Edgar Filing: North American Energy Partners Inc.

Approved by the Directors

Allen R. Sello, Director

Rodney J. Ruston, Director

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 2007

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 Form 20-F or Form 40-F.

Form 20-F x Form 40-F ¨

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

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

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 ¨ No x

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 82-

Included herein:

1.	2007 Annual Report to Shareholders.

2.	Notice of Annual Meeting and Management Information Circular.

3.	Form of Proxy to be used in connection with the annual meeting of shareholders to be held on September 19, 2007.

4.	Request for financial statements.

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/ Douglas A. Wilkes
Name: Title:		Douglas A. Wilkes Vice President, Finance and Chief Financial Officer

Date: August 31, 2007

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North American Energy Partners Inc. ]

AT A GLANCE

For more than 50 years, North American Energy Partners has provided mining and construction services to oil, natural gas and resource companies, specializing in the Canadian Oil Sands region. We are one of the largest providers of heavy construction, mining, piling and pipeline services in Western Canada and we maintain one of the largest independently owned equipment fleets in the region.

In November 2006, North American Energy Partners Inc. began trading on the Toronto Stock Exchange and New York Stock Exchange under the ticker symbol NOA.

HEAVY CONSTRUCTION AND MINING:* Surface mining for oil sands and other natural resources; construction of infrastructure associated with mining operations and reclamation activities; clearing, stripping, excavating and grading for mining operations and industrial site construction for mega projects; and underground utility installation for plant, refinery and commercial building construction.

PILING: Installation of all types of driven and drilled piles, caissons and earth retention and stabilization systems for industrial and commercial projects.

PIPELINE: Installation of transmission and distribution pipe made of various materials.

*	Previously Mining and Site Preparation.

2007 Revenue: $629.4 million

Revenue by Segment

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Revenue by End Market

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Heavy Equipment Fleet: 690 units

Fleet by Category


		March 31 2007
Haul Trucks		182
Shovels and Excavators		140
Dozers		113
Drill Rigs, Cranes and Pipelayers		86
Other Heavy Equipment		169

Fleet Total		690

Other Support Equipment		660


		Annual Report 2007 ][ 01 ]

North American Energy Partners Inc. ]

2007 PERFORMANCE HIGHLIGHTS

References to 2007 refer to the fiscal period April 1, 2006 to March 31, 2007

(in thousands of dollars except ratio and per share amounts)


	2007		2006			2005
Operating Data
Revenue	$	629,446	$	492,237		$	357,323
Gross profit		92,436		80,326			36,166
Operating income		51,126		49,426			9,431
Net income (loss)		21,079		(21,941	)		(42,323	)

Per share information
Net Income (loss) - basic		0.87		(1.18	)		(2.28	)
Net income (loss) - diluted		0.83		(1.18	)		(2.28	)

EBITDA ⁽¹⁾		87,351		70,027			10,684
Consolidated EBITDA ⁽¹⁾		90,235		72,422			34,448

Balance Sheet Data
Total assets		710,736		568,682			540,155
Total shareholders’ equity		244,278		18,111			38,829
Total long-term debt ⁽²⁾to total shareholders’ equity		1.2:1		20.7:1			9.3:1

•

Successfully completed $230 million initial public offering (IPO) in November 2006

•

Listed on the Toronto Stock Exchange and New York Stock Exchange on November 22, 2006

•

Achieved record revenue of $629.4 million, an improvement of 27.9 per cent compared to 2006

•

Increased Consolidated EBITDA ⁽¹⁾by 24.6 per cent to a record $90.2 million

•

Generated record net income of $21.1 million or $0.87 per share, compared to a loss of $21.9 million or $1.18 per share in 2006

•

Added over $100 million of new equipment, significantly expanding the Company’s equipment fleet

•

Acquired Calgary-based Midwest Foundation Technologies to expand into a high-margin niche segment of the piling industry

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(1)

Refer to Management’s Discussion and Analysis: “Consolidated Financial Highlights” for a reconciliation of net income (loss) to Consolidated EBITDA.

(2)

Total long-term debt consists of the senior notes, derivative financial instruments, long-term portion of capital lease obligations and borrowings under our senior secured credit facility.

(3)

The compound annual growth rate (“CAGR”).


[ 02 ][ Annual Report 2007

North American Energy Partners Inc. ]

TO OUR SHAREHOLDERS:

THE SCALE OF A 330-TON MINING TRUCK IS IMPRESSIVE. Rising nearly three stories off the ground, operators must climb a flight of stairs just to reach the cab and the tires stand three times taller than most men. These are among the largest trucks in the world, dwarfing most other vehicles.

The opportunities before North American Energy Partners are of a similar size and scale. With the Canadian Oil Sands containing an estimated 175 billion barrels of recoverable oil reserves – second only to Saudi Arabia – billions of dollars of investment are pouring into our core market each year. Canada’s other resource industries are adding to the momentum, creating a vibrant economy and driving unprecedented demand for mining, construction, pipeline and piling services.

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North American Energy Partners enjoys a significant competitive advantage when it comes to meeting this demand. Four times larger than our next largest heavy construction and mining competitor in the Canadian Oil Sands, we have positioned ourselves as the service provider best able to respond to our customers’ needs. In fiscal 2007 we set out to further entrench our position. We strengthened our balance sheet and set the stage for growth with a successful IPO. We invested $110 million into our equipment fleet. We hired and trained over 600 new employees and we enhanced our internal and operational controls to ensure we manage our business and our opportunities effectively. We continued to focus on our excellent safety record and while we were at it, turned in record financial results.

Operating Results

For the 12 months ended March 31, 2007, we generated consolidated revenue of $629.4 million, a 27.9 per cent improvement over 2006. Despite some unexpected project costs in our Heavy Construction and Mining division and fourth-quarter losses in our Pipeline division, we were able to achieve strong bottom-line growth. Our consolidated EBITDA climbed 24.6 per cent to $90.2 million and we achieved net income of $21.1 million, a significant improvement over the loss of $21.9 million we reported in 2006.

Our Heavy Construction and Mining division performed extremely well, capitalizing on the accelerating pace of oil sands development to achieve a 29 per cent increase in revenue and 40.1 per cent improvement in gross profit. Within this division, we increased production under our mining contract with Canadian Natural Resources Limited (Canadian Natural). We are currently in the third year of this 10-year overburden removal contract and by the end of fiscal 2007, were ahead of schedule. Our relationship with Albian Sands Energy Inc. also grew during the year as we began work on site grading, road construction and crusher pocket construction at Albian’s Jackpine Mine. Consistent with our objective of maintaining a diversified revenue base, we also executed significant construction work for De Beers’ Victor Project, a large diamond mine in northern Ontario.


		Annual Report 2007 ][ 03 ]

North American Energy Partners Inc. ][ Report to Shareholders

Our Piling division also achieved outstanding results with a 19.5 per cent year-over-year increase in revenue and a 52.3 per cent improvement in gross profit. Strong operational performance and very high demand contributed to the record revenue growth and enhanced margins.

Our gains in these two segments were partially offset by challenges in our Pipeline division. While we attracted new customers and grew revenue by 37.9 per cent, we incurred a $10.5 million divisional loss as a result of higher than expected costs related to difficult terrain, challenging weather and significant changes in scope on two fixed-price contracts. We are now working with the clients and have submitted claims to recover the additional costs. Any revenue obtained from this process will be recognized once the claims are agreed to by the clients.

To help reduce our exposure to this type of risk, we have revised our contracting strategy for the Pipeline division to move away from fixed-price contracts. We believe the strong market demand for pipeline services will enable us to negotiate profitable, cost-reimbursable contracts for our pipeline projects. We have recently signed a $185 million contract for the supply of pipeline construction services for Kinder Morgan Canada’s TMX Anchor Loop project. This is not a fixed-price contract.

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Positioned to Win

New project contracts are the lifeblood of our business and we are very good at winning them. Part of our success comes as a result of our extensive experience and long-term customer relationships. Reputation matters in our industry. Size matters, too. As the pace of development in the oil sands grows and the scale of projects becomes ever larger, service providers either have the equipment and people in place to respond or they make way for those that do. As I mentioned at the outset, our key strategic focus in fiscal 2007 was ensuring that our capabilities are scaled to the needs of our customers and the size of the opportunities before us – that is, ensuring we are positioned to win.

INCREASED FINANCIAL FLEXIBILITY: Our IPO strengthened our balance sheet, enabling us to increase our revolving credit facility from $55 million to $125 million in June 2007 and improve our rating with both Standard and Poor’s and Moody’s Investors Service.

FLEET EXPANSION: We upgraded our mining and construction equipment fleet with 26 new mining trucks ranging in size from 100 to 330 tons and acquired our second EX8000 Hitachi shovel, one of the largest hydraulic shovels in the world. We also secured lease financing for an even larger 495 Bucyrus electric cable shovel, which will go into service at Canadian Natural’s Horizon Mine in January 2008. Once installed, we will be the only contractor in the oil sands operating a shovel of this size.

PILING ACQUISITIONS: We added to our existing piling capabilities with the acquisition of Midwest Foundation Technologies, a micropile operator based in Calgary, Alberta and the acquisition of Active Auger, a screwpile operator located in Saskatoon, Saskatchewan. While relatively small in dollar value, these two acquisitions have expanded our service offering with additional expertise and an extended geographic reach.


[ 04 ][ Annual Report 2007

EMPLOYEE EXPANSION: We grew our employee base to ensure we have skilled operators running our equipment and experienced managers guiding our operations. We welcomed 600 new employees in 2007, including our new Vice President, Finance and CFO, Doug Wilkes and Vice President, Human Resources, Safety and Environment, Bob Harris. As a counterpoint to these gains, we announced the resignation of Bill Koehn, Chief Operating Officer, effective July 31, 2007. Bill played a key role in growing the company and in ensuring we have an exceptional operations team in place. We are going to miss Bill but thanks to his efforts we are well positioned to maintain undisrupted operations as we complete the search for his successor.

SAFETY AND TRAINING INITIATIVES: To ensure our employees work within a safe, productive environment, we upgraded our training and safety programs and improved our internal communications with the launch of an employee intranet.

CORPORATE-WIDE BUSINESS IMPROVEMENT INITIATIVE: We made excellent progress toward our goal of increasing productivity through the standardization and improvement of our internal processes, reporting and controls. This initiative included the expansion of our executive team to provide a better span of control, the redesign of Human Resources to support our continued growth, an expansion of our Finance Department to handle the reporting requirements of a public company and the restructuring of our operations to better align reporting responsibilities and accountability. By the end of fiscal 2007, we had implemented the resulting processes and reporting tools through approximately 80 per cent of our operations.

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Looking Ahead

Overall, we ended fiscal 2007 not just a larger company but a much stronger organization – and our timing has been ideal.

With world economic growth underpinning strong demand and high prices for oil, development activity in the Canadian Oil Sands continues to accelerate. This demand has been recently demonstrated by Shell’s and Suncor’s announcements of further oil sands related expansions at a cost of $27 billion and $4.4 billion respectively. This oil sands activity, together with strength across other resource sectors, has created a robust economy in Western Canada, which in turn is supporting infrastructure and general construction spending. Market conditions are quite simply the best we have ever seen and the momentum is driving growth in all of our operating segments.

We currently have a number of high-profile oil sands mining projects underway, including contracts with Canadian Natural’s Horizon Project, Albian’s Jackpine Mine and Suncor’s Project Voyageur. With the expansion of our workforce and acquisition of new equipment in 2007, coupled with further fleet expansions planned for 2008, we expect to continue to bid competitively and profitably into this expanding market. Our Industrial operations, which report as part of the Heavy Construction and Mining division, have also secured a design-build contract for construction of the new airstrip and related facilities at Albian’s Jackpine Mine and an additional five-year site services contract for below-ground construction at Suncor’s Project Voyageur.


		Annual Report 2007 ][ 05 ]

North American Energy Partners Inc. ][ Report to Shareholders

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As we move into 2008, we intend to maintain our position as a leading provider of mining and construction services to the Canadian Oil Sands while diversifying into other resource sectors and other Canadian provinces. Our contract to supply site preparation and heavy construction services to De Beers’ Victor Project supports this strategy.

Demand for piling services is also expected to increase in 2008 as a result of strong commercial and industrial construction activity in Western Canada. Piling provides important diversification in our business and we enjoy a very strong competitive position in this market. We plan to continue growing this division by taking advantage of opportunities that augment our existing strengths.

The outlook for our Pipeline division is also very positive. As existing pipelines in Western Canada reach capacity, a significant number of new pipelines are being planned to help transport oil and gas from Alberta to customers throughout Canada and the United States. Beginning in August 2007, we will start work on the $185 million TMX Anchor Loop project for Kinder Morgan Canada. Running through Jasper National Park and Mount Robson Provincial Park, this project will not only generate significant new revenues for our Pipeline division but will also showcase our ability to manage a large and environmentally sensitive project. We expect to emerge from this contract as an even stronger competitor, well placed to take advantage of anticipated growth in the pipeline sector.

With each of our divisions enjoying a high level of market demand and with a newly strengthened operational foundation in place, we are looking forward to continued improvement in our financial results in fiscal 2008.

I want to close by thanking our employees for making fiscal 2007 not just a record financial year but also a very safe year. I thank our directors and our former owners for their support and guidance as we have transformed and strengthened our business. Finally, I thank our new shareholders for providing the investment that has helped make our growth possible.

We have achieved the critical mass we need to respond to the opportunities presented by the oil sands and by Western Canada’s broader resource and commercial construction industries. With a strong infrastructure, the right people, a clear strategy and the support of our new shareholders, we are harnessing these opportunities and transforming them into results. In short, we are positioned to win.

Rod Ruston

President and Chief Executive Officer


[ 06 ][ Annual Report 2007

North American Energy Partners Inc. ]

BOARD OF DIRECTORS



	Ronald A. McIntosh Director Since: May 2004 Chair of the Board of Directors	Rodney J. Ruston Director Since: May 2005 President and CEO

	George R. Brokaw Director Since: June 2006	Richard D. Paterson Director Since: August 2005 Chair of the Compensation Committee

	John A. Brussa Director Since: November 2003	Allen R. Sello Director Since: January 2006 Chair of the Audit Committee

	John D. Hawkins Director Since: October 2003	Peter W. Tomsett Director Since: September 2006 Chair of the Governance Committee

d	William C. Oehmig Director Since: November 2003 Chair of the Risk Committee	Rick K. Turner Director Since: November 2006


		Annual Report 2007 ][ 07 ]

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North American Energy Partners Inc. ]

OPERATIONS REVIEW Heavy Construction and Mining

Production of bitumen in the Canadian Oil Sands is expected to increase from 1.1 million barrels per day in 2005, to approximately 3.0 million by 2015. To achieve this production increase, oil companies are investing billions of dollars into mine site development and the construction of processing plants and related infrastructure. North American Energy Partners is playing a key role in every phase of this development.

We are the largest and most experienced provider of mining and construction services to the oil sands, with client relationships going back to the 1960s. Through over four decades of operations in northern Alberta, we have learned how to perform effectively in harsh conditions and meet the needs of virtually all of the major oil sands operators, as well as a growing number of other mining industry customers.

During 2007 we significantly expanded our capabilities adding new employees and equipment, including the acquisition of one of the world’s largest mining shovels which will begin operating in January 2008. These investments have enhanced our position as the largest mining and construction contractor in the Canadian Oil Sands and helped us both maintain our excellent performance at our recurring business operations and compete successfully for significant new contract work.

2007 Division Highlights:

•

Increased revenue by 29.0 per cent compared to 2006

•

Increased profit by 40.1 per cent compared to 2006

•

Expanded haul truck fleet with the addition of two 330-ton haul trucks, nine 240-ton haul trucks, seven 150-ton haul trucks and eight 100-ton haul trucks

•

Took delivery of a new large-scale shovel, the EX8000, for use on Canadian Natural’s Horizon Project

•

Secured necessary equipment, tire and parts inventory in a year of tight market supply

•

Successfully tendered on major new contracts

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Services: Heavy Construction and Mining

•

Hard rock mining

•

Overburden removal

•

Mine site preparation (road building, crusher pocket construction, etc.)

•

Mine site reclamation

•

Hauling

Services: Industrial Construction

•

Design and planning

•

Construction management

•

Construction site preparation (muskeg removal, site dewatering, site preparation)

•

Underground utility installation

•

Construction of processing plants and related facilities infrastructure


		Annual Report 2007 ][ 09 ]

North American Energy Partners Inc. ][ Operations Review

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One of our two Hitachi EX8000 shovels operating at Canadian Natural’s Horizon Mine

Major Projects:

Heavy Construction & Mining

Canadian Natural Resources Limited

Horizon Mine Overburden Removal Project

Canadian Oil Sands

Canadian Natural’s Horizon Project is the largest project in the oil sands and in fact, the largest industrial project in all of Canada. In July 2005 we began a 10-year contract to remove 400 million cubic meters of overburden at this mine – the equivalent of over three million 300 haul truck loads. During 2007 we added a second large hydraulic shovel at the site to significantly increase our production levels and finished the year ahead of schedule. Our momentum is expected to continue to build in fiscal 2008 as we add the first of two large cable shovels as well as additional haul trucks.

De Beers

Victor Project

Northern Ontario

Situated in northern Ontario, 100 km inland from the coast of James Bay, De Beers’ Victor Project is Canada’s first diamond mine outside of the Northwest Territories. Each year since 2005, we have built and maintained the 300 km winter road that provides the vital lifeline for equipment and materials into the mine site. Over the same period, we have constructed a one kilometre all-weather runway for year-round flight services. We have also undertaken the work to establish the site for the construction of the ore processing, offices and camp facilities. In addition, we provide overburden removal services to reveal the kimberlite deposit and we are undertaking other projects including the assembly and installation of a high-density polyethylene (HDPE) pipe. Our work at the project is expected to continue through to March 2008.

Albian Sands

Jackpine Mine Crusher Pocket Project

Canadian Oil Sands

The new Jackpine Mine is part of the Albian Sands Expansion-1 located in the Canadian Oil Sands. During 2007 we undertook construction of the mine’s crusher pocket to enable the installation of the equipment used to size the mined ore prior to it being delivered to the extraction plant. This project involved the excavation of over 10 million cubic meters of material.


[ 10 ][ Annual Report 2007

North American Energy Partners Inc. ][ Operations Review

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Industrial work at Suncor Energy’s Millennium Naptha Unit project

Major Projects:

Industrial

Suncor Energy

Master Services Contract

Canadian Oil Sands

In 2007 we were awarded a five-year contract with Suncor Energy to provide construction services related to earthwork, piling and underground utilities installation at Suncor’s base mine operating facilities and major project growth expansions. We will serve as contractor and general contractor for various projects related to Suncor’s growth strategy.

Suncor Energy

Millennium Naphtha Unit Project

Canadian Oil Sands

The Millennium Naphtha Unit project (MNU) represents part of Suncor’s plan to increase oil sands production to more than 500,000 barrels per day by 2010-2012. In 2007 Suncor selected North American Energy Partners to provide construction services for site preparation, underground pipe installation, piling installation and foundations at this project. Construction commenced in January 2007 and is expected to be complete in fiscal 2008.

Suncor Energy

Voyageur Upgrader

Canadian Oil Sands

The Voyageur upgrader is the centerpiece of Suncor’s expansion strategy in the Canadian Oil Sands. In 2007 Suncor selected us to provide constructability services as it relates to site preparation, underground pipe installation, piling and various other general civil related projects for the new processing plant being built at this site. Budgeting for construction work commenced in May 2007. Construction is expected to commence in fiscal 2008.

Albian Sands Energy

Airstrip Project

Canadian Oil Sands

During 2007 we received a contract to develop Albian Sands’ on-site airstrip and related facilities. The largest complete design-build project in our history, we are responsible for every aspect of the new facility including the runway, building complex, terminal, airfield lighting and approach design. We began site preparation in February 2007, with construction scheduled for completion in October 2007.


		Annual Report 2007 ][ 11 ]

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North American Energy Partners Inc. ][ Operations Review

OPERATIONS REVIEW Piling

The significant activity in the energy sector is driving economic and population growth in Western Canada which, in turn, is driving demand for both business and public facilities, and infrastructure expansion. In Alberta alone, the provincial government has allocated over $18 billion to infrastructure improvement and expansion projects between 2008 and 2010. Combined with the many construction-related opportunities in the oil sands, demand for piling services has never been greater.

North American Energy Partners is one of the two largest piling contractors in Western Canada. We offer a diverse range of piling services and are recognized as a leader in the use of innovative technologies. For example, we were the first in Canada to use Continuous Flight Auger (CFA) piling, a low-noise, no-vibration installation method that allows for economical installation of piles in areas of poor soil conditions. We continued to build on our service capabilities in fiscal 2007, adding new micropiling capabilities through our acquisition of Midwest Foundation Technologies, a company based in Calgary, Alberta. Micropiling uses small equipment to install high-density, small-diameter piles into areas where access is challenging, such as restoration and refurbishing projects.

Subsequent to the year-end, we also acquired Active Auger, a small piling operator specializing in screwpiles, based near Saskatoon, Saskatchewan. Saskatoon is one of Canada’s fastest-growing cities and is considered the gateway to northern Saskatchewan, where significant exploration and development work is underway. These new additions have enhanced our ability to respond to the booming commercial construction markets in Calgary, Edmonton and Saskatoon.

2007 Division Highlights:

•

Increased revenue by 19.5 per cent compared to 2006

•

Increased profit by 52.3 per cent compared to 2006

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Introduced Continuous Flight Auger technology

•

Acquired micropiling capabilities

•

Acquired two new anchor installation rigs

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Piling Services:

•

Driven piles

•

Drilled piles

•

Screw piles

•

Micropiles

•

Continuous Flight Auger

•

Caissons

•

Earth retention

•

Soil densification


		Annual Report 2007 ][ 13 ]

North American Energy Partners Inc. ][ Operations Review

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Piling work at Suncor Energy’s Millennium Naptha Unit project

Major Projects:

Piling

Suncor Energy

Master Services Contract

Canadian Oil Sands

We have been on site at the Suncor Extraction plant for the past three years, providing over 5,000 piles to various construction projects on an “as-required” basis. We recently signed a five-year extension to this contract that runs through to the year 2011.

Suncor Energy

Voyageur Upgrader

Canadian Oil Sands

In 2007 we signed a major contract with Suncor to install 16,000 piles as part of the development taking place at the Voyageur upgrader site. We completed estimating, scheduling and testing in fiscal 2007, with construction expected to begin in fiscal 2008.

Shell

Scotford Upgrader Expansion

Canadian Oil Sands

We were selected to provide 8,000 piles as part of Shell’s Scotford Upgrader Expansion. Work commenced in fiscal 2007 and has progressed well, with completion anticipated in fiscal 2008.


[ 14 ][ Annual Report 2007

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North American Energy Partners Inc. ][ Operations Review

OPERATIONS REVIEW Pipeline

Western Canada’s pipeline network is nearing capacity and must be expanded to accommodate growing production from the oil sands. More than a dozen major new pipeline projects are currently in the planning phases and we are about to begin work on one of the largest of them: Kinder Morgan Canada’s TMX Anchor Loop project.

For over 30 years, North American Energy Partners has been installing transmission and distribution pipeline for the transportation of oil and natural gas in Western Canada. We have built an impressive fleet of equipment and a highly skilled team known industry-wide for its ability to tackle Western Canada’s challenging climate and terrain. During 2007 we continued to build on these capabilities as we carried out challenging projects for Husky Energy, Canadian Natural and Suncor. We also added new equipment and expertise in preparation for our TMX Anchor Loop contract with Kinder Morgan.

At the same time, we enhanced the division’s project management capabilities, upgrading our estimating and reporting processes and implementing other new strategies designed to reduce project risks. These steps were taken in response to the negative financial impact of severe weather conditions and terrain challenges encountered on two of our fixed-price contracts during the year. Moving forward, we believe the rapidly growing demand for pipeline services, our more stringent risk management procedures and our decision to severely restrict our involvement in fixed-price contracts will pave the way for much stronger results in 2008 and beyond.

2007 Division Highlights:

•

Increased revenue by 37.9 per cent compared to 2006

•

Successfully negotiated $185 million TMX Anchor Loop project pipeline contract with Kinder Morgan Canada

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Significantly strengthened project control capabilities

•

Added new equipment and technical expertise

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Pipeline Services:

•

Install gas and oil transmission pipelines

•

Install gas pipeline gathering systems and tie in well sites


[ 16 ][ Annual Report 2007

North American Energy Partners Inc. ][ Operations Review

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Pipeline installation for Lloydminster to Wainwright Mainline Loop Project

Major Projects:

Pipeline

Husky Energy

Lloydminster to Wainwright 24” Mainline Loop

Lloydminster, Alberta

Husky Energy contracted us to work on the construction of a of 24” diameter oil pipeline between Lloydminster and Wainwright, Alberta. Phase I, which consisted of 40 kilometers of pipeline, was completed in fiscal 2007. The remaining 30 kilometers will be constructed during July and August of 2007.

Suncor Energy

Twin Pipeline Project

Canadian Oil Sands

Between January and April 2007 we installed 16” and 20” diameter pipelines to transport product from Suncor’s Firebag in-situ plant site to the main Suncor plant site. The project involved installation of two pipelines that run together in a single ditch through 50 kilometers of muskeg. One of the pipes was installed using an innovative construction technique that involves preheating the pipe prior to installation. The trench is then backfilled to lock the pipe into its operating configuration prior to a hot product being transported through the pipeline. This technique reduces material costs and is expected to become a more commonly used construction method on future pipeline projects.

Kinder Morgan Canada

TMX Anchor Loop project

Alberta & British Columbia

Beginning in August 2007, we will supply pipeline construction services for Kinder Morgan’s TMX Anchor Loop project under a $185 million contract. Designed to increase Kinder Morgan’s capacity to carry petroleum products to the West Coast of Canada, the project starts west of Hinton, Alberta and will run 160 kilometers through Jasper National Park and Mount Robson Provincial Park.


		Annual Report 2007 ][ 17 ]

North American Energy Partners Inc. ]

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following discussion and analysis is as of June 8, 2007 and should be read in conjunction with our annual consolidated financial statements for the year-ended March 31, 2007, which has been prepared in accordance with Canadian generally accepted accounting principles (GAAP), and except where otherwise specifically indicated all amounts are expressed in Canadian dollars. Additional information relating to our business is available on SEDAR at www.sedar.com and EDGAR at www.sec.gov. Unless otherwise indicated, references to “2007,” “2006” and “2005” refer to the fiscal years ended March 31, 2007, 2006 and 2005, respectively.

This document contains forward-looking statements. Our forward-looking statements are 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 statements. Forward-looking statements are those that do 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”, “objective”, “projection”, “forecast”, “continue”, “strategy”, “position” or the negative of those terms or other variations of them or comparable terminology. Forward-looking statements included in this document include statements regarding: financial resources; capital spending; the outlook for our business; and our results generally. Factors that could cause actual results to vary from those in the forward-looking statements include but are not limited to, those discussed below and elsewhere in this document, particularly in “Risk Factors”.

Reorganization and Initial Public Offering (“IPO”)

On November 28, 2006, prior to the consummation of the IPO discussed below, NACG Holdings Inc. (“Holdings”) amalgamated with its wholly-owned subsidiaries, NACG Preferred Corp. and North American Energy Partners Inc. (“NAEPI”). 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.

On November 28, 2006, prior to the amalgamation, the following transactions took place:

•

Holdings repurchased the Series A preferred shares issued by NAEPI for their redemption value of $1.0 million and terminated the advisory services agreement (the “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 we had received ongoing consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. We paid the Sponsors a fee of $2.0 million to terminate the agreement, which was charged to income in 2007. Under the consulting and advisory services agreement, the Sponsors also received a fee of $0.9 million, equal to 0.5% of our aggregate gross proceeds from the IPO, which was included in share issue costs.

•

The $35.0 million of Series A preferred shares issued by NACG Preferred Corp. were acquired by Holdings for a $27.0 million promissory note issued to the holders of such shares and the forfeiture of accrued dividends of $1.4 million.

•

Each holder of the Series B preferred shares issued by NAEPI received 100 Holdings common shares for each Series B preferred share held.

On November 28, 2006 we completed our IPO in the United States and Canada of 8,750,000 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 an “if, as and when issued” basis on the Toronto Stock Exchange. 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). In addition, 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


[ 18 ][ Annual Report 2007

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

(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).

We used the net proceeds from the IPO:

•

to repurchase all of our outstanding 9% senior secured notes due 2010 for $74.7 million plus accrued interest of $3.0 million on November 28, 2006. The notes were repurchased at a premium of 109.26%, resulting in a loss on extinguishment of $6.3 million and the write-off of deferred financing fees of approximately $4.3 million and third-party transaction costs of $0.3 million. These items were charged to income in 2007;

•

to repay the $27.0 million promissory note issued in respect of the repurchase of the NACG Preferred Corp. Series A preferred shares;

•

to purchase certain leased equipment for $44.6 million;

•

to pay the $2.0 million fee required to terminate the Advisory Services Agreement with the Sponsors; and

•

$ 1.3 million for general corporate purposes.

