Nova Scotia Power 6-K Management’s Responsibility for Financial Reporting

Exhibit 99.2

MANAGEMENT’S DISCUSSION & ANALYSIS

As at February 9, 2011

Management’s Discussion and Analysis (“MD&A”) provides a review of the results of operations of Nova Scotia Power Inc. during the fourth quarter of 2010 relative to 2009, and the full year 2010 relative to 2009 and to 2008; and its financial position at December 31, 2010 relative to 2009. To enhance shareholders’ understanding, certain multi-year historical financial and statistical information is presented.

This discussion and analysis should be read in conjunction with the Nova Scotia Power Inc. annual audited financial statements and supporting notes. Nova Scotia Power Inc. follows Canadian Generally Accepted Accounting Principles (“CGAAP”) including the application of rate-regulated accounting. Nova Scotia Power Inc.’s accounting policies are subject to examination and approval by the Nova Scotia Utility and Review Board (“UARB”). The accounting policies of Nova Scotia Power Inc. may differ from CGAAP for non-regulated companies.

Throughout this discussion, “Nova Scotia Power”, “NSPI” and “Company” refer to Nova Scotia Power Inc.

All amounts are in Canadian dollars (“CAD”).

Additional information related to Nova Scotia Power Inc., 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 and forward-looking statements which reflect the current view with respect to the Company’s objectives, plans, financial and operating performance, business prospects and opportunities. Certain factors that may affect future operations and financial performance are discussed, including information in the Outlook section of the MD&A. Wherever used, the words “may”, “will”, “intend”, “estimate”, “plan”, “believe”, “anticipate”, “expect”, “project” and similar expressions are intended to identify such forward-looking statements 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.

Although NSPI believes such statements are based on reasonable assumptions, such statements are subject to certain risks, uncertainties and assumptions pertaining to, but not limited to, operating performance, regulatory requirements, weather, general economic conditions, commodity prices, interest rates and foreign exchange rates. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary significantly from those expected. NSPI disclaims any intention or obligation to update or revise any forward-looking information or forward-looking statements, whether as a result of new information, future events or otherwise, except as required under applicable securities laws.

Structure of MD&A

This MD&A begins with an Introduction and Strategic Overview, followed by a financial review of the statements of earnings, balance sheets and cash flow highlights; then continues with a discussion on Outlook, Liquidity and Capital Resources, Pension Funding, Off-Balance Sheet Arrangements, Transactions with Related Parties, Risk Management and Financial Instruments, Disclosure and Internal Controls, Significant Accounting Policies and Critical Accounting Estimates, Changes in Accounting Policies and Summary of Quarterly Results.

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INTRODUCTION AND STRATEGIC OVERVIEW

NSPI, created through the privatization in 1992 of the crown corporation Nova Scotia Power Corporation, is a fully-integrated regulated electric utility and the primary electricity supplier in Nova Scotia. NSPI has $4.0 billion of assets and provides electricity generation, transmission and distribution services to approximately 489,000 customers. The Company owns 2,368 megawatt (“MW”) of generating capacity, of which approximately 53% is coal-fired; natural gas and/or oil comprise another 27% of capacity; and hydro and wind production total 20%. In addition, NSPI has contracts to purchase renewable energy from independent power producers (“IPP”). These IPPs own 186 MW, increasing to 226 MW in 2011, of wind and biomass fueled generation capacity. A further 85 MW of renewable capacity is being built directly or purchased under long-term contracts by NSPI and is expected to be in service by the end of 2012. NSPI also owns approximately 5,000 kilometers of transmission facilities and 29,000 kilometers of distribution facilities. The Company has a workforce of approximately 1,900 people.

NSPI is a public utility as defined in the Public Utilities Act (Nova Scotia) (“Act”) and is subject to regulation under the Act by the UARB. The Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. The Company is not subject to a general annual rate review process, but rather participates in hearings from time to time at the Company’s or the UARB’s request.

NSPI 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. NSPI’s regulated return on equity (“ROE”) range for 2010 was 9.1% to 9.6%, on an actual regulated common equity component of up to 40% of average regulated capitalization.

In 2009, the UARB approved a fuel adjustment mechanism (“FAM”) allowing NSPI to recover fluctuating fuel expenses from customers through annual fuel rate adjustments. In 2010, revenue associated with fuel comprised approximately 45% of total revenue. As the FAM mitigates the Company’s net earnings’ exposure to fuel volatility, it facilitates longer planning cycles. This enables the Company to increase its focus on the impact that non-fuel components of the business have on net earnings, while retaining focus on managing fuel costs for customers. In 2010, tax benefits associated with renewable investments reduced costs and, thus NSPI did not seek a general rate adjustment with the UARB.

Although the market in Nova Scotia is otherwise mature, the transformation of energy supply to lower emission sources has created the opportunity for organic growth within NSPI, and the Company expects earnings growth of 3% to 5% annually over the next five years as new investments are made in renewable generation and transmission.

Non-GAAP Measure

“Electric margin”, defined as “Electric revenue” less “Fuel for generation and purchased power”, net of the “Fuel adjustment” and fuel related foreign exchange losses or gains, is a non-GAAP financial measure used by NSPI. This measure is disclosed as management believes it provides further information regarding the impact of the FAM on NSPI’s operations. Electric margin is discussed further in the Review of 2010 section.

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Developments

Deferral of Certain Tax Benefits Related to Renewable Energy Projects for Fiscal 2010

On December 23, 2010, the UARB granted NSPI approval to defer certain tax benefits related to renewable energy projects arising in 2010. Accordingly, effective December 31, 2010, NSPI recognized a deferral of $14.5 million through an increase in regulatory amortization. The UARB will convene a proceeding in 2011 to discuss how this deferral will be applied.

UARB Decision on Fuel Adjustment Mechanism

On December 8, 2010, the UARB approved NSPI’s setting of the 2011 base cost of fuel and its recovery of all unrecovered fuel related costs as submitted in the Company’s November 2010 filing. The recovery of these costs will begin January 1, 2011. The UARB approved the recovery of these costs by NSPI over three years, with 50% of the rate increase to be recovered in 2011, 30% in 2012 and 20% in 2013. The decision results in an average rate increase of approximately 4.5% for customers in 2011. Pursuant to the FAM Plan of Administration, NSPI is entitled to earn a return on the unrecovered balance of fuel related costs.

Renewable Energy Projects

Port Hawkesbury Biomass Project

On October 14, 2010, the UARB approved NSPI’s $208.6 million capital work order request for the Port Hawkesbury biomass project. NSPI will develop this 60-MW co-generating facility at the NewPage Port Hawkesbury Corporation (“NewPage”) site. NSPI will own the facility while NewPage will construct and operate the plant as well as supply the fuel. This project is expected to be commissioned in 2013 and supply approximately 3% of the province of Nova Scotia’s total electricity needs.

Point Tupper Wind Development Project

On June 14, 2010, the UARB approved NSPI’s $27.8 million capital work order for the Point Tupper Wind Development Project. The Project went into service in August 2010.

Digby Wind Project

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. NSPI has requested UARB approval of this project through the submission of a capital work order. The Project was completed and went into service in December 2010 at a total cost of approximately $80.0 million. The UARB hearing took place in January 2011, and a decision is pending.

Nova Scotia Provincial Environmental Regulations

Renewable Electricity Plan

On October 15, 2010, the Nova Scotia Government enacted regulations under the Electricity Act related to the Province’s Renewable Electricity Plan. These regulations establish the requirement that 25% of electricity be supplied from renewable sources by 2015. These regulations build on the previously legislated requirements for 2011 and 2013 by adding an additional 5% for 2015. Recent amendments to the Electricity Act, and the new regulations, provide for the appointment, by spring 2011, of a new, independent renewable electricity administrator to conduct the procurement of at least 300 gigawatt hours (“GWh”) of energy from IPPs to meet the 2015 standard. NSPI is also provided the opportunity to develop 300 GWh of renewable energy.

Mercury Emissions

On July 22, 2010, the Province of Nova Scotia announced, for the years 2010 through 2013, allowable mercury emissions would be increased from the previous cap of 65 kg per year. NSPI was

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requested to develop a plan of staged mercury emission reductions, for its generation facilities, for the period of 2010 to 2020 and meet an annual cap of 35 kg beginning in 2020.

Canadian Federal Environmental Regulations

Greenhouse Gas

On June 23, 2010, the Federal Department of Environment announced its intentions for a new national greenhouse gas (“GHG”) framework for the electricity sector. This federal framework, if developed further into regulations, would require thermal coal units to meet GHG emission levels equal to, or better than, a natural gas combined cycle generating unit at a future date. Nova Scotia’s existing GHG regulations require reductions in NSPI’s emissions similar to the intentions of the federal framework. NSPI is reviewing the implications of this federal framework and its alignment with NSPI’s current operating plans under existing Nova Scotia regulations.

US Securities and Exchange Commission Registration

On July 15, 2010, NSPI registered debt securities with the US Securities and Exchange Commission (“SEC”) under the US Securities Act of 1933.

Appointments

On May 3, 2010, Elaine Sibson and Lee Bragg joined the NSPI Board of Directors.

REVIEW OF 2010

Net Earnings millions of dollars	Three months  ended December 31						Year ended December 31
	2010			2009			2010			2009			2008
Electric revenue	$	296.4		$	302.9		$	1,167.3		$	1,188.1		$	1,111.1
Fuel for generation and purchased power		146.2			138.5			586.7			500.7			471.4
Fuel adjustment		(24.0	)		(10.6	)		(99.0	)		8.5			—
Operating, maintenance and general		65.0			58.4			237.5			215.1			203.7
Provincial grants and taxes		10.1			10.0			40.1			40.5			41.2
Depreciation and amortization		39.9			36.8			150.8			143.9			133.6
Regulatory amortization		23.7			14.7			36.9			27.2			17.7
Other revenue		(4.7	)		(4.0	)		(15.4	)		(14.0	)		(15.5	)
Earnings before financing charges and income taxes		40.2			59.1			229.7			266.2			259.0
Financing charges		32.8			33.3			125.8			114.7			106.8
Earnings before income taxes		7.4			25.8			103.9			151.5			152.2
Income taxes		(13.3	)		8.4			(17.4	)		42.2			46.6
Net earnings	$	20.7		$	17.4		$	121.3		$	109.3		$	105.6

NSPI’s net earnings increased $3.3 million to $20.7 million in Q4 2010, compared to $17.4 million in Q4 2009. Annual net earnings increased $12.0 million to $121.3 million in 2010 compared to $109.3 million in 2009, and $105.6 million in 2008.

