Exhibit 99.1
Management’s Discussion & Analysis
As at August 5, 2011
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 second quarter of 2011 relative to 2010, and its financial position as at June 30, 2011 relative to December 31, 2010. 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 affiliates.
Effective January 1, 2011, Emera changed the basis of presentation of its financial statements from Canadian Generally Accepted Accounting Principles (“CGAAP”) to United States Generally Accepted Accounting Principles (“USGAAP”) including the application of rate-regulated accounting policies for Emera’s rate-regulated subsidiaries.
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 six months ended June 30, 2011, prepared in accordance with USGAAP; and the Emera Incorporated MD&A and annual audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2010, prepared in accordance with CGAAP.
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 Commissions (“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 | |
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 Emera 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; derivative financial instruments and hedging availability and cost of financing; interest rate risk; counterparty risk; competitiveness of electricity; 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 reflects the transition to USGAAP from CGAAP, effective January 1, 2011, as previously noted. Information derived from the Consolidated Statements of Income for the three and six months ended June 30, 2010 and Consolidated Balance Sheets as at December 31, 2010, along with other select financial information for 2010 and 2009 has been adjusted to reflect USGAAP and is clearly labeled “adjusted”.
This MD&A begins with an Introduction and Strategic Overview; followed by the Consolidated Financial Review of the Statements of Income, Balance Sheets and Cash Flows, and outstanding share data; then presents information separately on Emera’s operations, specifically:
• | NSPI; |
• | Maine Utility Operations (Bangor Hydro, MPS and its parent company, Maine and Maritimes Corporation (“MAM”)); |
• | Caribbean Utility Operations (BLPC and its parent company, Light and Power Holdings Ltd. (“LPH”), GBPC, ICD Utilities Limited (“ICDU”) and St. Lucia Electricity Services (“Lucelec”)); |
• | Pipelines (Brunswick Pipeline and Maritimes & Northeast Pipeline (“M&NP”)); |
• | Other operations are grouped and discussed under Services, Renewables and Other Investments and include: |
• | Emera Energy (Emera Energy Services, Bayside Power Limited Partnership (“Bayside Power”), Bear Swamp Power Company LLC. (“Bear Swamp”)), |
• | Emera Utility Services (“EUS”), |
• | Emera Newfoundland and Labrador (“ENL”), |
• | Algonquin Power and Utilities Corp. (“APUC”), |
• | California Pacific Utilities Ventures, LLC (“CPUV”) and |
• | Atlantic Hydrogen Inc. (“AHI”); and |
• | Corporate-wide functions. |
The Outlook, Liquidity and Capital Resources, Transactions with Related Parties, Risk Management and Financial Instruments, Disclosure and Internal Controls, and Summary of Quarterly Results sections of the MD&A are presented on a consolidated basis.
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INTRODUCTION AND STRATEGIC OVERVIEW
Emera Incorporated is an energy and services company with $6.6 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 over the next five years 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 low risk generation.
Over 80 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.
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” and “Regulated fuel for generation and purchased power – affiliates”, net of the “Regulated fuel adjustment”, fuel related foreign exchange losses or gains 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”) on NSPI’s operations. Electric margin is discussed in the NSPI Review of 2011 section.
Services, Renewables and Other Investments
“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 income 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 – Significant Items section and the Review of 2011 – Services, Renewables and Other Investments section.
Earnings before interest and taxes (“EBIT”) is a non-GAAP financial measure used by Emera and is defined as “Income” before “Interest expense, net” and “Income tax expense (recovery)”. This measure is disclosed as management believes it provides useful information on how it views the operations of Emera Energy and Emera Utility Services. EBIT is discussed in the Review of 2011 – Services, Renewables and Other Investments section.
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CONSOLIDATED FINANCIAL REVIEW
Consolidated Financial Highlights
millions of Canadian dollars (except per share amounts) | Three months ended June 30 | Six months ended June 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Operating revenues | $ | 500.8 | $ | 364.7 | $ | 1,055.4 | $ | 803.2 | ||||||||
Consolidated net income attributable to common shareholders | 29.9 | 48.5 | 153.5 | 126.3 | ||||||||||||
Earnings per common share – basic | 0.24 | 0.43 | 1.29 | 1.11 | ||||||||||||
Earnings per common share – diluted | 0.24 | 0.42 | 1.26 | 1.08 | ||||||||||||
Dividends per common share declared | 0.3250 | 0.2825 | 0.6500 | 0.5550 |
Emera Inc.’s consolidated net earnings were $29.9 million in Q2 2011, compared to $48.5 million in Q2 2010 (adjusted). The 2010 comparative amount includes a $22.5 million non-taxable accounting gain on an acquisition. Absent this amount, Q2 2010 net earnings were $26.0 million. Reported basic earnings per share were $0.24 in Q2 2011 and $0.43 in Q2 2010 (adjusted) ($0.23 in Q2, 2010 (adjusted) excluding the aforementioned accounting gain).
millions of Canadian dollars (except per share amounts) | Three months ended June 30 | Six months ended June 30 | ||||||||||||||
Operating Unit Contributions | 2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | ||||||||||||
NSPI | $ | 16.7 | $ | 15.5 | $ | 80.3 | $ | 80.7 | ||||||||
Maine Utility Operations | 8.4 | 7.0 | 17.8 | 12.6 | ||||||||||||
Caribbean Utility Operations | 3.4 | 24.5 | 33.0 | 24.7 | ||||||||||||
Pipelines | 7.2 | 4.5 | 14.0 | 12.8 | ||||||||||||
Services, Renewables and Other Investments | (1.9 | ) | 0.7 | 18.7 | 0.1 | |||||||||||
Corporate | (3.9 | ) | (3.7 | ) | (10.3 | ) | (4.6 | ) | ||||||||
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Consolidated net income attributable to common shareholders | $ | 29.9 | $ | 48.5 | $ | 153.5 | $ | 126.3 | ||||||||
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Net income applicable to common shares, absent the Bear Swamp after-tax mark-to-market adjustment | $ | 30.7 | $ | 48.3 | $ | 153.1 | $ | 130.4 | ||||||||
Earnings per common share – basic | $ | 0.24 | $ | 0.43 | $ | 1.29 | $ | 1.11 | ||||||||
Earnings per common share – basic, absent the Bear Swamp after-tax mark-to-market adjustment | $ | 0.25 | $ | 0.43 | $ | 1.29 | $ | 1.15 |
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Developments
Emera
Common Share Financing
On March 16, 2011, Emera completed its offering of 6,359,500 common shares, including the exercise of the over-allotment option of 829,500 common shares, at $31.70 per common share, for net proceeds of approximately $196.0 million. The net proceeds of the offering were used for general corporate purposes, including repayment of indebtedness under Emera’s credit facility.
Strategic Partnership with Algonquin Power and Utilities Corp.
Closing of the California Pacific Transaction
On January 1, 2011, Emera and APUC closed their acquisition of the California-based electricity distribution and related generation assets of NV Energy, Inc. for total consideration of $134.2 million CAD ($131.8 million USD), subject to final adjustments. A new utility company, California Pacific Electric Company, LLC (“California Pacific”) was established to own and operate the assets. California Pacific is wholly owned by California Pacific Utilities Ventures LLC (“CPUV”), which in turn is owned 49.999 percent by Emera and 50.001 percent by APUC. Emera paid $31.5 million CAD ($30.9 million USD) for its interest in the common shares of CPUV.
Pursuant to an April 2009 Subscription Receipts Agreement with APUC, upon the closing of the California Pacific transaction in Q1, 2011, as described above, Emera exchanged subscription receipts acquired in 2009 into 8.523 million APUC common shares issued at $3.25 per share, resulting in an after-tax gain of $12.8 million. This gain is recorded in “Other income (expenses), net” on Emera’s Consolidated Statements of Income for the six months ended June 30, 2011. As a result of this transaction, and a subsequent conversion of certain APUC debentures to equity, Emera currently owns an approximate 7.2 percent equity interest in APUC.
New Hampshire Transaction
On March 25, 2011, Emera purchased 12 million subscription receipts from APUC at an issue price of $5.00 each for a total purchase price of $60 million. Emera issued a promissory note in exchange for the subscription receipts. The subscription receipts are convertible to 12 million APUC common shares upon the acquisition by APUC’s regulated subsidiary, Liberty Energy Utilities Co., of all issued and outstanding shares of Granite State Electric Company and Energy North Natural Gas Inc., two regulated electric utilities, currently owned by National Grid USA (the “New Hampshire Transaction”). The acquisition is subject to applicable regulatory approvals. The purchase of subscription receipts has received final Toronto Stock Exchange approval.
Assuming the completion of the New Hampshire Transaction, which is expected in late 2011, the associated conversion of the subscription receipts to APUC common shares, and the exercise of Emera’s anti-dilution rights, Emera’s percentage ownership interest in APUC will increase to approximately 15 percent. Proceeds from the subscription receipts will be used by APUC to finance a portion of this acquisition.
The subscription receipts are recorded in “Other assets” at cost as they do not have a quoted market price in an active market. The promissory note is recorded in “Short-term debt” and measured at its amortized cost using the effective interest method. The carrying value of the promissory note approximates its fair value given its short-term nature.
