Exhibit 99.1
Management’s Discussion & Analysis
As at November 2, 2011
Management’s Discussion and Analysis (“MD&A”) provides a review of the results of operations of Nova Scotia Power Inc. 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, “NSPI” and “Company” refer to Nova Scotia Power Inc.
Effective January 1, 2011, Nova Scotia Power Inc. changed the basis of presentation of its financial statements (including the application of rate-regulated accounting) 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 Nova Scotia Power Inc. unaudited condensed financial statements and supporting notes as at and for the nine months ended September 30, 2011, prepared in accordance with USGAAP; and the Nova Scotia Power Inc. MD&A and annual audited financial statements and supporting notes as at and for the year ended December 31, 2010, prepared in accordance with CGAAP.
Nova Scotia Power Inc.’s accounting policies are subject to examination and approval by the Nova Scotia Utility and Review Board (“UARB”). The rate-regulated accounting policies of Nova Scotia Power Inc. may differ from those used by non-regulated companies with respect to the timing of recognition of certain assets, liabilities, revenues and expenses.
All amounts are in Canadian dollars (“CAD”).
Additional information related to NSPI, including the Company’s Annual Information Form, can be found on SEDAR atwww.sedar.com and on EDGAR atwww.sec.gov.
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 NSPI’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.
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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, NSPI undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise.
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 Statements of Income for the three and nine months ended September 30, 2010 and 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 Financial Review of the Statements of Income, Balance Sheets and Statements of Cash Flows; then continues with a discussion on Outlook, Liquidity and Capital Resources, Transactions with Related Parties, Risk Management and Financial Instruments, Disclosure and Internal Controls and Summary of Quarterly Results.
INTRODUCTION AND STRATEGIC OVERVIEW
NSPI was created in 1992 through the privatization of the crown corporation Nova Scotia Power Corporation. NSPI is a fully-integrated regulated electric utility and the primary electricity supplier in Nova Scotia, Canada. The Company provides electricity generation, transmission and distribution services to approximately 492,000 customers and has $3.9 billion in assets. The Company 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 return on equity (“ROE”) range for 2011 is 9.1 percent to 9.6 percent, based on an actual regulated common equity component of up to 40 percent of average regulated capitalization.
Non-GAAP Financial Measure
NSPI uses a financial measure that does not have a standardized meaning under USGAAP.
“Electric margin” is a non-GAAP financial measure used by NSPI and is defined as “Electric revenues” less “Fuel for generation and purchased power” and “Fuel for generation and purchased power – affiliates”, net of the “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 Review of 2011 section.
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Developments
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.
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.
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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.
Appointments
On September 22, 2011, Ray Ivany, President and Vice-Chancellor of Acadia University, joined NSPI’s Board of Directors.
On May 16, 2011, Judy Steele, FCA was appointed Chief Financial Officer of NSPI 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 Emera’s Annual General Meeting.
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FINANCIAL REVIEW
Review of 2011
For the millions of Canadian dollars | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
| 2011 | 2010 (adjusted) | 2011 | 2010 (adjusted) | |||||||||||||
Operating revenues | $ | 276.0 | $ | 272.2 | $ | 943.8 | $ | 888.2 | ||||||||
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Fuel for generation and purchased power | 125.0 | 133.4 | 419.3 | 432.5 | ||||||||||||
Fuel for generation and purchased power – affiliates | 0.2 | 1.6 | 0.3 | 8.0 | ||||||||||||
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 | ||||||||||||
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Total operating expenses | 232.8 | 226.8 | 766.5 | 698.2 | ||||||||||||
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Income from operations | 43.2 | 45.4 | 177.3 | 190.0 | ||||||||||||
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Other expenses, net | 2.3 | 1.9 | 6.8 | 7.8 | ||||||||||||
Interest expense, net | 26.7 | 25.2 | 80.6 | 77.9 | ||||||||||||
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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 | ) | ||||||||
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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 | ||||||||||||
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Net income attributable to common shareholders | $ | 21.0 | $ | 18.6 | $ | 101.3 | $ | 99.3 | ||||||||
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NSPI’s net income attributable to common shareholders increased $2.4 million to $21.0 million in Q3 2011 compared to $18.6 million in Q3 2010 (adjusted). NSPI’s net income attributable to common shareholders 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 | ||||||
| Net income attributable to common shareholders – 2010 (adjusted) | $ 18.6 | $ 99.3 | ||||||