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Highlights of the earnings changes are summarized in the following table:

millions of dollars	Three months  ended December 31			Year ended December 31
Net earnings – 2008				$	105.6
Increased electric revenue due to an electricity price increase on January 1, 2009, partially offset by decreased industrial sales in the year					77.0
Increased fuel for generation and purchased power					(29.3	)
Fuel adjustment related to implementation of the FAM					(8.5	)
Increased operating, maintenance and general (“OM&G”) expenses primarily due to increased storm and reliability costs as well as customer service initiatives partially offset by decreased pension expense					(11.4	)
Increased depreciation and amortization primarily due to increased depreciation rates in 2009 as part of the phase-in of year-three rates as approved by the UARB					(10.3	)
Increased financing charges					(7.9	)
Increased regulatory amortization due to additional amortization of pre-2003 income tax regulatory asset					(9.5	)
Decreased income taxes due to decreased taxable income and lower statutory rate, partially offset by recovery of income taxes in 2008 relating to a prior year					4.4
Other					(0.8	)
Net earnings – 2009	$	17.4		$	109.3
Decreased electric margin (see Electric Margin for explanation)		(2.0	)		(11.6	)
Increased OM&G expenses primarily due to increased pension and storm costs. Year-to-date also reflects increased spending on customer service initiatives		(6.6	)		(22.4	)
Increased depreciation and amortization due primarily to increased property, plant and equipment		(3.1	)		(6.9	)
Increased regulatory amortization due to a deferral of certain tax benefits arising in 2010, partially offset by decreased amortization of the pre-2003 income tax regulatory asset		(9.0	)		(9.7	)
Decreased income taxes due to decreased earnings before income taxes, deductions related to renewable investments and a change in the expected benefit from other accelerated tax deductions		21.7			59.6
Other		2.3			3.0
Net earnings – 2010	$	20.7		$	121.3

Financing charges decreased $0.5 million in the quarter and increased $11.1 million for the year ended December 31, 2010. Foreign exchange gain and losses recovered through the FAM as fuel costs are included in the change in electric margin in the table above. See Electric Margin section for additional explanation.

Net Earnings History

millions of dollars	2010		2009		2008		2007		2006		2005
Net earnings	$	121.3	$	109.3	$	105.6	$	100.2	$	104.3	$	91.2

Balance Sheets Highlights

	As at December 31
millions of dollars	2010		2009		2008
Total assets	$	3,991.3	$	3,465.3	$	3,490.7
Total liabilities		2,779.8		2,379.9		2,349.3

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Significant changes in the balance sheets between December 31, 2010 and December 31, 2009 include:

millions of dollars	Increase (Decrease)			Explanation
Assets
Accounts receivable	$	(79.3	)	Settlement of a receivable from a natural gas supplier, partially offset by higher posted margin to counterparties.
Income tax receivable		40.6		Recovery of income taxes due to deductions related to renewable investments and a change in the expected benefit from other accelerated tax deductions.
Inventory		(11.4	)	Decreased fuel inventory levels and commodity prices, partially offset by higher materials inventory.
Future income tax assets		(30.3	)	Decreased future income tax (“FIT”) asset related to derivatives recognized in “Accumulated other comprehensive income (loss)” (“AOCI”) and reclassification of non-capital loss carry forward FIT assets to net FIT liabilities.
Other assets		173.7		Increased FIT regulatory asset, recognition of the FAM regulatory asset in 2010 and increased pension asset, partially offset by regulatory amortization and decreased regulatory assets related to financial instruments.
Property, plant and equipment		303.4		Capital spending.
Construction work in progress		126.4		Capital spending.
Liabilities and Shareholders’ Equity
Accounts payable and accrued charges and due to associated companies		11.8		Timing of payments.
Derivatives in a valid hedging relationship (including long-term portion)		(61.4	)	Favourable commodity price and USD hedge positions and natural gas derivatives reclassified to “Held-for-trading”. The effective portion of the change is recognized in AOCI.
Future income tax liabilities		111.1		Increased FIT liability on property, plant and equipment, including renewable investments and the FAM regulatory asset, partially offset by increased FIT asset on asset retirement obligations. The portion expected to be recovered from customers in future rates is recognized in “Other assets”.
Asset retirement obligations		37.2		Recognition of asset retirement obligations.
Short-term and long-term debt (including current portion)		286.2		Increased debt levels to fund significant capital programs.
Common shares		50.0		Issuance of common shares.
Accumulated other comprehensive income		54.8		Primarily represents the effective portion of favourable commodity price positions partially offset by unfavourable USD hedge positions.
Retained earnings		21.3		Net earnings in excess of dividends paid.

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Cash Flow Highlights

Significant changes in the cash flow statements between December 31, 2010 and December 31, 2009 include:

Three months ended December 31 millions of dollars	2010			2009			Explanation
Cash, beginning of period	$	0.3		$	0.3
Provided by (used in):
Operating activities		160.4			101.0		In 2010 and 2009, cash earnings and favourable non-cash working capital.
Investing activities		(180.5	)		(112.3	)	In 2010, capital spending including multi-year projects and renewable investments.
							In 2009, capital spending including multi-year projects.
Financing activities		20.1			11.3		In 2010 and 2009, increased short-term debt, partially offset by dividends on common shares.
Cash, end of period	$	0.3		$	0.3
Year ended December 31 millions of dollars	2010			2009			Explanation
Cash, beginning of year	$	0.3			—
Provided by (used in):
Operating activities		300.2		$	275.2		In 2010 and 2009, cash earnings and favourable non-cash working capital.
Investing activities		(533.3	)		(268.6	)	In 2010, capital spending including multi-year projects and renewable investments.
							In 2009, capital spending including multi-year projects.
Financing activities		233.1			(6.3	)	In 2010, increased debt levels and issuance of common shares, partially offset by dividends on common shares.
							In 2009, dividends on common shares and redemption of preferred shares, partially offset by increased debt levels.
Cash, end of year	$	0.3		$	0.3

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Electric Revenue

NSPI’s electricity rates are set based on a forecast of fuel and non-fuel costs plus a reasonable return to investors. Consequently, the Company’s electric revenue is comprised of revenue related to the recovery of fuel costs (“fuel electric revenue”) and revenue related to the recovery of non-fuel costs (“non-fuel electric revenue”).

With the introduction of the FAM on January 1, 2009, NSPI is able to seek full recovery of fuel costs through regularly scheduled rate adjustments, thus reducing the impact of volatile fuel markets on the Company’s earnings. As a result, fuel electric revenue does not have a material impact on net earnings.

NSPI’s customer classes contribute differently to the Company��s non-fuel electric revenue. Changes in volume of residential and commercial customers, largely due to weather, have the largest impact on non-fuel electric revenue. Changes in industrial load, which are generally due to economic conditions, do not have a significant impact on non-fuel electric revenue.

The fuel electric revenue is comprised of the recovery of fuel costs incurred in the current year and the over or under-recovery of fuel costs from the prior year. Since fuel costs are recovered through the FAM, the electric margin is solely influenced by revenues relating to non-fuel costs and the FAM incentive expense or recovery. Electric revenue is summarized in the following table:

millions of dollars	Three months  ended December 31					Year ended December 31
	2010			2009		2010			2009		2008
Fuel electric revenue current year	$	129.0		$	131.4	$	515.7		$	511.2		*
Fuel electric revenue prior year rebate		(5.7	)		—		(22.4	)		—		*
Non-fuel electric revenue		173.1			171.5		674.0			676.9		*
Total electric revenue	$	296.4		$	302.9	$	1,167.3		$	1,188.1	$	1,111.1

* Prior to the introduction of the FAM on January 1, 2009, electric revenue was not broken into the components above.

Electric revenue decreased $6.5 million to $296.4 million in Q4 2010 compared to $302.9 million in Q4 2009. For the year ended December 31, 2010, NSPI’s electric revenue decreased $20.8 million to $1,167.3 million compared to $1,188.1 million in 2009 and $1,111.1 million in 2008.

Highlights of the changes are summarized in the following table:

millions of dollars	Three months  ended December 31			Year ended December 31
Electric revenue – 2008				$	1,111.1
Increased electricity pricing effective January 1, 2009					102.1
Net change in residential and commercial sales volumes					4.2
Decreased industrial sales to several large industrial customers					(28.3	)
Decreased export sales					(1.0	)
Electric revenue – 2009	$	302.9		$	1,188.1
Decreased electricity pricing effective January 1, 2010 related to the FAM rebate (fuel-electric revenue) to customers of over-recovered fuel costs in 2009		(5.7	)		(22.4	)
Change in residential and commercial sales volumes due primarily to warmer weather		(1.7	)		(10.7	)
Increased industrial sales volume from several large industrial customers		0.6			13.2
Other		0.3			(0.9	)
Electric revenue – 2010	$	296.4		$	1,167.3

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Electric Sales Volumes

Q4 Electric Sales Volumes GWh							Year-to-Date (“YTD”) Electric Sales Volumes GWh
	2010		2009		2008			2010		2009		2008
Residential		1,080		1,091		1,093	Residential		4,147		4,228		4,179
Commercial		765		772		770	Commercial		3,088		3,107		3,115
Industrial		957		998		987	Industrial		3,908		3,642		4,144
Other		84		81		84	Other		312		328		334
Total		2,886		2,942		2,934	Total		11,455		11,305		11,772

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 consists of export sales, sales to municipal electric utilities and revenues from street lighting.

Electric Margin

As noted above, NSPI’s fuel costs are recoverable from customers through the FAM. Differences between actual fuel costs and amounts recovered from customers through electricity rates in a period are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent period. The only effect on net earnings in relation to the recovery of fuel costs is the incentive component of the FAM with NSPI retaining or absorbing 10% of the over or under-recovered amount less the difference between the incentive threshold and the base amount to a maximum of $5 million.

NSPI’s electric margin is influenced by non-fuel revenues and the FAM incentive. 

NSPI’s electric margin is summarized in the following table:

millions of dollars	Three months  ended December 31						Year ended December 31
	2010			2009			2010			2009		2008
Electric revenue	$	296.4		$	302.9		$	1,167.3		$	1,188.1		*
Fuel for generation and purchased power		146.2			138.5			586.7			500.7		*
Fuel adjustment		(24.0	)		(10.6	)		(99.0	)		8.5		*
Fuel related foreign exchange (losses) gains		(3.4	)		(2.2	)		(9.3	)		3.0		*
Electric margin	$	170.8		$	172.8		$	670.3		$	681.9		*

* Prior to the introduction of the FAM on January 1, 2009, electric margin was not broken into the components above.

