EX-99.1 2 dex991.htm ANNUAL INFORMATION FORM FOR THE FISCAL YEAR ENDED MARCH 31, 2010

##### Table of Contents

Exhibit 99.1

NORTH AMERICAN ENERGY PARTNERS INC.

ANNUAL INFORMATION FORM

June 10, 2010

##### Table of Contents

TABLE OF CONTENTS

Subject |  | Page
EXPLANATORY NOTES |  | 1
Industry Data and Forecasts |  | 1
Forward-Looking Information |  | 1
Adoption of United States generally accepted accounting principles (GAAP) |  | 3
CORPORATE STRUCTURE |  | 5
DESCRIPTION OF OUR BUSINESS |  | 6
Business Overview |  | 6
History and Development of the Business |  | 6
Our Competitive Strengths |  | 8
Our Strategy |  | 9
Our Operations and Segments |  | 10
Our Revenue Sources |  | 14
Revenue by Category |  | 14
Our Contract Types |  | 15
RESOURCES AND KEY TRENDS |  | 19
Our Fleet and Equipment |  | 19
Capital Expenditures |  | 19
Facilities |  | 20
Major Suppliers |  | 21
Variability of results |  | 21
LEGAL AND LABOUR MATTERS |  | 22
Laws, Regulations and Environmental Matters |  | 22
Employees and Labour Relations |  | 22
The IPO and Reorganization |  | 23
DESCRIPTION OF SHARE CAPITAL |  | 23
DESCRIPTION OF CERTAIN INDEBTEDNESS |  | 25
Credit Facility (Including April 2010 Subsequent Event) |  | 25
8 3/4% Senior Notes due 2011 (Redeemed April 2010) |  | 27
9.125% Series 1 Debentures (Issued April 7, 2010), due 2017 |  | 28
Letters of Credit |  | 29
Debt Ratings |  | 29
DIRECTORS AND OFFICERS |  | 30
THE BOARD AND BOARD COMMITTEES |  | 33
Audit Committee |  | 33
Compensation Committee |  | 33
Governance Committee |  | 34
Health, Safety, Environment and Business Risk Committee |  | 34
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS |  | 34
LEGAL PROCEEDINGS AND REGULATORY ACTIONS |  | 35
TRANSFER AGENT AND REGISTRAR |  | 35
MATERIAL CONTRACTS |  | 35
RISKS AND UNCERTAINTIES |  | 36
Risks Related to our Business |  | 36
Risks Related to Our Common Shares |  | 42
Quantitative and Qualitative Disclosures about Market Risk |  | 44
ADDITIONAL INFORMATION |  | 46
GLOSSARY |  | 47
EXHIBIT A |  | i
Audit Committee Charter |  | i
APPENDIX A: AUDIT COMMITTEE FINANCIAL EXPERT |  | vi

##### Table of Contents

Explanatory Notes

The information in this Annual Information Form (AIF) is stated as at June 10, 2010, unless otherwise indicated. For an explanation of the capitalized terms and expressions and certain defined terms, please refer to the “Glossary” at the end of this Annual Information Form. All references in this Annual Information Form to “we”, “us”, “NAEPI” or the “Company”, unless the context otherwise requires, mean North American Energy Partners Inc. and its Subsidiaries (as defined below).

Industry Data and Forecasts

This Annual Information Form includes industry data and forecasts that we have obtained from publicly available information, various industry publications, other published industry sources and our internal data and estimates. For example, information regarding actual and anticipated production, as well as, reserves, current and scheduled projects in the Canadian oil sands was obtained from the Energy Resources Conservation Board (“ERCB”), formerly the Energy and Utilities Board (“EUB”) and the Canadian Energy Research Institute. Information regarding historical capital expenditures in the oil sands was obtained from the Canadian Association of Petroleum Producers (“CAPP”).

Industry publications and other published industry sources generally indicate that the information contained therein was obtained from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. Although we believe that these publications and reports are reliable, we have not independently verified the data. Our internal data, estimates and forecasts are based upon information obtained from our customers, trade and business organizations and other contacts in the markets in which we operate and our management’s understanding of industry conditions. Although we believe that such information is reliable, we have not had such information verified by any independent sources. References to barrels of oil related to the oil sands in this document are quoted directly from source documents and refer to both barrels of bitumen and barrels of bitumen that have been upgraded into synthetic crude oil, which is considered synthetic because its original hydrocarbon mark has been altered in the upgrading process. We understand that there is generally some shrinkage of bitumen volumes through the upgrading process. The shrinkage is approximately 11% according to the Canadian National Energy Board. We have not made any estimates or calculations with regard to these volumes and have quoted these volumes as they appeared in the related source documents.

Forward-Looking Information

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

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

a) | our significant oil sands knowledge, experience and relationships, equipment capacity, scale of operations and broad services will enable us to support the growing volume of recurring services;

b) | the operational spending throughout the 30-40 year life of a mine and our ability to provide services through such period;

c) | our expectation that the demand for recurring oil sands services continues to grow even during periods of stable production because the geographical footprints of existing mines continue to expand under normal operation;

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

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

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

g) | our expectation that we anticipate steady demand for smaller pipeline projects and expansions and given the current oversupply of contracting capacity, we expect this market to remain highly competitive;

|  |  |  | 1 |  |

##### Table of Contents

h) | our expectation that steady growth in recurring revenue will continue as activity levels increase at existing mines and new oil sands projects move from the capital development stage into the operational phase;

i) | future events such as changes in existing laws and regulations that may require us to make additional expenditures; and

j) | our expectation that a new Collective Agreement will be reached without any disruption to the Company’s operations;

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

The forward-looking information in paragraphs (a), (b), (c), (d), (e), (f), (g) and (h) rely on certain market conditions and demand for our services and are based on the assumptions that: despite the slowdown in the global economy and tightening of credit conditions combined with short term declines in oil prices, which will slow capital development of Canada’s natural resources, in particular the oil sands, we still expect to see strong demand for our recurring services as the oil sands continue to be an economically viable source of energy; our customers and potential customers will continue to invest in the oil sands and other natural resources developments; our customers and potential customers will continue to outsource the type of activities for which we are capable of providing service; and the Western Canadian economy will continue to develop with additional investment in public construction. In connection with such assumptions, we are subject to the following risks and uncertainties that:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

|  | 2 |  |  |  |

##### Table of Contents

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

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

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

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

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

Adoption of United States generally accepted accounting principles (GAAP)

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

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

As required for the fiscal year of adoption of US GAAP and one subsequent fiscal year, we will provide a Canadian Supplement to our Management’s Discussion and Analysis (MD&A) that restates, based on financial information reconciled to Canadian GAAP, those parts of our MD&A that would contain material differences if they were based on financial statements prepared in accordance with Canadian GAAP. In support of the adoption of US GAAP commencing in fiscal 2010, we are restating and filing our unaudited consolidated financial statements, accompanying notes and MD&A’s for each of the interim periods for fiscal 2010 and providing a Canadian Supplement to our MD&A’s for each of these restated interim periods for fiscal 2010.

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

Non-GAAP financial measures

The body of generally accepted accounting principles applicable to us is commonly referred to as “GAAP”. A non-GAAP financial measure is generally defined by the Securities and Exchange Commission (SEC) and by the Canadian securities regulatory authorities as one that purports to measure historical or future financial performance, financial position or cash flows, but excludes or includes amounts that would not be so adjusted in the most comparable GAAP measures. In our MD&A, we use non-GAAP financial measures such as “net income before interest expense, income taxes, depreciation and amortization” (EBITDA) and “Consolidated EBITDA” (as defined within our credit agreement)”. Consolidated EBITDA is defined within our fourth amended and restated credit agreement as EBITDA, excluding the effects of unrealized foreign exchange gain or loss, realized and unrealized gain or loss on derivative financial instruments, non-cash stock-based compensation expense, gain or loss on disposal of plant and equipment and certain

|  |  |  | 3 |  |

##### Table of Contents

other non-cash items included in the calculation of net income. We believe that EBITDA is a meaningful measure of the performance of our business because it excludes items, such as depreciation and amortization, interest and taxes that are not directly related to the operating performance of our business. Management reviews EBITDA to determine whether plant and equipment are being allocated efficiently. In addition, our credit facility requires us to maintain a minimum interest coverage ratio and a maximum senior leverage ratio, which are calculated using Consolidated EBITDA. Non-compliance with these financial covenants could result in our being required to immediately repay all amounts outstanding under our credit facility. As EBITDA and Consolidated EBITDA are non-GAAP financial measures, our computations of EBITDA and Consolidated EBITDA may vary from others in our industry. EBITDA and Consolidated EBITDA should not be considered as alternatives to operating income or net income as measures of operating performance or cash flows as measures of liquidity. EBITDA and Consolidated EBITDA have important limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under US GAAP or Canadian GAAP. For example, EBITDA and Consolidated EBITDA do not:

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

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

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

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

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

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

A reconciliation of net income (loss) to EBITDA and Consolidated EBITDA can be found in our annual Management’s Discussion and Analysis for the year ended March 31, 2010, available on SEDAR at www.sedar.com and EDGAR at www.sec.com.

|  | 4 |  |  |  |

##### Table of Contents

Corporate Structure

The Company was amalgamated under the Canada Business Corporations Act on November 28, 2006, and was the entity continuing from the amalgamation of NACG Holdings Inc. with its wholly owned subsidiaries, NACG Preferred Corp. and North American Energy Partners Inc. The amalgamated entity continued under the name North American Energy Partners Inc. The Company’s corporate office is located at Suite 2400, 500 4 th Avenue SW, Calgary, Alberta, T2P 2V6.

The Company wholly-owns North American Fleet Company Ltd. (“NAFCL”) and North American Construction Group Inc. (“NACGI”). NACGI, in turn, wholly-owns our operating subsidiaries (collectively, the “Subsidiaries”). The chart below depicts our current corporate structure with respect to each of our direct and indirect Subsidiaries:

|  |  |  | 5 |  |

##### Table of Contents

Description of Our Business

Business Overview

We provide a wide range of heavy construction and mining, piling and pipeline installation services to customers in the Canadian oil sands, minerals mining, commercial and public construction and conventional oil and gas markets. Our primary market is the Alberta oil sands, where we support our customers’ mining operations and capital projects. While we provide services through all stages of an oil sands project’s lifecycle, our core focus is on providing recurring services, such as contract mining, during the operational phase. On a trailing 12-months basis to March 31, 2010, recurring services represented 89% of our oil sands business. Our principal oil sands customers include all four of the most significant producers that are currently mining bitumen in Alberta: Syncrude 1, Suncor 2, Shell Albian 3 and Canadian Natural 4. We focus on building long-term relationships with our customers. For example, we have been providing services to Syncrude and Suncor for over 30 years.

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

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

While our mining services are primarily focused on the oil sands, we believe that we have demonstrated our ability to successfully export knowledge and technology gained in the oil sands and put it to work in other resource development projects across Canada. As an example, in fiscal 2008 we successfully completed the development of a diamond mine site in Northern Ontario. This three-year project required us to operate effectively in a remote location in the extreme weather conditions prevalent in northern Canada. As a result of our successful work on this and other similar projects, we believe that we have attracted the attention of resource developers. While development of resources has been affected by the current economic environment, we remain committed to expanding our operations to other potential projects, including those in the high Arctic regions.

History and Development of the Business

We completed an Initial Public Offering (“IPO”) of our common shares and a related reorganization (the “Reorganization”) in November 2006 in order to deleverage our balance sheet and provide additional financial capacity as we pursued our growth strategy. The common shares began trading on the New York Stock Exchange on November 22, 2006 and became fully tradable on the Toronto Stock Exchange on November 28, 2006. Through the IPO, we raised a total of $152.6 million in net proceeds. These funds were primarily used to restructure our balance sheet, reduce outstanding debt and buy out a number of equipment operating leases. For more information on the IPO and the Reorganization see “The IPO and the Reorganization” elsewhere in this AIF.

The following is a summary of the significant events that have influenced our business over the past three years.

From the beginning of fiscal 2007 through the first nine months of fiscal 2009, we were in a rapid growth phase as we responded to increased demand for recurring services in the oil sands and a high level of new construction activity resulting from new oil sands development. Our growth was further fuelled by record prices for commodities and very strong economic conditions, which helped to drive the commercial and public construction, conventional oil and gas and minerals mining sectors in Canada. In response to the fast-growing demand, we hired additional personnel and invested over $550.0 million into new equipment, creating what we believe to be one of the largest and most diversified heavy equipment fleets in Western Canada. During this same period, we achieved record financial results in all three of our operating divisions. Our Heavy Construction and Mining segment achieved compound annual growth of 25%, benefiting from increased production at the Canadian Natural site under our ten year overburden removal contract, as well as increased demand for our site services under our master services agreements with Syncrude and Albian.

Our Piling segment achieved 19% compound annual revenue growth, primarily related to increased construction activity in the oil sands and robust commercial and public construction markets in Alberta, British Columbia and Saskatchewan.

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

2 | Suncor Energy Inc. (Suncor).

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

4 | Canadian Natural Resources Limited (Canadian Natural).

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

|  | 6 |  |  |  |

##### Table of Contents

Major projects included the provision of piling for the expansion of Shell Albian’s Scotford upgrader facility in Edmonton and the construction of the coker and naphtha units on Suncor’s Millennium site. We are also providing the piling work for Suncor’s latest development, Voyageur.

Our Pipeline segment achieved 44% compound annual revenue growth during this same three-year period. The division overcame losses on two fixed-price contracts in fiscal 2007 and fiscal 2008 as it refocused its bidding strategy and subsequently secured and successfully completed Kinder Morgan Inc.’s (“Kinder Morgan”) Trans Mountain (“TMX”) Anchor Loop project.

In the second quarter of fiscal 2009, market conditions began to change. Lower commodity prices and restricted access to capital forced some customers to delay or defer capital intensive projects. This in turn reduced the backlog of new development projects in the oil sands which has had a negative impact on our Piling and Heavy Construction and Mining segments. While new construction spending declined overall, customers, such as Exxon-Mobil Canada Ltd., and Shell Albian announced their intention to proceed with construction to capitalize on anticipated lower input costs and improved availability of labour. As a result, we have seen no slow down of construction at either Exxon’s Kearl project or Shell Albian’s Jackpine project over the last 12 months. While overall demand for project development services supporting new construction in the oil sands has been impacted, demand for our recurring services business remains stable and is anticipated to increase in the coming years.*

The commercial construction sector has also been negatively affected by weaker economic conditions, resulting in reduced demand for our piling services. However, public infrastructure spending is beginning to accelerate as a result of the federal and provincial governments’ attempts to stimulate the economy. This government stimulus may help to partially offset the impact of reduced demand from the commercial construction sector.

Prior to the global financial crisis, numerous pipeline construction and expansion projects had been announced, to address limited existing pipeline capacity and to accommodate predicted increases in oil sands production levels. This included Kinder Morgan’s TMX Anchor Loop project, which we worked on throughout fiscal 2009. While the full impact of reduced oil sands development on the pipeline industry is still unclear, companies in the late planning stages of their projects continue to move forward. However, competition for these projects has increased with more bidders willing to assume more risk to secure work. Given the continuing opportunities in other areas of our business, specifically recurring services coupled with the increased risk profile in the Pipeline division, we adopted a very cautious approach with respect to our bidding strategy for pipeline projects. As a result, until recently we had not secured a contract for the Pipeline division since completing the TMX project in the three months ended December 31, 2008. During fiscal 2010 we secured three relatively small pipeline contracts. The first of these involves installing 2 pipelines (24” and 20”) beneath the South Arm of the Fraser River in metro Vancouver, British Columbia, working for Terasen Inc.5 This complex project has had some execution delays but is expected to be completed close to bid margin in the summer of 2010. The second project involved laying a 37 km, 24” diameter natural gas line in North Eastern British Columbia for Spectra Energy. This project was bid very competitively and unfortunately, due to worse than anticipated weather and ground conditions resulted in a loss. The Pipeline division has since secured the second stage of this project with this client for 30.8 km’s of 24” pipe, with lower risk weather and site conditions. The third project, TransCanada Pipeline’s Groundbirch Mainline project located in North Eastern British Columbia, was secured at the end of the fiscal year. The project involves installing 77km of 36” pipe for TransCanada, extending the 56-year old Nova natural gas transportation network from Alberta into British Columbia. This project will be utilizing mechanized welding, a technology that will reduce labour, rework and schedule risk. Other resource sectors have also been impacted by the changing economic conditions, with lower commodity prices and limited access to capital reducing the viability of exploration and development. This, in turn, has impacted opportunities for Heavy Construction and Mining outside of the oil sands.*

We have responded to the changing market conditions by further strengthening our financial position through capital spending reductions, organizational restructuring, cost reduction initiatives and focused cash management. We have focused attention on those areas of our business that provide opportunities for profitable revenue generation, particularly recurring services to projects in the oil sands. We completed the acquisition of DF Investments Inc. and its subsidiary Drillco Foundation Co. Ltd. in our Piling division, providing us with a presence in the large Ontario construction market.

