40-F

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 40-F

o REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

OR

þ ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended March 31, 2008

Commission File Number 001-33161

NORTH AMERICAN ENERGY PARTNERS INC.

(Exact name of Registrant as specified in its charter)

Canada
(Province or other jurisdiction of incorporation or organization)

1629
(Primary Standard Industrial Classification Code Number (if applicable))

N/A
(I.R.S. Employer Identification Number (if applicable))

Zone 3, Acheson Industrial Area
2-53016 Highway 60
Acheson, Alberta T7X 5A7
(780) 960-7171
(Address and telephone number of Registrant’s principal executive offices)

CT Corporation System
111 Eighth Avenue, 13^th Floor
New York, New York 10011
(212) 894-8940
(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Shares	Toronto Stock Exchange
	The New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

For annual reports, indicate by check mark the information filed with this Form:

þ Annual information form þ Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

35,929,476 Common Shares

Indicate by check mark whether the Registrant by filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange Act”). If “Yes” is marked, indicate the filing number assigned to the Registrant in connection with such Rule.

Yes o                    No þ

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

Yes þ                    No o

ANNUAL INFORMATION FORM, AUDITED ANNUAL CONSOLIDATED
FINANCIAL STATEMENTS AND MANAGEMENT’S DISCUSSION AND ANALYSIS

Annual Information Form

     The Registrant’s Annual Information Form for the fiscal year ended March 31, 2008 is attached as Exhibit 99.1 to this Annual Report on Form 40-F and is incorporated herein by reference.

Audited Annual Consolidated Financial Statements

     The Registrant’s audited annual consolidated financial statements for the fiscal year ended March 31, 2008, including the report of the independent registered public accounting firm with respect thereto and the reconciliation of differences between Canadian and United States generally accepted accounting principles, are attached as Exhibit 99.2 to this Annual Report on Form 40-F and are incorporated herein by reference.

Management’s Discussion and Analysis

     The Registrant’s Management’s Discussion and Analysis for the fiscal year ended March 31, 2008 is attached as Exhibit 99.3 to this Annual Report on Form 40-F and is incorporated herein by reference.

DISCLOSURES REGARDING CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

     Please see “Internal Systems and Processes—Evaluation of Disclosure Controls and Procedures” included in the Registrant’s Management’s Discussion and Analysis for the fiscal year ended March 31, 2008, which is attached as Exhibit 99.3 to this Annual Report on Form 40-F and is incorporated herein by reference.

Management’s Annual Report on Internal Control Over Financial Reporting

     Please see “Internal Systems and Processes—Management’s Report on Internal Controls Over Financial Reporting (ICFR)” included in the Registrant’s Management’s Discussion and Analysis for the fiscal year ended March 31, 2008, which is attached as Exhibit 99.3 to this Annual Report on Form 40-F and is incorporated herein by reference.

Attestation Report of the Registered Public Accounting Firm

     The attestation report of the independent registered public accounting firm on the effectiveness of internal control over financial reporting is included under the heading “Report of Independent Registered Public Accounting Firm” on pages 3 and 4 of Exhibit 99.2 to this Annual Report on Form 40-F, which attestation report is incorporated herein by reference.

Changes in Internal Control over Financing Reporting

     Please see “Internal Systems and Processes—Changes to Internal Control Over Financial Reporting” included in the Registrant’s Management’s Discussion and Analysis for the fiscal year ended March 31, 2008, which is attached as Exhibit 99.3 to this Annual Report on Form 40-F and is incorporated herein by reference.

NOTICES PURSUANT TO REGULATION BTR

     None.

AUDIT COMMITTEE FINANCIAL EXPERT

     The Registrant’s board of directors has determined that Mr. Allen R. Sello, a member and the chairman of the Registrant’s audit committee, is an “audit committee financial expert” (as such term is defined by the rules and regulations of the Securities and Exchange Commission) and is “independent” (as that term is defined by the New York Stock Exchange’s listing standards applicable to the Registrant).

CODE OF ETHICS

     The Registrant has adopted a “code of ethics” (as that term is defined by the rules and regulations of the Securities and Exchange Commission), entitled the “Code of Conduct and Ethics Policy”, that applies to all employees the Registrant, including its President and Chief Executive Officer, its Chief Financial Officer and its Vice President, Finance. The Code of Conduct and Ethics Policy is available for viewing on the Registrant’s website at www.nacg.ca under “Investor Relations—Corporate Governance”. There were not any amendments to any provision of the Code of Conduct and Ethics Policy during the fiscal year ended March 31, 2008 that applied to the Registrant’s principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions. Further, there were not any waivers, including implicit waivers, granted from any provision of the Code of Conduct and Ethics Policy during the fiscal year ended March 31, 2008 that applied to the Registrant’s principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions.

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PRINCIPAL ACCOUNTANT FEES AND SERVICES AND
PRE-APPROVAL POLICIES AND PROCEDURES

     Please see “The Board and Board Committees—Audit Committee” included in the Registrant’s Annual Information Form for the fiscal year ended March 31, 2008, which is attached as Exhibit 99.1 to this Annual Report on Form 40-F and is incorporated herein by reference.

OFF-BALANCE SHEET ARRANGEMENTS

     Please see “Off-Balance Sheet Arrangements” included in the Registrant’s Management’s Discussion and Analysis for the fiscal year ended March 31, 2008, which is attached as Exhibit 99.3 to this Annual Report on Form 40-F and is incorporated herein by reference.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

     Please see “Capital Commitments—Contractual Obligations and Other Commitments” included in the Registrant’s Management’s Discussion and Analysis for the fiscal year ended March 31, 2008, which is attached as Exhibit 99.3 to this Annual Report on Form 40-F and is incorporated herein by reference.

IDENTIFICATION OF THE AUDIT COMMITTEE

     Please see “The Board and Board Committees—Audit Committee” included in the Registrant’s Annual Information Form for the fiscal year ended March 31, 2008, which is attached as Exhibit 99.1 to this Annual Report on Form 40-F and is incorporated herein by reference.

COMPLIANCE WITH NYSE CORPORATE GOVERNANCE RULES

     The Registrant has reviewed the New York Stock Exchange’s corporate governance rules and confirms that the Registrant’s corporate governance practices are not significantly different from those required of domestic companies under the New York Stock Exchange’s listing standards except that, as a foreign private issuer, the Registrant’s Chief Executive Officer is not required to certify to the New York Stock Exchange that he is not aware of any violation by the Registrant of NYSE Corporate governance listing standards.

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

Undertaking

     The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

Consent to Service of Process

     The Registrant is filing with the Commission a Form F-X together with this report.

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SIGNATURES

     Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto duly authorized.

NORTH AMERICAN ENERGY PARTNERS INC.
By:	/s/ Rodney J. Ruston
	Rodney J. Ruston
	President and Chief Executive Officer

Date: June 22, 2008

EXHIBIT INDEX

99.1	Annual Information Form for the fiscal year ended March 31, 2008.
99.2	Audited Annual Consolidated Financial Statements for the fiscal year ended March 31, 2008.
99.3	Management’s Discussion and Analysis for the fiscal year ended March 31, 2008.
99.4	Consent of KPMG LLP.
99.5	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934.
99.6	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934.
99.7	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.8	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

EX-99.1

Exhibit 99.1

NORTH AMERICAN ENERGY PARTNERS INC.

ANNUAL INFORMATION FORM

June 20, 2008

TABLE OF CONTENTS

EXPLANATORY NOTES	1
Industry Data and Forecasts	1
Forward-Looking Statements	1
Non-GAAP Financial Measures	4
CORPORATE STRUCTURE	6
DESCRIPTION OF THE BUSINESS	7
History and Development of the Business	7
Our Competitive Strengths	9
Our Strategy	11
Our Operations and Segments	12
Our Markets	15
Contracts	19
PROJECTS	21
Joint Venture	24
Our Fleet and Equipment	24
Capital Expenditures	25
Competition	26
Major Suppliers	27
Seasonality	27
Laws, Regulations and Environmental Matters	28
The IPO and Reorganization	29
DESCRIPTION OF SHARE CAPITAL	31
Dividends	32
DESCRIPTION OF CERTAIN INDEBTEDNESS	33
Revolving Credit Facility	33
83/4% Senior Notes due 2011	34
Swap Agreements	35
Debt Ratings	35
DIRECTORS AND OFFICERS	35
THE BOARD AND BOARD COMMITTEES	39
(i) Audit Fees	40
(ii) Audit Related Fees	40
(iii) Tax Fees	40
(iv) All Other Fees	40
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	41
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	42
TRANSFER AGENT AND REGISTRAR	44
MATERIAL CONTRACTS	44
RISKS AND UNCERTAINTIES	45

ADDITIONAL INFORMATION		56
Experts		56
Additional Information		57
Glossary		58
Audit Committee Charter	EXHIBIT A

EXPLANATORY NOTES

          The information in this annual information form is stated as at June 20, 2008, 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, means 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, in this annual information form, information regarding actual and anticipated production, reserves and current and scheduled projects in the Canadian oil sands was obtained from the Alberta Energy and Utilities Board (“EUB”) and the Canadian Energy Research Institute (“CERI”). 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 STATEMENTS

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

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

(a)	the expected continued rapid growth of operators in the oil sands business and the benefits to us therefrom;
(b)	the planned expenditures in the Canadian oil sands that will allow us to increase our business from current projects and create opportunities for us to provide services to new projects;
(c)	that acquisition opportunities will materialize that will allow us to expand our complementary service offerings which we will be able to cross-sell with our existing services;
(d)	the increase in the needs of oil sands operators for certain types of services as they expand their operations and as new oil sands operations come on line;
(e)	the expectation that we will increase revenues by providing recurring services to our existing customers;
(f)	our ability to generate additional heavy construction and mining, piling and pipeline services work through our relationships with certain of our customers;
(g)	the success of the enhancements to our maintenance practices resulting in improved availability through reduced repair time and increased utilization of our equipment;
(h)	our ability to become a competitive supplier in future projects of similar nature to the projects we have completed;
(i)	the limited risk that royalty changes will cause our customers to cancel, delay or reduce the scope of any significant mining developments;
(j)	the continued growth of diamond mining in Canada;
(k)	the strong infrastructure spending outlook in Canada;
(l)	the expectation that we will supply an additional 10 years of overburden removal for Canadian Natural once our current contract expires;
(m)	the effect on our business or financial position as a result of future compliance with applicable environmental laws and regulations;
(n)	the effect of 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 requiring us to make additional material expenditures;
(o)	the continued tire supply shortage; and
(p)	the completion of the various projects referenced in this document at the anticipated or scheduled time.

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

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          The forward-looking information in paragraphs (a), (b), (d), (e), (f), (i), (j), (k), (l), (o) and (p) rely on certain market conditions and demand for our services and are based on the assumptions that; the global economy remains strong and the demand for commodities, particularly oil, remains high; high demand for commodities results in strong prices which drive the development of Canada’s natural resources, in particular the oil sands; the oil sands continue to be an economically viable source of energy and our customers and potential customers continue to invest in the oil sands and other natural resources developments; our customers and potential customers will continue to outsource the type of activities for which we are capable of providing service; and the western Canadian economy continues to develop with additional investment in commercial and public construction; and are subject to the risks and uncertainties that:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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or requirements for capital expenditures or capital commitments, do not reflect changes in or cash requirements for, our working capital needs, do not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt, exclude tax payments that represent a reduction in cash available to us, and do not reflect any cash requirements for assets being depreciated and amortized that may have to be replaced in the future. Consolidated EBITDA per bank excludes unrealized foreign exchange gains and losses and realized and unrealized gains and losses on derivative financial instruments, which, in the case of unrealized losses, may ultimately result in a liability that will need to be paid and in the case of realized losses, represents an actual use of cash during the period. A reconciliation of net income (loss) to EBITDA and Consolidated EBITDA per bank can be found in our management’s discussion and analysis of financial condition and results of operation for the year ended March 31, 2008 available on SEDAR at www.sedar.com and EDGAR at www.sec.gov.

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CORPORATE STRUCTURE

Name, Address and Incorporation

          The Company was amalgamated under the Canada Business Corporations Act (the “CBCA”) on November 28, 2006, and was the entity continuing from the amalgamation of NACG Holdings Inc. (“Holdings”) 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 head office is located at Zone 3, Acheson Industrial Area, 2 – 53016 Hwy 60, Acheson, Alberta, T7X 5A7.

          The Company wholly-owns NACG Finance LLC and North American Construction Group Inc. (“NACG”). NACG, in turn, wholly-owns our operating subsidiaries (collectively, the “Subsidiaries”). The chart below depicts our corporate structure and indicates the jurisdiction of formation of each of our direct and indirect Subsidiaries.