NSPI’s electric margin decreased $2.0 million to $170.8 million in Q4 2010 compared to $172.8 million in Q4 2009 primarily due to the recognition of a FAM incentive expense compared to a recovery in 2009. For the year ended December 31, 2010, NSPI’s electric margin decreased $11.6 million to $670.3 million in 2010 compared to $681.9 million in 2009 due to lower residential load related to warmer weather and the recognition of a FAM incentive expense compared to a recovery in 2009.

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Q4 Electric Margin / MWh
	2010		2009		2008
Dollars per MWh	$	59	$	59		*

YTD Electric Margin / MWh
	2010		2009		2008
Dollars per MWh	$	59	$	60		*

* Prior to the introduction of the FAM on January 1, 2009, electric margin was not broken into the components above.

The change in average electric margin per MWh in 2010 compared to 2009 reflects a change in sales volume mix and recognition of a FAM incentive expense compared to a recovery in 2009.

Fuel for Generation and Purchased Power

Capacity

To ensure reliability of service, NSPI maintains a generating capacity greater than firm peak demand. The total Company-owned generation capacity is 2,368 MW, which is supplemented by 186 MW contracted with IPPs. NSPI meets the planning criteria for reserve capacity established by the Maritime Control Area and the Northeast Power Coordinating Council.

NSPI facilities continue to rank among the best in Canada on capacity related performance indicators. The high availability and capability of low cost thermal generating stations provide lower cost energy to customers. In 2010, thermal plant availability was 87% compared to 82% in 2009. The increase in availability from 2009 reflects decreased maintenance outages. Sustained high availability and low forced outage rates on low cost facilities are good indicators of sound maintenance and investment practices.

Fuel Expense

Q4 Production Volumes GWh
	2010		2009		2008
Coal & petcoke		2,049		2,069		2,177
Natural gas		438		534		249
Oil & diesel		16		16		218
Renewable		340		281		257
Purchased power*		315		335		296
Total		3,158		3,235		3,197
*  Purchased power includes 132 GWh of renewables in 2010 (2009 – 51 GWh; 2008 – 44 GWh).

YTD Production Volumes GWh
	2010		2009		2008
Coal & petcoke		7,839		8,177		9,009
Natural gas		2,275		1,612		1,258
Oil & diesel		36		307		339
Renewable		1,017		1,065		1,068
Purchased power*		997		931		889
Total		12,164		12,092		12,563
*  Purchased power includes 355 GWh of renewables in 2010 (2009 – 149 GWh; 2008 – 148 GWh).

Q4 Average Unit Fuel Costs
	2010		2009		2008
Dollars per MWh	$	46	$	43	$	44

YTD Average Unit Fuel Costs
	2010		2009		2008
Dollars per MWh	$	48	$	41	$	38

Solid fuel is NSPI’s dominant fuel source, supplying approximately 64% (2009 – 68%) of the Company’s annual energy. Historically, solid fuels have had the lowest per unit fuel cost, after hydro and NSPI-owned wind production, which have no fuel cost component. Natural gas, oil, and purchased power are next, depending on the relative pricing of each. Economic dispatch of the generating fleet brings the lowest cost options on stream first, with the result that the incremental cost of production increases as sales volume increases.

The average unit fuel costs increased in 2010 compared to 2009 mainly as a result of higher priced import coal and solid fuel commodity mix related to emission compliance.

The average unit fuel costs increased in 2009 compared to 2008 mainly as a result of higher priced commodity contracts for coal and natural gas.

A substantial amount of NSPI’s fuel supply comes from international suppliers, and is subject to commodity price and foreign exchange risk. The Company manages exposure to commodity price risk

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utilizing a portfolio strategy, combining physical fixed-price fuel contracts and financial instruments providing fixed or maximum prices. Foreign exchange risk is managed through forward and option contracts. Further details on the Company’s fuel cost risk management strategies are included in the Business Risks section. Fuel contracts may be exposed to broader global conditions which may include impacts on delivery reliability and price, despite contracted terms.

For the three months ended December 31, 2010, fuel for generation and purchased power increased $7.7 million to $146.2 million, compared to $138.5 million in Q4 2009. For the year ended December 31, 2010, fuel for generation and purchased power increased $86.0 million to $586.7 million compared to $500.7 million in 2009 and $471.4 million in 2008.

Highlights of the changes are summarized in the following table:

millions of dollars	Three months  ended December 31			Year ended December 31
Fuel for generation and purchased power – 2008				$	471.4
Commodity price increases					36.2
Decreased proceeds from the resale of natural gas					10.3
Valuation of contract receivable (see discussion below)					4.5
Decreased sales volume					(22.2	)
Mark-to-market on natural gas hedges not required in 2009 primarily due to decreased production volumes					(0.7	)
Changes in generation mix and plant performance					(10.2	)
Decreased hydro production					1.8
Primarily solid fuel handling costs previously included in OM&G expenses					10.7
Other					(1.1	)
Fuel for generation and purchased power – 2009	$	138.5		$	500.7
Commodity price and volume increases		0.4			34.5
Changes in generation mix and plant performance		12.6			24.3
Solid fuel commodity mix and additives related to emission compliance		0.8			25.3
Increased proceeds from the resale of natural gas		(0.8	)		(9.8	)
Valuation of contract receivable (see discussion below)		6.6			8.7
(Decreased) increased sales volume		(5.1	)		2.7
Increased hydro production		(6.2	)		(1.1	)
Mark-to-market on natural gas hedges recognized in 2009 as they were no longer required due to decreased 2009 production volumes		1.5			2.2
Other		(2.1	)		(0.8	)
Fuel for generation and purchased power – 2010	$	146.2		$	586.7

The valuation of the contract receivable from a natural gas supplier required NSPI to utilize a combination of historical and future natural gas prices. NSPI uses market-based forward indices when determining future prices. Future prices can change from period to period which will cause a corresponding change in the value of the contract receivable. The natural gas supply contract settled in November 2010.

Fuel Adjustment

The fuel adjustment related to the FAM includes the effect of fuel costs in both the current period and the preceding year. The difference between actual fuel costs and amounts recovered from customers in the current period is included in the fuel adjustment. This amount, less the incentive component, is deferred to a FAM regulatory asset in “Other assets” or a FAM regulatory liability in “Other Liabilities”. The FAM regulatory asset or liability includes amounts recognized as a fuel adjustment and associated interest included in “Financing charges”. Also included in the 2010 fuel adjustment is the rebate to customers of over recovered fuel costs from 2009.

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Details of the fuel adjustment deferral related to the FAM are summarized in the following table:

	Year ended December 31
millions of dollars	2010			2009			2008
FAM payable – Balance at January 1	$	(9.9	)		*			*
Under (over) recovery of current period fuel costs		80.3		$	(9.9	)		*
Rebate to customers from prior year		22.5			—			*
FAM receivable (payable) – Balance at December 31	$	92.9		$	(9.9	)		*

* The fuel adjustment mechanism came into effect on January 1, 2009.

In December 2010, as part of the FAM regulatory process, the UARB directed NSPI to recover the rate increase approved by the UARB for the reset of 2011 fuel costs and the projected under recovery from prior years from customers over three years, with 50% of the rate increase to be recovered in 2011, 30% in 2012 and 20% in 2013.

NSPI has recognized a future income tax expense related to the fuel adjustment based on its applicable statutory income tax rate. The FAM regulatory asset or liability includes amounts recognized as a fuel adjustment and associated interest included in “Financing charges”. As at December 31, 2010, NSPI’s future income tax liability related to the FAM was $29.2 million (2009 – asset of $3.4 million).

Operating, Maintenance and General

OM&G expenses increased $6.6 million to $65.0 million in Q4 2010 compared to $58.4 million in Q4 2009 and increased $22.4 million to $237.5 million for the year ended December 31, 2010 compared to $215.1 million in 2009 primarily due to increased pension and storm costs as well as customer service initiatives.

OM&G expenses increased $11.4 million to $215.1 million for the year ended December 31, 2009 compared to $203.7 million in 2008 primarily due to increased storm costs, system reliability spending and program costs associated with customer and new business initiatives, partially offset by lower pension expense.

Provincial Grants and Taxes

NSPI pays annual grants to the Province of Nova Scotia in lieu of municipal taxation other than deed transfer tax.

Depreciation and Amortization

Depreciation and amortization expense increased $3.1 million to $39.9 in Q4 2010 compared to $36.8 million in Q4 2009 and increased $6.9 million to $150.8 for the year ended December 31, 2010 compared to $143.9 million in 2009 primarily due to increased property, plant and equipment.

Depreciation and amortization expense increased $10.3 million to $143.9 for the year ended December 31, 2009 compared to $133.6 million in 2008 primarily due to the inclusion of year-three depreciation rates commencing on January 1, 2009 as approved by the UARB in its November 5, 2008 decision.

Regulatory Amortization

Regulatory amortization increased $9.0 million to $23.7 million in Q4 2010 compared to $14.7 million in Q4 2009 and increased $9.7 million to $36.9 million for the year ended December 31, 2010 compared to $27.2 million in 2009. This increase is due primarily to a $14.5 million deferral of certain tax benefits arising in 2010 related to renewable energy projects, as approved by the UARB, partially offset by a reduction in amortization of the pre-2003 income tax regulatory asset resulting from the UARB’s 2009 ROE decision of $4.8 million in 2010 (2009 – $10.0 million). The 2009 ROE decision allows NSPI to recognize additional amortization amounts in current periods and to reduce amortization in future periods to provide flexibility relating to customer rate requirements.

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Regulatory amortization increased $9.5 million to $27.2 million for the year ended December 31, 2009 compared to $17.7 million in 2008 due primarily to additional amortization of the pre-2003 income tax regulatory asset resulting from the UARB’s ROE decision noted above.

Other Revenue

Other revenue, which consists of miscellaneous revenues and commercial settlements, has remained relatively unchanged for the quarter and year ended December 31, 2010 compared to 2009 and 2008.

Financing Charges

Financing charges decreased $0.5 million to $32.8 million in Q4 2010 compared to $33.3 million in Q4 2009 and increased $11.1 million to $125.8 million for the year ended December 31, 2010 compared to $114.7 million in 2009 primarily due to higher foreign exchange costs, recovered through the FAM, and increased borrowing costs, partially offset by increased allowance for funds used during construction (“AFUDC”) related to increased capital spending.

