EXHIBIT 99.3

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the year ended March 31, 2010

Table of Contents

A.	Explanatory Notes	2
	Caution Regarding Forward-Looking Information	2
	Non-GAAP Financial Measures	2
	Adoption of United States GAAP	3
B.	Business Overview and Strategy	3
	Operations Overview	4
	End Markets Overview	5
	Revenue Sources	8
	Our Strategy	9
C.	Financial Results	9
	Adjustments related to prior year financial statements	9
	Differences between US and Canadian GAAP	11
	Consolidated Annual Results	14
	Segment Annual Results	16
	Consolidated Three Month Results	17
	Segment Three Month Results	18
	Non-Operating Income and Expense	19
	Backlog	21
	Claims and Change Orders	22
	Summary of Consolidated Quarterly Results	22
	Summary of Consolidated Financial Position	23
	Summary of Consolidated Cash Flows	24
D.	Outlook	25
E.	Legal and Labour Matters	26
	Laws and Regulations and Environmental Matters	26
	Employees and Labour Relations	26
F.	Resources and Systems	27
	Outstanding Share Data	27
	Liquidity and Capital Resources	27
	Capital Commitments	31
	Debt Ratings	32
	Related Parties	33
	Internal Systems and Processes	33
	Significant Accounting Policies	35
	Recently Adopted Accounting Policies	36
	Recent Accounting Pronouncements Not Yet Adopted	38
	Recently Adopted Accounting Policies (Canadian GAAP)	39
	Recent Accounting Pronouncements Not Yet Adopted (Canadian GAAP)	40
G.	Forward-Looking Information and Risk Factors	40
	Forward-Looking Information	40
	Risk Factors	43
	Quantitative and Qualitative Disclosures about Market Risk	48
H.	General Matters	50
	History and Development of the Company	50
	Additional Information	50

North American Energy Partners Inc.  Management’s Discussion and Analysis  1

Management’s Discussion and Analysis

For the year ended March 31, 2010

A. Explanatory Notes

June 10, 2010

The following discussion and analysis is as of June 10, 2010 and should be read in conjunction with the attached audited consolidated financial statements for the year ended March 31, 2010 and notes that follow. These statements have been prepared in accordance with United States (US) generally accepted accounting principles (GAAP) and reconciled to Canadian GAAP. Except where otherwise specifically indicated, all dollar amounts are expressed in Canadian dollars. For additional information and details, readers are referred to the unaudited consolidated financial statements, notes that follow and the accompanying interim period Management’s Discussion and Analysis (MD&A) for each interim period of fiscal 2010. The audited consolidated financial statements and additional information relating to our business, including our Annual Information Form (AIF), are available on the Canadian Securities Administrators’ SEDAR System at www.sedar.com, the Securities and Exchange Commission’s website at www.sec.gov and our company web site at www.nacg.ca.

Caution Regarding Forward-Looking Information

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

Non-GAAP Financial Measures

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

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

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

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

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

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

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

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

Adoption of United States GAAP

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

After significant analysis and consideration regarding the merits of reporting under IFRS or US GAAP we have decided to adopt US GAAP instead of adopting IFRS, commencing in fiscal 2010, as our primary reporting standard for our consolidated financial statements. Our audited consolidated financial statements for the year ended March 31, 2010, including related notes and this MD&A have therefore been prepared based on US GAAP. All comparative figures contained in these documents have been restated to reflect our results as if they had been historically reported in accordance with US GAAP as our reporting standard. All financial statements and MD&A previously filed were prepared under Canadian GAAP as our reporting standard.

As required by National Instrument 52-107, for the fiscal year of adoption of US GAAP and one subsequent fiscal year, we will provide a Canadian Supplement to our MD&A that restates, based on financial information reconciled to Canadian GAAP, those parts of our MD&A that would contain material differences if they were based on financial statements prepared in accordance with Canadian GAAP. In support of the adoption of US GAAP commencing in fiscal 2010 we will restate and file our unaudited consolidated financial statements, accompanying notes and MD&A’s for each of the interim periods for fiscal 2010. We will also provide Canadian Supplement MD&A’s for each of these restated interim periods for fiscal 2010.

The impact to our financial statements of the adoption of US GAAP as our reporting standard is discussed under “Differences between US and Canadian GAAP” in the Financial Results section of this MD&A.

B. Business Overview and Strategy

Business Overview

We provide a wide range of heavy construction and mining, piling and pipeline installation services to customers in the Canadian oil sands, minerals mining, commercial and public construction and conventional oil and gas markets. Our primary market is the Alberta oil sands, where we support our customers’ mining operations and capital projects. While we provide services through all stages of an oil sands project’s lifecycle, our core focus is on providing recurring services, such as contract mining, during the operational phase. On a trailing 12-months basis to March 31, 2010, recurring services represented 89% of our oil sands business. Our principal oil sands customers include all four of the most significant producers that are currently mining bitumen in Alberta: Syncrude¹, Suncor², Shell Albian³ and Canadian Natural⁴. We focus on building long-term relationships with our customers. For example, we have been providing services to Syncrude and Suncor for over 30 years.

We believe that we operate the largest fleet of equipment of any contract resource services provider in the oil sands. Our total fleet includes 698 pieces of diversified heavy construction equipment supported by over 765 ancillary vehicles. While our expertise covers mining, heavy construction, underground services (fire lines, sewer, water, etc.) for industrial projects, and piling and pipeline installation in many different types of locations, we have a specific capability operating in the harsh climate and difficult terrain of northern Canada, particularly in the oil sands in Alberta.*

We believe that our significant oil sands knowledge, experience, long-term customer relationships, equipment capacity, scale of operations and broad service offering differentiate us from our competition. In addition, we believe that these capabilities will enable us to support the growing volume of recurring services that is generated within the oil sands.^*

While our mining services are primarily focused on the oil sands, we believe that we have 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 an example, in fiscal 2008 we successfully completed the development of a diamond mine site in Northern Ontario. This three-year project required us to operate effectively in a remote location in the extreme

¹ Syncrude Canada Ltd. (Syncrude) – a joint venture amongst Canadian Oil Sands Limited (37%), Imperial Oil Resources (25%), Suncor Energy Inc. (formerly Petro-Canada Oil and Gas) (12%), ConocoPhillips Oil Sands Partnership II (9%), Nexen Oil Sands Partnership (7%), Murphy Oil Company Ltd. (5%) and Mocal Energy Limited (5%).

² Suncor Energy Inc. (Suncor).

³ Shell Canada Energy, a division of Shell Canada Limited, the operator of the Shell Albian Sands (Shell Albian) oil sands mining and extraction operations on behalf of Athabasca Oil Sands Project (AOSP), a joint venture amongst Shell Canada Limited (60%), Chevron Canada Limited (20%) and Marathon Oil Canada Corporation (20%). Prior to January 1, 2009, these operations were run by Albian Sands Energy Inc.

⁴ Canadian Natural Resources Limited (Canadian Natural).

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

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

weather conditions prevalent in northern Canada. As a result of our successful work on this and other similar projects, we believe that we have attracted the attention of resource developers. While development of resources has been affected by the current economic environment, we remain committed to expanding our operations to other potential projects, including those in the high Arctic regions.

Operations Overview

Our business is organized into three interrelated, yet distinct, operating segments: (i) Heavy Construction and Mining, (ii) Piling and (iii) Pipeline. Revenue generated from these three segments for the year ended March 31, 2010 can be seen in the chart below:

A complete discussion on segment results can be found in “Segment Annual Results” in the Financial Results section of this Management’s Discussion and Analysis.

Heavy Construction and Mining

Our Heavy Construction and Mining segment focuses primarily on providing surface mining support services for oil sands and other natural resources. This includes activities such as:

_Ÿ land clearing, stripping, muskeg removal and overburden removal to expose the mining area;

_Ÿ the supply of labour and equipment to be operated within the customers’ mining fleet, directly supporting the mining of ore;

_Ÿ general support services including road building, repair and maintenance for both mine and treatment plant operations, hauling of sand and gravel and relocation of treatment plants;

_Ÿ construction related to the expansion of existing projects including site development and construction of infrastructure; and

_Ÿ environmental services including construction and modification of tailing ponds and reclamation of completed mine sites to stringent environmental standards.

Most of these services are classified as recurring services and represent the majority of services provided by our Heavy Construction and Mining segment. Complementing these services, the Heavy Construction and Mining segment also provides industrial site construction for mega-projects and underground utility installation for plant, refinery and commercial building construction.

Piling

Our Piling segment installs all types of driven, drilled and screw piles, caissons, earth retention and stabilization systems. Operating from British Columbia to Ontario, this segment has a solid record of performance on both small and large-scale projects. Our Piling segment 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 community infrastructure projects.

Pipeline

Our Pipeline segment installs transmission, distribution and gathering systems made of steel, fiberglass and/or plastic pipe in sizes up to 52” in diameter. Penstock installation services are also provided. This segment has successfully completed jobs of varying magnitude for some of Canada’s largest energy companies, including Kinder Morgan’s⁵ Trans Mountain Expansion (TMX) Anchor Loop pipeline, which involved the installation of 160 km of large-diameter pipe through extremely challenging and ecologically sensitive terrain. The segment also provides recurring services to specific customers. As an example, we have a three-year contract to complete pipeline integrity excavations and hydrostatic retest on TransCanada Pipelines’⁶ mainline system in British Columbia, Saskatchewan, Manitoba and Ontario.

⁵ Kinder Morgan Energy Partners, L.P. (Kinder Morgan).

⁶ TransCanada Pipelines Limited (TransCanada Pipelines), a wholly owned subsidiary of TransCanada Corporation.

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

End Markets Overview

During the fiscal year ended March 31, 2010, we provided services to three distinct end markets: Canadian oil sands, conventional oil and gas and commercial and public construction. Revenue generated from these end markets for the year ended March 31, 2010, can be seen in the chart below:

Canadian Oil Sands

Our core market is the Alberta oil sands, where we generated 86% of our fiscal 2010 revenue. According to the Canadian Association of Petroleum Producers (CAPP), the oil sands represent 97% of Canada’s recoverable oil reserves. At 173 billion barrels, the Canadian oil sands deposits are second only to those of Saudi Arabia. The oil sands are located in three regions of northern Alberta: Athabasca, Cold Lake and Peace River. In 2009, oil sands production reached 1.4 million barrels per day (“bpd”), representing 49.7% of Canada’s total oil production.

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: (i) 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 (ii) in situ technology, where bitumen deposits are buried too deep for open pit mining to be cost effective and operators instead inject steam into the deposit, lowering the viscosity of the bitumen so that the bitumen can be separated from the sand and pumped to the surface, leaving the sand in place. Steam Assisted Gravity Drainage (SAGD) is a type of in situ technology that uses horizontal drilling to produce bitumen. CAPP estimates that approximately 20% of the oil sands are recoverable through open pit mining. Open pit mining projects tend to have greater production capacity than in situ projects. For example, approximately 52% of 2009 oil sands production was extracted from five active mining projects, while the remaining 48% of 2009 oil sands production was extracted from approximately 17 active in situ projects. So while the number of active and planned in situ projects far exceeds the number of mining projects, according to CAPP and other industry forecasts, future total production from mining and in situ projects is expected to remain approximately equal.*

Although, we have provided and intend to continue providing construction services to in situ projects, we currently provide most of our services to customers that access the oil sands through open pit mines. The three-to-four year initial construction and development phase of a new mine or in situ project creates demand for our project development services, such as clearing, site preparation, piling and underground utilities installation. Once the construction phase of an in situ project is complete, there is little opportunity for us to provide recurring services. In contrast, after the initial construction phase of a mining project is complete, the mine moves into the 30-40 year operational phase and demand shifts from project development services to recurring services such as surface mining, overburden removal, labour and equipment supply, mine infrastructure development and maintenance and land reclamation.^*

Approximately 89% of our oil sands related revenue, for the year ended March 31, 2010, came from the provision of recurring services to existing oil sands projects, with the balance coming from project development services.

Project Development Services: Demand for project development services in the oil sands is primarily driven by new developments and expansions. We support our customers’ new development and expansion projects by providing construction services such as clearing, site preparation, piling and underground utilities installation. Between 2000 and 2009, over $100 billion of capital has been invested into the oil sands, the core market for our project development services.^*

Recurring Services: Growth in our recurring services business is a function of both increased production levels in the oil sands and the inherent need for additional support services through the lifecycle of a mine.

Increases in production levels are achieved both when new mines enter the production phase and when existing mines eliminate bottlenecks and/or expand their existing operations. In each case, the required output from the extraction process increases, resulting in higher demand for the recurring services we provide, such as overburden removal, equipment and labour supply, mine maintenance and reclamation services.

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

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

The requirement for recurring services also typically grows as mines age. Mine operators tend to construct their plants closest to the easy-to-access bitumen deposits to maximize profitability and cash-flow at the beginning of their project. As the mines move through their typical 30-40 year life cycle, easy-to-access bitumen deposits are depleted and operators must go greater distances and move more material to access their ore reserves. Over this period, haulage distances progressively increase and the amount of overburden to be removed per cubic metre of exposed oil sand grows. As a result, the total capacity of digging and hauling equipment must increase, together with an increase in the ancillary equipment and services needed to support these activities. In addition, as the mine extends to new areas of the lease, operators will often relocate mine infrastructure in order to reduce haul distances. This creates demand for mine construction services in the expansion area, as well as reclamation services to remediate the mined-out area. Accordingly, the demand for recurring oil sands services continues to grow even during periods of stable production because the geographical footprints of existing mines continue to expand under normal operation.^*

Current Canadian Oil Sands Business Conditions

Project Development Services: Although last year saw a general slowdown in project development activity in the oil sands, we also saw construction on two projects, Exxon’s $8 billion Kearl mining project⁷ and Shell Albian’s $12 billion Jackpine mine expansion project, continue without any delay as these operators remained focused on the long term oil price as the project driver. As economic conditions have strengthened, oil prices have stabilized and producers are reaffirming their commitment to oil sands development with new construction approval announcements, including Husky Energy Inc.’s Sunrise⁸ in situ project and ConocoPhillips’ Surmont⁹ in situ project. Canadian Natural has indicated strong interest in proceeding with its Horizon Mine Phase 2/3 expansion and development of the Kirby in situ project, while Suncor is proceeding with additional stages of its Firebag in situ project as it completes the integration process of the Fort Hills¹⁰ mining project from its recent acquisition of Petro-Canada Limited. While capital spending in the oil sands declined from $18 billion in calendar 2008 to $11 billion in 2009, CAPP forecasts a recovery in capital spending to $13 billion in 2010.

Further positive indicators that investor interest in the oil sands is strengthening include PetroChina’s¹¹ recent $2 billion investment in Athabasca Oil Sands, followed by a $1.35 billion initial public offering by Athabasca Oil Sands Corp., the largest in oil sands history. China’s Sinopec Corp.¹² has also recently announced plans to buy ConocoPhillips’ stake in the Syncrude project for $4.65 billion. This is China’s largest investment in North America to date.

While the overall trends are positive, environmental activism opposing oil sands development has been increasing and receiving broad media coverage. Environmental costs to producers are also rising as a result of increasing regulatory requirements. As an example, the recently released ERCB Directive 074¹³ requires producers to invest in new research, development, technology and services to address the reclamation of tailings ponds in a significantly accelerated time span. Although this adds costs to the process, it also creates opportunities for service providers like ourselves to create new lines of business to support the construction and operation of these new reclamation processes.

Recurring Services: Despite significant volatility in oil prices over the past year, all of the existing oil sands mines maintained production levels and continued to create stable demand for recurring services. The stability of these operations is largely due to the immense up-front capital investment associated with them and the consequent need to operate at full capacity to achieve low per-unit operating costs, coupled with the harsh environment in which they operate, which makes them difficult to shut down for extended periods. The costs and operational risks associated with a production stoppage longer than a single summer season (such as a planned maintenance shutdown) virtually eliminate this as an economically viable option for oil sands producers.

We believe that demand for recurring services will continue to be stable in the improving economic environment. Moreover, we believe demand for recurring services will continue to grow, over the long-term, as existing oil sands mines progress and as new mines, such as Shell Albian’s Jackpine mine, come on-line.*

⁷ Exxon Kearl project is a joint venture oil sands mining and extraction project. Imperial Oil Limited holds a 70.96% interest in the joint venture with ExxonMobil Canada Properties, a subsidiary of Exxon Mobil Corporation (Exxon). Imperial Oil Limited is the project operator.

⁸ Husky Energy Inc.’s (Husky Energy) Sunrise Oil Sand project is a 50/50 joint venture with BP Canada Energy Company (BP), a wholly owned subsidiary of BP PLC. The Sunrise project is operated by Husky Energy.

⁹ ConocoPhillips Canada Resources Corporation’s (ConocoPhillips) Surmount Oil Sand in situ project is a 50/50 joint venture between ConocoPhillips Canada, a wholly owned subsidiary of ConocoPhillips Company and Total E&P Canada Ltd. (Total), a wholly owned subsidiary of Total SA. ConocoPhillips Canada is the project operator.

¹⁰ Fort Hills LP (Suncor Fort Hills), a limited partnership between Suncor Energy Inc. (60%), UTS Energy Corporate (20%) and Teck Resources Limited (20%). Suncor Energy Inc., the new project operator, acquired Petro-Canada Limited, the previous majority partner and project operator in 2008.

¹¹ PetroChina Company Limited (PetroChina), established as a joint company with limited liability by China National Petroleum Corporate (CNPC), a state-owned enterprise of the People’s Republic of China. CNPC is the sole sponsor and controlling shareholder of PetroChina.

¹² Sinopec Corp., previously known as China Petroleum & Chemical Corporation, was incorporated by China Petrochemical Corporation (Sinopec Group), a state-owned enterprise of the People’s Republic of China. Sinopec Group is the controlling shareholder of Sinopec Corp.

¹³ Energy Resources Conservation Board of Alberta (ERCB), Directive 074 – “Tailings Performance Criteria and Requirements for Oil Sands Mining Schemes”.

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

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

Commercial and Public Construction

We provide construction services, primarily piling and shoring wall construction, to the commercial and public construction markets in Alberta, British Columbia, Saskatchewan and most recently, Ontario, following our 2009 acquisition of Drillco Foundations.

Current Commercial and Public Construction Business Conditions

After a 24% decline in the value of industrial building permits and a 17% decrease in the value of commercial building permits in 2009, construction activity in Canada is entering the early phase of recovery. The recovery is being led by institutional and governmental construction, which according to Statistics Canada, has recently experienced a 10% increase over the value of building permits issued in calendar 2009.