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DESCRIPTION OF THE BUSINESS

General

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

          Our core market is the Alberta oil sands, where we generated 69% of our fiscal 2008 revenue. The oil sands are located in three regions of northern Alberta: Athabasca, Cold Lake and Peace River. According to the EUB, Canada’s oil sands are estimated to hold 315 billion barrels of ultimately recoverable oil reserves, with established reserves of almost 174 billion barrels, second only to those of Saudi Arabia. According to CAPP, oil sands production of bitumen was approximately 1.1 million barrels per day (“bpd”) in 2006, accounting for 43% of total Canadian Oil production. According to CERI, oil sands production is expected to increase to approximately 4.1 million bpd by 2015 and account for approximately 80% of total Canadian oil output. In order to achieve this increase in production, CERI estimates that over $228 billion of capital expenditures by companies operating in the oil sands will be required between 2007 and 2015.

          We believe that our significant knowledge, experience, equipment capacity and scale of operations in the oil sands differentiate us from our competition. Our principal customers are the major operators in the oil sands, including all three of the producers that currently mine bitumen, being Syncrude Canada Ltd., Suncor Energy Inc. and Albian Sands Energy Inc. (a joint venture among Shell Canada Limited, Chevron Canada Limited and Western Oil Sands Inc.). Canadian Natural Resources Limited (“Canadian Natural”), another significant customer, is developing a bitumen-mining project in the oil sands which is currently under construction. Petro-Canada, a new customer, is also developing a bitumen-mining project that recently began construction. We provide services to every company in the oil sands that uses surface mining techniques for its production. According to CAPP, these surface mining techniques currently account for over 60% of total oil sands production. We have also provided site construction services for in-situ producers, which use horizontally drilled wells to inject steam into deposits and pump bitumen to the surface.

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

History and Development of the Business

          The Company completed an initial public offering (“IPO”) of its common shares and related reorganization (the “Reorganization”) in November 2006 to finance growth and expansion. 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, the Company raised a total of $152.6 million in net proceeds, which was used primarily to restructure its balance sheet and to reduce

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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”. The following is a summary of the significant events that have influenced the Company’s business over the past 3 years.

          The Company has been in a rapid growth phase for the past three years, as we have responded to robust conditions in the Alberta oil sands, commercial and public construction, conventional oil and gas, and minerals mining sectors. In response to the growing demand for our services, we have acquired new equipment and have hired additional personnel over the past three years. The high level of construction activity resulting from the development of the Alberta oil sands has been the primary driver of our growth over the last three years. Oil sands customers typically employ our services and expertise throughout the entire lifecycle of their projects, beginning with initial constructability and budget planning through to site development, mine construction, expansions, site maintenance, production and eventual site reclamation.

          Numerous pipeline construction and expansion projects have also been announced to address limited existing pipeline capacity and to accommodate the increasing oil sands production levels. This includes Kinder Morgan’s Trans Mountain (“TMX”) Anchor Loop project, which we worked on throughout fiscal 2008. In addition, the development of the oil sands and the strength of the western Canadian economy have resulted in booming commercial construction markets and increased public infrastructure spending.

          Exploration and development in other resource sectors are also providing the Company with growth opportunities. The high levels of commodity prices are creating incentives for companies to develop properties across Canada, providing the Company with opportunities beyond the Alberta oil sands. For example, the Company recently completed a three-year contract for site preparation and initial construction with DeBeers at their Victor diamond mining project in northern Ontario.

          Our Heavy Construction and Mining segment recorded record revenue of $626.6 million in fiscal 2008 (representing 63.3% of fiscal 2008 consolidated revenue) and has achieved compound annual growth of 33.3% over the past three years. This division has benefited from the increase in production at the Canadian Natural site under our 10-year overburden removal contract, as well as increased demand for our site services under our master services agreements with Syncrude Canada Ltd. (“Syncrude”) and Albian Sands Ltd. (“Albian”). We recently expanded our oil sands customer base to include Petro-Canada, the latest producer to enter the oil sands. Consistent with our “first in, last off” strategy, we are providing early clearing, site preparation and construction services to Petro-Canada’s new Fort Hills project.

          Beyond the Alberta oil sands, our contract with DeBeers for the Victor diamond project in northern Ontario has provided significant revenue for the Heavy Construction and Mining division over the past three years. With the completion of this project, we intend on pursuing other opportunities with DeBeers through the our relationship with them established in the Victor project. We are also pursuing other non-oil sands opportunities in an effort to expand our operations and to maintain end-market diversification.

          We have also expanded our capabilities in the last year to include general contracting services. During fiscal 2008 we served as the primary contractor, and successfully completed a design-build contract for, the construction of Albian’s aerodrome. We have progressed substantially on the Suncor Millennium Naphtha Unit project where we were selected as the general contractor to manage and perform all of site preparation, underground utilities, piling and concrete foundation work. We are also fully engaged at Suncor Voyageur where we are the General Contractor for a significant portion of the

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underground pipe installation, construction dewatering and pilling installations. These projects are part of a five-year site services contract currently underway.

          Our Piling segment has achieved 38.6% compound annual revenue growth over the past three years and achieved revenue of $162.4 million (representing 16.4% of fiscal 2008 consolidated revenue) for the fiscal year ended March 31, 2008. The growth in this division is primarily related to increased construction activity in the oil sands and robust commercial and public construction markets in Alberta, British Columbia and Saskatchewan. Major recent projects include the provision of piling for the expansion of Shell’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.

          On September 1, 2006, we completed the acquisition of Midwest Foundations Technologies Ltd., which allowed us to gain expertise and proprietary technology for micro-piling, which the process of installing high-density, small diameter piles into areas where access is limited. On May 1, 2007, we completed the acquisition of Active Auger Services 2001 Ltd., which provided us with a presence in northern Saskatchewan. Both acquisitions have been contributors to the growth of our Piling business.

          Our Pipeline segment (representing 20.3% of fiscal 2008 consolidated revenue) has undergone a transformation over the past three years and has achieved an 85.4% compound annual revenue growth and generated total revenue of $201 million in the most recently completed fiscal year. Given the scale of most pipeline projects, we typically work with just one pipeline customer on one major project at a time. In fiscal 2006, the customer we were working with changed its outsourcing strategy, resulting in a reduced workload for our Pipeline segment. As the result of this capacity, we secured a number of pipeline construction contracts with new customers. During fiscal 2007 and 2008, we incurred losses on two of these new contracts as the result of unanticipated weather and ground conditions and client changes to fixed-price contracts. The legacy fixed-price contracts were completed in the first half of fiscal 2008 and all of the additional costs resulting from these contracts were recognized in fiscal 2007 and 2008. We are currently working with the clients through the claim process to recover some of these costs.

          Our Pipeline segment refocused its bidding strategy and subsequently secured the TMX Anchor Loop contract with Kinder Morgan. With an original contract value of $185 million, this is by far the largest pipeline contract we have ever executed and is a cost-reimbursable contract. The TMX Anchor Loop project is expected to be complete by October 2008. Our strategy going forward will be to continue to pursue similar cost-reimbursable contracts.

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 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 working in the oil sands over 30 years ago. We believe we operate the largest fleet of any contract services provider in the oil sands. We believe we are one of only a few companies capable of taking on long-term, large-scale projects in the oil sands. In addition, we have extensive experience operating in the challenging working conditions created by the harsh climate and difficult terrain of the oil sands and northern Canada. We believe the combination of our significant size, extensive experience and broad

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service offerings has allowed us to develop our market position and reputation in the oil sands. For example, we were selected 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, 2008, we had a heavy equipment fleet of 845 units, made up of shovels, excavators, trucks and dozers as well as loaders, graders, scrapers, cranes, pipelayers and drill rigs. Many of these units are among the largest pieces of equipment in the world and are designed for use in the largest earthmoving and mining applications globally. In addition, we had over 925 ancillary vehicles located which allow us to execute a full range of jobs for our customers. Our large, diverse fleet gives us flexibility in scheduling jobs and allows us to be responsive to our customers’ needs. A well-maintained fleet is critical in the harsh climatic and environmental conditions we encounter. We operate four significant maintenance and repair centers, which are capable of accommodating the largest pieces of equipment in our fleet, on the sites of the major oil sands projects. We believe that these factors have helped 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.

          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 those maintenance centers in the oil sands and therefore acts as a back-up facility in the event of peak maintenance or repair requirements for oil sands equipment.

Broad service offering across a project’s lifecycle

          We provide our customers with resource services to meet their needs across the entire lifecycle of a project. These services include engineering assistance, construction of infrastructure, site grading, piling and pipe installation, day-to-day site maintenance, equipment supply, site upgrading services, overburden removal and land reclamation. Given the capital intensive and long-term nature of oil sands projects, we believe that our broad service offerings provide us with a competitive advantage and position us to transition from one stage of the project to the next, as we typically have knowledge of a project during its initial planning and budgeting phase. We use this knowledge to help secure contracts during the initial construction of the project as well as plan for recurring and follow-on work. As a result, we have a reputation as a “first-in, last-out” service provider in the oil sands. For example, we have both removed overburden and reclaimed land for Syncrude.

Long-term customer relationships

          As the result of our work over the years, we have well-established relationships with major oil sands producers and conventional oil and gas producers. These relationships are based on our ability to our customers’ requirements, including strong safety and performance records, a well-maintained, highly capable fleet with specific equipment dedicated to individual customers and a staff of well-trained, experienced supervisors, operators and mechanics. Historically, our largest customers by revenue have included Syncrude, Suncor, Albian and Canadian Natural. We have worked with these since they began operations in the oil sands, which in the case of Syncrude and Suncor, was over 30 years ago.

Experienced management team

          Our management team has well-established relationships with major oil sands producers and other resource industry leaders in our core markets. We believe that our management team’s experience in the resource services and mining industries enhances our ability to accomplish our strategic objectives.

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The entire management team is focused on further developing our culture of performance and accountability and continuing our tradition of offering high quality service to our customers. In addition, our management and operations teams have the local level knowledge to identify acquisition opportunities.

Our Strategy

          The following is a summary of our growth strategies:

Capitalize on growth opportunities in the Canadian oil sands

          We intend to build on our market leadership position and successful track record with our customers in the oil sands to benefit from the expected rapid growth in this end market. CERI estimates that between 2007 and 2015 a total of over $228 billion in capital expenditures will be required to achieve expected increases in production. We believe that these planned expenditures will not only allow us to increase our business from current projects but also create opportunities to provide our services to new projects. To capitalize on these opportunities, we plan to continue to add to our equipment fleet. This new equipment will be acquired in regular intervals and, together with our existing fleet, will enable us to compete for new business opportunities in the oil sands as they arise.

Leverage our complementary services

          Our complementary service segments, including site preparation, pipeline installation, piling and other mining services allow us to compete for many different forms of business. Given our technical capabilities, performance history and on-site presence, we believe we are well-positioned to compete for new business across our service segments. For example, either during or after providing site preparation services to customers, we can often use the specific knowledge of the project to provide other services such as underground pipeline installation or piling work. We are often able to provide these additional services seamlessly and quickly, utilizing existing on-site resources. Unplanned work requirements frequently arise with little notice, which we are well-positioned to complete as the result of being on-site. For example, during a recent site development project, we were asked with short lead-time to install a large diameter water pipeline. We were able to coordinate our site development and pipeline projects such that we began installing pipeline on a completed portion of the site without delaying the site development schedule. We intend to build on our “first-in” position to cross-sell our other services and pursue selective acquisition opportunities that expand our complementary service offerings.

Increase our recurring revenue base

          We provide services to our customers both during construction and throughout the operation of the project. Work required as an integral part of an operating project provides us with the opportunity to perform recurring services for our customers. Over the past several years, we have increased our recurring revenues from mining services, including overburden removal, reclamation, road construction and maintenance and surface mining, from 20% of revenues in fiscal 2004 to 39% in fiscal 2008. We expect that oil sands operators’ needs for these types of services will increase as they expand their operations and as new oil sands operations come on line. We expect to increase the amount of revenues from recurring services to our existing customers.

Leverage long-term relationships with existing customers

          Several of our oil sands customers have announced intentions to increase their production capacity by expanding the infrastructure at their sites. We intend to continue to build on our relationships

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with these and other existing oil sands customers to win a substantial share of the heavy construction and mining, piling and pipeline services outsourced in connection with these projects. For example, we worked closely with Albian and its largest shareholder, Shell, at the Muskeg River site during its development in 2001 and we recently completed work on Shell’s Jackpine expansion project.

Increase our presence outside of the Canadian oil sands

          Canada has significant reserves of various natural resources, including diamonds, uranium, coal and gold. We have and intend to continue to utilize the expertise we have gained in the oil sands to provide similar services to other natural resource mining companies. For example, we entered into a contract with De Beers in November 2005 to provide site preparation services over a 27-month period at its second diamond mine in Canada. We recently provided consulting to Baffinland on the Mary River Iron Ore deposit in Nunavut and we are actively working with existing customers on additional “planning-stage” opportunities outside the oil sands.