Following the offering and the above noted transactions the number of issued and outstanding common shares of the Company was 35,604,660.

The impact of the reorganization and IPO on income before income taxes and EBITDA (as defined under “Consolidated Operations – Consolidated Financial Highlights”) for the year ended March 31, 2007 is as follows:

(in thousands)


	Income before income taxes			EBITDA
Accretion of NAEPI
Series A preferred shares	$	(625	)	$	(625	)
Termination of Advisory
Services Agreement		(2,000	)		(2,000	)
Loss on retirement of 9% senior secured notes		(10,935	)		(6,338	)
Gain on repurchase NACG
Preferred Corp. Series A preferred shares		9,400			9,400

	$	(4,160	)	$	437

CONSOLIDATED OPERATIONS

Overview and Outlook

The following charts show our Revenue, Growth in Segment Revenue, Gross Profit, Net Income and Consolidated EBITDA for the three fiscal years 2007, 2006 and 2005.

LOGO

(1)

The compound annual growth rate (“CAGR”)

(2)

Refer to “Consolidated Financial Highlights” for a reconciliation of Net income (loss) to Consolidated EBITDA.


		Annual Report 2007 ][ 19 ]

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

Our consolidated financial results over the last three years reflect the positive impact of rising natural resource commodity prices on the western Canadian natural resource sector. In particular, our business has benefited from increased oil sands development in northern Alberta.

According to the Alberta Energy and Utilities Board (“EUB”), Canadian Oil Sands are estimated to contain nearly 315 billion barrels of oil with established reserves of almost 174 billion barrels as of the end of 2004, however the extraction of oil from bitumen is significantly more complex and costly than in conventional oil operations. In recent years, higher oil prices have made oil sands production economically viable, and a diverse range of oil companies and consortiums are moving swiftly to develop this resource. Interest in the oil sands has been further bolstered by political unrest in the Middle East and the subsequent desire of Western economies to seek oil supplies from more stable regions.

As a leading supplier of construction and mining services to oil sands operators, our business has benefited from these developments. We have significantly grown our equipment fleet and employee base over the past three years to serve the needs of existing oil sands producers like Syncrude Canada Ltd. (“Syncrude”), Suncor Energy Inc. (“Suncor”) and Albian Sands Energy Inc. (“Albian”) (a joint venture of Shell Canada Limited, Chevron Canada Limited and Western Oil Sands Inc.). We have also been expanding our relationships with newer operators including Canadian Natural Resources Ltd .(“CNRL”), which is currently developing a bitumen-mining project in the Fort McMurray region of the oil sands.

In 2007, we recorded record revenue of $629.4 million, up from $492.2 million in 2006 and $357.3 million in 2005. This represents a compound annual growth rate of 32.7%. The higher revenues, together with a focus on higher-margin projects led to an even more significant improvement in profitability. Gross profit from our consolidated operations increased to $92.4 million in 2007, from $80.3 million in 2006 and $36.2 million in 2005, representing a compound annual growth rate of 59.8%.

Of our three operating segments, Mining and Site Preparation (74.7% and 64.4% of total three-year consolidated revenues and total three-year segment profits, respectively) has benefited most from oil sands development. This segment has enjoyed significant growth in revenue and gross profit since 2005 as a result of our expanding relationships with oil sands customers, as well as the positive impact of our contract with De Beers Canada at their Victor Project in northern Ontario, where we are providing winter road construction and maintenance and overburden removal services. All of the growth in this segment has been achieved organically. Segment profit has increased from $11.6 million in 2005 to $71.1 million in 2007, representing a compound annual growth rate of 147.3%.

Growth in our Piling business (17.7% and 34.0% of total three-year consolidated revenues and total three-year segment profits, respectively) has been driven both by oil sands development and by Western Canada’s strong economy, which has supported a high level of commercial and industrial construction activity. In addition, the Piling segment has realized benefits from the acquisition of Midwest Foundation Technologies Inc. (“Midwest Micropile”) in 2007, which has helped us expand into niche, higher-margin segments of the piling industry. Segment profit has increased from $13.3 million in 2005 to $34.4 million in 2007, representing a compound annual growth rate of 60.8%.

Our Pipeline business (7.6% and 1.6% of total three-year consolidated revenues and total three-year segment profits, respectively) has also achieved revenue growth in the past three years. Revenues increased to $47.0 million in 2007, from $34.1 million in 2006 and $31.5 million in 2005 as a result of large contracts with CNRL, Husky Energy Inc. and Suncor. However, profitability in this segment has been negatively affected by cost overruns related to poor weather and challenging ground conditions. Segment profit increased from $4.9 million in 2005 to $9.0 million in 2006. However, due to the conditions described above, we have incurred a segment loss of $10.5 million in 2007. To reduce the potential for similar impacts on future projects, we are revising our Pipeline contract strategy. Going forward, our Pipeline segment will primarily focus on cost-reimbursable contracts and we will only undertake fixed-price contracts on rare occasions when we perceive the risk to be very low. The new $170 million contract for the construction of Kinder Morgan Canada Inc.’s (“Kinder Morgan”) TMX Anchor Loop project will not be a fixed-price contract.

Our outlook for 2008 is positive. With world economic growth continuing to positively impact oil demand and price, we expect to experience increasing project activity in our core market, the Canadian Oil Sands. Activity in


[ 20 ][ Annual Report 2007

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

the Fort McMurray area remains very strong with a number of high-profile projects underway including the CNRL expansion, Albian’s Jackpine Mine, Suncor’s Project Voyageur and the planned Fort Hills project (a partnership between Petro-Canada Oil Sands Inc., UTS Energy Corp., Teck Cominco Ltd. and Fort Hills Energy Corp.). Our 2007 acquisition of new equipment ideally suited to heavy earth moving in the oil sands area 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.

In our Mining and Site Preparation operating segment, we are actively pursuing a strategy of retaining our leading position as a provider of mining and construction services in the Fort McMurray oil sands area, while concurrently expanding our order backlog by bidding on Canadian opportunities in resource areas outside the oil sands. Our significant involvement with De Beers Canada at their Victor Project in northern Ontario is the first of such projects for our Company. We anticipate that our Piling business will continue to enjoy strong demand in 2008 as a result of the oil sands development and continued strong construction activity in Western Canada. Our outlook for our Pipeline segment is also very positive with the $170 million Kinder Morgan TMX Anchor Loop project which is scheduled to commence construction in the summer of 2007.

Overall, we expect our operating performance will continue to improve in 2008 as a result of the strong market demand for our services and a number of internal initiatives undertaken and/or completed in 2007. These include the restructuring of our management team, the strengthening of our financial and operating controls, and the implementation of a major business improvement project aimed at increasing productivity and equipment utilization.

Consolidated Financial Highlights

(in thousands)


Year Ended March 31,	2007				2006					2005
Revenue	$	629,446			$	492,237				$	357,323
Gross profit		92,436	14.7	%		80,326		16.3	%		36,166		10.1	%
General & administative costs		39,769	6.3	%		30,903		6.3	%		22,873		6.4	%
Operating income		51,126	8.1	%		49,426		10.0	%		9,431		2.6	%
Net income (loss)		21,079	3.3	%		(21,941	)	(4.3	%)		(42,323	)	(11.8	%)

Per unit/share information
Net Income (loss) - basic		0.87				(1.18	)				(2.28	)
Net income (loss) - diluted		0.83				(1.18	)				(2.28	)

EBITDA⁽¹⁾		87,351	13.9	%		70,027		14.2	%		10,684		3.0	%
Consolidated EBITDA⁽¹⁾		90,235	14.3	%		72,422		14.7	%		34,448		9.6	%

(1)

EBITDA is calculated as net income (loss) before interest expense, income taxes, depreciation and amortization. Consolidated EBITDA is defined as EBITDA, excluding the effects of 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 capital assets 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. 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 are not measures of performance under Canadian GAAP or U.S. GAAP and our computations of EBITDA and Consolidated EBITDA may vary from others in our industry. EBITDA and Consolidated EBITDA should not be considered as alternatives to operating income or net income as measures of operating performance or cash flows as measures of liquidity. EBITDA and Consolidated EBITDA have important limitations as analytical tools, and you should not consider them in isolation, or as substitutes for analysis of our results as reported under Canadian GAAP or US GAAP. A reconciliation of net income (loss) to EBITDA is as follows:


		Annual Report 2007 ][ 21 ]

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

Consolidated Financial Highlights (continued)

(in thousands)


Year ended March 31,	2007			2006			2005
Net income (loss)	$	21,079		$	(21,941	)	$	(42,323	)
Adjustments:
Interest expense		37,249			68,776			31,141
Income taxes		(2,593	)		737			(2,264	)
Depreciation		31,034			21,725			20,762
Amortization of intangible assets		582			730			3,368

EBITDA	$	87,351		$	70,027		$	10,684

A reconcilation to EBITDA to consolidated EBITDA is as follows:

Adjustments:
EBITDA	$	87,351		$	70,027		$	10,684
Unrealized foreign exchange (gain) loss on senior notes		(5,017	)		(14,258	)		(20,340	)
Realized and unrealized loss on derivative financial instruments		(196	)		14,689			43,113
Loss (gain) on disposal of plant and equipment		959			(733	)		494
Stock-based compensation		2,101			923			497
Write-off of deferred financing costs		4,342			1,774			—
Write-down of other assets to replacement cost		695			—			—

Consolidated EBITDA	$	90,235		$	72,422		$	34,448

For Year Ended March 31, 2007

Compared to March 31, 2006

For the year ended March 31, 2007, our consolidated revenue increased to $629.4 million, from $492.2 million in 2006. While gains were achieved in all operating segments, the $137.2 million, or 27.9%, improvement was primarily due to increased project work in the Mining and Site Preparation segment, most notably at Albian’s Jackpine Mine.

Gross profit increased by 15.1% to $92.4 million in 2007, from $80.3 million in 2006 as a result of the increased revenue. As a percentage of revenue, gross profit declined to 14.7% in 2007 from 16.3% in 2006 resulting from losses on three pipeline projects. Gross profit was also reduced by a $3.6 million impairment charge recognized on a major piece of construction equipment and higher operating expenses. The increase in operating expenses reflects higher equipment, repair and maintenance, and shop overhead costs related to our fleet expansion, increased activity and escalating tire costs. Operating lease expense also increased in 2007 reflecting the addition of new leased equipment to support new projects, including the 10-year CNRL overburden removal project. The impact of higher operating costs and reduced Pipeline profitability was partially offset by improved project performance in the Mining and Site Preparation and Piling segments.

Operating income for 2007 increased to $51.1 million, from $49.4 million in 2006. This $1.7 million, or 3.4%, improvement was primarily due to the $12.1 million increase in gross profit discussed above, partially offset by a $8.9 million, or 28.7%, increase in general and administrative costs. The increase in general and administrative costs reflects increased employee costs related to our growing employee base, the payment of fees to the Sponsors for termination of the Advisory Services Agreement and higher professional fees for audit, legal and general consulting services. We recorded a loss of $1.0 million on the disposal of plant and equipment as a result of the sale and write-down of certain heavy equipment, compared to a gain of $0.7 million in 2006.

For Year Ended March 31, 2006

Compared to March 31, 2005

Consolidated 2006 revenue increased to $492.2 million from $357.3 million in 2005. This $134.9 million, or 37.8%, improvement was due to increased project work in the Mining and Site Preparation segment, as well as growth in our Piling division.


[ 22 ][ Annual Report 2007

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

Gross profit in 2006 increased to $80.3 million from $36.2 million in 2005, and as a percentage of revenue, gross profit increased to 16.3%, from 10.1% in 2005. The increase in gross profit reflects improved project performance in the Mining and Site Preparation and Piling segments and the recognition of $12.9 million of revenue from claims and unapproved change orders, in 2006 for which corresponding costs were recognized in 2005. These favorable impacts were partially offset by an increase in equipment costs, operating lease expense and depreciation. The increase in equipment costs and depreciation was primarily due to increased fleet size and activity levels, higher repair and maintenance costs caused by increased usage of larger equipment, increased cost of parts, primarily tires, and overhead and shop costs. The increase in operating lease expense for 2006 primarily relates to the addition of new leased equipment to support new projects, including the 10-year CNRL overburden removal project.

Operating income for 2006 increased to $49.4 million, from $9.4 million in 2005. This $40.0 million, or 424.1%, increase reflects the $44.1 million increase in gross profit discussed above, partially offset by higher general and administrative costs. General and administrative costs increased by $8.0 million, or 35.1%, as a result of increased professional fees relating to financing transactions in 2006, increased employee costs and higher bonuses. We also recorded a gain of $0.7 million on disposal of plant and equipment in 2006, compared to a loss of $0.5 million in 2005.

SEGMENT OPERATIONS

Segment profit is determined based on internal performance measures used to assess the performance of each business in a given period. Segmented profit includes revenue earned from the performance of our projects, including amounts arising from change orders and claims, less all direct projects expenses, including direct labour, short-term equipment rentals, materials, payments to subcontractors, indirect job costs and internal charges for use of capital equipment.

Segmented Operations

(in thousands)


Year Ended March 31,	2007					2006				2005
Revenue by operating segment:
Mining and site preparation	$	473,179		75.2	%	$	366,721	74.5	%	$	264,835	74.1	%
Piling		109,266		17.3	%		91,434	18.6	%		61,006	17.1	%
Pipeline		47,001		7.5	%		34,082	6.9	%		31,482	8.8	%

Total	$	629,446		100.0	%	$	492,237	100.0	%	$	357,323	100.0	%

Profit by operating segment:
Mining and site preparation	$	71,062		74.9	%	$	50,730	61.7	%	$	11,617	38.9	%
Piling		34,395		36.2	%		22,586	27.4	%		13,319	44.6	%
Pipeline		(10,539	)	(11.1	%)		8,996	10.9	%		4,902	16.5	%

Total	$	94,918		100.0	%	$	82,312	100.0	%	$	29,838	100.0	%

Equipment hours by operating segment:
Mining and site preparation		909,361		91.6	%		811,891	93.0	%		673,613	88.2	%
Piling		47,965		4.8	%		37,300	4.3	%		56,460	7.4	%
Pipeline		35,588		3.6	%		24,197	2.8	%		33,847	4.4	%

Total		992,914		100.0	%		873,388	100.0	%		763,920	100.0	%


		Annual Report 2007 ][ 23 ]

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

Mining and Site Preparation:

FOR YEAR ENDED MARCH 31, 2007

COMPARED TO MARCH 31, 2006

Mining and Site Preparation revenue increased 29.0% to $473.2 million in 2007, from $366.7 million in 2006. The growth in revenue was primarily due to higher oil sands activity relating to large site preparation projects at Albian’s Jackpine Mine and Birch Mountain Resources, combined with the continued ramp up on the CNRL overburden removal project and the De Beers Victor Project in northern Ontario.

Segment profit from our Mining and Site Preparation activities increased 40.1%, to $71.1 million, from $50.7 million in 2006, reflecting increased revenues. Segment profit in 2007 also benefited from the recognition of $12.7 million in claims revenue related to two large site preparation project completed in 2006 and 2005. The corresponding costs of these projects were recognized in fiscal years 2006 and 2005.

FOR YEAR ENDED MARCH 31, 2006

COMPARED TO MARCH 31, 2005

Mining and Site Preparation revenue increased 38.5% to $366.7 million in 2006, from $264.8 million in 2005. This increase primarily reflects our involvement in large site preparation, underground utility installation and overburden removal at the CNRL oil sands project in Fort McMurray. We also provided significant mining services for Grande Cache Coal Corporation during the year. In addition, we recognized $12.9 million of revenue from claims and unapproved change orders for 2006 in which corresponding costs were recognized in previous years.

Mining and Site Preparation segment profit for 2006 increased 336.7% to $50.7 million, from $11.6 million in 2005, reflecting increased project activity, more efficient use of equipment and a loss incurred on a large steam-assisted gravity drainage site project in 2005. Our segment profit also benefited from claims revenue being recognized in 2006 for which corresponding costs were recognized in previous years.

Piling:

FOR YEAR ENDED MARCH 31, 2007

COMPARED TO MARCH 31, 2006

Piling revenue increased 19.5% to $109.3 million, from $91.4 million in 2006. This increase was primarily due to strong economic conditions, which supported a higher volume of construction projects in the Fort McMurray and Calgary regions, and to a single large project in the Edmonton region.

Piling segment profit increased 52.3% to $34.4 million, from $22.6 million in 2006, resulting from increased volume and our execution of higher-margin projects.

FOR YEAR ENDED MARCH 31, 2006

COMPARED TO MARCH 31, 2005

Piling revenue increased 49.9% to $91.4 million, from $61.0 million in 2005. The increase was driven by a higher volume of projects in the Fort McMurray, Vancouver and Regina regions as a result of the strong economic environment and an increase in construction activities.

Piling segment profit increased 69.6% to $22.6 million, from $13.3 million in 2005 as a result of increased volumes and higher-margin work.

Pipeline:

FOR YEAR ENDED MARCH 31, 2007

COMPARED TO MARCH 31, 2006

Pipeline revenue for 2007 increased 37.9% to $47.0 million, from $34.1 million in 2006, as a result of our involvement in three significant pipeline projects. The increase in 2007 revenue was partially offset by reduced work from EnCana.

Our Pipeline segment recorded a loss of $10.5 million in 2007, compared to a profit of $9.0 million in 2006. The 2007 result relates primarily to losses on three large pipeline projects, which were caused primarily by increased scope and condition changes not recovered from our clients. We are currently working through several unapproved change orders and claims as a result of these losses.

FOR YEAR ENDED MARCH 31, 2006

COMPARED TO MARCH 31, 2005

Our Pipeline revenue increased 8.3% to $34.1 million, from $31.5 million in 2005, primarily as a result of increased work for EnCana and CNRL.

Pipeline profit increased 83.5% to $9.0 million, from $4.9 million in 2005, reflecting the combination of increased volume and higher-margin work during the 2006 period.


[ 24 ][ Annual Report 2007

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

NON-OPERATING EXPENSES (INCOME)

(in thousands)


Year Ended March 31,	2007			2006			2005
Interest expense
Interest on long term debt	$	29,542		$	29,295		$	23,419
Accretion and change in redemption value of mandatorily redeemable preferred shares		3,114			34,722			—
Interest on senior secured credit facility		—			564			3,274
Amortization of deferred financing costs		3,436			3,338			2,554
Other interest		1,157			857			1,894

Total interest expense	$	37,249		$	68,776		$	31,141
Foreign exchange loss (gain)	$	(5,044	)	$	(13,953	)	$	(19,815	)
Realized and unrealized (gain) loss on derivative financial instruments		(196	)		14,689			43,113
Gain on repurchase of NACG Preferred Corp. Series A preferred shares		(9,400	)		—			—
Loss on extinguishment of debt		10,935			2,095			—
Other income		(904	)		(977	)		(421	)
Income tax (recovery) expense		(2,593	)		737			(2,264	)

Non-Operating expenses (income):

FOR YEAR ENDED MARCH 31, 2007

COMPARED TO MARCH 31, 2006

Total interest expense decreased by $31.5 million in 2007 compared to 2006, primarily due to the amendment to the terms of NAEPI’s mandatorily redeemable Series B preferred shares on March 30, 2006 (as described in note 17(a) to the 2007 annual consolidated financial statements). Changes in the redemption value of the Series B preferred shares were charged to interest expense prior to the amendment date. In 2007, the accretion of redeemable preferred shares amounted to $2.5 million of interest expense, compared to $34.7 million in 2006 which related to both accretion and change in redemption value of mandatory redeemable preferred shares. In addition, as a result of the repurchase of NAEPI’s Series A preferred shares, $0.6 million of additional interest expense was recognized for 2007, in order to accrete up to the full redemption value of $1.0 million for these preferred shares. On November 28, 2006, each Series B preferred share was exchanged for 100 common shares of Holdings. On exchange, the carrying amount of the preferred shares, $44.7 million, was reclassified to common stock.

Substantially all of the $5.0 million foreign exchange gain recognized in 2007 relates to the exchange difference between the Canadian and U.S. dollar on conversion of the US$60.5 million of 9% senior secured notes (subsequently retired on November 28, 2006) and the US$200.0 million of 8³/4% senior notes.

We recorded a $0.2 million realized and unrealized gain on derivative financial instruments in 2007, compared to a $14.7 million realized and unrealized loss in 2006. We employ derivative financial instruments to provide an economic hedge for our 83³/4% senior notes. The subsequent gain or loss reflects changes in the fair value of these derivatives. See “Liquidity and Capital Resources – Liquidity Requirements” for further information regarding these derivative financial instruments.

We recognized a 2007 gain of $9.4 million on the repurchase of $27.0 million of the $35.0 million of NACG Preferred Corp. Series A preferred shares and related forfeited dividends of $1.4 million. Upon retiring NAEPI’s 9% senior secured notes, we recorded a loss of $10.9 million, which includes a $6.3 million loss on extinguishment of notes, a $4.3 million write-off of deferred financing fees and related transaction costs of $0.3 million.

We recorded an income tax recovery of $2.6 million in 2007, compared to an income tax expense of $0.7 million for 2006. The effective rate is significantly lower than the statutory tax rate primarily due to the impact of the enacted rate changes during the year, the reversal of the valuation allowance that existed at March 31, 2006 and the net impact of permanent differences


		Annual Report 2007 ][ 25 ]

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

relating to various income (charges) recognized for accounting purposes related to mandatory redeemable shares and other financing transactions which were non-taxable. Income tax expense in the prior year, primarily reflects the federal large corporation tax, which is a form of minimum tax, as a full valuation allowance was recorded against our net future tax asset given the uncertainty of recognizing the benefit of the net future tax asset at the end of 2006.

Non-operating expense (income):

FOR YEAR ENDED MARCH 31, 2006

COMPARED TO MARCH 31, 2005

Our total interest expense increased by $37.6 million in 2006 compared to 2005, primarily due to interest charges of $34.7 million resulting from the issuance in May 2005 of NAEPI’s mandatorily redeemable Series B preferred shares and a $5.9 million increase in interest on long-term debt resulting from the issuance in May 2005 of NAEPI’s 9% senior secured notes. These increases in interest expense were partially offset by decreased interest expense resulting from the full repayment in May 2005 of the borrowings under NAEPI’s senior secured credit facility.

Substantially all of the $14.0 million foreign exchange gain recognized in 2006 relates to the exchange difference between the Canadian and U.S. dollar on conversion of the US$60.5 million of 9% senior secured notes and the US$200.0 million of 83³/4% senior notes. By comparison, our 2005 foreign exchange gain related only to the US$200.0 million of 83³/4% senior notes. In 2006, we recorded a $14.7 million realized and unrealized loss on derivative financial instruments relating to the change in the fair value of these derivatives. By comparison, we recorded a realized and unrealized loss of $43.1 million on our derivative financial instruments in 2005. See “Liquidity and Capital Resources – Liquidity requirements” for further information regarding the derivative financial instruments.

We recognized a loss on extinguishment of debt of $2.1 million in 2006 as a result of $0.3 million of issue costs related to NAEPI’s Series A preferred shares and the write off of deferred financing fees of $1.8 million resulting from the May 2005 repayment of NAEPI’s previous senior secured credit facility.

We recorded an income tax expense of $0.7 million in 2006, compared to a net income tax recovery of $2.3 million in 2005. Income tax expense primarily reflects only the federal large corporation tax, which was a form of minimum tax, as a full valuation allowance was recorded against our net future tax asset given the uncertainty of recognizing the benefit of the net future tax asset at the end of 2006.

COMPARATIVE QUARTERLY RESULTS

A number of factors contribute to variations in our quarterly results between periods, including weather, customer capital spending on large oil sands and natural gas related 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.

We generally experience a decline in revenues during the first quarter of each fiscal year due to seasonality, as weather conditions make operating during this period difficult. The level of activity in the Mining and Site Preparation and Pipeline segments declines when frost leaves the ground and many secondary roads are temporarily rendered incapable of supporting the weight of heavy equipment. The duration of this period is referred to as “spring breakup” and it has a direct impact on our activity levels. Revenues during the fourth quarter of each fiscal year are typically highest as ground conditions are most favourable in our operating regions. As a result, full-year results are not likely to be a direct multiple of any particular quarter or combination of quarters.


[ 26 ][ Annual Report 2007

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

Comparative Quarterly Results

(in millions, except per share amounts)


	Fiscal Year 2007									Fiscal Year 2006
	Q4		Q3		Q2			Q1		Q4		Q3		Q2		Q1
Revenue	$	205.3	$	155.9	$	130.1		$	138.1	$	142.3	$	121.5	$	124.0	$	104.4
Gross profit		13.6		26.0		20.2			32.6		31.7		13.8		21.9		12.9
Operating income		4.5		13.8		9.7			23.1		22.4		5.9		15.9		5.2
Net income(loss)		1.4		6.6		(4.8	)		17.9		13.7		2.1		11.5		(49.2	)
EPS - basic ⁽¹⁾		0.04		0.27		(0.26	)		0.96		0.73		0.11		0.62		(2.65	)
EPS - diluted ⁽¹⁾		0.04		0.26		(0.26	)		0.71		0.73		0.11		0.47		(2.65	)
Equipment hours		268,565		239,341		236,711			248,297		231,633		221,355		234,649		185,751

(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.

Consolidated Fourth Quarter Results:

FOR THREE MONTHS ENDED MARCH 31, 2007

COMPARED TO MARCH 31, 2006

For the fourth quarter ended March 31, 2007, our consolidated revenue increased to $205.3 million, from $142.3 million in 2006. This $63.0 million, or 44.3%, increase was primarily due to increased project work at Albian’s Jackpine Mine in the Mining and Site Preparation segment, as well as growth in our Pipeline division.

Gross profit decreased by 56.9% to $13.6 million in 2007, from $31.7 million in 2006 as a result of project losses in the Pipeline segment, a $3.6 million asset impairment charge and higher equipment operating expenses. Equipment costs were driven by higher activity levels, significant increases in tire costs and increased shop labour and overhead. Operating lease expense decreased in the fourth quarter of 2007 due to the buy-out of numerous leases as part of the proceeds from the IPO. As a result of the pipeline losses, asset impairment charge and higher equipment operating costs, gross profit as a percentage of revenue was 6.6% in 2007, compared to 22.3% in 2006.

Operating income for the fourth quarter ended March 31, 2007 decreased to $4.5 million, from $22.4 million in 2006. This $17.9 million, or 79.9%, decrease was due to the reduction in gross profit discussed above. General and administrative costs remained largely unchanged in the fourth quarter ended March 31, 2007 as increased stock compensation expense was offset by decreased employee costs.

Segmented Fourth Quarter Results:

FOR THREE MONTHS ENDED MARCH 31, 2007

COMPARED TO MARCH 31, 2006

Mining and Site Preparation revenue for the fourth quarter ended March 31, 2007 increased 48.9% to $150.1 million in 2007, from $100.9 million in 2006. The growth in revenue was primarily due to higher oil sands and mining activity relating to large site preparation projects at Albian, continued ramp up on Canadian Natural’s overburden removal project and increased work at the De Beers Victor Project in northern Ontario. Piling revenue for the fourth quarter ended March 31, 2007 increased 6.2% to $29.9 million, from $28.1 million in 2006. This increase was primarily due to higher volume of construction projects in the Fort McMurray region and a large project in the Edmonton region. Pipeline revenue increased 91.0% to $25.4 million, from $13.3 million in 2006, as a result of a large pipeline project for Suncor.

Segment profit from our Mining and Site Preparation activities decreased 0.6%, to $23.5 million, from $23.6 million in 2006. Increased revenues and a claim settlement related to a large site preparation project completed in fiscal 2006 was entirely offset by margin reductions on a large site preparation project in the fourth quarter of 2007. Challenging soil and water conditions on this project resulted in the recognition of $4.7 million in additional costs, with no associated revenue. We are actively negotiating change orders with the client relating to these changed conditions. Fourth quarter Piling segment profit increased 6.1% to $8.8 million in 2007, from $8.3 million in 2006, reflecting the impact of


		Annual Report 2007 ][ 27 ]

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

increased volume. Our Pipeline segment recorded a loss of $9.8 million for the fourth quarter ended March 31, 2007, compared to a profit of $3.9 million in 2006. This change in profitability reflects the negative impact of increased scope, condition changes and difficult weather conditions on a large pipeline project that resulted in $8.0 million of additional costs, being recognized during the quarter without any associated revenue. We are in the process of requesting change orders from our customers to recover all or a portion of these additional costs but did not meet the criteria to recognize this revenue for the fourth quarter ended March 31, 2007.

