Nova Scotia Power 6-K Current report (foreign)

Exhibit 99.1

Management’s Discussion & Analysis

As at August 5, 2011

Management’s Discussion and Analysis (“MD&A”) provides a review of the results of operations of Nova Scotia Power Inc. during the second quarter of 2011 relative to 2010, and its financial position as at June 30, 2011 relative to December 31, 2010. To enhance shareholders’ understanding, certain multi-year historical financial and statistical information is presented. Throughout this discussion, “NSPI” and “Company” refer to Nova Scotia Power Inc.

Effective January 1, 2011, Nova Scotia Power Inc. changed the basis of presentation in its financial statements from Canadian Generally Accepted Accounting Principles (“CGAAP”) to United States Generally Accepted Accounting Principles (“USGAAP”), including the application of rate-regulated accounting.

This discussion and analysis should be read in conjunction with the Nova Scotia Power Inc. unaudited condensed financial statements and supporting notes as at and for the six months ended June 30, 2011, prepared in accordance with USGAAP; and the Nova Scotia Power Inc. MD&A and annual audited financial statements and supporting notes as at and for the year ended December 31, 2010, prepared in accordance with CGAAP.

Nova Scotia Power Inc.’s accounting policies are subject to examination and approval by the Nova Scotia Utility and Review Board (“UARB”). The rate-regulated accounting policies of Nova Scotia Power Inc. may differ from those used by non-regulated companies with respect to the timing of recognition of certain assets, liabilities, revenues and expenses.

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

Additional information related to NSPI, including the Company’s Annual Information Form, can be found on SEDAR atwww.sedar.com and on EDGAR atwww.sec.gov.

Forward Looking Information

This MD&A contains “forward-looking information” within the meaning of applicable Canadian securities laws and “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995 (collectively, “forward-looking information”). The words “anticipates”, “believes”, “could”, “estimates”, “expects”, “intends”, “may”, “plans”, “projects”, “schedule”, “should”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words.

The forward-looking information in this MD&A includes statements which reflect the current view with respect to the Company’s objectives, plans, financial and operating performance, business prospects and opportunities. The forward-looking information reflects NSPI management’s current beliefs and is based on information currently available to NSPI’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the times at which, such events, performance or results will be achieved.

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The forward-looking information is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ from current expectations are discussed in the Outlook section of the MD&A and may also include: regulatory risk; operating and maintenance risks; economic conditions; availability and price of energy and other commodities; capital resources and liquidity risk; weather; commodity price risk; competitive pressures; construction; derivative financial instruments and hedging availability and cost of financing; interest rate risk; counterparty risk; competitiveness of electricity; commodity supply; environmental risks; foreign exchange; regulatory and government decisions including changes to environmental, financial reporting and tax legislation; loss of service area; market energy sales prices; labour relations; and availability of labour and management resources.

Readers are cautioned not to place undue reliance on forward-looking information as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking information in this MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, NSPI undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise.

Structure of MD&A

This MD&A reflects the transition to USGAAP from CGAAP, effective January 1, 2011, as previously noted. Information derived from the Statements of Income for the three and six months ended June 30, 2010 and Balance Sheets as at December 31, 2010, along with other select financial information for 2010 and 2009 has been adjusted to reflect USGAAP and is clearly labeled “adjusted”.

This MD&A begins with an Introduction and Strategic Overview, followed by the Financial Review of the Statements of Income, Balance Sheets and Cash Flows; then continues with a discussion on Outlook, Liquidity and Capital Resources, Transactions with Related Parties, Risk Management and Financial Instruments, Disclosure and Internal Controls and Summary of Quarterly Results.