Enhance operating efficiencies to improve revenue and margins

          In order to enhance our profitability, competitiveness and responsiveness, we have initiated an operational improvement plan focused on implementing systems and process improvements, performance measurement techniques, enhanced communication and improved organizational effectiveness. It is intended that these new systems, process improvements and measures will allow us to enhance our maintenance practices and to deploy our fleet in a more effective manner, resulting in both improved availability through reduced repair time and increased utilization of our equipment. Increased equipment utilization should, in turn, increase revenue and margins through the fixed-cost nature of our equipment.

Our Operations and Segments

          Over the past 50 years, we have developed an expertise operating in the difficult working conditions created by the climate and terrain of western Canada. We provide our services primarily to oil and gas and other natural resource companies through our three reportable segments: (i) Heavy Construction and Mining, (ii) Piling and (iii) Pipeline.

(i)	Heavy Construction and Mining. The services provided by this segment include surface mining for oil sands and other natural resources, including overburden removal, hauling sand and gravel and supplying labor and equipment to support customers’ mining operations; plant site development, construction of infrastructure associated with mining operations and reclamation activities; clearing, stripping, excavating and grading for mining operations and industrial site construction for mega-projects; and underground utility installation for plant, refinery and commercial building construction.
(ii)	Piling. The services included in this segment include installing all types of driven and drilled piles, caissons and earth retention and stabilization systems for industrial projects primarily focused in the oil sands and related petrochemical or refinery complexes, as well as commercial buildings and infrastructure projects.
(iii)	Pipeline. The services included in this segment include installing transmission and distribution pipe made of various materials for oil, natural gas and water.

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          The table below shows the revenues generated by each operating segment for the fiscal years ended March 31, 2006, 2007 and 2008:

	Year Ended March 31,
	2008				2007				2006
	(Dollars in thousands)
Heavy construction & mining	$	626,582	63.3	%	$	473,179	75.2	%	$	366,721	74.5	%
Piling		162,397	16.4			109,266	17.3			91,434	18.6
Pipeline installation		200,717	20.3			47,001	7.5			34,082	6.9
Total	$	989,696	100.0	%	$	629,446	100.0	%	$	492,237	100.0	%

Heavy construction and mining

          Our heavy construction and mining segment encompasses a wide variety of services. These include a contract mining business providing the outsourcing of the equipment and labor component to the oil sands and other natural resources mining business. Our site preparation services include clearing, stripping, excavating and grading for mining operations, plant site development and other general construction projects, as well as underground utility installation for plant, refinery and commercial building construction. This business unit utilizes the vast majority of our equipment fleet and employs over 1,600 people. The majority of the employees and equipment associated with this business unit are located in the Alberta oil sands area.

          For the fiscal years ended March 31, 2006, 2007 and 2008, revenues from this segment accounted for 75%, 75% and 63% of our total revenues, respectively.

          Many oil sands and natural resource mining companies utilize contract services in their mine site operations. Our mining services consist of overburden removal, the hauling of sand and gravel, mining of the ore body and delivery of the ore to the crushing facility, supply of labor and equipment to support the owners’ mining operations, construction of infrastructure associated with mining operations, and reclamation activities, which include contouring of waste dumps and placement of secondary materials and muskeg. Many of the major producers outsource mine site operations to contractors like us so that they can better focus their own resources on exploration, property development and also to take advantage of a variety of cost efficiencies that mining contractors can provide. In our experience, mining contractors typically have had wage rates lower than those of the producers. In addition, most contractors have more flexible operating arrangements with personnel allowing for improved uptime and performance.

          Oil sands operators use our services to prepare their sites for the construction of mining infrastructure, including extraction plants and upgrading facilities, and for the eventual mining of the oil sands ore located on their properties. Outside of the oil sands, our site preparation services are used to assist in the construction of roads, natural resource mines, plants, refineries, commercial buildings, dams and irrigation systems. In order to successfully provide these types of services in the oil sands, our operators are required to use heavy equipment to transform barren terrain and difficult soil or rock conditions into a stable environment for site development. Our fleet of equipment is used for clearing vegetation and removing topsoil that is not usable as a stable sub-grade and for site grading, which includes grading, levelling and compacting the ground to provide a solid foundation for transportation or

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construction. We also provide utility pipe installation for the private and public sectors in western Canada. We are experienced in working with piping materials such as HDPE, concrete, PVC and steel. This work involves similar methods as those used for field, transmission and distribution pipelines in the oil and gas industry, but is generally more intricate and time consuming, as the work with these types of products is typically performed in existing plants with numerous tie-ins to live systems.

          As a result of our experience and expertise in the oil sands, we are often engaged at an early stage to help our customers plan and estimate costs to develop oil sands projects. This may entail the dissemination of information about working in the oil sands, including details about the difference in the cost of undertaking various projects in various seasons, constructability, equipment availability and requirements and our capability and insight into our customers’ plans and schedules, thereby allowing us to achieve greater accuracy in forecasting equipment and labour needs.

Piling

          Our piling services include the installation of all types of driven and drilled piles, caissons and earth retention and stabilization systems for private industrial projects such as plants and refineries; commercial buildings; and infrastructure projects, such as bridges. The piling segment currently employs approximately 350 people. Oil and gas companies developing the oil sands and related infrastructure represented approximately 55% of our piling revenue for fiscal 2008. The remaining 45% of our piling revenue was generated primarily from commercial construction companies operating in the Edmonton, Calgary, Regina, Saskatoon and Vancouver areas.

          In providing piling services, we operate a variety of crawler-mounted drill rigs, a fleet of 25-to-100-ton capacity piling cranes and pile driving hammers of all types from all of our western Canadian locations. Piles and caissons are deep foundation systems that extend up to 30 meters below a structure. Piles are long narrow shafts that distribute a load from a supported structure (such as a building or bridge) throughout the underlying soil mass and are necessary whenever the available footing area beneath a structure is insufficient to support the load above it. The foundation chosen for any particular structure depends on the strength of the rock or soil, magnitude of structural loads and depth of groundwater level. In fiscal 2006, we introduced Continuous Flight Auger (“CFA”) piling technology to the Canadian market. CFA piling is an installation method that allows for drilled, cast-in place concrete piles to be installed in an economical manner in areas of poor soil conditions. Aside from schedule enhancements to the project, CFA is also environmentally friendly, with low noise and no vibration generation. In fiscal 2007, we acquired micropiling capabilities. Micropiling is used in areas of limited access using small equipment to install small diameter piles which can be pressure grouted to achieve high load carrying capacity.

          For the fiscal years ended March 31, 2006, 2007 and 2008, revenues from our piling segment accounted for 19%, 17% and 16% of our total revenues, respectively.

Pipeline

          We install field, transmission and distribution pipe made of steel, plastic and fibreglass materials. We employ our fleet of construction equipment and skilled technical operators to build and test the pipelines for the delivery of oil and natural gas from the producing field to the consumer. Our pipeline teams have expertise in hand welding selected grade pipe and in operating in the harsh conditions of remote regions in western and northern Canada.

          Prior to fiscal 2007, almost all of our revenues in our pipeline business resulted from work performed for EnCana. In fiscal 2007 we also performed work for Canadian Natural, Suncor Energy Inc.

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and Husky Energy Inc. During fiscal 2008 we commenced work for the Kinder Morgan TMX pipeline expansion. This 18-month project requires the installation of approximately 160 kilometres of new pipeline through an ecologically sensitive area (including Jasper National Park) of the Rockies. To date we have laid approximately 105 kilometres of new pipeline with minimal impact to the environment, while meeting customer deadlines. We believe that this project demonstrates our ability to take on large pipeline expansions.

          For the fiscal years ended March 31, 2006, 2007 and 2008, revenues from our pipeline segment accounted for 7%, 8% and 20% of our total revenues, respectively.

Our Markets

	We provide our services in the following four markets:
1.	Canadian Oil Sands: Revenue generated from the construction, maintenance or operation of oil sands extraction, upgrading or transmission facilities and infrastructure.
2.	Minerals Mining: Revenue generated from the construction, maintenance or operation of non oil sands mining projects.
3.	Commercial and Public Construction: Revenue generated from commercial or public construction projects.
4.	Conventional Oil and Gas: Revenue generated from the construction, maintenance or operation of oil and gas transmission and/or refining facilities and infrastructure.

          The following chart provides a breakdown of our fiscal 2008 consolidated revenue by end market.

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Canadian Oil Sands

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

          The graph below illustrates the significant investment being projected for the Alberta oil sands until 2015.

According to CAPP, approximately $55.2 billion was invested in the oil sands from 1998 through 2006. According to CERI’s November 2007 report, “Canadian Oil Sands Supply Costs and Development Projects (2007-2027)”, an additional $228 billion of capital expenditures will be required between 2007 and 2015 to achieve production levels projected under their “constrained” scenario. According to the CERI, as of November 2007, there were 23 mining and upgrader projects in various stages, ranging from announcement to construction, with start-up dates through 2014. Beyond 2014, several new multi-billion dollar projects and a number of smaller projects are being considered by various oil sands operators. We intend to pursue business opportunities from these projects.

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          The graph below shows projected oil sands production under CERI’s “constrained” scenario from their November 2007 report. Production growth in the oil sands has been a driver of growth for our recurring site services, which includes equipment and labour supply, overburden removal and reclamation services.

Outlook

          Oil sands production has grown four-fold since 1990 and exceeded one million bpd in 2006 according to CAPP. CERI forecasts oil sands production to reach approximately 4.1 million bpd and account for over 80% of total Canadian oil production by 2015. By comparison, the Ghawar oil field in Saudi Arabia currently produces 5.0 million bpd, representing over 6% of the world’s total production and over 50% of Saudi Arabia’s production.

          On October 25, 2007, the Alberta government announced increases to the Alberta royalty rates affecting natural gas, conventional oil and oil sands producers. The announced increases were significant, but lower than increases recommended to the government by the Royalty Review Panel. While some of our customers have announced their intentions to reduce oil and gas investment in Alberta as a result of the increased royalties, to date, the areas affected by these investment reductions do not include oil sands mining projects.

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

          Demand for our services is driven primarily by the development, expansion and operation of oil sands projects. The oil sands operators’ capital investment decisions are driven by a number of factors, with one of the most important being the expected long-term price of oil. The development, expansion

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and operation of oil sands projects, related public infrastructure spending and commercial construction activity in western Canada play a key role in influencing our business activities.

          To transport the increased production expected from the oil sands and to provide natural gas as an energy source to the oil sands region, significant investment will be required to expand pipeline capacity. To date, there have been significant greenfield and expansion projects proposed, including:

• Enbridge Inc.’s proposed Gateway pipeline, which will transport oil from the oil sands area to Kitimat, British Columbia.

• The proposed Access Pipeline (a joint venture between MEG Energy Corp. and Devon ARL Canada Corp.), which will transport bitumen from the oil sands to refineries in Edmonton, Alberta and diluents from Edmonton, Alberta to the oil sands area.

• TransCanada Corporation’s proposed Keystone pipeline project, which will transport oil from Hardisty, Alberta to the Chicago area.

• The proposed Spirit pipeline system (a joint venture between Kinder Morgan and Pembina Pipeline Corporation), which will transport condensate from Kitimat, British Columbia to Edmonton, Alberta.

          We believe that our service offerings and pipeline construction experience position us well to compete for additional sizeable pipeline opportunities required for the expected growth in oil sands production.

Conventional Oil and Gas

          We provide services to conventional oil and gas producers, in addition to our work for oil sands operators. The Canadian Energy Pipeline Association estimates that over $20 billion of pipeline investment in Canada will be required for the development of new long-haul pipelines, feeder systems and other related pipeline construction. Conventional oil and gas producers require pipeline installation services in order to connect producing wells to existing pipeline systems. According to CAPP, Canada is one of the world’s largest producers of oil and gas, producing approximately 2.7 million barrels of oil per day and approximately 17.1 billion cubic feet of natural gas per day in 2006. Canadian Natural gas production is expected to increase with the development of arctic gas reserves. A producer group has been formed by Imperial Oil Limited, ConocoPhillips Canada Limited, Shell Canada and the Aboriginal Pipeline Group, for the purpose of bidding for work on the construction of a pipeline proposed to extend 1,220 kilometres (758 miles) from the MacKenzie River delta in the Beaufort Sea to existing natural gas pipelines in northern Alberta. Under the group’s proposal, Imperial Oil will lead the construction and operate the pipeline.