The increase in infrastructure spending is being driven in part by population demands. In recent years, activity in the energy sector has created significant economic and population growth in Western Canada, which has strained public facilities and infrastructure across the province. The Alberta government has responded by allocating approximately $120 billion over 20 years to improvement and expansion projects. In its 2010 budget, the Alberta government announced plans to spend $20.1 billion over the next three years on capital projects. This compares to $1 billion in 2002-2003.

The renewed interest in infrastructure investment is also being supported by government efforts to stimulate the economy. The government of Canada recently announced its 2010 budget, which includes $7.7 billion in stimulus spending in 2010-2011 as a part of its “Economic Action Plan”. In Ontario, the government recently announced $16.3 billion of infrastructure spending for 2010-2011 as part of its 2010 budget.

We believe that the demand for new infrastructure to support a larger population coupled with government investment in infrastructure to stimulate the economy provides a strong outlook for infrastructure spending in Western Canada and in Ontario. We believe that our ability to meet many of the construction and piling needs of core infrastructure customers, along with our strong local presence and significant regional experience, position us to capitalize on the expected growth in infrastructure projects. We are also seeing indications of a recovery in the commercial construction market and expect to benefit from increased spending in the private sector, over the coming years, as the economy recovers from the downturn.^*

Conventional Oil and Gas

According to the Canadian Energy Pipeline Association (CEPA), Canada has over 580,000 kilometres of pipeline that transports approximately 2.65 million barrels of crude oil and equivalents per day and 17.1 billion cubic feet of natural gas per day to various distribution points in Canada and the US. There are a number of new pipelines and pipeline

expansion projects under construction and in various stages of the planning and regulatory process to provide capacity for the expected increase in oil and gas production.

We provide pipeline installation and facility support services to Canada’s conventional oil and gas producers and pipeline transmission companies. Conventional oil and gas producers typically require pipeline installation services in order to connect producing wells to existing pipeline systems, while pipeline transmission companies install larger diameter pipelines to carry oil and gas to market.

According to CAPP, pipeline projects that are currently underway and are expected to be in service by the end of 2010 will provide an additional one million barrels per day of capacity. Based on current production forecasts, it is expected that further capacity increases will be required by 2016.

Current Conventional Oil and Gas Business Conditions

Forecasts of oil and gas production growth have been scaled back due to weaker economic conditions and schedules for new pipelines and expansions are being revised to reflect the new production expectations and the related capacity requirements. However, significant pipeline expansion is still required to meet future demand and companies involved in the transmission of oil and gas continue to move forward with investment in new pipeline development. In the near term, we anticipate steady demand for smaller pipeline projects and expansions and given the current oversupply of contracting capacity, we expect this market to remain highly competitive.*

Minerals Mining

Outside of the oil sands, we have identified the Canadian resource industry as one of our targets for new business opportunities.

According to the government agency, Natural Resources Canada (“NRC”), Canada is one of the largest mining nations in the world, producing more than 60 different minerals and metals. It is the world’s largest producer of potash, accounting for more than one third of the world’s potash production and exports. Canada is also a world leader in uranium mining having the two largest high-grade deposits of uranium in the world. According to NRC, 80% of Canada’s recoverable uranium reserve base is categorized as “low cost”. Historically, exploration and production has taken place primarily in Saskatchewan. Recently, however, significant exploration efforts are underway in the Northwest Territories, Yukon, Nunavut, Quebec, Newfoundland and Labrador, Ontario, Manitoba and Alberta.

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

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

The diamond mining industry in Canada is relatively new, having operated for only nine years. According to NRC, Canada continues to rank as the third largest diamond producing country in the world by value after Botswana and Russia. We intend to leverage the experience and skills gained through the successful completion of the construction of the De Beers Victor diamond mine to pursue other opportunities in this area.*

Current Minerals Mining Business Conditions

Canada’s resource mining sector was hard hit by the economic crisis and subsequent steep drop in commodity prices and saw exploration spending decline by 47% in calendar 2009, after reaching a record $3.3 billion in 2008. Despite this decrease, Canada remained the world’s top mining exploration destination, accounting for 34% of all exploration programs undertaken in the world in 2009.

Commodity prices are now beginning to recover and are expected to continue improving in 2010, but there is continuing uncertainty about the strength and sustainability of the economic recovery. Accordingly, preliminary spending indications for calendar 2010 indicate mining investment levels will be similar to or only slightly higher than in 2009.^*

Revenue Sources

Revenue by Category

We have experienced steady growth in recurring revenue from operating oil sands projects in recent years. Going forward, we expect to see this continue as activity levels increase at existing mines and new oil sands projects move from the capital development stage into the operational phase. Project development revenue, by contrast, has declined since September 2008, reflecting the impact of economic conditions on large-scale capital projects.^*

The following graph displays the breakdown between recurring services revenue and project development services revenue for the trailing 12-months at three month intervals from March 31, 2008 to March 31, 2010:

Recurring Services Revenue: Recurring services revenue is derived from long-term contracts and site services contracts as described below:

_Ÿ Long-term contracts. This category of revenue consists of revenue 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 include long-term contracts for overburden removal and reclamation. Revenue in this category is typically generated under unit-price contracts and is included in our calculation of backlog. This work is generally funded from our customers’ operating budgets.

_Ÿ Site Services Contracts. This category of revenue is generated from the master services agreements in place with Syncrude and Shell Albian, specific project contracts such as the truck rental contract with Suncor and ad hoc work on an as needed basis such as work being done on a time-and-materials basis to service the newly commenced operations of Canadian Natural. This revenue is typically generated by supporting the operations of our customers and is therefore considered to be recurring. It is primarily generated under time-and-materials contracts and because it is not guaranteed, it is not included in our calculation of backlog. This work is generally funded from our customers’ operating or maintenance capital budgets.

Project Development Services Revenue: Project development services revenue is typically generated during the support of 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. It can be included in backlog if generated under lump-sum, unit-price or time-and-materials contracts and the scope is defined. This work is generally funded from our customers’ capital budgets.

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

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

Revenue by End Market

Growth in both recurring services and capital projects increased our oil sands work volumes during 2008. The pipeline installation project for Kinder Morgan increased our revenues in the conventional oil and gas sector. The declining contribution of minerals mining revenue reflects the completion of the De Beers diamond mine project in early 2008. The following graph displays the breakdown between revenues from each end market for the trailing 12-month period at three month intervals from March 31, 2008 to March 31, 2010:

Our Strategy

Our strategy is to be an integrated service provider for the developers and operators of resource-based industries in a broad and often challenging range of environments. More specifically, our strategy is to:

_Ÿ Increase our recurring revenue base: It is our intention to continue expanding our recurring services business to provide a larger base of stable revenue.

_Ÿ Leverage our long-term relationships with customers: We intend to continue building our relationships with existing oil sands customers to win a substantial share of the heavy construction and mining, piling and pipeline services outsourced in connection with their projects.

_Ÿ Leverage and expand our complementary services: Our service segments, Heavy Construction and Mining, Pipeline and Piling are complementary to one another and allow us to compete for many different forms of business. We intend to build on our “first-in” position to cross-sell our many services, while also pursuing selective acquisition opportunities that expand our complementary service offerings.

_Ÿ 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.

_Ÿ Position for future growth: We intend to build on our market leadership position and successful track record with our customers to benefit from future oil sands development. We intend to use our fleet size, strong balance sheet and management capability to respond to new opportunities as they occur.

_Ÿ 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 with developing those natural resources.

To help us manage successfully through the current business environment, we are focused on:

_Ÿ working with our customers and suppliers to establish the most efficient and cost effective way for us to deliver services to meet a broad range of our customers’ project needs;

_Ÿ strategic prioritization of our capital expenditures to minimize cash outflows while maintaining the flexibility to take advantage of profitable opportunities; and

_Ÿ careful and thorough evaluation of all opportunities to ensure we maintain reasonable levels of profitability in the current economic environment and enhance shareholder value.

C. Financial Results

Adjustments related to prior year financial statements

The financial statements for fiscal 2009 and fiscal 2008 as initially reconciled to US GAAP have been amended to correct the following errors identified during the preparation of our fiscal 2010 financial statements under US GAAP:

(i) Adoption of CICA Handbook Section 3031, “Inventories”: We identified an error related to the adoption of Canadian Handbook Section 3031, “Inventories” in fiscal 2009. The change in accounting policy was accounted for

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

on a retrospective basis, without restatement of prior periods under Canadian GAAP resulting in a decrease to deficit of $1.0 million, net of taxes of $0.4 million, to reverse a tire impairment recorded in fiscal 2008. This decrease in deficit should have been adjusted for in the reconciliation to US GAAP as the tire impairment should not have been recorded in fiscal 2008 under US GAAP. As a result of this error, net income under US GAAP for fiscal 2008 increased by $1.0 million and deficit under US GAAP as at March 31, 2008 decreased by $1.0 million;

(ii) Reclassification of accrued liabilities: The financial statements for fiscal 2009 have been amended to correct a classification error with respect to accrued liabilities identified during the preparation of our fiscal 2010 consolidated financial statements. Certain operating lease agreements provide a maximum hourly usage limit, above which we will be required to pay for the over hour usage. These contingent rentals are recognized when payment is considered probable and are due at the end of the lease term. We have historically classified the contingent rentals as a current liability; however, certain of the amounts are due beyond one year from the balance sheet date. In the current year, we reclassified amounts due beyond one year, from the balance sheet date, as a long term liability and reclassified comparative figures accordingly. The amount reclassified on the Consolidated Balance Sheet was $7.1 million as at March 31, 2009;

(iii) Buy-out of leased assets: The financial statements for fiscal 2008 have been amended under US GAAP to correct an error related to the method of accounting for an incentive at the time of buying previously leased assets, which was identified during the preparation of our fiscal 2010 consolidated financial statements. When an asset is leased under an operating lease agreement, as stated in the paragraph above, contingent rentals are recognized when payment is considered probable and are due at the end of the lease term. We can buy the asset at the end of the lease term at a pre-determined market price at which point the liability is extinguished since the lease agreement is cancelled. We have been traditionally extinguishing the liability for such lease buyouts by reducing equipment costs related to leased equipment, instead of considering the extinguishment of the liability as an incentive to purchase the asset and therefore reducing the cost of the asset. The correction of this error increased “Equipment costs” by $2.7 million, reduced “Depreciation” by $0.1 million, reduced “Deferred income taxes” by $0.8 million and reduced “Net income and comprehensive income for the year” by $1,806 from the amounts originally reported in the Consolidated Statements of Operations and Comprehensive Income (Loss) for the year ended March 31, 2008. It also reduced “Property, plant and equipment” by $2.6 million, reduced long term “Deferred tax liabilities” by $0.8 million and increased “Deficit” for the year by $1.8 million from the amounts originally reported in our Consolidated Balance Sheet as at March 31, 2008. The financial statements for fiscal 2009 have also been amended under US GAAP to correct an error related to the method of accounting for an incentive at time of buying previously leased assets, which was identified during the preparation of our fiscal 2010 consolidated financial statements as stated above. The correction of this error increased “Equipment costs” by $6.6 million, reduced “Depreciation” by $0.6 million, reduced “Deferred income taxes” by $1.8 million and increased “Net loss and comprehensive loss for the year” by $4.2 million from the amounts originally reported in the Consolidated Statements of Operations and Comprehensive Income (Loss) for the year ended March 31, 2009. It also reduced “Property, plant and equipment” by $8.6 million, reduced long term “Deferred tax liabilities” by $2.6 million and increased “Deficit” for the year by $6.0 million from the amounts originally reported in our Consolidated Balance Sheet as at March 31, 2009.

(iv) Valuation of derivative financial instruments: The financial statements for fiscal 2009 have also been amended under US GAAP to correct an error related to the determination of the fair value of the cross-currency and interest rate swap liabilities (collectively, the “swap liability”) which was identified on settlement of the swap liability on April 8, 2010. We recorded the fair value of the swap liability and in addition recorded accrued interest on the swap liability. This resulted in the swap liability being misstated and the changes in the fair value of the swap liability being misstated by the change in the amount of the accrued interest at each reporting period from March 31, 2009. The periods before March 31, 2009 were not materially impacted because prior to February 2, 2009, the US Dollar interest rate swap was still in place (see note 24(c)(ii) of our consolidated financial statements for the year ended March 31, 2010), and therefore the net accrued interest payable under the swap liability was not material. The error increased “Realized and unrealized gain on derivative financial instruments” by $7.5 million, increased income tax expense by $1.7 million and reduced net loss by $5.8 million from amounts originally reported in the Consolidated Statements of Operations and Comprehensive Income (Loss) for the year ended March 31, 2009. It also reduced “Derivative financial instruments” by $7.5 million and increased long term “Deferred tax liabilities” by $1.7 million in the Consolidated Balance Sheet as at March 31, 2009.

The above error also impacted previously reported US GAAP amounts for the years ended March 31, 2009 and 2008, respectively, which were previously only reported on an annual basis. Please refer to note 3aa) of our consolidated financial statements for the year ended March 31, 2010 for further information on these items.

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

Differences between US and Canadian GAAP

The adoption of US GAAP as our reporting standard has the following impacts on our financial statements, the magniture of which vary, year to year:

Capitalization of interest

US GAAP requires capitalization of interest costs as part of the historical cost of acquiring certain qualifying assets that require a period of time to prepare for their intended use. This is not required under Canadian GAAP. The capitalized amount is subject to depreciation in accordance with our policies when the asset is placed into service.

Financing costs, discounts and premiums

For US GAAP purposes, deferred financing costs incurred in connection with our 8 ³/4% senior notes are being amortized over the term of the related debt using the effective interest method. Prior to April 1, 2007, for Canadian GAAP purposes, these transaction costs were recorded as a deferred asset under Canadian GAAP and these deferred financing costs were being amortized on a straight-line basis over the term of the debt.

Effective April 1, 2007, we adopted CICA Handbook Section 3855, “Financial Instruments – Recognition and Measurement” (“Section 3855”), on a retrospective basis without restatement as described below. Although Section 3855 also requires the use of the effective interest method to account for the amortization of finance costs, the requirement to bifurcate the issuer’s early prepayment option on issuance of the debt (which is not required under US GAAP) resulted in an additional premium that is being amortized over the term of the debt under Canadian GAAP. In addition, foreign denominated transaction costs, discounts and premiums are considered as part of the carrying value of the related financial liability under Canadian GAAP and are subject to foreign currency gains or losses resulting from periodic translation procedures as they are treated as a monetary item under Canadian GAAP. Under US GAAP, foreign denominated transaction costs are considered non-monetary and are not subject to foreign currency gains and losses resulting from periodic translation procedures.

In connection with the adoption of Section 3855, transaction costs incurred in connection with our revolving credit facility of $1.6 million were reclassified from deferred financing costs to intangible assets on April 1, 2007 under Canadian GAAP and these costs continue to be amortized on a straight-line basis over the term of the facility. Under US GAAP, we continue to amortize these transaction costs over the stated term of the related debt using the effective interest method. We disclose the financing costs for both the 8 ³/4% senior notes and the revolving credit facility as deferred financing costs on the Consolidated Balance Sheets with the amortization charge classified as interest on the Consolidated Statements of Operations and Comprehensive Income (Loss). Under Canadian GAAP, the 8 ³/4% senior notes financing costs are included in the “8 ³/4% senior notes” balance on the Consolidated Balance Sheets.

Stock-based compensation

Up until April 1, 2006, we followed the provisions of ASC 718, “Share-Based Payment” (formerly Statement of Financial Accounting Standards No. 123, “Stock-Based Compensation”), for US GAAP purposes. As we used the fair value method of accounting for all stock-based compensation payments under Canadian GAAP, there were no differences between Canadian and US GAAP prior to April 1, 2006. On April 1, 2006, we adopted the provisions of Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment” (“SFAS 123R”), which is now a part of ASC 718. As we used the minimum value method for purposes of complying with Statement of Financial Accounting Standards No. 123, we were required to adopt the provisions under the revised guidance prospectively. Under Canadian GAAP, we were permitted to exclude volatility from the determination of the fair value of stock options granted until the filing of our initial registration statement relating to the initial public offering of voting shares on July 21, 2006. As a result, for options issued between April 1, 2006 and July 21, 2006, there is a difference between Canadian and US GAAP relating to the determination of the fair value of options granted reflected in General and Administrative expense.

Derivative financial instruments

Under Canadian GAAP, we determined that our early prepayment option included in the senior notes should be bifurcated from the host contract, along with a contingent embedded derivative in our 8 ³/4% 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 our 8 ³/4% senior notes is accreted to par value over the term of the notes using the effective interest method and is recognized as interest expense. Prior to April 1, 2007 under Canadian GAAP, separate accounting of embedded derivatives from the host contract was not permitted by EIC-117.

Under US GAAP, ASC 815 (formerly Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”)) establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts and debt instruments) be recorded in the balance sheet as either an asset or liability measured at its fair value. The contingent embedded derivative in our 8 ³/4% senior notes that provides for accelerated redemption by the holders in certain instances met the

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

criteria for bifurcation from the debt contract and separate measurement at fair value. The embedded derivative has been measured at fair value and changes in fair value recorded in net income for all periods presented. The issuer’s early prepayment option included in our 8 ³/4% senior notes does not meet the criteria as an embedded derivative under ASC 815 (formerly SFAS 133) and was not bifurcated from the host contract and measured at fair value resulting in a US GAAP and Canadian GAAP difference for all periods presented.

On adoption of CICA Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, we reviewed the accounting treatment of a number of outstanding contracts and determined that a price escalation feature in a revenue construction contract and supplier contracts entered into prior to April 1, 2007 contained embedded derivatives that are not closely related to the host contract under Canadian GAAP. We recorded the fair value of these embedded derivatives on April 1, 2007 of $9,720, with a corresponding increase in opening deficit of $6,950, net of future income taxes of $2,770 for Canadian GAAP purposes. Under US GAAP, we had recognized and measured these embedded derivatives since inception of the related contracts.