| (Decreased) increased electric margin (see Electric Revenues section for explanation) | (4.9 | ) | 5.7 | |||||
| Decreased operating, maintenance and general expenses (“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 | ) | ||||
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| Net income attributable to common shareholders – 2011 | $ 21.0 | $ 101.3 | ||||||
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Balance Sheets Highlights
Significant changes in the balance sheets between September 30, 2011 and December 31, 2010 (adjusted) include:
millions of Canadian dollars | Increase (Decrease) | Explanation | ||||
Assets | ||||||
| Income taxes receivable | $ | (26.5 | ) | Decreased primarily due to receipt of prior year income taxes recoverable, partially offset by current year recovery of income taxes due to accelerated tax deductions for property, plant and equipment, including renewable investments. | ||
| Derivative instruments (current and long-term) | 32.8 | Increased primarily due to favourable USD price positions and additional hedges, partially offset by unfavourable commodity price positions. | ||||
| Prepaid expenses | 10.1 | Timing of provincial grants in lieu of taxes and insurance payments. | ||||
| Property, plant and equipment | 55.9 | Increased primarily due to capital spending, partially offset by depreciation. | ||||
| Deferred income taxes | (16.8 | ) | Decreased primarily due to increased deferred income tax liability on property, plant and equipment, including renewable investments, resulting in reclassification to deferred income tax liability. | |||
| Liabilities and Equity | ||||||
| Short-term debt and long-term debt (including current portion) | (41.1 | ) | Decreased debt levels. | |||
| Accounts payable | (24.3 | ) | Decreased primarily due to release of holdbacks and timing of fuel and other vendor payments. | |||
| Deferred income taxes (current and long-term) | 35.9 | Increased primarily due to increased deferred income tax liability on property, plant and equipment, including renewable investments, resulting in reclassification of deferred income tax asset. | ||||
| Regulatory liabilities (current and long-term) | (14.4 | ) | Decreased deferred income tax regulatory liability and decreased regulatory liability related to 2010 tax benefit deferral, partially offset by increased derivative regulatory liability. | |||
| Pension and post-retirement liabilities (current and long-term) | (16.5 | ) | Decreased primarily due to NSPI’s cash contributions exceeding the value of the current benefit accrual. | |||
| Asset retirement obligations | (54.9 | ) | Decreased primarily due to change in estimates of retirement dates and future decommissioning costs. | |||
| Common stock | 50.0 | Issuance of common shares. | ||||
| Accumulated other comprehensive loss | 17.2 | Amortization of unrecognized pension and post-retirement benefit costs. | ||||
| Retained earnings | 101.3 | Net income. | ||||
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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, beginning of period | $ | 0.3 | $ | 0.3 | ||||||
Provided by (used in): | ||||||||||
Operating activities | 226.7 | 152.3 | In 2011 and 2010, cash income, partially offset by unfavourable non-cash working capital. | |||||||
Investing activities | (229.3 | ) | (359.3 | ) | In 2011 and 2010, capital spending, including additions associated with multi-year projects and renewable investments. | |||||
Financing activities | $ | 2.3 | 207.0 | In 2011, issuance of common stock, partially offset by decreased short-term debt levels. In 2010, issuance of long-term debt and common stock, partially offset by retirement of long-term debt and decreased short-term debt levels. | ||||||
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Cash, end of period | — | $ | 0.3 | |||||||
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Operating Revenues
NSPI’s Operating Revenues 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 | ||||||||||||
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Operating revenues | $ | 276.0 | $ | 272.2 | $ | 943.8 | $ | 888.2 | ||||||||
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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 | |||||||||
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Total | 2,547 | 2,663 | 2,526 | |||||||||
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Year-to-date (“YTD”) Electric 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 | |||||||||
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Total | 8,714 | 8,569 | 8,363 | |||||||||
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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 | |||||||||
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Total | $ | 270.2 | $ | 266.4 | $ | 264.0 | ||||||
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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 | |||||||||
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Total | $ | 926.8 | $ | 870.9 | $ | 885.2 | ||||||
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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 | |||||
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Electric revenues – 2011 | $ | 270.2 | $ | 926.8 | ||||
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NSPI distinguishes revenues related to the recovery of fuel costs (“fuel electric revenues”) from revenues related to the recovery of non-fuel costs (“non-fuel electric revenues”) because the FAM introduced on January 1, 2009 enables NSPI to seek recovery of fuel costs through regularly scheduled rate adjustments. Differences between actual fuel costs and amounts recovered from customers through electricity rates in a 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.