Consolidated Financial Position

(in thousands)


Year Ended	March 31 2007			March 31 2006			% Change
Current assets	$	229,061		$	161,628		41.7	%
Current liabilities		(148,789	)		(92,096	)	61.6	%
Working capital		80,272			69,532		15.4	%
Plant and equipment		255,963			184,562		38.7	%
Total assets		710,736			568,682		25.0	%
Capital Lease obligations (including current portion)		(9,709	)		(10,952	)	(11.3	%)
Total long-term financial liabilities		(297,957	)		(453,092	)	(34.2	%)

At March 31, 2007, we had net working capital (current assets less current liabilities) of $80.3 million, compared to $69.5 million at March 31, 2006. The increase in working capital resulted from an increase in accounts receivable and unbilled revenue as a result of increased projects in process, partially offset by a reduction of cash due to capital equipment purchases and an increase in borrowings from our secured credit facility.

Plant and equipment, net of depreciation, increased by $71.4 million from March 31, 2006 to March 31, 2007 primarily as a result of the acquisition of several large mining trucks and the buy-out of certain leased equipment using the proceeds of the IPO.

Capital lease obligations, including the current portion, decreased by $1.2 million from March 31, 2006 to March 31, 2007 due to required repayments, the sale of a drill rig and repayment of the associated obligations, partially offset by the addition of new vehicles acquired by means of capital lease.

Total long-term financial liabilities are determined as non-current liabilities, excluding current portion of capital lease obligations and future income taxes. The decrease in 2007 is primarily as a result of the amalgamation and the IPO, as described in “Reorganization and Initial Public Offering”.


[ 28 ][ Annual Report 2007

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

Liquidity and Capital Resources

(in thousands)


Year Ended	March 31 2007			March 31 2006			% Change
Cash provided by (used in) operating activities	$	10,052		$	35,092		$	(5,673	)
Cash used in investing activities		(107,972	)		(23,396	)		(24,215	)
Cash provided by financing activities		63,011			13,184			11,217

Net increase (decrease) in cash and cash equivalents	$	(34,909	)	$	24,880		$	(18,671	)

Operating activities

Operating activities in 2007 resulted in a net increase in cash of $10.1 million, compared to an increase of $35.1 million in 2006 and a decrease of $5.7 million in 2005. The lower cash generated in 2007 compared to 2006 is the result of movements in net non-cash working capital from increased accounts receivable balances and tire purchases including deposits on tire purchases. The higher cash generated in 2006 compared to 2005 reflects improved earnings performance and the increased add back of non-cash items related to unrealized gains or losses on financial instruments and movements in future income taxes.

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 2007, we invested $7.6 million in sustaining capital expenditures (2006 – $7.4 million; 2005 – $7.5 million) and invested $102.4 million in growth capital expenditures (2006 – $21.5 million; 2005 –$17.3 million), for total capital expenditures of $110.0 million (2006 – $28.9 million; 2005 – $24.8 million). The significant increase in 2007 growth capital expenditures compared to the previous two years 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 2007 resulted in a cash inflow of $63.0 million 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 NAEPI. A portion of the proceeds from these issues was used to repay the amount outstanding under our senior secured credit facility at the time. Financing activities during 2005 resulted in a net cash inflow of $11.2 million, which related primarily to net borrowings under our revolving credit facility and repayment of capital lease obligations.

In connection with our IPO on November 28, 2006, which was completed after the transactions and amalgamation described above under the heading “Initial Public Offering and Reorganization,” we received net proceeds of $152.6 million (gross proceeds of $171.2 million, less underwriting discounts and commissions and offering expenses of $18.5 million). We used net proceeds from the offering to purchase certain equipment under operating leases for $44.6 million, to repurchase all of our outstanding 9% senior secured notes due in 2010 for $74.7 million plus accrued interest of $3.0 million, to repay the $27.0 million promissory note issued in respect of the repurchase of the NACG Preferred Corp. Series A preferred shares and to pay the $2.0 million fee to terminate the Advisory Services Agreement with the Sponsors.

Liquidity Requirements

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

Our long-term debt includes US$200 million of 8³/4% senior notes due in 2011. The foreign currency risk relating to both the principal and interest payments on 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. Interest totaling $13.0 million on the 8³/4% senior notes and the swap is payable semi-annually in June and December of each year until the


		Annual Report 2007 ][ 29 ]

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

notes mature on December 1, 2011. The swap agreement is an economic hedge, but has not been designated as a hedge for accounting purposes. There are no principal repayments required on the 8³/4% senior notes until maturity.

On November 28, 2006, we repurchased all of the outstanding 9% senior secured notes due in 2010 with a portion of the net proceeds from our IPO as described above.

One of our major customer contracts allows the customer to require that we provide up to $50 million in letters of credit. As at March 31, 2007, we had provided $25.0 million in letters of credit in connection with this contract. Any increase in the value of the letters of credit required by this customer must be requested by November 1, 2007 for an issue date of January 1, 2008.

We maintain a significant equipment and vehicle fleet comprised of units with various remaining useful lives. 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 growth as new projects are awarded to us. It is important to adequately maintain a 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. In order to maintain a balance of owned and leased equipment, we have financed a portion of our large pieces of heavy construction equipment through operating leases. In addition, we continue to lease our motor vehicle fleet.

Our cash requirements during 2007 increased due to continued growth and additional operating and capital expenditures associated with new projects. Our cash requirements for 2008 include funding operating lease obligations, debt and interest repayment obligations and working capital.

We expect our sustaining capital expenditures to range from $35.0 million to $45.0 million per year over the next two years. We expect our total capital expenditures in 2008 to range from $75.0 million to $85.0 million. It is our belief that working capital 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. On June 7, 2007, our amended and restated revolving credit facility was modified to provide for borrowings of up to $125.0 million under which revolving loans and letters of credit may be issued. Our previous revolving credit facility was subject to borrowing base limitations, under which revolving loans and letters of credit up to a limit of $55.0 million may have been issued. As of March 31, 2007, we had approximately $9.5 million of available borrowings under the revolving credit facility after taking into account $20.5 million of borrowings and $25.0 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, as well as a minimum current ratio.

Consolidated EBITDA 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 to consolidated cash interest expense, and the senior leverage is determined as a


[ 30 ][ Annual Report 2007

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

ratio of senior debt to Consolidated EBITDA. Measured as of the last day of each fiscal quarter on a trailing four-quarter basis, Consolidated EBITDA 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 2 times Consolidated EBITDA. We believe Consolidated EBITDA as defined in the credit facility is an important measure of our liquidity.

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 and as a result, the definition and determination 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 did not measure this amount in the prior year.

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. For 2007, our contract revenue consisted of 6% cost-plus, 28% time-and-materials, 53% unit-price and 13% lump-sum. Our definition of backlog results in the exclusion of cost-plus and time-and-material contracts performed under master service agreements. While contracts exist for a range of services to be provided, the work scope and value are not clearly defined under those contracts. For 2007, the total amount of all cost-plus and time-and-material based revenue was $220.9 million (34% of total revenues).

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

BY SEGMENT


Mining & Site Preparation	$	732.0
Piling		40.0
Pipeline		16.0

Total	$	788.0

BY CONTRACT TYPE


Unit-Price	$	778.0
Lump-Sum		10.0
Time & Material, Cost-Plus		—

Total	$	788.0

A contract with a single customer represented approximately $680 million of the March 31, 2007 backlog. It is expected that approximately $255 million of the backlog will be performed and realized in 2008.

Claims and Unapproved 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

•

Changes in anticipated 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 as a claim. Historical claim recoveries should not be considered indicative of future claim recoveries.

As a result of changed conditions discussed above, we have recognized $18 million in additional contract costs from a number of contracts for the year ended March 31, 2007, with no associated increase in contract value. We are working with our customers to come to resolution on the amounts, if any, to be paid to us in respect to these additional costs.


		Annual Report 2007 ][ 31 ]

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

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, 2007.

PAYMENTS DUE BY FISCAL YEAR

(in millions)


	Total		2008		2009		2010		2011		2012 and After
Senior notes ^(a)	$	230.6	$	- 0	$	- 0	$	- 0	$	-0	$	230.6
Capital leases (including interest)		10.7		3.9		3.1		2.1		1.4		0.2
Operating leases		40.6		13.9		13.3		10.3		3.0		0.1

Total contractual obligations	$	281.9	$	17.8	$	16.4	$	12.4	$	4.4	$	230.9

(a)

We have entered into cross-currency and interest rate swaps, which represent an economic hedge of the 8³/₄% senior notes. At maturity, we will be required to pay $263.0 million in order to retire these senior notes and the swaps. This amount reflects the fixed exchange rate of C$1.315=US$1.00 established as of November 26, 2003, the inception of the swap contracts. At March 31, 2007 the carrying value of the derivative financial instruments was $60.9 million, inclusive of the interest components.

Off-Balance Sheet Arrangements

The Company has no off-balance sheet arrangements in place at this time.

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 8, 2007, 35,292,260 common voting shares were outstanding and 412,400 common non-voting common shares were outstanding compared to 18,207,600 and 412,400, respectively, as at March 31, 2006. We had no outstanding preferred shares at March 31, 2007.

Stock-Based Compensation

Some of our directors, officers, employees and service providers have been granted options to purchase common shares under the Amended and Restated 2004 Share Option Plan. In June and September 2006 we granted 127,760 and 187,760 options, respectively, with an exercise price of $5.00 and $16.75 per share, respectively. In September 2006, we had a valuation performed by an unrelated valuation specialist, which valued our common shares at $16.10 per share. The plan and outstanding balances are disclosed in note 25 to our consolidated financial statements for 2007.

Related-Party Transactions

As described above under the Advisory Services Agreement, we received consulting and advisory services from the Sponsors with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. As compensation for these services an advisory fee of $400,000 for 2007 (2006 – $400,000; 2005 – $400,000) was paid to the Sponsors, as a group. This agreement was terminated upon completion of the IPO. We paid the Sponsors a fee of $2.0 million to terminate the agreement. Pursuant to the agreement, the Sponsors also received a fee of $854,000, equal to 0.5% of our aggregate gross proceeds from the IPO.

Pursuant to several office lease agreements, in 2007 we paid $572,000 (2006 – $836,000; 2005 – $824,000) to a company owned, indirectly and in part, by one of our directors. Effective November 28, 2006, the director resigned from the board.

Impairment of Goodwill

In accordance with Canadian Institute of Chartered Accountants’ Handbook Section 3062, “Goodwill and Other Intangible Assets”, we review our goodwill for impairment annually or whenever events or changes in circumstances suggest that the carrying amount may not be recoverable. We are required to test our goodwill for impairment at the reporting unit level and we have determined that we have three reporting units. The test for goodwill impairment is a two-step process:

•

Step 1 – We compare the carrying amount of each reporting unit to its fair value. If the carrying amount of a reporting unit exceeds its fair value, we have to perform the second step of the process. If not, no further work is required.


[ 32 ][ Annual Report 2007

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

•

Step 2 – We compare the implied fair value of each reporting unit’s goodwill to its carrying amount. If the carrying amount of a reporting unit’s goodwill exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess.

We completed Step 1 of this test during the quarter ended December 31, 2006 and were not required to record an impairment loss on goodwill. We conduct our annual assessment of goodwill in December of each year.

Controls and Procedures

Evaluation of disclosure controls and procedures

Under the supervision and with the participation of management, including our President and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures as of March 31, 2007, as defined in Canada by Multilateral Instrument 52-109, “Certification of Disclosure in Issuer’s Annual and Interim Fillings” and in the United States by Rule 13(a)-15(e) under the Securities Exchange Act of 1934, as amended, as of March 31, 2007. Based on this evaluation, and taking into account the compensating review procedures described below, our President and Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective.

Internal Control over Financial Reporting (“ICFR”)

Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and of the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Management is responsible for establishing and maintaining adequate internal controls appropriate to the nature and size of the business to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting for the Company.

In the course of preparing our 2007 financial statements, we identified a number of material weaknesses in our ICFR. A control deficiency is a material weakness in ICFR if the deficiency, or a combination of control deficiencies, is such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim consolidated financial statements will not be prevented or detected.

We noted the following material weaknesses in ICFR as at March 31, 2007:

•

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 within project changes subsequent to the end of each reporting period were not effectively implemented. The accounts that could potentially be affected by these deficiencies are revenue, project costs and their related accounts.

•

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. The accounts that could potentially be affected by these deficiencies are future income tax assets, future income tax liabilities and future income tax expense.

•

Accounts payable and procurement – The Company 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 could potentially be affected by these deficiencies are accounts payable, accrued liabilities, project costs, unbilled revenue, equipments costs, general and administrative costs and other expenses.

•

IT General Controls (“ITGCs”) – a number of deficiencies in ITGCs existed, including appropriate controls around spreadsheets and end user computing, controls over access and 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. In anticipation of providing an annual report on ICFR by March 31, 2008, management is currently evaluating the effectiveness of our 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.

Changes in Internal Control over Financial Reporting

We are currently addressing these deficiencies through the implementation of the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 in the United States and Multilateral Instrument 52-109 in Canada. We are in the remediation phase of a procurement project in which we implemented the purchase order functionality in our financial systems and trained our staff in the effective use of purchase orders to track our commitments and to record our expenses in a timely manner. We are implementing and testing a project controls improvement initiative over the claims and unapproved change orders process, as well as the completeness and accuracy of project forecasts. We are also in the final stages of upgrading our enterprise resource management software, which includes addressing the ITGC deficiencies noted above.


		Annual Report 2007 ][ 33 ]

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

We have added to our finance staff, and in particular we now have in-house Canadian GAAP expertise and a working knowledge of U.S. GAAP, which is supplemented by outside expertise. We have created a Corporate Controller position and added a Corporate Accounting Manager and Tax Manager. In addition, we have instituted standardized procedures for financial reporting and review, including the procedures by which general ledger transactions are closed, reviewed and consolidated. The redesign of and implementation of all planned changes to our disclosure controls and procedures are not yet complete. Until the implementation of such corrective measures is complete, we are compensating for the identified weaknesses in ICFR by performing additional review procedures.

Our target is to complete the above changes by March 31, 2008, the date as of which we will be required to provide management’s report on the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002. Because most of the costs of implementing the above changes to internal control over financial reporting have been incurred in anticipation of providing such report or due to required systems upgrades, we have not incurred material costs in connection with implementing corrective actions to correct identified internal control deficiencies. As discussed above, there were changes in our ICFR since March 31, 2006 that have materially affected, or are reasonably likely to affect, our ICFR.

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, 2007, our contracts consisted of 6% cost-plus, 28% time-and-materials, 53% unit-price and 13% 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. We believe our experience allows us to produce materially reliable estimates. However, our projects can be highly complex, and in almost every case, the profit margin estimates for a project will either increase or decrease to some extent from the amount that was originally estimated at the time of the related bid. Because we have many projects of varying levels of complexity and size in process at any given time, these changes in estimates can offset each other without materially impacting our profitability. However, sizable changes in cost estimates, particularly in larger, more complex projects, can have a significant effect on profitability.

Factors that can contribute to changes in estimates of contract cost and profitability include, without limitation:

•

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

•

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

•

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

•

the availability and proximity of materials;

•

unfavorable weather conditions hindering productivity;

•

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

•

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

The foregoing factors, as well as the stage of completion of contracts in process and the mix of contracts at different margins, may cause fluctuations in gross profit between periods, and these fluctuations may be significant.


[ 34 ][ Annual Report 2007

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

Plant and equipment

The most significant estimate in accounting for plant and equipment is the expected useful life of the asset and the expected residual value. Most of our property, plant and equipment have long lives which can exceed 20 years with proper repair work and preventative maintenance. Useful life is measured in operated 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 is tested at the reporting unit level by comparing the reporting unit’s carrying amount to its fair value. The process of determining fair values 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.

Derivative financial instruments

Our derivative financial instruments 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 swap and the CAD/USD foreign exchange spot rate.

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;

•

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

•

cost overruns on announced projects.

Changes in our customers’ perception of oil prices over the long-term could cause our customers to defer, reduce or stop their investment in oil sands 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 believe 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 could have a material adverse impact on our financial condition and results of operations.


		Annual Report 2007 ][ 35 ]

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

Insufficient pipeline, upgrading and refining capacity could cause our customers to delay, reduce or cancel plans to construct new oil sands projects or expand existing projects, which would, in turn, reduce our revenue from those customers.

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

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

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

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

Alberta, and in particular the oil sands area, has had and continues to have a shortage of skilled labor and other qualified personnel. New mining projects in the area will only make it more difficult for us and our customers to find and hire all the employees required to work on these projects. We are continuously exploring innovative ways to hire the people we need, which include project managers, trades people and other skilled employees. We have expanded our efforts to find qualified candidates outside of Canada 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.


[ 36 ][ Annual Report 2007

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

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 65%, 70% and 68% of our total revenue for 2007, 2006 and 2005, 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 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 generally allow the customer to terminate the contract without cause. The loss of or significant reduction in business with one or more of our major customers, whether as a result of completion of a contract, early termination or failure or inability to pay amounts owed to us, could have a material adverse effect on our business and results of operations.

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

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

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

Approximately 66%, 58% and 51% of our revenue for 2007, 2006 and 2005, respectively, was derived from lump-sum and unit-price contracts. See “Critical Accounting Policies and Estimates – Revenue Recognition”. 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.


		Annual Report 2007 ][ 37 ]

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

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 financial reporting obligations arising from our listings on the New York Stock Exchange and the Toronto Stock Exchange. We have had continuing problems providing accurate and timely financial information and reports and have restated NAEPI’s financial statements three times since the beginning of our 2005 fiscal year. In April of 2005, we had to restate NAEPI’s financial statements for the first and second quarters of 2005 to properly account for costs incurred in those quarters. During 2006, we had to restate NAEPI’s financial statements for each period after November 26, 2003 to the quarter ended December 31, 2004 and the quarter ended June 30, 2005 to eliminate the impact of hedge accounting with respect to the derivative financial instruments. We also had to restate NAEPI’s financial statements for the first quarter of 2006 to correct the accounting for various aspects of the refinancing transactions which occurred in May 2005. Each of these restatements resulted in our inability to file NAEPI’s financial statements within the deadlines imposed by covenants in the indentures governing our 8³/₄% senior notes and 9% senior secured notes.

We have identified a number of significant weaknesses (as defined under Canadian auditing standards) in our financial reporting processes and internal controls. See “Significant Weaknesses in Financial Reporting and Internal Controls.” 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.

If, as of the end of our 2008 fiscal year, we are unable to assert that our internal control over financial reporting is effective, or if our auditors are unable to confirm our assessment, investors could lose confidence in our reported financial information and the trading price of our common shares and our business could be adversely affected.

We are in the process of documenting, and plan to test our internal control procedures in order to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act, commencing with our year ending March 31, 2008. The Sarbanes-Oxley Act requires an annual assessment by management of the effectiveness of internal control over financial reporting and an attestation report by independent auditors on the effectiveness of internal control over financial reporting. We cannot be certain that we will be able to comply with all of our reporting obligations and successfully complete the procedures, certification and attestation requirements of Section 404 of the Sarbanes-Oxley Act in a timely manner. During the course of our testing we may identify deficiencies that we may not be able to remedy in time to meet the deadline imposed by the Sarbanes-Oxley Act for compliance with the requirements of Section 404. Effective internal control over financial reporting is important to help produce reliable financial reports and to prevent financial fraud. If, as of the end of fiscal 2008, we are unable to assert that our internal control over financial reporting is effective, or if our independent auditors are unable to attest that our internal control over financial reporting is effective, we could be subject to heightened regulatory scrutiny, investors could lose confidence in our reported financial information and the trading price of our common shares and our ability to maintain confidence in our business could be adversely affected.

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, 2007, we had outstanding $240.3 million of debt, including $9.7 million of capital leases. We also had cross-currency and interest rate swaps with a balance sheet liability of $60.9 million as of March 31, 2007. These swaps are secured equally and ratably with our revolving credit facility. We also had $25.0 million of outstanding, undrawn letters of credit, which reduce the amount of available borrowings under 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;


[ 38 ][ Annual Report 2007

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

•

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

•

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

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

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

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

•

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

•

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

•

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

•

issue equity securities of subsidiaries;

•

make certain investments or acquisitions;

•

create liens on our assets;

•

enter into transactions with affiliates;

•

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

•

transfer or sell assets, including shares of our subsidiaries.

Our revolving credit facility and some of our equipment lease programs also require 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.

Between March 31, 2004 and May 19, 2005, it was necessary to obtain a series of waivers and amend our then-existing credit agreement to avoid or to cure our default of various covenants contained in that credit agreement. We ultimately replaced that credit agreement with a new credit agreement on May 19, 2005, which was amended and restated on July 19, 2006, which we replaced with our current amended and restated credit agreement dated as of June 7, 2007.

Our inability to file NAEPI’s financial statements for the periods ended December 31, 2004, March 31, 2005 and September 30, 2005 with the SEC within the deadlines imposed by the regulators caused us to be out of compliance with the covenants in the indentures governing our 8³/₄% senior notes and our 9% senior secured notes (the latter indenture having been subsequently repaid and terminated on November 28, 2006). In each case, we filed these financial statements before the lack of compliance became an event of default under the indentures.

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

For 2005, we had negative operating cash flow of $5.7 million. 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.


		Annual Report 2007 ][ 39 ]

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

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 effect 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 8³/₄% 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. Between January 1, 2007 and May 31, 2007, the Canadian dollar/U.S. dollar exchange rate varied from a high of 0.9376 Canadian dollars per U.S. dollar to a low of 0.8419 Canadian dollars per U.S. dollar.

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, 2007, we had $25.0 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 are insufficient to satisfy our customers, 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 mining and site preparation project revenues constituted approximately 74% to 75% of our revenues in each of 2007, 2006 and 2005. 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.

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.


[ 40 ][ Annual Report 2007

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

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 underpricing 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 66% of our revenue for 2007 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.

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.

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 non-compliance 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 cleanup, without regard to fault, on specific classes of persons who are considered to be responsible for the release of harmful substances into the environment.


		Annual Report 2007 ][ 41 ]

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

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.

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. In May 2005, we hired a new Chief Executive Officer and promoted our Vice President, Operations to Chief Operating Officer. In January 2005 we hired a new Treasurer, who is now our Vice President, Supply Chain. In June 2006, we hired a new Vice President, Human Resources, Health, Safety and Environment. In September 2006, we hired a new Chief Financial Officer. Our Chief Operating Officer has resigned effective July 31, 2007. 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.


[ 42 ][ Annual Report 2007

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

We will incur significantly higher costs as a result of being a public company.

As a public company, we will incur significantly higher legal, accounting and other expenses than we did as a private company. In addition, the Sarbanes-Oxley Act of 2002, as well as similar or related rules adopted by the Securities and Exchange Commission, Canadian securities regulatory authorities, the New York Stock Exchange and the Toronto Stock Exchange, have imposed substantial requirements on public companies, including requiring changes in corporate governance practices and requirements relating to internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act. We expect these rules and regulations will increase our legal and financial compliance costs and make some activities more time-consuming and costly.

Recently Adopted Canadian Accounting Pronouncements

Conditional asset retirement obligations

In November 2005, the CICA issued Emerging Issues Committee Abstract No. 159, “Conditional Asset Retirement Obligations” (“EIC-159”) to clarify the accounting treatment for a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Under EIC-159, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the obligation can be reasonably estimated. The guidance is effective April 1, 2006, although early adoption is permitted and is to be applied retroactively, with restatement of prior periods. The Company adopted this standard in fiscal 2006 and the adoption did not have a material impact on the Company’s consolidated financial statements.

Stock-based compensation for employees eligible to retire before the vesting date

In July 2006, the CICA Emerging Issues Committee issued Abstract No. 162, “Stock-Based Compensation for Employees Eligible to Retire Before the Vesting Date” (“EIC-162”). EIC-162 requires that the compensation cost attributable to awards granted to employees eligible to retire at the grant date should be recognized on the grant date if the award’s exercisability does not depend on continued service. Additionally, awards granted to employees who will become eligible to retire during the vesting period should be recognized over the period from the grant date to the date the employee becomes eligible to retire. The Company adopted this standard for the interim period ended December 31, 2006 retroactively, with restatement of prior periods for all stock-based compensation awards. The adoption of this standard had no impact on the Company’s consolidated financial statements.

Determining the variability to be considered in applying the VIE standards

In September 2006, the CICA issued Emerging Issues Committee Abstract No. 163, “Determining the Variability to be Considered in Applying AcG-15” (“EIC-163”). This guidance provides additional clarification on how to analyze and consolidate a VIE. EIC-163 concludes that the “by-design” approach should be the method used to assess variability (that is created by risks the entity is designed to create and pass along to its interest holders) when applying the VIE standards. The “by-design” approach focuses on the substance of the risks created over the form of the relationship. The guidance may be applied to all entities (including newly created entities) with which an enterprise first becomes involved and to all entities previously required to be analyzed under the VIE standards when a reconsideration event has occurred and is effective for interim and annual periods beginning on or after January 1, 2007. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

Recent Canadian accounting pronouncements not yet adopted

Financial instruments

In January 2005, the CICA issued Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, Handbook Section 1530, “Comprehensive Income”, and Handbook Section 3865, “Hedges”. The new standards are effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2006, specifically April 1, 2007 for the Company. The new standards will require presentation of a separate statement of comprehensive income under specific circumstances. Foreign exchange gains and losses on the translation of the financial statements of self-sustaining subsidiaries previously recorded in a separate section of shareholder’s equity will be presented in comprehensive income. Derivative financial instruments will be recorded in the balance sheet at fair value and the changes in fair value of derivatives designated as cash flow hedges will be reported in comprehensive income. The Company is currently assessing the impact of the new standards.


		Annual Report 2007 ][ 43 ]

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

on the entity’s financial performance; and (2) the nature and extent of risks arising from the use of financial instruments by the entity during the period and at the balance sheet date, and how the entity manages those risks. The Company is currently assessing the impact of this standard.

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. 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. The Company is currently evaluating the impact of this standard.

In March 2007, the CICA issued Handbook Section 3863, “Financial Instruments – Presentation” to enhance financial statement users’ understanding of the significance of financial instruments to an entity’s financial position, performance and cash flows. 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. The Company is currently evaluating the impact of this standard.

Equity

On April 1, 2007, the Company will adopt 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 CICA Handbook Section 1530 and recommend that an enterprise should present separately the following components of equity: retained earnings, accumulated other comprehensive income, and the total for retained earnings and accumulated other comprehensive income, contributed surplus, share capital and reserves. The Company is currently evaluating the impact of this standard.

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 revised standard is effective for fiscal years beginning on or after January 1, 2007, specifically April 1, 2007 for the Company, and is not expected to have a material impact on the Company’s consolidated financial statements.

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. The Company is currently evaluating the impact of this standard.

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.

U.S. Generally Accepted Accounting Principles

Our consolidated financial statements have been prepared in accordance with Canadian GAAP, which differs in certain material respects from U.S. GAAP. The nature and effect of these differences are set out in Note 27 to our consolidated financial statements.


[ 44 ][ Annual Report 2007

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

United States accounting pronouncements recently adopted

Statement of Financial Accounting Standards No. 123R, “Share-Based Payment” (“SFAS 123R”) requires companies to recognize in the income statement, the grant-date fair value of stock options and other equity-based compensation issued to employees. The fair value of liability-classified awards is remeasured subsequently at each reporting date through the settlement date, while the fair value of equity-classified awards is not subsequently remeasured. The revised standard is effective for non-public companies beginning with the first annual reporting period that begins after December 15, 2005, which in our case is the period beginning April 1, 2006. We have used the fair value method under Statement 123 since its inception. We adopted SFAS 123R prospectively since we use the minimum value method for purposes of complying with Statement 123. The adoption of this standard did not have a material impact on our consolidated financial statements.

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections” (“SFAS 154”) which replaces Accounting Principles Board Opinion No. 20 “Accounting Changes” and Statement of Financial Accounting Standards No. 3, “Reporting Accounting Changes in Interim Financial Statements – An Amendment of APB Opinion No. 28”. SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 was effective for the Company for accounting changes and corrections of errors made by the Company in its fiscal year beginning on April 1, 2006. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

In September 2006, the U.S. Securities and Exchange Commission issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. It establishes an approach that requires quantification of financial statements misstatements based on the effects of the misstatements on each of the Company’s financial statements and the related financial statement disclosures. SAB 108 was effective for the Company’s annual financial statements for the fiscal year ending March 31, 2007. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

Recent United States accounting pronouncements not yet adopted

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 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 although early adoption is permitted. The Company is currently reviewing the impact of this statement.