NAEPI Series B Preferred Shares

Prior to the modification of the terms of the North American Energy Partners Inc. (“NAEPI”) Series B preferred shares on March 30, 2006, there were no differences between Canadian GAAP and US GAAP related to the NAEPI Series B preferred shares. As a result of the modification of terms of NAEPI’s Series B preferred shares, under Canadian GAAP, we continued to classify the NAEPI Series B preferred shares as a liability and were accreting the carrying amount of $42.2 million on the amendment date (March 30, 2006) to their December 31, 2011 redemption value of $69.6 million using the effective interest method. Under US GAAP, we recognized the fair value of the amended NAEPI Series B preferred shares as minority interest as such amount was recognized as temporary equity in the accounts of NAEPI in accordance with EITF Topic D-98 and recognized a charge of $3.7 million to retained earnings for the difference between the fair value and the carrying amount of the Series B preferred shares on the amendment date. Under US GAAP, we were accreting the initial fair value of the amended NAEPI Series B preferred shares of $45.9 million recorded on their amendment date (March 30, 2006) to the December 31, 2011 redemption value of $69.6 million using the effective interest method, which was consistent with the treatment of the NAEPI Series B preferred shares as temporary equity in the financial statements of NAEPI. The accretion charge was recognized by us as a charge to minority interest (as opposed to retained earnings in the accounts of NAEPI) under US GAAP and interest expense in our financial statements under Canadian GAAP.

On November 28, 2006, we exercised a call option to acquire all of the issued and outstanding NAEPI Series B preferred shares in exchange for 7,524,400 common shares of NACG Holdings Inc. (“NACG”). For Canadian GAAP purposes, we recorded the exchange by transferring the carrying value of the NAEPI Series B preferred shares on the exercise date of $44.7 million to common shares. For US GAAP purposes, the conversion has been accounted for as a combination of entities under common control as all of the shareholders of the NAEPI Series B preferred shares were also common shareholders of NACG, resulting in the reclassification of the carrying value of the minority interest on the exercise date of $48.1 million to common shares. NACG and NAEPI were amalgamated later in 2006 and the amalgamated entity continued as NAEPI.

Inventories

Effective April 1, 2008, we retrospectively adopted CICA Handbook Section 3031, “Inventories”, without restatement of prior periods. This standard requires inventories to be measured at the lower of cost and net realizable value and provides guidance on the determination of cost, including the allocation of overheads and other costs to inventories, the requirement for an entity to use a consistent cost formula for inventory of a similar nature and use and the reversal of previous write-downs to net realizable value when there are subsequent increases in the value of inventories. This new standard also clarifies that spare component parts that do not qualify for recognition as property, plant and equipment should be classified as inventory. In adopting this new standard, we reversed a tire impairment that was previously recorded at March 31, 2008 in other assets of $1.4 million with a corresponding decrease to opening deficit of $1.0 million net of future taxes of $0.4 million.

During the year ended March 31, 2008, the replacement cost (i.e. market) of spare tire inventory was lower than the original carrying amount of inventory. As a result, we recorded an inventory write-down of $1.4 million under Canadian GAAP. Under US GAAP, market means current replacement cost. However, market under US GAAP should not exceed the net realizable value nor should it be less than net realizable value reduced by an allowance for a normal profit margin. We established that the net realizable value and net realizable value less an allowance for a normal profit margin was greater than or equal to cost and as such a write-down of spare tires was not appropriate under US GAAP for the year ended March 31, 2008.

Joint venture

We own a 49% interest in Noramac Ventures Inc., a nominee company for our Noramac Joint Venture (JV) and we have joint 50/50 control of this entity. Under US GAAP, we record our share of earnings of the JV using the equity method of accounting. Under Canadian GAAP, we use the proportionate consolidation method of accounting for the JV. Under the proportionate consolidation method, we recognize our share of the results of operations, cash flows and financial position of the JV on a line-by-line basis in our consolidated financial statements and eliminate our share of all material

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

intercompany transactions with the JV. While there is no impact on net income or earnings per share as a result of the US GAAP treatment of the joint venture, as compared to Canadian GAAP, there are presentation differences affecting the disclosures in the consolidated financial statements and supporting notes.

Other matters

Other adjustments relate to the tax effect of items “Capitalization of interest” through “Inventories” above. The tax effects of temporary differences are described as future income taxes under Canadian GAAP whereas in these financial statements such amounts are described as deferred income taxes under US GAAP. In addition, Canadian GAAP generally refers to additional paid-in capital as contributed surplus for financial statement presentation purposes.

Summary of differences between US and Canadian GAAP

The impacts of the annual differences between US and Canadian GAAP are described in detail in a reconciliation to Canadian GAAP provided in note 34 – “United States and Canadian accounting policy differences” in our audited consolidated financial statements for the year ended March 31, 2010. A summary of these impacts appears below:

	Year ended March 31,
(dollars in thousands)	2010	2009		2008
Revenue – US GAAP	$758,965	$972,536		$989,696
Revenue – Canadian GAAP	763,301	972,536		989,696
Operating income (loss) – US GAAP	73,474	(87,092	)	91,727
Operating income (loss) – Canadian GAAP	72,811	(87,712	)	89,817
Net income (loss) – US GAAP	28,219	(135,404	)	41,534
Net income (loss) – Canadian GAAP	29,174	(137,877	)	37,978
Basic EPS – US GAAP	$0.78	$(3.76	)	$1.16
Basic EPS – Canadian GAAP	$0.81	$(3.83	)	$1.06

	Three months ended March 31,
(dollars in thousands)	2010		2009
Revenue – US GAAP	$220,569		$174,700
Revenue – Canadian GAAP	222,374		174,700
Operating income (loss) – US GAAP	13,127		(129,204	)
Operating income (loss) – Canadian GAAP	12,959		(129,333	)
Net loss – US GAAP	(943	)	(137,112	)
Net loss – Canadian GAAP	(2,963	)	(136,747	)
Basic EPS – US GAAP	$(0.03	)	$(3.80	)
Basic EPS – Canadian GAAP	$(0.08	)	$(3.79	)

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

Consolidated Annual Results

	Year ended March 31,
(dollars in thousands, except per share information)	2010	% of Revenue	2009		% of Revenue	2008	% of Revenue	2010 vs. 2009 Change		2010 vs. 2008. Change
Revenue	$758,965	100.0%	$972,536		100.0%	$989,696	100.0%	$(213,571	)	$(230,731	)
Project costs	301,307	39.7%	505,026		51.9%	592,458	59.9%	(203,719	)	(291,151	)
Equipment costs	209,408	27.6%	217,120		22.3%	176,190	17.8%	(7,712	)	33,218
Equipment operating lease expense	66,329	8.7%	43,583		4.5%	22,319	2.3%	22,746		44,010
Depreciation	42,636	5.6%	36,389		3.7%	35,720	3.6%	6,247		6,916
Gross profit	139,285	18.4%	170,418		17.5%	163,009	16.5%	(31,133	)	(23,724	)
General and administrative costs	62,530	8.2%	74,460		7.7%	69,806	7.1%	(11,930	)	(7,276	)
Operating income (loss)	73,474	9.7%	(87,092	)	(9.0)%	91,727	9.3%	160,566		(18,253	)
Net income (loss)	$28,219	3.7%	$(135,404	)	(13.9)%	$41,534	4.2%	$163,623		$(13,315	)
Per share information
Net income (loss)–basic	$0.78		$(3.76	)		$1.16		$4.54		$(0.38	)
Net income (loss)–diluted	$0.77		$(3.76	)		$1.13		$4.53		$(0.36	)
EBITDA(1)	$112,333	14.8%	$(53,269	)	(5.5)%	$124,254	12.6%	$165,602		$(11,921	)
Consolidated EBITDA(1)	$121,644	16.0%	$139,446		14.3%	$131,932	13.3%	$(17,802	)	$(10,288	)

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

	Year ended March 31,
(dollars in thousands)	2010		2009		2008
Net income (loss)	$28,219		$(135,404	)	$41,534
Adjustments:
Interest expense, net	26,080		29,612		29,080
Income taxes	13,679		14,633		17,116
Depreciation	42,636		36,389		35,720
Amortization of intangible assets	1,719		1,501		804
EBITDA	$112,333		$(53,269	)	$124,254
Adjustments:
Unrealized foreign exchange (gain) loss on senior notes	(48,920	)	46,466		(25,006	)
Realized and unrealized loss (gain) on derivative financial instruments	54,411		(37,250	)	30,075
Loss on disposal of property, plant, equipment and assets held for sale	1,606		5,349		672
Stock-based compensation	2,258		1,950		1,937
Equity in earnings of unconsolidated joint venture	(44	)	–		–
Impairment of goodwill	–		176,200		–
Consolidated EBITDA	$121,644		$139,446		$131,932

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

Analysis of Annual Consolidated Results

Revenue

For the year ended March 31, 2010, revenues of $759.0 million were $213.6 million lower than in the year ended March 31, 2009 and $230.7 million lower than in the year ended March 31, 2008. The revenue decline reflects reduced development activity in the oil sands, a sharp decline in Pipeline segment revenues and weakness in commercial and industrial construction markets. The impact of reduced project development activity was partially offset by continued growth in recurring services volumes as a result of increased mining services provided to Shell Albian, Suncor and Canadian Natural. Recurring services volumes at the Syncrude sites declined as a result a major upgrader maintenance program undertaken by the customer during the first half of the year and increased competition for work on these sites.

Gross Profit

For the year ended March 31, 2010, gross profit was $139.3 million, a decrease of $31.1 million from the previous year and a decrease of $23.7 million from the year ended March 31, 2008. The change in gross profit was primarily related to lower revenues. As a percentage of revenue, gross profit margin remained relatively stable at 18.4% compared to 17.5% at the year ended March 31, 2009 and increased 1.9% compared to the year ended March 31, 2008. Margins for the year ended March 31, 2009 also benefited from the settlement of outstanding Pipeline claims.

Project costs, as a percentage of revenue, decreased to 39.7% during the year ended March 31, 2010, from 51.9% and 59.9% in the years ended March 31, 2009 and 2008 respectively. Reduced project development activity in the oil sands was a contributing factor in this decrease, partially offset by an increase in the more equipment-intensive recurring services business as reflected by the increase of equipment costs to 27.6% of revenue during the year ended March 31, 2010, from 22.3% in 2009 and 17.8% in 2008. The current year equipment costs also reflect a savings related to the timing of planned repairs and maintenance. A $7.2 million year-over-year reduction in tire expenses for the year ended March 31, 2010 was a result of lower operating hours and company-wide efforts to improve efficiency and reduce expenses. Margins in both the current and prior year benefitted from significant improvements in the costs for large truck tires compared to the year ended March 31, 2008.

Equipment operating lease expense increased to $66.3 million in the current year, up $22.7 million and $44.0 million from the years ended March 31, 2009 and 2008, respectively. The year-over-year increase in equipment operating lease expense reflects the full-year impact of overburden removal equipment acquired in late 2008 and early 2009 to support full production on our long-term contract with Canadian Natural. Depreciation increased to 5.6% of revenue, compared to 3.7% and 3.6% of revenue for the years ended March 31, 2009 and 2008 respectively. This reflects increased contribution from the Heavy Construction and Mining segment and reduced use of rental equipment. It also reflects an accelerated depreciation charge of $3.6 million, compared to $0.8 million for the year ended March 31, 2009, as certain aging equipment was prepared for resale.

Operating income (loss)

For the year ended March 31, 2010, we recorded operating income of $73.5 million or 9.7% of revenue, compared to an operating loss of $87.1 million during the year ended March 31, 2009 and operating income of $91.7 million or 9.3% of revenue during the year ended March 31, 2008. The operating loss for the year ended March 31, 2009 included a charge of $176.2 million for goodwill impairment. Excluding this impairment, operating income would have been $89.1 million or 9.2% of revenue. For the year ended March 31, 2010, G&A costs decreased by $11.9 million and $7.3 million compared to the last two years, respectively. This improvement reflects the benefits of our reorganization and cost-reduction initiatives, partially offset by a $3.0 million year-over-year increase to stock-based compensation expense, resulting from the impact of the increased value in our share price that impacted the valuation of our deferred director share units and restricted share units.

Net income (loss)

For the year ended March 31, 2010, we recorded net income of $28.2 million (basic income per share of $0.78 and diluted income per share of $0.77). This compared to a net loss of $135.4 million (basic loss per share of $3.76) for the year ended March 31, 2009 and net income of $41.5 million (basic income per share of $1.16 and diluted income per share of $1.13) for the year ended March 31, 2008. Non-cash items affecting the current year results included the positive foreign exchange impact of the strengthening Canadian dollar on our 8 ³/4% senior notes, gains on the interest rate swaps, gains relating to embedded derivatives in long-term supplier contracts and redemption options in our 8 ³/4% senior notes. These items were partially offset by a loss on our cross-currency swaps and a loss relating to embedded derivatives in a long-term customer contract. Net income for the year ended March 31, 2009 was negatively affected by the non-cash impact of the goodwill impairment charge as described above. Excluding the above items, net income for the year ended March 31, 2010 would have been $20.9 million (basic income per share of $0.58 and diluted income per share of $0.57), compared to net income of $44.4 million during the same period last year (basic income per share of $1.23 and diluted income per share of $1.21). For the year ended March 31, 2008, we recorded net income of $41.5 million which was positively impacted by the non-cash foreign exchange gain on our 8 ³/4% senior notes, gains on the interest rate swaps and gains related to the embedded derivatives on long-term supplier contacts. The non-cash gains were mitigated by losses related to our embedded derivatives in a long-term customer contract and losses on the embedded derivative on our 8 ³/4% senior notes. Excluding the non-cash items, net income for the year ended March 31, 2008 would have been $45.3 million (basic income per share of $1.27 and diluted income per share of $1.23).

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

Segment Annual Results

Heavy Construction and Mining

	Year ended March 31,			Changes
(dollars in thousands)	2010	2009	2008	2010 vs. 2009		2010 vs. 2008
Segment revenue	$665,514	$716,053	$626,582	$(50,539	)	$38,932
Segment profit	111,016	109,580	102,686	1,436		8,330
Profit margin	16.7%	15.3%	16.4%

For the year ended March 31, 2010, the Heavy Construction and Mining segment reported revenues of $665.5 million, a $50.5 million decrease compared to the same period last year but a $38.9 million increase over the year ended March 31, 2008. Recurring services revenue grew by 12.3% year-over-year with increased services to Shell Albian, Suncor and Canadian Natural offsetting reduced activity at the Syncrude sites. A major upgrader maintenance program undertaken by this customer earlier in the year and increased competition for work on these sites resulted in lower activity levels during the year. Project development revenues were down year-over-year reflecting the deferral of activity at Suncor’s Fort Hills project and the completion of site development activity at other Suncor sites. Revenues in both the prior-year periods were further bolstered by a tire premium surcharge as well as a higher volume of third-party materials supply on certain contracts. Third-party materials supply involves the supply of fuel and/or construction materials such as gravel to a project which in some cases, can be a significant component of the contract and result in higher revenue. However, the cost of the materials is typically passed through to the customer with a minimal mark-up, reducing gross margins.

For the year ended March 31, 2010, Heavy Construction and Mining profit margin increased to 16.7% of revenue from 15.3% of revenue during the same period last year and was comparable to the profit margin for the year ended March 31, 2008. This improvement reflects the positive impact of higher margin on recurring services revenue due to improvements in contract execution, reduced volumes of low margin third-party materials supply and lower rental equipment costs, partially offset by the margin reduction on a long-term contract. The successful completion of a lump sum project on time and on schedule contributed to the favourable margins in the current year. The prior-year profit margin was negatively affected by production challenges on a single project.

Piling

	Year ended March 31,			Changes
(dollars in thousands)	2010	2009	2008	2010 vs. 2009	2010 vs. 2008
Segment revenue	$68,531	$155,076	$162,397	$(86,545)	$(93,866)
Segment profit	11,288	38,776	45,362	(27,488)	(34,074)
Profit margin	16.5%	25.0%	27.9%

For the year ended March 31, 2010, Piling segment revenues of $68.5 million were down $86.5 million and $93.9 million compared to the years ended March 31, 2009 and 2008, respectively. The decrease in Piling segment revenues reflects significantly reduced activity in the commercial and industrial construction markets due to weak economic conditions as well as a reduction in high-volume oil sands projects.

For the year ended March 31, 2010, Piling profit margin was 16.5% of revenue, compared to 25.0% of revenue and 27.9% of revenue for the years ended March 31, 2009 and 2008, respectively. The reduction in profit margin reflects reduced commercial and industrial construction market activity and increased competition for available work.

Pipeline

	Year ended March 31,			Changes
(dollars in thousands)	2010	2009	2008	2010 vs. 2009	2010 vs. 2008
Segment revenue	$24,920	$101,407	$200,717	$(76,487)	$(175,797)
Segment (loss) profit	(3,851)	22,470	25,465	(26,321)	(29,316)
Profit margin	(15.5)%	22.2%	12.7%

For the year ended March 31, 2010, the Pipeline segment reported revenues of $24.9 million, compared to $101.4 million and $200.7 million in the preceding two years. The significant decline in Pipeline revenue reflects completion of the TMX project in October 2008.

The Pipeline segment recorded a current year loss of $3.9 million, as a result of reduced productivity on a single lump-sum project, primarily resulting from unanticipated weather and ground conditions. Segment profit for the year ended March 31, 2009 was $22.5 million, which included the benefit of a $5.3 million settlement of claims revenue. Excluding this settlement, Pipeline profit margin would have been 16.9% of revenue. Segment profit for the year ended March 31, 2008 was $25.5 million or 12.7% of revenue.