Sale of CPUV to APUC
On April 29, 2011 Emera and APUC entered into a Strategic Investment Agreement (“SIA”) which established how Emera and APUC will work together to pursue specific strategic investments of mutual benefit. The SIA outlines “areas of pursuit” for both Emera and APUC. Emera will pursue investment opportunities related to regulated renewable projects within its service territories, and large electric utilities.
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Consistent with the framework established by the SIA referred to above, Emera has agreed to sell its 49.999 percent direct ownership in CPUV, recorded at $31.5 million, to APUC, subject to California regulatory approval. As consideration, Emera will receive 8.211 million APUC shares in two tranches. Approximately half of the APUC shares will be issued to Emera following regulatory approval of the CPUV ownership transfer with the remainder of the shares to be issued upon completion of California Pacific’s first rate case expected in the first half of 2012. The ultimate proceeds on disposition received from APUC for the CPUV shares will be based on the value of APUC shares when transferred.
First Wind
On April 30, 2011, Emera and APUC announced their intention to form a partnership with First Wind Holdings LLC (“First Wind”). First Wind’s assets include 370 megawatts (“MW”) of wind energy projects in the northeastern United States, including five operating projects and two projects near operation. These assets will become part of a new operating company, owned 51 percent by First Wind, and 49 percent by a new Emera / APUC owned entity, Northeast Wind. Northeast Wind will invest a total of approximately $333 million USD to acquire its 49 percent interest in the operating company, including a $150 million USD loan (“the First Wind Transaction”). The acquisition requires certain state and federal regulatory approvals and is expected to close by the end of the year. Emera will own 75 percent of Northeast Wind and APUC the balance. Emera will finance its share of the transaction through existing credit facilities subject to lender approval.
On July 29, 2011, Emera purchased approximately 6.9 million subscription receipts from APUC at an issue price of $5.37 each for a total purchase price of $37 million. Emera issued a promissory note in exchange for the subscription receipts. The subscription receipts are convertible to approximately 6.9 million APUC common shares immediately prior to the closing of the First Wind Transaction. The purchase of subscription receipts has received conditional Toronto Stock Exchange approval.
Including the investment in APUC subscription receipts, Emera’s total investment in the Northeast Wind Transaction will be approximately $289 million.
Assuming the completion of the Northeast Wind Transaction, the associated conversion of the subscription receipts to APUC common shares, and the exercise of Emera’s anti-dilution rights, Emera’s percentage ownership interest in APUC will increase by approximately 5.5%. Proceeds from the subscription receipts will be used by APUC to finance a portion of this acquisition.
This transaction, along with the sale of CPUV to APUC described previously, provides Emera with the opportunity to increase its ownership interest in APUC to 24.4 percent. This was approved by APUC shareholders in Q2, 2011.
The Barbados Light & Power Company Limited
On December 20, 2010, Emera offered to purchase all issued and outstanding common stock of LPH, the parent company of BLPC, at a cash price of $25.70 Barbadian dollars. The offer closed on January 24, 2011, and on January 25, 2011, Emera purchased 7.2 million shares representing an additional interest of 41.6 percent. With this additional investment of $92.0 million, Emera became the majority shareholder of LPH, with a total interest of 80.2 percent. Based on the purchase price allocation, as determined under USGAAP, the fair value of the net assets acquired in the LPH acquisition exceeded the purchase price by $28.0 million, which Emera has recorded as a non-taxable gain in “Other income (expenses), net” on Emera’s Consolidated Statements of Income for the six months ended June 30, 2011. Further information on the gain is provided in Significant Items.
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US Securities and Exchange Commission Registration
On February 23, 2011, Emera registered its debt securities, first preferred shares and second preferred shares under the US Securities Act of 1933, as amended, by filing a Form F-9 registration statement with the US Securities and Exchange Commission.
NSPI
Deferral of Certain Tax Benefits Decision
In December 2010, the UARB granted NSPI approval to defer $14.5 million of tax benefits which arose in 2010 related to renewable energy projects. On July 21, 2011, the UARB approved an agreement NSPI reached with stakeholders to apply the deferral against the FAM regulatory asset effective January 1, 2011. The application of the deferral will reduce the amount of the FAM balance outstanding with the reduction applied to the amount that would otherwise be recovered from customers in 2012.
General Rate Application
On May 13, 2011, NSPI filed a General Rate Application (“GRA”) with the UARB requesting an average 7.3 percent rate increase across all customer classes effective January 1, 2012. As an alternative, NSPI publicly proposed a three-year plan that would hold rate increases stable from 2012 to 2014 inclusive. If discussions with customer representatives produce an agreement-in-principle for the alternative plan, NSPI will amend its May 13th application filing and request approval from the UARB for the alternative plan.
Depreciation Settlement
On May 11, 2011, the UARB approved changes to NSPI’s depreciation rates following NSPI’s completion of a depreciation study and a settlement agreement with stakeholders. The overall impact on the average depreciation rate is not material. The new depreciation rates shall come into effect for use in the next GRA as presently filed for 2012.
Light–emitting Diode Streetlight Legislation
On April 21, 2011, the Nova Scotia Government introduced legislation making light-emitting diode (“LED”) lighting mandatory on Nova Scotia’s roads and highways within five years. This legislation builds on previous initiatives focused on energy efficiency and environmental responsibility. The cost to convert to LED lighting province-wide is estimated to be in the range of $100 million. NSPI’s related capital costs will be subject to UARB review and approval.
Nova Scotia Provincial Environmental Regulations
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 will allow regulations to be developed requiring an increase in the percentage of renewable energy in the generation mix from the planned 25 percent in 2015, to 40 percent by 2020.
On April 11, 2011, the Nova Scotia Government announced that the cap on the annual amount of new forest biomass that can be used to generate electricity will be lowered by 30 percent to 350,000 dry tonnes per year. NSPI’s 60 megawatt (“MW”) Port Hawkesbury Biomass Project is not affected by this announcement.
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Digby Wind Renewable Energy Project
On March 9, 2011, the UARB approved a capital work order for the Digby Wind Renewable Energy Project, which included a substation, network upgrades and interconnection costs, in the total amount of $79.8 million. This project went into service in December 2010.
Appointments
On May 2, 2011, James Eisenhauer, FCA was appointed Chairman of NSPI’s Board of Directors, replacing George A Caines, QC, who retired. On May 4, 2011 Mr. Eisenhauer was elected to Emera’s Board of Directors at the Company’s Annual General Meeting.
On June 7, 2011, Sarah MacDonald was appointed President and Chief Executive Officer of GBPC. Prior to this appointment, Ms. MacDonald served as the Executive Vice President of Human Resources at Emera and Chief Executive Officer of Emera Utility Services.
On May 16, 2011, Judy Steele, FCA was appointed Chief Financial Officer of Emera on an interim basis until such time as a permanent CFO is named. Prior to this appointment, Ms. Steele served as Vice President Finance of Emera Energy Inc.
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Significant Items
Bear Swamp Mark-to-Market Adjustment
As part of its long-term energy and capacity supply agreement with the Long Island Power Authority (“LIPA”), which extends to 2021, Bear Swamp has contracted with Emera’s joint venture partner to provide the off-peak power necessary to produce the requirements of the LIPA contract. One of the contracts is marked-to-market through income, as it does not meet the stringent accounting requirements of hedge accounting.
As at June 30, 2011, the fair value of the contract was a net liability of $7.3 million (December 31, 2010 – $8.2 million net liability), which will reverse over the life of the agreement as it is realized.
The mark-to-market adjustment relating to this contract was as follows:
millions of Canadian dollars (except earnings per common share) | Three months ended June 30 | Six months ended June 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Mark-to-market gain (loss) | $ | (1.4 | ) | $ | 0.3 | $ | 0.6 | $ | (6.8 | ) | ||||||
After-tax mark-to-market gain (loss) | $ | (0.8 | ) | $ | 0.2 | $ | 0.4 | $ | (4.1 | ) | ||||||
Earnings per common share – basic | $ | 0.24 | $ | 0.43 | $ | 1.29 | $ | 1.11 | ||||||||
Earnings per common share – basic, absent the Bear Swamp after-tax mark-to-market adjustment | $ | 0.25 | $ | 0.43 | $ | 1.29 | $ | 1.15 |
Gain on Exchange of Subscription Receipts to Shares
As discussed in the Emera Developments section, pursuant to an April 2009 Subscription Receipts Agreement with APUC, and 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.
Gain on Business Acquisition
Under USGAAP, in circumstances where the fair value of net assets acquired in a business acquisition exceeds the purchase price, the difference is recorded as a gain in the period.
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 $28.0 million, respectively. These amounts have been recorded in “Other income (expenses), net” on Emera’s Consolidated Statements of Income in the appropriate periods.
