6-K 1 o41528e6vk.htm FORM 6-K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 6-K
Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16
under the Securities Exchange Act of 1934
For the month of August 2008
Commission File Number 001-33161
NORTH AMERICAN ENERGY PARTNERS INC.
Zone 3 Acheson Industrial Area
2-53016 Highway 60
Acheson, Alberta
Canada T7X 5A7
(Address of principal executive offices)
Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F o |  | Form 40-F þ

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): o
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): o
Indicate by check mark whether by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes o |  | No þ

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): .

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Documents Included as Part of this Report

1. |  | 2008 Annual Report to Shareholders.

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

| NORTH AMERICAN ENERGY PARTNERS INC. |
| By: | /s/ Peter Dodd |
|  | Name: | Peter Dodd |
|  | Title: | Chief Financial Officer |

Date: August 5, 2008

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To Our Shareholders:
In our business, there is only one thing more important than having a large and versatile heavy equipment fleet: knowing how to execute with it.
During fiscal 2008, North American Energy Partners demonstrated that we know precisely how to put our growing capacity to work. Seizing opportunities in all three of our operating divisions, we boosted revenue to $989.7 million and carried the momentum through to our bottom line. With Consolidated EBITDA per bank of $135.1 million, net income of $39.8 million and earnings per share of $1.11, we posted the best results in our Company’s history.
Importantly, we maintained our strong focus on safety while achieving this growth. We don’t just talk safety at North American. We live it.
Heavy Construction and Mining
Our Heavy Construction and Mining operations led the way in fiscal 2008, with our strong oil sands position helping us achieve record segment revenue of $626.6 million and record segment profit of $105.4 million.
We installed new shovel capacity and significantly ramped up production under our 10-year overburden removal contract with Canadian Natural Resources Limited (Canadian Natural). In addition, we responded to increased demand for site services under our master services agreements with Syncrude Canada Ltd. (Syncrude) and Albian Sands Ltd. (Albian). While building business with these existing customers, we also secured a major new oil sands customer in Petro-Canada. Consistent with our “first in, last off” strategy, we are now providing early clearing, site preparation and construction services to Petro-Canada’s new Fort Hills’ project.
Beyond the oil sands, our contract with De Beers for the Victor Project in northern Ontario provided significant revenue for the mining side of the segment in fiscal 2008. Although this contract is now completed, we have developed a good relationship with De Beers – a company that is continuing to expand its operations in Canada.
On the construction side of the segment, our results reflected our continued expansion into general contracting. During fiscal 2008, we successfully completed a sizeable design-build contract for Albian’s onsite aerodrome, serving as general contractor on the entire project. We were also selected as the primary contract to manage site preparation, underground utilities and piling at Suncor’s Millennium Naphtha Unit project, as well as underground utilities and piling at the Voyageur site.
Piling
Our Piling segment also achieved excellent results, generating revenue of $162.4 million and segment profit of $45.4 million. Large-scale oil sands projects contributed to this growth with a 10,000 pile contract at Shell’s Scotford upgrader facility and contracts for a total of approximately 9,000 piles at Suncor’s Millennium and Voyageur sites getting underway during the year.
The Piling division’s results were further bolstered by continuing strong public and commercial construction activity in BC, Alberta and Saskatchewan. Two acquisitions, one in late fiscal 2007 and one in early fiscal 2008, helped us respond to these robust market conditions. The first acquisition brought us the expertise and proprietary technology for micro-piling, a system for installing high density, small-diameter piles into areas where access is challenging. The second acquisition established our presence in northern Saskatchewan, an area that is experiencing rapid development due to resource exploration.
04 Letter to Shareholders North American Energy Partners Inc.

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Another highlight for the Piling division was increasing success with our Continuous Flight Auger (CFA) strategy. We first introduced this low-impact technology in 2004, securing the expertise to execute CFA projects effectively. Demand from customers and communities for environmentally friendly operating practices is increasing and awareness and acceptance for CFA technology is gaining momentum in response. As the only piling company in Western Canada with purpose-built CFA equipment, we are benefiting from our market lead with this new technology. Demand has now grown to the point where we are buying additional equipment to expand our capability.
Pipeline
One of our most satisfying achievements in fiscal 2008 was restoring our Pipeline division to profitability. After incurring losses in fiscal 2007 and early fiscal 2008 on two legacy fixed-price contracts, we refocused our bidding strategy and began work on the TMX Anchor Loop project under a contract with Kinder Morgan.
Governed by a cost-reimbursable contract, the TMX Anchor Loop project helped boost Pipeline division revenue by 327 per cent to $200.7 million and resulted in segment profits of $25.5 million. The project also demonstrated our ability to lay large diameter pipeline through environmentally sensitive locations and in the harsh northern Canadian climate. By year-end we had all but completed the Jasper Park section of the pipe, by far the most sensitive section, and we left the area with accolades from Jasper Park residents and Parks Canada staff. We are now beginning work on the BC side of the project and expect to complete our contract on schedule in October 2008.
Enhancing Execution
While strong demand from the resource and construction sectors was the key factor in our fiscal 2008 revenue results, solid execution helped us carry the gains through to our bottom line. Across our operations, our frontline operators and supervisors applied their know-how and drive to getting the job done right. Behind the scenes, we ensured we had the systems, information, training and leadership support in place to help our people achieve a high level of productivity.
As part of our ongoing business improvement program, we enhanced our employment processes to attract the right people and ensure their proper integration into our business. We also expanded our internal leadership program in fiscal 2008, preparing our people to move up the ladder while also ensuring we have an excellent pool of supervisors and managers to draw on down the road. Additionally, we improved our communications to employees by hiring an employee communications specialist and diversifying our methods of communications.
At the executive level, we brought significant new bench strength to our Finance department with the appointments of Peter Dodd as Chief Financial Officer and David Blackley as Vice President, Finance. Peter and David have assumed responsibility for guiding our financial strategies and improving our financial controls and reporting, respectively. We also announced the appointment of Chris Yellowega to the newly created position of Vice President, Major Mining Developments. By leading North American’s involvement in the major upcoming oil sands mining projects, Chris has freed others on the executive team to maintain their focus on execution of our existing projects.
Looking Ahead
Going forward one of our key objectives will be to sustain our strong performance as we pursue opportunities in each of our operating segments.
In the oil sands, Shell has announced a $27 billion expansion, Petro-Canada plans to spend $14 billion on Phase One of its Fort Hills project and Suncor has announced it will spend another $20 billion at its Voyageur and Millennium sites. There are other new projects in the planning phases, in addition to those already underway in the region.
Our outlook for the Pipeline business is also very promising. While we anticipate a temporary slowdown in activity when the TMX Anchor Loop project winds down in October, we believe that there are a diverse range of new opportunities
North American Energy Partners Inc. Letter to Shareholders 05

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ahead. More than five major new pipeline projects are currently being planned for Western Canada to relieve limited capacity and accommodate growing oil sands production. As the contractor that secured and is successfully executing the demanding TMX Anchor Loop project – the largest pipeline project to be undertaken in Canada in over 20 years – we believe we are well positioned to compete for some of the new projects coming to tender.
Heavy Construction and Mining (left inset photo): The addition of a Bucyrus cable shovel helped us ramp up overburden removal for Canadian Natural Resources Ltd.
Piling (centre inset photo): Large-scale oil sands projects required installation of tens of thousands of piles in fiscal 2008.
Pipeline (right inset photo): The TMX Anchor Loop project is showcasing our expertise with large-diameter pipe installation.
At the same time, robust conditions in the commercial and public construction markets are providing new opportunities for our piling and heavy construction businesses. The Alberta government’s announcement of over $120 billion in infrastructure spending over the next 20 years adds to the potential pool from which we can seek work.
How will we respond to these growth opportunities?
In recent years, we have relied on organic growth to keep pace with rapidly growing demand. As an example, we added over $125 million of new equipment (including light trucks) and hired over 749 new permanent employees in fiscal 2008. We will continue pursuing organic growth in 2009 and we already have a large line-up of new equipment on order. In addition, we will be seeking acquisition and joint venture opportunities that help us achieve specific goals. This could include targets that help us respond to specific oil sands opportunities or that enhance our diversification by increasing our focus on other resource industries.
Implementation of our business improvement program will also continue in 2009 as we focus on project execution and cost reduction and respond to the demand for skilled project management that rapid growth has placed on our Company. Our goal? To be the very best service provider to customers in Canada’s oil sands, resource and construction sectors and to reward our shareholders with steadily improving performance.
At the close of an exceptional year, I want to thank our employees for their contribution to not just a record financial year but also a safe year. We benefit from one of the strongest, most capable teams in the West and I thank you for your hard work. My appreciation also goes to our Directors, who are providing strong support and excellent guidance as we grow and transform our business and to our customers for allowing us to be your partners. Finally, I thank our shareholders for recognizing that we have both the opportunity to grow and the power to perform. We plan to keep performing for you in 2009.
Rod Ruston
President and Chief Executive Officer
06 Letter to Shareholders North American Energy Partners Inc.

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Heavy Construction and Mining Services
· Design and constructability reviews
· Mine site preparation (road building, crusher pocket construction, etc.)
· Overburden removal
· Hard rock mining (open pit mining)
· Mine site reclamation
· Construction management
· Construction site preparation
(muskeg removal, site dewatering, site preparation)
· Underground utility installation
· Construction of processing plants and related facilities infrastructure
· Construction of airstrips

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Heavy Construction and Mining Division
Tough Enough for the Oil Sands
There’s nothing easy about operating in the oil sands. The weather is harsh with winter lasting half the year and temperatures routinely dipping below minus 40 degrees Celsius. Ground conditions are unforgiving, particularly in the spring when the soil turns to mud. The projects are huge and the stakes are high as producers move forward on multi-billion dollar investments. In this environment, a service provider had better know the terrain and no one knows it better than us.
Caterpillar D11R dozer at work at Canadian Natural’s Horizon mine.
North American Energy Partners has been operating in the Alberta oil sands for over three decades. In that time we have gained an incredible depth and breadth of experience, along with a clear understanding of what it takes to execute effectively in this environment.
It starts with a fleet that can match the conditions and scale of the projects the oil sands attract. We operate by far the largest equipment fleet of any contractor in the region with over 800 pieces of heavy equipment and just as many support vehicles. We added to this base in fiscal 2008 with the addition of 24 new haul trucks and a Bucyrus cable shovel, which went into service in March 2008. Electrically operated and with an 85 cubic yard shovel capacity, the Bucyrus is one of the world’s largest mining shovels, capable of moving the equivalent of some 120 tonnes per pass. We are the only contractor in Fort McMurray with this type of digging and loading capacity.
Matching qualified operators to our equipment is another vital requirement and one that we excel at. We hired and/or rehired and trained 1,276 equipment operators during fiscal 2008, with our reputation for industry- leading training and safety programs helping us attract the best. “Safety first” is a key focus for North American Energy Partners as we ensure our standards are maintained despite the dramatic increase in both our project activity and our employee base.
While the right equipment, knowledge and people are the building blocks to oil sands success, ultimately the
Heavy Construction and Mining Division Highlights – Fiscal 2008

• |  | Achieved record revenue of $626.6 million, a 32 per cent improvement over fiscal 2007
• |  | Achieved record segment profit of $105.4 million, 48 per cent better than in fiscal 2007
• |  | Expanded haul truck fleet with the addition of 24 new trucks
• |  | Commissioned a Bucyrus electric cable shovel at Canadian Natural’s Horizon Mine
• |  | Completed Albian aerodrome project in 39 weeks from mobilization to demobilization
• |  | Completed a three-year contract with De Beers at the Victor Project diamond mine in northern Ontario
• |  | Completed the fourth year of our 10-year, $1.2 billion overburden removal contract at Canadian Natural’s Horizon Mine
• |  | Provided site services under our multi-year, master services agreements with Syncrude and Albian
• |  | Selected as primary contractor to manage all site preparation, underground utilities and piling construction at Suncor’s Millennium Naphtha Unit and Voyageur sites under a five-year site services contract
• |  | Selected to provide early clearing, site preparation and construction services at Petro-Canada’s new Fort Hills project
• |  | Selected for one-year overburden removal contract at Syncrude’s Aurora mine
• |  | Executed 12 projects under our joint venture agreement with Fort McKay First Nations

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demonstrated ability to execute effectively is essential to earning the trust of customers. That trust can only be earned over time.
Many of our customer relationships date back to the earliest days of oil sands development. We have grown alongside producers like Suncor and Syncrude and expanded our service offering in step with customer needs. From pre-planning, to site preparation, to road building, to underground work for buildings and plants, to pilings for foundations, to mine construction and ongoing mining operations, right through to eventual land reclamation, our strategy, driven through the breadth of our services, is to be the first contractor on the site and the last off. In many cases, that’s precisely what happens. For example, we put the finishing touches on a land reclamation project for Syncrude in fiscal 2008, coming full circle in an area that we helped to prepare for mining over 20 years ago. Now we are beginning the cycle again as existing mines open new areas for extraction and new customers like Petro-Canada enter the oil sands.
Our close involvement in our customers’ businesses continues to grow. Whereas oil sands producers originally relied on North American to supplement their own in-house fleets, some of our customers are now outsourcing significant portions of their operational requirements to third parties. In 2005, Canadian Natural Resources Limited became the first oil sands producer to contract out its entire overburden mining operation when it awarded North American Energy Partners a 10-year contract for overburden removal. That decision has helped to lower Canadian Natural’s capital costs and enabled them to keep their focus squarely on the construction and start-up of their oil sands project. Some of the new producers preparing to enter the oil sands are reviewing this model carefully and appear poised to follow suit.
A similar trend is emerging on the industrial construction side of our business with customers inviting us to take on a larger role in their projects. During fiscal 2008, we served as general contractor on Albian Sands’ aerodrome project, which was built to accommodate direct air service to Albian’s Expansion One site. We were responsible for all aspects of the design and construction of the project, which included an airstrip capable of landing an Airbus 319, terminal buildings and other ancillary operations. Although a complex project, it proceeded smoothly and we successfully completed the aerodrome on schedule.
With some 2,000 workers, managers, contractors and visitors coming and going from Albian’s oil sands projects each year, regular air access to the site is a necessity. Albian contracted North American to design and build a private onsite aerodrome in 2008, complete with a 2.3 km paved runway capable of accommodating an Airbus A319, together with associated taxi-ways, apron, terminal, control tower and support facilities. North American served as general contractor on the project, bringing it in right on schedule.
10 Operations Review North American Energy Partners Inc.

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North America Energy Partners was responsible for all aspects of the design and construction of the Albian Sands’ aerodrome, which included an airstrip capable of landing an Airbus 319.

Our reputation for successfully managing complete projects in demanding environments has not only enhanced our reputation within the oil sands sector but is also helping to build our reputation beyond. Three years ago, we were selected by De Beers to provide site preparation services at its remote Victor Project in northern Ontario. Although some distance from our traditional operating region, De Beers was confident we could manage the project effectively. We did and were rewarded with an expansion in our contract. In addition to providing traditional site preparation and mining services, De Beers asked us to build its airstrip, construct and maintain the 300-kilometer winter road and install a water pipeline at the site. The contract was completed successfully in fiscal 2008 and we emerged with an excellent working relationship with the De Beers’ Canadian operations team.
More recently we were approached by another mining company, Baffinland Iron Mines Corp., largely because of our reputation for operating effectively in harsh climates. Baffinland is in the early planning stages for an iron ore operation in Canada’s extreme north. We are now closely involved in the pre-planning and constructability processes with this customer.
Tough enough to handle harsh environments. Experienced enough to execute effectively. Diverse and trusted enough to play a key role in our customers’ businesses. These qualities have made us one of the leading service suppliers to the Alberta oil sands and a valued supplier to customers in the broader Canadian resource industry.
Revenue (in millions)
$626.6 in 2008
$473.2 in 2007
$366.7 in 2006
Profit (in millions)
$105.4 in 2008
$71.1 in 2007
$50.7 in 2006
North American Energy Partners Inc. Operations Review 11

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Piling Division
Foundations for Growth
Across Western Canada’s diverse landscape, most structures depend on piling or shoring to provide foundational support. Getting this component right and on time is a critical step in the construction process and builders count on us to give their projects a sound footing. North American is one of the two largest piling and shoring wall contractors in Western Canada, with a reputation for being able to provide effective solutions in almost any type of terrain or circumstance.
From small micropiles that let us provide support in incredibly tight spaces, to vast fields of driven and drilled piles used to support massive oil sands processing plants, our repertoire of services and techniques is nearly as diverse as the customer base we serve.
In recent years, our Piling division has grown rapidly in response to both the oil sands development and the building boom occurring across Western Canada. During fiscal 2008, we drove tens of thousands of piles as we created foundations for major upgrader and oil sands projects. We also worked on a variety of commercial and public construction projects, including demanding projects like the Olympic Speed Skating Oval in Richmond, British Columbia. This project required us to use a range of piling methods to overcome soil challenges at the site.
One of the highlights of our year was dramatically increasing revenue in the Saskatchewan market as we took advantage of that province’s strong economy to grow the Saskatoon-based screwpile business we acquired earlier in the year. Calgary, Edmonton and Regina were also growth markets for us in fiscal 2008.
While revenue from our Piling division grew by 49 per cent in fiscal 2008, our profit margins were a little lower than those achieved in fiscal 2007. This reflected the impact of fewer fixed-price contracts, which can provide higher margins when the work is executed without
North American Energy Partners drilled 2,300 concrete piles at the Froth Treatment Plant at Albian.
Revenue (in millions)
$162.4 in 2008
$109.3 in 2007
$91.4 in 2006
Profit (in millions)
$45.4 in 2008
$34.4 in 2007
22.6 in 2006
Piling Division Highlights – Fiscal 2008

• |  | Achieved record revenue of $162.4 million, 49 per cent higher than in 2007
• |  | Achieved record segment profit of $45.4 million, 32 per cent better than in 2007
• |  | Installed 8,000 piles at Shell’s Scotford Upgrader Expansion in Edmonton, part of a 10,000 pile contract
• |  | Installed 2,500 piles at Suncor’s Voyageur Upgrader site, part of an 8,000 pile contract
• |  | Installed 3,200 piles at Suncor’s Millenium site
• |  | Benefited from continued strong commercial construction markets in Western Canada
• |  | Grew market share in the Saskatchewan market
• |  | Continued to build market acceptance for Continuous Flight Auger technology

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Three years ago, North American became the first company in Western Canada to introduce an innovative European piling technology that installs piles with no vibration and scarcely any noise. Called Continuous Flight Augering (CFA), this drill-based method has been winning over clients and their engineering firms because it works every bit as well as traditional methods, while dramatically reducing construction noise and impact. With the market’s only purpose-built CFA equipment and three years of experience, North American is ideally positioned to respond to the growing demand for this excellent new technology.

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Piling Services

· Driven piles

· Drilled piles

· Screw piles

· Micropiles

· Continuous Flight Auger

· Caissons

· Earth retention

· Soil densification

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the built-in risk factors being realized. It also reflects an increase in our driven pile work which came at the expense of the higher-margin drilled pile work we attracted in fiscal 2007. At 28 per cent, however, the division’s margins remain very attractive.
As we move forward, our Piling division is well positioned for continued growth. Interest in a new piling technology, called Continuous Flight Auger, or CFA, is gaining momentum as engineers and builders become more aware of its ability to speed up piling installation in poor soils, dramatically reduce construction noise and virtually eliminate the ground vibration caused when other piling techniques are used. Rather than pounding piles into soil, the CFA method uses specialized equipment to drill a hole and then immediately fill it with concrete while withdrawing the drill bit. North American Energy Partners was the first to introduce CFA technology in Western Canada, bringing the technology over from Europe in 2004. During fiscal 2008, we increased both our CFA equipment fleet and marketing efforts and landed 19 CFA contracts, compared to just three in fiscal 2007. With significantly greater demand expected in fiscal 2009, we intend to increase our CFA capacity another 50% next year. Over time, we expect that CFA will become increasingly popular because of its ability to get the job done quickly and with minimal impact. We intend to make the most of this high-margin opportunity by remaining Western Canada’s recognized leader in CFA technology.
The oil sands are providing additional opportunities for growth, with major new projects coming online and expected to generate new construction demand. The commercial and public construction sectors are also expected to remain robust with Western Canada’s resource-rich economy continuing to grow and major infrastructure projects getting underway across the West.
With the capacity to take on projects of almost any size, the diversity to work on many different types of projects and the know-how to overcome complex soil challenges, we believe we can benefit from this growth and we continue to expand this thriving division.
Over 1,000 concrete piles were drilled at Suncor’s Millennium Naphtha Unit.
North American Energy Partners Inc. Operations Review 15

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Pipeline Division
Back to Black in Pipeline
It takes a particular brand of toughness to succeed in the pipeline business. Projects are typically large and intense, often commanding a pipeline installer’s entire capacity for the duration of the contract. In Canada, weather and terrain challenges can and do create significant hurdles to progress. Mix in an industry tradition of awarding fixed-price contracts and the risks grow higher.
Is it a business worth pursuing given these realities? In fiscal 2008 we decisively demonstrated that it is. Our pipeline division led the Company in revenue and profit growth as we successfully executed our contract with Kinder Morgan on the TMX Anchor Loop Project.
Our success stood in sharp contrast to fiscal 2007 when our pipeline business posted losses on two fixed-price contracts. The decision to change our bidding and contracting strategy was a key factor in this improvement. Under our new approach, our Pipeline division now focuses primarily on cost-reimbursable contracts and considers fixed-price contracts only where we have extensive and detailed knowledge of the terrain and full control over our productivity.
The Kinder Morgan contract fits this new strategy. With an original contract value of $185 million, this is the largest pipeline project executed in Canada in the past two decades and it was awarded to us on a time-and-materials basis. The project involves twinning (or looping) a 158 kilometer section of the existing Trans Mountain pipeline system between Hinton, Alberta and Jackman, British Columbia. The route winds through mountainous terrain and involves over 104 watercourse crossings and adherence to rigorous environmental guidelines, particularly in the areas where the pipeline passes through Jasper National Park and Mount Robson Provincial Park.
Mountains, multiple river crossings, severe weather and a traverse across one of Canada’s most prized national parks were just some of the challenges facing North American as we lay pipe on Kinder Morgan’s TMX Anchor Loop Project in fiscal 2008. The project, which has received accolades from the residents and staff of Jasper National Park, showcased our ability to bring effective, environmentally sensitive solutions to an extremely demanding pipeline contract.
Tackling the project required a significant build-up of our pipeline capabilities. We expanded our roster with over 700 new pipeline employees ranging from operators to engineers to environmental and safety specialists. With our team in place, work on the project began in fiscal 2007 and we carried out the most significant portion of the installation in fiscal 2008.
Pipeline Division Highlights – Fiscal 2008

• |  | Led the company in revenue and profit growth in fiscal 2008
• |  | Achieved record revenue of $200.7 million, 327 per cent higher than in fiscal 2007
• |  | Achieved record segment profit of $25.5 million, compared to a loss of $10.5 million in 2007
• |  | Completed legacy fixed-price contracts
• |  | Successfully refocused bidding strategy to reduce reliance on fixed-price contracts
• |  | Completed a significant portion of the work on the TMX Anchor Loop Project pipeline contract with Kinder Morgan

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Installation of 36 inch pipeline in the Mt. Robson Provincial Park for the TMX Anchor Loop Project.
Results to date have confirmed our ability to execute a large and highly complex pipeline contract under intense scrutiny. The work completed in Jasper National Park won the appreciation of residents and Parks Canada staff, who praised us for the high quality of our work and our restoration of affected areas. The Jasper section was also completed ahead of schedule, enabling our customer to put the new capacity to work early. We will continue to focus on strong project execution as we complete the final leg of the project through the summer and early fall of fiscal 2009.
Going forward, we believe our success on the TMX Anchor Loop project enhances prospects for our Pipeline division. With Western Canada’s existing pipelines already at capacity and oil sands production increasing at a rapid rate, a number of new pipeline construction and expansion projects have been announced to address the capacity shortfall. Our work on the TMX Anchor Loop project has demonstrated our ability to execute successfully on a large and complex project and established our position as a serious player in Western Canada’s pipeline construction business. Combined with our new bidding strategy, we believe we have laid the foundation for continued profitable growth.
Revenue (in millions)
$200.7 in 2008
$47.0 in 2007
$34.1 in 2006
Profit (in millions)
$25.5 in 2008
$(10.5) in 2007
$9.0 in 2006
18 Operations Review North American Energy Partners Inc.

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Management’s Discussion and Analysis
The following discussion and analysis is as of June 20, 2008 and should be read in conjunction with the attached audited consolidated financial statements for the fiscal year ended March 31, 2008, which have been prepared in accordance with Canadian generally accepted accounting principles (GAAP) and reconciled to US GAAP. These financial statements and additional information relating to our business, including our AIF, are available on SEDAR at www.sedar.com and EDGAR at www.sec.gov. Except where otherwise specifically indicated, all dollar amounts are expressed in Canadian dollars.
June 20, 2008
Prior Year Comparisons
On November 28, 2006 we completed an initial public offering (“IPO”) of common shares in Canada and the U.S. We became publicly traded on the Toronto Stock Exchange and New York Stock Exchange under the symbol “NOA”. Prior to the consummation of the IPO, the predecessor company was amalgamated with its parent companies and we undertook certain transactions that resulted in changes to our capital structure. Upon completion of the IPO, we used the proceeds to undertake related transactions, which further changed our capital structure. These transactions included the repayment of all our outstanding senior secured notes, due in 2010, for a total payment of $77.8 million and the repayment of the $27.0 million of promissory notes issued in respect of the repurchase of the NACG Preferred Corp. Series A preferred shares. We also used proceeds from the IPO to purchase $44.6 million of equipment under operating leases. As a result, comparisons of current periods to prior periods are impacted by the amalgamation and capital restructuring transactions.
A. Business Overview and Strategy
Business Overview
We are a leading resource services provider to major oil, natural gas and other natural resource companies, with a primary focus on the Alberta oil sands. We provide a wide range of mining and site preparation, piling and pipeline installation services to our customers across the entire lifecycle of their projects. We are the largest provider of contract mining services in the oil sands area and we believe we are the largest piling foundations installer in Western Canada. In addition, we believe that we operate the largest fleet of equipment of any contract resource services provider in the oil sands. Our total fleet includes 845 pieces of diversified heavy construction equipment supported by over 925 ancillary vehicles. While our expertise covers heavy earth moving, site preparation, underground industrial piping, piling and pipeline installation in any location, we have a specific capability operating in the harsh climate and difficult terrain of the oil sands and Northern Canada.
We believe that our significant knowledge, experience, equipment capacity and scale of operations in the oil sands differentiate us from our competition. We provide services to every company in the Alberta oil sands that uses surface mining techniques in their production. These surface mining techniques account for over 65% of total oil sands production. We also provide site construction services for in-situ producers, which use horizontally drilled wells to inject steam into deposits and pump bitumen to the surface.
Our principal oil sands customers include all three of the producers that are currently mining bitumen in Alberta: Syncrude Canada Ltd. (Syncrude), Suncor Energy Inc. (Suncor) and Albian Sands Energy Inc. (Albian), a joint venture among Shell Canada Limited, Chevron Canada Limited and Marathon Oil Canada Corporation. We are also working with customers that are in the process of developing bitumen-mining projects, including Canadian Natural Resources Limited (Canadian Natural) and Petro-Canada Fort Hills (a joint venture between UTS Energy, Teck Cominco and Petro-Canada).
We have long-term relationships with most of our customers. For example, we have been providing services to Syncrude and Suncor since they pioneered oil sands development over 30 years ago. Approximately 39% of our revenues in fiscal 2008 were derived from recurring work and long-term contracts, which assist in providing stability in our operations.
Our Heavy Construction and Mining division successfully completed the development of a diamond mine site in 2008. This three-year project demonstrated our ability to operate effectively in a remote location under difficult weather conditions. We believe that we demonstrated our ability to successfully export knowledge and technology gained in the oil sands and put it to work in other resource development projects across Canada. As a result of our work in this area, we believe we have attracted the attention of resource developers and we are currently looking at other potential projects, including those in the high Arctic regions.
Our Piling division installs all types of driven, drilled and screw piles, caissons, earth retention and stabilization systems. Operating throughout Western Canada, this division has a solid record of performance on both small and large-scale projects. Our Piling division also has experience with industrial projects in the oil sands and related petrochemical and refinery complexes and has been involved in the development of commercial and infrastructure projects.
North American Energy Partners Inc. Management’s Discussion and Analysis 19

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Our Pipeline division installs penstocks as well as steel, fiberglass, and plastic pipe in sizes up to 52” in diameter. This division is experienced with jobs of varying magnitude for some of Canada’s largest energy companies. Our experience includes the recent construction of a new pipeline that goes through the Rockies. This project involves the construction of a 160 kilometre pipeline for Kinder Morgan’s Transmountain Crossing (TMX) through ecologically sensitive environments, including Jasper National Park, with minimal impact to the environment.
Canadian Oil Sands
Oil sands are grains of sand covered by a thin layer of water and coated by heavy oil, or bitumen. Bitumen, because of its structure, does not flow, and therefore requires non-conventional extraction techniques to separate it from the sand and other foreign matter. There are currently two main methods of extraction: open pit mining, where bitumen deposits are sufficiently close to the surface to make it economically viable to recover the bitumen by treating mined sand in a surface plant; and in-situ, where bitumen deposits are buried too deep for open pit mining to be cost effective, and operators instead inject steam into the deposit so that the bitumen can be separated from the sand and pumped to the surface. We currently provide most of our services to companies operating open pit mines to recover bitumen reserves. These customers utilize our services for surface mining, site preparation, piling, pipe installation, site maintenance, equipment and labor supply and land reclamation.
Oil Sands Outlook
On October 25, 2007, the Alberta government announced increases to the Alberta royalty rates affecting natural gas, conventional oil and oil sands producers. The announced increases were significant but lower than increases recommended to the government by the Royalty Review Panel. While some of our customers have announced their intentions to reduce oil and gas investment in Alberta as a result of the increased royalties, to date, the areas affected by these investment reductions do not include oil sands mining projects. Given the long-term nature and capital investment requirement to develop an oil sands mining operation, we anticipate that there is limited risk that the royalty changes will cause our customers to cancel, delay or reduce the scope of any significant mining developments currently underway.*
We are continuing to experience increasing requests for services under existing contracts with our major oil sands customers, in spite of the recent royalty changes. Our recent acquisitions of new equipment ideally suited to heavy earth moving in the oil sands area, together with the addition of a significant number of new employees, has strengthened our ability to bid competitively and profitably into this expanding market and we have secured contract wins on many of these new projects.
Demand for our services is primarily driven by the development, expansion and operation of oil sands projects. The oil sands operators’ capital investment decisions are driven by a number of factors, with what we believe is one of the most important being the expected long-term price of oil. The development, expansion and operation of oil sands projects, related public infrastructure spending and the commercial construction activity in Western Canada play a key role in influencing our business activities.
According to the Canadian Association of Petroleum Producers, or CAPP, approximately $55.2 billion was invested in the oil sands from 1998 through 2006. According to the Canadian Energy Research Institute’s (CERI) November 2007 report, “Canadian Oil Sands Supply Costs and Development Projects (2007 – 2027)”, an additional $228 billion of capital expenditures will be required between 2007 and 2015 to achieve production levels projected under their “constrained” scenario. According to the CERI, as of November 2007, there were 23 mining and upgrader projects in various stages, ranging from announcement to construction, with start-up dates through 2014. Beyond 2014, several new multi-billion dollar projects and a number of smaller multimillion dollar projects are being considered by various oil sands operators. We intend to pursue business opportunities from these projects.*
Strategy
Our strategy is to be an integrated service provider for the developers of resource-based industries in a broad and often challenging range of environments. This strategy is focused on the following priorities:*

• |  | Capitalize on growth opportunities in the Canadian oil sands: We intend to build on our market leadership position and successful track record with our customers to benefit from any continued growth in this market. We intend to increase our fleet size to be ready to meet the challenges from projected growth in the oil sands.
• |  | Leverage our complementary services: Our complementary service segments, including site preparation, pipeline installation, piling and other mining services allow us to compete for many different forms of business. We intend to build on our “first-in” position to cross-sell our other services and pursue selective acquisition opportunities that expand our complementary service offerings.

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

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

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• |  | Increase our recurring revenue base: We provide services both during the construction phase and once the project is in operation. These mining services include overburden removal, reclamation, road construction and maintenance and mining services.
• |  | Leverage our long-term relationships with customers: Several of our oil sands customers have announced their intentions to increase their production capacity by expanding the infrastructure at their sites. We intend to continue to build on our relationships with these and other existing oil sands customers to win a substantial share of the heavy construction and mining, piling and pipeline services outsourced in connection with these projects.
• |  | Increase our presence outside the oil sands: We intend to increase our presence outside the oil sands and extend our services to other resource industries across Canada. Canada has significant natural resources and we believe that we have the equipment and the experience to assist those companies as they develop natural resources.
• |  | Enhance operating efficiencies to improve revenues and margins: We aim to increase the availability and efficiency of our equipment through enhanced maintenance, providing the opportunity for improved revenue, margins and profitability.

Operations
As discussed above, we provide our services through three interrelated yet distinct business units: (i) Heavy Construction and Mining, (ii) Piling and (iii) Pipeline. Our services include initial advice and consulting to customers as they develop plans to exploit resources. We believe that we have the skills and equipment to build infrastructure in new locations (or to expand existing sites) for heavy construction projects. We are currently involved in assisting with on-site mining services, overburden removal and plant upgrades. We are also able to respond to customer needs for site reclamation services once a site’s resources are depleted.
The table below shows the revenues generated by each operating segment for the fiscal years ended March 31, 2006 through March 31, 2008:

|  | Year Ended March 31, |
|  |  |  |  |  | % of |  |  |  |  |  |  | % of |  |  |  |  |  |  | % of |
(dollars in thousands) |  | 2008 |  |  | Total |  |  | 2007 |  |  | Total |  |  | 2006 |  |  | Total |
Revenue by operating segment: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Heavy Construction and Mining |  |  | $626,582 |  |  |  | 63.3% |  |  |  | $473,179 |  |  |  | 75.2% |  |  |  | $366,721 |  |  |  | 74.5% |
Piling |  |  | 162,397 |  |  |  | 16.4% |  |  |  | 109,266 |  |  |  | 17.4% |  |  |  | 91,434 |  |  |  | 18.6% |
Pipeline |  |  | 200,717 |  |  |  | 20.3% |  |  |  | 47,001 |  |  |  | 7.5% |  |  |  | 34,082 |  |  |  | 6.9% |
Total |  |  | $989,696 |  |  |  | 100.0% |  |  |  | $629,446 |  |  |  | 100.0% |  |  |  | $492,237 |  |  |  | 100.0% |

B. Financial Results
Consolidated Results

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

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

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

• |  | do not reflect our cash expenditures or requirements for capital expenditures or capital commitments;
• |  | do not reflect changes in, or cash requirements for, our working capital needs;
• |  | do not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;
• |  | exclude tax payments that represent a reduction in cash available to us; and
• |  | do not reflect any cash requirements for assets being depreciated and amortized that may have to be replaced in the future.

