Exhibit 99.1
Management’s Discussion & Analysis
As at November 4, 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 third quarter of 2011 relative to 2010, and its financial position as at September 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 investments.
Effective January 1, 2011, Emera changed the basis of presentation of its financial statements (including the application of rate-regulated accounting policies for Emera’s rate-regulated subsidiaries) from Canadian Generally Accepted Accounting Principles (“CGAAP”) to United States Generally Accepted Accounting Principles (“USGAAP”).
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 nine months ended September 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 (“GBPA”) | |||
Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”) | National Energy Board (“NEB”) |
All amounts are in Canadian dollars (“CAD”) except for the Maine Utility Operations section of the MD&A, which is reported in US dollars (“USD”) unless otherwise stated.
Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR atwww.sedar.com or on EDGAR atwww.sec.gov.
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Forward Looking Information
This MD&A contains “forward-looking information” within the meaning of applicable Canadian securities laws and “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995 (collectively, “forward-looking information”). The words “anticipates”, “believes”, “could”, “estimates”, “expects”, “intends”, “may”, “plans”, “projects”, “schedule”, “should”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words.
The forward-looking information in this MD&A includes statements which reflect the current view with respect to the Company’s objectives, plans, financial and operating performance, business prospects and opportunities. The forward-looking information reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the times at which, such events, performance or results will be achieved.
The forward-looking information is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ from current expectations are discussed in the Outlook section of the MD&A and may also include: regulatory risk; operating and maintenance risks; economic conditions; availability and price of energy and other commodities; capital resources and liquidity risk; weather; commodity price risk; competitive pressures; construction; derivative financial instruments and hedging availability and cost of financing; interest rate risk; counterparty risk; competitiveness of electricity as an energy source; commodity supply; environmental risks; foreign exchange; regulatory and government decisions including changes to environmental, financial reporting and tax legislation; loss of service area; market energy sales prices; labour relations; and availability of labour and management resources.
Readers are cautioned not to place undue reliance on forward-looking information as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking information in this MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise.
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Structure of MD&A
This MD&A 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 nine months ended September 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, Statements of Cash Flows, and outstanding share data; then presents information separately on Emera’s consolidated subsidiaries and investments, specifically:
• | NSPI; |
• | Maine Utility Operations (Bangor Hydro, MPS and its parent company, Maine and Maritimes Corporation (“MAM”)); |
• | Caribbean Utility Operations (BLPC and its parent company, Light & Power Holdings Ltd. (“LPH”), GBPC, ICD Utilities Limited (“ICDU”) and St. Lucia Electricity Services Limited (“Lucelec”)); |
• | Pipelines (Brunswick Pipeline and Maritimes & Northeast Pipeline (“M&NP”)); |
• | Other operations and investments are grouped and discussed under Services, Renewables and Other Investments and include: |
¡ | Emera Energy Inc. (Emera Energy Services, Bayside Power Limited Partnership (“Bayside Power”), Bear Swamp Power Company LLC. (“Bear Swamp”)), |
¡ | Emera Utility Services Inc. (“EUS”), |
¡ | Emera Newfoundland & Labrador Holdings Inc. (“ENL”), |
¡ | Algonquin Power & Utilities Corp. (“APUC”), |
¡ | California Pacific Utilities Ventures, LLC (“CPUV”) and |
¡ | Atlantic Hydrogen Inc. (“AHI”); and |
• | Corporate |
The Outlook, Liquidity and Capital Resources, Transactions with Related Parties, Risk Management and Financial Instruments, Disclosure and Internal Controls, 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 $6.8 billion in assets. The Company invests in electricity generation, transmission and distribution, gas transmission and utility energy services. Emera’s strategy is focused on the transformation of the electricity industry to cleaner generation and the delivery of that cleaner energy to market. Emera has interests throughout northeastern North America, in three Caribbean countries and in California.
Emera’s goal is to increase earnings per share by an average of 4 percent to 6 percent annually and to build and diversify its income base with a focus on cleaner energy in its markets. Emera will continue to build its existing business and will leverage its core strength in the electricity business to pursue acquisitions and greenfield development opportunities in regulated electricity transmission, distribution and lower risk generation.
Approximately 90 percent of Emera’s net income is earned by its rate-regulated subsidiaries. The success of these subsidiaries is integral to the creation of shareholder value, providing strong, predictable income and cash flows to fund dividends and reinvestment.
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
“Net income applicable to common shares, absent the Bear Swamp after-tax mark-to-market adjustment”, “Earnings per common share – basic, absent the Bear Swamp after-tax mark-to-market adjustment”, “Contribution to consolidated net income, absent the Bear Swamp after-tax mark-to-market adjustment” and “Contribution to consolidated net earnings per common share, absent the Bear Swamp after-tax mark-to-market adjustment” are non-GAAP financial measures used by Emera. Management discloses these financial measures as it believes the inclusion of the mark-to-market adjustment in Bear Swamp’s financial results does not accurately reflect its operational performance. The adjustment is discussed further in the Consolidated Financial Review – Consolidated Financial Highlights section, Consolidated Financial Review – Significant Items section, and Services, Renewables and Other Investments – Review of 2011 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 Inc. and EUS. EBIT is discussed in the Services, Renewables and Other Investments – Review of 2011 section.
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CONSOLIDATED FINANCIAL REVIEW
Consolidated Financial Highlights
For the millions of Canadian dollars (except per share amounts) | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Operating revenues | $496.1 | $394.0 | $1,552.4 | $1,197.2 | ||||||||||||
Net income attributable to common shareholders | 40.8 | 40.3 | 194.3 | 166.6 | ||||||||||||
Earnings per common share – basic | $0.33 | $0.35 | $1.61 | $1.46 | ||||||||||||
Earnings per common share – diluted | $0.33 | $0.35 | $1.59 | $1.43 | ||||||||||||
Dividends per common share declared | $0.6625 | $0.6075 | $1.3125 | $1.1625 |
For the millions of Canadian dollars (except per share amounts) | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
Operating Unit Contributions | 2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | ||||||||||||
NSPI | $21.0 | $18.6 | $101.3 | $99.3 | ||||||||||||
Maine Utility Operations | 9.4 | 11.5 | 27.2 | 24.1 | ||||||||||||
Caribbean Utility Operations | 10.7 | 2.8 | 43.7 | 27.5 | ||||||||||||
Pipelines | 7.0 | 8.1 | 21.0 | 20.9 | ||||||||||||
Services, Renewables and Other Investments | 2.3 | 6.7 | 21.0 | 6.8 | ||||||||||||
Corporate | (9.6) | (7.4) | (19.9) | (12.0) | ||||||||||||
Net income attributable to common shareholders | $40.8 | $40.3 | $194.3 | $166.6 | ||||||||||||
Net income applicable to common shares, absent the Bear Swamp after-tax mark-to-market adjustment | $41.3 | $42.2 | $194.4 | $172.6 | ||||||||||||
Earnings per common share – basic | $0.33 | $0.35 | $1.61 | $1.46 | ||||||||||||
Earnings per common share – basic, absent the Bear Swamp after-tax mark-to-market adjustment | $0.34 | $0.37 | $1.61 | $1.51 |
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Developments
Emera
Sale of St. Lucia Electricity Services
On October 4, 2011, a wholly-owned subsidiary of Emera agreed to sell its 19.1 percent interest in St. Lucia Electricity Services (“Lucelec”) at book value to Light & Power Holdings Ltd. (“LPH”), a subsidiary owned 80.2 percent by Emera, for $25.8 million USD. The terms of the acquisition agreement provide for a potential sales price increase or decrease of up to $4 million USD within 30 months of the closing date of the transaction. Any adjustment would be triggered by either an additional public offering by Lucelec or a change in Lucelec’s allowed return on equity as a result of a change in its regulatory framework. This transaction is subject to relevant government and regulatory approvals and is expected to close in the fourth quarter of 2011.
Increase in Common Share Dividend
On September 23, 2011, Emera’s Board of Directors approved an increase in the annual common share dividend rate from $1.30 to $1.35, and accordingly declared a quarterly dividend of $0.3375 per common share.