INTRODUCTION AND STRATEGIC OVERVIEW

NSPI was created in 1992 through the privatization of the crown corporation Nova Scotia Power Corporation. NSPI is a fully-integrated regulated electric utility and the primary electricity supplier in Nova Scotia, Canada. The Company provides electricity generation, transmission and distribution services to approximately 490,000 customers and has $3.9 billion in assets. The Company is regulated by the UARB under a cost-of-service model, with rates set to recover prudently-incurred costs of providing electricity service to customers, and provide an appropriate return to investors. NSPI’s prescribed regulated return on equity (“ROE”) range for 2011 is 9.1 percent to 9.6 percent, based on an actual regulated common equity component of up to 40 percent of average regulated capitalization.

Non-GAAP Financial Measure

NSPI uses a financial measure that does not have a standardized meaning under USGAAP.

“Electric margin” is a non-GAAP financial measure used by NSPI and is defined as “Electric revenues” less “Fuel for generation and purchased power” and “Fuel for generation and purchased power – affiliates”, net of the “Fuel adjustment”, fuel related foreign exchange losses or gains and other fuel related costs. This measure is disclosed as management believes it provides useful information regarding the effect of the fuel adjustment mechanism (“FAM”) on NSPI’s operations. Electric margin is discussed in the Review of 2011 section.

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Developments

Deferral of Certain Tax Benefits Decision

In December 2010, the UARB granted NSPI approval to defer $14.5 million of tax benefits which arose in 2010 related to renewable energy projects. On July 21, 2011, the UARB approved an agreement NSPI reached with stakeholders to apply the deferral against the FAM regulatory asset effective January 1, 2011. The application of the deferral will reduce the amount of the FAM balance outstanding with the reduction applied to the amount that would otherwise be recovered from customers in 2012.

General Rate Application

On May 13, 2011, NSPI filed a General Rate Application (“GRA”) with the UARB requesting an average 7.3 percent rate increase across all customer classes effective January 1, 2012. As an alternative, NSPI publicly proposed a three-year plan that would hold rates stable from 2012 to 2014 inclusive. If discussions with customer representatives produce an agreement-in-principle for the alternative plan, NSPI will amend its May 13^th application filing and request approval from the UARB for the alternative plan.

Depreciation Settlement

On May 11, 2011, the UARB approved changes to NSPI’s depreciation rates following NSPI’s completion of a depreciation study and a settlement agreement with stakeholders. The overall impact on the average depreciation rate is not material. The new depreciation rates shall come into effect for use in the next GRA as presently filed for 2012.

Light–emitting Diode Streetlight Legislation

On April 21, 2011, the Nova Scotia Government introduced legislation making light-emitting diode (“LED”) lighting mandatory on Nova Scotia’s roads and highways within five years. This legislation builds on previous initiatives focused on energy efficiency and environmental responsibility. The cost to convert to LED lighting province-wide is estimated to be in the range of $100 million. NSPI’s related capital costs will be subject to UARB review and approval.

Nova Scotia Provincial Environmental Regulations

On May 19, 2011, the Nova Scotia Government approved The Electricity Act (Amended) to facilitate the eligibility of energy from the Lower Churchill Project in Labrador as a resource for meeting Nova Scotia’s renewable electricity targets. The amendment will allow regulations to be developed requiring an increase in the percentage of renewable energy in the generation mix from the planned 25 percent in 2015, to 40 percent by 2020.

On April 11, 2011, the Nova Scotia Government announced that the cap on the annual amount of new forest biomass that can be used to generate electricity will be lowered by 30 percent to 350,000 dry tonnes per year. NSPI’s 60 megawatt (“MW”) Port Hawkesbury Biomass Project is not affected by this announcement.

Digby Wind Renewable Energy Project

On March 9, 2011, the UARB approved a capital work order for the Digby Wind Renewable Energy Project, which included a substation, network upgrades and interconnection costs, in the total amount of $79.8 million. This project went into service in December 2010.

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Appointments

On May 2, 2011, James Eisenhauer, FCA was appointed Chairman of NSPI’s Board of Directors, replacing George A Caines, who retired. On May 4, 2011 Mr. Eisenhauer was elected to Emera’s Board of Directors at Emera’s Annual General Meeting.