Consolidated EBITDA per bank excludes unrealized foreign exchange gains and losses and realized and unrealized gains and losses on derivative financial instruments, which, in the case of unrealized losses, may ultimately result in a liability that will need to be paid and in the case of realized losses, represents an actual use of cash during the period. A reconciliation of net income (loss) to EBITDA and Consolidated EBITDA per bank is as follows:

|  | Year Ended March 31, |
(dollars in thousands) |  | 2008 |  |  | 2007 |  |  | 2006 |
Net income (loss) |  |  | $ 39,784 |  |  |  | $21,079 |  |  |  | $(21,941 | )
Adjustments: |  |  |  |  |  |  |  |  |  |  |  |
Interest expense |  |  | 27,019 |  |  |  | 37,249 |  |  |  | 68,776 |
Income taxes |  |  | 17,379 |  |  |  | (2,593 | ) |  |  | 737 |
Depreciation |  |  | 36,729 |  |  |  | 31,034 |  |  |  | 21,725 |
Amortization of intangible assets |  |  | 1,071 |  |  |  | 582 |  |  |  | 730 |
EBITDA |  |  | $121,982 |  |  |  | $87,351 |  |  |  | $ 70,027 |
Adjustments: |  |  |  |  |  |  |  |  |  |  |  |
Unrealized foreign exchange loss (gain) on senior notes |  |  | (24,788 | ) |  |  | (5,017 | ) |  |  | (14,258 | )
Realized and unrealized loss (gain) on derivative financial instruments |  |  | 34,075 |  |  |  | (196 | ) |  |  | 14,689 |
Loss (gain) on disposal of plant and equipment and assets held for sale |  |  | 179 |  |  |  | 959 |  |  |  | (733 | )
Stock-based compensation |  |  | 1,991 |  |  |  | 2,101 |  |  |  | 923 |
Director deferred stock unit expense |  |  | (190 | ) |  |  | – |  |  |  | – |
Write-off of deferred financing costs |  |  | – |  |  |  | 4,342 |  |  |  | 1,774 |
Write-down of other assets to replacement cost |  |  | 1,845 |  |  |  | 695 |  |  |  | – |
Consolidated EBITDA per bank |  |  | $135,094 |  |  |  | $90,235 |  |  |  | $ 72,422 |

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

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Analysis of Results:
Demand for our services continued to grow in fiscal 2008 with a high volume of project work in the Alberta oil sands, increased activity on a major pipeline project and strong commercial construction markets in Western Canada contributing to record results. For the 12 months ended March 31, 2008, our consolidated revenue increased to $989.7 million, $360.3 million (or 57.2%) higher than in fiscal 2007 and $497.5 million (or 101%) higher than fiscal 2006.
The Heavy Construction and Mining segment was a significant contributor to this growth with division revenue up $153.4 million from 2007 and $259.9 million higher than in 2006. Robust oil sands activity, including the ramp-up of the overburden removal contract with Canadian Natural, helped to support these results, offsetting the effect of the completion of a significant contract with the De Beers’ mine in northern Ontario. The Pipeline segment also had a strongly positive impact, with revenue up $153.7 million compared to fiscal 2007 and $166.6 million compared to fiscal 2006 as work progressed on the Kinder Morgan TMX project. The Piling segment contributed the balance of the consolidated revenue growth as it responded to oil sands and commercial construction opportunities in Western Canada.
Projects costs of $592.5 million represented 59.9% of total revenue in fiscal 2008, up from 57.8% last year. This increase reflected the higher volumes in our Pipeline operations, which use more subcontractors than our other business segments. Subcontractor costs were also higher on the Albian airstrip and Suncor Millenium Naphtha Unit projects reflecting our role as general contractor. Overall equipment costs also increased in fiscal 2008 reflecting higher levels of fleet activity and tire cost inflation resulting from shortages of some types of tires. Subsequent improvements in our tire procurement and consumption practices, along with an easing of tire supply in the market, helped to reduce tire costs in the latter part of fiscal 2008.
Gross profit margin increased to 16.5% in fiscal 2008, from 14.7% last year. This improvement primarily reflects the return to profitability in our Pipeline operations and a favourable project mix in the Heavy Construction and Mining segment. Margins increased slightly compared to 2006 with gains in the Pipeline and Heavy Construction and Mining segments offsetting a decline in Piling margins. Piling margins returned to a more sustainable level in 2008 after benefiting from an unusually profitable project mix in 2007.
Fiscal 2008 general and administrative costs (G&A) were $69.7 million, an increase of $29.9 million over 2007 and $38.8 million higher than in fiscal 2006. Increased compensation costs, as a result of additions to our salaried workforce, were a significant contributor to this increase. G&A costs also included $1.9 million of costs relating to the secondary offering of common shares in the second quarter.
Net income for the year increased 88.7% to $39.8 million, or $1.11 per share, from $21.1 million, or $0.87 per share in the prior year. Unrealized non-cash gains and losses on foreign exchange and derivative financial instruments reduced net income by $5.5 million, net of tax, compared to a net gain of $6.1 million, net of tax, in the prior year. Excluding these items, basic earnings per share would have been $1.27 per share compared to $0.62 per share in the prior year.
Consolidated Results (Fourth Quarter)

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

(1) |  | Non GAAP Financial measures – see footnote on page 22

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

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

|  | Three Months Ended March 31, |
(dollars in thousands) |  | 2008 |  |  | 2007 |
Net income (loss) |  |  | $22,662 |  |  |  | $1,303 |
Adjustments: |  |  |  |  |  |  |  |
Interest expense |  |  | 6,686 |  |  |  | 7,463 |
Income taxes |  |  | 11,297 |  |  |  | (2,942 | )
Depreciation |  |  | 12,550 |  |  |  | 12,369 |
Amortization of intangible assets |  |  | 305 |  |  |  | 90 |
EBITDA |  |  | $53,500 |  |  |  | $18,283 |
Adjustments: |  |  |  |  |  |  |  |
(Gain) loss on disposal of plant and equipment |  |  | (671 | ) |  |  | 120 |
Unrealized foreign exchange loss (gain) on senior notes |  |  | 7,838 |  |  |  | (2,480 | )
Stock-based compensation |  |  | 968 |  |  |  | 359 |
Director deferred stock unit expense |  |  | (190 | ) |  |  | – |
Write-down of other assets to replacement cost |  |  | – |  |  |  | 695 |
Write-off financing costs |  |  | – |  |  |  | 4,342 |
Realized and unrealized loss (gain) on derivative financial instruments |  |  | (5,691 | ) |  |  | 1,337 |
Consolidated EBITDA per bank |  |  | $55,754 |  |  |  | $22,656 |

Revenues for the three months ended March 31, 2008 (fourth quarter) of $323.6 million were $118.2 million (or 58%) higher than in the same period last year. Strong revenue performance in Heavy Construction and Mining ($45.3 million favourable versus 2007) together with higher Pipeline revenue as a result of the TMX project (up $62.0 million), were key contributors to the year-over-year improvements.
Gross profit of $62.6 million in the fourth quarter of fiscal 2008 (19.3% of revenues in 2008 compared to 6.6% in 2007) was $48.9 million better than in fiscal 2007. The return to profitability in Pipeline (gross profit was $36.0 million higher than in fiscal 2007) was a leading factor in this improvement. Favourable margins in the Heavy Construction and Mining and Piling segments added to the gains. G&A costs of $20.7 million were $11.8 million higher than in the fourth quarter of 2007. The addition of new employees in response to growing demand for our services was the largest contributor to this increase.
Net income of $22.7 million increased by $21.4 million in the fourth quarter of fiscal 2008, driven by the improvements in operating income. Basic earnings per share for the quarter were $0.63 compared to $0.04 per share in the prior year. Unrealized non-cash losses on foreign exchange and unrealized non-cash gains on derivative financial instruments combined to reduce net income by $1.0 million, net of tax, compared a net gain of to $1.4 million, net of tax, in the prior year. Excluding these items, basic earnings per share would have been $0.66 per share compared to $0.00 per share in the prior year.
Segment results
Segmented profit includes revenue earned from the performance of our projects, including amounts arising from approved change orders and claims that have met the appropriate accounting criteria for recognition, less all direct projects expenses, including direct labour, short-term equipment rentals and materials, payments to subcontractors, indirect job costs and internal charges for use of capital equipment.
Heavy Construction and Mining

|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | Year Ended March 31, |
|  |  |  |  |  | % of |  |  |  |  |  |  | % of |  |  |  |  |  |  | % of |
(dollars in thousands) |  | 2008 |  |  | Revenue |  |  | 2007 |  |  | Revenue |  |  | 2006 |  |  | Revenue |
Segment revenue |  |  | $626,582 |  |  |  |  |  |  |  | $473,179 |  |  |  |  |  |  |  | $366,721 |  |  |  |  |
Segment profit: |  |  | $105,378 |  |  |  | 16.8% |  |  |  | $71,062 |  |  |  | 15.0% |  |  |  | $50,730 |  |  |  | 13.8% |

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

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Piling

|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | Year Ended March 31, |
|  |  |  |  |  | % of |  |  |  |  |  |  | % of |  |  |  |  |  |  | % of |
(dollars in thousands) |  | 2008 |  |  | Revenue |  |  | 2007 |  |  | Revenue |  |  | 2006 |  |  | Revenue |
Segment revenue |  |  | $162,397 |  |  |  |  |  |  |  | $109,266 |  |  |  |  |  |  |  | $91,434 |  |  |  |  |
Segment profit: |  |  | $45,362 |  |  |  | 27.9% |  |  |  | $34,395 |  |  |  | 31.5% |  |  |  | $22,586 |  |  |  | 24.7% |

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

|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | Year Ended March 31, |
|  |  |  |  |  | % of |  |  |  |  |  |  | % of |  |  |  |  |  |  | % of |
(dollars in thousands) |  | 2008 |  |  | Revenue |  |  | 2007 |  |  | Revenue |  |  | 2006 |  |  | Revenue |
Segment revenue |  |  | $200,717 |  |  |  |  |  |  |  | $47,001 |  |  |  |  |  |  |  | $34,082 |  |  |  |  |
Segment profit: |  |  | $25,465 |  |  |  | 12.7% |  |  |  | $(10,539 | ) |  |  | -22.4% |  |  |  | $8,996 |  |  |  | 26.4% |

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

|  |  |  |  |  |  |  |  |  | Year Ended March 31, |
|  |  |  |  |  | % of |  |  |  |  |  |  | % of |
(dollars in thousands) |  | 2008 |  |  | Revenue |  |  | 2007 |  |  | Revenue |
Segment revenue |  |  | $195,442 |  |  |  |  |  |  |  | $150,131 |  |  |  |  |
Segment profit: |  |  | $36,747 |  |  |  | 18.8% |  |  |  | $23,512 |  |  |  | 15.7% |

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

|  |  |  |  |  |  |  |  |  | Year Ended March 31, |
|  |  |  |  |  | % of |  |  |  |  |  |  | % of |
(dollars in thousands) |  | 2008 |  |  | Revenue |  |  | 2007 |  |  | Revenue |
Segment revenue |  |  | $40,699 |  |  |  |  |  |  |  | $29,872 |  |  |  |  |
Segment profit: |  |  | $13,637 |  |  |  | 33.5% |  |  |  | $8,822 |  |  |  | 29.5% |

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

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

|  | Year Ended March 31, |
|  |  |  |  |  | % of |  |  |  |  |  |  | % of |
(dollars in thousands) |  | 2008 |  |  | Revenue |  |  | 2007 |  |  | Revenue |
Segment revenue |  |  | $87,459 |  |  |  |  |  |  |  | $25,419 |  |  |  |  |
Segment profit: |  |  | $11,311 |  |  |  | 12.9 | % |  |  | $(9,829 | ) |  |  | -38.7% |

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

|  | Three Months Ended March 31, |  |  | Year Ended March 31, |
(dollars in thousands) |  | 2008 |  |  | 2007 |  |  | 2008 |  |  | 2007 |  |  | 2006 |
Interest expense interest on senior debt |  |  | $5,835 |  |  |  | $5,835 |  |  |  | $23,338 |  |  |  | $27,417 |  |  |  | $28,838 |
Interest on revolving credit facility and other interest |  |  | 399 |  |  |  | 635 |  |  |  | 2,063 |  |  |  | 1,157 |  |  |  | 1,421 |
Interest on capital lease obligations |  |  | 283 |  |  |  | 245 |  |  |  | 780 |  |  |  | 725 |  |  |  | 457 |
Interest on NACG Preferred Corp. Series A preferred shares |  |  | – |  |  |  | – |  |  |  | – |  |  |  | 1,400 |  |  |  | – |
Accretion and change in redemption value of mandatorily redeemable preferred shares |  |  | – |  |  |  | – |  |  |  | – |  |  |  | 3,114 |  |  |  | 34,722 |
Amortization of deferred bond issue costs |  |  | 169 |  |  |  | – |  |  |  | 838 |  |  |  | – |  |  |  | – |
Amortization of deferred financing costs |  |  | – |  |  |  | 748 |  |  |  | – |  |  |  | 3,436 |  |  |  | 3,338 |
Total Interest expense |  |  | $6,686 |  |  |  | $7,463 |  |  |  | $27,019 |  |  |  | $37,249 |  |  |  | $68,776 |
Foreign exchange (gain) loss on senior notes |  |  | $7,694 |  |  |  | $(2,547 | ) |  |  | $(25,442 | ) |  |  | $(5,044 | ) |  |  | $(13,953 | )
Realized and unrealized (gain) loss on derivative financial instruments |  |  | (5,691 | ) |  |  | 1,337 |  |  |  | 34,075 |  |  |  | (196 | ) |  |  | 14,689 |
Gain on repurchase of NACG Preferred Corp. Series A preferred shares |  |  | – |  |  |  | – |  |  |  | – |  |  |  | (9,400 | ) |  |  | – |
Loss on extinguishment of debt |  |  | – |  |  |  | 7 |  |  |  | – |  |  |  | 10,935 |  |  |  | 2,095 |
Other income |  |  | (67 | ) |  |  | (80 | ) |  |  | (418 | ) |  |  | (904 | ) |  |  | (977 | )
Income tax (recovery) expense |  |  | 11,297 |  |  |  | (2,942 | ) |  |  | 17,379 |  |  |  | (2,593 | ) |  |  | 737 |

Total interest expense decreased by $10.2 million in fiscal 2008 compared to the same period last year, primarily due to the retirement of the senior secured 9% notes with proceeds from our IPO and the exchange of the Series B redeemable preferred shares for common shares as part of the amalgamation that occurred prior to the IPO. The foreign exchange gains and losses recognized in the current and prior-year periods primarily relate to changes in the strength of the Canadian versus the U.S. dollar on conversion of the US$200 million of 8 3/4% senior notes. The Canadian dollar has strengthened from $0.8674 CAN/US on April 1, 2007 to $0.9729 CAN/US on March 31, 2008.
26 Management’s Discussion and Analysis North American Energy Partners Inc.

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The realized and unrealized gains on derivative financial instruments in the prior year reflect changes in the fair value of the cross-currency and interest rate swaps that we employ to provide an economic hedge for our US dollar denominated 8 3/4% senior notes. Changes in the fair value of the swaps generally have an offsetting effect to changes in the value of our 8 3/4% senior notes, both caused by variations in the Canadian/US foreign exchange rate. However, the valuation of the derivative financial instruments can also be impacted by changes in interest rates and the remaining present value of scheduled interest payments on the 8 3/4% senior notes. Interest payments occur in the first and third quarters of each year until maturity.
Due to the adoption of a new Canadian accounting standard regarding financial instruments, the current year realized and unrealized gains and losses on derivative financial instruments also includes changes in the fair value of derivatives embedded in our US dollar denominated 8 3/4% senior notes, in a long-term construction contract and in a supplier contract. In the current year, the change in the fair value of the swaps was a gain of $3.5 million during the fourth quarter and a $20.8 million loss during the fiscal year 2008. The balance of the realized and unrealized gains and losses on derivative financial instruments resulted from gains and losses on derivatives embedded in our 8 3/4% senior notes, in a long-term construction contract and in a supplier contract.
Effective April 1, 2007, we adopted the new Canadian CICA Handbook Section 3855 “Financial Instruments - Recognition and Measurement” which resulted in the recognition of derivatives embedded in our 8 3/4% senior notes, in a long-term construction contract and in a supplier maintenance agreement as follows:

• |  | Our 8 3/4% senior notes include certain embedded derivatives, notably optional redemption and change of control redemption rights. These embedded derivatives met the criteria for separation from the debt contract and separate measurement at fair value. Upon adoption of Section 3855, we recorded a reduction in the carrying amount of our 8 3/4% senior notes of $8.5 million together with related impacts on retained earnings and future income taxes on April 1, 2007. The change in the fair value of these embedded derivatives resulted in a pre-tax increase to earnings of $0.3 million in the fourth quarter and a change to earnings of $4.2 million in fiscal 2008.
• |  | A long-term construction contract contains a price escalation feature that represents an embedded foreign currency and price index derivative that meets the criteria for separation from the host contract and separate measurement at fair value. Upon adoption of Section 3855, we recorded a liability of $7.2 million together with related impacts on retained earnings and future income taxes on April 1, 2007. The change in the fair value of the liability resulted in a pre-tax benefit to earnings of $1.4 million in the fourth quarter and a pre-tax charge to earnings of $7.6 million for fiscal 2008.
• |  | We identified an additional embedded derivative that is not closely related to the host contract in the fourth quarter of 2008 with respect to a price escalation feature in a supplier contract. The embedded derivative has been measured at fair value. Upon adoption of Section 3855, we recorded a liability of $2.5 million together with related impacts on retained earnings and future income taxes on April 1, 2007. The change in the fair value of the liability resulted in a pre-tax gain of $1.2 million in the fourth quarter and a pre-tax gain of $1.2 million for fiscal 2008.

With respect to the early redemption provision in the 8 3/4% senior notes, the process to determine the fair value of the implied derivative was to compare the rate on the notes to the best financial alternative. The fair value determined as at April 1, 2007 resulted in a positive adjustment to opening retained earnings. The change in fair value in future periods is recognized as a charge to earnings. Changes in fair value result from changes in long-term bond interest rates during that period. The valuation process presumes a 100% probability of our implementing the inferred transaction and does not permit a reduction in the probability if there are other factors that would impact the decision.
With respect to the customer contract, there is a provision that requires an adjustment to billings to our customer to reflect actual exchange rate and price index changes versus the contract amount. The embedded derivative instrument takes into account the impact on revenues but does not consider the impact on costs as a result of fluctuations in these measures.
The new accounting guidelines for embedded derivatives will cause our reported earnings to fluctuate as currency exchange and interest rates change. The accounting for these derivatives will have no impact on operations, Consolidated EBITDA per bank or how we will evaluate performance.
We recorded income tax expense of $11.3 million in the fourth quarter and $17.4 million for fiscal 2008, as compared to an income tax recovery of $2.9 million and $2.6 million for the corresponding periods last year. Income tax expense as a percentage of income before tax for fiscal 2008 differs from the statutory rate of 31.47%, primarily due to the impact of the enacted rate changes during the year and the new accounting standards for the recognition, measurement and disclosure of financial instruments as certain embedded derivatives are considered capital in nature for income tax purposes. Income tax expense as a percentage of income before tax for the year ended March 31, 2007 differs from the statutory rate of 32.12%, primarily due to the elimination of the valuation allowance of $5.9 million that was recorded during that period and a non-taxable gain which resulted in a recovery for the year.
North American Energy Partners Inc. Management’s Discussion and Analysis 27

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Consolidated Financial Position

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

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

The strength of our financial position has improved over the last year. At March 31, 2008, we had net working capital (current assets less current liabilities) of $107.7 million compared to $77.6 million at March 31, 2007, an increase of $30.1 million. Positive cash flow caused our overall cash balance to increase by $25.0 million to $32.9 million. Increased revenues in the fourth quarter resulted in higher accounts receivable and unbilled revenue, up $60.8 million compared to the fourth quarter of fiscal 2007. Increased project activity drove accounts payable and accrued liabilities, which increased by $40.3 million, mitigating the effect of higher receivables and repayment of borrowings under the revolving credit facility. Reductions in the number of truck tires on hand as well as an inventory of lower-cost tires at year end versus the prior year resulted in a decline in other assets (included in current assets above) of $6.5 million compared to fiscal 2007, which lessened the effect of higher receivables in the same period.
Plant and equipment, net of depreciation, increased by $25.1 million for the 12 months ended March 31, 2008 as compared to the previous year. The purchase of additional haul trucks and piling rigs (mainly in the second quarter) was partially offset by depreciation and the disposal of surplus equipment in the first quarter.
Capital lease obligations, including the current portion, increased by $5.1 million as of March 31, 2008, as compared to the prior year end, due to the acquisition of additional support vehicles.
Claims and change orders
Due to the complexity of the projects we undertake, changes often occur after work has commenced. These changes include but are not limited to:

• |  | Client requirements, specifications and design;
• |  | Materials and work schedules; and
• |  | Changes in ground and weather conditions.

Contract change management processes require that we prepare and submit change orders to the client requesting approval of scope and/or price adjustments to the contract. Accounting guidelines require that management consider changes in cost estimates that have occurred up to the release of the financial statements and reflect the impact of these changes in the financial statements. Conversely, potential revenue associated with increases in cost estimates is not included in financial statements until an agreement is reached with the client or specific criteria for the recognition of revenue from unapproved change orders and claims are met. This can, and often does, lead to costs being recognized in one period and revenue being recognized in subsequent periods.
Occasionally, disagreements arise regarding changes, their nature, measurement, timing and other characteristics that impact costs and revenue under the contract. If a change becomes a point of dispute between our customer and us, we then consider it to be a claim. Historical claim recoveries should not be considered indicative of future claim recoveries.
As a result of certain projects experiencing the changed conditions discussed above, at March 31, 2008 we had recognized approximately $13.0 million in additional contract costs from project inception to date, with no associated increase in contract value. We are working with our customers to come to resolution on additional amounts, if any, to be paid to us in respect to these additional costs.
Subsequent Event
On June 25, 2008, the Company reached an agreement with a customer to settle all outstanding claims arising from a pipeline project completed in April 2007 for $8.0 million. The Company had previously recognized claims revenue of $2.7 million related to such outstanding claims as at March 31, 2008 and it will recognize the excess of the settlement over previously recognized claims revenue of $5.3 million as revenue in the quarter ended June 30, 2008.
28 Management’s Discussion and Analysis North American Energy Partners Inc.

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Quarterly Operating Results

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

(1) Net income (loss) per share for each quarter has been computed based on the weighted average number of shares issued and outstanding during the respective quarter; therefore, quarterly amounts may not add to the annual total. Per share calculations are based on full dollar and share amounts.
A number of factors contribute to variations in our quarterly results between periods, including weather, capital spending by our customers on large oil sands projects, our ability to manage our project-related business so as to avoid or minimize periods of relative inactivity and the strength of the western Canadian economy.
By way of example, we generally experience a decline in revenues during the first quarter of each fiscal year (April 1 to June 30) due to seasonal weather conditions that make many roads unsuitable for the operation of heavy equipment. Conversely, we tend to experience our highest revenues in the latter half of our fiscal year as climatic conditions become favourable to our operating requirements. As a result, full-year results are not likely to be a direct multiple of any particular quarter or combination of quarters.
The timing of large projects can influence the quarterly revenue as well. For example, pipeline installation revenues were $31.3 million in the second quarter of fiscal 2008 (up $28.5 million from Q2 of fiscal 2007), $76.7 million in the third quarter of fiscal 2008 (up $61.5 million compared to Q3 of fiscal 2007) and $87.5 million in the fourth quarter of fiscal 2008 (up $62.0 million compared to Q4 of fiscal 2007). Heavy Construction and Mining saw increased revenues in fiscal 2008 arising from the execution of work with Suncor on the Millennium Naphtha Unit project under our five-year site services agreement and the construction of an aerodrome for Albian, along with increased demand under our master service agreements with Albian and Syncrude. Timing of work under the site services agreements can vary based on our customers’ production activities.
In addition to revenue variability, gross margins can be negatively impacted in less active periods, such as the first and second quarter, because we are likely to incur higher maintenance and repair costs due to our equipment being available for service as compared with the more active periods, such as the third and fourth quarter. We incurred higher equipment costs in the first quarter of fiscal 2008 due to the increased equipment repairs and tire costs.
Profitability also varies from period-to-period due to claims and change orders. Claims and change orders are a normal aspect of the contracting business but can cause variability in profit margin due to the unmatched recognition of costs and revenues. For further explanation see Claims and Change Orders. During the first quarter of fiscal 2007, a $6.1 million dollar claim was recognized causing gross margins to increase above normal levels. The additional costs relating to the claim were incurred in fiscal 2005. During the fourth quarter of fiscal 2007 and the first half of fiscal 2008, we recognized additional costs related to fixed-price contracts in the Pipeline segment and as a result, we are currently working with our clients through the claims process.
Variations in quarterly results also result from our operating leverage. During the higher activity periods we have experienced improvements in operating income as certain costs, which are generally fixed, including general and administrative expenses, are spread over higher revenue levels. Net income and EPS are also subject to operating leverage as provided by fixed interest expense.
We have, however, experienced earnings variability in all periods due to the recognition of realized and unrealized non-cash gains and losses on derivative financial instruments and foreign exchange, primarily driven by changes in the Canadian and US dollar exchange rates.
North American Energy Partners Inc. Management’s Discussion and Analysis 29

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C. Key Trends
Seasonality
A number of factors contribute to variations in our quarterly results between periods, including weather, capital spending by our customers on large oil sands projects, our ability to manage our project-related business so as to avoid or minimize periods of relative inactivity and the strength of the western Canadian economy.
In addition to revenue variability, gross margins can be negatively impacted in less active periods because we are likely to incur higher maintenance and repair costs due to our equipment being available for scheduled maintenance. Profitability also varies from period-to-period due to claims and change orders. Claims and change orders are a normal aspect of the contracting business but can cause variability in profit margin due to the unmatched recognition of costs and revenues. For further explanation see “Claims and Change Orders”.
During the higher activity periods we have experienced improvements in operating income due to operating leverage. General and administrative costs are generally fixed and we see these costs decrease as a percent of revenue. Net income and EPS are also subject to operating leverage as provided by fixed interest expense, however we have experienced earnings variability in all periods due to the recognition of realized and unrealized non-cash gains and losses on derivative financial instruments and foreign exchange primarily driven by changes in the Canadian and US dollar exchange rates.
Backlog
Backlog is a measure of the amount of secured work we have outstanding and as such is an indicator of future revenue potential. Backlog is not a GAAP measure. As a result, the definition and determination of a backlog will vary among different organizations ascribing a value to backlog. Although backlog reflects business that we consider to be firm, cancellations or reductions may occur and may reduce backlog and future income.
We define backlog as that work that has a high certainty of being performed as evidenced by the existence of a signed contract or work order specifying job scope, value and timing. We have also set a policy that our definition of backlog will be limited to contracts or work orders with values exceeding $500,000 and work that will be performed in the next five years, even if the related contracts extend beyond five years.
We work with our customers using cost-plus, time-and-materials, unit-price and lump-sum contracts and the mix of contract types varies year-by-year. Our definition of backlog results in the exclusion of cost-plus and time-and-material contracts performed under master service agreements where scope is not clearly defined. While contracts exist for a range of services to be provided, the work scope and value are not clearly defined under those contracts. For the 12 month period ended March 31, 2008, the total amount of revenue earned under the master services agreements that did not qualify for inclusion in our calculation of backlog was $223 million.
Our estimated backlog as at March 31, 2008 and 2007 was (in millions):

|  | March 31, |
By Segment |  | 2008 |  |  | 2007 |
Heavy Construction & Mining |  |  | $896.3 |  |  |  | $732.0 |
Piling |  |  | 20.5 |  |  |  | 40.0 |
Pipeline |  |  | 65.5 |  |  |  | 16.0 |
Total |  |  | $982.3 |  |  |  | $788.0 |

|  | March 31, |
By Contract Type |  | 2008 |  |  | 2007 |
Unit-Price |  |  | $905.2 |  |  |  | $778.0 |
Lump-Sum |  |  | 11.6 |  |  |  | 10.0 |
Time-and-Material, Cost-Plus |  |  | 65.5 |  |  |  | - |
Total |  |  | $982.3 |  |  |  | $788.0 |

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

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

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

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Revenue Sources:
This section contains new disclosures.
We have experienced a steady growth in master services agreements as oil sands development continues to grow. While there is no long-term commitment from customers regarding this work as described below, we expect these trends to continue into fiscal 2009 as we continue to provide services to Syncrude and Suncor and benefit from growth at the Shell sites.*
Long-term Contracts This category of revenue is generated from long-term contracts (greater than one year) with total contract values greater than $20 million. These contracts are for work that supports the operations of our customers and is therefore considered to be recurring including long-term contracts for overburden removal and reclamation. This revenue is typically generated under unit-price contracts and is included in our calculation of backlog.
Master Services Agreements This category includes revenue generated from the master services agreements in place with Syncrude, Suncor and Albian. This category of revenue is also generated by supporting the operations of our customers and is therefore considered to be recurring. This revenue is not guaranteed under contract and would not be included in our calculation of backlog. This revenue is primarily generated under time-and-materials arrangements.
Major Projects Revenue generated from projects with contract values greater than $20 million and durations of greater than six months. This category of revenue is typically generated supporting major capital construction projects and is therefore considered to be non-recurring. This revenue can be generated under lump-sum, unit-price, time-and-materials and cost-plus contracts. This revenue can be included in backlog if generated under lump-sum, unit-price or time-and-materials contracts.
Other Projects Revenue generated from contracts with values of less than $20 million and durations of, typically, less than six months. This category of revenue is generally driven by capital construction and is therefore non-recurring. This revenue can be generated under lump-sum, unit-price, time-and-materials and cost-plus contracts. This revenue is included in backlog if generated under lump-sum, unit-price contracts or time-and-materials contracts.

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

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

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Projects in the oil sands increased our work volumes during 2008. The pipeline installation project for Kinder Morgan increased our revenues in the conventional oil and gas sector. Minerals mining work slowed in 2008 as we completed the work on the DeBeers diamond mine project.
Contracts
We complete work under the following types of contracts: cost-plus, time-and-materials, unit-price and lump-sum. Each contract contains a different level of risk associated with its formation and execution.
Cost-plus A cost-plus contract is a contract in which all the work is completed based on actual costs incurred to complete the work. These costs include all labor, equipment, materials and any subcontractor’s costs. In addition to these direct costs, all site and corporate overhead costs are charged to the job. An agreed-upon fee in the form of a fixed percentage is then applied to all costs charged to the project. This type of contract is utilized where the project involves a large amount of risk or the scope of the project cannot be readily determined.
Time-and-materials A time-and-materials contract involves using the components of a cost-plus job to calculate rates for the supply of labor and equipment. In this regard, all components of the rates are fixed and we are compensated for each hour of labor and equipment supplied. The risk associated with this type of contract is the estimation of the rates and incurrence of expenses in excess of a specific component of the agreed-upon rate. Any cost overrun in this type of contract must come out of the fixed margin included in the rates.
Unit-price A unit-price contract is utilized in the execution of projects with large repetitive quantities of work and is commonly utilized for site preparation, mining and pipeline work. We are compensated for each unit of work we perform (for example, cubic meters of earth moved, lineal meters of pipe installed or completed piles). Within the unit-price contract, there is an allowance for labor, equipment, materials and any subcontractor’s costs. Once these costs are calculated, we add any site and corporate overhead costs along with an allowance for the margin we want to achieve. The risk associated with this type of contract is in the calculation of the unit costs with respect to completing the required work.
Lump-sum A lump-sum contract is utilized when a detailed scope of work is known for a specific project. Thus, the associated costs can be readily calculated and a firm price provided to the customer for the execution of the work. The risk lies in the fact that there is no escalation of the price if the work takes longer or more resources are required than were estimated in the established price, as the price is fixed regardless of the amount of work required to complete the project.
Major Suppliers
We have long-term relationships with the following equipment suppliers: Finning International Inc. (45 years), Wajax Income Fund (20 years) and Brandt Tractor Ltd. (30 years). Finning is a major Caterpillar heavy equipment dealer for Canada. Wajax is a major Hitachi equipment supplier to us for both mining and construction equipment. We purchase or rent John Deere equipment, including excavators, loaders and small bulldozers, from Brandt Tractor. In addition to the supply of new equipment, each of these companies is a major supplier for equipment rentals, parts and service labor.
Tire supply remains a challenge for our haul truck fleet. We prefer to use radial tires from proven manufacturers, but the shortage of supply has forced us to increase the use of bias tires and radial tires from new manufacturers. Bias tires have a shorter usage life and are of a lower quality than radial tires. This affects operations as we are forced to reduce operating speeds and loads to compensate for the quality of the tires. During the year ended March 31, 2008 we reduced our inventory of bias tires for the 150-ton haul trucks and are now acquiring radial tires for these trucks as required.
32 Management’s Discussion and Analysis North American Energy Partners Inc.

