading Commission, Barbados | |
Grand Bahama Power Company Limited (“GBPC”) | The Grand Bahama Port Authority (“GBPA”) | |
Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”) | National Energy Board (“NEB”) |
All amounts are in Canadian dollars (“CAD”) except for the Maine Utility Operations section of the MD&A, which is reported in US dollars (“USD”) unless otherwise stated.
Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR atwww.sedar.com. or on EDGAR atwww.sec.gov.
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Forward-Looking Information
This MD&A contains “forward-looking information” within the meaning of applicable Canadian securities laws and “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995 (collectively, “forward-looking information”). The words “anticipates”, “believes”, “could”, “estimates”, “expects”, “intends”, “may”, “plans”, “projects”, “schedule”, “should”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words.
The forward-looking information in this MD&A includes statements which reflect the current view with respect to the Company’s objectives, plans, financial and operating performance, business prospects and opportunities. The forward-looking information reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the times at which, such events, performance or results will be achieved.
The forward-looking information is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ from current expectations are discussed in the Outlook section of the MD&A and may also include: regulatory risk; operating and maintenance risks; economic conditions; availability and price of energy and other commodities; capital resources and liquidity risk; weather; commodity price risk; competitive pressures; construction risk; derivative financial instruments and hedging availability and cost of financing; interest rate risk; counterparty risk; competitiveness of electricity as an energy source; commodity supply; environmental risks; foreign exchange; regulatory and government decisions including changes to environmental, financial reporting and tax legislation; loss of service area; market energy sales prices; labour relations; and availability of labour and management resources.
Readers are cautioned not to place undue reliance on forward-looking information as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking information in this MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise.
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Structure of MD&A
This MD&A begins with an Introduction and Strategic Overview; followed by the Consolidated Financial Review of the Statements of Income, Balance Sheets, Statements of Cash Flows, and outstanding share data; then presents information separately on Emera’s consolidated subsidiaries and investments, specifically:
• | NSPI; |
• | Maine Utility Operations (Bangor Hydro and MPS); |
• | Caribbean Utility Operations (BLPC and its parent company, Light & Power Holdings Ltd. (“LPH”), GBPC and St. Lucia Electricity Services Limited (“Lucelec”)); |
• | Pipelines (Brunswick Pipeline and Maritimes & Northeast Pipeline (“M&NP”)); |
• | Other operations and investments are grouped and discussed under Services, Renewables and Other Investments (“SRO”) and include: |
¡ | Emera Energy Inc. (“Emera Energy”) includes (Emera Energy Services, Bayside Power Limited Partnership (“Bayside Power”), Bear Swamp Power Company LLC. (“Bear Swamp”)), |
¡ | Emera Utility Services Inc. (“EUS”), |
¡ | Emera Newfoundland & Labrador Holdings Inc. (“ENL”), |
¡ | Algonquin Power & Utilities Corp. (“APUC”), |
¡ | California Pacific Utilities Ventures, LLC (“CPUV”) and |
¡ | Atlantic Hydrogen Inc. (“AHI”); and |
• | Corporate |
The Outlook, Liquidity and Capital Resources, Transactions with Related Parties, Risk Management and Financial Instruments, Disclosure and Internal Controls, Critical Accounting Estimates and Summary of Quarterly Results sections of the MD&A are presented on a consolidated basis.
INTRODUCTION AND STRATEGIC OVERVIEW
Emera Incorporated is an energy and services company with approximately $7 billion in assets. The Company invests in electricity generation, transmission and distribution, gas transmission and utility energy services. Emera’s strategy is focused on the transformation of the electricity industry to cleaner generation and the delivery of that cleaner energy to market. Emera has interests throughout northeastern North America, in three Caribbean countries and in California.
Emera’s goal is to increase earnings per share by an average of 4 percent to 6 percent annually and to build and diversify its income base with a focus on cleaner energy in its markets. Emera will continue to build its existing business and will leverage its core strength in the electricity business to pursue acquisitions and greenfield development opportunities in regulated electricity transmission, distribution and lower risk generation.
Approximately 90 percent of Emera’s net income is earned by its rate-regulated subsidiaries. The success of these subsidiaries is integral to the creation of shareholder value, providing strong, predictable income and cash flows to fund dividends and reinvestment.
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Non-GAAP Financial Measures
Emera uses financial measures that do not have a standardized meaning under USGAAP.
NSPI
“Electric margin” is a non-GAAP financial measure used by NSPI and is defined as “Electric revenues” less “Regulated fuel for generation and purchased power, including affiliates” and net of the “Regulated fuel and fixed cost adjustments”, fuel-related foreign exchange gains or losses and other fuel-related costs. This measure is disclosed as management believes it provides useful information regarding the effect of the fuel adjustment mechanism (“FAM”) and fixed cost recovery deferral (“FCR”) on NSPI’s operations. Electric margin is discussed further in the Consolidated Financial Review – Consolidated Financial Highlights section and the NSPI – Review of 2012 section.
Caribbean Utility Operations
“Electric margin” is a non-GAAP financial measure used by Caribbean Utility Operations and is defined as “Electric revenues” and “Fuel surcharge” less “Regulated fuel for generation and purchased power”. This measure is disclosed as management believes it provides useful information regarding the effect of the fuel recovery mechanisms on Caribbean Utility operations. Electric margin is discussed further in the Caribbean Utility – Review of 2012 section.
Services, Renewables and Other Investments
“Net income applicable to common shares, absent the Bear Swamp after-tax mark-to-market adjustment”, “Earnings per common share – basic, absent the Bear Swamp after-tax mark-to-market adjustment”, “Contribution to consolidated net income, absent the Bear Swamp after-tax mark-to-market adjustment” and “Contribution to consolidated net earnings per common share, absent the Bear Swamp after-tax mark-to-market adjustment” are non-GAAP financial measures used by Emera. Management discloses these financial measures as it believes the inclusion of the mark-to-market adjustment in Bear Swamp’s financial results does not accurately reflect its operational performance. The adjustment is discussed further in the Consolidated Financial Review – Consolidated Financial Highlights section, Consolidated Financial Review – Review of 2012 section, and Services, Renewables and Other Investments – Review of 2012 section.
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CONSOLIDATED FINANCIAL REVIEW
Consolidated Financial Highlights
For the | Three months ended March 31 | |||||||
millions of Canadian dollars (except per share amounts) | 2012 | 2011 | ||||||
Operating revenues | $ | 568.0 | $ | 554.6 | ||||
Net income attributable to common shareholders | 80.2 | 123.6 | ||||||
Earnings per common share – basic | $ | 0.65 | $ | 1.06 | ||||
Earnings per common share – diluted | $ | 0.64 | $ | 1.03 | ||||
Dividends per common share declared | $ | 0.3375 | $ | 0.3250 | ||||
For the | Three months ended March 31 | |||||||
millions of Canadian dollars (except per share amounts) | 2012 | 2011 | ||||||
Operating Unit Contributions | ||||||||
NSPI | $ | 59.6 | $ | 63.6 | ||||
Maine Utility Operations | 8.5 | 9.4 | ||||||
Caribbean Utility Operations | 3.9 | 29.6 | ||||||
Pipelines | 6.8 | 6.8 | ||||||
Services, Renewables and Other Investments | 6.0 | 20.6 | ||||||
Corporate | (4.6 | ) | (6.4) | |||||
Net income attributable to common shareholders | $ | 80.2 | $ | 123.6 | ||||
Net income applicable to common shares, absent the Bear Swamp after-tax mark-to-market adjustment | $ | 81.1 | $ | 122.4 | ||||
Earnings per common share – basic | $ | 0.65 | $ | 1.06 | ||||
Earnings per common share – basic, absent the Bear Swamp after-tax mark-to-market adjustment | $ | 0.66 | $ | 1.05 |
Highlights of the changes are summarized in the following table:
For the | Three months ended | |||
millions of Canadian dollars | March 31 | |||
Consolidated net income attributable to common shareholders – 2011 | $ | 123.6 | ||
NSPI – Decreased net income primarily due to an unusally mild winter, and increased income taxes, depreciation and amortization, partially offset by increased electric rates, and decreased operating, maintenance and general (“OM&G”) expenses | (4.0) | |||
Maine Utility Operations – Decreased net income primarily due to decreased operating revenues due to lower sales volumes as a result of warmer weather, partially offset by decreased income tax expense | (0.9) | |||
Caribbean Utility Operations – Decreased net income primarily due to the $28.2 million gain on acquisition of controlling interest of LPH recorded in Q1 2011; partially offset by the impact of increased investment in LPH for a full quarter in 2012; and increased net income in GBPC | (25.7) | |||
Services, Renewables and Other Investments – Decreased net income primarily due to the $12.8 million after-tax gain on APUC subscription receipts recorded in Q1 2011, and an unfavourable change in the fair value of the net derivatives in Bear Swamp in 2012 | (14.6) | |||
Corporate – Decreased costs primarily due to decreased business development and foreign exchange expenses | 1.8 | |||
Consolidated net income attributable to common shareholders – 2012 | $ | 80.2 |
Basic earnings per share were $0.65 in Q1 2012 compared to $1.06 in Q1 2011.