On May 16, 2011, Judy Steele, FCA was appointed Chief Financial Officer of NSPI on an interim basis until such time as a permanent CFO is named. Prior to this appointment, Ms. Steele served as Vice President Finance of Emera Energy Inc.

FINANCIAL REVIEW

Review of 2011

millions of Canadian dollars	Three months ended June 30						Six months ended June 30
	2011			2010 (adjusted)			2011			2010 (adjusted)
Operating revenues		$299.0			$273.2			$667.8			$616.0
Fuel for generation and purchased power		125.4			119.5			294.3			299.1
Fuel for generation and purchased power – affiliates		0.4			4.8			0.1			6.4
Fuel adjustment		6.2			(12.6	)		0.4			(52.0	)
Operating, maintenance and general		68.9			60.0			134.4			114.9
Provincial grants and taxes		9.6			10.0			19.2			20.0
Depreciation and amortization		42.7			41.9			85.3			83.0
Total operating expenses		253.2			223.6			533.7			471.4
Income from operations		45.8			49.6			134.1			144.6
Other expenses, net		2.3			2.3			4.5			5.9
Interest expense, net		27.0			26.6			53.9			52.7
Income before provision for income taxes		16.5			20.7			75.7			86.0
Income tax (recovery) expense		(2.2	)		3.2			(8.6	)		1.3
Net income of Nova Scotia Power Inc.		18.7			17.5			84.3			84.7
Preferred stock dividends		2.0			2.0			4.0			4.0
Net income attributable to common shareholders	$	16.7		$	15.5		$	80.3		$	80.7

NSPI’s net income attributable to common shareholders increased $1.2 million to $16.7 million in Q2 2011 compared to $15.5 million in Q2 2010 (adjusted). NSPI’s net income attributable to common shareholders year-to-date decreased $0.4 million to $80.3 million in 2011 compared to $80.7 million in 2010 (adjusted). Highlights of the net income changes are summarized in the following table:

millions of Canadian dollars	Three months ended June  30			Six months ended June 30
Net income attributable to common shareholders – 2010 (adjusted)	$	15.5		$	80.7
Increased electric margin (see Electric Revenues section for explanation)		4.8			10.6
Increased operating, maintenance and general expenses due primarily to increased pension costs, labour escalation and increased plant maintenance costs		(8.9	)		(19.5	)
Increased net depreciation and amortization due primarily to increased property, plant and equipment partially offset by decreased regulatory amortization		(0.5	)		(1.7	)
Decreased income taxes due primarily to decreased income before provision for income taxes, accelerated tax deductions for property, plant and equipment and a lower statutory income tax rate		5.4			9.9
Other		0.4			0.3
Net income attributable to common shareholders – 2011	$	16.7		$	80.3

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Balance Sheets Highlights

Significant changes in the balance sheets between June 30, 2011 and December 31, 2010 (adjusted) include:

millions of Canadian dollars	Increase (Decrease)			Explanation
Assets
Receivables, net	$	26.9		Increase due to fuel related electricity pricing effective January 1, 2011 and timing of billings and receipts, partially offset by seasonal trends of business.
Income taxes receivable		11.7		Recovery of income taxes due to accelerated tax deductions for property, plant and equipment, including renewable investments.
Derivative instruments (current and long-term)		(11.6	)	Decrease primarily due to favourable hedges settling in 2011.
Regulatory assets (current and long-term)		27.0		Increased deferred income taxes regulatory asset, partially offset by regulatory amortization.
Prepaid expenses		20.2		Timing of provincial grants in lieu of taxes and insurance payments.
Deferred income taxes		(16.8	)	Decreased deferred income tax asset on net pension liability, and increased deferred income tax liability on property, plant and equipment, including renewable investments, resulting in reclassification to deferred income tax liability.
Liabilities and Equity
Short-term debt and long-term debt (including current portion)		21.0		Increased debt levels.
Accounts payable		(48.4	)	Timing of payments.
Deferred income taxes (current and long-term)		46.6		Increased deferred income tax liability on property, plant and equipment, including renewable investments, and decreased deferred income tax asset on net pension liability, resulting in reclassification of deferred income tax asset.
Regulatory liabilities (current and long-term)		(44.2	)	Decreased deferred income taxes regulatory liability and decreased derivative regulatory liability.
Pension and post-retirement liabilities (current and long-term)		(11.0	)	Decreased primarily due to NSPI’s cash contributions exceeding the value of the current benefit accrual.
Asset retirement obligations		(56.4	)	Decreased primarily due to change in estimates of retirement dates and future decommissioning costs.
Common stock		50.0		Issuance of common shares.
Accumulated other comprehensive loss		11.4		Amortization of unrecognized pension and post-retirement benefit costs.
Retained earnings		80.3		Net income.