In April 2010, we issued C$225.0 million of Series 1 Debentures and entered into an amended and restated credit agreement that extended the maturity of our credit facilities to April 2013 and provided a new $50.0 million term loan. The net proceeds of the sale of the Series 1 Debentures, combined with the new $50.0 million term loan and cash on hand were used in April 2010 to redeem all outstanding US dollar 8 3/4% senior notes and terminate the associated swap agreements. The result of these transactions was to reduce our overall debt by approximately $20 million and substantially decrease our exposure to interest rate and foreign exchange fluctuations.

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

5 | Terasen Inc., a wholly owned subsidiary of Fortis Inc.

|  |  |  | 7 |  |

##### Table of Contents

Our Competitive Strengths

We believe our competitive strengths are as follows:

Leading market position

We are the largest provider of contract mining services in the Alberta oil sands area and we believe we are the largest piling foundations installer in Western Canada. We have operated in Western Canada for over 50 years and have participated in every significant oil sands mining project since operators first began developing this resource over 30 years ago. This has given us extensive experience operating in the challenging working conditions created by the harsh climate and difficult terrain of the oil sands and Northern Canada. We have also amassed what we believe is the largest fleet of any contract services provider in the oil sands. We believe the combination of our significant size, extensive experience and broad service offerings makes us one of only a few companies capable of taking on long-term, large-scale mining and heavy construction projects in the oil sands. For example, we were selected in fiscal 2005 by Canadian Natural to provide substantial services under several contracts, including a 10-year overburden removal contract.

Large, well-maintained equipment fleet

As of March 31, 2010, we had a heavy equipment fleet of 698 units, made up of shovels, excavators, trucks and dozers as well as loaders, graders, scrapers, cranes, pipe layers and drill rigs. Over the past three years we have invested over $550.0 million into our fleet including upgrades, new equipment purchases and capital equipment leases. As a result of this investment, we believe we now have an unmatched, modernized fleet of equipment to service our clients’ needs. Our fleet includes some of the largest shovels in the world which are designed for use in the largest earthmoving and mining applications globally. Being the only contractor in the oil sands to operate shovels of this size and one of only two contractors to operate trucks larger than 240 tons capacity gives us a competitive advantage in respect to both skill base and equipment availability, particularly at a time when our customers are not only looking at larger equipment to reduce site congestion and enhance safety but are also less inclined to make major investments in capital-intensive equipment themselves and prefer to utilize contractors to offset risk. Furthermore, the size and diversity of our fleet enables us to respond on short notice and provide customized fleet solutions for each specific job.

A well-maintained fleet is critical in the harsh climatic and environmental conditions we encounter. We operate four significant maintenance and repair centers on our customers’ oil sands sites. These facilities are capable of accommodating the largest pieces of equipment in our fleet. In addition, we have a major repair facility located at our corporate headquarters near Edmonton, Alberta. This facility can perform the same major maintenance and repair activities as our facilities in the oil sands and provides back-up in the event of peak maintenance or repair requirements for oil sands equipment. We believe our combination of onsite and offsite service capabilities increases our efficiency. This, in turn, reduces costs and increases our equipment utilization, thereby enhancing our competitive edge and profitability.

Broad service offering across a project’s lifecycle

We are considered to be a “first-in, last-out” service provider in the oil sands because we provide services through the entire lifecycle of an oil sands project. Our work typically begins with the initial consulting services provided during the planning phase, including constructability, engineering reviews and budgeting. This leads into the construction phase during which we provide a full range of services, including clearing, muskeg removal, site preparation, mine infrastructure construction, piling, pipeline and underground utility installation. As the mine moves into production, we support the preparation of the mine by providing ongoing site maintenance and upgrading, equipment and labour supply, overburden removal and land reclamation. Given the long-term nature of oil sands projects, we believe that our broad service offering enables us to establish ongoing relationships with our customers through a continuous supply of services as we transition from one stage of the project to the next.

Long-term customer relationships

We have established strong, long-term relationships with major oil sands producers and conventional oil and gas producers. Our largest oil sands customers by revenue are Syncrude, Suncor, Shell Albian and Canadian Natural. We have worked with each of these customers since they began operations in the oil sands. In the case of Syncrude and Suncor, our relationships date back over 30 years. The longevity of our customer relationships reflects our ability to deliver a strong safety and performance record, a well-maintained, highly capable fleet with specific equipment dedicated to individual customers and a staff of well-trained, experienced supervisors, operators and mechanics. In addition, our practice of maintaining offices and maintenance facilities directly on most of our oil sands customers’ sites enhances the relationship. Our proximity and close working relationships typically result in advance notice of projects, enabling us to anticipate our customers’ needs and align our resources accordingly.

Operational flexibility

The combination of our onsite fleets and relationships with multiple oil sands operators makes it possible for us to easily and cost efficiently transfer equipment and other resources among projects. This keeps us highly responsive to customer needs and is an essential element in securing recurring services business. In this part of the business, lead times are short and the work is usually conducted outside of long-term contracts. The nature of this work acts as a

|  | 8 |  |  |  |

##### Table of Contents

disincentive for potential new competitors who may be unwilling to take on the risk of mobilizing a fleet for a single project or without the benefit of secure contracts. The fact that we work on every major site in the oil sands contributes to our flexibility, enhances the stability of our business model and has enabled us to continue bidding profitably on new contracts. This has helped us remain viable through the recent economic downturn. Some oil sands competitors that work on only one or two sites did not fare as well.

Our Strategy

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

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

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

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

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

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

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

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

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

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

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

|  |  |  | 9 |  |

##### Table of Contents

Our Operations and Segments

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

A complete discussion on segment results can be found in “Segment Annual Results” in the Financial Results section of the most recent MD&A.

Heavy Construction and Mining

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

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

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

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

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

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

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

Piling

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

Pipeline

Our Pipeline segment installs transmission, distribution and gathering systems made of steel, fiberglass and/or plastic pipe in sizes up to 52” in diameter. Penstock installation services are also provided. This segment has successfully completed jobs of varying magnitude for some of Canada’s largest energy companies, including Kinder Morgan’s 6 Trans Mountain Expansion (TMX) Anchor Loop pipeline, which involved the installation of 160 kilometres of large-diameter pipe through extremely challenging and ecologically sensitive terrain. The segment also provides recurring services to specific customers. As an example, we have a three-year contract to complete pipeline integrity excavations and hydrostatic retest on TransCanada Pipelines’7 mainline system in British Columbia, Saskatchewan, Manitoba and Ontario.

6 | Kinder Morgan Energy Partners, L.P. (Kinder Morgan).

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

|  | 10 |  |  |  |

##### Table of Contents

The table below shows the revenues generated by each operating segment for the years ended March 31, 2010, 2009 and 2008:

|  | Year ended March 31,
(dollars in thousands) |  | 2010 |  | 2009 |  | 2008
Heavy Construction & Mining |  | $665,514 |  | 87.7% |  | $716,053 |  | 73.6% |  | $626,582 |  | 63.3%
Piling |  | 68,531 |  | 9.0 |  | 155,076 |  | 16.0 |  | 162,397 |  | 16.4
Pipeline |  | 24,920 |  | 3.3 |  | 101,407 |  | 10.4 |  | 200,717 |  | 20.3
Total |  | 758,965 |  | 100.0% |  | 972,536 |  | 100.0% |  | 989,696 |  | 100.0%

Our Markets

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

Canadian Oil Sands

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

Oil sands are grains of sand covered by a thin layer of water and coated by heavy oil or bitumen. Bitumen, because of its structure, does not flow and therefore requires non-conventional extraction techniques to separate it from the sand and other foreign matter. There are currently two main methods of extraction: (i) open pit mining, where bitumen deposits are sufficiently close to the surface to make it economically viable to recover the bitumen by treating mined sand in a surface plant; and (ii) in situ technology, where bitumen deposits are buried too deep for open pit mining to be cost effective and operators instead inject steam into the deposit, lowering the viscosity of the bitumen so that the bitumen can be separated from the sand and pumped to the surface, leaving the sand in place. Steam Assisted Gravity Drainage (SAGD) is a type of in situ technology that uses horizontal drilling to produce bitumen. CAPP estimates that approximately 20% of the oil sands are recoverable through open pit mining. Open pit mining projects tend to have greater production capacity than in situ technology. For example, approximately 52% of 2009 oil sands production was extracted from five active mining projects, while the remaining 48% of 2009 oil sands production was extracted from approximately 17 active in situ projects. While the number of active and planned in situ projects far exceeds the number of mining projects, according to CAPP and other industry forecasts, future total production from mining and in situ technology is expected to remain approximately equal.*

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

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

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

|  |  |  | 11 |  |

##### Table of Contents

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

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

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

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

Current Canadian Oil Sands Business Conditions

Project Development: Although last year saw a general slowdown in project development activity in the oil sands, we also saw construction on two projects, Exxon’s $8 billion Kearl mining project 8 and Shell Albian’s $12 billion Jackpine mine expansion project, continue without any delay as these operators remained focused on the long term oil price as the project driver. As economic conditions have strengthened, oil prices have stabilized and producers are reaffirming their commitment to oil sands development with new construction approval announcements, including Husky Energy Inc.’s Sunrise 9 in situ project and ConocoPhillips’ Surmont 10 in situ project. Canadian Natural has indicated strong interest in proceeding with its Horizon Mine Phase 2/3 expansion and development of the Kirby in situ project, while Suncor is proceeding with additional stages of its Firebag in situ project as it completes the integration process of the Fort Hills 11 mining project from its recent acquisition of Petro-Canada Limited. While capital spending in the oil sands declined from $18 billion in calendar 2008 to $11 billion in 2009, CAPP forecasts a recovery in capital spending to $13 billion in 2010.

Further positive indicators that investor interest in the oil sands is strengthening include PetroChina’s 12 recent $2 billion investment in Athabasca Oil Sands, followed by a $1.35 billion initial public offering by Athabasca Oil Sands Corp., the largest in oil sands history. China’s Sinopec Corp.13 recently announced plans to buy ConocoPhillips’ stake in the Syncrude project for $4.65 billion. This is China’s largest investment in North America to date.

While the overall trend is positive, environmental activism opposing oil sands development has been increasing and receiving broad media coverage. Environmental costs to producers are rising as a result of increasing regulatory requirements. As an example, the recently released ERCB Directive 074 14 requires producers to invest in new research, development, technology and services to address the reclamation of tailings ponds in a significantly accelerated time span. Although this adds costs to the process, it also creates opportunities for service providers like ourselves to create new lines of business to support the construction and operation of these new reclamation processes.

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

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

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

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

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

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

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

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

|  | 12 |  |  |  |

##### Table of Contents

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

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

Commercial and Public Construction

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

Current Commercial and Public Construction Business Conditions

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

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

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

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

Conventional Oil and Gas

According to the Canadian Energy Pipeline Association (CEPA), Canada has over 580,000 kilometres of pipeline that transports approximately 2.65 million barrels of crude oil and equivalents per day and 17.1 billion cubic feet of natural gas per day to various distribution points in Canada and the US. There are a number of new pipelines and pipeline expansion projects under construction and in various stages of the planning and regulatory process to provide capacity for the expected increase in oil and gas production.

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

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

Current Conventional Oil and Gas Business Conditions

Forecasts of oil and gas production growth have been scaled back due to weaker economic conditions and timelines for new pipelines and expansions are being revised to reflect the new production expectations and the related capacity

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

|  |  |  | 13 |  |

##### Table of Contents

requirements. However, significant pipeline expansion is still required to meet future demand and companies involved in the transmission of oil and gas continue to move forward with investment in new pipeline development. In the near term, we anticipate steady demand for smaller pipeline projects and expansions and given the current oversupply of contracting capacity, we expect this market to remain highly competitive.*

Minerals Mining

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

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

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

Current Minerals Mining Business Conditions

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

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

Our Revenue Sources

Revenue by Category

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

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

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

• |  | Long-term contracts. This category of revenue consists of revenue generated from long-term contracts (greater than one year) with total contract values greater than $20.0 million. These contracts are for work that supports the operations of our customers and include long-term contracts for overburden removal and

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

|  | 14 |  |  |  |

##### Table of Contents

| reclamation. Revenue in this category is typically generated under unit-price contracts and is included in our calculation of backlog. This work is generally funded from our customers’ operating budgets.

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

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

Revenue by End Market

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

Our Contract Types

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

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

Unit-price. A unit-price contract is utilized in the execution of projects with large repetitive quantities of work and is commonly used for site preparation, mining and pipeline work. We are compensated for each unit of work we perform

|  |  |  | 15 |  |

##### Table of Contents

(for example, cubic meters of earth moved, lineal meters of pipe installed or completed piles). Within the unit-price contract, there is an allowance for labour, equipment, materials and subcontractors’ costs. Once these costs are calculated, we add any site and corporate overhead costs along with an allowance for the margin we want to achieve. The risk associated with this type of contract is in the calculation of the unit costs with respect to completing the required work.

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

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

In addition to the types of contracts listed above, we also use Master Services Agreements for work in the oil sands to support the operations of our customers. The Master Service Agreement specifies the rates that will be charged for the supply of labour and equipment, but does not specify scope or schedule of work. This revenue is primarily generated under time-and-materials contracts and is generally funded from our customers’ operating or maintenance capital budgets.

We also do a substantial amount of work as a subcontractor to other general contractors. Subcontracts vary in type and in conditions, with respect to the pricing and terms, and are governed by one specific prime contract that governs a large project generally. In such cases, the contract with the subcontractors contains more specific provisions regarding a specified aspect of a project than the provisions provided in the prime contract.

PROJECTS

Active Projects

Canadian Natural: Overburden Removal Project

Canadian Natural completed construction of its Horizon Oil Sands Project and achieved first oil production in early 2009. This oil sands mining project has a targeted production capacity of 110,000 barrels per day (“bpd”) from Phase 1. Canadian Natural has plans to ultimately increase total production capacity to 500,000 bpd through future expansions of which phases 2 and 3 are currently in the planning stages.

In 2005, we secured a contract with Canadian Natural under which we are to remove approximately 400.0 million bank cubic meters (“BCM”) of overburden and use 300.0 million BCM of that material to build a tailings dyke at the site. This is a unit-price contract worth approximately $1.3 billion over the ten year life of the contract (five years of the contract value is reflected in our reported backlog). The life of the mine is estimated at approximately 30-40 years and we will be working closely with our client with the aim of renewing the contract for an additional ten years once our current contract expires. As the mine develops, we believe our recurring revenue on this site can increase as we provide mine site services of the type that we traditionally perform at other operating oil sands mines.*

Shell Albian Muskeg River Mine and Jackpine: Labour & Equipment Supply

Shell Albian is the operator for the Athabasca Oil Sands Project (“AOSP”), a joint venture between Shell Canada Limited, Chevron Canada and Marathon Oil Canada Corporation. The AOSP includes Muskeg River Mine, which has a target production capacity of 155,000 bpd and Jackpine Mine, which is currently under development and is nearing completion (first oil is expected in July of 2010), increasing production capacity of Shell Albian’s oil sands operations by 100,000 bpd. Future planned mining expansions, while not imminent, are expected to ultimately increase total production capacity to 500,000 bpd.

In 2009, we signed a three-year earthmoving and mine support services agreement with Shell Albian. The contract covers the provision of recurring services including construction, earthmoving and mine support and replaces an expiring two-year master services agreement (MSA). Work under the agreement covers general master services work and includes three years of defined scope and volumes for pre-strip and base-of-feed cleanup mining at the Muskeg River Mine. This type of work is typically performed under a time-and-materials arrangement and is not reflected in our reported backlog.

Work at the Jackpine mine site is currently transitioning from preproduction activities (site development type work) to mine support activities. As the Jackpine mine begins to produce bitumen, we will transition to support the mining operation with services very similar to those we have been providing at the Muskeg River Mine for the last several years.

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

|  | 16 |  |  |  |

##### Table of Contents

We are currently involved in two projects not covered by our Master Services Agreement at the Muskeg River Mine. These two projects are related to tailings management and involve the construction of a pipeline corridor and the preparation of an area which will be used for the atmospheric drying of mature fine tails.