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 & 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 nine months ended September 30, 2011. As a result of this transaction, and APUC’s subsequent conversion of certain of its debentures to equity, Emera owns an approximate 7.2 percent equity interest in APUC as at September 30, 2011.
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 acquisitions are subject to applicable regulatory approvals. The purchase of subscription receipts has received final Toronto Stock Exchange approval.
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Assuming the completion of the New Hampshire Transaction, which is expected in late 2011 or early 2012, the associated conversion of the subscription receipts to APUC common shares, and the exercise of Emera’s anti-dilution rights, Emera’s ownership interest in APUC will increase to approximately 15 percent. Proceeds from the subscription receipts will be used by Liberty Energy Utilities Co. to finance a portion of this acquisition.
Sale of CPUV to APUC
On April 29, 2011 Emera and APUC entered into a Strategic Investment Agreement (“SIA”), which establishes 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. For Emera, these include investment opportunities related to regulated renewable projects within its service territories and large electric utilities. For Algonquin, these include investment opportunities relating to unregulated renewable generation, small electric utilities and gas distribution utilities. Emera and Algonquin are committed to working together on opportunities if they fit within each other’s “areas of pursuit”.
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.
On September 12, 2011, Emera purchased 8.211 million subscription receipts from APUC at an issue price of $4.72 each for a total purchase price of $38.8 million.
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 nearing operation. These assets will become part of a new operating company, owned 51 percent by First Wind, and 49 percent by a new Emera and 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 in late 2011 or early 2012. 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 First 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 percent. 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 approximately 23 percent. APUC shareholders approved an investment, by Emera, in APUC common equity of up to 25 percent in Q2 2011.
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All 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.
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 per share. The offer closed on January 24, 2011, and on January 25, 2011, Emera purchased 7.2 million shares representing an additional interest of 41.8 percent. With this additional investment of $92.6 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 $28.3 million, which Emera has recorded as a non-taxable gain in “Other income (expenses), net” on Emera’s Consolidated Statements of Income for the nine months ended September 30, 2011. Further information on the gain is provided in the Consolidated Financial Review – Significant Items section.
US Securities and Exchange Commission Registration
On October 5, 2011, Emera registered its common shares under the US Securities Exchange Act of 1934, as amended.
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.
NSPI
2012 Proposed General Rate Settlement
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. On September 19, 2011, prior to the commencement of the GRA hearing, NSPI and customer representatives announced a proposed settlement for 2012 electricity rates. If approved by the UARB, the settlement will result in an average rate increase of approximately 5.0 percent for all customers, effective January 1, 2012. Rates are proposed based on a 9.2 percent ROE, applied to a 37.5 percent common equity component. A decision is expected during Q4 2011.
NewPage Port Hawkesbury Corp.
On September 9, 2011, NewPage Port Hawkesbury Corp. (“NewPage”), NSPI’s largest customer was granted creditor protection under the Companies’ Creditors Arrangement Act. On September 7, 2011, NewPage Group Inc., NewPage’s corporate parent, commenced a voluntary case under Chapter 11 of the United States Bankruptcy Code. NewPage is actively seeking a buyer for its operations; it has ceased operations, but is maintaining the mill in a “hot idle�� status such that a new owner would be able to re-start operations immediately. NSPI is currently assessing the impact of the developments at NewPage, the full extent of which will not be known until it is determined whether the mill will continue operations under new ownership. In light of the uncertainty inherent in this situation, the proposed General Rate Settlement referred to above provides for any unrecovered non-fuel electric charges in 2012 related to this customer to be deferred and recovered beginning in 2013. NewPage was also responsible for the construction of a 60 megawatt (“MW”) biomass facility in Port Hawkesbury, Nova Scotia for NSPI. NSPI is proceeding with this project and has assumed construction management responsibilities.
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Canadian Environmental Regulations
On August 19, 2011, Environment Canada announced proposed regulations for a new national carbon dioxide framework for the electricity sector in Canada. These proposed regulations would apply to new coal-fired electricity generation units and existing coal-fired electricity generation units once they have reached the end of their deemed economic life of forty-five years after commissioning. These proposed regulations will be effective July 1, 2015. Nova Scotia’s existing greenhouse gas regulations require reductions in NSPI’s emissions similar to those reflected in the federal framework. NSPI is reviewing the implications of this federal framework and its alignment with its current operating plans under existing Nova Scotia regulations.
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 requires regulations to be developed that increase the percentage of renewable energy in the generation mix from the planned 25 percent in 2015, to 40 percent by 2020.
On April 11, 2011, the Nova Scotia Government announced that the cap on the annual amount of new forest biomass that can be used to generate electricity will be lowered by 30 percent to 350,000 dry tonnes per year. NSPI’s 60 MW Port Hawkesbury Biomass Project is not affected by this announcement.
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 reduced the amount of the FAM balance outstanding with the reduction applied to the amount that would otherwise be recovered from customers in 2012.
Light-emitting Diode Streetlight Legislation
On May 19, 2011, the Nova Scotia Government passed legislation making light-emitting diode (“LED”) lighting mandatory on Nova Scotia’s roads and highways. 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.
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 immaterial. The new depreciation rates shall be effective January 1, 2012 pending approval of the 2012 proposed GRA settlement by the UARB.
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 amount of $79.8 million. This project went into service in December 2010.
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Appointments
On September 13, 2011, Robert Hanf, was appointed Executive Chairman of Light & Power Holdings Ltd. and Director of Barbados Light & Power Company Limited. Prior to these appointments, Mr. Hanf served as Chief Legal Officer of Emera Incorporated.
On September 22, 2011, Ray Ivany, President and Vice-Chancellor of Acadia University, joined NSPI’s Board of Directors.
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 Inc.
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.
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.
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 mark-to-market through income, as it does not meet the stringent accounting requirements of hedge accounting.
As at September 30, 2011, the fair value of the contract was a net liability of $8.6 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:
For the millions of Canadian dollars (except per share amounts) |
| Three months ended September 30 |
|
| Nine months ended September 30 |
| ||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Mark-to-market loss | $0.7 | $3.2 | $0.1 | $10.0 | ||||||||||||
After-tax mark-to-market loss | $0.5 | $1.9 | $0.1 | $6.0 | ||||||||||||
Earnings per common share – basic | $0.33 | $0.35 | $1.61 | $1.46 | ||||||||||||
Earnings per common share – basic, absent the Bear Swamp after-tax mark-to- market adjustment | $0.34 | $0.37 | $1.61 | $1.51 |
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 “Other income (expenses), net” on Emera’s Consolidated Statements of Income in Q1 2011.
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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 $28.3 million, respectively. These amounts have been recorded in “Other income (expenses), net” on Emera’s Consolidated Statements of Income.