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Cash Flow Highlights

Significant changes in the statements of cash flows between the six month periods ended June 30, 2011 and 2010 (adjusted) include:

Six months ended June 30 millions of Canadian dollars	2011			2010 (adjusted)			Explanation
Cash, beginning of period	$	0.3		$	0.3
Provided by (used in):
Operating activities		67.1			50.6		In 2011 and 2010, cash income, partially offset by unfavourable non-cash working capital.
Investing activities		(134.1	)		(214.0	)	In 2011 and 2010, capital spending, including additions associated with multi-year projects and renewable investments.
Financing activities		67.0			163.4		In 2011, issuance of common stock and increased short-term debt levels. In 2010, issuance of long-term debt and common stock, partially offset by decreased short-term debt levels and retirement of long-term debt.
Cash, end of period	$	0.3		$	0.3

Operating Revenues

NSPI’s Operating Revenues include sales of electricity and other services as summarized in the following table:

millions of Canadian dollars	Three months ended June 30				Six months ended June 30
	2011		2010 (adjusted)		2011		2010 (adjusted)
Electric revenues	$	293.2	$	267.0	$	656.6	$	604.5
Other revenues		5.8		6.2		11.2		11.5
Operating revenues	$	299.0	$	273.2	$	667.8	$	616.0

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Electric Revenues

Sales Volume (“load”)

Electric sales volume is primarily driven by general economic conditions, population and weather. Residential and commercial electricity sales are seasonal, with Q1 and Q4 the strongest periods, reflecting colder weather and fewer daylight hours in the winter season.

NSPI’s residential load generally comprises individual homes, apartments and condominiums. Commercial customers include small retail operations, large office and commercial complexes, and the province’s universities and hospitals. Industrial customers include manufacturing facilities and other large volume operations. Other revenues consist of export sales, sales to municipal electric utilities and revenues from street lighting.

Electric sales volumes are summarized in the following tables by customer class:

Q2 Electric Sales Volumes Gigawatt hours (“GWh”)
	2011		2010		2009
Residential		965		887		916
Commercial		729		722		713
Industrial		1,011		938		887
Other		71		69		75
Total		2,776		2,616		2,591

Year-to-date (“YTD”) Electric Sales Volumes GWh
	2011		2010		2009
Residential		2,410		2,277		2,348
Commercial		1,601		1,571		1,590
Industrial		1,998		1,903		1,726
Other		158		155		173
Total		6,167		5,906		5,837

Electricity Pricing (“rates”)

Electric revenues are summarized in the following tables by customer class:

Q2 Electric Revenues millions of Canadian dollars
	2011		2010		2009
Residential	$	129.1	$	115.8	$	120.8
Commercial		80.8		76.7		77.5
Industrial		73.1		64.9		65.2
Other		10.2		9.6		9.9
Total	$	293.2	$	267.0	$	273.4

YTD Electric Revenues millions of Canadian dollars
	2011		2010		2009
Residential	$	314.3	$	288.1	$	300.0
Commercial		176.0		165.1		170.6
Industrial		144.8		131.1		129.1
Other		21.5		20.2		21.5
Total	$	656.6	$	604.5	$	621.2