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Developments
Emera
Strategic Investment Agreement with Algonquin Power & Utilities Corp.
Emera has a Strategic Investment Agreement (“SIA”) with Algonquin Power & Utilities Corp (“APUC” or “Algonquin”) which establishes how Emera and APUC will work together to pursue specific strategic investments of mutual benefit. The SIA also provides for Emera to acquire up to 25 percent of APUC through the purchase of common shares issued by APUC to fund certain investment opportunities developed in conjunction with Emera under the SIA. The acquisition of APUC shares is subject to regulatory approval from the MPUC, which has limited Emera’s ownership in APUC to 20 percent, with additional investment requiring specific approval. The share purchases are executed via the acquisition of subscription receipts in exchange for promissory notes at an agreed upon price, which are then exchangeable into common shares when certain conditions relating to the specific transactions are met. The acquisition of subscription receipts is subject to approvals required under applicable laws, including the rules of the Toronto Stock Exchange (“TSX”).
The table below outlines the transactions currently in process under the SIA. Full details of these transactions are contained in the Emera Inc. Management’s Discussion & Analysis for the year ended December 31, 2011.
Underlying Transaction | Number of shares/subscription receipts | Price per Subscription Receipt | Closed or Expected to Close | |||
Acquisition of California Pacific | 8,523,000 | $3.25 | Q1 2011 | |||
New Hampshire Acquisition | 12,000,000 | $5.00 | Q2 2012 | |||
Sale of California Pacific | 4,790,000 | $4.72 | 2012 | |||
Completion of California Pacific’s Rate Case | 3,421,000 | $4.72 | 2013 |
Assuming the completion of the pending transactions noted in the table above and the associated conversion of the subscription receipts to APUC common shares, Emera’s ownership interest in APUC will increase to approximately 17 percent.
Emera’s Investment in First Wind Holdings LLC
Emera is partnering with First Wind Holdings LLC (“First Wind”) to own 370 megawatts (“MW”) of wind energy facilities in the northeastern United States. These assets will become part of a new operating company, owned 51 percent by First Wind, and 49 percent by a new Emera owned entity, Northeast Wind. Northeast Wind will invest a total of approximately $366 million USD, subject to certain closing adjustments, to acquire its 49 percent interest in the operating company, including a $150 million USD loan. The acquisition requires certain state and federal regulatory approvals, all of which have been obtained, subject to certain conditions. Emera will finance the transaction through existing credit facilities subject to lender approval. The transaction is expected to close in Q2 2012.
US Securities and Exchange Commission Registration
On March 20, 2012, Emera filed with the United Stated Securities and Exchange Commission (“SEC”) a post-effective amendment to its Form F-9 registration statement removing from registration its debt securities, first preferred shares and second preferred shares. Emera continues to have reporting obligations under US securities laws by virtue of the registration of its common shares.
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NSPI
Regulatory Filings
On May 8, 2012, NSPI filed a General Rate Application (“GRA”) for 2013 and 2014 with the UARB. In an effort to smooth rate increases, NSPI is asking the UARB to approve an average 3 percent overall increase in rates effective January 1, 2013 and again on January 1, 2014, and for those years to continue in part, deferral of the FCR that was approved in the 2012 GRA Decision. If approved, the filing provides customers with predictable and more manageable rate increases over the next two years. To facilitate the stabilization plan, the amounts deferred would be collected from customers, beginning January 1, 2015, when other regulatory assets are fully amortized and these new recoveries can be absorbed. In the absence of the requested rate stabilization and deferral plan, average rate increases of 11 percent and 5 percent respectively for 2013 and 2014 would be necessary, applying traditional cost of service ratemaking procedures.
On April 27, 2012, NSPI filed with the UARB, as a co-applicant with Pacific West Commercial Corporation (“PWCC”), for approval of a Load Retention Tariff mechanism and other commercial arrangements relating to the operation of a paper mill in Port Hawkesbury, Nova Scotia. The impact of this arrangement on Emera, should it proceed, is not expected to be material.
United States Securities Exchange Commission Registration Termination
On December 12, 2011, NSPI filed with the SEC to remove from registration all unsold debt securities as of that date. NSPI also filed to terminate its reporting obligations under Section 15(d) of the United States Securities Exchange Act of 1934, as amended. Effective March 12, 2012, the SEC review period expired, and NSPI’s reporting obligations under United States securities laws terminated.
Appointments
Executive
Scott Balfour was appointed Executive Vice President and Chief Financial Officer of Emera Incorporated (“Emera”) and NSPI effective April 16, 2012. Prior to joining Emera, Mr. Balfour was President of Ensimian Capital Corporation, a private company providing consulting services and private investment. Mr. Balfour previously held the position of President and Chief Financial Officer of Aecon Group Inc., a publicly traded construction and infrastructure development company headquartered in Toronto, Ontario.
Significant Items
Gain on Exchange of Subscription Receipts to Shares
Upon closing of the California Pacific transaction in Q1 2011, Emera exchanged subscription receipts acquired in 2009 into 8.523 million APUC common shares, issued at $3.25 per share. This resulted in an after-tax gain of $12.8 million recorded in Q1 2011 in “Other income (expenses), net” on Emera’s Consolidated Statements of Income.
Gain on Business Acquisition
Emera’s interest in LPH was acquired in two tranches, in Q2 2010 and Q1 2011, and gave rise to non-taxable gains of $22.5 million and $ 28.2 million, respectively. These amounts were recorded in “Other income (expenses), net” on Emera’s Consolidated Statements of Income.
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REVIEW OF 2012
Emera Consolidated Statements of Income
For the | Three months ended March 31 | |||||||
millions of Canadian dollars (except per share amounts) | 2012 | 2011 | ||||||
Operating revenues – regulated | $ | 526.1 | $ | 507.5 | ||||
Operating revenues – non-regulated | 41.9 | 47.1 | ||||||
Total operating revenues | 568.0 | 554.6 | ||||||
Regulated fuel for generation and purchased power | 218.1 | 229.5 | ||||||
Regulated fuel and fixed cost adjustments | 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 | 1.5 | 41.6 | ||||||
Interest expense, net | 41.9 | 40.9 | ||||||
Income before provision for income taxes | 91.6 | 130.2 | ||||||
Income tax expense (recovery) | 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 | ||||||
Earnings per common share – basic | $ | 0.65 | $ | 1.06 | ||||
Earnings per common share – diluted | $ | 0.64 | $ | 1.03 |
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Emera’s consolidated net income decreased $43.4 million to $80.2 million in Q1 2012 compared to $123.6 million in Q1 2011. Highlights of the changes are summarized in the following table:
For the | Three months ended | |||
millions of Canadian dollars | March 31 | |||
Consolidated net income attributable to common shareholders – 2011 | $ | 123.6 | ||
Operating revenues – Increased primarily due to higher electricity pricing in NSPI, and increased investment in LPH as of January 25, 2011, partially offset by decreased industrial sales volume to a large NSPI customer; and an unusually mild winter affecting NSPI | 13.4 | |||
Regulated fuel for generation and purchased power – Decreased primarily due to lower sales volumes, commodity prices, and favourable changes in generation mix and plant performance in NSPI, partially offset by an increased investment in LPH as of January 25, 2011 | 11.4 | |||
Regulated fuel and fixed cost adjustments – Increased due to over recovery of current year fuel costs from customers versus an under recovery in 2011, and a higher recovery of prior year fuel costs; partially offset by the introduction of the fixed cost recovery deferral in NSPI | (16.9) | |||
Non-regulated fuel for generation and purchased power – Decreased due to lower natural gas prices | 6.8 | |||
Depreciation and amortization – Increased primarily due to increased property, plant and equipment and higher depreciation rates in NSPI, and increased investment in LPH as of January 25, 2011 | (8.0) | |||
Income from equity investments – Decreased primarily due to an unfavourable change in the fair value of the net derivatives in Bear Swamp and decreased earnings from CPUV as a result of warmer weather | (5.9) | |||