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

Consolidated Three Month Results

	Three months ended, March 31,
(dollars in thousands, except per share information)	2010		% of Revenue	2009		% of Revenue	Change
Revenue	$220,569		100.0%	$174,700		100.0%	$45,869
Project costs	92,401		41.9%	71,522		40.9%	20,879
Equipment costs	61,493		27.9%	48,374		27.7%	13,119
Equipment operating lease expense	22,009		10.0%	13,266		7.6%	8,743
Depreciation	11,493		5.4%	8,596		4.9%	3,347
Gross profit	32,723		14.8%	32,942		18.9%	(219	)
General and administrative costs	19,104		8.7%	16,700		9.6%	2,404
Operating income (loss)	13,127		6.0%	(129,204	)	(74.0)%	142,331
Net loss	$(943	)	(0.4)%	$(137,112	)	(78.5)%	$136,169
Per share information
Net loss – basic	$(0.03	)		$(3.80	)		$3.78
Net loss – diluted	(0.03	)		(3.80	)		3.78
EBITDA (1)	$20,914		9.5%	$(115,792	)	(66.3)%	$136,706
Consolidated EBITDA (1)	$26,428		12.0%	$25,191		14.4%	$1,237

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

	Three Months Ended March 31,
(dollars in thousands)	2010		2009
Net loss	$(943)		$(137,112)
Adjustments:
Interest expense, net	6,355		8,336
Income taxes	3,278		3,936
Depreciation	11,943		8,596
Amortization of intangible assets	281		452
EBITDA	$20,914		$(115,792)
Adjustments:
Unrealized foreign exchange (gain) loss on senior notes	(6,200	)	7,119
Realized and unrealized loss (gain) on derivative financial instruments	11,226		(11,424	)
(Gain) loss on disposal of property, plant and equipment and assets held for sale	189		1,547
Stock-based compensation	277		294
Equity in loss of unconsolidated joint venture	22		–
Impairment of goodwill	–		143,447
Consolidated EBITDA	$26,428		$25,191

Analysis of Three Month Results

Revenue

For the three months ended March 31, 2010, revenue of $220.6 million was $45.9 million higher than in the same period last year. Higher recurring services activity in our Heavy Construction and Mining segment and the completion of a project in our Pipeline segment more than offset lower volumes in our Piling segment. Higher recurring services revenues reflect increased activity with Canadian Natural, Shell Albian and Suncor, partially offset by lower volumes at Syncrude due to increased competition. During the prior year period, recurring service revenues in the Heavy Construction and Mining segment were negatively affected by a temporary slowdown of overburden removal activities during Canadian Natural’s production start-up period.

Gross Profit

Gross profit margin for the three months ended March 31, 2010 decreased to 14.8% of revenue from 18.9% during the same period last year. The loss on one lump-sum Pipeline project and lower margins in both the Piling and Heavy Construction and Mining segments due to increased competitive pressures were the key factors in the decline. Margins recorded last year also reflected the benefits of project close out activities and higher margin site services work.

Operating income (loss)

For the three months ended March 31, 2010, we recorded operating income of $13.1 million, or 6.0% of revenue, compared to an operating loss of $129.2 million, during the same period last year. Last year’s operating loss reflects the non-cash impact of a $143.4 million impairment of goodwill. Excluding this impairment, operating income would have been $14.2 million or 8.1% of revenue for the three months ended March 31, 2009. General and administrative (G&A)

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

expense for the three months ended March 31, 2010 increased by $2.4 million, reflecting a change in value of the employee short-term incentive plan liability in the current year and the year-over-year increase to stock-based compensation expense, resulting from the impact of the increased value in our share price that impacted on the valuation of our deferred director share units and restricted share units.

Net loss

We recorded net loss of $0.9 million (basic and diluted loss per share of $0.03) for the three months ended March 31, 2010, compared to net loss of $137.1 million (basic loss per share of $3.80) during the same period last year. Non-cash items negatively affecting net income included non-cash losses on embedded derivatives in long-term customer contracts, losses on embedded derivatives in long-term supplier contracts and losses on the cross currency. This was partially mitigated by gains on the redemption options on the derivative within the 8 ³/4% senior notes, gain on the interest rate swap and the foreign exchange gain on the 8 ³/4% senior notes which resulted from the appreciation of the Canadian dollar. Excluding these non-cash items in the current and prior period, we would have had an impact of nil (basic income per share of nil) down from net income of $2.2 million (basic and diluted income per share of $0.06).

Segment Three Month Results

Heavy Construction and Mining

	Three months ended March 31,
(dollars in thousands)	2010	2009	Change
Segment revenue	$196,002	$151,952	$44,050
Segment profit	29,286	29,314	(28	)
Profit margin	14.9%	19.3%

For the three months ended March 31, 2010, the Heavy Construction and Mining segment achieved revenues of $196.0 million, a $44.1 million increase from the same period last year. A 32.8% increase in recurring services compared to a year ago, reflects increased volumes with Canadian Natural, Shell Albian and Suncor, partially offset by reduced volumes with Syncrude due to increased competition. Higher overburden removal volumes at Canadian Natural’s Horizon mine in the current period reflect normal production levels, compared to the same period last year when activity was delayed during the commissioning of the Horizon project. Higher volumes with Shell Albian reflect continued strong activity levels under our three year earthmoving and mine support services agreement signed earlier in the year and increased activity with Suncor reflects work performed under our recently renewed 12 month mining services contract with this customer.

Recurring services represented 87.9% of Heavy Construction and Mining’s revenues in the three month period ended March 31, 2010 compared to 85.5% in the same period last year.

Segment margins, for the three months ended March 31, 2010, were 14.9%, compared to 19.3% during the same period last year, reflecting the return to normal segment margins in the current period. Segment margins in the prior year period benefitted from a redeployment of equipment from the overburden project to other sites as well as the processing of change orders related to several large projects completed in the period.

Piling

	Three months ended March 31,
(dollars in thousands)	2010	2009	Change
Segment revenue	$18,263	$22,367	$(4,104)
Segment profit	2,149	6,331	(4,182	)
Profit margin	11.8%	28.3%

The Piling segment achieved revenues of $18.3 million in the three months ended March 31, 2010, a decrease of $4.1 million compared to the same period last year. The change in Piling revenues reflects the lower level of activity in the commercial construction market as well as a reduction in high-volume oil sands projects.

For the three months ended March 31, 2010 segment margins decreased to 11.8%, from 28.3% in the same period last year. The negative effect of the declining commercial construction market, delays in processing change orders and productivity issues on a larger lump-sum job were key contributors to this decline. Profit margins for the prior year period also benefitted from the processing of change orders related to large projects completed in the period.

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

Pipeline

	Three months ended March 31,
(dollars in thousands)	2010		2009	Change
Segment revenue	$6,304		$381	$5,923
Segment (loss) profit	(5,152	)	6	(5,158)
Profit margin	(81.7)%		1.6%

Pipeline revenues for the three months ended March 31, 2010 increased $5.9 million from the same period a year ago, reflecting an increase in project activity.

The segment loss for the three months ended March 31, 2010 reflects the negative impact of unfavourable weather conditions and reduced productivity on a single lump-sum Pipeline project.

Non-Operating Income and Expense

	Three Months Ended March 31,				Year Ended March 31,
(dollars in thousands)	2010		2009		2010		2009		2008
Interest expense
Interest on 8 3/4% senior notes and swaps	$4,573		$7,876		$19,041		$25,379		$23,338
Interest on capital lease obligations	227		347		1,032		1,234		780
Amortization of deferred financing costs	859		780		3,348		2,970		2,899
Interest on credit facilities	990		92		2,375		298		769
Interest on long-term debt	$6,649		$9,095		$25,796		$29,881		$27,786
Other Interest	(294	)	(759	)	284		(269	)	1,294
Total Interest expense	$6,355		$8,336		$26,080		$29,612		$29,080
Foreign exchange (gain) loss	$(5,971	)	$7,651		$(48,901	)	$47,272		$(25,660	)
Realized and unrealized loss (gain) on derivative financial instruments	11,226		(11,424	)	54,411		(37,250	)	30,075
Other income	(818	)	(591	)	(14	)	(5,955	)	(418	)
Income tax expense	3,278		3,936		13,679		14,633		17,116

Interest expense

The cancellation of one leg of the swap agreement on February 2, 2009, one of three swap agreements hedging the interest and currency risk associated with our US dollar denominated 8 ³/4% senior notes, led to an increase in the interest rate swap payment as shown in the “Realized and unrealized loss (gain) on derivative financial instruments” section below. The combination of our interest expense on 8 ³/4% senior notes and the swap interest payment loss reflects the higher cost to us as a result of the counterparty’s cancellation of this US dollar interest rate swap. With the cancellation of this US dollar interest rate swap, by the counterparties, we also became exposed to currency risk and interest rate risk on the coupon payment. A more detailed discussion about our currency and interest rate risk can be found under “Quantitative and Qualitative Disclosures about Market Risk”.

Compared to the corresponding periods in the prior years, interest on our 8 ³/4% senior notes decreased $3.3 million and $6.3 million for the three months and year ended March 31, 2010, respectively. The cancellation of the interest rate swap along with the strengthening of the Canadian dollar in the current year resulted in this decrease. The corresponding increases in swap interest payment loss of $3.5 million and $12.9 million for the three months and year ended March 31, 2010, respectively, reflects the combined impact of the counterparties’ cancellation of this US dollar interest rate swap.

Foreign exchange (gain) loss

The foreign exchange gains recognized in the current year and three month periods relate primarily to changes in the strength of the Canadian dollar against the US dollar on conversion of the US$200 million 8 ³/4% senior notes. A significant increase in the value of the Canadian dollar, from 0.7935 CAN/US at March 31, 2009 to 0.9555 CAN/US at December 31, 2009 and then to 0.9846 CAN/US at March 31, 2010, resulted in significant unrealized foreign exchange gains for both the current three month and annual periods, respectively. The Canadian dollar weakened during the three months and year ended March 31, 2009, resulting in unrealized foreign exchange losses for the respective periods. The Canadian dollar strengthened during the year ended March 31, 2008, resulting in an unrealized foreign exchange gain for the period. A more detailed discussion about our foreign currency risk can be found under “Quantitative and Qualitative Disclosures about Market Risk – Foreign exchange risk”.

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

Realized and unrealized loss (gain) on derivative financial instruments

The realized and unrealized loss (gain) on derivative financial instruments reflect changes in the fair value of derivatives embedded in our US dollar denominated 8  ³/4% senior notes, as well as 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 8 ³/4% senior notes. Realized and unrealized gains and losses also include changes to embedded derivatives in a long-term construction contract and in supplier maintenance agreements. The realized and unrealized losses and (gains) on these derivative financial instruments, for the three and twelve months ended March 31, 2010, are detailed in the table below:

	Three months ended March 31,					Year ended March 31,
(dollars in thousands)	2010	2009		Change		2010		2009		2008		2010 vs. 2009 Change		2010 vs. 2008 Change
Swap liability loss (gain)	$6,344	$(13,303	)	$19,647		$49,078		$(49,613	)	$20,788		$98,691		$28,290
Redemption options embedded derivatives (gain) loss	(118)	1,420		(1,538	)	(3,716	)	3,331		249		(7,047	)	(3,965	)
Supplier contracts embedded derivatives loss (gain)	643	2,010		(1,367	)	(13,315	)	21,509		(1,205	)	(34,824	)	(12,110	)
Customer contract embedded derivative loss (gain)	190	(2,218	)	2,408		6,805		(15,145	)	7,575		21,950		(770	)
Swap interest payment	4,167	667		3,500		15,559		2,668		2,668		12,891		12,891
Total	$11,226	$(11,424	)	$22,650		$54,411		$(37,250	)	$30,075		$91,661		$24,336

The swap liability loss (gain) reflects 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 8 ³/4% senior notes. Changes in the fair value of these swaps generally have an offsetting effect to changes in the value of our 8  ³/4% senior notes (and resulting foreign exchange gains and losses), with both being triggered by variations in the Canadian/US exchange rate. However, the valuations of the derivative financial instruments are also impacted by changes in interest rates and the remaining present value of scheduled interest payments on the swaps, which occur in June and December of each year until maturity.

The redemption options embedded derivatives (gain) loss reflects changes in the fair value of the derivative embedded in our US dollar denominated 8  ³/4% senior notes. Changes in fair value result from changes in long-term bond interest rates during a reporting period.

With respect to the supplier contracts, the embedded derivative related to a long-term maintenance contract was increased due to changes in the underlying base price index in the three months ended March 31, 2010. For the year ended March 31, 2010, the embedded derivative related to the long-term maintenance contract was reduced with the commissioning of certain pieces of heavy equipment. Included in the embedded derivative valuation was the impact of fluctuations in provisions that require a price adjustment to reflect changes in the Canadian/US dollar exchange rate and the United States government published Producers’ Price Index (US-PPI) for Mining Machinery and Equipment from the original contract amount.

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

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

The measurement of swap interest payment loss reflects the realized loss on our swap interest payments. As of February 2, 2009, one of three swap agreements hedging the interest and currency risk associated with our US dollar denominated 8 ³/4% senior notes was cancelled by the counterparties. The counterparties’ cancellation of this US dollar interest rate swap increased swap interest payments and we are now exposed to interest rate and foreign currency risk. For the current year, we paid higher swap interest payments net of swap counterparty receipts.

As discussed in the interest expense discussion of this MD&A, the financial impact of the counterparties’ cancellation of this US dollar interest rate swap is reported in swap interest payment loss. The year-over-year increases in swap interest payment loss of $3.5 million and $12.9 million for the three months and year ended March 31, 2010, respectively, reflect the effect of the counterparties’ cancellation of this US dollar interest rate swap as the semi-annual fixed payments exceed the floating quarterly interest received from our swap counterparties.

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

Income tax expense

For the three months ended March 31, 2010, we recorded current income taxes of $1.9 million and deferred income tax of $1.3 million for a total income tax expense of $3.3 million. This compares to combined income tax expense of $3.9 million for the same period last year. For the three months ended March 31, 2010, income tax expense as a percentage of income before income taxes differs from the statutory rate of 28.91% primarily due to the impact of income tax adjustments and reassessments, non-deductible items and changes in the timing of the reversal of temporary differences. For the three month period ended March 31, 2009, income tax expense as a percentage of income before income taxes differed from the statutory rate of 29.38% primarily due to non-deductible items, including a permanent difference relating to the $143.4 million non-deductible goodwill impairment.

For the year ended March 31, 2010, we recorded current income taxes of $3.8 million and deferred income tax expense of $9.9 million for a total income tax expense of $13.7 million. This compares to combined income tax expense of $14.6 million for the same period last year. For the year ended March 31, 2010, income tax expense as a percentage of income before income taxes differs from the statutory rate of 28.91% primarily due to the impact of income tax adjustments and reassessments, non-deductible items and changes in the timing of the reversal of temporary differences. For the year ended March 31, 2009, income tax expense as a percentage of income before income taxes differed from the statutory rate of 29.38% primarily due to non-deductible items, as well as a permanent difference relating to the $176.2 million non-deductible goodwill impairment. For the year ended March 31, 2008, income tax expense as a percentage of income before income taxes differed from the statutory rate of 31.47% primarily due to the impact of enacted rate changes during the period.

Backlog

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

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

Our measure of backlog does not define what we expect our future workload to be. We work with our customers using cost-plus, time-and-materials, unit-price and lump-sum contracts. This mix of contract types varies year-by-year. Our definition of backlog results in the exclusion of a range of services to be provided under cost-plus and time-and-material contracts performed under master service agreements where scope is not clearly defined. For the three and twelve months ended March 31, 2010, the total amount of revenue earned from time-and-material contracts performed under our master services agreements was approximately $116.5 million and $422.6 million respectively.

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

By Segment

(dollars in thousands)	March 31, 2010	December 31, 2009	March 31, 2009
Heavy Construction and Mining	$725,767	$718,418	$667,674
Piling	16,423	9,091	8,538
Pipeline	6,861	14,763	–
Total	$749,051	$742,272	$676,212
By Contract Type
(dollars in thousands)	March 31, 2010	December 31, 2009	March 31, 2009
Unit-Price	$722,710	$722,663	$672,725
Lump-Sum	18,429	9,102	3,487
Time-and-Material, Cost-Plus	7,912	10,507	–
Total	$749,051	$742,272	$676,212

A contract with a single customer represented approximately $706.7 million of the March 31, 2010 backlog compared to $681.4 million reported as backlog in our Management’s Discussion and Analysis for the three and nine months ended December 31, 2009. The change in the five year backlog for this customer relates to the timing of scheduled volumes through the life of the contract.

We expect that approximately $226.7 million of total backlog will be performed and realized in the 12 months ending March 31, 2011.^*

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

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

Claims and Change Orders

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

_Ÿ changes in client requirements, specifications and design;

_Ÿ changes in materials and work schedules; and

_Ÿ changes in ground and weather conditions.

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

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

For the three months and year ended March 31, 2010, due to the timing of receipt of signed change orders, the Heavy Construction and Mining segment had approximately $0.1 million and $1.2 million respectively in claims revenue recognized to the extent of costs incurred, the Piling segment had $0.3 million and $1.3 million respectively in claims revenue recognized to the extent of costs incurred and the Pipeline segment had $0.4 million and $2.1 million respectively in claims revenue recognized to the extent of costs incurred. We are working with our customers to come to resolution on additional amounts, if any to be paid to us in respect to these additional costs.

Summary of Consolidated Quarterly Results

	Fiscal 2010					Fiscal 2009
(dollars in millions, except per share amounts)	Q4		Q3	Q2	Q1	Q4		Q3		Q2	Q1
Revenue	$220.6		$221.2	$170.7	$146.5	$174.7		$258.6		$280.3	$259.0
Gross profit	32.7		47.6	33.8	25.1	32.9		51.4		44.7	41.3
Operating income (loss)	13.1		31.3	18.9	10.1	(129.2	)	(1.9	)	23.4	20.6
Net income (loss)	(0.9	)	14.9	4.3	9.9	(137.1	)	(15.0	)	2.9	13.8
Net income (loss) per share – Basic(1)	$(0.03	)	$0.41	$0.12	$0.28	$(3.80	)	$(0.42	)	$0.08	$0.38
Net income (loss) per share – Diluted(1)	(0.03	)	0.41	0.12	0.27	(3.80	)	(0.42	)	0.08	0.37

⁽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.

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

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

The timing of large projects can influence quarterly revenues. For example, Pipeline segment revenues were as high as $55.6 million in the three month period ended September 30, 2008, as low as $0.1 million in the three months ended June 30, 2009 and are currently at $6.3 million for the three month period ended March 31, 2010. The Heavy Construction and Mining segment experienced reduced volumes in the three month periods ending December 31, 2008 and March 31, 2009 as a result of the temporary shut-down of overburden removal at the Horizon project while Canadian Natural prepared for operations start-up. Subsequent three month periods reflected the ramp up of overburden removal activities at the Horizon project through to the current three month period where activity has returned to planned

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

activity levels. Changes in demand under our master service agreements with Shell Albian and Syncrude had a positive effect on our revenues for the three month periods ended June 30, 2008, September 30, 2008 and December 31, 2008 respectively. Changes in demand from Syncrude had a negative effect on our revenues for the three month periods subsequent to December 31, 2008, while master service agreement demand from Shell Albian continues to positively affect period-over-period comparatives.

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

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

We have also experienced net income variability in all periods due to the recognition of unrealized non-cash gains and losses on both derivative financial instruments and our 8 ³/4% senior notes, primarily driven by changes in the Canadian/ US dollar exchange rates.