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REVIEW OF 2011
Emera Incorporated’s consolidated net income decreased $18.6 million to $29.9 million in Q2 2011 compared to $48.5 million in Q2 2010 (adjusted). The 2010 comparative amount includes a $22.5 million non-taxable accounting gain on acquisition. Absent this amount, Q2 2010 (adjusted) net earnings were $26.0 million. Year-to-date, Emera’s consolidated net income increased $27.2 million to $153.5 million in 2011 compared to $126.3 million in 2010 (adjusted). Highlights of the changes are summarized in the following table:
millions of Canadian dollars | Three months ended June 30 | Six months ended June 30 | ||||||
Consolidated net income attributable to common shareholders – 2010 (adjusted) | $ | 48.5 | $ | 126.3 | ||||
NSPI – Increased net income during the quarter primarily due to decreased income tax expense and increased electric margin, partially offset by increased operating, maintenance and general expenses; Decreased net income year-to-date due primarily to increased operating, maintenance and general expenses, partially offset by increased electric margin and decreased income taxes | 1.2 | (0.4 | ) | |||||
Maine Utility Operations – Increased net income due primarily to higher transmission pool revenue due to the recovery of regionally funded transmission investments and a transmission rate increase in June 2010. Year-to-date is also increased due to the acquisition of MPS | 1.4 | 5.2 | ||||||
Caribbean Utility Operations – Decreased net income in the quarter due to recognition of a non-taxable gain on acquisition of $22.5 million in Q2 2010; Increased net income year-to-date due primarily to additional $28.0 million gain on acquisition recorded in Q1 2011 and an increased investment in both BLPC and GBPC | (21.1 | ) | 8.3 | |||||
Pipelines – Increased net income primarily due to change in the mark-to-market of currency hedges | 2.7 | 1.2 | ||||||
Services, Renewables and Other Investments – Decreased during the quarter due to increased income taxes and APUC’s convertible debenture conversion; Increased year-to-date due primarily to an after-tax gain of $12.8 million on APUC subscription receipts, and a positive change in the fair value of the net derivatives in Bear Swamp | (2.6 | ) | 18.6 | |||||
Corporate – Increased costs year-to-date due primarily to increased deferred compensation, corporate activities and preferred share dividends partially offset by decreased acquisition costs | (0.2 | ) | (5.7 | ) | ||||
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Consolidated net income attributable to common shareholders – 2011 | $ | 29.9 | $ | 153.5 | ||||
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Basic earnings per share are $0.24 in Q2 2011 compared to $0.43 in Q2 2010 (adjusted) ($0.23 in Q2, 2010 excluding the aforementioned $22.5 million accounting gain); and $1.29 year-to-date in 2011 compared to $1.11 in 2010 (adjusted).
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Consolidated Balance Sheets Highlights
Significant changes in the consolidated balance sheets between June 30, 2011 and December 31, 2010 (adjusted) include:
millions of Canadian dollars | Increase (Decrease) | Explanation | ||||
Assets | ||||||
Cash and cash equivalents | $ | 67.6 | See consolidated cash flow highlights section. | |||
Restricted cash | (49.6 | ) | Decreased due primarily to use of restricted cash in Q1, 2011 related to the purchase of APUC subscription receipts offset in part by new restricted cash due to acquisition of LPH. | |||
Receivables, net | 33.0 | Increased due primarily to acquisition of LPH and increase in NSPI fuel related electricity pricing effective January 1, 2011 and timing of billings and receipts, partially offset by seasonal business trends. | ||||
Income taxes receivable | 13.0 | Recovery of income taxes due to accelerated tax deductions for property, plant and equipment, including renewable investments. | ||||
Inventory | 17.3 | Increase due primarily to acquisition of LPH. | ||||
Deferred income taxes (current and long-term) | (11.0 | ) | Decreased deferred income tax asset on net pension liability, and increased deferred income tax liability on property, plant and equipment, including renewable investments, resulting in reclassification to deferred income tax liability. | |||
Derivative instruments (current and long-term) | (16.0 | ) | Decrease primarily due to favourable hedges settling in 2011. | |||
Regulatory assets (current and long-term) | 33.8 | Increased deferred income taxes regulatory asset, partially offset by regulatory amortization. | ||||
Prepaid expenses | 29.0 | Increased due to timing of provincial grants in lieu of taxes and insurance payments and acquisition of LPH. | ||||
Other assets (current and long-term) | 30.7 | Increased primarily due to purchase of APUC subscription receipts. | ||||
Property, plant & equipment, net of accumulated depreciation | 295.0 | Increased primarily due to acquisition of LPH and capital spending. | ||||
Investments subject to significant influence | (32.0 | ) | Decreased due primarily to acquisition of LPH partially offset by the APUC investment. | |||
Available-for-sale investment | 54.2 | Increased due to acquisition of LPH. | ||||
Liabilities and Equity | ||||||
Short-term debt and long-term debt (including current portion) | 91.2 | Increased primarily due to acquisition of LPH. | ||||
Deferred income taxes (current and long-term) | 65.8 | Increased deferred income tax liability on property, plant and equipment, including renewable investments, and decreased deferred income tax asset on net pension liability, resulting in reclassification of deferred income tax asset. | ||||
Regulatory liabilities (current and long-term) | 28.5 | Increased due to acquisition of LPH, partially offset by decreased deferred income taxes regulatory liability and decreased derivative regulatory liability. | ||||
Pension and post-retirement liabilities (current and long-term) | (12.4 | ) | Decreased primarily due to NSPI’s cash contributions exceeding the value of the current benefit accrual. | |||
Asset retirement obligations | (54.2 | ) | Decreased primarily due to change in estimates of the retirement dates and future decommissioning costs. | |||
Common stock | 220.2 | Issuance of common shares. | ||||
Accumulated other comprehensive loss | 13.5 | Increased primarily due to the unfavourable effect of a stronger CAD on Emera’s foreign investments. | ||||
Non-controlling interest in subsidiaries | 60.3 | Increased primarily due to acquisition of LPH. | ||||
Retained earnings | 76.3 | 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 the six months ended June 30, 2011 and 2010 (adjusted) include:
Six months ended June 30 millions of Canadian dollars | 2011 | 2010 (adjusted) | Explanation | |||||||
Cash and cash equivalents, beginning of period | $ | 7.3 | $ | 20.2 | ||||||
Provided by (used in): | ||||||||||
Operating activities | 151.8 | 110.0 | In 2011 and 2010, increased cash income and non-cash working capital. | |||||||
Investing activities | (267.1 | ) | (302.1 | ) | In 2011, increased investment in LPH and APUC subscription receipts, capital spending, including NSPI additions associated with multi-year projects and renewable investments. | |||||
In 2010, capital spending, including NSPI additions associated with multi-year projects, and renewable investments. | ||||||||||
Financing activities | 182.1 | 216.8 | In 2011, issuance of common shares, partially offset by decreased debt levels. | |||||||
In 2010, increased debt levels and the issuance of preferred shares, partially offset by dividends on common shares. | ||||||||||
Foreign currency impact on cash balances | 0.8 | 0.2 | ||||||||
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Cash and cash equivalents, end of period | $ | 74.9 | $ | 45.1 | ||||||
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Outstanding Share Data
Issued and Outstanding: | Millions of Shares | Common Stock millions of Canadian dollars (adjusted) | ||||||
December 31, 2009 | 112.98 | $ | 1,097.9 | |||||
Issued for cash under purchase plans | 1.32 | 32.8 | ||||||
Options exercised under senior management stock option plan | 0.32 | 6.0 | ||||||
Stock-based compensation | — | 1.1 | ||||||
December 31, 2010 | 114.62 | $ | 1,137.8 | |||||
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Issuance of common stock | 6.36 | 196.0 | ||||||
Issued for cash under purchase plans | 0.64 | 19.0 | ||||||
Options exercised under senior management stock option plan | 0.21 | 4.5 | ||||||
Stock-based compensation | — | 0.7 | ||||||
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June 30, 2011 | 121.83 | $ | 1,358.0 | |||||
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As at July 22, 2011 the amount of issued and outstanding common stock was 121.89 million.
13
NSPI
Overview
Nova Scotia Power Inc. (“NSPI”) is a fully-integrated regulated electric utility with $3.9 billion of assets and the primary electricity supplier in Nova Scotia. NSPI provides electricity generation, transmission and distribution services to approximately 490,000 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 prescribed regulated ROE range for 2011 is 9.1 percent to 9.6 percent, based on an actual regulated common equity component of up to 40 percent of average regulated capitalization.
