Edgar Filing: North American Energy Partners Inc.

Form 6-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K/A

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16

under the Securities Exchange Act of 1934

For the month of August 2010

Commission File Number 001-33161

NORTH AMERICAN ENERGY PARTNERS INC.

Zone 3 Acheson Industrial Area

2-53016 Highway 60

Acheson, Alberta

Canada T7X 5A7

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F ¨ Form 40-F x

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨

Explanatory Note

This Form 6-K/A is being furnished to reflect the correction of information included under the heading “Backlog” in the Management’s Discussion and Analysis for the three months ended June 30, 2010 that was included in North American Energy Partners Inc.’s (“the Company”) Form 6-K furnished on August 4, 2010. The information in this Form 6-K/A has not been updated from such Form 6-K except to reflect such correction and does not include the interim consolidated financial statements or Canadian supplement to Management’s Discussion and Analysis that were included in the original filing. Additionally, this Form 6-K/A does not purport to provide an update or a discussion of any other developments at the Company subsequent to the original filing.

Documents Included as Part of this Report

1.	Revised Management’s Discussion and Analysis for the three months ended June 30, 2010.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


NORTH AMERICAN ENERGY PARTNERS INC.

By:		/s/ David Blackley
Name:		David Blackley
Title:		Chief Financial Officer

Date: August 5, 2010

NORTH AMERICAN ENERGY PARTNERS INC.

Revised Management’s Discussion and Analysis

For the three months ended June 30, 2010

LOGO

TABLE OF CONTENTS


A.	Explanatory Notes	3
	Caution Regarding Forward-Looking Information	3
	Non-GAAP Financial Measures	3
	Adoption of United States GAAP	4
B.	Financial results	5
	Analysis of Consolidated Results	5
	Segment Results	6
	Non-Operating Income and Expense	7
	Backlog	9
	Claims and Change Orders	9
	Summary of Consolidated Quarterly Results	10
	Summary of Consolidated Financial Position	11
	Summary of Consolidated Cash Flows	12
C.	Outlook	12
D.	Legal and Labour Matters	13
	Laws and Regulations and Environmental Matters	13
	Employees and Labour Relations	13
E.	Resources and Systems	13
	Outstanding Share Data	13
	Liquidity and Capital Resources	13
	Capital Commitments	17
	Debt Ratings	17
	Related Parties	18
	Internal Systems and Processes	19
	Recently Adopted Accounting Policies	19
	Recent Accounting Pronouncements Not Yet Adopted	19
F.	Forward-Looking Information and Risk Factors	20
	Forward-Looking Information	20
	Risk Factors	22
	Quantitative and Qualitative Disclosures about Market Risk	22
G.	General Matters	22
	Additional Information	22

2 Management’s Discussion and Analysis North American Energy Partners Inc.

Revised Management’s Discussion and Analysis

Management’s Discussion and Analysis for the three months ended June 30, 2010 has been refiled to reflect a correction of the backlog figures on page 9.

For the three months ended June 30, 2010

A. Explanatory Notes

August 5, 2010

The following Management’s Discussion and Analysis (MD&A) for the three months ended June 30, 2010 should be read in conjunction with the attached unaudited consolidated financial statements and accompanying notes for the three months ended June 30, 2010. These statements have been prepared in accordance with United States (US) generally accepted accounting principles (GAAP). This interim MD&A should also be read in conjunction with the audited consolidated financial statements for the year ended March 31, 2010, together with our annual MD&A for the year ended March 31, 2010. The consolidated financial statements and additional information relating to our business, including our most recent Annual Information Form (AIF), are available on the Canadian Securities Administrators’ SEDAR System at www.sedar.com, the Securities and Exchange Commission’s website at www.sec.gov and our company web site at www.nacg.ca.

Caution Regarding Forward-Looking Information

Our MD&A is intended to enable readers to gain an understanding of our current results and financial position. To do so, we provide information and analysis comparing results of operations and financial position for the current period to those of the preceding periods. We also provide analysis and commentary that we believe is necessary to assess our future prospects. Accordingly, certain sections of this report contain forward-looking information that is based on current plans and expectations. This forward-looking information is affected by risks and uncertainties that could have a material impact on future prospects. Please refer to “Forward-Looking Information and Risk Factors” for a discussion of the risks and uncertainties related to such information. Readers are cautioned that actual events and results may vary.

Non-GAAP Financial Measures

The body of generally accepted accounting principles applicable to us is commonly referred to as “GAAP”. A non-GAAP financial measure is generally defined by the Securities and Exchange Commission (SEC) and by the Canadian securities regulatory authorities as one that purports to measure historical or future financial performance, financial position or cash flows but excludes or includes amounts that would not be so adjusted in the most comparable GAAP measures. In our MD&A, we use non-GAAP financial measures such as “net income before interest expense, income taxes, depreciation and amortization” (EBITDA) and “Consolidated EBITDA” (as defined in our credit agreement). Consolidated EBITDA is defined as EBITDA, excluding the effects of unrealized foreign exchange gain or loss, realized and unrealized gain or loss on derivative financial instruments, non-cash stock-based compensation expense, gain or loss on disposal of plant and equipment and certain other non-cash items included in the calculation of net income. We believe that EBITDA is a meaningful measure of the performance of our business because it excludes items, such as depreciation and amortization, interest and taxes that are not directly related to the operating performance of our business. Management reviews EBITDA to determine whether plant and equipment are being allocated efficiently. In addition, our credit facility requires us to maintain a minimum interest coverage ratio and a maximum senior leverage ratio, which are calculated using Consolidated EBITDA. Non-compliance with these financial covenants could result in our being required to immediately repay all amounts outstanding under our credit facility. As EBITDA and Consolidated EBITDA are non-GAAP financial measures, our computations of EBITDA and Consolidated EBITDA may vary from others in our industry. EBITDA and Consolidated EBITDA should not be considered as alternatives to operating income or net income as measures of operating performance or cash flows as measures of liquidity. EBITDA and Consolidated EBITDA have important limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under US GAAP or Canadian GAAP. For example, EBITDA and Consolidated EBITDA do not:

_Ÿ

reflect our cash expenditures or requirements for capital expenditures or capital commitments;

_Ÿ

reflect changes in our cash requirements for our working capital needs;

_Ÿ

reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;

_Ÿ

include tax payments that represent a reduction in cash available to us; and

_Ÿ

reflect any cash requirements for assets being depreciated and amortized that may have to be replaced in the future.

Consolidated EBITDA excludes unrealized foreign exchange gains and losses and realized and unrealized gains and losses on derivative financial instruments, which, in the case of unrealized losses, may ultimately result in a liability that will need to be paid and in the case of realized losses, represents an actual use of cash during the period. Where relevant, particularly for earnings-based measures, we provide tables in this document that reconcile non-GAAP measures used to amounts reported on the face of the consolidated financial statements.

North American Energy Partners Inc. Management’s Discussion and Analysis 3

Adoption of United States GAAP

As a Canadian based company, we have historically prepared our consolidated financial statements in accordance with Canadian GAAP and provided reconciliations to United States (US) GAAP. In 2006, the Canadian Accounting Standards Board (“AcSB”) published a new strategic plan that significantly affected financial reporting requirements for Canadian public companies. The AcSB strategic plan outlined the convergence of Canadian GAAP with International Financial Reporting Standards (IFRS) over an expected five-year transitional period. In February 2008, the AcSB confirmed that IFRS would be mandatory in Canada for profit-oriented publicly accountable entities for fiscal periods beginning on or after January 1, 2011, unless we, as a Securities and Exchange Commission (SEC) registrant and as permitted by National Instrument 52-107, were to adopt US GAAP on or before this date.

After significant analysis and consideration regarding the merits of reporting under IFRS or US GAAP, we decided to adopt US GAAP, commencing in fiscal 2010, as our primary reporting standard for our consolidated financial statements. Our interim consolidated financial statements for the three months ended June 30, 2009, including related notes and accompanying MD&A, were restated based on US GAAP on June 10, 2010 and are available on the Canadian Securities Administrators’ SEDAR System at www.sedar.com, the Securities and Exchange Commission’s website at www.sec.gov and our company web site at www.nacg.ca. All comparative figures contained in our current interim consolidated financial statements for the three months ended June 30, 2010, including related notes and this MD&A, reflect our results in accordance with US GAAP as our reporting standard.

As required by National Instrument 52-107, for the fiscal year of adoption of US GAAP and one subsequent fiscal year, we will provide a Canadian Supplement to our MD&A that restates, based on financial information reconciled to Canadian GAAP, those parts of our MD&A that would contain material differences if they were based on financial statements prepared in accordance with Canadian GAAP. In support of the adoption of US GAAP commencing in fiscal 2010 we provided a Canadian Supplement MD&A for our audited consolidated financial statements, related notes and accompanying MD&A, for the year ended March 31, 2010. As well, we provided a Canadian Supplement MD&A for each of the restated interim periods for fiscal 2010. The Canadian Supplement MD&A will continue to be provided through fiscal 2011 for each of the reporting periods.

