North American Construction 40F 2008 Annual report | NOA Filing

Exhibit 99.3

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the year ended March 31, 2008

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

The following discussion and analysis is as of June 20, 2008 and should be read in conjunction with the attached audited consolidated financial statements for the fiscal year ended March 31, 2008, which have been prepared in accordance with Canadian generally accepted accounting principles (GAAP) and reconciled to US GAAP. These financial statements and additional information relating to our business, including our AIF is available on SEDAR atwww.sedar.comand EDGAR atwww.sec.gov. Except where otherwise specifically indicated, all dollar amounts are expressed in Canadian dollars.

June 20, 2008

Prior Year Comparisons

On November 28, 2006 we completed an initial public offering (“IPO”) of common shares in Canada and the U.S. We became publicly traded on the Toronto Stock Exchange and New York Stock Exchange under the symbol “NOA”. Prior to the consummation of the IPO, the predecessor company was amalgamated with its parent companies and we undertook certain transactions that resulted in changes to our capital structure. Upon completion of the IPO, we used the proceeds to undertake related transactions, which further changed our capital structure. These transactions included the repayment of all our outstanding senior secured notes, due in 2010, for a total payment of $77.8 million and the repayment of the $27.0 million of promissory notes issued in respect of the repurchase of the NACG Preferred Corp. Series A preferred shares. We also used proceeds from the IPO to purchase $44.6 million of equipment under operating leases. As a result, comparisons of current periods to prior periods are impacted by the amalgamation and capital restructuring transactions.

A. Business Overview and Strategy

Business Overview

We are a leading resource services provider to major oil, natural gas and other natural resource companies, with a primary focus on the Alberta oil sands. We provide a wide range of mining and site preparation, piling and pipeline installation services to our customers across the entire lifecycle of their projects. We are the largest provider of contract mining services in the oil sands area and we believe we are the largest piling foundations installer in Western Canada. In addition, we believe that we operate the largest fleet of equipment of any contract resource services provider in the oil sands. Our total fleet includes 845 pieces of diversified heavy construction equipment supported by over 925 ancillary vehicles. While our expertise covers heavy earth moving, site preparation, underground industrial piping, piling and pipeline installation in any location, we have a specific capability operating in the harsh climate and difficult terrain of the oil sands and northern Canada.

We believe that our significant knowledge, experience, equipment capacity and scale of operations in the oil sands differentiate us from our competition. We provide services to every company in the Alberta oil sands that uses surface mining techniques in their production. These surface mining techniques account for over 65% of total oil sands production. We also provide site construction services for in-situ producers, which use horizontally drilled wells to inject steam into deposits and pump bitumen to the surface.

Our principal oil sands customers include all three of the producers that are currently mining bitumen in Alberta: Syncrude Canada Ltd. (Syncrude), Suncor Energy Inc. (Suncor) and Albian Sands Energy Inc. (Albian), a joint venture among Shell Canada Limited, Chevron Canada Limited and Marathon Oil Canada Corporation. We are also working with customers that are in the process of developing bitumen-mining projects, including Canadian Natural Resources Limited (Canadian Natural) and Petro-Canada Fort Hills (a joint venture between UTS Energy, Teck Cominco and Petro-Canada).

We have long-term relationships with most of our customers. For example, we have been providing services to Syncrude and Suncor since they pioneered oil sands development over 30 years ago. Approximately 39% of our revenues in fiscal 2008 were derived from recurring work and long-term contracts, which assist in providing stability in our operations.

Our Heavy Construction and Mining division successfully completed the development of a diamond mine site in 2008. This three-year project demonstrated our ability to operate effectively in a remote location under difficult weather conditions. We

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

believe that we demonstrated our ability to successfully export knowledge and technology gained in the oil sands and put it to work in other resource development projects across Canada. As a result of our work in this area, we believe we have attracted the attention of resource developers and we are currently looking at other potential projects, including those in the high arctic regions.

Our Piling division installs all types of driven, drilled and screw piles, caissons, earth retention and stabilization systems. Operating throughout western Canada, this division has a solid record of performance on both small and large-scale projects. Our Piling division also has experience with industrial projects in the oil sands and related petrochemical and refinery complexes and has been involved in the development of commercial and infrastructure projects.

Our Pipeline division installs penstocks as well as steel, fiberglass, and plastic pipe in sizes up to 52” in diameter. This division is experienced with jobs of varying magnitude for some of Canada’s largest energy companies. Our experience includes the recent construction of a new pipeline that goes through the Rockies. This project involves the construction of a 160 kilometre pipeline, for Kinder Morgan’s Transmountain Crossing (TMX), through ecologically sensitive environments, including Jasper National Park, with minimal impact to the environment.

Canadian Oil Sands

Oil sands are grains of sand covered by a thin layer of water and coated by heavy oil, or bitumen. Bitumen, because of its structure, does not flow, and therefore requires non-conventional extraction techniques to separate it from the sand and other foreign matter. There are currently two main methods of extraction: open pit mining, where bitumen deposits are sufficiently close to the surface to make it economically viable to recover the bitumen by treating mined sand in a surface plant; and in-situ, where bitumen deposits are buried too deep for open pit mining to be cost effective, and operators instead inject steam into the deposit so that the bitumen can be separated from the sand and pumped to the surface. We currently provide most of our services to companies operating open pit mines to recover bitumen reserves. These customers utilize our services for surface mining, site preparation, piling, pipe installation, site maintenance, equipment and labor supply and land reclamation.

Oil Sands Outlook

On October 25, 2007, the Alberta government announced increases to the Alberta royalty rates affecting natural gas, conventional oil and oil sands producers. The announced increases were significant but lower than increases recommended to the government by the Royalty Review Panel. While some of our customers have announced their intentions to reduce oil and gas investment in Alberta as a result of the increased royalties, to date, the areas affected by these investment reductions do not include oil sands mining projects. Given the long-term nature and capital investment requirement to develop an oil sands mining operation, we anticipate that there is limited risk that the royalty changes will cause our customers to cancel, delay or reduce the scope of any significant mining developments presently underway.*

We are continuing to experience increasing requests for services under existing contracts with our major oil sands customers, in spite of the recent royalty changes. Our recent acquisitions of new equipment ideally suited to heavy earth moving in the oil sands area, together with the addition of a significant number of new employees, has strengthened our ability to bid competitively and profitably into this expanding market and we have secured contract wins on many of these new projects.

Demand for our services is primarily driven by the development, expansion and operation of oil sands projects. The oil sands operators’ capital investment decisions are driven by a number of factors, with what we believe is one of the most important being the expected long-term price of oil. The development, expansion and operation of oil sands projects, related public infrastructure spending and the commercial construction activity in western Canada play a key role in influencing our business activities.

According to the Canadian Association of Petroleum Producers, or CAPP, approximately $55.2 billion was invested in the oil sands from 1998 through 2006. According to CERI’s November 2007 report, “Canadian Oil Sands Supply Costs and Development Projects (2007 — 2027)”, an additional $228 billion of capital expenditures will be required between 2007 and 2015 to achieve

* This paragraph contains forward looking statements. 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
For the year ended March 31, 2008

production levels projected under their “constrained” scenario. According to the CERI, as of November 2007, there were 23 mining and upgrader projects in various stages, ranging from announcement to construction, with start-up dates through 2014. Beyond 2014, several new multi-billion dollar projects and a number of smaller multimillion dollar projects are being considered by various oil sands operators. We intend to pursue business opportunities from these projects.*

Strategy

Our strategy is to be an integrated service provider for the developers of resource-based industries in a broad and often challenging range of environments. This strategy is focused on the following priorities:*

	•		Capitalize on growth opportunities in the Canadian oil sands:We intend to build on our market leadership position and successful track record with our customers to benefit from any continued growth in this market. We intend to increase our fleet size to be ready to meet the challenges from the projected growth in oil sands.

	•		Leverage our complementary services:Our complementary service segments, including site preparation, pipeline installation, Piling and other mining services allow us to compete for many different forms of business. We intend to build on our “first-in” position to cross-sell our other services and pursue selective acquisition opportunities that expand our complementary service offerings.

	•		Increase our recurring revenue base:We provide services both during the construction phase and once the project is in operation. These mining services include overburden removal, reclamation, road construction and maintenance and mining services.

	•		Leverage our long term relationships with customers:Several of our oil sands customers have announced their intentions to increase their production capacity by expanding the infrastructure at their sites. We intend to continue to build on our relationships with these and other existing oil sands customers to win a substantial share of the heavy construction and mining, Piling and pipeline services outsourced in connection with these projects.

	•		Increase our presence outside the oil sands:We intend to increase our presence outside the oil sands and extend our services to other resource industries across Canada. Canada has significant natural resources and we believe that we have the equipment and the experience to assist those companies with developing those natural resources.

	•		Enhance operating efficiencies to improve revenues and margins:We aim to increase the availability and efficiency of our equipment through enhanced maintenance, providing the opportunity for improved revenue, margins and profitability.

Operations

As discussed above we provide our services through three interrelated yet distinct business units: (i) Heavy Construction and Mining, (ii) Piling and (iii) Pipeline. Our services include initial advice and consulting to customers as they develop plans to exploit resources. We believe that we have the skills and equipment to build infrastructure in new locations (or to expand existing sites) for heavy construction projects. We are currently involved in assisting with on-site mining services, overburden removal and plant upgrades. We are also able to respond to customer needs for site reclamation services once a site’s resources are depleted.

* This paragraph contains forward looking statements. 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
For the year ended March 31, 2008

The table below shows the revenues generated by each operating segment for the fiscal years ended March 31, 2006 through March 31, 2008:


	Year Ended March 31,
			% of					% of					% of
	2008		Total			2007		Total			2006		Total
(dollars in thousands)
Revenue by operating segment:
Heavy Construction and Mining	$	626,582		63.3	%	$	473,179		75.2	%	$	366,721		74.5	%
Piling		162,397		16.4	%		109,266		17.4	%		91,434		18.6	%
Pipeline		200,717		20.3	%		47,001		7.5	%		34,082		6.9	%

Total	$	989,696		100.0	%	$	629,446		100.0	%	$	492,237		100.0	%

B. Financial Results

Consolidated Results


	Year Ended March 31,
			% of					% of						% of
	2008		Revenue			2007		Revenue			2006			Revenue
(dollars in thousands, except per share information)
Revenue	$	989,696		100.0	%	$	629,446		100.0	%	$	492,237			100.0	%
Project costs		592,458		59.9	%		363,930		57.8	%		308,949			62.8	%
Equipment costs		174,873		17.7	%		122,306		19.4	%		64,832			13.2	%
Equipment operating lease expense		22,319		2.3	%		19,740		3.1	%		16,405			3.3	%
Depreciation		36,729		3.7	%		31,034		4.9	%		21,725			4.4	%
Gross profit		163,317		16.5	%		92,436		14.7	%		80,326			16.3	%
General & administrative costs		69,670		7.0	%		39,769		6.3	%		30,903			6.3	%
Operating income		92,397		9.3	%		51,126		8.1	%		49,426			10.0	%
Net income (loss)		39,784		4.0	%		21,079		3.3	%		(21,941	)		-4.5	%
Per share information
Net income (loss) — basic	$	1.11				$	0.87				$	(1.18	)
Net income (loss) — diluted		1.08					0.83					(1.18	)
EBITDA⁽¹⁾	$	121,982		12.3	%	$	87,351		13.9	%	$	70,027			14.2	%
Consolidated EBITDA per bank⁽¹⁾		135,094		13.7	%		90,235		14.3	%		72,422			14.7	%


(1)		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. EBITDA is calculated as net income (loss) before interest expense, income taxes, depreciation and amortization. Consolidated EBITDA per bank 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 (loss). 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 revolving credit facility requires us to maintain a minimum interest coverage ratio and a maximum senior leverage ratio, which are calculated using Consolidated EBITDA per bank. Non-compliance with these financial covenants could result in our being required to immediately repay all amounts outstanding under our

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

revolving credit facility. EBITDA and Consolidated EBITDA per bank are not measures of performance under Canadian GAAP or U.S. GAAP and our computations of EBITDA and Consolidated EBITDA per bank may vary from others in our industry. EBITDA and Consolidated EBITDA per bank 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 per bank have important limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under Canadian GAAP or U.S. GAAP. For example, EBITDA and Consolidated EBITDA per bank:

	•		do not reflect our cash expenditures or requirements for capital expenditures or capital commitments;

	•		do not reflect changes in or cash requirements for, our working capital needs;

	•		do not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;

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

	•		do not reflect any cash requirements for assets being depreciated and amortized that may have to be replaced in the future.

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


	Year Ended March 31,
	2008			2007			2006

(dollars in thousands)
Net income (loss)	$	39,784		$	21,079		$	(21,941	)
Adjustments:
Interest expense		27,019			37,249			68,776
Income taxes		17,379			(2,593	)		737
Depreciation		36,729			31,034			21,725
Amortization of intangible assets		1,071			582			730

EBITDA	$	121,982		$	87,351		$	70,027

Adjustments:
Unrealized foreign exchange loss (gain) on senior notes		(24,788	)		(5,017	)		(14,258	)
Realized and unrealized loss (gain) on derivative financial instruments		34,075			(196	)		14,689
Loss (gain) on disposal of plant and equipment and assets held for sale		179			959			(733	)
Stock-based compensation		1,991			2,101			923
Director deferred stock unit expense		(190	)		—			—
Write-off of deferred financing costs		—			4,342			1,774
Write-down of other assets to replacement cost		1,845			695			-

Consolidated EBITDA per bank	$	135,094		$	90,235		$	72,422

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Analysis of Results:

Demand for our services continued to grow in fiscal 2008 with a high volume of project work in the Alberta Oil Sands, increased activity on a major pipeline project and strong commercial construction markets in western Canada contributing to record results. For the 12 months ended March 31, 2008, our consolidated revenue increased to $989.7 million, $360.3 million (or 57.2%) higher than in fiscal 2007 and $497.5 million (or 101%) higher than fiscal 2006.

The Heavy Construction and Mining segment was a significant contributor to this growth with division revenue up $153.4 million from 2007 and $259.9 million higher than in 2006. Robust oil sands activity, including the ramp-up of the overburden removal contract with Canadian Natural, helped to support these results offsetting the effect of the completion of a significant contract with the De Beers’ mine in northern Ontario. The Pipeline segment also had a strongly positive impact, with revenue up $153.7 million compared to fiscal 2007 and $166.6 million compared to fiscal 2006 as work progressed on the Kinder Morgan TMX project. The Piling segment contributed the balance of the consolidated revenue growth as it responded to oil sands and commercial construction opportunities in western Canada.