Financing charges increased $7.9 million to $114.7 million for the year ended December 31, 2009 compared to $106.8 million in 2008 primarily due to lower foreign exchange gains in 2009 compared to 2008. In 2009, NSPI recorded income tax refund interest of $3.0 million which was received as a result of the Company amending its 1999 to 2003 corporate income tax returns. This refund interest was recorded as a reduction of “Financing charges”.

Income Taxes

NSPI uses the future income tax method of accounting for income taxes. In accordance with NSPI’s rate-regulated accounting policy as approved by the UARB, NSPI defers any future income taxes to a regulatory asset or liability where the future income taxes are expected to be included in future rates.

In 2010, NSPI was subject to provincial capital tax (0.125%), corporate income tax (34%) and Part VI.1 tax relating to preferred dividends (40%). NSPI also receives a reduction in its corporate income tax otherwise payable related to the Part VI.1 tax deduction (41% of preferred dividends).

Income taxes decreased $21.7 million to a $13.3 million income tax recovery in Q4 2010 compared to $8.4 million income tax expense in Q4 2009 and decreased $59.6 million to a $17.4 million recovery for the year ended December 31, 2010 compared to $42.2 million income tax expense in 2009 primarily due to decreased earnings before income taxes, deductions related to renewable investments and a change in the expected benefit from other accelerated tax deductions.

Income taxes decreased $4.4 million to $42.2 million for the year ended December 31, 2009 compared to $46.6 million in 2008 primarily due to decreased taxable income and a lower statutory rate in 2009 compared to 2008, partially offset by a recovery of income taxes in 2008 relating to a prior year.

In 2010, NSPI revised its estimate of the expected benefit from accelerated tax deductions. The impact for the three months and twelve months ended December 31, 2010 was to reduce income tax expense by approximately $8.0 million and $14.0 million respectively. In accordance with rate-regulated accounting, the future income tax implications of this change in estimate have been deferred to a regulatory asset in “Other assets”. This change in accounting estimate has been accounted for on a prospective basis.

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OUTLOOK

Business Environment

Economic Environment

NSPI expects investment opportunities related to the transformation of the energy industry to lower emissions and has embarked on a significant capital plan to increase the Company’s generation from renewable sources and to improve the transmission connections within its service territory as NSPI transitions to lower carbon intensive energy sources.

Environmental Regulations

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 a total capital program budget of approximately $350 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 mainly through its operations involving the generation, transmission and distribution of electricity. NSPI’s customer base is diversified by both sales volume and revenues among residential, commercial, industrial and other customers. Circumstances that could affect the Company’s ability to generate cash include general economic downturns, 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 $600 million committed syndicated revolving bank line of credit, which includes an additional $100 million of credit extended in June 2010 when NSPI’s revolving bank line was renewed for a three-year term maturing in June 2013. NSPI has an active commercial paper program for up to $400 million, of which outstanding amounts are 100% backed by the Company’s bank line and this results in an equal amount of credit being considered drawn and unavailable.

As at December 31, 2010, the outstanding short-term debt is as follows:

millions of dollars	Maturity		Credit Line Committed		Utilized		Undrawn and Available
Operating credit facility		June 2013 – Revolver	$	600	$	289	$	311

NSPI has debt covenants associated with its credit facilities. These covenants are tested regularly, and the Company is in compliance with the covenant requirements.

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Debt Management

In May 2010, NSPI redeemed $100 million medium-term notes using short-term credit facilities.

In May 2010, NSPI filed a $500 million debt shelf prospectus providing the Company with access to long-term debt.

In June 2010, subsequent to filing its shelf prospectus, NSPI completed a $300 million medium-term note issue, proceeds of which were used to pay down outstanding short-term debt. These notes bear interest at the rate of 5.61% and yield 5.616% per annum until June 15, 2040.

In June 2010, NSPI issued a total of five million common shares to Emera Inc. and an Emera affiliate under common control for total proceeds of $50 million.

The weighted average coupon rate on NSPI’s outstanding medium-term and debenture notes at December 31, 2010 was 6.74% (2009 – 6.80%). Approximately 27% of the debt matures over the next ten years, 70% matures between 2021 and 2040 and $50 million, or 3%, matures in 2097. The quoted market weighted average interest rate for the same or similar issues of the same remaining maturities was 4.50% as at December 31, 2010 (2009 – 4.87%).

NSPI’s credit ratings issued by Dominion Bond Rating Service (“DBRS”) and Standard & Poor’s (“S&P”) are as follows:

	DBRS	S&P
Corporate	N/A	BBB+
Senior unsecured debt	A (low)	BBB+
Preferred stock	Pfd-2 (low)	P-2 (low)
Commercial paper	R-1 (low)	A-1 (low)

Contractual Obligations

The contractual obligations over the next five years and thereafter include:

millions of dollars	Total		Payments Due by Period
			3 year renewable (1)		2011		2012		2013		2014		2015		After 2015
Long-term debt	$	1,946.8	$	241.7	$	0.1		—	$	300.0		—	$	70.0	$	1,335.0
Preferred shares		135.0		—		—		—		—		—		135.0		—
Operating leases		3.0		—		1.8	$	0.3		0.3	$	0.3		0.3		—
Purchase obligations		3,769.3		—		304.2		274.1		217.6		152.9		121.7		2,698.8
Capital obligations		111.5		—		76.1		33.9		1.5		—		—		—
Asset retirement obligations		440.3		—		1.6		1.9		1.2		1.2		1.3		433.1
Total contractual obligations	$	6,405.9	$	241.7	$	383.8	$	310.2	$	520.6	$	154.4	$	328.3	$	4,466.9

(1) Short-term discount notes are backed by an operating credit facility which matures in 2013.

Operating lease obligations:NSPI’s operating lease obligations consist of operating lease agreements for office space and rail cars.

Purchase obligations:NSPI has purchasing commitments for electricity from independent power producers, transportation of coal, natural gas, fuel and transportation capacity on the Maritimes & Northeast Pipeline.

Capital obligations: NSPI has commitments to third parties for construction on capital projects and other goods and services.

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Asset retirement obligations:The Company has asset retirement obligations for its generation, transmission and distribution assets.

The Company expects to be able to meet its obligations with cash from operations.

Capital Resources

Capital expenditures for 2010, including AFUDC, were approximately $550 million. Significant capital expenditures included the Nuttby Mountain Wind project, the Digby Wind project, the Point Tupper Wind Development project, the Tuft’s Cove 6 Waste Heat Recovery project, the Port Hawkesbury Biomass project, and the new corporate head office project.

PENSION FUNDING

For funding purposes, NSPI determines required contributions to its defined benefit pension plans based on smoothed asset values. This reduces volatility in the cash funding requirement as the impact of investment gains and losses are recognized over a three year period. The cash required in 2011 for defined benefit pension plans will be approximately $38.8 million (2010 – $34.6 million actual). All pension plan contributions are tax deductible and will be funded with cash from operations.

NSPI’s defined benefit pension plan is managed with a diversified portfolio of asset classes, investment managers and geographic investments. NSPI reviews the investment managers on a regular basis, and the plan’s asset mix from time to time.

NSPI’s projected contribution to defined contribution pension plans is $1.4 million for 2011 (2010 – $1.3 million actual).

OFF-BALANCE SHEET ARRANGEMENTS

Upon privatization of the former provincially owned Nova Scotia Power Corporation (“NSPC”) in 1992, NSPI became responsible for managing a portfolio of defeasance securities, which at December 31, 2010 totaled $1.0 billion. The securities are held in trust for Nova Scotia Power Finance Corporation (“NSPFC”), an affiliate of the Province of Nova Scotia. NSPI is responsible for ensuring the defeasance securities provide the principal and interest streams to match the related defeased NSPC debt. Approximately 73% of the defeasance portfolio consists of investments in the related debt, eliminating all risk associated with this portion of the portfolio; the remaining defeasance portfolio has a market value higher than the related debt, reducing the future risk of this portion of the portfolio.

TRANSACTIONS WITH RELATED PARTIES

The Company enters into various transactions with its affiliates in the normal course of operations. All transactions are recorded, subject to terms in the Code of Conduct, at the exchange value, which is generally based on commercial rates or as agreed to by the parties. The Code of Conduct governs transactions between NSPI and its affiliates and is approved by the UARB.

Due to associated companies represents the total carrying amounts of trade payables, which are owed from NSPI to NSPI’s parent company, Emera Inc., and companies wholly-owned by Emera Inc. The terms of repayment are the same as those for non-affiliate trade payables.

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NSPI had sales and purchases from companies under common control of Emera Inc. as follows:

For the millions of dollars		Three months  ended December 31				Year ended December 31
Affiliate	Purpose of transaction	2010		2009		2010			2009
Emera Energy Services	Net sales (purchases) of gas, electricity	$	0.9	$	1.4	$	(6.7	)	$	25.0
Other	Other services provided		2.0		2.0		7.4			6.9
Other	Various services purchased		11.7		4.7		48.3			15.7

In the ordinary course of business, the Company purchased natural gas transportation capacity totaling $4.0 million (2009 – $4.4 million) during the three months ended December 31, 2010, and $18.0 million (2009 – $18.2 million) during the year ended December 31, 2010 from the Maritimes & Northeast Pipeline, an investment under significant influence of Emera Inc. The amount is recognized in “Fuel for generation and purchased power” and is measured at the exchange amount. As at December 31, 2010, the amount payable to the related party was $1.0 million (2009 – $1.5 million), and is under normal interest and credit terms.

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. At December 31, 2010, there was no amount due.

During the year ended December 31, 2010, the Company issued a total of 5.0 million (2009 – 0.4 million) common shares to Emera Inc. and an affiliate under common control of Emera Inc. for total consideration of $50.0 million (2009 – $4.1 million).

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

Financial Risks and Financial Instruments

NSPI manages its exposure to foreign exchange, interest rate, and commodity risks in accordance with established risk management policies and procedures. The Company uses financial instruments consisting mainly of foreign exchange forward contracts, and coal, oil and gas options and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas, and financial contracts held-for-trading (“HFT”). Collectively these contracts are referred to as derivatives.

The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that qualify and are designated as contracts held for normal purchase or sale.

Derivatives that meet stringent documentation requirements, and can be proven to be effective both at the inception and over the term of the derivative, qualify for hedge accounting. Specifically, for cash flow hedges, the change in the fair value of the effective portion of hedging derivatives is deferred to “Other comprehensive income (loss)” and recognized in earnings in the same period the related hedged item is realized. Any ineffective portion of the change in the fair value of derivatives is recognized in net earnings in the reporting period.

Where the documentation or effectiveness requirements are not met, the derivative instruments are recognized at fair value with any changes in fair value recognized in net earnings in the reporting period, unless deferred as a result of regulatory accounting.