Suncor Energy: Equipment Supply Agreement

Suncor’s current mining operation includes the Steepbank and Millennium mines, which have a combined production capacity in excess of 300,000 bpd. An additional 120,000 bpd of production capacity is anticipated from the planned development of the Voyageur South mine. Following the merger with Petro-Canada, Suncor’s minable assets now also include a 60% interest in the Fort Hills Oil Sands Project.

In March 2009, we secured a contract to supply mining equipment and services to Suncor’s operations. In December 2009, Suncor extended this agreement for an additional 12 months.

Syncrude: Base Plant: Labour & Equipment Supply

Syncrude’s current mining operations include Base Mine (Mildred Lake) and Aurora Mine, which have a current combined production capacity of approximately 350,000 bpd. Further expansions are planned, including the development of a new mine (Aurora South), with the target of increasing total production capacity to 600,000 bpd by 2020.

We have a master services agreement in place with Syncrude that enables us to execute various types of projects for this customer. Construction work authorizations are issued for each piece of work under both time-and-materials and unit-rate arrangements and are generally not reflected in our reported backlog. This agreement was originally negotiated in 1998 and has been continuously renewed with our current agreement extending to November 30, 2010. We will continue to bid projects for Syncrude up to and beyond this date.

Exxon’s Kearl: Crusher MSE Wall Construction Project

Exxon’s Kearl project is currently in construction phase one of three phases. The targeted production capacity for the entire project will be 345,000 bpd. Phase 1 expects to achieve first oil production by August, 2012. We were recently awarded a unit-price contract to construct the crusher MSE wall and associated truck dump pad and grading at the base of the wall with an estimated completion date of November 30, 2010.

Canadian Cooperative Refinery Limited: Tank Farm Project

The CCRL revamp and expansion project is underway in Regina, Saskatchewan. We have two of our divisions working on this project. Our Industrial group is completing tank farm earthworks construction, associated piping and pipelines and other heavy civil works as required by the client under an open services agreement. Our Piling team is installing piling foundations inside the operating facility and outside of the plant limits in the new expansion areas.

Recently Completed Projects

Spectra Maxhamish Loop – North

We completed a 37 kilometres, 24 inch diameter natural gas pipeline in the Fort Nelson area of British Columbia for this client. The project was our first pipeline work in the North Eastern gas fields of British Columbia and we are using it as the first project in a long term strategy to work in this market. We have been awarded the second phase of this work and will begin work on the South Loop in the summer of 2010. The North Loop was completed in February 2010.

Shell Albian: Jackpine Compensation Lake Project

We completed a highly technical project involving the construction of inlet and outlet channels including a man-made lake that was designed by Shell Albian to accommodate regulatory requirements to create a fish habitat in the area of the Jackpine Mine. Compensation Lake has an area of 473,000 square meters at 280 water surface elevation. It has a maximum depth of 11 meters in the southern basin and 7 meters in the northern basin.

Suncor (formerly Petro Canada): Fort Hills Project

The Suncor Fort Hills Project involved the development of a new oil sand mine in the Fort McMurray region. The first phase of this project was set to deliver approximately 140,000 barrels of bitumen per day beginning in late 2011. We were initially contracted in January of 2007 to begin site preparation work. Work concluded in December of 2008 when Petro Canada announced the deferral of the project due to escalating costs and falling oil prices. With the acquisition of Petro Canada by Suncor it is unclear when this project may be revisited.

Syncrude: Reclamation Project

We completed four years of work as part of a contract to provide complete reclamation of overburden dumps and tailings dams at the Syncrude site. The scope of services under this contract included the excavation, hauling and placing of approximately 15.7 million cubic meters of muskeg (wet peat soil) and other secondary material. Reclamation was performed during the final stages of the mining process as we returned the land to a stable, biologically self-sustaining state.

|  |  |  | 17 |  |

##### Table of Contents

Kinder Morgan: TMX Anchor Loop Project

The Kinder Morgan TMX Anchor Loop pipeline expansion, Phase 1, involved “twinning” (or looping) a 158-kilometre section of the existing Trans Mountain pipeline system between Hinton, Alberta and Jackman, British Columbia. It also involved the addition of two new pump stations. We were selected to undertake this challenging project, which included construction through mountainous terrain, multiple river crossings and adherence to rigorous environmental guidelines, as the pipeline crosses through one of Canada’s protected national parks. We began work on this contract in fiscal 2007 and carried out a significant portion of the work in 2008. Work under this contract was completed in November 2008.

University of Saskatchewan – Hospital Expansion Project

We completed a large diameter piling project at a hospital expansion with our CFA (Continuous flight auger) technology. This was a unique application of our CFA capabilities in very difficult soil conditions. The project was successfully completed in May 2010.

Anthony Henday – North Loop Caissons Project

We completed a substantial drilled caisson project in the Edmonton area in 2009. The project involved large diameter drilled shaft foundations to support a number of overpass structures for this large civil infrastructure project.

Suncor: Voyageur Project

Suncor’s Voyageur Project is a combination of 10 different project area plans that will complete the strategy to double the size of Suncor’s Fort McMurray oil sands operations from 250,000 to 550,000 bpd between 2010 and 2012. The project includes the construction of Suncor’s third oil sands upgrader.

In 2007, we were contracted to supply and install the underground piping systems at Voyageur. We also provided construction dewatering and the piling to support the foundations of the pipe rack systems, vessels and other structures across the site. Work under this contract was completed in December 2008.

Suncor: Millennium Naphtha Unit (“MNU”) Project

Suncor’s MNU Project involved the construction of various plants and a series of pipe racks that tie the new plants to the existing ones. We worked on this project under a time-and-materials contract that included the provision of site grading and road works services, as well as the installation of deep and shallow undergrounds, piling foundations and concrete pavement. Work under this contract was completed in September 2008.

Joint Venture

We are party to a joint venture operated through a corporation called Noramac Ventures Inc., or “Noramac”, with Fort McKay Construction Ltd., as general partner for and on behalf of Fort McKay Construction Limited Partnership. This joint venture exists for the purpose of performing contracts within the Regional Municipality of Wood Buffalo which require the provision of heavy construction equipment to conduct earthworks and related services for the construction, development and operation of open-pit mining projects. The affairs of Noramac are managed, and all decisions and determinations with respect to Noramac are made, by a management committee (the “Management Committee”) with an equal number of representatives from our partner and us. The Management Committee is responsible for determining the work in relation to each contract that will be performed by Noramac. The joint venture agreement provides that if a prospective project is neither listed in the annual business plan for Noramac nor agreed by the parties to be a project in respect of which a tender is to be submitted or where the parties fail to reach agreement on the terms upon which Noramac shall tender or propose for a contract, then either we or our partner may pursue the contract without hindrance, interference or participation by the other. In no case, however, are we permitted to joint venture any industrial construction work in the Regional Municipality of Wood Buffalo with any other first nations group nor is our partner permitted to perform industrial construction work in the same area with any other non First Nations group. The joint venture agreement does not prohibit or restrict us from undertaking and performing, for our own account, any work for existing customers other than work to be performed by Noramac pursuant to an existing contract between Noramac and such customer.

|  | 18 |  |  |  |

##### Table of Contents

Resources and Key Trends

Our Fleet and Equipment

We operate and maintain a heavy equipment fleet, including crawlers, graders, loaders, mining trucks, compactors, scrapers and excavators. We also maintain a fleet of ancillary vehicles including various service and maintenance vehicles. Overall, the equipment is in good condition, subject to normal wear and tear. Our credit facility and currency and interest rate swaps are secured by liens on substantially all of our equipment. We lease some of this equipment under lease terms that include purchase options.

The following table sets forth our heavy equipment fleet as at March 31, 2010:

Category |  | Capacity Range |  | Horsepower Range |  | Number in Fleet |  | Number Leased
Heavy Construction and Mining:
Articulating trucks |  | 30 to 40 tons |  | 305 – 406 |  | 26 |  | 0
Mining trucks |  | 40 to 330 tons |  | 476 – 2,700 |  | 177 |  | 67
Shovels |  | 35-80 cubic yards |  | 2,600 –3,760 |  | 8 |  | 6
Excavators |  | 1 to 29 cubic yards |  | 90 – 1,944 |  | 108 |  | 26
Dozers |  | 20,741 lbs to 230,100 lbs |  | 96 – 850 |  | 116 |  | 42
Graders |  | 14 to 24 feet |  | 150 – 500 |  | 29 |  | 11
Scrapers |  | 28 to 31 cubic yards |  | 462 |  | 1 |  | 0
Loaders |  | 1.5 to 16 cubic yards |  | 110– 690 |  | 91 |  | 0
Packers |  | 14,175 to 68,796 lbs |  | 216 – 3 15 |  | 16 |  | 0
Rigid Frame Water Trucks |  | 18,000 gallon |  | 703 |  | 1 |  | 0
Scraper Water Wagons |  | 10,000 gallon |  | 462 |  | 2 |  | 0
Float Trucks |  | 250 tons |  | 703 |  | 5 |  | 0
Tractors |  | 43,000 lbs |  | 460 |  | 2 |  | 0
Pipeline:
Trenchers |  | 60,000 lbs |  | 165 |  | 1 |  | 0
Pipe layers |  | 20,000 to 202,000 lbs |  | 78 – 265 |  | 39 |  | 0
Piling:
Drill rigs |  | Up to 170 feet (drill depth) |  | 210 – 1,500 |  | 50 |  | 1
Cranes |  | 25 to 150 tons |  | 200 – 263 |  | 26 |  | 0
Total |  |  |  |  |  | 698 |  | 153

For the fiscal years ended March 31, 2010, 2009 and 2008, we incurred expenses of $209.4 million, $217.1 million and $176.2 million, respectively, to maintain our equipment.

Many of our heavy equipment units are among the largest pieces of equipment in the world and are designed for use in the largest earthmoving and mining applications globally. Our large, diverse fleet gives us flexibility in scheduling jobs and we believe that this allows us to be responsive to our customers’ needs. A well maintained fleet is critical in the harsh climate and environmental conditions in which we operate. We operate four significant maintenance and repair centers on the sites of the major oil sands projects, which are capable of accommodating the largest pieces of equipment in our fleet. These factors help us to be more efficient, thereby reducing costs to our customers to further improve our competitive edge, while concurrently increasing our equipment utilization and thereby improving our profitability.

Capital Expenditures

The following table sets out capital expenditures for our main operating segments for the periods indicated, excluding new capital leases:

|  | Year Ended March 31,
(dollars in thousands) |  | 2010 |  | 2009 |  | 2008
Heavy Construction & Mining |  | $40,532 |  | $73,689 |  | $35,216
Piling |  | 1,081 |  | 8,679 |  | 12,945
Pipeline |  | 948 |  | 75 |  | 5,229
Other |  | 12,790 |  | 5,096 |  | 1,689
Total |  | $55,351 |  | $87,539 |  | $55,079

|  |  |  | 19 |  |

##### Table of Contents

Facilities

We own and lease a number of buildings and properties for use in our business. Our corporate offices are located in Calgary, Alberta. Our primary administrative functions are located in Edmonton, Alberta and Acheson, Alberta, which also houses a major equipment maintenance facility. Project management and equipment maintenance are also performed at regional facilities in Calgary and Fort McMurray, Alberta; New Westminster, British Columbia; Regina and Martensville, Saskatchewan; and Milton, Ontario. We lease premises in British Columbia, Alberta and Saskatchewan under leases which expire between 2010 and 2022, subject to various renewal and termination rights. We are currently finalizing the renewal of our Ruth Lake facility land lease with Syncrude, the term of which has been extended to August 31, 2021. We own land and buildings in Milton, Ontario, from which we carry on our Ontario Piling operations. We also occupy, without charge, some customer-provided lands. The following table describes our primary facilities:

Location |  | Function |  | Owned or Leased |  | Lease Expiration Date
Acheson, Alberta |  | Administrative office and major equipment repair facility |  | Leased |  | 11/30/2012
Calgary, Alberta (Corporate Office) |  | Executive head office |  | Leased |  | 1/29/2012
Calgary, Alberta (Piling) |  | Regional office and major equipment repair facility for Piling operations |  | Leased |  | 12/31/2014
Edmonton, Alberta (Mayfield) |  | Regional office (Piling) and administrative office |  | Leased |  | 12/31/2017
Fort McMurray, Alberta (Shell Albian Muskeg River Mine site) |  | Satellite office and equipment facility for all operations |  | Building leased Land provided |  | Term of Shell Albian contract
Fort McMurray, Alberta (CNRL site) |  | Site office and maintenance facility |  | Building owned Land provided |  | Term of CNRL contract
Fort McMurray, Alberta (Syncrude Ruth Lake site) |  | Satellite office and maintenance facility for all operations |  | Building owned Land leased |  | 8/31/2021 Currently finalizing extension
Fort McMurray, Alberta (Timberlea) |  | Satellite and administrative office Mining Operations |  | Leased |  | 2/28/2022
Martensville, Saskatchewan |  | Regional office and equipment repair facility for Piling operations |  | Leased |  | 4/30/2012
Regina, Saskatchewan |  | Regional office and equipment repair facility for Piling operations |  | Leased |  | 3/14/2013
New Westminster, BC |  | Regional office and equipment repair facility for Piling operations |  | Leased |  | 12/31/2017
Milton, Ontario (DrillCo) |  | Regional office and equipment repair facility for Piling operations |  | Owned |  | N / A

Our physical locations were chosen for their geographic proximity to our major customers.

|  | 20 |  |  |  |

##### Table of Contents

Competition

The majority of our new business is secured through formal bidding processes in which we are required to compete against other suppliers. Factors that impact success on competitive bids include price, safety, reliability, scale of operations, equipment and labour availability and quality of service. Our industry is highly competitive in each of our markets and competition on project bids increased noticeably during the year ended March 31, 2010 as a result of weaker economic conditions. While competition initially increased in the oil sands, several oil sands competitors went on to experience financial difficulty. We believe one of our competitors, Cross-Terra Construction, has exited the market. A smaller competitor, Atcon Group, had been operating under creditor protection for some time and has now entered receivership. More recently, Cow Harbour Construction Ltd has entered creditor protection. Our principal competitors in the Heavy Construction and Mining segment include Klemke Mining Corporation, Cow Harbour Construction Ltd. (currently under creditor protection), Graham Group Ltd, Ledcor Construction Limited, Peter Kiewit and Sons Co., Tercon Contractors Ltd., Sureway Construction Ltd. and Thompson Bros. (Construction) Ltd. In underground utilities installation (a part of our Heavy Construction and Mining segment), Voice Construction Ltd., Ledcor Construction Limited and I.G.L. Industrial Services are our major competitors. The main competition to our deep foundation piling operations comes from Foundations, Double Star Drilling and Pacer Industries, in Western Canada and from Deep Foundations, Anchor Shoring and Bermingham Construction, in Eastern Canada. The primary competitors in the pipeline installation business include Ledcor Construction Limited, Washcuk Pipe Line Construction Ltd. and Willbros. In the public sector, we compete against national firms, as well as local competitors within individual geographic markets. Most of our public sector customers are local governments that are focused on serving only their regions. Competition in the public sector continues to increase and we typically choose to compete on projects only where we can utilize our equipment and operating strengths to secure profitable business.

Major Suppliers

We have long-term relationships with the following equipment suppliers: Finning International Inc. (over 45 years), Wajax Income Fund (over 20 years) and Brandt Tractor Ltd. (over 30 years). Finning is a major Caterpillar heavy equipment dealer for Canada. Wajax is a major Hitachi equipment supplier to us for both mining and construction equipment. We purchase or rent John Deere equipment, including excavators, loaders and small bulldozers, from Brandt Tractor. In addition to the supply of new equipment, each of these companies is a major supplier for equipment rentals, parts and service labour. We have seen a significant reduction in lead time required for placing heavy equipment orders which allows us to react quickly to increased demand for our services from our customers. We are also actively working with these suppliers to identify cost saving opportunities such as reducing our rental fleet and focusing on parts management.

Tire supply has been a challenge for our haul truck fleet over the past few years. We prefer to use radial tires from proven manufacturers, but the shortage of supply in past forced us to use bias tires and source radial tires from new manufacturers. Bias tires have a shorter usage life and are of a lower quality than radial tires. This affects operations as we are forced to reduce operating speeds and loads to compensate for the quality of the tires. Tire supply has continued to improve over the past year. The reduction in demand for tires has resulted in a decline in the premium pricing from these non-dealer sources. Given this reduction in price, combined with the improved tire supply, we reduced our inventory levels during the current year and eliminated the purchase of bias tires.