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 is effective for the Company’s 2008 fiscal year. The Company is currently reviewing the impact of this Interpretation.

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 and the Company is currently assessing the impact of this guidance.


		Annual Report 2007 ][ 45 ]

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

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 the Company for fair value measurements and disclosures made by the Company in its fiscal year beginning on April 1, 2008. The Company is currently reviewing the impact of this statement.

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, with earlier adoption permitted. The Company is currently reviewing the impact of this pronouncement.

Quantitative and Qualitative Disclosures Regarding Market Risk

Foreign currency risk

We are subject to currency exchange risk as our 8³/₄% senior notes are denominated in U.S. dollars and all of our revenues and most of our expenses are denominated in Canadian dollars. To manage the foreign currency risk and potential cash flow impact on our $200 million in U.S. dollar-denominated notes, we have entered into currency swap and interest rate swap agreements. These financial instruments consist of three components: a U.S. dollar interest rate swap; a U.S. dollar-Canadian dollar cross-currency basis swap; and a Canadian dollar interest rate swap. The cross currency and interest rate swap agreements can be cancelled at the counterparty’s option at any time after December 1, 2007 if the counterparty pays a cancellation premium. The premium is equal to 4.375% of the US$200 million if exercised between December 1, 2007 and December 1, 2008; 2.1875% if exercised between December 1, 2008 and December 1, 2009; and repurchased at par if cancelled after December 1, 2009.

Interest rate risk

We are exposed to interest rate risk on the revolving credit facility, capital lease obligations and certain operating leases with a variable payment that is tied to prime rates. We do not use derivative financial instruments to reduce our exposure to these risks. The estimated financial impact as a result of fluctuations in interest rates is not significant.

Inflation

Inflation has not had a material impact on our operations as many of our contracts contain a provision for annual price increases. Inflation is not expected to have a material impact on our operations in the foreseeable future provided the rate of inflation remains consistent with recent levels and we are able to continue passing costs increases along to our customers.


[ 46 ][ Annual Report 2007

North American Energy Partners Inc. ]

Management’s Report

The management of North American Energy Partners Inc. is responsible for the preparation of the accompanying consolidated financial statements and related financial information. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles and include amounts based on estimates and judgments. Financial information included elsewhere in this report is consistent with the consolidated financial statements.

Management maintains an appropriate system of accounting and administrative controls to provide reasonable assurance that transactions are appropriately authorized, assets are safeguarded and financial records are properly maintained to provide reliable consolidated financial statements. In addition, programs of proper business conduct and risk management have been implemented to protect the Company’s assets and operations.

The consolidated financial statements have been examined by KPMG LLP, the Company’s external auditors. The external auditors are responsible for examining the consolidated financial statements and expressing their opinion on the fairness of the financial statements in accordance with Canadian generally accepted accounting principles. The auditors’ report outlines the scope of their audit examination and states their opinion.

The Board of Directors, through its Audit Committee, is responsible for ensuring that management fulfills its financial reporting responsibilities. The Audit Committee reviews the consolidated financial statements and meets regularly with management and KPMG LLP to discuss internal controls, accounting and auditing and financial matters. The Audit Committee reports its findings and recommends approval of the annual consolidated financial statements to the Board of Directors.




Rodney J. Ruston				Douglas A. Wilkes
Chief Executive Officer				Chief Financial Officer

June 19, 2007


		Annual Report 2007 ][ 47 ]

North American Energy Partners Inc. ]

REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors

We have audited the consolidated balance sheets of North American Energy Partners Inc. (formerly NACG Holdings Inc.) as at March 31, 2007 and 2006 and the consolidated statements of operations and deficit and cash flows for each of the years in the three-year period ended March 31, 2007. 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. We also conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance 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 audit opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of North American Energy Partners Inc. (formerly NACG Holdings Inc.) as of March 31, 2007 and 2006 and the results of its operations and its cash flows for each of the years in the three-year period ended March 31, 2007 in accordance with Canadian generally accepted accounting principles.

As discussed in Note 3(r) to the consolidated financial statements, the Company adopted new accounting pronouncements related to the accounting for stock-based compensation for employees eligible to retire before the vesting date and determining the variability to be considered in applying the variable interest entities standards in 2007.

Canadian generally accepted accounting principles vary in certain significant respects from accounting principles generally accepted in the United States of America. Information relating to the nature and effect of such differences is presented in note 27 to the consolidated financial statements.

Chartered Accountants

Edmonton, Canada

June 19, 2007


[ 48 ][ Annual Report 2007

North American Energy Partners Inc. ]

CONSOLIDATED BALANCE SHEETS

As at March 31

(in thousands of Canadian dollars)


	2007			2006
Assets
Current assets:
Cash and cash equivalents	$	7,895		$	42,804
Accounts receivable (note 5)		93,220			67,235
Unbilled revenue (note 6)		82,833			43,494
Inventory		156			57
Asset held for sale (note 8)		8,268			—
Prepaid expenses and deposits (note 7)		11,932			1,796
Other assets		10,164			1,004
Future income taxes (note 16)		14,593			5,238

		229,061			161,628
Future income taxes (note 16)		14,364			5,383
Plant and equipment (note 9)		255,963			184,562
Goodwill (note 4)		199,392			198,549
Intangible assets, net of accumulated amortization of $17,608 (March 31, 2006 - $ 17,026) (note 10)		600			772
Deferred financing costs, net of accumulated amortization of $7,595 (March 31, 2006 - $ 6,004) (notes 2 and 11)		11,356			17,788

	$	710,736		$	568,682
Liabilities and Shareholders’ Equity
Current liabilities:
Revolving credit facility (notes 12 and 28)	$	20,500		$	—
Accounts payable		94,548			54,085
Accrued liabilities (note 13)		23,393			24,603
Billings in excess of costs incurred and estimated earnings on uncompleted contracts (note 6)		2,999			5,124
Current portion of capital lease obligations (note 14)		3,195			3,046
Future income taxes (note 16)		4,154			5,238

		148,789			92,096
Capital lease obligations (note 14)		6,514			7,906
Senior notes (note 15)		230,580			304,007
Derivative financial instruments (note 22(b))		60,863			63,611
Redeemable preferred shares (notes 2 and 17(a))		—			77,568
Future income taxes (note 16)		19,712			5,383

		466,458			550,571

Shareholders’ equity:
Common shares (authorized – unlimited number of voting and non-voting common shares; issued and outstanding – March 31, 2007 – 35,192,260 voting common shares and 412,400 non-voting common shares (March 31, 2006 – 18,207,600 voting common shares and 412,400 non-voting common shares)) (notes 2 and 17(b))		296,198			93,100
Contributed surplus (notes 17(c) and 25)		3,606			1,557
Deficit		(55,526	)		(76,546	)

		244,278			18,111

Commitments (note 23)
United States generally accepted accounting principles (note 27)
Subsequent events (note 28)

	$	710,736		$	568,682

See accompanying notes to consolidated financial statements


		Annual Report 2007 ][ 49 ]

North American Energy Partners Inc. ]

CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT

For the years ended March 31

(in thousands of Canadian dollars except per share amounts)


	2007			2006			2005
Revenue	$	629,446		$	492,237		$	357,323
Project costs		363,930			308,949			240,919
Equipment costs		122,306			64,832			52,831
Equipment operating lease expense		19,740			16,405			6,645
Depreciation (note 8)		31,034			21,725			20,762

Gross profit		92,436			80,326			36,166
General and administrative costs (note 21)		39,769			30,903			22,873
Loss (gain) on disposal of plant and equipment		959			(733	)		494
Amortization of intangible assets		582			730			3,368

Operating income before the undernoted		51,126			49,426			9,431
Interest expense (note 18)		37,249			68,776			31,141
Foreign exchange gain (note 22(b))		(5,044	)		(13,953	)		(19,815	)
Realized and unrealized (gain) loss on derivative financial instruments (note 22(b))		(196	)		14,689			43,113
Gain on repurchase of NACG Preferred Corp. Series A preferred shares (notes 2 and 17(a))		(9,400	)		—			—
Loss on extinguishment of debt (notes 2, 11 and 15)		10,935			2,095			—
Other income		(904	)		(977	)		(421	)

Income (loss) before income taxes		18,486			(21,204	)		(44,587	)
Income taxes: (note 16)
Current income taxes		(2,975	)		737			2,711
Future income taxes		382			—			(4,975	)

Net income (loss)		21,079			(21,941	)		(42,323	)
Deficit, beginning of year		(76,546	)		(54,605	)		(12,282	)
Premium on repurchase of common shares (note 17(b))		(59	)		—			—

Deficit, end of year	$	(55,526	)	$	(76,546	)	$	(54,605	)

Net income (loss) per share – basic (note 17(d))	$	0.87		$	(1.18	)	$	(2.28	)

Net income (loss) per share – diluted (note 17(d))	$	0.83		$	(1.18	)	$	(2.28	)

See accompanying notes to consolidated financial statements


[ 50 ][ Annual Report 2007

North American Energy Partners Inc. ]

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended March 31

(in thousands of Canadian dollars)


	2007			2006			2005
Cash provided by (used in):
Operating activities:
Net income (loss) for the period	$	21,079		$	(21,941	)	$	(42,323	)
Items not affecting cash:
Depreciation		31,034			21,725			20,762
Write-down of other assets to replacement cost (note 3(g))		695			—			—
Amortization of intangible assets		582			730			3,368
Amortization of deferred financing costs		3,436			3,338			2,554
Loss (gain) on disposal of plant and equipment		959			(733	)		494
Unrealized foreign exchange gain on senior notes (note 22(b))		(5,017	)		(14,258	)		(20,340	)
Unrealized (gain) loss on derivative financial instruments (note 22(b))		(2,748	)		11,888			40,457
Stock-based compensation expense (note 25)		2,101			923			497
Gain on repurchase of NACG Preferred Corp. Series A preferred shares (notes 2 and 17(a))		(8,000	)		—			—
Loss on extinguishment of debt (notes 2, 11 and 15)		10,680			2,095			—
Change in redemption value and accretion of redeemable preferred shares		3,114			34,722			—
Future income taxes		382			—			(4,975	)
Net changes in non-cash working capital (note 19(b))		(48,245	)		(3,397	)		(6,167	)

		10,052			35,092			(5,673	)

Investing activities:
Acquisition, net of cash acquired (note 4)		(1,517	)		—			—
Purchase of plant and equipment		(110,019	)		(28,852	)		(24,839	)
Proceeds on disposal of plant and equipment		3,564			5,456			624

		(107,972	)		(23,396	)		(24,215	)

Financing activities:
Increase in revolving credit facility		20,500			—			—
Issue of 9% senior secured notes (note 15)		—			76,345			—
Repayment of 9% senior secured notes (note 15)		(74,748	)		—			—
Repayment of senior secured credit facility (note 11)		—			(61,257	)		(7,250	)
Issue of Series B preferred shares (note 17(a))		—			8,376			—
Repurchase of Series B preferred shares (notes 2 and 17(a))		—			(851	)		—
Repurchase of NAEPI Series A preferred shares (notes 2 and 17(a))		(1,000	)		—			—
Repurchase of NACG Preferred Corp. Series A preferred shares (notes 2 and 17(a))		(27,000	)		—			—
Financing costs (note 11)		(1,346	)		(7,546	)		(642	)
Repayment of capital lease obligations		(6,033	)		(2,183	)		(1,198	)
Increase in senior secured credit facility		—			—			20,007
Issue of common shares (note 2 and 17(b))		171,304			300			300
Share issue costs (notes 2 and 17(b))		(18,582	)		—			—
Repurchase of common shares for cancellation (note 17(b))		(84	)		—			—

		63,011			13,184			11,217

(Decrease) increase in cash and cash equivalents		(34,909	)		24,880			(18,671	)
Cash and cash equivalents, beginning of year		42,804			17,924			36,595

Cash and cash equivalents, end of year	$	7,895		$	42,804		$	17,924

See accompanying notes to consolidated financial statements


		Annual Report 2007 ][ 51 ]

North American Energy Partners Inc. ]

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1.	Nature of operations

NACG Holdings Inc. (the “Company”) 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 Norama 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 contract mining, 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.	Reorganization and initial public offering

On November 28, 2006, prior to the amalgamation referred to in note 1, the Company 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 17(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, the Company repurchased the NAEPI Series A preferred shares for their redemption value of $1,000. The Company 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 the Company 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, 0.5% of the aggregate gross proceeds to the Company from the offering, 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 Holdings Inc. 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 17(a)). Upon exchange, the carrying value in the amount of $44,682 for the NAEPI Series B preferred shares on the exercise date 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 17(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;

•

to repay the promissory note in respect of the repurchase of the NACG Preferred Corp. Series A preferred shares for $27,000 as described above;

•

to purchase certain equipment leased under operating leases for $44,623;

•

to cancel the consulting and advisory services agreement with the Sponsors for $2,000; and

•

for general corporate purposes.

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 27.

These consolidated financial statements include the accounts of the Company, its wholly-owned subsidiary, North American Construction Group Inc. (“NACGI”), the Company’s joint venture, Noramac Ventures Inc. and the following 100% owned subsidiaries of NACGI:

•

North American Caisson Ltd.

•

North American Pipeline Inc.

•

North American Construction Ltd.

•

North American Road Inc.

•

North American Engineering Ltd.

•

North American Services Inc.

•

North American Enterprises Ltd.

•

North American Site Development Ltd.

•

North American Industries Inc.

•

North American Site Services Inc.

•

North American Mining Inc.

•

Griffiths Pile Driving Inc.

•

North American Maintenance Ltd.

•

Midwest Foundation Technologies Ltd.


[ 52 ] [ Annual Report 2007

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

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 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 derivative 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.

c)	Revenue recognition

The Company performs its projects under the following types of contracts: time-and-materials; cost-plus; unit-price; and lump sum. For time-and-materials and cost-plus contracts, revenue is recognized as costs are incurred. Revenue on unit-price and lump sum contracts is recognized using the percentage-of-completion method, measured by the ratio of costs incurred to date to estimated total costs. Excluded from costs incurred to date, particularly in the early stages of the contract, are the costs of items that do not relate to performance of contracted work.

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 income that are recognized in the period in which such adjustments are determined. Profit incentives are included in revenue when their realization is reasonably assured.

Once a project is underway, 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 it is probable that the change order will result in a bona fide addition to contract value and can be reliably estimated.

Revenues related to 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 (1) a bona fide addition to contract value and (2) revenues can be reliably estimated. These 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.

Claims revenue recognized was $14.5 million for the year ended March 31, 2007 (2006 - $12.9 million; 2005 - $nil), $8.4 million of which is included in unbilled revenue and remains uncollected at the end of the year (2005 - $nil). Of the amount included in unbilled revenue at March 31, 2007, $6.6 million was collected subsequent to year end.

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 cost (on a first-in, first-out basis) and replacement cost, and consists primarily of job 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. Included in equipment costs for the year ended March 31, 2007 is a $695 write-down of other assets to their replacement cost at March 31, 2007.

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


		Annual Report 2007 ][ 53 ]

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

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 service. 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 bases 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	10-20%
Licensed motor vehicles	Declining balance	30%
Office and computer equipment	Straight-line	25%
Buildings	Straight-line	10%
Leasehold improvements	Straight-line	Over shorter of estimated useful life and lease term
Assets under construction	N/A	N/A

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 December 31, 2006 and December 31, 2005 and determined that there was no impairment in carrying value. The Company conducts its annual impairment test of goodwill on December 31 of each year.

j)	Intangible assets

Intangible assets include: customer contracts in progress 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; 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; and employee arrangements, which are being amortized on a straight-line basis over the three-year term of the arrangements.

k)	Deferred financing costs

Costs relating to the issue of the senior notes and the revolving credit facility have been deferred and are being amortized on a straight-line basis over the term of the related debt. Deferred financing costs related to debt that has been extinguished are written-off in the period of extinguishment.

l)	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 the 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; 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.

m)	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.

n)	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 swap agreements and interest rate swap agreements. 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.


[ 54 ][ Annual Report 2007

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

A derivative financial instrument must be designated and effective, at inception and on at least a quarterly basis, to be accounted for as a hedge. For cash flow hedges, effectiveness is achieved if the changes in the cash flows of the derivative financial instrument substantially offset the changes in the cash flows of the related hedged item and if the timing of the cash flows is similar. Effectiveness for fair value hedges is achieved if changes in the fair value of the derivative financial instrument substantially offset changes in the fair value of the hedged item attributable to the risk being hedged. In the event that a derivative financial instrument does not meet the designation or effectiveness criteria, the derivative financial instrument is accounted for at fair value and realized and unrealized gains and losses on the derivative are recognized in the Consolidated Statement of Operations and Deficit in accordance with the Canadian Institute of Chartered Accountants (“CICA”) Emerging Issues Committee Abstract No. 128, “Accounting for Trading, Speculative or Non-Hedging Derivative Financial Instruments” (“EIC-128”). If a derivative financial instrument that previously qualified for hedge accounting no longer qualifies or is settled or de-designated, the fair value on that date is deferred and recognized when the corresponding hedged transaction is recognized in earnings. Premiums paid or received with respect to derivatives that are hedges are deferred and amortized to income over the term of the hedge.

o)	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. 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.

p)	Stock–based compensation plan

The Company accounts for all stock-based compensation payments 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 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.

q)	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 17(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 that outstanding in-the-money stock options were exercised and that 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.

r)	Recently adopted Canadian accounting pronouncements

i.	Consolidation of variable interest entities

Effective January 1, 2005, the Company prospectively adopted CICA Accounting Guideline 15, “Consolidation of Variable Interest Entities” (“AcG-15”). Variable interest entities (“VIEs”) are entities that have insufficient equity at risk to finance their operations without additional subordinated financial support and/or entities whose equity investors lack one or more of the specified essential characteristics of a controlling financial interest. AcG-15 provides specific guidance for determining when an entity is a variable interest entity (“VIE”) and who, if anyone, should consolidate the VIE. The Company has determined the joint venture in which it has an investment (note 19(c)) qualifies as a VIE and began consolidating this VIE effective January 1, 2005.

ii.

Arrangements containing a lease

Effective January 1, 2005, the Company adopted the CICA Emerging Issues Committee Abstract No. 150, “Determining Whether an Arrangement Contains a Lease” (EIC-150”). EIC-150 addresses a situation where an entity enters into an arrangement, comprising a transaction that does not take the legal form of a lease but conveys a right to use a tangible asset in return for a payment or series of payments. The implementation of this standard did not have a material impact on the Company’s consolidated financial statements.

iii.

Vendor rebates

In April 2005, the Company adopted the CICA Emerging Issues Committee Abstract No. 144, “Accounting by a Customer (Including a Reseller) for Certain Consideration Received from a Vendor” (“EIC-144”). EIC-144 requires companies to recognize the benefit of non-discretionary rebates for achieving specified cumulative purchasing levels as a reduction of the cost of purchases over the relevant period, provided the rebate is probable and reasonably estimable. Otherwise, the rebates would be recognized as purchasing milestones are achieved. The implementation of this new standard did not have a material impact on the Company’s consolidated financial statements.

iv.

Non-monetary transactions

Effective January 1, 2006, the Company adopted the requirements of CICA Handbook Section 3831, “Non-monetary Transactions”. The new standard requires that an asset exchanged or transferred in a non-monetary transaction must be measured at its fair value except when: the transaction lacks commercial substance; the transaction is an exchange of production or property held for sale in the ordinary course of business for production or property to be sold in the same line of business to facilitate sales to customers other than the parties to the exchange; neither the fair value of the assets or services received nor the fair value of the assets or services


		Annual Report 2007 ][ 55 ]

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

given up is reliably measurable; or the transaction is a non-monetary, non-reciprocal transfer to owners that represents a spin-off or other form of restructuring or liquidation. In these cases, the transaction must be measured at carrying value. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

v.	Implicit variable interests under AcG-15

Effective January 1, 2006, the Company adopted the CICA Emerging Issues Committee Abstract No. 157, “Implicit Variable Interests Under AcG-15” (“EIC-157”). EIC-157 requires a company to assess whether it has an implicit variable interest in a VIE or potential VIE when specific conditions exist. An implicit variable interest acts the same as an explicit variable interest except it involves the absorbing and/or receiving of variability indirectly from the entity (rather than directly). The identification of an implicit variable interest is a matter of judgment that depends on the relevant facts and circumstances. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

vi.

Conditional asset retirement obligations

In November 2005, the CICA issued Emerging Issues Committee Abstract No. 159, “Conditional Asset Retirement Obligations” (“EIC-159”) to clarify the accounting treatment for a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Under EIC-159, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the obligation can be reasonably estimated. The guidance is effective April 1, 2006 although early adoption is permitted and is to be applied retroactively, with restatement of prior periods. The Company adopted this standard in fiscal 2006 and the adoption did not have a material impact on the Company’s consolidated financial statements.

vii.

Stock-based compensation for employees eligible to retire before the vesting date

In July 2006, the CICA Emerging Issues Committee issued Abstract No. 162, “Stock-Based Compensation for Employees Eligible to Retire Before the Vesting Date” (“EIC-162”). EIC-162 requires that the compensation cost attributable to awards granted to employees eligible to retire at the grant date should be recognized on the grant date if the award’s exercisability does not depend on continued service. Additionally, awards granted to employees who will become eligible to retire during the vesting period should be recognized over the period from the grant date to the date the employee becomes eligible to retire. The Company adopted this standard for the interim period ended December 31, 2006 retroactively, with restatement of prior periods for all stock-based compensation awards. The adoption of this standard had no impact on the Company’s consolidated financial statements.

viii.

Determining the variability to be considered in applying the VIE standards

In September 2006, the CICA issued Emerging Issues Committee Abstract No. 163, “Determining the Variability to be Considered in Applying AcG-15” (“EIC-163”). This guidance provides additional clarification on how to analyze and consolidate a VIE. EIC-163 concludes that the “by-design” approach should be the method used to assess variability (that is created by risks the entity is designed to create and pass along to its interest holders) when applying the VIE standards. The “by-design” approach focuses on the substance of the risks created over the form of the relationship. The guidance may be applied to all entities (including newly created entities) with which an enterprise first becomes involved and to all entities previously required to be analyzed under the VIE standards when a reconsideration event has occurred and is effective for interim and annual periods beginning on or after January 1, 2007. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

s)	Recent Canadian accounting pronouncements not yet adopted

i.	Financial instruments

In January 2005, the CICA issued Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, Handbook Section 1530, “Comprehensive Income”, and Handbook Section 3865, “Hedges”. The new standards are effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2006, specifically April 1, 2007 for the Company. The new standards will require presentation of a separate statement of comprehensive income under specific circumstances. Foreign exchange gains and losses on the translation of the financial statements of self-sustaining subsidiaries previously recorded in a separate section of shareholder’s equity will be presented in comprehensive income. Derivative financial instruments will be recorded in the balance sheet at fair value and the changes in fair value of derivatives designated as cash flow hedges will be reported in comprehensive income. The Company is currently assessing the impact of the new standards.

Effective April 1, 2007, the Company will also be required to adopt CICA Handbook Section 3861, “Financial Instruments –Disclosure and Presentation” (“CICA 3861”), which requires entities to provide disclosures in their financial statements that enable users to evaluate: (1) the significance of financial instruments on the entity’s financial performance; and (2) the nature and extent of risks arising from the use of financial instruments by the entity during the period and at the balance sheet date, and how the entity manages those risks. The Company is currently assessing the impact of this standard.


[ 56 ][ Annual Report 2007

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

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. The Company is currently evaluating the impact of this standard.

ii.

Equity

On April 1, 2007, the Company will adopt 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 CICA Handbook Section 1530 and recommend that an enterprise should present separately the following components of equity: retained earnings, accumulated other comprehensive income, and the total for retained earnings and accumulated other comprehensive income, contributed surplus, share capital and reserves. The Company is currently evaluating the impact of this standard.

iii.

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 revised standard is effective for fiscal years beginning on or after January 1, 2007, specifically April 1, 2007 for the Company, and is not expected to have a material impact on the Company’s consolidated financial statements.

iv.

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. The Company is currently evaluating the impact of this standard.

v.	Inventories

4.	Acquisition

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 totalling $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 final purchase price allocation is as follows:


Net assets acquired at fair values:
Working capital (including cash of $129)	$	170
Plant and equipment		554
Intangible assets
Customer relationships		210
Non-competition agreement		200
Goodwill (assigned to the Piling segment)		843
Future income tax liability		(194	)
Capital lease obligations		(137	)

	$	1,646

5.	Accounts receivable


	March 31 2007			March 31 2006
Accounts receivable – trade	$	69,320		$	55,666
Accounts receivable – holdbacks		19,496			10,748
Income and other taxes receivable		3,034			—
Accounts receivable – other		1,458			891
Allowance for doubtful accounts		(88	)		(70	)

	$	93,220		$	67,235

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 2007			March 31 2006
Costs incurred and estimated earnings on uncompleted contracts	$	742,186		$	610,006
Less: billings to date		(662,352	)		(571,636	)

	$	79,834		$	38,370

Costs incurred and estimated earnings net of billings on uncompleted contracts is presented in the consolidated balance sheets under the following captions:


	March 31 2007			March 31 2006
Unbilled revenue	$	82,833		$	43,494
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		(2,999	)		(5,124	)

	$	79,834		$	38,370


		Annual Report 2007 ][ 57 ]

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

7.	Prepaid expenses and deposits


	March 31 2007		March 31 2006
Prepaid insurance and property taxes	$	916	$	345
Prepaid lease payments		3,934		—
Deposits for tires		7,082		1,451

	$	11,932	$	1,796

8.	Asset held for sale

Included in depreciation expense for the year ended March 31, 2007 is an impairment charge of $3,582 (2006 - $nil; 2005 - $nil) relating to a decision to dispose of a heavy construction asset in the Mining & Site Preparation segment. The impairment charge is the amount by which the carrying value of the asset exceeded its fair value less costs to sell. The asset has been reclassified from plant and equipment to current assets as the sale of the asset is expected to occur in fiscal 2008.

9.	Plant and equipment


March 31, 2007	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	254,107	$	46,609	$	207,498
Major component parts in use		7,884		2,489		5,395
Other equipment		16,001		5,651		10,350
Licensed motor vehicles		23,345		12,121		11,224
Office and computer equipment		4,841		2,249		2,592
Buildings		16,443		716		15,727
Leasehold improvements		2,992		664		2,328
Assets under construction		849		—		849

	$	326,462	$	70,499	$	255,963


March 31, 2006	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	174,042	$	31,347	$	142,695
Major component parts in use		5,088		2,091		2,997
Other equipment		13,074		4,186		8,888
Licensed motor vehicles		18,223		8,410		9,813
Office and computer equipment		3,362		1,493		1,869
Leasehold improvements		2,959		247		2,712
Assets under construction		15,588		—		15,588

	$	232,336	$	47,774	$	184,562

The above amounts include $15,422 (March 31, 2006 – $14,559) of assets under capital lease and $7,302 (March 31, 2006 –$4,479) of related accumulated depreciation. During the year ended March 31, 2007 additions to plant and equipment included $4,653 of assets that were acquired by means of capital leases (2006 - $5,910; 2005 – $5,385). Depreciation of equipment under capital lease of $1,481 (2006 - $2,545; 2005 – $1,659) is included in depreciation expense.


[ 58 ][ Annual Report 2007

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

10.

Intangible assets


March 31, 2007	Cost		Accumulated amortization		Net 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


March 31, 2006	Cost		Accumulated amortization		Net book value
Customer contracts in progress and related relationships	$	15,323	$	15,323	$	—
Other intangible assets		2,475		1,703		772

	$	17,798	$	17,026	$	772

Amortization of intangible assets of $582 was recorded for the year ended March 31, 2007 (2006 - $730; 2005 - $3,368).

The estimated amortization expense for the next five years is as follows:


For the year ending March 31,
2008	$	156
2009		134
2010		78
2011		49
2012 and thereafter		183

	$	600

11.

Deferred financing costs

For the year ended March 31, 2007, fees of $275 were paid to the holders of the 8³/4% senior notes in connection with an amendment of the indenture governing the 8³/4% senior notes (note 15). 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 will be amortized on a straight-line basis over the remaining term of the

8³/4%

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 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.

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 15) 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 (note 15) and the NAEPI Series B preferred shares (note 17(a)). In connection with the repayment of the senior secured credit facility on May 19, 2005, the Company wrote off deferred financing costs of $1,774 during the year ended March 31, 2006.

Amortization of deferred financing costs of $3,436 was recorded for the year ended March 31, 2007 (2006 - $3,338; 2005 - $2,554).

12.

Revolving credit facility

On May 19, 2005, NAEPI entered into a revolving credit facility with a syndicate of lenders. In connection with the revolving credit facility, NAEPI was required to amend its existing swap agreements to increase the effective rate of interest on its 8³/4% senior notes from 9.765% to 9.889% (note 22(c)) and issue to one of the counterparties to the swap agreements $1.0 million of NAEPI Series A redeemable preferred shares (note 17(a)).