REVIEW OF 2011
Emera Incorporated’s consolidated net income increased $0.5 million to $40.8 million in Q3 2011 compared to $40.3 million in Q3 2010 (adjusted). Year-to-date, Emera’s consolidated net income increased $27.7 million to $194.3 million in 2011 compared to $166.6 million in 2010 (adjusted). Highlights of the changes are summarized in the following table:
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||
Consolidated net income attributable to common shareholders – 2010 (adjusted) | $40.3 | $166.6 | ||||||
NSPI – Increased net income during the quarter primarily due to decreased income taxes and operating, maintenance and general expenses (“OM&G”), partially offset by lower electric margin. Increased net income year-to-date primarily due to decreased income tax expense and higher electric margin, partially offset by increased OM&G. | 2.4 | 2.0 | ||||||
Maine Utility Operations – Decreased net income during the quarter due to lower revenue as a result of cooler temperatures. Increased net income year-to-date primarily due to higher revenue as a result of a transmission rate increase in June 2010, the recovery of regionally funded transmission investments, and the acquisition of MAM in Q4 2010. | (2.1 | ) | 3.1 | |||||
Caribbean Utility Operations – Increased net income during the quarter primarily due to increased ownership of both GBPC and LPH. Year-to-date increase also reflects an incremental $5.8 million gain on the acquisition of LPH recorded in 2011 versus 2010. | 7.9 | 16.2 | ||||||
Pipelines – Decreased net income during the quarter primarily due to change in the mark-to-market of currency hedges. | (1.1 | ) | 0.1 | |||||
Services, Renewables and Other Investments – Decreased net income during the quarter primarily due to the reversal of mark-to-market gains. Increased year-to-date net income due to gain on APUC subscription receipts and stronger energy marketing results, partially offset by the reversal of the Emera Energy 2010 mark-to-market gains. | (4.4 | ) | 14.2 | |||||
Corporate – Increased costs during the quarter primarily due to increased foreign exchange expense resulting from a weaker CAD. Increased costs year-to-date primarily due to increased foreign exchange expense resulting for a weaker CAD and preferred share dividends, partially offset by decreased deferred compensation and acquisition costs. | (2.2 | ) | (7.9 | ) | ||||
Consolidated net income attributable to common shareholders – 2011 | $40.8 | $194.3 |
Basic earnings per share were $0.33 in Q3 2011 compared to $0.35 in Q3 2010 (adjusted); and $1.61 year-to-date in 2011 compared to $1.46 in 2010 (adjusted).
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Consolidated Balance Sheets Highlights
Significant changes in the consolidated balance sheets between September 30, 2011 and December 31, 2010 (adjusted) include:
millions of Canadian dollars | Increase (Decrease) | Explanation | ||||
Assets | ||||||
Cash and cash equivalents | $76.9 | See consolidated cash flow highlights section. | ||||
Restricted cash | (47.0) | Decreased primarily due to use of restricted cash in Q1 2011 related to the purchase of APUC subscription receipts, partially offset by new restricted cash due to acquisition of a controlling interest in LPH. | ||||
Receivables, net | 20.5 | Increased primarily due to acquisition of a controlling interest in LPH and timing of billings and receipts, partially offset by seasonal business trends. | ||||
Income taxes receivable | (28.4) | Decreased primarily due to receipt of prior year taxes recoverable, partially offset by current year recovery of income taxes due to accelerated tax deductions for property, plant and equipment, including renewable investments. | ||||
Inventory | 22.8 | Increased primarily due to acquisition of a controlling interest in LPH. | ||||
Derivative instruments (current and long-term) | 27.2 | Increased primarily due to favourable USD price positions and additional hedges, partially offset by unfavourable commodity price positions. | ||||
Prepaid expenses | 18.2 | Timing of provincial grants in lieu of taxes and insurance payments. | ||||
Other assets (current and long-term) | 73.7 | Increased primarily due to purchase of APUC subscription receipts. | ||||
Property, plant & equipment, net of accumulated depreciation | 463.2 | Increased primarily due to acquisition of a controlling interest in LPH and capital spending, partially offset by depreciation. | ||||
Investments subject to significant influence | (22.6) | Decreased primarily due to acquisition of a controlling interest in LPH, partially offset by the APUC investment. | ||||
Available-for-sale investments | 56.8 | Increased due to acquisition of a controlling interest in LPH. | ||||
Goodwill | 30.7 | Increased primarily due to acquisition GBPC and weaker Canadian dollar. | ||||
Liabilities and Equity | ||||||
Short-term debt and long-term debt (including current portion) | 137.4 | Increased primarily due to acquisition of a controlling interest in LPH and APUC subscription receipts. | ||||
Accounts Payable | 41.1 | Increased due to timing of payments and acquisition of a controlling interest in LPH. | ||||
Deferred income taxes (current and long-term) | 76.9 | Increased primarily due to increased deferred income tax liability on property, plant and equipment, including renewable investments and acquisition of a controlling interest in LPH, resulting in reclassification of deferred income tax asset. | ||||
Regulatory liabilities (current and long-term) | 55.9 | Increased primarily due to acquisition of a controlling interest in LPH, partially offset by decreased deferred income tax regulatory liability and decreased regulatory liability related to 2010 tax benefit deferral. | ||||
Pension and post-retirement liabilities (current and long-term) | (16.6) | Decreased primarily due to NSPI’s cash contributions exceeding the current benefit accrual. | ||||
Other Liabilities (current and long term) | 59.5 | Increased primarily due to dividends payable. | ||||
Asset retirement obligations | (52.4) | Decreased primarily due to change in estimates of retirement dates and future decommissioning costs, partially offset by the acquisition of a controlling interest in LPH. | ||||
Common stock | 231.3 | Issuance of common shares. | ||||
Accumulated other comprehensive loss | (59.0) | Decreased primarily due to the favorable effect of a weaker CAD on Emera’s foreign investments, partially offset by amortization of unrecognized pension and post-retirement benefit costs. | ||||
Retained earnings | 35.9 | Net income of Emera Incorporated in excess of dividends declared and other stock-based compensation. | ||||
Non-controlling interest in subsidiaries | 69.1 | Increased primarily due to acquisition of a controlling interest in LPH. |
12
Consolidated Cash Flow Highlights
Significant changes in the statements of cash flows between the nine months ended September 30, 2011 and 2010 (adjusted) include:
Nine months ended September 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 | 361.7 | 238.0 | In 2011 and 2010, increased cash income, partially offset by unfavourable non-cash working capital. | |||||||
Investing activities | (462.6) | (458.4) | 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 | 178.9 | 243.5 | In 2011, issuance of common shares, partially offset by decreased debt levels and dividends on common shares. | |||||||
In 2010, increased debt levels and the issuance of preferred shares, partially offset by dividends on common shares. | ||||||||||
Foreign currency impact on cash balances | (1.1) | 0.2 | ||||||||
Cash and cash equivalents, end of period | $84.2 | $43.5 |
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 | ||||||
Issuance of common stock | 6.36 | 196.0 | ||||||
Issued for cash under purchase plans | 1.03 | 29.7 | ||||||
Options exercised under senior management stock option plan | 0.22 | 4.7 | ||||||
Stock-based compensation | – | 0.9 | ||||||
September 30, 2011 | 122.23 | $1,369.1 |
As at October 21, 2011 the amount of issued and outstanding common stock was 122.27 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 492,000 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 (except per share amounts) | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Operating revenues – regulated | $276.0 | $272.2 | $943.8 | $888.2 | ||||||||||||
Regulated fuel for generation and purchased power | 125.0 | 133.4 | 419.3 | 432.5 | ||||||||||||
Regulated fuel for generation and purchased power – affiliates | 0.2 | 1.6 | 0.3 | 8.0 | ||||||||||||
Regulated fuel adjustment | (4.4) | (23.0) | (4.0) | (75.0) | ||||||||||||
Operating, maintenance and general | 59.2 | 63.4 | 193.6 | 178.3 | ||||||||||||
Provincial grants and taxes | 9.7 | 10.0 | 28.9 | 30.0 | ||||||||||||
Depreciation and amortization | 43.1 | 41.4 | 128.4 | 124.4 | ||||||||||||
Total operating expenses | 232.8 | 226.8 | 766.5 | 698.2 | ||||||||||||
Income from operations | 43.2 | 45.4 | 177.3 | 190.0 | ||||||||||||
Other expenses, net | 2.3 | 1.9 | 6.8 | 7.8 | ||||||||||||
Interest expense, net | 26.7 | 25.2 | 80.6 | 77.9 | ||||||||||||
Income before provision for income taxes | 14.2 | 18.3 | 89.9 | 104.3 | ||||||||||||
Income tax recovery | (8.8) | (2.3) | (17.4) | (1.0) | ||||||||||||
Net income of Nova Scotia Power Inc. | 23.0 | 20.6 | 107.3 | 105.3 | ||||||||||||
Preferred stock dividends | 2.0 | 2.0 | 6.0 | 6.0 | ||||||||||||
Contribution to consolidated net income | $21.0 | $18.6 | $101.3 | $99.3 | ||||||||||||
Contribution to consolidated earnings per common share | $0.17 | $0.16 | $0.84 | $0.87 |
NSPI’s contribution to consolidated net income increased $2.4 million to $21.0 million in Q3 2011 compared to $18.6 million in Q3 2010 (adjusted). NSPI’s contribution to consolidated net income year-to-date increased $2.0 million to $101.3 million in 2011 compared to $99.3 million in 2010 (adjusted). Highlights of the changes are summarized in the following table:
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||
Contribution to consolidated net income – 2010 (adjusted) | $18.6 | $99.3 | ||||||
(Decreased) increased electric margin (see Electric Revenues section for explanation) | (4.9) | 5.7 | ||||||
Decreased OM&G in the quarter primarily due to timing of maintenance costs on transmission and distribution assets, partially offset by increased pension costs; Increased OM&G year-to-date primarily due to increased pension, plant maintenance costs and labour escalation | 4.2 | (15.3) | ||||||
Increased net depreciation and amortization primarily due to increased property, plant and equipment, partially offset by decreased regulatory amortization | (1.3) | (3.0) | ||||||
Increased income tax recovery primarily due to decreased income before provision for income taxes, decreased regulatory amortization, a lower FAM regulatory asset and a lower statutory income tax rate | 6.5 | 16.4 | ||||||
Other | (2.1) | (1.8) | ||||||
Contribution to consolidated net income – 2011 | $21.0 | $101.3 |
14
Operating Revenues – Regulated
NSPI’s Operating Revenues – Regulated include sales of electricity and other services as summarized in the following table:
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Electric revenues | $270.2 | $266.4 | $926.8 | $870.9 | ||||||||||||
Other revenues | 5.8 | 5.8 | 17.0 | 17.3 | ||||||||||||
Operating revenues – regulated | $276.0 | $272.2 | $943.8 | $888.2 |
Electric Revenues
Electric sales volume is primarily driven by general economic conditions, population and weather. Residential and commercial electricity sales are seasonal, with Q1 and Q4 the strongest periods, reflecting colder weather and fewer daylight hours in the winter season.