Projects costs of $592.5 million represented 59.9% of total revenue in fiscal 2008, up from 57.8% last year. This increase reflected the higher volumes in our Pipeline operations, which use more subcontractors than our other business segments. Subcontractor costs were also higher on the Albian airstrip and Suncor Millenium Naptha Unit projects reflecting our role as general contractor. Overall equipment costs also increased in fiscal 2008 reflecting higher levels of fleet activity and tire cost inflation resulting from shortages of some types of tires. Subsequent improvements in our tire procurement and consumption practices, along with an easing of tire supply in the market, helped to reduce tire costs in the latter part of fiscal 2008.

Gross profit margin increased to 16.5% in fiscal 2008, from 14.7% last year. This improvement primarily reflects the return to profitability in our Pipeline operations and a favourable project mix in the Heavy Construction and Mining segment. Margins increased slightly compared to 2006 with gains in the Pipeline and Heavy Construction and Mining segments offsetting a decline in Piling margins. Piling margins returned to a more sustainable level in 2008 after benefiting from an unusually profitable project mix in 2007.

Fiscal 2008 general and administrative costs (G&A) were $69.7 million, an increase of $29.9 million over 2007 and $38.8 million higher than in fiscal 2006. Increased compensation costs, as a result of additions to our salaried workforce, was a significant contributor to this increase. G&A costs also include $1.9 million of costs relating to the secondary offering of common shares in the second quarter.

Net income for the year increased 88.7% to $39.8 million, or $1.11 per share, from $21.1 million, or $0.87 per share in the prior year. Unrealized non-cash gains and losses on foreign exchange and derivative financial instruments reduced net income by $5.5 million, net of tax, compared to a net gain of $6.1 million, net of tax, in the prior year. Excluding these items, basic earnings per share would have been $1.27 per share compared to $0.62 per share in the prior year.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Consolidated Results (Fourth Quarter)


	Three Months Ended March 31,
			% of					% of
	2008		Revenue			2007		Revenue
(dollars in thousands, except per share information)
Revenue	$	323,600		100.0	%	$	205,422		100.0	%
Project costs		195,196		60.3	%		131,815		64.2	%
Equipment costs		43,291		13.4	%		43,529		21.2	%
Equipment operating lease expense		9,990		3.1	%		4,083		2.0	%
Depreciation		12,550		3.9	%		12,369		6.0	%
Gross profit		62,573		19.3	%		13,626		6.6	%
General & administrative costs		20,674		6.4	%		8,875		4.3	%
Operating income		42,581		13.2	%		4,541		2.2	%
Net income (loss)		22,662		7.0	%		1,303		0.6	%
Per share information
Net income (loss) — basic	$	0.63				$	0.04
Net income (loss) — diluted		0.62					0.04
EBITDA⁽¹⁾	$	53,500		16.5	%	$	18,283		8.9	%
Consolidated EBITDA per bank⁽¹⁾		55,754		17.2	%		22,656		11.0	%


(1)		Non GAAP Financial measures — see footnote on page 4

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


	Three Months Ended March 31,
	2008			2007
(dollars in thousands)
Net income (loss)	$	22,662		$	1,303
Adjustments:
Interest expense		6,686			7,463
Income taxes		11,297			(2,942	)
Depreciation		12,550			12,369
Amortization of intangible assets		305			90

EBITDA	$	53,500		$	18,283

Adjustments:
(Gain) loss on disposal of plant and equipment		(671	)		120
Unrealized foreign exchange loss (gain) on senior notes		7,838			(2,480	)
Stock-based compensation		968			359
Director deferred stock unit expense		(190	)		—
Write-down of other assets to replacement cost		—			695
Write-off financing costs		—			4,342
Realized and unrealized loss (gain) on derivative financial instruments		(5,691	)		1,337

Consolidated EBITDA per bank	$	55,754		$	22,656

Revenues for the three months ended March 31, 2008 (fourth quarter) of $323.6 million were $118.2 million (or 58%) higher than in the same period last year. Strong revenue performance in Heavy Construction and Mining ($45.3 million favourable versus 2007) together with higher Pipeline revenue as a result of the TMX project (up $62.0 million), were key contributors to the year-over-year improvements.

Gross profit of $62.6 million in the fourth quarter of fiscal 2008 (19.3% of revenues in 2008 compared to 6.6% in 2007) was $48.9 million better than in fiscal 2007. The return to profitability in Pipeline (gross profit was $36.0 million higher than in fiscal 2007) was a leading factor in this improvement. Favourable margins in the Heavy Construction and Mining and Piling segments added to the gains. G&A costs of $20.7 million were $11.8 million higher than in the fourth quarter of 2007. The addition of new employees in response to growing demand for our services was the largest contributor to this increase.

Net income of $22.7 million increased by $21.4 million in the fourth quarter of fiscal 2008, driven by the improvements in operating income. Basic earnings per share for the quarter were $0.63 compared to $0.04 per share in the prior year. Unrealized non-cash losses on foreign exchange and unrealized non-cash gains on derivative financial instruments combined to reduce net income by $1.0 million, net of tax, compared a net gain of to $1.4 million, net of tax, in the prior year. Excluding these items, basic earnings per share would have been $0.66 per share compared to $0.00 per share in the prior year.

Segment results

Segmented profit includes revenue earned from the performance of our projects, including amounts arising from approved change orders and claims that have met the appropriate accounting criteria for recognition, less all direct projects expenses, including direct labour, short-term equipment rentals and materials, payments to subcontractors, indirect job costs and internal charges for use of capital equipment.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Heavy Construction and Mining


	Year Ended March 31,

			% of					% of					% of
	2008		Revenue			2007		Revenue			2006		Revenue

(dollars in thousands)
Segment revenue	$	626,582				$	473,179				$	366,721
Segment profit:	$	105,378		16.8	%	$	71,062		15.0	%	$	50,730		13.8	%

Heavy Construction and Mining revenues of $626.6 million were $153.4 million higher than in fiscal 2007 and $259.9 million more than in 2006. Oil sands construction continued to be a strong driver of the revenues for the segment. The segment benefited from site preparation and underground installations at Suncor’s Millennium and Voyager projects. We completed work on the Shell Albian airstrip and the DeBeers Diamond mine. We commenced work at Petro Canada’s Fort Hills site during the fourth quarter of fiscal 2008 and the continued ramp up of the Canadian Natural overburden removal contract was according to plan. On-time, on-budget execution of work on the Shell Albian airstrip project and the DeBeers contract was a significant contributor to margin improvements in this segment during fiscal 2008.

Piling


	Year Ended March 31,

			% of					% of					% of
	2008		Revenue			2007		Revenue			2006		Revenue

(dollars in thousands)
Segment revenue	$	162,397				$	109,266				$	91,434
Segment profit:	$	45,362		27.9	%	$	34,395		31.5	%	$	22,586		24.7	%

Piling revenues of $162.4 million in fiscal 2008 were $53.1 million higher than in fiscal 2007 and $71.0 million higher compared to fiscal 2006. Piling work for the Scotford Upgrader expansion combined with growth in Saskatchewan and the ongoing construction boom in Calgary drove the revenue improvements for the year. Margins from this segment returned to normal levels in 2008 after achieving record levels in 2007. Results for fiscal 2007 included a larger portion of higher-margin fixed price contracts while 2008 saw a return to a more balanced portfolio of lower-margin cost-plus and higher-margin fixed-price contracts. This led to normalized segment margins of 27.9% in fiscal 2008, compared to 31.5% in fiscal 2007. The benefits of the higher-margin 2007 work spilled over into the first quarter of fiscal 2008, resulting in higher year-over-year segment profits during the first quarter period.

Pipeline


	Year Ended March 31,

			% of						% of					% of
	2008		Revenue			2007			Revenue			2006		Revenue

(dollars in thousands)
Segment revenue	$	200,717				$	47,001					$	34,082
Segment profit:	$	25,465		12.7	%	$	(10,539	)		-22.4	%	$	8,996		26.4	%

Pipeline revenues for fiscal 2008 were $200.7 million, up $153.7 million from fiscal 2007 and $166.6 million from fiscal 2006. The completion of two pipeline projects in the first quarter of fiscal 2008 combined with the start of the TMX project in the second quarter led to significant revenue growth for the 2008 fiscal year compared to both fiscal 2007 and fiscal 2006. The cost plus contract for TMX progressed well through the year with production activity in line with schedule. This resulted in the Pipeline segment’s return to profitability in fiscal 2008. Losses experienced in fiscal 2007 and in the first quarter of fiscal 2008 related to a customer changing the scope of work on a fixed-price contract. These losses came about as a result of the customer enforcing a contractual right for us to commence work prior to renegotiating changes to contract pricing flowing from the scope change.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Fourth Quarter Segment Results

Heavy Construction and Mining


	Three Months Ended March 31,
			% of					% of
	2008		Revenue			2007		Revenue

(dollars in thousands)
Segment revenue	$	195,442				$	150,131
Segment profit:	$	36,747		18.8	%	$	23,512		15.7	%

Fourth quarter fiscal 2008 revenues of $195.4 million were $45.3 million higher than in the same period in fiscal 2007. The strong demand for site services work drove the improvement in revenue. Construction work on the Suncor Voyageur and Millennium Naptha Unit projects offset the fiscal 2007 revenues from the completion of the Shell Albian Crusher slot. Site preparation work commenced on the Petro Canada Fort Hills location during the fourth quarter offsetting the declines from reduced volume at the DeBeers diamond mine site. An increase in higher-margin site services and site preparation work lessened the effect of lower-margin overburden removal work leading to segment profits of 18.8% of revenues versus 15.7% in 2007.

Piling


	Three Months Ended March 31,
			% of					% of
	2008		Revenue			2007		Revenue

(dollars in thousands)
Segment revenue	$	40,699				$	29,872
Segment profit:	$	13,637		33.5	%	$	8,822		29.5	%

Fourth quarter fiscal 2008 Piling revenues of $40.7 million were $10.8 million higher than the same period in fiscal 2007. Plant and upgrader construction related to the oil sands was a significant contributor to the revenue growth. The Piling group also benefited from a high level of construction activity in Calgary. A favourable mix of work with projects related to upgrader expansion work saw segment margins increase to 33.5% in the fourth quarter of fiscal 2008, compared to 29.5% during the same period in fiscal 2007.

Pipeline


	Three Months Ended March 31,
			% of						% of
	2008		Revenue			2007			Revenue

(dollars in thousands)
Segment revenue	$	87,459				$	25,419
Segment profit:	$	11,311		12.9	%	$	(9,829	)		-38.7	%

The TMX project continued to drive revenues in the Pipeline division during the fourth quarter with this project contributing revenues of $87.5 million. Margins were also significantly ahead of last year as the Pipeline group returned to profitability after incurring losses on two fixed-price contracts in fiscal 2007. This resulted in a segment profit margin of 12.9% for the quarter, compared to a loss in fourth quarter of fiscal 2007. Losses in fiscal 2007 related primarily to, increased scope and condition changes on three large pipeline projects not recovered from our clients. We continue to pursue recovery of these changes with unapproved change orders and claims as a result of these losses but there has been no resolution of these outstanding unapproved change orders and claims.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Non — operating expense (income)


	Three Months Ended March 31,						Year Ended March 31,
	2008			2007			2008			2007			2006
(dollars in thousands)
Interest expense Interest on senior debt	$	5,835		$	5,835		$	23,338		$	27,417		$	28,838
Interest on revolving credit facility and other interest		399			635			2,063			1,157			1,421
Interest on capital lease obligations		283			245			780			725			457
Interest on NACG Preferred Corp. Series A preferred shares		—			—			—			1,400			—
Accretion and change in redemption value of mandatorily redeemable preferred shares		—			—			—			3,114			34,722
Amortization of deferred bond issue costs		169			—			838			—			—
Amortization of deferred financing costs		—			748			—			3,436			3,338


Total Interest expense	$	6,686		$	7,463		$	27,019		$	37,249		$	68,776


Foreign exchange (gain) loss on senior notes	$	7,694		$	(2,547	)	$	(25,442	)	$	(5,044	)	$	(13,953	)
Realized and unrealized (gain) loss on derivative financial instruments		(5,691	)		1,337			34,075			(196	)		14,689

Gain on repurchase of NACG Preferred Corp. Series A preferred shares		—			—			—			(9,400	)		—
Loss on extinguishment of debt		—			7			—			10,935			2,095
Other income		(67	)		(80	)		(418	)		(904	)		(977	)
Income tax (recovery) expense		11,297			(2,942	)		17,379			(2,593	)		737

Total interest expense decreased by $10.2 million in fiscal 2008, compared to the same period last year, primarily due to the retirement of the senior secured 9% notes with proceeds from our IPO and the exchange of the Series B redeemable preferred shares for common shares as part of the amalgamation that occurred prior to the IPO. The foreign exchange gains and losses recognized in the current and prior-year periods primarily relate to changes in the strength of the Canadian versus the U.S. dollar on conversion of the US$200 million of 8³/4% senior notes. The Canadian dollar has strengthened from $0.8674 CAN/US on April 1, 2007 to $0.9729 CAN/US on March 31, 2008.

The realized and unrealized gains on derivative financial instruments in the prior year reflect changes in the fair value of the cross-currency and interest rate swaps that we employ to provide an economic hedge for our US dollar denominated 8³/4% senior notes. Changes in the fair value of the swaps generally have an offsetting effect to changes in the value of our 8³/4% senior notes, both caused by variations in the Canadian/US foreign exchange rate. However, the valuation of the derivative financial instruments can also be impacted by changes in interest rates and the remaining present value of scheduled interest payments on the 8³/4% senior notes. Interest payments occur in the first and third quarters of each year until maturity.

Due to the adoption of a new Canadian accounting standard regarding financial instruments, the current year realized and unrealized gains and losses on derivative financial instruments also includes changes in the fair value of derivatives embedded in our US dollar denominated 8³/4% senior notes, in a long-term construction contract and in a supplier contract. In the current year, the change in the fair value of the swaps was a gain of $3.5 million during the fourth quarter and a $20.8 million loss during the fiscal year 2008. The balance of the realized and unrealized gains and losses on derivative financial instruments resulted from gain and losses on derivatives embedded in our 8³/4% senior notes, in a long-term construction contract, and in a supplier contract.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Effective April 1, 2007, we adopted the new Canadian CICA Handbook Section 3855 “Financial Instruments — Recognition and Measurement” which resulted in the recognition of derivatives embedded in our 8³/4% senior notes, in a long-term construction contract and in a supplier maintenance agreement as follows:

	•		Our 8³/4% senior notes include certain embedded derivatives, notably optional redemption and change of control redemption rights. These embedded derivatives met the criteria for separation from the debt contract and separate measurement at fair value. Upon adoption of Section 3855, we recorded a reduction in the carrying amount of our 8³/4% senior notes of $8.5 million together with related impacts on retained earnings and future income taxes on April 1, 2007. The change in the fair value of these embedded derivatives resulted in a pre-tax increase to earnings of $0.3 million in the fourth quarter and a change to earnings of $4.2 million in fiscal 2008.