Minerals Mining

          According to the government agency Natural Resources Canada (“NRC”), Canada is also one of the largest mining nations in the world, producing more than 60 different minerals and metals. Canada is also the top destination of mineral exploration capital from worldwide sources in 2006, according to NRC. In 2007, the mining and minerals processing industries contributed approximately $41.9 billion to the Canadian economy, an amount equal to approximately 3.4% of GDP. The value of minerals produced (i.e. excluding petroleum and natural gas) reached $40.4 billion in 2007.

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          The diamond mining industry in Canada is relatively new, having operated for only nine years. According to NRC, the industry has grown from 13.2 million carats of production in 2006 to an estimated 17.0 million carats of production in 2007, representing a production growth rate of 28.1%, and establishing Canada as the third largest diamond producing country in the world by value after Botswana and Russia. We believe Canadian diamond mining will continue to grow as existing mines increase production and new mine projects are developed. Outside the oil sands, we have identified the Canadian diamond mining industry as a primary target for new business opportunities. We intend on leveraging the experience and skills gained in through the successful completion of the construction of the DeBeers Victor diamond mine to pursue other opportunities in this area.

          Canada is the world leader in uranium mining. The two largest high-grade deposits of uranium in the world have been discovered in Canada. According to NRC, 80% of Canada’s recoverable reserve base is categorized as “low-cost”. Historically, exploration and production have 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, with as many as 90 junior exploration companies involved in exploration.

          We intend to build on our core services and strong regional presence to capitalize on the opportunities in the minerals mining industries of Canada.

Commercial and Public Construction

          According to Statistics Canada, the Canadian commercial and public construction market was approximately $28.8 billion in 2007. The significant activity in the energy sector, in western Canada has resulted in economic and population growth. The Alberta government has responded to the potential strain that such growth will have on public facilities and infrastructure by allocating approximately $120 billion over 20 years to improvement and expansion projects. We believe that this need for infrastructure to support growth, along with historic under-investment in infrastructure, provides for a strong infrastructure spending outlook.

          The success of the energy industry in western Canada is also leading to increased commercial development in many urban centers in British Columbia and Alberta. According to the Alberta government, as of April 2008, the inventory of commercial, retail and infrastructure projects in Alberta was valued at approximately $30.6 billion. These large expenditures will be further supplemented by the 2010 Olympic Winter Games, which will be held in the Vancouver area. The City of Vancouver estimates that the 2010 Olympic Winter Games will require $4.0 billion in infrastructure and construction spending. We believe that the significant resources and capital intensive nature of the core infrastructure and construction services required to meet these demands, along with our strong local presence and significant regional experience, position us to implement our business model to capitalize on the large and growing infrastructure and construction demands of western Canada.

Contracts

          We complete work under the following four types of contracts:

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

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2.	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 equipment supplied. The risk associated with this type of contract is that the estimation of the rates and the 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.
3.	Unit-price: A unit-price contract is utilized in the execution of projects with large repetitive quantities of work and is commonly utilized for site preparation, mining and pipeline work. We are compensated for each unit of work we perform (for example, cubic meters of earth moved, lineal meters of pipe installed or completed piles). Within the unit-price contract, there is an allowance for labour, equipment, materials and any subcontractor’s costs. Once these costs are calculated, we add any site and corporate overhead costs along with an allowance for the margin we want to achieve. The risk associated with this type of contract is in the calculation of the unit costs with respect to completing the required work.
4.	Lump sum: A lump-sum contract is utilized when a detailed scope of work is known for a specific project. Thus, the associated costs can be readily calculated and a firm price provided to the customer for the execution of the work. The risk lies in the fact that there is no escalation of the price if the work takes longer or more resources are required than were estimated in the established price, as the price is fixed regardless of the amount of work required to complete the project.

          In addition to the types of contracts listed above, we also use master service agreements for work in the oil sands sector where the scope of the project is not known and timing is critical. The master service agreement is a form of a time-and-materials agreement that specifies the rates that will be charged for the supply of labour and equipment. The agreement does not identify any specific scope or schedule of work. In this regard, the customer specifies the work to be completed at each location. We use master service agreements with the work we perform for Syncrude, Suncor and Albian.

          We also do a substantial amount of work as a subcontractor where we are governed by the contracts with the general contractor to which we are not a party. Subcontracts vary in type and 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.

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     The following chart shows our fiscal 2008 consolidated revenue by contract type (other than cost-plus contracts which constituted less than 1% of consolidated revenue).

PROJECTS

Current Projects

Canadian Natural: Overburden Removal

          Canadian Natural’s Horizon Project is located 70 kilometres north of Fort McMurray in the Alberta oil sands. Production is scheduled to begin in late calendar 2008 and is expected to produce 110,000  bpd. Future phases will see production of 232,000 bpd, followed in due course by an increase to 500,000 bpd.

          In 2005, we won a contract with Canadian Natural to remove approximately 400 million bank cubic meters (“BCM”) of overburden and to use 200 million BCM of it to build tailings dykes at the site. This is a unit price contract worth approximately $1.3 billion over the 10-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 expect to supply an additional 10 years of overburden removal for Canadian Natural once our current contract expires.

Syncrude: Reclamation

          We have completed three years of work on a five-year contract to provide complete reclamation of overburden dumps and tailings dams at the Syncrude site. The scope of services under this five-year contract includes the excavation, hauling and placing of approximately 15.7 million cubic meters of muskeg (wet peat soil) and other secondary material. Reclamation is performed during the final stages of the mining process, where material that is suitable as a growing medium is placed over various areas in

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the oil sands mine site to return the land to a stable, biologically self-sustaining state. This contract is reflected in our backlog under time and materials and is scheduled to be completed by March 2010.

          The original four-year contract was entered into in 1998; however, the contract has been continually renewed since 2002. Our current agreement was renewed in September 2007 and is up for renewal in October 2008.

Syncrude: Base Plant: Labour & Equipment Supply

          We were contracted by Syncrude to perform various aspects of work at their base plant in Fort McMurray. The scope of work under this contract is undefined and is not reflected in our reported backlog. Construction Work Authorizations are issued for each piece of work required and are normally completed under time and materials arrangement on an hourly basis utilizing different types of equipment and labour. The contract was renewed in September 2007 and is due for renewal in October 2008. This agreement had been originally negotiated in 1998.

Albian: Muskeg River: Labour & Equipment Supply

          Albian is the operator of the Muskeg River Mine located 75 kilometres north of Fort McMurray, Alberta. At full production, the Muskeg River Mine produces 155,000 bpd of bitumen for the Athabasca Oil Sands Project, a joint venture among Shell Canada Limited, Chevron Canada and Marathon Oil Canada Corporation.

          We supply the necessary labour and equipment for a variety of heavy construction and mining projects such as overburden removal, reclamation, ditching, grading and tailing dyke construction. We entered a two-year mining and construction services agreement with Albian, effective May 1, 2007, which replaced a similar mining services contract which began in March 2002. Under the expanded scope of the current agreement, we perform heavy construction jobs in addition to supplying labour and equipment to Albian’s mining operations at the Muskeg River Mine. The work is typically performed under a time and materials arrangement and is not reflected in our reported backlog.

Suncor: Millennium Naphtha Unit

     Suncor’s MNU Project involves the construction of various plants and a series of pipe racks that tie the new plants to the existing ones. We are currently working on this project under a contract that includes the provision of site grading and road works services, and the installation of deep and shallow undergrounds, piling, foundations, grounding and concrete pavement. This contract is reflected in our backlog under time and materials and is anticipated to be completed by July 2008.

Suncor: Voyageur

          Suncor Energy Inc.’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, construction dewatering and provide the piling to support the foundations of the pipe rack systems, vessels and other structures across the site. This contract is reflected in our backlog under time and materials and is anticipated to be completed by November 2009.

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Shell: Scotford

          Shell has undertaken a major expansion to their upgrading facility in the Edmonton Area in preparation for the planned production increases slated for the oil sands. We were contracted to supply the majority of the piling work for this project back in 2006 and to date we have installed over 7,000 piles and we are still active on the site. This work is performed under a unit rate contract, and is reflected in our backlog.

Kinder Morgan: TMX Anchor Loop

          The Kinder Morgan TMX Anchor Loop pipeline involves “twinning” (or “looping”) a 158 kilometre section of the existing Trans Mountain pipeline system between Hinton, Alberta and Jackman, British Columbia. It also involves the addition of two new pump stations. We were selected to undertake the first phase of this challenging project, which includes 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. The contract is reflected in our backlog under time and materials and is anticipated to be completed by October 2008.

Recently Completed Projects

DeBeers: Victor Project

          The Victor Project is located in the James Bay Lowlands of Northern Ontario, approximately 90 kilometres west of the coastal First Nations community of Attawapiskat. The Victor mine will be the first diamond mine in Ontario and the second in Canada for DeBeers.

          We provided site preparation services including site dewatering, ditching, crushing, fill placement, airstrip construction, plant grading, road construction, mine haul road development, removal of 1 million BCM of muskeg and 2.5 million cubic meters of limestone blasting. In 2006 we also built the winter ice road for temporary land access to the site. During the warmer summer months the only access is by air. We completed the contract in fiscal 2008.

Albian: Aerodrome

          We recently built an airstrip and associated facilities for Albian’s Expansion One site, expanding our own service offering to include engineering, procurement and final commissioning in addition to construction services. The aerodrome project involved the construction of a 2.3 kilometre paved runway with associated taxiways, apron, terminal and support facilities which accommodate aircraft sizes up to an Airbus A319. The private airstrip is used for employee and executive transportation to and from the site. The aerodrome project was completed on schedule in October 2007.

Various Subcontracts

          In addition to the contracts listed above, 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.

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Joint Venture

          We are party to a joint venture operated through a corporation called Noramac Ventures Inc., or Noramac, with Fort McKay Construction Ltd. This joint venture was created for the purpose of performing contracts for the construction, development and operation of open-pit mining projects within a 50-kilometre radius of Fort McKay, Alberta, which require the provision of heavy construction equipment. 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 each of our partner and us. The Management Committee is responsible for determining the percentage of work in relation to each contract that will be performed by us and by our partner, provided that contracts for a duration of less than two years and of a tender value between $10.0 million and $100.0 million that require a parent guarantee or performance bond, will be subcontracted to us. The joint venture agreement provides that if the Management Committee does not tender for a contract, or fails to reach agreement on the terms upon which Noramac will tender for a contract, our partner or we may pursue the contract in our respective capacities, without hindrance, interference or participation by the other party. 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. The joint venture is accounted for as a variable interest entity and consolidated in our financial statements.

Our Fleet and Equipment

          We operate and maintain 845 pieces of diversified heavy equipment, including crawlers, graders, loaders, mining trucks, compactors, scrapers and excavators, as well as over 925 ancillary vehicles, including various service and maintenance vehicles. Overall, the equipment is in good condition, subject to normal wear and tear. Our revolving 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, 2008:

		Horsepower	Number	Number
Category	Capacity Range	Range	in Fleet	Leased
Heavy construction and mining:
Articulating trucks	30-42 tons	305-460	60	0
Mining trucks	50-330 tons	650-2,700	152	28
Shovels	36-58 cubic yards	2,600-3,760	5	3
Excavators	1-20 cubic yards	94-1,350	183	20
Crawler tractors	N/A	120-1,350	147	25
Graders	14-24 feet	150-500	25	5
Scrapers	28-31 cubic yards	450	10	0
Loaders	1.5-16 cubic yards	110-690	65	0
Skidsteer loaders	1-2.25 cubic yards	70-150	55	0
Packers	44,175-68,796 lbs	216-315	22	0

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		Horsepower	Number	Number
Category	Capacity Range	Range	in Fleet	Leased
Pipeline:
Snow cats	N/A	175	4	0
Trenchers	N/A	165	1	0
Pipelayers	16,000-140,000 lbs	78-265	59	0
Piling:
Drill rigs	60-135 feet (drill depth)	210-1,500	43	0
Cranes	25-100 tons	200-263	14	0
Total			845	81

          For the fiscal years ended March 31, 2006, 2007 and 2008 we incurred expenses of $64.8 million, $122.3 million and $174.9 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,
	2008		2007		2006
	(Dollars in thousands)
Heavy construction & mining	$	37,916	$	95,829	$	25,090
Piling		12,945		8,940		880
Pipeline		5,229		1,918		82
Other		1,689		3,332		2,800
Total	$	57,779	$	110,019	$	28,852

Facilities

          We own and lease a number of buildings and properties for use in our business. Our administrative functions are located at our headquarters near Edmonton, 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; Vancouver, Fort Nelson and New Westminster, British Columbia; and Regina and Martensville, Saskatchewan. We lease premises in British Columbia,

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Alberta and Saskatchewan under leases which expire between 2008 and 2015, subject to various renewal and termination rights. We have renewed our office lease, which now expires in 2012. We also occupy, without charge, some customer-provided lands. Our revolving credit facility and currency and interest rate swaps are secured by liens on substantially all of our properties. The following table describes our primary facilities.