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Tires for 240-ton haul trucks continue to be in short supply. To address the shortfall we are purchasing bias tires from new manufacturers and radial tires from non-dealer sources at a large premium above dealer prices. We were able to negotiate a five year contract (commencing in 2008) with Bridgestone Firestone Canada Inc. to secure a tire allotment for select tire sizes for the 240-to-320 ton haul trucks which will alleviate some of the shortage. We are continuing negotiations with Bridgestone to improve the security of tire supply. We have also been successful in acquiring radial tires with new trucks as they are delivered and hope to continue this practice in fiscal 2009 and fiscal 2010. Suppliers have improved overall tire supply but we believe the tire shortage will remain an issue for the foreseeable future.*
Competition
Our industry is highly competitive in each of our markets. Historically, the majority of our new business was awarded to us based on past client relationships without a formal bidding process, in which, typically, a small number of pre-qualified firms submit bids for the project work. Recently, in order to generate new business with new customers, we have had to participate in formal bidding processes. As new major projects arise, we expect to have to participate in bidding processes on a meaningful portion of the work available to us on these projects. Factors that impact competition include price, safety, reliability, scale of operations, availability and quality of service. Most of our clients and potential clients in the oil sands area operate their own heavy mining equipment fleet. However, these operators have historically outsourced a significant portion of their mining and site preparation operations and other construction services.*
Our principal competitors in the Heavy Construction and Mining segment include Cow Harbour, Cross Construction Ltd., Klemke Mining Corporation, Ledcor Construction Limited, Peter Kiewit & Sons Co., Tercon Contractors Ltd., Sureway Construction Ltd. and Thompson Bros. (Constr) Ltd. In underground utilities installation (a part of our Heavy Construction and Mining segment) Voice Construction Ltd., Ledcor Construction Limited and I.G.L. Industrial Services are our major competitors. The main competition to our deep foundation piling operations comes from Agra Foundations Limited, Double Star Co. and Ruskin Construction Ltd. The primary competitors in the pipeline installation business include Ledcor Construction Limited, Washcuk Pipe Line Construction Ltd. and Willbros.
In the public sector, we compete against national firms, and there is usually more than one competitor in each local market. Most of our public sector customers are local governments that are focused on serving only their local regions. Competition in the public sector continues to increase and we typically choose to compete on projects only where we can utilize our equipment and operating strengths to secure profitable business.
D. Outlook
Moving forward, continued development of the oil sands is expected to drive a significant portion of our fiscal 2009 revenue. In addition to existing mining and site services contracts with customers including Canadian Natural, Suncor, Syncrude, Albian and Petro-Canada, we also anticipate increased demand for our services at Petro-Canada’s Fort Hills site as that project progresses.*
Outside of the oil sands, we are providing constructability assistance to Baffinland Iron Mines Corp. as it prepares feasibility studies for an iron ore development in northern Canada. This customer approached us based on our experience and success at De Beers’ Victor Project in northern Ontario and we expect our involvement on their project will continue to grow. Our success with the Albian aerodrome project, meanwhile, has resulted in significant interest from customers looking to develop airstrips in Northern Alberta.*
Demand for our piling services is expected to remain strong in fiscal 2009 with commercial construction activity at a high level in Western Canada. A number of upgrader facilities are also being considered for the Edmonton area, providing opportunities to bid on larger-scale piling contracts.*
While we anticipate a temporary slowdown in our pipeline activity once the TMX project concludes in October 2008, we see significant long-term opportunities for this division. More than five major new pipeline projects are planned for Western Canada to relieve limited capacity and accommodate growing oil sands production. We believe our success on the large and environmentally-demanding TMX project positions us to compete effectively as the new pipeline projects are tendered.*
Overall, our outlook for fiscal 2009 remains positive.

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

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

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E. Legal and Labour Matters
Laws and Regulations and Environmental Matters
Many aspects of our operations are subject to various federal, provincial and local laws and regulations, including, among others:

• |  | permitting and licensing requirements applicable to contractors in their respective trades;
• |  | building and similar codes and zoning ordinances;
• |  | laws and regulations relating to consumer protection; and
• |  | laws and regulations relating to worker safety and protection of human health.

We believe we have all material required permits and licenses to conduct our operations and are in substantial compliance with applicable regulatory requirements relating to our operations. Our failure to comply with the applicable regulations could result in substantial fines or revocation of our operating permits.
Our operations are subject to numerous federal, provincial and municipal environmental laws and regulations, including those governing the release of substances, the remediation of contaminated soil and groundwater, vehicle emissions and air and water emissions. These laws and regulations are administered by federal, provincial and municipal authorities, such as Alberta Environment, Saskatchewan Environment, the British Columbia Ministry of Environment, and other governmental agencies. The requirements of these laws and regulations are becoming increasingly complex and stringent, and meeting these requirements can be expensive. The nature of our operations and our ownership or operation of property exposes us to the risk of claims with respect to environmental matters and there can be no assurance that material costs or liabilities will not be incurred with such claims. For example, some laws can impose strict, joint and several liability on past and present owners or operators of facilities at, from or to which a release of hazardous substances has occurred, on parties who generated hazardous substances that were released at such facilities and on parties who arranged for the transportation of hazardous substances to such facilities. If we were found to be a responsible party under these statutes, we could be held liable for all investigative and remedial costs associated with addressing such contamination, even though the releases were caused by a prior owner or operator or third party. We are not currently named as a responsible party for any environmental liabilities on any of the properties on which we currently perform or have performed services. However, our leases typically include covenants which obligate us to comply with all applicable environmental regulations and to remediate any environmental damage caused by us to the leased premises. In addition, claims alleging personal injury or property damage may be brought against us if we cause the release of, or any exposure to, harmful substances.
Our construction contracts require us to comply with all environmental and safety standards set by our customers. These requirements cover such areas as safety training for new hires, equipment use on site, visitor access on site and procedures for dealing with hazardous substances.
Capital expenditures relating to environmental matters during the fiscal years ended March 31, 2006, 2007 and 2008 were not material. We do not currently anticipate any material adverse effect on our business or financial position as a result of future compliance with applicable environmental laws and regulations. Future events, however, such as changes in existing laws and regulations or their interpretation, more vigorous enforcement policies of regulatory agencies or stricter or different interpretations of existing laws and regulations may require us to make additional expenditures which may be material.*
Employees and Labour Relations
As of March 31, 2008, we had over 280 salaried employees and over 2,100 hourly employees. During fiscal 2008 we welcomed 71 new salaried employees and 581 new hourly employees, bringing our total number of employees to 2,410 at March 31, 2008. Our hourly workforce will fluctuate according to the seasonality of our business from an estimated low of 1,500 employees in the spring to a high of approximately 2,400 employees over the winter. We also utilize the services of subcontractors in our construction business. An estimated 8% to 10% of the construction work we do is performed by subcontractors. Approximately 2,000 employees are members of various unions and work under collective bargaining agreements. The majority of our work is done through employees governed by our Mining Overburden collective bargaining agreement with the International Union of Operating Engineers Local 955, the primary term of which expires on October 31, 2009. A small portion of our employees work under an industrial collective bargaining agreement with the Alberta Road Builders and Heavy Construction Association and the International Union of Operating Engineers Local 955,

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

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

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the primary term of which expires February 28, 2009. We are subject to other industry and specialty collective agreements under which we complete work and the primary terms of all of these agreements are currently in effect. We believe that our relationships with all our employees, both union and non-union, are satisfactory. We have not yet experienced a strike or lockout.
F. Resources and Systems
Outstanding Share Data
We are authorized to issue an unlimited number of common voting shares and an unlimited number of common non-voting shares. As at June 20, 2008, 36,016,476 common voting shares were outstanding compared to 35,929,476 common voting shares as at March 31, 2008 and 35,192,260 common voting shares and 412,400 non-voting common shares as at March 31, 2007. As at June 20, 2008 there are no non-voting shares outstanding.
Liquidity
Liquidity requirements
Our primary uses of cash are for plant and equipment purchases, to fulfill debt repayment and interest payment obligations, to fund operating lease obligations and to finance working capital requirements.
Our long-term debt includes US$200 million of 8 3/4% senior notes due in 2011. The foreign currency risk relating to both the principal and interest portions of these senior notes has been managed with a cross-currency swap and interest rate swaps, which went into effect concurrent with the issuance of the notes on November 26, 2003. The swap agreement is an economic hedge but has not been designated as a hedge for accounting purposes. Interest totaling $13.0 million on the 8 3/4% senior notes and the swap is payable semi-annually in June and December of each year until the notes mature on December 1, 2011. The $200 million US principal amount was hedged at C$1.315=US$1.000, resulting in a principal repayment of $263 million due on December 1, 2011. There are no principal repayments required on the 8 3/4% senior notes until maturity.
One of our major contracts allows the customer to require that we provide up to $50 million in letters of credit. As at March 31, 2008, we had $20 million in letters of credit outstanding in connection with this contract. Any change in the amount of the letters of credit required by this customer must be requested by November 1st for an issue date of January 1st, each year for the remaining life of the contract.
We maintain a significant equipment and vehicle fleet comprised of units with remaining useful lives covering a variety of time spans. It is important to adequately maintain our large revenue-producing fleet in order to avoid equipment downtime which can impact our revenue stream and inhibit our ability to satisfactorily perform on our projects. Once units reach the end of their useful lives, they are replaced as it becomes cost prohibitive to continue to maintain them. As a result, we are continually acquiring new equipment to replace retired units and to support our growth as we take on new projects. In order to maintain a balance of owned and leased equipment, we have financed a portion of our heavy construction fleet through operating leases. In addition, we continue to lease our motor vehicle fleet through our capital lease facilities.
We require between $30 million and $40 million for sustaining capital expenditures and our total capital requirements will typically range from $125 million to $200 million depending on our growth capital requirements. We typically finance approximately 30% to 50% of our total capital requirements through our operating lease facilities, 5% to 10% through capital lease facilities and the remainder out of cash flow from operations. We believe our operating and capital lease facilities and cash flow from operations will be sufficient to meet these requirements.
Sources of liquidity
Our principal sources of cash are funds from operations and borrowings under our revolving credit facility. As of March 31, 2008, we had approximately $105 million of available borrowings under the revolving credit facility after taking into account $20.0 million of outstanding and undrawn letters of credit to support performance guarantees associated with customer contracts. The indebtedness under the revolving credit facility is secured by a first priority lien on substantially all of our existing and after-acquired property.
Our revolving credit facility contains covenants that restrict our activities, including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions. Under the revolving credit facility Consolidated Capital Expenditures during any applicable period cannot exceed 120% of the amount in the capital expenditure plan. In addition, we are required to satisfy certain financial covenants, including a minimum interest coverage ratio and a maximum senior leverage ratio, both of which are calculated using Consolidated EBITDA per bank, as well as a minimum current ratio.
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Consolidated EBITDA per bank is defined in the credit facility as the sum, without duplication, of (1) consolidated net income, (2) consolidated interest expense, (3) provision for taxes based on income, (4) total depreciation expense, (5) total amortization expense, (6) costs and expenses incurred by us in entering into the credit facility, (7) accrual of stock-based compensation expense to the extent not paid in cash or if satisfied by the issue of new equity, and (8) other non-cash items (other than any such non-cash item to the extent it represents an accrual of or reserve for cash expenditure in any future period), but only, in the case of clauses (2)-(8), to the extent deducted in the calculation of consolidated net income, less other non-cash items added in the calculation of consolidated net income (other than any such non-cash item to the extent it will result in the receipt of cash payments in any future period), all of the foregoing as determined on a consolidated basis for us in conformity with Canadian GAAP.
Interest coverage is determined based on a ratio of Consolidated EBITDA per bank to consolidated cash interest expense, and the senior leverage is determined as a ratio of senior debt to Consolidated EBITDA per bank. Measured as of the last day of each fiscal quarter on a trailing four-quarter basis, Consolidated EBITDA per bank shall not be less than 2.5 times consolidated cash interest expense (2.35 times at June 30, 2007). Also, measured as of the last day of each fiscal quarter on a trailing four-quarter basis, senior leverage shall not exceed two times Consolidated EBITDA per bank. We believe Consolidated EBITDA per bank as defined in the credit facility is an important measure of our performance.
Revolving credit facility
We entered into an amended and restated credit agreement dated as of June 7, 2007 with a syndicate of lenders that provides us with a $125.0 million revolving credit facility. Our revolving credit facility provides for an original principal amount of up to $125.0 million under which revolving loans may be made and under which letters of credit may be issued. The facility will mature on June 7, 2010, subject to possible extension. The credit facility is secured by a first priority lien on substantially all of our and our subsidiaries’ existing and after-acquired property (tangible and intangible), including, without limitation, accounts receivable, inventory, equipment, intellectual property and other personal property, and real property, whether owned or leased, and a pledge of the shares of our subsidiaries, subject to various exceptions.
The facility bears interest on each prime loan at variable rates based on the Canadian prime rate plus the applicable pricing margin (as defined in the credit agreement). Interest on U.S. base rate loans is paid at a rate per annum equal to the U.S. base rate plus the applicable pricing margin. Interest on prime and U.S. base rate loans is payable monthly in arrears and computed on the basis of a 365 or 366-day year, as the case may be. Interest on LIBOR loans is paid during each interest period at a rate per annum, calculated on a 360-day year, equal to the LIBOR rate with respect to such interest period plus the applicable pricing margin.
The credit facility may be prepaid in whole or in part without penalty, except for bankers’ acceptances, which will not be prepayable prior to their maturity. However, the credit facility requires prepayments under various circumstances, such as: (i) 100% of the net cash proceeds of certain asset dispositions, (ii) 100% of the net cash proceeds from our issuance of equity (unless the use of such securities proceeds is otherwise designated by the applicable offering document) and (iii) 100% of all casualty insurance and condemnation proceeds, subject to exceptions.
Under the credit facility, we are required to satisfy certain financial covenants, including a current ratio, a senior leverage ratio and an interest coverage ratio.
Working capital fluctuations effect on cash
The seasonality of our work may result in a slow down in cash collections between December and early February, which may result in an increase in our working capital requirements. Our working capital is also significantly affected by the timing of completion of projects. Our customers are permitted to withhold payment of a percentage (defined by the contract and in some cases provincial legislation) of the amount owing to us for a stipulated period of time (usually defined by the contract and in some cases provincial legislation). This amount acts as a form of security for our customers and is referred to as a holdback. We are only entitled to collect payment on holdbacks once substantial completion of the contract is performed, there are no outstanding claims by subcontractors or others related to work performed by us and we have met the time period specified by the contract (usually 45 days after completion of the work). As at March 31, 2008 we saw holdbacks increase to $35 million from $19.5 million in 2007. This represents 21% (18% for 2007) of our total Accounts Receivable outstanding as at March 31, 2008. This increase is attributable to the stronger revenues in the last half of fiscal 2008 with a corresponding increase in work in progress resulting in more holdbacks at year end. As at March 31, 2008 we carried $22.4 million in holdbacks for two large projects (the DeBeers Victor Diamond Mine and the Kinder Morgan pipeline project). The holdback for DeBeers was subsequently collected in May 2008 reducing holdbacks by $11 million. As at March 31, 2007 we carried $5.2 million in holdbacks for the DeBeers project.
36 Management’s Discussion and Analysis North American Energy Partners Inc.

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Debt Ratings
In December 2007, Standard & Poor’s upgraded our debt rating to B+ (from B) with a stable outlook following a review of our current and prospective business risk and financial risk profiles. In March 2008, Standard & Poor’s upgraded our senior unsecured notes rating to B+ with a recovery rating of “4” indicating an expectation for an average of (30% – 50%) recovery in the event of a payment default.
In December 2007, Moody’s maintained our debt rating at B2 with a stable outlook (the upgrade to B2 was issued in December 2006 following our IPO). Moody’s rates our senior unsecured notes at B3 with a loss given default rating of “5”.
Cash Flow

|  | Three Months Ended March 31, |  |  | Year Ended March 31, |
(in thousands) |  | 2008 |  |  | 2007 |  |  | 2006 |  |  | 2008 |  |  | 2007 |  |  | 2006 |
Cash provided by operating activities |  |  | $36,183 |  |  |  | $7,392 |  |  |  | $17,152 |  |  |  | $97,600 |  |  |  | $2,130 |  |  |  | $33,701 |
Cash (used in) investing activities |  |  | (2,746 | ) |  |  | (10,901 | ) |  |  | (5,814 | ) |  |  | (48,632 | ) |  |  | (100,050 | ) |  |  | (22,005 | )
Cash (used in) provided by financing activities |  |  | (21,809 | ) |  |  | 4,297 |  |  |  | (332 | ) |  |  | (23,992 | ) |  |  | 63,011 |  |  |  | 13,184 |
Net increase (decrease) in cash and cash equivalents |  |  | $11,628 |  |  |  | $788 |  |  |  | $11,006 |  |  |  | $24,976 |  |  |  | $(34,909 | ) |  |  | $24,880 |

Operating activities
Operating activities in the fourth quarter benefitted from the favourable cash collections in the last half of fiscal 2008 resulting in a net cash increase of $36.0 million compared to $7.4 million in fiscal 2007. Operating activities in fiscal 2008 resulted in a net increase in cash of $97.6 million, compared to an increase of $2.1 million in fiscal 2007 and an increase of $33.7 million in fiscal 2006. Strong earnings performance in 2008, combined with favourable cash collections (minimizing working capital increases), drove the improvement in cash collections compared to fiscal 2007. The lower cash generated in fiscal 2007 compared to fiscal 2006 was the result of movements in net non-cash working capital from increased accounts receivable balances and deposits on tire purchases.
Investing activities
Sustaining capital expenditures are those that are required to keep our existing fleet of equipment at its optimal useful life through capital maintenance or replacement. Growth capital expenditures relate to equipment additions required to perform larger or a greater number of projects.
During fiscal 2008, we invested $21.3 million in sustaining capital expenditures (2007– $7.6 million; 2006 – $7.4 million) and invested $36.5 million in growth capital expenditures (2007 – $102.4 million; 2006 – $21.5 million), for total capital expenditures of $57.8 million (2007 – $110.0 million; 2006 – $28.9 million). Proceeds from asset disposals of $17.1 million in fiscal 2008 ($3.6 million in fiscal 2007 and $5.5 million in fiscal 2006) lessened the effect of capital purchases resulting in net cash invested of $48.6 million for fiscal 2008 ($100.1 million in fiscal 2007 and $22.0 million in fiscal 2006). A shift to operating leases to fund equipment purchases saw an additional $88.7 million (2007 – $49.5 million; 2006 – $18.9 million) not reflected in the capital spent for 2008. The significant increase in 2007 growth capital expenditures reflects the purchase of certain leased equipment for $44.6 million using a portion of the net IPO proceeds and the purchase of several large trucks to accommodate the increasing volume of available work.
Financing activities
Financing activities in 2008 resulted in a cash outflow of $24.0 million as we repaid $20.5 million on the revolving credit facility in the fourth quarter of 2008. Cash inflows in 2007 were primarily provided by the net proceeds of our IPO as described in the following paragraph, offset by the repayment of our 9% senior secured notes. Financing activities during 2006 resulted in net cash inflow of $13.2 million. This inflow reflects proceeds received from our May 19, 2005 issuance of the US$60.5 million of 9% senior secured notes and $7.5 million of Series B preferred shares of our predecessor company. A significant portion of the proceeds from these issues was used to repay the amount outstanding under our senior secured credit facility at the time.
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Capital Commitments
Contractual Obligations and Other Commitments
Our principal contractual obligations relate to our long-term debt and capital and operating leases. The following table summarizes our future contractual obligations, excluding interest payments unless otherwise noted, as of March 31, 2008.

|  | Payments due by fiscal year
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 2013 and |
(in millions) |  | Total |  |  | 2009 |  |  | 2010 |  |  | 2011 |  |  | 2012 |  |  | after |
Senior notes (1) |  |  | $263.0 |  |  |  | $– |  |  |  | $– |  |  |  | $– |  |  |  | $263.0 |  |  |  | $– |
Capital leases (including interest) |  |  | 16.4 |  |  |  | 5.5 |  |  |  | 4.7 |  |  |  | 3.3 |  |  |  | 2.7 |  |  |  | 0.2 |
Operating leases |  |  | 96.0 |  |  |  | 31.1 |  |  |  | 26.0 |  |  |  | 16.5 |  |  |  | 10.9 |  |  |  | 11.5 |
Supplier contracts |  |  | 36.6 |  |  |  | 5.3 |  |  |  | 6.0 |  |  |  | 8.2 |  |  |  | 9.8 |  |  |  | 7.3 |
Total contractual obligations |  |  | $412.0 |  |  |  | $41.9 |  |  |  | $36.7 |  |  |  | $28.0 |  |  |  | $286.4 |  |  |  | $19.0 |

(1) |  | We have entered into cross-currency and interest rate swaps, which represent an economic hedge of the 8 3/4% senior notes. At maturity, we will be required to pay $263.0 million in order to retire these senior notes and the swaps. This amount reflects the fixed exchange rate of C$1.315=US$1.00 established as of November 26, 2003, the inception of the swap contracts. At March 31, 2008 the carrying value of these derivative financial instruments was $81.6 million, inclusive of the interest components.

Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements in place at this time.
Cash Requirements
As of March 31, 2008 our cash balance of $32.9 million was $25.0 million higher than our cash balance in fiscal 2007. We anticipate that we will continue to generate a net cash surplus in fiscal 2009 from cash generated from operations. In the event that we require additional funding, we believe that any such funding requirements would be satisfied by the funds available from our revolving credit facility.*
Internal Systems and Processes
Overview of information systems
We currently use JDE (Enterprise One) as our Enterprise Resource Planning (ERP) tool and deploy the financial system, payroll, procurement, job costing and equipment maintenance modules from this tool. We supplement this functionality with either third-party software (for our estimating system) or in-house developed tools (for project management).
In fiscal 2008 we focused on developing systems and processes using our ERP system to increase the automation of transactional activities and improve management information. The proper identification of costs is a critical part of our ability to recognize revenues and we have focused resources to address this issue. Throughout fiscal 2008 we concentrated on the development of better cost-tracking tools through the implementation of a procure-to-pay process in our ERP system. We also started work on improving the process for tracking and reporting equipment and maintenance costs. Despite some initial implementation hurdles over the summer and fall of 2007, we are beginning to see improvements in the identification and tracking of our procurement costs.
We are currently performing a user-needs analysis and comparing this to the functionality of our ERP system. We will make a determination over the first quarter of fiscal 2009 whether we can implement additional modules or commence a review of industry-specific software to supplement our existing ERP functionality.
During the 2008 fiscal year we experienced significant staff turnover within the financial reporting team while experiencing significant revenue growth during the same period. These two factors significantly impacted the effectiveness of our internal systems and processes as discussed below.
Evaluation of disclosure controls and procedures
Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by the Company is recorded, processed, summarized and reported within the time periods specified under Canadian and U.S. securities laws and include controls and procedures designed to ensure that information is accumulated and communicated to management, including the President and Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosure.
As of March 31, 2008, an evaluation was carried out under the supervision of and with the participation of management, including the President and Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) under the U.S. Securities Exchange Act of 1934 and in Multilateral

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

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Instrument 52-109 under the Canadian Securities Administrators Rules and Policies. Based on that evaluation, the President and Chief Executive Officer and Chief Financial Officer concluded that as a result of the material weaknesses in the Company’s internal control over financial reporting discussed below, the disclosure controls and procedures were not effective as of the end of the period covered by this annual report.
Management’s report on internal controls over financial reporting (ICFR):
Internal control over financial reporting is a process designed to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and of the preparation of financial statements for external purposes in accordance with Canadian generally accepted accounting principles (GAAP) and reconciled to US GAAP. Management, including the President and Chief Executive Officer and Chief Financial Officer, are responsible for establishing and maintaining adequate ICFR, as such term is defined in Rule 13a-15(e) under the US Securities Exchange Act of 1934 and in Multilateral Instrument 52-109 under the Canadian Securities Administrators Rules and Policies to provide reasonable, but not absolute, assurance regarding the reliability of our financial reporting. A material weakness in ICFR exists if the deficiency is such that there is reasonable possibility that a material misstatement of our annual or interim consolidated financial statements will not be prevented or detected on a timely basis.
Because of its inherent limitations, ICFR may not prevent or detect misstatements. Also, projections or any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As of March 31, 2008 we assessed the effectiveness of the Company’s ICFR. In making this assessment, we used the criteria set forth in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). During this process, we identified material weaknesses in internal controls over financial reporting as described below.
Given the circumstances outlined above, we did not maintain effective processes and controls related to the following:

• |  | Specific to complex and non-routine transactions and period-end controls: There was a lack of sufficient accounting and finance personnel with an appropriate level of technical accounting knowledge and training commensurate with the complexity of the Company’s financial accounting and reporting requirements. Complex and non-routine financial reporting matters that would be affected by this deficiency include the identification of embedded derivatives and preparation of our US GAAP reconciliation note. Additionally, we did not adequately perform period-end controls related to the review and approval of account analysis, verification of inputs and reconciliations. The accounts that would be affected by these deficiencies are cash, senior notes, contributed surplus, stock-based compensation expense, foreign exchange gain and related financial statement disclosures.
• |  | Specific to revenue recognition: A formal process to track claims and unapproved change orders and sufficient monitoring controls over the completeness and accuracy of forecasts, including the consideration of project changes subsequent to the end of each reporting period, were not effectively implemented. The accounts that would be affected by these deficiencies are revenue, project costs, unbilled revenue and billings in excess of costs incurred and estimated earnings on uncompleted contracts.
• |  | Specific to accounts payable and procurement: We did not have an effectively implemented procurement process to track purchase commitments, reconcile vendor accounts and accurately accrue costs not invoiced by vendors at each reporting date. The accounts that would be affected by these deficiencies are accounts payable, accrued liabilities, unbilled revenue, billings in excess of costs incurred and estimated earnings on uncompleted contracts, revenue, project costs, equipment costs, general and administrative costs and other expenses.

These material weaknesses in ICFR, which are pervasive in nature, resulted in material errors in the financial statements that were noted by our external auditors and corrected prior to release of the financial statements, and therefore, there is a reasonable possibility that a material misstatement of our financial statements will not be prevented or detected on a timely basis. Notwithstanding the above mentioned weaknesses, we have concluded that the Consolidated Financial Statements included in this report fairly present our consolidated financial position and consolidated results of operations as of and for the fiscal year ending March 31, 2008.
Remediation plans
In response to the material weaknesses identified above, we have undertaken the following actions:

• |  | We have taken steps to rectify the complex and non-routine transactions and period-end control weaknesses by reorganizing the corporate accounting group and recruiting new staff with the appropriate levels of experience and technical skills to prevent a reoccurrence of these issues.
• |  | We implemented new processes over revenue recognition in the last quarter of fiscal 2008. These processes have not been in place long enough to fully evaluate the effectiveness of the controls. We are evaluating the results of the implementation over the next two quarters to ensure that the new controls adequately address our ability to recognize revenue in the correct period.

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

Changes to internal control over financial reporting
In our 2007 fiscal year we identified the following additional material weaknesses in our ICFR. These weaknesses were remediated in 2008 as follows:

• |  | Income taxes – there was a lack of review and monitoring controls as well as a lack of segregation of duties of the income tax function. New review processes, together with increased technical support from third party experts have improved the review and monitoring controls and addressed the segregation of duties issues in the income tax function.
• |  | IT General Controls (“ITGCs”) – A number of deficiencies in ITGCs were identified, including appropriate controls around spreadsheets and end-user computing, controls over access to and the accuracy of one of our systems, as well as general maintenance of access rights and nominal program change controls. When aggregated, these deficiencies represented a material weakness in ICFR. Improvements to access rights and program change controls were implemented in fiscal 2008 to address certain of the deficiencies identified in fiscal 2007.

Significant Accounting Policies
Critical accounting estimates
Certain accounting policies require management to make significant estimates and assumptions about future events that affect the amounts reported in our financial statements and the accompanying notes. Therefore, the determination of estimates requires the exercise of management’s judgment. Actual results could differ from those estimates and any differences may be material to our financial statements.
Revenue recognition
Our contracts with customers fall under the following contract types: cost-plus, time-and-materials, unit-price and lump-sum. While contracts are generally less than one year in duration, we do have several long-term contracts. The mix of contract types varies year-by-year. For the year ended March 31, 2008, our revenue consisted of 55.0% time-and-materials, 37.3% unit-price and 7.7% lump-sum.
Profit for each type of contract is included in revenue when its realization is reasonably assured. Estimated contract losses are recognized in full when determined. Claims and unapproved change orders are included in total estimated contract revenue only to the extent that contract costs related to the claim or unapproved change order have been incurred, when it is probable that the claim or unapproved change order will result in a bona fide addition to contract value and the amount of revenue can be reliably estimated.
The accuracy of our revenue and profit recognition in a given period is dependent, in part, on the accuracy of our estimates of the cost to complete each unit-price and lump-sum project. Our cost estimates use a detailed “bottom up’’ approach, using inputs such as labour and equipment hours, detailed drawings and material lists. These estimates are updated monthly. We have noted a material weakness related to our procurement processes. This is discussed in more detail in the section “Management’s Report on Internal Controls over Financial Reporting.” To address these weaknesses, we implemented monitoring and review controls to assist with the determination of our cost estimates. These controls require a significant review of our payable activities after month-end to ensure that we have identified project costs in the correct period. Given the time delay in identifying costs we may misstate revenues. However, we believe our experience allows us to produce materially reliable estimates. Our projects can be highly complex and in almost every case, the profit margin estimates for a project will either increase or decrease to some extent from the amount that was originally estimated at the time of the related bid. Because we have many projects of varying levels of complexity and size in process at any given time, these changes in estimates can offset each other without materially impacting our profitability. However, sizable changes in cost estimates, particularly in larger, more complex projects, can have a significant effect on profitability. Factors that can contribute to changes in estimates of contract cost and profitability include, without limitation:

• |  | site conditions that differ from those assumed in the original bid, to the extent that contract remedies are unavailable;
• |  | identification and evaluation of scope modifications during the execution of the project;
• |  | the availability and cost of skilled workers in the geographic location of the project;

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• |  | the availability and proximity of materials;
• |  | unfavorable weather conditions hindering productivity;
• |  | equipment productivity and timing differences resulting from project construction not starting on time; and
• |  | general coordination of work inherent in all large projects we undertake.