Electric revenues increased $26.2 million to $293.2 million in Q2 2011 compared to $267.0 million in Q2 2010. Year-to-date, electric revenues increased $52.1 million to $656.6 million in 2011 from $604.5 million in 2010. Highlights of the changes are summarized in the following table:

millions of Canadian dollars	Three months ended June  30		Six months ended June  30
Electric revenues – 2010	$	267.0	$	604.5
Increased fuel related electricity pricing effective January 1, 2011		12.7		28.4
Increased residential sales volumes in the quarter. Increased residential and commercial sales volumes year-to-date.		9.3		17.9
Increased industrial sales volume		4.0		5.3
Other		0.2		0.5
Electric revenues – 2011	$	293.2	$	656.6

NSPI distinguishes revenues related to the recovery of fuel costs (“fuel electric revenues”) from revenues related to the recovery of non-fuel costs (“non-fuel electric revenues”) because the FAM introduced on January 1, 2009 enables NSPI to seek recovery of fuel costs through regularly scheduled rate adjustments. Differences between actual fuel costs and amounts recovered from customers through electricity rates in a period are deferred to a FAM regulatory asset or liability and recovered from or

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returned to customers in a subsequent period. Consequently, fuel electric revenues and fuel costs do not have a material effect on NSPI’s electric margin or net income, with the exception of the incentive component of the FAM, whereby NSPI retains or absorbs 10 percent of the over or under recovered amount to a maximum of $5 million.

As fuel costs are recovered through the FAM, electric margin and net income are influenced primarily by revenues relating to non-fuel costs. NSPI’s customer classes contribute differently to the Company’s non-fuel electric revenues with residential and commercial customers contributing more than industrials. Accordingly, changes in residential and commercial load, largely due to weather, have the largest effect on non-fuel electric revenues. Changes in industrial load, which are generally due to economic conditions, do not have as significant an effect on non-fuel electric revenues.

Electric margin is summarized in the following table:

millions of Canadian dollars	Three months ended June 30						Six months ended June 30
	2011			2010			2011			2010
Fuel electric revenues – current year	$	126.1		$	116.9		$	281.3		$	265.6
Fuel electric revenues – preceding periods		6.4			(5.1	)		14.6			(11.5	)
Non-fuel electric revenues		160.7			155.2			360.7			350.4
Total electric revenues		293.2			267.0			656.6			604.5
Fuel for generation and purchased power, including affiliates		(125.8	)		(124.3	)		(294.4	)		(305.5	)
Fuel adjustment		(6.2	)		12.6			(0.4	)		52.0
Other fuel related costs		(2.0	)		(0.9	)		(3.9	)		(3.7	)
Electric margin	$	159.2		$	154.4		$	357.9		$	347.3

NSPI’s electric margin increased $4.8 million to $159.2 million in Q2 2011 compared to $154.4 million in Q2 2010 due primarily to increased residential sales as a result of load growth and colder weather. Year-to-date, NSPI’s electric margin increased $10.6 million to $357.9 million in 2011 compared to $347.3 million in 2010 due primarily to increased residential and commercial sales as a result of load growth and colder weather.

Q2 Average Electric Margin / Megawatt hour (“MWh”)

	2011		2010		2009
Dollars per MWh	$	57	$	59	$	61

YTD Average Electric Margin / MWh

	2011		2010		2009
Dollars per MWh	$	58	$	59	$	61

The change in Q2 and year-to-date average electric margin per MWh in 2011 compared to 2010 reflects a change in sales mix.

Fuel for Generation and Purchased Power (including affiliates)

Q2 Production Volumes GWh
	2011		2010		2009
Coal and petcoke		1,436		1,645		1,956
Natural gas		668		578		356
Oil		3		4		18
Renewables		393		237		287
Purchased power		394		268		107
Total		2,894		2,732		2,724

Purchased power includes 178 GWh of renewables in Q2 2011 (2010 – 128 GWh; 2009 – 66 GWh).