4 Management’s Discussion and Analysis North American Energy Partners Inc.

B. Financial results

Consolidated Three Month Results


	Three months ended June 30,
(dollars in thousands)	2010		% of Revenue	2009	% of Revenue	Change
Revenue	$183,594		100.0%	$146,519	100.0%	$37,075
Project costs	77,277		42.1%	54,262	37.0%	23,015
Equipment costs	65,003		35.4%	46,044	31.4%	18,959
Equipment operating lease expense	17,491		9.5%	12,349	8.4%	5,142
Depreciation	8,203		4.5%	8,724	6.0%	(521	)

Gross profit	15,620		8.5%	25,140	17.2%	(9,520	)
General and administrative costs	13,729		7.5%	14,976	10.2%	(1,247	)

Operating income	1,064		0.6%	10,138	6.9%	(9,074	)
Net (loss) income	$(10,309	)	(5.6)%	$9,927	6.8%	$(20,236	)
Per share information
Net (loss) income – basic	(0.29	)		0.28		(0.57	)
Net (loss) income – diluted	(0.29	)		0.27		(0.56	)
EBITDA⁽¹⁾	4,198		2.3%	28,237	19.3%	(24,039	)
Consolidated EBITDA⁽¹⁾ (as defined within our credit agreement)	$12,179		6.6%	$19,394	13.2%	$(7,215	)

⁽¹⁾	A reconciliation of net (loss) income to EBITDA and Consolidated EBITDA is as follows:


	Three months ended June 30,
(dollars in thousands)	2010		2009		Change
Net (loss) income	$(10,309	)	$9,927		$(20,236	)
Adjustments:
Interest expense	7,729		6,552		1,177
Income taxes (benefit)	(2,013	)	2,541		(4,554	)
Depreciation	8,203		8,724		(521	)
Amortization of intangible assets	588		493		95

EBITDA	$4,198		$28,237		$(24,039	)
Adjustments:
Unrealized foreign exchange gain on senior notes	–		(19,540	)	19,540
Realized and unrealized loss on derivative financial instruments	3,008		10,021		(7,013	)
Gain on disposal of property, plant and equipment and assets held for sale	(4	)	(276	)	272
Stock-based compensation expense	410		1,143		(733	)
Equity in loss (earnings) of unconsolidated joint venture	243		(191	)	434
Loss on debt extinguishment	4,324		–		4,324

Consolidated EBITDA (as defined within our credit agreement)	$12,179		$19,394		$(7,215	)

Analysis of Consolidated Results

Revenue

For the three months ended June 30, 2010, consolidated revenues of $183.6 million were $37.1 million higher than in the same period last year. As anticipated, recurring services grew during the quarter, reflecting higher activity on our long-term contract with Canadian Natural¹ and increased demand for mine support services from Syncrude² and Suncor³. These gains were partially offset by reduced activity at Shell Albian’s⁴ Muskeg River operation, which was shut down during the period in preparation for maintenance and the transition to production at the Jackpine Mine.

The improvement in consolidated revenues was further supported by an increase in Piling segment revenues which benefited from increased commercial and industrial construction market activity during the quarter. These gains were made despite abnormally high precipitation levels in Western Canada during the spring break-up period which delayed some piling work to future periods.

¹	Canadian Natural Resources Limited (Canadian Natural) Horizon project

Syncrude Canada Ltd. (Syncrude) – a joint venture amongst Canadian Oil Sands Limited (37%), Imperial Oil Resources (25%), Suncor Energy Inc. (formerly Petro-Canada Oil and Gas) (12%), Sinopec International Petroleum Exploration and Production Company (SIPC) (9%), Nexen Oil Sands Partnership (7%), Murphy Oil Company Ltd. (5%) and Mocal Energy Limited (5%). SIPC purchased the Syncrude interest of ConocoPhillips Oil Sands Partnership II on June 25, 2010.

³	Suncor Energy Inc. (Suncor)

⁴

Shell Canada Energy, a division of Shell Canada Limited, the operator of the Shell Albian Sands’ (Shell Albian) oils sands mining and extraction operations on behalf of Athabasca Oil Sands Project (AOSP), a joint venture amongst Shell Canada Limited (60%), Chevron Canada Limited (20%) and Marathon Oil Canada Corporation (20%). Prior to January 1, 2009, these operations were run by Albian Sands Energy Inc.

North American Energy Partners Inc. Management’s Discussion and Analysis 5

Gross Profit

Gross profit for the three months ended June 30, 2010 was $15.6 million (8.5% of revenue), compared to $25.1 million (17.2% of revenue) in the prior period. The decline in gross profit reflects a $2.3 million reduction in profit on our long-term overburden removal contract resulting from the negative impact of a weaker Canadian dollar on the value of the contract. Consolidated gross profit was also negatively affected by higher equipment costs due to increased repair maintenance activity during the longer than usual spring break-up period as well as by reduced margins in our Piling segment due to delays in executing a higher than normal amount of change orders.

Project costs, as a percentage of revenue, increased to 42.1% during the three months ended June 30, 2010, from 37.0% in the same period last year while equipment costs increased to 35.4% of revenue, from 31.4% last year, reflecting the negative margin effect of a longer than usual spring break-up period and an increase in scheduled major overhaul maintenance work on our leased fleet. Equipment operating lease expense increased $5.1 million to $17.5 million as a result of new operating leases added during the prior fiscal year to support our long-term overburden removal contract. Depreciation decreased to 4.5% of revenue in the three months ended June 30, 2010, from 6.0% of revenue in the same period last year. Depreciation in the prior-year period included an accelerated depreciation charge of $1.8 million as certain aged equipment was prepared for sale.

Operating income

For the three months ended June 30, 2010, we recorded operating income of $1.1 million (0.6% of revenue) compared to an operating income of $10.1 million (6.9% of revenue) during the same period last year. General and administrative (G&A) costs decreased by $1.2 million year-over-year, with prior-year period G&A costs negatively affected by the valuation of our deferred performance share units and director share units, as a result of increases in our share price.

Net (loss) income

We recorded a net loss of $10.3 million (basic and diluted loss per share of $0.29) for the three months ended June 30, 2010, compared to net income of $9.9 million (basic income per share of $0.28 and diluted income per share of $0.27) during the same period last year. The non-cash items affecting results in the most recent period included a loss related to the write-off of deferred financing costs on the extinguishment of our 8³/4% senior notes and a loss relating to embedded derivatives in long-term supplier contracts. These items were partially offset by a realized foreign exchange gain resulting from the extinguishment of our 8³/4% senior notes and a gain relating to embedded derivatives in a long-term customer contract. Net income for the same period last year was positively affected by the positive foreign exchange impact of the strengthening Canadian dollar on our 8³/4% senior notes, a gain related to embedded derivatives in an early redemption option on our 8³/4% senior notes and a gain relating to embedded derivatives in long-term supplier contracts, which was partially offset by a loss on our cross-currency and interest rate swaps and a loss relating to embedded derivatives in a long-term customer contract. Excluding the above items, net loss for the three months ended June 30, 2010 would have been $4.1 million (basic and diluted loss per share of $0.11), compared to net income of $0.1 million (basic and diluted income per share of $nil) during the same period last year.

Segment Results

Heavy Construction and Mining


	Three months ended June 30,
(dollars in thousands)	2010	2009	Change
Segment revenue	$163,609	$131,826	$31,783
Segment profit	22,247	23,514	(1,267	)
Profit margin	13.6%	17.8%

For the three months ended June 30, 2010, Heavy Construction and Mining segment revenues increased $31.8 million, to $163.6 million, primarily as a result of increased recurring services revenue. The growth in recurring services revenue was driven by a return to planned operational levels on our long-term overburden removal contract at Canadian Natural and increased mining services provided to Syncrude, under our extended master services agreement. We also increased activity levels at Suncor’s site under a new mining service agreement that includes additional scope. The recurring services gains were partially offset by lower activity levels at Shell Albian’s sites as a result of the shutdown of the Muskeg River site for maintenance and in preparation for the transition to production at the Jackpine mine. Project development revenues also increased in the current period as a result of a construction project executed for Exxon’s Kearl⁵ project.

For the three months ended June 30, 2010, Heavy Construction and Mining profit margin was 13.6% of revenue, compared to 17.8% of revenue during the same period last year. This change primarily reflects a $2.3 million foreign exchange-related reduction in profit forecast for our long-term overburden removal contract. In the prior year we recorded a $4.0 million profit increase in our forecast for this same project as a result of an increase in the strength of the Canadian dollar. Contributing to the reduced segment profit was lower project efficiency during the longer than normal spring break-up period.

⁵	Exxon’s Kearl project is a joint venture oil sands mining and extraction project. Imperial Oil Limited holds a 70.96% interest in the joint venture with ExxonMobil Canada Properties, a subsidiary of Exxon Mobil Corporation (Exxon). Imperial Oil Limited is the project operator.

6 Management’s Discussion and Analysis North American Energy Partners Inc.

Piling


	Three months ended June 30,
(dollars in thousands)	2010	2009	Change
Segment revenue	$19,146	$14,618	$4,528
Segment profit	1,394	2,684	(1,290	)
Profit margin	7.3%	18.4%

For the three months ended June 30, 2010, the Piling segment recorded revenues of $19.1 million, an increase of $4.5 million over the same period last year. The improvement in Piling segment revenue reflects a partial recovery in activity levels in the commercial and industrial construction markets. These gains were made despite abnormally high precipitation levels in Western Canada which delayed some piling work to future periods.

For the three months ended June 30, 2010, Piling profit margin decreased to 7.3% of revenue, from 18.4% of revenue a year ago. This decline reflects the delay in the execution of a higher than normal amount of change orders to future periods. Contributing to the lower margins for the current period was a larger than normal amount of equipment tooling costs and the effect of the abnormally high precipitation levels on project efficiency.

Pipeline


	Three months ended June 30,
(dollars in thousands)	2010		2009		Change
Segment revenue	$839		$75		$764
Segment (loss) profit	(723	)	367		(1,090	)
(Loss) profit margin	(86.2	)%	489.3	%

For the three months ended June 30, 2010, the Pipeline segment increased revenues to $0.8 million, from $0.1 million a year ago reflecting the partial resumption of work on a contract in British Columbia during the period.

For the three months ended June 30, 2010, the Pipeline segment recorded a loss of $0.7 million compared to a profit of $0.4 million during the same period last year. The loss in the current period was the result of fixed project costs incurred during a temporary shutdown of work on a contract in British Columbia.

Non-Operating Income and Expense


	Three months ended June 30,
(dollars in thousands)	2010		2009		Change
Interest expense
Long-term debt
Interest on 8 ³/4% senior notes and swaps	1,147		5,144		(3,997	)
Interest on series 1 debentures	4,734		—		4,734
Interest on term facilities	1,057		165		892
Interest on capital lease obligations	208		291		(83	)
Amortization of deferred financing costs	526		805		(279	)

Interest on long-term debt	7,672		6,405		1,267
Other interest	57		147		(90	)

Total interest expense	$7,729		$6,552		$1,177
Foreign exchange gain	(1,697	)	(19,436	)	17,739
Realized and unrealized loss on derivative financial instruments	3,008		10,021		(7,013	)
Other expense	—		533		(533	)
Income taxes (benefit)	(2,013	)	2,541		(4,554	)

Interest expense

Total interest expense increased $1.2 million in the three months ended June 30, 2010, compared to the prior year. In April 2010, we closed a private placement of 9.125% Series 1 Debentures due April 7, 2017 for gross proceeds of $225.0 million. On March 29, 2010, we issued a redemption notice to holders of the 8³/4% senior notes to redeem all outstanding 8³/4% senior notes and, on April 28, 2010, the notes were redeemed and cancelled. The redemption amount included the US$200.0 million principal outstanding and US$7.1 million of accrued interest. On April 8, 2010, we terminated the cross currency and interest rate swaps used to provide an economic hedge on the US dollar denominated 8³/4% senior notes. Interest expense on our 8³/4% senior notes of $1.1 million reflects the amount of interest for the current period until redemption was complete. Interest expense of $4.7 million for the new Series 1 Debentures reflects interest for the partial period that followed the issuance of the Series 1 Debentures on April 7, 2010. The redemption and associated swap agreement terminations eliminate the refinancing risk in December 2011. A more detailed discussion on the restructuring of our long-term debt can be found under “Liquidity and Capital Resources”.