Variability of Results

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

In addition to revenue variability, gross margins can be negatively impacted in less active periods because we are likely to incur higher maintenance and repair costs due to our equipment being available for servicing. Profitability also varies from period-to-period due to claims and change orders. Claims and change orders are a normal aspect of the contracting business but can cause variability in profit margin between quarters due to the unmatched recognition of costs in one quarter and revenues in a subsequent quarter.

During the higher activity periods, we have experienced improvements in operating income due to operating leverage. General and administrative costs are generally fixed and we see these costs decrease as a percentage of revenue when our project volume increases. Net income and earnings per share are also subject to operating leverage as provided by fixed interest expense. However, we have experienced earnings variability in all periods due to the recognition of realized and unrealized non-cash gains and losses on derivative financial instruments and foreign exchange primarily driven by changes in the Canadian and US dollar exchange rates. The non-cash goodwill impairment charge, recognized in the year ended March 31, 2009, added to the earnings variability.

|  |  |  | 21 |  |

##### Table of Contents

Legal and Labour Matters

Laws, Regulations and Environmental Matters

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

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

Ÿ |  | building and similar codes and zoning ordinances;

Ÿ |  | laws and regulations relating to consumer protection; and

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

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

Our operations are subject to numerous federal, provincial and municipal environmental laws and regulations, including those governing the release of substances, the remediation of contaminated soil and groundwater, vehicle emissions and air and water emissions. These laws and regulations are administered by federal, provincial and municipal authorities, such as Environment Canada, Alberta Environment, Saskatchewan Environment, the British Columbia Ministry of Environment and other governmental agencies. The requirements of these laws and regulations are becoming increasingly complex and stringent and meeting these requirements can be expensive.

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

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

The nature of our operations and our ownership or operation of property exposes us to the risk of claims with respect to environmental matters and there can be no assurance that material costs or liabilities will not be incurred with such claims. For example, some laws can impose strict, joint and several liability on past and present owners or operators of facilities at, from or to which a release of hazardous substances has occurred, on parties who generated hazardous substances that were released at such facilities and on parties who arranged for the transportation of hazardous substances to such facilities. If we were found to be a responsible party under these statutes, we could be held liable for all investigative and remedial costs associated with addressing such contamination, even though the releases were caused by a prior owner or operator or third party. We are not currently named as a responsible party for any environmental liabilities on any of the properties on which we currently perform or have performed services.

Capital expenditures relating to environmental matters during the fiscal years ended March 31, 2010, 2009 and 2008 were not material. We do not currently anticipate any material adverse effect on our business or financial position as a result of future compliance with applicable environmental laws and regulations. Future events, however, such as changes in existing laws and regulations or their interpretation, more vigorous enforcement policies of regulatory agencies or stricter or different interpretations of existing laws and regulations may require us to make additional expenditures which may or may not be material.*

Employees and Labour Relations

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

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

|  | 22 |  |  |  |

##### Table of Contents

Engineers and Labourers Unions, Piling sector collective agreements in Saskatchewan with the Operating Engineers and Labourers, Pipeline sector agreements in both British Columbia and Alberta with the Christian Labour Association of Canada (“CLAC”) as well as an all-sector agreement with CLAC in Ontario. We are subject to other industry and specialty collective agreements under which we complete work and the primary terms of all of these agreements are currently in effect. We believe that our relationships with all our employees, both union and non-union, are strong. We have not experienced a strike or lockout.*

The IPO and Reorganization

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

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

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

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

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

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

Description of Share Capital

General

Our articles of amalgamation authorize us to issue an unlimited number of voting common shares and an unlimited number of non-voting common shares. As of June 8, 2010, we had 36,062,036 common shares outstanding (36,049,276 outstanding as at March 31, 2010).

Some of the statements contained herein are summaries of the material provisions of our articles of amalgamation relating to dividends, distribution of assets upon dissolution, liquidation or winding up and are qualified in their entirety by reference to our articles of amalgamation which can be found on www.sedar.com.

Voting Common Shares

Each voting common share has an equal and ratable right to receive dividends to be paid from our assets legally available therefore when, as and if declared by our board of directors. Our ability to declare dividends is restricted by the terms of the indenture that governs our 8 3/4% senior notes. See “Description of Certain Indebtedness” elsewhere in this AIF.

In the event of our dissolution, liquidation or winding up, the holders of common shares are entitled to share equally and ratably in the assets available for distribution after payments are made to our creditors. Holders of common shares have no pre-emptive rights or other rights to subscribe for our securities. Each common share entitles the holder thereof to one vote in the election of directors and all other matters submitted to a vote of shareholders, and holders of common shares have no rights to cumulate their votes in the election of directors.

|  |  |  | 23 |  |

##### Table of Contents

Non-Voting Common Shares

Regulatory requirements applicable to affiliates of one of our shareholders limited the amount of our voting shares it may own. Therefore, in addition to our voting common shares that it owns, it also owned all of our non-voting common shares, which it acquired on November 26, 2003. Except as prescribed by Canadian law and except in limited circumstances, the non-voting common shares have no voting rights but are otherwise identical to the voting common shares in all respects. The non-voting common shares are convertible into voting common shares on a share-for-share basis at the option of the holder if it transfers, sells or otherwise disposes of the converted voting common shares: (i) in a public offering of our voting common shares; (ii) to a third party that, prior to such sale, controls us; (iii) to a third party that, after such sale, is a beneficial owner of not more than 2% of our outstanding voting shares; (iv) in a transaction that complies with Rule 144 under the Securities Act of 1933, as amended; or (v) in a transaction approved in advance by regulatory bodies.

On July 27, 2007, the holder of the Company’s non-voting common shares exchanged its non-voting common shares for voting common shares. Each holder of the non-voting common shares received one voting common share for each non-voting share held on the exchange date.

Dividends

We have not declared or paid any dividends on our common shares since our inception, and we do not anticipate declaring or paying any dividends on our common shares for the foreseeable future. We currently intend to retain any future earnings to finance future growth. Any future determination to pay dividends will be at the discretion of our board of directors and will depend on our financial condition, results of operations, capital requirements and other factors the board of directors considers relevant. In addition, our ability to declare and pay dividends is restricted by our governing statute, as well as the terms of our credit agreement and the indenture that governs our 9.125% Series 1 Debentures.

Trading Price and Volume

The following tables summarize the highest trading price, lowest trading price and volume for our common shares on the Toronto Stock Exchange (in Canadian dollars) and on the New York Stock Exchange (in US dollars) on a monthly basis from April 1, 2009 to May 31, 2010:

Toronto Stock Exchange

Date |  | High |  | Low |  | Volume
May 2010 |  | $11.35 |  | $8.80 |  | 233,382
April 2010 |  | 11.76 |  | 9.68 |  | 429,557
March 2010 |  | 11.00 |  | 8.74 |  | 494,961
February 2010 |  | 11.00 |  | 7.10 |  | 509,891
January 2010 |  | 8.46 |  | 7.02 |  | 128,358
December 2009 |  | 7.80 |  | 6.18 |  | 118,390
November 2009 |  | 6.90 |  | 5.60 |  | 595,659
October 2009 |  | 7.30 |  | 5.91 |  | 167,623
September 2009 |  | 7.40 |  | 6.25 |  | 74,080
August 2009 |  | 7.63 |  | 5.50 |  | 358,524
July 2009 |  | 6.88 |  | 5.26 |  | 205,723
June 2009 |  | 9.27 |  | 5.49 |  | 402,956
May 2009 |  | 7.85 |  | 4.54 |  | 346,206
April 2009 |  | 5.05 |  | 3.53 |  | 145,215
New York Stock Exchange |  |  |  |  |  |
Date |  | High |  | Low |  | Volume
May 2010 |  | $11.44 |  | $8.15 |  | 4,777,909
April 2010 |  | 11.68 |  | 9.51 |  | 4,191,250
March 2010 |  | 10.60 |  | 8.45 |  | 4,815,032
February 2010 |  | 10.44 |  | 6.51 |  | 9,249,005
January 2010 |  | 8.20 |  | 6.51 |  | 1,940,600
December 2009 |  | 7.50 |  | 5.96 |  | 1,939,507
November 2009 |  | 6.59 |  | 5.43 |  | 2,731,308
October 2009 |  | 6.90 |  | 5.42 |  | 2,267,855
September 2009 |  | 6.91 |  | 5.79 |  | 1,867,771
August 2009 |  | 7.03 |  | 5.04 |  | 3,605,509
July 2009 |  | 6.20 |  | 4.51 |  | 2,984,142
June 2009 |  | 8.56 |  | 4.75 |  | 5,333,677
May 2009 |  | 7.16 |  | 3.82 |  | 3,352,533
April 2009 |  | 4.18 |  | 2.81 |  | 3,230,868

|  | 24 |  |  |  |

##### Table of Contents

Description of Certain Indebtedness

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

9.125% Series 1 Debentures

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

8 3/4% Senior Notes Redemption

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

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

Termination of Cross-Currency and Interest Rate Swaps

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

$50.0 million Term Facility and Use of Cash

On April 30, 2010, we entered into a fourth amended and restated credit agreement to extend the term of the credit agreement and also to add additional borrowings of up to $50.0 million through a second term facility within the credit agreement. At April 30, 2010, the Term B Facility was fully drawn at $50.0 million. The cash from the $50.0 term facility along with cash on hand was used to settle the balance of the 8 3/4% senior notes redemption and the terminated swaps.

Credit Facility (Including April 2010 Subsequent Event)

On June 7, 2007, we entered into an amended and restated credit agreement with a syndicate of lenders that provided us with a $125.0 million revolving credit facility.

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

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

On April 30, 2010, we entered into a fourth amended and restated credit agreement to extend the term of the credit facilities to April 30, 2013 and increase the amount of the term loans. The new agreement includes the following borrowing capacity:

Ÿ |  | an amended Revolving Facility, reduced to $85.0 million (previously $90.0 million);

Ÿ |  | Term A Facility, established in the June 24, 2009 third amended and restated credit agreement, continued with a balance of $28.4 million as of April 30, 2010; and

Ÿ |  | a new $50.0 million term facility (“Term B Facility”), which was fully drawn as of April 30, 2010.

|  |  |  | 25 |  |

##### Table of Contents

The total available borrowing was increased to up to $163.4 million (previously $125.0 million) under which revolving loans, term loans and letters of credit could be drawn. As of April 30, 2010, both term facilities were fully drawn, for a total of $78.4 million of borrowing. The Revolving Facility had no outstanding borrowings and $14.4 million of issued and undrawn letters of credit, leaving $70.6 million of available borrowings.

Advances under the Revolving Facility may be repaid from time to time at our option. The term facilities include mandatory repayments totalling $10.0 million per year with $2.5 million paid on the last day of each quarter, commencing June 30, 2010, with the balance due April 30, 2013. The credit facility, based on the type of borrowing, bears interest at the Canadian prime rate, the US dollar base rate, the Canadian bankers’ acceptance rate or the London interbank offered rate (LIBOR) (all such terms as used or defined in the fourth amended and restated credit agreement) plus applicable margins. In each case, the applicable pricing margin depends on our current debt rating. For a discussion on our current debt rating, refer to the “Debt Ratings” section of this Annual Information Form. In addition, we must make annual principal payments within 120 days of the end of our fiscal year in the amount of 50% of Consolidated Excess Cash Flow (as defined in the credit agreement) to a maximum of $4.0 million.

The following is a summary of certain provisions of the fourth amended and restated credit agreement:

Security: The fourth amended and restated credit agreement are secured by a first priority lien on substantially all of our existing and after acquired property and contain customary covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions or paying dividends or redeeming shares of capital stock.

Interest rates and fees: The facilities bear interest on each prime loan at variable rates based on the Canadian prime rate plus the applicable pricing margin (as defined within the fourth amended and restated credit agreement). Interest on Bankers’ Acceptances is paid, in advance, at a rate per annum based on the applicable CDOR rate with respect to such interest period plus a stamping fee and the applicable pricing margin. Interest on US base rate loans is paid at a rate per annum equal to the US base rate plus the applicable pricing margin. Interest on prime and US base rate loans is payable monthly in arrears and computed on the basis of a 365-day or 366-day year, as the case may be. Interest on LIBOR loans is paid during each interest period at a rate per annum, calculated on a 360-day year, equal to the LIBOR rate with respect to such interest period plus the applicable pricing margin. Letters of credit are subject to a fee payable quarterly in arrears, calculated at a rate per annum equal to the applicable pricing margin and on the average daily amount of such letters of credit for the number of days such letters of credit were outstanding. Letters of credit are also subject to customary fees and expenses and a fronting fee equal to the greater of $500 or 0.125% per annum on the amount of such letter of credit paid quarterly in arrears. Standby fees are calculated at a rate per annum equal to the applicable pricing margin on the amount by which the amount of the outstanding principal owing to each lender under the fourth amended and restated credit agreement for each day is less than the commitment of such lender and accrue daily from the first day to the last day of each fiscal quarter. In each case, the applicable pricing margin depends on our credit rating. Interest rates are increased by 2% per annum in excess of the rate otherwise payable on any amount not paid when due.

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

Covenants:

We are required to meet certain financial covenants under the fourth amended and restated credit agreement including:

Consolidated Interest Coverage Ratio, which is determined based on a ratio of Consolidated EBITDA (as defined within the fourth amended and restated credit agreement) to Consolidated Cash Interest Expense, must be greater than 2.5 times. Senior Leverage Ratio, which is determined based on a ratio of Senior Debt to Consolidated EBITDA (as defined within the fourth amended and restated credit agreement), measured as of the last day of each fiscal quarter on a trailing four-quarter basis, shall not exceed 2.0 times;

Current Ratio, which is determined based on the ratio of current assets to current liabilities (as defined within the fourth amended and restated credit agreement), measured as of the last day of each fiscal quarter, shall not be less than 1.25 times.

Continued access to the facilities is not contingent on the maintenance of a specific credit rating.

The fourth amended and restated credit agreement also contains restrictive covenants limiting our ability, and the ability of our Subsidiaries to, without limitation and subject to various exceptions:

Ÿ |  | incur debt or enter into sale and leaseback transactions or contractual contingent obligations;

|  | 26 |  |  |  |

##### Table of Contents

Ÿ |  | amend the indenture governing our 9.125% Series 1 Debentures (this replaces the covenant specific to the 8 3/4 % senior notes indenture);

Ÿ |  | create or allow to exist liens or other encumbrances;

Ÿ |  | transfer assets (including any notes or receivables or capital stock of Subsidiaries) except for sales and other transfers of inventory or surplus, immaterial or obsolete assets in our ordinary course of business and other exceptions set forth in the credit agreement;

Ÿ |  | enter into mergers, consolidations and asset dispositions of all or substantially all of our, or any of our Subsidiaries’ properties;

Ÿ |  | make investments, including acquisitions;

Ÿ |  | enter into transactions with related parties other than on an arm’s-length basis on terms no less favourable to us than those available from third parties;

Ÿ |  | make any material change in the general nature of the business conducted by us; and

Ÿ |  | make consolidated capital expenditures in excess of 120% of the amount in the capital expenditure plan as approved by our board of directors.

Events of default: The fourth amended and restated credit agreement contains customary events of default, including, without limitation, failure to make payments when due, defaults under other agreements or instruments of indebtedness, non-compliance with covenants, breaches of representations and warranties, bankruptcy, judgments in excess of specified amounts, invalidity of loan documents, impairment of security interest in collateral and changes of control.

Financing fees of approximately $1.0 million were incurred in connection with the fourth amended and restated credit agreement dated April 30, 2010. These fees will be recorded as deferred financing costs in the three months ending June 30, 2010 and are to be amortized using the effective interest method over the remaining term of the agreement.

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

8 3/4% Senior Notes due 2011 (Redeemed April 2010)

General: On November 26, 2003, we issued an aggregate principal amount of US$200.0 million of 8 3/4% senior notes pursuant to an indenture among us, the subsidiary guarantors and Wells Fargo Bank, N.A., as trustee. These notes were to mature on December 1, 2011. Interest on these notes accrued at 8 3 /4% per annum and was payable in arrears on June 1 and December 1 of each year. All of our Subsidiaries jointly and severally guaranteed the 8 3/4% senior notes.

Redemption and Repurchase: We were able to redeem some or all of the 8 3/4% senior notes at any time on or after December 1, 2007, at specified redemption prices. We were able to redeem up to 35% of the original aggregate principal amount of the 8 3/ 4% senior notes in the event of certain equity sales at any time on or before December 1, 2006 at a redemption price equal to 108.75%. We were able to redeem all but not part of the notes in the event of various changes in the laws affecting withholding taxes. We were not required to make mandatory redemption or sinking fund payments with respect to the 8 3/4% senior notes. On March 29, 2010, we issued a redemption notice to holders of the notes to redeem all outstanding 8 3/4% senior notes and on April 28, 2010, the notes were redeemed and cancelled.