The foregoing factors, as well as the stage of completion of contracts in process and the mix of contracts at different margins, may cause fluctuations in gross profit between periods and these fluctuations may be significant. These changes in cost estimates and revenue recognition impact all three business segments, namely, Heavy Construction and Mining, Piling and Pipeline.
Once contract performance 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 change orders and claims are recognized when they are incurred. Change orders are included in total estimated contract revenue when it is probable that the change order will result in a bona fide addition to contract value and can be reliably estimated. Claims are included in total estimated contract revenue, only to the extent that contract costs related to the claim have been incurred and when it is probable that the claim will result in a bona fide addition to contract value and can be reliably estimated. Those two conditions are satisfied when (1) the contract or other evidence provides a legal basis for the claim or a legal opinion is obtained providing a reasonable basis to support the claim, (2) additional costs incurred were caused by unforeseen circumstances and are not the result of deficiencies in our performance, (3) costs associated with the claim are identifiable and reasonable in view of work performed and (4) evidence supporting the claim is objective and verifiable. No profit is recognized on claims until final settlement occurs. This can lead to a situation where costs are recognized in one period and revenue is recognized when customer agreement is obtained or claim resolution occurs, which can be in subsequent periods. Historical claim recoveries should not be considered indicative of future claim recoveries.
Plant and equipment
The most significant estimates in accounting for plant and equipment are the expected useful life of the asset and the expected residual value. Most of our property, plant and equipment have long lives that can exceed 20 years with proper repair work and preventative maintenance. Useful life is measured in operating hours, excluding idle hours and a depreciation rate is calculated for each type of unit. Depreciation expense is determined monthly based on daily actual operating hours.
Another key estimate is the expected cash flows from the use of an asset and the expected disposal proceeds in applying Canadian Institute of Chartered Accountants Handbook Section 3063 “Impairment of Long-Lived Assets’’ and Section 3475 “Disposal of Long-Lived Assets and Discontinued Operations’’. These standards require the recognition of an impairment loss for a long-lived asset when changes in circumstances cause its carrying value to exceed the total undiscounted cash flows expected from its use. An impairment loss, if any, is determined as the excess of the carrying value of the asset over its fair value.
Goodwill impairment
Impairment is tested at the reporting unit level by comparing the reporting unit’s carrying amount to its fair value. The process of determining fair value is subjective and requires us to exercise judgment in making assumptions about future results, including revenue and cash flow projections at the reporting unit level and discount rates. We previously tested goodwill annually on December 31. For the current fiscal year we completed the goodwill impairment testing on October 1. This change in timing was made to reduce conflict between the impairment testing and our financial reporting close process for the third quarter ending December 31. It is our intention to continue to complete subsequent goodwill impairment testing on October 1 going forward. This change in accounting policy was applied on a retrospective basis and has no impact on the consolidated financial statements.
Financial instruments
In determining the fair value of financial instruments, 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.
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Related Parties
We may receive consulting and advisory services provided by the Sponsors (principals or employees of such Sponsors are our directors) with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters, and no fee is charged for these consulting and advisory services.
In order for the Sponsors to provide such advice and consulting we provide reports, financial data and other information. This permits them to consult with and advise our management on matters relating to our operations, company affairs and finances.
In addition, this permits them to visit and inspect any of our properties and facilities. The transactions are in the normal course of operations and are measured at the exchange amount of consideration established and agreed to by the related parties.
Recently Adopted Accounting Policies
Financial instruments
Our derivative financial instruments related to cross-currency and interest rate swaps are not designated as hedges for accounting purposes and are recorded on the balance sheet at fair value, which is determined based on values quoted by the counterparties to the agreements. The primary factors affecting fair value are the changes in the interest rate term structures in the US and Canada, the life of the swaps and the CAD/USD foreign exchange spot rate.
Effective April 1, 2007, we adopted the new standards issued by the CICA on financial instruments, hedges and comprehensive income. Section 1530, “Comprehensive income”, Section 3855, “Financial instruments-recognition and measurement”, Section 3861, “Financial instruments-disclosure and presentation” and Section 3865, “Hedges”, were effective for our first quarter of fiscal 2008.
On April 1, 2007, we made the following transitional adjustments to our consolidated balance sheet to adopt the new standards (in thousands of dollars):

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

We identified an additional embedded derivative that is not closely related to the host contract in the fourth quarter of 2008 with respect to price escalation features in a supplier contract. The embedded derivative has been measured at fair value and included in derivative financial instruments on the consolidated balance sheet, with changes in fair value recognized in net income. We recorded the fair value of $2,474 related to this embedded derivative on April 1, 2007, with corresponding increase in opening deficit of $1,769, net of future income taxes of $705.
The details of the transitional adjustments are noted below.
The impact of the new standards on our income before income taxes for the three months and year ended March 31, 2008 is as follows (in thousands of dollars):

|  | Three Months |  |  | Twelve Months |
|  | Ended March 31, |  |  | Ended March 31, |
|  | 2008 |  |  | 2008 |
Decrease in interest expense due to change in method of amortizing deferred financing costs and discounts (premiums), net |  |  | $(353 | ) |  |  | $(1,250 | )
(Increase) decrease in unrealized foreign exchange gain on senior notes |  |  | (121 | ) |  |  | 212 |
Increase (decrease) in unrealized loss on derivative financial instruments |  |  | (490 | ) |  |  | 4,530 |
Decrease (increase) in income before income taxes |  |  | $(964 | ) |  |  | $3,492 |

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The new standards require all financial assets and liabilities to be carried at fair value in our consolidated balance sheet, except for loans and receivables, held-to-maturity investments and other financial liabilities, which are carried at their amortized cost. We do not currently have any financial assets designated as available-for-sale. On adoption of the standard, we have classified our cash and cash equivalents as held for trading and accounts receivable and unbilled revenue as loans and receivables and revolving credit facility, accounts payable, accrued liabilities and senior notes as other financial liabilities.
All derivatives, including embedded derivates that must be separately accounted for, are measured at fair value in our consolidated balance sheet. The types of hedging relationships that qualify for hedge accounting have not changed under the new standards. We currently do not designate any of these derivatives as hedging instruments for accounting purposes.
Derivatives may be embedded in financial instruments (the “host instrument”). Under the new standards, embedded derivatives are treated as separate derivatives when their economic characteristics and risks are not closely related to those of the host instrument, the terms of the embedded derivative are similar to those of a stand-alone derivative and the combined contract is not held-for-trading or designated at fair value. These embedded derivatives are measured at fair value with subsequent changes recognized in income. We have elected April 1, 2003 as our transition date for identifying contracts with embedded derivatives. Currently we have prepayment options that are embedded in our senior notes and foreign exchange rate and price index escalation/de-escalation features in a long-term construction contract and supplier contract, which meet the criteria for bifurcation. The impact of the prepayment options and escalation/de-escalation clauses on our consolidated financial statements is described below and in our consolidated financial statements for the year ended March 31, 2008.
In determining the fair value of our financial instruments, we used a variety of valuation methods and assumptions that are based on market conditions and risks existing on each reporting date. Standard market conventions and techniques, such as discounted cash flow analysis and option pricing models, are used to determine the fair value of our financial instruments, including derivatives. All methods of fair value measurement result in a general approximation of value and such value may never actually be realized.
The transitional impact of adopting the new financial instruments standards as at April 1, 2007 on our consolidated financial statements is as follows:
Embedded derivatives:
We determined that the issuer’s early prepayment option included in the senior notes should be bifurcated from the host contract, along with a contingent embedded derivative in the senior notes that provides for accelerated redemption by the holders in certain instances. These embedded derivatives were measured at fair value at the inception of the senior notes and the residual amount of the proceeds was allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of the senior notes is accreted to the par value over the term of the notes using the effective interest method and is recognized as interest expense. At transition on April 1, 2007, we recorded the fair value of $8.5 million related to these embedded derivatives and a corresponding decrease in opening deficit of $7.3 million, net of future income taxes of $1.2 million. The impact of the bifurcation of these embedded derivatives at issuance of the senior notes resulted in an increase in senior notes of $5.7 million and an increase in opening deficit of $4.0 million, net of income taxes of $1.7 million, after applying the effective interest method to the premium resulting from the bifurcation of these embedded derivatives on April 1, 2007.
We also have foreign exchange rate and price index escalation/de-escalation features in a long-term construction contract and supplier contract that qualify as an embedded derivative. These amounts must be separated for reporting in accordance with the new standards. As at April 1, 2007, we separated the fair value of the embedded derivative liability of $9.7 million from the contracts, resulting in a corresponding increase to opening deficit of $6.9 million, net of future income taxes of $2.8 million.
Effective interest method:
We incurred underwriting commissions and expenses relating to our senior notes offering. Previously, these costs were classified as long-term assets and amortized on a straight-line basis over the term of the debt. The new standard requires us to reclassify the costs as a reduction in the cost of debt and to use the effective interest rate method to amortize the deferred amounts to interest expense. As at April 1, 2007, we reclassified $9.7 million of unamortized costs from deferred financing costs to long-term debt and recorded an adjustment to the unamortized cost balance as if the effective interest rate method had been used since inception.
Transaction costs incurred in connection with our revolving credit facility of $1,622 were reclassified from deferred financing costs to intangible assets on April 1, 2007 and these costs continue to be amortized on a straight-line basis over the term of the facility.
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Revised CICA Handbook Section 3861, “Financial Instruments – Disclosure and Presentation” replaces CICA Handbook Section 3860, “Financial Instruments – Disclosure and Presentation” and establishes standards for presentation of financial instruments and non-financial derivatives and identifies information that should be disclosed. There was no material effect on our financial statements upon adoption of CICA Handbook Section 3861 effective April 1, 2007.
Comprehensive income and equity
Effective April 1, 2007, we adopted CICA Handbook Section 1530, “Comprehensive Income”, which establishes standards for the reporting and display of comprehensive income. The new section defines other comprehensive income to include revenues, expenses, and gains and losses that, in accordance with primary sources of GAAP, are recognized in comprehensive income but excluded from net income. The standard does not address issues of recognition or measurement for comprehensive income and its components. The adoption of this standard did not have a material impact on our financial statement presentation in the current year.
Effective April 1, 2007, we adopted CICA Handbook Section 3251 “Equity”, which establishes standards for the presentation of equity and changes in equity during the reporting period. The requirements in this section are in addition to those of Section 1530 and recommend that an enterprise should present separately the following components of equity: retained earnings, accumulated other comprehensive income, the total for retained earnings and accumulated other comprehensive income, contributed surplus, share capital and reserves. The adoption of CICA Handbook Section 3251 did not have an impact on the Company’s financial statement presentation in the current period. We currently have no accumulated other comprehensive income components.
Accounting changes
In July 2006, the CICA revised Handbook Section 1506, “Accounting Changes”, which requires that: (1) voluntary changes in accounting policy are made only if they result in the financial statements providing reliable and more relevant information; (2) changes in accounting policy are generally applied retrospectively; and (3) prior period errors are corrected retrospectively. This guidance was adopted by us on April 1, 2007 and did not have a material impact on the consolidated financial statements.
Accounting policy choice for transaction costs
In June 2007, the CICA issued Emerging Issues Committee Abstract No. 166, “Accounting Policy Choice for Transaction Costs” (“EIC-166”). CICA Handbook Section 3855 requires that when an entity acquires a financial asset or incurs a financial liability classified other than as held-for-trading, it adopts an accounting policy for transaction costs of either: (a) recognizing all transaction costs in net income; or (b) adding transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability to the carrying amount of the financial instrument. EIC- 166 clarifies that the same accounting policy choice should be made for all similar instruments classified as other than held-for-trading, but that a different accounting policy choice may be made for financial instruments that are not similar. As described in note 3(q)(i), our accounting policy is to add transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability to the carrying amount of the financial instrument. This guidance was adopted by us on April 1, 2007 and did not have a material impact on the consolidated financial statements.
Recent Accounting Pronouncements Not Yet Adopted
Capital disclosures
In December 2006, the CICA issued Handbook Section 1535, “Capital Disclosures”. This standard requires that an entity disclose information that enables users of its financial statements to evaluate an entity’s objectives, policies and processes for managing capital, including disclosures of any externally imposed capital requirements and the consequences of non-compliance. The new standard applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company. Disclosures required by the new standard will be included in our interim and annual consolidated financial statements commencing April 1, 2008.
Financial instruments – disclosure and presentation
In March 2007, the CICA issued Handbook Section 3862, “Financial Instruments–Disclosures”, which replaces CICA 3861 and provides expanded disclosure requirements that provide additional detail by financial assets and liability categories to enhance financial statement users’ understanding of the significance of financial instruments to an entity’s financial position, performance and cash flows. This standard harmonizes disclosures with International Financial Reporting Standards. The standard applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company. Disclosures required by the new standard will be included in our interim and annual consolidated financial statements commencing April 1, 2008.
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In March 2007, the CICA issued Handbook Section 3863, “Financial Instruments–Presentation”. This Section establishes standards for presentation of financial instruments and non-financial derivatives. It deals with the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, gains and losses, and the circumstances in which financial assets and financial liabilities are offset. This standard harmonizes disclosures with International Financial Reporting Standards and applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company and is not expected to have a material impact on the consolidated financial statements.
Inventories
In June 2007, the CICA issued Handbook Section 3031, “Inventories” to harmonize accounting for inventories under Canadian GAAP with International Financial Reporting Standards. This standard requires the measurement of inventories at the lower of cost and net realizable value and includes guidance on the determination of cost, including allocation of overheads and other costs to inventory. The standard also requires the consistent use of either first-in, first out (FIFO) or weighted average cost formula to measure the cost of other inventories and requires the reversal of previous write-downs to net realizable value when there is a subsequent increase in the value of inventories. The new standard applies to interim and annual financial statements relating to fiscal years beginning on or after January 1, 2008, specifically April 1, 2008 for the Company. We are currently evaluating the impact of this standard.
Going concern
In April 2007, the CICA approved amendments to Handbook Section 1400, “General Standards of Financial Statement Presentation”. These amendments require management to assess an entity’s ability to continue as a going concern. When management is aware of material uncertainties related to events or conditions that may cast doubt on an entity’s ability to continue as a going concern, those uncertainties must be disclosed. In assessing the appropriateness of the going concern assumption, the standard requires management to consider all available information about the future, which is at least, but not limited to, 12 months from the balance sheet date. The new requirements of the standard are applicable for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2008, specifically April 1, 2008 for the Company. We are currently evaluating the impact of this standard.
Goodwill and intangible assets
In February 2008, the CICA issued Handbook Section 3064, (“CICA 3064”) Goodwill and Intangible Assets. CICA 3064, which replaces Section 3062, Goodwill and Intangible Assets, and Section 3450, Research and Development Costs, establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The provisions relating to the definition and initial recognition of intangible assets, including internally generated intangible assets, are equivalent to the corresponding provisions of International Financial Reporting Standard IAS 38, Intangible Assets. This new standard is effective for interim and annual consolidated financial statements commencing April 1, 2009. We are currently evaluating the impact of this standard.
G. Forward-Looking Information and Risk Factors
Forward-Looking Information
This document contains forward-looking information that is based on expectations and estimates as of the date of this document. Our forward-looking information is information that is subject to known and unknown risks and other factors that may cause future actions, conditions or events to differ materially from the anticipated actions, conditions or events expressed or implied by such forward-looking information. Forward-looking information is information that does not relate strictly to historical or current facts, and can be identified by the use of the future tense or other forward-looking words such as “believe”, “expect”, “anticipate”, “intend”, “plan”, “estimate”, “should”, “may”, “could,” “would,” “should,” “target,” “objective”, “projection”, “forecast”, “continue”, “strategy”, “intend,” “position” or the negative of those terms or other variations of them or comparable terminology.
Examples of such forward-looking information in this document include but are not limited to statements with respect to the following, each of which is subject to significant risks and uncertainties and is based on a number of assumptions which may prove to be incorrect:

(a) |  | the limited risk that royalty changes will cause our customers to cancel, delay or reduce the scope of any significant mining developments presently underway;
(b) |  | the expected continued rapid growth of operators in the oil sands business, their planned projects and our intention to pursue business opportunities from these projects;
(c) |  | our intention to increase our fleet size to be ready to meet the challenges from the projected growth in oil sands;

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(d) |  | that acquisition opportunities will materialize that will allow us to expand our complementary service offerings which we will be able to cross-sell with our existing services;
(e) |  | our intention to increase our presence outside the oil sands and extend our services to other resource industries across Canada;
(f) |  | the success of the enhancements to maintenance practices resulting in improved availability through reduced repair time and increased utilization of our equipment with a consequent improvement in our revenue, margins and profitability;
(g) |  | the amount of our backlog expected to be performed and realized in the 12 months ending March 31, 2009 (such estimates assist us in planning our activity level and may not be suitable for other purposes);
(h) |  | the expected growth in master services Agreements through 2009;
(i) |  | the arrival of new projects and our required participation in the bidding process for work on such projects;
(j) |  | the continued development of the oil sands and the expectation that it will drive a significant portion of our 2009 revenue;
(k) |  | our commencement of work in the latter half of fiscal 2009 at Imperial Oil’s upcoming Kearl project;
(l) |  | the anticipated increased demand for our services at Petro-Canada’s Fort Hills site;
(m) |  | our expected increased involvement with Baffinland Iron Mines Corp.;
(n) |  | the demand for our piling services remaining strong in fiscal 2009;
(o) |  | the anticipated temporary slowdown in our pipeline activity once the TMX project concludes in October 2008 and significant long-term opportunities for this division; and
(p) |  | our expected generation of a net cash surplus in fiscal 2009.

Some of the risks and other factors which could cause results to differ materially from those expressed in the forward-looking statements contained in this document include, but are not limited to:
The forward-looking information in paragraphs (a), (b), (i), (j), (k), (l), (m), (n) and (o) rely on certain market conditions and demand for our services and are based on the assumptions that; the global economy remains strong and the demand for commodities, particularly oil, remains high; high demand for commodities results in strong prices which drive the development of Canada’s natural resources, in particular the oil sands; the oil sands continue to be an economically viable source of energy and our customers and potential customers continue to invest in the oil sands and other natural resources developments; our customers and potential customers will continue to outsource the type of activities for which we are capable of providing service; and the Western Canadian economy continues to develop with additional investment in commercial and public construction; and are subject to the risks and uncertainties that:

• |  | anticipated major projects in the oil sands may not materialize;
• |  | demand for our services may be adversely impacted by regulations affecting the energy industry;
• |  | failure by our customers to obtain required permits and licenses may affect the demand for our services;
• |  | changes in our customers’ perception of oil prices over the long term could cause our customers to defer, reduce or stop their investment in oil sands projects, which would, in turn, reduce our revenue from those customers;
• |  | insufficient pipeline, upgrading and refining capacity or lack of sufficient governmental infrastructure to support growth in the oil sands region could cause our customers to delay, reduce or cancel plans to construct new oil sands projects or expand existing projects, which would, in turn, reduce our revenue from those customers;
• |  | a change in strategy by our customers to reduce outsourcing could adversely affect our results;
• |  | cost overruns by our customers on their projects may cause our customers to terminate future projects or expansions which could adversely affect the amount of work we receive from those customers;
• |  | because most of our customers are Canadian energy companies, a downturn in the Canadian energy industry could result in a decrease in the demand for our services;
• |  | shortages of qualified personnel or significant labour disputes could adversely affect our business; and
• |  | unanticipated short-term shutdowns of our customers’ operating facilities may result in temporary cessation or cancellation of projects in which we are participating.

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The forward-looking information in paragraphs (c), (d), (e), (f), (g), (h), (i), (j), (k), (l), (m), (n), (o) and (p) rely on our ability to execute our growth strategy and are based on the assumptions that; the management team can successfully manage the business, we can maintain and develop our relationships with our current customers, we will be successful in developing relationships with new customers, we will be successful in the competitive bidding process to secure new projects, and that we will identify and implement improvements in our maintenance and fleet management practices; and are subject to the risks and uncertainties that:

• |  | our ability to grow our operations in the future may be hampered by our inability to obtain long lead time equipment and tires, which are currently in limited supply;
• |  | if we are unable to obtain surety bonds or letters of credit required by some of our customers, our business could be impaired;
• |  | we are dependent on our ability to lease equipment, and a tightening of this form of credit could adversely affect our ability to bid for new work and/or supply some of our existing contracts;
• |  | our business is highly competitive and competitors may outbid us on major projects that are awarded based on bid proposals;
• |  | our customer base is concentrated, and the loss of or a significant reduction in business from a major customer could adversely impact our financial condition;
• |  | lump-sum and unit-price contracts expose us to losses when our estimates of project costs are lower than actual costs;
• |  | our operations are subject to weather-related factors that may cause delays in our project work;
• |  | environmental laws and regulations may expose us to liability arising out of our operations or the operations of our customers; and
• |  | many of our senior officers have either recently joined the Company or have just been promoted and have only worked together as a management team for a short period of time.

While we anticipate that subsequent events and developments may cause our views to change, we do not have an intention to update this forward-looking information, except as required by applicable securities laws. This forward-looking information represents our views as of the date of this document and such information should not be relied upon as representing our views as of any date subsequent to the date of this document. We have attempted to identify important factors that could cause actual results, performance or achievements to vary from those current expectations or estimates expressed or implied by the forward-looking information. However, there may be other factors that cause results, performance or achievements not to be as expected or estimated and that could cause actual results, performance or achievements to differ materially from current expectations. There can be no assurance that forward-looking information will prove to be accurate, as actual results and future events could differ materially from those expected or estimated in such statements. Accordingly, readers should not place undue reliance on forward-looking information. These factors are not intended to represent a complete list of the factors that could affect us. See “Risk Factors” below and risk factors highlighted in materials filed with the securities regulatory authorities filed in the United States and Canada from time to time.
Risk Factors
Anticipated major projects in the oil sands may not materialize.
Notwithstanding the National Energy Board’s estimates regarding new investment and growth in the Canadian oil sands, planned and anticipated projects in the oil sands and other related projects may not materialize. The underlying assumptions on which the projects are based are subject to significant uncertainties and actual investments in the oil sands could be significantly less than estimated. Projected investments and new projects may be postponed or cancelled for any number of reasons, including among others:

• |  | changes in the perception of the economic viability of these projects;
• |  | shortage of pipeline capacity to transport production to major markets;
• |  | lack of sufficient governmental infrastructure to support growth;
• |  | delays in issuing environmental permits or refusal to grant such permits;
• |  | shortage of skilled workers in this remote region of Canada; and
• |  | cost overruns on announced projects.

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Demand for our services may be adversely impacted by regulations affecting the energy industry.
Our principal customers are energy companies involved in the development of the oil sands and in natural gas production. The operations of these companies, including their mining operations in the oil sands, are subject to or impacted by a wide array of regulations in the jurisdictions where they operate, including those directly impacting mining activities and those indirectly affecting their businesses, such as applicable environmental laws. As a result of changes in regulations and laws relating to the energy production industry, including the operation of mines, our customers’ operations could be disrupted or curtailed by governmental authorities. The high cost of compliance with applicable regulations may cause customers to discontinue or limit their operations, and may discourage companies from continuing development activities. As a result, demand for our services could be substantially affected by regulations adversely impacting the energy industry.
Failure by our customers to obtain required permits and licenses may affect the demand for our services.
The development of the oil sands requires our customers to obtain regulatory and other permits and licenses from various governmental licensing bodies. Our customers may not be able to obtain all necessary permits and licenses that may be required for the development of the oil sands on their properties. In such a case, our customers’ projects will not proceed, thereby adversely impacting demand for our services.
Changes in our customers’ perception of oil prices over the long-term could cause our customers to defer, reduce or stop their investment in oil sands projects, which would, in turn, reduce our revenue from those customers.
Due to the amount of capital investment required to build an oil sands project, or construct a significant expansion to an existing project, investment decisions by oil sands operators are based upon long-term views of the economic viability of the project. Economic viability is dependent upon the anticipated revenues the project will produce, the anticipated amount of capital investment required and the anticipated cost of operating the project. The most important consideration is the customer’s view of the long-term price of oil which is influenced by many factors, including the condition of developed and developing economies and the resulting demand for oil and gas, the level of supply of oil and gas, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political conditions in oil producing nations, including those in the Middle East, war or the threat of war in oil producing regions and the availability of fuel from alternate sources. If our customers believe the long-term outlook for the price of oil is not favorable, or believes oil sands projects are not viable for any other reason, they may delay, reduce or cancel plans to construct new oil sands projects or expansions to existing projects. Delays, reductions or cancellations of major oil sands projects would adversely affect our prospects and could have a material adverse impact on our financial condition and results of operations.
Insufficient pipeline, upgrading and refining capacity could cause our customers to delay, reduce or cancel plans to construct new oil sands projects or expand existing projects, which would, in turn, reduce our revenue from those customers.
For our customers to operate successfully in the oil sands, they must be able to transport the bitumen produced to upgrading facilities and transport the upgraded oil to refineries. Some oil sands projects have upgraders at mine site and others transport bitumen to upgraders located elsewhere. While current pipeline and upgrading capacity is sufficient for current production, future increases in production from new oil sands projects and expansions to existing projects will require increased upgrading and pipeline capacity. If these increases do not materialize, whether due to inadequate economics for the sponsors of such projects, shortages of labor or materials or any other reason, our customers may be unable to efficiently deliver increased production to market and may therefore delay, reduce or cancel planned capital investment. Such delays, reductions or cancellations of major oil sands projects would adversely affect our prospects and could have a material adverse impact on our financial condition and results of operations.
Lack of sufficient governmental infrastructure to support the growth in the oil sands region could cause our customers to delay, reduce or cancel their future expansions, which would, in turn, reduce our revenue from those customers.
The development in the oil sands region has put a great strain on the existing government infrastructure, necessitating substantial improvements to accommodate growth in the region. The local government having responsibility for a majority of the oil sands region has been exceptionally impacted by this growth and is not currently in a position to provide the necessary additional infrastructure. In an effort to delay further development until infrastructure funding issues are resolved, the local governmental authority has intervened in two recent hearings considering applications by major oil sands companies to the EUB for approval to expand their operations. Similar action could be taken with respect to any future applications. The EUB has issued conditional approval for the expansion in respect of one of the hearings despite the intervention by the local government authority, and a decision in the second hearing is pending. The EUB has indicated that it believes that additional infrastructure investment in the oil sands region is needed and that there is a short window of opportunity to make these investments in parallel with continued oil sands development. If the necessary infrastructure is not put in place, future growth of our customers’ operations could be delayed, reduced or canceled which could in turn adversely affect our prospects and could have a material adverse impact on our financial condition and results of operations.
48 Management’s Discussion and Analysis North American Energy Partners Inc.

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Shortages of qualified personnel or significant labor disputes could adversely affect our business.
Alberta, and in particular the oil sands area, has had and continues to have a shortage of skilled labor and other qualified personnel. New mining projects in the area will only make it more difficult for us and our customers to find and hire all the employees required to work on these projects. We are continuously exploring innovative ways to hire the project managers, trades people and other skilled employees that we need. We have expanded our search efforts outside of Canada to find qualified candidates who might relocate to our area. In addition, we have undertaken more extensive training of existing employees and we are enhancing our use of technology and developing programs to provide better working conditions. We believe the labor shortage, which affects us and all of our major customers, will continue to be a challenge for everyone in the mining and oil and gas industries in Western Canada for the foreseeable future. If we are not able to recruit and retain enough employees with the appropriate skills, we may be unable to maintain our customer service levels, and we may not be able to satisfy any increased demand for our services. This, in turn, could have a material adverse effect on our business, financial condition and results of operations. If our customers are not able to recruit and retain enough employees with the appropriate skills, they may be unable to develop projects in the oil sands area.
Substantially all of our hourly employees are subject to collective bargaining agreements to which we are a party or are otherwise subject. Any work stoppage resulting from a strike or lockout could have a material adverse effect on our business, financial condition and results of operations. In addition, our customers employ workers under collective bargaining agreements. Any work stoppage or labor disruption experienced by our key customers could significantly reduce the amount of our services that they need.
Cost overruns by our customers on their projects may cause our customers to terminate future projects or expansions which could adversely affect the amount of work we receive from those customers.
Oil sands development projects require substantial capital expenditures. In the past, several of our customers’ projects have experienced significant cost overruns, impacting their returns. If cost overruns continue to challenge our customers, they could reassess future projects and expansions which could adversely affect the amount of work we receive from our customers.
Our ability to grow our operations in the future may be hampered by our inability to obtain long lead time equipment and tires, which are currently in limited supply.
Our ability to grow our business is, in part, dependent upon obtaining equipment on a timely basis. Due to the long production lead times of suppliers of large mining equipment, we must forecast our demand for equipment many months or even years in advance. If we fail to forecast accurately, we could suffer equipment shortages or surpluses, which could have a material adverse impact on our financial condition and results of operations.
Global demand for tires of the size and specifications we require is exceeding the available supply. For example, two of our trucks are currently not in service because we cannot get tires for these particular trucks. We expect the supply/ demand imbalance for certain tires to continue for several years. Our inability to procure tires to meet the demands for our existing fleet as well as to meet new demand for our services could have an adverse effect on our ability to grow our business.
Our customer base is concentrated, and the loss of or a significant reduction in business from a major customer could adversely impact our financial condition.
Most of our revenue comes from the provision of services to a small number of major oil sands mining companies. Revenue from our five largest customers represented approximately 81%, 65% and 69% of our total revenue for fiscal years 2008, 2007 and 2006, respectively, and those customers are expected to continue to account for a significant percentage of our revenues in the future. In addition, the majority of our Pipeline revenues in the current and previous fiscal years resulted from work performed for one customer. If we lose or experience a significant reduction of business from one or more of our significant customers, we may not be able to replace the lost work with work from other customers. Our long-term contracts typically allow our customers to unilaterally reduce or eliminate the work which we are to perform under the contract. Our contracts also generally allow the customer to terminate the contract without cause. The loss of or significant reduction in business with one or more of our major customers, whether as a result of completion of a contract, early termination or failure or inability to pay amounts owed to us, could have a material adverse effect on our business and results of operations.
Because most of our customers are Canadian energy companies, a downturn in the Canadian energy industry could result in a decrease in the demand for our services.
Most of our customers are Canadian energy companies. A downturn in the Canadian energy industry could cause our customers to slow down or curtail their current production and future expansions which would, in turn, reduce our revenue from those customers. Such a delay or curtailment could have a material adverse impact on our financial condition and results of operations.
North American Energy Partners Inc. Management’s Discussion and Analysis 49

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

• |  | site conditions differing from those assumed in the original bid;
• |  | scope modifications during the execution of the project;
• |  | the availability and cost of skilled workers;
• |  | the availability and proximity of materials;
• |  | unfavorable weather conditions hindering productivity;
• |  | inability or failure of our customers to perform their contractual commitments;
• |  | equipment availability and productivity and timing differences resulting from project construction not starting on time; and
• |  | the general coordination of work inherent in all large projects we undertake.

When we are unable to accurately estimate the costs of lump-sum and unit-price contracts, or when we incur unrecoverable cost overruns, the related projects result in lower margins than anticipated or may incur losses, which could adversely impact our results of operations, financial condition and cash flow.
Until we establish and maintain effective internal controls over financial reporting, we cannot assure you that we will have appropriate procedures in place to eliminate future financial reporting inaccuracies and avoid delays in financial reporting.
We have identified a number of material weaknesses in our financial reporting processes and internal controls. See “Management’s Report on Internal Controls over Financial Reporting.” As a result, there can be no assurance that we will be able to generate accurate financial reports in a timely manner. Failure to do so would cause us to breach the U.S. and Canadian securities regulations with respect to reporting requirements in the future as well as the covenants applicable to our indebtedness. This could, in turn, have a material adverse effect on our business and financial condition. Until we establish and maintain effective internal controls and procedures for financial reporting, we may not have appropriate measures in place to eliminate financial statement inaccuracies and avoid delays in financial reporting.
Our substantial debt could adversely affect us, make us more vulnerable to adverse economic or industry conditions and prevent us from fulfilling our debt obligations.
We have a substantial amount of debt outstanding and significant debt service requirements. As of March 31, 2008, we had outstanding $213.0 million of debt, including $14.8 million of capital leases. We also had cross-currency and interest rate swaps with a balance sheet liability of $81.6 million as of March 31, 2008. These swaps are secured equally and ratably with our revolving credit facility. Our substantial indebtedness could have serious consequences, such as:

• |  | limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements, potential growth or other purposes;
• |  | limiting our ability to use operating cash flow in other areas of our business;
• |  | limiting our ability to post surety bonds required by some of our customers;
• |  | placing us at a competitive disadvantage compared to competitors with less debt;
• |  | increasing our vulnerability to, and reducing our flexibility in planning for, adverse changes in economic, industry and competitive conditions; and
• |  | increasing our vulnerability to increases in interest rates because borrowings under our revolving credit facility and payments under some of our equipment leases are subject to variable interest rates.

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

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The terms of our debt agreements may restrict our current and future operations, particularly our ability to respond to changes in our business or take certain actions.
Our revolving credit facility and the indenture governing our notes limit, among other things, our ability and the ability of our subsidiaries to:

• |  | incur or guarantee additional debt, issue certain equity securities or enter into sale and leaseback transactions;
• |  | pay dividends or distributions on our shares or repurchase our shares, redeem subordinated debt or make other restricted payments;
• |  | incur dividend or other payment restrictions affecting certain of our subsidiaries;
• |  | issue equity securities of subsidiaries;
• |  | make certain investments or acquisitions;
• |  | create liens on our assets;
• |  | enter into transactions with affiliates;
• |  | consolidate, merge or transfer all or substantially all of our assets; and
• |  | transfer or sell assets, including shares of our subsidiaries.

Our revolving credit facility also requires us, and our future credit facilities may require us, to maintain specified financial ratios and satisfy specified financial tests, some of which become more restrictive over time. Our ability to meet these financial ratios and tests can be affected by events beyond our control, and we may be unable to meet those tests.
As a result of these covenants, our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be significantly restricted, and we may be prevented from engaging in transactions that might otherwise be considered beneficial to us. The breach of any of these covenants could result in an event of default under our revolving credit facility or any future credit facilities or under the indenture governing our notes. Under our revolving credit facility, our failure to pay certain amounts when due to other creditors, including to certain equipment lessors, or the acceleration of such other indebtedness, would also result in an event of default. Upon the occurrence of an event of default under our revolving credit facility or future credit facilities, the lenders could elect to stop lending to us or declare all amounts outstanding under such credit facilities to be immediately due and payable. Similarly, upon the occurrence of an event of default under the indenture governing our notes, the outstanding principal and accrued interest on the notes may become immediately due and payable. If amounts outstanding under such credit facilities and indenture were to be accelerated, or if we were not able to borrow under our revolving credit facility, we could become insolvent or be forced into insolvency proceedings and you could lose your investment in us.
We may not be able to generate sufficient cash flow to meet our debt service and other obligations due to events beyond our control.
Our ability to generate sufficient operating cash flow to make scheduled payments on our indebtedness and meet other capital requirements will depend on our future operating and financial performance. Our future performance will be impacted by a range of economic, competitive and business factors that we cannot control, such as general economic and financial conditions in our industry or the economy generally.
A significant reduction in operating cash flows resulting from changes in economic conditions, increased competition, reduced work or other events could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on our business, financial condition, results of operations, prospects and our ability to service our debt and other obligations. If we are unable to service our indebtedness, we will be forced to adopt an alternative strategy that may include actions such as selling assets, restructuring or refinancing our indebtedness, seeking additional equity capital or reducing capital expenditures. We may not be able to affect any of these alternative strategies on satisfactory terms, if at all, or they may not yield sufficient funds to make required payments on our indebtedness.
Currency rate fluctuations could adversely affect our ability to repay our 8 3/4% senior notes and may affect the cost of goods we purchase.
We have entered into cross-currency and interest rate swaps that represent economic hedges of our 83/4% senior notes, which are denominated in U.S. dollars. The current exchange rate between the Canadian and U.S. dollars as compared to the rate implicit in the swap agreement has resulted in a large liability on the balance sheet under the caption “derivative financial instruments.” If the Canadian dollar increases in value or remains at its current value against the U.S. dollar, then if we repay the 83/4 senior notes prior to their maturity in 2011, we will have to pay this liability.
Exchange rate fluctuations may also cause the price of goods to increase or decrease for us. For example, a decrease in the value of the Canadian dollar compared to the U.S. dollar would proportionately increase the cost of equipment which is sold to us or priced in U.S. dollars.
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If we are unable to obtain surety bonds or letters of credit required by some of our customers, our business could be impaired.
We are at times required to post a bid or performance bond issued by a financial institution, known as a surety, to secure our performance commitments. The surety industry experiences periods of unsettled and volatile markets, usually in the aftermath of substantial loss exposures or corporate bankruptcies with significant surety exposure. Historically, these types of events have caused reinsurers and sureties to reevaluate their committed levels of underwriting and required returns. If for any reason, whether because of our financial condition, our level of secured debt or general conditions in the surety bond market, our bonding capacity becomes insufficient to satisfy our future bonding requirements, our business and results of operations could be adversely affected.
Some of our customers require letters of credit to secure our performance commitments. Our second amended and restated revolving credit facility provides for the issuance of letters of credit up to $125.0 million, and at March 31, 2008, we had $20.0 million of issued letters of credit outstanding. One of our major contracts allows the customer to require up to $50.0 million in letters of credit. If we were unable to provide letters of credit in the amount requested by this customer, we could lose business from such customer and our business and cash flow would be adversely affected. If our capacity to issue letters of credit under our revolving credit facility and our cash on hand is insufficient to satisfy our customers requirements, our business and results of operations could be adversely affected.
A change in strategy by our customers to reduce outsourcing could adversely affect our results.
Outsourced mining and site preparation services constitute a large portion of the work we perform for our customers. For example, our Heavy Construction and Mining project revenues constituted approximately 63%, 75%, and 74% of our revenues in each of fiscal years 2008, 2007 and 2006 respectively. The election by one or more of our customers to perform some or all of these services themselves, rather than outsourcing the work to us, could have a material adverse impact on our business and results of operations. Certain customers perform some of this work internally and may choose to expand on the use of internal resources to complete this work.
Our operations are subject to weather-related factors that may cause delays in our project work.
Because our operations are located in Western Canada and Northern Ontario, we are often subject to extreme weather conditions. While our operations are not significantly affected by normal seasonal weather patterns, extreme weather, including heavy rain and snow, can cause delays in our project work, which could adversely impact our results of operations.
We are dependent on our ability to lease equipment, and a tightening of this form of credit could adversely affect our ability to bid for new work and/or supply some of our existing contracts.
A portion of our equipment fleet is currently leased from third parties. Further, we anticipate leasing substantial amounts of equipment to perform the work on contracts for which we have been engaged in the upcoming year, particularly the overburden removal contract with CNRL. Other future projects may require us to lease additional equipment. If equipment lessors are unable or unwilling to provide us with the equipment we need to perform our work, our results of operations will be materially adversely affected.
Our business is highly competitive and competitors may outbid us on major projects that are awarded based on bid proposals.
We compete with a broad range of companies in each of our markets. Many of these competitors are substantially larger than we are. In addition, we expect the anticipated growth in the oil sands region will attract new and sometimes larger competitors to enter the region and compete against us for projects. This increased competition may adversely affect our ability to be awarded new business.
Approximately 80% of the major projects that we pursue are awarded to us based on bid proposals, and projects are typically awarded based in large part on price. We often compete for these projects against companies that have substantially greater financial and other resources than we do and therefore can better bear the risk of under pricing projects. We also compete against smaller competitors that may have lower overhead cost structures and, therefore, may be able to provide their services at lower rates than we can. Our business may be adversely impacted to the extent that we are unable to successfully bid against these companies. The loss of existing customers to our competitors or the failure to win new projects could materially and adversely affect our business and results of operations.
A significant amount of our revenue is generated by providing non-recurring services.
More than 61% of our revenue for 2008 was derived from projects which we consider to be non-recurring. This revenue primarily relates to site preparation and piling services provided for the construction of extraction, upgrading and other oil sands mining infrastructure projects.
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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.
Unanticipated short-term shutdowns of our customers’ operating facilities may result in temporary cessation or cancellation of projects in which we are participating.
The majority of our work is generated from the development, expansion and ongoing maintenance of oil sands mining, extraction and upgrading facilities. Unplanned shutdowns of these facilities due to events outside our control or the control of our customers, such as fires, mechanical breakdowns and technology failures, could lead to the temporary shutdown or complete cessation of projects in which we are working. When these events have happened in the past, our business has been adversely affected. Our ability to maintain revenues and margins may be affected to the extent these events cause reductions in the utilization of equipment.
Many of our senior officers have either recently joined the Company or have just been promoted and have only worked together as a management team for a short period of time.
We recently made several significant changes to our senior management team. We promoted our Vice President Business Development and Estimating to the role of Vice President Operations in September 2007. We promoted our Director of Business Development to the role of Vice President Business Development and Estimating in September 2007, we promoted our General Manager Heavy Construction and Mining to the role of Vice President Supply Chain in December
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2007 and in January 2008, we recruited and hired a new Chief Financial Officer and a new Vice President Finance. As a result of these and other recent changes in senior management, many of our officers have only worked together as a management team for a short period of time and do not have a long history with us. Because our senior management team is responsible for the management of our business and operations, failure to successfully integrate our senior management team could have an adverse impact on our business, financial condition and results of operations.
H. General Matters
History and Development of the Company
NACG Holdings Inc. (“Holdings”) was formed in October 2003 in connection with the acquisition discussed below. Prior to the acquisition, NACG Holdings Inc. had no operations or significant assets and the acquisition was primarily a change of ownership of the businesses acquired.
On October 31, 2003, two wholly owned subsidiaries of Holdings, as the buyers, entered into a purchase and sale agreement with Norama Ltd. and one of its subsidiaries, as the sellers. On November 26, 2003, pursuant to the purchase and sale agreement, Norama Ltd. sold to the buyers the businesses comprising North American Construction Group in exchange for total consideration of approximately $405.5 million, net of cash received and including the impact of certain post-closing adjustments. The businesses we acquired from Norama Ltd. have been in operation since 1953. Subsequent to the acquisition, we have operated the businesses in substantially the same manner as prior to the acquisition.
On November 28, 2006, prior to the consummation of the IPO discussed below, Holdings amalgamated with its wholly owned subsidiaries, NACG Preferred Corp and North American Energy Partners Inc. The amalgamated entity continued under the name North American Energy Partners Inc. The voting common shares of the new entity, North American Energy Partners Inc., were the shares sold in the IPO and related secondary offering. On November 28, 2006, we completed the IPO in the United States and Canada of 8,750,000 voting common shares and a secondary offering of 3,750,000 voting common shares for $18.38 per share (U.S. $16.00 per share).
On November 22, 2006 our common shares commenced trading on the New York Stock Exchange and on the Toronto Stock Exchange on an “if, as and when issued” basis. On November 28, 2006, our common shares became fully tradable on the Toronto Stock Exchange.
Net proceeds from the IPO were $140.9 million (gross proceeds of $158.5 million, less underwriting discounts and costs and offering expenses of $17.6 million). On December 6, 2006, the underwriters exercised their option to purchase an additional 687,500 common shares from us. The net proceeds from the exercise of the underwriters’ option were $11.7 million (gross proceeds of $12.6 million, less underwriting fees of $0.9 million). Total net proceeds were $152.6 million (total gross proceeds of $171.1 million less total underwriting discounts and costs and offering expenses of $18.5 million).
As of March 31, 2008, our authorized capital consists of an unlimited number of voting and non-voting common shares, of which 35,929,476 voting common shares were issued and outstanding.
Our head office is located at Zone 3, Acheson Industrial Area, 2 – 53016 Hwy 60, Acheson, Alberta, T7X 5A7. Our telephone and facsimile numbers are (780) 960-7171 and (780) 960-7103, respectively.
Transition to IFRS
The Canadian Accounting Standards Board announced in February 2008 that 2011 is the changeover date for publicly-listed companies to use International Financial Reporting Standards (IFRS), replacing Canada’s own Generally Accepted Accounting Principles (GAAP). The date is for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011. As a publicly listed company, we will start a project in July 2008 to address the impact of transitioning to IFRS. Specific areas to be addressed in the project include:

• |  | Accounting policies, including choices among policies permitted under IFRS, and implementation decisions, such as whether certain changes will be applied on a retrospective or a prospective basis
• |  | Information technology and data systems
• |  | Internal controls over financial reporting
• |  | Disclosure controls and procedures, including investor relations and external communications plans
• |  | Sufficiency of financial reporting expertise, including training requirements
• |  | Business activities that may be influenced by GAAP measures, such as foreign currency, hedging, debt covenants, capital requirements, and compensation arrangements.