Other income (expenses), net – Decreased primarily due to gain on acquisition of a controlling interest in LPH of $28.2 million and APUC subscription receipts of $12.8 after-tax gain in Q1 2011 | (40.1) | |||
Income tax expense (recovery) – Increased expense primarily due to decreased accelerated tax deductions related to property, plant and equipment, partially offset by increased deductions related to pension and a decrease to income before the provision of taxes | (4.1) | |||
Consolidated net income attributable to common shareholders – 2012 | $ | 80.2 |
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Consolidated Balance Sheets Highlights
Significant changes in the consolidated balance sheets between March 31, 2012 and December 31, 2011 include:
millions of Canadian dollars |
| Increase (Decrease) |
| Explanation | ||
Assets | ||||||
Cash and cash equivalents | $ | 32.1 | See consolidated cash flow highlights section. | |||
Derivative instruments (current and long-term) | (11.5 | ) | Decreased primarily due to settlements and unfavourable USD price positions. | |||
Regulatory assets (current and long-term) | 25.6 | Increased primarily due to NSPI’s regulatory assets related to deferred income taxes, FCR regulatory asset and derivatives, partially offset by decreased regulatory assets related to the FAM. | ||||
Prepaid expenses | 14.0 | Increased primarily due to timing of provincial grants in lieu of taxes and insurance payments in NSPI. | ||||
Other assets (current and long-term) | (31.8 | ) | Decreased primarily due to cancellation of APUC subscription receipts related to the First Wind transaction. | |||
Property, plant & equipment, net of accumulated depreciation | 26.0 | Increased primarily due to capital spending, partially offset by depreciation. | ||||
Liabilities and Equity | ||||||
Short-term debt and long-term debt (including current portion) | 34.2 | Increased debt levels partially offset by cancellation of the promissory note related to the First Wind transaction. | ||||
Accounts payable | (70.3 | ) | Decreased primarily due to timing of payments and lower commodity prices. | |||
Other liabilities (current and long-term) | 19.1 | Increased primarily due to timing of payments. | ||||
Deferred income taxes (current and long-term) | 32.8 | Increased primarily due to increased deferred income tax liability on property, plant and equipment. | ||||
Common stock | 18.0 | Increased due to issuance of common shares. | ||||
Accumulated other comprehensive loss | 14.3 | Increased primarily due to the unfavorable effect of a stronger CAD dollar on Emera’s foreign investments. | ||||
Retained earnings | 38.4 | Increased due to net income of Emera Incorporated in excess of dividends declared and other stock-based compensation. |
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Consolidated Cash Flow Highlights
Significant changes in the statements of cash flows between March 31, 2012 and 2011 include:
Three months ended March 31 | 2012 | 2011 | ||||||||
millions of Canadian dollars | Explanation | |||||||||
Cash and cash equivalents, beginning of period | $ | 76.9 | $ | 7.3 | ||||||
Provided by (used in): | ||||||||||
Operating activities | 95.0 | 69.3 | Cash provided by operating activities increased in 2012 primarily due to increased non-cash working capital and increased recovery of current and prior year fuel costs through the FAM. | |||||||
Investing activities | (68.8 | ) | (142.6 | ) | Cash used in investing activities decreased in 2012 primarily due to the investment in LPH in Q1 2011. | |||||
Financing activities | 7.3 | 145.8 | Cash provided by financing activities decreased in 2012 primarily reflecting common share issuance in 2011, as well as repayments on short-term borrowings; partially offset by long-term debt issuances. | |||||||
Foreign currency impact on cash balances | (1.4 | ) | 0.3 | |||||||
Cash and cash equivalents, end of period | $ | 109.0 | $ | 80.1 |
Outstanding Share Data
Issued and outstanding: | | millions of Shares | | | Common stock millions of Canadian dollars | | ||
December 31, 2010 | 114.62 | $ 1,137.8 | ||||||
Issuance of common stock | 6.36 | 196.0 | ||||||
Issued for cash under Purchase Plans at market rate | 1.40 | 42.8 | ||||||
Discount on shares purchased under Dividend Reinvestment Plan | - | (1.8) | ||||||
Options exercised under senior management stock option plan | 0.45 | 8.8 | ||||||
Stock-based compensation | - | 1.4 | ||||||
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 stock option plan | 0.30 | 5.9 | ||||||
Stock-based compensation | - | 0.6 | ||||||
March 31, 2012 | 123.49 | $ 1,403.0 |
As at April 27, 2012 the amount of issued and outstanding common stock was 123.54 million.
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NSPI
Overview
NSPI is a fully-integrated regulated electric utility with approximately $4.0 billion of assets and the primary electricity supplier in Nova Scotia. NSPI provides electricity generation, transmission and distribution services to approximately 494,000 customers. It is regulated by the UARB under a cost-of-service model, with rates set to recover prudently-incurred costs of providing electricity service to customers, and provide an appropriate return to investors. NSPI’s target regulated return on equity (“ROE”) range for 2012 is 9.1 percent to 9.5 percent, based on an actual average regulated common equity component of up to 40 percent of actual average regulated capitalization. In Q4 2011, the UARB approved a GRA settlement agreement between NSPI and customer representatives which resulted in an average rate increase of 5.1 percent for all customers effective January 1, 2012.
Review of 2012
NSPI Net Income
For the | Three months ended March 31 | |||||||
millions of Canadian dollars (except per share amounts) | 2012 | 2011 | ||||||
Operating revenues – regulated | $ | 360.9 | $ | 368.8 | ||||
Regulated fuel for generation and purchased power (1) | 136.4 | 168.9 | ||||||
Regulated fuel for generation and purchased power – affiliates (1) | 2.4 | (0.3) | ||||||
Regulated fuel and fixed cost adjustments | 11.1 | (5.8) | ||||||
Operating, maintenance and general | 62.1 | 65.5 | ||||||
Provincial grants and taxes | 9.5 | 9.6 | ||||||
Depreciation and amortization | 45.8 | 42.6 | ||||||
Total operating expenses | 267.3 | 280.5 | ||||||
Income from operations | 93.6 | 88.3 | ||||||
Other expenses, net (2) | 1.4 | 2.2 | ||||||
Interest expense, net | 27.6 | 26.9 | ||||||
Income before provision for income taxes | 64.6 | 59.2 | ||||||
Income tax expense (recovery) | 3.0 | (6.4) | ||||||
Net income of Nova Scotia Power Inc. | 61.6 | 65.6 | ||||||
Preferred stock dividends | 2.0 | 2.0 | ||||||
Contribution to consolidated net income | $ | 59.6 | $ | 63.6 | ||||
Contribution to consolidated earnings per common share | $ | 0.48 | $ | 0.55 |
(1) Fuel for generation and purchased power includes proceeds from the sale of natural gas.
(2) Other expenses, net is included in “Other income (expenses), net” on the Consolidated Statements of Income.
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NSPI’s contribution to consolidated net income decreased $4.0 million to $59.6 million in Q1 2012 compared to $63.6 million in Q1 2011. Highlights of the net income changes are summarized in the following table:
For the | Three months ended | |||
millions of Canadian dollars | March 31 | |||
Contribution to consolidated net income – 2011 | $ | 63.6 | ||
Increased electric margin (see Electric Margin section for explanation) | 6.3 | |||
Decreased OM&G expenses primarily due to increased overhead credits applied to capital projects and decreased storm costs, partially offset by increased pension costs | 3.4 | |||
Increased depreciation and amortization primarily due to increased property, plant and equipment and new depreciation rates effective January 1, 2012 | (3.5) | |||
Increased income taxes primarily due to decreased accelerated tax deductions related to property, plant and equipment, partially offset by increased tax deductions related to pension | (9.4) | |||
Other | (0.8) | |||
Contribution to consolidated net income – 2012 | $ | 59.6 |
Operating Revenues – Regulated
NSPI’s Operating Revenues – Regulated include sales of electricity and other services as summarized in the following table:
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2012 | 2011 | ||||||
Electric revenues | $ | 355.3 | $ | 363.4 | ||||
Other revenues | 5.6 | 5.4 | ||||||
Operating revenues – regulated | $ | 360.9 | $ | 368.8 |
Electric Revenues
Electric sales volume is primarily driven by general economic conditions, population and weather. Residential and commercial electricity sales are seasonal, with Q1 and Q4 being the strongest periods, reflecting colder weather and fewer daylight hours in the winter season.
NSPI’s residential load generally comprises individual homes, apartments and condominiums. Commercial customers include small retail operations, large office and commercial complexes, and the province’s universities and hospitals. Industrial customers include manufacturing facilities and other large volume operations. Other electric revenues consist of export sales, sales to municipal electric utilities and revenues from street lighting.