	•		A long-term construction contract contains a price escalation feature that represents an embedded foreign currency and price index derivative that meets the criteria for separation from the host contract and separate measurement at fair value. Upon adoption of Section 3855, we recorded a liability of $7.2 million together with related impacts on retained earnings and future income taxes on April 1, 2007. The change in the fair value of the liability resulted in a pre-tax benefit to earnings of $1.4 million in the fourth quarter and a pre-tax charge to earnings of $7.6 million for fiscal 2008.

	•		We identified an additional embedded derivative that is not closely related to the host contract in the fourth quarter of 2008 with respect to a price escalation feature in a supplier contract. The embedded derivative has been measured at fair value. Upon adoption of Section 3855, we recorded a liability of $2.5 million together with related impacts on retained earnings and future income taxes on April 1, 2007. The change in the fair value of the liability resulted in a pre-tax gain of $1.2 million in the fourth quarter and a pre-tax gain of $1.2 million for fiscal 2008.

With respect to the early redemption provision in the 8³/4% senior notes, the process to determine the fair value of the implied derivative was to compare the rate on the notes to the best financial alternative. The fair value determined as at April 1, 2007 resulted in a positive adjustment to opening retained earnings. The change in fair value in future periods is recognized as a charge to earnings. Changes in fair value result from changes in long-term bond interest rates during that period. The valuation process presumes a 100% probability of our implementing the inferred transaction and does not permit a reduction in the probability if there are other factors that would impact the decision.

With respect to the customer contract, there is a provision that requires an adjustment to billings to our customer to reflect actual exchange rate and price index changes versus the contract amount. 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 new accounting guidelines for embedded derivatives will cause our reported earnings to fluctuate as currency exchange and interest rates change. The accounting for these derivatives will have no impact on operations, Consolidated EBITDA per bank or how we will evaluate performance.

We recorded income tax expense of $11.3 million in the fourth quarter and $17.4 million for fiscal 2008, as compared to an income tax recovery of $2.9 million and $2.6 million for the corresponding periods last year. Income tax expense as a percentage of income before tax for fiscal 2008 differs from the statutory rate of 31.47%, primarily due to the impact of the enacted rate changes during the year and the new accounting standards for the recognition, measurement and disclosure of financial instruments as certain embedded derivatives are considered capital in nature for income tax purposes. Income tax expense as a percentage of income before tax for the year ended March 31, 2007 differs from the statutory rate of 32.12% primarily due to the elimination of the valuation allowance of $5.9 million that was recorded during that period and a non taxable gain which resulted in a recovery for the year.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Consolidated Financial Position


(in thousands)	March 31, 2008			March 31, 2007			% Change
Current assets	$	291,086		$	229,061			27.1	%
Current liabilities		(183,353	)		(151,458	)		21.1	%
Net working capital		107,733			77,603			38.8	%
Plant and equipment		281,039			255,963			9.8	%
Total assets		793,598			710,736			11.7	%
Capital Lease obligations (including current portion)		14,776			9,709			55.7	%
Total long-term financial liabilities⁽¹⁾		(301,497	)		(295,288	)		2.1	%


(1)		Total long-term financial liabilities exclude the current portions of capital lease obligations, current portions of derivative financial instruments, both current and non-current future income taxes balances, and deferred leasehold inducement.

The strength of our financial position has improved over the last year. At March 31, 2008, we had net working capital (current assets less current liabilities) of $107.7 million compared to $77.6 million at March 31, 2007, an increase of $30.1 million. Positive cash flow caused our overall cash balance to increase by $25.0 million to $32.9 million. Increased revenues in the fourth quarter resulted in higher accounts receivable and unbilled revenue; up $60.8 million compared to the fourth quarter of fiscal 2007. Increased project activity drove accounts payable and accrued liabilities which increased by $40.3 million, mitigating the effect of higher receivables and repayment of borrowings under the revolving credit facility. Reductions in the number of truck tires on hand as well as an inventory of lower cost tires at year end versus the prior year resulted in a decline in other assets (included in current assets above) of $6.5 million compared to fiscal 2007 which lessened the effect of higher receivables in the same period.

Plant and equipment, net of depreciation, increased by $25.1 million for the 12 months ended March 31, 2008 as compared to the previous year. The purchase of additional haul trucks and Piling rigs (mainly in the second quarter) was partially offset by depreciation and the disposal of surplus equipment in the first quarter.

Capital lease obligations, including the current portion, increased by $5.1 million as of March 31, 2008, as compared to the prior year end, due to the acquisition of additional support vehicles.

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:

	•		Client requirements, specifications and design;

	•		Materials and work schedules; and

	•		Changes in ground and weather conditions.

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 management 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 the 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.

As a result of certain projects experiencing the changed conditions discussed above, at March 31, 2008 we had recognized approximately $13.0 million in additional contract costs from project inception to date, with no associated increase in contract value. 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.

Quarterly Operating Results


(dollars in millions, except per	Fiscal 2008									Fiscal 2007
share amounts)	Q4		Q3		Q2		Q1			Q4		Q3		Q2			Q1
Revenue	$	323.6	$	274.9	$	223.6	$	167.6		$	205.3	$	155.9	$	130.1		$	138.1
Gross profit		62.6		50.6		35.2		14.9			13.6		26.0		20.2			32.6
Operating income (loss)		42.6		33.2		17.1		(0.4	)		4.5		13.8		9.7			23.1
Net income (loss)		22.7		25.4		2.1		(10.3	)		1.3		6.6		(4.6	)		17.9
EPS — Basic⁽¹⁾	$	0.63	$	0.71	$	0.06	$	(0.29	)	$	0.04	$	0.27	$	(0.26	)	$	0.96
EPS — Diluted⁽¹⁾		0.61		0.69		0.06		(0.29	)		0.04		0.26		(0.26	)		0.71


(1)		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.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

related business so as to avoid or minimize periods of relative inactivity and the strength of the western Canadian economy.

By way of example, we generally experience a decline in revenues during the first quarter of each fiscal year (April 1 to June 30) due to seasonal weather conditions that make many roads unsuitable for the operation of heavy equipment. Conversely, we tend to experience our highest revenues in the latter half of our fiscal year as climatic conditions become favourable to our operating requirements. As a result, full-year results are not likely to be a direct multiple of any particular quarter or combination of quarters.

The timing of large projects can influence the quarterly revenue as well. For example, pipeline installation revenues were $31.3 million in the second quarter of fiscal 2008 (up $28.5 million from Q2 of fiscal 2007), $76.7 million in the third quarter of fiscal 2008 (up $61.5 million compared to Q3 of fiscal 2007) and $87.5 million in the fourth quarter of fiscal 2008 (up $62.0 million compared to Q4 of fiscal 2007). Heavy Construction and Mining saw increased revenues in fiscal 2008 arising from the execution of work with Suncor on the Millennium Naphtha Unit project under our five-year site services agreement and the construction of an aerodrome for Albian, along with increased demand under our master service agreements with Albian and Syncrude. Timing of work under the site services agreements can vary based on our customers’ production activities.

In addition to revenue variability, gross margins can be negatively impacted in less active periods, such as the first and second quarter, because we are likely to incur higher maintenance and repair costs due to our equipment being available for service as compared with the more active periods, such as the third and fourth quarter. We incurred higher equipment costs in the first quarter of fiscal 2008 due to the increased equipment repairs and tire costs.

Profitability also varies from period to period due to 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 seeClaims and Change Orders.During the first quarter of fiscal 2007, a $6.1 million dollar claim was recognized causing gross margins to increase above normal levels. The additional costs relating to the claim were incurred in fiscal 2005. During the fourth quarter of fiscal 2007 and the first half of fiscal 2008 we recognized additional costs related to fixed-price contracts in the Pipeline segment and as a result, we are currently working with our clients through the claims process.

Variations in quarterly results also result from our operating leverage. During the higher activity periods we have experienced improvements in operating income as certain costs, which are generally fixed, including general and administrative expenses, are spread over higher revenue levels. Net income and EPS are also subject to operating leverage as provided by fixed interest expense.

We have, however, experienced earnings variability in all periods due to the recognition of realized and unrealized non-cash gains and losses on derivative financial instruments and foreign exchange primarily driven by changes in the Canadian and US dollar exchange rates.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

C. Key Trends

Seasonality

A number of factors contribute to variations in our quarterly results between periods, including weather, capital spending by our customers on large oil sands projects, our ability to manage our project-related business so as to avoid or minimize periods of relative inactivity and the strength of the Western Canadian economy.

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 scheduled maintenance. Profitability also varies from period to period due to 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”.

During the higher activity periods we have experienced improvements in operating income due to operating leverage. General and administrative costs are generally fixed and we see these costs decrease as a percent of revenue. Net income and EPS are also subject to operating leverage as provided by fixed interest expense, however we have experienced earnings variability in all periods due to the recognition of realized and unrealized non-cash gains and losses on derivative financial instruments and foreign exchange primarily driven by changes in the Canadian and US dollar exchange rates.

Backlog

Backlog is a measure of the amount of secured work we have outstanding and as such is an indicator 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 that 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.

We work with our customers using cost-plus, time-and-materials, unit-price and lump-sum contracts and the mix of contract types varies year-by-year. Our definition of backlog results in the exclusion of cost-plus and time-and-material contracts performed under master service agreements where scope is not clearly defined. While contracts exist for a range of services to be provided, the work scope and value are not clearly defined under those contracts. For the 12 month period ended March 31, 2008, the total amount of revenue earned under the master services agreements that did not qualify for inclusion in our calculation of backlog was $223 million.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Our estimated backlog as at March 31, 2008 and 2007 was (in millions):


By Segment	March 31,
	2008		2007
Heavy Construction & Mining	$	896.3	$	732.0
Piling		20.5		40.0
Pipeline		65.5		16.0

Total	$	982.3	$	788.0


By Contract Type	March 31,
	2008		2007
Unit-Price	$	905.2	$	778.0
Lump-Sum		11.6		10.0
Time-and-Material, Cost-Plus		65.5		—

Total	$	982.3	$	788.0

A contract with a single customer represented approximately $778.4 million of the March 31, 2008 backlog. It is expected that approximately $366.1 million of the total backlog will be performed and realized in the 12 months ending March 31, 2009.*

Revenue Sources:

This section contains new disclosures.

We have experienced a steady growth in Master Services Agreements as oil sands development continues to grow. While there is no long term commitment from customers regarding this work as described below, we expect these trends to continue into fiscal 2009 as we continue to provide services to Syncrude and Suncor as well benefitting from the growth at the Shell sites.*

Long-term contracts.This category of revenue is generated from long-term contracts (greater than one year) with total contract values greater than $20 million. These contracts are for work that supports the operations of our customers and is therefore considered to be recurring including long-term contracts for overburden removal and reclamation. This revenue is typically generated under unit price contracts and is included in our calculation of backlog.

Master Services Agreements.This category includes revenue generated from the master services agreements in place with Syncrude, Suncor and Albian. This category of revenue is also generated by supporting the operations of our customers and is therefore considered to be recurring. This revenue is not guaranteed under contract and would not be included in our calculation of backlog. This revenue is primarily generated under time-and-materials arrangements.

* This sentence or paragraph contains forward looking statements. 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
For the year ended March 31, 2008

Major Projects.Revenue generated from projects with contract values greater than $20 million and durations of greater than 6 months. This category of revenue is typically generated supporting major capital construction projects and is therefore considered to be non-recurring. This revenue can be generated under lump-sum, unit-price, time-and-materials and cost-plus contracts. This revenue can be included in backlog if generated under lump-sum, unit-price or time-and-materials contracts.

Other Projects.Revenue generated from contracts with values of less than $20 million and durations of, typically, less than 6 months. This category of revenue is generally driven by capital construction and is therefore non-recurring. This revenue can be generated under lump-sum, unit-price, time-and-materials and cost-plus contracts. This revenue is included in backlog if generated under lump-sum, unit-price contracts or time-and-materials contracts.

Projects in the oil sands increased our work volumes during 2008. The pipeline installation project for Kinder Morgan increased our revenues in the conventional oil and gas sector. Minerals mining work slowed in 2008 as we completed the work on the DeBeers diamond mine project.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Contracts

We complete work under the following types of contracts: cost-plus, time-and-materials, unit-price and lump-sum. Each contract contains a different level of risk associated with its formation and execution.

Cost-plus.A cost-plus contract is a contract in which all the work is completed based on actual costs incurred to complete the work. These costs include all labor, equipment, materials and any subcontractor’s costs. In addition to these direct costs, all site and corporate overhead costs are charged to the job. An agreed upon fee in the form of a fixed percentage is then applied to all costs charged to the project. This type of contract is utilized where the project involves a large amount of risk or the scope of the project cannot be readily determined.

Time-and-materials.A time-and-materials contract involves using the components of a cost-plus job to calculate rates for the supply of labor and equipment. In this regard, all components of the rates are fixed and we are compensated for each hour of labor and equipment supplied. The risk associated with this type of contract is the estimation of the rates and incurrence of expenses in excess of a specific component of the agreed-upon rate. Any cost overrun, in this type of contract, must come out of the fixed margin included in the rates.

Unit-price.A unit-price contract is utilized in the execution of projects with large repetitive quantities of work and is commonly utilized for site preparation, mining and pipeline work. We are compensated for each unit of work we perform (for example, cubic meters of earth moved, lineal meters of pipe installed or completed piles). Within the unit-price contract, there is an allowance for labor, equipment, materials and any subcontractor’s costs. Once these costs are calculated, we add any site and corporate overhead costs along with an allowance for the margin we want to achieve. The risk associated with this type of contract is in the calculation of the unit costs with respect to completing the required work.