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

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Management Report
The accompanying consolidated financial statements and all of the information in Management’s Discussion and Analysis (MD&A) are the responsibility of management of the Company. The consolidated financial statements were prepared by management in accordance with generally accepted accounting principles. Where alternative accounting methods exist, management has chosen those it considers most appropriate in the circumstances. The significant accounting policies used are described in note 3 to the consolidated financial statements. Certain amounts in the financial statements are based on estimates and judgments relating to matters not concluded by year end. The integrity of the information presented in the consolidated financial statements is the responsibility of management.
The Board of Directors is responsible for ensuring that management fulfills its responsibilities and for approval of the consolidated financial statements. The board carries out this responsibility through its Audit Committee. The Board has appointed an Audit Committee comprising three independent directors. The Audit Committee meets at least four times each year to discharge its responsibilities under a written mandate from the Board of Directors. The Audit Committee meets with management and with external auditors to satisfy itself that they are properly discharging their responsibilities; reviews the consolidated financial statements, MD&A, and the Report of Independent Registered Public Accounting Firm on the financial statements; and examines other auditing and accounting matters. The Audit Committee has reviewed the consolidated financial statements with management and discussed the quality of the accounting principles as applied and significant judgments affecting the consolidated financial statements. The Audit Committee has discussed with the external auditors, the external auditors’ judgments of the quality of those principles as applied and the judgments noted above. The consolidated financial statements and the MD&A have been reviewed by the Audit Committee and approved by the Board of Directors of North American Energy Partners Inc.
The consolidated financial statements have been examined by the shareholders’ auditors, KPMG LLP, Chartered Accountants. The Report of Independent Registered Public Accounting Firm on the financial statements outlines the nature of their examination and their opinion on the consolidated financial statements of the Company. The external auditors have full and unrestricted access to the Audit Committee.
Management’s Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining an adequate system of internal control over financial reporting. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Management conducted an evaluation of the effectiveness of the system of internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that the Company’s system of internal control over the financial reporting was not effective as of March 31, 2008. The details of this evaluation, conclusion and remediation plans are documented in the MD&A.
KPMG LLP, which has audited the consolidated financial statements of the Company for the year ended March 31, 2008, has also issued a report stating its opinion that the Company has not maintained effective internal control over financial reporting as of March 31, 2008 based on the criteria established in Internal Control – Integrated Framework issued by the COSO.

Rodney J. Ruston |  | Peter Dodd
President & Chief Executive Officer |  | Chief Financial Officer
June 20, 2008 |  | June 20, 2008

North American Energy Partners Inc. Financial Section 55

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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of North American Energy Partners Inc.
We have audited the accompanying consolidated balance sheets of North American Energy Partners Inc. (the “Company”) as of March 31, 2008 and 2007 and the related consolidated statements of operations, comprehensive income (loss) and deficit and cash flows for each of the years in the three-year period ended March 31, 2008. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of March 31, 2008 and 2007 and the results of its operations and its cash flows for each of the years in the three-year period ended March 31, 2008 in conformity with Canadian generally accepted accounting principles.
As discussed in Note 3 (q) (i) to the consolidated financial statements, the Company adopted new accounting pronouncements related to recognition and measurement of financial instruments in 2008.
Canadian generally accepted accounting principles vary in certain significant respects from U.S. generally accepted accounting principles. Information relating to the nature and effect of such differences is presented in Note 30 to the consolidated financial statements.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of March 31, 2008, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated June 20, 2008 expressed our opinion that the Company did not maintain effective internal control over financial reporting as of March 31, 2008.
Chartered Accountants
Edmonton, Canada
June 20, 2008, except as to note 31 which is as of June 25, 2008
Report of Independent Registered Public Accounting Firm
To the Board of Directors
of North American Energy Partners Inc.
We have audited North American Energy Partners Inc. (“the Company”)’s internal control over financial reporting as of March 31, 2008, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in Management’s Report on Internal Control over Financial Reporting in the accompanying Management’s Discussion and Analysis for the year ended March 31, 2008. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
56 Financial Section North American Energy Partners Inc.

#####

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s financial statements will not be prevented or detected on a timely basis. The following material weaknesses have been identified and included in management’s assessment:

– |  | There was a lack of sufficient accounting and finance personnel with an appropriate level of technical accounting knowledge and training to properly account for complex and non-routine transactions and to properly perform review and approval controls within the period-end financial reporting process;
– |  | A formal process to track claims and unapproved change orders and sufficient monitoring controls over the completeness and accuracy of forecasts, including the consideration of project changes subsequent to the end of each reporting period were not effectively implemented; and
– |  | Controls were not effective in the procurement process to track purchase commitments, reconcile vendor accounts and accurately accrue costs not invoiced by vendors at each reporting date.

We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the 2008 consolidated financial statements of the Company. These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2008 consolidated financial statements, and this report does not affect our report dated June 20, 2008, which expressed an unqualified opinion on those consolidated financial statements.
In our opinion, because of the effect of the aforementioned material weaknesses on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of March 31, 2008, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Chartered Accountants
Edmonton, Canada
June 20, 2008
North American Energy Partners Inc. Financial Section 57

#####

Consolidated Balance Sheets
As at March 31
(in thousands of Canadian dollars)

|  | 2008 |  |  | 2007 |
Assets |  |  |  |  |  |  |  |
Current assets: |  |  |  |  |  |  |  |
Cash and cash equivalents |  |  | $32,871 |  |  |  | $7,895 |
Accounts receivable (note 5) |  |  | 166,002 |  |  |  | 107,344 |
Unbilled revenue (note 6) |  |  | 70,883 |  |  |  | 68,709 |
Inventory |  |  | 110 |  |  |  | 156 |
Prepaid expenses and deposits (note 7) |  |  | 9,300 |  |  |  | 11,932 |
Asset held for sale (note 8) |  |  | – |  |  |  | 8,268 |
Other assets |  |  | 3,703 |  |  |  | 10,164 |
Future income taxes (notes 3(q)(i) and 17) |  |  | 8,217 |  |  |  | 14,593 |
|  |  | 291,086 |  |  |  | 229,061 |
Future income taxes (note 17) |  |  | 18,199 |  |  |  | 14,364 |
Assets held for sale (note 8) |  |  | 1,074 |  |  |  | – |
Plant and equipment (note 9) |  |  | 281,039 |  |  |  | 255,963 |
Goodwill |  |  | 200,072 |  |  |  | 199,392 |
Intangible assets, net of accumulated amortization of $2,105 (March 31, 2007 – $17,608) (notes 3(q)(i) and 10) |  |  | 2,128 |  |  |  | 600 |
Deferred financing costs, net of accumulated amortization of $nil (March 31, 2007 – $7,595) (notes 3(q)(i) and 11) |  |  | – |  |  |  | 11,356 |
|  |  | $793,598 |  |  |  | $710,736 |
Liabilities and Shareholders’ Equity |  |  |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |  |  |
Current portion of revolving credit facility (note 12) |  |  | $ – |  |  |  | $20,500 |
Accounts payable |  |  | 113,143 |  |  |  | 94,548 |
Accrued liabilities (note 14) |  |  | 45,078 |  |  |  | 23,393 |
Billings in excess of costs incurred and estimated earnings on uncompleted contracts (note 6) |  |  | 4,772 |  |  |  | 2,999 |
Current portion of capital lease obligations (note 15) |  |  | 4,733 |  |  |  | 3,195 |
Current portion of derivative financial instruments (notes 20 and 25(b)(i)) |  |  | 4,720 |  |  |  | 2,669 |
Future income taxes (notes 3(q)(i) and 17) |  |  | 10,907 |  |  |  | 4,154 |
|  |  | 183,353 |  |  |  | 151,458 |
Deferred lease inducements (note 13) |  |  | 941 |  |  |  | – |
Capital lease obligations (note 15) |  |  | 10,043 |  |  |  | 6,514 |
Senior notes (notes 3(q)(i) and 16) |  |  | 198,245 |  |  |  | 230,580 |
Director deferred stock unit liability (note 28) |  |  | 190 |  |  |  | – |
Derivative financial instruments (notes 3(q)(i) and 20 and 25(b)(i)) |  |  | 93,019 |  |  |  | 58,194 |
Future income taxes (notes 3(q)(i) and 17) |  |  | 24,443 |  |  |  | 19,712 |
|  |  | $510,234 |  |  |  | 466,458 |
Shareholders’ equity: |  |  |  |  |  |  |  |
Common shares (authorized – unlimited number of voting and non-voting common shares; issued and outstanding – March 31, 2008 – 35,929,476 voting common shares (March 31, 2007 – 35,192,260 voting common shares and 412,400 non-voting common shares)) (note 18(b)) |  |  | 298,436 |  |  |  | 296,198 |
Contributed surplus (note 18(c)) |  |  | 4,215 |  |  |  | 3,606 |
Deficit |  |  | (19,287 | ) |  |  | (55,526 | )
|  |  | $283,364 |  |  |  | 244,278 |
Guarantee (note 23) |  |  |  |  |  |  |  |
Commitments (note 26) |  |  |  |  |  |  |  |
Canadian and United States accounting policy differences (note 30) |  |  |  |  |  |  |  |
Subsequent event (note 31) |  |  |  |  |  |  |  |
|  |  | $793,598 |  |  |  | $710,736 |

See accompanying notes to consolidated financial statements.
Approved on behalf of the Board

Ronald A. McIntosh, Director |  | Allen R. Sello, Director

58 Financial Section North American Energy Partners Inc.

#####

Consolidated Statements of Operations, Comprehensive Income (Loss) and Deficit
For the years ended March 31
(in thousands of Canadian dollars, except per share amounts)

|  | 2008 |  |  | 2007 |  |  | 2006 |
Revenue |  |  | $989,696 |  |  |  | $629,446 |  |  |  | $492,237 |
Project costs |  |  | 592,458 |  |  |  | 363,930 |  |  |  | 308,949 |
Equipment costs |  |  | 174,873 |  |  |  | 122,306 |  |  |  | 64,832 |
Equipment operating lease expense |  |  | 22,319 |  |  |  | 19,740 |  |  |  | 16,405 |
Depreciation |  |  | 36,729 |  |  |  | 31,034 |  |  |  | 21,725 |
Gross profit |  |  | 163,317 |  |  |  | 92,436 |  |  |  | 80,326 |
General and administrative costs (note 24) |  |  | 69,670 |  |  |  | 39,769 |  |  |  | 30,903 |
Loss (gain) on disposal of plant and equipment |  |  | 179 |  |  |  | 959 |  |  |  | (733 | )
Amortization of intangible assets (note 10) |  |  | 1,071 |  |  |  | 582 |  |  |  | 730 |
Operating income before the undernoted |  |  | 92,397 |  |  |  | 51,126 |  |  |  | 49,426 |
Interest expense (note 19) |  |  | 27,019 |  |  |  | 37,249 |  |  |  | 68,776 |
Foreign exchange gain |  |  | (25,442 | ) |  |  | (5,044 | ) |  |  | (13,953 | )
Realized and unrealized loss (gain) on derivative financial instruments (note 20(a)) |  |  | 34,075 |  |  |  | (196 | ) |  |  | 14,689 |
Gain on repurchase of NACG Preferred Corp. Series A preferred shares (notes 2 and 18(a)) |  |  | – |  |  |  | (9,400 | ) |  |  | – |
Loss on extinguishment of debt (notes 2 and 16) |  |  | – |  |  |  | 10,935 |  |  |  | 2,095 |
Other income |  |  | (418 | ) |  |  | (904 | ) |  |  | (977 | )
Income (loss) before income taxes |  |  | 57,163 |  |  |  | 18,486 |  |  |  | (21,204 | )
Income taxes (note 17): |  |  |  |  |  |  |  |  |  |  |  |
Current income taxes |  |  | 80 |  |  |  | (2,975 | ) |  |  | 737 |
Future income taxes |  |  | 17,299 |  |  |  | 382 |  |  |  | – |
Net income (loss) and comprehensive income (loss) for the year |  |  | 39,784 |  |  |  | 21,079 |  |  |  | (21,941 | )
Deficit, beginning of year – as previously stated |  |  | (55,526 | ) |  |  | (76,546 | ) |  |  | (54,605 | )
Change in accounting policy related to financial instruments (note 3(q)(i)) |  |  | (3,545 | ) |  |  | – |  |  |  | – |
Premium on repurchase of common shares (note 18(b)) |  |  | – |  |  |  | (59 | ) |  |  | – |
Deficit, end of year |  |  | $(19,287 | ) |  |  | $(55,526 | ) |  |  | $(76,546 | )
Net income (loss) per share – basic (note 18(d)) |  |  | $1.11 |  |  |  | $0.87 |  |  |  | $(1.18 | )
Net income (loss) per share – diluted (note 18(d)) |  |  | $1.08 |  |  |  | $0.83 |  |  |  | $(1.18 | )

See accompanying notes to consolidated financial statements.
North American Energy Partners Inc. Financial Section 59

#####

Consolidated Statement of Cash Flows
For the years ended March 31
(in thousands of Canadian dollars)

|  | 2008 |  |  | 2007 |  |  | 2006 |
Cash provided by (used in): |  |  |  |  |  |  |  |  |  |  |  |
Operating activities: |  |  |  |  |  |  |  |  |  |  |  |
Net income (loss) for the period |  |  | $39,784 |  |  |  | $21,079 |  |  |  | $(21,941 | )
Items not affecting cash: |  |  |  |  |  |  |  |  |  |  |  |
Depreciation |  |  | 36,729 |  |  |  | 31,034 |  |  |  | 21,725 |
Write-down of other assets to replacement cost (note 3(g)) |  |  | 1,845 |  |  |  | 695 |  |  |  | – |
Amortization of intangible assets |  |  | 1,071 |  |  |  | 582 |  |  |  | 730 |
Amortization of deferred lease inducements |  |  | (104 | ) |  |  | – |  |  |  | – |
Amortization of bond issue costs, premiums and financing costs (notes 3(q)(i) and 19) |  |  | 838 |  |  |  | 3,436 |  |  |  | 3,338 |
Loss (gain) on disposal of plant and equipment |  |  | 179 |  |  |  | 959 |  |  |  | (733 | )
Unrealized foreign exchange gain on senior notes |  |  | (24,788 | ) |  |  | (5,017 | ) |  |  | (14,258 | )
Unrealized (gain) loss on derivative financial instruments |  |  | 31,406 |  |  |  | (2,748 | ) |  |  | 11,888 |
Stock-based compensation expense (note 28) |  |  | 1,991 |  |  |  | 2,101 |  |  |  | 923 |
Gain on repurchase of NACG Preferred Corp. Series A preferred shares (notes 2 and 18(a)) |  |  | – |  |  |  | (8,000 | ) |  |  | – |
Loss on extinguishment of debt (notes 2 and 16) |  |  | – |  |  |  | 10,680 |  |  |  | 2,095 |
Change in redemption value and accretion of redeemable preferred shares |  |  | – |  |  |  | 3,114 |  |  |  | 34,722 |
Future income taxes |  |  | 17,299 |  |  |  | 382 |  |  |  | – |
Net changes in non-cash working capital (note 21(b)) |  |  | (8,650 | ) |  |  | (56,167 | ) |  |  | (4,788 | )
|  |  | 97,600 |  |  |  | 2,130 |  |  |  | 33,701 |
Investing activities: |  |  |  |  |  |  |  |  |  |  |  |
Acquisition, net of cash acquired (note 4) |  |  | (1,581 | ) |  |  | (1,517 | ) |  |  | – |
Purchase of plant and equipment |  |  | (57,779 | ) |  |  | (110,019 | ) |  |  | (28,852 | )
Additions to assets held for sale |  |  | (3,499 | ) |  |  | – |  |  |  | – |
Proceeds on disposal of plant and equipment |  |  | 6,862 |  |  |  | 3,564 |  |  |  | 5,456 |
Proceeds of disposal of assets held for sale |  |  | 10,200 |  |  |  | – |  |  |  | – |
Net changes in non-cash working capital (note 21(b)) |  |  | (2,835 | ) |  |  | 7,922 |  |  |  | 1,391 |
|  |  | (48,632 | ) |  |  | (100,050 | ) |  |  | (22,005 | )
Financing activities: |  |  |  |  |  |  |  |  |  |  |  |
(Decrease) increase in revolving credit facility |  |  | (20,500 | ) |  |  | 20,500 |  |  |  | – |
Issue of 9% senior secured notes (note 16) |  |  | – |  |  |  | – |  |  |  | 76,345 |
Repayment of 9% senior secured notes (note 16) |  |  | – |  |  |  | (74,748 | ) |  |  | – |
Repayment of senior secured credit facility |  |  | – |  |  |  | – |  |  |  | (61,257 | )
Issue of Series B preferred shares (note 18(a)(iii)) |  |  | – |  |  |  | – |  |  |  | 8,376 |
Repurchase of Series B preferred shares (notes 2 and 18(a)(iii)) |  |  | – |  |  |  | – |  |  |  | (851 | )
Repurchase of NAEPI Series A preferred shares (notes 2 and 18(a)(ii)) |  |  | – |  |  |  | (1,000 | ) |  |  | – |
Repurchase of NACG Preferred Corp. Series A preferred shares (notes 2 and 18(a)(ii)) |  |  | – |  |  |  | (27,000 | ) |  |  | – |
Cash settlement of stock options (note 18(c)) |  |  | (581 | ) |  |  | – |  |  |  | – |
Financing costs (notes 10 and 11) |  |  | (776 | ) |  |  | (1,346 | ) |  |  | (7,546 | )
Repayment of capital lease obligations |  |  | (3,762 | ) |  |  | (6,033 | ) |  |  | (2,183 | )
Issue of common shares (note 2 and 18(b)) |  |  | 1,627 |  |  |  | 171,304 |  |  |  | 300 |
Share issue costs (notes 2 and 18(b)) |  |  | – |  |  |  | (18,582 | ) |  |  | – |
Repurchase of common shares for cancellation (note 18(b)) |  |  | – |  |  |  | (84 | ) |  |  | – |
|  |  | (23,992 | ) |  |  | 63,011 |  |  |  | 13,184 |
Increase (decrease) in cash and cash equivalents |  |  | 24,976 |  |  |  | (34,909 | ) |  |  | 24,880 |
Cash and cash equivalents, beginning of year |  |  | 7,895 |  |  |  | 42,804 |  |  |  | 17,924 |
Cash and cash equivalents, end of year |  |  | $32,871 |  |  |  | $7,895 |  |  |  | $42,804 |

See accompanying notes to consolidated financial statements.
60 Financial Section North American Energy Partners Inc.

#####

Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)
1. Nature of operations
North American Energy Partners Inc. (the “Company”), formerly NACG Holdings Inc. (“NACG”), was incorporated under the Canada Business Corporations Act on October 17, 2003. On November 26, 2003, the Company purchased all the issued and outstanding shares of North American Construction Group Inc. (“NACGI”), including subsidiaries of NACGI, from Noramac Ltd. which had been operating continuously in Western Canada since 1953. The Company had no operations prior to November 26, 2003. The Company undertakes several types of projects including heavy construction, industrial and commercial site development, pipeline and piling installations in Canada.
On November 28, 2006, immediately prior to the closing of the initial public offering (“IPO”) of common shares in Canada and the United States (note 2), the Company amalgamated with its wholly owned subsidiaries, NACG Preferred Corp., and North American Energy Partners Inc. (“NAEPI”). The amalgamated entity was continued as North American Energy Partners Inc. The voting common shares of the new entity, North American Energy Partners Inc., include the shares offered in the IPO and outstanding common shares in North American Energy Partners Inc. that were not sold in the concurrent secondary offering.
2. Re-organization and initial public offering
On November 28, 2006, prior to the amalgamation referred to in Note 1, NACG acquired the NACG Preferred Corp. Series A preferred shares with a carrying value of $35,000 in exchange for a promissory note in the amount of $27,000 and the forfeiture of accrued dividends of $1,400 (note 18(a)). The Company recorded a gain of $9,400 on the repurchase of the NACG Preferred Corp. Series A preferred shares.
On November 28, 2006, prior to the amalgamation referred to in Note 1, NACG repurchased the NAEPI Series A preferred shares for their redemption value of $1,000. NACG also cancelled the consulting and advisory services agreement with The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc., and SF Holding Corp. (collectively, the “Sponsors”), under which NACG had received ongoing consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements and other matters. The consideration paid for the cancellation of the consulting and advisory services agreement on the closing of the offering was $2,000, which was recorded as general and administrative expense in the consolidated statement of operations. Under the consulting and advisory services agreement, the Sponsors also received a fee of $854, which approximates 0.5% of the aggregate gross proceeds to NACG from the IPO, which was recorded as a share issue cost.
On November 28, 2006, prior to the amalgamation referred to in Note 1, each holder of NAEPI Series B preferred shares received 100 common shares of NACG for each NAEPI Series B preferred share held as a result of the Company exercising a call option to acquire the NAEPI Series B preferred shares (note 18(a)). Upon exchange, the carrying value of the NAEPI Series B preferred shares on the exercise date of $44,682 was transferred to share capital.
On November 28, 2006, the Company completed an IPO for the sale of 8,750,000 common voting shares for total gross proceeds of $158,549. Net proceeds from the IPO, after deducting underwriting fees and offering expenses, were $140,850. Subsequent to the IPO, the underwriters exercised their overallotment option to purchase 687,500 additional voting common shares of the Company for gross proceeds of $12,616. Net proceeds from the overallotment, after deducting underwriting fees and offering expenses, were $11,733. Total net proceeds from the IPO and subsequent overallotment were $152,583 (note 18(b)).
The net proceeds from the IPO and subsequent overallotment were used to:

• |  | repurchase all of the Company’s outstanding 9% senior secured notes due 2010 for $74,748 plus accrued interest of $3,027. The notes were redeemed at a premium of 109.26% resulting in a loss on extinguishment of $6,338. The loss on extinguishment, along with the write-off of deferred financing fees of $4,342 and other costs of $255, was recorded as a loss on extinguishment of debt in the consolidated statement of operations;
• |  | repay the promissory note in respect of the repurchase of the NACG Preferred Corp. Series A preferred shares for $27,000 as described above;
• |  | purchase certain equipment leased under operating leases for $44,623;
• |  | cancel the consulting and advisory services agreement with the Sponsors for $2,000; and
• |  | for general corporate purposes.

North American Energy Partners Inc. Financial Section 61

#####

North American Energy Partners –Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)
3. Significant accounting policies
a) Basis of presentation
These consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles (“GAAP”). Material inter-company transactions and balances are eliminated on consolidation. Material items that give rise to measurement differences to the consolidated financial statements under United States GAAP are outlined in note 30.
These consolidated financial statements include the accounts of the Company, its wholly owned subsidiaries, North American Construction Group Inc. (“NACGI”) and NACG Finance LLC, the Company’s joint venture, Noramac Ventures Inc. and the following 100% owned subsidiaries of NACGI:

• |  | North American Caisson Ltd.
• |  | North American Construction Ltd.
• |  | North American Engineering Ltd.
• |  | North American Enterprises Ltd.
• |  | North American Industries Inc.
• |  | North American Mining Inc.
• |  | North American Maintenance Ltd.
• |  | North American Pipeline Inc.
• |  | North American Road Inc.
• |  | North American Services Inc.
• |  | North American Site Development Ltd.
• |  | North American Site Services Inc.
• |  | North American Pile Driving Inc.

b) Use of estimates
The preparation of financial statements in conformity with Canadian GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and disclosures reported in these consolidated financial statements and accompanying notes.
Significant estimates made by management include the assessment of the percentage of completion on time-and-materials, unit-price or lump-sum contracts (including estimated total costs and provisions for estimated losses) and the recognition of claims and change orders on contracts, assumptions used to value financial instruments, assumptions used to determine the redemption value of redeemable securities, assumptions used in periodic impairment testing, and estimates and assumptions used in the determination of the allowance for doubtful accounts and the useful lives of plant and equipment. Actual results could differ materially from those estimates.
The accuracy of the Company’s revenue and profit recognition in a given period is dependent, in part, on the accuracy of our estimates of the cost to complete each time-and-materials, unit-price, or lump-sum project. Our cost estimates use a detailed “bottom up’’ approach, using inputs such as labour and equipment hours, detailed drawings and material lists. These estimates are reviewed and updated monthly. The Company believes our experience allows us to produce materially reliable estimates. However, our projects can be highly complex. Profit margin estimates for a project may either increase or decrease to some extent from the amount that was originally estimated at the time of the related bid. With many projects of varying levels of complexity and size in process at any given time, changes in estimates can offset each other without materially impacting our profitability. Major changes in cost estimates, particularly in larger, more complex projects, can have a significant effect on profitability.
c) Revenue recognition
The Company performs its 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. 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 the Company’s 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.
62 Financial Section North American Energy Partners Inc.

#####

North American Energy Partners – Notes to Consolidated Financial Statements For the years ended March 31, 2008, 2007 and 2006 (Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified) |  |

Once a project is underway, the Company 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 the Company and a customer, the Company will then consider it as a claim.
Costs related to change orders and claims are recognized when they are incurred. Revenues related to change orders 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 claim will result in:

• |  | a bona fide addition to contract value; and
• |  | revenues can be reliably estimated.

These two conditions are satisfied when:

• |  | the contract or other evidence provides a legal basis for the claim or a legal opinion is obtained providing a reasonable basis to support the claim;
• |  | additional costs incurred were caused by unforeseen circumstances and are not the result of deficiencies in the Company’s performance;
• |  | costs associated with the claim are identifiable and reasonable in view of work performed; and
• |  | evidence supporting the claim is objective and verifiable.

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.
Claims revenue recognized was nil for the year ended March 31, 2008 (2007 – $14.5 million; 2006 – $12.9 million). Claims revenue of $3.1 million related to prior year claims is included in unbilled revenue and remains uncollected at the end of the year (2007 – $8.4 million).
The Company’s long-term contracts typically allow its 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.
The asset entitled “unbilled revenue” represents revenue recognized in advance of amounts invoiced. The liability entitled “billings in excess of costs incurred and estimated earnings on uncompleted contracts” represents amounts invoiced in excess of revenue recognized.
d) Cash and cash equivalents
Cash and cash equivalents include cash on hand, bank balances net of outstanding cheques, and short-term investments with maturities of three months or less when purchased.
e) Allowance for doubtful accounts
The Company evaluates the probability of collection of accounts receivable and records an allowance for doubtful accounts, which reduces accounts receivable to the amount management reasonably believes will be collected. In determining the amount of the allowance, the following factors are considered: the length of time the receivable has been outstanding, specific knowledge of each customer’s financial condition, and historical experience.
f) Inventory
Inventory is carried at the lower of weighted average cost and replacement cost, and consists primarily of project materials.
g) Other assets
Other assets consist of tires and spare component parts, and are stated at the lower of weighted average cost or replacement cost. Other assets are charged to earnings when they are put into use. A write-down of other assets to reduce other assets to the lower of weighted average cost or replacement cost of $1,845 (2007 – $695) is included in equipment costs for the year ended March 31, 2008.
h) Plant and equipment
Plant and equipment are recorded at cost. Major components of heavy construction equipment in use such as engines and transmissions are recorded separately. Equipment under capital lease is recorded at the present value of minimum lease payments at the inception of the lease. Depreciation is not recorded until an asset is available for use.
North American Energy Partners Inc. Financial Section 63

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North American Energy Partners – Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)
Depreciation for each category is calculated based on the cost, net of the estimated residual value, over the estimated useful life of the assets on the following basis and annual rates:

Asset |  | Basis |  | Rate
Heavy equipment |  | Straight-line |  | Operating hours
Major component parts in use |  | Straight-line |  | Operating hours
Other equipment |  | Straight-line |  | 5 – 10 years
Licensed motor vehicles |  | Declining balance |  | 30%
Office and computer equipment |  | Straight-line |  | 4 years
Buildings |  | Straight-line |  | 10 years
Leasehold improvements |  | Straight-line |  | Over shorter of estimated useful life and lease term
Assets under capital lease |  | Declining balance |  | Over life of lease

The costs for periodic repairs and maintenance are expensed to the extent the expenditures serve only to restore the assets to their normal operating condition without enhancing their service potential or extending their useful lives.
i) Goodwill
Goodwill represents the excess purchase price paid by the Company over the fair value of tangible and identifiable intangible assets and liabilities acquired as a result of purchasing a business entity. Goodwill is not amortized but instead is tested for impairment annually or more frequently if events or changes in circumstances indicate that it may be impaired. The impairment test is carried out in two steps. In the first step, the carrying amount of the reporting unit, including goodwill, is compared to its fair value. When the fair value of the reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to be impaired and the second step of the impairment test is unnecessary. The second step is carried out when the carrying amount of a reporting unit exceeds its fair value, in which case the implied fair value of the reporting unit’s goodwill, determined in the same manner as the value of goodwill is determined in a business combination, is compared with its carrying amount to measure the amount of the impairment loss, if any.
The Company tested goodwill for impairment at October 1, 2007 and determined that there was no impairment in carrying value. During the current year, the Company changed the date of its annual impairment test for goodwill from December 31 to October 1 of each year. This change in accounting policy was applied on a retrospective basis and had no impact on the consolidated financial statements.
j) Intangible assets
Intangible assets include:

• |  | customer contracts in process and related relationships, which are being amortized based on the net present value of the estimated period cash flows over the remaining lives of the related contracts and relationships;
• |  | trade names, which are being amortized on a straight-line basis over their estimated useful life of 10 years;
• |  | non-competition agreements, which are being amortized on a straight-line basis between the three and five-year terms of the respective agreements;
• |  | financing costs related to the revolving credit facility are amortized on a straight-line basis over the term of the agreement; and
• |  | employee arrangements, which are being amortized on a straight-line basis over the three-year term of the arrangements.

k) Impairment of long-lived assets
Long-lived assets and identifiable intangible assets subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is assessed by a comparison of the carrying value of the asset to future undiscounted cash flows expected to be generated by the asset. If the value of such asset is considered to be impaired, the impairment loss is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset, and is charged to depreciation expense.
Long-lived assets are classified as held for sale when certain criteria are met, which include:

• |  | management’s commitment to a plan to sell the assets;
• |  | the assets are available for immediate sale in their present condition;
• |  | an active program to locate buyers and other actions to sell the assets have been initiated;
• |  | the sale of the assets is probable and their transfer is expected to qualify for recognition as a completed sale within one year;

64 Financial Section North American Energy Partners Inc.

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North American Energy Partners – Notes to Consolidated Financial Statements For the years ended March 31, 2008, 2007 and 2006 (Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified) |  |

• |  | the assets are being actively marketed at reasonable prices in relation to their fair value; and
• |  | it is unlikely that significant changes will be made to the plan to sell the assets or that the plan will be withdrawn.