Electric sales volumes are summarized in the following tables by customer class:
Q1 Electric Sales Volumes |
| |||||||||||
Gigawatt hours (“GWh”) | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Residential | 1,403 | 1,445 | 1,390 | |||||||||
Commercial | 849 | 872 | 849 | |||||||||
Industrial | 529 | 987 | 965 | |||||||||
Other | 89 | 87 | 86 | |||||||||
Total | 2,870 | 3,391 | 3,290 |
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Electric revenues are summarized in the following tables by customer class:
Q1 Electric Revenues |
| |||||||||||
millions of Canadian dollars | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Residential | $ | 197.0 | $ | 185.2 | $ | 172.3 | ||||||
Commercial | 99.8 | 95.2 | 88.4 | |||||||||
Industrial | 46.6 | 71.7 | 66.2 | |||||||||
Other | 11.9 | 11.3 | 10.6 | |||||||||
Total | $ | 355.3 | $ | 363.4 | $ | 337.5 |
Electric revenues decreased $8.1 million to $355.3 million in Q1 2012 from $363.4 million in Q1 2011. Highlights of the changes are summarized in the following table:
For the | Three months ended | |||
millions of Canadian dollars | March 31 | |||
Electric revenues – 2011 | $ | 363.4 | ||
Increased electricity pricing effective January 1, 2012 | 15.5 | |||
Increased electricity pricing effective January 1, 2012 related to recovery of prior years’ fuel costs | 12.7 | |||
Decreased industrial sales volume due to a large industrial customer suspending operations | (28.6) | |||
Decreased residential and commercial sales volumes primarily due to an unusually mild winter | (7.5) | |||
Other | (0.2) | |||
Electric revenues – 2012 | $ | 355.3 |
Regulated Fuel for Generation and Purchased Power (including affiliates)
Q1 Production Volumes |
| |||||||||||
GWh | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Coal and petcoke | 1,786 | 2,217 | 2,299 | |||||||||
Natural gas | 660 | 661 | 650 | |||||||||
Oil | 3 | 23 | 6 | |||||||||
Renewables | 351 | 415 | 286 | |||||||||
Purchased power | 283 | 271 | 221 | |||||||||
Total | 3,083 | 3,587 | 3,462 |
Purchased power includes 217 GWh of renewables in Q1 2012 (2011 – 182 GWh; 2010 – 109 GWh).
Q1 Average Unit Fuel Costs | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Dollars per MWh | $ | 45 | $ | 47 | $ | 52 |
14
Regulated fuel for generation and purchased power, including affiliates decreased $29.8 million to $138.8 million in Q1 2012 compared to $168.6 million in Q1 2011. Highlights of the changes are summarized in the following table:
For the | Three months ended | |||
millions of Canadian dollars | March 31 | |||
Regulated fuel for generation and purchased power, including affiliates – 2011 | $ | 168.6 | ||
Decreased sales volume | (20.8) | |||
Decreased commodity prices | (8.1) | |||
Favorable changes in generation mix and plant performance | (7.1) | |||
Unfavorable solid fuel commodity mix and additives related to emission compliance | 3.0 | |||
Decreased hydro and wind production | 2.6 | |||
Other | 0.6 | |||
Regulated fuel for generation and purchased power, including affiliates – 2012 | $ | 138.8 |
Regulated Fuel and Fixed Cost Adjustments
Regulated Fuel Adjustment and FAM Regulatory Asset
NSPI has a Fuel Adjustment Mechanism (“FAM”) which enables the Company to seek recovery of fuel costs through regularly scheduled rate adjustments. Differences between actual fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or (liability) and recovered from or returned to customers in a subsequent year. The FAM has an incentive component whereby NSPI retains or absorbs 10 percent of the over or under recovered amount to a maximum of $5 million. In November 2011, the UARB suspended the FAM incentive for 2012 as part of the settlement agreement for the 2012 GRA Decision.
The regulated fuel adjustment related to the FAM includes the effect of fuel costs in both the current and two preceding years, specifically:
Ÿ | 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”. |
Ÿ | The recovery from (rebate to) customers of over (under) recovered costs from prior years. |
Details of the FAM regulatory asset are summarized in the following table:
millions of Canadian dollars | 2012 | |||
FAM regulatory asset – Balance at January 1 | $ | 93.7 | ||
Under (over) recovery of current year fuel costs | (2.4) | |||
Rebate to (recovery from) customers of prior years’ fuel costs | (19.7) | |||
Interest revenue on FAM balance | 1.6 | |||
FAM regulatory asset – Balance at March 31 | $ | 73.2 |
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 and FCR Regulatory Asset
For 2012, the UARB approved a Fixed Cost Recovery Deferral (“FCR”). The FCR is intended to address uncertainty associated with the operations of two large industrial customers currently
15
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).
Electric Margin
NSPI distinguishes revenues related to the recovery of fuel costs (“fuel electric revenues”) from revenues related to the recovery of non-fuel costs (“non-fuel electric revenues”) because the FAM effectively seeks to recover all fuel costs, and consequently, fuel electric revenues and fuel costs do not have a material effect on NSPI’s electric margin or net income, except for the incentive component. For 2012, electric margin is also affected by the FCR which defers recovery of non-fuel costs associated with two large industrial customers, with the result that reduced sales to these customers have no impact on NSPI’s electric margin this year.
Electric margin and net income are influenced primarily by revenues relating to non-fuel costs. NSPI’s customer classes contribute differently to the Company’s non-fuel electric revenues, with residential and commercial customers contributing more than industrials. Accordingly, changes in residential and commercial load, largely due to weather and growth, have the largest effect on non-fuel electric revenues. Changes in industrial load, which are generally due to economic conditions, have less of an effect on non-fuel electric revenues than a similar volume change in residential and commercial load.
Electric margin is summarized in the following table:
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2012 | 2011 | ||||||
Fuel electric revenues – current year | $ | 141.6 | $ | 155.2 | ||||
Fuel electric revenues – preceding years | 19.7 | 8.2 | ||||||
Non-fuel electric revenues | 194.0 | 200.0 | ||||||
Total electric revenues | 355.3 | 363.4 | ||||||
Regulated fuel for generation and purchased power, including affiliates | (138.8 | ) | (168.6) | |||||
Regulated fuel adjustment | (22.1 | ) | 5.8 | |||||
Regulated fixed cost adjustment | 11.0 | - | ||||||
Foreign exchange and other fuel-related costs | (0.4 | ) | (1.9) | |||||
Electric margin | $ | 205.0 | $ | 198.7 |
NSPI’s electric margin increased $6.3 million to $205.0 million in Q1 2012 compared to $198.7 million in Q1 2011 primarily due to increased non-fuel electric revenues across all customer groups due to increased rates, partially offset by decreased sales as a result of an unusually mild winter. Decreased non-fuel electric revenues related to two large industrial customers were offset by the regulated fixed cost adjustment.
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Q1 Average Electric Margin / Megawatt hour (“MWh”) | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Dollars per MWh | $ | 71 | $ | 59 | $ | 59 |
The change in Q1 average electric margin per MWH in 2012 compared to 2011 reflects changes in customer mix, the effect of the FCR and increased electricity rates.
17
MAINE UTILITY OPERATIONS
Overview
Maine Utility Operations (“Maine Utilities”) includes Bangor Hydro Electric Company (“Bangor Hydro”) and Maine Public Service Company (“MPS”). All amounts in the Maine Utility Operations section are reported in USD unless otherwise stated.
Bangor Hydro and MPS are both transmission and distribution (“T&D”) electric utilities. Bangor Hydro is the second largest utility in Maine. Bangor Hydro has approximately $812.3 million of assets and serves approximately 118,000 customers in eastern Maine while MPS has approximately $141.2 million of assets and serves approximately 38,000 customers in northern Maine.
Electricity generation is deregulated in Maine, and several suppliers compete to provide customers with the energy delivered through both utilities’ T&D networks. Both utilities operate under a traditional cost-of-service regulatory structure.
MPS was purchased in late December 2010, thus its results are not included in the 2010 operating statistics.
Review of 2012
Maine Utility Operations’ Net Income
For the | Three months ended March 31 | |||||||
millions of US dollars (except per share amounts) | 2012 | 2011 | ||||||
Operating revenues – regulated | $ | 51.1 | $ | 53.3 | ||||
Regulated fuel for generation and purchased power | 8.0 | 7.6 | ||||||
Transmission pool expense (1) | 4.4 | 4.9 | ||||||
Operating, maintenance and general | 12.1 | 12.7 | ||||||
Provincial, state and municipal taxes | 2.6 | 2.4 | ||||||
Depreciation and amortization | 8.6 | 7.9 | ||||||
Total operating expenses | 35.7 | 35.5 | ||||||
Income from operations | 15.4 | 17.8 | ||||||
Other income (expenses), net | 1.1 | 0.7 | ||||||
Interest expense, net | 3.2 | 3.1 | ||||||
Income before provision for income taxes | 13.3 | 15.4 | ||||||
Income tax expense (recovery) | 4.8 | 5.9 | ||||||
Contribution to consolidated net income – USD | $ | 8.5 | $ | 9.5 | ||||
Contribution to consolidated net income – CAD | $ | 8.5 | $ | 9.4 | ||||
Contribution to consolidated earnings per common share – CAD | $ | 0.07 | $ | 0.08 | ||||
Net income weighted average foreign exchange rate – CAD/USD | $ | 1.00 | $ | 0.99 |
(1) Transmission pool expense is included in “Regulated fuel for generation and purchased power” on the Consolidated Statements of Income.