Lump sum.A lump-sum contract is utilized when a detailed scope of work is known for a specific project. Thus, the associated costs can be readily calculated and a firm price provided to the customer for the execution of the work. The risk lies in the fact that there is no escalation of the price if the work takes longer or more resources are required than were estimated in the established price, as the price is fixed regardless of the amount of work required to complete the project.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Major Suppliers

We have long-term relationships with the following equipment suppliers: Finning International Inc. (45 years), Wajax Income Fund (20 years) and Brandt Tractor Ltd. (30 years). Finning is a major Caterpillar heavy equipment dealer for Canada. Wajax is a major Hitachi equipment supplier to us for both mining and construction equipment. We purchase or rent John Deere equipment, including excavators, loaders and small bulldozers, from Brandt Tractor. In addition to the supply of new equipment, each of these companies is a major supplier for equipment rentals, parts and service labor.

Tire supply remains a challenge for our haul truck fleet. We prefer to use radial tires from proven manufacturers, but the shortage of supply has forced us to increase the use of bias tires and radial tires from new manufacturers. Bias tires have a shorter usage life and are of a lower quality than radial tires. This affects operations as we are forced to reduce operating speeds and loads to compensate for the quality of the tires. During the year ended March 31, 2008 we reduced our inventory of bias tires for the 150 ton haul trucks and are now acquiring radial tires for these trucks as required. Tires for 240 ton haul trucks continue to be in short supply. To address the shortfall we are purchasing bias tires from new manufacturers and radial tires from non dealer sources at a large premium above dealer prices. We were able to negotiate a five year contract (commencing in 2008) with Bridgestone Firestone Canada Inc. to secure a tire allotment for select tire sizes for the 240 to 320 ton haul trucks which will alleviate some of the shortage. We are continuing negotiations with Bridgestone to improve the security of tire supply. We have also been successful in acquiring radial tires with new trucks as they are delivered and hope to continue this practice in fiscal 2009 and fiscal 2010. Suppliers have improved overall tire supply, but we believe the tire shortage will remain an issue for the foreseeable future.*

Competition

Our industry is highly competitive in each of our markets. Historically, the majority of our new business was awarded to us based on past client relationships without a formal bidding process, in which, typically, a small number of pre-qualified firms submit bids for the project work. Recently, in order to generate new business with new customers, we have had to participate in formal bidding processes. As new major projects arise, we expect to have to participate in bidding processes on a meaningful portion of the work available to us on these projects. Factors that impact competition include price, safety, reliability, scale of operations, availability and quality of service. Most of our clients and potential clients in the oil sands area operate their own heavy mining equipment fleet. However, these operators have historically outsourced a significant portion of their mining and site preparation operations and other construction services.*

Our principal competitors in the heavy construction and mining segment include Cow Harbour, Cross Construction Ltd., Klemke Mining Corporation, Ledcor Construction Limited, Peter Kiewit & Sons Co., Tercon Contractors Ltd., Sureway Construction Ltd. and Thompson Bros. (Constr) Ltd. In underground utilities installation (a part of our Heavy Construction and Mining segment) Voice Construction Ltd., Ledcor Construction Limited and I.G.L. Industrial Services are our major competitors. The main competition to our deep foundation Piling operations comes from Agra Foundations Limited, Double Star Co. and Ruskin Construction Ltd. The primary competitors in the pipeline installation business include Ledcor Construction Limited, Washcuk Pipe Line Construction Ltd. and Willbros.

In the public sector, we compete against national firms, and there is usually more than one competitor in each local market. Most of our public sector customers are local governments that are focused on serving only their local regions. Competition in the public sector continues to increase, and we typically choose to compete on projects only where we can utilize our equipment and operating strengths to secure profitable business.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

D. Outlook

Moving forward, continued development of the oil sands is expected to drive a significant portion of our fiscal 2009 revenue. In addition to existing mining and site services contracts with customers including Canadian Natural, Suncor, Syncrude, Albian and Petro-Canada, we also anticipate increased demand for our services at Petro-Canada’s Fort Hills site as that project progresses.*

Outside of the oil sands, we are providing constructability assistance to Baffinland Iron Mines Corp. as it prepares feasibility studies for an iron ore development in northern Canada. This customer approached us based on our experience and success at De Beers’ Victor Project in northern Ontario and we expect our involvement on their project will continue to grow. Our success with the Albian aerodrome project, meanwhile, has resulted in significant interest from customers looking to develop airstrips in northern Alberta.*

Demand for our piling services is expected to remain strong in fiscal 2009 with commercial construction activity at a high level in western Canada. A number of upgrader facilities are also being considered for the Edmonton area, providing opportunities to bid on larger-scale piling contracts.*

While we anticipate a temporary slowdown in our pipeline activity once the TMX project concludes in October 2008, we see significant long-term opportunities for this division. More than 5 major new pipeline projects are planned for western Canada to relieve limited capacity and accommodate growing oil sands production. We believe our success on the large and environmentally-demanding TMX project positions us to compete effectively as the new pipeline projects are tendered.*

Overall, our outlook for fiscal 2009 remains positive.

E. 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, among others:

	•		permitting and licensing requirements applicable to contractors in their respective trades;

	•		building and similar codes and zoning ordinances;

	•		laws and regulations relating to consumer protection; and

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

We believe we have all material required permits and licenses to conduct our operations and are in substantial compliance with applicable regulatory requirements relating to our operations. Our failure to comply with the applicable regulations could result in substantial fines or revocation of our operating permits.

Our operations are subject to numerous federal, provincial and municipal environmental laws and regulations, including those governing the release of substances, the remediation of contaminated soil and groundwater, vehicle emissions and air and water emissions. These laws and regulations are administered by federal, provincial and municipal authorities, such as Alberta Environment, Saskatchewan Environment, the British Columbia Ministry of Environment, and other governmental agencies. The requirements of these laws and regulations are becoming increasingly complex and stringent, and meeting these requirements can be expensive. The nature of our operations and our ownership or operation of property exposes us to the risk of claims with respect to environmental matters, and there can be no assurance that material costs or liabilities will not be incurred with such claims. For example, some laws can impose strict, joint and several liability on past and present owners or operators of facilities at, from or to which a release of hazardous substances has occurred, on parties who generated hazardous substances that were released at such facilities and on parties who arranged for the transportation of hazardous substances to such facilities. If we were found to be a responsible party under these statutes, we could be held liable for all investigative and remedial costs associated with addressing such contamination, even though the releases were caused by a prior owner or operator or third party. We are not currently named as a responsible party for any environmental liabilities on any of the properties on which we

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

currently perform or have performed services. However, our leases typically include covenants which obligate us to comply with all applicable environmental regulations and to remediate any environmental damage caused by us to the leased premises. In addition, claims alleging personal injury or property damage may be brought against us if we cause the release of, or any exposure to, harmful substances.

Our construction contracts require us to comply with all environmental and safety standards set by our customers. These requirements cover such areas as safety training for new hires, equipment use on site, visitor access on site and procedures for dealing with hazardous substances.

Capital expenditures relating to environmental matters during the fiscal years ended March 31, 2006, 2007 and 2008 were not material. We do not currently anticipate any material adverse effect on our business or financial position as a result of future compliance with applicable environmental laws and regulations. Future events, however, such as changes in existing laws and regulations or their interpretation, more vigorous enforcement policies of regulatory agencies or stricter or different interpretations of existing laws and regulations may require us to make additional expenditures which may be material.*

Employees and Labor Relations

As of March 31, 2008, we had over 280 salaried employees and over 2,100 hourly employees. During fiscal 2008 we welcomed 71 new salaried employees and 581 new hourly employees, bringing our total number of employees to 2,410 at March 31, 2008. Our hourly workforce will fluctuate according to the seasonality of our business from an estimated low of 1,500 employees in the spring to a high of approximately 2,400 employees over the winter. 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 2,000 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 expires on October 31, 2009. A small portion of our employees work under an Industrial collective bargaining agreement with the Alberta Road Builders and Heavy Construction Association and the International Union of Operating Engineers Local 955, the primary term of which expires February 28, 2009. 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. We believe that our relationships with all our employees, both union and non-union, are satisfactory. We have not yet experienced a strike or lockout.

F. Resources and Systems

Outstanding Share Data

We are authorized to issue an unlimited number of common voting shares and an unlimited number of common non-voting shares. As at June 20, 2008, 36,016,476 common voting shares were outstanding compared to 35,929,476 common voting shares as at March 31, 2008 and 35,192,260 common voting shares and 412,400 non-voting common shares as at March 31, 2007. As at June 20, 2008 there are no non-voting shares outstanding.

Liquidity

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.

Our long-term debt includes US$200 million of 8³/4% senior notes due in 2011. The foreign currency risk relating to both the principal and interest portions of these senior notes has been managed with a cross-currency swap and interest rate swaps, which went into effect concurrent with the issuance of the notes on November 26, 2003. The swap agreement is an economic hedge but

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

has not been designated as a hedge for accounting purposes. Interest totaling $13.0 million on the 8³/4% senior notes and the swap is payable semi-annually in June and December of each year until the notes mature on December 1, 2011. The $200 million US principal amount was hedged at C$1.315=US$1.000, resulting in a principal repayment of $263 million due on December 1, 2011. There are no principal repayments required on the 8³/4% senior notes until maturity.

One of our major contracts allows the customer to require that we provide up to $50 million in letters of credit. As at March 31, 2008, we had $20 million in letters of credit outstanding in connection with this contract. Any change in the amount of the letters of credit required by this customer must be requested by November 1^st for an issue date of January 1^st, each year for the remaining life of the contract.

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 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 for sustaining capital expenditures and our total capital requirements will typically range from $125 million to $200 million depending on our growth capital requirements. We typically finance approximately 30% to 50% of our total capital requirements through our operating lease facilities, 5% to 10% through capital lease facilities and the remainder out of cash flow from operations. We believe our operating and capital lease facilities and cash flow from operations will be sufficient to meet these requirements.

Sources of liquidity

Our principal sources of cash are funds from operations and borrowings under our revolving credit facility. As of March 31, 2008, we had approximately $105 million of available borrowings under the revolving credit facility after taking into account $20.0 million of outstanding and undrawn letters of credit to support performance guarantees associated with customer contracts. The indebtedness under the revolving credit facility is secured by a first priority lien on substantially all of our existing and after-acquired property.

Our revolving credit facility contains covenants that restrict our activities, including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions. Under the revolving credit facility Consolidated Capital Expenditures during any applicable period cannot exceed 120% of the amount in the capital expenditure plan. In addition, we are required to satisfy certain financial covenants, including a minimum interest coverage ratio and a maximum senior leverage ratio, both of which are calculated using Consolidated EBITDA per bank, as well as a minimum current ratio.

Consolidated EBITDA per bank is defined in the credit facility as the sum, without duplication, of (1) consolidated net income, (2) consolidated interest expense, (3) provision for taxes based on income, (4) total depreciation expense, (5) total amortization expense, (6) costs and expenses incurred by us in entering into the credit facility, (7) accrual of stock-based compensation expense to the extent not paid in cash or if satisfied by the issue of new equity, and (8) other non-cash items (other than any such non-cash item to the extent it represents an accrual of or reserve for cash expenditure in any future period), but only, in the case of clauses (2)-(8), to the extent deducted in the calculation of consolidated net income, less 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 for us in conformity with Canadian GAAP.

Interest coverage is determined based on a ratio of Consolidated EBITDA per bank to consolidated cash interest expense, and the senior leverage is determined as a ratio of senior debt to Consolidated EBITDA per bank. Measured as of the last day of each fiscal quarter on a trailing four-quarter basis, Consolidated EBITDA per bank shall not be less than 2.5 times consolidated cash interest expense (2.35 times at June 30, 2007). Also, measured as of the last day of each fiscal quarter on a trailing

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

four-quarter basis, senior leverage shall not exceed 2 times Consolidated EBITDA per bank. We believe Consolidated EBITDA per bank as defined in the credit facility is an important measure of our performance.

Revolving credit facility

We entered into an amended and restated credit agreement dated as of June 7, 2007 with a syndicate of lenders that provides us with a $125.0 million revolving credit facility. Our revolving credit facility provides for an original principal amount of up to $125.0 million under which revolving loans may be made and under which letters of credit may be issued. The facility will mature on June 7, 2010, subject to possible extension. The credit facility is secured by a first priority lien on substantially all of our and our subsidiaries’ existing and after-acquired property (tangible and intangible), including, without limitation, accounts receivable, inventory, equipment, intellectual property and other personal property, and real property, whether owned or leased, and a pledge of the shares of our subsidiaries, subject to various exceptions.

The facility bears interest on each prime loan at variable rates based on the Canadian prime rate plus the applicable pricing margin (as defined in the credit agreement). Interest on U.S. base rate loans is paid at a rate per annum equal to the U.S. base rate plus the applicable pricing margin. Interest on prime and U.S. base rate loans is payable monthly in arrears and computed on the basis of a 365- or 366-day year, as the case may be. Interest on LIBOR loans is paid during each interest period at a rate per annum, calculated on a 360-day year, equal to the LIBOR rate with respect to such interest period plus the applicable pricing margin.

The credit facility may be prepaid in whole or in part without penalty, except for bankers’ acceptances, which will not be prepayable 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.

Under the credit facility, we are required to satisfy certain financial covenants, including a current ratio, a senior leverage ratio and an interest coverage ratio.

Working capital fluctuations effect on cash

The seasonality of our work may result in a slow down in cash collections between December and early February which may result in an increase in our working capital requirements. Our working capital is also significantly affected by the timing of completion of projects. Our customers are permitted to withhold payment of a percentage (defined by the contract and in some cases provincial legislation) of the amount owing to us for a stipulated period of time (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. 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). As at March 31, 2008 we saw holdbacks increase to $35 million from $19.5 million in 2007. This represents 21% (18% for 2007) of our total Accounts Receivable outstanding as at March 31, 2008. This increase is attributable to the stronger revenues in the last half of fiscal 2008 with a corresponding increase in work in progress resulting in more holdbacks at year end. As at March 31, 2008 we carried $22.4 million in holdbacks for two large projects (the DeBeers Victor Diamond Mine and the Kinder Morgan pipeline project). The holdback for DeBeers was subsequently collected in May 2008 reducing holdbacks by $11 million. As at March 31, 2007 we carried $5.2 million in holdbacks for the DeBeers project.

Debt Ratings

In December 2007, Standard & Poor’s upgraded our debt rating to B+ (from B) with a stable outlook following a review of our current and prospective business risk and financial risk profiles. In March 2008, Standard & Poor’s upgraded our senior unsecured notes rating to B+ with a recovery rating of “4” indicating an expectation for an average of (30% — 50%) recovery in the event of a payment default.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

In December 2007 Moody’s maintained our debt rating at B2 with a stable outlook (the upgrade to B2 was issued in December 2006 following our IPO). Moody’s rates our senior unsecured notes at B3 with a loss given default rating of 5.