			Lease Expiration
Location	Function	Owned or Leased	Date
Acheson, Alberta	Corporate Headquarters and major equipment repair facility	Leased	11/30/2012
Calgary, Alberta	Regional office and major equipment repair facility – piling operations	Leased	12/31/2010
Calgary, Alberta	Satellite office	Leased	month-to-month
Fort McMurray, Alberta Syncrude Plant Site	Satellite office and minor repair facility – all operations	Building Owned Land Leased	11/30/2009
Fort McMurray, Alberta CNRL Plant Site	Site office and maintenance facility	Building Owned Land Provided	n/a
Fort McMurray, Alberta Aurora Mine Site	Satellite office and equipment facility – all operations	Leased	month-to-month
Fort McMurray, Alberta Albian Sands Mine Site	Satellite office and equipment facility – all operations	Building Leased Land Provided	month-to-month
Fort McMurray, Alberta	Satellite office	Building Leased	13 yr. term from date of business opening
Fort Nelson, British Columbia	Satellite office – pipeline operations	Leased	7/10/2008
Regina, Saskatchewan	Regional office and equipment repair facility – piling operations	Leased	3/14/2013
Martensville, Saskatchewan	Regional office and equipment repair facility – piling operations	Leased	4/30/2012
Calgary, Alberta	Satellite office and shop for micropile division	Leased	month-to-month
Edmonton, Alberta	Regional office and warehouse storage facility	Leased	12/31/2010
Delta, British Columbia	Storage facility	Land Leased	month-to-month
Acheson, Alberta	Temporary satellite office	Leased	month-to-month

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

Competition

          We experience high levels of competition in each of our markets. Sometimes, we are awarded work through our existing relationships with clients, but more typically, we have had to participate in formal bidding processes to secure jobs with existing clients and in order to generate new business with new customers. As new major projects arise, we expect to have to participate in bidding processes on a meaningful portion of the work available to us on these projects. Factors that impact our ability to compete in such bidding include price, safety, reliability, scale of operations, availability and quality of service. Most of our customers and potential customers in the oil sands area operate their own heavy

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mining equipment fleet. However, these operators have historically outsourced a significant portion of their mining and site preparation operations and other construction services.

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

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

Major Suppliers

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

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

Seasonality

          A number of factors contribute to variations in our quarterly results between periods, including weather, capital spending by our customers on large oil sands projects, our ability to manage our project-related business so as to avoid or minimize periods of relative inactivity and the strength of the Western Canadian economy. For example, we generally experience a decline in revenues during the first quarter of each fiscal year (i.e. from April 1 to June 30) due to seasonal weather conditions that make many roads unsuitable for the operation of heavy equipment. Conversely, we tend to experience our highest revenues in the latter half of our fiscal year as climate conditions become favourable to our operating requirements.

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          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 maintenance. Profitability also varies from period to period due to claims and change orders. Claims and change orders are a normal aspect of the contracting business but can cause variability in profit margin due to the unmatched recognition of costs and revenues.

          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. 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.

Laws, Regulations and Environmental Matters

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

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

• building and similar codes and zoning ordinances;

• laws and regulations relating to consumer protection; and

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

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

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

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or property damage may be brought against us if we cause the release of, or any exposure to, harmful substances.

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

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

Employees

          As of March 31, 2008, we had over 280 salaried employees and over 2,120 hourly employees. Our hourly workforce will fluctuate according to the seasonality of our business from an estimated low of 1,500 employees in the spring to a high of approximately 2,300 employees over the winter. We also utilize the services of subcontractors in our construction business. An estimated 8% to 10% of the construction work we do is performed by subcontractors. Approximately 2,000 employees are members of various unions and work under collective bargaining agreements. The majority of our work is done through employees governed by a collective bargaining agreement with the International Union of Operating Engineers Local 955, the primary term of which expires on October 31, 2009. A small portion of our employees work under an industrial collective bargaining agreement with the Alberta Road Builders and Heavy Construction Association and the International Union of Operating Engineers Local 955, the primary term of which expires February 28, 2009. We are subject to other industry and specialty collective agreements under which we complete work, and the primary terms of all of these agreements are currently in effect. We believe that our relationships with all our employees, both union and non-union, are satisfactory. We have not experienced a strike or lockout.

The IPO and Reorganization

          NACG Holdings Inc. (“Holdings”), a predecessor to the Company, 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 (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 our 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 same class of shares sold in our IPO.

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

• NACG Holdings Inc. repurchased the Series A preferred shares issued by the pre-amalgamated North American Energy Partners Inc. for their redemption value of $1.0 million and terminated the advisory services agreement with The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc. and SF Holding Corp. (whom we refer to collectively as the sponsors), under which we had received ongoing consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. We paid the sponsors a fee of $2.0 million to terminate the agreement, which was charged to income in fiscal 2007. Under the consulting and advisory services agreement, the sponsors also received a fee of $0.9 million, equal to 0.5% of our aggregate gross proceeds from our IPO, which was included in share issue costs.

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

• Each holder of the Series B preferred shares issued by the pre-amalgamated North American Energy Partners Inc. received 100 NACG Holdings Inc. common shares for each Series B preferred share held.

          On November 28, 2006, we completed our IPO in the United States and Canada of 8,750,000 voting common shares for $18.38 per share (U.S. $16.00 per share). On November 22, 2006, our common shares commenced trading on the New York Stock Exchange and on an “if, as and when issued” basis on the Toronto Stock Exchange. On November 28, 2006, our common shares became fully tradable on the Toronto Stock Exchange. Net proceeds from the IPO were $140.9 million (gross proceeds of $158.5 million, less underwriting discounts and costs and offering expenses of $17.6 million). In addition, on December 6, 2006, the underwriters exercised their option to purchase an additional 687,500 common shares from us. The net proceeds from the exercise of the underwriters’ option were $11.7 million (gross proceeds of $12.6 million, less underwriting fees of $0.9 million). Total net proceeds were $152.6 million (total gross proceeds of $171.1 million less total underwriting discounts and costs and offering expenses of $18.5 million).

          We used the net proceeds from the IPO:

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

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

• to purchase certain leased equipment for $44.6 million;

• to pay the $2.0 million fee required to terminate the advisory services agreement with the sponsors; and

• $1.3 million for working capital and general corporate purposes.

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          As of March 31, 2008, our authorized capital consists of an unlimited number of voting and non-voting common shares, of which 35,929,476 voting common shares were issued and outstanding. On July 27, 2007, the Company’s non-voting common shares were exchanged 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.

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 16, 2008, we had 36,016,476 common shares outstanding, and no non-voting common shares outstanding.

          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 therefor 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 8³/4% senior notes. See “Description of Certain Indebtedness”.

          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 preemptive 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.

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 (1) in a public offering of our voting common shares; (2) to a third party that, prior to such sale, controls us; (3) to a third party that, after such sale, is a beneficial owner of not more than 2% of our outstanding voting shares; (4) in a transaction that complies with Rule 144 under the Securities Act; or (5) in a transaction approved in advance by regulatory bodies.

          On July 27, 2007, the holder of the Company’s non-voting common shares were exchanged 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.

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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 revolving credit facility and the indenture that governs our notes.

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 U.S. dollars) on a monthly basis from April 1, 2007 to March 31, 2008.

Toronto Stock Exchange
Date	High		Low		Volume
March 2008		16.33		11.50		79,736
February 2008		16.98		9.73		178,074
January 2008		14.02		10.87		111,203
December 2007		14.02		12.57		141,573
November 2007		18.56		12.25		75,667
October 2007		18.54		16.53		31,250
September 2007		18.85		16.50		23,470
August 2007		19.80		17.23		106,312
July 2007		22.29		18.33		35,565
June 2007		23.30		21.24		50,250
May 2007		26.15		22.01		25,620
April 2007		25.76		21.87		34,395

New York Stock Exchange
Date	High		Low		Volume
March 2008		16.74		14.18		2,228,650
February 2008		17.50		9.68		4,280,347
January 2008		14.58		10.64		2,808,400
December 2007		14.28		12.30		2,827,700
November 2007		20.08		12.37		3,906,301
October 2007		19.47		16.76		2,603,100
September 2007		18.06		16.05		2,396,900
August 2007		19.00		16.11		4,970,000
July 2007		21.43		17.13		1,436,000
June 2007		21.98		19.51		1,437,800
May 2007		23.72		20.68		1,637,800
April 2007		22.80		18.60		1,773,400

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DESCRIPTION OF CERTAIN INDEBTEDNESS

Revolving Credit Facility

          We entered into an amended and restated credit agreement dated as of June 7, 2007 with a syndicate of lenders that provides us with a $125.0 million revolving credit facility. The following is a summary of certain provisions of the revolving credit facility.

          General: Our revolving credit facility provides for an original principal amount of up to $125.0 million under which revolving loans may be made and under which letters of credit may be issued. The facility will mature on June 7, 2010, subject to possible extension.

          Security: The credit facility is secured by a first priority lien on substantially all of our and our subsidiaries’ existing and after-acquired property (tangible and intangible), including, without limitation, accounts receivable, inventory, equipment, intellectual property and other personal property, and real property, whether owned or leased, and a pledge of the shares of our subsidiaries, subject to various exceptions.

          Interest rates and fees: The facility bears interest on each prime loan at variable rates based on the Canadian prime rate plus the applicable pricing margin (as defined in the credit agreement). Interest on U.S. base rate loans is paid at a rate per annum equal to the U.S. base rate plus the applicable pricing margin. Interest on prime and U.S. base rate loans is payable monthly in arrears and computed on the basis of a 365- or 366-day year, as the case may be. Interest on LIBOR loans is paid during each interest period at a rate per annum, calculated on a 360-day year, equal to the LIBOR rate with respect to such interest period plus the applicable pricing margin. A stamping fee equal to the applicable pricing margin, calculated on the principal amount at maturity, is paid upon the acceptance by a lender of a bankers’ acceptance. 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 0.10% 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 applied to the amount by which the amount of the outstanding principal owing to each lender under the credit facility for each day is less than the commitment of such lender and accrue daily from the first day to the last day of each fiscal quarter. In each case, the applicable pricing margin depends on our credit rating. Interest rates are increased by 2% per annum in excess of the rate otherwise payable on any amount not paid when due.

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

          Covenants: The credit facility contains restrictive covenants limiting our ability, and the ability of our subsidiaries to, without limitation and subject to various exceptions:

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

• amend the indenture governing our 8³/4% senior notes;

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• create or allow to exist liens or other encumbrances;

• transfer assets (including any class of stock or the voting rights of any of our 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;

• enter into mergers, consolidations and asset dispositions of all or substantially all of our, or any of our subsidiaries’ properties;

• make investments, including acquisitions;

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

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

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

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

          Events of default: The credit facility 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.

8³/4% Senior Notes due 2011

          General: On November 26, 2003, we issued an aggregate of US$200.0 million of 8³/4% senior unsecured notes pursuant to an indenture among us, the subsidiary guarantors and Wells Fargo Bank, N.A., as trustee. These notes will mature on December 1, 2011. Interest on these notes accrues at 8³/4% per annum and is payable in arrears on June 1 and December 1 of each year. All of our subsidiaries jointly and severally guarantee the 8³/4% senior notes.

          Redemption and Repurchase: We may redeem some or all of the 8³/4% senior notes at any time on or after December 1, 2007, at specified redemption prices. We may redeem up to 35% of the original aggregate principal amount of the 8³/4% senior notes in the event of certain equity sales at any time on or after December 1, 2007 at specified redemption prices. We may redeem all but not part of the notes in the event of various changes in the laws affecting withholding taxes. We are not required to make mandatory redemption or sinking fund payments with respect to the 8³/4% senior notes. We will be required to offer to repurchase the 8³/4% senior notes from holders if we undergo a change of control or sell our assets in specified circumstances.

          Covenants: The indenture governing the 8³/4% senior notes 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.

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Swap Agreements

          We have 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. As of March 31, 2008, the liability, measured at fair value, associated with the swap agreements was approximately $81.6 million.

Debt Ratings

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

DIRECTORS AND OFFICERS

Directors and Officers

          The following sets forth information about our directors and executive officers. Ages reflected are as of May 31, 2008. 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 Zone 3, Acheson Industrial Area, 2-53016 Highway 60, Acheson, Alberta, T7X 5A7. As of June 20, 2008, the directors and executive officers of the Company, as a group, beneficially owned, directly or indirectly, or exercised control or direction over 767,864 common shares of the Company (representing approximately 2.1% of all issued and outstanding common shares).