North American Energy Partners Inc. Management’s Discussion and Analysis 7

On April 30, 2010, we also entered into a fourth amended and restated credit agreement to extend the term of the credit agreement and to add additional borrowing capacity of up to $50.0 million through a second term facility within the credit agreement. At June 30, 2010, the second term facility was fully drawn at $50.0 million. The new term facility, along with the existing term facility, matures on April 30, 2013. At June 30, 2010, we had $75.9 million outstanding on the Term Facility ($28.4 million at March 31, 2010). Interest expense for the credit facility, for the three months ended June 30, 2010 was $1.1 million, an increase of $0.9 million compared to the prior year.

Foreign exchange gain

The foreign exchange gains recognized in the current and prior year three-month periods relate primarily to the effect of changes in the exchange rate of the Canadian dollar against the US dollar on the carrying value of the US$200 million 8³/4% senior notes. The increase in the value of the Canadian dollar, from 0.9846 CAN/US at March 31, 2010 to 0.9874 CAN/US at April 28, 2010 when the 8³/4% senior notes were redeemed, resulted in a realized foreign exchange gain. A more detailed discussion about our foreign currency risk can be found under “Quantitative and Qualitative Disclosures about Market Risk – Foreign exchange risk”.

Realized and unrealized loss (gain) on derivative financial instruments

The realized and unrealized loss (gain) on derivative financial instruments reflect changes in the fair value of derivatives embedded in our previously held US dollar denominated 8³/4% senior notes, as well as changes in the fair value of the cross-currency and interest rate swaps that we employed to provide an economic hedge for our previously held US dollar denominated 8³/4% senior notes. Realized and unrealized gains and losses also include changes in the value of embedded derivatives in a long-term customer contract and in supplier maintenance agreements. The realized and unrealized gains and losses on these derivative financial instruments, for the three months ended June 30, 2010 are detailed in the table below:


	Three months ended June 30,
(dollars in thousands)	2010		2009		Change
Swap liability loss	$1,783		$19,835		$(18,052	)
Redemption option embedded derivative gain	–		(2,273	)	2,273
Supplier contracts embedded derivatives loss (gain)	1,647		(14,164	)	15,811
Customer contract embedded derivative (gain) loss	(750	)	3,287		(4,037	)
Swap interest payment	328		3,336		(3,008	)

Total	$3,008		$10,021		$(7,013	)

The measurement of embedded derivatives, as required by GAAP, causes our reported net income to fluctuate as Canadian/US dollar exchange rates, interest rates and the US-PPI for Mining Machinery and Equipment change. The accounting for these derivatives has no impact on operations, Consolidated EBITDA (as defined within our credit agreement) or how we evaluate performance.

The Swap liability loss reflects the changes in the fair value of the cross-currency and interest rate swaps that we employed to provide an economic hedge for our previously held US dollar denominated 8³/4% senior notes. Changes in the fair value of these swaps generally had an offsetting effect to changes in the value of our previously held 8³/4% senior notes (and resulting foreign exchange gains and losses), with both being triggered by variations in the Canadian/US dollar exchange rate. However, the valuations of the derivative financial instruments were also impacted by changes in interest rates and the remaining present value of scheduled interest payments on the swaps, which occurred in June and December of each year until termination of the swap agreements on April 8, 2010.

The redemption option embedded derivative gain in the prior year reflects changes in the fair value of a derivative embedded in our previously held US dollar denominated 8³/4% senior notes. Changes in fair value resulted from changes in long-term bond interest rates during a reporting period.

With respect to the supplier contracts, the fair value of the embedded derivative related to a long-term maintenance contract was increased as a result of the addition of certain pieces of heavy equipment to the repair and maintenance program with the supplier contract in the three months ended June 30, 2010. Included in the embedded derivative valuation was the impact of fluctuations in provisions that require a price adjustment to reflect changes in the Canadian/US dollar exchange rate and the United States government published Producers’ Price Index (US-PPI) for Mining Machinery and Equipment from the original contract amount.

With respect to the long-term customer contract, there is a provision that requires an adjustment to customer billings to reflect actual exchange rates and price indices. The embedded derivative instrument takes into account the impact on revenues, but does not consider the impact on costs as a result of fluctuations in these measures.

The measurement of swap interest payment loss reflects the realized loss on our previously held interest rate swaps. As of February 2, 2009, one of three swap agreements hedging the interest and currency risk associated with our previously held US dollar denominated 8³/4% senior notes was cancelled by the counterparties. As a result of the counterparties’ cancellation of this US dollar interest rate swap, we were incurring higher interest expense and we were exposed to interest rate and foreign currency risk.

8 Management’s Discussion and Analysis North American Energy Partners Inc.

Income taxes (benefit)

For the three months ended June 30, 2010, we recorded current income tax expense of $1.2 million and deferred income tax benefit of $3.2 million for a total income tax recovery of $2.0 million. This compares to combined income tax expense of $2.5 million for the same period last year. For the three months ended June 30, 2010, income tax expense as a percentage of income before income taxes differs from the statutory rate of 27.77% primarily due to the effect of changes in enacted tax rates and the realization of capital loss on the extinguishment of the 8³/4% senior notes and the cross-currency swap. For the three months ended June 30, 2009, income tax expense as a percentage of income before income taxes differed from the statutory rate of 28.91% primarily due to the effect of changes in enacted tax rates and the benefit from changes in the timing of the reversal of temporary differences.

Backlog

Backlog is a measure of the amount of secured work we have outstanding and, as such, is an indicator of a base level of future revenue potential. Backlog is not a GAAP measure. As a result, the definition and determination of a backlog will vary among different organizations ascribing a value to backlog. Although backlog reflects business that we consider to be firm, cancellations or reductions may occur and may reduce backlog and future income.

We define backlog as work that has a high certainty of being performed as evidenced by the existence of a signed contract or work order specifying job scope, value and timing. We have also set a policy that our definition of backlog will be limited to contracts or work orders with values exceeding $500,000 and work that will be performed in the next five years, even if the related contracts extend beyond five years.

Our measure of backlog does not define what we expect our future workload to be. We work with our customers using cost-plus, time-and-materials, unit-price and lump-sum contracts. This mix of contract types varies year-by-year. Our definition of backlog results in the exclusion of a range of services to be provided under cost-plus and time-and-material contracts performed under master service agreements where scope is not clearly defined. For the three months ended June 30, 2010, the total amount of revenue earned from time-and-material contracts performed under our master services agreements was approximately $81.9 million.

Our estimated backlog by segment and contract type as at June 30, 2010 and 2009 as well as March 31, 2010 was:

By Segment


(dollars in thousands)	June 30, 2010	March 31, 2010	June 30, 2009
Heavy Construction and Mining	$807,111	$725,767	$696,412
Piling	16,579	16,423	5,731
Pipeline	40,989	6,861	–

Total	$864,679	$749,051	$702,143


By Contract Type
(dollars in thousands)	June 30, 2010	March 31, 2010	June 30, 2009
Unit-Price	$796,670	$722,710	$698,550
Lump-Sum	63,383	18,429	2,165
Time-and-Materials and Cost-Plus	4,626	7,912	1,428

Total	$864,679	$749,051	$702,143

A contract with a single customer represented approximately $768.8 million of our June 30, 2010 backlog, compared to $674.6 million reported as backlog in our interim Management’s Discussion and Analysis for the three months ended June 30, 2009 and $706.7 million in our annual Management’s Discussion and Analysis for the year ended March 31, 2010.

We expect that approximately $283.3 million of total backlog will be performed and realized in the twelve months ending June 30, 2011.*

Claims and Change Orders

Due to the complexity of the projects we undertake, changes often occur after work has commenced. These changes include but are not limited to:

_Ÿ

changes in client requirements, specifications and design;

_Ÿ

changes in materials and work schedules; and

_Ÿ

changes in ground and weather conditions.

^*	This paragraph contains forward-looking information. Please refer to “Forward-Looking Information and Risk Factors” for a discussion on the risks and uncertainties related to such information.

North American Energy Partners Inc. Management’s Discussion and Analysis 9

Contract change management processes require that we prepare and submit change orders to the client requesting approval of scope and/or price adjustments to the contract. Accounting guidelines require that we consider changes in cost estimates that have occurred up to the release of the financial statements and reflect the impact of these changes in the financial statements. Conversely, potential revenue associated with increases in cost estimates is not included in financial statements until an agreement is reached with a client or specific criteria for the recognition of revenue from unapproved change orders and claims are met. This can, and often does, lead to costs being recognized in one period and revenue being recognized in subsequent periods.

Occasionally, disagreements arise regarding changes, their nature, measurement, timing and other characteristics that impact costs and revenue under the contract. If a change becomes a point of dispute between our customer and us, we then consider it to be a claim. Historical claim recoveries should not be considered indicative of future claim recoveries.

For the three months ended June 30, 2010, due to the timing of receipt of signed change orders, the Heavy Construction and Mining segment had approximately $0.6 million in claims revenue recognized to the extent of costs incurred, the Piling segment had $1.3 million in claims revenue recognized to the extent of costs incurred, and the Pipeline segment had $0.1 million in claims revenue recognized to the extent of costs incurred. We are working with our customers to come to resolution on additional amounts, if any, to be paid to us in respect to these additional costs.