Cash Flow


	Three Months Ended March 31,									Year Ended March 31,
(in thousands)	2008			2007			2006			2008			2007			2006
Cash provided by operating activities	$	36,183		$	7,392		$	17,152		$	97,600		$	2,130		$	33,701
Cash (used in) investing activities		(2,746	)		(10,901	)		(5,814	)		(48,632	)		(100,050	)		(22,005	)
Cash (used in) provided by financing activities		(21,809	)		4,297			(332	)		(23,992	)		63,011			13,184

Net increase (decrease) in cash and cash equivalents	$	11,628		$	788		$	11,006		$	24,976		$	(34,909	)	$	24,880

Operating activities

Operating activities in the fourth quarter benefitted from the favourable cash collections in the last half of fiscal 2008 resulting in a net cash increase of $36.0 million compared to $7.4 million in fiscal 2007. Operating activities in fiscal 2008 resulted in a net increase in cash of $97.6 million, compared to an increase of $2.1 million in fiscal 2007 and an increase of $33.7 million in fiscal 2006. Strong earnings performance in 2008, combined with favourable cash collections (minimizing working capital increases), drove the improvement in cash collections compared to fiscal 2007. The lower cash generated in fiscal 2007 compared to fiscal 2006 was the result of movements in net non-cash working capital from increased accounts receivable balances and deposits on tire purchases.

Investing activities

Sustaining capital expenditures are those that are required to keep our existing fleet of equipment at its optimal useful life through capital maintenance or replacement. Growth capital expenditures relate to equipment additions required to perform larger or a greater number of projects.

During fiscal 2008, we invested $21.3 million in sustaining capital expenditures (2007— $7.6 million; 2006 — $7.4 million) and invested $36.5 million in growth capital expenditures (2007 — $102.4 million; 2006 — $21.5 million), for total capital expenditures of $57.8 million (2007 — $110.0 million; 2006 — $28.9 million). Proceeds from asset disposals of $17.1 million in fiscal 2008 ($3.6 million in fiscal 2007 and $5.5 million in fiscal 2006) lessened the effect of capital purchases resulting in net cash invested of $48.6 million for fiscal 2008 ($100.1 million in fiscal 2007 and $22.0 million in fiscal 2006). A shift to operating leases to fund equipment purchases saw an additional $88.7 million (2007 — $49.5 million; 2006 — $18.9 million) not reflected in the capital spent for 2008. The significant increase in 2007 growth capital expenditures reflects the purchase of certain leased equipment for $44.6 million using a portion of the net IPO proceeds and the purchase of several large trucks to accommodate the increasing volume of available work.

Financing activities

Financing activities in 2008 resulted in a cash outflow of $24.0 million as we repaid $20.5 million on the revolving credit facility in the fourth quarter of 2008. Cash inflows in 2007 were primarily provided by the net proceeds of our IPO as described in the following paragraph, offset by the repayment of our 9% senior secured notes. Financing activities during 2006 resulted in net cash inflow of $13.2 million. This inflow reflects proceeds received from our May 19, 2005 issuance of the US$60.5 million of 9% senior secured notes and $7.5 million of Series B preferred shares of our predecessor company. A significant portion of the proceeds from these issues was used to repay the amount outstanding under our senior secured credit facility at the time.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Capital commitments

Contractual Obligations and Other Commitments

Our principal contractual obligations relate to our long-term debt and capital and operating leases. The following table summarizes our future contractual obligations, excluding interest payments unless otherwise noted, as of March 31, 2008.


	Payments due by fiscal year
											2013 and
(in millions)	Total		2009		2010		2011		2012		after
Senior notes⁽¹⁾	$	263.0	$	—	$	—	$	—	$	263.0	$	—
Capital leases (including interest)		16.4		5.5		4.7		3.3		2.7		0.2
Operating leases		96.0		31.1		26.0		16.5		10.9		11.5
Supplier contracts		36.6		5.3		6.0		8.2		9.8		7.3

Total contractual obligations	$	412.0	$	41.9	$	36.7	$	28.0	$	286.4	$	19.0


(1)		We have entered into cross-currency and interest rate swaps, which represent an economic hedge of the 8³/4% senior notes. At maturity, we will be required to pay $263.0 million in order to retire these senior notes and the swaps. This amount reflects the fixed exchange rate of C$1.315=US$1.00 established as of November 26, 2003, the inception of the swap contracts. At March 31, 2008 the carrying value of these derivative financial instruments was $81.6 million, inclusive of the interest components.

Off-Balance Sheet Arrangements

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

Cash Requirements

As of March 31, 2008 our cash balance of $32.9 million was $25.0 million higher than our cash balance in fiscal 2007. We anticipate that we will continue to generate a net cash surplus in fiscal 2009 from cash generated from operations. In the event that we require additional funding, we believe that any such funding requirements would be satisfied by the funds available from our revolving credit facility.*

Internal Systems and Processes

Overview of information systems

We currently use JDE (Enterprise One) as our Enterprise Resource Planning (ERP) tool and deploy the financial system, payroll, procurement, job costing and equipment maintenance modules from this tool. We supplement this functionality with either third-party software (for our estimating system) or in-house developed tools (for project management).

In fiscal 2008 we focused on developing systems and processes using our ERP system to increase the automation of transactional activities and improve management information. The proper identification of costs is a critical part of our ability to recognize revenues and we have focused resources to address this issue. Throughout fiscal 2008 we concentrated on the development of better cost tracking tools through the implementation of a procure-to-pay process in our ERP system. We also started work on improving the process for tracking and reporting equipment and maintenance costs. Despite some initial implementation hurdles over the summer and fall of 2007, we are beginning to see improvements in the identification and tracking of our procurement costs.

We are currently performing a user needs analysis and comparing this to the functionality of our ERP system. We will make a determination over the first quarter of fiscal 2009 whether we can implement additional modules or commence a review of industry-specific software to supplement our existing ERP functionality.

During the 2008 fiscal year we experienced significant staff turnover within the financial reporting team while experiencing significant revenue growth during the same period. These two factors significantly impacted the effectiveness of our internal systems and processes as discussed below.

Evaluation of Disclosure Controls and Procedures

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by the Company is recorded, processed, summarized and reported within the time periods specified under Canadian and U.S. 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 disclosure.

As of March 31, 2008, an evaluation was carried out under the supervision of and with the participation of management, including the President and Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) under the U.S. Securities Exchange Act of 1934 and in Multilateral Instrument 52-109 under the Canadian Securities Administrators Rules and Policies. Based on that evaluation, the President and Chief Executive Officer and Chief Financial Officer concluded that as a result of the material weaknesses in the Company’s internal control over financial reporting discussed below the disclosure controls and procedures were not effective as of the end of the period covered by this annual report.

Management’s Report on Internal Controls over Financial Reporting (ICFR):

Internal control over financial reporting is a process designed to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and of the preparation of financial statements for external purposes in accordance with Canadian generally accepted accounting principles (GAAP) and reconciled to US GAAP. Management, including the President and Chief Executive Officer and Chief Financial Officer, are responsible for establishing and maintaining adequate ICFR, as such term is defined in Rule 13a-15(e) under the US Securities Exchange Act of 1934 and in Multilateral Instrument 52-109 under the Canadian Securities Administrators Rules and Policies to provide reasonable, but not absolute, assurance regarding the reliability of our financial reporting. A material weakness in ICFR exists if the deficiency is such that there is reasonable possibility that a material misstatement of our annual or interim consolidated financial statements will not be prevented or detected on a timely basis.

Because of its inherent limitations, ICFR may not prevent or detect misstatements. Also, projections or any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As of March 31, 2008 we assessed the effectiveness of the Company’s 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 material weaknesses in internal controls over financial reporting as described below.

Given the circumstances outlined above, we did not maintain effective processes and controls related to the following:

	•		Specific to complex and non routine transactions and period end controls: There was a lack of sufficient accounting and finance personnel with an appropriate level of technical accounting knowledge and training commensurate with the complexity of the Company’s financial accounting and reporting requirements. Complex and non routine financial reporting matters that would be affected by this deficiency include the identification of embedded derivatives and preparation of the Company’s US GAAP reconciliation note. Additionally, we did not adequately perform period end controls related to the review and approval of account analysis, verification of inputs and reconciliations. The accounts that would be affected by these deficiencies are cash, senior notes, contributed surplus, stock-based compensation expense, foreign exchange gain and related financial statement disclosures.

	•		Specific to revenue recognition: A formal process to track claims and unapproved change orders and sufficient monitoring controls over the completeness and accuracy of forecasts, including the consideration of project changes subsequent to the end of each reporting period, were not effectively implemented. The accounts that would be affected by these deficiencies are revenue, project costs, unbilled revenue and billings in excess of costs incurred and estimated earnings on uncompleted contracts.

	•		Specific to accounts payable and procurement — We did not have an effectively implemented procurement

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

process to track purchase commitments, reconcile vendor accounts and accurately accrue costs not invoiced by vendors at each reporting date. The accounts that would be affected by these deficiencies are accounts payable, accrued liabilities, unbilled revenue, billings in excess of costs incurred and estimated earnings on uncompleted contracts, revenue, project costs, equipment costs, general and administrative costs and other expenses.

These material weaknesses in ICFR, which are pervasive in nature, resulted in material errors in the financial statements that were noted by our external auditors and corrected prior to release of the financial statements, and therefore, 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 weaknesses, we have concluded that the Consolidated Financial Statements included in this report fairly present the Company’s consolidated financial position and consolidated results of operations as of and for the fiscal year ending March 31, 2008.

Remediation plans

In response to the material weaknesses identified above, the Company has undertaken the following actions:

	•		We have taken steps to rectify the complex and non-routine transactions and period end control weaknesses by reorganizing the corporate accounting group and recruiting new staff with the appropriate levels of experience and technical skills to prevent a reoccurrence of these issues.

	•		We implemented new processes over revenue recognition in the last quarter of fiscal 2008. These processes have not been in place long enough to fully evaluate the effectiveness of the controls. We are evaluating the results of the implementation over the next two quarters to ensure that the new controls adequately address our ability to recognize revenue in the correct period.

	•		During the last quarter of fiscal 2008 we developed new procurement processes and started a redesign of our ERP system to address the internal control deficiencies. During this redesign and implementation phase we implemented monitoring and detective controls to address our deficiencies. We are evaluating the results of the implementation over the next two quarters to ensure that these mitigating controls adequately address our ability to identify our costs in a timely manner.

Changes to Internal Control over Financial Reporting

In our 2007 fiscal year we identified the following additional material weaknesses in our ICFR. These weaknesses were remediated in 2008 as follows:

	•		Income taxes — there was a lack of review and monitoring controls as well as a lack of segregation of duties of the income tax function. New review processes together with increased technical support from third party experts have improved the review and monitoring controls and addressed the segregation of duties issues in the income tax function.

	•		IT General Controls (“ITGCs”) — A number of deficiencies in ITGCs were identified, including appropriate controls around spreadsheets and end-user computing, controls over access to and the accuracy of one of our systems, as well as general maintenance of access rights and nominal program change controls. When aggregated, these deficiencies represented a material weakness in ICFR. Improvements to access rights and program change controls were implemented in fiscal 2008 to address certain of the deficiencies identified in fiscal 2007.

Significant Accounting Policies

Critical Accounting Estimates

Certain accounting policies require management to make significant estimates and assumptions about future events that affect the amounts reported in our financial statements and the accompanying notes. Therefore, the determination of estimates requires the exercise of management’s judgment. Actual results could differ from those estimates and any differences may be material to our financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Revenue recognition

Our contracts with customers fall under the following contract types: cost-plus, time-and-materials, unit-price and lump-sum. While contracts are generally less than one year in duration, we do have several long-term contracts. The mix of contract types varies year-by-year. For the year ended March 31, 2008, our revenue consisted of 55.0% time-and-materials, 37.3% unit-price and 7.7% lump-sum.

Profit for each type of contract is included in revenue when its realization is reasonably assured. Estimated contract losses are recognized in full when determined. Claims and unapproved change orders are included in total estimated contract revenue only to the extent that contract costs related to the claim or unapproved change order have been incurred, when it is probable that the claim or unapproved change order will result in a bona fide addition to contract value and the amount of revenue can be reliably estimated.

The accuracy of our revenue and profit recognition in a given period is dependent, in part, on the accuracy of our estimates of the cost to complete each unit-price and lump-sum project. Our cost estimates use a detailed “bottom up’’ approach, using inputs such as labour and equipment hours, detailed drawings and material lists. These estimates are updated monthly. We have noted a material weakness related to our procurement processes. This is discussed in more detail in the section “Management’s Report on Internal Controls over Financial Reporting.” To address these weaknesses, we implemented monitoring and review controls to assist with the determination of our cost estimates. These controls require a significant review of our payable activities after month end to ensure that we have identified project costs in the correct period. Given the time delay in identifying costs we may misstate revenues. However, we believe our experience allows us to produce materially reliable estimates. Our projects can be highly complex and in almost every case, the profit margin estimates for a project will either increase or decrease to some extent from the amount that was originally estimated at the time of the related bid. Because we have many projects of varying levels of complexity and size in process at any given time, these changes in estimates can offset each other without materially impacting our profitability. However, sizable changes in cost estimates, particularly in larger, more complex projects, can have a significant effect on profitability. Factors that can contribute to changes in estimates of contract cost and profitability include, without limitation:

	•		site conditions that differ from those assumed in the original bid, to the extent that contract remedies are unavailable;

	•		identification and evaluation of scope modifications during the execution of the project;

	•		the availability and cost of skilled workers in the geographic location of the project;

	•		the availability and proximity of materials;

	•		unfavorable weather conditions hindering productivity;

	•		equipment productivity and timing differences resulting from project construction not starting on time; and

	•		general coordination of work inherent in all large projects we undertake.

The foregoing factors, as well as the stage of completion of contracts in process and the mix of contracts at different margins, may cause fluctuations in gross profit between periods and these fluctuations may be significant. These changes in cost estimates and revenue recognition impact all three business segments, namely, heavy construction and mining, piling and pipeline installation.

Once contract performance is underway, we will often experience changes in conditions, client requirements, specifications,

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

designs, materials and work schedule. Generally, a “change order” will be negotiated with the customer to modify the original contract to approve both the scope and price of the change. Occasionally, however, disagreements arise regarding changes, their nature, measurement, timing and other characteristics that impact costs and revenue under the contract. When a change becomes a point of dispute between us and a customer, we will then consider it as a claim.