Change of Control: We were required to offer to repurchase the 8 3/4% senior notes from holders if we underwent a change of control or sold our assets in specified circumstances.

Covenants: The indenture governing the 8 3/4% senior notes restricted, among other things, our ability to pay dividends, redeem capital stock or prepay certain subordinated debt; incur additional debt or issue preferred stock; grant liens; merge, consolidate or transfer substantially all of our assets; enter into certain transactions with affiliates; impose restrictions on any subsidiary’s ability to pay dividends or transfer assets to us; enter into certain sale and leaseback transactions; and permit subsidiaries to guarantee debt. All of these restrictions were subject to customary exceptions.

|  |  |  | 27 |  |

##### Table of Contents

Swap Agreements (Terminated April 2010)

We entered into three separate “International Swap Dealer Association – Master Agreements”, one with BNP Paribas, as counterparty, dated November 23, 2003; one with HSBC Bank Canada, as counterparty, dated March 26, 2004; and one with CIBC, as counterparty, dated August 9, 2006. These agreements are collectively referred to as the “swap agreements”. Pursuant to the swap agreements, we have and may enter into one or more interest rate or currency swap transactions governed by the terms of the swap agreements and the confirmations issued by the counterparty in respect of each transaction. The swap agreements contain customary representations and warranties, covenants and events of default. Specifically, each swap agreement contains a provision that an event of default under our existing credit agreement will constitute an event of default under such swap agreement and that the counterparty will be entitled to terminate the swap agreement if our payment obligations to the counterparty cease to be secured pari passu with the obligations under the credit agreement.

On December 17, 2008, we received notice that all three swap counterparties had exercised the cancellation option on the US dollar interest rate swap and, effective February 2, 2009, the US dollar interest rate swap was terminated. In addition to net accrued interest to the termination date of US$0.7 million, the counterparties paid a cancellation premium of 2.2% on the notional amount of US$200.0 million or US$4.4 million (equivalent to C$5.3 million).

As a result of this cancellation of the US dollar interest rate swap, we were exposed to changes in the value of the Canadian dollar versus the US dollar. To the extent that three month LIBOR was less than 4.6% (the difference between the 8.75% coupon on our 8 3/4% senior notes and the 4.2% spread over three month LIBOR on the cross currency basis swap), we had to acquire US dollars to fund a portion of the semi-annual coupon payment on our 8 3/4% senior notes. At the three month LIBOR rate of 0.268% at March 31, 2010, a $0.01 increase (decrease) in the Canadian dollar would result in an insignificant decrease (increase) in the amount of Canadian dollars required to fund each semi-annual coupon payment.

As a result of the US dollar interest swap cancellation above, we were also exposed to changes in interest rates. We had a fixed semi-annual coupon payment of 8.75% on our US$200.0 million 8 3/4% senior notes. With the termination of the US dollar interest rate swap, we no longer received fixed US dollar payments from the counterparties to offset the coupon payment on our 8 3/4% senior notes. As a result, we had interest rate exposure to changes in the three month LIBOR rate (0.268% at March 31, 2010). As at the effective date of the cancellation, at the current LIBOR rate, our effective annual interest costs increased by US$6.8 million per annum over the remaining term of the 8 3/4% senior notes. A 100 basis point increase (decrease) in the three month LIBOR rate would result in a US$2.0 million increase (decrease) in the annual floating rate payment received from the swap counterparties.

As of March 31, 2010, the liability, measured at fair value, associated with the swap agreements was approximately $81.1 million.

9.125% Series 1 Debentures due 201715 (Issued April 7, 2010)

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

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

Redemption and Repurchase: The Series 1 Debentures are redeemable at our option, in whole at any time, or in part from time to time, on not fewer than 30 and not more than 60 days prior notice, on or after: April 7, 2013 at 104.563% of the principal amount redeemed; April 7, 2014 at 103.042% of the principal amount redeemed; April 7, 2015 at 101.520% of the principal amount redeemed; April 7, 2016 and thereafter at 100.000% of the principal amount redeemed. In addition, accrued and unpaid interest, if any, will be paid to the redemption date.

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

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

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

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

15 | The following is a summary which does not purport to be complete. Reference should be made to the trust indenture, available on SEDAR at www.sedar.com for the complete details of the trust indenture.

|  | 28 |  |  |  |

##### Table of Contents

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

Covenants: The indenture governing the Series 1 Debentures restricts, among other things, our ability to pay dividends, redeem capital stock or prepay certain subordinated debt; incur additional debt or issue preferred stock; grant liens; merge, consolidate or transfer substantially all of our assets; enter into certain transactions with affiliates; impose restrictions on any subsidiary’s ability to pay dividends or transfer assets to us; enter into certain sale and leaseback transactions; and permit subsidiaries to guarantee debt. All of these restrictions are subject to customary exceptions.

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

Letters of Credit

One of our major contracts allows the customer to require that we provide up to $50.0 million in letters of credit. As at March 31, 2010, we had $10.0 million in letters of credit outstanding in connection with this contract (we had $10.4 million in letters of credit outstanding in total for all customers as of March 31, 2010). Any change in the amount of the letters of credit required by this customer must be requested by November 1st in each year for an issue date of January 1st following the date of such request, for the remaining life of the contract.

Debt Ratings

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

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

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

(1) | Loss Given Default

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

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

Standard & Poor’s

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

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

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

Moody’s

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

|  |  |  | 29 |  |

##### Table of Contents

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

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

Directors and Officers

The following table sets forth information about our directors and executive officers. Ages reflected are as of May 31, 2010. Each director is elected for a one-year term or until such person’s successor is duly elected or appointed, unless his office is earlier vacated. Unless otherwise indicated below, the business address of each of our directors and executive officers is Suite 2400, 500 4 th Avenue SW, Calgary, Alberta, T2P 2V6. As of May 31, 2010, the directors and executive officers of the Company, as a group, beneficially owned, directly or indirectly, or exercised control or direction over 798,755 common shares of the Company (representing approximately 2.2% of all issued and outstanding common shares).

Name and Municipality of Residence |  | Age |  | Position
Rodney J. Ruston Calgary, Alberta, Canada |  | 59 |  | Director, President and Chief Executive Officer
David Blackley Calgary, Alberta, Canada |  | 49 |  | Chief Financial Officer
Robert G. Harris Edmonton, Alberta, Canada |  | 62 |  | Vice President, Human Resources, Health, Safety & Environment
Kevin Mather Calgary, Alberta, Canada |  | 37 |  | Vice President, Supply Chain & Estimating
Bernard T. Robert Calgary, Alberta, Canada |  | 43 |  | Vice President, Corporate Affairs & Business Strategy
Christopher R. Yellowega Airdrie, Alberta, Canada |  | 39 |  | Vice President, Operations
Ronald A. McIntosh Calgary, Alberta, Canada |  | 68 |  | Chairman of the Board
George R. Brokaw Southampton, New York, United States |  | 42 |  | Director
John A. Brussa Calgary, Alberta, Canada |  | 53 |  | Director
Peter R. Dodd Sydney, Australia |  | 60 |  | Director
John D. Hawkins Houston, Texas, United States |  | 46 |  | Director
William C. Oehmig Houston, Texas, United States |  | 60 |  | Director
Allen R. Sello West Vancouver, British Columbia, Canada |  | 70 |  | Director
Peter W. Tomsett West Vancouver, British Columbia, Canada |  | 52 |  | Director
K. Rick Turner Houston, Texas, United States |  | 52 |  | Director

|  | 30 |  |  |  |

##### Table of Contents

Rodney J. Ruston became President, Chief Executive Officer of NAEPI on May 9, 2005 and a Director of NAEPI on June 15, 2005. He took the Company public with a listing on both the NYSE and TSX on November 22, 2006. In 2007, Mr. Ruston joined Northern Alberta Institute of Technology’s President’s Advisory Committee. Previously, Mr. Ruston was Managing Director and Chief Executive Officer of Ticor Limited, a publicly listed Australian natural resources company with operations in Australia, South Africa, and Madagascar. Mr. Ruston has spent his entire career in the natural resources industry, holding management positions with Pasminco Limited, Savage Resources Limited, Wambo Mining Corporation, Oakbridge Limited and Kembla Coal & Coke Pty. Limited. He was Chairman of the Australian Minerals Tertiary Education Council from July 2003 until May 2005 and received his Masters of Business Administration from the University of Wollongong and Bachelor of Engineering (Mining) from the University of New South Wales in Australia.

David Blackley became Chief Financial Officer of NAEPI on June 11, 2009. Mr. Blackley joined NAEPI as Vice-President, Finance on January 14, 2008, bringing extensive experience leading accounting and financial reporting teams and overseeing the design and implementation of internal financial controls and processes. Previously Mr. Blackley served as Vice-President, Finance of Lafarge North America’s Aggregates and Concrete division. A Chartered Accountant, Mr. Blackley holds a Bachelor of Commerce from Rhodes University in South Africa.

Robert G. Harris became Vice-President, Human Resources, Health, Safety & Environment on June 19, 2006. Mr. Harris began his career in 1969 with Chrysler Canada in various personnel and human resources positions before taking on the role of Environmental Health & Safety Manager and subsequently the Labour Relations Supervisor role. In 1982, he accepted a position with IPSCO Inc. where he was responsible for human resources over six facilities in Canada and the United States. Since 1987, he has held senior human resources roles at Labatt Breweries of Canada including National Manager, Industrial Relations & Training and Director, Human Resources at both regional and national levels. Mr. Harris graduated in 1969 from the University of Windsor with a Bachelor of Arts in Sociology/Psychology and has received his Certified Human Resources Professional designation.

Kevin Mather joined us in 1998 and held various project positions working on Syncrude projects in the oil sands prior to becoming a Project Manager in 2000. As a Project Manager, Mr. Mather managed our work developing the Albian Sands Muskeg River Mine. Mr. Mather was appointed General Manager, Heavy Construction and Mining in 2004 as the division executed major projects at Canadian Natural’s Horizon Mine, Syncrude Aurora and Base Mines, Albian Sands Muskeg River and Jackpine Mines, Grande Cache Coal and DeBeers Victor Diamond Mine until he was appointed Vice-President, Supply Chain Management on December 1, 2007, and Vice-President, Supply Chain & Estimating on January 23, 2009. Mr. Mather attended the University of Alberta and obtained a Bachelor of Science in Civil Engineering in 1996 and his Masters of Science in Construction Engineering and Management in 1998.

Bernard T. Robert joined us in March 1998 as Controller and held various positions within the Finance department including Director, Project Accounting and Treasurer until his transfer to the position of Director, Business Development in 2006. Mr. Robert held this position until he was appointed Vice-President, Business Development and Estimating on September 1, 2007. On January 23, 2009, Mr. Robert was appointed Vice-President, Corporate Affairs and Business Strategy. Prior to joining us, Mr. Robert worked as the Manager, Budgets & Forecasts for Telus Communications in Edmonton. Mr. Robert began his career at Enbridge Pipelines Inc. (formerly Interprovincial Pipelines Inc.) where he worked in various roles within the Finance and Regulatory areas. Mr. Robert is a Certified General Accountant having graduated in 1995.

Christopher R. Yellowega became Vice-President, Major Mining Projects on April 1, 2008 bringing with him an extensive oil sands development and operations experience. He was appointed Vice-President, Operations on January 23, 2009. Prior to joining us, Mr. Yellowega served as Vice President, Upstream Operations with Synenco Energy Inc., where he played a leadership role in planning and designing a major oil sands mining development. Before that, Mr. Yellowega served at the Athabasca Oilsands Project Expansion (Albian Sands) as Superintendent responsible for leading the expansion project team for upstream operations. A Mining Engineer, Mr. Yellowega is currently a member of the Board of Directors for the Alberta Chamber of Resources and is recognized as a Registered Professional Engineer.

Ronald A. McIntosh became Chairman of our Board of Directors on May 20, 2004. From January 2004 until August of 2006, Mr. McIntosh was Chairman of NAV Energy Trust, a Calgary based oil and natural gas investment fund. Between October 2002 and January 2004, he was President and Chief Executive Officer of Navigo Energy Inc. and was instrumental in the conversion of Navigo into NAV Energy Trust. He was Senior Vice President and Chief Operating Officer of Gulf Canada Resources Limited from December 2001 to July 2002 and Vice President, Exploration and International of Petro-Canada from April 1996 through November 2001. Mr. McIntosh’s significant experience in the energy industry includes the former position of Chief Operating Officer of Amerada Hess Canada. Mr. McIntosh is on the Board of Directors of Advantage Oil & Gas Ltd. and Fortress Energy Inc.

George R. Brokaw became one of our Directors on June 28, 2006. Mr. Brokaw joined Perry Capital, L.L.C., an affiliate of Perry Corp., in August 2005. Mr. Brokaw is a Managing Director of Perry Corp. From January 2003 to May 2005, Mr. Brokaw was Managing Director (Mergers & Acquisitions) of Lazard Frères & Co. LLC, which he joined in 1996. Between 1994 and 1996, Mr. Brokaw was an investment banking associate for Dillon Read & Co. Mr. Brokaw received a Bachelor of Arts degree from Yale University and a Juris Doctorate and Masters of Business Administration from the

|  |  |  | 31 |  |

##### Table of Contents

University of Virginia. He is admitted to practice law in the State of New York. Investment entities controlled by Perry Corp. are holders of our common shares. (See our most recent information circular that involved the elections of directors for details.)

John A. Brussa became one of our Directors on November 26, 2003. Mr. Brussa is a senior partner and head of the Tax Department at the law firm of Burnet, Duckworth & Palmer LLP, a leading natural resource and energy law firm located in Calgary. He has been a partner since 1987 and has worked at the firm since 1981. Mr. Brussa is Chairman of Penn West Energy Trust and Crew Energy Inc. Mr. Brussa also serves as a director of a number of natural resource and energy companies. He is a member and former Governor of the Executive Committee of the Canadian Tax Foundation. Mr. Brussa attended the University of Windsor and received his Bachelor of Arts in History and Economics in 1978 and his Bachelor of Law in 1981.

Peter R. Dodd retired as Chief Financial Officer of NAEPI on June 10, 2009 and became a non-independent director of the Corporation. Mr. Dodd has over 25 years experience in strategic business planning, corporate finance and investment banking. Prior to joining NAEPI, Mr. Dodd served as Director of Strategy and Development for CSR Ltd., an Australian based conglomerate with sugar, building products, aluminium and property divisions. Previously, Mr. Dodd was Managing Director and Global Head of Corporate Finance for ABN AMRO in London, England, managing corporate finance teams in 23 countries. Mr. Dodd has a PhD in Accounting and Finance from the William E. Simon School of Management at the University of Rochester and is currently Deputy Vice-Chancellor & Chief Operating Officer of Macquarie University in Sydney, Australia.

John D. Hawkins became one of our Directors on October 17, 2003. Mr. Hawkins joined The Sterling Group, L.P. in 1992 and has been a Partner since 1999. The Sterling Group is a private equity investment firm and an investment entity affiliated with the Sterling Group that is a holder of our common shares. (See our most recent information circular that involved the elections of directors for details.) Before joining Sterling he was on the professional staff of Arthur Andersen & Co. from 1986 to 1990. He received a Bachelor of Science in Business Administration in Accounting from the University of Tennessee and his Masters of Business Administration from the Owen Graduate School of Management at Vanderbilt University.

William C. Oehmig served as Chairman of our Board of Directors from November 26, 2003 and until passing off this position and assuming the role of Director and chair of the Executive Committee on May 20, 2004. He now serves as chairman of the Risk Committee and on the Compensation Committee. Mr. Oehmig is a Partner with The Sterling Group, L.P., a private equity investment firm. An investment entity affiliated with The Sterling Group is a holder of our common shares. (See our most recent information circular that involved the elections of directors for details.) Prior to joining Sterling in 1984, Mr. Oehmig worked in banking, mergers and acquisitions, and represented foreign investors in purchasing and managing U.S. companies in the oilfield service, manufacturing, distribution, heavy equipment and real estate sectors. He began his career in Houston in 1974 at Texas Commerce Bank. Mr. Oehmig currently serves on the board of Universal Fibers Inc. In the past he has served as Chairman of Royster-Clark, Purina Mills, Exopack and Sterling Diagnostic Imaging and has served on the board of several portfolio companies since joining Sterling. Mr. Oehmig serves or has served on numerous other corporate non-profit boards. Mr. Oehmig received his Bachelor of Business Administration (B.B.A.) in Economics from Transylvania University and his Masters of Business Administration (M.B.A.) from the Owen Graduate School of Management at Vanderbilt University.