Summary of Consolidated Quarterly Results


	June 30, 2010		March 31, 2010		Dec 31, 2009	Sept 30, 2009	Jun 30, 2009	Mar 31, 2009		Dec 31, 2008		Sept 30, 2008
	Fiscal 2011		Fiscal 2010					Fiscal 2009
Revenue	$183.6		$220.6		$221.2	$170.7	$146.5	$174.7		$258.6		$280.3
Gross profit	15.6		32.7		47.6	33.8	25.1	32.9		51.4		44.7
Operating income (loss)	1.1		13.1		31.3	18.9	10.1	(129.2	)	(1.9	)	23.4
Net (loss) income	(10.3	)	(0.9	)	14.9	4.3	9.9	(137.1	)	(15.0	)	2.9
Net (loss) income per share – Basic^(±)	$(0.29	)	$(0.03	)	$0.41	$0.12	$0.28	$(3.80	)	$(0.42	)	$0.08
Net (loss) income per share – Diluted^(±)	$(0.29	)	$(0.03	)	$0.41	$0.12	$0.27	$(3.80	)	$(0.42	)	$0.08

^±	Net income (loss) per share for each quarter has been computed based on the weighted average number of shares issued and outstanding during the respective quarter; therefore, quarterly amounts may not add to the annual total. Per-share calculations are based on full dollar and share amounts.

A number of factors have the potential to contribute to variations in our quarterly financial results between periods, including the capital project-based nature of our project development revenue, seasonal weather and ground conditions, capital spending decisions by our customers on large oil sands projects, the timing of equipment maintenance and repairs, claims and change orders and the accounting for unrealized non-cash gains and losses related to foreign exchange and derivative financial instruments.

We generally experience a decline in revenues during the first three months of each fiscal year due to seasonality, as weather conditions make performance in our operating regions difficult during this period. The level of activity in the Heavy Construction and Mining and Pipeline segments declines when frost leaves the ground and many secondary roads are temporarily rendered incapable of supporting the weight of heavy equipment. The duration of this period is referred to as “spring breakup” and it has a direct impact on our activity levels. Revenues during the three months ended March 31 of each fiscal year are typically highest as ground conditions are most favourable in our operating regions. As a result, full-year results are not likely to be a direct multiple of any particular three month period or combination of three month periods. In addition to revenue variability, gross margins can be negatively impacted in less active periods because we are likely to incur higher maintenance and repair costs due to our equipment being available for servicing.

The timing of large projects can influence quarterly revenues. For example, Pipeline segment revenues were as high as $87.5 million in the three months ended March 31, 2008, as low as $0.1 million in the three months ended June 30, 2009 and are currently at $0.8 million for the three months ended June 30, 2010. The Heavy Construction and Mining segment experienced reduced volumes in the three months ended December 31, 2008 and March 31, 2009 as a result of the temporary shut-down of overburden removal at the Horizon project while Canadian Natural prepared for operations start-up. Subsequent three-month periods reflected the ramp up of overburden removal activities at the Horizon project through to the three months ended March 31, 2010, where activity returned to planned activity levels. Changes in demand under our master service agreements with Shell Albian and Syncrude had a positive effect on our revenues for the three months ended September 30, 2008 and June 30, 2009 respectively. Changes in demand with Syncrude had a negative effect on our revenues for the three month periods subsequent to June 30, 2009, until the current three month period ended June 30, 2010. Master service agreement demand from Shell Albian positively

10 Management’s Discussion and Analysis North American Energy Partners Inc.

affected period-over-period comparatives until the current three month period ended June 30, 2009, as a result of a shut down at Shell Albian’s Muskeg River mine for planned maintenance and in preparation for the operational start-up of the Jackpine mine.

Variations in quarterly results can also be caused by changes in our operating leverage. During periods of higher activity, we have experienced improvements in operating margin. This reflects the impact of relatively fixed costs, such as G&A costs, being spread over higher revenue levels. If activity decreases, these same fixed costs are spread over lower revenue levels. Net income and income per share are also subject to operating leverage as provided by fixed interest expense.

Profitability also varies from quarter-to-quarter as a result of claims and change orders. Claims and change orders are a normal aspect of the contracting business but can cause variability in profit margin due to the unmatched recognition of costs and revenues. For further explanation, see “Claims and Change Orders”. As an example, during the three months ended June 30, 2008, a $5.3 million claim was recognized causing gross margins for the Pipeline segment to be higher than normal. The additional costs relating to this claim were incurred and recognized in the year ended March 31, 2007 and in the three months ended June 30, 2007.

We have also experienced net income variability in all periods due to the recognition of unrealized non-cash gains and losses on both derivative financial instruments and our previously held US dollar denominated 8³/4% senior notes, primarily driven by changes in the Canadian/ US dollar exchange rate. The 8³/4% senior notes were redeemed on April 28, 2010 and the associated cross-currency and interest rate swaps were terminated on April 8, 2010.

Summary of Consolidated Financial Position


(dollars in thousands)	As at June 30, 2010		As at March 31, 2010		Change
Cash	$78,868		$103,005		$(24,137	)
Current assets (excluding cash)	204,181		212,607		(8,426	)
Current liabilities	(146,508	)	(165,641	)	19,133

Net working capital	136,541		149,971		(13,430	)
Property, plant and equipment	326,550		328,743		(2,193	)
Total assets	682,639		702,617		(19,978	)
Capital lease obligations (including current portion)	(12,013	)	(13,393	)	1,380
Total long-term financial liabilities^(†)	(331,875	)	(327,356	)	(4,519	)

^†	Total long-term financial liabilities exclude the current portions of capital lease obligations, current portions of derivative financial instruments, long-term lease inducements, asset retirement obligations and both current and non-current deferred income tax balances.

At June 30, 2010, net working capital (cash and current assets less current liabilities) was $136.5 million compared to $150.0 million at March 31, 2010, a decrease of $13.4 million.

The cash balance at June 30, 2010 was $24.1 million lower than at March 31, 2010 reflecting the redemption of the 8³/4% senior notes and associated currency and interest rate swaps.

Current assets excluding cash decreased $8.4 million between March 31, 2010 and June 30, 2010. A $22.0 million decrease in trade receivables and holdbacks along with a $5.6 million increase in unbilled revenue during the three month period ended June 30, 2010 was partially offset by a $4.7 million planned increase of parts inventory, for the purpose of completing scheduled major equipment overhauls in the coming months and a $3.9 million increase in prepaid expenses, as a result of annual payments of both insurance premiums and property taxes.

Current liabilities decreased $19.1 million between June 30, 2010 and March 31, 2010, as a result of a $5.0 million increase in accounts payable offset by a $14.4 million reduction in accrued liabilities primarily as a result of our April 2010 interest payment for our 8³/4% senior notes and interest rate swap. The current portion of embedded derivatives in financial instruments decreased $19.5 million primarily as a result of the redemption of both our 8³/4% senior notes and the accompanying currency and interest rate swaps. Equipment purchases of $3.5 million, which are scheduled to be paid after June 30, 2010, are included in accounts payable as of June 30, 2010.

Property, plant and equipment decreased by $2.2 million between March 31, 2010 and June 30, 2010. This reflects the capital investment of $6.1 million of equipment purchases and new capital leases during the three months ending June 30, 2010, more than offset by depreciation of $8.2 million.

Total long-term financial liabilities increased by $4.5 million between March 31, 2010 and June 30, 2010, due largely to a $225.0 million increase from issuance of the Series 1 Debentures and an increase of $43.6 million in the long-term portion of our term loan resulting from new term loans under our amended and restated credit agreement. This was substantially offset by a $203.1 million decrease in the carrying amount of our 8³/4% senior notes resulting from the redemption of the senior notes and a $61.5 million decrease related to the cross-currency and interest rate swap agreements due to the settlement of the swap liabilities.

North American Energy Partners Inc. Management’s Discussion and Analysis 11

Summary of Consolidated Cash Flows


	Three months ended June 30,
(dollars in thousands)	2010		2009		Change
Cash provided by (used in) operating activities	$15,804		$(7,722	)	$23,526
Cash used in investing activities	(9,838	)	(20,384	)	10,546
Cash (used in) provided by financing activities	(30,103	)	9,215		(39,318	)

Decrease in cash and cash equivalents	(24,137	)	$(18,891	)	$(5,246	)

Operating activities

Cash provided by operating activities for the three months ended June 30, 2010 was $15.8 million, compared to $7.7 million used by operations for the three months ended June 30, 2009. The cash provided by operating activities in the current period is primarily a result of improved non-cash net working capital.

Investing activities

Cash used in investing activities for the three months ended June 30, 2010 was $9.8 million compared to $20.4 million for the same period a year ago. Investing activities this year included capital expenditures of $6.0 million and a net outflow from non-cash working capital of $2.8 million. Cash used in investing activities last year included capital expenditures of $19.2 million and a net outflow from non-cash working capital of $1.3 million partly offset by an inflow of proceeds from asset dispositions of $1.0 million.

Financing activities

Cash used in financing activities during the three months ended June 30, 2010 was $30.1 million, primarily as a result of the debt refinancing and swap cancellation activities, which included $6.7 million of financing costs for the fourth amended and restated credit agreement and the Series 1 Debentures (an additional $1.0 million of financing costs for these items was incurred in the three months ended March 31, 2010). Additional activity included scheduled repayments on our term credit facility of $2.5 million and the $1.4 million repayment of capital lease obligations. Cash provided by financing activities for the three months ended June 30, 2009 of $9.2 million was a result of the addition of a term facility as part of our third amended and restated credit agreement partly offset by $1.1 million of associated financing costs and the $1.5 million repayment of capital lease obligations.

C. Outlook

While spring break-up weather conditions have extended into the second quarter, we still anticipate a gradual strengthening of demand for services through the balance of the year.*

In the oil sands, demand for recurring services is expected to remain strong and we are currently working with all four of the active oil sands operators. We are also continuing to develop our new tailings pond and reclamations services offering, which over time, is expected to provide opportunities to further expand our recurring services business. Currently, we are working with customers to develop pilot projects related to their tailings pond management strategies.^*

Our outlook for project development in the oil sands also remains positive. We continue to win piling and heavy construction-related projects at Exxon’s Kearl site and see opportunities to further expand our business with this customer. Other new developments such as Husky Energy Inc.’s Sunrise⁶, ConocoPhillips’ Surmont⁷ and Suncor’s Firebag in situ projects are moving forward and could eventually provide additional project development opportunities as they reach the construction phase.^*

In the Piling division, activity levels are beginning to ramp up as weather conditions in Western Canada improve and projects delayed by the earlier rainy conditions get underway. The Piling division built up a significant backlog of projects over the past six months and anticipates it will be able to work through these projects by the end of the fiscal year. The division has also been successful in attracting a growing volume of business in the Ontario market, including its first significant commercial development piling project.