Costs related to change orders and claims are recognized when they are incurred. Change orders are included in total estimated contract revenue when it is probable that the change order will result in a bona fide addition to contract value and can be reliably estimated. Claims are included in total estimated contract revenue, only to the extent that contract costs related to the claim have been incurred and when it is probable that the claim will result in a bona fide addition to contract value and can be reliably estimated. Those two conditions are satisfied when (1) the contract or other evidence provides a legal basis for the claim or a legal opinion is obtained providing a reasonable basis to support the claim, (2) additional costs incurred were caused by unforeseen circumstances and are not the result of deficiencies in our performance, (3) costs associated with the claim are identifiable and reasonable in view of work performed and (4) evidence supporting the claim is objective and verifiable. No profit is recognized on claims until final settlement occurs. This can lead to a situation where costs are recognized in one period and revenue is recognized when customer agreement is obtained or claim resolution occurs, which can be in subsequent periods. Historical claim recoveries should not be considered indicative of future claim recoveries.

Plant and equipment

The most significant estimates in accounting for plant and equipment are the expected useful life of the asset and the expected residual value. Most of our property, plant and equipment have long lives that can exceed 20 years with proper repair work and preventative maintenance. Useful life is measured in operating hours, excluding idle hours and a depreciation rate is calculated for each type of unit. Depreciation expense is determined monthly based on daily actual operating hours.

Another key estimate is the expected cash flows from the use of an asset and the expected disposal proceeds in applying Canadian Institute of Chartered Accountants Handbook Section 3063 “Impairment of Long-Lived Assets’’ and Section 3475 “Disposal of Long-Lived Assets and Discontinued Operations’’. These standards require the recognition of an impairment loss for a long-lived asset when changes in circumstances cause its carrying value to exceed the total undiscounted cash flows expected from its use. An impairment loss, if any, is determined as the excess of the carrying value of the asset over its fair value.

Goodwill impairment

Impairment is tested at the reporting unit level by comparing the reporting unit’s carrying amount to its fair value. The process of determining fair value is subjective and requires us to exercise judgment in making assumptions about future results, including revenue and cash flow projections at the reporting unit level and discount rates. We previously tested goodwill annually on December 31. For the current fiscal year we completed the goodwill impairment testing on October 1. This change in timing was made to reduce conflict between the impairment testing and our financial reporting close process for the third quarter ending December 31. It is our intention to continue to complete subsequent goodwill impairment testing on October 1 going forward. This change in accounting policy was applied on a retrospective basis and has no impact on the consolidated financial statements.

Financial Instruments

In determining the fair value of financial instruments, the Company uses a variety of methods and assumptions that are based on market conditions and risks existing on each reporting date. Counterparty confirmations and standard market conventions and techniques, such as discounted cash flow analysis and option pricing models, are used to determine the fair value of the Company’s financial instruments, including derivatives. All methods of fair value measurement result in a general approximation of value and such value may never actually be realized.

Related Parties

We may receive consulting and advisory services provided by the Sponsors (principals or employees of such Sponsors are our directors) with respect to the organization of the companies, 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 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.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

In addition this permits them to visit and inspect any of our properties and facilities. The transactions are in the normal course of operations and are measured at the exchange amount of consideration established and agreed to by the related parties.

Recently adopted Accounting Policies

Financial Instruments

Our derivative financial instruments related to cross-currency and interest rate swaps are not designated as hedges for accounting purposes and are recorded on the balance sheet at fair value, which is determined based on values quoted by the counterparties to the agreements. The primary factors affecting fair value are the changes in the interest rate term structures in the US and Canada, the life of the swaps and the CAD/USD foreign exchange spot rate.

Effective April 1, 2007, we adopted the new standards issued by the CICA on financial instruments, hedges and comprehensive income. Section 1530, “Comprehensive income”, Section 3855, “Financial instruments-recognition and measurement”, Section 3861, “Financial instruments-disclosure and presentation” and Section 3865, “Hedges”, were effective for our first quarter of fiscal 2008.

On April 1, 2007, we made the following transitional adjustments to our consolidated balance sheet to adopt the new standards (in thousands of dollars):


	Increase
	(decrease)
Deferred financing costs	$	(11,356	)
Intangible assets		1,622
Long-term future income tax asset		3,293
Senior notes		(12,634	)
Derivative financial instruments		9,720
Long-term future income tax liability		18
Opening deficit		3,545

We identified an additional embedded derivative that is not closely related to the host contract in the fourth quarter of 2008 with respect to price escalation features in a supplier contract. The embedded derivative has been measured at fair value and included in derivative financial instruments on the consolidated balance sheet, with changes in fair value recognized in net income. We recorded the fair value of $2,474 related to this embedded derivative on April 1, 2007, with corresponding increase in opening deficit of $1,769, net of future income taxes of $705.

The details of the transitional adjustments are noted below.

The impact of the new standards on our income before income taxes for the three months and year ended March 31, 2008 is as follows (in thousands of dollars):


	Three Months			Twelve Months
	Ended March 31,			Ended March 31,
	2008			2008
Decrease in interest expense due to change in method of amortizing deferred financing costs and discounts (premiums), net	$	(353	)	$	(1,250	)
(Increase) decrease in unrealized foreign exchange gain on senior notes		(121	)		212
Increase (decrease) in unrealized loss on derivative financial instruments		(490	)		4,530

Decrease (increase) in income before income taxes	$	(964	)	$	3,492

The new standards require all financial assets and liabilities to be carried at fair value in our consolidated balance sheet, except for loans and receivables, held-to-maturity investments and other financial liabilities, which are carried at their amortized cost. We do not currently have any financial assets designated as available-for-sale. On adoption of the standard, we have classified our cash and cash equivalents as held for trading and accounts receivable and unbilled revenue as loans and receivables and revolving credit facility, accounts payable, accrued liabilities, and senior notes as other financial liabilities.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

All derivatives, including embedded derivates that must be separately accounted for, are measured at fair value in our consolidated balance sheet. The types of hedging relationships that qualify for hedge accounting have not changed under the new standards. We currently do not designate any of these derivatives as hedging instruments for accounting purposes.

Derivatives may be embedded in financial instruments (the “host instrument”). Under the new standards, embedded derivatives are treated as separate derivatives when their economic characteristics and risks are not closely related to those of the host instrument, the terms of the embedded derivative are similar to those of a stand-alone derivative and the combined contract is not held-for-trading or designated at fair value. These embedded derivatives are measured at fair value with subsequent changes recognized in income. We have elected April 1, 2003 as our transition date for identifying contracts with embedded derivatives. Currently we have prepayment options that are embedded in our senior notes and foreign exchange rate and price index escalation/de-escalation features in a long-term construction contract and supplier contract, which meet the criteria for bifurcation. The impact of the prepayment options and escalation/de-escalation clauses on our consolidated financial statements is described below and in our consolidated financial statements for the year ended March 31, 2008.

In determining the fair value of our financial instruments, we used a variety of valuation methods and assumptions that are based on market conditions and risks existing on each reporting date. Standard market conventions and techniques, such as discounted cash flow analysis and option pricing models, are used to determine the fair value of our financial instruments, including derivatives. All methods of fair value measurement result in a general approximation of value and such value may never actually be realized.

The transitional impact of adopting the new financial instruments standards as at April 1, 2007 on our consolidated financial statements is as follows:

Embedded derivatives:

We determined that the issuer’s early prepayment option included in the senior notes should be bifurcated from the host contract, along with a contingent embedded derivative in the senior notes that provides for accelerated redemption by the holders in certain instances. These embedded derivatives were measured at fair value at the inception of the senior notes and the residual amount of the proceeds was allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of the senior notes is accreted to the par value over the term of the notes using the effective interest method and is recognized as interest expense. At transition on April 1, 2007, we recorded the fair value of $8.5 million related to these embedded derivatives and a corresponding decrease in opening deficit of $7.3 million, net of future income taxes of $1.2 million. The impact of the bifurcation of these embedded derivatives at issuance of the senior notes resulted in an increase in senior notes of $5.7 million and an increase in opening deficit of $4.0 million, net of income taxes of $1.7 million after applying the effective interest method to the premium resulting from the bifurcation of these embedded derivatives on April 1, 2007.

We also have foreign exchange rate and price index escalation/de-escalation features in a long-term construction contract and supplier contract that qualify as an embedded derivative. These amounts must be separated for reporting in accordance with the new standards. As at April 1, 2007, we separated the fair value of the embedded derivative liability of $9.7 million from the contracts, resulting in a corresponding increase to opening deficit of $6.9 million, net of future income taxes of $2.8 million.

Effective interest method:

We incurred underwriting commissions and expenses relating to our senior notes offering. Previously, these costs were classified as long term assets and amortized on a straight-line basis over the term of the debt. The new standard requires us to reclassify the costs as a reduction in the cost of debt and to use the effective interest rate method to amortize the deferred amounts to interest expense. As at April 1, 2007, we reclassified $9.7 million of unamortized costs from deferred financing costs to long-term debt and recorded an adjustment to the unamortized cost balance as if the effective interest rate method had been used since inception.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Transaction costs incurred in connection with our revolving credit facility of $1,622 were reclassified from deferred financing costs to intangible assets on April 1, 2007 and these costs continue to be amortized on a straight-line basis over the term of the facility.

Revised CICA Handbook Section 3861, “Financial Instruments — Disclosure and Presentation” replaces CICA Handbook Section 3860, “Financial Instruments — Disclosure and Presentation” and establishes standards for presentation of financial instruments and non-financial derivatives and identifies information that should be disclosed. There was no material effect on our financial statements upon adoption of CICA Handbook Section 3861 effective April 1, 2007.

Comprehensive Income and Equity

Effective April 1, 2007, the Company adopted CICA Handbook Section 1530, “Comprehensive Income”, which establishes standards for the reporting and display of comprehensive income. The new section defines other comprehensive income to include revenues, expenses, and gains and losses that, in accordance with primary sources of GAAP, are recognized in comprehensive income but excluded from net income. The standard does not address issues of recognition or measurement for comprehensive income and its components. The adoption of this standard did not have a material impact on the Company’s financial statement presentation in the current year.

Effective April 1, 2007, the Company adopted CICA Handbook Section 3251 “Equity”, which establishes standards for the presentation of equity and changes in equity during the reporting period. The requirements in this section are in addition to those of Section 1530 and recommend that an enterprise should present separately the following components of equity: retained earnings, accumulated other comprehensive income, the total for retained earnings and accumulated other comprehensive income, contributed surplus, share capital and reserves. The adoption of CICA Handbook Section 3251 did not have an impact on the Company’s financial statement presentation in the current period. The Company currently has no accumulated other comprehensive income components.

Accounting Changes

In July 2006, the CICA revised Handbook Section 1506, “Accounting Changes”, which requires that: (1) voluntary changes in accounting policy are made only if they result in the financial statements providing reliable and more relevant information; (2) changes in accounting policy are generally applied retrospectively; and (3) prior period errors are corrected retrospectively. This guidance was adopted by the Company on April 1, 2007 and did not have a material impact on the consolidated financial statements.

Accounting Policy Choice For Transaction Costs

In June 2007, the CICA issued Emerging Issues Committee Abstract No. 166, “Accounting Policy Choice for Transaction Costs” (“EIC-166”). CICA Handbook Section 3855 requires that when an entity acquires a financial asset or incurs a financial liability classified other than as held-for-trading, it adopts an accounting policy for transaction costs of either: (a) recognizing all transaction costs in net income; or (b) adding transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability to the carrying amount of the financial instrument. EIC- 166 clarifies that the same accounting policy choice should be made for all similar instruments classified as other than held-for-trading, but that a different accounting policy choice may be made for financial instruments that are not similar. As described in note 3(q)(i), the Company’s accounting policy is to add transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability to the carrying amount of the financial instrument. This guidance was adopted by the Company on April 1, 2007 and did not have a material impact on the consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Recent Accounting pronouncements not yet adopted

Capital disclosures

In December 2006, the CICA issued Handbook Section 1535, “Capital Disclosures”. This standard requires that an entity disclose information that enables users of its financial statements to evaluate an entity’s objectives, policies and processes for managing capital, including disclosures of any externally imposed capital requirements and the consequences of non-compliance. The new standard applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company. Disclosures required by the new standard will be included in the Company’s interim and annual consolidated financial statements commencing April 1, 2008.

Financial Instruments — disclosure and presentation

In March 2007, the CICA issued Handbook Section 3862, “Financial Instruments—Disclosures”, which replaces CICA 3861 and provides expanded disclosure requirements that provide additional detail by financial assets and liability categories to enhance financial statement users’ understanding of the significance of financial instruments to an entity’s financial position, performance and cash flows. This standard harmonizes disclosures with International Financial Reporting Standards. The standard applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company. Disclosures required by the new standard will be included in the Company’s interim and annual consolidated financial statements commencing April 1, 2008.

In March 2007, the CICA issued Handbook Section 3863, “Financial Instruments—Presentation”. This Section establishes standards for presentation of financial instruments and non-financial derivatives. It deals with the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, gains and losses, and the circumstances in which financial assets and financial liabilities are offset. This standard harmonizes disclosures with International Financial Reporting Standards and applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company and is not expected to have a material impact on the consolidated financial statements.

Inventories

In June 2007, the CICA issued Handbook Section 3031, “Inventories” to harmonize accounting for inventories under Canadian GAAP with International Financial Reporting Standards. This standard requires the measurement of inventories at the lower of cost and net realizable value and includes guidance on the determination of cost, including allocation of overheads and other costs to inventory. The standard also requires the consistent use of either first-in, first out (FIFO) or weighted average cost formula to measure the cost of other inventories and requires the reversal of previous write-downs to net realizable value when there is a subsequent increase in the value of inventories. The new standard applies to interim and annual financial statements relating to fiscal years beginning on or after January 1, 2008, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.

Going concern

In April 2007, the CICA approved amendments to Handbook Section 1400, “General Standards of Financial Statement Presentation”. These amendments require management to assess an entity’s ability to continue as a going concern. When management is aware of material uncertainties related to events or conditions that may cast doubt on an entity’s ability to continue as a going concern, those uncertainties must be disclosed. In assessing the appropriateness of the going concern assumption, the standard requires management to consider all available information about the future, which is at least, but not limited to, twelve months from the balance sheet date. The new requirements of the standard are applicable for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2008, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Goodwill and intangible assets

In February 2008, the CICA issued Handbook Section 3064, (“CICA 3064”) Goodwill and Intangible Assets. CICA 3064, which replaces Section 3062, Goodwill and Intangible Assets, and Section 3450, Research and Development Costs, establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The provisions relating to the definition and initial recognition of intangible assets, including internally generated intangible assets, are equivalent to the corresponding provisions of International Financial Reporting Standard IAS 38, Intangible Assets. This new standard is effective for the Company’s interim and annual consolidated financial statements commencing April 1, 2009. The Company is currently evaluating the impact of this standard.