Allen R. Sello became one of our Directors on January 26, 2006. His career began at Ford Motor Company of Canada in 1964, where he held finance and marketing management positions, including Treasurer. In 1979, Mr. Sello joined Gulf Canada Limited, at which he held various senior financial positions, including Vice-President and Controller. He was appointed Vice-President, Finance of its successor company Gulf Canada Resources Limited in 1987 and Chief Financial Officer in 1988. Mr. Sello then joined International Forest Products Ltd. in 1996 as Chief Financial Officer. From 1999 until his retirement in 2004 he held the position of Senior Vice-President and Chief Financial Officer for UMA Group Limited. Mr. Sello is currently a trustee of Sterling Shoes Income Fund and Chair of the Vancouver Board of Trade Government Provincial Budget and Finance Committee. Mr. Sello received his Bachelor of Commerce from the University of Manitoba and his Masters of Business Administration (M.B.A.) from the University of Toronto.

Peter W. Tomsett became one of our Directors on September 20, 2006. From September 2004 to January 2006, Mr. Tomsett was President & Chief Executive Officer of Placer Dome Inc. based in Vancouver. He joined the Placer Dome Group in 1986 as a Mining Engineer with the Project Development group in Sydney, Australia. After various project and operating positions, he assumed the role of Executive Vice-President, Asia-Pacific for Placer Dome Inc. in 2001. In 2004, Mr. Tomsett also took on responsibility for Placer Dome Africa which included mines in South Africa and Tanzania. Mr. Tomsett has been a Director of the Minerals Council of Australia, the World Gold Council and the International Council for Mining & Metals. Mr. Tomsett graduated with a Bachelor of Engineering (Honours) in Mining Engineering from the University of New South Wales and also attained a Master’s of Science (Distinction) in Mineral Production Management from Imperial College, London. Mr. Tomsett is also a director of Silver Standard Resources Inc.

K. Rick Turner became one of our Directors on November 26, 2003. Mr. Turner has been employed by Stephens’ family entities since 1983. Mr. Turner is currently Senior Managing Director of The Stephens Group, LLC. He first became a private equity principal in 1990 after serving as the Assistant to the Chairman, Jackson T. Stephens. His areas of focus

|  | 32 |  |  |  |

##### Table of Contents

have been oil and gas exploration, natural gas gathering, processing industries and power technology. Mr. Turner currently serves as a director of Atlantic Oil Corporation; JV Industrials, LLC; JEBCO Seismic, LLC; Seminole Energy Services, LLC; the General Partner of Energy Transfer Partners, LP (“ETP”); and the General Partner of Energy Transfer Equity, LP (“ETE”). Prior to joining Stephens, Mr. Turner was employed by Peat, Marwick, Mitchell and Company. Mr. Turner earned his Bachelor of Science in Business Administration (B.S.B.A.) from the University of Arkansas and is a non-practicing Certified Public Accountant.

The Board and Board Committees

Our board supervises the management of our business as provided by Canadian law. We comply with the listing requirements of the New York Stock Exchange applicable to domestic listed companies, which require that our board of directors be composed of a majority of independent directors. Accordingly, a majority of our board members are independent.

Our board has established the following committees:

Audit Committee

The Audit Committee recommends independent public accountants to the board of directors, reviews the quarterly and annual financial statements and related MD&A, press releases, auditor reports and the fees paid to our auditors. The Audit Committee approves quarterly financial statements and recommends annual financial statements for approval to the board of directors. In accordance with Rule 10A-3 under the Securities Exchange Act of 1934, as amended, the listing requirements of the New York Stock Exchange and the requirements of the Canadian Securities regulatory authorities, our board of directors has affirmatively determined that our Audit Committee is composed solely of independent directors. The board of directors has determined that Mr. Allen R. Sello is the audit committee financial expert, as defined by Item 407(d) (5) of the SEC’s Regulation S-K. Our board of directors has adopted a written charter for the Audit Committee that is attached as Exhibit A to this AIF. The Audit Committee is currently composed of Messrs. Brokaw, Hawkins, McIntosh, Sello and Turner, with Mr. Sello serving as Chairman. Based on their experience (see “Directors and Officers” above), each of the members of the Audit Committee is financially literate. The members of the audit committee have significant exposure to the complexities of financial reporting associated with us and are able to provide due oversight and the necessary governance over, our financial reporting.

Our auditors are KPMG LLP. Our Audit Committee pre-approved the engagement of KPMG to perform the audit of our financial statements for the fiscal year ended March 31, 2010.

The fees we have paid to KPMG for services rendered by them include:

Ÿ |  | Audit Fees KPMG billed us $1,852,800, $2,374,000 and $3,037,500 for audit fees during the years ended March 31, 2010, 2009 and 2008, respectively. Audit fees were incurred for the audit of our annual financial statements, the audit of compliance and internal controls over financial reporting, related audit work in connection with registration statements and other filings with various regulatory authorities, and quarterly interim reviews of the consolidated financial statements.

Ÿ |  | Audit Related Fees KPMG billed us $394,645, $nil and $55,000 during the years ended March 31, 2010, 2009 and 2008, respectively, for professional services related to the conversion to United States generally accepted accounting principles (US GAAP) and for planning and scoping work and advice relating to internal controls over financial reporting.

Ÿ |  | Tax Fees KPMG billed us $7,500, $62,000 and $33,000 for the years ended March 31, 2010, 2009 and 2008, respectively, for income tax advisory and compliance services.

Ÿ |  | All Other Fees KPMG billed us nil, $64,000 and nil, for the years ended March 31, 2010, 2009 and 2008 respectively, for fees related to analysis of the conversion to International Financial Reporting Standards (IFRS), respectively. KPMG did not perform any other services for us in the years ended March 31, 2010 and 2008.

Compensation Committee

The Compensation Committee is charged with the responsibility for supervising executive compensation policies for us and our 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. In accordance with the listing requirements of the New York Stock Exchange applicable to domestic listed companies and applicable Canadian securities laws, our board of directors has affirmatively determined that our Compensation Committee is composed solely of independent directors. Our board of directors has adopted a written charter for the Compensation Committee that is available on our website. The Compensation Committee is currently composed by Messrs. Brussa, Oehmig, Sello and Tomsett, with Mr. Tomsett serving as Chairman. None of the members of the Compensation Committee is or has been one of our officers or employees, and none of our executive officers served during fiscal 2010 on a board of directors of another entity which has employed any of the members of the Compensation Committee.

|  |  |  | 33 |  |

##### Table of Contents

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 and for conducting an annual review as to the re-nominations of incumbents and proposed nominees for election by the board of directors to fill vacancies that occur between shareholder meetings. The Governance Committee also makes recommendations to the board of directors regarding corporate governance matters and practices. In accordance with the listing requirements of the New York Stock Exchange applicable to domestic listed companies and applicable Canadian securities laws, our board of directors has affirmatively determined that our Governance Committee is composed solely of independent directors. Our board of directors has adopted a written charter for the Governance Committee that is available on our website at www.nacg.ca. The Governance Committee is currently composed of Messrs. Brussa, Hawkins, McIntosh and Turner, with Mr. Hawkins serving as Chairman.

Health, Safety, Environment and Business Risk Committee

The Health, Safety, Environment and Business Risk Committee (the “HSE&B Risk Committee”) is responsible for monitoring, evaluating, advising and making recommendations on matters relating to the health and safety of our employees, the management of our health, safety and environmental risks, due diligence related to health, safety and environment matters, as well as the integration of health, safety, environment, economics and social responsibility into our business practices. The HSE&B Risk Committee is also responsible for overseeing all of our non-financial risks, approving our risk management policies, monitoring risk management performance, reviewing the risks and related risk mitigation plans within our strategic plan, reviewing and approving tenders and contracts greater than $50 million in expected revenue and any other matter where board guidelines require approval at a level above President & CEO, and reviewing and monitoring all insurance policies including directors and officers insurance coverage. Our board of directors has affirmatively determined that our HSE&B Risk Committee is composed solely of independent directors. Our board of directors has adopted a written charter for the HSE&B Risk Committee that is available on our website at www.nacg.ca. The HSE&B Risk Committee is currently composed of Messrs. Brokaw, Dodd, McIntosh, Oehmig and Tomsett, with Mr. Oehmig serving as Chairman.

Interest of Management and Others in Material Transactions

Voting and Corporate Governance Agreement

We have entered into a letter agreement with The Sterling Group, L.P. and Perry Strategic Capital Inc. (the significant shareholders) pursuant to which we have engaged each significant shareholder to provide its expertise and advice to us for no fee, which is in their interests because of their investments in us. In order for the significant shareholders to provide such advice, we have agreed to:

Ÿ |  | provide them copies of all documents, reports, financial data and other information regarding us;

Ÿ |  | permit them to consult with and advise our management on matters relating to our operations;

Ÿ |  | permit them to discuss our company’s affairs, finances and accounts with our officers, directors and outside accountants;

Ÿ |  | permit them to visit and inspect any of our properties and facilities, including but not limited to books of account;

Ÿ |  | permit them to attend, to the extent that a director is not related to the Sponsor, to designate and send a representative to attend all meetings of our board of directors in a non-voting observer capacity;

Ÿ |  | provide them copies of certain of our financial statements and reports; and

Ÿ |  | provide them copies of all materials sent by us to our board of directors, other than materials relating to transactions in which the significant shareholder has an interest.

We may terminate a significant shareholder’s letter agreement in certain circumstances. All the foregoing rights are subject to customary confidentiality requirements and subject to security clearance requirements imposed by applicable government authorities.

Registration Rights Agreement

We are party to a registration rights agreement with certain shareholders, including affiliates of each of the significant shareholders, Paribas North America, Inc. and Mr. William Oehmig, one of our directors. The shareholders party to the agreement and their permitted transferees are entitled, subject to certain limitations, to include their common shares in a registration of common shares we initiate under the Securities Act of 1933, as amended. In addition, after the 120th day following our IPO, any one or more shareholders party to the agreement has the right to require us to effect the registration of all or any part of such shareholders’ common shares under the Securities Act, referred to as a “demand registration,” so long as the amount of 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

|  | 34 |  |  |  |

##### Table of Contents

initiated by us pursuant to the registration rights agreement. In the event the aggregate number of common shares which the shareholders party to the agreement request us to include in any registration, together, in the case of a registration we initiate, with the 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.

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

Ÿ |  | up to 120 days if:

| ¡ |  | we have decided to file a registration statement for an underwritten public offering of our common shares, the net proceeds of which are expected to be at least US$20.0 million; or

| ¡ |  | initiated discussions with underwriters in preparation for a public offering of our common shares as to which we expect 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

Ÿ |  | up to 90 days following a request for a demand registration if we are in possession of material information that we reasonably deem advisable not to disclose in a registration statement.

Our right to delay the filing of a registration statement if we possess information that we deem advisable not to disclose does not obviate any disclosure obligations which we may have under the Exchange Act or other applicable laws; it merely permits us to avoid filing a registration statement if our 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 our management believes is premature or otherwise inadvisable.

The registration rights agreement contains customary provisions whereby we 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 us 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.

Legal Proceedings and Regulatory Actions

From time to time, we are a party to litigation and legal proceedings that we consider to be a part of the ordinary course of business. While no assurance can be given, we believe that, taking into account reserves and insurance coverage, none of the litigation or legal proceedings in which we are currently involved could reasonably be expected to have a material adverse effect on our business, financial condition or results of operations. We may, however, become involved in material legal proceedings in the future.

Transfer Agent and Registrar

The transfer agent and registrar of the Company is CIBC Mellon Trust Co. and the address of CIBC Mellon Trust Co. is 600 The Dome Tower, 333 – 7 Avenue SW, Calgary, Alberta, T2P 2Z1.

Material Contracts

We are party to the following material contracts, other than contracts entered into in the ordinary course of our business:

Ÿ |  | Indemnity Agreement between NACG Holdings Inc., NACG Preferred Corp., North American Energy Partners Inc., North American Construction Group Inc. and their respective officers and directors Please refer to the most recently filed management information circular for details;

Ÿ |  | Indenture, dated as of April 7, 2010, among North American Energy Partners Inc., the guarantors named therein and CIBC Mellon Trust Company, as Trustee, and Supplemental Indenture dated as of April 7, 2010, among North American Energy Partners Inc., the guarantors named therein and CIBC Mellon Trust Company, as Trustee. Please refer to “Description of Indebtedness – 9.125% Series 1 Debentures Due 2017” for details;

Ÿ |  | Registration Rights Agreement, dated as of November 26, 2003, among NACG Holdings Inc. and the shareholders party thereto. Please refer to “Interest of Management and Others in Material Transactions-Registration Rights Agreement” for details ;

|  |  |  | 35 |  |

##### Table of Contents

Ÿ |  | Amended and Restated 2004 Share Option Plan. Please refer to the most recently filed management information circular for details;

Ÿ |  | Directors Deferred Share Unit plan, dated January 1, 2008. Please refer to the most recently filed management information circular for details;

Ÿ |  | Deferred Performance Share Unit plan dated April 1, 2008. Please refer to the most recently filed management information circular for details;

Ÿ |  | Overburden Removal and Mining Services Contract, dated November 17, 2004, between Canadian Natural Resources Ltd. and Noramac Ventures Inc. Please refer to “Projects – Active Projects: Canadian Natural Overburden Removal” for details;

Ÿ |  | Amended and Restated Joint Venture Agreement, dated as of September 15, 2008, among North American Construction Group Inc., Fort McKay Construction Ltd., as General Partner for and on behalf of Fort McKay Construction Limited Partnership, and Noramac Ventures Inc. Please refer to “Projects – Joint Ventures” for details;

Ÿ |  | Lease dated December 1, 1997, between NAR Group Holdings Ltd., as landlord, and North American Construction Group Inc., as tenant, as renewed by a Renewal Lease Agreement dated December 1, 2002, between Norama Inc. (successor to NAR Group Holdings Ltd.), as landlord, and North American Construction Group Inc., as tenant, as amended by a Lease Amendment and Consent Agreement dated November 26, 2003, between Acheson Properties Ltd. (successor to Norama Inc.), as landlord, and North American Construction Group Inc., as tenant, and as further amended by an Amending Agreement to Lease Amendment and Consent Agreement dated September 29, 2006, between Acheson Properties Ltd., as landlord, and North American Construction Group Inc., as tenant. This lease is for our offices in Acheson, Alberta. Please refer to “Resources and Key Trends—Facilities” for details; and

Ÿ |  | Fourth Amended and Restated Credit Agreement dated as of April 30, 2010, among North American Energy Partners Inc., Canadian Imperial Bank of Commerce, HSBC Bank Canada, and the lenders party there to from time to time. Please refer to “Description of Certain Indebtedness—Credit Facility” for details.

Risks and Uncertainties

Risks Related to our Business

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

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

Ÿ |  | reductions in available credit for customers to fund capital projects;

Ÿ |  | changes in the perception of the economic viability of these projects;

Ÿ |  | shortage of pipeline capacity to transport production to major markets;

Ÿ |  | lack of sufficient governmental infrastructure funding to support growth;

Ÿ |  | delays in issuing environmental permits or refusal to grant such permits;

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

Ÿ |  | cost overruns on announced projects.

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

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

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

Due to the amount of capital investment required to build an oil sands project, or construct a significant capital expansion to an existing project, investment decisions by oil sands operators are based upon long-term views of the

|  | 36 |  |  |  |

##### Table of Contents

economic viability of the project. Economic viability is dependent upon the anticipated revenues the capital project will produce, the anticipated amount of capital investment required and the anticipated fixed cost of operating the project. The most important consideration is the customer’s view of the long-term price of oil which is influenced by many factors, including the condition of developed and developing economies and the resulting demand for oil and gas, the level of supply of oil and gas, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political conditions in oil producing nations, including those in the Middle East, war or the threat of war in oil producing regions and the availability of fuel from alternate sources. If our customers believe the long-term outlook for the price of oil is not favourable, or believes oil-sands projects are not viable for any other reason, they may delay, reduce or cancel plans to construct new oil sands capital projects or capital expansions to existing projects. Recently, the market price of oil decreased significantly. In addition, the slowing world economy is leading to lower international demand for oil, which could continue to suppress oil prices. As a result of these developments, many of our customers have decided to scale back their capital development plans and are significantly reducing their capital expenditures on oil sands projects. Delays, reductions or cancellations of major oil sands projects would adversely affect our prospects for revenues from capital projects and could have an adverse impact on our financial condition and results of operations.