Name and Municipality of Residence	Age	Position
Rodney J. Ruston	57	Director, President and Chief Executive Officer
Edmonton, Alberta
Peter R. Dodd	58	Chief Financial Officer
Edmonton, Alberta
David Blackley	47	Vice President, Finance
Sherwood Park, Alberta
Robert G. Harris	60	Vice President, Human Resources, Health, Safety
Edmonton, Alberta		& Environment
Kevin Mather	35	Vice President, Supply Chain
Spruce Grove, Alberta

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Name and Municipality of Residence	Age	Position
Bernard T. Robert	41	Vice President, Business Development & Estimating
Sherwood Park, Alberta
Miles W. Safranovich	43	Vice President, Operations
Spruce Grove, Alberta
Christopher R. Yellowega	37	Vice President, Major Mining Developments
Airdrie, Alberta
Ronald A. McIntosh	66	Chairman of the Board
Calgary, Alberta
George R. Brokaw	40	Director
Southampton, New York
John A. Brussa	51	Director
Calgary, Alberta
John D. Hawkins	44	Director
Houston, Texas
William C. Oehmig	58	Director
Houston, Texas
Allen R. Sello	68	Director
West Vancouver, British Columbia
Peter W. Tomsett	50	Director
West Vancouver, British Columbia
K. Rick Turner	50	Director
Houston, Texas

Rodney J. Ruston became President and Chief Executive Officer of NAEPI on May 9, 2005 and 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.

Peter R. Dodd became Chief Financial Officer of NAEPI on February 4, 2008. Mr. Dodd has over 25 years experience in strategic business planning, corporate finance and investment banking. Prior to joining us, 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. A PhD in Accounting and Finance, Mr. Dodd served as Dean and Managing Director of the Australian Graduate School of Management, a world recognized business school serving both the University of New South Wales and the University of Sydney.

David Blackley became Vice President, Finance of NAEPI 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 at Lafarge Canada Inc. as Vice President, Finance of the North American Aggregates and Concrete division. A

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Chartered Accountant, Mr. Blackley holds a Bachelor of Commerce from Rhodes University in South Africa.

Robert G. Harris joined us in June 2006 as Vice President, Human Resources, Health, Safety & Environment. 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 in November 2007. 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 in September 2007. 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.

Miles W. Safranovich joined us in November 2004 and held the position of General Manager, Industrial and Heavy Civil until he was appointed Vice President, Contracts and Technical Services in July 2005 and Vice President, Business Development and Estimating in July 2006 and Vice President, Operations in September 2007. He has extensive experience in the construction industry, spending most of his career at Voice Construction Ltd. where he held a variety of positions between 2000 and October 2004, including Operations Manager and Construction Manager. Mr. Safranovich attended the University of Alberta and obtained a Bachelor of Science in Biology in 1986 and a Bachelor of Science in Civil Engineering specializing in Construction Management in 1992.

Christopher R. Yellowega became Vice President, Major Mining Projects on April 1, 2008 bringing extensive oil sands development and operations experience. 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.

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Ronald A. McIntosh became the Chairman of our board of directors on May 20, 2004. Mr. McIntosh was Chairman of NAV Energy Trust, a Calgary-based oil and natural gas investment fund from January 2004 to August 2006. 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. From July 2002 to October 2002, Mr. McIntosh managed his personal investments. 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 positions of Chief Operating Officer of Amerada Hess Canada, Director of Crispin Energy Inc. and on the Board of Directors of C1 Energy Ltd. Mr. McIntosh is on the Board of Directors of Advantage Oil & Gas Ltd.

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 as a Managing Director. Investment entities controlled by Perry Corp. are holders of our common shares. (See our most recent information circular that involved the elections of directors.) Prior to joining Perry, Mr. Brokaw as a Managing Director of Lazard Frères & Co. LLC, engaged in mergers and acquisition advisory across a broad range of sectors including energy and power, transportation and general industrials. Prior to joining Lazard, Mr. Brokaw was an Associate at Dillon Read & Co. where he worked in the mergers and acquisitions department. Mr. Brokaw has a Bachelor of Arts degree from Yale University, a Juris Doctorate and Masters of Business Administration from the University of Virginia. He is a member of the New York Bar.

John A. Brussa is a senior partner and head of the Tax Department at the law firm if 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, Crew Energy Inc. and Divestco 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.

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, a private equity investment firm, provided certain services to us pursuant to an advisory services agreement, and 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.) 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 until passing off this position and assuming the role of Director on May 20, 2004. He is a Partner with The Sterling Group, L.P., a private equity investment firm. The Sterling Group provided certain services to us pursuant to an advisory services agreement, and an investment entity affiliated with The Sterling Group is a holder of our common shares. (See our most recent information circular that involved the election of directors.) 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 boards of Propex Inc., Panolam Industries International Incorporated and Universal Fiber Systems. On January 18, 2008, Propex Inc.,and its wholly owned domestic subsidiaries filed voluntary petitions for relief under chapter 11 of title 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for Eastern District of

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Tennessee. 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 received his Bachelor of Science in Economics from Transylvania University and his Masters of Business Management 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 numerous 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 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 Chair of the Vancouver Board of Trade Government Budget and Finance Committee and a trustee of Sterling Shoes Income Fund. Mr. Sello received his Bachelor of Commerce from the University of Manitoba and his Masters of Business Administration from the University of Toronto.

Peter W. Tomsett became one of our Directors in September 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. He is a member of the Australian Institute of Mining and Metallurgy. Mr. Tomsett graduated with a Bachelor of Engineering (Honours) in Mining Engineering from the University of New South Wales and also attained a Masters of Science (Distinction) in Mineral Production Management from Imperial College, London. He is also a director of Silver Standard Resources Inc. and Chairman of Equinox Minerals Limited.

K. Rick Turner became one of our Directors on November 26, 2003. Mr. Turner has been employed by Stephens’ family entities since 1983. SF Holding Corp., formerly Stephens Group, Inc., provided certain services to us pursuant to an advisory services agreement, and an investment entity controlled by SF Holding Corp. is a holder of our common shares. (See our most recent information circular that involved the elections of directors.) 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 have been oil and gas exploration, natural gas gathering, processing industries and power technology. He currently serves on the board of two other publicly-held companies: Energy Transfer Partners and Energy Transfer Equity. He also serves on numerous private company boards, including JV Industrial; BTEC Turbines, LP; Spitzer Industries, Inc.; JEBCO Seismic, LP; Seminole Energy Services, LLC; Multi-Shot, LLC; and Acute Technologies, Inc. Mr. Turner earned his Bachelor of Science in Business Administration from the University of Arkansas and is a non-practicing CPA.

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. However, we do not, and are not required to, submit an annual Chief Executive Officer certification to the New York Stock Exchange.

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Our board has established the following committees:

1.	Audit Committee: The Audit Committee recommends independent public accountants to the board, reviews the quarterly and annual financial statements and related MD&A, press releases and auditor reports, and reviews the fees paid to our auditors. The Audit Committee approves quarterly financial statements and recommends annual financial statements for approval to the board. In accordance with Rule 10A-3 under the Securities Exchange Act of 1934, as amended, and 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. Our 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 annual information form. The Audit Committee is currently composed of Messrs. Brokaw, Hawkins, 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 are financially literate. The members of the audit committee have significant exposure to the complexities of financial reporting associated with us and are able to address with due oversight, and provide 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, 2008.
	The fees we have paid to KPMG for services rendered by them include:

(i)

Audit Fees

KPMG billed us $3,037,500 in 2008, $2,375,000 in 2007 and $2,617,000 in 2006 for audit services. Audit fees were incurred for the audit of our annual financial statements, the audit of 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.

(ii)	Audit Related Fees
	KPMG billed us $55,000 in 2008, $52,000 in 2007 and $62,000 in 2006 for planning and scoping work and advice relating to compliance and internal controls over financial reporting.

(iii)	Tax Fees
	KPMG billed us $33,000 in 2008, $16,640 in 2007 and $15,000 in 2006 for tax compliance services.

(iv)	All Other Fees
	KPMG did not perform any other services for us.

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2. 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.

3. Governance Committee: The Governance Committee is responsible for recommending to the board of directors proposed nominees for election to the board of directors by the shareholders at annual meetings, including an annual review as to the renominations of incumbents and proposed nominees for election by the board of directors to fill vacancies that occur between shareholder meetings, and making recommendations to the board of directors regarding corporate governance matters and practices. 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. The Governance Committee is currently composed of Messrs. Brussa, Hawkins, McIntosh and Turner, with Mr. Hawkins serving as Chairman.

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

The board may also establish other committees.

Compensation Committee Interlocks and Insider Participation

      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 2008 on a board of directors of another entity which has employed any of the members of the Compensation Committee.

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.

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INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Advisory Services Agreement

          We were party to an advisory services agreement, dated November 26, 2003, with The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc., and SF Holding Corp. (collectively, the “Sponsors”). The advisory services agreement was terminated upon the completion of our IPO.

Voting and Corporate Governance Agreement

          We were party to a voting agreement, dated November 26, 2003, with affiliates of the Sponsors. The voting agreement was terminated upon the completion of our IPO. We have entered into a letter agreement with each Sponsor pursuant to which we have engaged such Sponsor to provide their expertise and advice to us for no fee, which is in their interest because of their investment in us. In order for the Sponsors to provide such advice, we have agreed to

• provide them copies of all documents, reports, financial data and other information regarding us,

• permit them to consult with and advise our management on matters relating to our operations,

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

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

• 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,

• provide them copies of certain of our financial statements and reports, and

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

          We may terminate a Sponsor’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.

Shareholders Agreements

          All holders of our common shares who were also our employees or employees of any of our subsidiaries were parties to an employee shareholders agreement. All other holders of our common shares were parties to an investor shareholders agreement. Both shareholders agreements were terminated upon the completion of our IPO.

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Registration Rights Agreement

          We are party to a registration rights agreement with certain shareholders, including affiliates of each of the sponsors, 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 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:

• up to 120 days if

o 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

o 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

• 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

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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.

Properties and Facilities

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

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 located at 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:

• Form of 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;

• Indenture, dated as of November 26, 2003, among North American Energy Partners Inc., the guarantors named therein and Wells Fargo Bank, NA., as Trustee;

• Registration Rights Agreement, dated as of November 26, 2003, among NACG Holdings Inc. and the shareholders party thereto;

• Amended and Restated 2004 Share Option Plan;

• Overburden Removal and Mining Services Contract, dated November 17, 2004, between Canadian Natural and Noramac Ventures Inc.;

• Amended and Restated Joint Venture Agreement, dated September 30, 2004, among North American Construction Group Inc., Fort McKay Construction Ltd. and Noramac Ventures Ltd., including the assignment of contract from Noramac Ventures Ltd. To North American Construction Group Inc., dated February 27, 2006;

• Office Lease, as amended as of November 26, 2003, between Acheson Properties Ltd. and North American Construction Group Inc.;

• Office Lease, dated as of March 15, 2003, between Acheson Properties Ltd. and North American Construction Group Inc.;

• Office Lease, dated as of July 1, 2003, between Acheson Properties Ltd. and North American Construction Group Inc.; and

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• Revolving Credit Facility. Please refer to “Description of Capital Structure — Revolving Credit Facility” for information regarding the second amended and restated credit agreement that provides our revolving credit facility.

RISKS AND UNCERTAINTIES

Risks Related to our Business

Anticipated major projects in the oil sands may not materialize.

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

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

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

• lack of sufficient governmental infrastructure to support growth;

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

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

• cost overruns on announced projects.

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

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

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

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

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

          Due to the amount of capital investment required to build an oil sands project, or construct a significant expansion to an existing project, investment decisions by oil sands operators are based upon long-term views of the economic viability of the project. Economic viability is dependent upon the anticipated revenues the project will produce, the anticipated amount of capital investment required and the anticipated cost of operating the project. The most important consideration is the customer’s view of the long-term price of oil which is influenced by many factors, including the condition of developed and developing economies and the resulting demand for oil and gas, the level of supply of oil and gas, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political conditions in oil producing nations, including those in the Middle East, war or the threat of war in oil producing regions and the availability of fuel from alternate sources. If our customers believe the long-term outlook for the price of oil is not favorable, or believes oil sands projects are not viable for any other reason, they may delay, reduce or cancel plans to construct new oil sands projects or expansions to existing projects. Delays, reductions or cancellations of major oil sands projects would adversely affect our prospects and could have a material adverse impact on our financial condition and results of operations.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• scope modifications during the execution of the project;

• the availability and cost of skilled workers;

• the availability and proximity of materials;

• unfavorable weather conditions hindering productivity;

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

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

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

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

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

          We have identified a number of material weaknesses in our financial reporting processes and internal controls. See “Management’s Report on Internal Controls over Financial Reporting” in our annual management, discussion and analysis for our fiscal year ended March 31, 2008. As a result, there can be no assurance that we will be able to generate accurate financial reports in a timely manner. Failure to do so would cause us to breach the U.S. and Canadian securities regulations with respect to reporting requirements in the future as well as the covenants applicable to our indebtedness. This could, in turn, have a material adverse effect on our business and financial condition. Until we establish and maintain effective internal controls and procedures for financial reporting, we may not have appropriate measures in place to eliminate financial statement inaccuracies and avoid delays in financial reporting.