YTD Production Volumes GWh
	2011		2010		2009
Coal and petcoke		3,653		3,944		4,333
Natural gas		1,329		1,228		660
Oil		26		10		280
Renewables		808		523		600
Purchased power		665		489		312
Total		6,481		6,194		6,185

Purchased power includes 360 GWh of renewables in 2011 (2010 – 237 GWh; 2009 – 146 GWh).

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Q2 Average Unit Fuel Costs

	2011		2010		2009
Dollars per MWh	$	43	$	45	$	37

YTD Average Unit Fuel Costs

	2011		2010		2009
Dollars per MWh	$	45	$	49	$	40

Fuel for generation and purchased power, including affiliates increased $1.5 million to $125.8 million in Q2 2011 compared to $124.3 million in Q2 2010. Year-to-date, fuel for generation and purchased power, including affiliates decreased $11.1 million to $294.4 million in 2011 compared to $305.5 million in 2010. Highlights of the changes are summarized in the following table:

millions of Canadian dollars	Three months ended June 30			Six months ended June 30
Fuel for generation and purchased power, including affiliates – 2010	$	124.3		$	305.5
Decreased commodity prices		(14.5	)		(28.2	)
Increased hydro and wind production		(7.9	)		(18.1	)
Favourable solid fuel commodity mix and additives related to emission compliance		(4.4	)		(14.4	)
Changes in generation mix and plant performance		10.0			18.5
Increased sales volume		8.2			15.9
Valuation of contract receivable (see discussion below)		10.3			15.7
Other		(0.2	)		(0.5	)
Fuel for generation and purchased power, including affiliates – 2011	$	125.8		$	294.4

Through Q4, 2010, NSPI had a long-term contract receivable with a natural gas supplier that was required to be fair-valued. The natural gas supply contract settled in November 2010.

Fuel Adjustment

In December 2010, as part of the FAM regulatory process, the UARB approved NSPI’s setting of the 2011 base cost of fuel and the under-recovered fuel related costs from prior years. The UARB approved the recovery of the prior year FAM balance from customers over three years, effective January 1, 2011, with 50 percent to be recovered in 2011, 30 percent in 2012 and 20 percent in 2013.

The FAM regulatory asset or liability includes amounts recognized as a fuel adjustment and associated interest included in “Interest expense - net”.

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

millions of Canadian dollars	2011
FAM regulatory asset – Balance at January 1	$	92.9
Under-recovery of current period fuel costs		14.2
Recovery from customers of prior periods fuel costs		(14.6	)
Interest revenue on FAM balance		3.9
FAM regulatory asset – Balance at June 30	$	96.4

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OUTLOOK

Business Environment

Economic Environment

NSPI will continue to pursue investment opportunities related to the transformation of the energy industry to lower emissions. NSPI 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 less carbon intensive energy sources.

Environmental Legislation

NSPI is subject to environmental regulations as set by both the Province of Nova Scotia and the Government of Canada. The Company continues to work with officials at both levels of government so as to comply with these regulations in an integrated way.

Operations

NSPI anticipates earning a regulated ROE within its allowed range in 2011. NSPI continues to implement its strategy, which is focused on regulated investments in renewable energy and system reliability projects with an annual capital expenditure plan of approximately $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 volumes and revenues among customer classes. Circumstances that could affect the Company’s ability to generate cash include general economic downturns in our markets, the loss of one or more large customers, regulatory decisions affecting customer rates and changes in environmental legislation.

In addition to internally generated funds, NSPI has access to a $600 million committed syndicated revolving bank line of credit. NSPI has an active commercial paper program for up to $400 million, of which outstanding amounts are 100 percent backed by the Company’s bank lines referred to above, and this results in an equal amount of credit being considered drawn and unavailable.