On July 19, 2006, the Company amended and restated its credit agreement to provide for borrowings of up to $55.0 million (previously $40.0 million), subject to borrowing base limitations, under which revolving loans and letters of credit may be issued (previously up to a limit of $30.0 million). Prime rate revolving loans under the amended and restated agreement bear interest at the Canadian prime rate plus 2.0% per annum and swing line revolving loans bear interest at the Canadian prime rate plus 1.5% per annum. Canadian bankers’ acceptances have stamping fees equal to 3.0% per annum and letters of credit are subject to a fee of 3.0% per annum.

Advances under the July 19, 2006 amended and restated agreement are margined with a borrowing base calculation defined as the aggregate of 60.0% of the net book value of the Company’s plant and equipment, 75.0% of eligible accounts receivable and unpledged cash in excess of $15.0 million. The sum of all borrowings (including issued letters of credit) and the fair value of the Company’s liability under existing swap agreements must not exceed the borrowing base. The amended and restated credit facility is secured by a first priority lien on substantially all of the Company’s existing and after-acquired property.


		Annual Report 2007 ][ 59 ]

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

The facility contains certain restrictive covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments (including acquisitions), paying dividends or redeeming shares of capital stock. The Company is also required to meet certain financial covenants. Other terms of the agreement, including the expiry date, did not change. The expiry date of the amended and restated revolving credit facility is March 1, 2010.

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. As of March 31, 2006, the Company had issued $18.0 million in letters of credit to support bonding requirements and performance guarantees associated with customer contracts and operating leases. The Company’s borrowing availability under the facility was $9.5 million at March 31, 2007 (2006 – $9.3 million).

The Company entered into an amended and restated credit agreement on June 7, 2007 (note 28).

13.

Accrued liabilities


	March 31 2007		March 31 2006
Accrued interest payable	$	8,669	$	10,878
Payroll liabilities		7,484		7,423
Liabilities related to equipment leases		7,039		5,061
Income and other taxes payable		201		1,241

	$	23,393	$	24,603

14.

Capital lease obligations

The Company leases a portion of its licensed motor vehicles for which the minimum lease payments due in each of the next five fiscal years are as follows:


2008	$	3,795
2009		3,133
2010		2,121
2011		1,395
2012		242

		10,686
Less: amount representing interest – weighted average rate of 9.14%		977

Present value of minimum lease payments		9,709
Less: current portion		3,195

	$	6,514

15.

Senior notes


	March 31 2007		March 31 2006
8³/4% senior unsecured notes due 2011	$	230,580	$	233,420
9% senior secured notes due 2010		—		70,587

	$	230,580	$	304,007

The 8³/4% 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 8³/4% 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 8³/4% 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 8³/4% 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.

On December 21, 2006, the indenture governing the 8³/4% senior notes was amended to remove the requirement to provide a reconciliation from Canadian GAAP to United States GAAP in the Company’s interim consolidated financial statements.

The 9% senior secured notes were issued 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.


[ 60 ][ Annual Report 2007

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

16.

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,	2007			2006			2005
Income (loss) before income taxes	$	18,486		$	(21,204	)	$	(44,587	)
Statutory tax rate		32.12	%		33.62	%		33.62	%

Expected provision (recovery) at statutory tax rate	$	5,938		$	(7,129	)	$	(14,990	)
Increase (decrease) related to:
Change in future income tax liability, resulting from enacted change in future statutory income tax rates		(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	)		12,189
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			871
Other		392			(427	)		(334	)

Income tax provision (recovery)	$	(2,593	)	$	737		$	(2,264	)


Classified as:

Year ended March 31,	2007			2006			2005
Current income taxes	$	(2,975	)	$	737		$	2,711
Future income taxes		382			—			(4,975	)

	$	(2,593	)	$	737		$	(2,264	)


		Annual Report 2007 ][ 61 ]

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

The income tax effects of temporary differences that give rise to future income tax assets and liabilities are as follows:


	March 31 2007		March 31 2006
Future income tax assets:
Non-capital losses carried forward	$	23,875	$	22,312
Deferred share issue costs		4,547		—
Deferred premium on senior notes		1,614		—
Derivative financial instruments		4,787		6,843
Unrealized foreign exchange loss on senior notes		1,730		2,299
Billings in excess of costs on uncompleted contracts		963		1,723
Capital lease obligations		1,713		1,631

Total future income tax assets		39,229		34,808
Less valuation allowance		—		(5,858	)

Net future income tax assets		39,229		28,950

Future income tax liabilities:
Unbilled revenue and uncertified revenue included in accounts receivable		3,751		1,970
Asset held for sale		1,878		—
Accounts receivable – holdbacks		6,262		3,613
Plant and equipment		20,897		20,263
Deferred financing costs		1,176		1,038
Intangible assets		174		130
Unrealized foreign exchange gain on senior notes		—		1,936

Total future income tax liabilities		34,138		28,950

Net future income taxes	$	5,091	$	—

Classified as:


	March 31 2007			March 31 2006
Current asset	$	14,593		$	5,238
Long-term asset		14,364			5,383
Current liability		(4,154	)		(5,238	)
Long-term liability		(19,712	)		(5,383	)

	$	5,091		$	—

Future income tax expense for the year ended March 31, 2007 includes a recovery of $5,858 resulting from the elimination of the valuation allowance. Management considers the scheduled reversals of future income tax liabilities, the character of income tax assets and available tax planning strategies of the Company and its subsidiaries when evaluating the expected realization of future income tax assets. Based on management’s estimate of the expected realization of future income tax assets during the current period, the Company eliminated the valuation allowance recorded against future income tax assets to reflect that it is more likely than not that the future income tax assets will be realized.

At March 31, 2007, the Company has non-capital losses for income tax purposes of approximately $75,087 which expire as follows:


2015	$	45,888
2026		9,000
2027		20,199

17.

Shares

a)	Redeemable preferred shares


	March 31 2007		March 31 2006
NACG Preferred Corp. Series A preferred shares (i)	$	—	$	35,000
NAEPI Series A preferred shares (ii)		—		375
NAEPI Series B preferred shares (iii)		—		42,193

	$	—	$	77,568

i.	NACG Preferred Corp. preferred shares

Issued and outstanding


	Number of Shares		Amount
Issued and outstanding at March 31, 2004, 2005 and 2006	35,000		$	35,000
Repurchased and cancelled	(35,000	)		(35,000	)

Issued and outstanding at March 31, 2007	—		$	—

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. The redemption price was $1,000.00 per share plus all accrued and unpaid dividends. In the event of a change in control, each holder of NACG Preferred Corp. Series A preferred shares had the right to require the Company to redeem all or any part of such holder’s shares.

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 (note 2).


[ 62 ][ Annual Report 2007

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

ii.

NAEPI Series A preferred shares

Issued and outstanding


	Number of Shares		Amount
Issued and outstanding at March 31, 2004 and 2005	—			—
Issued	1,000			321
Accretion	—			54

Issued and outstanding at March 31, 2006	1,000		$	375
Accretion	—			625
Repurchased and cancelled	(1,000	)		(1,000	)

Issued and outstanding at March 31, 2007	—		$	—

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 8³/4% 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, 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.

iii.

NAEPI Series B preferred shares

Issued and outstanding:


	Number of Shares		Amount
Issued and outstanding at March 31, 2004 and 2005	—			—
Issued	83,462			8,376
Repurchased	(8,218	)		(851	)
Change in redemption amount	—			34,668

Issued and outstanding at March 31, 2006	75,244		$	42,193
Accretion	—			2,489
Transferred to common shares on conversion	(75,244	)		(44,682	)

Issued and outstanding at March 31, 2007	—		$	—

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 8³/4% 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, 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


		Annual Report 2007 ][ 63 ]

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

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, the Company 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 the Company to exchange each of the holder’s NAEPI Series B preferred shares for 100 common shares (on a post-split basis – note 17(b)) of the Company. The Put/Call Right could only be exercised upon delivery by the Company 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 17(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).

The Put/Call Agreement also granted the Company 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 17(b)) of the Company 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 the 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 the Company 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 the Company’s voting and non-voting common shares. All information relating to the exchange of the NAEPI Series B preferred shares (note 17(a)), the issued and outstanding common shares (below), basic and diluted net income (loss) per share data (note 17(d)), stock options (note 25), and basic and diluted net income (loss) per share data under U.S. GAAP (note 27) 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, 2004	18,087,600		$	90,438
Issued	60,000			300

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	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

*Common non-voting shares:*
Issued and outstanding at March 31, 2004, 2005, 2006 and 2007	412,400		$	2,062

*Total common shares at March 31, 2007*	35,604,660		$	296,198

(1)

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


[ 64 ][ Annual Report 2007

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

During the year ended March 31, 2005, 60,000 common voting shares were issued for cash consideration of $300. 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.

c)	Contributed surplus


Balance, March 31, 2004	$	137
Stock-based compensation (note 25)		497

Balance, March 31, 2005		634
Stock-based compensation (note 25)		923
Balance, March 31, 2006		1,557
Stock-based compensation (note 25)		2,101
Transferred to common shares on exercise of stock options		(52	)

Balance, March 31, 2007	$	3,606

d)	Net income (loss) per share


Year ended March 31,	2007		2006			2005
Basic net income (loss) per share
Net income (loss) available to common shareholders	$	21,079	$	(21,941	)	$	(42,323	)
Weighted average number of common shares		24,352,156		18,574,800			18,539,720

Basic net income (loss) per share	$	0.87	$	(1.18	)	$	(2.28	)

Diluted net income (loss) per share
Net income (loss) available to common shareholders	$	21,079	$	(21,941	)	$	(42,323	)

Weighted average number of common shares		24,352,156		18,574,800			18,539,720
Dilutive effect of:
Stock options		1,091,751		—			—

Weighted average number of diluted common shares		25,443,907		18,574,800			18,539,720

Diluted net income (loss) per share	$	0.83	$	(1.18	)	$	(2.28	)

For the year ended March 31, 2007, average stock options of 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 years ending March 31, 2006 and March 31, 2005, 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 these years.

18.

Interest expense


Year ended March 31,	2007		2006		2005
Interest on senior notes	$	27,417	$	28,838	$	23,189
Interest on capital lease obligations		725		457		230
Interest on senior secured credit facility		—		564		3,274
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		32,656		64,581		26,693
Amortization of deferred financing costs		3,436		3,338		2,554
Other interest		1,157		857		1,894

	$	37,249	$	68,776	$	31,141


		Annual Report 2007 ][ 65 ]

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

19.

Other information

a)	Supplemental cash flow information


Year ended March 31,	2007		2006		2005
Cash paid during the year for:
Interest	$	34,061	$	29,978	$	31,398
Income taxes		342		617		3,588
Cash received during the year for:
Interest		1,156		530		362
Income taxes		160		2		—
Non-cash transactions:
Acquisition of plant and equipment by means of capital leases		4,653		5,910		5,385
Issue of Series A preferred shares		—		321		—

b)	Net change in non-cash working capital


Year ended March 31,	2007			2006			2005
Accounts receivable	$	(25,278	)	$	(9,396	)	$	(24,029	)
Allowance for doubtful accounts		18			(94	)		(69	)
Unbilled revenue		(39,339	)		(2,083	)		(13,735	)
Inventory		(99	)		77			1,475
Prepaid expenses and deposits		(10,133	)		66			(590	)
Other assets		(9,855	)		(163	)		(840	)
Accounts payable		39,995			(5,005	)		29,789
Accrued liabilities		(1,429	)		9,402			507
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		(2,125	)		3,799			1,325

	$	(48,245	)	$	(3,397	)	$	(6,167	)

c)	Investment in joint venture

The Company has determined that the joint venture in which it participates is a variable interest entity as defined by AcG-15 and that the Company is the primary beneficiary. Accordingly, the joint venture has been consolidated on a prospective basis effective January 1, 2005. During the fourth quarter of 2005, the arrangement of this joint venture was amended such that the Company is responsible for all of its activities and revenues. As a result, no minority interest has been recorded.

The Company’s transactions with the joint venture eliminate on consolidation.

Details of the Company’s proportionate share of the results of operations and cash flows of the joint venture, prior to its consolidation, that are included in the consolidated financial statements are as follows:


Year ended March 31	2005
Revenue	$	7,631
Project costs		(8,840	)
General and administrative		—

Net income (loss)	$	(1,209	)


Year ended March 31	2005
Cash provided by:
Operating activities	$	(4,668	)
Investing activities		—
Financing activities		5,061

	$	393


[ 66 ][ Annual Report 2007

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

20.

Segmented information

a)	General overview

The Company conducts business in three business segments: Mining and Site Preparation, Piling and Pipeline.

•

Mining and Site Preparation:

The Mining and Site Preparation 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.

b)	Results by business segment:


For the year ended March 31, 2007	Mining and Site Preparation		Piling		Pipeline			Total
Revenues from external customers	$	473,179	$	109,266	$	47,001		$	629,446
Depreciation of plant and equipment		21,855		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

For the year ended March 31, 2006	Mining and Site Preparation		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

For the year ended March 31, 2005	Mining and Site Preparation		Piling		Pipeline			Total
Revenues from external customers	$	264,835	$	61,006	$	31,482		$	357,323
Depreciation of plant and equipment		10,308		2,335		218			12,861
Segment profits		11,617		13,319		4,902			29,838
Segment assets		315,740		74,975		48,635			439,350
Expenditures for segment plant and equipment		16,888		202		774			17,864

c)	Reconciliations

Income (loss) before income taxes


Year ended March 31,	2007			2006			2005
Total profit for reportable segments	$	94,918		$	82,312		$	29,838
Unallocated corporate expenses		(73,950	)		(102,190	)		(80,219	)
(Unallocated) over allocated equipment costs		(2,482	)		(1,326	)		5,794

Income (loss) before income taxes	$	18,486		$	(21,204	)	$	(44,587	)

ii.

Total assets


	March 31 2007		March 31 2006
Total assets for reportable segments	$	621,636	$	460,771
Corporate assets		89,100		107,911

Total assets	$	710,736	$	568,682

The Company’s goodwill is assigned to the Mining and Site Preparation, Piling and Pipeline segments in the amounts of $125,447, $41,192, and $32,753, respectively.

All of the Company’s assets are located in Canada and activities are carried out throughout the year.


		Annual Report 2007 ][ 67 ]

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

d)	Customers

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


Year ended March 31,	2007		2006		2005
Customer A	17	%	32	%	12	%
Customer B	16	%	5	%	8	%
Customer C	12	%	16	%	26	%
Customer D	10	%	6	%	4	%
Customer E	10	%	2	%	0	%
Customer F	4	%	10	%	9	%
Customer G	1	%	6	%	10	%
Customer H	1	%	2	%	11	%

Revenue by major customer was earned in all three segments: Mining and Site Preparation, Pipeline and Piling

21.

Related party transactions

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; 2005 - $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. 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.

During the year ended March 31, 2006, 75,000 NAEPI Series B preferred shares (on a post-split basis – note 17(a)(iii)) were issued to the above Sponsor group in exchange for cash of $7.5 million (note 17(a)).

Pursuant to several office lease agreements, for the year ended March 31, 2007 the Company paid $572 (2006 - $836; 2005 - $824) 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.

All related party transactions described above were measured at the exchange amount, being the consideration established and agreed to by the related parties.

22.

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 (collectively “the debt”) are based on management estimates which are determined by discounting cash flows required under the debt 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, 2007 and March 31, 2006 are not significantly different than their carrying values. The fair value of the 8?% notes, based upon their year end trading value as at March 31, 2007, is $239,803 (March 31, 2006 - $228,752) compared to their carrying value of $230,580 (March 31, 2006 - $233,420). The fair value of the 9% senior secured notes, based upon their year end trading value as at March 31, 2006, was $74,646 compared to their carrying value of $70,587.

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 8³/4 % 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 converting the 8.75% rate payable on the 8³/4% senior notes into a fixed rate of 9.765% for the duration that the 8³/4% 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, 2007, the Company’s derivative financial instruments are carried on the consolidated balance sheets at their fair value of $60,863 (March 31, 2006 - $63,611). 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, 2007, 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 a cross-currency swap agreement to hedge this foreign currency exposure.


[ 68 ][ Annual Report 2007

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

ii.

Interest rate risk

The Company is exposed to interest rate risk on the revolving credit facility and its capital lease obligations. The Company also leases equipment with a variable lease payment component that is tied to prime rates. The Company does not use derivative financial instruments to reduce its exposure to these risks.

iii.

Credit risk

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.

At March 31, 2007 and March 31, 2006, the following customers represented 10% or more of accounts receivable and unbilled revenue:


March 31,	2007		2006
Customer A	15	%	6	%
Customer B	10	%	5	%
Customer C	10	%	1	%
Customer D	9	%	21	%
Customer E	7	%	11	%

23.

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,
2008	$	13,787
2009		13,331
2010		10,298
2011		3,016
2012 and thereafter		135

	$	40,567

24.

Employee contribution 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, 2007 were $645 (2006 - $409; 2005 - $305).

25.

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.


	Number of options⁽¹⁾		Weighted average exercise price $ per share ⁽¹⁾
Outstanding at March 31, 2004	1,082,600		$	5.00
Granted	482,240			5.00
Exercised	—			—
Forfeited	(40,000	)		(5.00	)

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

(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 17(b).


		Annual Report 2007 ][ 69 ]

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

The following table summarizes information about stock options outstanding at March 31, 2007:


	Number	Options outstanding			Options exercisable
Exercise price	Number	Weighted average remaining life	Weighted average exercise price ($)		Number	Weighted average exercise price ($)
$ 5.00	1,959,080	7.6 years	$	5.00	837,352	$	5.00
$ 16.75	187,760	9.5 years	$	16.75	—		—

	2,146,840		$	6.03	837,352	$	5.00

At March 31, 2007, the weighted average remaining contractual life of outstanding options is 7.7 years (March 31, 2006 - 8.2 years). The Company recorded $2,101 of compensation expense related to stock options in the year ended March 31, 2007 (2006 - $923; 2005 - $497) with such amount being credited to contributed surplus.

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,	2007		2006		2005
Number of options granted ⁽¹⁾	315,520		745,520		482,240
Weighted average fair value per option granted ($) ⁽¹⁾	9.91		3.41		3.43
Weighted average assumptions:
Dividend yield	nil	%	nil	%	nil	%
Expected volatility	24.73	%	nil	%	nil	%
Risk-free interest rate	4.30	%	4.13	%	4.25	%
Expected life (years)	6.4		10		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 17(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 be 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 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.


[ 70 ][ Annual Report 2007

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

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.

26.

Comparative figures

Certain of the prior year figures have been reclassified to conform with the current year’s presentation.

27.

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,	2007			2006			2005
Net income (loss) - as reported	$	21,079		$	(21,941	)	$	(42,323	)
Capitalized interest (a)		249			847			—
Depreciation of capitalized interest (a)		(143	)		—			—
Amortization using effective interest method (b)		1,246			590			—
Difference between accretion of NAEPI Series B preferred shares under Canadian GAAP and U.S. GAAP (f)		249			—			—
Realized and unrealized loss on derivative financial instruments (e)		348			(484	)		—

Income (loss) before income taxes		23,028			(20,988	)		(42,323	)
Income taxes:
Deferred income taxes (h)		(954	)		—			—

Net income (loss) – U.S. GAAP	$	22,074		$	(20,988	)	$	(42,323	)

Net income (loss) per share – basic – U.S. GAAP ⁽¹⁾	$	0.91		$	(1.13	)	$	(2.28	)

Net income (loss) per share – diluted – U.S. GAAP ⁽¹⁾	$	0.87		$	(1.13	)	$	(2.28	)

(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 17(a)).

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


	March 31 2007			March 31 2006
Shareholders’ equity (as reported) – Canadian GAAP	$	244,278		$	18,111
Capitalized interest (a)		1,096			847
Depreciation of capitalized interest (a)		(143	)		—
Amortization using effective interest method (b)		1,836			590
Realized and unrealized loss on derivative financial instruments (e)		(136	)		(484	)
Excess of fair value of amended NAEPI Series B preferred shares over carrying value of original NAEPI Series B preferred shares (f)		—			(3,707	)
Deferred income taxes		(954	)		—

Shareholders’ equity – U.S. GAAP	$	245,977		$	15,357


		Annual Report 2007 ][ 71 ]

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

A continuity schedule of each component of the Company’s shareholders’ equity under U.S. GAAP for the year ended March 31, 2007 is as follows:


	Common shares			Contributed surplus			Deficit			Total
April 1, 2004 – U.S. GAAP	$	92,500		$	137		$	(12,282	)	$	80,355
Net loss		—			—			(42,323	)		(42,323	)
Stock based compensation (d)		—			497			—			497
Share issue		300			—			—			300

March 31, 2005	$	92,800		$	634		$	(54,605	)	$	38,829
Net loss		—			—			(20,988	)		(20,988	)
Stock based compensation (d)		—			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 (f)		—			—			(3,707	)		(3,707	)

March 31, 2006	$	93,100		$	1,557		$	(79,300	)	$	15,357
Net income		—			—			22,074			22,074
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		48,140			—			—			48,140
Reclassification on exercise of stock options		52			(52	)		—			—

March 31, 2007 – U.S. GAAP	$	299,656		$	3,606		$	(57,285	)	$	245,977

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. Accordingly, the capitalized amount is subject to depreciation in accordance with the Company’s policies when the asset is placed into service.

b)	Deferred charges

Under Canadian GAAP, the Company defers and amortizes debt issue costs on a straight-line basis over the stated term of the related debt. Under U.S. GAAP, the Company is required to amortize financing costs over the stated term of the related debt using the effective interest method resulting in a consistent interest rate over the term of the debt in accordance with Accounting Principles Board Opinion No. 21 (“APB 21”).

c)	Reporting comprehensive income

Statement of Financial Accounting Standards No. 130, “Reporting Comprehensive Income” (“SFAS 130”) establishes standards for the reporting and display of comprehensive income and its components in a full set of general purpose financial statements. Comprehensive income equals net income (loss) for the period as adjusted for all other non-owner changes in shareholders’ equity. SFAS 130 requires that all items that are required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement. The only component of comprehensive income (loss) is the net income (loss) for the period.

d)	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.

The methodology for determining the expense to be recognized in each period that is prescribed by SFAS 123(R) differs from that prescribed by Canadian GAAP. Canadian GAAP permits accounting for forfeitures of share-based payments as they occur while U.S. standards require an estimate of forfeitures to be made at the date of grant and thereafter until the requisite service period has been completed or the awards are cancelled. The required adjustment under U.S. GAAP to account for estimated forfeitures was not significant for all periods presented.


[ 72 ][ Annual Report 2007

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

During the year ended March 31, 2007, the Company granted 315,520 stock options to employees and a director prior to the completion of the IPO. In determining the grant-date fair value of these stock options, the Company included an expected volatility of 40%. The additional compensation cost for these stock options under U.S. GAAP was not significant.

e)	Derivative financial instruments

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. On November 26, 2003, the Company issued 8³/₄% senior notes for US$200 million (Canadian $263 million) and on May 19, 2005 the Company issued 9% senior secured notes for US$60.4 million (Canadian $76.3 million). Both of these issues included certain contingent embedded derivatives which provided for the acceleration of redemption by the holder at a premium in certain instances. These embedded derivatives 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 classified as part of the carrying amount of the Senior Notes on the consolidated balance sheet, with changes in the fair value being recorded in net income as realized and unrealized (gain) loss on derivative financial instruments for the period under U.S. GAAP. Under Canadian GAAP, separate accounting of embedded derivatives from the host contract is not permitted by EIC-117.

f)	NAEPI Series B Preferred Shares

Prior to the modification of the terms of the NAEPI Series B preferred shares, 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 on March 30, 2006, under Canadian GAAP, the Company 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, the Company 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, the Company 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 as a charge to minority interest (as opposed to retained earnings in the accounts of NAEPI) under US GAAP and interest expense in the Company’s financial statements under Canadian GAAP.

On November 28, 2006, the Company 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 the Company. For Canadian GAAP purposes, the Company 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 the Company resulting in the reclassification of the carrying value of the minority interest on the exercise date of $48,140 to common shares.

g)	Investment in joint venture

The Company has determined that the joint venture in which it participates is a VIE and that the Company is the primary beneficiary. Accordingly the joint venture has been consolidated on a prospective basis effective January 1, 2005. Prior to its consolidation, the joint venture was accounted for using the proportionate consolidation method under Canadian GAAP. Under U.S. GAAP, investments in joint ventures are accounted for using the equity method. The different accounting treatment affects only the display and classification of financial statement items and not net earnings or shareholders’ equity. Rules prescribed by the Securities and Exchange Commission of the United States permit the use of the proportionate consolidation method in the reconciliation to U.S. GAAP provided the joint venture is an operating entity and the significant financial operating policies are, by contractual agreement, jointly controlled by all parties having an interest in the joint venture. In addition, the Company disclosed in note 19(c) the major components of its financial statements resulting from the use of the proportionate consolidation method to account for its interest in the joint venture prior to its consolidation.

h)	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.

i)	United States accounting pronouncements recently adopted

Statement on Financial Accounting Standards No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” was issued in May 2003. This Statement establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. The Statement also includes required disclosures for financial instruments within its scope. For the Company, the Statement was adopted as of January 1, 2004, except for certain mandatorily redeemable financial instruments. For certain mandatorily redeemable financial instruments, the Statement was adopted by the Company on January 1, 2005. The adoption of the standard required the Company to reclassify the carrying value of the NACG Preferred Corp. Series A preferred shares from minority interest to redeemable preferred shares. After the adoption of the standard, the Company issued other mandatorily redeemable preferred shares that were within the scope of the standard, which have been disclosed in note 17(a) to the consolidated financial statements.

In November 2004, the FASB issued Statement on Financial Accounting Standards No. 151, “Inventory Costs”. This standard requires the allocation of fixed production overhead costs be based


		Annual Report 2007 ][ 73 ]

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

on the normal capacity of the production facilities and unallocated overhead costs recognized as an expense in the period incurred. In addition, other items such as abnormal freight, handling costs and wasted materials require treatment as current period charges rather than being considered an inventory cost. This standard was effective for fiscal 2006 for the Company. The adoption of this standard did not have a material impact on the Company’s financial statements.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143” (“FIN 47”), which requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. FIN 47 is effective for fiscal years ending after December 15, 2005. The adoption of this standard did not have a material impact on the Company’s financial statements.

Statement on Financial Accounting Standards No. 153, “Exchanges of Non-monetary Assets – an Amendment of APB Opinion 29” (“SFAS 153”), was issued in December 2004. Accounting Principles Board (“APB”) Opinion 29 is based on the principle that exchanges of non-monetary assets should be measured based on the fair value of assets exchanged. SFAS 153 amends APB Opinion 29 to eliminate the exception for non-monetary exchanges of similar productive assets and replaces it with a general exception for exchanges of non-monetary assets that do not have commercial substance. The standard is effective for the Company for non-monetary asset exchanges occurring in fiscal periods beginning after June 15, 2005, being July 1, 2005 for the Company. The adoption of this standard did not have a material impact on the Company’s financial statements.

In March 2005, FASB Staff Position FIN 46R-5, “Implicit Variable Interests under FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities”, to address whether a company has an implicit variable interest in a VIE or potential VIE when specific conditions exist. The guidance describes an implicit variable interest as an implied financial interest in an entity that changes with changes in the fair value of the entity’s net assets exclusive of variable interests. An implicit variable interest acts the same as an explicit variable interest except that it involves the absorbing and/or receiving of variability indirectly from the entity (rather than directly). This guidance was adopted in 2006 and did not have a material impact on the Company’s consolidated financial statements.

The impact of the adoption of SFAS 123(R) is described in note 27(d).

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections” (“SFAS 154”) which replaces Accounting Principles Board Opinion No. 20 “Accounting Changes” and Statement of Financial Accounting Standards No. 3, “Reporting Accounting Changes in Interim Financial Statements – An Amendment of APB Opinion No. 28.” SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 was effective for the Company for accounting changes and corrections of errors made by the Company in its fiscal year beginning on April 1, 2006. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

In September 2006, the U.S. Securities and Exchange Commission issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. It establishes an approach that requires quantification of financial statements misstatements based on the effects of the misstatements on each of the Company’s financial statements and the related financial statement disclosures. SAB 108 was effective for the Company’s annual financial statements for the fiscal year ending March 31, 2007. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

j)	Recent United States accounting pronouncements not yet adopted

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 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 although early adoption is permitted. The Company is currently reviewing the impact of this statement.

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 is effective for the Company’s 2008 fiscal year. The Company is currently reviewing the impact of this Interpretation.