For fair value hedges, the change in fair value of the hedging derivatives and the hedged item are recorded in net earnings. Therefore, the change in fair value of the ineffective portion of hedging derivatives is recognized in net earnings in the reporting period.

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The Company’s HFT derivatives are recorded on the balance sheet at fair value, with changes recorded in net earnings in the reporting period, unless deferred as a result of regulatory accounting. The Company has not designated any derivatives to be included in the HFT category.

The Company has contracts for the purchase and sale of natural gas at its Tufts Cove generating station (“TUC”) that are considered HFT derivatives and accordingly are recognized on the balance sheet at fair value. This reflects NSPI’s history of buying and reselling any natural gas not used in the production of electricity at TUC. Changes in fair value of HFT derivatives are normally recognized in net earnings. In accordance with NSPI’s accounting policy for financial instruments and hedges relating to TUC fuel, NSPI has deferred any changes in fair value to a regulatory asset or liability. In 2009, the UARB approved an amendment to NSPI’s accounting practice to include all TUC financial commodity hedges which are no longer required. This change in practice has impacted the timing of recognition between “Fuel for generation and purchased power” and “Fuel adjustment” as a result of the FAM implemented in 2009. The change in accounting practice was applied prospectively, beginning in 2009, as required by the UARB.

Hedging Items Recognized on the Balance Sheet

The Company has the following categories on the balance sheet related to derivatives in valid hedging relationships:

millions of dollars	December 31 2010		December 31 2009
Inventory	$	4.7	$	22.2
Derivatives in a valid hedging relationship		34.0		(23.8	)
Long-term debt		—		0.1
	$	38.7	$	(1.5	)

Hedging Impact Recognized in Earnings

The Company recognized in net earnings the following gains (losses) related to the effective portion of hedging relationships under the following categories:

millions of dollars	Three months ended December 31						Year ended December 31
	2010			2009			2010			2009
Fuel and purchased power increase	$	(9.7	)	$	(27.1	)	$	(64.7	)	$	(38.4	)
Financing charges decrease		1.2			1.0			1.8			6.9
Effectiveness losses	$	(8.5	)	$	(26.1	)	$	(62.9	)	$	(31.5	)

The effectiveness gains (losses) reflected in the above table are offset in net earnings by the change in the fair value of the hedged item realized in the period.

The Company recognized in net earnings the following gains (losses) related to the ineffective portion of hedging relationships under the following categories:

millions of dollars	Three months ended December 31						Year ended December 31
	2010			2009			2010			2009
Fuel and purchased power decrease (increase)	$	0.1		$	(1.0	)	$	(0.8	)	$	(12.8	)
Financing charges (increase) decrease		(0.1	)		0.3			(0.3	)		(0.5	)
Ineffectiveness losses		—		$	(0.7	)	$	(1.1	)	$	(13.3	)

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HFT Items Recognized on the Balance Sheet

The Company has recognized on the balance sheet a net HFT derivatives liability of $8.1 million as at December 31, 2010 (2009 – $1.6 million asset).

HFT Derivatives Recognized in Earnings

The Company has recognized the following realized and unrealized (losses) gains with respect to HFT derivatives in earnings:

millions of dollars	Three months ended December 31						Year ended December 31
	2010			2009			2010			2009
Fuel and purchased power	$	(1.3	)	$	1.4		$	(1.3	)	$	13.0
Financing charges		(0.1	)		(0.1	)		—			—
Held-for-trading derivatives (losses) gains	$	(1.4	)	$	1.3		$	(1.3	)	$	13.0

As discussed in note 21 of NSPI’s financial statements at the reporting date, various valuation techniques are used to determine the fair value of derivative instruments. These include may include quoted market prices or, internal models using observable or non-observable market information.

Business Risks

Measurement of Risk

Significant risk management activities for NSPI are overseen by the Enterprise Risk Management Committee to ensure risks are appropriately assessed, monitored and controlled within predetermined risk tolerances established through approved policies.

The Company’s risk management activities are focused on those areas that most significantly impact profitability, quality of earnings and cash flow. These risks include, but are not limited to, exposure to commodity prices, foreign exchange, interest rates, credit risk, and regulatory risk.

The UARB approved the implementation of a FAM for NSPI effective January 1, 2009, reducing the utility’s exposure to fuel price volatility by providing a mechanism for NSPI to recover actual fuel costs. The FAM mitigates the risk to NSPI’s net earnings associated with fluctuations in commodity prices and foreign exchange.

Commodity Price Risk

Substantially all of the Company’s annual fuel requirement is subject to fluctuation in commodity market prices. The Company utilizes a portfolio strategy for fuel procurement with a combination of long, medium, and short-term supply agreements. It also provides for supply and supplier diversification. The strategy is designed to reduce the effects from market volatility through agreements with staggered expiration dates, volume options, and varied pricing mechanisms.

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Coal/Petroleum Coke

A substantial portion of NSPI’s coal and petroleum coke (“petcoke”) supply comes from international suppliers, which was contracted at or near the market prices prevailing at the time of contract. The Company has entered into fixed-price and index price contractual arrangements with several suppliers as part of the fuel procurement portfolio strategy. All index priced contractual arrangements are matched with a corresponding financial instrument to fix the price. The approximate percentage of coal and petcoke requirements contracted at December 31, 2010 is as follows:

• 2011 – 77%

• 2012 – 39%

• 2013 – 24%

Heavy Fuel Oil

NSPI manages exposure to changes in the market price of heavy fuel oil through the use of swaps, options, and forward contracts. For 2011 and 2012, NSPI currently does not have heavy fuel oil hedging requirements.

Natural Gas

NSPI has entered into multi-year contracts to purchase approximately 47,600 mmbtu of natural gas per day in 2011, and 39,300 mmbtu of natural gas per day in 2012. Volumes exposed to market prices are managed using financial instruments where the fuel is required for NSPI’s generation; and the balance is sold against market prices when available for resale. Gas volumes not required for generation will be resold into the gas market with the margin hedged using financial instruments. As at December 31, 2010, amounts of natural gas volumes that have been economically and/or financially hedged and contracted are approximately as follows:

• 2011 – 87%

• 2012 – 35%

Foreign Exchange Risk

NSPI enters into foreign exchange forward and swap contracts to limit the exposure of currency rate fluctuations related to fuel purchases. Currency forwards are used to fix the CAD cost to acquire USD, reducing exposure to currency rate fluctuations.

The risk due to fluctuation of the CAD against the USD for fuel purchases is measured and managed. In 2011, NSPI expects approximately 60% of its anticipated net fuel costs to be denominated in USD. USD from sales of surplus natural gas will provide a natural hedge against a portion of USD fuel costs.

Forward contracts to buy $225.5 million USD were in place at December 31, 2010 at a weighted average rate of $0.99, representing 70% of 2011’s anticipated USD requirements. Forward contracts to buy $443.0 million USD in 2012 through 2015 at a weighted average rate of $1.03 were in place at December 31, 2010. These contracts cover 31% of anticipated USD requirements in these years.

NSPI uses foreign exchange forward contracts to hedge the currency risk for capital projects and receivables denominated in foreign currencies. Forward contracts to buy €1.8 million were in place at December 31, 2010 at a weighted average rate of $1.56 (versus CAD) for capital projects in 2011.

Interest Rate Risk

NSPI manages interest rate risk through a combination of fixed and floating borrowing and a hedging program. Floating-rate debt is estimated to represent approximately 16% of total debt in 2011. The Company has no interest rate hedging contracts outstanding as at December 31, 2010.

Credit Risk

Credit risk arising as a result of contractual obligations between the Company and other counterparties is managed by assessing the counterparties’ financial creditworthiness prior to assigning credit limits based

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on the Board of Directors’ approved credit policies. The Company frequently uses collateral agreements within its negotiated master agreements to further mitigate credit exposure.

Labour Risk

NSPI has a contract with its union which will expire in April 2012.

Regulatory Risk

NSPI faces risk with respect to the timeliness and certainty of full recovery of costs. The adoption and implementation of the FAM effective January 1, 2009, has helped NSPI manage that risk. The UARB oversees the FAM, including review of fuel costs, contracts and transactions. The FAM will help ensure customer rates reflect the actual price of the fuel used to make electricity. Concurrent with the implementation of the FAM in 2009, NSPI’s regulated ROE range was reduced by 0.2%, changing its regulated ROE range to 9.1% to 9.6%, with rates set at 9.35%.

The first rate adjustment under the FAM, effective on January 1, 2010, was approved by the UARB on December 9, 2009. On December 8, 2010, the UARB approved NSPI’s setting of the 2011 base cost of fuel and its recovery of all unrecovered fuel related costs as submitted in the Company’s November 2010 filing. The recovery of these costs will begin January 1, 2011. The UARB approved the recovery of these costs by NSPI over three years, with 50% of the rate increase to be recovered in 2011, 30% in 2012 and 20% in 2013.

In December 2010, the UARB granted NSPI approval to defer certain tax benefits related to renewable energy projects arising in 2010. The UARB will convene a proceeding in 2011 to discuss how this deferral will be applied.

Environment

Corporate Environmental Governance

NSPI is committed to operating in a manner that is respectful and protective of the environment, and in full compliance with legal requirements and Company policy. NSPI has implemented this policy through development and application of environmental management systems (“EMS”).

Implementation of EMS has provided a systematic focus on environmental issues so risks are identified and managed proactively. All areas of NSPI undertook initiatives in 2010 to reduce potential environmental risks and associated costs. Activities included, but were not limited to, reducing air emissions, protecting water resources, and continued management of PCB contaminated electrical equipment.

Conformance with legislative and Company requirements is verified through a comprehensive environmental audit program. There were no significant environmental or regulatory compliance issues identified during the 2010 audits. Plans are in place to promptly address any audit findings and continually improve the environmental management of the Company’s operations.

Oversight of environmental matters is carried out by the Board of Directors or committees of the Board of Directors with specific environmental responsibilities. In addition, an Environmental Council, made up of senior NSPI employees with working accountability for environmental matters, continues to guide the implementation of programs that address key environmental issues. In addition to programs for employees, the EMS procedures include planning, implementing and monitoring of contractors’ performance.

NSPI completed an Integrated Resource Plan in 2007 and refreshed it in 2009. The Integrated Resource Plan includes current environmental requirements and assumptions on future regulations as constraints on possible generation plans. This allows for the assembly of better generation plans for the future. NSPI stakeholders were engaged in the assumptions and the scenarios to be modeled. The results of these planning exercises can be found on the NSPI website.