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

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

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

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

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

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

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

• competitive conditions; and

• increasing our vulnerability to increases in interest rates because borrowings under our revolving credit facility and

• payments under some of our equipment leases are subject to variable interest rates.

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

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

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

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

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

• payments;

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

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• issue equity securities of subsidiaries;

• make certain investments or acquisitions;

• create liens on our assets;

• enter into transactions with affiliates;

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

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

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

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

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

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

Currency rate fluctuations could adversely affect our ability to repay our 8 3/4% senior notes and may affect the cost of goods we purchase.

          We have entered into cross-currency and interest rate swaps that represent economic hedges of our 8 3/4% senior notes, which are denominated in U.S. dollars. The current exchange rate between the

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Canadian and U.S. dollars as compared to the rate implicit in the swap agreement has resulted in a large liability on the balance sheet under the caption “derivative financial instruments.” If the Canadian dollar increases in value or remains at its current value against the U.S. dollar, then if we repay the 8 3/4% senior notes prior to their maturity in 2011, we will have to pay this liability.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

          We recently made several significant changes to our senior management team. We promoted our Vice President Business Development and Estimating to the role of Vice President Operations in September 2007. We promoted our Director of Business Development to the role of Vice President Business Development and Estimating in September 2007, we promoted our General Manager Heavy Construction and Mining to the role of Vice President Supply Chain in December 2007 and in January 2008 we recruited and hired a new Chief Financial Officer and a new Vice President Finance. As a result of these and other recent

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changes in senior management, many of our officers have only worked together as a management team for a short period of time and do not have a long history with us. Because our senior management team is responsible for the management of our business and operations, failure to successfully integrate our senior management team could have an adverse impact on our business, financial condition and results of operations.

Risks Related to Our Common Shares

Fluctuations in the value of the Canadian and U.S. 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. If you are a U.S. shareholder, the value of your investment in us will fluctuate as the U.S. 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 U.S. dollar rises in value relative to the Canadian dollar, the U.S. dollar value of the dividend payments received by a U.S. common shareholder would be less than they would have been if exchange rates were stable.

If our share price fluctuates, you could lose a significant part of your 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:

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

• 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;

• actual or anticipated fluctuations in our operating results or future prospects;

• reaction to our public announcements;

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

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

• changes in accounting standards, policies, guidance, interpretations or principles;

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

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

• 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.

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          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 your 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 (1) we are, or would after the payment be, unable to pay our liabilities as they become due or (2) 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 your interests as a shareholder.

          Investment entities controlled by The Sterling Group, L.P., Perry Strategic Capital Inc. and SF Holding Corp., whom we collectively refer to as the sponsors, collectively held over 25% of our common shares. As a result, the sponsors and their affiliates will 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 sponsors maintain a significant interest in our common shares, so long as a designated affiliate of each sponsor holds our common shares, such sponsor 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 — Voting and Corporate Governance Agreement.”

          For so long as the sponsors own a significant percentage of our outstanding common shares, even if less than a majority, the sponsors 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

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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 sponsors and their affiliates may not coincide with the interests of our other shareholders. In particular, the sponsors 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 sponsors 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 sponsors and their affiliates continue to own a significant portion of the outstanding common shares, they will continue to be able to influence our decisions.

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.

You may be unable to enforce actions against us and some of our directors and officers under U.S. 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 for you to effect service of process within the United States upon those persons. Furthermore, it may not be possible for you to enforce against us or them, in or outside the United States, judgments obtained in U.S. 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 U.S. federal securities laws and as to the enforceability in Canadian courts of judgments of U.S. courts obtained in actions based upon the civil liability provisions of the U.S. 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 prospectus.

ADDITIONAL INFORMATION

Experts

          KPMG LLP is the external auditor of the Company who prepared the Report of Independent Registered Public Accounting Firm dated June 20, 2008, with respect to the financial statements of the Company as at March 31, 2008, 2007 and 2006 consisting of the consolidated balance sheets as at March 31, 2008 and March 31, 2007 and the consolidated statements of operations, comprehensive income (loss) and deficit and cash flows for each of the years in the three-year period ended March 31, 2008. KPMG LLP is independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta.

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Additional Information

          Additional information relating to the Company may be found on SEDAR at (www.sedar.com). 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 security of the Company, 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 the Company’s directors and our management’s discussion and analysis of financial condition and results of operations for the year ended March 31, 2008. Additional financial information is provided in the Company’s financial statements for the year ended March 31, 2008.

Additional information relating to us may be found on SEDAR at (www.sedar.com) and on EDGAR at (www.sec.gov).

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GLOSSARY

The following are definitions of certain terms commonly used in our industry and this annual information form.

“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.

“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.

Ultimate 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 • initial 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 (hydroprocessing).

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EXHIBIT A

North American Energy Partners Inc.

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 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.

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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 member 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.

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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.

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

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	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;
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

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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

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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
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.

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

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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.

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EX-99.2

Exhibit 99.2

NORTH AMERICAN ENERGY PARTNERS INC.

Consolidated Financial Statements

For the years ended March 31, 2008, 2007 and 2006
(Expressed in thousands of Canadian dollars)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of North American Energy Partners Inc.

We have audited the accompanying consolidated balance sheets of North American Energy Partners Inc. (the “Company”) as of March 31, 2008 and 2007 and the related consolidated statements of operations, comprehensive income (loss) and deficit and cash flows for each of the years in the three-year period ended March 31, 2008. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of March 31, 2008 and 2007 and the results of its operations and its cash flows for each of the years in the three-year period ended March 31, 2008 in conformity with Canadian generally accepted accounting principles.

As discussed in Note 3 (q) (i) to the consolidated financial statements, the Company adopted new accounting pronouncements related to recognition and measurement of financial instruments in 2008.

Canadian generally accepted accounting principles vary in certain significant respects from U.S. generally accepted accounting principles. Information relating to the nature and effect of such differences is presented in Note 30 to the consolidated financial statements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of March 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated June 20, 2008 expressed our opinion that the Company did not maintain effective internal control over financial reporting as of March 31, 2008.

/s/ KPMG LLP

Chartered Accountants

Edmonton, Canada

June 20, 2008

2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of North American Energy Partners Inc.

We have audited North American Energy Partners Inc. (“the Company”)’s internal control over financial reporting as of March 31, 2008, based on the criteria established in Internal Control - -Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in Management’s Report on Internal Control over Financial Reporting in the accompanying Management’s Discussion and Analysis for the year ended March 31, 2008. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

3

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s financial statements will not be prevented or detected on a timely basis. The following material weaknesses have been identified and included in management’s assessment:

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

We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the 2008 consolidated financial statements of the Company. These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2008 consolidated financial statements, and this report does not affect our report dated June 20, 2008, which expressed an unqualified opinion on those consolidated financial statements.

In our opinion, because of the effect of the aforementioned material weaknesses on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of March 31, 2008, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

/s/ KPMG LLP

Chartered Accountants

Edmonton, Canada

June 20, 2008

4

NORTH AMERICAN ENERGY PARTNERS INC.

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

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

See accompanying notes to consolidated financial statements.

Approved on behalf of the Board

/s/ Ronald A. McIntosh	/s/ Allen R. Sello
Ronald A. McIntosh, Director	Allen R. Sello, Director

5

NORTH AMERICAN ENERGY PARTNERS INC.

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

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

See accompanying notes to consolidated financial statements.

6

NORTH AMERICAN ENERGY PARTNERS INC.

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

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

See accompanying notes to consolidated financial statements.

7

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

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

8

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

The net proceeds from the IPO and subsequent overallotment were used to:

• repurchase all of the Company’s outstanding 9% senior secured notes due 2010 for $74,748 plus accrued interest of $3,027. The notes were redeemed at a premium of 109.26% resulting in a loss on extinguishment of $6,338. The loss on extinguishment, along with the write-off of deferred financing fees of $4,342 and other costs of $255, was recorded as a loss on extinguishment of debt in the consolidated statement of operations;

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

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

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

• for general corporate purposes.

3. Significant accounting policies

a)	Basis of presentation
	These consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles (“GAAP”). Material inter-company transactions and balances are eliminated on consolidation. Material items that give rise to measurement differences to the consolidated financial statements under United States GAAP are outlined in note 30.
	These consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, North American Construction Group Inc. (“NACGI”) and NACG Finance LLC, the Company’s joint venture, Noramac Ventures Inc. and the following 100% owned subsidiaries of NACGI:

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

b)	Use of estimates
	The preparation of financial statements in conformity with Canadian GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and disclosures reported in these consolidated financial statements and accompanying notes.
	Significant estimates made by management include the assessment of the percentage of completion on time-and-materials, unit-price or lump-sum contracts (including estimated total costs and provisions for estimated losses) and the recognition of claims and change orders on contracts, assumptions used to value financial instruments, assumptions used to determine the redemption value of redeemable securities, assumptions used in periodic impairment testing, and estimates and assumptions used in the

9

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

	determination of the allowance for doubtful accounts and the useful lives of plant and equipment. Actual results could differ materially from those estimates.
	The accuracy of the Company’s revenue and profit recognition in a given period is dependent, in part, on the accuracy of our estimates of the cost to complete each time-and-materials, unit-price, or lump-sum project. Our cost estimates use a detailed “bottom up’’ approach, using inputs such as labour and equipment hours, detailed drawings and material lists. These estimates are reviewed and updated monthly. The Company believes our experience allows us to produce materially reliable estimates. However, our projects can be highly complex. Profit margin estimates for a project may either increase or decrease to some extent from the amount that was originally estimated at the time of the related bid. With many projects of varying levels of complexity and size in process at any given time, changes in estimates can offset each other without materially impacting our profitability. Major changes in cost estimates, particularly in larger, more complex projects, can have a significant effect on profitability.
c)	Revenue recognition
	The Company performs its projects under the following types of contracts: time-and-materials; cost-plus; unit-price; and lump sum. Revenue is recognized as costs are incurred for time-and-materials and cost-plus service contracts with no clearly defined scope. Revenue on cost plus, unit-price, lump sum and time-and-materials contracts with defined scope are recognized using the percentage-of-completion method, measured by the ratio of costs incurred to date to estimated total costs. The resulting percent complete methodology is applied to the approved contract value to determine the revenue recognized. The estimated total cost of the contract and percent complete is determined based upon estimates made by management. The costs of items that do not relate to performance of contracted work, particularly in the early stages of the contract, are excluded from costs incurred to date.
	The length of the Company’s contracts varies from less than one year for typical contracts to several years for certain larger contracts. Contract project costs include all direct labour, material, subcontract and equipment costs and those indirect costs related to contract performance such as indirect labour, supplies, and tools. General and administrative costs are charged to expense as incurred. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Changes in project performance, project conditions, and estimated profitability, including those arising from contract penalty provisions and final contract settlements, may result in revisions to costs and revenue that are recognized in the period in which such adjustments are determined. Profit incentives are included in revenue when their realization is reasonably assured.
	Once a project is underway, the Company will often experience changes in conditions, client requirements, specifications, designs, materials and work schedule. Generally, a “change order” will be negotiated with the customer to modify the original contract to approve both the scope and price of the change. Occasionally, however, disagreements arise regarding changes, their nature, measurement, timing and other characteristics that impact costs and revenue under the contract. When a change becomes a point of dispute between the Company and a customer, the Company will then consider it as a claim.
	Costs related to change orders and claims are recognized when they are incurred. Revenues related to change orders are included in total estimated contract revenue when they are approved.

10

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

Revenues related to unapproved change orders and claims are included in total estimated contract revenue only to the extent that contract costs related to the claim have been incurred and when it is probable that the claim will result in:

• a bona fide addition to contract value; and

• revenues can be reliably estimated.

These two conditions are satisfied when:

• the contract or other evidence provides a legal basis for the claim or a legal opinion is obtained providing a reasonable basis to support the claim;

• additional costs incurred were caused by unforeseen circumstances and are not the result of deficiencies in the Company’s performance;

• costs associated with the claim are identifiable and reasonable in view of work performed; and

• evidence supporting the claim is objective and verifiable.