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

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

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

Outsourced Heavy Construction and Mining services constitute a large portion of the work we perform for our customers. For example, our mining and site preparation project revenues constituted approximately 88%, 74% and 63% of our revenues in each of the years ended March 31, 2010, 2009 and 2008, respectively. The election by one or more of our customers to perform some or all of these services themselves, rather than outsourcing the work to us, could have a material adverse impact on our business and results of operations. Certain customers perform some of this work internally and may choose to expand on the use of internal resources to complete this work. Additionally, the recent tightening of the credit market and worldwide economic downturn may result in our customers reducing their spending on outsourced mining and site preparation services if they believe they can perform this work in a more cost effective and efficient manner using their internal resources.

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

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

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

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

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

Most of our revenue comes from the provision of services to a small number of major oil sands mining companies. Revenue from our five largest customers represented approximately 88%, 74% and 63% of our total revenue for 2010, 2009 and 2008, respectively, and those customers are expected to continue to account for a significant percentage of

|  |  |  | 37 |  |

##### Table of Contents

our revenues in the future. In addition, the majority of our Pipeline revenues in the previous fiscal years resulted from work performed for one customer. If we lose or experience a significant reduction of business from one or more of our significant customers, we may not be able to replace the lost work with work from other customers. Our long-term contracts typically allow our customers to unilaterally reduce or eliminate the work which we are to perform under the contract. Our contracts also generally allow the customer to terminate the contract without cause and, in many cases, with minimal or no notice to us. Additionally, certain of these contracts provide for limited compensation following such suspension or termination operations and we can provide no assurance that we could replace the lost work with work from other customers. The loss of or significant reduction in business with one or more of our major customers, whether as a result of the completion, early termination or suspension of a contract, or failure or inability to pay amounts owed to us, could have a material adverse effect on our business and results of operations.

Failure by our customers to obtain required permits and licenses due to complex and stringent environmental protection laws and regulations may affect the demand for our services.

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

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

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

Significant labour disputes could adversely affect our business.

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

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

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

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

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

Some of our customers require letters of credit to secure our performance commitments. Our April 30, 2010 amended and restated credit agreement provides for the issuance of letters of credit up to $85.0 million, and at June 10, 2010,

|  | 38 |  |  |  |

##### Table of Contents

we had $14.4 million of issued letters of credit outstanding. One of our major contracts allows the customer to require up to $50.0 million in letters of credit. If we were unable to provide letters of credit in the amount requested by this customer, we could lose business from such customer and our business and cash flow would be adversely affected. If our capacity to issue letters of credit under our amended and restated credit agreement and our cash on hand is insufficient to satisfy our customer’s requirements, our business and results of operations could be adversely affected.

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

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

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

Approximately 39%, 29% and 44% of our revenue for the years ended March 31, 2010, 2009 and 2008, respectively, was derived from lump-sum and unit-price contracts. Lump-sum and unit-price contracts require us to guarantee the price of the services we provide and thereby expose us to losses if our estimates of project costs are lower than the actual project costs we incur. Our profitability under these contracts is dependent upon our ability to accurately predict the costs associated with our services. The costs we actually incur may be affected by a variety of factors beyond our control. Factors that may contribute to actual costs exceeding estimated costs and which therefore affect profitability include, without limitation:

Ÿ |  | site conditions differing from those assumed in the original bid;

Ÿ |  | scope modifications during the execution of the project;

Ÿ |  | the availability and cost of skilled workers;

Ÿ |  | the availability and proximity of materials;

Ÿ |  | unfavourable weather conditions hindering productivity;

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

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

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

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

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

We have a substantial amount of debt outstanding and significant debt service requirements. As of March 31, 2010, we had outstanding $477.3 million of debt 16, including $13.4 million of capital leases. We also had cross-currency and interest rate swaps with a balance sheet liability of $81.1 million as of March 31, 2010. These swaps are secured equally and ratably with our Revolving Facility. Our substantial indebtedness could have serious consequences, such as:

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

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

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

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

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

16 | Debt includes all liabilities with the exception of future income taxes

|  |  |  | 39 |  |

##### Table of Contents

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

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

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

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

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

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

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

Ÿ |  | issue equity securities of subsidiaries;

Ÿ |  | make certain investments or acquisitions;

Ÿ |  | create liens on our assets;

Ÿ |  | enter into transactions with affiliates;

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

Ÿ |  | transfer or sell assets, including shares of our subsidiaries.

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

As a result of these covenants, our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be significantly restricted, and we may be prevented from engaging in transactions that might otherwise be considered beneficial to us. The breach of any of these covenants could result in an event of default under our revolving credit facility or any future credit facilities or under the indenture governing our notes. Under our credit agreement, our failure to pay certain amounts when due to other creditors, including to certain equipment lessors, or the acceleration of such other indebtedness, would also result in an event of default. Upon the occurrence of an event of default under our amended and restated credit agreement or future credit facilities, the lenders could elect to stop lending to us or declare all amounts outstanding under such credit facilities to be immediately due and payable. Similarly, upon the occurrence of an event of default under the trust indenture governing our Series 1 Debentures the outstanding principal and accrued interest on the notes may become immediately due and payable. If amounts outstanding under such credit agreements and the trust indenture were to be accelerated, or if we were not able to borrow under our amended and restated credit agreement, we could become insolvent or be forced into insolvency proceedings.

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

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

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

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

More than 27% of our revenue for the year ended March 31, 2010 was derived from projects which we consider to be non-recurring. This revenue primarily relates to site preparation and Piling services provided for the construction of extraction, upgrading and other oil sands mining infrastructure projects.

|  | 40 |  |  |  |

##### Table of Contents

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

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

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

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

In strong economic times, global demand for tires of the size and specifications we require can exceed the available supply. Our inability to procure tires to meet the demands for our existing fleet as well as to meet new demand for our services could have an adverse effect on our ability to grow our business.

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

Our ability to generate sufficient operating cash flow to make scheduled payments on our indebtedness and meet other capital requirements will depend on our future operating and financial performance. Our future performance will be impacted by a range of economic, competitive and business factors that we cannot control, such as general economic and financial conditions in our industry or the economy generally.

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

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

Because our operations are located in Western Canada and Northern Ontario, we are often subject to extreme weather conditions. While our operations are not significantly affected by normal seasonal weather patterns, extreme weather, including heavy rain and snow, can cause delays in our project work, which could adversely impact our results of operations.

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

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

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

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

We install deep foundations, often in congested and densely populated areas, and provide construction management services for significant projects. Notwithstanding the fact that we generally will not accept liability for consequential

|  |  |  | 41 |  |

##### Table of Contents

damages in our contracts, any catastrophic occurrence in excess of insurance limits at projects where our structures are installed or services are performed could result in significant professional liability, product liability, warranty or other claims against us. Such liabilities could potentially exceed our current insurance coverage and the fees we derive from those services. A partially or completely uninsured claim, if successful and of a significant magnitude, could result in substantial losses.

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

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

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

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

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

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

Risks Related to Our Common Shares

Fluctuations in the value of the Canadian and US dollars can affect the value of our common shares and future dividends, if any.

Our operations and our principal executive offices are in Canada. Accordingly, we report our results in Canadian dollars. The value of a US shareholder’s investment in us will fluctuate as the US dollar rises and falls against the Canadian dollar. Also, if we pay dividends in the future, we will pay those dividends in Canadian dollars. Accordingly, if the US dollar rises in value relative to the Canadian dollar, the US dollar value of the dividend payments received by a US common shareholder would be less than they would have been if exchange rates were stable.

If our share price fluctuates, an investor could lose a significant part of their investment.

There has been significant volatility in the market price and trading volume of equity securities, which is unrelated to the financial performance of the companies issuing the securities. The market price of our common shares is likely to be similarly volatile, and an investor may not be able to resell our shares at or above the price at which the investor acquired the shares due to fluctuations in the market price of our common shares, including changes in price caused by factors unrelated to our operating performance or prospects.

Specific factors that may have a significant effect on the market price for our common shares include:

Ÿ |  | changes in projections as to the level of capital spending in the oil sands region;

Ÿ |  | changes in stock market analyst recommendations or earnings estimates regarding our common shares, other comparable companies or the construction or oil and gas industries generally;

Ÿ |  | actual or anticipated fluctuations in our operating results or future prospects;

Ÿ |  | reaction to our public announcements;

Ÿ |  | strategic actions taken by us or our competitors, such as acquisitions or restructurings;

Ÿ |  | new laws or regulations or new interpretations of existing laws or regulations applicable to our business and operations;

Ÿ |  | changes in accounting standards, policies, guidance, interpretations or principles;

|  | 42 |  |  |  |

##### Table of Contents

Ÿ |  | adverse conditions in the financial markets or general economic conditions, including those resulting from war, incidents of terrorism and responses to such events;

Ÿ |  | sales of common shares by us, members of our management team or our existing shareholders; and

Ÿ |  | the extent of analysts’ interest in following our company.

Future sales or the perception of future sales of a substantial amount of our common shares may depress the price of our common shares.

Future sales or the perception of the availability for sale of substantial amounts of our common shares could adversely affect the prevailing market price of our common shares and could impair our ability to raise capital through future sales of equity securities at a time and price that we deem appropriate.

We may issue additional common shares, which would dilute the percentage ownership interest of our existing shareholders.

We may issue our common shares or convertible securities from time to time as consideration for future acquisitions and investments. In the event any such acquisition or investment is significant, the number of common shares or convertible securities that we may issue could be significant. We may also grant registration rights covering those shares or convertible securities in connection with any such acquisitions and investments. Any additional capital raised through the sale of our common shares or securities convertible into our common shares will dilute our common shareholders’ percentage ownership in us.

We currently do not intend to pay cash dividends on our common shares, and our ability to pay dividends is limited by the indenture that governs our notes, our subsidiaries’ ability to distribute funds to us and Canadian law.

We have never paid cash dividends on our common shares. It is our present intention to retain all future earnings for use in our business, and we do not expect to pay cash dividends on the common shares in the foreseeable future. Any future determination to pay cash dividends will be at the discretion of our board of directors and will depend on our results of operations, financial condition, current and anticipated cash needs, contractual restrictions, restrictions imposed by applicable law and other factors that our board of directors considers relevant. Our ability to declare dividends is restricted by the terms of the indenture that governs our notes. See “Description of Certain Indebtedness.”

Substantially all of the assets shown on our consolidated balance sheet are held by our subsidiaries. Accordingly, our earnings and cash flow and our ability to pay dividends are largely dependent upon the earnings and cash flows of our subsidiaries and the distribution or other payment of such earnings to us in the form of dividends.

Our ability to pay dividends is also subject to the satisfaction of a statutory solvency test under Canadian law, which requires that there be no reasonable grounds for believing that (i) we are, or would after the payment be, unable to pay our liabilities as they become due or (ii) the realizable value of our assets would, after payment of the dividend, be less than the aggregate of our liabilities and stated capital of all classes.

Our principal shareholders are in a position to affect our ongoing operations, corporate transactions and other matters, and their interests may conflict with or differ from the interests of our other common shareholders.

Investment entities controlled by the significant shareholders, collectively hold over 25% of our common shares. As a result, the significant shareholders and their affiliates would be able to exert influence over the outcome of most matters submitted to a vote of our shareholders, including the election of members of our board of directors, if they were to act together.

Regardless of whether the significant shareholders maintain a significant interest in our common shares, so long as a designated affiliate of each significant shareholder holds our common shares, such significant shareholder will have certain rights, including the right to obtain copies of financial data and other information regarding us, the right to consult with and advise our management and the right to visit and inspect any of our properties and facilities. See “Interest of Management and Others in Material Transactions – Letter Agreements”.

For so long as the significant shareholders own a significant percentage of our outstanding common shares, even if less than a majority, the significant shareholders will be able to exercise influence over our business and affairs, including the incurrence of indebtedness by us, the issuance of any additional common shares or other equity securities, the repurchase of common shares and the payment of dividends, if any, and will have the power to influence the outcome of matters submitted to a vote of our shareholders, including election of directors, mergers, consolidations, sales or dispositions of assets, other business combinations and amendments to our articles of incorporation. The interests of the significant shareholders and their affiliates may not coincide with the interests of our other shareholders. In particular, the significant shareholders and their affiliates are in the business of making investments in companies and they may, from time to time, acquire and hold interests in businesses that compete directly or indirectly with us. The significant shareholders and their affiliates may also pursue, for their own account, acquisition opportunities that may be complementary to our business, and as a result, those acquisition opportunities may not be available to us. So long as the significant shareholders and their affiliates continue to own a significant portion of the outstanding common shares, they will continue to be able to influence our decisions.

|  |  |  | 43 |  |

##### Table of Contents

We are a holding company and rely on our subsidiaries for our operating funds, and our subsidiaries have no obligation to supply us with any funds.

We are a holding company with no operations of our own. We conduct our operations through subsidiaries and are dependent upon our subsidiaries for the funds we need to operate. Each of our subsidiaries is a distinct legal entity and has no obligation to transfer funds to us. The ability of our subsidiaries to transfer funds to us could be restricted by the terms of our financings. The payment of dividends to us by our subsidiaries is subject to legal restrictions as well as various business considerations and contractual provisions, which may restrict the payment of dividends and distributions and the transfer of assets to us.

Actions against us and some of our directors and officers may not be enforceable under US federal securities laws.

We are a corporation incorporated under the Canada Business Corporations Act. Consequently, we are and will be governed by all applicable provincial and federal laws of Canada. Several of our directors and officers reside principally in Canada. Because these persons are located outside the United States, it may not be possible to effect service of process within the United States upon those persons. Furthermore, it may not be possible to enforce against us or them, in or outside the United States, judgments obtained in US courts, because substantially all of our assets and the assets of these persons are located outside the United States. We have been advised that there is doubt as to the enforceability, in original actions in Canadian courts, of liabilities based upon the US federal securities laws and as to the enforceability in Canadian courts of judgments of US courts obtained in actions based upon the civil liability provisions of the US federal securities laws. Therefore, it may not be possible to enforce those actions against us, our directors and officers or other persons named in this AIF.

Quantitative and Qualitative Disclosures about Market Risk

Foreign exchange risk

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

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

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

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

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

|  | 44 |  |  |  |

##### Table of Contents

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

Interest rate risk

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

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

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

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

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

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

|  |  |  | 45 |  |

##### Table of Contents

Additional Information

Experts

KPMG LLP is the external auditor of the Company who prepared the Report of Independent Registered Public Accounting Firm to the Shareholders and Board of Directors dated June 10, 2010, with respect to the consolidated balance sheets of the Company as of March 31, 2010 and 2009 and the consolidated statements of operations, comprehensive income (loss), shareholders’ equity and cash flows for the years ended March 31, 2010, 2009 and 2008, respectively. KPMG LLP is independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta.

Additional Information

Additional information, including information in respect of (i) the remuneration and indebtedness of the directors and executive officers of the Company, (ii) the principal holders of our securities and (iii) securities authorized for issuance under equity compensation plans, is contained in our information circular for our most recent annual meeting of holders of common shares that involved the election of our directors, and our MD&A for the year ended March 31, 2010. Additional financial information is provided in our audited consolidated financial statements for the year ended March 31, 2010.

Additional information relating to us can be found on the Canadian Securities Administrators System for Electronic Document Analysis and Retrieval (SEDAR) database at www.sedar.com and the Securities and Exchange Commission’s Electronic Data Gathering, Analysis and Retrieval (EDGAR) system at www.sec.gov.

|  | 46 |  |  |  |

##### Table of Contents

Glossary

The following are definitions of certain terms commonly used in our industry and this AIF.

“bitumen” means the molasses-like substance that comprises the oil in the oil sands.

“coker” means a vessel in which bitumen is cracked into its fractions and from which coke is withdrawn to start the process of converting bitumen to upgraded crude oil.

“established reserves” means those reserves recoverable under current technology and present and anticipated economic conditions specifically proved by drilling, testing or production, plus the portion of contiguous recoverable reserves that are interpreted to exist from geological, geophysical or similar information with reasonable certainty.

“upgrader” is a facility that upgrades bitumen into synthetic crude oil. Upgrader plants are typically located close to oil sands production.

“muskeg” means a swamp or bog formed by an accumulation of sphagnum moss, leaves and decayed matter resembling peat.

“naphtha” is a refined petroleum product in the lighter classification that is often used to make gasoline.