The Pipeline division anticipates a stronger second and third quarter with work on two new projects getting underway in August 2010. These include TransCanada Pipelines’⁸ NPS Groundbirch Mainline project, which involves the construction of 77 kilometres of 36-inch pipeline in British Columbia. The Pipeline division will also commence work on the second

^*	This paragraph contains forward-looking information. Please refer to “Forward-Looking Information and Risk Factors” for a discussion on the risks and uncertainties related to such information.

⁶	Husky Energy Inc.’s (Husky Energy) Sunrise Oil Sand project is a 50/50 joint venture with BP Canada Energy Company (BP), a wholly owned subsidiary of BP PLC. The Sunrise project is operated by Husky Energy.

⁷

ConocoPhillips Canada Resources Corporation’s (ConocoPhillips) Surmount Oil Sand in situ project is a 50/50 joint venture between ConocoPhillips Canada, a wholly owned subsidiary of ConocoPhillips Company and Total E&P Canada Ltd. (Total), a wholly owned subsidiary of Total SA. ConocoPhillips Canada is the project operator.

⁸	TransCanada Pipelines Limited (TransCanada Pipelines), a wholly owned subsidiary of TransCanada Corporation.

12 Management’s Discussion and Analysis North American Energy Partners Inc.

phase of Spectra Energy’s⁹ Maxhamish Loop project, which involves the construction of 30 kilometres of 24-inch pipeline, also in British Columbia. Both projects are scheduled for completion in November 2010.^*

Overall we are encouraged by the improving market conditions and by our increasing backlog of work.

D. Legal and Labour Matters

Laws and Regulations and Environmental Matters

Many aspects of our operations are subject to various federal, provincial and local laws and regulations, including:

_Ÿ

permit and licensing requirements applicable to contractors in their respective trades;

_Ÿ

building and similar codes and zoning ordinances;

_Ÿ

laws and regulations relating to consumer protection; and

_Ÿ

laws and regulations relating to worker safety and protection of human health.

For a more detailed discussion of laws and regulations and environmental matters applicable to us, see our most recent annual Management’s Discussion and Analysis.

Employees and Labour Relations

As of June 30, 2010, we had 470 salaried employees and over 1,850 hourly employees. Our hourly workforce fluctuates according to the seasonality of our business and the staging and timing of projects by our customers. The hourly workforce typically ranges in size from 1,000 employees to approximately 2,500 employees depending on the time of year and duration of awarded projects. We also utilize the services of subcontractors in our construction business. An estimated 8% to 10% of the construction work we do is performed by subcontractors. Approximately 1,600 employees are members of various unions and work under collective bargaining agreements. The majority of our work is done through employees governed by our mining overburden collective bargaining agreement with the International Union of Operating Engineers Local 955, the primary term of which expired on October 31, 2009. As of the end of June 2010 negotiations remained underway for the renewal of this union agreement and we are confident that a renewal agreement will be reached without a labour disruption. Other collective agreements in operation include the provincial Industrial, Commercial and Institutional (ICI) agreements in Alberta and Ontario with both the Operating Engineers and Labourers Unions, Piling sector collective agreements in Saskatchewan with the Operating Engineers and Labourers, Pipeline sector agreements in both British Columbia and Alberta with the Christian Labour Association of Canada (CLAC) as well as an all-sector agreement with CLAC in Ontario. We are subject to other industry and specialty collective agreements under which we complete work and the primary terms of all of these agreements are currently in effect. The provincial collective agreement between IUOE Local 955 and the Alberta Roadbuilders and Heavy Construction Association expires February 28, 2011. Management is confident a settlement will be reached without disruption. We believe that our relationships with all our employees, both union and non-union, are strong. We have not experienced a strike or lockout. ^*

E. Resources and Systems

Outstanding Share Data

We are authorized to issue an unlimited number of voting Common Shares and an unlimited number of Non-Voting Common Shares. As at August 4, 2010, there were 36,072,036 voting Common Shares outstanding (36,038,476 as at March 31, 2010). We had no Non-Voting Common Shares outstanding on any of the foregoing dates.

Liquidity and Capital Resources

Liquidity requirements

Our primary uses of cash are for plant and equipment purchases, to fulfill debt repayment and interest payment obligations, to fund operating lease obligations and to finance working capital requirements.

We maintain a significant equipment and vehicle fleet comprised of units with remaining useful lives covering a variety of time spans. It is important to adequately maintain our large revenue-producing fleet in order to avoid equipment downtime, which can impact our revenue stream and inhibit our ability to satisfactorily perform on our projects. Once units reach the end of their useful lives, they are replaced as it becomes cost prohibitive to continue to maintain them. As a result, we are continually acquiring new equipment both to replace retired units and to support our growth as we take on new projects. In order to maintain a balance of owned and leased equipment, we have financed a portion of our heavy construction fleet through operating leases. In addition, we continue to lease our motor vehicle fleet through our capital lease facilities.

We require between $30 million and $40 million annually for sustaining capital expenditures and our total capital requirements typically range from $75 million to $150 million depending on our growth capital requirements. With the

⁹	Spectra Energy Partners, LP (Spectra Energy)

^*	This paragraph contains forward-looking information. Please refer to “Forward-Looking Information and Risk Factors” for a discussion on the risks and uncertainties related to such information.

North American Energy Partners Inc. Management’s Discussion and Analysis 13

potential future customer demand for larger-sized heavy equipment in the oil sands, we expect our capital needs in the current fiscal year to be approximately $50 to $75 million.

We typically finance approximately 30% to 50% of our total capital requirements through our operating lease facilities and the remainder from cash flow from operations. We believe our operating and capital lease facilities and cash flow from operations will be sufficient to meet these requirements. Our equipment fleet value is currently split among owned (43%), leased (46%) and rented equipment (11%). Approximately 37% of our leased fleet is specific to one long-term overburden removal project. This equipment mix is a change from the mix reported in previous periods as a result of our declining need for the same levels of rental equipment, along with the conversion of some rental equipment to operating leases to meet specific volume demands. Our equipment ownership strategy allows us to meet our customers’ variable service requirements while balancing the need to maximize equipment utilization with the need to achieve the lowest ownership costs. We are continually evaluating our capital needs and continue to monitor equipment lead times with suppliers to ensure that we control our capital spending while still being in a position to respond to opportunities when they materialize.*

We continue to receive interest from finance companies to support our current lease requirements and we have availability under one of our supplier’s leasing program to meet our current equipment needs from this supplier. We anticipate having sufficient lease capacity to meet our capital requirements in fiscal year 2011.^*

Long-term Debt Restructuring

Our long-term debt, as at March 31, 2010, included US$200.0 million of 8³/4% senior unsecured notes due in December 2011 (the “8³/4% senior notes”). The foreign currency risk relating to both the principal and interest portions of the 8³/4% senior notes was managed with Canadian dollar interest rate swap and cross-currency swap agreements. The swap agreements were an economic hedge but had not been designated as hedges for accounting purposes. The US$200.0 million principal amount was fixed at C$1.315=US$1.000, resulting in a principal repayment of $263.0 million due on December 1, 2011. A more detailed discussion of this cancellation can be found below in the “Foreign exchange risk” and “Interest rate risk” sections of “Quantitative and Qualitative Disclosures about Market Risk”.

In April 2010, we issued C$225.0 million of Series 1 Debentures and entered into an amended and restated credit agreement that extended the maturity of our credit facilities to April 2013 and provided a new $50.0 million term loan. The net proceeds of the Series 1 Debentures, combined with the new $50.0 million term loan and cash on hand were used to redeem all outstanding 8³/4% senior notes and terminate the associated swap agreements in April 2010. The full details of this debt restructuring are as follows:

9.125% Series 1 Debentures

On April 7, 2010, we closed a private placement of 9.125% Series 1 Debentures (the “Series 1 Debentures”) due 2017 for gross proceeds of $225.0 million and net proceeds after commissions and related expenses of $218.3 million. A more detailed discussion on the Series 1 Debentures can be found under “9.125% Series 1 Debentures” in the “Liquidity and Capital Resources” section of this Management’s Discussion and Analysis.

8³/ 4% Senior Notes Redemption

Beginning December 1, 2009, our 8³/4% senior notes were redeemable at 100% of the principal amount. On March 29, 2010, we issued a redemption notice to holders of the notes to redeem all outstanding 8³/4% senior notes and, on April 28, 2010, the notes were redeemed and cancelled. The redemption amount included the US$200.0 million principal outstanding and US$7.1 million of accrued interest. The redemption and associated swap agreement terminations eliminate refinancing risk in December 2011.

In connection with the redemption of our 8³/4% senior notes, we wrote off deferred financing costs of $4.5 million.

Termination of Cross-Currency and Interest Rate Swaps

On April 8, 2010, we terminated the cross-currency and interest rate swaps associated with the 8³/4% senior notes. The payment to the counterparties required to terminate the swaps was $91.1 million and represented the fair value of the swap agreements, including accrued interest.

$50.0 million Term Facility

On April 30, 2010, we entered into a fourth amended and restated credit agreement to extend the term of the credit agreement and also to add additional borrowings of up to $50.0 million through a second term facility within the credit agreement. At April 30, 2010, the second term facility was fully drawn at $50.0 million. The new term facility, along with the existing term facility, matures on April 30, 2013. A more detailed discussion on the April 30, 2010 amended and restated credit agreement can be found under “Credit facilities” in the “Liquidity and Capital Resources” section of this Management’s Discussion and Analysis.

Letters of credit

One of our major contracts allows the customer to require that we provide up to $50.0 million in letters of credit. As at June 30, 2010, we had $10.0 million in letters of credit outstanding in connection with this contract (we had $14.4

^*	This paragraph contains forward-looking information. Please refer to “Forward-Looking Information and Risk Factors” for a discussion on the risks and uncertainties related to such information.

14 Management’s Discussion and Analysis North American Energy Partners Inc.

million in letters of credit outstanding in total for all customers as of June 30, 2010). Any change in the amount of the letters of credit required by this customer must be requested by November 1st in each year for an issue date of January 1st following the date of such request, for the remaining life of the contract. In July 2010, we issued another $2.0 million in letters of credit for another contract.