[ 74 ][ Annual Report 2007

North American Energy Partners Inc. ][ Notes to the Consolidated Financial Statements

28.

Subsequent events

On June 7, 2007, the Company modified its amended and restated credit agreement to provide for borrowings of up to $125 million (previously $55.0 million) under which revolving loans and letters of credit may be issued. At the current credit rating, prime rate and swing line revolving loans under the agreement will bear interest at the Canadian prime rate plus 0.5% per annum. At the current credit rating, Canadian bankers’ acceptances have stamping fees equal to 2.0% per annum and letters of credit are subject to a fee of 1.5% per annum.

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.

On June 13, 2007, the Company secured financing of $22.3 million for a new piece of heavy equipment. Progress draws under the agreement commenced on June 13, 2007 and the 7.5 year operating lease will be fully funded when the equipment is commissioned, which is expected to be December 31, 2007. During the progress funding period, interest will accrue at the Canadian prime rate plus 1.25% per annum and will be capitalized into the lease. Once fully funded, the Company will choose between a fixed rate (determined as the June 2015 Government of Canada Bond rate plus 3.0% per annum) and a variable rate, being the one-month Canadian bankers’ acceptance rate plus 2.85% per annum.


		Annual Report 2007 ][ 75 ]

North American Energy Partners Inc. ][

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

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

Annual General Meeting

The Annual General Meeting of

North American Energy Partners Inc.

will be held at The Westin Edmonton Hotel,

10135 – 100th Street, Edmonton, Alberta

at 4:00 p.m. on

Wednesday, September 19, 2007


[ 76 ][ Annual Report 2007

North American Energy Partners Inc. ]

SENIOR MANAGEMENT



		Rodney J. Ruston President and Chief Executive Officer				William M. Koehn Vice President, Operations and Chief Operating Officer (resigned July 31, 2007)

		Douglas A. Wilkes Vice President, Finance and Chief Financial Officer				Miles W. Safranovich Vice President, Business Development and Estimating

		Robert G. Harris Vice President, Human Resources, Health, Safety and Environment				Pamela M. Winters Director, Information Technology

		Christopher J. Hayman Vice President, Supply Chain

LOGO

NORTH AMERICAN ENERGY PARTNERS INC.

NOTICE OF ANNUAL MEETING

AND MANAGEMENT INFORMATION CIRCULAR

ANNUAL MEETING OF SHAREHOLDERS TO BE HELD

SEPTEMBER 19, 2007

AUGUST 17, 2007

NORTH AMERICAN ENERGY PARTNERS INC.

NOTICE OF ANNUAL MEETING OF SHAREHOLDERS TO BE HELD ON SEPTEMBER 19, 2007

NOTICE IS HEREBY GIVEN that the annual meeting of holders of common shares (the “NAEP Shareholders”) of North American Energy Partners Inc. (the “Corporation”) will be held at The Westin Edmonton Hotel, 10135-100^th Street, Edmonton, Alberta T5J 0N7 on the 19^th day of September, 2007, at 4:00 p.m. (Mountain Time) (the “Meeting”), for the following purposes:

to receive the financial statements of the Corporation for the year ended March 31, 2007 and the auditors’ report thereon;

to elect the directors of the Corporation for the ensuing year;

to re-appoint the auditors of the Corporation for the ensuing year and to authorize the directors to fix the remuneration of the auditors as such; and

to transact such other business as may properly come before the Meeting or any adjournments thereof.

The specific details of the foregoing matters to be put before the Meeting and a description of the rights of NAEP Shareholders, are set forth in the management information circular accompanying this notice (the “Information Circular”). Capitalized terms used in this notice of annual meeting and not otherwise defined herein shall have the meanings ascribed to such terms in the Information Circular.

A copy of the 2007 Annual Report of the Corporation, the Information Circular and a form of proxy accompany this notice.

NAEP Shareholders who are unable to attend the Meeting are requested to complete, sign, date and return the enclosed form of proxy in accordance with the instructions set out in the form of proxy and in the Information Circular accompanying this notice. A proxy will not be valid unless it is deposited with CIBC Mellon Trust Company at Proxy Dept., CIBC Mellon Trust Company, P.O. Box 721, Agincourt, Ontario M1S 0A1 (facsimile no. (416) 752-8239) no later than 4:30 p.m. (Mountain Time) on September 17, 2007 and if the Meeting is adjourned, no later than 24 hours (excluding Saturdays and holidays) prior to the commencement of any adjournment thereof.

DATED at Acheson, Alberta, this 17^th day of August, 2007.

BY ORDER OF THE BOARD OF DIRECTORS OF
NORTH AMERICAN ENERGY PARTNERS INC.

(signed) “Douglas A. Wilkes”

Chief Financial Officer

NORTH AMERICAN ENERGY PARTNERS INC.

MANAGEMENT INFORMATION CIRCULAR

SOLICITATION OF PROXIES

This management information circular (the “Information Circular”) and accompanying form of proxy (the “Proxy”) are furnished in connection with the solicitation of proxies by or on behalf of management of North American Energy Partners Inc. (the “Corporation” or “NAEP”) for use at the annual meeting (the “Meeting”) of holders of common shares of the Corporation (the “NAEP Shareholders”) to be held at The Westin Edmonton Hotel, 10135-100^th Street, Edmonton, Alberta T5J 0N7 on the 19^th day of September, 2007, at 4:00 p.m. (Mountain Time), and at any adjournments thereof, for the purposes set forth in the accompanying notice of meeting dated August 17, 2007 (the “Notice of Meeting”).

It is expected that the solicitation will be primarily by mail. Proxies may also be solicited personally by officers of the Corporation at nominal cost. The cost of this solicitation will be borne by the Corporation. The Corporation may pay the reasonable costs incurred by persons who are the registered but not beneficial owners of voting shares of the Corporation (such as brokers, dealers, other registrants under applicable securities laws, nominees and/or custodians) in sending or delivering copies of this Information Circular, the Notice of Meeting and Proxy to the beneficial owners of such shares. The Corporation will provide, without cost to such persons, upon request to the Secretary of the Corporation, additional copies of the foregoing documents required for this purpose. The Notice of Meeting, Proxy and this Information Circular will be mailed to NAEP Shareholders commencing on or about August 22, 2007. In this Information Circular, except where otherwise indicated, all dollar amounts are expressed in Canadian currency.

No person has been authorized by the Corporation to give any information or make any representations in connection with the matters contained herein other than those contained in this Information Circular and, if given or made, any such information or representation must not be relied upon as having been authorized by the Corporation.

This Information Circular does not constitute an offer or a solicitation to any person in any jurisdiction in which such offer or solicitation is unlawful.

STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Information Circular may contain forward-looking statements. Forward-looking statements include statements preceded by, followed by or that include the words “may”, “could”, “would”, “should”, “believe”, “expect”, “anticipate”, “plan”, “estimate”, “target”, “project”, “intend”, “continue”, “further” or similar expressions. Actual results could differ materially from those contemplated by such forward-looking statements as a result of any number of factors and uncertainties, many of which are beyond the Corporation’s control. Important factors that could cause actual results to differ materially from those in forward-looking statements include success of business development efforts, changes in oil and gas prices, availability of a skilled labour force, internal controls, general economic conditions, terms of the Corporation’s debt instruments, exchange rate fluctuations, weather conditions, performance of the Corporation’s customers, access to equipment, changes in laws and ability to execute transactions. Undue reliance should not be placed upon forward-looking statements and we undertake no obligation, other than those required by applicable law, to update or revise those statements.

RECORD DATE

The record date (the “Record Date”) for determining which NAEP Shareholders shall be entitled to receive notice of and to vote at the Meeting is August 13, 2007. Only NAEP Shareholders of record as of the Record Date are entitled to receive notice of and to vote at the Meeting, unless after the Record Date such shareholder of record transfers its shares and the transferee (the “Transferee”), upon establishing that the Transferee owns such shares, requests in writing at least 10 days prior to the Meeting or any adjournments thereof that the Transferee may have his or her name included on the list of NAEP Shareholders entitled to vote at the Meeting, in which case the Transferee is entitled to vote such shares at the Meeting. Such written request by the Transferee shall be filed with CIBC Mellon Trust Company at Proxy Dept., CIBC Mellon Trust Company, P.O. Box 721, Agincourt, Ontario M1S 0A1, together with a copy to the Secretary of the Corporation at North American Energy Partners Inc., Zone 3, Acheson Industrial Area, 2-53016 Highway 60, Acheson, Alberta T7X 5A7.

Under normal conditions, confidentiality of voting is maintained by virtue of the fact that the Corporation’s transfer agent tabulates proxies and votes. However, such confidentiality may be lost as to any proxy or ballot if a question arises as to its validity or revocation or any other like matter. Loss of confidentiality may also occur if the Board of Directors decides that disclosure is in the interest of the Corporation or its shareholders.

APPOINTMENT OF PROXYHOLDERS

The persons named in the accompanying Proxy as proxyholders are representatives of management of the Corporation. A NAEP Shareholder desiring to appoint some other person (who need not be a shareholder of NAEP) to represent him or her at the Meeting, may do so either by striking out the printed names and inserting the desired person’s name in the blank space provided in the Proxy or by completing another proper proxy and, in either case, delivering the completed proxy to CIBC Mellon Trust Company at Proxy Dept., CIBC Mellon Trust Company, P.O. Box 721, Agincourt, Ontario M1S 0A1 (facsimile no. (416) 752-8239) no later than 4:30 p.m. (Mountain Time) on September 17, 2007 and if the Meeting is adjourned, no later than 24 hours (excluding Saturdays and holidays) prior to the commencement of any adjournment thereof. A Proxy should be executed by a NAEP Shareholder or its attorney duly authorized in writing or, if a NAEP Shareholder is a corporation, by an officer or attorney thereof duly authorized in writing. If a proxy is given by joint shareholders, it must be executed by all such joint shareholders.

VOTING OF PROXIES

If a Proxy is completed, signed and delivered to the Corporation in the manner specified above, the persons named as proxyholders therein shall vote or withhold from voting the shares in respect of which they are appointed as proxyholders at the Meeting, in accordance with the instructions of the NAEP Shareholder appointing them, on any show of hands or any ballot that may be called for and, if the NAEP Shareholder specifies a choice with respect to any matter to be acted upon at the Meeting, the persons appointed as proxyholders shall vote in accordance with the specification so made. In the absence of such specification, or if the specification is not certain, the shares represented by such Proxy will be voted in favour of the matters to be acted upon as specified in the Notice of Meeting.

A Proxy confers discretionary authority upon the persons named therein with respect to all other matters which may properly come before the Meeting or any adjournments thereof. As of the date of this Information Circular, the Board of Directors of the Corporation knows of no such amendments, variations or other matters to come before the Meeting, other than matters referred to in the Notice of Meeting. However, if other matters should properly come before the Meeting, the Proxy will be voted on such matters in accordance with the best judgment of the person or persons voting such Proxy.

REVOCABILITY OF PROXY

Any NAEP Shareholder returning an enclosed Proxy may revoke the same at any time insofar as it has not been exercised. In addition to revocation in any other manner permitted by law, a Proxy may be revoked by instrument in writing executed by the NAEP Shareholder or by his or her attorney authorized in writing or, if the NAEP Shareholder is a corporation, by an officer or attorney thereof duly authorized, and deposited at the registered office of the Corporation to the attention of Kevin Rowand, at any time up to and including the last business day preceding the day of the Meeting, or any adjournment thereof, or with the chairperson of the Meeting, prior to the commencement of the Meeting. A NAEP Shareholder attending the Meeting has the right to vote in person and, if he or she does so, his or her proxy is nullified with respect to the matters such person votes upon and any subsequent matters thereafter to be voted upon at the Meeting or any adjournment thereof.

ADVICE TO BENEFICIAL HOLDERS OF COMMON SHARES

The information set forth in this section is of significant importance to many NAEP Shareholders, as a substantial number of NAEP Shareholders do not hold common shares of the Corporation (“NAEP Common Shares”) in their own name, and thus are considered non-registered shareholders. NAEP Shareholders who do not hold their NAEP Common Shares in their own name (“Beneficial Shareholders”) should note that only Proxies deposited by NAEP Shareholders whose names appear on the records of the Corporation as the registered holders of NAEP Common Shares can be recognized and acted upon at the Meeting. If NAEP Common Shares are listed in an account statement provided to a NAEP Shareholder by a broker, then, in almost all cases, those NAEP Common Shares will not be registered in the NAEP Shareholder’s name on the records of the Corporation. Such NAEP Common Shares will more likely be registered under the name of the NAEP Shareholder’s broker or an agent of that broker or another similar entity (called an “Intermediary”). NAEP Common Shares held by an Intermediary can only be voted by the Intermediary (for, withheld or against resolutions) upon the instructions of the Beneficial Shareholder. Without specific instructions, Intermediaries are prohibited from voting NAEP Common Shares.

Beneficial Shareholders should ensure that instructions respecting the voting of their NAEP Common Shares are communicated in a timely manner and in accordance with the instructions provided by their Intermediary. Applicable regulatory rules require Intermediaries to seek voting instructions from Beneficial Shareholders in advance of shareholders’ meetings. Every Intermediary has its own mailing procedures and provides its own return instructions to clients, which should be carefully followed by Beneficial Shareholders in order to ensure that their NAEP Common Shares are voted at the Meeting.

Although a Beneficial Shareholder may not be recognized directly at the Meeting for the purposes of voting NAEP Common Shares registered in the name of their Intermediary, a Beneficial Shareholder may attend at the Meeting as proxyholder for the Intermediary and vote the NAEP Common Shares in that capacity. Beneficial Shareholders who wish to attend the Meeting and indirectly vote their NAEP Common Shares as a proxyholder, should enter their own names in the blank space on the form of proxy provided to them by their Intermediary and timely return the same to their Intermediary in accordance with the instructions provided by their Intermediary, well in advance of the Meeting.

NOTICE TO UNITED STATES SHAREHOLDERS

The solicitation of proxies by the Corporation is not subject to the requirements of Section 14(a) of the United States (“US”) Securities Exchange Act of 1934, as amended (the “US Exchange Act”), by virtue of an exemption applicable to proxy solicitations by “foreign private issuers” as defined in Rule 3b-4 under the US Exchange Act. Accordingly, this Information Circular has been prepared in accordance with the applicable disclosure requirements in Canada. Residents of the United States should be aware that such requirements may be different than those of the United States applicable to proxy statements under the US Exchange Act.

VOTING SHARES AND PRINCIPAL HOLDERS THEREOF

The Corporation’s authorized capital consists of an unlimited number of NAEP Common Shares, and an unlimited number of non-voting Common Shares. As at August 13, 2007, there were a total of 35,752,060 NAEP Common Shares outstanding. Each NAEP Common Share entitles the holder thereof to one vote in respect of each of the matters to be voted upon at the Meeting. For a list of persons or corporations who beneficially own, directly or indirectly, or exercise control or direction over securities carrying more than 10% of the voting rights attached to the NAEP Common Shares, please see the table included under the Section captioned “Business to be Transacted at the Meeting – Election of Directors”.

QUORUM

A quorum for the transaction of business at the Meeting shall consist of at least two persons holding or representing by proxy not less than twenty (20%) percent of the outstanding shares of the Corporation entitled to vote at the Meeting.

If a quorum is not present at the opening of the Meeting, the NAEP Shareholders present may adjourn the Meeting to a fixed time and place but may not transact any other business. If a meeting of shareholders is adjourned by one or more adjournments for an aggregate of less than 30 days it is not necessary to give notice of the adjourned meeting other than by announcement at the time of an adjournment. If a meeting of NAEP Shareholders is adjourned by one or more adjournments for an aggregate of more than 29 days and not more than 90 days, notice of the adjourned meeting shall be given as for an original meeting but the management of the Corporation shall not be required to send a form of proxy in the form prescribed by applicable law to each NAEP Shareholder who is entitled to receive notice of the meeting. Those NAEP Shareholders present at any duly adjourned meeting shall constitute a quorum.

The Corporation’s list of NAEP Shareholders as of the Record Date has been used to deliver to NAEP Shareholders the Notice of Meeting and this Information Circular as well as to determine the NAEP Shareholders who are eligible to vote.

PRESENTATION OF FINANCIAL STATEMENTS

The audited comparative consolidated financial statements of the Corporation for the financial year ended March 31, 2007, together with the report of the auditors thereon, copies of which are contained in the Corporation’s annual report, will be presented to the NAEP Shareholders at the Meeting. Receipt in the Meeting of the auditors’ report and the Corporation’s financial statements for its last completed fiscal period will not constitute approval or disapproval of any matters referred to therein.

BUSINESS TO BE TRANSACTED AT THE MEETING

1. Election of Directors

The Board of Directors of the Corporation presently consists of 10 directors to be elected annually. All of the nominees are now directors of the Corporation and have been directors since the dates indicated below. Unless a NAEP Shareholder directs that his or her NAEP Common Shares be otherwise voted or withheld from voting in connection with the election of directors, the persons named in the enclosed form of proxy will vote for the election of the nine nominees whose names are set forth below. Management does not contemplate that any of the following nominees will be unable or unwilling to serve as a director but if that should occur for any reason prior to the Meeting, the persons named in the enclosed Proxy will have the right to vote for another nominee in their discretion. Each director elected at the Meeting will hold office until the next annual meeting or until his or her successor is duly elected or appointed.

For each nominee, the following table and the notes thereto state, as of August 10, 2007, the: (i) name, municipality and country of residence, and age; (ii) date of first becoming a director; (iii) current position(s) with the Corporation; (iv) approximate number of NAEP Common Shares beneficially owned, directly or indirectly, or over which control or direction is exercised; and (v) present principal occupation.


Name, Present Principal Occupation, Municipality and Country of Residence and Age	Director Since	Position(s) with the Corporation, if any	Number of Common Shares Beneficially Owned, Directly or Indirectly or Over Which Control or Direction is Exercised⁽¹⁾		Principal Occupation
GEORGE R. BROKAW⁽²⁾⁽⁵⁾ Southampton, New York, U.S.A., 39	June 28, 2006	Director	16,656	⁽⁶⁾	Managing Director, Perry Capital, L.L.C., an affiliate of Perry Corp., a private investment firm; Managing Director (Mergers & Acquisitions) of Lazard Frères & Co. LLC from January 2003 to May 2005.

JOHN A. BRUSSA⁽³⁾⁽⁴⁾ Calgary, Alberta, Canada, 50	November 26, 2003	Director	129,056	⁽⁶⁾	Senior partner and head of the Tax Department at the law firm of Burnet, Duckworth & Palmer LLP; Chairman of Penn West Energy Trust, Crew Energy Inc. and Divestco Inc.; currently a Director of a number of natural resource and energy companies and mutual fund trusts.

JOHN D. HAWKINS⁽²⁾⁽⁴⁾ Houston, Texas, U.S.A., 43	October 17, 2003	Director	16,656	⁽⁶⁾	Partner with The Sterling Group, L.P., a private equity investment firm, since 1999.

RONALD A. MCINTOSH⁽²⁾⁽⁵⁾ Calgary, Alberta, Canada, 65	May 20, 2004	Chairman of the Board	84,200	⁽⁷⁾	Chairman of NAV Energy Trust, a Calgary-based oil and natural gas investment fund, from January 2004 to August 2006; President and Chief Executive Officer of Navigo Energy Inc. from October 2002 and January 2004; Senior Vice President and Chief Operating Officer of Gulf Canada Resources Limited from December 2001 to July 2002.


Name, Present Principal Occupation, Municipality and Country of Residence and Age	Director Since	Position(s) with the Corporation, if any	Number of Common Shares Beneficially Owned, Directly or Indirectly or Over Which Control or Direction is Exercised⁽¹⁾		Principal Occupation
WILLIAM C. OEHMIG⁽³⁾⁽⁵⁾ Houston, Texas, U.S.A., 58	May 20, 2004	Director	205,460	⁽⁸⁾	Formerly Chairman of the Corporation’s Board of Directors from November 26, 2003; Partner with The Sterling Group, L.P., a private equity investment firm; Mr. Oehmig currently serves on the boards of Propex Fabrics Inc. and Panolam Industries International Incorporated; previously served as Chairman of Royster-Clark, Purina Mills, and as a Director of Exopack and Sterling Diagnostic Imaging.

RODNEY J. RUSTON Edmonton, Alberta, Canada, 56	May 9, 2005	Director, President and Chief Executive Officer	126,700	⁽⁹⁾	Previously, Managing Director and Chief Executive Officer of Ticor Limited; previously a Principal with Ruston Consulting Services Pty. Ltd.; Formerly held management positions with Pasminco Limited, Savage Resources Limited, Wambo Mining Corporation, Oakbridge Limited, and Kembla Coal & Coke Pty. Limited; Chairman of the Australian Minerals Tertiary Education Council from July 2003 until May 2005.

ALLEN R. SELLO⁽²⁾⁽³⁾ West Vancouver, British Columbia, Canada, 68	January 26, 2006	Director	33,652		From 1999 until September 2004 Mr. Sello held the position of Senior Vice President and Chief Financial Officer for UMA Group Limited; currently Chair of the Vancouver Board of Trade Government Budget and Finance Committee; trustee of Sterling Shoes Income Fund; Director of Infowave Software Inc.


Name, Present Principal Occupation, Municipality and Country of Residence and Age	Director Since	Position(s) with the Corporation, if any	Number of Common Shares Beneficially Owned, Directly or Indirectly or Over Which Control or Direction is Exercised⁽¹⁾		Principal Occupation
PETER W. TOMSETT⁽⁴⁾⁽⁵⁾ West Vancouver, British Columbia, Canada, 49	September 19, 2006	Director	—		Company Director. From September 2004 to January 2006, President and CEO of Placer Dome Inc, prior thereto, Executive Vice President of Placer Dome Inc.; currently Director of Silver Standard Resources Inc, and Chairman of Equinox Minerals Ltd.

K. RICK TURNER⁽²⁾⁽⁴⁾ Little Rock, Arkansas, U.S.A., 49	November 26, 2003	Director	16,656	⁽⁶⁾	Employed by Stephens’ family entities since 1983; currently Senior Managing Principal of The Stephens Group, LLC., private equity investment firm; currently serves on the board of two other publicly-held companies: Energy Transfer Partners and Energy Transfer Equity; serves on numerous private company boards.

⁽¹⁾	The information as to NAEP Common Shares beneficially owned or over which control is exercised, not being within the knowledge of the Corporation, has been furnished by the respective nominees individually, effective as of August 10, 2007.

⁽²⁾	Member of the Audit Committee.

⁽³⁾	Member of the Compensation Committee.

⁽⁴⁾	Member of the Governance Committee.

⁽⁵⁾	Member of the Risk Committee.

⁽⁶⁾	Includes currently exercisable options to purchase 16,656 shares.

⁽⁷⁾	Includes currently exercisable options to purchase 28,000 shares.

⁽⁸⁾	Includes 22,870 shares that have been donated by Mr. Oehmig but over which Mr. Oehmig retains sole voting power.

⁽⁹⁾	Includes currently exercisable options to purchase 110,000 shares.

The following persons or entities beneficially own, directly or indirectly, or exercise control or direction over securities carrying more than 10% of the voting rights attached to the NAEP Common Shares based on information available on August 17, 2007.


Name of Beneficial Owner	Number of NAEP Common Shares	% of Outstanding NAEP Common Shares
Sterling Group Partners I, L.P.^(a)	4,626,265	12.94
Richard Perry^(b)	4,598,466	12.86
FMR Corp.	3,786,800	10.59
MFS Investment Management	4,424,472	12.38

(a)

Sterling Group Partners I GP, L.P. is the sole general partner of Sterling Group Partners I, L.P. Sterling Group Partners I GP, L.P. has five general partners, each of which is wholly-owned by one of Frank J. Hevrdejs, William C. Oehmig, T. Hunter Nelson, John D. Hawkins and C. Kevin Garland. Each of these individuals disclaims beneficial ownership of the shares owned by Sterling Group Partners I, L.P. Sterling Group Partners I, L.P. is an affiliate of The Sterling Group, L.P.

(b)

Perry Partners, L.P. directly holds 2,161,361 NAEP Common Shares. Perry Luxco S.A.R.L. directly holds 1,718,443 NAEP Common Shares. Perry Partners International, Inc. directly holds 718,662 NAEP Common Shares. Richard Perry is the President and sole shareholder of Perry Corp., which is the investment manager of Perry Partners International, Inc. and the managing general partner of Perry Partners, L.P. Perry Partners International, Inc. is the indirect sole shareholder of the class of securities owned by Perry Luxco S.A.R.L. As such, Mr. Perry may be deemed to have beneficial ownership over the respective common shares owned by Perry Luxco S.A.R.L., Perry Partners, L.P. and Perry Partners International, Inc.; however, Mr. Perry disclaims such beneficial ownership, except to the extent of his pecuniary interest, if any, therein. Perry Corp. is an affiliate of Perry Strategic Capital Inc.

Unless a NAEP Shareholder otherwise directs, or directs that his or her NAEP Common Shares are to be withheld from voting in connection with the election of the directors as specified above, the persons named in the enclosed form of Proxy intend to vote for the election of the directors as specified above, such directors to hold office until the next annual meeting or until his or her successor is appointed.

2. Re-appointment of Independent Auditors and Authorization of Directors to fix their Remuneration

At the Meeting, NAEP Shareholders will be requested to vote on the re-appointment of KPMG LLP (“KPMG”) as the independent auditors of the Corporation to hold office until the next annual meeting of shareholders or until a successor is appointed, and to authorize the Board of Directors to fix the auditors’ remuneration. KPMG has been the auditors of the Corporation since the fiscal period from November 26, 2003 to March 31, 2004. Prior to that, KPMG was the auditors of NACG Holdings Inc., a predecessor to the Corporation, since October 31, 2003.

Unless a NAEP Shareholder otherwise directs, or directs that his or her NAEP Common Shares are to be withheld from voting in connection with the appointment of auditors, the persons named in the enclosed form of Proxy intend to vote for the reappointment of KPMG as auditors of the Corporation until the next annual meeting of shareholders and to authorize the directors to fix their remuneration.

3. Other Matters

Management of the Corporation know of no matters to come before the Meeting other than as set forth in the Notice of Meeting. However, if other matters which are not currently known to management should properly come before the Meeting, the accompanying Proxy will be voted on such matters in accordance with the best judgment of the persons voting the Proxy.

EXECUTIVE COMPENSATION

Summary Compensation Table

The following table sets forth all compensation earned during the fiscal years ended March 31, 2007, March 31, 2006 and March 31, 2005 by Rodney J. Ruston, Douglas A. Wilkes, Christopher J. Hayman, William M. Koehn and Miles W. Safranovich (collectively, the “Named Executive Officers”).


	Annual Compensation								Long-Term Compensation			All Other Compensation
Name and Principal Position	Year	Salary			Bonus^(b)		Other Annual Compensation		Securities Underlying Options^(a)	Shares Subject to Resale Restrictions		All Other Compensation
RODNEY J. RUSTON	2007	$	525,000	^(e)	$	386,615		^(c)	—	^(f	⁾
President and Chief	2006	$	536,539		$	300,000		^(c)	550,000
Executive Officer	2005		—			—	—		—
(Hired May 2005)

DOUGLAS A. WILKES	2007	$	135,417		$	142,361		^(c)	100,000	^(f	⁾
Vice President, Finance and	2006		—			—	—		—
Chief Financial Officer (Hired September 2006)	2005		—			—	—		—

CHRISTOPHER J. HAYMAN	2007	$	207,100		$	150,313		^(c)	—	^(f	⁾
Vice President, Supply	2006	$	183,641		$	186,910		^(c)	40,000
Chain (Hired January 2005)	2005	$	56,250			—		^(c)	60,000

WILLIAM M. KOEHN^(d)	2007	$	249,000		$	92,577		^(c)	—	^(f	⁾
Vice President, Operations	2006	$	240,000		$	241,385		^(c)	—
and Chief Operating Officer	2005	$	224,000			—		^(c)	—

MILES W. SAFRANOVICH	2007	$	218,000		$	164,355		^(c)	—	^(f	⁾
Vice President, Business	2006	$	195,808		$	210,384		^(c)	40,000
Development & Estimating	2005	$	61,385			—		^(c)	60,000
(Hired November 2004)

(a)

Consists of options to purchase NAEP Common Shares. The options granted to Mr. Ruston expire on May 8, 2015. The options granted in fiscal 2007 to Mr. Wilkes expire on September 18, 2016. The options granted to Mr. Koehn expire on November 26, 2013. The options granted in fiscal 2005 and 2006 to Mr. Safranovich expire on November 17, 2014 and November 2, 2015, respectively. The options granted in fiscal 2005 and 2006 to Mr. Hayman expire on February 17, 2015 and November 2, 2015, respectively.