Assets to be disposed of by sale are reported at the lower of their carrying amount or fair value less costs to sell and are included in current assets. These assets are not depreciated.
l) Foreign currency translation
The functional currency of the Company is Canadian dollars. Transactions denominated in foreign currencies are recorded at the rate of exchange on the transaction date. Monetary assets and liabilities, including long-term debt denominated in U.S. dollars, are translated into Canadian dollars at the rate of exchange prevailing at the balance sheet date.
m) Derivative financial instruments
The Company uses derivative financial instruments to manage financial risks from fluctuations in exchange rates and interest rates. These instruments include cross-currency and interest rate swap agreements as well as embedded price escalation features in revenue and supplier contracts. All such instruments are only used for risk management purposes. The Company does not hold or issue derivative financial instruments for trading or speculative purposes. Derivative financial instruments are subject to standard credit terms and conditions, financial controls, management and risk monitoring procedures. These derivative financial instruments are not designated as hedges for accounting purposes and are recorded at fair value with realized and unrealized gains and losses recognized in the Consolidated Statement of Operations, Comprehensive Income (Loss) and Deficit.
n) Income taxes
The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, future income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Future income tax assets and liabilities are measured using enacted or substantively enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on future income tax assets and liabilities from a change in tax rates is recognized in income in the period of enactment or substantive enactment. The Company accrues interest and penalties for uncertain tax positions in the period in which these uncertainties are identified. A valuation allowance is recorded against any future income tax asset if it is more likely than not that the asset will not be realized.
o) Stock–based compensation plan
The Company accounts for all stock-based compensation payments that are settled by the issuance of equity instruments in accordance with a fair value based method of accounting. Under this fair value based method, compensation cost is measured using the Black-Scholes model at the grant date and is expensed on a straight-line basis over the award’s vesting period, with a corresponding increase to contributed surplus. Upon exercise of a stock option, share capital is recorded at the sum of proceeds received and the related amount of contributed surplus.
The Company has a Director’s Deferred Stock Unit (“DDSU”) plan, which is described in note 28. The measurement of the liability and compensation costs for these awards is based on the intrinsic value of the award and is recorded as a charge to operating income over the vesting period of the award. Subsequent changes in the Company’s payment obligation after vesting of the award and prior to the settlement date are recorded as a charge to operating income in the period such changes occur.
p) Net income (loss) per share
Basic net income (loss) per share is computed by dividing net earnings (loss) available to common shareholders by the weighted average number of shares outstanding during the year (see note 18(d)). Diluted per share amounts are calculated using the treasury stock and if-converted methods. The treasury stock method increases the diluted weighted average shares outstanding to include additional shares from the assumed exercise of stock options, if dilutive. The number of additional shares is calculated by assuming outstanding in-the-money stock options were exercised and the proceeds from such exercises, including any unamortized stock-based compensation cost, were used to acquire shares of common stock at the average market price during the year. The if-converted method assumes the conversion of convertible securities at the later of the beginning of the reported period or issue date, if dilutive.
q) Recently adopted Canadian accounting pronouncements
i. Financial instruments – recognition and measurement
Effective April 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants (“CICA”) Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, and Handbook Section 3865, “Hedges”. These standards have been applied retrospectively without restatement as discussed below and, accordingly, comparative amounts for prior periods have not been restated.
North American Energy Partners Inc. Financial Section 65

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North American Energy Partners – Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)
CICA Handbook Sections 3855 and 3865 provide guidance on when a financial asset, financial liability or non-financial derivative is to be recognized on the balance sheet of the Company and on what basis these assets, liabilities and derivatives should be valued, including hedging relationships. Under the standards:

• |  | Financial assets are classified as loans and receivables, held-to-maturity, held-for-trading or available-for-sale. Loans and receivables are initially recorded at fair value and subsequent to initial recognition are accounted for at amortized cost using the effective interest method. Held-to-maturity classification is restricted to fixed maturity instruments that the Company intends and is able to hold to maturity and is accounted for on initial recognition at fair value and subsequent to initial recognition at amortized cost using the effective interest method. Held-for-trading instruments are recorded at fair value with changes in fair value reported in net income. The remaining financial assets are classified as available-for-sale. These are recorded at fair value with changes in fair value reported in other comprehensive income until the investment is derecognized or impaired at which time the amounts would be recorded in net income. On adoption of the standard, the Company has classified its cash and cash equivalents as held for trading and accounts receivable and unbilled revenue as loans and receivables. The Company did not hold any financial assets that were available-for-sale or held-to-maturity;
• |  | Financial liabilities are classified as either held-for-trading or other financial liabilities. Held-for-trading instruments are recorded at fair value with changes in fair value reported in net income. Other financial liabilities are accounted for on initial recognition at fair value and subsequent to initial recognition at amortized cost using the effective interest method with gains and losses reported in net income in the period that the liability is derecognized. The Company has classified its revolving credit facility, accounts payable, accrued liabilities, and senior notes as other financial liabilities;
• |  | Derivative financial instruments, including non-financial derivatives, are classified as held-for-trading and measured at fair value unless exempted from derivative treatment as a normal purchase or sale. Certain derivatives embedded in other contracts are also measured at fair value.
• |  | Section 3865 specifies circumstances under which hedge accounting is permissible and how hedge accounting is performed. For the periods presented, the Company did not apply hedge accounting.
• |  | The Company elected April 1, 2003 as the transition date for identifying contracts with embedded derivatives. Transaction costs that are directly attributable to the acquisition or issue of financial assets or liabilities are accounted for as a part of the respective asset or liability’s carrying value at inception.

In determining the fair value of financial instruments, the Company uses a variety of methods and assumptions that are based on market conditions and risks existing on each reporting date. Counterparty confirmations and standard market conventions and techniques, such as discounted cash flow analysis and option pricing models, are used to determine the fair value of the Company’s financial instruments, including derivatives. All methods of fair value measurement result in a general approximation of value and such value may never actually be realized.
On April 1, 2007, the Company made the following transitional adjustments to the consolidated balance sheet to adopt the new standards:

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

The trade date is used to account for regular way purchase or sale contracts. The adoption of these standards resulted in the following adjustments as of April 1, 2007 in accordance with the transition provisions:

• |  | Deferred financing costs related to the issue of the senior notes that were previously presented as a separate asset on the consolidated balance sheet are now included in the carrying value of the senior notes and are being amortized using the effective interest method over the remaining term of the debt. Prior to April 1, 2007, these deferred financing costs were amortized on a straight line basis over the term of the debt. As a result of the change in method of accounting, financing costs were re-measured on April 1, 2007 using the effective interest method. This re-measurement resulted in a $9,734 decrease in deferred financing costs, a decrease of $9,815 in senior notes, a decrease of $63 in opening deficit and an increase of $18 in the future income tax liability.

66 Financial Section North American Energy Partners Inc.

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North American Energy Partners – Notes to Consolidated Financial Statements For the years ended March 31, 2008, 2007 and 2006 (Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified) |  |

• |  | Transaction costs incurred in connection with the Company’s revolving credit facility of $1,622 were reclassified from deferred financing costs to intangible assets on April 1, 2007 and these costs continue to be amortized on a straight-line basis over the term of the facility.
• |  | The Company determined that the issuer’s early prepayment option included in the senior notes should be bifurcated from the host contract, along with a contingent embedded derivative in the senior notes that provide for accelerated redemption by the holders in certain instances. These embedded derivatives were measured at fair value at the inception of the senior notes and the residual amount of the proceeds was allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of the senior notes is accreted to par value over the term of the notes using the effective interest method and is recognized as interest expense. At transition on April 1, 2007, the Company recorded the fair value of $8,519 related to these embedded derivatives and a corresponding decrease in opening deficit of $7,305, net of future income taxes of $1,214. The impact of the bifurcation of these embedded derivatives at issuance of the senior notes resulted in an increase of senior notes of $5,700 and an increase in opening deficit of $3,963, net of income taxes of $1,737 after applying the effective interest method to the premium resulting from the bifurcation of these embedded derivatives on April 1, 2007.
• |  | The Company determined that a price escalation feature in a revenue construction contract is an embedded derivative that is not closely related to the host contract. The embedded derivative has been measured at fair value and included in derivative financial instruments on the consolidated balance sheet, with changes in the fair value recognized in net income. The Company recorded the fair value of $7,246 related to this embedded derivative on April 1, 2007, with a corresponding increase in opening deficit of $5,181, net of future income taxes of $2,065.
• |  | The Company identified an additional embedded derivative that is not closely related to the host contract in the fourth quarter of 2008 with respect to price escalation features in a supplier contract. The embedded derivative has been measured at fair value and included in derivative financial instruments on the consolidated balance sheet, with changes in fair value recognized in net income. The Company has amended its original transition adjustment disclosed in the first quarter and recorded the fair value of $2,474 related to this embedded derivative on April 1, 2007, with corresponding increase in opening deficit of $1,769, net of future income taxes of $705.

ii. Financial instruments – disclosure and presentation
Effective April 1, 2007, the Company adopted revised CICA Handbook Section 3861, “Financial Instruments – Disclosure and Presentation”, which replaces CICA Handbook Section 3860, “Financial Instruments – Disclosure and Presentation”, and establishes standards for presentation of financial instruments and non-financial derivatives, and identifies information that should be disclosed. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.
iii. Comprehensive income and equity
Effective April 1, 2007, the Company adopted CICA Handbook Section 1530, “Comprehensive Income”, which establishes standards for the reporting and display of comprehensive income. The new section defines other comprehensive income to include revenues, expenses, and gains and losses that, in accordance with primary sources of GAAP, are recognized in comprehensive income but excluded from net income. The standard does not address issues of recognition or measurement for comprehensive income and its components. The adoption of this standard did not have a material impact on the Company’s financial statement presentation in the current year.
Effective April 1, 2007, the Company adopted CICA Handbook Section 3251 “Equity”, which establishes standards for the presentation of equity and changes in equity during the reporting period. The requirements in this section are in addition to those of Section 1530 and recommend that an enterprise should present separately the following components of equity: retained earnings, accumulated other comprehensive income, the total for retained earnings and accumulated other comprehensive income, contributed surplus, share capital and reserves. The adoption of CICA Handbook Section 3251 did not have an impact on the Company’s financial statement presentation in the current period. The Company currently has no accumulated other comprehensive income components.
iv. Accounting changes
In July 2006, the CICA revised Handbook Section 1506, “Accounting Changes”, which requires that: (1) voluntary changes in accounting policy are made only if they result in the financial statements providing reliable and more relevant information; (2) changes in accounting policy are generally applied retrospectively; and (3) prior period errors are corrected retrospectively. This guidance was adopted by the Company on April 1, 2007 and did not have a material impact on the consolidated financial statements.
v. Accounting policy choice for transaction costs
In June 2007, the CICA issued Emerging Issues Committee Abstract No. 166, “Accounting Policy Choice for Transaction Costs” (“EIC-166”). CICA Handbook Section 3855 requires that when an entity acquires a financial asset or incurs a financial liability classified other than as held-for-trading, it adopts an accounting policy for transaction costs of either: (a) recognizing all transaction costs in net income; or (b) adding transaction costs that are directly attributable to the
North American Energy Partners Inc. Financial Section 67

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North American Energy Partners – Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)
acquisition or issue of a financial asset or financial liability to the carrying amount of the financial instrument. EIC-166 clarifies that the same accounting policy choice should be made for all similar instruments classified as other than held-for-trading, but that a different accounting policy choice may be made for financial instruments that are not similar. As described in note 3(q)(i), the Company’s accounting policy is to add transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability to the carrying amount of the financial instrument. This guidance was adopted by the Company on April 1, 2007 and did not have a material impact on the consolidated financial statements.
r) Recent Canadian accounting pronouncements not yet adopted
i. Capital disclosures
In December 2006, the CICA issued Handbook Section 1535, “Capital Disclosures”. This standard requires that an entity disclose information that enables users of its financial statements to evaluate an entity’s objectives, policies and processes for managing capital, including disclosures of any externally imposed capital requirements and the consequences of non-compliance. The new standard applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company. Disclosures required by the new standard will be included in the Company’s interim and annual consolidated financial statements commencing April 1, 2008.
ii. Financial instruments – disclosure and presentation
In March 2007, the CICA issued Handbook Section 3862, “Financial Instruments–Disclosures”, which replaces CICA 3861 and provides expanded disclosure requirements that provide additional detail by financial assets and liability categories to enhance financial statement users’ understanding of the significance of financial instruments to an entity’s financial position, performance and cash flows. This standard harmonizes disclosures with International Financial Reporting Standards. The standard applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company. Disclosures required by the new standard will be included in the Company’s interim and annual consolidated financial statements commencing April 1, 2008.
In March 2007, the CICA issued Handbook Section 3863, “Financial Instruments–Presentation”. This Section establishes standards for presentation of financial instruments and non-financial derivatives. It deals with the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, gains and losses, and the circumstances in which financial assets and financial liabilities are offset. This standard harmonizes disclosures with International Financial Reporting Standards and applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company, and is not expected to have a material impact on the Company’s consolidated financial statements.
iii. Inventories
In June 2007, the CICA issued Handbook Section 3031, “Inventories” to harmonize accounting for inventories under Canadian GAAP with International Financial Reporting Standards. This standard requires the measurement of inventories at the lower of cost and net realizable value and includes guidance on the determination of cost, including allocation of overheads and other costs to inventory. The standard also requires the consistent use of either first-in, first out (FIFO) or weighted average cost formula to measure the cost of other inventories and requires the reversal of previous write-downs to net realizable value when there is a subsequent increase in the value of inventories. The new standard applies to interim and annual financial statements relating to fiscal years beginning on or after January 1, 2008, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.
iv. Going concern
In April 2007, the CICA approved amendments to Handbook Section 1400, “General Standards of Financial Statement Presentation”. These amendments require management to assess an entity’s ability to continue as a going concern. When management is aware of material uncertainties related to events or conditions that may cast doubt on an entity’s ability to continue as a going concern, those uncertainties must be disclosed. In assessing the appropriateness of the going concern assumption, the standard requires management to consider all available information about the future, which is at least, but not limited to, twelve months from the balance sheet date. The new requirements of the standard are applicable for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2008, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.
v. Goodwill and intangible assets
In February 2008, the CICA issued Handbook Section 3064, (“CICA 3064”) Goodwill and Intangible Assets. CICA 3064, which replaces Section 3062, Goodwill and Intangible Assets, and Section 3450, Research and Development Costs, establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The provisions relating to the definition and initial recognition of intangible assets, including internally generated intangible assets, are equivalent to the corresponding provisions of International Financial Reporting Standard IAS 38, Intangible Assets.
68 Financial Section North American Energy Partners Inc.

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North American Energy Partners – Notes to Consolidated Financial Statements For the years ended March 31, 2008, 2007 and 2006 (Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified) |  |

This new standard is effective for the Company’s interim and annual consolidated financial statements commencing April 1, 2009. The Company is currently evaluating the impact of this standard.
4. Acquisition
On May 1, 2007, the Company acquired all of the assets of Active Auger Services 2001 Ltd., a piling company specializing in the design and installation of screw piles in north central Saskatchewan, for total cash consideration and acquisition costs of $1,581. The transaction has been accounted for by the purchase method with the results of operations included in the financial statements from the date of acquisition. The goodwill acquired is deductible for tax purposes. The purchase price allocation is as follows:

|  | Preliminary |  |  | Final |
Net assets acquired at assigned values: |  |  |  |  |  |  |  |
Plant and equipment |  |  | $700 |  |  |  | $700 |
Intangible assets |  |  | 217 |  |  |  | 201 |
Goodwill (assigned to the piling segment) |  |  | 664 |  |  |  | 680 |
|  |  | $1,581 |  |  |  | $1,581 |

On September 1, 2006, the Company acquired all of the shares of Midwest Foundation Technologies Ltd., a piling company specializing in the design and installation of micropile foundations in Western Canada, for cash consideration and acquisition costs totaling $1,646. The transaction has been accounted for by the purchase method with the results of operations included in the financial statements from the date of acquisition. The goodwill related to this transaction is not deductible for tax purposes. The final purchase price allocation is as follows:

Net assets acquired at assigned values: |  |  |  |
Working capital (including cash of $129) |  |  | $170 |
Plant and equipment |  |  | 554 |
Intangible assets |  |  | 410 |
Goodwill (assigned to the piling segment) |  |  | 843 |
Future income tax liability |  |  | (194 | )
Capital lease obligations |  |  | (137 | )
|  |  | $1,646 |

5. Accounts receivable

|  | March 31, |  |  | March 31, |
|  | 2008 |  |  | 2007 |
Accounts receivable – trade |  |  | $122,241 |  |  |  | $83,444 |
Accounts receivable – holdbacks |  |  | 34,996 |  |  |  | 19,496 |
Income and other taxes receivable |  |  | 2,734 |  |  |  | 3,034 |
Accounts receivable – other |  |  | 6,773 |  |  |  | 1,458 |
Allowance for doubtful accounts |  |  | (742 | ) |  |  | (88 | )
|  |  | $166,002 |  |  |  | $107,344 |

Accounts receivable – holdbacks represent amounts up to 10% under certain contracts that the customer is contractually entitled to withhold until completion of the project or until certain project milestones are achieved.
6. Costs incurred and estimated earnings net of billings on uncompleted contracts

|  | March 31, |  |  | March 31, |
|  | 2008 |  |  | 2007 |
Costs incurred and estimated earnings on uncompleted contracts |  |  | $1,037,273 |  |  |  | $742,186 |
Less: billings to date |  |  | (971,162 | ) |  |  | (676,476 | )
|  |  | $66,111 |  |  |  | $65,710 |

North American Energy Partners Inc. Financial Section 69

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North American Energy Partners – Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)
Costs incurred and estimated earnings net of billings on uncompleted contracts is presented in the consolidated balance sheets under the following captions:

|  | March 31, |  |  | March 31, |
|  | 2008 |  |  | 2007 |
Unbilled revenue |  |  | $70,883 |  |  |  | $68,709 |
Billings in excess of costs incurred and estimated earnings on uncompleted contracts |  |  | (4,772 | ) |  |  | (2,999 | )
|  |  | $66,111 |  |  |  | $65,710 |

7. Prepaid expenses and deposits

|  | March 31, |  |  | March 31, |
|  | 2008 |  |  | 2007 |
Prepaid insurance and property taxes |  |  | $1,065 |  |  |  | $916 |
Prepaid lease payments |  |  | 6,606 |  |  |  | 3,934 |
Deposits on other assets |  |  | 1,629 |  |  |  | 7,082 |
|  |  | $9,300 |  |  |  | $11,932 |

8. Assets held for sale
Included in depreciation expense for the year ended March 31, 2008 is an impairment charge of $493 (2007 – $3,582; 2006 – $nil) relating to a decision to dispose of heavy construction assets in the Heavy Construction & Mining segment. The impairment charge is the amount by which the carrying value of the related assets exceeded their fair value less costs to sell. The assets held for sale at March 31, 2008 have been reclassified from plant and equipment to long-term assets as the assets have not yet been sold.
9. Plant and equipment

|  |  |  |  |  | Accumulated |  |  | Net |
March 31, 2008 |  | Cost |  |  | depreciation |  |  | book value |
Heavy equipment |  |  | $281,975 |  |  |  | $62,539 |  |  |  | $219,436 |
Major component parts in use |  |  | 12,291 |  |  |  | 4,797 |  |  |  | 7,494 |
Other equipment |  |  | 17,086 |  |  |  | 6,232 |  |  |  | 10,854 |
Licensed motor vehicles |  |  | 8,981 |  |  |  | 6,110 |  |  |  | 2,871 |
Office and computer equipment |  |  | 9,016 |  |  |  | 3,479 |  |  |  | 5,537 |
Buildings |  |  | 19,530 |  |  |  | 3,443 |  |  |  | 16,087 |
Leasehold improvements |  |  | 6,272 |  |  |  | 1,107 |  |  |  | 5,165 |
Assets under capital lease |  |  | 23,271 |  |  |  | 9,676 |  |  |  | 13,595 |
|  |  | $378,422 |  |  |  | $97,383 |  |  |  | $281,039 |

|  |  |  |  |  | Accumulated |  |  | Net |
March 31, 2007 |  | Cost |  |  | depreciation |  |  | book value |
Heavy equipment |  |  | $254,643 |  |  |  | $46,609 |  |  |  | $208,034 |
Major component parts in use |  |  | 7,884 |  |  |  | 2,489 |  |  |  | 5,395 |
Other equipment |  |  | 16,244 |  |  |  | 5,641 |  |  |  | 10,603 |
Licensed motor vehicles |  |  | 7,998 |  |  |  | 4,829 |  |  |  | 3,169 |
Office and computer equipment |  |  | 4,836 |  |  |  | 2,249 |  |  |  | 2,587 |
Buildings |  |  | 16,443 |  |  |  | 716 |  |  |  | 15,727 |
Leasehold improvements |  |  | 2,992 |  |  |  | 664 |  |  |  | 2,328 |
Assets under capital lease |  |  | 15,422 |  |  |  | 7,302 |  |  |  | 8,120 |
|  |  | $326,462 |  |  |  | $70,499 |  |  |  | $255,963 |

During the year ended March 31, 2008, additions to plant and equipment included $8,829 of assets that were acquired by means of capital leases (2007 – $4,653; 2006 – $5,910). Depreciation of equipment under capital lease of $2,928 (2007 – $1,481; 2006 – $2,545) is included in depreciation expense.
70 Financial Section North American Energy Partners Inc.

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North American Energy Partners – Notes to Consolidated Financial Statements For the years ended March 31, 2008, 2007 and 2006 (Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified) |  |

10. Intangible assets

|  |  |  |  |  | Accumulated |  |  | Net |
March 31, 2008 |  | Cost |  |  | depreciation |  |  | book value |
Customer contracts in progress and related relationships |  |  | $340 |  |  |  | $160 |  |  |  | $180 |
Financing costs |  |  | 3,017 |  |  |  | 1,601 |  |  |  | 1,416 |
Other intangible assets |  |  | 876 |  |  |  | 344 |  |  |  | 532 |
|  |  | $4,233 |  |  |  | $2,105 |  |  |  | $2,128 |

|  |  |  |  |  | Accumulated |  |  | Net |
March 31, 2007 |  | Cost |  |  | depreciation |  |  | book value |
Customer contracts in progress and related relationships |  |  | $15,533 |  |  |  | $15,360 |  |  |  | $173 |
Other intangible assets |  |  | 2,675 |  |  |  | 2,248 |  |  |  | 427 |
|  |  | $18,208 |  |  |  | $17,608 |  |  |  | $600 |

During the year ended March 31, 2008, financing fees totaling $776 paid in connection with an amendment of the revolving credit facility (note 12) were recorded as financing costs. These costs, together with the existing unamortized financing costs, will be amortized on a straight-line basis over the term of the amended revolving credit facility consistent with accounting for the amendment of the revolving credit facility as a modification.
Amortization of intangible assets for the year ended March 31, 2008 was $1,071 (2007 – $582; 2006 – $730). The estimated amortization expense for future years is as follows:

For the year ending March 31, |  |  |  |  |  |  |  |  |
2009 |  |  |  |  |  |  |  |  |  |  | $1,088 |
2010 |  |  |  |  |  |  |  |  |  |  | 862 |
2011 |  |  |  |  |  |  |  |  |  |  | 55 |
2012 |  |  |  |  |  |  |  |  |  |  | 48 |
2013 and thereafter |  |  |  |  |  |  |  |  |  |  | 75 |
|  |  |  |  |  |  |  |  |  |  | $2,128 |

11. Deferred financing costs
Deferred financing costs related to the senior notes that were previously presented as a separate asset on the consolidated balance sheet are now included in the carrying value of the senior notes (see notes 3(q)(i) and 16). Transaction costs incurred in connection with the Company’s revolving credit facility of $1,622 were reclassified from deferred financing costs to intangible assets effective April 1, 2007 (notes 3(q)(i) and 10).
For the year ended March 31, 2007, fees of $275 were paid to the holders of the 8 3/4% senior notes in connection with an amendment of the indenture governing the 8 3/4% senior notes (note 16). The amendment has been accounted for as a modification, and the fees paid to the note holders, together with the existing unamortized deferred financing costs, were deferred and amortized on a straight-line basis over the remaining term of the 8 3/4% senior notes.
During the year ended March 31, 2007, financing fees totaling $1,071 paid in connection with amendment of the revolving credit facility (note 12) were recorded as deferred financing costs. These costs, together with the existing unamortized deferred financing costs, were deferred and amortized over the term of the amended revolving credit facility consistent with accounting for the amendment of the revolving credit facility as a modification.
In connection with the retirement of the 9% senior secured notes on November 28, 2006, the Company wrote off deferred financing costs of $4,342 (notes 2 and 16) during the year ended March 31, 2007.
For the year ended March 31, 2006, financing costs of $7,546 were incurred in connection with the issue of the 9% senior secured notes and revolving credit facility and were recorded as deferred financing costs. In addition, financing costs of $321 were incurred in connection with the issue of the NAEPI Series A redeemable preferred shares and expensed in the year ended March 31, 2006.
On May 19, 2005, the Company repaid its entire indebtedness under a previous revolving credit facility and term loan using the net proceeds from the issue of the 9% senior secured notes and the NAEPI Series B preferred shares. In connection with the repayment of the secured credit facility on May 19, 2006, the Company wrote off deferred financing costs of $1,774 during the year ended March 31, 2006. Amortization of the deferred financing costs for the year ended March 31, 2007 was $3,436 (2006 – $3,338).
North American Energy Partners Inc. Financial Section 71

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North American Energy Partners – Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)
12. Revolving credit facility
On June 7, 2007, the Company modified its amended and restated credit agreement to provide for borrowings of up to $125.0 million (previously $55.0 million) under which revolving loans and letters of credit may be issued. Based upon the Company’s current credit rating, prime rate and swing line revolving loans under the agreement will bear interest at the Canadian prime rate plus 0.25% per annum, Canadian bankers’ acceptances have stamping fees equal to 1.75% per annum and letters of credit are subject to a fee of 1.25% per annum. Standby fees are calculated at a rate per annum equal to the applicable pricing margin applied to the amount by which the amount of the outstanding principal owing to each lender under the credit facility for each day is less than the commitment of such lender and accrue daily from the first day to the last day of each fiscal quarter. In each case, the applicable pricing margin depends on our credit rating. Interest rates are increased by 2% per annum in excess of the rate otherwise payable on any amount not paid when due.
The credit facility is secured by a first priority lien on substantially all the Company’s existing and after-acquired property and contains certain restrictive covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions or to pay dividends or redeem shares of capital stock. The Company is also required to meet certain financial covenants under the new credit agreement. The Company was in compliance with all the covenants under this agreement as at and through out the year ended March 31, 2008.
As of March 31, 2008, the Company had nil outstanding borrowings under the revolving credit facility and had issued $20.0 million in letters of credit to support performance guarantees associated with a customer contract. The Company’s unused borrowing availability under the facility was $105.0 million at March 31, 2008. The credit facility matures June 7, 2010. During the twelve months ended March 31, 2008, financing fees of $776, were incurred in connection with the modifications to the amended and restated credit agreement and were recorded as an intangible asset.
As of March 31, 2007, the Company had outstanding borrowings of $20.5 million (2006 – $nil) under the revolving credit facility and had issued $25.0 million in letters of credit to support performance guarantees associated with customer contracts. The Company’s borrowing availability under the facility was $9.5 million at March 31, 2007.
13. Deferred lease inducements
Lease inducements applicable to lease contracts are deferred and amortized as a reduction of general and administrative costs on a straight-line basis over the lease term, which includes the initial lease term and renewal periods only where renewal is determined to be reasonably assured. During the year ended March 31, 2008, the Company received inducements from a lessor in the form of leasehold improvements to an office facility of $1,045. Amortization of deferred lease inducements of $104 was recorded for the year ended March 31, 2008.
14. Accrued liabilities

|  | March 31, |  |  | March 31, |
|  | 2008 |  |  | 2007 |
Accrued interest payable |  |  | $8,693 |  |  |  | $8,669 |
Payroll liabilities |  |  | 19,564 |  |  |  | 7,484 |
Liabilities related to equipment leases |  |  | 14,617 |  |  |  | 7,039 |
Income and other taxes payable |  |  | 2,204 |  |  |  | 201 |
|  |  | $45,078 |  |  |  | $23,393 |

15. Capital lease obligations
The Company’s capital leases primarily relate to licensed motor vehicles. The minimum lease payments due in each of the next five fiscal years are as follows:

2009 |  |  |  |  |  |  | $5,537 |
2010 |  |  |  |  |  |  | 4,697 |
2011 |  |  |  |  |  |  | 3,335 |
2012 |  |  |  |  |  |  | 2,702 |
2013 |  |  |  |  |  |  | 239 |
|  |  |  |  |  |  | 16,510 |
Less: amount representing interest – weighted average rate of 10.50% |  |  |  |  |  |  | 1,734 |
Present value of minimum lease payments |  |  |  |  |  |  | 14,776 |
Less: current portion |  |  |  |  |  |  | 4,733 |
|  |  |  |  |  |  | $10,043 |

72 Financial Section North American Energy Partners Inc.

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North American Energy Partners – Notes to Consolidated Financial Statements For the years ended March 31, 2008, 2007 and 2006 (Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified) |  |

16. Senior notes

|  |  |  |  |  | March 31, |  |  | March 31, |
|  |  |  |  |  | 2008 |  |  | 2007 |
8 3/4% senior unsecured notes due 2011 ($US) |  |  |  |  |  |  | $200,000 |  |  |  | $200,000 |
Unrealized foreign exchange |  |  |  |  |  |  | 5,574 |  |  |  | 30,580 |
Unamortized financing costs and premiums, net |  |  |  |  |  |  | (3,059 | ) |  |  | – |
Fair value of embedded prepayment and early redemption options (note 20(a)) |  |  |  |  |  |  | (4,270 | ) |  |  | – |
|  |  |  |  |  |  | $198,245 |  |  |  | $230,580 |

The 8 3/4% senior notes were issued on November 26, 2003 in the amount of US$200 million (Canadian $263 million). These notes mature on December 1, 2011 with interest payable semi-annually on June 1 and December 1 of each year.
The 8 3/4% senior notes 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 the Company or any of its subsidiaries. The notes are effectively subordinated to all secured debt to the extent of the outstanding amount of such debt.
The 8 3/4% senior notes are redeemable at the option of the Company, in whole or in part, at any time on or after: December 1, 2007 at 104.375% of the principal amount; December 1, 2008 at 102.188% of the principal amount; December 1, 2009 at 100.00% of the principal amount; plus, in each case, interest accrued to the redemption date.
If a change of control occurs, the Company will be required to offer to purchase all or a portion of each holder’s 8 3/4% senior notes, at a purchase price in cash equal to 101% of the principal amount of the notes offered for repurchase plus accrued interest to the date of purchase.
As at March 31, 2008, the Company’s effective weighted average interest rate on its 8 3/4 senior notes, including the effect of financing costs and premiums, was approximately 8.94%.
On December 21, 2006, the indenture governing the 8 3/4% senior notes was amended to remove the requirement to provide reconciliation from Canadian GAAP to United States GAAP in the Company’s interim consolidated financial statements.
The Company issued 9% senior secured notes on May 19, 2005 in the amount of US$60.481 million (Canadian $76.345 million). In connection with the IPO (note 2), the Company repurchased the 9% senior secured notes for $74,748 plus accrued interest of $3,027 on November 28, 2006. These notes were redeemed at a premium of 109.26% on November 28, 2006 resulting in a loss on extinguishment of $6,338. The loss on settlement, along with the write-off of deferred financing fees of $4,342 and third party transaction costs of $255, was recorded as a loss on extinguishment of debt in the consolidated statement of operations for the year ended March 31, 2007.
17. Income taxes
Income tax provision (recovery) differs from the amount that would be computed by applying the federal and provincial statutory income tax rate to income from continuing operations. The reasons for the differences are as follows:

|  | Year ended March 31, |
|  | 2008 |  |  | 2007 |  |  | 2006 |
Income (loss) before income taxes |  |  | $57,163 |  |  |  | $18,486 |  |  |  | $(21,204 | )
Statutory tax rate |  |  | 31.47% |  |  |  | 32.12% |  |  |  | 33.62% |
Expected provision (recovery) at statutory tax rate |  |  | $17,989 |  |  |  | $5,938 |  |  |  | $(7,129 | )
Increase (decrease) related to: |  |  |  |  |  |  |  |  |  |  |  |
Impact of enacted future statutory income tax rates |  |  | (1,287 | ) |  |  | (2,106 | ) |  |  | – |
Change in redemption value and accretion of redeemable preferred shares |  |  | – |  |  |  | 1,000 |  |  |  | 11,674 |
Change in future income tax liability, resulting from valuation allowance |  |  | – |  |  |  | (5,858 | ) |  |  | (4,097 | )
Non-taxable gain on repurchase of NACG Preferred Corp. |  |  |  |  |  |  |  |  |  |  |  |
Series A preferred shares |  |  | – |  |  |  | (3,019 | ) |  |  | – |
Non-deductible financing transactions |  |  | – |  |  |  | 1,196 |  |  |  | – |
Large corporations tax |  |  | – |  |  |  | (136 | ) |  |  | 716 |
Other |  |  | 677 |  |  |  | 392 |  |  |  | (427 | )
Income tax provision (recovery) |  |  | $17,379 |  |  |  | $(2,593 | ) |  |  | $737 |