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Maine Utilities’ USD contribution to consolidated net income decreased by $1.0 million to $8.5 million in Q1 2012 compared to $9.5 million in Q1 2011. Highlights of the USD net income changes are summarized in the following table:
For the millions of US dollars | Three months ended March 31 | |||
Contribution to consolidated net income – 2011 | $ | 9.5 | ||
Decreased operating revenues primarily due to lower sales volumes as a result of warmer weather | (2.2) | |||
Decreased OM&G expenses primarily due to increased overhead credits applied to capital projects and decreased labour costs | 0.6 | |||
Decreased income taxes primarily due to decrease in income before provision for income taxes | 1.1 | |||
Other | (0.5) | |||
Contribution to consolidated net income – 2012 | $ | 8.5 |
Maine Utility Operations’ CAD contribution to consolidated net income decreased by $0.9 million to $8.5 million in Q1 2012 from $9.4 million in Q1 2011. The impact of a weaker CAD, quarter over quarter increased CAD earnings by $0.1 million for the three months ended March 31, 2012.
Operating Revenues – Regulated
Maine Utilities Operating Revenues – Regulated include sales of electricity and other services as summarized in the following table:
For the | Three months ended March 31 | |||||||
millions of US dollars | 2012 | 2011 | ||||||
Electric revenues | $ | 37.3 | $ | 39.1 | ||||
Transmission pool revenue | 9.4 | 9.8 | ||||||
Resale of purchased power | 4.4 | 4.4 | ||||||
Operating revenues – regulated | $ | 51.1 | $ | 53.3 |
Electric Revenues
Electric sales volume is primarily driven by general economic conditions, population and weather. Electric sales pricing in Maine is regulated, and therefore changes in accordance with regulatory decisions.
Q1 Electric Sales Volumes |
| |||||||||||
GWh | 2012 | 2011 | * 2010 | |||||||||
Residential | 212 | 215 | 154 | |||||||||
Commercial | 217 | 216 | 147 | |||||||||
Industrial | 86 | 91 | 78 | |||||||||
Other | 3 | 3 | 3 | |||||||||
Total | 518 | 525 | 382 |
* Excludes MPS which was acquired at the end of the year
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Electric revenues are summarized in the following tables by customer class:
Q1 Electric Revenues |
| |||||||||||
millions of US dollars | ||||||||||||
2012 | 2011 | * 2010 | ||||||||||
Residential | $ | 18.0 | $ | 18.5 | $ | 12.5 | ||||||
Commercial | 14.3 | 15.0 | 8.9 | |||||||||
Industrial | 2.4 | 2.9 | 2.5 | |||||||||
Other | 2.6 | 2.7 | 3.0 | |||||||||
Total | $ | 37.3 | $ | 39.1 | $ | 26.9 |
* Excludes MPS which was acquired at the end of the year
Electric revenues decreased $1.8 million to $37.3 million in Q1 2012 compared to $39.1 million in Q1 2011. Highlights of the changes are summarized in the following table:
For the millions of US dollars | Three months ended March 31 | |||
Electric revenues – 2011 | $ | 39.1 | ||
Decreased sales volumes primarily due to warmer weather | (0.5) | |||
Decreased primarily due to MPS stranded cost rate reduction in 2012 | (1.3) | |||
Electric revenues – 2012 | $ | 37.3 |
Q1 Average Electric Revenue / Megawatt hour (“MWh”) |
| |||||||||||
2012 | 2011 | * 2010 | ||||||||||
Dollars per MWh | $ | 72 | $ | 74 | $ | 70 |
* | Excludes MPS which was acquired at the end of the year |
The change in annual average electric revenue per MWh in Q1 2012 compared to Q1 2011 reflects an approximate 50 percent decrease in MPS’ stranded cost rates on January 1, 2012.
Transmission Pool Revenues and Expenses
Bangor Hydro is a participant in the New England regional interconnected high voltage transmission system, whereby transmission assets deemed to be integral to the regional transmission grid (“pool transmission facilities” or “PTF”) are supported by all the participants. Individual participant support is determined by the proportion that participant’s system load bears to the total of the New England participants’ system load. PTF costs are recovered from retail customers based on rates determined by FERC, and are adjusted annually on June 1. These transmission pool expenses are recorded in “Regulated fuel for generation and purchased power” in the Consolidated Statements of Income.
Transmission pool revenues and expenses are summarized in the following table:
For the | Three months ended | |||||||
millions of US dollars | March 31 | |||||||
2012 | 2011 | |||||||
Transmission pool revenues | $ | 9.4 | $ | 9.8 | ||||
Transmission pool expenses | 4.4 | 4.9 | ||||||
Net transmission pool revenues | $ | 5.0 | $ | 4.9 |
Maine Utilities’ net transmission pool revenues increased $0.1 million to $5.0 million in Q1 2012 compared to $4.9 million in Q1 2011 primarily due to a higher revenue requirement being recovered from New England customers offset by lower loads in the New England region as a result of warmer weather.
20
CARIBBEAN UTILITY OPERATIONS
Overview
Caribbean Utility Operations includes Emera’s:
• | 80.0 percent investment in Light & Power Holdings Ltd. (“LPH”) and its wholly-owned subsidiary Barbados Light & Power Company Ltd. (“BLPC”), a vertically-integrated utility and the sole provider of electricity on the island of Barbados, which serves approximately 123,000 customers and is regulated by the Fair Trading Commission, Barbados. The government of Barbados has granted BLPC a franchise to generate, transmit and distribute electricity on the island until 2028. BLPC is regulated under a cost-of-service model with rates set to recover prudently-incurred costs of providing electricity service to customers, and provide an appropriate return to investors. BLPC’s approved regulated return on assets for 2012 is 10 percent. A fuel pass-through mechanism ensures fuel costs are recovered. |
• | 50 percent direct and 30.4 percent indirect interest in Grand Bahama Power Company Ltd. (“GBPC”), a vertically-integrated utility and the sole provider of electricity on Grand Bahama Island. GBPC serves 19,000 customers and is regulated by GBPA, which has granted it a licensed, regulated and exclusive franchise to generate, transmit and distribute electricity on the island until 2054. There is a fuel pass-through mechanism and flexible tariff adjustment policy to ensure costs are recovered and a reasonable return earned. |
• | 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. The investment in Lucelec is accounted for on the equity basis. |
Review of 2012
Caribbean Utility Operations’ Net Income
For the | Three months ended March 31 | |||||||
millions of Canadian dollars (except per share amounts) | 2012 | 2011 | ||||||
Operating revenues – regulated | $ | 101.6 | $ | 73.6 | ||||
Regulated fuel for generation and purchased power | 66.8 | 48.6 | ||||||
Operating, maintenance and general | 20.8 | 18.7 | ||||||
Property taxes (1) | 0.4 | 0.3 | ||||||
Depreciation and amortization | 7.4 | 3.6 | ||||||
Total operating expenses | 95.4 | 71.2 | ||||||
Income from operations | 6.2 | 2.4 | ||||||
Income from equity investment | 0.2 | 1.3 | ||||||
Other income (expenses), net | 0.8 | 28.4 | ||||||
Interest expense, net | 2.0 | 2.0 | ||||||
Income before provision for income taxes | 5.2 | 30.1 | ||||||
Income tax expense (recovery) | 0.4 | 0.3 | ||||||
Net income | 4.8 | 29.8 | ||||||
Non-controlling interest in subsidiaries | (0.9 | ) | (0.2) | |||||
Contribution to consolidated net income | $ | 3.9 | $ | 29.6 | ||||
Contribution to consolidated earnings per common share | $ | 0.03 | $ | 0.25 |
(1) Included in Provincial, state and municipal taxes on the Consolidated Statements of Income
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Caribbean Utility Operations’ contribution to consolidated net income decreased by $25.7 million to $3.9 million in Q1 2012 compared to $29.6 million in Q1 2011. Highlights of the net income changes are summarized in the following table:
For the millions of Canadian dollars | Three months ended March 31 | |||
Contribution to consolidated net income – 2011 | $ | 29.6 | ||
Increased electric margin primarily due to increased investment in LPH as of January 25, 2011 | 7.7 | |||
Increased OM&G expenses primarily due to the increased investment in LPH as of January 25, 2011 | (2.1) | |||
Increased depreciation and amortization primarily due to the increased investment in LPH as of January 25, 2011 | (2.2) | |||
Decreased income from equity investment due to acquisition of a controlling interest in LPH as of January 25, 2011 | (1.1) | |||
Decreased other income (expenses), net primarily due to gain on increased investment in LPH as of January 25, 2011 | (27.6) | |||
Other | (0.4) | |||
Contribution to consolidated net income – 2012 | $ | 3.9 |
Operating Revenues – Regulated
Caribbean Utility Operations Operating Revenues – Regulated include sales of electricity and other services as summarized in the following table:
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2012 | 2011 | ||||||
Electric revenues – base rates | $ | 36.4 | $ | 29.8 | ||||
Fuel surcharge | 64.5 | 43.6 | ||||||
Total electric revenues | 100.9 | 73.4 | ||||||
Other revenues | 0.7 | 0.2 | ||||||
Operating revenues – regulated | $ | 101.6 | $ | 73.6 |
Electric Revenues
Electric sales volume is primarily driven by general economic conditions, population and weather. Residential and commercial electricity sales are seasonal, with Q3 being the strongest period, reflecting warmer weather.