(b)	Bonus pursuant to the Corporation’s Annual Incentive Plan. Bonuses relating to performance in a particular fiscal year are paid in July of the following fiscal year.

(c)	The amount of other annual compensation does not exceed the lesser of $50,000 and 10% of the salary and bonus for the fiscal year.

(d)	William M. Koehn resigned from the Corporation effective July 31, 2007.

(e)	This figure includes an annual travel allowance of $25,000 to cover the costs of traveling to and from Mr. Ruston’s home country of Australia.

(f)

Each of Messrs. Ruston, Wilkes, Hayman, Koehn and Safranovich entered into lock-up agreements in connection with the Corporation’s IPO whereby each of them agreed, amongst other things, not to, (i) offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any NAEP Common Shares, during the Lock-Up Period (as defined in the lock-up agreements), or (ii) make any demand for, or exercise any right with respect to, the registration of any NAEP Common Shares or any security convertible into or exercisable or exchangeable for NAEP Common Shares, without the prior written consent of the Corporation’s underwriters in the IPO.

The Corporation does not have a pension plan. For the fiscal year ended March 31, 2007, the total amount the Corporation set aside for pension, retirement and similar benefits for the executive officers and directors was $50,015, consisting of employer matching contributions to the executive officers’ Registered Retirement Savings Plans. The Corporation does not have a long-term incentive plan, other than the Share Option Plan referred to below.

Share Option Plan

The Board of Directors has approved the Corporation’s Amended and Restated 2004 Share Option Plan (the “Share Option Plan”). The Share Option Plan was approved by the Corporation’s shareholders on November 3, 2006 and became effective on November 28, 2006. The Share Option Plan is administered by the Compensation Committee. Option grants under the Share Option Plan may be made to the Corporation’s directors, officers, employees and consultants selected by the Compensation Committee. The Share Option Plan provides for the discretionary grant of options to purchase NAEP Common Shares. Options granted under the Share Option Plan are evidenced by an agreement, specifying the vesting, exercise price and expiration of such options, which terms are determined for each optionee by the Compensation Committee. Options to be granted under the Share 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 Share Option Plan provides that up to 10% of the Corporation’s issued and outstanding NAEP Common Shares from time to time may be reserved for issuance or issued from treasury and also provides that the maximum number of NAEP Common Shares issuable to insiders under the Share Option Plan (and any other security based compensation arrangements of the Corporation) is 10% of the Corporation’s issued and outstanding NAEP Common Shares. In the event of certain change of control events as defined in the Share Option Plan, all outstanding options will become immediately vested and exercisable.

The Share 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 Share Option Plan provides that the Corporation may elect, at its sole discretion, to net settle the option with stock. As of March 31, 2007 there were 2,186,840 NAEP Common Shares issuable upon the exercise of outstanding options, of which 837,352 of such options were vested.

The Share Option Plan provides that, in the event of the termination (with or without cause) or retirement of an optionee, the options held by an optionee cease to be exercisable 30 days after the termination or retirement date, subject to adjustment by the Compensation Committee. The Corporation does not provide financial assistance to participants under the Share Option Plan to facilitate the purchase of securities under the Share Option Plan. Options granted under the Share Option Plan are not transferable by an optionee, except by an optionee’s will or by the laws of descent and distribution. During the lifetime of an optionee, the options are exercisable by only him or her (or, in the case of the optionee’s disability, by his or her legal representative(s), if applicable).

Amendments to the Share Option Plan

The Share Option Plan provides that shareholder and regulatory approval is required in order for the Board of Directors to make certain specified amendments to the Share Option Plan, including (i) any amendment to the number of securities issuable under the Share Option Plan, (ii) any changes in the participants in the plan that have the potential of broadening or increasing insider participation, (iii) the introduction of, or amendments to, any form of financial assistance and (iv) any other amendments that may lead to significant or unreasonable dilution in the Corporation’s outstanding securities or may provide additional benefits to eligible participants, especially to participants who are insiders. The Share Option Plan authorizes the Board of Directors to make other amendments to the plan, subject only to regulatory approval (i.e. without shareholder approval, unless specifically required by applicable law), including (i) amendments of a “housekeeping” nature (i.e. amendments for the purpose of curing any ambiguity, error or omission in the Share Option Plan, or to comply with applicable

law or the requirements of any stock exchange on which the NAEP Common Shares are listed), (ii) any change to the vesting provisions, (iii) any changes in the termination provisions of an option or of the Share Option Plan which does not entail an extension beyond the original expiry date, (iv) a discontinuance of the Share Option Plan and (v) 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.

Option Grants to Named Executive Officers in Fiscal 2007


Name	Number of Securities Underlying Options Granted	Percentage of Total Options Granted to Employees and Directors in Fiscal Year	Exercise Price ($/Security)^(a)	Market Value of Securities Underlying Options on the Date of Grant ($/Security)^(b)	Expiration Date
RODNEY J. RUSTON	—	—	—	—	—
DOUGLAS A. WILKES	100,000	32%	$16.75	$8.09	20-Sep-16
CHRISTOPHER J. HAYMAN	—	—	—	—	—
WILLIAM M. KOEHN	—	—	—	—	—
MILES W. SAFRANOVICH	—	—	—	—	—

(a)	In September 2006, the Corporation had a valuation performed by an unrelated valuation specialist, which valued the NAEP Common Shares at $16.75 per share. The plan and outstanding balances are disclosed in note 25 to the Corporation’s consolidated financial statements for 2007.

(b)

Value estimated using the Black-Scholes option-pricing model. For assumptions used, see note 25 to the Corporation’s consolidated financial statements, a copy of which can be found on the Canadian Securities Administrators’ System for Electronic Document Analysis and Retrieval (SEDAR) database at www.sedar.com.

Aggregated Option Exercises in Fiscal 2007 and Fiscal Year End Option Values


Name	Securities Acquired on Exercise (#)	Aggregate Value Realized ($)	Unexercised Options at March 31, 2007 Exercisable/Unexercisable (#)	Value of Unexercised in-the-Money Options at March 31, 2007 Exercisable/ Unexercisable^(a) ($)
RODNEY J. RUSTON	—	—	110,000/440,000	$	2,090,000/$8,360,000
DOUGLAS A. WILKES	—	—	—/100,000	$	—/$725,000
CHRISTOPHER J. HAYMAN	—	—	32,000/68,000	$	608,000/$1,292,000
WILLIAM M. KOEHN^(b)	—	—	60,000/40,000	$	1,140,000/$760,000
MILES W. SAFRANOVICH	—	—	32,000/68,000	$	608,000/$1,292,000

(a)	March 31, 2007 option values are determined using the Friday, March 30, 2007 closing price on the Toronto Stock Exchange.

(b)	William M. Koehn resigned from the Corporation effective July 31, 2007.

Employment Contracts and Termination of Employment

The Corporation has an employment agreement with Rodney Ruston, its President and Chief Executive Officer. The initial term of Mr. Ruston’s employment is five years, beginning May 2005, unless earlier terminated. If his employment is terminated by the Corporation without cause or if his employment is not renewed at the end of the initial five year term, Mr. Ruston will receive a severance payment equal to his then- annual salary plus the amount of his bonus payment in the year preceding the termination date. The arrangement provides for a $500,000 annual salary, to be reviewed annually by the Board of Directors, plus an initial grant of options to purchase 550,000 NAEP Common Shares, with an exercise price of $5 per NAEP Common Share and subject to vesting at the rate of 20% per year. During the term of the agreement, Mr. Ruston is eligible for an

annual cash bonus of up to 100% of his annual salary upon achievement of performance targets approved by the Board, receives a monthly vehicle allowance of $800, receives reimbursement of the annual fee for membership in one health or sports club and receives an annual travel allowance of $25,000 to cover the costs of traveling to and from his home country of Australia.

The Corporation also has an employment agreement with each of Douglas Wilkes, Vice President, Finance and Chief Financial Officer, Christopher Hayman, Vice President, Supply Chain and Miles Safranovich, Vice President, Business Development and Estimating.

In each case, the executive officer’s employment will continue until terminated by him or by the Corporation in accordance with the provisions of his respective agreement. In the cases of each of Messrs. Wilkes, Hayman and Safranovich, if his employment is terminated by the Corporation without cause, he will receive a payment equal to one year annual base salary if terminated on or prior to his fifth anniversary of employment with the Corporation or one of its predecessors, a payment equal to one and a quarter times his annual base salary if terminated after his fifth anniversary but on or before his tenth anniversary or a payment of one and a half times his annual base salary if terminated after the tenth anniversary of employment with the Corporation or one of its predecessors plus a payment equal to 90% of the amount of his target bonus payment for the current fiscal year pro rated to the date of termination.

These agreements provide for an annual salary of $250,000 for Mr. Wilkes, $212,800 for Mr. Hayman and $224,000 for Mr. Safranovich, each to be reviewed annually by the Compensation Committee, plus an initial grant of options to purchase 100,000 common shares, subject to vesting at the rate of 20% per year and with an exercise price of $5.00 per share, except in the case of Mr. Wilkes whose options have an exercise price of $16.75 per share.

During the term of the agreement, each executive officer is eligible for an annual cash bonus of up to 100% of his annual salary upon achievement of performance targets approved by the Board of Directors, receives a monthly vehicle allowance of $800 and receives reimbursement of the annual fee for membership in one club or an allowance for similar expenditures. In addition, Mr. Wilkes was provided a serviced apartment for four months after his commencement date and receives reimbursement for reasonable travel expenses between Vancouver and Edmonton weekly through December 31, 2007 and every other week from January 1, 2008 through December 31, 2009.

Each executive officer has agreed that, for a period of two years after the termination of his respective employment, regardless of the reason for the cessation of such employment, he will not interfere with the employment of or attempt to hire any of the Corporation’s employees or consultants.

The Corporation had an employment agreement with William Koehn; however, Mr. Koehn resigned from the Corporation effective July 31, 2007. Mr. Koehn’s employment agreement provided for an annual salary of $249,000 and contained terms and provisions similar to those in the employment contracts with each of Messrs. Wilkes, Hayman and Safranovich described above. As of the date of Mr. Koehn’s resignation, he was entitled to exercise 60,000 options to purchase NAEP Common Shares with an exercise price of $5.00 per NAEP Common Share. At Mr. Koehn’s request, the Corporation agreed to amend the terms of his share option agreement to provide that, in the event that he was subject to a lock-up agreement which prevented him from exercising his options which he would otherwise be entitled to exercise, Mr. Koehn would be entitled to exercise his options until the date that was 30 days following the end of such lock-up period. Forming part of Mr. Koehn’s resignation agreement and in exchange for certain considerations to the Corporation, Mr. Koehn’s option agreement was amended such that he will be eligible to receive the remaining 40,000 of his original 100,000 options vesting on March 31, 2009 and exercisable until the day that is 90 days after March 31, 2009.

A copy of the employment agreements for each of Messrs. Koehn, Ruston, Safranovich, Wilkes and Hayman can be accessed at www.sedar.com.

Composition of the Compensation Committee

The Compensation Committee is currently composed of Messrs. Brussa, Oehmig, Paterson and Sello, with Mr. Paterson serving as Chairman. None of the members of the Compensation Committee is or has been an officer or employee of the Corporation, and none of the executive officers of the Corporation served during fiscal 2007 on a board of directors of another entity which has employed any of the members of the Compensation Committee.

REPORT ON EXECUTIVE COMPENSATION

The Compensation Committee is responsible for reviewing and recommending the Corporation’s compensation philosophy and guiding principles. The Compensation Committee reviews and recommends for approval to the Board the adequacy and form of compensation for executive management, including the Chief Executive Officer, as well as the levels and types of benefits granted to executive management, including any material special benefits or perquisites. The Compensation Committee also reviews and recommends upon bonus and incentive plans, annual general salary increases, share option plans and director compensation. The Compensation Committee may review any and all aspects of total compensation at its discretion; however, a formal review is undertaken annually with base salary adjustments and short-term bonus payments processed in July of each year. Short-term bonuses awarded and paid out in July 2007 were for the achievement of results in fiscal 2007.

Compensation Principles

The Compensation Committee’s executive compensation philosophy is premised upon three objectives:

(i)

recruitment and retention of the best available executive leadership;

(ii)

performance and accountability of executives; and

(iii)

alignment of shareholder and executive interests.

Recruitment & Retention

The Compensation Committee recognizes the highly competitive market for talented executives in Alberta as a result of the continued economic prosperity and growth of the Alberta economy, particularly in the energy sector. Accordingly, the Compensation Committee has recommended a market competitive total executive compensation package consisting of base salary with annual increases based on performance, short-term bonus with a target payout of 100% of base salary based on actual results compared to the Corporation’s planned EBITDA performance and specific divisional and personal metrics, long-term incentives consisting of stock option grants and a perquisite program providing a vehicle allowance and club membership or equivalent consideration. The Compensation Committee is committed to ensuring that the Corporation’s compensation plans are market competitive and, as such, commissioned a review by third-party specialized compensation consultants to evaluate the Corporation’s total compensation against that of leading corporations within Alberta in the industries in which the Corporation operates (the “Comparator Group”). With respect to long-term incentive plans (namely, the Share Option Plan) and compensation for directors, the Committee also utilizes specialized compensation consultants to assist with the structure and design of these plans.

Performance & Accountability

The Compensation Committee believes that executive compensation should be correlated to performance, as the financial vitality of the business is dependent upon the results achieved by the executives, the key decision-makers of the Corporation. Thus, the annual Management Incentive Plan (the “MIP”), which is discussed further below, was introduced in 2006 with the key underlying principle of ensuring that executives are held accountable to stakeholders by measuring the performance of the Corporation against the EBITDA forecast in the approved annual budget.

Alignment of Executive and Shareholder Interests

It is in the Corporation’s best interests to meet shareholder expectations and ensure continued access to capital on favourable terms. Accordingly the MIP was designed to ensure that the continued profitability of the Corporation results in increased financial reward for shareholders and executives alike. Executives are rewarded through the MIP based on three criteria: (i) organizational performance; (ii) divisional performance; and (iii) individual performance. The Chief Executive Officer is rewarded through the MIP based on two criteria: (i) organizational performance and (ii) individual performance. This approach ensures that the role of the individual within the team is appropriately recognized. The MIP is a key mechanism utilized in realizing the compensation principles, particularly the latter two. The MIP remuneration structure for fiscal 2007 is set out below:


Management Level	Company Performance	Business Unit or Divisional Performance	Individual Performance	Proportion Of Salary Payable At Target
Chief Executive Officer	80%	—	20%	100%
Operational VPs	60%	20%	20%	100%
Non-Operational VPs	65%	15%	20%	100%

As the Corporation continues to grow rapidly and the divisions become larger, with more projects and more people, there is a need to further adjust variable pay to align and direct the focus of leadership effort more toward divisional performance based on preset and division specific Key Performance Indicators (“KPIs”) and key projects, and continue the Corporation’s current level of incentive for individual performance targeted at personal and team development. The Compensation Committee has recommended the following MIP structure for fiscal 2008:


Management Level	Company Performance	Business Unit or Divisional Performance	Individual Performance	Proportion Of Salary Payable At Target
Chief Executive Officer	70%	—	30%	100%
Operational VPs	50%	30%	20%	100%
Non-Operational VPs	50%	30%	20%	100%

The Corporation’s KPI is based on total Company EBITDA, while business unit and divisional KPIs are selected measures specific to a division based on key business drivers of that division examples of which include production efficiencies, equipment utilization and safety. Individual KPIs are related to the development of the team and development of key individuals within the division.

Compensation Structure

The compensation of executives, excluding the Chief Executive Officer, is based on three key components:

Base Salary

The Compensation Committee will review and recommend to the Board on the adequacy and form of base salaries for executive management.

Fiscal 2007 base salaries for executive management were reviewed and approved by the Compensation Committee. The Chief Executive Officer provided his recommendations to the Compensation Committee for base salary adjustments for each executive, excluding himself, within a specified range, based on the performance of each executive. The base salary ranges were determined by salary data from a market study conducted by specialized compensation consultants. The consultants conducted market research comparing the Corporation’s base salaries within the total compensation framework to that of a selected comparator group of corporations.

Fiscal 2007 base salary was adjusted effective July 1, 2006 for Mr. Koehn from $240,000 to $252,000, for Mr. Safranovich from $200,000 to $224,000 and for Mr. Hayman from $190,000 to $212,800.

Short-Term Incentives (“STI”)

The Compensation Committee will review and approve the adequacy and form of STIs for executive management.

The framework for STI for executive management, also known as the MIP, is described above in “Alignment of Executive and Shareholder Interests”. The Compensation Committee approved MIP payments in July 2007 upon the recommendations made by the Chief Executive Officer based on corporate, divisional and individual results achieved by the following executives in fiscal 2007. MIP payments were made in the amount of $142,361 for Mr. Wilkes, $92,577 for Mr. Koehn, $164,355 for Mr. Safranovich and $150,313 for Mr. Hayman.

Long-Term Incentive Plan (“LTIP”)

The Compensation Committee will review and recommend to the Board on the adequacy and the form of LTIP for executive management.

The Corporation’s LTIP (namely, the Share Option Plan) that was put in place prior to the IPO has remained in place; however, no new options were granted since the time of the IPO, except to new management employees. A new LTIP is being considered by the Board of Directors and management of the Corporation, with features that are more appropriate for a public issuer. Based on the results of the study and market review conducted by the Corporation’s third-party consultant into the Comparator Group total compensation, the Compensation Committee believes that there is an increasing trend within the Comparator Group toward the utilization of LTIPs and/or retention programs. Consequently, the Compensation Committee directed management to develop an LTIP for launch in the second quarter of fiscal 2008. Management will utilize total compensation data supplied by the compensation consultants, together with the design capability of the consultants to develop the LTIP.

Chief Executive Officer Compensation

The Compensation Committee reviews and recommends to the Board of Directors on the Chief Executive Officer’s position description and the position’s annual goals and objectives. The Chief Executive Officer’s base compensation and short-term bonus is evaluated annually by the Compensation Committee based on an assessment of performance.

On July 16, 2006, the Compensation Committee recommended, and the Board of Directors approved, two changes to the structure of the Chief Executive Officer’s compensation to more closely align the interests of the Chief Executive Officer with those of NAEP Shareholders. These two changes were: (i) a 16% base salary decrease from the fiscal 2006 base salary of $625,000 to $525,000 (these amounts include a $25,000 travel allowance); and (ii) a corresponding increase to the short-term bonus eligibility for fiscal 2007 from 50% to 100% of base salary (excluding travel allowance). A short-term bonus payment for fiscal 2007, recommended by the Compensation Committee and approved by the Board of Directors, for the Chief Executive Officer was processed on July 20, 2006, such bonus in the amount of $386,615.

Report Presented by the Compensation Committee:

John Brussa

William Oehmig

Richard Paterson (Chairman)

Allen Sello

PERFORMANCE GRAPH

The following graph compares the percentage change in the cumulative NAEP Shareholder return for $100 invested in NAEP Common Shares at the IPO of $18.38 for each NAEP Common Share with the total cumulative return of the S&P/TSX Composite Index for the period from November 22, 2006 to March 31, 2007. On March 30, 2007, the NAEP Common Shares closed at $24.00 per NAEP Common Share on the TSX.

LOGO

The following table shows the value of $100 invested in NAEP Common Shares on November 22, 2006 compared to $100 invested in the S&P/TSX Composite Index*:


For the Financial Years Ended:	November 22, 2006		March 31, 2007
North American Energy Partners Inc.	$	100.00	$	130.58
S&P/TSX Composite Index	$	100.00	$	101.05

*	Assuming reinvestment of dividends/distributions.

COMPENSATION OF DIRECTORS

The Corporation’s directors, other than Messrs. McIntosh and Ruston, each receive an annual aggregate retainer of $32,500 and a fee of $1,500 for each meeting of the Board of Directors or any committee of the Board that they attend, and are reimbursed for reasonable out-of-pocket expenses incurred in connection with their services pursuant to the Corporation’s policies. The Chair of the Corporation’s audit committee receives an additional annual retainer of $10,000. Mr. McIntosh, the Chairman of the Board received a retainer from April 1, 2006 to July 1, 2006 paid at a rate of $150,000 per annum. From July 1, 2006 to March 31, 2007, Mr. McIntosh received a retainer paid at a rate of $157,500 per annum. In addition, Mr. McIntosh received bonuses of $205,000 in June 2005, $163,733 in July 2006 and $106,543 in March 2007. Mr. Ruston does not receive director compensation.

In addition, the Corporation’s directors have received grants of stock options under the 2004 Share Option Plan. Effective November 2003, each director, excluding Messrs. Brokaw, Tomsett, McIntosh, Paterson, Sello and Ruston, received options to purchase 27,760 NAEP Common Shares. Mr. McIntosh received options to acquire 70,000 NAEP Common Shares in May 2004, Mr. Paterson received options to purchase 27,760 NAEP Common Shares in November 2005, Mr. Sello received options to purchase 27,760 NAEP Common Shares in February 2006 and Mr. Brokaw received options to purchase 27,760 NAEP Common Shares in June 2006. All the options have an exercise price of $5 per share, vest at the rate of 20% per year over five years and expire ten years after their grant date. The vesting of the options granted to Messrs. Brokaw and Paterson has been accelerated as if they had been issued effective November 2003. Mr. Tomsett was granted options to acquire 27,760 NAEP Common Shares in September 2006. These options have an exercise price of $16.75 per share, vest at the rate of 20% per year over five years and expire ten years after their grant date.

On June 29, 2006, NACG Holdings Inc., the predecessor to the Corporation, offered each director holding stock options, excluding Messrs. McIntosh and Ruston, the option to have all of his options become immediately exercisable on the condition that he exercise all such options by September 30, 2006. One director, Mr. Oehmig, accepted this option. The stock options of the other directors remained unchanged.

Directors’ and Officers’ Insurance

The Corporation maintains directors’ and officers’ insurance for an aggregate amount of $25,000,000. The policy provides primary coverage of $10,000,000 for the one-year period from June 1, 2007 to June 1, 2008 at a premium of $138,000 and a deductible of $500,000. An excess layer of coverage for $10,000,000 has also been purchased at a premium of $90,000 for the one-year period from June 1, 2007 to June 1, 2008. The excess layer does not have a deductible. There is also a second excess layer of coverage for $5,000,000, which has been purchased at a premium of $33,750 for the one-year period from June 1, 2007 to June 1, 2008, and for which there is no deductible.

Indemnification

The Corporation has entered into indemnity agreements with its directors and officers, whereby it has agreed to indemnify its directors, officers and certain other employees from all liabilities, obligations, charges and expenses, reasonably incurred by such director, officer or other employee in respect of any civil, criminal, investigative, administrative action or other proceeding in which such individual is involved by reason of being or having been a director, officer or employee of the Corporation (or a direct or indirect affiliate) of the Corporation, provided that (i) he or she acted honestly and in good faith with a view to the best interests of the Corporation, or (ii) in the case of a criminal or administrative action or proceeding that is enforced by a monetary penalty, he or she had reasonable grounds for believing that his conduct was lawful, and (iii) in the case of an action by or on behalf of the Corporation or other entity to procure a judgment in its favour, the Corporation obtains any approval required under the Canada Business Corporations Act in respect of such indemnification.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

Plan Category

Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights

(a)

Figure in column
(a) as a
percentage of
issued and
outstanding
NAEP Common
Shares

(b)

Weighted-
average
exercise
price of
outstanding
options,
warrants
and rights

(c)

Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding
securities reflected
in column (a))^(A)

(d)

Figure in column
(d) as a
percentage of
issued and
outstanding
NAEP Common
Shares

(e)

Equity compensation plans approved by securityholders

2,186,840

6.12%

$6.03

1,332,386

3.73%

Equity compensation plans not approved by securityholders

N/A

Total

2,186,840

6.12%

$6.03

1,332,386

3.73%

(A)

The Share Option Plan states that the Compensation Committee may issue options, provided that the aggregate number of NAEP Common Shares that may be issued from treasury under the plan may not exceed 10% (representing as of August 13, 2007, 3,575,206 NAEP Common Shares) of the number of issued and outstanding NAEP Common Shares on a non-diluted basis immediately prior to the proposed option issuance.

INDEBTEDNESS OF DIRECTORS AND OFFICERS

None of the directors or officers of the Corporation had any outstanding indebtedness to the Corporation or any of its subsidiaries during fiscal 2007 or as at the date hereof.

INTEREST OF INFORMED PERSONS IN MATERIAL TRANSACTIONS

No director or executive officer of the Corporation at any time since the beginning of the Corporation’s last completed financial year, no proposed nominee for election as a director nor any associate or any affiliate of any such director, officer or nominee, has any material interest, direct or indirect, by way of beneficial ownership of securities or otherwise, in any matter to be acted upon at the Meeting, except as disclosed below. Furthermore, no informed person (as such term is defined under applicable securities laws), proposed nominee for election as a director of the Corporation or any associate or affiliate of any informed person or proposed nominee has or had a material interest, direct or indirect, in any transaction since the beginning of the Corporation’s last financial year or in any proposed transaction which has materially affected or would materially affect the Corporation or any of its subsidiaries or affiliates, except as disclosed below.

Certain Selling Shareholders

Certain of the Corporation’s shareholders sold NAEP Common Shares in (i) the Corporation’s initial public offering and secondary offering in November, 2006 (the “IPO”), as more particularly described in the Corporation’s prospectus dated November 21, 2006 (the “IPO Prospectus”) in connection with such offering and (ii) the secondary offering of NAEP Common Shares in August, 2007 (the “2007 Offering”), as more particularly described in the Corporation’s short form prospectus dated July 31, 2007 (the “2007 Prospectus”) in connection with such offering. The shareholders of the Corporation who sold NAEP Common Shares in the IPO and in the 2007 Offering sold, as a group, an aggregate of 4,437,500 NAEP Common Shares in the IPO (including the over-allotment option in connection therewith) and 8,358,604 NAEP Common Shares in the 2007 Offering (including the over-allotment option in connection therewith). Certain of the Corporation’s directors are affiliated with the Selling Shareholders, as more particularly described in the IPO Prospectus and the 2007 Prospectus, copies of which can be accessed at www.sedar.com.

Advisory Services Agreement

For purposes of this section, a reference to the “Corporation” refers to a reference to North American Energy Partners Inc., any predecessor corporation, and its direct and indirect affiliates. The Corporation was party to an advisory services agreement, dated November 21, 2003, with The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc., and SF Holding Corp., referred to in the agreement as the “sponsors,” that was terminated in connection with the IPO for aggregate consideration of $2.0 million. Pursuant to the agreement, the sponsors provided certain services to the Corporation, including financial advisory services in connection with corporate financing transactions and business combinations. For additional information, please refer to the IPO Prospectus and the 2007 Prospectus, copies of which can be accessed at www.sedar.com.

Office Leases

The Corporation is a party to lease agreements with Acheson Properties Ltd., a company owned, indirectly and in part, by Martin Gouin, one of the Corporation’s former directors. Mr. Gouin has a 50% beneficial interest in Acheson Properties Ltd. Pursuant to the agreements, the Corporation leases its corporate headquarters in Acheson, Alberta, and its offices in Fort Nelson, British Columbia and Regina, Saskatchewan. For the fiscal years ended March 31, 2007, 2006 and 2005, we paid $571,994, $836,484 and $823,827, respectively, pursuant to these leases. The fiscal 2007 amount represents the lease payments from April 2006 to November 2006, as upon completion of the Corporation’s IPO the lease was no longer a related party transaction. The lease agreements were in place before the Acquisition in November 2003. Management believes the terms of these lease agreements are similar to what would have been obtained from an unaffiliated third-party.

Information Rights Agreements

The Corporation was party to a voting agreement, dated November 26, 2003, with affiliates of the sponsors that terminated upon the completion of the IPO. The Corporation has entered into a letter agreement with each sponsor pursuant to which the Corporation has engaged such sponsor to provide its expertise and advice to the Corporation for no fee. For additional information, please refer to the IPO Prospectus and the 2007 Prospectus, copies of which can be accessed at www.sedar.com.

Shareholders Agreements

All holders of NAEP Common Shares who were also employees of the Corporation or employees of any of the Corporation’s subsidiaries were parties to an employee shareholders agreement prior to the IPO. All other holders of NAEP Common Shares prior to the IPO were parties to an investor shareholders agreement. Both the employee shareholders agreement and the investor shareholders agreement terminated upon the completion of the IPO.