NSPI’s residential load generally comprises individual homes, apartments and condominiums. Commercial customers include small retail operations, large office and commercial complexes, and the province’s universities and hospitals. Industrial customers include manufacturing facilities and other large volume operations. Other electric revenues consist of export sales, sales to municipal electric utilities and revenues from street lighting.
Electric sales volumes are summarized in the following tables by customer class:
Q3 Electric Sales Volumes Gigawatt hours (“GWh”) | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
Residential | 792 | 790 | 789 | |||||||||
Commercial | 733 | 752 | 745 | |||||||||
Industrial | 950 | 1,048 | 918 | |||||||||
Other | 72 | 73 | 74 | |||||||||
Total | 2,547 | 2,663 | 2,526 |
Year-to-date (“YTD”) Electric Sales Volumes GWh | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
Residential | 3,202 | 3,067 | 3,137 | |||||||||
Commercial | 2,334 | 2,323 | 2,335 | |||||||||
Industrial | 2,948 | 2,951 | 2,644 | |||||||||
Other | 230 | 228 | 247 | |||||||||
Total | 8,714 | 8,569 | 8,363 |
Electric revenues are summarized in the following tables by customer class:
Q3 Electric Revenues millions of Canadian dollars | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
Residential | $109.6 | $105.8 | $106.9 | |||||||||
Commercial | 80.0 | 78.1 | 79.1 | |||||||||
Industrial | 70.1 | 72.2 | 67.4 | |||||||||
Other | 10.5 | 10.3 | 10.6 | |||||||||
Total | $270.2 | $266.4 | $264.0 |
YTD Electric Revenues millions of Canadian dollars | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
Residential | $423.9 | $393.9 | $406.9 | |||||||||
Commercial | 256.0 | 243.2 | 249.7 | |||||||||
Industrial | 214.9 | 203.3 | 196.5 | |||||||||
Other | 32.0 | 30.5 | 32.1 | |||||||||
Total | $926.8 | $870.9 | $885.2 |
15
Electric revenues increased $3.8 million to $270.2 million in Q3 2011 compared to $266.4 million in Q3 2010. Year-to-date, electric revenues increased $55.9 million to $926.8 million in 2011 from $870.9 million in 2010. Highlights of the changes are summarized in the following table:
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||
Electric revenues – 2010 | $266.4 | $870.9 | ||||||
Increased fuel-related electricity pricing effective January 1, 2011 | 11.6 | 40.0 | ||||||
Decreased commercial sales volumes in the quarter and increased residential sales volumes year-to-date due to colder weather and load growth | (1.5) | 16.4 | ||||||
Decreased industrial sales volume primarily due to the indefinite shut-down of a large industrial customer | (6.2) | (0.9) | ||||||
Other | (0.1) | 0.4 | ||||||
Electric revenues – 2011 | $270.2 | $926.8 |
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 year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year. 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, have less of an effect on non-fuel electric revenues than a similar volume change in residential and commercial load.
Electric margin is summarized in the following table:
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Fuel electric revenues – current year | $115.7 | $119.0 | $397.0 | $384.6 | ||||||||||||
Fuel electric revenues – preceding years | 5.9 | (5.2) | 20.5 | (16.7) | ||||||||||||
Non-fuel electric revenues | 148.6 | 152.6 | 509.3 | 503.0 | ||||||||||||
Total electric revenues | $270.2 | $266.4 | $926.8 | $870.9 | ||||||||||||
Regulated fuel for generation and purchased power, including affiliates | (125.2) | (135.0) | (419.6) | (440.5) | ||||||||||||
Regulated fuel adjustment | 4.4 | 23.0 | 4.0 | 75.0 | ||||||||||||
Foreign exchange and other fuel related costs | (2.1) | (2.2) | (6.0) | (5.9) | ||||||||||||
Electric margin | $147.3 | $152.2 | $505.2 | $499.5 |
NSPI’s electric margin decreased $4.9 million to $147.3 million in Q3 2011 compared to $152.2 million in Q3 2010 primarily due to decreased industrial sales. Year-to-date, NSPI’s electric margin increased $5.7 million to $505.2 million in 2011 compared to $499.5 million in 2010 primarily due to increased residential sales as a result of colder weather and load growth, partially offset by decreased industrial electric margin.
Q3 Average Electric Margin / Megawatt hour (“MWh”) | YTD Average Electric Margin / MWh | |||||||||||||||||||||||||||
2011 | 2010 | 2009 | 2011 | 2010 | 2009 | |||||||||||||||||||||||
Dollars per MWh | $58 | $57 | $60 | Dollars per MWh | $58 | $58 | $61 |
16
Regulated Fuel for Generation and Purchased Power (including affiliates)
Q3 Production Volumes GWh | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
Coal and petcoke | 1,571 | 1,846 | 1,775 | |||||||||
Natural gas | 619 | 609 | 418 | |||||||||
Oil | 2 | 10 | 11 | |||||||||
Renewables | 200 | 154 | 184 | |||||||||
Purchased power | 306 | 193 | 284 | |||||||||
Total | 2,698 | 2,812 | 2,672 | |||||||||
Purchased power includes 156 GWh of renewables in Q3 2011 (2010 – 114 GWh; 2009 – 63 GWh). |
YTD Production Volumes GWh | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
Coal and petcoke | 5,224 | 5,790 | 6,108 | |||||||||
Natural gas | 1,948 | 1,837 | 1,078 | |||||||||
Oil | 28 | 20 | 291 | |||||||||
Renewables | 1,008 | 677 | 784 | |||||||||
Purchased power | 971 | 682 | 596 | |||||||||
Total | 9,179 | 9,006 | 8,857 | |||||||||
Purchased power includes 516 GWh of renewables YTD in 2011 (2010 – 351 GWh; 2009 – 209 GWh). |
Q3 Average Unit Fuel Costs | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
Dollars per MWh | $46 | $48 | $42 |
YTD Average Unit Fuel Costs | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
Dollars per MWh | $46 | $49 | $41 |
Regulated fuel for generation and purchased power, including affiliates decreased $9.8 million to $125.2 million in Q3 2011 compared to $135.0 million in Q3 2010. Year-to-date, regulated fuel for generation and purchased power, including affiliates decreased $20.9 million to $419.6 million in 2011 compared to $440.5 million in 2010. Highlights of the changes are summarized in the following table:
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||
Regulated fuel for generation and purchased power, including affiliates – 2010 | $135.0 | $440.5 | ||||||
Decreased commodity prices | (9.7) | (37.9) | ||||||
Increased hydro and wind production | (2.4) | (20.5) | ||||||
Changes in solid fuel commodity mix and additives related to emission compliance | 3.9 | (10.5) | ||||||
Changes in generation mix and plant performance | (2.6) | 15.9 | ||||||
(Decreased) increased sales volume | (5.4) | 10.5 | ||||||
Valuation of contract receivable (see discussion below) | 8.9 | 24.6 | ||||||
Other | (2.5) | (3.0) | ||||||
Regulated fuel for generation and purchased power, including affiliates – 2011 | $125.2 | $419.6 |
Through 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. The fair value related to the contract had a favourable impact on natural gas pricing during 2010. The impact is segregated in the table above.