As at June 30, 2011, the outstanding short-term debt is as follows:

millions of Canadian dollars	Maturity		Credit Line Committed		Utilized		Undrawn and available
Operating credit facility		June 2013 – Revolver	$	600	$	307	$	293

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

In May 2011, NSPI filed an amendment to its amended and restated short form base shelf prospectus and an amendment to its prospectus supplement for medium-term notes (unsecured). These amendments increased the aggregate principal amount of debt securities and medium-term notes that may be offered from time to time under the short form base shelf prospectus and prospectus supplement (respectively) from $500 million to $800 million. To date, $300 million in medium-term notes have been issued under NSPI’s short form base shelf prospectus and prospectus supplement since their initial filing in 2010.

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Concurrently with the Canadian filing of these amendments, NSPI also filed a registration statement on Form F-9 with the U.S. Securities and Exchange Commission to register debt securities having an aggregate initial offering price of up to $500 million for sale in the United States.

TRANSACTIONS WITH RELATED PARTIES

The Company enters into transactions with related parties in the normal course of operations. All related party transactions with NSPI are governed by an affiliate Code of Conduct that is approved by the UARB.

NSPI, Emera Energy Services (“EES”), Bangor Hydro Electric Company (“Bangor Hydro”) and Emera Utility Services (“EUS”) are wholly owned subsidiaries of Emera Incorporated (“Emera”). Emera owns a 12.9 percent interest in the Maritimes & Northeast Pipeline (“M&NP”).

Related party transactions are summarized in the following table:

For the millions of Canadian dollars			Three months ended June  30				Six months ended June  30
	Nature of Service	Presentation	2011		2010		2011		2010
Sales:
EUS	Steam sales	Operating revenues		—		—	$	0.2	$	0.1
Emera	Corporate support and other services	Operating, maintenance and general	$	0.6	$	0.8		1.4		1.6
EES	Corporate support and other services	Operating, maintenance and general		0.3		0.3		0.6		0.6
Bangor Hydro	Corporate support and other services	Operating, maintenance and general		0.3		0.3		0.5		0.5
Other	Corporate support and other services	Operating, maintenance and general		0.2		0.1		0.6		0.4
Purchases:
EES	Net purchase of electricity	Fuel for generation and purchased power – affiliates		—		4.7		—		5.7
EES	Net purchase of natural gas	Fuel for generation and purchased power – affiliates		0.4		0.1		0.1		0.7
EUS	Maintenance services	Operating, maintenance and general		0.9		0.1		5.0		0.6
EUS	Purchase of inventory	Inventory		0.1		0.4		0.4		0.7
EUS	Construction services	Property, plant and equipment		3.6		11.8		5.8		14.8

Beginning in Q2 2011, NSPI has recorded the impact of two agreements related to the purchase of power and receipt of contract revenues from Emera on a net basis on the statements of income. Under the agreements, NSPI purchased power from Emera and received contract revenues from Emera of $2.5 million (2010 – nil) for the three months ended June 30, 2011 and $4.9 million (2010 – nil) for the six months ended June 30, 2011. Prior interim periods have been reclassified to reflect this change.

In the ordinary course of business, the Company purchased $4.1 million (2010 – $4.8 million) in natural gas transportation capacity from M&NP during the three months ended June 30, 2011, and $8.3 million (2010 - $9.2 million) for the six months ended June 30, 2011. The amount is recognized in “Fuel for generation and purchased power” and is measured at the exchange amount. As at June 30, 2011, the amount payable to M&NP is $1.5 million (December 31, 2010 – $1.0 million) and is under normal interest and credit terms.

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During the three months ended June 30, 2011, the Company issued nil common shares (2010 – 5.0 million) to Emera and an affiliate under common control of Emera for total consideration of nil (2010 - $50.0 million). During the six months ended June 30, 2011, the Company issued 5.0 million (2010 – 5.0 million) common shares to Emera and an affiliate under common control of Emera for total consideration of $50.0 million (2010 - $50.0 million).

On May 28, 2010, NSPI purchased $30.1 million in wind generation assets under development related to the Digby Wind Project from a subsidiary of Emera. This transaction was measured at the carrying amount of the assets transferred. As at June 30, 2011 and December 31, 2010, there were no amounts due.