Sources of liquidity

Our principal sources of cash are funds from operations and borrowings under our credit facility. As of June 30, 2010, the credit facility includes the $85.0 million Revolving Facility and the outstanding borrowings of $75.9 million (March 31, 2010 – $28.4 million) under the Term Facilities, after the scheduled principal payments of $2.5 million in the quarter. As of June 30, 2010, we had issued $14.4 million (March 31, 2010 – $10.4 million) in letters of credit under the Revolving Facility to support performance guarantees associated with customer contracts. Our unused borrowing availability under the Revolving Facility was $70.6 million at June 30, 2010.

As at June 30, 2010, we had $8.2 million in trade receivables that were more than 30 days past due compared to $7.5 million as at March 31, 2010. We have currently provided an allowance for doubtful accounts related to our trade receivables of $0.8 million ($1.7 million at March 31, 2010). We continue to monitor the credit worthiness of our customers. To date our exposure to potential write-downs in trade receivables has been limited to the financial condition of developers of condominiums and high-rise developments in our Piling segment.

Working capital fluctuations effect on cash

The seasonality of our business results in a higher accounts receivable balance between December and early February during peak activity levels, which may result in an increase in our working capital requirements. Our working capital is also significantly affected by the timing of the completion of projects. In some cases, our customers are permitted to withhold payment of a percentage of the amount owing to us for a stipulated period of time (such percentage and time period is usually defined by the contract and in some cases provincial legislation). This amount acts as a form of security for our customers and is referred to as a “holdback”. Typically, we are only entitled to collect payment on holdbacks once substantial completion of the contract is performed; there are no outstanding claims by subcontractors or others related to work performed by us; and we have met the time period specified by the contract (usually 45 days after completion of the work). However, in some cases, we are able to negotiate the progressive release of holdbacks as the job reaches various stages of completion. As at June 30, 2010, holdbacks totaled $5.5 million, up from $3.9 million as at March 31, 2010. Holdbacks represent 6.1% of our total accounts receivable as at June 30, 2010 (3.5% as at March 31, 2010).^*

Cash requirements

As at June 30, 2010, our cash balance of $78.9 million was $24.1 million lower than our cash balance at March 31, 2010. The change in cash balance reflects the April 2010 settlement of our 8³/4% senior notes and the accompanying currency and interest rate swaps, funded in part by our Series 1 Debentures and the addition of an additional term facility secured through our fourth amended and restated credit facility. We anticipate that we will generate a net cash surplus from operations at least through March 31, 2011. In the event that we require additional funding, we believe that any such funding requirements would be satisfied by the funds available from our credit facilities described immediately below.^*

Credit facilities

On April 30, 2010, we entered into an amended and restated credit agreement to extend the term of the credit facilities and increase the amount of the term loans. The new credit facilities provide for total borrowings of up to $163.4 million (previously $125.0 million) under which revolving loans, term loans and letters of credit may be issued. The Revolving Facility of $85.0 million (previously $90.0 million) was undrawn at closing. The new agreement includes two term facilities providing for borrowings of up to $78.4 million. At April 30, 2010, the Term A Facility and Term B Facility were both fully drawn at $28.4 million and $50.0 million, respectively. The new facilities mature on April 30, 2013.

Advances under the Revolving Facility may be repaid from time to time at our option. The Term Facilities include scheduled repayments totaling $10.0 million per year with $2.5 million paid on the last day of each quarter commencing June 30, 2010. In addition, we must make annual payments within 120 days of the end of our fiscal year in the amount of 50% of Consolidated Excess Cash Flow (as defined in the credit agreement) to a maximum of $4.0 million.

The facilities bear interest at variable rates based on the Canadian prime rate plus the applicable pricing margin (as defined within the credit agreement). Interest on US base rate loans is paid at a rate per annum equal to the US base rate plus the applicable pricing margin. Interest on Canadian prime and US base rate loans is payable monthly in arrears and computed on the basis of a 365-day or 366-day year, as the case may be. Interest on US dollar LIBOR loans is paid during each interest period at a rate per annum, calculated on a 360-day year, equal to the US dollar LIBOR rate with respect to such interest period plus the applicable pricing margin. Stamping Fees and interest on Banker’s Acceptance advances are paid in advance, at the time of issuance.

^*	This paragraph contains forward-looking information. Please refer to “Forward-Looking Information and Risk Factors” for a discussion on the risks and uncertainties related to such information.

North American Energy Partners Inc. Management’s Discussion and Analysis 15

The new credit facilities are secured by a first priority lien on substantially all of our existing and after acquired property and contain customary covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions or paying dividends or redeeming shares of capital stock. We are also required to meet certain financial covenants under the new credit agreement including: (i) Senior Leverage Ratio (Senior Leverage to Consolidated EBITDA) must be less than 2.0 times, (ii) Consolidated Interest Coverage Ratio (Consolidated EBITDA to Consolidated Interest Expense) must be greater than 2.5 times, and (iii) Current Ratio (Current Assets to Current Liabilities) must be greater than 1.25 times. Continued access to the facilities is not contingent on the maintenance of a specific credit rating. These covenants are unchanged from the previous third amended and restated credit agreement.

Financing fees of $1.0 million were incurred in connection with the amended and restated credit agreement, dated April 30, 2010 and were recorded as deferred financing costs.

Consolidated EBITDA is defined within the credit agreement to be the sum, without duplication, of (a) consolidated net income, (b) consolidated interest expense, (c) provision for taxes based on income, (d) total depreciation expense, (e) total amortization expense, (f) costs and expenses incurred by us in entering into the credit facility, (g) accrual of stock-based compensation expense to the extent not paid in cash or if satisfied by the issuance of new equity, (h) the non-cash currency translation losses or mark-to-market losses on any hedge agreement (defined in the credit agreement) or any embedded derivative, and (i) other non-cash items including goodwill impairment (other than any such non-cash item to the extent it represents an accrual of or reserve for cash expenditures in any future period) but only, in the case of clauses (b)-(i), to the extent deducted in the calculation of consolidated net income, less (i) the non-cash currency translation gains or mark-to-market gains on any hedge agreement or any embedded derivative to the extent added in the calculation of consolidated net income, and (ii) other non-cash items added in the calculation of consolidated net income (other than any such non-cash item to the extent it will result in the receipt of cash payments in any future period), all of the foregoing as determined on a consolidated basis in conformity with GAAP.

The credit facility may be prepaid in whole or in part without penalty, except for bankers’ acceptances, which are not pre-payable prior to their maturity. However, the credit facility requires prepayments under various circumstances, such as: (i) 100% of the net cash proceeds of certain asset dispositions, (ii) 100% of the net cash proceeds from our issuance of equity (unless the use of such securities’ proceeds is otherwise designated by the applicable offering document) and (iii) 100% of all casualty insurance and condemnation proceeds, subject to exceptions.

9.125% Series 1 Debentures

On April 7, 2010, we closed a private placement of Series 1 Debentures for gross proceeds of $225.0 million and net proceeds after commissions and related expenses of $218.3 million. Financing fees of $6.6 million were incurred in connection with the Series 1 Debentures and were recorded as deferred financing costs.

The Series 1 Debentures are unsecured senior obligations and rank equally with all other existing and future unsecured senior debt and senior to any subordinated debt that may be issued by us or any of our subsidiaries. The Series 1 Debentures are effectively subordinated to all secured debt to the extent of the value of the collateral.

At any time prior to April 7, 2013, we may redeem up to 35% of the aggregate principal amount of the Series 1 Debentures, with the net cash proceeds of one or more of our Public Equity Offerings (as defined in the trust indenture that governs the Series 1 Debenture) at a redemption price equal to 109.125% of the principal amount plus accrued and unpaid interest to the date of redemption, so long as:

i.	at least 65% of the original aggregate amount of the Series 1 Debentures remains outstanding after each redemption; and

ii.	any redemption is made within 90 days of the equity offering.

At any time prior to April 7, 2013, we may on one or more occasions redeem the Series 1 Debentures, in whole or in part, at a redemption price which is equal to the greater of (a) the Canada Yield Price (as defined in the trust indenture that governs the Series 1 Debenture) and (b) 100% of the aggregate principal amount of Series 1 Debentures redeemed, plus, in each case, accrued and unpaid interest to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

The Series 1 Debentures are redeemable at our option, in whole or in part, at any time on or after: April 7, 2013 at 104.563% of the principal amount; April 7, 2014 at 103.042% of the principal amount; April 7, 2015 at 101.520% of the principal amount; April 7, 2016 and thereafter at 100% of the principal amount; plus, in each case, interest accrued to the redemption date.

If a change of control, as defined in the trust indenture, occurs we will be required to offer to purchase all or a portion of each holder’s Series 1 Debentures at a purchase price in cash equal to 101% of the principal amount of the Series 1 Debentures offered for repurchase plus accrued interest to the date of purchase.

The Series 1 Debentures were rated B+ by Standard & Poor’s and B3 by Moody’s (see “Debt Ratings”).

16 Management’s Discussion and Analysis North American Energy Partners Inc.

Capital resources

We acquire our equipment requirements in three ways: capital expenditures, capital leases and operating leases. Capital expenditures require the outflow of cash for the full value of the equipment at the time of purchase. Capital leases, while not considered capital expenditures, are restricted under the terms of our credit agreement to a maximum of $30.0 million. Operating leases are not considered capital expenditures and are not restricted under the terms of our credit agreement.

We define our equipment requirements as either sustaining capital additions, those that are needed to keep our existing fleet of equipment at its optimal useful life through capital maintenance or replacement, or growth capital additions, those that are needed to perform larger or a greater number of projects.

A summary of equipment additions by nature and by period is shown on the table below:


	Three months ended June 30,
(dollars in thousands)	2010	2009	Change
Capital Expenditures
Sustaining	$3,341	$2,161	$1,180
Growth	3,248	17,549	(14,301	)

Total	$6,589	$19,710	$(13,121	)
Capital Leases
Sustaining	$–	$–	$–
Growth	48	624	(576	)

Total	$48	$624	$(576	)
Total Sustaining Capital Additions	$3,341	$2,161	$1,180
Total Growth Capital Additions	$3,296	$18,173	$(14,877	)
Operating Leases	$4,938	$5,608	($670	)

The increase in sustaining capital additions, for the three months ended June 30, 2010, compared to the same periods in the prior year, is reflective of increases in capital maintenance activity in the current period.