Q1 Electric Sales Volumes | ||||||||
GWh | ||||||||
2012 | * 2011 | |||||||
Residential | 94 | 77 | ||||||
Commercial | 173 | 134 | ||||||
Industrial | 22 | 21 | ||||||
Other | 6 | 5 | ||||||
Total | 295 | 237 |
* Emera acquired a controlling interest in LPH on January 25, 2011
22
Electric revenues are summarized in the following tables by customer class:
Q1 Electric Revenues | ||||||||
millions of Canadian dollars | ||||||||
2012 | * 2011 | |||||||
Residential | $ | 29.7 | $ | 22.3 | ||||
Commercial | 59.6 | 41.9 | ||||||
Industrial | 7.8 | 7.6 | ||||||
Other | 3.8 | 1.6 | ||||||
Total | $ | 100.9 | $ | 73.4 |
* Emera acquired a controlling interest in LPH on January 25, 2011
Electric revenues increased $27.5 million to $100.9 million in Q1 2012 compared to $73.4 million in Q1 2011. Highlights of the changes are summarized in the following table:
For the millions of Canadian dollars | Three months ended March 31 | |||
Electric revenues – 2011 | $ | 73.4 | ||
Increased due to the increased investment in LPH as of January 25, 2011 | 17.6 | |||
Increased primarily as a result of an increase in regulatory cost recoveries in GBPC in 2012 | 2.1 | |||
Increased fuel surcharge due to higher fuel costs | 7.7 | |||
Other | 0.1 | |||
Electric revenues – 2012 | $ | 100.9 |
Q1 Average Electric Revenue/MWh | ||||||||
2012 | 2011 | |||||||
Dollars per MWh | $ | 342 | $ | 310 |
Electric Margin
Caribbean Utility Operations distinguishes revenues related to the recovery of fuel costs through the fuel surcharge from revenues related primarily to the recovery of non-fuel costs (“base rates”). The fuel surcharge recovers all the fuel costs except in GBPC, where the first $20 USD/barrel of oil is included in the base rates. Consequently, electric margin and net income are influenced primarily by the base rates, whereas the fuel surcharge and fuel costs do not have a material effect on electric margin or net income.
In both BLPC and GBPC, customer classes contribute differently to the Company’s base rate revenue, with residential and commercial customers contributing more than industrials. Residential and commercial load is primarily affected by changes in weather and economic conditions, while industrial load is primarily affected by changes in economic conditions.
Electric margin is summarized in the following table:
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2012 | 2011 | ||||||
Electric revenues – base rate | $ | 36.4 | $ | 29.8 | ||||
Fuel surcharge | 64.5 | 43.6 | ||||||
Total electric revenues | 100.9 | 73.4 | ||||||
Regulated fuel for generation and purchased power (1) | 66.8 | 48.6 | ||||||
Regulatory amortization (2) | 0.2 | (1.4) | ||||||
Electric margin | $ | 33.9 | $ | 26.2 |
(1) Regulated fuel for generation and purchased power includes $1.8 million (2011 – $1.4 million) of temporary generation costs
(2) Included in Depreciation and amortization on the Consolidated Statements of Income
23
Caribbean Utility Operations’ electric margin increased $7.7 million to $33.9 million in Q1 2012 compared to $26.2 million in Q1 2011 primarily due to the increased investment in LPH as of January 25, 2011.
Regulated Fuel for Generation and Purchased Power
Q1 Production Volumes | ||||||||
GWh | ||||||||
2012 | 2011 | |||||||
Oil | 322 | 261 | ||||||
Q1 Average Unit Fuel Costs | ||||||||
2012 | 2011 | |||||||
Dollars per MWh | $ | 202 | $ | 181 |
Regulated fuel for generation and purchased power increased $18.2 million to $66.8 million in Q1 2012 compared to $48.6 million in Q1 2011 due to the increased investment in LPH as of January 25, 2011 and higher fuel costs.
Fuel Recovery Mechanisms
BLPC
All BLPC fuel costs are passed to customers through the fuel clause adjustment (“fuel surcharge”). Fair Trading Commission, Barbados has approved the calculation of the fuel surcharge, which is adjusted on a monthly basis. BLPC has the ability to carryover an under-recovery to later months to smooth the fuel surcharge for customers.
GBPC
The current base rate includes $20 USD per barrel of oil consumed by GBPC for generation of electricity. The amount by which actual fuel costs exceed $20 USD dollars per barrel is recovered or rebated through the fuel surcharge, which is adjusted on a monthly basis. The methodology for calculating the amount of the fuel surcharge has been approved by GBPA.
24
PIPELINES
Overview
Pipelines comprises Emera’s wholly-owned Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”) and the Company’s 12.9 percent interest in the Maritimes & Northeast Pipeline (“M&NP”).
• | Brunswick Pipeline is a 145-kilometre pipeline delivering re-gasified natural gas from the Canaport™ liquefied natural gas (“LNG”) import terminal near Saint John, New Brunswick, to markets in the northeastern United States. The pipeline, which went into service in July 2009, transports natural gas for Repsol Energy Canada under a 25 year firm service agreement. The NEB, which regulates Brunswick Pipeline, has classified it as a Group II pipeline. Brunswick Pipeline is accounted for as a direct financing lease. |
• | M&NP is a $2 billion, 1,400-kilometer pipeline which transports natural gas from offshore Nova Scotia to markets in Maritime Canada and the northeastern United States. The investment in M&NP is accounted for on the equity basis. |
Review of 2012
Pipelines’ Net Income
For the | Three months ended March 31 | |||||||
millions of Canadian dollars (except per share amounts) | 2012 | 2011 | ||||||
Operating revenues – regulated | $ | 12.4 | $ | 12.4 | ||||
Accretion (1) | 0.1 | - | ||||||
Income from equity investment | 3.5 | 3.6 | ||||||
Other income (expenses), net | (0.1 | ) | (0.3) | |||||
Interest expense, net | 7.6 | 7.4 | ||||||
Income before provision for income taxes | 8.1 | 8.3 | ||||||
Income tax expense (recovery) | 1.3 | 1.5 | ||||||
Contribution to consolidated net income | $ | 6.8 | $ | 6.8 | ||||
Contribution to consolidated earnings per common share | $ | 0.06 | $ | 0.06 |
(1) Included in Depreciation and amortization on the Consolidated Statements of Income
Pipelines’ contribution to consolidated net income did not change overall in Q1 2012 compared to Q1 2011.
25
SERVICES, RENEWABLES AND OTHER INVESTMENTS
Overview
Services, Renewables and Other Investments includes Emera Energy Inc. (“Emera Energy”); Emera Utility Services Inc. (“EUS”); and Emera Newfoundland & Labrador Holdings Inc. (“ENL”), as well as other investments.