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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 | ||||||||||||
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| Total electric revenues | $ | 270.2 | $ | 266.4 | $ | 926.8 | $ | 870.9 | ||||||||
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| Fuel for generation and purchased power, including affiliates | (125.2 | ) | (135.0 | ) | (419.6 | ) | (440.5 | ) | ||||||||
| 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 | ) | ||||||||
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| Electric margin | $ | 147.3 | $ | 152.2 | $ | 505.2 | $ | 499.5 | ||||||||
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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”)
| 2011 | 2010 | 2009 | ||||||||||
Dollars per MWh | $ | 58 | $ | 57 | $ | 60 | ||||||
YTD Average Electric Margin / MWh
| 2011 | 2010 | 2009 | ||||||||||
Dollars per MWh | $ | 58 | $ | 58 | $ | 61 | ||||||
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 | |||||||||
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Total | 2,698 | 2,812 | 2,672 | |||||||||
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Purchased power includes 156 GWh of renewables in Q3 2011 (2010 – 114 GWh; 2009 – 63 GWh).
YTD Production Volumes GWh | ||||||||||||
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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 | |||||||||
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Total | 9,179 | 9,006 | 8,857 | |||||||||
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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 | ||||||
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, 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.
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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 | ||||||
| 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 | ) | ||||
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| Fuel for generation and purchased power, including affiliates – 2011 | $ 125.2 | $ 419.6 | ||||||
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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.
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.
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 | |||
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FAM regulatory asset – Balance at September 30 | $ | 87.4 | ||
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OUTLOOK
Economic Environment
NSPI will continue to pursue investments related to the transformation of the energy industry to lower emissions and comply with renewable energy standards. This will also include improvement to the transmission system.
Environmental Legislation
NSPI is subject to environmental regulations as set by both the Province of Nova Scotia and the Government of Canada. The Company continues to work with officials at both levels of government so as to comply with these regulations in an integrated way.
Operations
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.
LIQUIDITY AND CAPITAL RESOURCES
The Company generates cash primarily through the generation, transmission and distribution of electricity. NSPI’s customer base is 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 NSPI’s markets, the loss of one or more large customers, regulatory decisions affecting customer rates and changes in environmental legislation.
In addition to internally generated funds, NSPI has access to a $500 million committed syndicated revolving bank line of credit. In August 2011, NSPI reduced its committed facility from $600 million to $500 million and the maturity 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 the Company’s 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 Canadian dollars | Maturity | Credit Line Committed | Utilized | Undrawn and available | ||||||||||
Operating credit facility | June 2015 – Revolver | $ | 500 | $ | 243 | $ | 257 | |||||||
NSPI has debt covenants associated with its credit facilities. Covenants are tested regularly and the Company is in compliance with covenant requirements.
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.
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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.
TRANSACTIONS WITH RELATED PARTIES
The Company enters into transactions with related parties in the normal course of operations. All related party transactions with NSPI are governed by an affiliate Code of Conduct that is approved by the UARB.
NSPI, Emera Energy Services (“EES”), Bangor Hydro Electric Company (“Bangor Hydro”) and Emera Utility Services (“EUS”) are wholly-owned subsidiaries of Emera Incorporated (“Emera”). Emera owns a 12.9 percent interest in the Maritimes & Northeast Pipeline (“M&NP”).
Related party transactions are summarized in the following table:
For the millions of Canadian | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||||||
Nature of Service | Presentation | 2011 | 2010 | 2011 | 2010 | |||||||||||||||
| Sales: | ||||||||||||||||||||
| Emera | Corporate support and other services | OM&G | $ | 0.6 | $ | 0.6 | $ | 2.0 | $ | 2.2 | ||||||||||
| EES | Corporate support and other services | OM&G | 0.3 | 0.3 | 0.9 | 0.9 | ||||||||||||||
| Bangor Hydro | Corporate support and other services | OM&G | 0.2 | 0.2 | 0.7 | 0.7 | ||||||||||||||
| Other | Corporate support and other services | OM&G | 0.5 | 0.2 | 1.3 | 0.7 | ||||||||||||||
| Purchases: | ||||||||||||||||||||
| EES | Net purchase of electricity | Fuel for generation and purchased power – affiliates | — | 0.6 | — | 6.3 | ||||||||||||||
| EES | Net purchase of natural gas | Fuel for generation and purchased power – affiliates | 0.2 | 1.0 | 0.3 | 1.7 | ||||||||||||||
| EUS | Maintenance services | OM&G | 0.2 | 0.1 | 5.2 | 0.7 | ||||||||||||||
| EUS | Purchase of inventory | Inventory | 0.1 | 0.2 | 0.5 | 0.9 | ||||||||||||||
| EUS | Construction services | Property, plant and equipment | 4.4 | 18.9 | 10.2 | 33.7 | ||||||||||||||
Beginning in Q2 2011, NSPI has recorded the impact of two agreements with Emera on a net basis in the statements of income. Under the agreements, NSPI purchased power from Emera and received contract revenues from Emera of $1.9 million (2010 – nil) for the three months ended September 30, 2011 and $6.8 million (2010 – nil) for the nine months ended September 30, 2011. Prior interim periods have been reclassified to reflect this change.