The reduction in growth capital additions, for the three months ended June 30, 2010, compared to the same periods in the prior year, reflects the impact of fewer development projects as a result of the current economic slowdown.

There is a minimal change in operating leases for the three months ended June 30, 2010, compared to the same period in the previous year.

Capital Commitments

Contractual obligations and other commitments

Our principal contractual obligations relate to our long-term debt, capital and operating leases and supplier contracts. The following table summarizes our future contractual obligations, excluding interest payments, unless otherwise noted, as of June 30, 2010.


	Payments due by fiscal year
(dollars in thousands)	Total	2011	2012	2013	2014	2015 and after
Series 1 Debentures	$225,000	$–	$–	$–	$–	$225,000
Term Facilities	75,946	7,500	10,000	10,000	48,446	–
Capital leases (including interest)	12,981	4,111	5,220	2,998	474	178
Operating leases	188,040	49,282	56,628	38,876	26,919	16,335
Supplier contracts	53,083	9,505	14,751	14,751	11,816	2,260

Total contractual obligations	$555,050	$70,398	$86,599	$66,625	$87,655	$243,773

Off-balance sheet arrangements

We have no off-balance sheet arrangements in place at this time.

Debt Ratings

Debt Ratings

Moody’s Investor Service, Inc. (“Moody’s”) and Standard & Poor’s Ratings Services (“S&P”) affirmed our corporate credit ratings in March 2010 and April 2010, respectively. S&P increased our Outlook from ‘negative’ to ‘stable’. Both agencies also provided a rating for our new Series 1 Debentures.

North American Energy Partners Inc. Management’s Discussion and Analysis 17

Our credit ratings from these two agencies are as follows:


Category	Standard & Poor’s	Moody’s
Corporate Rating	B+ (‘stable’ outlook)	B2 (‘stable’ outlook)
Series 1 Debentures	B+ (recovery rating of “3”)	B3 (LGD^≠ rating of “5”)

≠	Loss Given Default:

A credit rating is a current opinion of the credit worthiness of an obligor with respect to a specific financial obligation, a specific class of financial obligations, or a specific financial program (including ratings on medium-term note programs and commercial paper programs). It takes into consideration the credit worthiness of guarantors, insurers, or other forms of credit enhancement on the obligation and takes into account the currency in which the obligation is denominated. The opinion evaluates the obligor’s capacity and willingness to meet its financial commitments as they come due, and may assess terms, such as collateral security and subordination, which could affect ultimate payment in the event of default. A credit rating is not a statement of fact or recommendation to purchase, sell, or hold a financial obligation or make any investment decisions nor is it a comment regarding an issuer’s market price or suitability for a particular investor. A credit rating speaks only as of the date it is issued and can be revised upward or downward or withdrawn at any time by the issuing rating agency if it decides circumstances warrant a revision. We undertake no obligation to maintain our credit ratings or to advise investors of a change in ratings.

A definition of the categories of each rating has been obtained from each respective rating organization’s website as outlined below:

Standard and Poor’s

An obligation rated B is regarded as having speculative characteristics, but the obligor currently has the capacity to meet its financial commitment on the obligation. Adverse business, financial, or economic conditions will likely impair the obligor’s capacity or willingness to meet its financial commitment on the obligation. The ratings from AA to CCC may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories.

A recovery rating of “3” for the Series 1 Debentures indicates an expectation for an average of 50% to 70% recovery in the event of a payment default.

A Standard & Poor’s rating outlook assesses the potential direction of a long-term credit rating over the intermediate term (typically nine months to two years). In determining a rating outlook, consideration is given to any changes in the economic and/or fundamental business conditions. An outlook is not necessarily a precursor of a rating change or future CreditWatch action. A Stable outlook means that a rating is not likely to change.

Moody’s

Obligations rated “B” are considered speculative and are subject to high credit risk. Moody’s appends numerical modifiers to each generic rating classification from “Aaa” through “C”. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of that generic rating category.

LGD assessments are opinions about expected loss given default on fixed income obligations expressed as a percent of principal and accrued interest at the resolution of the default. An LGD assessment (or rate) is the expected LGD divided by the expected amount of principal and interest due at resolution. A LGD rating of “5” indicates a loss range of greater than or equal to 70% and less than 90%.

A Moody’s rating outlook is an opinion regarding the likely direction of an issuer’s rating over the medium term. Where assigned, rating outlooks fall into the following four categories: Positive (“POS”), Negative (“NEG”), Stable (“STA”) and Developing (“DEV” – contingent upon an event). In the few instances where an issuer has multiple ratings with outlooks of differing directions, an “(m)” modifier (indicating multiple, differing outlooks) will be displayed and Moody’s written research will describe any differences and provide the rationale for these differences. A “RUR” (Rating(s) Under Review) designation indicates that the issuer has one or more ratings under review for possible change, and thus overrides the outlook designation. When an outlook has not been assigned to an eligible entity, “NOO” (No Outlook) may be displayed. A Stable outlook means that a rating is not likely to change.

Related Parties

We may receive consulting and advisory services provided by the principals or employees of companies owned or operated by certain of our directors (the Sponsors) with respect to the organization of our employee benefit and compensation arrangements and other matters and no fee is charged for these consulting and advisory services.

In order for the Sponsors to provide such advice and consulting, we provide the Sponsors with reports, financial data and other information. This permits them to consult with and advise our management on matters relating to our operations, company affairs and finances. In addition, this permits them to visit and inspect any of our properties and facilities. These services are provided in the normal course of operations and are measured at the value of consideration established and agreed to by the related parties.

Additionally, we provide shared service support for our joint venture nominee, Noramac Ventures Inc.

18 Management’s Discussion and Analysis North American Energy Partners Inc.

Internal Systems and Processes

Evaluation of disclosure controls and procedures

Our disclosure controls and procedures are designed to provide reasonable assurance that information we are required to disclose is recorded, processed, summarized and reported with the time periods specified under Canadian and US securities laws and include controls and procedures designed to ensure that information is accumulated and communicated to management, including the President and Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosures.

As of June 30, 2010, an evaluation was carried out under the supervision of and with the participation of management, including the President and Chief Executive Officer and the Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) under the US Securities Exchange Act of 1934, as amended, and in National Instrument 52-109 under the Canadian Securities Administrators Rules and Policies. Based on that evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that as a result of the material weaknesses in our internal control over financial reporting (ICFR) discussed below, the disclosure controls and procedures were not effective as of June 30, 2010.

Material changes to internal controls over financial reporting

As of March 31, 2010, we assessed the effectiveness of our ICFR. In making this assessment, we used the criteria set forth in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). During this process we identified a continued material weakness in ICFR as described below and as a result, we concluded that our ICFR was ineffective as of March 31, 2010.

Similar to the material weakness identified for the year ended March 31, 2009, we did not maintain effective processes and controls specific to revenue recognition. We did not effectively develop, communicate and implement sufficient monitoring controls over the completeness and accuracy of forecasts, including the consideration of project changes subsequent to the end of each reporting period. The accounts that could be affected by these deficiencies are revenue, project costs, unbilled revenue and billings in excess of costs incurred and estimated earnings on uncompleted contracts. This material weakness in ICFR, which is pervasive in nature, resulted in material errors in the financial statements that were corrected prior to release of the financial statements. Further, there is a reasonable possibility that a material misstatement of our financial statements will not be prevented or detected on a timely basis. Notwithstanding the above mentioned weakness, we have concluded that the Consolidated Financial Statements included in this report fairly present our consolidated financial position and consolidated results of operations as of and for the three months ended June 30, 2010.

Material changes to internal controls over financial reporting and remediation plans

In response to the continued material weakness in revenue recognition identified above, during the three months ended and subsequent to March 31, 2010, we put a dedicated project team in place, led by a senior member of our Finance team, to develop and implement standard business practices and controls specific to ensuring the accuracy of forecast, including the consideration of project changes subsequent to the end of each reporting period. As of June 30, 2010, progress has been made on our remediation plans and we will evaluate the effectiveness of these controls during the fiscal year to determine if they adequately address our ability to recognize revenue in accordance with GAAP. For a discussion of the risks associated with such weakness, please see our most recent annual Management’s Discussion and Analysis

Recently Adopted Accounting Policies

Improvements to financial reporting by enterprises involved with variable interest entities

In December 2009, the FASB issued ASU No. 2009-17, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities”, which amends ASC 810, “Consolidation”. The amendments give guidance and clarification of how to determine when a reporting entity should include the assets, liabilities, non-controlling interests and results of activities of a variable interest entity in its consolidated financial statements. We adopted this ASU effective April 1, 2010. The adoption of this standard did not have a material effect on our interim consolidated financial statements.

Recent Accounting Pronouncements Not Yet Adopted

Revenue recognition

In October 2009, the FASB issued ASU No. 2009-13, “Revenue Recognition: Multiple-Deliverable Revenue Arrangements”, which addresses the accounting for multiple-deliverable arrangements to enable vendors to account for products or services separately rather than as a combined unit. The amendments establish a selling price hierarchy for determining the selling price of a deliverable. The amendments also eliminate the residual method of allocation and require that arrangement consideration be allocated at the inception of the arrangement to all deliverables using the relative selling price method. For us, this ASU is effective prospectively for revenue arrangements entered into or materially modified on or after April 1, 2011. We are currently evaluating the effect of this ASU on our interim consolidated financial statements.

North American Energy Partners Inc. Management’s Discussion and Analysis 19

Embedded credit derivatives

In March 2010, the FASB issued ASU No. 2010-11, “Scope Exception Related to Embedded Credit Derivatives”, which clarifies that financial instruments that contain embedded credit-derivative features related only to the transfer of credit risk in the form of subordination of one instrument to another are not subject to bifurcation and separate accounting. The scope exception only applies to an embedded derivative feature that relates to subordination between tranches of debt issued by an entity and other features that relate to another type of risk must be evaluated for separation as an embedded derivative. The ASU was effective for us beginning on July 1, 2010, with early adoption permitted in first fiscal quarter beginning after March 5, 2010. We are currently evaluating the effect of this ASU on our interim consolidated financial statements.

Share based payment awards

In April 2010, the FASB issued ASU No. 2010-13, “Effect of Denominating the Exercise Price of Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades”, which clarifies that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. This ASU will amend ASC 718, “Compensation-Stock Compensation” and it is effective for us beginning on April 1, 2011. We are currently evaluating the effect of this ASU on our interim consolidated financial statements.