• | Emera Energy includes: |
• | Emera Energy Services, a physical energy business which purchases and sells natural gas and electricity and provides related energy asset management services. |
• | Bayside Power, a 260-MW gas-fired merchant electricity generating facility in Saint John, New Brunswick. |
• | Emera’s 50 percent joint venture ownership of Bear Swamp, a 600-MW pumped storage hydro-electric facility in northern Massachusetts. This investment is accounted for on the equity basis. |
• | EUS is a utility services contractor operating in Atlantic Canada and the Bahamas. |
• | ENL is a wholly-owned subsidiary of Emera focused on transmission investments related to a proposed 824-MW hydro-electric generating facility at Muskrat Falls in Labrador. These investments include an estimated $1.2 billion transmission project between Newfoundland and Nova Scotia, including a 180-kilometre subsea cable (“Maritime Link Project”). In addition, together with Nalcor Energy, Newfoundland and Labrador’s provincial energy crown corporation leading the project in that province, Emera is investing in the development of a $2.1 billion electricity transmission project in Newfoundland and Labrador (“Labrador-Island Transmission Link Project”). These projects are scheduled to be in service in 2017. Development costs incurred to date have been capitalized. |
• | Other investments include a 5.8 percent investment in Algonquin Power & Utilities Corporation (“APUC”), a 49.999 percent investment in California Pacific Utilities Ventures (“CPUV”) and a 37.7 percent investment in Atlantic Hydrogen Inc. (“AHI”). These investments are accounted for on the equity basis. |
26
Review of 2012
Services, Renewables and Other Investments Net Income
For the | Three months ended March 31 | |||||||
millions of Canadian dollars (except per share amounts) | 2012 | 2011 | ||||||
Trading and marketing margin | $ | 4.6 | $ | 8.9 | ||||
Electricity sales | 20.2 | 24.7 | ||||||
Utility services | 17.0 | 13.6 | ||||||
Total operating revenues – non-regulated | 41.8 | 47.2 | ||||||
Non-regulated fuel for generation and purchased power | 13.9 | 20.7 | ||||||
Non-regulated direct costs | 14.3 | 12.8 | ||||||
Operating, maintenance and general | 7.9 | 8.1 | ||||||
Depreciation and amortization | 0.9 | 0.9 | ||||||
Total operating expenses | 37.0 | 42.5 | ||||||
Income from operations | 4.8 | 4.7 | ||||||
Income from equity investments | 2.3 | 7.0 | ||||||
Other income (expenses), net | 0.4 | 15.0 | ||||||
Interest expense, net | 0.2 | 0.3 | ||||||
Income before provision for income taxes | 7.3 | 26.4 | ||||||
Income tax expense (recovery) | 1.3 | 5.8 | ||||||
Contribution to consolidated net income | $ | 6.0 | $ | 20.6 | ||||
Bear Swamp after-tax mark-to-market adjustment | $ | (0.9 | ) | $ | 1.2 | |||
Contribution to consolidated net income, absent the Bear Swamp after-tax mark-to-market adjustment | $ | 6.9 | $ | 19.4 | ||||
Contribution to consolidated earnings per common share | $ | 0.05 | $ | 0.18 | ||||
Contribution to consolidated earnings per common share, absent the Bear Swamp after-tax mark-to-market adjustment | $ | 0.06 | $ | 0.17 |
Services, Renewables and Other Investments contribution to consolidated net income decreased $14.6 million to $6.0 million in Q1 2012 compared to $20.6 million in Q1 2011. Highlights of the net income changes are summarized in the following table:
For the millions of Canadian dollars | Three months ended March 31 | |||
Contribution to consolidated net income – 2011 | $ | 20.6 | ||
Operating revenues – non-regulated – see table below for highlights | (5.4 | ) | ||
Decreased non-regulated fuel for generation and purchased power primarily due to lower natural gas prices | 6.8 | |||
Decreased income from equity investments primarily due to an unfavourable change in the fair value of the net derivatives in Bear Swamp and decreased earnings in CPUV as a result of warmer weather | (4.7 | ) | ||
Decreased other income (expenses), net primarily due to the gain on APUC subscription receipts in 2011 | (14.6 | ) | ||
Decreased income tax expense (recovery) primarily due to decreased income before provision for income taxes | 4.5 | |||
Other | (1.2 | ) | ||
Contribution to consolidated net income – 2012 | $ | 6.0 |
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For the millions of Canadian dollars | Three months ended March 31 | |||
Operating revenues – non-regulated – 2011 | $ | 47.2 | ||
Trading and marketing margin – Decreased due to reduced energy marketing opportunities | (4.3 | ) | ||
Electricity sales – Decreased primarily due to lower priced contracted energy sales reflecting lower natural gas prices, partially offset by increased generation | (4.5 | ) | ||
Utility services – Increased due to construction activity in the Caribbean and Newfoundland | 3.4 | |||
Operating revenues – non-regulated – 2012 | $ | 41.8 |
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CORPORATE
Overview
Corporate includes certain corporate-wide functions including executive management, strategic planning, treasury services, financial reporting, tax planning, business development and corporate governance. Corporate also includes interest expense and income taxes associated with corporate activities.
Review of 2012
Corporate
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2012 | 2011 | ||||||
Revenue | $ | 7.6 | $ | 7.4 | ||||
Corporate costs | 5.6 | 7.7 | ||||||
Interest expense | 9.0 | 8.7 | ||||||
Income tax expense (recovery) | (4.1) | (4.3) | ||||||
Preferred stock dividends | 1.7 | 1.7 | ||||||
Contribution to consolidated net income | $ | (4.6) | $ | (6.4) |
Revenue
Revenue consists of intercompany interest and preferred dividends from Brunswick Pipeline.
Corporate Costs
Corporate costs decreased $2.1 million to $5.6 million in Q1 2012 compared to $7.7 million in Q1 2011 due to decreased business development costs and foreign exchange expense.
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OUTLOOK
Emera will continue to pursue investment opportunities related to the transformation of the energy industry to produce lower emissions. Emera has embarked on a significant capital plan to increase the Company’s generation from renewable sources, to improve the transmission connections within its service territories, and to expand access to natural gas as Emera transitions to a cleaner, greener company.
Although markets in Maine and Nova Scotia are otherwise mature, the transformation of energy supply to lower emission sources has created the opportunity for organic growth within NSPI and Emera’s Maine Utility Operations. The utilities expect average income growth to be 3 percent to 5 percent annually over the next five years as new investments are made in renewable generation and transmission.
NSPI
NSPI anticipates earning a regulated ROE within its allowed range in 2012. NSPI continues to implement its strategy, which is focused on regulated investments in renewable energy and system reliability projects with an annual capital expenditure plan of approximately $330 million in 2012. NSPI expects to finance its capital expenditures with funds from operations and debt.
Maine Utility Operations
USD income from Maine Utility Operations is expected to be slightly higher in 2012 compared to 2011 due to the recovery of investments in new transmission assets. In 2012, Maine Utilities expect to invest approximately $110 million USD, including approximately $72 million USD for major transmission projects.
Caribbean Utility Operations
Income from Caribbean Utility Operations is expected to be higher in 2012 compared to 2011 primarily as a result of increased capital investments in LPH and GBPC. Caribbean Utility Operations plans to invest approximately $62 million in capital programs in 2012.
Pipelines
Income from Pipelines is expected to decline marginally in 2012 as compared to 2011 as a result of capital lease accounting treatment which yields declining earnings over the life of the asset.
Services, Renewables and Other Investments
Income from Services, Renewables and Other Investments is expected to be consistent with 2011. ENL plans to invest approximately $110 million on the Maritime Link Project and Labrador-Island Transmission Link Project in 2012.
Corporate
Income from Corporate is expected to be lower in 2012 compared to 2011 due to higher interest costs due to business growth.
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LIQUIDITY AND CAPITAL RESOURCES
The Company generates cash primarily through the generation, transmission and distribution of electricity through its regulated electric utilities. The utilities’ customer bases are diversified by both sales volumes and revenues among customer classes. Circumstances that could affect the Company’s ability to generate cash include general economic downturns in Emera’s markets, the loss of one or more large customers, regulatory decisions affecting customer rates and changes in environmental legislation. Emera’s subsidiaries are capable of paying dividends to Emera provided they do not breach their debt covenants after giving effect to the dividend payment.
In addition to internally generated funds, Emera and its subsidiaries have, in aggregate, access to $1.3 billion committed syndicated revolving bank lines of credit as discussed in the table below. NSPI has an active commercial paper program for up to $400 million, of which outstanding amounts are 100 percent backed by NSPI’s bank line referred to above, which results in an equal amount of credit being considered drawn and unavailable.
As at March 31, 2012, the Company’s total credit facilities, outstanding borrowings and available capacity were as follows:
millions of dollars | Maturity | Revolving Credit Facilities | Utilized | Undrawn and Available | ||||||||||
Emera – Operating and acquisition credit facility | June 2015 – Revolver | $ | 700 | $ | 185 | $ | 515 | |||||||
NSPI – Operating credit facility | June 2015 – Revolver | 500 | 174 | 326 | ||||||||||
Bangor Hydro – in USD – Operating credit facility | September 2013 – Revolver | 80 | 4 | 76 | ||||||||||
Other – in USD – Operating credit facilities | 2012 | 29 | 9 | 20 |
Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly and the Company is in compliance with covenant requirements.
Emera
On March 30, 2012, Standard and Poor’s Rating Services (“S&P”) affirmed its BBB+ rating for Emera, but revised its outlook to negative from stable citing increased regulatory risk due to capital expenditure requirements to meet federal and provincial energy targets.
On April 3, 2012, Dominion Bond Rating Service (“DBRS”) confirmed its BBB (high) rating for Emera, but changed its trend to negative from stable citing concerns over non-consolidated debt metrics.
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.
On March 28, 2012, DBRS confirmed its A (low) with stable trend rating for NSPI.
On March 30, 2012, S&P affirmed its BBB+ rating for NSPI, but revised its outlook to negative from stable citing increased regulatory risk due to capital expenditure requirements to meet federal and provincial energy targets.
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Maine Utility Operations
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.
Caribbean Utility Operations
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.
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.