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 FAM balance as filed from customers over three years effective January 1, 2011, with 50 percent to be recovered in 2011, 30 percent in 2012 and 20 percent in 2013.
The FAM regulatory asset includes amounts recognized as a fuel adjustment, associated interest that is included in “Interest expense, net”, and the application of the deferral of tax benefits.
17
Details of the FAM regulatory asset 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 year fuel costs | 24.5 | |||
Recovery from customers of prior years’ fuel costs | (20.5) | |||
Application of deferral related to tax benefits from 2010 | (14.5) | |||
Interest revenue on FAM balance | 5.0 | |||
FAM regulatory asset – Balance at September 30 | $87.4 |
18
MAINE UTILITY OPERATIONS
Overview
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.
Bangor Hydro and MPS are both transmission and distribution (“T&D”) electric utilities. Bangor Hydro has approximately $782.5 million of assets and serves approximately 120,000 customers in eastern Maine. MPS has approximately $138.0 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 September 30, 2010 comparative information.
Review of 2011
Maine Utility Operations’ Net Income millions of US dollars (except per share amounts) | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Operating revenues – regulated | $52.0 | $46.7 | $153.5 | $124.4 | ||||||||||||
Operating revenues – non-regulated | 0.4 | – | 0.4 | – | ||||||||||||
Total operating revenues | 52.4 | 46.7 | 153.9 | 124.4 | ||||||||||||
Regulated fuel for generation and purchased power | 4.2 | 6.5 | 18.7 | 21.7 | ||||||||||||
Transmission pool expense(1) | 4.8 | 5.3 | 13.6 | 13.4 | ||||||||||||
Operating, maintenance and general | 11.1 | 8.0 | 34.7 | 26.1 | ||||||||||||
Provincial, state and municipal taxes | 2.2 | 1.7 | 6.8 | 5.2 | ||||||||||||
Depreciation and amortization | 12.5 | 5.5 | 28.5 | 15.8 | ||||||||||||
Total operating expenses | 34.8 | 27.0 | 102.3 | 82.2 | ||||||||||||
Income from operations | 17.6 | 19.7 | 51.6 | 42.2 | ||||||||||||
Other income | 1.3 | 1.1 | 2.7 | 3.0 | ||||||||||||
Interest expense, net | 2.9 | 2.7 | 9.0 | 8.0 | ||||||||||||
Income before provision for income taxes | 16.0 | 18.1 | 45.3 | 37.2 | ||||||||||||
Income tax expense | 6.5 | 7.0 | 17.5 | 13.9 | ||||||||||||
Contribution to consolidated net income – USD | $9.5 | $11.1 | $27.8 | $23.3 | ||||||||||||
Contribution to consolidated net income – CAD | $9.4 | $11.5 | $27.2 | $24.1 | ||||||||||||
Contribution to consolidated earnings per common share –CAD | $0.07 | $0.10 | $0.23 | $0.21 | ||||||||||||
Net income weighted average foreign exchange rate – CAD/USD | $0.99 | $1.04 | $0.98 | $1.03 |
(1) | Transmission pool expense is included in “Regulated fuel for generation and purchased power” on the Consolidated Statements of Income. |
19
Maine Utilities’ contribution to consolidated net income decreased by $1.6 million to $9.5 million in Q3 2011 compared to $11.1 million in Q3 2010 (adjusted). Year-to-date, Maine Utilities contribution to consolidated net income increased by $4.5 million to $27.8 million in 2011, compared to $23.3 million in 2010 (adjusted). Highlights of the net income changes are summarized in the following table:
For the millions of US dollars | Three months ended September 30 | Nine months ended September 30 | ||||||
Contribution to consolidated net income – 2010 (adjusted) | $11.1 | $23.3 | ||||||
Decreased electric revenue during the quarter in Bangor Hydro due to lower sales volumes resulting from cooler temperatures in Q3 2011; Increased electric revenue year-to-date due to a transmission rate increase in June 2010 | (1.3) | 1.1 | ||||||
Decreased transmission pool revenue during the quarter in Bangor Hydro due to cooler temperatures in Q3 2011; Increased transmission pool revenue year-to-date due to recovery of regionally funded transmission investments | (1.3) | 2.5 | ||||||
Decreased transmission pool expenses during the quarter due to cooler temperatures in Q3 2011 throughout New England; Increased transmission pool expenses year-to-date due to higher charges for Bangor Hydro’s share of regionally funded transmission expenses | 0.5 | (0.1) | ||||||
Impact of the acquisition of MAM | (0.1) | 1.7 | ||||||
Other | 0.6 | (0.7) | ||||||
Contribution to consolidated net income – 2011 | $9.5 | $27.8 |
Maine Utilities’ USD and CAD contribution to consolidated net income decreased in Q3 2011, and increased year-to-date. The impact of a stronger Canadian dollar, year over year, reduced CAD earnings by $0.5 million in Q3 2011 and $1.4 million year-to-date.
Operating Revenues – Regulated
Q3 Operating Revenues – Regulated millions of US dollars | ||||||||||||
2011 | 2010 (adjusted) | 2009 (adjusted) | ||||||||||
Residential electric revenues | $16.9 | $13.5 | $11.9 | |||||||||
Commercial electric revenues | 14.0 | 11.1 | 9.6 | |||||||||
Industrial electric revenues | 2.8 | 3.3 | 3.0 | |||||||||
Other electric revenues | 2.3 | 2.0 | 2.8 | |||||||||
Total electric revenues | $36.0 | $29.9 | $27.3 | |||||||||
Resale of purchased power | 4.4 | 4.0 | 4.6 | |||||||||
Transmission pool revenue | 11.6 | 12.8 | 8.1 | |||||||||
Operating revenues – regulated | $52.0 | $46.7 | $40.0 |
YTD Operating Revenues – Regulated millions of US dollars | ||||||||||||
2011 | 2010 (adjusted) | 2009 (adjusted) | ||||||||||
Residential electric revenues | $50.9 | $37.0 | $35.7 | |||||||||
Commercial electric revenues | 41.9 | 29.1 | 26.8 | |||||||||
Industrial electric revenues | 8.6 | 8.6 | 7.8 | |||||||||
Other electric revenues | 7.3 | 7.2 | 8.5 | |||||||||
Total electric revenues | $108.7 | $81.9 | $78.8 | |||||||||
Resale of purchased power | 13.4 | 13.7 | 14.0 | |||||||||
Transmission pool revenue | 31.4 | 28.8 | 20.8 | |||||||||
Operating revenues – regulated | $153.5 | $124.4 | $113.6 |
20
Electric Revenue
Q3 Electric Sales Volumes | ||||||||||||
GWh | 2011 | 2010 | 2009 | |||||||||
Residential | 190.9 | 152.6 | 145.4 | |||||||||
Commercial | 222.0 | 162.6 | 155.1 | |||||||||
Industrial | 105.8 | 107.2 | 101.4 | |||||||||
Other | 3.0 | 3.3 | 3.1 | |||||||||
Total | 521.7 | 425.7 | 405.0 |
YTD Electric Sales Volumes | ||||||||||||
GWh | 2011 | 2010 | 2009 | |||||||||
Residential | 582.3 | 436.0 | 437.3 | |||||||||
Commercial | 639.0 | 447.4 | 443.2 | |||||||||
Industrial | 289.4 | 278.6 | 263.8 | |||||||||
Other | 8.6 | 8.7 | 8.7 | |||||||||
Total | 1,519.3 | 1,170.7 | 1,153.0 |
Q3 Average Electric Revenue/MWh | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
Dollars per MWh | $69 | $70 | $67 |
YTD Average Electric Revenue/MWh | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
Dollars per MWh | $72 | $70 | $68 |
The change in average electric revenue per MWh in 2011 compared to 2010 reflects a decrease in Bangor Hydro’s transmission rates on June 1, 2011, an increase to stranded cost rates on June 1, 2011 and an increase to transmission rates on June 1, 2010. The decreased transmission rates and increased stranded cost rates on June 1, 2011 are largely offsetting.