Review of 2011
NSPI Net Income millions of Canadian dollars | Three months ended June 30 | Six months ended June 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Operating revenues – regulated | $ | 299.0 | $ | 273.2 | $ | 667.8 | $ | 616.0 | ||||||||
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Regulated fuel for generation and purchased power | 125.4 | 119.5 | 294.3 | 299.1 | ||||||||||||
Regulated fuel for generation and purchased power – affiliates | 0.4 | 4.8 | 0.1 | 6.4 | ||||||||||||
Regulated fuel adjustment | 6.2 | (12.6 | ) | 0.4 | (52.0 | ) | ||||||||||
Operating, maintenance and general | 68.9 | 60.0 | 134.4 | 114.9 | ||||||||||||
Provincial grants and taxes | 9.6 | 10.0 | 19.2 | 20.0 | ||||||||||||
Depreciation and amortization | 42.7 | 41.9 | 85.3 | 83.0 | ||||||||||||
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Total operating expenses | 253.2 | 223.6 | 533.7 | 471.4 | ||||||||||||
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Income from operations | 45.8 | 49.6 | 134.1 | 144.6 | ||||||||||||
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Other expenses, net | 2.3 | 2.3 | 4.5 | 5.9 | ||||||||||||
Interest expense, net | 27.0 | 26.6 | 53.9 | 52.7 | ||||||||||||
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Income before provision for income taxes | 16.5 | 20.7 | 75.7 | 86.0 | ||||||||||||
Income tax (recovery) expense | (2.2 | ) | 3.2 | (8.6 | ) | 1.3 | ||||||||||
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Net income of Nova Scotia Power Inc. | 18.7 | 17.5 | 84.3 | 84.7 | ||||||||||||
Preferred stock dividends | 2.0 | 2.0 | 4.0 | 4.0 | ||||||||||||
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Contribution to consolidated net income | $ | 16.7 | $ | 15.5 | $ | 80.3 | $ | 80.7 | ||||||||
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Contribution to consolidated earnings per common share | $ | 0.13 | $ | 0.14 | $ | 0.67 | $ | 0.71 | ||||||||
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NSPI’s contribution to consolidated net income increased $1.2 million to $16.7 million in Q2 2011 compared to $15.5 million in Q2 2010 (adjusted). NSPI’s contribution to consolidated net income year-to-date decreased $0.4 million to $80.3 million in 2011 compared to $80.7 million in 2010 (adjusted). Highlights of the net income changes are summarized in the following table:
millions of Canadian dollars | Three months ended June 30 | Six months ended June 30 | ||||||
Contribution to consolidated net income – 2010 (adjusted) | $ | 15.5 | $ | 80.7 | ||||
Increased electric margin (see Electric Revenues section for explanation) | 4.8 | 10.6 | ||||||
Increased operating, maintenance and general expenses due primarily to increased pension costs, labour escalation and increased plant maintenance costs | (8.9 | ) | (19.5 | ) | ||||
Increased net depreciation and amortization due primarily to increased property, plant and equipment partially offset by decreased regulatory amortization | (0.5 | ) | (1.7 | ) | ||||
Decreased income tax expense due primarily to decreased income before provision for income taxes, accelerated tax deductions for property, plant and equipment and a lower statutory income tax rate | 5.4 | 9.9 | ||||||
Other | 0.4 | 0.3 | ||||||
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Contribution to consolidated net income – 2011 | $ | 16.7 | $ | 80.3 | ||||
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14
Operating Revenues – Regulated
NSPI’s Operating Revenues – Regulated include sales of electricity and other services as summarized in the following table:
millions of Canadian dollars | Three months ended June 30 | Six months ended June 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Electric revenues | $ | 293.2 | $ | 267.0 | $ | 656.6 | $ | 604.5 | ||||||||
Other revenues | 5.8 | 6.2 | 11.2 | 11.5 | ||||||||||||
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Operating revenues – regulated | $ | 299.0 | $ | 273.2 | $ | 667.8 | $ | 616.0 | ||||||||
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Electric Revenues
Sales volume (“load”)
Electric sales volume is primarily driven by general economic conditions, population and weather. Residential and commercial electricity sales are seasonal, with Q1 and Q4 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 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:
Q2 Electric Sales Volumes
Gigawatt hours (“GWh”)
2011 | 2010 | 2009 | ||||||||||
Residential | 965 | 887 | 916 | |||||||||
Commercial | 729 | 722 | 713 | |||||||||
Industrial | 1,011 | 938 | 887 | |||||||||
Other | 71 | 69 | 75 | |||||||||
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Total | 2,776 | 2,616 | 2,591 | |||||||||
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Year-to-date (“YTD”) Electric Sales Volumes
GWh
2011 | 2010 | 2009 | ||||||||||
Residential | 2,410 | 2,277 | 2,348 | |||||||||
Commercial | 1,601 | 1,571 | 1,590 | |||||||||
Industrial | 1,998 | 1,903 | 1,726 | |||||||||
Other | 158 | 155 | 173 | |||||||||
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Total | 6,167 | 5,906 | 5,837 | |||||||||
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Electricity Pricing (“rates”)
Electric revenues are summarized in the following tables by customer class:
Q2 Electric Revenues
millions of Canadian dollars
2011 | 2010 | 2009 | ||||||||||
Residential | $ | 129.1 | $ | 115.8 | $ | 120.8 | ||||||
Commercial | 80.8 | 76.7 | 77.5 | |||||||||
Industrial | 73.1 | 64.9 | 65.2 | |||||||||
Other | 10.2 | 9.6 | 9.9 | |||||||||
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Total | $ | 293.2 | $ | 267.0 | $ | 273.4 | ||||||
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YTD Electric Revenues
millions of Canadian dollars
2011 | 2010 | 2009 | ||||||||||
Residential | $ | 314.3 | $ | 288.1 | $ | 300.0 | ||||||
Commercial | 176.0 | 165.1 | 170.6 | |||||||||
Industrial | 144.8 | 131.1 | 129.1 | |||||||||
Other | 21.5 | 20.2 | 21.5 | |||||||||
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Total | $ | 656.6 | $ | 604.5 | $ | 621.2 | ||||||
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15
Electric revenues increased $26.2 million to $293.2 million in Q2 2011 compared to $267.0 million in Q2 2010. Year-to-date, electric revenues increased $52.1 million to $656.6 million in 2011 from $604.5 million in 2010. Highlights of the changes are summarized in the following table:
millions of Canadian dollars | Three months ended June 30 | Six months ended June 30 | ||||||
Electric revenues – 2010 | $ | 267.0 | $ | 604.5 | ||||
Increased fuel related electricity pricing effective January 1, 2011 | 12.7 | 28.4 | ||||||
Increased residential sales volumes in the quarter. Increased residential and commercial sales volumes year-to-date. | 9.3 | 17.9 | ||||||
Increased industrial sales volume | 4.0 | 5.3 | ||||||
Other | 0.2 | 0.5 | ||||||
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Electric revenues – 2011 | $ | 293.2 | $ | 656.6 | ||||
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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 introduced on January 1, 2009 enables NSPI to seek recovery of fuel costs through regularly scheduled rate adjustments. Differences between actual fuel costs and amounts recovered from customers through electricity rates in a period are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent period. Consequently, fuel electric revenues and fuel costs do not have a material effect on NSPI’s electric margin or net income, with the exception of the incentive component of the FAM, whereby NSPI retains or absorbs 10 percent of the over or under recovered amount to a maximum of $5 million.
As fuel costs are recovered through the FAM, 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, have the largest effect on non-fuel electric revenues. Changes in industrial load, which are generally due to economic conditions, do not have as significant an effect on non-fuel electric revenues.
Electric margin is summarized in the following table:
millions of Canadian dollars | Three months ended June 30 | Six months ended June 30 | ||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Fuel electric revenues – current year | $ | 126.1 | $ | 116.9 | $ | 281.3 | $ | 265.6 | ||||||||
Fuel electric revenues – preceding periods | 6.4 | (5.1 | ) | 14.6 | (11.5 | ) | ||||||||||
Non-fuel electric revenues | 160.7 | 155.2 | 360.7 | 350.4 | ||||||||||||
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Total electric revenues | 293.2 | 267.0 | 656.6 | 604.5 | ||||||||||||
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Regulated fuel for generation and purchased power, including affiliates | (125.8 | ) | (124.3 | ) | (294.4 | ) | (305.5 | ) | ||||||||
Regulated fuel adjustment | (6.2 | ) | 12.6 | (0.4 | ) | 52.0 | ||||||||||
Other fuel related costs | (2.0 | ) | (0.9 | ) | (3.9 | ) | (3.7 | ) | ||||||||
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Electric margin | $ | 159.2 | $ | 154.4 | $ | 357.9 | $ | 347.3 | ||||||||
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NSPI’s electric margin increased $4.8 million to $159.2 million in Q2 2011 compared to $154.4 million in Q2 2010 due primarily to increased residential sales as a result of load growth and colder weather. Year-to-date, NSPI’s electric margin increased $10.6 million to $357.9 million in 2011 compared to $347.3 million in 2010 due primarily to increased residential and commercial sales as a result of load growth and colder weather.
16
Q2 Average Electric Margin / Megawatt hour (“MWh”)
2011 | 2010 | 2009 | ||||||||||
Dollars per MWh | $ | 57 | $ | 59 | $ | 61 |
YTD Average Electric Margin / MWh
2011 | 2010 | 2009 | ||||||||||
Dollars per MWh | $ | 58 | $ | 59 | $ | 61 |
The change in Q2 and year-to-date average electric margin per MWh in 2011 compared to 2010 reflects a change in sales mix.