Capital Expenditures
Capital expenditures for Q1 2012, including AFUDC, were approximately $110 million and included:
• | $55 million in NSPI; |
• | $20 million in Maine Utility Operations; |
• | $30 million in Caribbean Utility Operations; and |
• | $5 million in Services, Renewables and Other Investments. |
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Contractual Obligations
As at March 31, 2012, commitments 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 | |||||||||||||||||||||
Long-term debt | $ | 33.1 | $ | 322.4 | $ | 305.4 | $ | 340.2 | $ | 254.7 | $ | 2,096.4 | $ | 3,352.2 | ||||||||||||||
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 | |||||||||||||||||||||
Pension and post-retirement obligations (2) | 66.3 | 67.3 | 66.9 | 60.2 | 51.5 | 445.8 | 758.0 | |||||||||||||||||||||
Asset retirement obligations | 2.4 | 2.2 | 2.0 | 1.4 | 2.7 | 340.5 | 351.2 | |||||||||||||||||||||
Transportation (3) | 54.5 | 31.3 | 28.8 | 16.3 | 2.2 | 2.7 | 135.8 | |||||||||||||||||||||
Long-term service agreements (4) | 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 (5) | 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 | |||||||||||||||||||||
$ | 470.0 | $ | 693.3 | $ | 629.5 | $ | 609.3 | $ | 455.6 | $ | 4,846.0 | $ | 7,703.7 |
(1)�� Purchased power: annual requirement to purchase 100 percent of electricity production from independent power producers.
(2) Pension and post-retirement obligations: are based on regulatory requirements and assume that members stop accruing service effective December 31, 2011. As most of Emera’s defined benefit pension plans still allow continued accrual of service and each plan’s contribution requirements are reassessed on a regular basis, actual future pension contributions will differ from the amounts shown.
(3) Transportation: purchasing commitments for transportation of solid fuel and transportation capacity on various pipelines.
(4) Long-term service agreements: outsourced management of the Company’s computer and communication infrastructure, vegetation management and maintenance of certain generation equipment.
(5) Leases: operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles.
TRANSACTIONS WITH RELATED PARTIES
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.
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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 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.
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Commodity, Foreign Exchange and Interest Rate Risks
Emera’s risk management policies and procedures provide a framework through which management monitors various risk exposures. The risk management practices are overseen by the Board of Directors. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group which is independent of all operations.
The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange and interest rates using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. Collectively these contracts are considered “derivatives”.
The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. The Company continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts where the criteria are no longer met.
Derivatives qualify for hedge accounting if they meet stringent documentation requirements, and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the effective portion of the change in the fair value of derivatives is deferred to Accumulated Other Comprehensive Loss (“AOCL”) and recognized in income in the same period the related hedged item is realized. Any ineffective portion of the change in the fair value of the cash flow hedges is recognized in net income in the reporting period.
Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value, with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.
Derivatives entered into by NSPI that are documented as economic hedges, and for which the NPNS exception has not been taken, receive regulatory deferral as approved by the 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
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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.
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 or losses are recognized in net income of the period unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category when another accounting treatment applies.
Hedging Items Recognized on the Balance Sheets
The Company has the following categories on the balance sheet related to derivatives in valid hedging relationships:
As at millions of Canadian dollars | March 31 2012 | December 31 2011 | ||||||
Derivative instrument assets (current and other assets) | $ | 6.3 | $ | 5.7 | ||||
Derivative instrument liabilities (current and long-term liabilities) | (22.9) | (27.8) | ||||||
Net derivative instrument assets (liabilities) | $ | (16.6) | $ | (22.1) |
Hedging Impact Recognized in Net Income
The Company recognized the following gains (losses) related to the effective portion of hedging relationships under the following categories:
The effectiveness gains (losses) reflected in the above table would be offset in net income by the change in the hedged item realized in the period.
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2012 | 2011 | ||||||
Regulated operating revenues | $ | 0.8 | $ | 0.8 | ||||
Non-regulated fuel and purchased power | (2.0) | (1.0) | ||||||
Other income (expenses), net | (0.2) | (0.1) | ||||||
Effectiveness net gains (losses) | $ | (1.4) | $ | (0.3) |
The Company recognized in net income the following gains (losses) related to the ineffective portion of hedging relationships under the following categories:
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2012 | 2011 | ||||||
Non-regulated fuel and purchased power | $ | (0.1) | $ | (0.6) | ||||
Ineffectiveness gains (losses) | $ | (0.1) | $ | (0.6) |
Regulatory Items Recognized on the Balance Sheets
The Company has the following categories on the balance sheet related to derivatives receiving regulatory deferral:
As at millions of Canadian dollars | March 31 2012 | December 31 2011 | ||||||
Derivative instrument assets (current and other assets) | $ | 34.7 | $ | 44.5 | ||||
Regulatory assets (current and other assets) | 54.7 | 46.3 | ||||||
Derivative instrument liabilities (current and long-term liabilities) | (54.7) | (46.3) | ||||||
Regulatory liabilities (current and long-term liabilities) | (34.7) | (44.5) | ||||||
Net asset (liability) | $ | - | $ | - | �� |
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Regulatory Impact Recognized in Net Income
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) |
Held-for-trading Items Recognized on the Balance Sheets
The Company has the following categories on the balance sheet related to HFT derivatives:
As at millions of Canadian dollars | March 31 2012 | December 31 2011 | ||||||
Derivative instruments assets (current and other assets) | $ | 14.4 | $ | 16.7 | ||||
Derivative instruments liabilities (current and long-term liabilities) | (13.0) | (14.7) | ||||||
Net derivative instrument assets (liabilities) | $ | 1.4 | $ | 2.0 |
Held-for-trading Items Recognized in Net Income
The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives in net income:
For the | Three months ended March 31 | |||||||
millions of Canadian dollars | 2012 | 2011 | ||||||
Non-regulated operating revenues | $ | 5.0 | $ | 6.6 | ||||
Other income (expenses), net | - | 0.3 | ||||||
Effectiveness net gains (losses) | $ | 5.0 | $ | 6.9 |
Business Risks
As discussed in the December 31, 2011 Emera annual MD&A, Repsol Energy Canada (“REC”) has a 25 year firm service agreement with Brunswick Pipeline to transport liquefied natural gas.
In Q1 2012, REC’s parent company, Repsol YPF, S.A (“Repsol”), was downgraded by Moody’s 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.
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DISCLOSURE AND INTERNAL CONTROLS
The Company, under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, has designed as at March 31, 2012 disclosure controls and procedures (“DC&P”) and internal controls over financial reporting (“ICFR”) as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”).
Pursuant to Section 404(c) of the Sarbanes-Oxley Act of 2002 (“SOX”), as added by Section 989G of the Dodd-Frank Wall Street Reform and Consumer Protection Act, the requirement under Section 404(b) of SOX to file an auditor attestation report on an issuer’s ICFR does not apply with respect to any audit report prepared for an issuer that is neither an accelerated filer nor a large accelerated filer, as defined in Rule 12b-2 under the United States Securities Exchange Act of 1934, as amended. As previously noted, in December 2011, NSPI made the necessary filings to terminate its SEC reporting obligations and is no longer a SEC registrant. As a new registrant, Emera was not required to include an attestation report on its ICFR in its first Annual Report to be filed with the SEC for the year ending December 31, 2011, but would be required to include an attestation report in its subsequent Annual Reports for any year in which it is an accelerated filer or a large accelerated filer.
There have been no changes in Emera or its consolidated subsidiaries’ ICFR during the period beginning on January 1, 2012 and ending on March 31, 2012, which have materially affected, or are reasonably likely to materially affect ICFR.
CRITICAL ACCOUNTING ESTIMATES
The preparation of consolidated 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. Significant areas requiring the use of management estimates relate to rate-regulation, the determination of pension and other post-retirement employee benefits, unbilled revenue, useful lives for depreciable assets, income taxes, asset retirement obligations and goodwill impairment assessments. Actual results may differ from these estimates.
SUMMARY OF QUARTERLY RESULTS
For the quarter ended | ||||||||||||||||||||||||||||||||
millions of dollars | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | ||||||||||||||||||||||||
(except per share amounts) | 2012 | 2011 | 2011 | 2011 | 2011 | 2010 | 2010 | 2010 | ||||||||||||||||||||||||
Operating revenues | $ | 568.0 | $ | 512.0 | $ | 496.1 | $ | 501.7 | $ | 554.6 | $ | 408.9 | $ | 394.0 | $ | 364.7 | ||||||||||||||||
Net income attributable to common shareholders | 80.2 | 46.8 | 40.8 | 29.9 | 123.6 | 24.1 | 40.3 | 48.5 | ||||||||||||||||||||||||
Earnings per common share – basic | 0.65 | 0.38 | 0.33 | 0.24 | 1.06 | 0.21 | 0.35 | 0.43 | ||||||||||||||||||||||||
Earnings per common share – diluted | 0.64 | 0.38 | 0.33 | 0.24 | 1.03 | 0.21 | 0.35 | 0.42 |
Quarterly operating revenues and net income attributable to common shareholders are affected by seasonality. Q1 and Q4 are generally the strongest because a significant portion of the Company’s operations are located in northeast North America, where winter is the peak electricity season. Quarterly results are also affected by items outlined in the Significant Items section.
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