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In 2007, NSPI was audited by the Canadian Electricity Association (“CEA”) to verify the quality of its environmental reporting and management systems. The auditor from the CEA concluded that NSPI had “robust programs, environmental leadership and a strong, mature EMS.”

Regulatory

NSPI produces its electrical energy approximately 64% from coal and 19% from natural gas and/or oil. As such, it is subject to regulation with respect to air pollutants and greenhouse gas emissions. NSPI operates under a cost-of-service regulation model. Accordingly, all prudently incurred costs, including those capital and operating costs associated with meeting present and future environmental liabilities, can be recovered in rates collected from customers.

NSPI is subject to environmental regulation as set by both Canadian federal and Nova Scotia provincial governments. NSPI is in material compliance with current environmental regulations. All required permits are in place for NSPI’s generating stations. These permits are generally for a ten year period but can be subject to review, variation, or suspension by the Minister of Environment of Nova Scotia.

Climate Change and Air Emissions

Renewable Energy

On October 15, 2010, the Nova Scotia Government enacted regulations under the Electricity Act related to the province’s Renewable Electricity Plan. These regulations establish the requirement that 25% of electricity be supplied from renewable sources by 2015. These regulations build on the previously legislated requirements for 2011 and 2013. Recent amendments to the Electricity Act, and the new regulations, provide for the appointment, by spring 2011, of a new, independent renewable electricity administrator to conduct the procurement of at least 300 GWh of energy from IPPs to meet the 2015 standard. NSPI is also provided the opportunity to develop 300 GWh of renewable energy.

In January 2007, the Nova Scotia Government approved the Renewable Energy Standard Regulation (“RES”) to increase the percentage of renewable energy in the generation mix. In October 2009, the RES was amended. The year for 5% of electricity to be supplied from post-2001 sources of renewable energy, owned by independent power producers, was extended to 2011 from 2010. The requirement for 2013, which requires an additional 5% of renewable energy, is unchanged.

Greenhouse Gas Emissions

NSPI has stabilized, and in recent years, reduced greenhouse gas emissions. This has been achieved by energy efficiency and conservation programs, increased use of natural gas, improved efficiency of converting natural gas to electricity and adding and contracting for new renewable energy sources to the generation portfolio.

Greenhouse gas emissions from NSPI facilities are capped beginning in 2010 through to 2020. The 2010 to 2015 caps will be achieved by the continued success of energy efficiency and conservation programs and the addition of renewable energy to meet the 2011, 2013 and 2015 provincial renewable energy standards. The regulations also include a transmission incentive compliance mechanism recognizing expenditures on transmission which facilitates additional renewable energy sources. Up to 3% of the annual cap can be offset in this way to 2019. Further, the 2010 to 2020 period years are combined to form multi-year compliance periods recognizing the variability in electricity supply sources and demand.

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Beyond 2015, reduced greenhouse gas emissions will be achieved through a combination of additional renewable energy, co-firing of biomass in existing coal power plants, import of non-emitting energy and energy efficiency and conservation as per the 2007/2009 Integrated Resource Plan.

On June 23, 2010, Environment Canada announced its intentions for a new national GHG framework for the electricity sector. This federal framework, if developed further into regulations, would require thermal coal units to meet GHG emission levels equal to, or better than, a natural gas combined cycle generating unit at a specific anniversary. Nova Scotia’s existing GHG regulations require reductions in NSPI’s emissions similar to the intentions of the federal framework. NSPI is reviewing the implications of this federal framework and its alignment with NSPI’s current operating plans under existing Nova Scotia regulations.

Mercury

On July 22, 2010, the Province of Nova Scotia announced, for the years 2010 through 2013, allowable mercury emissions would be increased from the previous cap of 65 kg per year. NSPI was requested to develop a plan of staged mercury emission reductions for its generation facilities for the period of 2010 to 2020 and to meet an annual cap of 35 kg beginning in 2020.

In 2008, NSPI carried out extensive testing on mercury abatement technology in its coal power plants. A capital program to add sorbent injection to each of the seven pulverized fuel coal units was completed in 2009. This allowed NSPI to meet the 2010 mercury emission cap of 65 kg established by the Province.

Compared to historical levels, NSPI has reduced mercury emissions by 60%.

Nitrogen Oxide and Sulphur Dioxide Emissions

NSPI has completed in 2009 its capital program of retrofitting low nitrogen oxide combustion firing systems on six of its seven pulverized fuel coal units. NSPI now meets the 2009 nitrogen oxide emission cap of 21,365 tonnes per year established by the province.

NSPI continues to meet its emission cap on sulphur dioxide emissions by the use of compliant fuel.

Compared to historical levels, NSPI has reduced emissions of nitrogen oxide by 40% and sulphur dioxide by 50%.

Obligations

The Company recognizes asset retirement obligations (“ARO”) for property, plant and equipment in the period in which they are incurred if a reasonable estimate of fair value can be determined. Using the Company’s credit-adjusted risk-free rate, the fair value is determined by discounting the Company’s estimated future cash flows necessary to discharge legal obligations related to reclamation of land at the Company’s thermal, hydro, combustion turbine sites, and disposal of polychlorinated biphenyls (“PCBs”) in its transmission and distribution equipment. Estimated future cash flows are based on the Company’s completed depreciation studies, prior experience, estimated useful lives of assets, governmental regulatory requirements and the costs of activities such as demolition, restoration and remedial work based on present-day methods and technologies. Actual results may differ from these estimates.

The UARB included the amount of future expenditures associated with the removal of generation facilities in the 2003 NSPI depreciation settlement discussed under Property, Plant and Equipment in the Significant Accounting Policies and Critical Accounting Estimates section. NSPI believes that it will continue to be able to recover ARO through rates. Accordingly, changes to the ARO, or cost recognition attributable to changes in the factors discussed above, should not impact the results of operations of the Company.

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Some of the Company’s hydro, transmission and distribution assets may have additional ARO. As the Company expects to use the majority of its installed assets for an indefinite period, no removal date can be determined and consequently a reasonable estimate of the fair value of any related ARO cannot be made at this time. Additionally, some of the Company’s transmission and distribution assets may have conditional ARO, the fair value of which cannot be reasonably estimated as sufficient information does not exist to estimate the obligations. A liability will be recognized in the period in which sufficient information becomes available.

The key assumptions used to determine the ARO are as follows:

Asset	Credit-adjusted risk-free rate						Estimated undiscounted future obligation (millions of dollars)				Expected settlement date (number of years)
	2010			2009			2010		2009		2010		2009
Thermal		5.30	%		5.31	%	$	258.9	$	242.3		10 –29		11 –30
Hydro		5.27	%		5.31	%		101.4		60.8		21 – 51		22 –52
Wind		5.21	%		—			45.5		—		13 – 20		—
Combustion turbines		5.25	%		5.31	%		12.9		5.1		1 – 14		1 – 14
Transmission & distribution		5.74	%		5.74	%		21.6		18.1		1 – 15		1 – 16
							$	440.3	$	326.3

As at December 31, 2010, the asset retirement obligations recorded on the balance sheet were $138.7 million (2009 – $101.5 million). The Company estimates the undiscounted amount of cash flow required to settle the obligations is approximately $440.3 million, which will be incurred between 2011 and 2061. The majority of these costs will be incurred between 2020 and 2041.

DISCLOSURE AND INTERNAL CONTROLS

NSPI’s management is responsible for establishing and maintaining 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. The objective of this instrument is to improve the quality, reliability and transparency of information that is filed or submitted under securities legislation.

The President and Chief Executive Officer and the Chief Financial Officer have designed, with the assistance of Company employees, DC&P and ICFR to provide reasonable assurance that material information is reported to them on a timely basis; financial reporting is reliable; and financial statements prepared for external purposes are in accordance with CGAAP.

The President and Chief Executive Officer and the Chief Financial Officer have evaluated, with the assistance of Company employees, the effectiveness of NSPI’s DC&P and ICFR and based on that evaluation have concluded DC&P and ICFR were effective at December 31, 2010.

There have been no changes in NSPI’s ICFR during the period beginning on January 1, 2010 and ended on December 31, 2010, which have materially affected, or are reasonably likely to materially affect ICFR.

SIGNIFICANT ACCOUNTING POLICIES AND CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, related amounts of revenues and expenses, and disclosure of contingent assets and liabilities. Significant areas requiring the use of management

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estimates relate to rate-regulation, the determination of post-retirement employee benefits, unbilled revenue, contract receivable, asset retirement obligations, useful lives for depreciable assets and income taxes. Actual results may differ from these estimates.

Rate Regulation

NSPI’s accounting policies are subject to examination and approval by the UARB. As a result, its rate-regulated accounting policies may differ from accounting policies for non-rate-regulated companies. These differences occur when the regulator renders its decisions on rate applications or other matters and generally involve a difference in the timing of revenue and expense recognition. The accounting for these items is based on the expectation of the future actions of the regulators.

If the regulator’s future actions are different from the regulator’s previous rulings, the timing and amount of the recovery of liabilities and refund of assets, recorded or unrecorded, could be significantly different from that reflected in the financial statements.

Pension and Other Post-Retirement Employee Benefits

The Company provides post-retirement benefits to employees, including defined benefit pension plans. The cost of providing these benefits is dependent upon many factors that result from actual plan experience and assumptions of future experience.

The benefit cost and accrued benefit obligation for employee future benefits included in annual compensation expenses are affected by employee demographics, including age, compensation levels, employment periods, contribution levels and earnings on plan assets.

Changes to the provision of the plan may also affect current and future pension costs. Benefit costs may also be affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and discount rates used in determining the accrued benefit obligation and benefit costs.

The pension plan assets are comprised primarily of equity and fixed income investments. Fluctuations in actual equity market returns and changes in interest rates may result in increased or decreased pension costs in future periods.

Consistent with CGAAP and NSPI’s accounting policy, the Company amortizes the net actuarial gain or loss, which exceeds 10% of the greater of the accrued benefit obligation (“ABO”) and the market-related value of assets, over active plan members’ average remaining service period, which is currently 9 years. NSPI’s use of smoothed asset values further reduces the volatility related to the amortization of actuarial investment experience. As a result, the main cause of volatility in reported pension cost is the discount rate used to determine the ABO.

The discount rate used to determine benefit costs is based on high quality long-term Canadian corporate bonds. The discount rate is determined with reference to bonds which have the same duration as the ABO as at January 1 of the fiscal year rounded to the nearest 25 basis points. For benefit cost purposes, NSPI’s rate was 6.50% for 2010 (2009 – 7.50%).