For the three months ended September 30, 2011, MPS (which was acquired in December 2010) contributed approximately $7.5 million to Maine Utility Operations’ Operating revenues – regulated and $(0.1) million to consolidated net income. For the nine months ended September 30, 2011, MPS contributed approximately $25.7 million to Maine Utility Operations’ Operating revenues – regulated and $1.7 million to consolidated net income.
21
CARIBBEAN UTILITY OPERATIONS
Overview
Caribbean Utility Operations includes Emera’s:
• | 80.2 percent investment in Light & 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 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 September 30, 2010 comparative information; the September 30, 2010 results contain only equity income. |
• | 50 percent direct and 30.4 percent indirect interest in Grand Bahama Power Company Ltd. (“GBPC”), a vertically-integrated utility and the sole provider of electricity on Grand Bahama Island. GBPC serves 19,000 customers and is regulated by GBPA which has granted it a licensed, regulated and exclusive franchise to produce, transmit and distribute electricity on the island until 2054. There is a fuel pass-through mechanism and flexible tariff adjustment policy to ensure costs are recovered and a reasonable return earned. A controlling interest in GBPC was acquired in December 2010, and accordingly its results are not fully consolidated in the September 30, 2010 comparative information; the September 30, 2010 results contain only equity income. |
• | 19.1 percent interest in St. Lucia Electricity Services Limited (“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 September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Operating revenues – regulated | $114.5 | – | $298.3 | – | ||||||||||||
Regulated fuel for generation and purchased power | 75.8 | – | 200.3 | – | ||||||||||||
Operating, maintenance and general | 22.2 | – | 63.8 | – | ||||||||||||
Property taxes | 0.4 | – | 1.1 | – | ||||||||||||
Depreciation and amortization | 8.5 | – | 17.2 | – | ||||||||||||
Total operating expenses | 106.9 | – | 282.4 | – | ||||||||||||
Income from operations | 7.6 | – | 15.9 | – | ||||||||||||
Income from equity investment | 0.6 | 3.2 | 2.1 | 5.4 | ||||||||||||
Other income (expenses), net | 6.7 | (0.2) | 35.4 | 22.3 | ||||||||||||
Interest expense, net | 2.0 | – | 6.4 | – | ||||||||||||
Income before provision for income taxes | 12.9 | 3.0 | 47.0 | 27.7 | ||||||||||||
Income tax expense | – | – | 0.2 | – | ||||||||||||
Net income | 12.9 | 3.0 | 46.8 | 27.7 | ||||||||||||
Non-controlling interest in subsidiaries | (2.2) | (0.2) | (3.1) | (0.2) | ||||||||||||
Contribution to consolidated net income | $10.7 | $2.8 | $43.7 | $27.5 | ||||||||||||
Contribution to consolidated earnings per common share | $0.09 | $0.02 | $0.36 | $0.24 |
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Caribbean Utility Operations’ contribution to consolidated net income increased by $7.9 million to $10.7 million in Q3 2011 compared to $2.8 million in Q3 2010 (adjusted). Year-to-date contribution to consolidated net income increased by $16.2 million to $43.7 million in 2011 compared to $27.5 million in 2010 (adjusted). Highlights of the net income changes are summarized in the following table:
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||
Contribution to consolidated net income – 2010 (adjusted) | $2.8 | $27.5 | ||||||
Gain on acquisition of LPH in 2010 | – | (22.5) | ||||||
Gain on acquisition of LPH in Q1 2011 | 0.3 | 28.3 | ||||||
Increased investment in LPH and GBPC | 7.6 | 10.4 | ||||||
Contribution to consolidated net income – 2011 | $10.7 | $43.7 |
Operating Revenues – Regulated
Q3 Operating Revenues – Regulated millions of Canadian dollars | ||||
2011 | ||||
Residential electric revenues | $13.4 | |||
Commercial electric revenues | 24.4 | |||
Industrial electric revenues | 3.1 | |||
Other electric revenues | 0.9 | |||
Total electric revenues | $41.8 | |||
Other – service installation revenue and fuel surcharge | 72.7 | |||
Operating revenues – regulated | $114.5 |
YTD Operating Revenues – Regulated millions of Canadian dollars | ||||
2011 | ||||
Residential electric revenues | $33.7 | |||
Commercial electric revenues | 64.5 | |||
Industrial electric revenues | 10.4 | |||
Other electric revenues | 2.7 | |||
Total electric revenues | $111.3 | |||
Other – service installation revenue and fuel surcharge | 187.0 | |||
Operating revenues – regulated | $298.3 |
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.
Q3 Electric Sales Volumes GWh | ||||
2011 | ||||
Residential | 111.2 | |||
Commercial | 196.9 | |||
Industrial | 21.3 | |||
Other | 5.5 | |||
Total | 334.9 |
YTD Electric Sales Volumes GWh | ||||
2011 | ||||
Residential | 287.5 | |||
Commercial | 521.2 | |||
Industrial | 68.3 | |||
Other | 16.1 | |||
Total | 893.1 |
Q3 Average Electric Revenue/MWh | ||||
2011 | ||||
Dollars per MWh | $124.8 |
YTD Average Electric Revenue/MWh | ||||
2011 | ||||
Dollars per MWh | $124.6 |
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Regulated Fuel for Generation and Purchased Power
Q3 Production Volumes GWh | ||||
2011 | ||||
Oil | 361.4 |
YTD Production Volumes GWh | ||||
2011 | ||||
Oil | 977.5 |
Q3 Average Unit Fuel Costs | ||||
2011 | ||||
Dollars per MWh | $209.7 |
YTD Average Unit Fuel Costs | ||||
2011 | ||||
Dollars per MWh | $204.9 |
Fuel Pass–Through Mechanisms
BLPC
All BLPC fuel costs are passed to customers through the fuel clause adjustment (“fuel surcharge”). Fair Trading Commission, Barbados has approved the calculation of the fuel surcharge, which is adjusted on a monthly basis. BLPC has the ability to carryover an under-recovery to later months to smooth the fuel surcharge for customers.
GBPC
The current base tariff is calculated based on a price of $20 USD per barrel of oil. The amount by which actual fuel costs exceed $20 USD dollars per barrel is recovered or rebated through the fuel surcharge, which is adjusted on a monthly basis. The methodology for calculating the amount of the fuel surcharge has been approved by GBPA.