Regulated Fuel for Generation and Purchased Power (including affiliates)
Q2 Production Volumes
GWh
2011 | 2010 | 2009 | ||||||||||
Coal and petcoke | 1,436 | 1,645 | 1,956 | |||||||||
Natural gas | 668 | 578 | 356 | |||||||||
Oil | 3 | 4 | 18 | |||||||||
Renewables | 393 | 237 | 287 | |||||||||
Purchased power | 394 | 268 | 107 | |||||||||
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Total | 2,894 | 2,732 | 2,724 | |||||||||
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Purchased power includes 178 GWh of renewables in Q2 2011 (2010 – 128 GWh; 2009 – 66 GWh). |
Q2 Average Unit Fuel Costs
2011 | 2010 | 2009 | ||||||||||
Dollars per MWh | $ | 43 | $ | 45 | $ | 37 |
YTD Production Volumes
GWh
2011 | 2010 | 2009 | ||||||||||
Coal and petcoke | 3,653 | 3,944 | 4,333 | |||||||||
Natural gas | 1,329 | 1,228 | 660 | |||||||||
Oil | 26 | 10 | 280 | |||||||||
Renewables | 808 | 523 | 600 | |||||||||
Purchased power | 665 | 489 | 312 | |||||||||
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Total | 6,481 | 6,194 | 6,185 | |||||||||
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Purchased power includes 360 GWh of renewables in 2011 (2010 – 237 GWh; 2009 – 146 GWh). |
YTD Average Unit Fuel Costs
2011 | 2010 | 2009 | ||||||||||
Dollars per MWh | $ | 45 | $ | 49 | $ | 40 |
Regulated fuel for generation and purchased power, including affiliates increased $1.5 million to $125.8 million in Q2 2011 compared to $124.3 million in Q2 2010. Year-to-date, regulated fuel for generation and purchased power, including affiliates decreased $11.1 million to $294.4 million in 2011 compared to $305.5 million in 2010. Highlights of the changes are summarized in the following table:
millions of Canadian dollars | Three months ended June 30 | Six months ended June 30 | ||||||
Regulated fuel for generation and purchased power, including affiliates – 2010 | $ | 124.3 | $ | 305.5 | ||||
Decreased commodity prices | (14.5 | ) | (28.2 | ) | ||||
Increased hydro and wind production | (7.9 | ) | (18.1 | ) | ||||
Favourable solid fuel commodity mix and additives related to emission compliance | (4.4 | ) | (14.4 | ) | ||||
Changes in generation mix and plant performance | 10.0 | 18.5 | ||||||
Increased sales volume | 8.2 | 15.9 | ||||||
Valuation of contract receivable (see discussion below) | 10.3 | 15.7 | ||||||
Other | (0.2 | ) | (0.5 | ) | ||||
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Regulated fuel for generation and purchased power, including affiliates – 2011 | $ | 125.8 | $ | 294.4 | ||||
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Through Q4, 2010, NSPI had a long-term contract receivable with a natural gas supplier that was required to be fair-valued. The natural gas supply contract settled in November 2010.
Regulated Fuel Adjustment
In December 2010, as part of the FAM regulatory process, the UARB approved NSPI’s setting of the 2011 base cost of fuel and the under-recovered fuel related costs from prior years. The UARB approved the recovery of the prior year FAM balance from customers over three years effective January 1, 2011, with 50 percent to be recovered in 2011, 30 percent in 2012 and 20 percent in 2013.
17
The FAM regulatory asset or liability includes amounts recognized as a regulated fuel adjustment and associated interest included in “Interest expense – net”. Details of the regulated fuel adjustment deferral related to the FAM are summarized in the following table:
millions of Canadian dollars | 2011 | |||
FAM regulatory asset – Balance at January 1 | $ | 92.9 | ||
Under-recovery of current period fuel costs | 14.2 | |||
Recovery from customers of prior periods fuel costs | (14.6 | ) | ||
Interest revenue on FAM balance | 3.9 | |||
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FAM regulatory asset – Balance at June 30 | $ | 96.4 | ||
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18
MAINE UTILITY OPERATIONS
Maine Utility Operations (“Maine Utilities”) includes Bangor Hydro Electric Company (“Bangor Hydro”), Maine Public Service Company (“MPS”) and Maine and Maritimes Corporation (“MAM”), the parent company of MPS. All amounts in the Maine Utility Operations section are reported in USD unless otherwise stated.
Overview
Bangor Hydro and MPS are both transmission and distribution (“T&D”) electric utilities. Bangor Hydro has approximately $768.2 million of assets and serves approximately 119,000 customers in eastern Maine. MPS has approximately $138.1 million of assets and serves approximately 36,000 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.
MAM was purchased in late December 2010, thus its results are not included in the June 30, 2010 comparative information.
Review of 2011
Maine Utility Operations’ Net Income millions of US dollars (except per share amounts) | Three months ended June 30 | Six months ended June 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Operating revenues – regulated | $ | 48.2 | $ | 38.8 | $ | 101.5 | $ | 77.7 | ||||||||
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Regulated fuel for generation and purchased power | 6.8 | 7.2 | 14.5 | 15.2 | ||||||||||||
Transmission pool expense (1) | 4.0 | 3.9 | 8.8 | 8.1 | ||||||||||||
Operating, maintenance and general | 10.5 | 8.4 | 23.6 | 18.1 | ||||||||||||
Provincial, state and municipal taxes | 2.2 | 1.6 | 4.6 | 3.5 | ||||||||||||
Depreciation and amortization | 8.5 | 5.2 | 16.0 | 10.3 | ||||||||||||
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Total operating expenses | 32.0 | 26.3 | 67.5 | 55.2 | ||||||||||||
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Income from operations | 16.2 | 12.5 | 34.0 | 22.5 | ||||||||||||
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Other income (expenses), net | 0.7 | 1.0 | 1.4 | 1.9 | ||||||||||||
Interest expense, net | 3.0 | 2.7 | 6.1 | 5.3 | ||||||||||||
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Income before provision for income taxes | 13.9 | 10.8 | 29.3 | 19.1 | ||||||||||||
Income tax expense (recovery) | 5.1 | 4.0 | 11.0 | 6.9 | ||||||||||||
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Contribution to consolidated net income – USD | $ | 8.8 | $ | 6.8 | $ | 18.3 | $ | 12.2 | ||||||||
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Contribution to consolidated net income – CAD | $ | 8.4 | $ | 7.0 | $ | 17.8 | $ | 12.6 | ||||||||
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Contribution to consolidated earnings per common share – CAD | $ | 0.07 | $ | 0.06 | $ | 0.15 | $ | 0.11 | ||||||||
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Net income weighted average foreign exchange rate – CAD/USD | $ | 0.95 | $ | 1.03 | $ | 0.97 | $ | 1.03 | ||||||||
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(1) | Transmission pool expenses are included in “Regulated fuel for generation and purchased power” on the Statements of Income. |
19
Maine Utilities’ contribution to consolidated net income increased by $2.0 million to $8.8 million in Q2 2011 compared to $6.8 million in Q2 2010 (adjusted). Year-to-date, Maine Utilities contribution to consolidated net income increased by $6.1 million to $18.3 million in 2011, compared to $12.2 million in 2010 (adjusted). Highlights of the net income changes are summarized in the following table:
millions of US dollars | Three months ended June 30 | Six months ended June 30 | ||||||
Contribution to consolidated net income – 2010 (adjusted) | $ | 6.8 | $ | 12.2 | ||||
Higher electric revenue in Bangor Hydro due to a transmission rate increase in June 2010 | 0.9 | 2.4 | ||||||
Higher transmission pool revenue in Bangor Hydro due to recovery of regionally funded transmission investments | 1.0 | 3.8 | ||||||
Other | 0.1 | (0.1 | ) | |||||
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Contribution to consolidated net income – 2011 | $ | 8.8 | $ | 18.3 | ||||
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Maine Utilities’ USD and CAD contribution to consolidated net income increased in both Q2 and year-to-date. The impact of a stronger Canadian dollar, year over year, reduced CAD earnings by $0.7 million in Q2 2011 and $1.1 million year-to-date.
Operating Revenues – Regulated
Q2 Electric Sales Volumes
GWh | 2011 | 2010 | 2009 | |||||||||
Residential | 176.3 | 129.9 | 130.3 | |||||||||
Commercial | 200.6 | 137.6 | 137.3 | |||||||||
Industrial | 93.1 | 93.4 | 83.1 | |||||||||
Other | 2.8 | 2.0 | 2.3 | |||||||||
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Total | 472.8 | 362.9 | 353.0 | |||||||||
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YTD Electric Sales Volumes
GWh | 2011 | 2010 | 2009 | |||||||||
Residential | 391.4 | 283.4 | 291.9 | |||||||||
Commercial | 417.0 | 284.8 | 288.1 | |||||||||
Industrial | 183.6 | 171.4 | 162.4 | |||||||||
Other | 5.6 | 5.4 | 5.6 | |||||||||
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Total | 997.6 | 745.0 | 748.0 | |||||||||
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Q2 Operating Revenues – Regulated
millions of US dollars | ||||||||||||
2011 | 2010 (adjusted) | 2009 (adjusted) | ||||||||||
Residential electric | $ | 15.5 | $ | 11.0 | $ | 10.7 | ||||||
Commercial electric | 12.9 | 9.1 | 8.5 | |||||||||
Industrial electric | 2.9 | 2.8 | 2.1 | |||||||||
Other electric | 2.3 | 2.2 | 3.1 | |||||||||
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Total electric revenues | 33.6 | 25.1 | 24.4 | |||||||||
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Resale of purchased power | 4.6 | 4.5 | 4.6 | |||||||||
Transmission pool revenue | 10.0 | 9.2 | 7.8 | |||||||||
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Operating revenues – regulated | $ | 48.2 | $ | 38.8 | $ | 36.8 | ||||||
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YTD Operating Revenues – Regulated
millions of US dollars | ||||||||||||
2011 | 2010 (adjusted) | 2009 (adjusted) | ||||||||||
Residential electric | $ | 34.0 | $ | 23.5 | $ | 23.8 | ||||||
Commercial electric | 27.9 | 18.0 | 17.2 | |||||||||
Industrial electric | 5.8 | 5.3 | 4.8 | |||||||||
Other electric | 5.0 | 5.2 | 5.7 | |||||||||
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Total electric revenues | 72.7 | 52.0 | 51.5 | |||||||||
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Resale of purchased power | 9.0 | 9.7 | 9.4 | |||||||||
Transmission pool revenue | 19.8 | 16.0 | 12.7 | |||||||||
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| |||||||
Operating revenues – regulated | $ | 101.5 | $ | 77.7 | $ | 73.6 | ||||||
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Q2 Average Electric Revenue/MWh
2011 | 2010 | 2009 | ||||||||||
Dollars per MWh | $ | 71 | $ | 70 | $ | 69 | ||||||
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YTD Average Electric Revenue/MWh
2011 | 2010 | 2009 | ||||||||||
Dollars per MWh | $ | 73 | $ | 70 | $ | 69 | ||||||
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20
In both Q2 and year-to-date, the change in average electric revenue per MWh in 2011 compared to 2010 reflects increases in Bangor Hydro’s transmission rates on June 1, 2010. MPS, which was acquired in December 2010, contributed approximately $7.5 million to Maine Utility Operations’ Q2 2011 Operating revenues – regulated and $(0.1) million to Maine Utility Operations’ Q2 2011 consolidated net income.