The expected return on plan assets is based on management’s best estimate of future returns, considering economic and consensus forecasts. The benefit cost calculations assumed that plan assets would earn a rate of return of 7.25% for 2010 and 2009.

The reported benefit cost for 2010 for all defined benefit and defined contribution plans, based on management’s best estimate assumptions, is $26.2 million. While there are numerous assumptions which are used to determine the benefit cost, the discount rate and asset return assumptions have an impact on the calculations.

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The following shows the impact on 2010 benefit cost of a 25 basis point change (0.25%) in the discount rate and asset return assumptions:

	Increase 0.25%						Decrease 0.25%
millions of dollars	2010			2009			2010		2009
Discount rate assumption	$	(3.0	)	$	(0.9	)	$	3.1	$	0.9
Asset return assumption	$	(1.7	)	$	(1.7	)	$	1.7	$	1.7

The sensitivity to the discount rate assumption was significantly lower for 2010 benefit cost than in recent years because the net unamortized gains and losses subject to amortization fell within the 10% corridor. As such, for 2010, small changes to the discount rate assumption do not impact the amount of actuarial gains and losses being amortized and included in the calculation of benefit cost.

Unbilled Revenue

Electric revenues are billed on a systematic basis over a one or two-month period. At the end of each month, the Company must make an estimate of energy delivered to customers since the date their meter was last read and of related revenues earned but not yet billed. The unbilled revenue is estimated based on several factors, including current month’s generation, estimated customer usage by class, weather, line losses and applicable customer rates. Based on the extent of the estimates included in the determination of unbilled revenue, actual results may differ from the estimate. As at December 31, 2010, unbilled revenues amount to $84.1 million (2009 – $85.4 million) on a base of annual electric revenues of approximately $1.2 billion (2009 – $1.2 billion).

Contract Receivable

NSPI’s natural gas purchase agreement expired in October 2010. The agreement included a price adjustment clause covering three years of natural gas purchases. The clause stated that NSPI would pay for all gas purchases at the agreed contract price, but would be entitled to a price rebate on a portion of the volumes. The first settlement took place in November 2007 for purchases to the end of October 2007 and the final settlement took place in November 2010.

Asset Retirement Obligations

The Company recognizes ARO’s for property, plant and equipment in the period in which they are incurred if a reasonable estimate of fair value can be determined. The fair value of the liability is described as the amount at which the liability could be settled in a current transaction between willing parties. Expected values are discounted at the risk-free interest rate adjusted to reflect the market’s evaluation of the Company’s credit standing. Determining ARO’s requires estimating the life of the related asset and the costs of activities such as demolition, restoration and remedial work based on present-day methods and technologies. Actual results may differ from these estimates.

As part of the 2003 NSPI depreciation settlement, the UARB included the amount of future expenditures associated with the removal of generation facilities. NSPI believes that it will continue to be able to recover ARO’s through rates. Accordingly, changes to the ARO, or cost recognition attributable to changes in the factors discussed above, should not impact the results of operations of the Company.

Property, Plant and Equipment

Property, plant and equipment represents 67% of total assets recognized on the Company’s balance sheet. Included in “Property, plant and equipment” are the generation, transmission and distribution and other assets of the Company. Due to the magnitude of the Company’s property, plant and equipment, changes in estimated depreciation rates can have a material impact on depreciation expense.

Depreciation is calculated on a straight-line basis over the estimated service life of the asset. The estimated useful lives of the assets are largely based on formal depreciation studies, which are conducted from time to time.

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In 2002, NSPI commissioned a depreciation study by an external consultant. The study was filed with the UARB in 2003. A settlement agreement on the matter was reached with all interveners, which recommended a four-year phase-in of new depreciation rates, which, based on assets in service in the study, would reach an overall increase in depreciation expense of $20 million by 2007. The UARB approved the settlement. NSPI began phasing the new rates in 2004. In its rate decision for 2005, the UARB deferred the scheduled phase-in for 2005. In the rate decision for 2006, the UARB included the phase-in of year-two in rates. In its February 5, 2007 decision, the UARB postponed the phase-in of year-three rates until the next rate application. In its November 5, 2008 decision, the UARB approved year-three phase-in rates effective January 1, 2009. On October 29, 2010, NSPI filed a depreciation study with the UARB.

Income Taxes

Income taxes are determined based on the expected tax treatment of transactions recorded in the financial statements. In determining income taxes, tax legislation is interpreted, the likelihood that future tax assets will be recovered from future taxable income is assessed and assumptions about the expected timing of the reversal of future tax assets and liabilities are made. If interpretations differ from those of tax authorities or if the recovery of future tax assets or timing of reversals is not as anticipated, the provision for income taxes could increase or decrease in future periods. The amount of any such increase or decrease cannot be reasonably estimated.

CHANGES IN ACCOUNTING POLICIES

Future Accounting Policy Changes

Changeover to United States Generally Accepted Accounting Principles

In February 2008, the Canadian Institute of Chartered Accountants (“CICA”) announced CGAAP for publicly accountable enterprises will be replaced by International Financial Reporting Standards (“IFRS”) for fiscal years beginning on or after January 1, 2011. The Company began planning its transition to IFRS in 2008 and transition activities progressed on schedule through 2009. In Q4 2009, due primarily to the continued uncertainty around the timing and eventual adoption of a rate-regulated accounting (“RRA”) standard under IFRS, management of Emera, NSPI’s parent company, began reviewing the option of adopting United States Generally Accepted Accounting Principles (“US GAAP”) instead of IFRS. In Q1 2010, the Company decided to transition to US GAAP financial reporting standards beginning Q1 2011.

The adoption of US GAAP in Q1 2011 is expected to result in fewer significant changes in the Company’s accounting policies than would have been experienced with the adoption of IFRS. Management believes this will result in financial information that is more comparable to the Company’s prior years’ financial statements prepared under CGAAP, making them easier for readers to understand.

US GAAP reporting is permitted by Canadian securities laws and the Toronto Stock Exchange (“TSX”) for companies subject to reporting obligations under US securities laws. On July 15, 2010, NSPI registered debt securities with the SEC under the US Securities Act of 1933, thereby becoming subject to US reporting obligations. Registration with the SEC will enhance the Company’s ability to access US capital markets in the future.

The Company’s application of CGAAP currently relies on US GAAP for guidance on the application of RRA. RRA allows the economic impact of regulatory activities to be recognized consistent with the timing that amounts are included in customer rates. The Company believes continued recognition of its regulatory assets and liabilities under US GAAP best reflects the effect regulatory activities have on the Company’s financial position. Without a RRA standard, a transition to IFRS would likely result in the

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accounting write-off of the Company’s significant regulatory assets and liabilities, and net earnings could be subject to greater volatility on an on-going basis.

Transition Activities

A formal project was established to transition to US GAAP for 2011, register securities of NSPI with the SEC and prepare the Company to comply with the on-going reporting requirements of the SEC and requirements of the Sarbanes-Oxley Act (“SOX”). A four-phased project approach was adopted to manage project activities. The project is proceeding on schedule to achieve its required milestones. The following is a brief overview of the activities of each phase and current status. An update on the project’s status and achievement of its key milestones are provided to the Company’s Audit Committee on a quarterly basis.

Phase One: Preliminary Assessment and Planning – Completed

Phase One was substantially completed in May 2010. It involved assessment and planning activities required to develop the initial project plan and identify resource requirements for the project. Internal resources were dedicated to the project to ensure its completion within the required timeline. KPMG LLP, who was assisting with the Company’s changeover to IFRS, was engaged to continue providing technical advisory services during the Company’s transition to US GAAP. In addition to resourcing activities, the Project Charter, Governance Structure and a Project Management Office were established to support the subsequent phases of the project.

Two key assessments were performed in this phase:

• The first assessment compared the most significant differences between US GAAP and CGAAP to determine which areas were most likely to impact the Company’s accounting policies and financial reporting. The purpose of this assessment was to highlight areas where detailed analysis of GAAP differences was needed to determine and conclude on the nature and extent of impact. Detailed analysis activities and conclusions on the impact of US GAAP on the Company’s accounting policies are discussed under Phase Two.

• The second assessment compared the requirements of the National Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and Interim Filings” (“NI 52-109”) and those of Sections 302 (“SOX 302”) and 404 (“SOX 404”) of the Sarbanes-Oxley Act. The purpose of this assessment was to identify the impact of SOX 302 and SOX 404 on the Company’s current NI 52-109 program over disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”).

Consistent with NI 52-109, SOX 302 requires certification by the certifying officers of all publicly-traded companies that they have established, maintained and designed DC&P and ICFR and evaluated DC&P. SOX 302 requires a quarterly evaluation of DC&P while NI 52-109 requires an annual evaluation, however, NSPI is not required to file quarterly 302 certificates with the SEC. Also consistent with NI 52-109, SOX 404 requires that all publicly-traded companies must establish ICFR; document, test and maintain those controls and procedures to ensure their effectiveness; and management must report on their evaluation of the effectiveness of ICFR.

Under SOX 404, the Company is required to obtain an external audit opinion annually on the design and effectiveness of the Company’s ICFR which is not required under NI 52-109. This was the only significant difference identified between the requirements of NI 52-109 and SOX 404. The first external audit on ICFR is required as of December 31, 2011. Activities being performed to prepare the Company for SOX 404 attestation are described below.

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Phase Two: Detailed Assessment, Development and SEC Registration – Completed

Phase Two commenced in April 2010. This phase involved registering securities of NSPI with the SEC and addressing all new requirements related to complying with US GAAP, SOX and SEC reporting obligations.

Detailed analysis was performed on those areas identified in Phase One where significant differences between US GAAP and CGAAP were most likely to impact the Company’s accounting policies, financial statements, information systems, internal controls and other business activities. Areas examined included revenue recognition, hedge accounting, RRA, pension and other post-retirement benefits, income taxes, preferred shares and foreign currency. Where differences were identified, prior period financial information is being restated to US GAAP for comparative purposes in 2011. Restatement activities are part of Phase Three.

The Company’s financial statements were drafted or “mocked-up” in accordance with US GAAP to identify the financial statement and disclosure impact of transitioning to US GAAP.

NSPI’s regulated accounting policies were updated to reflect the transition to US GAAP. These were approved by the UARB in December 2010.

Based on the work completed in this phase and the Company’s conclusion that it is able to continue with its application of RRA under US GAAP, material adjustments to the Company’s reported post-transition net earnings were not identified. The on-going impact of the differences identified between CGAAP and US GAAP are mostly limited to changes in classification and presentation within the financial statements and in the extent of disclosure requirements.