Registration Rights Agreement

The Corporation is a party to a registration rights agreement with certain of the Corporation’s shareholders, including affiliates of each of the sponsors, Paribas North America, Inc. and Mr. William Oehmig, one of the Corporation’s directors. After the IPO, the shareholders party to the agreement and their permitted transferees are entitled, subject to certain limitations, to include their NAEP Common Shares in a registration of NAEP Common Shares the Corporation initiates under the Securities Act of 1933, as amended (the “Securities Act”). In addition, after the 120th day following the IPO, any one or more shareholders party to the agreement has the right to require the Corporation to effect the registration of all or any part of such shareholders’ NAEP Common Shares under the Securities Act, referred to as a “demand registration,” so long as the amount of NAEP Common Shares to be registered has an aggregate fair market value of at least US$5.0 million and, at such time, the SEC has ordered or declared effective fewer than four demand registrations initiated by the Corporation pursuant to the registration rights agreement. In the event the aggregate number of NAEP Common Shares which the

shareholders party to the agreement request the Corporation to include in any registration, together, in the case of a registration initiated by the Corporation, with the NAEP Common Shares to be included in such registration, exceeds the number which, in the opinion of the managing underwriter, can be sold in such offering without materially affecting the offering price of such shares, the number of shares of each shareholder to be included in such registration will be reduced pro rata based on the aggregate number of shares for which registration was requested. The shareholders party to the agreement have the right to require, after four demand registrations, one registration in which their common shares will not be subject to pro rata reduction with others entitled to registration rights.

The Corporation may opt to delay the filing of a registration statement required pursuant to any demand registration for:

•

up to 120 days if the Corporation has (i) decided to file a registration statement for an underwritten public offering of NAEP Common Shares, the net proceeds of which are expected to be at least US$20.0 million, or (ii) initiated discussions with underwriters in preparation for a public offering of NAEP Common Shares as to which the Corporation expects to receive net proceeds of at least US$20.0 million and the demand registration, in the underwriters’ opinion, would have a material adverse effect on the offering or

•

up to 90 days following a request for a demand registration if the Corporation is in possession of material information that it reasonably deems advisable not to disclose in a registration statement.

The Corporation’s right to delay the filing of a registration statement if it possesses information that it deems advisable not to disclose does not obviate any disclosure obligations which it may have under the Exchange Act or other applicable laws; it merely permits the Corporation to avoid filing a registration statement if management believes that such a filing would require the disclosure of information which otherwise is not required to be disclosed and the disclosure of which management believes is premature or otherwise inadvisable.

The registration rights agreement contains customary provisions whereby the Corporation and the shareholders party to the agreement indemnify and agree to contribute to each other with regard to losses caused by the misstatement of any information or the omission of any information required to be provided in a registration statement filed under the Securities Act. The registration rights agreement requires the Corporation to pay the expenses associated with any registration other than sales discounts, commissions, transfer taxes and amounts to be borne by underwriters or as otherwise required by law. Management believes the registration rights agreement, though not negotiated on an arm’s length basis, is on terms comparable to other similar agreements.

Series B Preferred Shares

In connection with the reorganization of the Corporation and its predecessor entities, each holder of Series B preferred shares in the capital of the pre-amalgamation North American Energy Partners Inc., one of the predecessor entities to the Corporation, received 100 NACG Holdings Inc. common shares for each Series B preferred share held. Pursuant to this conversion, the investment entities controlled by the indicated sponsors received the following number of common shares in exchange for their Series B preferred shares:


The Sterling Group, L.P.		2,278,500

Genstar Capital, L.P.		1,650,000

Perry Strategic Capital Inc.		1,650,000

SF Holding Corp.		1,099,700

For additional information on the Series B preferred shares, refer to note 17(a)(iii) in the Corporation’s consolidated financial statements, a copy of which can be accessed at www.sedar.com.

REPORT ON CORPORATE GOVERNANCE PRACTICES

Board of Directors

The National Policy 58-201 – Corporate Governance Guidelines of the Canadian Securities Administrators recommends that boards of directors of reporting issuers be composed of a majority of independent directors. With eight of the nine directors proposed to be nominated considered independent, the Board of Directors is composed of a majority of independent directors. Mr. Ruston is considered to have a material relation with the Corporation by virtue of his executive officer position with the Corporation and is therefore not independent. The remaining directors are independent and the Chairman of the Board, Mr. McIntosh, is an independent director. The Board of Directors has determined that each of the directors, other than Mr. Ruston, is an independent director within the meaning of the rules of the New York Stock Exchange applicable to U.S. domestic listed companies and applicable Canadian securities laws.

In order to facilitate open and candid discussion among the Corporation’s independent directors, the Board holds in-camera sessions which exclude the non-independent director, Mr. Ruston.

Directorships with Other Issuers

Currently, the following directors serve on the boards or act as trustees of other public companies, as listed below:


Name	Name of Reporting Issuer	Exchange	From
RONALD A. MCINTOSH	Advantage Oil & Gas Ltd.^(a)	TSX	September 1998

	C1 Energy Ltd.	TSX	2001

JOHN A. BRUSSA	Penn West Energy Trust	NYSE	April 1995

	Crew Energy Inc.	TSX	July 2003

	Divestco Inc.	TSX	September 2006

	Baytex Energy Ltd. (a wholly owned subsidiary of Baytex Energy Trust)	TSX	July 2003

	BlackWatch Energy Services Ltd. (a wholly owned subsidiary of BlackWatch Energy Services Trust)	TSX	June 2006

	Cirrus Energy Corporation	CDNX	March 2004

	E4 Energy Inc.	CDNX	August 2002

	Endev Energy Inc.	TSX	January 2002

	Enseco Energy Services Corp.	TSX	March 2006

	FET Resources Inc. (a wholly-owned subsidiary of Focus Energy Trust)	CDNX	October 1997

	Flagship Energy Inc.	TSX	May 2005

	Galleon Energy Inc.	TSX	March 2003

	Harvest Operations Corp. (a wholly owned subsidiary of Harvest Energy Trust)	TSX	October 2002

	Highpine Oil & Gas Limited	TSX	February 2000


Name	Name of Reporting Issuer	Exchange	From
	Ontario Energy Savings Corp. (a wholly-owned subsidiary of Energy Savings Income Fund)	CDNX

	Orleans Energy Ltd.	CDNX	February 2001

	Pilot Energy Ltd.	TSX	June 2005

	Progress Energy Ltd. (a wholly owned subsidiary of Progress Energy Trust)	TSX	April 2004

	Rider Resources Ltd.	TSX	November 2000

	Sound Energy Trust (formerly NAV Energy Trust)	TSX	February 2003

	SET Resources (a wholly owned subsidiary of Sound Energy Trust)	TSX	August 2006

	Trafalgar Energy Ltd.	TSX	June 2006
WILLIAM C. OEHMIG	Propex Inc. Panolam Industries International Incorporated	N/A^(b) N/A^(b)	November 2004 September 2005
RICHARD D. PATERSON	Propex Inc.	N/A^(b)	December 2003
ALLEN R. SELLO	Sterling Shoes Income Fund^(c) Infowave Software Inc.	TSX TSX	May 2005 January 2006
PETER W. TOMSETT	Silver Standard Resources Inc. Equinox Minerals Ltd.	TSX TSX	November 2006 July 2007
K. RICK TURNER	Energy Transfer Partners L.P. Energy Transfer Equity, L.P.	NYSE NYSE	February 2004 February 2006

(a)	Advantage Oil & Gas Ltd. is a wholly-owned subsidiary of Advantage Energy Income Fund, an open-ended, unincorporated investment trust established under the laws of the Province of Alberta and created pursuant to a Trust Indenture on April 17, 2001.

(b)	These companies have issued bonds to the public in the United States which are registered with the Securities and Exchange Commission.

(c)	Mr. Sello is a trustee of Sterling Shoes Income Fund and also serves as a director of the general partner of the underlying partnership (Sterling Shoes GP Inc.).

Board and Committee Attendance of Directors

With respect to fiscal 2007, the Board of Directors formally met nine times, the Audit Committee formally met seven times, the Compensation Committee formally met five times the Governance Committee formally met one time, and the Risk Committee formally met four times. Attendance records of the members of the Board of Directors and Committee members with respect to fiscal 2007 were as follows:

Name

Board
Meetings
Attended /
Scheduled

Audit
Committee
Meetings
Attended /
Scheduled

Compensation
Committee
Meetings
Attended /
Scheduled

Governance
Committee
Meetings
Attended /
Scheduled

Risk
Committee
Meetings
Attended /
Scheduled

E.J. ANTONIO^(a)

1/1

DON GETTY^(b)

5/5

2/2^(b)

MARTIN GOUIN^(c)

1/7

GEORGE R. BROKAW

9/9

6/7

4/4

JOHN A. BRUSSA

8/9

2/3^(e)

4/5

1/1

JOHN D. HAWKINS

9/9

7/7

1/1

RONALD A. MCINTOSH

8/9

7/7

2/2^(f)

4/4

WILLIAM C. OEHMIG

8/9

4/5

4/4

RICHARD PATERSON

9/9

5/5

1/1

RODNEY J. RUSTON

7/9

ALLEN R. SELLO

9/9

7/7

4/4^(g)

PETER W. TOMSETT^(d)

6/9

1/1

4/4

K. RICK TURNER

9/9

6/7

1/1

(a)	Mr. Antonio resigned as a director of the Corporation effective June 29, 2006

(b)	Mr. Getty ceased to be a director of the Corporation on November 3, 2006

(c)	Mr. Gouin resigned as a director effective November 28, 2006

(d)	Mr. Tomsett became a director of the Corporation on September 19, 2006

(e)	Mr. Brussa ceased to be a member of the Audit Committee after September 19, 2006

(f)	Mr. McIntosh ceased to be a member of the Compensation Committee after September 19, 2006

(g)	Mr. Sello did not become a member of the Compensation Committee until after June 28, 2006

Mandate of the Board of Directors

The Board of Directors supervises the management of the Corporation’s business as provided by Canadian law and complies with the listing requirements of the New York Stock Exchange applicable to U.S. domestic listed companies, which require that the Board of Directors be composed of a majority of independent directors within one year of the listing of the NAEP Common Shares on the New York Stock Exchange.

Position Descriptions for the Chairman of the Board of Directors and Committee Chairs

The Chairman of the Board of Directors (the “Board Chair”) reports to the Board of Directors and shareholders and provides leadership to the Board of Directors relating to the effective execution of all Board responsibilities. The Board Chair is a non-management director and the Board Chair’s performance will be measured against the effectiveness with which the Board functions, including satisfaction of Board members regarding the functioning of the Board.

Specifically, the Board Chair has the responsibility to, amongst other things:

(a)

provide leadership in ensuring that the Board works harmoniously as a cohesive team;

(b)

facilitate the Board functioning independently of management by ensuring that the Board meets regularly without management and by engaging outside advisors as required;

(c)

provide guidance to the Board and management to ensure that the responsibilities of the Board are well understood by both the Board and management and that the boundaries between Board and management responsibilities are clearly understood and respected;

(d)

attend committee meetings and communicate with directors between meetings as required;

(e)

establish procedures to govern the function of the Board;

(f)

assist the Governance Committee in implementing the Board assessment;

(g)

lead in continuous improvement of Board processes;

(h)

upon the recommendation of the Governance Committee, approach new candidates to serve on the Board;

(i)

represent shareholders and the Board to management and represent management to the Board and shareholders;

(j)

work with the Board and the Chief Executive Officer to ensure that the Corporation is building a healthy governance culture, assist in effective communication between the Board and management, maintain regular contact with the Chief Executive Officer, and serve as advisor to the Chief Executive Officer and other senior officers;

(k)

act as the Chair for annual and special meetings of the shareholders; and

(l)

receive concerns addressed to the Board from stakeholders about the Corporation’s corporate governance, business conduct and ethics or financial practices.

The Chair of each of the Audit Committee, Compensation Committee, Governance Committee and Risk Committee each has the responsibility to (i) provide leadership to the committee and to ensure that each of his or her respective Committees works harmoniously as a cohesive team, (ii) facilitate the Committee functioning independently of management by meeting regularly without management and engaging outside advisors as required, (iii) communicate with Committee members between meetings as required, (iv) facilitate information sharing with other Committees as required, (v) lead in continuous improvement of Committee processes, and (vi) assist in effective communication between the Committee and management. The Chair of each Committee determines the time, place and procedures for the Committee meetings, subject to requirements of the Committee’s charter.

Position Description for the Chief Executive Officer

The Corporation has developed a written position description for the Chief Executive Officer. This description is included in the Compensation Committee Charter as Appendix A. The description provides that the Chief Executive Officer is responsible for the successful management of the business and affairs of the Corporation and has the responsibility to:

(a)

report to and work with the Board of Directors so that it may fulfill its oversight role;

(b)

advise the Board of Directors in a timely manner of major issues and risks that may affect the Corporation;

(c)

recommend to the Board the strategic direction of the Corporation and implement approved operational and business plans;

(d)

provide the overall leadership, direction and management of the business operations to achieve the Corporation’s goals and objectives;

(e)

allocate financial and human capital for the successful management and financial performance of the Corporation;

(f)

foster a culture of integrity and set the ethical tone for the Corporation;

(g)

establish the policies and procedures to effectively operate the Corporation in an efficient and controlled manner;

(h)

monitor and manage the risks of the Corporation;

(i)

recommend to the Board any acquisition, merger, divestiture and the entry or exit of any business unit of the Corporation;

(j)

establish the corporate structure and major accountabilities;

(k)

oversee the relationship between the Corporation and the public;

(l)

develop, supervise and evaluate the executive officers and recommend to the Compensation Committee the selection and compensation of executive officers; and

(m)

identify potential successors for the positions of Chief Executive Officer and develop a succession plan for executive management.

Orientation and Continuing Education

Management encourages the directors to attend relevant education and development opportunities to improve their skills and abilities to carry out the role as a director at the Corporation. Expenses associated with attendance at seminars, conferences and education sessions and/or membership to the Institute of Corporate Directors are reimbursed by the Corporation.

Management has provided two sources of training and industry seminars which have been placed on the director extranet site and are updated regularly:

Industry Conferences – Management updates this list as conferences are scheduled.

Access to the Institute of Corporate Directors website – This website offers current information for directors and a variety of development opportunities.

Code of Conduct and Ethics Policy

In order to ensure that directors exercise independent judgment and to encourage and promote ethical standards and behaviour, the Board of Directors has a written Code of Conduct and Ethics Policy (the “Code”) setting out general statements of conduct and ethical standards to be followed by all of the Corporation’s personnel. A copy of the Code may be obtained at the Corporation’s website at www.naepi.ca.

In order to ensure compliance with the Code, the Board of Directors and the Corporation have implemented an ethics reporting policy (the “Reporting Policy”), a copy of which may be obtained at the Corporation’s website at www.naepi.ca. The objectives of the Reporting Policy are to (i) provide a means of reporting non-compliance with the Code and (ii) to comply with the Sarbanes Oxley Act and securities regulations. Under the Reporting Policy, the Corporation’s personnel are required to report any conduct which they believe, in good faith, to be a violation or apparent violation of the Code. The Corporation keeps the identity of the person making the report for every reported violation confidential, except as otherwise required by law, and a copy of all reported violations are confidential until action is taken to correct the violation, at which time the violation may become known (but not the identity of the individual filing the report). The Policy further provides that there is not to be any retaliation against the reporter.

The Corporation has the option to report violations of the Code either internally or externally in the following ways:

(a)

internal reporting is through a supervisor, the Corporation’s executive or its Board of Directors and its Committees;

(b)

effective anonymous reporting is through an independent ethics reporting firm; or

(c)

directly to the Chairman of the Board or Audit Committee Chair.

In all cases there are two reviewers for each reported violation, which ensures an effective independent review and a control over segregation of reviewing responsibility to ensure that reported violations are investigated appropriately and thoroughly. For serious violations of the Code, the Audit Committee Chair or the Board Chair will be advised immediately of the reported violation. All reported violations are summarized and provided to the Audit Committee at least quarterly. The Audit Committee Chair and the Board Chair will have access, at all times, to the status and content of Reported Violations.

The Code provides additional safeguards to ensure that directors exercise independent judgment in considering transactions and agreements in respect of which a director or executive officer has a material interest by requiring that all personnel avoid any activity which creates or gives the appearance of a conflict of interest between an individual’s personal interests and the Corporation’s interests. Specifically, the Code provides that, unless a waiver is granted, no personnel shall (i) seek or accept any personal loan or guarantee of any obligation or services from any outside business, (ii) act as a consultant or employee of or otherwise operate an outside business if the demands of the outside business would interfere with the employee’s responsibilities to the Corporation, (iii) conduct business on behalf of the Corporation with a close personal friend or immediate family member, (iv) take for themselves opportunities that arise through the use of the Corporation’s property or information or through their position within the Corporation.

Nomination of Directors

Please see section captioned “Governance Committee” below.

Compensation Determination

Please see section captioned “Compensation Committee” below.

Committee and Director Assessments

Given the Corporation’s recent IPO, the Corporation is in the process of conducting Committee and Board effectiveness assessments. These assessments will be completed in fiscal 2008.

BOARD COMMITTEES

Audit Committee

The Audit Committee has full and unrestricted access to the Corporation’s internal finance department to review issues as appropriate and meets directly with the external auditors of the Corporation on a regular basis. The Audit Committee monitors the integrity of the Corporation’s financial information and monitors the system of internal controls over financial reporting. The Audit Committee also recommends independent public accountants to the Board, oversees the work of the external auditor, reviews the quarterly and annual financial statements and associated audit reports and reviews the fees paid to the Corporation’s auditors. The Audit Committee reviews the audit findings report, approves quarterly financial statements and recommends annual financial statements for approval to the Board. The Corporation complies with Rule 10A-3 under the Securities Exchange Act of 1934 (the “Exchange Act”), as amended, and the listing requirements of the New York Stock Exchange and the requirements of the Canadian securities regulatory authorities that require that the Corporation’s Audit Committee be composed solely of independent directors within one year of the effectiveness date of the registration statement. One member of the Audit Committee is designated as the audit committee financial expert, as defined by Item 401(h) of Regulation S-K of the Exchange Act. The Board of Directors has adopted a written charter for the Audit Committee that is available on the Corporation’s website and which can be accessed at www.sedar.ca. The Audit Committee is currently composed of Messrs. Brokaw, Hawkins, McIntosh, Sello and Turner, with Mr. Sello serving as Chairman.

For the fiscal years ended March 31, 2007 (“fiscal 2007”) and March 31, 2006, the Corporation incurred the following fees for the services of KPMG:

Audit Fees

The aggregate fees billed by KPMG, the Corporation’s independent auditor, for the fiscal years ended March 31, 2007, 2006 and 2005, for professional services rendered by KPMG for the audit of the Corporation’s annual financial statements, related audit work in connection with registration statements and other filings with various regulatory authorities, and quarterly interim reviews of the consolidated financial statements or services that are normally provided by KPMG in connection with statutory and regulatory filings or engagements for such fiscal years, were $2,375,000, $2,617,000 and $1,330,000, respectively.

Audit Related Fees

The aggregate fees billed by KPMG for the fiscal years ended March 31, 2007, 2006 and 2005, for planning and scoping work and advice relating to compliance and internal controls over financial reporting were $52,000, $62,000 and $31,000, respectively.

Tax Fees

The aggregate fees billed by KPMG for the fiscal years ended March 31, 2007, 2006 and 2005, for tax compliance services were $16,640, $15,000 and $25,000, respectively.

All Other Fees

KPMG did not perform any other services for the Corporation.

Recommendation of the Board of Directors

The Board of Directors recommends a vote “for” the re-appointment of KPMG as independent auditors of the Corporation for the fiscal year ending March 31, 2008 and authorizing the Board of Directors to fix the auditor’s remuneration.

Compensation Committee

The Corporation has engaged the services of specialized compensation consultants to assist in developing the appropriate total compensation philosophy and structure and to assist management in the development of the various programs within our Compensation framework. The Corporation engaged the services of these consultants to perform studies of the market comparator group of corporations to evaluate the NAEP total compensation and to make recommendations. The Corporation also engaged the services of compensation consultants to assist NAEP in developing a new long-term incentive plan for fiscal 2008 and to assist with director compensation. The Compensation Committee is responsible for supervising executive compensation policies for the Corporation and its subsidiaries, administering the employee incentive plans, reviewing officers’ salaries, approving significant changes in executive employee benefits and recommending to the Board such other forms of remuneration as it deems appropriate. The Corporation complies with the listing requirements of the New York Stock Exchange applicable to U.S. domestic listed corporations that require the Corporation’s Compensation Committee be composed of a majority of independent directors within 90 days of the listing of the Corporation’s common shares on the New York Stock Exchange and that it be composed solely of independent directors within one year of such listing. The Corporation’s Board of Directors has adopted a written charter for the Compensation Committee that is available on the Corporation’s website (www.naepi.ca). The Compensation Committee is currently composed of Messrs. Brussa, Oehmig, Paterson and Sello, with Mr. Paterson serving as Chairman.

Governance Committee

The Governance Committee is responsible for recommending to the Board of Directors proposed nominees for election to the Board of Directors by the shareholders at annual meetings, including an annual review as to the renominations of incumbents and proposed nominees for election by the Board of Directors to fill vacancies that occur between shareholder meetings, and making recommendations to the Board of Directors regarding corporate governance matters and practices. The Corporation complies with the listing requirements of the New York Stock Exchange applicable to domestic listed corporations that require the Corporation to establish a nominating and corporate governance committee composed of a majority of independent directors within 90 days of the listing of the Corporation’s common shares on the New York Stock Exchange and that it be composed solely of independent directors and have at least three members within one year of such listing. The Corporation’s Board of Directors has adopted a written charter for the Governance Committee that is available on the Corporation’s website. The Governance Committee is currently composed of Messrs. Brussa, Hawkins, Paterson, Tomsett and Turner, with Mr. Tomsett serving as Chairman.

Risk Committee

The Risk Committee is responsible for overseeing all of the Corporation’s non-financial risks, approving the Corporation’s risk management policies and reviewing the risks and related risk mitigation plans within the Corporation’s strategic plan. The Risk Committee is currently composed of Messrs. Brokaw, McIntosh, Oehmig and Tomsett, with Mr. Oehmig serving as Chairman.

The Board may also establish other committees.

ADDITIONAL INFORMATION

Copies of the following documents are available upon written request to the Secretary of the Corporation at North American Energy Partners Inc., Zone 3, Acheson Industrial Area, 2-53016 Highway 60, Acheson, Alberta T7X 5A7:

(i)

the 2007 Annual Report to Shareholders containing the audited consolidated financial statements for the year ended March 31, 2007 together with the accompanying Auditor’s Report and the Annual MD&A;

(ii)

this Information Circular; and

(iii)

the 2007 Annual Information Form, as amended.

Additional information relating to the Corporation can be found on the Canadian Securities Administrators’ System for Electronic Document Analysis and Retrieval (SEDAR) database at www.sedar.com and the website of the Securities and Exchange Commission at www.sec.gov. Financial information of the Corporation is provided in the Corporation’s comparative financial statements and Annual MD&A for the Corporation’s most recently completed financial year.

GENERAL

All matters referred to herein for approval by NAEP Shareholders require a simple majority of the NAEP Shareholders voting at the Meeting, whether in person or by proxy. Except where otherwise indicated, information contained herein is given as of the date hereof.

APPROVAL OF PROXY CIRCULAR

The undersigned hereby certifies that the contents and the distribution of this Information Circular have been approved by the Board of Directors of the Corporation.

DATED at Acheson, Alberta, this 17^th day of August, 2007.

(signed) “Douglas A. Wilkes”

Chief Financial Officer

LOGO

NORTH AMERICAN ENERGY PARTNERS INC.

PROXY

THIS PROXY IS TO BE USED IN CONNECTION WITH THE

ANNUAL MEETING OF SHAREHOLDERS

TO BE HELD ON SEPTEMBER 19, 2007

This proxy is solicited by and on behalf of management of North American Energy Partners Inc. (the “Corporation”) and should be read in conjunction with the accompanying management information circular of the Corporation dated August 17, 2007 (the “Information Circular”). The undersigned holder of common shares in the capital of the Corporation hereby appoints Douglas Wilkes, or failing that person, Rodney Ruston, or instead of either of them , as proxy, with power of substitution, to attend, vote all such shares held by the undersigned and otherwise act for and on behalf of the undersigned at the annual meeting of shareholders of the Corporation (the “Meeting”) to be held at The Westin Edmonton Hotel, 10135-100^th Street, Edmonton, Alberta, T5J 0N7 on September 19, 2007 commencing at 4:00 p.m. (Mountain Time) and at any adjournment thereof, to the same extent and with the same power as if the undersigned were personally present at the Meeting or such adjournment or adjournments thereof and, without limiting the generality of the power hereby conferred, the person(s) named above is specifically directed as indicated below with respect to those shares registered in the name of the undersigned.

Without limiting the general powers hereby conferred, the undersigned hereby directs the said proxyholder to vote the shares represented by this instrument of proxy in the following manner:

1. FOR ¨ or WITHHOLD FROM VOTING FOR ¨ the election of directors as specified in the Information Circular in connection with the Meeting; and

2. FOR ¨ or WITHHOLD FROM VOTING FOR ¨ the appointment of KPMG LLP, Chartered Accountants, as auditors of the Corporation for the ensuing year and the authorization of the directors to fix their remuneration as such.

This Proxy is solicited on behalf of the Management of the Corporation. The shares represented by this Proxy will be voted and, where the shareholder has specified a choice with respect to the above matters, will be voted as directed above or, if no direction is given, will be voted FOR each of the above matters.

Every shareholder has the right to appoint some other person or company of their choice, who need not be a shareholder, to attend and act on their behalf at the Meeting. If you wish to appoint a person or company other than the persons whose names are printed herein, please insert the name of your chosen proxyholder in the space provided above.

If any amendments or variations to the matters above referred to or to any other matters identified in the Notice of Meeting are proposed at the Meeting or any adjournment thereof or if any other matters which are not now known to Management should properly come before the Meeting or any adjournment thereof, this Proxy confers discretionary authority on the person voting the Proxy to vote on such amendments or variations or such other matters in accordance with the best judgment of such person.

The securities represented by this Proxy will be voted or withheld from voting, in accordance with the instructions of the shareholder, on any ballot that may be called for and, if the shareholder has specified a choice with respect to any matter to be acted on, the securities will be voted accordingly; however, if such a direction is not made in respect of any matter, this Proxy will be voted for each of the matters referred to in the Proxy.

To be effective, a Proxy must be received by CIBC Mellon Trust Company at Proxy Dept., CIBC Mellon Trust Company, P.O. Box 721, Agincourt, Ontario M1S 0A1 (facsimile no. (416) 752-8239) no later than 4:30 p.m. (Mountain Time) on September 17, 2007 and if the Meeting is adjourned, no later than 24 hours (excluding Saturdays and holidays) prior to the commencement of any adjournment thereof.

This Proxy supersedes and revokes any proxy previously given in respect of the Meeting.

DATED this day of , 2007.



				Signature of Shareholder or officer of Shareholder



				Name of Shareholder (please print)

* * *

SEE NOTES ON FOLLOWING PAGE

NOTES

This Proxy must be signed by the shareholder or the shareholder’s attorney authorized in writing. If the shareholder is a corporation, this Proxy must be signed by the duly authorized officer, attorney or other authorized signatory of the shareholder. A person signing on behalf of a shareholder must provide, with this Proxy, satisfactory proof of such person’s authority and must indicate the capacity in which such person is signing.

2.	If the securities are registered in the name of more than one owner (for example, joint ownership, trustees, executors, etc.), then all those registered should sign this Proxy.

3.	This Proxy should be signed in the exact manner as the name appears on the Proxy.

4.	If this Proxy is not dated, it will be deemed to bear the date on which it is mailed by Management to the shareholder.

LOGO

Dear Shareholder:

As a beneficial owner or registered holder of shares of North American Energy Partners Inc. you are entitled to receive interim financial statements and annual financial statements (including the related Management’s Discussion and Analysis). If you wish to receive interim financial statements and/or annual financial statements for the current financial year ending March 31, 2007, please complete and return this letter by mail. Your name will then be placed on the Supplemental Mailing List maintained by our Transfer Agent and Registrar, CIBC Mellon Trust Company.

As long as you remain a shareholder you will receive a letter like this each year and will be required to renew your request to receive financial statements for the applicable financial year. If you have any questions about this procedure, please contact CIBC Mellon Trust Company by phone at 1-800-387-0825 or (416) 643-5500 or at www.cibcmellon.com/InvestorInquiry.

We encourage you to submit your request online at www.cibcmellon.com/FinancialStatements. The Company Code Number is 5094A

REQUEST FOR FINANCIAL STATEMENTS

TO:	CIBC Mellon Trust Company

P.O. Box 7010

Adelaide Street Postal Station

Toronto, ON M5C 2W9

Please add my name to the Supplemental Mailing List for North American Energy Partners Inc. and send me their financial statements as indicated below:

Interim Financial Statements ¨ Annual Financial Statements ¨

(Please Print)


Name

Address





Postal Code/Zip Code


Signature of Shareholder								Date