North American Energy Partners Inc. Financial Section 73

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North American Energy Partners – Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)
Classified as:

|  | Year ended March 31, |
|  | 2008 |  |  | 2007 |  |  | 2006 |
Current income taxes |  |  | $80 |  |  |  | $(2,975 | ) |  |  | $737 |
Future income taxes |  |  | 17,299 |  |  |  | 382 |  |  |  | – |
|  |  | $17,379 |  |  |  | $(2,593 | ) |  |  | $737 |

|  |  |  |  |  | March 31, |  |  | March 31, |
|  |  |  |  |  | 2008 |  |  | 2007 |
Future income tax assets: |  |  |  |  |  |  |  |  |  |  |  |
Non-capital losses carried forward |  |  |  |  |  |  | $19,985 |  |  |  | $23,875 |
Deferred share issue costs |  |  |  |  |  |  | 3,312 |  |  |  | 4,547 |
Deferred premium on senior notes |  |  |  |  |  |  | 1,002 |  |  |  | 1,614 |
Derivative financial instruments |  |  |  |  |  |  | 8,448 |  |  |  | 4,787 |
Unrealized foreign exchange loss on senior notes |  |  |  |  |  |  | 1,805 |  |  |  | 1,730 |
Billings in excess of costs on uncompleted contracts |  |  |  |  |  |  | 1,402 |  |  |  | 963 |
Capital lease obligations |  |  |  |  |  |  | 3,594 |  |  |  | 1,713 |
Intangible assets |  |  |  |  |  |  | 1,560 |  |  |  | – |
Deferred lease inducements |  |  |  |  |  |  | 244 |  |  |  | – |
|  |  |  |  |  |  | 41,352 |  |  |  | 39,229 |
Future income tax liabilities: |  |  |  |  |  |  |  |  |  |  |  |
Unbilled revenue and uncertified revenue included in accounts receivable |  |  |  |  |  |  | 8,978 |  |  |  | 3,751 |
Asset held for sale |  |  |  |  |  |  | 316 |  |  |  | 1,878 |
Accounts receivable – holdbacks |  |  |  |  |  |  | 10,239 |  |  |  | 6,262 |
Plant and equipment |  |  |  |  |  |  | 27,009 |  |  |  | 20,897 |
Deferred financing costs |  |  |  |  |  |  | – |  |  |  | 1,176 |
Intangible assets |  |  |  |  |  |  | 568 |  |  |  | 174 |
Embedded derivatives and financing costs on senior notes |  |  |  |  |  |  | 3,176 |  |  |  | – |
|  |  |  |  |  |  | 50,286 |  |  |  | 34,138 |
Net future income taxes |  |  |  |  |  |  | $(8,934 | ) |  |  | $5,091 |

Classified as:

|  |  |  |  |  | March 31, |  |  | March 31, |
|  |  |  |  |  | 2008 |  |  | 2007 |
Current asset |  |  |  |  |  |  | $8,217 |  |  |  | $14,593 |
Long-term asset |  |  |  |  |  |  | 18,199 |  |  |  | 14,364 |
Current liability |  |  |  |  |  |  | (10,907 | ) |  |  | (4,154 | )
Long-term liability |  |  |  |  |  |  | (24,443 | ) |  |  | (19,712 | )
|  |  |  |  |  |  | $(8,934 | ) |  |  | $5,091 |

The Company and its subsidiaries file income tax returns in the Canadian federal jurisdiction, and several provincial jurisdictions. Taxation years ending 2004 through 2008 in all jurisdictions remain open for potential examination by the tax authorities.
The Company has accrued no amounts as of April 1, 2007 and March 31, 2008, for uncertain tax positions. Additionally, for the year ended March 31, 2008, the Company has not recognized any amounts in respect of potential interest and penalties associated with uncertain tax positions.
At March 31, 2008, the Company has non-capital losses for income tax purposes of approximately $68,663 which expire as follows:

2015 |  |  |  |  |  |  |  |  |  |  | $50,891 |
2026 |  |  |  |  |  |  |  |  |  |  | 9,000 |
2027 |  |  |  |  |  |  |  |  |  |  | 8,772 |

74 Financial Section North American Energy Partners Inc.

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North American Energy Partners – Notes to Consolidated Financial Statements For the years ended March 31, 2008, 2007 and 2006 (Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified) |  |

18. Shares
a) Redeemable preferred shares
i. NACG Preferred Corp. preferred shares

|  | Number of |  |  |  |
|  | Shares |  |  | Amount |
Issued and outstanding March 31, 2005 |  |  | 35,000 |  |  |  | $35,000 |
Issued and outstanding March 31, 2006 |  |  | 35,000 |  |  |  | 35,000 |
Repurchased and cancelled |  |  | (35,000 | ) |  |  | (35,000 | )
Issued and outstanding March 31, 2007 and 2008 |  |  | – |  |  |  | $ – |

NACG Preferred Corp. was authorized to issue an unlimited number of Series A preferred shares. The NACG Preferred Corp. Series A preferred shares accrued dividends at a rate of $80.00 per share annually if earnings before interest, taxes, depreciation and amortization (“EBITDA”) for NAEPI was in excess of $75.0 million for the year. The dividends were payable in cash, additional NACG Preferred Corp. Series A preferred shares, or any combination of cash and shares as determined by the Company. The number of shares issuable was .001 of a whole NACG Preferred Corp. Series A preferred share for each $1.00 of dividend declared.
The NACG Preferred Corp. Series A preferred shares, which were issued in connection with the acquisition described in note 1 and were recorded at their guaranteed redemption amount, were redeemable at any time at the option of the Company, and were required to be redeemed on or before November 26, 2012. On November 28, 2006, the Company acquired the NACG Preferred Corp. Series A preferred shares for a promissory note in the amount of $27,000 and accrued dividends of $1,400 at that time were forfeited resulting in a gain on settlement of $9,400. The promissory note was subsequently repaid with the proceeds from the IPO as described in note 2.
ii. NAEPI Series A preferred shares

|  | Number of |  |  |  |
|  | Shares |  |  | Amount |
Issued and outstanding March 31, 2005 |  |  | – |  |  |  | $ – |
Issued |  |  | 1,000 |  |  |  | 321 |
Accretion |  |  | – |  |  |  | 54 |
Issued and outstanding March 31, 2006 |  |  | 1,000 |  |  |  | 375 |
Accretion |  |  | – |  |  |  | 625 |
Repurchase and cancellation |  |  | (1,000 | ) |  |  | (1,000 | )
Issued and outstanding March 31, 2007 and 2008 |  |  | – |  |  |  | $ – |

NAEPI was authorized to issue an unlimited number of Series A preferred shares. The NAEPI Series A preferred shares were non-voting and were not entitled to any dividends. The NAEPI Series A preferred shares were mandatorily redeemable at $1,000 per share on the earlier of (1) December 31, 2011 and (2) an Accelerated Redemption Event, specifically (i) the occurrence of a change of control, or (ii) if there is an initial public offering of common shares, the later of (a) the consummation of the initial public offering or (b) the date on which all of the Company’s 8 3/4% senior notes and the Company’s 9% senior secured notes are no longer outstanding. NAEPI had the right to redeem the NAEPI Series A preferred shares, in whole or in part, at $1,000 per share at any time.
The NAEPI Series A preferred shares were issued to one of the counterparties to NAEPI’s swap agreements on May 19, 2005 in connection with obtaining a new revolving credit facility. These shares were not entitled to dividends. The NAEPI Series A preferred shares were initially recorded at their fair value on the date of issue, which was estimated to be $321 based on the present value of the required cash flows using the discount rate implicit at inception. Each reporting period, the accretion of the carrying value to the present value of the redemption amount at each balance sheet date was recorded as interest expense. For the year ended March 31, 2007, the Company recognized $625 of accretion as interest expense (2006 – $54).
On October 6, 2006, the Board of Directors approved the purchase of the NAEPI Series A preferred shares for $1,000 effective with the consummation of the IPO (note 2), and these shares were purchased on November 28, 2006 pursuant to an affiliate purchase right under the terms of the NAEPI Series A preferred shares. Accordingly, the Company recorded the additional accretion charge and the extinguishment of the obligation in the year ended March 31, 2007.
North American Energy Partners Inc. Financial Section 75

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North American Energy Partners – Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)
iii. NAEPI Series B preferred shares

|  | Number of |  |  |  |
|  | Shares |  |  | Amount |
Issued and outstanding March 31, 2005 |  |  | – |  |  |  | $ – |
Issued |  |  | 83,462 |  |  |  | 8,376 |
Repurchased |  |  | (8,218 | ) |  |  | (851 | )
Change in redemption amount |  |  | – |  |  |  | 34,668 |
Issued and outstanding March 31, 2006 |  |  | 75,244 |  |  |  | 42,193 |
Accretion |  |  | – |  |  |  | 2,489 |
Repurchase and cancellation |  |  | (75,244 | ) |  |  | (44,682 | )
Issued and outstanding March 31, 2007 and 2008 |  |  | – |  |  |  | $ – |

NAEPI was authorized to issue an unlimited number of Series B preferred shares. The NAEPI Series B preferred shares were non-voting and were entitled to cumulative dividends at an annual rate of 15% of the issue price of each share. No dividends were payable on NAEPI common shares or other classes of preferred shares (defined as Junior Shares) unless all cumulative dividends had been paid on the NAEPI Series B preferred shares and NAEPI declared a NAEPI Series B preferred share dividend equal to 25% of the Junior Share dividend (except for dividends paid as part of employee and officer arrangements, intercompany administrative charges of up to $1 million annually and tax sharing arrangements). The payment of dividends and the redemption of the NAEPI Series B preferred shares were prohibited by the Company’s revolving credit facility agreement. The payment of dividends and the redemption of the NAEPI Series B preferred shares was also restricted by the indenture agreements governing the Company’s 9% senior secured notes and 8 3/4% senior notes.
7,500 NAEPI Series B preferred shares were issued to non-employee shareholders of the Company for cash proceeds of $7.5 million on May 19, 2005. The NAEPI Series B preferred shares were initially issued to certain non-employee shareholders with the agreement that an offer to purchase these NAEPI Series B preferred shares would also be extended to other shareholders of the Company on a pro rata basis to their interest in the common shares of the Company.
On June 15, 2005, the NAEPI Series B preferred shares were split 10-for-1.
On August 31, 2005, NAEPI issued 8,218 NAEPI Series B preferred shares for cash consideration of $851 to certain shareholders of the Company as a result of this offer. On November 1, 2005, NAEPI repurchased and cancelled 8,218 of the NAEPI Series B preferred shares held by the original non-employee shareholders for cash consideration of $851.
On October 6, 2005, an additional 244 NAEPI Series B preferred shares were issued for cash consideration of $25. Initially, the redemption price of the NAEPI Series B preferred shares was an amount equal to the greatest of (i) two times the issue price($1,000), less the amount, if any, of dividends previously paid in cash on the NAEPI Series B preferred shares; (ii) an amount, not to exceed $100 million which, after taking into account any dividends previously paid in cash on such NAEPI Series B preferred shares, provides the holder with a 40% rate of return, compounded annually, on the issue price from the date of issue; and (iii) an amount, not to exceed $100 million, which is equal to 25% of the arm’s length fair market value of NAEPI’s common shares without taking into account the NAEPI Series B preferred shares.
On March 30, 2006, the terms of the NAEPI Series B preferred shares were amended to eliminate option (iii) from the calculation of the redemption price of the shares.
Prior to the amendment to the terms of the NAEPI Series B preferred shares on March 30, 2006, the NAEPI Series B preferred shares were considered mandatorily redeemable and the Company was required to measure the NAEPI Series B preferred shares at the amount of cash that would be paid under the conditions specified in the contract if settlement occurred at each reporting date prior to the amendment. At March 30, 2006, management estimated the redemption amount to be $42,193. As a result, the Company has recognized the increase of $34,668 in the carrying value as an increase in interest expense for the year ended March 31, 2006.
Concurrent with the amendment to the NAEPI Series B preferred shares, NACG entered into a Put/Call Agreement with the holders of the NAEPI Series B preferred shares. The Put/Call Agreement granted to each holder of the NAEPI Series B preferred shares the right (the “Put/Call Right”) to require NACG to exchange each of the holder’s NAEPI Series B preferred shares for 100 common shares (on a post-split basis – note 18(b)) of NACG. The Put/Call Right could only be exercised upon delivery by NACG of an “Event Notice”, being either: (i) a redemption or purchase call for the redemption or purchase of the NAEPI Series B preferred shares in connection with (A) a redemption on December 31, 2011, or (B) an Accelerated Redemption Event (as defined in note 18(a)(ii)); or (ii) a notice in connection with a Liquidation Event (defined as a liquidation, winding-up or dissolution of NAEPI, whether voluntary or involuntary).
76 Financial Section North American Energy Partners Inc.

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North American Energy Partners – Notes to Consolidated Financial Statements For the years ended March 31, 2008, 2007 and 2006 (Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified) |  |

The Put/Call Agreement also granted NACG the right to require the holders of the NAEPI Series B preferred shares to exchange each of their NAEPI Series B preferred shares for 100 common shares (on a post-split basis – note 18(b)) of NACG upon delivery of a call notice to shareholders within five business days of an Event Notice.
As a result of the March 30, 2006 amendment to the terms of the NAEPI Series B preferred shares and the concurrent execution of the Put/Call Agreement, the Company accounted for the amendment as a related party transaction at carrying amount. No value was ascribed to the equity classified Put/Call Right as it was a related party transaction. The NAEPI Series B preferred shares were being accreted from their carrying value of $42.2 million on the date of amendment to their redemption value of $69.6 million on December 31, 2011 through a charge to interest expense using the effective interest method over the period to December 31, 2011. For the year ended March 31, 2007, the Company recognized $2,489 of interest expense for this accretion.
On October 6, 2006, the Board of Directors approved the exercise of the 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 and the option was exercised on November 28, 2006. The Company recorded the exchange by transferring the carrying value of the Series B preferred shares on the exercise date of $44,682 to common shares.
b) Common shares
On November 3, 2006, the Board of Directors and common shareholders approved a 20-for-1 share split of NACG’s voting and non-voting common shares. All information relating to the exchange of the NAEPI Series B preferred shares (note 18(a)), the issued and outstanding common shares (below), basic and diluted net income (loss) per share data (note 18(d)), stock options (note 28), and basic and diluted net income (loss) per share data under U.S. GAAP (note 30) have been adjusted retroactively to reflect the impact of the share split in these financial statements. The share split was effective November 3, 2006.
Authorized:
Unlimited number of common voting
shares Unlimited number of common
non-voting shares Issued and
outstanding:

|  | Number of |  |  |  |
|  | Shares(1) |  |  | Amount |
Common voting shares |  |  |  |  |  |  |  |
Issued and outstanding at March 31, 2005 |  |  | 18,147,600 |  |  |  | 90,738 |
Issued |  |  | 60,000 |  |  |  | 300 |
Issued and outstanding at March 31, 2006 |  |  | 18,207,600 |  |  |  | 91,038 |
Issued upon exercise of stock options |  |  | 27,760 |  |  |  | 139 |
Transferred from contributed surplus on exercise of stock options |  |  | – |  |  |  | 52 |
Repurchased and cancelled prior to initial public offering |  |  | (5,000 | ) |  |  | (25 | )
Conversion of NAEPI Series B preferred shares |  |  | 7,524,400 |  |  |  | 44,682 |
Initial public offering (note 2) |  |  | 9,437,500 |  |  |  | 171,165 |
Share issue costs (net of future income tax recovery of $5,667) |  |  | – |  |  |  | (12,915 | )
Issued and outstanding at March 31, 2007 |  |  | 35,192,260 |  |  |  | 294,136 |
Issued upon exercise of stock options |  |  | 324,816 |  |  |  | 1,627 |
Transferred from contributed surplus on exercise of stock options |  |  | – |  |  |  | 611 |
Conversion of common non-voting shares |  |  | 412,400 |  |  |  | 2,062 |
Issued and outstanding at March 31, 2008 |  |  | 35,929,476 |  |  |  | $298,436 |
Common non-voting shares |  |  |  |  |  |  |  |
Issued and outstanding at March 31, 2007, 2006 and 2005 |  |  | 412,400 |  |  |  | $2,062 |
Conversion to common voting shares |  |  | (412,400 | ) |  |  | (2,062 | )
Outstanding at March 31, 2008 |  |  | – |  |  |  | – |
Total common shares at March 31, 2008 |  |  | 35,929,476 |  |  |  | $298,436 |

(1) |  | The issued and outstanding common shares have been retroactively adjusted to reflect the 20-for-1 share split effected on November 3, 2006.

During the year ended March 31, 2006, 60,000 common voting shares were issued for cash consideration of $300. During the year ended March 31, 2007, 5,000 common shares were repurchased for cancellation at a cost of $84, of which $25 reduced share capital and $59 increased the Company’s deficit.
North American Energy Partners Inc. Financial Section 77

#####

North American Energy Partners – Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)
c) Contributed surplus

Balance, March 31, 2005 |  |  | 634 |
Stock-based compensation (note 28) |  |  | 923 |
Balance, March 31, 2006 |  |  | 1,557 |
Stock-based compensation (note 28) |  |  | 2,101 |
Transferred to common shares on exercise of stock options |  |  | (52 | )
Balance, March 31, 2007 |  |  | $3,606 |
Stock-based compensation (note 28) |  |  | 1,801 |
Transferred to common shares on exercise of stock options |  |  | (611 | )
Cash settlement of stock options |  |  | (581 | )
Balance, March 31, 2008 |  |  | $4,215 |

d) Net income (loss) per share

|  | Year ended March 31, |
|  | 2008 |  |  | 2007 |  |  | 2006 |
Basic net income (loss) per share Net income (loss) available to common shareholders |  |  | $39,784 |  |  |  | $21,079 |  |  |  | $(21,941 | )
Weighted average number of common shares |  |  | 35,788,776 |  |  |  | 24,352,156 |  |  |  | 18,574,800 |
Basic net income (loss) per share |  |  | $1.11 |  |  |  | $0.87 |  |  |  | $(1.18 | )
Diluted net income (loss) per share |  |  |  |  |  |  |  |  |  |  |  |
Net income (loss) available to common shareholders |  |  | $39,784 |  |  |  | $21,079 |  |  |  | $(21,941 | )
Weighted average number of common shares |  |  | 35,788,776 |  |  |  | 24,352,156 |  |  |  | 18,574,800 |
Dilutive effect of: |  |  |  |  |  |  |  |  |  |  |  |
Stock options |  |  | 1,126,859 |  |  |  | 1,091,751 |  |  |  | – |
Weighted average number of diluted common shares |  |  | 36,915,635 |  |  |  | 25,443,907 |  |  |  | 18,574,800 |
Diluted net income (loss) per share |  |  | $1.08 |  |  |  | $0.83 |  |  |  | $(1.18 | )

For the year ended March 31, 2008, weighted average stock options of 283,674 (March 31, 2007 – 98,767) were excluded from the calculation of diluted net income per share as the options’ average exercise price was greater than the average market price of the common shares for the year.
For the year ending March 31, 2006, the effect of outstanding stock options and convertible securities on net loss per share was anti-dilutive. As such, the effect of outstanding stock options and convertible securities used to calculate the diluted net loss per share has not been disclosed for this year.
19. Interest expense

|  | Year ended March 31, |
|  | 2008 |  |  | 2007 |  |  | 2006 |
Interest on senior notes |  |  | $23,338 |  |  |  | $27,417 |  |  |  | $28,838 |
Interest on capital lease obligations |  |  | 780 |  |  |  | 725 |  |  |  | 457 |
Interest on senior secured/revolving credit facility |  |  | 769 |  |  |  | 346 |  |  |  | 564 |
Interest on NACG Preferred Corp. Series A preferred shares |  |  | – |  |  |  | 1,400 |  |  |  | – |
Accretion and change in redemption value of NAEPI Series B preferred shares |  |  | – |  |  |  | 2,489 |  |  |  | 34,668 |
Accretion of NAEPI Series A preferred shares |  |  | – |  |  |  | 625 |  |  |  | 54 |
Interest on long-term debt |  |  | 24,887 |  |  |  | 33,002 |  |  |  | 64,581 |
Amortization of deferred financing costs |  |  | – |  |  |  | 3,436 |  |  |  | 3,338 |
Amortization of bond issue costs and premiums |  |  | 838 |  |  |  | – |  |  |  | – |
Other interest |  |  | 1,294 |  |  |  | 811 |  |  |  | 857 |
|  |  | $27,019 |  |  |  | $37,249 |  |  |  | $68,776 |

78 Financial Section North American Energy Partners Inc.

#####

North American Energy Partners – Notes to Consolidated Financial Statements For the years ended March 31, 2008, 2007 and 2006 (Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified) |  |

20. Derivative financial instruments
a) Realized and unrealized (gain) loss on derivative financial instruments

|  | Year ended March 31, |
|  | 2008 |  |  | 2007 |  |  | 2006 |
Realized and unrealized (gain) loss on cross-currency and interest rate swaps |  |  | $23,456 |  |  |  | $(196 | ) |  |  | $14,689 |
Unrealized loss on embedded price escalation features in a long-term revenue construction contract |  |  | 7,575 |  |  |  | – |  |  |  | – |
Unrealized (gain) on embedded price escalation features in a long-term supplier contract |  |  | (1,205 | ) |  |  | – |  |  |  | – |
Unrealized loss on embedded pre-payment and early redemption options on senior notes |  |  | 4,249 |  |  |  | – |  |  |  | – |
|  |  | $34,075 |  |  |  | $(196 | ) |  |  | $14,689 |

b) Fair value of derivative financial instruments

|  |  |  |  |  | Derivative |  |  |  |
|  |  |  |  |  | financial |  |  |  |
March 31, 2008 |  |  |  |  |  | instruments |  |  | Senior notes |
Cross-currency and interest rate swaps |  |  |  |  |  |  | $81,649 |  |  |  | $ – |
Embedded price escalation features in a long-term revenue construction contract |  |  |  |  |  |  | 14,821 |  |  |  | – |
Embedded price escalation features in a long-term supplier contract |  |  |  |  |  |  | 1,269 |  |  |  | – |
Embedded pre-payment and early redemption options on senior notes |  |  |  |  |  |  | – |  |  |  | (4,270 | )
Total fair value of derivative financial instruments |  |  |  |  |  |  | 97,739 |  |  |  | (4,270 | )
Less: current portion |  |  |  |  |  |  | 4,720 |  |  |  | – |
|  |  |  |  |  |  | $93,019 |  |  |  | $(4,270 | )

|  |  |  |  |  | Derivative |  |  |  |
|  |  |  |  |  | financial |  |  |  |
April 1, 2007 |  |  |  |  |  | instruments |  |  | Senior notes |
Cross-currency and interest rate swaps |  |  |  |  |  |  | $60,863 |  |  |  | $ – |
Embedded price escalation features in a long-term revenue construction contract |  |  |  |  |  |  | 7,246 |  |  |  | – |
Embedded price escalation features in a long-term supplier contract |  |  |  |  |  |  | 2,474 |  |  |  | – |
Embedded pre-payment and early redemption options on senior notes |  |  |  |  |  |  | – |  |  |  | (8,519 | )
Total fair value of derivative financial instruments |  |  |  |  |  |  | 70,583 |  |  |  | (8,519 | )
Less: current portion |  |  |  |  |  |  | (2,669 | ) |  |  | – |
|  |  |  |  |  |  | $67,914 |  |  |  | $(8,519 | )

21. Other information
a) Supplemental cash flow information

|  | Year ended March 31, |
|  | 2008 |  |  | 2007 |  |  | 2006 |
Cash paid during the year for: |  |  |  |  |  |  |  |  |  |  |  |
Interest |  |  | $29,658 |  |  |  | $34,061 |  |  |  | $29,978 |
Income taxes |  |  | 80 |  |  |  | 342 |  |  |  | 617 |
Cash received during the year for: |  |  |  |  |  |  |  |  |  |  |  |
Interest |  |  | 345 |  |  |  | 1,156 |  |  |  | 530 |
Income taxes |  |  | 300 |  |  |  | 160 |  |  |  | 2 |
Non-cash transactions: |  |  |  |  |  |  |  |  |  |  |  |
Acquisition of plant and equipment by means of capital leases |  |  | 8,829 |  |  |  | 4,653 |  |  |  | 5,910 |
Lease inducements |  |  | 1,045 |  |  |  | – |  |  |  | – |
Issue of Series A preferred shares |  |  | – |  |  |  | – |  |  |  | 321 |

North American Energy Partners Inc. Financial Section 79

#####

North American Energy Partners – Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)
b) Net change in non-cash working capital

|  |  |  |  |  | Year ended March 31, |
|  |  |  |  |  | 2008 |  |  | 2007 |  |  | 2006 |
Operating activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accounts receivable |  |  |  |  |  |  | $(59,312 | ) |  |  | $(25,278 | ) |  |  | $(9,396 | )
Allowance for doubtful accounts |  |  |  |  |  |  | 654 |  |  |  | 18 |  |  |  | (94 | )
Unbilled revenue |  |  |  |  |  |  | (2,174 | ) |  |  | (39,339 | ) |  |  | (2,083 | )
Inventory |  |  |  |  |  |  | 46 |  |  |  | (99 | ) |  |  | 77 |
Prepaid expenses and deposits |  |  |  |  |  |  | 2,632 |  |  |  | (10,133 | ) |  |  | 66 |
Other assets |  |  |  |  |  |  | 4,616 |  |  |  | (9,855 | ) |  |  | (163 | )
Accounts payable |  |  |  |  |  |  | 21,430 |  |  |  | 32,073 |  |  |  | (6,396 | )
Accrued liabilities |  |  |  |  |  |  | 21,685 |  |  |  | (1,429 | ) |  |  | 9,402 |
Billings in excess of costs incurred and estimated earnings on uncompleted contracts |  |  |  |  |  |  | 1,773 |  |  |  | (2,125 | ) |  |  | 3,799 |
|  |  |  |  |  |  | (8,650 | ) |  |  | (56,167 | ) |  |  | (4,788 | )
Investing activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accounts payable |  |  |  |  |  |  | $(2,835 | ) |  |  | $7,922 |  |  |  | $1,391 |
|  |  |  |  |  |  | (2,835 | ) |  |  | 7,922 |  |  |  | 1,391 |

22. Segmented information
a) General overview
The Company operates in the following reportable business segments, which follow the organization, management and reporting structure within the Company.

• |  | Heavy Construction and Mining:
|  | The Heavy Construction and Mining segment provides mining and site preparation services, including overburden removal and reclamation services, project management and underground utility construction, to a variety of customers throughout Canada.
• |  | Piling:
|  | The Piling segment provides deep foundation construction and design build services to a variety of industrial and commercial customers throughout Western Canada.
• |  | Pipeline:
|  | The Pipeline segment provides both small and large diameter pipeline construction and installation services to energy and industrial clients throughout Western Canada.

Certain business units of the Company have been aggregated into the Heavy Construction and Mining segment as they have similar economic characteristics. These business units are considered to have similar economic characteristics based on similarities in the nature of the services provided, the customer base and the similarities in the production process and the resources used to provide these services.
b) Results by business segment:

|  | Heavy |  |  |  |  |  |  |  |  |  |
For the year ended |  | Construction |  |  |  |  |  |  |  |  |  |
March 31, 2008 |  | and Mining |  |  | Piling |  |  | Pipeline |  |  | Total |
Revenues from external customers |  |  | $626,582 |  |  |  | $162,397 |  |  |  | $200,717 |  |  |  | $989,696 |
Depreciation of plant and equipment |  |  | 23,761 |  |  |  | 3,340 |  |  |  | 969 |  |  |  | 28,070 |
Segment profits |  |  | 105,378 |  |  |  | 45,362 |  |  |  | 25,465 |  |  |  | 176,205 |
Segment assets |  |  | 500,535 |  |  |  | 110,288 |  |  |  | 88,143 |  |  |  | 698,966 |
Expenditures for segment plant and equipment |  |  | 37,916 |  |  |  | 12,945 |  |  |  | 5,229 |  |  |  | 56,090 |

80 Financial Section North American Energy Partners Inc.

#####

North American Energy Partners – Notes to Consolidated Financial Statements For the years ended March 31, 2008, 2007 and 2006 (Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified) |  |

|  | Heavy |  |  |  |  |  |  |  |  |  |
For the year ended |  | Construction |  |  |  |  |  |  |  |  |  |
March 31, 2007 |  | and Mining |  |  | Piling |  |  | Pipeline |  |  | Total |
Revenues from external customers |  |  | $473,179 |  |  |  | $109,266 |  |  |  | $47,001 |  |  |  | $629,446 |
Depreciation of plant and equipment |  |  | 21,885 |  |  |  | 2,949 |  |  |  | 946 |  |  |  | 25,780 |
Segment profits |  |  | 71,062 |  |  |  | 34,395 |  |  |  | (10,539 | ) |  |  | 94,918 |
Segment assets |  |  | 467,315 |  |  |  | 93,703 |  |  |  | 66,118 |  |  |  | 627,136 |
Expenditures for segment plant and equipment |  |  | 95,829 |  |  |  | 8,940 |  |  |  | 1,918 |  |  |  | 106,687 |

|  | Heavy |  |  |  |  |  |  |  |  |  |
For the year ended |  | Construction |  |  |  |  |  |  |  |  |  |
March 31, 2006 |  | and Mining |  |  | Piling |  |  | Pipeline |  |  | Total |
Revenues from external customers |  |  | $366,721 |  |  |  | $91,434 |  |  |  | $34,082 |  |  |  | $492,237 |
Depreciation of plant and equipment |  |  | 10,118 |  |  |  | 2,543 |  |  |  | 1,352 |  |  |  | 14,013 |
Segment profits |  |  | 50,730 |  |  |  | 22,586 |  |  |  | 8,996 |  |  |  | 82,312 |
Segment assets |  |  | 327,850 |  |  |  | 84,117 |  |  |  | 48,804 |  |  |  | 460,771 |
Expenditures for segment plant and equipment |  |  | 25,090 |  |  |  | 880 |  |  |  | 82 |  |  |  | 26,052 |

c) Reconciliations
i. Income (loss) before income taxes

|  |  |  |  |  | Year ended March 31, |
|  |  |  |  |  | 2008 |  |  | 2007 |  |  | 2006 |
Total profit for reportable segments |  |  |  |  |  |  | $176,205 |  |  |  | $94,918 |  |  |  | $82,312 |
Unallocated corporate expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
General and administrative expense |  |  |  |  |  |  | (69,670 | ) |  |  | (39,769 | ) |  |  | (30,903 | )
Loss (gain) on disposal of plant and equipment |  |  |  |  |  |  | (179 | ) |  |  | (959 | ) |  |  | 733 |
Amortization of intangibles |  |  |  |  |  |  | (1,071 | ) |  |  | (582 | ) |  |  | (730 | )
Interest expense |  |  |  |  |  |  | (27,019 | ) |  |  | (37,249 | ) |  |  | (68,776 | )
Foreign exchange gain |  |  |  |  |  |  | 25,442 |  |  |  | 5,044 |  |  |  | 13,953 |
Realized and unrealized loss (gain) on derivative financial instruments |  |  |  |  |  |  | (34,075 | ) |  |  | 196 |  |  |  | (14,689 | )
Gain on repurchase of NACG Preferred Corp. preferred shares |  |  |  |  |  |  | – |  |  |  | 9,400 |  |  |  | – |
Loss on extinguishment of debt |  |  |  |  |  |  | – |  |  |  | (10,935 | ) |  |  | (2,095 | )
Other income |  |  |  |  |  |  | 418 |  |  |  | 904 |  |  |  | 977 |
Unallocated equipment costs (1) |  |  |  |  |  |  | (12,888 | ) |  |  | (2,482 | ) |  |  | (1,986 | )
Income (loss) before income taxes |  |  |  |  |  |  | $57,163 |  |  |  | $18,486 |  |  |  | $(21,204 | )

(1) |  | Unallocated equipment costs represent actual equipment costs, including non-cash items such as depreciation, which have not been allocated to reportable segments.

ii. Total assets

|  |  |  |  |  |  |  |  |  | March 31, |  |  | March 31, |
|  |  |  |  |  |  |  |  |  | 2008 |  |  | 2007 |
Total assets for reportable segments |  |  |  |  |  |  |  |  |  |  | $698,966 |  |  |  | $621,636 |
Corporate assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash |  |  |  |  |  |  |  |  |  |  | 32,871 |  |  |  | 7,895 |
Plant & equipment |  |  |  |  |  |  |  |  |  |  | 26,785 |  |  |  | 18,794 |
Future income taxes |  |  |  |  |  |  |  |  |  |  | 26,416 |  |  |  | 28,957 |
Other |  |  |  |  |  |  |  |  |  |  | 8,560 |  |  |  | 33,454 |
Total corporate assets |  |  |  |  |  |  |  |  |  |  | 94,632 |  |  |  | 89,100 |
Total assets |  |  |  |  |  |  |  |  |  |  | $793,598 |  |  |  | $710,736 |

The Company’s goodwill is assigned to the Mining and Site Preparation, Piling and Pipeline segments in the amounts of $125,447, $41,872, and $32,753, respectively.
All of the Company’s assets are located in Canada and activities are carried out throughout the year.
North American Energy Partners Inc. Financial Section 81

#####

North American Energy Partners – Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)
iii. Depreciation of plant and equipment

|  | Year ended March 31, |
|  | 2008 |  |  | 2007 |  |  | 2006 |
Total depreciation for reportable segments |  |  | $28,070 |  |  |  | $25,780 |  |  |  | $14,013 |
Depreciation for corporate assets |  |  | 8,659 |  |  |  | 5,254 |  |  |  | 7,712 |
Total depreciation |  |  | $36,729 |  |  |  | $31,034 |  |  |  | $21,725 |

iv. Capital expenditures for plant and equipment

|  | Year ended March 31, |
|  | 2008 |  |  | 2007 |  |  | 2006 |
Total capital expenditures for reportable segments |  |  | $56,090 |  |  |  | $106,687 |  |  |  | $26,052 |
Capital expenditures for corporate assets |  |  | 1,689 |  |  |  | 3,332 |  |  |  | 2,800 |
Total capital expenditures |  |  | $57,779 |  |  |  | $110,019 |  |  |  | $28,852 |

d) Customers
The following customers accounted for 10% or more of total revenues:

|  | Year ended March 31, |
|  | 2008 |  |  | 2007 |  |  | 2006 |
Customer A |  |  | 23% |  |  |  | 16% |  |  |  | 5% |
Customer B |  |  | 19% |  |  |  | 0% |  |  |  | 0% |
Customer C |  |  | 13% |  |  |  | 17% |  |  |  | 32% |
Customer D |  |  | 13% |  |  |  | 12% |  |  |  | 16% |
Customer E |  |  | 13% |  |  |  | 10% |  |  |  | 6% |
Customer F |  |  | 4% |  |  |  | 10% |  |  |  | 2% |
Customer G |  |  | 0% |  |  |  | 4% |  |  |  | 10% |

The revenue by major customer was earned in the Heavy Construction and Mining, Piling and Pipeline segments.
23. Guarantee
At March 31, 2008, in connection with a heavy equipment financing agreement, the Company has guaranteed $18.5 million of debt owed to the equipment manufacturer by a third party finance company. The Company’s guarantee of this indebtedness will expire when the equipment is commissioned, which is expected to be November 1, 2008. The Company has determined that the fair value of this financial instrument at inception and at March 31, 2008 was not significant.
24. Related Party Transactions
The Company may receive consulting and advisory services provided by the Sponsors (principals or employees of such Sponsors are directors of the Company) with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters, and no fee is charged for these consulting and advisory engagements.
In order for the Sponsors to provide such advice and consulting we consider 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. The transactions are in the normal course of operations and are measured at the exchange amount of consideration established and agreed to by the related parties.
Prior to the reorganization and IPO described in Note 2, the Company had a consulting and advisory services agreement with the Sponsors, under which the Company and certain of its subsidiaries received consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. An advisory fee of $400 for the year ended March 31, 2007 (2006 – $400) was paid for these services and was recorded as part of general and administrative costs in the consolidated statement of operations.
On November 28, 2006, upon closing of the IPO described in Note 2, the consulting and advisory services agreement was cancelled. The consideration paid by the Company on the closing of the offering to cancel the agreement was $2,000, which was recorded as part of general and administrative expense during the year ended March 31, 2007.
82 Financial Section North American Energy Partners Inc.