Summary of Consolidated Financial Position

	Year ended March 31,
(dollars in thousands)	2010		2009		2008		2010 vs 2009 Change		2010 vs 2008 Change
Cash	$103,005		$98,880		31,863		4,125		71,142
Current assets (excluding cash)	212,607		157,858		260,606		54,749		(47,999	)
Current liabilities	(165,641	)	(127,957	)	(177,650	)	(37,684	)	12,009
Net working capital	149,971		128,781		114,819		21,190		35,152
Property, plant and equipment	328,743		316,115		276,319		12,628		52,424
Total assets	702,617		629,275		802,336		72,342		(99,719	)
Capital lease obligations (including current portion)	(13,393	)	(17,484	)	(14,776	)	4,091		1,383
Total long-term financial liabilities(1)	(327,356	)	(318,559	)	(314,751	)	(8,797	)	(12,605	)

⁽¹⁾ Total long-term financial liabilities exclude the current portions of capital lease obligations, current portions of derivative financial instruments, long-term lease inducements, asset retirement obligation and both current and non-current future income tax balances.

At March 31, 2010, net working capital (current assets less current liabilities) was $150.0 million compared to $128.8 million at March 31, 2009 and $114.8 million at March 31, 2008. This was an increase of $21.2 million and an increase of $35.2 million over March 31, 2009 and 2008, respectively.

Current assets excluding cash increased $54.7 million between March 31, 2009 and March 31, 2010. A $33.6 million increase in trade receivables and holdbacks along with a $28.8 million increase in unbilled revenue during the year ended March 31, 2010 was partially offset by a $6.2 million reduction of inventory from consumption of tires, previously stockpiled for new leased haul trucks (haul trucks do not arrive with tires included). The prior year trade receivables, holdbacks and unbilled revenue balances benefitted from the completion and settlement of projects at Suncor’s Fort Hills and Kinder Morgan’s TMX. Current assets excluding cash decreased $48.0 million between March 31, 2008 and March 31, 2010. A $55.1 million decrease in trade receivables and holdbacks along with a $3.7 million decrease in other assets, and a $2.4 million decrease in prepaid expenses and deposits during the year ended March 31, 2010 was partially offset by a $13.8 million increase in unbilled revenue and a $4.2 million increase in inventory.

Current liabilities during the year ended March 31, 2010 increased by $37.7 million, reflecting a $10.7 million increase in accounts payable, a $10.6 million increase in current portion of derivative financial instruments, a $6.1 million increase in current portion of long term debt, a $2.2 million increase in accrued liabilities and a $9.0 million increase in deferred tax liabilities. Equipment purchases of $6.3 million, which are scheduled to be paid after March 31, 2010, are included in accounts payable as of March 31, 2010. Current liabilities during the year ended March 31, 2010 were comparable to March 31, 2008, reflecting a $46.3 million decrease in accounts payable offset by $7.8 million increase in accrued liabilities and $6.1 million increase in current portion of long term debt, resulting from new term loans under our amended and restated credit agreement and $17.3 million re-class of the swap liability from long-term to current portion, due to the settlement of the swap liability on April 8, 2010. For a more detailed discussion of the swap liability settlement please refer to “Interest rate risk” in Quantitative and Qualitative disclosures about Market Risk.

North American Energy Partners Inc.  Management’s Discussion and Analysis  23

Property, plant and equipment increased by $12.6 million between March 31, 2009 and March 31, 2010. This reflects the capital investment of $56.7 million of equipment purchases and new capital leases during the year ended March 31, 2010, offset by equipment disposals of $2.7 million (net book value) and depreciation of $42.6 million. Property, plant and equipment increased by $52.4 million between March 31, 2008 and March 31, 2010.

Total long-term financial liabilities increased by $8.8 million between March 31, 2009 and March 31, 2010, due to a $32.0 million increase related to the cross-currency and interest rate swap agreements, an increase of $22.4 million in the long-term portion of our term loan resulting from new term loans under our amended and restated credit agreement, an increase in the long-term contingent rent liability on our operating leases and an increase of $5.4 million in the value of the long-term portion of the embedded derivatives in a long-term revenue construction contract. This was partially offset by a $52.6 million decrease in the carrying amount of our 8  ³/4% senior notes, a $5.6 million decrease related to the long-term portion of the embedded derivatives in long-term supplier contracts and a $3.7 million decrease in the non-current portion of our capital lease obligations. Total long-term financial liabilities increased by $12.6 million between March 31, 2008 and March 31, 2010, due to a $9.2 million increase in long-term accrued liabilities related to the contingent rent on operating leases, a $3.4 million increase in liabilities related to stock based compensation, an increase of $22.4 million in the long-term portion of our term loan resulting from new term loans under our amended and restated credit agreement. The increases were partially offset by a $17.3 re-class of swap liability to short term as stated above, a $2.7 million decrease in the carrying amount of senior notes related to the decrease in the exchange rate and a $1.7 million decrease in the non-current portion of our capital lease obligations.

Summary of Consolidated Cash Flows

	Three months ended March 31,						Year ended March 31,
(dollars in thousands)	2010		2009		Change		2010		2009	2008	2010 vs. 2009 Change		2010 vs. 2008 Change
Cash provided by operating activities	$16,477		$71,989		$(55,512	)	$42,869		$151,185	$94,797	$(108,316	)	$(51,928	)
Cash used in investing activities	(5,312	)	(11,276)		5,964		(59,611	)	(78,715)	(45,932)	19,104		(13,679	)
Cash (used in) provided by financing activities	(3,037	)	(1,436	)	(1,601	)	20,867		(5,453)	(23,992)	26,320		44,859
Increase in cash and cash equivalents	$8,128		$59,277		$(51,149)		$4,125		$67,017	$24,873	$(62,892	)	$(20,748	)

Operating activities

Cash provided by operating activities for the three months ended March 31, 2010 was an inflow of $16.5 million, compared to a cash inflow of $72.0 million for the three months ended March 31, 2009. The lower cash provided by operating activities in the current period is primarily a result of lower gross profit, higher effective interest costs and increased non-cash net working capital.

Cash provided by operating activities for the year ended March 31, 2010 was an inflow of $42.9 million, compared to cash inflows of $151.2 million and $94.8 million for the years ended March 31, 2009 and 2008 respectively. The lower cash provided by operating activities in the current period is primarily a result of lower gross profit, higher effective interest costs and increased non-cash net working capital. The cash inflow for the year ended March 31, 2009 benefitted from significant project closeout activities in the period.

Investing activities

Cash used in net investing activities for the three months ended March 31, 2010 was an outflow of $5.3 million compared with an outflow of $11.3 million for the same period a year ago. Investing activities this current period included capital and intangible asset expenditures of $7.3 million. Proceeds from asset dispositions of $0.5 million and a net inflow from non-cash working capital of $2.2 million lessened the effect of capital purchases. Cash used in investing activities last year included a net outflow from non-cash working capital of $3.8 million and capital and intangible asset expenditures of $9.2 million, offset by an inflow of proceeds from asset dispositions of $3.5 million.

Cash used in net investing activities for the year ended March 31, 2010 was an outflow of $59.6 million compared with outflows of $78.7 million and $45.9 million for the years ended March 31, 2009 and 2008, respectively. Current period investing activities included capital and intangible expenditures of $55.4 million along with $5.4 million for the acquisition of DF Investments Limited. A cash inflow of proceeds from asset dispositions of $3.9 million and a net inflow from non-cash working capital of $1.8 million lessened the effect of cash outflows for capital purchases and the acquisition. Cash used in investing activities last year included capital and intangible expenditures of $87.5 million, partially offset by proceeds from asset dispositions of $11.5 million and a net inflow from non-cash working capital of $0.6 million. Cash used in investing activities for the year ended March 31, 2008 included capital and intangible expenditures of $55.1 million along with $1.6 million for the acquisition of Active Auger Services 2001 Ltd., partially offset by proceeds from asset dispositions of $17.1 million.

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

Financing activities

Cash used in financing activities during the three month period ended March 31, 2010 resulted in a cash outflow of $3.0 million as a result of a scheduled $1.5 million repayment on our term credit facility and a $1.4 million repayment of capital lease obligations. Cash used in financing activities for the three month period ended March 31, 2009 of $1.4 million was a result of the scheduled repayment of capital lease obligations.

Cash provided by financing activities during the year ended March 31, 2010 resulted in a cash inflow of $20.9 million. Capital expenditure financing of $28.4 million, through our new term credit facility (net of term credit facility repayments), was partially offset by the $5.6 million repayment of capital lease obligations, $1.1 million in financing costs for our amended and restated credit agreement and the repayment of debt assumed with the acquisition of DF Investments Limited. Cash used in financing activities for the year ended March 31, 2009 of $5.5 million was a result of the $6.2 million repayment of capital lease obligations partially offset by the cash settlement of stock options. Cash used in financing activities for the year ended March 31, 2008 of $24.0 million included a $20.5 million repayment to the revolving credit facility and the $3.8 million repayment of capital leases. The $1.6 million proceeds from exercised stock options was partially offset by the expenditure of $0.8 million for financing costs and $0.6 million for cash settlement of stock options.

D. Outlook

While our expectations for the 2011 fiscal year remain cautious, recent market and industry activity suggest we are now past the worst of the economic downturn and we expect to see demand for our services gradually strengthen as the year progresses.*

In the oil sands, we expect that project development opportunities will continue to expand with Exxon’s Kearl, ConocoPhillips’s Surmont and Suncor’s Firebag projects moving forward. We have been successful in securing piling and heavy construction-related projects on Exxon’s Kearl project and we intend to continue pursuing opportunities on this and other projects. ^*

In our recurring services business, we anticipate some short-term demand variability in early fiscal 2011 as Shell Albian completes a major maintenance program and Suncor repairs damage caused by a recent fire at its plant. Demand for recurring services at these sites is expected to recover during the second quarter of fiscal 2011 and remain stable through the balance of the year. Overburden removal activity at Canadian Natural’s Horizon is expected to remain at normal levels during the year and we expect to provide steady support to Syncrude after recently renewing our site services agreement with this customer.^*

We also see opportunities to continue building our oil sands business with new tailings pond management and reclamation services. The oil sands industry is currently responding to environmental concerns and more stringent requirements relating to the remediation of tailings ponds under the recently released Directive 74. In calendar 2010, the Alberta Energy Resources Conservation Board (ERCB) will review proposals from all of the oil sands producers to modify existing tailings disposal systems to meet the new requirements. Once these plans are approved, the producers will have to implement these new systems, which will involve anything from new and/or smaller ponds to drying lay down areas. We believe these and the associated infrastructure will generate opportunities for us to provide an expanded range of services in support of these initiatives. Given the aggressive timelines set out for producers to achieve regulatory compliance and the amount of tailings material that will need to be addressed, we believe this has the potential to become a significant revenue growth opportunity over time.^*

In the Pipeline division, we have recently been awarded two new contracts that we expect to complete during fiscal 2011. These include the second phase of Spectra Energy’s Maxhamish Loop project, which involves construction of a 30 km, 24 inch pipeline in British Columbia. We were awarded this follow-on contract after completing the first phase safely and on schedule, despite adverse operating conditions. We were able to adjust the forecast production rates to reduce risk because the customer recognized and understood the conditions we met in the first stage. We have also been awarded the contract for TransCanada Pipelines’ NPS Groundbirch Mainline project. This project involves construction of a 77 km, 36 inch pipeline, also in British Columbia. Overall, the Pipeline construction market remains highly competitive with an oversupply of contractor capacity in the marketplace. As a result, contracts continue to be negotiated with higher-than-normal contractor risk exposure and low margins. We believe we have mitigated our risk exposure in our new contracts and we expect a return to profitability in the Pipeline segment in fiscal 2011.^*

In our Piling division, we expect to see a gradual increase in opportunities as fiscal 2011 progresses. Demand has now begun to improve in the commercial and public construction market with the result that we have already secured significant work for the coming year. We expect this improvement to continue as the year progresses.^*

Overall, the markets we serve are experiencing gradually improving economic conditions and we expect this to be the trend in Canada, led by Alberta, for several years to come.^*

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

North American Energy Partners Inc.  Management’s Discussion and Analysis  25

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:

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

_Ÿ building and similar codes and zoning ordinances;

_Ÿ laws and regulations relating to consumer protection; and

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

We believe that 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, Ontario Ministry of the 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 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, 2008, 2009 and 2010 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 or may not be material.

Employees and Labour Relations

As of March 31, 2010, the Company employed 412 salaried employees and over 1,815 hourly employees. Our hourly workforce fluctuates according to the seasonality of our business and the staging and timing of projects by our customers. The hourly workforce typically ranges in size from 1,000 employees to approximately 2,500 employees depending on the time of year and duration of awarded projects. We also utilize the services of subcontractors in our construction business. An estimated 8% to 10% of the construction work we do is performed by subcontractors. Approximately 1,693 employees are members of various unions and work under collective bargaining agreements. The majority of our work is done by employees governed by our mining overburden collective bargaining agreement (“Collective Agreement”) with the International Union of Operating Engineers Local 955. The Collective Agreement expired on October 31, 2009 and the Company has been involved in negotiations for the renewal of the Collective Agreement since that time. The parties reached a tentative agreement on May 27, 2010 and it is expected that it will be ratified by the union’s membership by the end of June, 2010. Other collective agreements in operation include the provincial Industrial, Commercial and Institutional (ICI) agreements in Alberta and Ontario with both the Operating Engineers and Labourers Unions, Piling sector collective agreements in Saskatchewan with the Operating Engineers and Labourers, Pipeline sector agreements in both British Columbia and Alberta with the Christian Labour Association of Canada (CLAC) as well as an all-sector agreement with CLAC in Ontario. We are subject to other industry and specialty collective agreements under which we complete work and the primary terms of all of these agreements are

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

currently in effect. We believe that our relationships with all our employees, both union and non-union, are strong. We have not experienced a strike or lockout.*

F. Resources and Systems

Outstanding Share Data

We are authorized to issue an unlimited number of voting Common Shares and an unlimited number of Non-Voting Common Shares. As at June 8, 2010, there were 36,062,036 voting Common Shares outstanding (36,049,276 as at March 31, 2010). We had no Non-Voting Common Shares outstanding on any of the foregoing dates.

Liquidity and Capital Resources

Liquidity requirements

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

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

We require between $30 million and $40 million annually for sustaining capital expenditures and our total capital requirements typically range from $75 million to $150 million depending on our growth capital requirements. With the potential future customer demand for larger-sized heavy equipment in the oil sands, we expect our capital needs in the next fiscal year to be approximately $50 to $75 million. We may, however increase our capital spend to approximately $100 million to take advantage of available equipment as a result of the recent declaration of bankruptcy by one of our competitors.^*

We typically finance approximately 30% to 50% of our total capital requirements through our operating lease facilities and the remainder from cash flow from operations. We believe our operating and capital lease facilities and cash flow from operations will be sufficient to meet these requirements. Our equipment fleet value is currently split among owned (43%), leased (49%) and rented equipment (8%). Approximately 38% of our leased fleet is specific to one long-term overburden removal project. This equipment mix is a change from the mix reported in previous periods as a result of our declining need for the same levels of rental equipment along with the conversion of some rental equipment to operating leases to meet specific volume demands. Our equipment ownership strategy allows us to meet our customers’ variable service requirements while balancing the need to maximize equipment utilization with the need to achieve the lowest ownership costs. We are continually evaluating our capital needs and continue to monitor equipment lead times with suppliers to ensure that we control our capital spending while still being in a position to respond to opportunities when they materialize.^*

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

Long-term Debt

Our long-term debt, as at March 31, 2010, included US$200.0 million of 8 ³/4% senior unsecured notes due in December 2011 (the “8 ³/4% senior notes”). Prior to February 2, 2009, the foreign currency risk relating to both the principal and interest portions of these 8 ³/4% senior notes was 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 agreements were an economic hedge but had not been designated as hedges for accounting purposes. Prior to the cancellation of the US dollar interest rate swap, interest totaling $13.0 million on the 8 ³/4% senior notes and the swap was payable semi-annually in June and December of each year until the notes would mature on December 1, 2011. The US$200.0 million principal amount was fixed at C$1.315=US$1.000, resulting in a principal repayment of $263.0 million due on December 1, 2011. There were no principal repayments required on the 8 ³/4% senior notes until maturity. Effective February 2, 2009, the US dollar interest rate swap was terminated by the counterparties and our effective interest expense increased by approximately US$6.8 million per annum (based on the then current US dollar LIBOR rates) for the remaining life of the 8 ³/4% senior notes. This increase was net of US dollar floating interest payments on the cross-currency swap agreement we received every March 1, June 1, September 1 and December 1, effective March 1, 2009 until the notes were to mature on December 1, 2011. The value of the quarterly floating rate US dollar payments we received was the prevailing 3-month US dollar LIBOR rate plus a spread of 4.2% on the notional amount of US$200.0 million. Our Canadian dollar interest rate swap and cross-currency swap agreements are not cancellable at the option of

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

North American Energy Partners Inc.  Management’s Discussion and Analysis  27

the counterparties. A more detailed discussion of this cancellation can be found below in the “Foreign exchange risk” and “Interest rate risk” sections of “Quantitative and Qualitative Disclosures about Market Risk”.

In April 2010, we issued C$225.0 million of Series 1 Debentures and entered into an amended and restated credit agreement that extended the maturity of our credit facilities to April 2013 and provided a new $50.0 million term loan. The net proceeds of the Series 1 Debentures, combined with the new $50.0 million term loan and cash on hand were used to redeem all outstanding 8 ³/4% senior notes and terminate the associated swap agreements in April. The full details of this subsequent event are as follows:

9.125% Series 1 Debentures

In April 2010, we closed a private placement of 9.125% Series 1 Debentures due 2017 (the “Series 1 Debentures”) for gross proceeds of $225.0 million and net proceeds after commissions and related expenses of approximately $218.3 million.

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

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

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

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

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

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

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

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

8  ³/4% Senior Notes Redemption

Beginning December 1, 2009, our 8 ³/4% senior notes were redeemable at 100% of the principal amount. On March 29, 2010, we issued a redemption notice to holders of the notes to redeem all outstanding 8 ³/4% senior notes and, on April 28, 2010, the notes were redeemed and cancelled. The redemption amount included the US$200.0 million principal outstanding and US$7.1 million of accrued interest. The redemption and associated swap agreement terminations eliminates refinancing risk in December 2011 and significantly reduces our effective annual interest costs.