Areas where the financial impact of transitioning to US GAAP is more significant are outlined below. These areas do not represent a complete list of expected changes. The net impact of all adjustments required to restate retained earnings on January 1, 2010 to US GAAP is an approximate $7 million reduction. However, the net impact of all adjustments required to restate AOCI on January 1, 2010 to US GAAP will be material. The amount of any significant adjustments to retained earnings and AOCI are identified below under the financial statement item to which the adjustments relate.

Pension and other post-employment benefits –Under US GAAP, the Company will recognize its unfunded pension obligation as a liability in its financial statements and will need to recognize unamortized gains and losses associated with pension and other post-retirement benefits in AOCI in shareholders’ equity. Currently, under CGAAP, the unamortized amounts together with their impact on the funded status of the pension liability or asset, are disclosed but not recognized.

Financial impact: Restating the amounts under US GAAP results in a $256 million unamortized loss recorded in AOCI, a $7 million reduction to retained earnings, and a $263 million increase to pension liability on January 1, 2010.

Hedge accounting –The Company has determined that certain hedging strategies that qualify for hedge accounting under CGAAP do not qualify for the same treatment under US GAAP primarily due to differences in effectiveness testing requirements. Effective for hedges put in place beginning in 2010, the Company has changed its strategies to ensure compliance with US GAAP prospectively.

Prior to the Company’s decision to transition to US GAAP, NSPI, in consultation with interveners and consultants for the UARB, discussed deferral accounting for all of its economic hedges. Based on these discussions and the Company’s decision to adopt US GAAP, NSPI filed an amended accounting policy with the UARB requesting deferral accounting for all of its economic hedges. The UARB approved the amended regulatory accounting policy in December 2010, resulting in the deferral of the periodic changes in the fair value of these derivatives so that they impact NSPI’s net earnings in a manner consistent with that achieved if hedge accounting had been applied.

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Financial impact: NSPI’s amended accounting policy results in a $44 million increase in AOCI and net regulatory assets to restate its economic hedges on January 1, 2010 to US GAAP.

Income taxes

Enacted tax rates

US GAAP requires that the enacted tax rate be used in measuring current taxes and FIT. Under CGAAP, the tax impact of the Part VI.1 tax deduction related to preferred share dividends is recorded at the substantively enacted tax rates, which is consistent with Canada Revenue Agency’s assessing practice. Under US GAAP, the Company will recognize an income tax liability for the difference between the enacted tax rates and the substantively enacted tax rates for the Part VI.1 tax deduction.

Financial impact: Restating the amounts under US GAAP results in a $9 million increase to income tax payable and decrease to retained earnings on January 1, 2010.

Investment tax credits

Under CGAAP, certain investment tax credits related to qualifying scientific research and development expenditures are recorded as a reduction to property, plant and equipment. Under US GAAP, the Company will recognize the investment tax credit as a reduction in tax expense.

Financial impact: Restating the amounts under US GAAP results in a $4 million increase to property, plant and equipment and retained earnings on January 1, 2010.

Uncertain tax positions

During 2010, the Company revised its estimate of the expected benefit from accelerated tax deductions under CGAAP. A portion of the impact of the 2010 revised estimate is related to the US GAAP guidance for determining the unit of account and resulting expected benefit. As a result, for US GAAP, the Company will recognize a portion of the 2010 change in estimate in years prior to January 1, 2010.

Financial impact: Restating the amounts under US GAAP results in a $4 million decrease in income tax payable and increase retained earnings on January 1, 2010.

US GAAP transition adjustments

Under US GAAP, the Company will recognize the FIT impact on the US GAAP adjustments for pension and other post-employment benefits and hedge accounting as noted above, and on other US GAAP adjustments to the balance sheet.

Financial impact: Material adjustments are expected to restate FIT assets and liabilities on January 1, 2010 to US GAAP. The amount of these adjustments is still being determined, however, the impact of a change in FIT expense (recoveries) will be deferred to a regulatory asset or liability where the FIT is expected to be included in future rates. The net impact of income tax adjustments under US GAAP required to restate retained earnings and AOCI on January 1, 2010 is not expected to be material due to rate-regulated accounting.

The Company has various agreements with external parties that reference CGAAP as the basis for satisfying financial reporting requirements, including covenant calculations. NSPI renegotiated its revolving credit facility with its banking syndicate in June 2010 and in Q4 2010, and reached an agreement with its trustee to bilaterally amend its respective trust indentures by way of supplemental indentures. This amended agreement allows for USGAAP as the basis for satisfying financial reporting requirements.

The impact of the transition to US GAAP on information systems is minimal.

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All Phase Two activities are complete.

Phase Three: Implementation – In-Progress

Phase Three began in July 2010 and involves implementing the changes identified and planned in Phase Two that are necessary to comply with US GAAP in 2011, along with SOX and SEC reporting obligations as they become effective.

2009 and 2010 financial information prepared under CGAAP is being restated to US GAAP for comparative purposes in 2011, with most adjustments now complete and the remainder to be completed in Q1 2011, including restatement of Q4 2010. Reconciliation of prior period financial information from CGAAP to US GAAP, along with other significant transitional disclosure, will be presented in the 2011 financial statements.

The Company’s financial reporting processes and consolidation software are being reconfigured to support the preparation of US GAAP financial statements in 2011 and the consolidation of prior period restatements. The required changes are not significant and will be on-going through Q1 2011.

As of July 15, 2010, NSPI is an SEC registrant and subject to SEC reporting obligations. NSPI is now required to furnish all filings made with the Canadian securities regulatory authorities concurrently with the SEC.

Changes are being implemented to business processes and ICFR to help ensure an efficient SOX 404 attestation process. Changes will be completed in Q1 2011.

Education and training activities have occurred throughout all project phases. In this phase, education activities are focused on ensuring all personnel and senior management impacted by the transition understand the new requirements and have the skills and expertise necessary to ensure the organization’s on-going ability to report under US GAAP, fulfill its reporting obligations to the SEC and comply with SOX. Members of the Company’s Board of Directors participated in education sessions in Q4 2010. Additional education sessions are planned in Q1 2011, including one for members of the Company’s Audit Committee to review the financial impact of the transition, prior period restatements and the Company’s transitional disclosure.

With the exception of the Q4 2010 restatements, the activities of this phase were originally planned to be substantially completed in December 2010, however, certain implementation activities identified above will be completed in February 2011. These delays do not jeopardize the project’s ability to meet its key milestones, nor the Company’s ability to meet its Q1 2011 reporting obligations.

Phase Four: Operational Support – In-Progress

Phase Four began January 2011 and is scheduled to be completed by the end of Q2 2011. The impact of transitioning to US GAAP and complying with SEC reporting obligations and SOX requirements will be fully integrated into the Company’s financial reporting processes at that time.

Final transitional activities will be completed in this phase.

Following release of the Company’s Q1 2011 financial statements, the project will be formally closed and internal resources currently dedicated to the project will resume responsibility for financial reporting activities within the business.

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Recently Issued US GAAP Accounting Standards

As indicated above, beginning with its external reporting in Q1 2011, the Company will retrospectively adopt US GAAP as its accounting framework and will no longer prepare its consolidated financial statements under CGAAP. In evaluating the impact of adopting US GAAP, the Company has considered US GAAP accounting standards currently in effect through December 31, 2010. In 2011, additional US GAAP standards will become effective and the Company will adopt them in accordance with their individual transition guidelines. The identified issued standards that have effective dates in 2011 and may be relevant to the Company are set out below.

Revenue Recognition

In October 2009, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2009-13,Revenue Recognition (Topic 605): Multiple-Deliverable Revenue Arrangements. ASU 2009-13 amends existing US GAAP revenue recognition guidance to eliminate the requirement that all undelivered elements have vendor specific objective evidence of selling price (“VSOE”) or third party evidence of selling price (“TPE”) before an entity can recognize the portion of an overall arrangement fee that is attributable to items that already have been delivered. In the absence of VSOE and TPE for one or more delivered or undelivered elements in a multiple-element arrangement, entities will be required to estimate the selling prices of those elements. The overall arrangement fee will be allocated to each element (both delivered and undelivered items) based on their relative selling prices, regardless of whether those selling prices are evidenced by VSOE or TPE or are based on the entity’s estimated selling price. Application of the “residual method” of allocating an overall arrangement fee between delivered and undelivered elements will no longer be permitted upon adoption of ASU 2009-13. Additionally, the new guidance will require entities to disclose more information about their multiple-element revenue arrangements. ASU 2009-13 is effective prospectively for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010. The Company will adopt ASU 2009-13 effective January 1, 2011 but does not expect that its adoption will have a material impact on its financial statements.

Fair Value Measurements

In January 2010, the FASB issued ASU 2010-06,Improving Disclosures about Fair Value Measurements. ASU 2010-06 amends FASB Accounting Standards Codification (“ASC”) Topic 820,Fair Value Measurements and Disclosures, to require reporting entities to make new disclosures about recurring or nonrecurring fair-value measurements including significant transfers into and out of Level 1 and Level 2 fair-value measurements and information about purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair-value measurements. The ASU also clarifies existing fair-value measurement disclosure guidance about the level of disaggregation, inputs, and valuation techniques. Except for the detailed Level 3 roll forward disclosures, the guidance in the ASU was effective for interim and annual reporting periods beginning after December 15, 2009. The new disclosures about purchases, sales, issuances, and settlements in the roll forward activity for Level 3 fair-value measurements are effective for fiscal years beginning after December 15, 2010. The Company will adopt the disclosure requirements of ASU 2010-06 in its 2011 US GAAP financial reporting but does not expect they will have a material impact on its financial statements.

Goodwill Impairment

In December 2010, the FASB issued ASU 2010-28 Intangibles—Goodwill and Other (Topic 350):When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts. ASU 2010-28 amends ASC 350-20 to modify Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist consistent with the existing guidance in US GAAP. ASU 2010-28 is effective for interim periods and fiscal years beginning on or after December 15, 2010. The Company will adopt ASU 2010-28 effective January 1, 2011 but does not expect that its adoption will have a material impact on its financial statements.

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SUMMARY OF QUARTERLY RESULTS

For the quarter ended	Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
millions of dollars	2010		2010		2010		2010		2009		2009		2009		2009
Total revenues	$	301.1	$	270.3	$	270.6	$	340.7	$	306.9	$	267.5	$	276.9	$	350.8
Net earnings applicable to common shares		20.7		22.4		14.9		63.3		17.4		16.6		22.8		52.5

Quarterly total revenues and net earnings applicable to common shares 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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