F. Forward-Looking Information and Risk Factors

Forward-Looking Information

This document contains forward-looking information that is based on expectations and estimates as of the date of this document. Our forward-looking information is information that is subject to known and unknown risks and other factors that may cause future actions, conditions or events to differ materially from the anticipated actions, conditions or events expressed or implied by such forward-looking information. Forward-looking information is information that does not relate strictly to historical or current facts and can be identified by the use of the future tense or other forward-looking words such as “believe”, “expect”, “anticipate”, “intend”, “plan”, “estimate”, “should”, “may”, “could”, “would”, “target”, “objective”, “projection”, “forecast”, “continue”, “strategy”, “intend”, “position” or the negative of those terms or other variations of them or comparable terminology.

Examples of such forward-looking information in this document include, but are not limited to, statements with respect to the following, each of which is subject to significant risks and uncertainties and is based on a number of assumptions which may prove to be incorrect:

(a)	the amount of our backlog expected to be performed and realized in the twelve months ending June 30, 2011;

(b)	our expectation of continued gradual strengthening of demand of our services through the balance of the year;

(c)	our expectation that demand for recurring services will continue to be strong and our development of the our new tailings pond and reclamations services offering will provide opportunities to further expand our recurring services business;

(d)	our expectation that we will receive project development opportunities as new mine developments such as Husky Energy’s Sunrise, ConocoPhillips’s Surmont, and Suncor’s Firebag projects move forward to the construction phase;

(e)	our expectation that the Piling division will be able to work through the backlog of projects that have built up over the last six months by the end of the fiscal year;

(f)	our expectation that the Pipeline segment will have a stronger second and third quarter with work on two new projects getting underway in August 2010;

(g)	the expectation for a renewal agreement between our employees party to a collective bargaining agreement which expired October 31, 2009 and us;

(h)	the expectation that the provincial collective agreement between IUOE Local 955 and the Alberta Roadbuilders and Heavy Construction Association expiring on February 28, 2011 will reach a settlement;

(i)	our expectation that our capital needs in fiscal 2011 will be approximately $50-$75 million;

(j)	our operating and lease facilities and cash flow from operations will be sufficient to meet our capital requirements;

(k)	our lease capacity will be sufficient to meet our capital requirements in fiscal 2011;

(l)	the seasonality of our business results may result in an increase in working capital requirements;

(m)	our expectation that we will generate a net cash surplus from operations through March 31, 2011; and

(n)	any additional funding required by us will be satisfied by the credit facility.

The forward-looking information in paragraphs (a), (b), (c), (d), (e), (f), (i), (j), (k), (l), (m) and (n) rely on certain market conditions and demand for our services and are based on the assumptions that: despite the slowdown in the global

20 Management’s Discussion and Analysis North American Energy Partners Inc.

economy and tightening of credit conditions, we still expect to see strong demand for our recurring services as the oil sands continue to be an economically viable source of energy, our customers and potential customers continue to invest in the oil sands and other natural resource developments; our customers and potential customers will continue to outsource the type of activities for which we are capable of providing service; and the Western Canadian economy continues to develop with additional investment in public construction; and are subject to the following risks and uncertainties, which could cause results to differ materially from those expressed in the forward-looking information contained in this MD&A, but are not limited to:

_Ÿ

anticipated new major capital projects in the oil sands may not materialize;

_Ÿ

demand for our services may be adversely impacted by regulations affecting the energy industry;

_Ÿ

failure by our customers to obtain required permits and licenses may affect the demand for our services;

_Ÿ

changes in our customers’ perception of oil prices over the long-term could cause our customers to defer, reduce or stop their capital investment in oil sands projects, which would, in turn, reduce our revenue from those customers;

_Ÿ

reduced financing as a result of the tightening credit markets may affect our customers’ decisions to invest in infrastructure projects;

_Ÿ

insufficient pipeline, upgrading and refining capacity or lack of sufficient governmental infrastructure to support growth in the oil sands region could cause our customers to delay, reduce or cancel plans to construct new oil sands projects or expand existing projects, which would, in turn, reduce our revenue from those customers;

_Ÿ

a change in strategy by our customers to reduce outsourcing could adversely affect our results;

_Ÿ

cost overruns by our customers on their projects may cause our customers to terminate future projects or expansions which could adversely affect the amount of work we receive from those customers;

_Ÿ

because most of our customers are Canadian energy companies, a further downturn in the Canadian energy industry could result in a decrease in the demand for our services;

_Ÿ

shortages of qualified personnel or significant labour disputes could adversely affect our business; and

_Ÿ

unanticipated short term shutdowns of our customers’ operating facilities may result in temporary cessation or cancellation of projects in which we are participating.

The forward-looking information in paragraphs (a), (b), (c), (d), (e), (f), (g), (h), (i), (j), (k), (l), (m) and (n) rely on our ability to execute our growth strategy and are based on the assumptions that the management team can successfully manage the business; we can maintain and develop our relationships with our current customers; we will be successful in developing relationships with new customers; we will be successful in the competitive bidding process to secure new projects; we will identify and implement improvements in our maintenance and fleet management practices; we will be able to benefit from increased recurring revenue base tied to the operational activities of the oil sands; we will be able to access sufficient funds to finance our capital growth; and are subject to the risks and uncertainties that:

_Ÿ

continued reduced demand for oil and other commodities as a result of slowing market conditions in the global economy may result in reduced oil production and a decline in oil prices;

_Ÿ

if we are unable to obtain surety bonds or letters of credit required by some of our customers, our business could be impaired;

_Ÿ

we are dependent on our ability to lease equipment and a tightening of this form of credit could adversely affect our ability to bid for new work and/or supply some of our existing contracts;

_Ÿ

our business is highly competitive and competitors may outbid us on major projects that are awarded based on bid proposals;

_Ÿ

our customer base is concentrated and the loss of or a significant reduction in business from a major customer could adversely impact our financial condition;

_Ÿ

lump-sum and unit-price contracts expose us to losses when our estimates of project costs are lower than actual costs;

_Ÿ

our operations are subject to weather-related factors that may cause delays in our project work; and

_Ÿ

environmental laws and regulations may expose us to liability arising out of our operations or the operations of our customers.

While we anticipate that subsequent events and developments may cause our views to change, we do not have an intention to update this forward-looking information, except as required by applicable securities laws. This forward-looking information represents our views as of the date of this document and such information should not be relied upon as representing our views as of any date subsequent to the date of this document. We have attempted to identify important factors that could cause actual results, performance or achievements to vary from those current expectations or estimates expressed or implied by the forward-looking information. However, there may be other factors that cause results, performance or achievements not to be as expected or estimated and that could cause actual results,

North American Energy Partners Inc. Management’s Discussion and Analysis 21

performance or achievements to differ materially from current expectations. There can be no assurance that forward-looking information will prove to be accurate, as actual results and future events could differ materially from those expected or estimated in such statements. Accordingly, readers should not place undue reliance on forward-looking information. These factors are not intended to represent a complete list of the factors that could affect us. See “Risk Factors” below and risk factors highlighted in materials filed with the securities regulatory authorities filed in the United States and Canada from time to time, including, but not limited to, our most recent Annual Information Form.

Risk Factors

For the three months ended June 30, 2010, there has been no significant change in our risk factors discussed in our most recent annual Management’s Discussion and Analysis, which was current as of June 10, 2010. The risk factors discussed in our most recent annual Management’s Discussion and Analysis should be reviewed in conjunction with this interim Management’s Discussion and Analysis.

Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices such as foreign currency exchange rates and interest rates. The level of market risk to which we are exposed at any point in time varies depending on market conditions, expectations of future price or market rate movements and composition of our financial assets and liabilities held, non-trading physical assets and contract portfolios.

To manage the exposure related to changes in market risk, we use various risk management techniques including the use of derivative instruments. Such instruments may be used to establish a fixed price for a commodity, an interest-bearing obligation or a cash flow denominated in a foreign currency.

The sensitivities provided below are hypothetical and should not be considered to be predictive of future performance or indicative of earnings on these contracts.

Foreign exchange risk

Foreign exchange risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to changes in foreign exchange rates. We regularly transact in foreign currencies when purchasing equipment and spare parts as well as certain general and administrative goods and services. These exposures are generally of a short-term nature and the impact of changes in exchange rates has not been significant in the past. We may fix our exposure in either the Canadian dollar or the US dollar for these short-term transactions, if material.

At June 30, 2010, with other variables unchanged, the impact of a $0.01 increase (decrease) in exchange rates of the Canadian dollar to the US dollar on short-term exposures would be insignificant and there would be no impact to other comprehensive income.

Interest rate risk

We are exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of our financial instruments. Amounts outstanding under our amended credit facilities are subject to a floating rate. Our Series 1 Debentures are subject to a fixed rate. Our interest rate risk arises from long-term borrowings issued at fixed rates that create fair value interest rate risk and variable rate borrowings that create cash flow interest rate risk.

In some circumstances, floating rate funding may be used for short-term borrowings and other liquidity requirements. We may use derivative instruments to manage interest rate risk. We manage our interest rate risk exposure by using a mix of fixed and variable rate debt and may use derivative instruments to achieve the desired proportion of variable to fixed-rate debt.

At June 30, 2010, we held $75.9 million of floating rate debt pertaining to our term facilities within our amended and restated credit agreement (March 31, 2010 – $28.4 million). As at June 30, 2010, holding all other variables constant, a 100 basis point increase (decrease) to interest rates on floating rate debt would result in a $0.8 million increase (decrease) in effective annual interest costs. This assumes that the amount of floating rate debt remains unchanged from that which was held at June 30, 2010.

G. General Matters

Our corporate head office is located at Suite 2400, 500 4th Avenue SW, Calgary, Alberta, T2P 2V6. Our corporate head office telephone and facsimile numbers are 403-767-4825 and 403-767-4849, respectively.

Additional Information

Additional information relating to us, including our Annual Information Form dated June 10, 2010, can be found on the Canadian Securities Administrators System for Electronic Document Analysis and Retrieval (SEDAR) database at www.sedar.com, the Securities and Exchange Commission’s website at www.sec.gov and our company’s web site at www.nacg.ca.

22 Management’s Discussion and Analysis North American Energy Partners Inc.

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