In connection with the redemption of our 8 ³/4% senior notes, we wrote off deferred financing costs of $4.5 million. The write off of these deferred financing costs will be recorded in our Interim Consolidated Statements of Operations and Comprehensive Income for the three months ended June 30, 2010.

Termination of Cross-Currency and Interest Rate Swaps

On April 8, 2010, we terminated the cross-currency and interest rate swaps associated with the 8 ³/4% senior notes. The payment to the counterparties required to terminate the swaps was approximately $92.5 million and represented the fair value of the swap agreements, including accrued interest.

New Term Facility

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

Letters of credit

One of our major contracts allows the customer to require that we provide up to $50.0 million in letters of credit. As at March 31, 2010, we had $10.0 million in letters of credit outstanding in connection with this contract (we had $10.4 million in letters of credit outstanding in total for all customers as of March 31, 2010). Any change in the amount of the

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

letters of credit required by this customer must be requested by November 1st in each year for an issue date of January 1st following the date of such request, for the remaining life of the contract. In the event that we require additional letters of credit for either this major contract or other contracts, we have included an option in our June 24, 2009 amended and restated credit agreement to request an increase to the revolving portion of the credit facility, on a one-time basis, by an amount up to the lesser of $25.0 million or the requested increase to the letters of credit for this customer.

Sources of liquidity

Our principal sources of cash are funds from operations and borrowings under our credit facility. As at March 31, 2010, we had approximately $79.6 million of available borrowings under our Revolving Facility (as defined herein) provided for in our amended and restated credit agreement, after taking into account $10.4 million of outstanding and undrawn letters of credit to support performance guarantees associated with customer contracts. On December 1, 2009, we were notified by a major customer that it had reduced its letter of credit requirements from $20.0 million to $10.0 million, which became effective January 6, 2010.

As at March 31, 2010, we had $7.4 million in trade receivables that were more than 30 days past due compared to $16.0 million as at March 31, 2009. We have currently provided an allowance for doubtful accounts related to our trade receivables of $1.7 million ($2.6 million at March 31, 2009). We continue to monitor the credit worthiness of our customers. To date our exposure to potential write-downs in trade receivables has been limited to the financial condition of developers of condominiums and high-rise developments in our Piling segment.

Working capital fluctuations effect on cash

The seasonality of our business results in higher accounts receivable balances between December and early February during peak activity levels, which may result in an increase in our working capital requirements. Our working capital is also significantly affected by the timing of the completion of projects. In some cases, our customers are permitted to withhold payment of a percentage of the amount owing to us for a stipulated period of time (such percentage and time period is usually defined by the contract and in some cases provincial legislation). This amount acts as a form of security for our customers and is referred to as a “holdback”. Typically, we are only entitled to collect payment on holdbacks once substantial completion of the contract is performed, there are no outstanding claims by subcontractors or others related to work performed by us and we have met the time period specified by the contract (usually 45 days after completion of the work). However, in some cases, we are able to negotiate the progressive release of holdbacks as the job reaches various stages of completion. As at March 31, 2010, holdbacks totaled $3.9 million, down from $9.4 million as at March 31, 2009. Holdbacks represent 3.5% of our total accounts receivable as at March 31, 2010 (12.0% as at March 31, 2009). This decrease is attributable to the reduction of revenue in our Piling segment for the three months ended March 31, 2010 and March 31, 2009 compared to the same periods in the prior year. As at March 31, 2010, we carried $1.1 million in holdbacks for three large customers.^*

Cash requirements

As at March 31, 2010, our cash balance of $103.0 million was $4.1 million higher than our cash balance at March 31, 2009. The change in cash balance reflects the timing of capital expenditures and the timing of processing change orders and payment certificates. Offsetting these outflows of cash was the cash inflow of $28.4 million, net of term facility repayments, secured through our amended and restated credit facility. In the event that we require additional funding, we believe that any such funding requirements would be satisfied by the funds available from our credit facility described immediately below.

Credit facility

We entered into an amended and restated credit agreement on June 24, 2009 with a syndicate of lenders that provided us with a credit facility, under which revolving loans, term loans and letters of credit may be issued. The facility will mature on June 8, 2011. The total credit facility remained unchanged at $125.0 million and included a $75.0 million Revolving Facility (the “Revolving Facility”) and a $50.0 million Term Facility (the “Term Facility”). The Term Facility commitments were available until August 31, 2009 and aggregate borrowings under this facility had to exceed $25.0 million. Any undrawn amount under the Term Facility, up to a maximum of $15.0 million, could be reallocated to the Revolving Facility. On August 31, 2009, the maximum undrawn portion of the Term Facility totaling $15.0 million was reallocated to the Revolving Facility resulting in Revolving Facility commitments of $90.0 million. The Term Facility includes scheduled mandatory principal payments while the funds available under the Revolving Facility are reduced by any outstanding letters of credit.

As of March 31, 2010, the total credit facility included the $90.0 million Revolving Facility and the outstanding borrowings of $28.4 million (March 31, 2009 — $nil) under the non-revolving Term Facility, after the mandatory principal payments of $1.5 million in the quarter. As of March 31, 2010, we had issued $10.4 million (March 31, 2009 — $20.8 million) in letters of credit under the Revolving Facility to support performance guarantees associated with customer contracts. Our unused borrowing availability under the credit facility was $79.6 million at March 31, 2010.

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

North American Energy Partners Inc.  Management’s Discussion and Analysis  29

Advances under the Revolving Facility may be repaid from time to time at our option. Beginning September 30, 2009, and at the end of each fiscal quarter thereafter, we must make quarterly repayments on the Term Facility of $1.5 million through June 2011, with the balance due at that time. The credit facility, based on the type of borrowing, bears interest at the Canadian prime rate, the US dollar base rate, the Canadian bankers’ acceptance rate or the London interbank offered rate (US dollar LIBOR) (all such terms as used or defined in the credit facility) plus applicable margins. In each case, the applicable pricing margin depends on our current debt rating. For a discussion on our current debt rating refer to the “Debt Ratings” section of this Management’s Discussion and Analysis.

During the year ended March 31, 2010, financing fees of $1.1 million were incurred in connection with the modifications to the amended and restated credit agreement dated June 24, 2009. These fees were recorded as deferred financing costs and are amortized using the effective interest method over the remaining term of the agreement.

Included in the amended and restated credit agreement is an option to request an increase to the total revolving credit facility commitments if our requirements for providing letters of credit to our customers exceed $21.0 million. In that event we are permitted to request, on a one-time basis, an increase to the overall revolving credit facility by an amount up to the lesser of $25.0 million or the requested increase to the letters of credit by our customers.

Under the credit agreement, we are required to satisfy certain financial covenants, including an amended minimum interest coverage ratio. The interest coverage covenant is determined based on a ratio of Consolidated EBITDA (as defined within the credit agreement) to consolidated cash interest expense. Measured as of the last day of each fiscal quarter, on a trailing four-quarter basis, the interest coverage ratio shall not be less than 2.0 times at any time up to June 29, 2010 and shall not be less than 2.5 times any time thereafter.

Covenants remaining unchanged in the credit agreement include:

_Ÿ The senior leverage covenant, which is determined based on a ratio of senior debt to Consolidated EBITDA (as defined within the credit agreement). Measured as of the last day of each fiscal quarter on a trailing four-quarter basis, the senior leverage ratio shall not exceed 2.0 times.

_Ÿ The current ratio covenant is determined based on the ratio of current assets to current liabilities (as defined within the credit agreement). Measured as of the last day of each fiscal quarter, the current ratio shall not be less than 1.25 times.

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

The credit facility may be prepaid in whole or in part without penalty, except for bankers’ acceptances, which are not pre-payable prior to their maturity. However, the credit facility requires prepayments under various circumstances, such as with: (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.

Credit Agreement Renewal – April 2010

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

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

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

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

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

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

Capital resources

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

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

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

	Three months ended March 31,					Year ended March 31,
(dollars in thousands)	2010	2009		Change		2010	2009	2008	2010 vs. 2009 Change		2010 vs. 2008 Change
Capital Expenditures
Sustaining	$4,823	$2,803		$2,020		$13,644	$13,467	$18,560	$177		$(4,916	)
Growth	2,489	6,325		(3,836	)	44,861	74,072	36,519	(29,211	)	8,342
Total	$7,312	$9,128		$(1,816	)	$58,505	$87,539	$55,079	$(29,034	)	$3,426
Capital Leases
Sustaining	$418	$–		$418		$867	$3,056	$7,727	$(2,189	)	$(6,860	)
Growth	–	(4,244	)	4,244		656	5,807	1,102	(5,151	)	(446	)
Total	$418	$(4,244	)	$4,662		$1,523	$8,863	$8,829	$(7,340	)	$(7,306	)
Total Sustaining Capital Additions	$5,241	$2,803		$2,438		$14,511	$16,523	$26,287	$(2,012	)	$(11,776	)
Total Growth Capital Additions	$2,489	$2,081		$408		$45,517	$79,879	$37,621	$(34,362	)	$7,896
Operating Leases	$30,501	$42,204		$(11,703	)	$105,771	$127,410	$88,733	$(21,639	)	$17,038

The increase in sustaining capital additions for the three months ended March 31, 2010, compared to the same period in the previous year, is a result of the purchase of replacement maintenance equipment. The impact of the increase was mitigated by fewer equipment purchases due to lower activity volumes.

The reduction in growth capital expenditures for the three months and year ended March 31, 2010, compared to the same period in the prior year, reflects the impact of fewer development projects as a result of the current economic slowdown.

The decrease in operating leases, for both the three and twelve months ended March 31, 2010, compared to the same periods in the previous year, reflects the timing of scheduled equipment additions related to the Canadian Natural overburden project along with the impact of fewer development projects as a result of the current economic slowdown.

Capital Commitments

Contractual obligations and other commitments

Our principal contractual obligations relate to our long-term debt, capital and operating leases and supplier contracts.

North American Energy Partners Inc.  Management’s Discussion and Analysis  31

The following table summarizes our future contractual obligations, excluding interest payments, unless otherwise noted, as of March 31, 2010.

	Payments due by fiscal year
(dollars in thousands)	Total	2011	2012	2013	2014	2015 and after
Senior notes(1)	$203,120	$203,120	$–	$–	$–	$–
Term Facility	31,242	7,637	23,605	–	–	–
Capital leases (including interest)	14,561	5,734	5,209	2,987	462	169
Operating leases	195,667	62,862	52,999	37,899	25,942	15,965
Supplier contracts	54,185	11,467	13,616	13,616	13,226	2,260
Total contractual obligations	$498,775	$290,820	$95,429	$54,502	$39,630	$18,394

⁽¹⁾ We previously entered into cross-currency and interest rate swaps, which represented an economic hedge of the 8 ³/4% senior notes. At maturity, we were required to pay $263.0 million in order to retire these senior notes and the swaps. This amount reflected the fixed exchange rate of C$1.315=US$1.00 established as of November 26, 2003, the inception date of the swap contracts (see “Interest rate risk” in Quantitative and Qualitative Disclosures about Market Risk regarding the cancellation of the US dollar interest rate swap effective February 2, 2009). We decided to exercise our early redemption option rights on senior notes, and as such, the senior notes were redeemed on April 28, 2010 using the proceeds from the 9.125% Series 1 Debenture issue and the amended term loan facility as stated in the “Liquidity and Capital Resources” section. At March 31, 2010, the carrying value of the derivative financial instruments related to 8 ³/4% senior notes was $89.0 million, inclusive of the interest components.

Off-balance sheet arrangements

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

Debt Ratings

Moody’s Investor Services, Inc. (“Moody’s”) and Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc. (“S&P”) affirmed our corporate credit ratings and the ratings on our 8 ³/4% senior notes in March 2010 and April 2010, respectively. S&P increased our Outlook from ‘negative’ to ‘stable’. Both agencies also provided a rating for our new 9.125% Series 1 Senior Unsecured Debentures issued on April 7, 2010.

Our corporate credit ratings from these two agencies are as follows:

Category	Standard & Poor’s	Moody’s
Corporate Rating	B+ (‘stable’ outlook)	B2 (‘stable’ outlook)
8  3/4% Senior Notes	B+ (recovery rating of “4”)	B3 (LGD(1) rating of “5”)
9.125% Series 1 Debentures	B+ (recovery rating of “3”)	B3 (LGD(1) rating of “5”)

⁽¹⁾ Loss Given Default

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

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

Standard & Poor’s

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

A recovery rating of “4” for the 8 ³/4% Senior Notes indicates an expectation for an average of 30% to 50% recovery in the event of a payment default. A recovery rating of “3” for the 9.125% Series 1 Debentures indicates an expectation for an average of 50% to 70% recovery in the event of a payment default.

A Standard & Poor’s rating outlook assesses the potential direction of a long-term credit rating over the intermediate term (typically nine months to two years). In determining a rating outlook, consideration is given to any changes in the

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

economic and/or fundamental business conditions. An outlook is not necessarily a precursor of a rating change or future CreditWatch action. A Stable outlook means that a rating is not likely to change.

Moody’s

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

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

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

Related Parties

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

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

Additionally, we entered into a shared service agreement with our joint venture, Noramac Ventures Inc. There have been no transactions under this agreement during the year ended March 31, 2010.

There were no material related party transactions during the years ended March 31, 2010, 2009 and 2008. All related party transactions were in the normal course of operations and were measured at the exchange amount, being the consideration established and agreed to by the related parties.

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).

The proper identification of costs is a critical part of our ability to recognize revenues and provide accurate management information for decision making. We continue to focus resources to address this in our ERP system through the automation of transactional activities. We continue to work on improving the process for tracking and reporting equipment and maintenance costs. We have seen some improvements in the identification and tracking of our procurement costs.

During the fiscal year ended March 31, 2010, we started the implementation of specific JDE modules based on the user-needs analysis and ERP system functionality assessment we completed in the prior year. As part of this analysis, we determined if we could implement additional modules in JDE or whether we needed to commence a review of industry-specific software to supplement our existing ERP functionality. Based on this analysis, we decided to implement project management software that would complement the functionality of JDE. We are in the process of proving if this software can be fully integrated into our ERP system.

During each of the interim periods ended June 30, 2009, September 30, 2009 and December 31, 2009, we identified an additional material weakness in ICFR, which is described below.

We did not maintain effective processes and controls specific to our reliance on the accuracy of data provided from third-party valuations specialists that is used to prepare our consolidated financial statements. Specifically, we did not maintain effective controls to validate the accuracy of a third-party valuation of our cross-currency and interest rate swaps related to our 8¾% senior notes. The accounts that could be affected by this deficiency are current portion of derivative financial instruments liabilities on the balance sheet and realized and unrealized loss (gain) on derivative financial instruments on the

North American Energy Partners Inc.  Management’s Discussion and Analysis  33

consolidated statements of operations and comprehensive income (loss). This material weakness in ICFR, which is isolated in nature, resulted in material errors in our interim financial statements prepared under Canadian GAAP as at and for the interim periods ended June 30, 2009, September 30, 2009 and December 31, 2009 that were not corrected prior to the original release of these financial statements. These material errors have been corrected in the United States and Canadian accounting policies differences note in the restated interim financial statements released on June 10, 2010. The errors arising from this material weakness in internal controls were detected and corrected as at March 31, 2010 through detective controls applied to the settlement of the cross-currency and interest rate swaps related to our 8¾% senior notes in April 2010. The Company has no further material reliance on data provided by third-party valuations specialists.

As discussed in the section Adjustments related to prior year financial statements, the financial statements for fiscal 2008 and fiscal 2009 have been amended under Canadian GAAP to correct an error related to the method of accounting for an incentive at the time of buying a previously leased asset, which was identified during the preparation of our fiscal 2010 consolidated financial statements. This error arose as a result of the previously disclosed material weakness in ICFR related to the lack of sufficient accounting and finance personnel with an appropriate level of technical accounting knowledge and training commensurate with the complexity of our financial accounting and reporting requirements. We rectified this material weakness in fiscal 2009 by reorganizing the corporate accounting group and recruiting new staff with the appropriate experience and technical skills to prevent a reoccurrence of these issues.

Evaluation of disclosure controls and procedures

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

As of March 31, 2010, an evaluation was carried out under the supervision of and with the participation of management, including the President and Chief Executive Officer and the Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) under the US Securities Exchange Act of 1934, as amended, and in National Instrument 52-109 under the Canadian Securities Administrators Rules and Policies. Based on that evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that as a result of the material weaknesses in our internal control over financial reporting (ICFR) discussed below the disclosure controls and procedures were not effective as of March 31, 2010.

Management’s Report on Internal Control 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 US GAAP and reconciled to Canadian 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 National Instrument 52-109 under the Canadian Securities Administrators Rules and Policies. 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, 2010, 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 a continued material weakness in ICFR as described below and, as a result, we concluded that the Company’s ICFR is ineffective as of March 31, 2010.

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

KPMG LLP, the registered public accounting firm that audited the financial statements included in the annual report containing this disclosure has issued an attestation report on our internal control over financial reporting.

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

Material changes to internal controls over financial reporting and remediation plans

In response to the revenue recognition material weakness identified for the year ended March 31, 2009, we formalized our revenue recognition policy to assist in the understanding and consistent application of GAAP, developed and implemented a procedural manual to assist with applying the revenue recognition policy, designed new process-level controls and conducted staff training. These changes had a material effect on the Company’s ICFR during the year ended March 31, 2010.

In response to the continued material weakness in revenue recognition identified above, during the three months ended and subsequent to March 31, 2010, we put a dedicated project team in place, led by a senior member of our Finance team, to develop and implement standard business practices and controls specific to ensuring the accuracy of forecasts, including the consideration of project changes subsequent to the end of each reporting period. We will evaluate the effectiveness of these controls during the next fiscal year to determine if they adequately address our ability to recognize revenue in accordance with GAAP.

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.

Revenue recognition

We perform our projects under the following types of contracts: time-and-materials; cost-plus; unit-price; and lump sum. Revenue is recognized as costs are incurred for time-and-materials and cost-plus service contracts with no clearly defined scope. Revenue on cost-plus, unit-price, lump-sum and time-and-materials contracts with defined scope are recognized using the percentage-of-completion method, measured by the ratio of costs incurred to date to estimated total costs. The resulting percent complete methodology is applied to the approved contract value to determine the revenue recognized. Customer payment milestones typically occur on a periodic basis over the period of contract completion. The estimated total cost of the contract and percent complete is determined based upon estimates made by management. The costs of items that do not relate to performance of contracted work, particularly in the early stages of the contract, are excluded from costs incurred to date.