21
CARIBBEAN UTILITY OPERATIONS
Overview
Caribbean Utility Operations includes Emera’s:
• | 80.2 percent investment in Light and Power Holdings Ltd. (“LPH”) and its wholly owned subsidiary Barbados Light & Power Company Ltd. (“BLPC”). BLPC is a vertically-integrated utility and the sole provider of electricity on the island of Barbados which serves approximately 120,000 customers and is regulated by the Fair Trading Commission, Barbados. The government of Barbados has granted BLPC a licensed, regulated and exclusive franchise to produce, transmit and distribute electricity on the island until 2028. BLPC is regulated under a cost-of-service model with rates set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. BLPC’s approved regulated return on assets for 2011 is 10 percent. A fuel pass-through mechanism ensures fuel costs are recovered. A controlling interest in LPH was acquired in January 2011, and accordingly its results are not fully consolidated in the June 30, 2010 comparative information; the June 30, 2010 results contain only equity earnings. |
• | 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 The Grand Bahama Port Authority which has granted it a licensed, regulated and exclusive franchise to produce, transmit and distribute electricity on the island until 2054. There is a fuel pass-through mechanism and flexible tariff adjustment policies to ensure costs are recovered and a reasonable return earned. A controlling interest in GBPC was acquired in December 2010, and accordingly its results are not fully consolidated in the June 30, 2010 comparative information; the June 30, 2010 results contain only equity earnings. |
• | 19.1 percent interest in St. Lucia Electricity Services (“Lucelec”), a vertically-integrated electric utility on the island of St. Lucia. The investment in Lucelec is equity accounted. |
Review of 2011
Caribbean Utility Operations’ Net Income
millions of Canadian dollars (except per share amounts) | Three months ended June 30 | Six months ended June 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Operating revenues – regulated | $ | 109.3 | — | $ | 182.9 | — | ||||||||||
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Regulated fuel for generation and purchased power | 72.8 | — | 120.0 | — | ||||||||||||
Operating, maintenance and general | 22.9 | — | 41.6 | — | ||||||||||||
Property taxes | 0.4 | — | 0.7 | — | ||||||||||||
Depreciation and amortization | 7.3 | — | 12.3 | — | ||||||||||||
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Total operating expenses | 103.4 | — | 174.6 | — | ||||||||||||
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Income from operations | 5.9 | — | 8.3 | — | ||||||||||||
Income from equity investment | 0.2 | $ | 2.1 | 1.5 | $ | 2.2 | ||||||||||
Other income (expenses), net | 0.3 | 22.5 | 28.7 | 22.5 | ||||||||||||
Interest expense, net | 2.4 | — | 4.4 | — | ||||||||||||
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Income before provision for income taxes | 4.0 | 24.6 | 34.1 | 24.7 | ||||||||||||
Income tax expense (recovery) | (0.1 | ) | — | 0.2 | — | |||||||||||
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Net income | 4.1 | 24.6 | 33.9 | 24.7 | ||||||||||||
Non-controlling interest in subsidiaries | (0.7 | ) | (0.1 | ) | (0.9 | ) | — | |||||||||
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Contribution to consolidated net income | $ | 3.4 | $ | 24.5 | $ | 33.0 | $ | 24.7 | ||||||||
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Contribution to consolidated earnings per common share | $ | 0.03 | $ | 0.21 | $ | 0.28 | $ | 0.22 |
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Caribbean Utility Operations’ contribution to consolidated net income decreased by $21.1 million to $3.4 million in Q2 2011 compared to $24.5 million in Q2 2010 (adjusted) due primarily to a non-taxable gain of $22.5 million on acquisition of LPH recognized in 2010. Year-to-date, contribution to consolidated net income increased by $8.3 million to $33.0 million in 2011 compared to $24.7 million in 2010 (adjusted) due to an additional $28 million gain on acquisition recorded in Q1 2011. Highlights of the net income changes are summarized in the following table:
millions of Canadian dollars | Three months ended June 30 | Six months ended June 30 | ||||||
Contribution to consolidated net income – 2010 (adjusted) | $ | 24.5 | $ | 24.7 | ||||
Gain on acquisition of LPH in 2010 | (22.5 | ) | (22.5 | ) | ||||
Gain on acquisition of LPH in Q1 2011 | — | 28.0 | ||||||
Increased investment in LPH and GBPC | 1.4 | 2.8 | ||||||
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Contribution to consolidated net income – 2011 | $ | 3.4 | $ | 33.0 | ||||
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Electric Revenue
Electric sales volume is primarily driven by general economic conditions, population and weather. Residential and commercial electricity sales are seasonal, with Q2 and Q3 the strongest periods, reflecting warmer weather.
Q2 Electric Sales Volumes
GWh | 2011 | |||
Residential | 99.8 | |||
Commercial | 190.5 | |||
Industrial | 25.9 | |||
Other | 5.6 | |||
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Total | 321.8 | |||
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YTD Electric Sales Volumes
GWh | 2011 | |||
Residential | 176.3 | |||
Commercial | 324.3 | |||
Industrial | 47.0 | |||
Other | 10.6 | |||
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Total | 558.2 | |||
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Q2 Average Electric Revenue/MWh
2011 | ||||
Dollars per MWh | $ | 123.4 | ||
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YTD Average Electric Revenue/MWh
2011 | ||||
Dollars per MWh | $ | 124.5 | ||
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Operating Revenues – Regulated
Q2 Operating Revenues – Regulated
millions of Canadian dollars | 2011 | |||
Residential electric revenue | $ | 11.6 | ||
Commercial electric revenue | 23.3 | |||
Industrial electric revenue | 3.9 | |||
Other electric revenue | 0.9 | |||
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Total electric revenue | 39.7 | |||
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Other – service installation revenue and fuel surcharge | 69.6 | |||
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Operating revenues - regulated | $ | 109.3 | ||
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YTD Operating Revenues – Regulated | ||||
millions of Canadian dollars | 2011 | |||
Residential electric revenue | $ | 20.3 | ||
Commercial electric revenue | 40.1 | |||
Industrial electric revenue | 7.3 | |||
Other electric revenue | 1.8 | |||
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Total electric revenue | $ | 69.5 | ||
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Other – service installation revenue and fuel surcharge | 113.4 | |||
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Operating revenues – regulated | $ | 182.9 | ||
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Fuel for Generation and Purchased Power
Q2 Production Volumes | ||||
GWh | 2011 | |||
Oil | 354.7 | |||
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Q2 Average Unit Fuel Costs/MWh | ||||
2011 | ||||
Dollars per MWh | $ | 205.1 | ||
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YTD Production Volumes | ||||
GWh | 2011 | |||
Oil | 616.1 | |||
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YTD Average Unit Fuel Costs/MWh | ||||
2011 | ||||
Dollars per MWh | $ | 194.7 | ||
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Fuel Pass–Through Mechanisms
BLPC
All BLPC fuel costs pass through to customers through the fuel clause adjustment (“fuel surcharge”). Fair Trading Commission, Barbados has approved the calculation of the fuel surcharge, which is adjusted on a monthly basis. BLPC has the ability to carryover an under-recovery to later months to smooth the fuel surcharge for customers.
GBPC
The current base tariff is calculated based on a price of $20 USD per barrel of oil. The amount by which actual fuel costs exceed $20 USD dollars per barrel is recovered or rebated through the fuel surcharge, which is adjusted on a monthly basis. The methodology for calculating the amount of the fuel surcharge has been approved by The Grand Bahama Port Authority.
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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 natural gas from the Canaport™ re-gasified liquefied natural gas (“LNG”) import terminal near Saint John, New Brunswick, to markets in the northeastern United States. The pipeline, which went into service on July 16, 2009, transports LNG for Repsol Energy Canada under a 25 year firm service agreement. The NEB, which regulates Brunswick Pipeline, has classified it as a Group 2 pipeline. Brunswick Pipeline is accounted for as a direct financing lease.
M&NP is a $2 billion, 1,400-kilometre pipeline which transports natural gas from offshore Nova Scotia to markets in Maritime Canada and the northeastern United States.