Amounts due (to) from associated companies are summarized in the following table:

As at millions of Canadian dollars	June 30 2011			December 31 2010 (adjusted)
Due from associated companies:
EES		—		$	0.7
Emera	$	1.6			—
		1.6			0.7
Due to associated companies:
EUS		(1.6	)		(5.5	)
EES		(0.4	)		—
Emera		—			(1.4	)
		(2.0	)		(6.9	)
Net due to associated companies	$	(0.4	)	$	(6.2	)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

NSPI’s risk management policies and procedures provide a framework through which management monitors various risk exposures. The risk management plan has been approved by the Board of Directors. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group which is independent of all operations.

The Company manages its exposure to normal operating and market risks relating to commodity price and foreign exchange risks using financial instruments consisting mainly of foreign exchange forwards and swaps, and coal, oil and gas options and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas, and physical and financial contracts. Collectively these contracts are considered “derivatives”.

The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. The Company continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts where the criteria are no longer met.

Derivatives entered into by NSPI that are documented as economic hedges, and for which the NPNS exception has not been taken, receive regulatory deferral as approved by the UARB. These derivatives are recorded at fair value on the balance sheet. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized when the derivatives settle. Management believes that any gains or losses resulting from settlement of these derivatives will be refunded to or collected from customers in future rates.

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Regulatory Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheets related to derivatives receiving regulatory deferral:

millions of Canadian dollars	June 30 2011			December 31 2010 (adjusted)
Derivative instrument assets (including current and other assets)	$	48.3		$	59.9
Regulatory assets (including current and other assets)		37.3			34.2
Derivative instrument liabilities (including current and long-term liabilities)		(37.3	)		(34.2	)
Regulatory liabilities (including current and long-term liabilities)		(48.3	)		(59.9	)
		—			—

Regulatory Impact Recognized in Net Income

The Company recognized in net income the following net losses related to derivatives receiving regulatory deferral:

	Three months ended						Six months ended
millions of Canadian dollars	June 30						June 30
	2011			2010 (adjusted)			2011			2010 (adjusted)
Other expenses, net increase		—		$	(2.0	)		—		$	(1.0	)
Fuel for generation and purchased power increase	$	(1.3	)		(8.1	)	$	(16.9	)		(45.2	)
Total losses	$	(1.3	)	$	(10.1	)	$	(16.9	)	$	(46.2	)

DISCLOSURE AND INTERNAL CONTROLS

The Company, under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, have designed as at June 30, 2011 disclosure controls and procedures (“DC&P”) and internal controls over financial reporting (“ICFR”) as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”).

Pursuant to Section 404(c) of the Sarbanes-Oxley Act of 2002 (“SOX”), as added by Section 989G of the Dodd-Frank Wall Street Reform and Consumer Protection Act, the requirement under Section 404(b) of SOX to file an auditor attestation report on an issuer’s ICFR does not apply with respect to any audit report prepared for an issuer that is neither an accelerated filer nor a large accelerated filer, as defined in Rule 12b-2 under the United States Securities Exchange Act of 1934, as amended. NSPI is currently not an accelerated filer or a large accelerated filer and therefore is not required to file an attestation report on its ICFR.

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SUMMARY OF QUARTERLY RESULTS

For the quarter ended millions of Canadian dollars	Q2 2011		Q1 2011		Q4 2010 (adjusted)		Q3 2010 (adjusted)		Q2 2010 (adjusted)		Q1 2010 (adjusted)		Q4 2009 (adjusted)		Q3 2009 (adjusted)
Total operating revenues	$	299.0	$	368.8	$	303.2	$	272.2	$	273.2	$	342.8	$	309.3	$	269.7
Net income attributable to common shareholders		16.7		63.6		19.9		18.6		15.5		65.2		17.7		16.7

Quarterly total operating revenues and net income attributable to common shareholders are affected by seasonality, with Q1 and Q4 the strongest periods, reflecting colder weather and fewer daylight hours at those times of year.

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