In the ordinary course of business, the Company purchased $3.3 million (2010 – $4.8 million) in natural gas transportation capacity from M&NP for the three months ended September 30, 2011, and $11.6 million (2010 – $14.0 million) for the nine months ended September 30, 2011. The amount is recognized in “Fuel for generation and purchased power” and is measured at the exchange amount. As at September 30, 2011, the amount payable to M&NP is $0.9 million (December 31, 2010 – $1.0 million) and is under normal interest and credit terms.
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During the three months ended September 30, 2011 and 2010, no common shares were issued to Emera or an affiliate under common control of Emera. During the nine months ended September 30, 2011, the Company issued 5.0 million (2010 – 5.0 million) common shares to Emera and an affiliate under common control of Emera for total consideration of $50.0 million (2010 – $50.0 million).
On May 28, 2010, NSPI purchased $30.1 million in wind generation assets under development related to the Digby Wind Project from a subsidiary of Emera. This transaction was measured at the carrying amount of the assets transferred. As at September 30, 2011 and December 31, 2010, there were no amounts due.
Amounts due (to) from related parties are summarized in the following table:
As at millions of Canadian dollars | September 30 2011 | December 31 2010 (adjusted) | ||||||
Due from related parties: | ||||||||
EES | $ 0.2 | $ 0.7 | ||||||
Bangor Hydro | 0.4 | — | ||||||
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| 0.6 | 0.7 | |||||||
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EUS | (0.9 | ) | (5.5 | ) | ||||
Emera | (0.5 | ) | (1.4 | ) | ||||
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Net due to related parties | $ (0.8 | ) | $ (6.2 | ) | ||||
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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
NSPI’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 and foreign exchange using financial instruments consisting mainly of foreign exchange forwards and swaps, and coal, oil and gas 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 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.
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Regulatory Items Recognized on the Balance Sheets
The Company has the following categories on the balance sheets related to derivatives receiving regulatory deferral:
As at millions of Canadian dollars | September 30 2011 | December 31 2010 (adjusted) | ||||||
Derivative instrument assets (including current and other assets) | $ 92.7 | $ 59.9 | ||||||
Regulatory assets (including current and other assets) | 24.9 | 34.2 | ||||||
Derivative instrument liabilities (including current and long-term liabilities) | (24.9 | ) | (34.2 | ) | ||||
Regulatory liabilities (including current and long-term liabilities) | $ (92.7 | ) | $ (59.9 | ) | ||||
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Net asset (liability) | — | — | ||||||
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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 expenses, net | — | $ 1.5 | — | $ 0.5 | ||||||||||||
Fuel for generation and purchased power | $ (0.6 | ) | (10.7 | ) | $ (17.5 | ) | (55.9 | ) | ||||||||
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Net losses | $ (0.6 | ) | $ (9.2 | ) | $ (17.5 | ) | $ (55.4 | ) | ||||||||
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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, have designed as at September 30, 2011 disclosure controls and procedures and internal controls over financial reporting (“ICFR”) as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”).
Pursuant to Section 404(c) of the Sarbanes-Oxley Act of 2002 (“SOX”), as added by Section 989G of the Dodd-Frank Wall Street Reform and Consumer Protection Act, the requirement under Section 404(b) of SOX to file an auditor attestation report on an issuer’s ICFR does not apply with respect to any audit report prepared for an issuer that is neither an accelerated filer nor a large accelerated filer, as defined in Rule 12b-2 under the United States Securities Exchange Act of 1934, as amended. NSPI is currently not an accelerated filer or a large accelerated filer and therefore is not required to file an attestation report on its ICFR.
SUMMARY OF QUARTERLY RESULTS
For the quarter ended millions of Canadian dollars | Q3 2011 | Q2 2011 | Q1 2011 | Q4 2010 (adjusted) | Q3 2010 (adjusted) | Q2 2010 (adjusted) | Q1 2010 (adjusted) | Q4 2009 (adjusted) | ||||||||||||||||||||||||
Total operating revenues | $ | 276.0 | $ | 299.0 | $ | 368.8 | $ | 303.2 | $ | 272.2 | $ | 273.2 | $ | 342.8 | $ | 309.3 | ||||||||||||||||
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| Net income attributable to common shareholders | 21.0 | 16.7 | 63.6 | 19.9 | 18.6 | 15.5 | 65.2 | 17.7 | ||||||||||||||||||||||||
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Quarterly total operating revenues and net income attributable to common shareholders are affected by seasonality, with Q1 and Q4 the strongest periods, reflecting colder weather and fewer daylight hours at those times of year.
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