Review of 2011
Pipelines’ Net Income
millions of Canadian dollars (except per share amounts) | Three months ended June 30 | Six months ended June 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Brunswick Pipeline | ||||||||||||||||
Operating revenues – regulated | $ | 12.1 | $ | 12.6 | $ | 24.5 | $ | 24.8 | ||||||||
Other income (expenses), net | 0.6 | (2.1 | ) | 0.3 | (0.8 | ) | ||||||||||
Interest expense, net | 7.6 | 7.9 | 15.0 | 15.3 | ||||||||||||
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Brunswick Pipeline net income | 5.1 | 2.6 | 9.8 | 8.7 | ||||||||||||
Income from equity investment | 2.1 | 1.9 | 4.2 | 4.1 | ||||||||||||
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Contribution to consolidated net income | $ | 7.2 | $ | 4.5 | $ | 14.0 | $ | 12.8 | ||||||||
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Contribution to consolidated earnings per common share | $ | 0.06 | $ | 0.04 | $ | 0.12 | $ | 0.11 | ||||||||
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Pipelines’ contribution to consolidated net income increased by $2.7 million to $7.2 million in Q2 2011 compared to $4.5 million in Q2 2010 (adjusted). Year-to-date, Pipelines’ contribution to consolidated net income increased $1.2 million to $14.0 million in 2011 compared to $12.8 million in 2010 (adjusted). Highlights of the income changes are summarized in the following table:
millions of Canadian dollars | Three months ended June 30 | Six months ended June 30 | ||||||
Contribution to consolidated net income – 2010 (adjusted) | $ | 4.5 | $ | 12.8 | ||||
Brunswick Pipeline – Increased net income primarily due to the change in the mark-to-market of currency hedges year-to-date partially offset by decrease in financing income from the pipeline | 2.5 | 1.1 | ||||||
Income from M&NP equity investment | 0.2 | 0.1 | ||||||
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Contribution to consolidated net income – 2011 | $ | 7.2 | $ | 14.0 | ||||
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25
SERVICES, RENEWABLES AND OTHER INVESTMENTS
Services, Renewables and Other Investments includes three subsidiaries, Emera Energy Inc. (“Emera Energy”); Emera Utility Services (“EUS”); and Emera Newfoundland and Labrador (“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. |
• | EUS is a utility services contractor. |
• | Emera Newfoundland and Labrador (“ENL”) is a wholly owned subsidiary of Emera focused on T&D 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. In addition, together with Nalcor Energy, the Newfoundland and Labrador 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. The project is expected to be in service in 2017. Development costs incurred to date have been capitalized. |
• | Other investments include a 7.2 percent investment in Algonquin Power & Utilities Corporation (“APUC”), a 49.999 percent investment in California Pacific Utilities Ventures (“CPUV”) and a 32.1 percent investment in Atlantic Hydrogen Inc (“AHI”). |
Review of 2011
Emera Energy and EUS are reported on an income before interest expense, net and income tax expense (recovery) (“EBIT”) basis. APUC, AHI and CPUV are reported on an equity income basis.
Services, Renewables and Other Investments Net Income millions of Canadian dollars (except per share amounts) | Three months ended June 30 | Six months ended June 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Emera Energy | $ | (2.5 | ) | $ | (2.1 | ) | $ | 5.3 | $ | (0.9 | ) | |||||
EUS | (0.2 | ) | 0.3 | (0.1 | ) | (0.1 | ) | |||||||||
Income from equity investments | 0.4 | (0.2 | ) | 1.2 | (0.2 | ) | ||||||||||
Other income (expenses), net | (1.0 | ) | — | 14.1 | — | |||||||||||
Interest expense, net | 0.4 | — | 0.7 | 0.7 | ||||||||||||
Income tax expense (recovery) | (1.8 | ) | (2.7 | ) | 1.1 | (2.0 | ) | |||||||||
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Contribution to consolidated net (loss) income | $ | (1.9 | ) | $ | 0.7 | $ | 18.7 | $ | 0.1 | |||||||
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Bear Swamp after-tax mark-to-market adjustment | $ | (0.8 | ) | $ | 0.2 | $ | 0.4 | $ | (4.1 | ) | ||||||
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Contribution to consolidated net (loss) income, absent the Bear Swamp after-tax mark-to-market adjustment | $ | (1.1 | ) | $ | 0.5 | $ | 18.3 | $ | 4.2 | |||||||
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Contribution to consolidated net (loss) income per common share | $ | (0.02 | ) | $ | 0.01 | $ | 0.16 | $ | nil | |||||||
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Contribution to consolidated net income per common share, absent the Bear Swamp after-tax mark-to-market adjustment | $ | (0.01 | ) | $ | 0.01 | $ | 0.16 | $ | 0.04 | |||||||
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Services, Renewables and Other Investments contribution to consolidated net income decreased by $2.6 million to a net loss of $1.9 million in Q2 2011 compared to net income of $0.7 million in Q2 2010 (adjusted). Year-to-date, Emera’s contribution to consolidated net income increased $18.6 million to $18.7 million in 2011 compared to $0.1 million in 2010 (adjusted). Highlights of the income changes are summarized in the following table:
millions of Canadian dollars | Three months ended June 30 | Six months ended June 30 | ||||||
Contribution to consolidated net income – 2010 (adjusted) | $ | 0.7 | $ | 0.1 | ||||
Emera Energy – Increased year-to-date due to a positive change in the fair value of the net derivatives in Bear Swamp, and stronger energy marketing results. | (0.4 | ) | 6.2 | |||||
EUS – Decreased due to timing of project activity | (0.5 | ) | — | |||||
Income from equity investments – Increased due to investments in APUC and California Pacific | 0.6 | 1.4 | ||||||
Other income (expenses), net – Decreased during the quarter due to APUC’s convertible debenture conversion; Increased year-to-date due primarily to an after-tax gain of $12.8 million on APUC subscription receipts | (1.0 | ) | 14.1 | |||||
Income tax expense – Increased year-to-date primarily due to the taxable gain on APUC subscription receipts and increased income in Emera Energy. | (0.9 | ) | (3.1 | ) | ||||
Other | (0.4 | ) | — | |||||
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Contribution to consolidated net income – 2011 | $ | (1.9 | ) | $ | 18.7 | |||
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27
CORPORATE
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 2011
Corporate millions of Canadian dollars | Three months ended June 30 | Six months ended June 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Revenue | $ | 7.6 | $ | 7.9 | $ | 15.0 | $ | 15.3 | ||||||||
Corporate costs | 5.7 | 6.5 | 13.4 | 11.2 | ||||||||||||
Interest expense | 8.2 | 8.5 | 16.9 | 16.6 | ||||||||||||
Income tax (recovery) | (4.0 | ) | (3.4 | ) | (8.3 | ) | (7.9 | ) | ||||||||
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(2.3 | ) | (3.7 | ) | (7.0 | ) | (4.6 | ) | |||||||||
Preferred stock dividends | 1.6 | — | 3.3 | — | ||||||||||||
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Total corporate | $ | (3.9 | ) | $ | (3.7 | ) | $ | (10.3 | ) | $ | (4.6 | ) | ||||
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Revenue
Revenue consists of intercompany interest from Brunswick Pipeline.
Corporate Costs
Corporate costs decreased by $0.8 million to $5.7 million in Q2 2011 compared to $6.5 million in Q2 2010 (adjusted) due to decreased acquisition costs partially offset by increased deferred compensation and corporate activities. Year-to-date, corporate costs increased $2.2 million to $13.4 million in 2011 compared to $11.2 million in 2010 (adjusted) due to increased deferred compensation costs and corporate activities partially offset by decreased acquisition costs.
Preferred Stock Dividends
Preferred stock dividends increased to $1.6 million in Q2 2011 (Q2 2010 (adjusted) – nil) and increased to $3.3 million year-to-date in 2011 (2010 (adjusted) – nil) due to the issuance of preferred shares in June 2010.
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OUTLOOK
Business Environment
Economic Environment
Emera will continue to pursue investment opportunities related to the transformation of the energy industry to 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 Utilities. 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 2011. 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 $350 million in 2011. NSPI expects to finance its capital expenditures with funds from operations, debt and equity.
Maine Utility Operations
USD income from Maine Utility Operations is expected to be slightly higher in 2011 compared to 2010 due to the recovery of investments in new transmission assets and the acquisition of MAM. In 2011, Bangor Hydro expects to invest approximately $81 million USD, including approximately $57 million USD for major transmission projects.
Caribbean Utility Operations
Income from Caribbean Utility Operations is expected to be higher in 2011 compared to 2010 primarily as a result of increased investments in GBPC and LPH. Caribbean Utility Operations plans to invest approximately $164 million in capital programs in 2011, of which $92M relates to the acquisition of LPH in Q1 2011.
Pipelines
Income from Pipelines is expected to be consistent with 2010.
Services, Renewables and Other Investments
Income from Services, Renewables and Other Investments is expected to be higher in 2011 compared to 2010 due to the APUC gain on subscription receipts partially offset by higher financing costs. Emera Newfoundland and Labrador (“ENL”) plans to invest approximately $20 million in the Maritime Link and the Island Link Transmission Projects in 2011.
Corporate
Income from Corporate is expected to be lower in 2011 compared to 2010 due to higher financing costs related to acquisitions.
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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 our 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, of which approximately $536 million is undrawn and available as at June 30, 2011. NSPI has an active commercial paper program for up to $400 million, of which outstanding amounts are 100 percent backed by the bank lines referred to above, which results in an equal amount of credit being considered drawn and unavailable.