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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 in July 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 II pipeline. Brunswick Pipeline is accounted for as a direct financing lease. |
• | M&NP is a $2 billion, 1,400-kilometer pipeline which transports natural gas from offshore Nova Scotia to markets in Maritime Canada and the northeastern United States. The investment in M&NP is equity accounted. |
Review of 2011
Pipelines’ Net Income millions of Canadian dollars (except per share amounts) | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Brunswick Pipeline | ||||||||||||||||
Operating revenues – regulated | $12.5 | $12.1 | $37.0 | $36.9 | ||||||||||||
Other income | 0.1 | 1.4 | 0.4 | 0.6 | ||||||||||||
Interest expense, net | 7.6 | 7.6 | 22.6 | 22.9 | ||||||||||||
Brunswick Pipeline net income | 5.0 | 5.9 | 14.8 | 14.6 | ||||||||||||
Income from equity investment | 2.0 | 2.2 | 6.2 | 6.3 | ||||||||||||
Contribution to consolidated net income | $7.0 | $8.1 | $21.0 | $20.9 | ||||||||||||
Contribution to consolidated earnings per common share | $0.06 | $0.07 | $0.17 | $0.18 |
Pipelines’ contribution to consolidated net income decreased by $1.1 million to $7.0 million in Q3 2011 compared to $8.1 million in Q3 2010 (adjusted). Year-to-date, Pipelines’ contribution to consolidated net income increased $0.1 million to $21.0 million in 2011 compared to $20.9 million in 2010 (adjusted). Highlights of the income changes are summarized in the following table:
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||
Contribution to consolidated net income – 2010 (adjusted) | $8.1 | $20.9 | ||||||
Brunswick Pipeline – Decreased net income during the quarter primarily due to the change in the mark-to-market of currency hedges | (0.9) | 0.2 | ||||||
Decreased income from M&NP equity investment | (0.2) | (0.1) | ||||||
Contribution to consolidated net income – 2011 | $7.0 | $21.0 |
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SERVICES, RENEWABLES AND OTHER INVESTMENTS
Overview
Services, Renewables and Other Investments includes Emera Energy Inc. (“Emera Energy”); Emera Utility Services Inc. (“EUS”); and Emera Newfoundland & Labrador Holdings Inc. (“ENL”), as well as other investments.
• | Emera Energy includes: |
• | Emera Energy Services, a physical energy business which purchases and sells natural gas and electricity and provides related energy asset management services. |
• | Bayside Power, a 260-MW gas-fired merchant electricity generating facility in Saint John, New Brunswick. |
• | Emera’s 50 percent joint venture ownership of Bear Swamp, a 600-MW pumped storage hydro-electric facility in northern Massachusetts. This investment is equity accounted. |
• | EUS is a utility services contractor. |
• | ENL is a wholly-owned subsidiary of Emera focused on transmission investments related to a proposed 824-MW hydro-electric generating facility at Muskrat Falls in Labrador. These investments include an estimated $1.2 billion transmission project between Newfoundland and Nova Scotia, including a 180-kilometre subsea cable (“Maritime Link Project”). In addition, together with Nalcor Energy, the Newfoundland and Labrador’s crown-owned energy company leading the project in that province, Emera is investing in the development of a $2.1 billion electricity transmission project in Newfoundland and Labrador. These projects are 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 37.7 percent investment in Atlantic Hydrogen Inc (“AHI”). These investments are equity accounted. |
Review of 2011
Emera Energy and EUS are reported on an income before interest expense, net and income tax expense (recovery) (“EBIT”) basis.
Services, Renewables and Other Investments Net Income millions of Canadian dollars (except per share amounts) | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Emera Energy | $(0.1) | $4.8 | $5.2 | $3.9 | ||||||||||||
EUS | 2.4 | 4.1 | 2.3 | 4.0 | ||||||||||||
Income (loss) from equity investments | 1.0 | (0.3) | 2.2 | (0.5) | ||||||||||||
Other income | – | – | 14.1 | – | ||||||||||||
Interest expense, net | 0.2 | 0.3 | 0.9 | 1.0 | ||||||||||||
Income tax expense (recovery) | 0.8 | 1.6 | 1.9 | (0.4) | ||||||||||||
Contribution to consolidated net income | $2.3 | $6.7 | $21.0 | $6.8 | ||||||||||||
Bear Swamp after-tax mark-to-market adjustment | $(0.5) | $(1.9) | $(0.1) | $(6.0) | ||||||||||||
Contribution to consolidated net income, absent the Bear Swamp after-tax mark-to-market adjustment | $2.8 | $8.6 | $21.1 | $12.8 | ||||||||||||
Contribution to consolidated earnings per common share | $0.02 | $0.06 | $0.17 | $0.06 | ||||||||||||
Contribution to consolidated earnings per common share, absent the Bear Swamp after-tax mark-to-market adjustment | $0.03 | $0.08 | $0.17 | $0.11 |
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Services, Renewables and Other Investments contribution to consolidated net income decreased by $4.4 million to net income of $2.3 million in Q3 2011 compared to net income of $6.7 million in Q3 2010 (adjusted). Year-to-date, contribution to consolidated net income increased $14.2 million to $21.0 million in 2011 compared to $6.8 million in 2010 (adjusted). Highlights of the income changes are summarized in the following table:
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||
Contribution to consolidated net income – 2010 (adjusted) | $6.7 | $6.8 | ||||||
Emera Energy – Decreased during the quarter due to the reversal of mark-to-market gains; 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, partially offset by the reversal of the 2010 mark-to-market gains | (4.9) | 1.3 | ||||||
EUS – Decreased due to reduced construction activity | (1.7) | (1.7) | ||||||
Income from equity investments – Increased due to investments in APUC and CPUV | 1.3 | 2.7 | ||||||
Other income (expenses), net – Increased year-to-date primarily due to an after-tax gain of $12.8 million on APUC subscription receipts | – | 14.1 | ||||||
Income tax expense – Decreased during the quarter primarily due to lower earnings and a lower statutory income tax rate; Increased year-to-date primarily due to the taxable gain on APUC subscription receipts | 0.8 | (2.3) | ||||||
Other | 0.1 | 0.1 | ||||||
Contribution to consolidated net income – 2011 | $2.3 | $21.0 |
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CORPORATE
Overview
Corporate includes certain corporate-wide functions including executive management, strategic planning, treasury services, financial reporting, tax planning, business development and corporate governance. Corporate also includes interest expense and income taxes associated with corporate activities.
Review of 2011
Corporate millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Revenue | $7.6 | $7.6 | $22.6 | $22.9 | ||||||||||||
Corporate costs | 9.5 | 6.9 | 22.9 | 18.1 | ||||||||||||
Interest expense | 8.5 | 7.7 | 25.4 | 24.3 | ||||||||||||
Income tax recovery | (4.1) | (2.6) | (12.4) | (10.5) | ||||||||||||
(6.3) | (4.4) | (13.3) | (9.0) | |||||||||||||
Preferred stock dividends | 3.3 | 3.0 | 6.6 | 3.0 | ||||||||||||
Contribution to consolidated net income | $(9.6) | $(7.4) | $(19.9) | $(12.0) |
Revenue
Revenue consists of intercompany interest and preferred dividends from Brunswick Pipeline.
Corporate Costs
Corporate costs increased by $2.6 million to $9.5 million in Q3 2011 compared to $6.9 million in Q3 2010 (adjusted) due to increased foreign exchange expense resulting from a weaker CAD, partially offset by decreased deferred compensation costs. Year-to-date, corporate costs increased $4.8 million to $22.9 million in 2011 compared to $18.1 million in 2010 (adjusted) due to increased foreign exchange expense resulting from a weaker CAD, partially offset by decreased deferred compensation costs and decreased acquisition costs.
Income Tax Recovery
Income tax recovery increased by $1.5 million to $4.1 million in Q3 2011 compared to $2.6 million in Q3 2010 (adjusted) and year-to-date income tax recovery increased by $1.9 million to $12.4 million in 2011 compared to $10.5 million in 2010 (adjusted) due to an increase in corporate costs and interest expense.
Preferred Stock Dividends
Preferred stock dividends increased by $0.3 million to $3.3 million in Q3 2011 compared to $3.0 million in Q3 2010 (adjusted) and year-to-date preferred stock dividends increased by $3.6 million to $6.6 million in 2011 compared to $3.0 million in 2010 (adjusted) due to the issuance of preferred shares in June 2010.