G. 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,” “should,” “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 limited risk that royalty changes will cause our customers to cancel, delay or reduce the scope of any significant mining developments presently underway;

	(b)		the expected continued rapid growth of operators in the oil sands business, their planned projects and our intention to pursue business opportunities from these projects;

	(c)		our intention to increase our fleet size to be ready to meet the challenges from the projected growth in oil sands;

	(d)		that acquisition opportunities will materialize that will allow us to expand our complementary service offerings which we will be able to cross-sell with our existing services;

	(e)		our intention to increase our presence outside the oil sands and extend our services to other resource industries across Canada;

	(f)		the success of the enhancements to maintenance practices resulting in improved availability through reduced repair time and increased utilization of our equipment with a consequent improvement in our revenue, margins and profitability;

	(g)		the amount of our backlog expected to be performed and realized in the 12 months ending March 31, 2009 (such estimates assist us in planning our activity level and may not be suitable for other purposes);

	(h)		the expected growth in Master Services Agreements through 2009;

	(i)		the arrival of new projects and our required participation in the bidding process for work on such projects;

	(j)		the continued development of the oil sands and the expectation that it will drive a significant portion of our 2009 revenue;

	(k)		our commencement of work in the latter half of fiscal 2009 at Imperial Oil’s upcoming Kearl project;

	(l)		the anticipated increased demand for our services at Petro-Canada’s Fort Hills site;

	(m)		our expected increased involvement with Baffinland Iron Mines Corp.;

	(n)		the demand for our piling services remaining strong in fiscal 2009;

	(o)		the anticipated temporary slowdown in our pipeline activity once the TMX project concludes in October 2008 and significant long-term opportunities for this division; and

	(p)		our expected generation of a net cash surplus in fiscal 2009.

Some of the risks and other factors which could cause results to differ materially from those expressed in the forward-looking statements contained in this document include, but are not limited to:

The forward-looking information in paragraphs (a), (b), (i), (j), (k), (l), (m), (n) and (o) rely on certain market conditions and demand for our services and are based on the assumptions that; the global economy remains strong and the demand for commodities, particularly oil, remains high; high demand for commodities results in strong prices which drive the development of Canada’s natural resources, in particular the oil sands; the oil sands continue to be an economically viable source of energy and our customers and potential customers continue to invest in the oil sands and other natural resources 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 commercial and public construction; and are subject to the risks and uncertainties that:

	•		anticipated major projects in the oil sands may not materialize;

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

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

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

	•		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;

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

	•		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;

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

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

	•		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 (c), (d), (e), (f), (g), (h), (i), (j), (k), (l), (m), (n), (o) and (p) 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, and that we will identify and implement improvements in our maintenance and fleet management practices; and are subject to the risks and uncertainties that:

	•		our ability to grow our operations in the future may be hampered by our inability to obtain long lead time equipment and tires, which are currently in limited supply;

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

	•		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;

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

	•		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;

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

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

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

	•		many of our senior officers have either recently joined the company or have just been promoted and have only worked together as a management team for a short period of time.

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, 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.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Risk Factors

Anticipated major projects in the oil sands may not materialize.

Notwithstanding the National Energy Board’s estimates regarding new investment and growth in the Canadian oil sands, planned and anticipated projects in the oil sands and other related projects may not materialize. The underlying assumptions on which the projects are based are subject to significant uncertainties, and actual investments in the oil sands could be significantly less than estimated. Projected investments and new projects may be postponed or cancelled for any number of reasons, including among others:

	•		changes in the perception of the economic viability of these projects;

	•		shortage of pipeline capacity to transport production to major markets;

	•		lack of sufficient governmental infrastructure to support growth;

	•		delays in issuing environmental permits or refusal to grant such permits;

	•		shortage of skilled workers in this remote region of Canada; and

	•		cost overruns on announced projects.

Demand for our services may be adversely impacted by regulations affecting the energy industry.

Our principal customers are energy companies involved in the development of the oil sands and in natural gas production. The operations of these companies, including their mining operations in the oil sands, are subject to or impacted by a wide array of regulations in the jurisdictions where they operate, including those directly impacting mining activities and those indirectly affecting their businesses, such as applicable environmental laws. As a result of changes in regulations and laws relating to the energy production industry, including the operation of mines, our customers’ operations could be disrupted or curtailed by governmental authorities. The high cost of compliance with applicable regulations may cause customers to discontinue or limit their operations, and may discourage companies from continuing development activities. As a result, demand for our services could be substantially affected by regulations adversely impacting the energy industry.

Failure by our customers to obtain required permits and licenses may affect the demand for our services.

The development of the oil sands requires our customers to obtain regulatory and other permits and licenses from various governmental licensing bodies. Our customers may not be able to obtain all necessary permits and licenses that may be required for the development of the oil sands on their properties. In such a case, our customers’ projects will not proceed, thereby adversely impacting demand for our services.

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

Due to the amount of capital investment required to build an oil sands project, or construct a significant expansion to an existing project, investment decisions by oil sands operators are based upon long-term views of the economic viability of the project. Economic viability is dependent upon the anticipated revenues the project will produce, the anticipated amount of capital investment required and the anticipated cost of operating the project. The most important

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

consideration is the customer’s view of the long-term price of oil which is influenced by many factors, including the condition of developed and developing economies and the resulting demand for oil and gas, the level of supply of oil and gas, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political conditions in oil producing nations, including those in the Middle East, war or the threat of war in oil producing regions and the availability of fuel from alternate sources. If our customers believe the long-term outlook for the price of oil is not favorable, or believes oil sands projects are not viable for any other reason, they may delay, reduce or cancel plans to construct new oil sands projects or expansions to existing projects. Delays, reductions or cancellations of major oil sands projects would adversely affect our prospects and could have a material adverse impact on our financial condition and results of operations.

Insufficient pipeline, upgrading and refining capacity 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.

For our customers to operate successfully in the oil sands, they must be able to transport the bitumen produced to upgrading facilities and transport the upgraded oil to refineries. Some oil sands projects have upgraders at mine site and others transport bitumen to upgraders located elsewhere. While current pipeline and upgrading capacity is sufficient for current production, future increases in production from new oil sands projects and expansions to existing projects will require increased upgrading and pipeline capacity. If these increases do not materialize, whether due to inadequate economics for the sponsors of such projects, shortages of labor or materials or any other reason, our customers may be unable to efficiently deliver increased production to market and may therefore delay, reduce or cancel planned capital investment. Such delays, reductions or cancellations of major oil sands projects would adversely affect our prospects and could have a material adverse impact on our financial condition and results of operations.

Lack of sufficient governmental infrastructure to support the growth in the oil sands region could cause our customers to delay, reduce or cancel their future expansions, which would, in turn, reduce our revenue from those customers.

The development in the oil sands region has put a great strain on the existing government infrastructure, necessitating substantial improvements to accommodate growth in the region. The local government having responsibility for a majority of the oil sands region has been exceptionally impacted by this growth and is not currently in a position to provide the necessary additional infrastructure. In an effort to delay further development until infrastructure funding issues are resolved, the local governmental authority has intervened in two recent hearings considering applications by major oil sands companies to the EUB for approval to expand their operations. Similar action could be taken with respect to any future applications. The EUB has issued conditional approval for the expansion in respect of one of the hearings despite the intervention by the local government authority, and a decision in the second hearing is pending. The EUB has indicated that it believes that additional infrastructure investment in the oil sands region is needed and that there is a short window of opportunity to make these investments in parallel with continued oil sands development. If the necessary infrastructure is not put in place, future growth of our customers’ operations could be delayed, reduced or canceled which could in turn adversely affect our prospects and could have a material adverse impact on our financial condition and results of operations.

Shortages of qualified personnel or significant labor disputes could adversely affect our business.

Alberta, and in particular the oil sands area, has had and continues to have a shortage of skilled labor and other qualified personnel. New mining projects in the area will only make it more difficult for us and our customers to find and hire all the employees required to work on these projects. We are continuously exploring innovative ways to hire the project managers, trades people and other skilled employees that we need. We have expanded our search efforts outside of Canada to find qualified candidates who might relocate to our area. In addition, we have undertaken more extensive training of existing employees and we are enhancing our use of technology and developing programs to provide better working conditions. We believe the labor shortage, which affects us and all of our major customers, will continue to be a challenge for everyone in the mining and oil and gas industries in western Canada for the foreseeable future. If we are not able to recruit and retain enough employees with the appropriate skills, we may be unable to maintain our customer service levels, and we may not be able to satisfy any increased demand for our services. This, in turn, could have a material adverse effect on our business, financial condition and results of operations. If our customers are not able to

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

recruit and retain enough employees with the appropriate skills, they may be unable to develop projects in the oil sands area.

Substantially all of our hourly employees are subject to collective bargaining agreements to which we are a party or are otherwise subject. Any work stoppage resulting from a strike or lockout could have a material adverse effect on our business, financial condition and results of operations. In addition, our customers employ workers under collective bargaining agreements. Any work stoppage or labor disruption experienced by our key customers could significantly reduce the amount of our services that they need.

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.

Oil sands development projects require substantial capital expenditures. In the past, several of our customers’ projects have experienced significant cost overruns, impacting their returns. If cost overruns continue to challenge our customers, they could reassess future projects and expansions which could adversely affect the amount of work we receive from our customers.

Our ability to grow our operations in the future may be hampered by our inability to obtain long lead time equipment and tires, which are currently in limited supply.

Our ability to grow our business is, in part, dependent upon obtaining equipment on a timely basis. Due to the long production lead times of suppliers of large mining equipment, we must forecast our demand for equipment many months or even years in advance. If we fail to forecast accurately, we could suffer equipment shortages or surpluses, which could have a material adverse impact on our financial condition and results of operations.

Global demand for tires of the size and specifications we require is exceeding the available supply. For example, two of our trucks are currently not in service because we cannot get tires for these particular trucks. We expect the supply/demand imbalance for certain tires to continue for several years. Our inability to procure tires to meet the demands for our existing fleet as well as to meet new demand for our services could have an adverse effect on our ability to grow our business.

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.

Most of our revenue comes from the provision of services to a small number of major oil sands mining companies. Revenue from our five largest customers represented approximately 81%, 65% and 69% of our total revenue for fiscal years 2008, 2007 and 2006, respectively, and those customers are expected to continue to account for a significant percentage of our revenues in the future. In addition, the majority of our Pipeline revenues in the current and previous fiscal years resulted from work performed for one customer. If we lose or experience a significant reduction of business from one or more of our significant customers, we may not be able to replace the lost work with work from other customers. Our long-term contracts typically allow our customers to unilaterally reduce or eliminate the work which we are to perform under the contract. Our contracts also generally allow the customer to terminate the contract without cause. The loss of or significant reduction in business with one or more of our major customers, whether as a result of completion of a contract, early termination or failure or inability to pay amounts owed to us, could have a material adverse effect on our business and results of operations.

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

Most of our customers are Canadian energy companies. A downturn in the Canadian energy industry could cause our customers to slow down or curtail their current production and future expansions which would, in turn, reduce our revenue from those customers. Such a delay or curtailment could have a material adverse impact on our financial condition and results of operations.

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

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Approximately 45%, 66% and 58% of our revenue for 2008, 2007 and 2006, respectively, was derived from lump-sum and unit-price contracts. Lump-sum and unit-price contracts require us to guarantee the price of the services we provide and thereby expose us to losses if our estimates of project costs are lower than the actual project costs we incur. Our profitability under these contracts is dependent upon our ability to accurately predict the costs associated with our services. The costs we actually incur may be affected by a variety of factors beyond our control. Factors that may contribute to actual costs exceeding estimated costs and which therefore affect profitability include, without limitation:

	•		site conditions differing from those assumed in the original bid;

	•		scope modifications during the execution of the project;

	•		the availability and cost of skilled workers;

	•		the availability and proximity of materials;

	•		unfavorable weather conditions hindering productivity;

	•		inability or failure of our customers to perform their contractual commitments;

	•		equipment availability and productivity and timing differences resulting from project construction not starting on time; and

	•		the general coordination of work inherent in all large projects we undertake.

When we are unable to accurately estimate the costs of lump-sum and unit-price contracts, or when we incur unrecoverable cost overruns, the related projects result in lower margins than anticipated or may incur losses, which could adversely impact our results of operations, financial condition and cash flow.

Until we establish and maintain effective internal controls over financial reporting, we cannot assure you that we will have appropriate procedures in place to eliminate future financial reporting inaccuracies and avoid delays in financial reporting.

We have identified a number of material weaknesses in our financial reporting processes and internal controls. See “Management’s Report on Internal Controls over Financial Reporting.” As a result, there can be no assurance that we will be able to generate accurate financial reports in a timely manner. Failure to do so would cause us to breach the U.S. and Canadian securities regulations with respect to reporting requirements in the future as well as the covenants applicable to our indebtedness. This could, in turn, have a material adverse effect on our business and financial condition. Until we establish and maintain effective internal controls and procedures for financial reporting, we may not have appropriate measures in place to eliminate financial statement inaccuracies and avoid delays in financial reporting.

Our substantial debt could adversely affect us, make us more vulnerable to adverse economic or industry conditions and prevent us from fulfilling our debt obligations.

We have a substantial amount of debt outstanding and significant debt service requirements. As of March 31, 2008, we had outstanding $213.0 million of debt, including $14.8 million of capital leases. We also had cross-currency and interest rate swaps with a balance sheet liability of $81.6 million as of March 31, 2008. These swaps are secured equally and ratably with our revolving credit facility. Our substantial indebtedness could have serious consequences, such as:

	•		limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements, potential growth or other purposes;

	•		limiting our ability to use operating cash flow in other areas of our business;

	•		limiting our ability to post surety bonds required by some of our customers;

	•		placing us at a competitive disadvantage compared to competitors with less debt;

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

	•		increasing our vulnerability to, and reducing our flexibility in planning for, adverse changes in economic, industry and competitive conditions; and

	•		increasing our vulnerability to increases in interest rates because borrowings under our revolving credit facility and payments under some of our equipment leases are subject to variable interest rates.