As at June 30, 2011, the outstanding short-term debt is as follows:
millions of dollars | Maturity | Credit Line Committed | Utilized | Undrawn and Available | ||||||||||
Emera – Operating and acquisition credit facility | June 2013 – Revolver | $ | 600 | $ | 414 | $ | 186 | |||||||
NSPI – Operating credit facility | June 2013 – Revolver | 600 | 307 | 293 | ||||||||||
Bangor Hydro – in USD – Operating credit facility | September 2013 – Revolver | 80 | 40 | 40 | ||||||||||
Other – in USD – Operating credit facilities | Various | 40 | 13 | 17 |
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.
In February 2011, Emera filed an amended and restated short form base shelf prospectus. This amendment increased the aggregate principal amount of debt securities and preferred shares that may be offered from time to time under the short form base shelf prospectus from $500 million to $650 million. To date, $150 million in preferred shares have been issued under the short form base shelf prospectus and a shelf prospectus supplement since the initial filing of the shelf prospectus in 2010.
Concurrently with the Canadian filing of this amendment, Emera also filed a registration statement on Form F-9 with the U.S. Securities and Exchange Commission to register debt securities and preferred shares having an aggregate initial offering price of up to $500 million for sale in the United States.
In May 2011, NSPI filed an amendment to its amended and restated short form base shelf prospectus and an amendment to its prospectus supplement for medium-term notes (unsecured). These amendments increased the aggregate principal amount of debt securities and medium-term notes that may be offered from time to time under the short form base shelf prospectus and prospectus supplement (respectively) from $500 million to $800 million. To date, $300 million in medium-term notes have been issued under NSPI’s short form base shelf prospectus and prospectus supplement since their initial filing in 2010.
Concurrently with the Canadian filing of these amendments, NSPI also filed a registration statement on Form F-9 with the U.S. Securities and Exchange Commission to register debt securities having an aggregate initial offering price of up to $500 million for sale in the United States.
30
TRANSACTIONS WITH RELATED PARTIES
In the ordinary course of business, Emera purchased natural gas transportation capacity from M&NP, an investment under significant influence of the Company, totaling $12.5 million (2010 – $14.5 million) during the three months ended June 30, 2011, and $25.4 million for the six months ended June 30, 2011 (2010 – $28.0 million). 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 June 30, 2011, the amount payable to the related party was $4.3 million (December 31, 2010 – $3.9 million), and is under normal interest and credit terms.
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Emera’s risk management policies and procedures provide a framework through which management monitors various risk exposures. The risk management plan has been approved by the Board of Directors. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group which is independent of all operations.
The Company manages its exposure to normal operating and market risks relating to commodity price, foreign exchange and interest rate risks using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, and coal, oil and gas options and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas, and physical and financial contracts held-for-trading (“HFT”). Collectively these contracts are considered “derivatives”.
The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. 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 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 the derivatives settle. Management believes that any gains or losses resulting from settlement of these derivatives will be refunded to or collected from customers in future rates.
Derivatives that do not meet any of the above criteria are designated as HFT and are recognized on the balance sheet at fair value. All gains and losses are recognized in net income of the period unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category when another accounting treatment applies.
31
Hedging Items Recognized on the Balance Sheets
The Company has the following categories on the balance sheet related to derivatives in valid hedging relationships:
millions of Canadian dollars | June 30 2011 | December 31 2010 (adjusted) | ||||||
Derivative instrument assets (current and other assets) | $ | 8.8 | $ | 7.0 | ||||
Derivative instrument liabilities (current and long-term liabilities) | (15.3 | ) | (18.3 | ) | ||||
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Net derivative instrument liability | $ | (6.5 | ) | $ | (11.3 | ) | ||
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Hedging Impact Recognized in Net Income
The Company recognized in net income the following net gains (losses) related to the effective portion of hedging relationships under the following categories:
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2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Regulated operating revenues increase | $ | 0.8 | — | $ | 1.6 | — | ||||||||||
Non-regulated fuel and purchased power increase | (1.8 | ) | $ | (2.4 | ) | (2.8 | ) | $ | (4.3 | ) | ||||||
Other income, net increase | 0.1 | — | 0.1 | — | ||||||||||||
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Effectiveness losses | $ | (0.9 | ) | $ | (2.4 | ) | $ | (1.1 | ) | $ | (4.3 | ) | ||||
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The effectiveness net gains and losses reflected in the above table would be offset in net income by the change in the hedged item realized in the period.
The Company recognized in net income the following losses related to the ineffective portion of hedging relationships under the following categories:
millions of Canadian dollars | Three months ended June 30 | Six months ended June 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Non-regulated fuel and purchased power increase | $ | (0.2 | ) | — | $ | (0.8 | ) | — | ||||||||
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Ineffectiveness losses | $ | (0.2 | ) | — | $ | (0.8 | ) | — | ||||||||
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Regulatory Items Recognized on the Balance Sheets
The Company has the following categories on the balance sheet related to derivatives receiving regulatory deferral:
millions of Canadian dollars | June 30 2011 | December 31 2010 (adjusted) | ||||||
Derivative instrument assets (current and other assets) | $ | 48.3 | $ | 59.9 | ||||
Regulatory assets (current and other assets) | 37.3 | 34.2 | ||||||
Derivative instrument liabilities (current and long-term liabilities) | (37.3 | ) | (34.2 | ) | ||||
Regulatory liabilities (current and long-term liabilities) | (48.3 | ) | (59.9 | ) | ||||
— | — |
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Regulatory Impact Recognized in Net Income
The Company recognized in net income the following net losses related to derivatives receiving regulatory deferral:
millions of Canadian dollars | Three months ended June 30 | Six months ended June 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Other expenses, net increase | — | $ | (2.0 | ) | — | $ | (1.0 | ) | ||||||||
Regulated fuel for generation and purchased power increase | $ | (1.3 | ) | (8.1 | ) | $ | (16.9 | ) | (45.2 | ) | ||||||
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Total losses | $ | (1.3 | ) | $ | (10.1 | ) | $ | (16.9 | ) | $ | (46.2 | ) | ||||
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Held-for-trading Items Recognized on the Balance Sheets
The Company has the following categories on the balance sheet related to HFT derivatives:
millions of Canadian dollars | June 30 2011 | December 31 2010 (adjusted) | ||||||
Derivative instruments assets (current and other assets) | $ | 12.6 | $ | 18.8 | ||||
Derivative instruments liabilities (current and long-term liabilities) | (9.9 | ) | (13.2 | ) | ||||
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Net asset | $ | 2.7 | $ | 5.6 | ||||
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Held-for-trading Items Recognized in Net Income
The Company has recognized the following realized and unrealized gains and losses with respect to HFT derivatives in net income:
millions of Canadian dollars | Three months ended June 30 | Six months ended June 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Non-regulated operating revenues increase | $ | 3.7 | $ | 0.6 | $ | 10.3 | $ | 5.3 | ||||||||
Other income (expenses), net increase | — | (1.9 | ) | 0.3 | — | |||||||||||
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Total gains (losses) | $ | 3.7 | $ | (1.3 | ) | $ | 10.6 | $ | 5.3 | |||||||
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The Company has a derivative related to Bear Swamp, as discussed in the Significant Items section, where no observable market exists, therefore modeling techniques are employed using assumptions reflective of current market rates, yield curves and forward prices, as applicable, to interpolate certain prices.
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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 June 30, 2011 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”).
As permitted by NI 52-109, the Company has limited the scope of its design of DC&P and ICFR by excluding the controls, policies and procedures at LPH, which was acquired on January 25, 2011, GBPC, which was acquired on December 22, 2010, and MAM, which was acquired on December 21, 2010. Summary financial information about these acquisitions is included in Note 14 of the Unaudited Condensed Consolidated Financial Statements for the six months ended June 30, 2011 and 2010. The relative size of these entities has not materially changed since their respective acquisition dates.
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. NSPI is currently not an accelerated filer or a large accelerated filer and therefore is not required to file attestation reports on its ICFR. As a new registrant, Emera is not required to include an attestation report on its ICFR in its first Annual Report 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.
SUMMARY OF QUARTERLY RESULTS
For the quarter ended millions of dollars (except earnings per common share) | Q2 2011 | Q1 2011 | Q4 2010 (adjusted) | Q3 2010 (adjusted) | Q2 2010 (adjusted) | Q1 2010 (adjusted) | Q4 2009 (adjusted) | Q3 2009 (adjusted) | ||||||||||||||||||||||||
Total operating revenues | $ | 500.8 | $ | 554.6 | $ | 408.9 | $ | 394.1 | $ | 364.6 | $ | 438.5 | $ | 400.1 | $ | 344.1 | ||||||||||||||||
Net income attributable to common shareholders | 29.9 | 123.6 | 24.1 | 40.3 | 48.5 | 77.8 | 37.8 | 42.6 | ||||||||||||||||||||||||
Earnings per common share – basic | 0.24 | 1.06 | 0.21 | 0.35 | 0.43 | 0.68 | 0.33 | 0.38 | ||||||||||||||||||||||||
Earnings per common share – diluted | 0.24 | 1.03 | 0.21 | 0.34 | 0.42 | 0.67 | 0.33 | 0.37 |
Quarterly total 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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