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OUTLOOK
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 Utility Operations. The utilities expect average income growth to be 3 percent to 5 percent annually over the next five years as new investments are made in renewable generation and transmission.
NSPI
NSPI anticipates earning a regulated ROE within its allowed range in 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 $340 million in 2011. The Company 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 $62 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 LPH and GBPC. Caribbean Utility Operations plans to invest approximately $164 million in capital programs in 2011, including $92.6 million related to the acquisition of LPH.
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. ENL plans to invest approximately $20 million on the Maritime Link Project 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 Emera’s markets, the loss of one or more large customers, regulatory decisions affecting customer rates and changes in environmental legislation. Emera’s subsidiaries are capable of paying dividends to Emera provided they do not breach their debt covenants after giving effect to the dividend payment.
In addition to internally generated funds, Emera and its subsidiaries have, in aggregate access to $1.3 billion committed syndicated revolving bank lines of credit, of which approximately $558 million is undrawn and available as at September 30, 2011. In August 2011, Emera increased its committed syndicated facility from $600 million to $700 million, and NSPI’s reduced its committed syndicated facility from $600 million to $500 million. The maturity of both facilities was extended from June 2013 to June 2015. NSPI has an active commercial paper program for up to $400 million, of which outstanding amounts are 100 percent backed by NSPIs’ bank lines referred to above, which results in an equal amount of credit being considered drawn and unavailable.
As at September 30, 2011, the outstanding short-term debt is as follows:
millions of dollars | Maturity | Credit Line | Utilized | Undrawn and Available | ||||||||||||
Emera – Operating and acquisition credit facility | June 2015 – Revolver | $700 | $449 | $251 | ||||||||||||
NSPI – Operating credit facility | June 2015 – Revolver | 500 | 243 | 257 | ||||||||||||
Bangor Hydro – in USD – Operating credit facility | September 2013 – Revolver | 80 | 55 | 25 | ||||||||||||
Other – in USD – Operating credit facilities | Various | 29 | 6 | 23 |
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. As at September 30, 2011, $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 from $500 million to $800 million, respectively. As at September 30, 2011, $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 $11.3 million (2010 – $14.3 million) during the three months ended September 30, 2011, and $36.7 million (2010 – $42.3 million) for the nine months ended September 30, 2011. The amount is recognized in “Regulated fuel for generation and purchased power” or netted against energy marketing margin in “Non-regulated operating revenues” and is measured at the exchange amount. As at September 30, 2011, the amount payable to the related party was $3.5 million (December 31, 2010 – $3.9 million), and is under normal interest and credit terms.
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 practices are overseen by the Board of Directors. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group which is independent of all operations.
The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange and interest rates using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. These physical and financial contracts are classified as held-for-trading (“HFT”). Collectively these contracts are considered “derivatives”.
The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. The Company continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts where the criteria are no longer met.
Derivatives qualify for hedge accounting if they meet stringent documentation requirements, and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the effective portion of the change in the fair value of derivatives is deferred to Accumulated Other Comprehensive Loss (“AOCL”) and recognized in income in the same period the related hedged item is realized. Any ineffective portion of the change in the fair value of the cash flow hedges is recognized in net income in the reporting period.
Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value, with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.
Derivatives entered into by NSPI that are documented as economic hedges, and for which the NPNS exception has not been taken, receive regulatory deferral as approved by the UARB. These derivatives are recorded at fair value on the balance sheet as derivative assets or liabilities. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized when 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
31
as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category when another accounting treatment applies.
Hedging Items Recognized on the Balance Sheets
The Company has the following categories on the balance sheet related to derivatives in valid hedging relationships:
As at millions of Canadian dollars | September 30 2011 | December 31 2010 (adjusted) | ||||||
Derivative instrument assets (current and other assets) | $2.9 | $7.0 | ||||||
Derivative instrument liabilities (current and long-term liabilities) | (20.5) | (18.3) | ||||||
Net derivative instrument liabilities | $(17.6) | $(11.3) |
Hedging Impact Recognized in Net Income
The Company recognized the following gains (losses) related to the effective portion of hedging relationships under the following categories:
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Regulated operating revenues | $0.8 | – | $2.4 | – | ||||||||||||
Non-regulated fuel and purchased power | (1.9) | $(2.2) | (4.7) | $(6.5) | ||||||||||||
Other income (expense), net | (0.4) | – | (0.1) | – | ||||||||||||
Effectiveness net losses | $(1.5) | $(2.2) | $(2.4) | $(6.5) |
The effectiveness gains (losses) reflected in the above table would be offset in net income by the change in the hedged item realized in the period.
The Company recognized in net income the following gains (losses) related to the ineffective portion of hedging relationships under the following categories:
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Non-regulated fuel and purchased power | $(0.1) | – | $(0.9) | – | ||||||||||||
Ineffectiveness losses | $(0.1) | – | $(0.9) | – |
Regulatory Items Recognized on the Balance Sheets
The Company has the following categories on the balance sheet related to derivatives receiving regulatory deferral:
As at millions of Canadian dollars | September 30 2011 | December 31 2010 (adjusted) | ||||||
Derivative instrument assets (current and other assets) | $92.7 | $59.9 | ||||||
Regulatory assets (current and other assets) | 24.9 | 34.2 | ||||||
Derivative instrument liabilities (current and long-term liabilities) | (24.9) | (34.2) | ||||||
Regulatory liabilities (current and long-term liabilities) | $(92.7) | $(59.9) | ||||||
– | – |
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Regulatory Impact Recognized in Net Income
The Company recognized the following gains (losses) related to derivatives receiving regulatory deferral as follows:
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Other income (expenses), net | – | $1.5 | – | $0.5 | ||||||||||||
Regulated fuel for generation and purchased power | $(0.6) | (10.7) | $(17.5) | (55.9) | ||||||||||||
Net losses | $(0.6) | $(9.2) | $(17.5) | $(55.4) |
Held-for-trading Items Recognized on the Balance Sheets
The Company has the following categories on the balance sheet related to HFT derivatives:
As at millions of Canadian dollars | September 30 2011 | December 31 2010 (adjusted) | ||||||
Derivative instruments assets (current and other assets) | $17.3 | $18.8 | ||||||
Derivative instruments liabilities (current and long-term liabilities) | (15.1) | (13.2) | ||||||
Net derivative instrument assets | $2.2 | $5.6 |
Held-for-trading Items Recognized in Net Income
The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives in net income:
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Non-regulated operating revenues | $(0.3) | $9.7 | $10.0 | $15.0 | ||||||||||||
Other income (expenses), net | (0.6) | 1.8 | (0.3) | 1.8 | ||||||||||||
Net (losses) gains | $(0.9) | $11.5 | $9.7 | $16.8 |
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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 September 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 16 of the Unaudited Condensed Consolidated Financial Statements as at and for the nine months ended September 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 to be filed with the SEC for the year ending December 31, 2011, but would be required to include an attestation report in its subsequent Annual Reports for any year in which it is an accelerated filer or a large accelerated filer.
SUMMARY OF QUARTERLY RESULTS
For the quarter ended millions of dollars (except | Q3 2011 | Q2 2011 | Q1 2011 | Q4 2010 (adjusted) | Q3 2010 (adjusted) | Q2 2010 (adjusted) | Q1 2010 (adjusted) | Q4 2009 (adjusted) | ||||||||||||||||||||||||
Total operating revenues | $496.1 | $501.7 | $554.6 | $408.9 | $394.0 | $364.7 | $438.5 | $400.1 | ||||||||||||||||||||||||
Net income attributable to common shareholders | 40.8 | 29.9 | 123.6 | 24.1 | 40.3 | 48.5 | 77.8 | 37.8 | ||||||||||||||||||||||||
Earnings per common share – basic | 0.33 | 0.24 | 1.06 | 0.21 | 0.35 | 0.43 | 0.68 | 0.33 | ||||||||||||||||||||||||
Earnings per common share – diluted | 0.33 | 0.24 | 1.03 | 0.21 | 0.35 | 0.42 | 0.67 | 0.33 |
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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