The potential consequences of our substantial indebtedness make us more vulnerable to defaults and place us at a competitive disadvantage. Further, if we do not have sufficient earnings to service our debt, we would need to refinance all or part of our existing debt, sell assets, borrow more money or sell securities, none of which we can guarantee we will be able to achieve on commercially reasonable terms, if at all.

The terms of our debt agreements may restrict our current and future operations, particularly our ability to respond to changes in our business or take certain actions.

Our revolving credit facility and the indenture governing our notes limit, among other things, our ability and the ability of our subsidiaries to:

	•		incur or guarantee additional debt, issue certain equity securities or enter into sale and leaseback transactions;

	•		pay dividends or distributions on our shares or repurchase our shares, redeem subordinated debt or make other restricted payments;

	•		incur dividend or other payment restrictions affecting certain of our subsidiaries;

	•		issue equity securities of subsidiaries;

	•		make certain investments or acquisitions;

	•		create liens on our assets;

	•		enter into transactions with affiliates;

	•		consolidate, merge or transfer all or substantially all of our assets; and

	•		transfer or sell assets, including shares of our subsidiaries.

Our revolving credit facility also requires us, and our future credit facilities may require us, to maintain specified financial ratios and satisfy specified financial tests, some of which become more restrictive over time. Our ability to meet these financial ratios and tests can be affected by events beyond our control, and we may be unable to meet those tests.

As a result of these covenants, our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be significantly restricted, and we may be prevented from engaging in transactions that might otherwise be considered beneficial to us. The breach of any of these covenants could result in an event of default under our revolving credit facility or any future credit facilities or under the indenture governing our notes. Under our revolving credit facility, our failure to pay certain amounts when due to other creditors, including to certain equipment lessors, or the acceleration of such other indebtedness, would also result in an event of default. Upon the occurrence of an event of default under our revolving credit facility or future credit facilities, the lenders could elect to stop lending to us or declare all amounts outstanding under such credit facilities to be immediately due and payable. Similarly, upon the occurrence of an event of default under the indenture governing our notes, the outstanding principal and accrued interest on the notes may become immediately due and payable. If amounts outstanding under such credit facilities and indenture were to be accelerated, or if we were not able to borrow under our revolving credit facility, we could become insolvent or be forced into insolvency proceedings and you could lose your investment in us.

We may not be able to generate sufficient cash flow to meet our debt service and other obligations due to events beyond our control.

Our ability to generate sufficient operating cash flow to make scheduled payments on our indebtedness and meet other capital requirements will depend on our future operating and financial performance. Our future performance will

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

be impacted by a range of economic, competitive and business factors that we cannot control, such as general economic and financial conditions in our industry or the economy generally.

A significant reduction in operating cash flows resulting from changes in economic conditions, increased competition, reduced work or other events could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on our business, financial condition, results of operations, prospects and our ability to service our debt and other obligations. If we are unable to service our indebtedness, we will be forced to adopt an alternative strategy that may include actions such as selling assets, restructuring or refinancing our indebtedness, seeking additional equity capital or reducing capital expenditures. We may not be able to affect any of these alternative strategies on satisfactory terms, if at all, or they may not yield sufficient funds to make required payments on our indebtedness.

Currency rate fluctuations could adversely affect our ability to repay our 8¾% senior notes and may affect the cost of goods we purchase.

We have entered into cross-currency and interest rate swaps that represent economic hedges of our 8¾% senior notes, which are denominated in U.S. dollars. The current exchange rate between the Canadian and U.S. dollars as compared to the rate implicit in the swap agreement has resulted in a large liability on the balance sheet under the caption “derivative financial instruments.” If the Canadian dollar increases in value or remains at its current value against the U.S. dollar, then if we repay the 8¾ senior notes prior to their maturity in 2011, we will have to pay this liability.

Exchange rate fluctuations may also cause the price of goods to increase or decrease for us. For example, a decrease in the value of the Canadian dollar compared to the U.S. dollar would proportionately increase the cost of equipment which is sold to us or priced in U.S. dollars.

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

We are at times required to post a bid or performance bond issued by a financial institution, known as a surety, to secure our performance commitments. The surety industry experiences periods of unsettled and volatile markets, usually in the aftermath of substantial loss exposures or corporate bankruptcies with significant surety exposure. Historically, these types of events have caused reinsurers and sureties to reevaluate their committed levels of underwriting and required returns. If for any reason, whether because of our financial condition, our level of secured debt or general conditions in the surety bond market, our bonding capacity becomes insufficient to satisfy our future bonding requirements, our business and results of operations could be adversely affected.

Some of our customers require letters of credit to secure our performance commitments. Our second amended and restated revolving credit facility provides for the issuance of letters of credit up to $125.0 million, and at March 31, 2008, we had $20.0 million of issued letters of credit outstanding. One of our major contracts allows the customer to require up to $50.0 million in letters of credit. If we were unable to provide letters of credit in the amount requested by this customer, we could lose business from such customer and our business and cash flow would be adversely affected. If our capacity to issue letters of credit under our revolving credit facility and our cash on hand is insufficient to satisfy our customers requirements, our business and results of operations could be adversely affected.

A change in strategy by our customers to reduce outsourcing could adversely affect our results.

Outsourced mining and site preparation services constitute a large portion of the work we perform for our customers. For example, our Heavy Construction and Mining project revenues constituted approximately 63%, 75%, 74% of our revenues in each of fiscal years 2008, 2007 and 2006 respectively. The election by one or more of our customers to perform some or all of these services themselves, rather than outsourcing the work to us, could have a material adverse impact on our business and results of operations. Certain customers perform some of this work internally and may choose to expand on the use of internal resources to complete this work.

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

Because our operations are located in western Canada and northern Ontario, we are often subject to extreme weather conditions. While our operations are not significantly affected by normal seasonal weather patterns, extreme

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

weather, including heavy rain and snow, can cause delays in our project work, which could adversely impact our results of operations.

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.

A portion of our equipment fleet is currently leased from third parties. Further, we anticipate leasing substantial amounts of equipment to perform the work on contracts for which we have been engaged in the upcoming year, particularly the overburden removal contract with CNRL. Other future projects may require us to lease additional equipment. If equipment lessors are unable or unwilling to provide us with the equipment we need to perform our work, our results of operations will be materially adversely affected.

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

We compete with a broad range of companies in each of our markets. Many of these competitors are substantially larger than we are. In addition, we expect the anticipated growth in the oil sands region will attract new and sometimes larger competitors to enter the region and compete against us for projects. This increased competition may adversely affect our ability to be awarded new business.

Approximately 80% of the major projects that we pursue are awarded to us based on bid proposals, and projects are typically awarded based in large part on price. We often compete for these projects against companies that have substantially greater financial and other resources than we do and therefore can better bear the risk of under pricing projects. We also compete against smaller competitors that may have lower overhead cost structures and, therefore, may be able to provide their services at lower rates than we can. Our business may be adversely impacted to the extent that we are unable to successfully bid against these companies. The loss of existing customers to our competitors or the failure to win new projects could materially and adversely affect our business and results of operations.

A significant amount of our revenue is generated by providing non-recurring services.

More than 61% of our revenue for 2008 was derived from projects which we consider to be non-recurring. This revenue primarily relates to site preparation and Piling services provided for the construction of extraction, upgrading and other oil sands mining infrastructure projects.

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

Our operations are subject to numerous environmental protection laws and regulations that are complex and stringent. We regularly perform work in and around sensitive environmental areas such as rivers, lakes and forests. Significant fines and penalties may be imposed on us or our customers for noncompliance with environmental laws and regulations, and our contracts generally require us to indemnify our customers for environmental claims suffered by them as a result of our actions. In addition, some environmental laws impose strict, joint and several liability for investigative and remediation costs in relation to releases of harmful substances. These laws may impose liability without regard to negligence or fault. We also may be subject to claims alleging personal injury or property damage if we cause the release of, or any exposure to, harmful substances.

We own or lease, and operate, several properties that have been used for a number of years for the storage and maintenance of equipment and other industrial uses. Fuel may have been spilled, or hydrocarbons or other wastes may have been released on these properties. Any release of substances by us or by third parties who previously operated on these properties may be subject to laws which impose joint and several liability for clean-up, without regard to fault, on specific classes of persons who are considered to be responsible for the release of harmful substances into the environment.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

Our projects expose us to potential professional liability, product liability, warranty or other claims.

We install deep foundations, often in congested and densely populated areas, and provide construction management services for significant projects. Notwithstanding the fact that we generally will not accept liability for consequential damages in our contracts, any catastrophic occurrence in excess of insurance limits at projects where our structures are installed or services are performed could result in significant professional liability, product liability, warranty or other claims against us. Such liabilities could potentially exceed our current insurance coverage and the fees we derive from those services. A partially or completely uninsured claim, if successful and of a significant magnitude, could result in substantial losses.

We may not be able to achieve the expected benefits from any future acquisitions, which would adversely affect our financial condition and results of operations.

We intend to pursue selective acquisitions as a method of expanding our business. However, we may not be able to identify or successfully bid on businesses that we might find attractive. If we do find attractive acquisition opportunities, we might not be able to acquire these businesses at a reasonable price. If we do acquire other businesses, we might not be able to successfully integrate these businesses into our then-existing business. We might not be able to maintain the levels of operating efficiency that acquired companies will have achieved or might achieve separately. Successful integration of acquired operations will depend upon our ability to manage those operations and to eliminate redundant and excess costs. Because of difficulties in combining operations, we may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve through these acquisitions. Any of these factors could harm our financial condition and results of operations.

Aboriginal peoples may make claims against our customers or their projects regarding the lands on which their projects are located.

Aboriginal peoples have claimed aboriginal title and rights to a substantial portion of western Canada. Any claims that may be asserted against our customers, if successful, could have an adverse effect on our customers which may, in turn, negatively impact our business.

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

The majority of our work is generated from the development, expansion and ongoing maintenance of oil sands mining, extraction and upgrading facilities. Unplanned shutdowns of these facilities due to events outside our control or the control of our customers, such as fires, mechanical breakdowns and technology failures, could lead to the temporary shutdown or complete cessation of projects in which we are working. When these events have happened in the past, our business has been adversely affected. Our ability to maintain revenues and margins may be affected to the extent these events cause reductions in the utilization of equipment.

Many of our senior officers have either recently joined the company or have just been promoted and have only worked together as a management team for a short period of time.

We recently made several significant changes to our senior management team. We promoted our Vice President Business Development and Estimating to the role of Vice President Operations in September 2007. We promoted our Director of Business Development to the role of Vice President Business Development and Estimating in September 2007, we promoted our General Manager Heavy Construction and Mining to the role of Vice President Supply Chain in December 2007 and in January 2008 we recruited and hired a new Chief Financial Officer and a new Vice President Finance. As a result of these and other recent changes in senior management, many of our officers have only worked together as a management team for a short period of time and do not have a long history with us. Because our senior management team is responsible for the management of our business and operations, failure to successfully integrate our senior management team could have an adverse impact on our business, financial condition and results of operations.

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

H. General Matters

History and Development of the Company

NACG Holdings Inc. (“Holdings”) was formed in October 2003 in connection with the acquisition discussed below. Prior to the acquisition, NACG Holdings Inc. had no operations or significant assets and the acquisition was primarily a change of ownership of the businesses acquired.

On October 31, 2003, two wholly owned subsidiaries of Holdings, as the buyers, entered into a purchase and sale agreement with Norama Ltd. and one of its subsidiaries, as the sellers. On November 26, 2003, pursuant to the purchase and sale agreement, Norama Ltd. sold to the buyers the businesses comprising North American Construction Group in exchange for total consideration of approximately $405.5 million, net of cash received and including the impact of certain post-closing adjustments. The businesses we acquired from Norama Ltd. have been in operation since 1953. Subsequent to the acquisition, we have operated the businesses in substantially the same manner as prior to the acquisition.

On November 28, 2006, prior to the consummation of the IPO discussed below, Holdings amalgamated with its wholly-owned subsidiaries, NACG Preferred Corp and North American Energy Partners Inc. The amalgamated entity continued under the name North American Energy Partners Inc. The voting common shares of the new entity, North American Energy Partners Inc., were the shares sold in the IPO and related secondary offering. On November 28, 2006, we completed the IPO in the United States and Canada of 8,750,000 voting common shares and a secondary offering of 3,750,000 voting common shares for $18.38 per share (U.S. $16.00 per share).

On November 22, 2006 our common shares commenced trading on the New York Stock Exchange and on the Toronto Stock Exchange on an “if, as and when issued” basis. On November 28, 2006, our common shares became fully tradable on the Toronto Stock Exchange.

Net proceeds from the IPO were $140.9 million (gross proceeds of $158.5 million, less underwriting discounts and costs and offering expenses of $17.6 million). On December 6, 2006, the underwriters exercised their option to purchase an additional 687,500 common shares from us. The net proceeds from the exercise of the underwriters’ option were $11.7 million (gross proceeds of $12.6 million, less underwriting fees of $0.9 million). Total net proceeds were $152.6 million (total gross proceeds of $171.1 million less total underwriting discounts and costs and offering expenses of $18.5 million).

As of March 31, 2008, our authorized capital consists of an unlimited number of voting and non-voting common shares, of which 35,929,476 voting common shares were issued and outstanding.

Our head office is located at Zone 3, Acheson Industrial Area, 2 — 53016 Hwy 60, Acheson, Alberta, T7X 5A7. Our telephone and facsimile numbers are (780) 960-7171 and (780) 960-7103, respectively.

Transition to IFRS

The Canadian Accounting Standards Board announced in February 2008 that 2011 is the changeover date for publicly-listed companies to use International Financial Reporting Standards (IFRS), replacing Canada’s own Generally Accepted Accounting Principles (GAAP). The date is for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011. As a publicly listed company we will start a project in July 2008 to address the impact of transitioning to IFRS. Specific areas to be addressed in the project include:

NORTH AMERICAN ENERGY PARTNERS INC.
Management’s Discussion and Analysis
For the year ended March 31, 2008

	•		Accounting policies, including choices among policies permitted under IFRS, and implementation decisions, such as whether certain changes will be applied on a retrospective or a prospective basis

	•		Information technology and data systems

	•		Internal controls over financial reporting

	•		Disclosure controls and procedures, including investor relations and external communications plans

	•		Sufficiency of financial reporting expertise, including training requirements

	•		Business activities that may be influenced by GAAP measures, such as foreign currency, hedging, debt covenants, capital requirements, and compensation arrangements.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	H.S. freshman V bad

North American Construction (NOA) 40-F2008 FY Annual report (Canada)

Content analysis