The length of our contracts varies from less than one year for typical contracts to several years for certain larger contracts. Contract project costs include all direct labour, material, subcontract and equipment costs and those indirect costs related to contract performance such as indirect labour, supplies and tools. General and administrative costs are charged to expense as incurred. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Changes in project performance, project conditions and estimated profitability, including those arising from contract penalty provisions and final contract settlements, may result in revisions to costs and revenue that are recognized in the period in which such adjustments are determined. Profit incentives are included in revenue when their realization is reasonably assured.

Once a project is underway, we will often experience changes in conditions, client requirements, specifications, 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 unapproved change orders and claims are recognized when they are incurred. Revenues related to unapproved change orders and claims are included in total estimated contract revenue when they are approved.

Revenues related to unapproved change orders and 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 unapproved change order or claim will result in:

_Ÿ a bona fide addition to contract value; and

_Ÿ revenues can be reliably estimated.

These two conditions are satisfied when:

_Ÿ the contract or other evidence provides a legal basis for the unapproved change order or claim or a legal opinion is obtained providing a reasonable basis to support the unapproved change order or claim;

_Ÿ additional costs incurred were caused by unforeseen circumstances and are not the result of deficiencies in our performance;

_Ÿ costs associated with the unapproved change order or claim are identifiable and reasonable in view of work performed; and

_Ÿ evidence supporting the unapproved change order or claim is objective and verifiable.

North American Energy Partners Inc.  Management’s Discussion and Analysis  35

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.

Our long-term contracts typically allow our customers to unilaterally reduce or eliminate the scope of the work as contracted without cause. These long-term contracts represent higher risk due to uncertainty of total contract value and estimated costs to complete; therefore, potentially impacting revenue recognition in future periods.

A contract is regarded as substantially completed when remaining costs and potential risks are insignificant in amount.

Property, plant and equipment

The most significant estimates in accounting for property, 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. In determining the estimates of these useful lives, we take into account industry trends and company-specific factors, including changing technologies and expectations for the in-service period of certain assets. On an annual basis, we re-assess our existing estimates of useful lives to ensure they match the anticipated life of the equipment from a revenue-producing perspective. If technological change happens more quickly or in a different way than anticipated, we might have to reduce the estimated life of property, plant and equipment, which could result in a higher depreciation expense in future periods or we may record an impairment charge to write down the value of property, plant and equipment.

Another key estimate is the expected cash flows from the use of an asset and the expected disposal proceeds in applying ASC 360, “Property, Plant and Equipment”, on the impairment and disposal of long-lived assets. This standard requires 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 and disposition. An impairment loss, if any, is determined as the excess of the carrying value of the asset over its fair value. The valuation of long-lived assets requires us to exercise judgment in the determination of an asset group and in making assumptions about future results, including revenue and cash flow projections for an asset group.

Allowance for doubtful accounts receivable

We regularly review our accounts receivable balances for each of our customers and we write down these balances to their expected realizable value when outstanding amounts are determined not to be fully collectible. This generally occurs when our customer has indicated an inability to pay, we were unable to communicate with our customer over an extended period of time and we have considered other methods to obtain payment without success. We determine estimates of the allowance for doubtful accounts on a customer-by-customer evaluation of collectability at each reporting date, taking into consideration the following factors: the length of time the receivable has been outstanding, specific knowledge of each customer’s financial condition and history.

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 test goodwill annually on October 1. It is our intention to continue to complete goodwill impairment testing annually on October 1 going forward or whenever events or changes in circumstances indicate that impairment may exist. We completed our most recent annual goodwill impairment testing on October 1, 2009. This impairment test showed that the fair value of the Piling reporting unit exceeded its carrying values.

Financial instruments

In determining the fair value of financial instruments, we use 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 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.

Recently Adopted Accounting Policies

The FASB accounting standards codification and the hierarchy of generally accepted accounting principles

In June 2009, the Financial Accounting Standards Board (FASB) issued the FASB Accounting Standards Codification (ASC) 105. The ASC amended the hierarchy of generally accepted accounting principles (GAAP) such that the ASC became the single source of authoritative nongovernmental US GAAP, except for SEC rules and interpretative releases which, for our company, are also authoritative US GAAP. The ASC did not change current US GAAP, but was intended to simplify user access to all authoritative US GAAP by providing all the authoritative literature related to a particular topic in one place. All previously existing accounting standard documents were superseded and all other accounting literature not included in the ASC is considered non-authoritative. The ASC identifies the sources of accounting principles and the

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

framework for selecting the principles to be used in the preparation of financial statements in accordance with US GAAP. The ASC was effective on September 15, 2009. The adoption of this standard did not have a material impact on our consolidated financial statements.

Fair value measurements

In September 2006, the FASB issued an accounting standard codified in ASC 820, “Fair Value Measurements and Disclosures”. This standard established a single definition of fair value and a framework for measuring fair value, set out a fair value hierarchy to be used to classify the source of information used in fair value measurements and required disclosures of assets and liabilities measured at fair value based on their level in the hierarchy. This standard applies under other accounting standards that require or permit fair value measurements. One of the amendments deferred the effective date for one year, relative to non-financial assets and liabilities that are measured at fair value, but are recognized or disclosed at fair value on a non-recurring basis. This deferral applied to such items as non-financial assets and liabilities initially measured at fair value in a business combination (but not measured at fair value in subsequent periods) or non-financial long-lived asset groups measured at fair value for an impairment assessment. These remaining aspects of the fair value measurement standard were adopted by us prospectively beginning April 1, 2009.

Business combinations

In December 2007, the FASB issued SFAS No. 141R, “Business Combinations” (“SFAS 141R”), and in April 2009, issued FAS 141 (R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies”, to amend and clarify SFAS No. 141(R), “Business Combinations”, now part of ASC 805, “Business Combinations”. Effective on April 1, 2009, the standard establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and any goodwill and establishes disclosure requirements that enable users of our financial statements to evaluate the nature and financial effects of the business combination. This new standard was applied to the acquisition of DF Investments Limited and its subsidiary Drillco Foundation Co. Ltd.

Non-controlling interests in consolidated financial statements

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements – An Amendment of ARB No. 51 (“SFAS 160”)”, which is now a part of ASC 810. The amendments to ASC 810 are effective for the fiscal year beginning April 1, 2009 and changes the accounting and reporting for ownership interests in subsidiaries held by parties other than the parent. These non-controlling interests are to be presented in the consolidated balance sheet within equity but separate from the parent’s equity. The amount of consolidated net income attributable to the parent and to the non-controlling interest is to be clearly identified and presented on the face of the consolidated statement of operations. In addition, this ASC establishes standards for a change in a parent’s ownership interest in a subsidiary and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. The ASC also establishes reporting requirements for providing sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. We prospectively adopted this ASC effective April 1, 2009. The adoption of this standard did not have a material impact on our consolidated financial statements.

Determination of the useful life of intangible assets

In April 2008, the FASB issued FSP No. FAS 142-3, “Determination of the Useful Life of Intangible Assets”, which amends the list of factors an entity should consider in developing renewal or extension assumptions used in determining the useful life of recognized intangible assets under SFAS No. 142, “Goodwill and Other Intangible Assets”. The guidance, now part of ASC 350, “Intangibles – Goodwill and Others”, and ASC 275, “Risks and Uncertainties”, applies to (i) intangible assets that are acquired individually or with a group of other assets and (ii) intangible assets acquired in both business combinations and asset acquisitions. Entities estimating the useful life of a recognized intangible asset must now consider their experience in renewing or extending similar arrangements or, in the absence of experience, must consider assumptions that market participants would use about renewal or extension. We adopted this standard effective April 1, 2009. The adoption of this standard did not have a material impact on our consolidated financial statements.

Equity method investment accounting considerations

In November 2008, the FASB issued EITF 08-06, “Equity Method Investment Accounting Considerations”, now part of ASC 323, “Investments – Equity Method and Joint Ventures”, which clarifies the accounting for certain transactions and impairment considerations involving equity method investments. The intent is to provide guidance on: (i) determining the initial measurement of an equity method investment, (ii) recognizing other-than-temporary impairments of an equity method investment and (iii) accounting for an equity method investee’s issuance of shares. We adopted this standard effective April 1, 2009. The adoption of this standard did not have a material impact on our consolidated financial statements.

Determining fair value when the volume and level of activity for the asset or liability have significantly decreased and identifying transactions that are not orderly

In April 2009, the FASB issued FSP No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”. The guidance, now

North American Energy Partners Inc.  Management’s Discussion and Analysis  37

part of ASC 820, “Fair Value Measurements and Disclosures”, provides additional guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased. It also includes guidance on identifying circumstances that indicate a transaction is not orderly. We adopted this standard effective July 1, 2009. The adoption of this standard did not have a material impact on our consolidated financial statements.

Subsequent events

In May 2009, the FASB issued ASC 855, “Subsequent Events” (formerly SFAS No. 165 “Subsequent Events”) which requires SEC filers to evaluate subsequent events through the date the financial statements are issued. In February 2010, the FASB issued ASU 2010-09, “Amendments to Certain Recognition and Disclosure Requirements”, which amended the guidance in ASC 855 to remove the requirement to disclose the date through which subsequent events have been evaluated in originally issued and revised financial statements. The adoption of this guidance did not have a material impact on our consolidated financial statements.

Measuring liabilities at fair value

In August 2009, the FASB issued ASU No. 2009-05, “Measuring Liabilities at Fair Value”, which provides additional guidance on how companies should measure liabilities at fair value under ASC 820, “Fair Value Measurements and Disclosures”. The ASU clarifies that the quoted price for an identical liability should be used; however, if such information is not available, an entity may use the quoted price of an identical liability when traded as an asset, quoted prices for similar liabilities or similar liabilities traded as assets, or another valuation technique (such as the market or income approach). The ASU also indicates that the fair value of a liability is not adjusted to reflect the impact of contractual restrictions that prevent its transfer and indicates circumstances in which quoted prices for an identical liability or quoted price for an identical liability traded as an asset may be considered Level 1 fair value measurements. We adopted this ASU effective October 1, 2009. The adoption of this standard did not have a material impact on our consolidated financial statements.

Accounting and reporting for decreases in ownership of a subsidiary

In January 2010, the FASB issued ASU 2010-02, “Consolidation (Topic 810) – Accounting and Reporting for Decreases in Ownership of a Subsidiary – A Scope Clarification”. The ASU clarifies that the scope of the decrease in ownership provisions included in ASC 810, “Consolidations” and related guidance applies to: (i) a subsidiary or a group of assets that is a business or a non-profit activity; (ii) a subsidiary that is a business or a non-profit activity that is transferred to an equity method investee or a joint venture; and (iii) an exchange of a group of assets that constitutes a business or non-profit activity for a non-controlling interest in an entity. The standard also clarifies that the decrease in ownership guidance does not apply to certain transactions, such as sales of in substance real estate or conveyance of oil and gas properties. We adopted this standard effective April 1, 2009 in conjunction with adoption of the non-controlling interest standard. The adoption of this standard did not have a material impact on our consolidated financial statements.

Equity

In January 2010, the FASB issued ASU No. 2010-01, “Equity”, which clarifies that the stock portion of a distribution to shareholders that allows them to elect to receive cash or shares with a potential limitation on the total amount of cash that all shareholders can elect to receive in the aggregate is considered a share issuance that is reflected in EPS prospectively and is not a stock dividend for purposes of earnings per share calculations. We adopted this ASU effective December 31, 2009. The adoption of this standard did not have a material impact on our consolidated financial statements.

Improving disclosures about fair value measurements

In January 2010, the FASB issued ASU No. 2010-06, “Improving Disclosures About Fair Value Measurements”, that amends existing disclosure requirements under ASC 820 by adding required disclosures about items transferring into and out of Level 1 and Level 2 in the fair value hierarchy; adding separate disclosures about purchase, sales, issuances and settlements relative to Level 3 measurements; and clarifying, among other things, the existing fair value disclosures about the level of disaggregation. The ASU is effective beginning on January 1, 2010, except for disclosures about purchases, sales, issuances and settlements in the roll forward of activity in Level 3 fair value measurements, which is effective beginning on April  1, 2011. The adoption of this standard did not have a material impact on our consolidated financial statements.

Recent Accounting Pronouncements Not Yet Adopted

Revenue recognition

In October 2009, the FASB issued ASU No. 2009-13, “Revenue Recognition: Multiple-Deliverable Revenue Arrangements”, which addresses the accounting for multiple-deliverable arrangements to enable vendors to account for products or services separately rather than as a combined unit. The amendments establish a selling price hierarchy for determining the selling price of a deliverable. The amendments also eliminate the residual method of allocation and require that arrangement consideration be allocated at the inception of the arrangement to all deliverables using the relative selling price method. This ASU is effective prospectively for revenue arrangements entered into or materially modified on or after April 1, 2010. We are currently evaluating the impact of this ASU on our consolidated financial statements.

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

Improvements to financial reporting by enterprises involved with variable interest entities

In December 2009, the FASB issued ASU No. 2009-17, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities”, which amends ASC 810, “Consolidation”. The amendments give guidance and clarification of how to determine when a reporting entity should include the assets, liabilities, non-controlling interests and results of activities of a variable interest entity in its consolidated financial statements. The amendments in this ASU are effective beginning on April 1, 2011. We are currently evaluating the impact of this ASU on our consolidated financial statements.

Embedded credit derivatives

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

Share based payment awards

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

Recently Adopted Accounting Policies (Canadian GAAP)

Goodwill and intangible assets

Effective April 1, 2009, we adopted, on a retrospective basis, CICA Handbook Section 3064, “Goodwill and Intangible Assets”, which replaces Section 3062, “Goodwill and Other Intangible Assets” and Section 3450, “Research and Development Costs” and 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 Accounting Standard IAS 38, “Intangible Assets”. The adoption of this standard resulted in the reclassification for certain qualifying assets related to software from property, plant and equipment to intangible assets for all periods presented.

Business combinations

On July 1, 2009, we early adopted CICA Handbook Section 1582, “Business Combinations”, effective April 1, 2009. This section establishes standards for the accounting of business combinations and states that all assets and liabilities of an acquired business will be recorded at fair value. Obligations for contingent consideration and contingencies will also be recorded at fair value at the acquisition date. The standard also states that acquisition related costs will be expensed as incurred, that restructuring charges will be expensed in periods after the acquisition date and that non-controlling interests should be measured at fair value at the date of acquisition. This standard is to be applied prospectively to business combinations with acquisition dates on or after April 1, 2009. This new standard was applied to the acquisition of DF Investments Limited and its subsidiary Drillco Foundation Co. Ltd.

Consolidated financial statements

On July 1, 2009, we early adopted CICA Handbook Section 1601, “Consolidated Financial Statements”, effective April 1, 2009. The new standard replaces Section 1600 “Consolidated Financial Statements”. This Section carries forward existing Canadian guidance for preparing consolidated financial statements other than guidance for non-controlling interests. The adoption of this standard did not have a material impact on our consolidated financial statements.

Non-controlling interests

On July 1, 2009, we early adopted CICA Handbook Section 1602, “Non-Controlling Interests”, effective April 1, 2009. The new standard establishes standards for the accounting of non-controlling interests of a subsidiary in the preparation of consolidated financial statements subsequent to a business combination. The adoption of this standard did not have a material impact on our consolidated financial statements.

Equity

In August 2009, the CICA amended presentation requirements of Handbook Section 3251, “Equity”, as a result of issuing Section 1602, “Non-Controlling Interests”. The amendments apply only to entities that have adopted Section 1602. We early adopted this standard effective April 1, 2009. The adoption of this standard did not have a material impact on our consolidated financial statements.

North American Energy Partners Inc.  Management’s Discussion and Analysis  39

Financial instruments – recognition and measurement

Effective July 1, 2009, we adopted CICA amendments to Handbook Section 3855, “Financial Instruments – Recognition and Measurement” which add guidance concerning the assessment of embedded derivatives upon reclassification of a financial asset out of the held-for-trading category. These amendments apply to reclassifications made on or after July 1, 2009. The adoption of these amendments did not have a material impact on our consolidated financial statements.

Financial instruments – disclosure

In June 2009, the CICA amended Handbook Section 3862, “Financial Instruments – Disclosures”, to include additional disclosure requirements about fair value measurements of financial instruments and to enhance liquidity risk disclosure requirements. The amendments apply to annual financial statements relating to fiscal years ending after September 30, 2009. The adoption of these amendments did not have a material impact on our consolidated financial statements.

Recent Accounting Pronouncements Not Yet Adopted (Canadian GAAP)

Accounting changes

In June 2009, the CICA amended Handbook Section 1506, “Accounting Changes”, to exclude from its scope changes in accounting policies upon the complete replacement of an entity’s primary basis of accounting. The amendment applies to interim and annual financial statements relating to fiscal years beginning on or after July 1, 2009. We are currently evaluating the impact of the amendments to the standard.

Financial instruments – recognition and measurement

In June 2009, the CICA amended Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, to clarify the application of the effective interest method after a debt instrument has been impaired. The Section has also been amended to clarify when an embedded prepayment option is separated from its host instrument for accounting purposes. The amendments apply to interim and annual financial statements relating to fiscal years beginning on or after May 1, 2009 for the amendments relating to the effective interest method and on or after January 1, 2011 for the amendments relating to embedded prepayment options. We are currently evaluating the impact of the amendments to the standard.

Comprehensive revaluation of assets and liabilities

In August 2009, the CICA amended Handbook Section 1625, “Comprehensive Revaluation of Assets and Liabilities”, as a result of issuing Section 1582, “Business Combinations”, Section 1601, “Consolidated Financial Statements” and Section 1602, “Non-Controlling Interests”, in January 2009. The amendments apply prospectively to comprehensive revaluations of assets and liabilities occurring in fiscal years beginning on or after January 1, 2011. Earlier adoption is permitted as of the beginning of a fiscal year, provided that Section 1582 is also adopted. We are currently evaluating the impact of the amendments to the standard.

Multiple deliverable arrangements

In December 2009, the CICA issued Emerging Issues Committee (EIC) 175, “Multiple deliverable arrangements”. This abstract addresses how to determine whether an arrangement involving multiple deliverables contains more than one unit of accounting. It also addresses how arrangement consideration should be measured and allocated to the separate units of accounting in the arrangement. For us, this abstract is effective on prospective basis to all revenue arrangements with multiple deliverables entered into or materially modified in the fiscal period beginning April 1, 2011. We are currently evaluating the impact of this abstract on our consolidated financial statements.