#####

North American Energy Partners – Notes to Consolidated Financial Statements For the years ended March 31, 2008, 2007 and 2006 (Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified) |  |

In addition, the Sponsors also received a fee of $854, 0.5% of the aggregate gross proceeds to the Company from the IPO, which was recorded as a share issue cost.
Pursuant to several office lease agreements, for the year ended March 31, 2007 the Company paid $572 (2006 – $836) to a company owned, indirectly and in part, by one of the directors. Effective November 28, 2006 the director resigned from the board. Accordingly, the lease agreement is no longer considered to be with a related party.
During the year ended March 31, 2006, 75,000 NAEPI Series B preferred shares (on a post-split basis – note 18(a)(iii)) were issued to the above Sponsor group in exchange for cash of $7.5 million (note 18(a)).
All related party transactions described above were measured at the exchange amount, being the consideration established and agreed to by the related parties.
25. Financial instruments and risk management
a) Fair value of financial instruments
The fair values of the Company’s cash and cash equivalents, accounts receivable, unbilled revenue, accounts payable and accrued liabilities approximate their carrying amounts due to the relatively short periods to maturity for the instruments.
The fair value of amounts due under the revolving credit facility and capital lease obligations are based on management estimates which are determined by discounting cash flows required under the instruments at the interest rate currently estimated to be available for loans with similar terms. Based on these estimates, the fair value of amounts due under the revolving credit facility and the Company’s capital lease obligations as at March 31, 2008 and March 31, 2007 are not significantly different than their carrying values. The fair value of the 8 3/4% notes, based upon their year end trading value as at March 31, 2008, is $209,178 (March 31, 2007 – $239,803) compared to their carrying value of $198,245 (March 31, 2007 – $230,580).
The methods used to determine fair value of embedded derivatives are described in note 3(q)(i) and the method used to determine fair value of cross-currency and interest rate swaps is disclosed in note 25(b)(i).
b) Risk management
The Company is exposed to market risks related to interest rate and foreign currency fluctuations. To mitigate these risks, the Company uses derivative financial instruments such as foreign currency and interest rate swap contracts.
i. Foreign currency risk and derivative financial instruments
The Company has 8 3/4% senior notes denominated in U.S. dollars in the amount of US$200 million. In order to reduce its exposure to changes in the U.S. to Canadian dollar exchange rate, the Company 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 through the whole period beginning from the issue date to the maturity date. In conjunction with the cross-currency swap agreement, the Company also entered into a U.S. 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 fixed rate of 9.765% for the duration that the 8 3/4% senior notes are outstanding. On May 19, 2005 in connection with the Company’s new revolving credit facility at that time, this fixed rate was increased to 9.889%. These derivative financial instruments were not designated as a hedge for accounting purposes. At March 31, 2008, the Company’s derivative financial instruments are carried on the consolidated balance sheets at their fair value of $97,739 (March 31, 2007 – $60,863). The fair values of the Company’s cross-currency and interest rate swap agreements are based on values quoted by the counterparties to the agreements.
At March 31, 2008, the notional principal amount of the cross-currency swap was US$200 million. The notional principal amounts of the interest rate swaps were US$200 million and Canadian $263 million.
The Company is also exposed to foreign currency risk on U.S. dollar operating lease commitments as the Company has not entered into forward foreign exchange contracts or similar instruments to manage this foreign currency exposure.
ii. Interest rate risk
The Company is exposed to interest rate risk on the revolving credit facility and its capital lease obligations. The Company does not use derivative financial instruments to reduce its exposure to these risks.
iii. Credit risk
The Company is exposed to credit risk in the event of non-payment by customers in connection with its accounts receivable and unbilled revenue. Reflective of its normal business, a majority of the Company’s accounts receivable are due from large companies operating in the resource sector. The Company regularly monitors the activities and balances in these accounts to manage its credit risk and to assess the need for an allowance for any doubtful accounts.
North American Energy Partners Inc. Financial Section 83

#####

North American Energy Partners –Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)
At March 31, 2008 and March 31, 2007, the following customers represented 10% or more of accounts receivable and unbilled revenue:

|  | March 31, |  |  | March 31, |
|  | 2008 |  |  | 2007 |
Customer A |  |  | 19% |  |  |  | 10% |
Customer B |  |  | 18% |  |  |  | 0% |
Customer C |  |  | 11% |  |  |  | 7% |
Customer D |  |  | 11% |  |  |  | 0% |
Customer E |  |  | 9% |  |  |  | 9% |

26. Commitments
The annual future minimum lease payments in respect of operating leases for the next five years and thereafter are as follows:

For the year ending March 31, |  |  |  |
2009 |  |  | $31,090 |
2010 |  |  | 26,040 |
2011 |  |  | 16,527 |
2012 |  |  | 10,871 |
2013 and thereafter |  |  | 11,510 |
|  |  | $96,038 |

27. Employee benefit plans
The Company and its subsidiaries match voluntary contributions made by the employees to their Registered Retirement Savings Plans to a maximum of 5% of base salary for each employee. Contributions made by the Company during the year ended March 31, 2008 were $789 (2007 – $645; 2006 – $409).
28. Stock-based compensation plan
Under the 2004 Amended and Restated Share Option Plan, directors, officers, employees and certain service providers to the Company are eligible to receive stock options to acquire voting common shares in the Company. Each stock option provides the right to acquire one common share in the Company and expires ten years from the grant date or on termination of employment. Options may be exercised at a price determined at the time the option is awarded, and vest as follows: no options vest on the award date and twenty percent vest on each subsequent anniversary date.

|  |  |  |  |  | Weighted |
|  |  |  |  |  | average |
|  | Number of |  |  | exercise price |
|  | options (1) |  |  | $ per share (1) |
Outstanding at March 31, 2005 |  |  | 1,524,840 |  |  |  | $5.00 |
Granted |  |  | 745,520 |  |  |  | 5.00 |
Exercised |  |  | – |  |  |  | – |
Forfeited |  |  | (204,000 | ) |  |  | (5.00 | )
Outstanding at March 31, 2006 |  |  | 2,066,360 |  |  |  | 5.00 |
Granted |  |  | 315,520 |  |  |  | 11.99 |
Exercised |  |  | (27,760 | ) |  |  | (5.00 | )
Forfeited |  |  | (207,280 | ) |  |  | (5.00 | )
Outstanding at March 31, 2007 |  |  | 2,146,840 |  |  |  | 6.03 |
Granted |  |  | 481,600 |  |  |  | 13.80 |
Exercised |  |  | (324,816 | ) |  |  | (5.00 | )
Cancelled (2) |  |  | (62,760 | ) |  |  | (5.00 | )
Forfeited |  |  | (204,500 | ) |  |  | (11.56 | )
Outstanding at March 31, 2008 |  |  | 2,036,364 |  |  |  | $7.54 |

(1) |  | The number of options and the weighted average exercise price per share have been retroactively adjusted to reflect the impact of the 20-for-1 share split disclosed in note 18(b).
(2) |  | Options settled for cash.

84 Financial Section North American Energy Partners Inc.

#####

North American Energy Partners – Notes to Consolidated Financial Statements For the years ended March 31, 2008, 2007 and 2006 (Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified) |  |

The following table summarizes information about stock options outstanding at March 31, 2008:

|  |  |  |  |  | Options outstanding |  |  | Options exercisable |
|  |  |  |  |  |  |  |  |  | Weighted |  |  |  |  |  |  | Weighted |
|  |  |  |  |  | Weighted |  |  | average |  |  |  |  |  |  | average |
|  |  |  |  |  | average |  |  | exercise |  |  |  |  |  |  | exercise |
Exercise price |  | Number |  |  | remaining life |  |  | price ($) |  |  | Number |  |  | price ($) |
$5.00 |  |  | 1,478,704 |  |  | 7.3 years |  |  | $5.00 |  |  |  | 784,640 |  |  |  | $5.00 |
$16.75 |  |  | 87,760 |  |  | 9.0 years |  |  | $16.75 |  |  |  | 17,552 |  |  |  | $16.75 |
$13.50 |  |  | 305,400 |  |  | 8.5 years |  |  | $13.50 |  |  |  | 2,000 |  |  |  | $13.50 |
$15.37 |  |  | 89,500 |  |  | 9.7 years |  |  | $15.37 |  |  |  | – |  |  |  | $ – |
$13.21 |  |  | 75,000 |  |  | 9.8 years |  |  | $13.21 |  |  |  | – |  |  |  | $ – |
|  |  | 2,036,364 |  |  | 7.9 years |  |  | $7.54 |  |  |  | 804,192 |  |  |  | $5.30 |

At March 31, 2008, the weighted average remaining contractual life of outstanding options is 7.6 years (March 31, 2007 –7.7 years). The Company recorded $1,801 of compensation expense related to stock options in the year ended March 31, 2008 (2007 – $2,101; 2006 –$923) with such amount being credited to contributed surplus. At March 31, 2008 the total compensation costs related to nonvested awards not yet recognized was $5,553 and these costs are expected to be recognized over a weighted average period of 3.0 years.
The fair value of each option granted by the Company was estimated on the grant date using the Black-Scholes option-pricing model with the following assumptions:

|  | Year ended March 31, |
|  | 2008 |  |  | 2007 |  |  | 2006 |
Number of options granted (1) |  |  | 481,600 |  |  |  | 315,520 |  |  |  | 745,520 |
Weighted average fair value per option granted ($) (1) |  |  | 4.92 |  |  |  | 9.91 |  |  |  | 3.41 |
Weighted average assumptions |  |  |  |  |  |  |  |  |  |  |  |
Dividend yield |  | nil% |  |  | nil% |  |  | nil% |
Expected volatility |  |  | 38.80% |  |  |  | 24.73% |  |  | nil% |
Risk-free interest rate |  |  | 4.25% |  |  |  | 4.30% |  |  |  | 4.13% |
Expected life (years) |  |  | 6.5 |  |  |  | 6.4 |  |  |  | 10 |

(1) |  | The number of options and the weighted average fair value per option granted have been retroactively adjusted to reflect the impact of the 20-for-1 share split disclosed in note 18(b).

As a result of the filing of a preliminary prospectus on July 21, 2006 with the various Canadian and U.S. securities commissions in preparation for the public sale of common shares, the Company is no longer eligible to use the minimum value method for measuring stock-based compensation. Accordingly, the Company considered the effect of expected volatility in its assumptions using the Black-Scholes option pricing model for options granted after this date. The Company determined its expected volatility based on a statistical analysis of historical volatility for a peer group of companies, which was prepared by an independent valuation firm. During the year ended March 31, 2007, the Company offered to accelerate the vesting of 222,080 options held by certain members of its Board of Directors, providing for the options to become immediately exercisable on the condition that such options were exercised by September 30, 2006. On July 31, 2006, 27,760 options were exercised pursuant to this offer resulting in additional compensation cost of $24 for the year ended March 31, 2007. The vesting period remained unchanged for stock options held by Directors who did not accept the Company’s offer.
On October 6, 2006, the Company approved the Amended and Restated 2004 Share Option Plan. The amended plan was approved by the shareholders on November 3, 2006 and became effective on the closing of the IPO described in Note 2. Option grants under the amended option plan may be made to directors, officers, employees and service providers selected by the Compensation Committee of the Company’s Board of Directors. The Compensation Committee may provide that any options granted will vest immediately or in increments over a period of time. Options to be granted under the amended option plan will have an exercise price of not less than the volume weighted average trading price of the common shares on the Toronto Stock Exchange or the New York Stock Exchange at the time of grant. The amended option plan provides that up to 10% of the Company’s issued and outstanding common shares from time to time may be reserved for issue or issued from treasury under the amended option plan.
In the event of certain change of control events as defined in the amended option plan, all outstanding options will become immediately vested and exercisable. The amended option plan provides that the Company’s Board of Directors can make certain specified amendments to the option plan subject to receipt of shareholder and regulatory approval, and
North American Energy Partners Inc. Financial Section 85

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North American Energy Partners – Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)
further authorizes the Board of Directors to make all other amendments to the plan, subject only to regulatory approval but without shareholder approval. The amendments the Board of Directors may make without shareholder approval include amendments of a housekeeping nature, changes to the vesting provisions of an option or the option plan, changes to the termination provisions of an option or the option plan which do not entail an extension beyond the original expiry date, the discontinuance of the option plan, and the addition of provisions relating to phantom share units, such as restricted share units and deferred share units which result in participants receiving cash payments, and the terms governing such features.
The amended option plan provides that each option includes a cashless exercise alternative which provides a holder of an option with the right to elect to receive cash in lieu of purchasing the number of shares under the option. Notwithstanding such right, the amended option plan provides that the Company may elect, at its sole discretion, to net settle the option in common stock.
All outstanding options granted under the 2004 Stock Option Plan remained outstanding after the amended and restated plan became effective.
Director’s deferred stock unit plan:
On November 27, 2007, the Company approved a Directors’ Deferred Stock Unit (“DDSU”) Plan, which became effective January 1, 2008. Under the DDSU Plan, non-employee or officer directors of the Company shall receive 50% of their annual fixed remuneration (which is included in general and administrative expenses in the consolidated statement of operations) in the form of DDSUs and may elect to receive all or a part of their annual fixed remuneration in excess of 50% in the form of DDSUs. The DDSUs vest immediately upon grant and are redeemable, in cash, equal to the difference between the market value of the Company’s common stock at maturity and the market value of the Company’s common stock on the grant date (maturity occurs when the director resigns or retires). DDSUs must be redeemed within 60 days following maturity. Directors, who are not US taxpayers, may elect to defer the maturity date until a date no later than December 1st of the calendar year following the year in which the actual maturity date occurred. As at March 31, 2008, an expense and liability of $190 was recorded relating to 11,807 outstanding units that were granted during the year.
29. Comparative figures
The comparative consolidated financial statements have been reclassified from statements previously presented to conform to the presentation of the current year consolidated financial statements.
30. United States generally accepted accounting principles
These consolidated financial statements have been prepared in accordance with Canadian GAAP, which differs in certain respects from U.S. GAAP. If U.S. GAAP were employed, the Company’s net income (loss) would be adjusted as follows:

|  | Year ended March 31, |
|  | (restated – note 30(d)) |
|  | 2008 |  |  | 2007 |  |  | 2006 |
Net income (loss) – as reported under Canadian GAAP |  |  | $39,784 |  |  |  | $21,079 |  |  |  | $(21,941 | )
Capitalized interest on assets held for construction (a) |  |  | – |  |  |  | 249 |  |  |  | 847 |
Depreciation of capitalized interest (a) |  |  | (131 | ) |  |  | (143 | ) |  |  | – |
Differences in accounting for financing costs, discounts and premiums (b) |  |  | (1,049 | ) |  |  | 1,246 |  |  |  | 590 |
Difference in fair value of stock options under US GAAP (c) |  |  | (136 | ) |  |  | – |  |  |  | – |
Unrealized (loss) gain on embedded price escalation features in a long-term revenue construction contract and supplier contract (d) |  |  | – |  |  |  | 526 |  |  |  | (3,449 | )
Unrealized (loss) gain on embedded redemption rights on senior notes (d) |  |  | 4,000 |  |  |  | 348 |  |  |  | (484 | )
Difference between accretion of NAEPI Series B preferred shares under |  |  |  |  |  |  |  |  |  |  |  |
Canadian GAAP and U.S. GAAP (e) |  |  | – |  |  |  | 249 |  |  |  | – |
Income (loss) before income taxes |  |  | 42,468 |  |  |  | 23,554 |  |  |  | (24,437 | )
Income taxes: |  |  |  |  |  |  |  |  |  |  |  |
Deferred income taxes (f) |  |  | (119 | ) |  |  | 1,816 |  |  |  | – |
Net income (loss) – U.S. GAAP |  |  | $42,349 |  |  |  | $25,370 |  |  |  | $(24,437 | )
Net income (loss) per share – basic – U.S. GAAP (1) |  |  | $1.18 |  |  |  | $1.04 |  |  |  | $(1.32 | )
Net income (loss) per share – diluted – U.S. GAAP (1) |  |  | $1.15 |  |  |  | $1.00 |  |  |  | $(1.32 | )

(1) |  | Basic net income (loss) per share – U.S. GAAP and diluted net income (loss) per share – U.S. GAAP have been retroactively adjusted to reflect the Company’s 20-for-1 share split effected on November 3, 2006 (see note 18(a)).

86 Financial Section North American Energy Partners Inc.

#####

North American Energy Partners – Notes to Consolidated Financial Statements For the years ended March 31, 2008, 2007 and 2006 (Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified) |  |

The cumulative effect of material differences between Canadian and U.S. GAAP on the consolidated shareholder’s equity of the Company is as follows:

|  | (Restated – note 30(d)) |
|  | March 31, |  |  | March 31, |  |  | March 31, |
|  | 2008 |  |  | 2007 |  |  | 2006 |
Shareholders’ equity (as reported) – Canadian GAAP |  |  | $283,364 |  |  |  | $244,278 |  |  |  | $18,111 |
Capitalized interest (a) |  |  | 1,096 |  |  |  | 1,096 |  |  |  | 847 |
Depreciation of capitalized interest (a) |  |  | (274 | ) |  |  | (143 | ) |  |  | – |
Difference in accounting for finance costs, discounts and premiums (b) |  |  | 6,217 |  |  |  | 1,836 |  |  |  | 590 |
Unrealized loss on embedded price escalation features in a long-term revenue construction contract and supplier contract (d) |  |  | – |  |  |  | (9,720 | ) |  |  | (10,246 | )
Unrealized loss on embedded redemption rights on senior notes (d) |  |  | (4,655 | ) |  |  | (136 | ) |  |  | (484 | )
Excess of fair value of amended NAEPI Series B preferred shares over carrying value of original NAEPI Series B preferred shares (e) |  |  | – |  |  |  | – |  |  |  | (3,707 | )
Deferred income taxes (f) |  |  | (1,389 | ) |  |  | 1,816 |  |  |  | – |
Shareholders’ equity – U.S. GAAP |  |  | $284,359 |  |  |  | $239,027 |  |  |  | $5,111 |

A continuity schedule of each component of the Company’s shareholders’ equity under U.S. GAAP for the year ended March 31, 2008 is as follows:

|  | Common |  |  | Contributed |  |  |  |  |  |  |
|  | shares |  |  | surplus |  |  | Deficit |  |  | Total |
March 31, 2005, as previously reported |  |  | $92,800 |  |  |  | $634 |  |  |  | $(54,605 | ) |  |  | $38,829 |
Restatement to record liability for embedded price escalation features in a long-term revenue construction contract and supplier contract (d) |  |  | – |  |  |  | – |  |  |  | (6,797 | ) |  |  | (6,797 | )
March 31, 2005, as restated |  |  | $92,800 |  |  |  | $634 |  |  |  | $(61,402 | ) |  |  | $32,032 |
Net loss, as restated |  |  | – |  |  |  | – |  |  |  | (24,437 | ) |  |  | (24,437 | )
Stock based compensation |  |  | – |  |  |  | 923 |  |  |  | – |  |  |  | 923 |
Share issue |  |  | 300 |  |  |  | – |  |  |  | – |  |  |  | 300 |
Excess of fair value of amended NAEPI Series B preferred shares over carrying value of original NAEPI Series B preferred shares (e) |  |  | – |  |  |  | – |  |  |  | (3,707 | ) |  |  | (3,707 | )
March 31, 2006 |  |  | $93,100 |  |  |  | $1,557 |  |  |  | $(89,546 | ) |  |  | $5,111 |
Net income, as restated |  |  | – |  |  |  | – |  |  |  | 25,370 |  |  |  | 25,370 |
Stock based compensation |  |  | – |  |  |  | 2,101 |  |  |  | – |  |  |  | 2,101 |
Issued upon exercise of stock options |  |  | 139 |  |  |  | – |  |  |  | – |  |  |  | 139 |
Share issues |  |  | 171,165 |  |  |  | – |  |  |  | – |  |  |  | 171,165 |
Share issue costs |  |  | (12,915 | ) |  |  | – |  |  |  | – |  |  |  | (12,915 | )
Repurchase of common shares |  |  | (25 | ) |  |  | – |  |  |  | (59 | ) |  |  | (84 | )
Conversion of NAEPI Series B preferred shares (e) |  |  | 48,140 |  |  |  | – |  |  |  | – |  |  |  | 48,140 |
Reclassification on exercise of stock options |  |  | 52 |  |  |  | (52 | ) |  |  | – |  |  |  | – |
March 31, 2007 – U.S. GAAP |  |  | $299,656 |  |  |  | $3,606 |  |  |  | $(64,235 | ) |  |  | $239,027 |
Net income |  |  | – |  |  |  | – |  |  |  | 42,349 |  |  |  | 42,349 |
Stock based compensation (c) |  |  | – |  |  |  | 1,937 |  |  |  | – |  |  |  | 1,937 |
Reclassification on exercise of stock options |  |  | 611 |  |  |  | (611 | ) |  |  | – |  |  |  | – |
Cash settlement of stock options |  |  | – |  |  |  | (581 | ) |  |  | – |  |  |  | (581 | )
Issued upon the exercise of stock options |  |  | 1,627 |  |  |  | – |  |  |  | – |  |  |  | 1,627 |
March 31, 2008 – U.S. GAAP |  |  | $301,894 |  |  |  | $4,351 |  |  |  | $(21,886 | ) |  |  | $284,359 |

The areas of material difference between Canadian and U.S. GAAP and their impact on the Company’s consolidated financial statements are described below:
a) Capitalization of interest
U.S. 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 the Company’s policies when the asset is placed into service.
North American Energy Partners Inc. Financial Section 87

#####

North American Energy Partners – Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)
b) Financing costs, discounts and premiums
Prior to April 1, 2007, transaction costs incurred in connection with the Company’s senior notes 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. For US GAAP purposes, these deferred financing costs are being amortized over the term of the related debt using the effective interest method in accordance with Accounting Principles Board Opinion No. 21 (“APB 21”).
Effective April 1, 2007, the Company adopted CICA Handbook Section 3855, “Financial Instruments – Recognition and Measurement” on a retrospective basis without restatement as described in note 3(q)(i). 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 the Company’s revolving credit facility of $1,622 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 U.S. GAAP, the Company continues to amortize these transaction costs over the stated term of the related debt using the effective interest method under APB 21.
c) Stock-based compensation
Up until April 1, 2006, the Company followed the provisions of Statement of Financial Accounting Standards No. 123, “Stock-Based Compensation” for U.S. GAAP purposes. As the Company uses the fair value method of accounting for all stock-based compensation payments under Canadian GAAP there were no differences between Canadian and U.S. GAAP prior to April 1, 2006. On April 1, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment” (“SFAS 123R”). As the Company used the minimum value method for purposes of complying with Statement of Financial Accounting Standards No. 123, it was required to adopt SFAS 123(R) prospectively. Under Canadian GAAP the Company was permitted to exclude volatility from the determination of the fair value of stock options granted until the filing of it’s 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 U.S. GAAP relating to the determination of the fair value of options granted.
d) Derivative financial instruments
Effective April 1, 2007, the Company adopted the CICA Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, and Handbook Section 3865, “Hedges”.
Under Canadian GAAP, the Company determined that the issuer’s early prepayment option included in the senior notes should be bifurcated from the host contract, along with a contingent embedded derivative in the senior notes that provide for accelerated redemption by the holders in certain instances. These embedded derivatives were measured at fair value at the inception of the senior notes and the residual amount of the proceeds was allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of the senior notes is accreted to par value over the term of the notes using the effective interest method and is recognized as interest expense as discussed in b) above. Prior to April 1, 2007 under Canadian GAAP, separate accounting of embedded derivatives from the host contract was not permitted by EIC-117.
Under U.S. GAAP, 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 the senior notes that provide for accelerated redemption by the holders in certain instances met the criteria for bifurcation from the debt contract and separate measurement at fair value. The embedded derivatives have 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 the senior notes does not meet the criteria as an embedded derivative under SFAS 133 and was not bifurcated from the host contract and measured at fair value resulting in a U.S. GAAP difference for all periods presented.
88 Financial Section North American Energy Partners Inc.

#####

North American Energy Partners – Notes to Consolidated Financial Statements For the years ended March 31, 2008, 2007 and 2006 (Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified) |  |

On adoption of CICA Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, the Company reviewed the accounting treatment of a number of outstanding contracts and determined that a price escalation feature in a revenue construction contract and a supplier contract entered into prior to April 1, 2007 contained embedded derivatives that are not closely related to the host contract under both Canadian and U.S. GAAP. The Company 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. The Company has restated its U.S. GAAP reconciliation to account for these embedded derivatives since inception of the related contracts resulting in a reduction of shareholders’ equity under U.S. GAAP at April 1, 2005 of $6,797, net of deferred income taxes of nil. This also resulted in an increase in net loss of $3,449, net of deferred income taxes of nil for the year ended March 31, 2006 and an increase in net income of $3,296 for the year ended March 31, 2007 including a deferred income tax recovery of $2,770.
e) NAEPI Series B Preferred Shares
Prior to the modification of the terms of the NAEPI Series B preferred shares March 30, 2006, there were no differences between Canadian GAAP and U.S. 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, NACG continued to classify the NAEPI Series B preferred shares as a liability and was 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 U.S. GAAP, NACG 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 U.S. GAAP, NACG was 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 NACG as a charge to minority interest (as opposed to retained earnings in the accounts of NAEPI) under US GAAP and interest expense in NACG’s financial statements under Canadian GAAP.
On November 28, 2006, NACG 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. For Canadian GAAP purposes, NACG recorded the exchange by transferring the carrying value of the NAEPI Series B preferred shares on the exercise date of $44,682 to common shares. For U.S. 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 are also common shareholders of NACG resulting in the reclassification of the carrying value of the minority interest on the exercise date of $48,140 to common shares.
f) Other matters
The tax effects of temporary differences under Canadian GAAP are described as future income taxes in these financial statements whereas such amounts are described as deferred income taxes under U.S. GAAP.
g) United States accounting pronouncements recently adopted
In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109” (“FIN 48 “) which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This Interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition requirements. FIN 48 was effective for the Company’s 2008 fiscal year. The adoption of this standard did not have a material impact on the Company’s financial statements and disclosures required under the standard are provided in note 17 to the financial statements.
In May 2007, the FASB issued FASB Staff Position No. FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48”, which provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. This FASB Staff Position is effective upon the initial adoption of FIN 48. The adoption of this standard did not have a material impact on the Company’s financial statements.
Statement of Financial Accounting Standards No. 155, “Accounting for Certain Hybrid Financial Instruments–an amendment of FASB Statements No. 133 and 140” (“SFAS 155”) was issued February 2006. This Statement is effective for all financial instruments acquired, issued, or subject to a remeasurement (new basis) event occurring after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The fair value election provided for in paragraph 4(c) of this Statement may also be applied upon adoption of this Statement for hybrid financial instruments that had been bifurcated under paragraph 12 of Statement 133 prior to the adoption of this Statement. This states that an entity that initially recognizes a host contract and a derivative instrument may irrevocably elect to initially and subsequently
North American Energy Partners Inc. Financial Section 89

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North American Energy Partners – Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)
measure that hybrid financial instrument, in its entirety, at fair value with changes in fair value recognized in earnings. SFAS 155 is applicable for all financial instruments acquired or issued in the Company’s 2008 fiscal year. The adoption of this standard did not have a material impact on the Company’s financial statements.
h) Recent United States accounting pronouncements not yet adopted
Statement of Financial Accounting Standards No. 157, “Fair Value Measurement” (“SFAS 157”) was issued September 2006. The Statement provides guidance for using fair value to measure assets and liabilities. The Statement also expands disclosures about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurement on earnings. This Statement applies under other accounting pronouncements that require or permit fair value measurements. This Statement does not expand the use of fair value measurements in any new circumstances. Under this Statement, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. SFAS 157 is effective for fair value measurements and disclosures made by the Company in its fiscal year beginning on April 1, 2008. The Company is currently evaluating the impact of this standard.
Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”) was issued in February 2007. The statement permits entities to choose to measure many financial instruments and certain other items at fair value, providing the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without the need to apply hedge accounting provisions. SFAS 159 is effective for fiscal years beginning after November 15, 2007, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.
Statement of Financial Accounting Standards No. 141R, “Business Combinations” (“SFAS 141R”) was issued December 2007. SFAS No. 141R is effective for the fiscal year beginning April 1, 2009. The statement 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. This statement establishes disclosure requirements that will enable users of the Company’s financial statements to evaluate the nature and financial effects of the business combination. The Company is currently evaluating the impact of this standard.
Statement of Financial Accounting Standards No. 160 “Noncontrolling Interests in Consolidated Financial Statements. An Amendment of ARB No. 51 (“SFAS 160”), was issued December 2007. SFAS 160 is effective for the fiscal year beginning April 1, 2009. This statement 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 statement of financial position 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 statement 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 statement 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. The Company is currently evaluating the impact of this standard.
Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities -an amendment of FASB Statement 133” (“SFAS 161”) was issued March 2008. SFAS 161 is effective for the fiscal year beginning April 1, 2009. The statement requires companies with derivative instruments to disclose information about how and why a company uses derivative instruments, how derivative instruments and related hedged items are accounted for under Statement 133, and how derivative instruments and related hedged items affect the company’s financial position, financial performance and cash flows. The required disclosures include the fair value of derivative instruments and their gains or losses in tabular format, information about credit-risk-related contingent features in derivative agreements, counterparty credit risk, and the company’s strategies and objectives for using derivative instruments. The Statement expands the current disclosure framework in Statement 133. The Company is currently evaluating the impact of this standard.
31. Subsequent Event
On June 25, 2008, the Company reached an agreement with a customer to settle all outstanding claims arising from a pipeline project completed in April 2007 for $8,000. The Company had previously recognized claims revenue of $2,744 related to such outstanding claims as at March 31, 2008 and it will recognize the excess of the settlement over previously recognized claims revenue of $5,256 as revenue in the quarter ended June 30, 2008.
90 Financial Section North American Energy Partners Inc.

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Board of Directors

Ronald A.
McIntosh
Director since May 2004
Chair of the Board of Directors
George R.
Brokaw
Director since June 2006
John A.
Brussa
Director since November 2003
John D.
Hawkins
Director since October 2003
Chair of the
Governance Committee
William C.
Oehmig
Director since November 2003
Chair of the Risk Committee
Rodney J.
Ruston
Director since May 2005
President and CEO
Allen R.
Sello
Director since January 2006
Chair of the Audit Committee
Peter W.
Tomsett
Director since September 2006
Chair of the
Compensation Committee
K. Rick
Turner
Director since November 2006
North American Energy Partners Inc. Board of Directors 91

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Senior Management

Rodney J.
Ruston
President and
Chief Executive Officer
Peter R.
Dodd
Chief Financial Officer
David
Blackley
Vice President,
Finance
Robert G.
Harris
Vice President,
Human Resources, Health,
Safety & Environment
Kevin
Mather
Vice President,
Supply Chain
Miles W.
Safranovich
Vice President,
Operations
Bernard T.
Robert
Vice President,
Business Development
& Estimating
Christopher R.
Yellowega
Vice President,
Major Mine Developments
92 Senior Management North American Energy Partners Inc.

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Corporate Information
Corporate
Headquarters
Zone 3
Acheson Industrial Area
2 - 53016 - Hwy. 60
Acheson, Alberta T7X 5A7
Phone: 780.960.7171
Fax: 780.960.7103
Auditors
KPMG LLP
Edmonton, Alberta
Solicitors
Bracewell & Giuliani LLP
Houston, Texas
Borden Ladner Gervais LLP
Toronto, Ontario
Exchange Listings
Toronto Stock Exchange
New York Stock Exchange
Ticker Symbol: NOA
Transfer Agent
CIBC Mellon Trust Company
600 The Dome Tower
333 - 7th Avenue S.W
Calgary, Alberta
Phone: 403.232.2400
Email: inquiries@cibcmellon.com
Web: www.cibcmellon.com
Investor Information
Investor
Relations
Kevin Rowand
Investor Relations Manager
Phone: 780.960.4531
Fax: 780.960.7103
E-mail: IR@nacg.ca
Web: www.nacg.ca
Annual General
Meeting
The Annual General Meeting of North American Energy Partners Inc. will be held at:
The Calgary Petroleum Club, 319 – 5th Avenue SW, Calgary, Alberta Wednesday, September 17, 2008 at 4:00 p.m.
Paper and Printing Note:
Topkote paper used in the front of this report is Forest Stewardship Council (FSC) certified, Oxygen bleached, Acid Free, Elemental Chlorine Free and contains 20% recycled fibre. Cougar natural paper used for the financials has 10% recycled post consumer fibre. The printing inks used are vegetable-based and free from ozone-damaging petroleum distillates and Volatile Organic Compounds (VOCs).

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