“oil sands” means the grains of sand covered by a thin layer of water and coated by heavy oil, or bitumen.

“overburden” means the layer of rocky, clay-like material that covers the oil sands.

“ultimately recoverable oil reserves” means an estimate of the initial established reserves that will have been developed in an area by the time all exploratory and development activity has ceased, having regard for the geological prospects of that area and anticipated technology and economic conditions.

Ultimately recoverable oil reserves include cumulative production, remaining established reserves and future additions through extensions and revisions to existing pools and the discovery of new pools. Ultimate potential can be expressed by the following simple equation: Ultimate potential cumulative production established reserves additions to existing pools future discoveries.

“upgrading” means the conversion of heavy bitumen into a lighter crude oil by increasing the hydrogen to carbon ratio, either through the removal of carbon (coking) or the addition of hydrogen (hydro processing).

|  |  |  | 47 |  |

##### Table of Contents

Exhibit A

Audit Committee Charter

1. | MANDATE & AUTHORITY

| 1.1 | The Board of Directors (the “Board”) of North American Energy Partners Inc. (the “Company”) has established an Audit Committee (the “Committee”) to assist the Board in meeting its oversight responsibilities. The Committee’s responsibilities are summarized as follows:

| a) | monitor the integrity of the Company’s financial and related information of the Company including its financial statements;

| b) | monitor the system of internal controls over financial reporting;

| c) | monitor the disclosure controls and procedures;

| d) | oversee the work of the external auditor;

| e) | monitor the internal audit function;

| f) | identify and monitor the financial risks of the Company;

| g) | establish the Company’s ethics reporting procedures; and

| h) | monitor the Company’s compliance with legal and regulatory requirements.

| 1.2 | While the Committee shall have the responsibilities and powers set forth in this charter, it shall not be the responsibility of the Committee to determine whether the Company’s financial statements are complete, accurate or prepared in accordance with generally accepted accounting principles, to manage financial risks or to conduct audits. These are the responsibilities of management and the external auditor in accordance with their respective roles.

| 1.3 | The Committee will take reasonable steps to ensure that management establishes and maintains the controls, procedures and processes that comply with all appropriate laws, regulations or policies of the Company. It is not the responsibility of the Committee to conduct investigations or to ensure compliance with laws or regulations or Company policies. Management is responsible for establishing and maintaining the controls, procedures and processes over these matters and the Committee has the responsibility to ensure they exist.

| 1.4 | The Committee has the power to conduct or authorize investigations into any matters within the Committee’s scope of responsibilities. The Committee has the authority to engage independent counsel and other advisors, as it determines necessary to carry out its duties. The Company will provide the resources and funding required by the Committee to carry out its duties.

| 1.5 | The Committee shall also have unrestricted access to the Company’s personnel and documents and will be provided with the resources to carry out its responsibilities. The Committee shall have direct communication channels with the external auditor and the individual responsible for the internal auditor function to discuss and review specific issues as appropriate.

2. | MEMBERSHIP

| 2.1 | The Committee shall be composed of a minimum of three (3) directors of the Company. Each member of the Committee shall be appointed by the Board.

| 2.2 | The Board shall appoint one of the members to be the Chair of the Committee.

| 2.3 | All members of the Committee shall be “independent” as that term is defined under the requirements of applicable securities laws and the standards of any stock exchange on which the Company’s securities are listed, taking into account any transitional provisions that are permitted.

| 2.4 | Members shall serve one year terms and may serve consecutive terms to ensure continuity of experience. Members shall be reappointed each year to the Committee by the Board at the Board meeting that coincides with the annual shareholder meeting. A member of the Committee shall automatically cease to be a member upon ceasing to be a director of the Company. Any member may resign or be removed by the Board from membership on the Committee or as Chair.

| 2.5 | All members of the Committee must be “financially literate” as that qualification is interpreted by the Board or acquire such literacy within a reasonable period of time after joining the Committee. At the present time, the Board interprets “financial literacy” to mean a basic understanding of finance and accounting and the

|  |  |  | i |  |

##### Table of Contents

| ability to read and understand financial statements (including the related notes) of the sort released or prepared by the Company in the normal course of its business.

| 2.6 | At least one member of the Committee shall be an “audit committee financial expert” who shall possess the attributes outlined in Appendix A.

| 2.7 | No director who is currently serving on the audit committee of another public company will be appointed to the Committee unless the Board determines that such simultaneous service would not impair the ability of such member to serve on the Committee. The maximum number of audit committees a director can serve on at any one time is set at three by the NYSE.

| 2.8 | The responsibilities of a member of the Committee are in addition to that member’s duties as a member of the Board.

| 2.9 | The Company is responsible for the orientation and continuing education of the members.

3. | MEETINGS

| 3.1 | Committee meetings will be conducted in a manner consistent with the Company By-laws, the Audit Committee Charter and the applicable business corporation act.

| 3.2 | The Notice of Meeting will be governed by the Company By-laws. Meetings will be called by the Chair or any other member of the Committee as appropriate.

| 3.3 | The Chair shall determine the time, place and procedures for Committee meetings, subject to the requirements of this Charter.

| 3.4 | Any director of the Company may attend Committee meetings, however, only members of the Committee are eligible to vote or establish a quorum.

| 3.5 | The external auditor will be requested to attend the meetings where the Committee is reviewing quarterly or annual financial statements. The Committee or any member may request that the external auditor appear before the Committee at any time.

| 3.6 | The Committee will meet a minimum of four times per year and shall determine whether additional meetings are required.

| 3.7 | The Chair of the Committee shall preside at and chair all meetings of the Committee. If the Chair is absent from a meeting, the remaining members of the Committee shall appoint a member to act as Chair for that meeting.

| 3.8 | A quorum for a meeting will be established if a majority of the members are present. Members of the Committee may participate in a meeting through any means which permits all parties to communicate adequately with each other. Any members not physically present but participating in the meeting through such means is deemed to be present at the meeting. A quorum, once established, is maintained even if members of the Committee leave before the meeting concludes.

| 3.9 | In the event of a tie vote on a resolution, the issue will be forwarded to the full board for a vote.

| 3.10 | A resolution signed by all members of the Committee entitled to vote on that resolution is as valid as if it had been passed at a meeting of the Committee.

| 3.11 | In camera sessions will be held as deemed necessary by the Committee with the external auditor, the individual responsible for the internal audit function, management and the Committee by itself.

| 3.12 | The Corporate Secretary or another person appointed by the Chair will act as secretary of the Committee meetings.

| 3.13 | The secretary of the meeting will keep minutes of each meeting, which shall record the decisions reached by the Committee.

| 3.14 | The minutes shall be distributed to Committee members with copies provided to (a) the Board; (b) the CEO; (c) the Vice President Finance; (d) the external auditor; and (e) the individual responsible for the internal audit function.

| 3.15 | The Corporate Secretary or another person will file the Committee minutes and all meeting material with the corporate minute books.

|  | ii |  |  |  |

##### Table of Contents

4. | RESPONSIBILITIES

| 4.1 | General

| 4.1.1 | The Committee will meet as set out in section 3 above.

| 4.1.2 | The Committee will report to the Board on all matters in this charter as well as such matters as the Board may from time to time refer or delegate to the Committee.

| 4.1.3 | The Committee will maintain a formal written Committee charter and annually assess the adequacy of the charter, submit such evaluation to the Board and recommend any proposed changes to the Board for approval.

| 4.1.4 | The Committee members will conduct an assessment of the effectiveness of the Committee.

| 4.2 | Financial reporting and internal controls

| 4.2.1 | Annual financial statements

|  | The Committee is responsible for the assessment of the annual audited financial statements of the Company and to recommend approval of the statements to the Board.

| 4.2.2 | Interim financial statements

|  | The Committee is responsible for the assessment and approval of the quarterly interim unaudited financial statements.

| 4.2.3 | Accounting policies

|  | The Committee will review and discuss with management and the external auditor, as appropriate, the Company’s financial reporting policies, including changes in or adoptions of, accounting standards and principles and disclosure practices.

|  | The Committee will review with management and the external auditor their qualitative judgments about the appropriateness, not just the acceptability, of accounting principles and accounting disclosure practices used or proposed to be used and particularly, the degree of aggressiveness or conservatism of the Company’s accounting principles and underlying estimates.

| 4.2.4 | Internal controls over financial reporting

|  | The Committee will review and discuss with management, the external auditor and others, as appropriate, the existence and design of the Company’s internal controls over financial reporting established by management and the effectiveness of such controls.

|  | The Committee will monitor the work undertaken by management to design and implement and to provide an assessment of the effectiveness of its system of internal control over financial reporting. The Committee will review and discuss with the external auditor, when required, the opinion on management’s assessment of the effectiveness of its system of internal controls over financial reporting.

| 4.2.5 | Disclosure controls and procedures

|  | The Committee will review and discuss with management, the external auditor and others, as appropriate, the existence and design of the Company’s disclosure controls and procedures established by management and the effectiveness of such controls.

|  | The Committee will review and approve the disclosure policy of the Company and periodically assess the adequacy of such policy for completeness and accuracy. The Committee will ensure that the Company has satisfactory procedures in place for the review of the Company’s public disclosure of financial information extracted or derived from the Company’s financial statements. The Committee will also monitor and oversee the activities of the Company’s Disclosure Committee.

| 4.2.6 | Other public disclosures

|  | The Committee will review and approve, and in some instances recommend approval to the Board, material financial disclosures in the following documents prior to their public release or filing with securities regulators:

| a) | management’s discussion and analysis;

| b) | any prospectus or offering document;

|  |  |  | iii |  |

##### Table of Contents

| c) | annual reports or annual information forms;

| d) | all material financial information required by securities regulations (e.g., Forms 6-K, 20-F and F-4) including all exhibits thereto (including the certifications required of the Company’s principal executive officer and principal financial officer);

| e) | any related party transactions;

| f) | any off balance sheet structures;

| g) | any correspondence with securities regulators or government financial agencies; and

| h) | news or press releases, containing audited or unaudited financial information, including the type and presentation of information and in particular any pro-forma or non-GAAP information.

| 4.3 | External Auditor

| 4.3.1 | The Committee shall recommend to the Board the external auditor to be nominated for the purpose of preparing or issuing the auditor’s report or performing other audit, review or attest services for the Company and the compensation of the external auditor and, as necessary, review and recommend to the Board the discharge of the external auditor.

| 4.3.2 | In the event of a change of external auditor, the Committee shall review all issues and provide documentation to the Board related to the change, including the information to be included in the Notice of Change of Auditors and the planned steps for an orderly transition period.

| 4.3.3 | The Committee shall engage the external auditor for the purpose of preparing or issuing the auditor’s report or performing other audit, review or attest services for the Company.

| 4.3.4 | The Committee shall review the audit scope and plan of the external auditor.

| 4.3.5 | The external auditor shall report directly to the Committee.

| 4.3.6 | The Committee will review and discuss with management and the external auditor, as appropriate, at the completion of the annual audit and each quarterly review:

| a) | the external auditor’s audit or review of the financial statements and its report thereon;

| b) | any significant changes required to be made in the external auditor’s audit plan;

| c) | any serious difficulties or disputes between management and the external auditor during the course of the quarterly review or annual audit;

| d) | any improper influence by officers on the external auditor;

| e) | any special audit or review steps adopted in light of material control deficiencies;

| f) | the summary of adjusted and unadjusted differences;

| g) | any related findings and recommendations of the external auditor together with management’s responses including the status of previous recommendations; and

| h) | any other matters related to the conduct of the external audit, which are to be communicated to the Committee by the external auditor under generally accepted auditing standards.

| 4.3.7 | The Committee shall take reasonable steps to confirm the independence of the external auditor, which shall include but shall not be limited to:

| a) | ensuring receipt, at least annually, from the external auditor of a formal written statement delineating all relationships between the external auditor and the Company, including non-audit services provided to the Company;

| b) | considering and discussing with the external auditor any disclosed relationships or services, including non-audit services, that may impact the objectivity and independence of the external auditor;

| c) | enquiring into and determining the appropriate resolution of any conflict of interest in respect of the external auditor;

| d) | reviewing and approving the Company’s hiring policies regarding the hiring of partners, employees and former partners and employees of the Company’s existing and former external auditor;

| e) | requesting the rotation of the lead audit partner every five (5) years; and

|  | iv |  |  |  |

##### Table of Contents

| f) | giving consideration to the rotation of the audit firm on a periodic basis.

| 4.3.8 | The Committee shall pre-approve any non-audit services to be provided to the Company or its subsidiaries by the external auditor except that the Committee has delegated a deminimus level of $20,000 per annum to the Audit Committee Chair who will report to the Audit Committee at their next meeting of any work approved within this limit.

| 4.3.9 | The Committee will review the nature of work performed by audit firms (other than the external auditor) to ensure that at least one of the nationally recognized firms remains independent in the event a change in external auditor is necessary or desired.

| 4.4 | Internal Audit Function

| 4.4.1 | The Committee will determine if an internal audit function should exist taking into account any legislative or listing requirements.

| 4.4.2 | The individual responsible for the internal auditor function reports administratively to the President and has a functional reporting relationship to the Chair of the Committee.

| 4.4.3 | The Committee will review management’s proposed appointment, termination or replacement of the internal audit function. If the Company out-sources its internal audit function, the Company’s external auditor cannot be engaged to perform such services.

| 4.4.4 | The Committee will review the responsibility and charter as well as the effectiveness of the internal audit function on an annual basis. The effectiveness assessment will include a review of its reporting relationships, activities, resources, its independence from management and its working relationship with the external auditor.

| 4.4.5 | The Committee will review and approve the annual internal audit plan, scope of work and ensure that the internal audit plan is coordinated with the activities of the external auditor.

| 4.4.6 | The Committee will review all internal audit reports and management’s responses.

| 4.5 | Risk Management

|  | The Committee shall review the significant financial risks and approve the Company’s policies to manage such financial risk including the Antifraud Policy.

| 4.6 | Ethics Reporting

| 4.6.1 | The Committee is responsible for the establishment of a policy and procedures for:

| a) | the receipt, retention and treatment of any complaint received by the Company regarding financial reporting, accounting, internal accounting controls or auditing matters; and

| b) | the confidential, anonymous submissions by employees of the Company of concerns regarding questionable accounting or auditing matters.

| 4.6.2 | The Committee will review, on a timely basis, serious violations of the Code of Conduct and Ethics Policy including all instances of fraud.

| 4.6.3 | The Committee will review on a summary basis at least quarterly all reported violations of the Code of Conduct and Ethics Policy.

| 4.7 | Legal and Regulatory Compliance

| 4.7.1 | The Committee will review any litigation, claim or other contingent liability, including any tax reassessment that could have a material effect on the financial statements.

| 4.7.2 | The Committee will review compliance with applicable financial, tax or securities regulations and the accuracy and timeliness of filings with regulators.

| 4.7.3 | The Committee will review compliance by management in filing and paying all statutory withholdings within the prescribed time.

Prepared By: /s/ Vincent Gallant Vincent Gallant Vice President, Corporate and Secretary |  | Approved By: /s/ Allen Sello Allen Sello, Chair Audit Committee |  | Date of Approval and Issue: December 7, 2006

|  |  |  | v |  |

##### Table of Contents

Appendix A: Audit Committee Financial Expert

At least one member of the Committee shall be an “audit committee financial expert” who shall possess the attributes outlined below:

1. | An understanding of generally accepted accounting principles and financial statements;

2. | The ability to assess the general application of generally accepted accounting principles in connection with the accounting for estimates, accruals and reserves;

3. | Experience in preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by the Company’s financial statements, or experience in actively supervising one or more persons engaged in such activities;

4. | An understanding of internal control over financial reporting;

5. | An understanding of audit committee functions;

6. | As provided in the rules of the SEC, the designation or identification of a person as an audit committee financial expert does not (a) impose on that person any duties, obligations or liability that are greater than the duties, obligations or liability imposed on that person as a member of the Committee and the Board in the absence of such designation or identification or (b) affect the duties, obligations or liability of any other member of the Committee or the Board; and

7. | A member of the Committee may qualify as an audit committee financial expert as a result of his or her:

| (a) | education and experience as a principal financial officer, principal accounting officer, controller, public accountant or auditor or experience in one or more positions that involve the performance of similar functions;

| (b) | experience actively supervising a principal financial officer, principal accounting officer, controller, public accountant, auditor or person performing similar functions;

| (c) | experience overseeing or assessing the performance of companies or public accountants with respect to the preparation, auditing or evaluation of financial statements; or

| (d) | other relevant experience.

|  | vi |  |  |  |