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”, “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) our expectation that demand for recurring services will continue to be stable in the improving economic environment and that demand for recurring services will continue to grow, over the long-term, as existing oil sands mines progress and as new mines, such as Canadian Natural’s Horizon mine and Albian’s Jackpine mine, come on-line;

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

(b) our expectation that the demand for new infrastructure to support a larger population coupled with government investment in infrastructure to stimulate the economy provides a strong outlook for infrastructure spending in Western Canada and in Ontario and our belief of our ability to capitalize on the expected growth in infrastructure projects;

(c) our expectation that we will benefit from increased spending in the private sector, over the coming years, as the economy recovers from the downturn;

(d) our expectation that in the near term the market for smaller pipeline projects and expansions will remain highly competitive given the current oversupply of contracting capacity and steady demand;

(e) our expectation that commodity prices will continue improving in 2010;

(f) our expectation for continued steady growth in recurring revenue from operating oil sands projects as activity levels increase at existing mines and new oil sands projects move from the capital development stage into the operational phase;

(g) the amount of our expected backlog (which estimate assists us in planning our activity levels and may not be suitable for other purposes), to be performed and realized in the twelve months ending March 31, 2011;

(h) we expect to see demand for our services will gradually strengthen as the year progresses;

(i) our expectation that development opportunities will continue to expand with Exxon’s Kearl, ConocoPhillips’s Surmont and Suncor’s Firebag projects moving forward;

(j) our expectation that there will some short-term variability in the demand for recurring services in early fiscal 2011 and our expectation that demand will recover during the three months ending September 30, 2010 and remain stable through the balance of the year;

(k) our expectation that the infrastructure associated with modifications to tailings disposal systems will generate opportunities for us to provide an expanded range of services in support of these initiatives and will become a significant revenue growth opportunity for us over time;

(l) our expectation that we will be able complete our two new Pipeline contracts during fiscal 2011 and that we have mitigated our risk exposure in our new contracts;

(m) our expectation that our Pipeline segment will return to profitability in fiscal 2011;

(n) our expectation that we will see a gradual increase in opportunities for our Piling division as fiscal 2011 progresses and our expectation that demand improvement will continue in the commercial and public construction market as the year progresses;

(o) our expectation that the economic conditions in Canada, led by Alberta, will continue to improve for several years to come;

(p) our expectation that a renewal Collective Agreement will be ratified without any disruption to the Company’s operations;

(q) our expectation that our capital needs in fiscal 2011 will be approximately $50-$75 million, but we could also increase our capital spend to approximately $100 million as a result of the availability of equipment from the recent bankruptcy of one of our competitors;

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

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

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

The forward-looking information in paragraphs (a), (b), (c), (d), (e), (f), (g), (h), (i), (j), (k), (m), (n), (o), (q), (r), (s), and (t) rely on certain market conditions and demand for our services and are based on the assumptions that: despite the slowdown in the global economy and tightening of credit conditions, we still expect to see strong demand for our recurring services as the oil sands continue to be an economically viable source of energy, our customers and potential customers continue to invest in the oil sands and other natural resource developments; our customers and potential customers will continue to outsource the type of activities for which we are capable of providing service; and the Western Canadian economy continues to develop with additional investment in public construction; and are subject to the following risks and uncertainties, which could cause results to differ materially from those expressed in the forward-looking information contained in this MD&A, but are not limited to:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

While we anticipate that subsequent events and developments may cause our views to change, we do not have an intention to update this forward-looking information, except as required by applicable securities laws. This forward-looking information represents our views as of the date of this document and such information should not be relied upon as representing our views as of any date subsequent to the date of this document. We have attempted to identify important factors that could cause actual results, performance or achievements to vary from those current expectations or estimates expressed or implied by the forward-looking information. However, there may be other factors that cause results, performance or achievements not to be as expected or estimated and that could cause actual results, performance or achievements to differ materially from current expectations. There can be no assurance that forward-looking information will prove to be accurate, as actual results and future events could differ materially from those expected or estimated in such statements. Accordingly, readers should not place undue reliance on forward-looking information. These factors are not intended to represent a complete list of the factors that could affect us. See “Risk Factors” below and risk factors highlighted in materials filed with the securities regulatory authorities filed in the United States and Canada from time to time, including, but not limited to, our most recent Annual Information Form.

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Risk Factors

Anticipated new major capital projects in the oil sands may not materialize.

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

_Ÿ reductions in available credit for customers to fund capital projects;

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

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

_Ÿ lack of sufficient governmental infrastructure funding to support growth;

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

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

_Ÿ cost overruns on announced projects.

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 is leading our customers to slow down or curtail their future capital expansion which, in turn, has reduced our revenue from those customers on their capital projects. The continuation of such a delay or curtailment could have an adverse impact on our financial condition and results of operations. In addition, a reduction in the number of new oil sands capital projects by customers would also likely result in increased competition among oil sands service providers, which could also reduce our ability to successfully bid for new capital projects.

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 capital projects, which would, in turn, reduce our revenue from capital projects from those customers.

Due to the amount of capital investment required to build an oil sands project, or construct a significant capital 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 capital project will produce, the anticipated amount of capital investment required and the anticipated fixed cost of operating the project. The most important 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 favourable, or believes oil-sands projects are not viable for any other reason, they may delay, reduce or cancel plans to construct new oil sands capital projects or capital expansions to existing projects. Recently, the market price of oil decreased significantly. In addition, the slowing world economy is leading to lower international demand for oil, which could continue to suppress oil prices. As a result of these developments, many of our customers have decided to scale back their capital development plans and are significantly reducing their capital expenditures on oil sands projects. Delays, reductions or cancellations of major oil sands projects would adversely affect our prospects for revenues from capital projects and could have an adverse impact on our financial condition and results of operations.

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.

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

Outsourced Heavy Construction and Mining services constitute a large portion of the work we perform for our customers. For example, our mining and site preparation project revenues constituted approximately 88%, 74% and 63% of our revenues in each of the years ended March 31, 2010, 2009 and 2008, 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. Additionally, the recent tightening of the credit market and worldwide economic downturn may result in our customers reducing their spending

North American Energy Partners Inc.  Management’s Discussion and Analysis  43

on outsourced mining and site preparation services if they believe they can perform this work in a more cost effective and efficient manner using their internal resources.

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 material weakness in our financial reporting processes and internal controls specific to revenue recognition in our most recent “Management’s Report on Internal Controls over Financial Reporting (ICFR)”. 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 violate the US 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.

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 and climate change 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 or the market for their products could be adversely impacted. The high cost of compliance with applicable regulations or the reduction and demand for our customers’ products 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.

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 88%, 74% and 63% of our total revenue for 2010, 2009 and 2008, 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 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 and, in many cases, with minimal or no notice to us. Additionally, certain of these contracts provide for limited compensation following such suspension or termination operations and we can provide no assurance that we could replace the lost work with work from other customers. The loss of or significant reduction in business with one or more of our major customers, whether as a result of the completion, early termination or suspension of a contract, or failure or inability to pay amounts owed to us, could have a material adverse effect on our business and results of operations.

Failure by our customers to obtain required permits and licenses due to complex and stringent environmental protection laws and regulations 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.

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 previously intervened in hearings considering applications by major oil sands companies to the Energy Resources Conservation Board (“ERCB”), formerly the Energy and Utilities Board (EUB), for approval to expand their operations. Similar action could be taken with respect to any future applications. The ERCB 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 cancelled which could in turn adversely affect our prospects and could have a material adverse impact on our financial condition and results of operations.

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

Significant labour disputes could adversely affect our business.

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 labour disruption experienced by our key customers could significantly reduce the amount of our services that they need.

An upturn in the Canadian economy, resulting in an increased demand for our services from the Canadian energy industry, could lead to a new shortage of qualified personnel.

From fiscal 2007 through the first nine months of fiscal 2009, Alberta, and in particular the oil sands area, experienced significant economic growth which resulted in a shortage of skilled labour and other qualified personnel. New mining projects in the area made it more difficult for us and our customers to find and hire all the employees required to work on these projects. If the economy returns to these previous growth levels and we are not able to recruit and retain sufficient numbers of employees with the appropriate skills, we may not be able to satisfy an increased demand for our services. This in turn, could have a material adverse effect on our business, financial condition and results of operation. If our customers are not able to recruit and retain enough employees with the appropriate skills, they may be unable to develop projects in the oils sands area.

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 re-evaluate 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 April 30, 2010 amended and restated credit agreement provides for the issuance of letters of credit up to $85.0 million, and at June 10, 2010, we had $14.4 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 customer’s requirements, our business and results of operations could be adversely affected.

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 labour 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.

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

Approximately 39%, 29% and 44% of our revenue for the years ended March 31, 2010, 2009 and 2008, 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:

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

_Ÿ scope modifications during the execution of the project;

_Ÿ the availability and cost of skilled workers;

_Ÿ the availability and proximity of materials;

_Ÿ unfavourable weather conditions hindering productivity;

North American Energy Partners Inc.  Management’s Discussion and Analysis  45

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

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

_Ÿ 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.

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, 2010, we had outstanding $477.3 million of debt ¹⁴, including $13.4 million of capital leases. We also had cross-currency and interest rate swaps with a balance sheet liability of $81.1 million as of March 31, 2010. These swaps are secured equally and ratably with our Revolving Facility. Our substantial indebtedness could have serious consequences, such as:

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

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

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

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

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

_Ÿ 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 amended and restated credit agreement facility and the trust indenture governing our Series 1 Debentures limit, among other things, our ability and the ability of our subsidiaries to:

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

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

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

_Ÿ issue equity securities of subsidiaries;

_Ÿ make certain investments or acquisitions;

_Ÿ create liens on our assets;

_Ÿ enter into transactions with affiliates;

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

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

Our credit agreement also requires us, and our future credit agreements 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 credit agreement, 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 trust indenture governing our Series 1 Debentures the outstanding principal

¹⁴   Debt includes all liabilities with the exception of future income taxes

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

and accrued interest on the notes may become immediately due and payable. If amounts outstanding under such credit agreements and the trust 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.

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 27% of our revenue for the year ended March 31, 2010 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.

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.

Our ability to grow our operations in the future may be hampered by our inability to obtain long lead time equipment and tires, which can be in limited supply during strong economic times.

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 during strong economic times, we may have to 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.

In strong economic times, global demand for tires of the size and specifications we require can exceed the available supply. 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.

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 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.

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

North American Energy Partners Inc.  Management’s Discussion and Analysis  47

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.

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.

Reduced availability or increased cost of leasing our equipment fleet could adversely affect our results

A portion of our equipment fleet is currently leased from third parties. Further, we anticipate leasing substantial amounts of equipment to meet equipment acquisition commitments related to our long-term overburden removal contract in the upcoming fiscal year. Other future projects may require us to lease additional equipment. If equipment lessors are unable or unwilling to provide us with reasonable lease terms within our expectations, it will significantly increase the cost of leasing equipment or may result in more restrictive lease terms that require recognition of the lease as a capital lease. We are actively pursuing new lessor relationships to dilute our exposure to the loss of one or more of our lessors.

Quantitative and Qualitative Disclosures about Market Risk

Foreign exchange risk

Foreign exchange risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to changes in foreign exchange rates. At March 31, 2010 we had 8 ³/4% senior notes denominated in US dollars in the amount of US$200.0 million. In order to reduce our exposure to changes in the United States to Canadian dollar exchange rate, we entered into a cross-currency swap agreement to manage this foreign currency exposure for both the principal balance due on December 1, 2011 as well as the semi-annual interest payments from the issue date to the maturity date. In conjunction with the cross-currency swap agreement, we also entered into a US dollar interest rate swap and a Canadian dollar interest rate swap. These derivative financial instruments were not designated as hedges for accounting purposes. At March 31, 2010 and March 31, 2009, the notional principal amount of the cross-currency swap was US$200.0 million and Canadian $263.0 million.

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

On December 17, 2008, we received notice that all three swap counterparties had exercised the cancellation option on the US dollar interest rate swap and, effective February 2, 2009, the US dollar interest rate swap was terminated. Our Canadian dollar interest rate swap and cross-currency swap agreements are not cancellable at the option of the counterparties and remained in effect at March 31, 2010. We will continue to pay the counterparties an average fixed rate of 9.889% on the notional amount of Canadian $263.0 million or Canadian $13.0 million semi-annually until December 1, 2011. Beginning March 1, 2009, we received quarterly floating rate payments in US dollars on the cross-currency swap agreement at the prevailing three month US dollar LIBOR rate plus a spread of 4.2% on the notional amount of US $200.0 million.

As a result of the cancellation of the US dollar interest rate swap, we are exposed to changes in the value of the Canadian dollar versus the US dollar. To the extent that the three month US dollar LIBOR rate is less than 4.6% (the difference between the 8 ³/4% senior notes coupon and the 4.2% spread over three month US dollar LIBOR on the cross-currency swap agreement), we will have to acquire US dollars to fund a portion of our semi-annual coupon payment on our 8 ³/4% senior notes. At the three-month US dollar LIBOR rate of 0.268% at March 31, 2010, a $0.01 increase (decrease) in exchange rates in the Canadian dollar would result in an insignificant decrease (increase) in the amount of Canadian dollars required to fund each semi-annual coupon payment.

At March 31, 2010, with other variables unchanged, a $0.01 increase (decrease) in exchange rates of the Canadian dollar to the US dollar related to the US dollar denominated 8 ³/4% senior notes would decrease (increase) net income and decrease (increase) equity by approximately $1.9 million, net of tax. With other variables unchanged, a $0.01 increase (decrease) in exchange rates in the Canadian to the US dollar related to the cross-currency swap would increase (decrease) net income and increase (decrease) equity by approximately $1.9 million, net of tax. The impact of similar exchange rate changes on short-term exposures would be insignificant and there would be no impact to other comprehensive income.

As discussed in the “Liquidity and Capital Resources” section, all of our US dollar denominated 8 ³/4% senior notes were redeemed in April 2010 and the associated swap agreements were terminated. As a result of these transactions, we are no longer exposed to foreign exchange risk with respect to our long-term debt, interest payments or cross-currency and interest rate swap obligations.

We also regularly transact in foreign currencies when purchasing equipment, spare parts as well as certain general and administrative goods and services. These exposures are generally of a short-term nature and the impact of changes in exchange rates has not been significant in the past. We may fix our exposure in either the Canadian dollar or the US dollar for these short-term transactions, if material.

Interest rate risk

We are exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of our financial instruments. Amounts outstanding under our amended credit facilities are subject to a floating rate. Our 8 ³/4% senior notes and 9.125% Series 1 Debentures are subject to a fixed rate. Our interest rate risk arises from long-term borrowings issued at fixed rates that create fair value interest rate risk and variable rate borrowings that create cash flow interest rate risk. Changes in market interest rates cause the fair value of long-term debt with fixed interest rates to fluctuate but do not affect earnings, as our debt is carried at amortized cost and the carrying value does not change as interest rates change.

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

We also entered into a US dollar interest rate swap and a Canadian dollar interest rate swap with the net effect of economically converting the 8.75% rate payable on the 8 ³/4% senior notes into a Canadian fixed rate of 9.889% for the duration that the 8 ³/4% senior notes are outstanding. These derivative financial instruments were not designated as hedges for accounting purposes. As a result of the US dollar interest rate swap cancellation, we are exposed to changes in interest rates. We have a fixed semi-annual coupon payment of 8.75% on our US$200.0 million senior notes. With the termination of the US dollar interest rate swap, we no longer receive fixed US dollar payments from the counterparties to offset the coupon payment on our 8 ³/4% senior notes. As a result of this termination, our effective annual interest costs at the current US dollar LIBOR rate will increase US$8.6 million. In addition, we are now exposed to interest rate risk where a 100 basis point increase (decrease) in the three month US dollar LIBOR rate will result in a US$2.0 million decrease (increase) in effective annual interest costs. As at March 31, 2010, holding all other variables constant, a 100 basis point increase (decrease) to Canadian interest rates would impact the fair value of the interest rate swaps by $2.4 million, net of tax, with this change in fair value being recorded in net income. As at March 31, 2010, holding all other variables constant, a 100 basis point increase (decrease) to US interest rates would impact the fair value of the interest rate swaps by $0.2 million, net of tax, with this change in fair value being recorded in net income. As at March 31, 2010, holding all other variables constant, a 100 basis point increase (decrease) of Canadian to US interest rate volatility would have no impact on the fair value of the interest rate swaps.

North American Energy Partners Inc.  Management’s Discussion and Analysis  49

As discussed in the “Liquidity and Capital Resources” section, our US dollar denominated 8 ³/4% senior notes were fully redeemed in April 2010 and the associated swap agreements were terminated. As a result of these transactions, we are no longer exposed to cash flow interest rate risk with respect to the interest payments associated with our swap agreements.

At March 31, 2010, we held $28.4 million of floating rate debt pertaining to our term facility within our amended and restated credit agreement dated June 24, 2009 (March 31, 2009 – $nil). As at March 31, 2010, holding all other variables constant, a 100 basis point increase (decrease) to interest rates on floating rate debt would result in a $0.3 million increase (decrease) in annual interest expense. This assumes that the amount of floating rate debt remains unchanged from that which was held at March 31, 2010.

As discussed in the “Liquidity and Capital Resources” section, we entered into an amended and restated credit agreement effective April 30, 2010. In addition to extending the maturity of the facility to April 2013, the new credit facilities included an $85.0 million Revolving Facility, a $28.4 million Term A Facility and a $50.0 million Term B Facility. At April 30, 2010, the Revolving Facility had no borrowings outstanding and $10.4 million of issued and undrawn letters of credit. The Term A Facility and Term B Facility were fully drawn, resulting in $78.4 million of floating rate debt. Holding all other variables constant, a 100 basis point increase (decrease) to interest rates on this floating rate debt would result in a $0.8 million increase (decrease) in annual interest expense.

H. General Matters

History and Development of the Company

NACG Holdings Inc. (NACG) was formed in October 2003 in connection with the Acquisition discussed below. Prior to the Acquisition, NACG 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 NACG, 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. 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, NACG 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 (US $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.

On December 6, 2006, the underwriters exercised their option to purchase an additional 687,500 common shares from us.

Additional Information

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

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

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