	This can lead to a situation where costs are recognized in one period and revenue is recognized when customer agreement is obtained or claim resolution occurs, which can be in subsequent periods. Historical claim recoveries should not be considered indicative of future claim recoveries.
	Claims revenue recognized was nil for the year ended March 31, 2008 (2007 — $14.5 million; 2006 — $12.9 million). Claims revenue of $3.1 million related to prior year claims is included in unbilled revenue and remains uncollected at the end of the year (2007 — $8.4 million).
	The Company’s long-term contracts typically allow its customers to unilaterally reduce or eliminate the scope of the work as contracted without cause. These long-term contracts represent higher risk due to uncertainty of total contract value and estimated costs to complete; therefore, potentially impacting revenue recognition in future periods.
	The asset entitled “unbilled revenue” represents revenue recognized in advance of amounts invoiced. The liability entitled “billings in excess of costs incurred and estimated earnings on uncompleted contracts” represents amounts invoiced in excess of revenue recognized.
d)	Cash and cash equivalents
	Cash and cash equivalents include cash on hand, bank balances net of outstanding cheques, and short-term investments with maturities of three months or less when purchased.
e)	Allowance for doubtful accounts
	The Company evaluates the probability of collection of accounts receivable and records an allowance for doubtful accounts, which reduces accounts receivable to the amount management reasonably believes will be collected. In determining the amount of the allowance, the following factors are considered: the length of time the receivable has been outstanding, specific knowledge of each customer’s financial condition, and historical experience.
f)	Inventory
	Inventory is carried at the lower of weighted average cost and replacement cost, and consists primarily of project materials.

11

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

g)	Other assets
	Other assets consist of tires and spare component parts, and are stated at the lower of weighted average cost or replacement cost. Other assets are charged to earnings when they are put into use. A write-down of other assets to reduce other assets to the lower of weighted average cost or replacement cost of $1,845 (2007 — $695) is included in equipment costs for the year ended March 31, 2008.
h)	Plant and equipment
	Plant and equipment are recorded at cost. Major components of heavy construction equipment in use such as engines and transmissions are recorded separately. Equipment under capital lease is recorded at the present value of minimum lease payments at the inception of the lease. Depreciation is not recorded until an asset is available for use. Depreciation for each category is calculated based on the cost, net of the estimated residual value, over the estimated useful life of the assets on the following bases and annual rates:

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

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

12

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

	impairment test for goodwill from December 31 to October 1 of each year. This change in accounting policy was applied on a retrospective basis and had no impact on the consolidated financial statements.
j)	Intangible assets
	Intangible assets include:

• customer contracts in process and related relationships, which are being amortized based on the net present value of the estimated period cash flows over the remaining lives of the related contracts and relationships;

• trade names, which are being amortized on a straight-line basis over their estimated useful life of 10 years;

• non-competition agreements, which are being amortized on a straight-line basis between the three and five-year terms of the respective agreements;

• financing costs related to the revolving credit facility are amortized on a straight-line basis over the term of the agreement; and

• employee arrangements, which are being amortized on a straight-line basis over the three-year term of the arrangements.

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

• management’s commitment to a plan to sell the assets;

• the assets are available for immediate sale in their present condition;

• an active program to locate buyers and other actions to sell the assets have been initiated;

• the sale of the assets is probable and their transfer is expected to qualify for recognition as a completed sale within one year;

• the assets are being actively marketed at reasonable prices in relation to their fair value; and

• it is unlikely that significant changes will be made to the plan to sell the assets or that the plan will be withdrawn.

Assets to be disposed of by sale are reported at the lower of their carrying amount or fair value less costs to sell and are included in current assets. These assets are not depreciated.

13

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

l)	Foreign currency translation
	The functional currency of the Company is Canadian dollars. Transactions denominated in foreign currencies are recorded at the rate of exchange on the transaction date. Monetary assets and liabilities, including long-term debt denominated in U.S. dollars, are translated into Canadian dollars at the rate of exchange prevailing at the balance sheet date.
m)	Derivative financial instruments
	The Company uses derivative financial instruments to manage financial risks from fluctuations in exchange rates and interest rates. These instruments include cross-currency and interest rate swap agreements as well as embedded price escalation features in revenue and supplier contracts. All such instruments are only used for risk management purposes. The Company does not hold or issue derivative financial instruments for trading or speculative purposes. Derivative financial instruments are subject to standard credit terms and conditions, financial controls, management and risk monitoring procedures. These derivative financial instruments are not designated as hedges for accounting purposes and are recorded at fair value with realized and unrealized gains and losses recognized in the Consolidated Statement of Operations, Comprehensive Income (Loss) and Deficit.
n)	Income taxes
	The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, future income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Future income tax assets and liabilities are measured using enacted or substantively enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on future income tax assets and liabilities from a change in tax rates is recognized in income in the period of enactment or substantive enactment. The Company accrues interest and penalties for uncertain tax positions in the period in which these uncertainties are identified. A valuation allowance is recorded against any future income tax asset if it is more likely than not that the asset will not be realized.
o)	Stock—based compensation plan
	The Company accounts for all stock-based compensation payments that are settled by the issuance of equity instruments in accordance with a fair value based method of accounting. Under this fair value based method, compensation cost is measured using the Black-Scholes model at the grant date and is expensed on a straight-line basis over the award’s vesting period, with a corresponding increase to contributed surplus. Upon exercise of a stock option, share capital is recorded at the sum of proceeds received and the related amount of contributed surplus.
	The Company has a Director’s Deferred Stock Unit (“DDSU”) plan, which is described in note 28. The measurement of the liability and compensation costs for these awards is based on the intrinsic value of the award and is recorded as a charge to operating income over the vesting period of the award. Subsequent changes in the Company’s payment obligation after vesting of the award and prior to the settlement date are recorded as a charge to operating income in the period such changes occur.
p)	Net income (loss) per share
	Basic net income (loss) per share is computed by dividing net earnings (loss) available to common shareholders by the weighted average number of shares outstanding during the year (see note 18(d)). Diluted per share amounts are calculated using the treasury stock and if-converted methods. The treasury stock method increases the diluted weighted average shares outstanding to include additional shares from the assumed exercise of stock options, if dilutive. The number of additional shares is

14

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

calculated by assuming outstanding in-the-money stock options were exercised and the proceeds from such exercises, including any unamortized stock-based compensation cost, were used to acquire shares of common stock at the average market price during the year. The if-converted method assumes the conversion of convertible securities at the later of the beginning of the reported period or issue date, if dilutive.

q)

Recently adopted Canadian accounting pronouncements

i) Financial instruments — recognition and measurement

Effective April 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants (“CICA”) Handbook Section 3855, “Financial Instruments — Recognition and Measurement”, and Handbook Section 3865, “Hedges”. These standards have been applied retrospectively without restatement as discussed below and, accordingly, comparative amounts for prior periods have not been restated.

CICA Handbook Sections 3855 and 3865 provide guidance on when a financial asset, financial liability or non-financial derivative is to be recognized on the balance sheet of the Company and on what basis these assets, liabilities and derivatives should be valued, including hedging relationships. Under the standards:

• Financial assets are classified as loans and receivables, held-to-maturity, held-for-trading or available-for-sale. Loans and receivables are initially recorded at fair value and subsequent to initial recognition are accounted for at amortized cost using the effective interest method. Held-to-maturity classification is restricted to fixed maturity instruments that the Company intends and is able to hold to maturity and is accounted for on initial recognition at fair value and subsequent to initial recognition at amortized cost using the effective interest method. Held-for-trading instruments are recorded at fair value with changes in fair value reported in net income. The remaining financial assets are classified as available-for-sale. These are recorded at fair value with changes in fair value reported in other comprehensive income until the investment is derecognized or impaired at which time the amounts would be recorded in net income. On adoption of the standard, the Company has classified its cash and cash equivalents as held for trading and accounts receivable and unbilled revenue as loans and receivables. The Company did not hold any financial assets that were available-for-sale or held-to-maturity;

• Financial liabilities are classified as either held-for-trading or other financial liabilities. Held-for-trading instruments are recorded at fair value with changes in fair value reported in net income. Other financial liabilities are accounted for on initial recognition at fair value and subsequent to initial recognition at amortized cost using the effective interest method with gains and losses reported in net income in the period that the liability is derecognized. The Company has classified its revolving credit facility, accounts payable, accrued liabilities, and senior notes as other financial liabilities;

• Derivative financial instruments, including non-financial derivatives, are classified as held-for-trading and measured at fair value unless exempted from derivative treatment as a normal purchase or sale. Certain derivatives embedded in other contracts are also measured at fair value.

• Section 3865 specifies circumstances under which hedge accounting is permissible and how hedge accounting is performed. For the periods presented, the Company did not apply hedge accounting.

• The Company elected April 1, 2003 as the transition date for identifying contracts with embedded derivatives. Transaction costs that are directly attributable to the acquisition or issue of financial

15

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

assets or liabilities are accounted for as a part of the respective asset or liability’s carrying value at inception.

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

On April 1, 2007, the Company made the following transitional adjustments to the consolidated balance sheet to adopt the new standards:

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

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

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

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

• The Company determined that the issuer’s early prepayment option included in the senior notes should be bifurcated from the host contract, along with a contingent embedded derivative in the senior notes that provide for accelerated redemption by the holders in certain instances. These embedded derivatives were measured at fair value at the inception of the senior notes and the residual amount of the proceeds was allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of the senior notes is accreted to par value over the term of the notes using the effective interest method and is recognized as interest expense. At transition on April 1, 2007, the Company recorded the fair value of $8,519

16

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

	related to these embedded derivatives and a corresponding decrease in opening deficit of $7,305, net of future income taxes of $1,214. The impact of the bifurcation of these embedded derivatives at issuance of the senior notes resulted in an increase of senior notes of $5,700 and an increase in opening deficit of $3,963, net of income taxes of $1,737 after applying the effective interest method to the premium resulting from the bifurcation of these embedded derivatives on April 1, 2007.
•	The Company determined that a price escalation feature in a revenue construction contract is an embedded derivative that is not closely related to the host contract. The embedded derivative has been measured at fair value and included in derivative financial instruments on the consolidated balance sheet, with changes in the fair value recognized in net income. The Company recorded the fair value of $7,246 related to this embedded derivative on April 1, 2007, with a corresponding increase in opening deficit of $5,181, net of future income taxes of $2,065.
•	The Company identified an additional embedded derivative that is not closely related to the host contract in the fourth quarter of 2008 with respect to price escalation features in a supplier contract. The embedded derivative has been measured at fair value and included in derivative financial instruments on the consolidated balance sheet, with changes in fair value recognized in net income. The Company has amended its original transition adjustment disclosed in the first quarter and recorded the fair value of $2,474 related to this embedded derivative on April 1, 2007, with corresponding increase in opening deficit of $1,769, net of future income taxes of $705.

ii. Financial instruments — disclosure and presentation

Effective April 1, 2007, the Company adopted revised CICA Handbook Section 3861, “Financial Instruments — Disclosure and Presentation”, which replaces CICA Handbook Section 3860, “Financial Instruments — Disclosure and Presentation”, and establishes standards for presentation of financial instruments and non-financial derivatives, and identifies information that should be disclosed. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

iii. Comprehensive income and equity

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

Effective April 1, 2007, the Company adopted CICA Handbook Section 3251 “Equity”, which establishes standards for the presentation of equity and changes in equity during the reporting period. The requirements in this section are in addition to those of Section 1530 and recommend that an enterprise should present separately the following components of equity: retained earnings, accumulated other comprehensive income, the total for retained earnings and accumulated other comprehensive income, contributed surplus, share capital and

17

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

reserves. The adoption of CICA Handbook Section 3251 did not have an impact on the Company’s financial statement presentation in the current period. The Company currently has no accumulated other comprehensive income components.

iv. Accounting changes

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

v. Accounting policy choice for transaction costs

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

r) Recent Canadian accounting pronouncements not yet adopted

i. Capital disclosures

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

ii. Financial instruments — disclosure and presentation

In March 2007, the CICA issued Handbook Section 3862, “Financial Instruments—Disclosures”, which replaces CICA 3861 and provides expanded disclosure requirements that provide additional detail by financial assets and liability categories to enhance financial statement users’ understanding of the significance of financial instruments to an entity’s financial position, performance and cash flows. This standard harmonizes disclosures with International Financial Reporting Standards. The standard

18

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company. Disclosures required by the new standard will be included in the Company’s interim and annual consolidated financial statements commencing April 1, 2008.

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

iii. Inventories

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

iv. Going concern

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

v. Goodwill and intangible assets

In February 2008, the CICA issued Handbook Section 3064, (“CICA 3064”) Goodwill and Intangible Assets. CICA 3064, which replaces Section 3062, Goodwill and Intangible Assets, and Section 3450, Research and Development Costs, establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The provisions relating to the definition and initial recognition of intangible assets, including internally generated intangible assets, are equivalent to the corresponding provisions of International Financial Reporting Standard IAS 38, Intangible Assets.

19

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

This new standard is effective for the Company’s interim and annual consolidated financial statements commencing April 1, 2009. The Company is currently evaluating the impact of this standard.

4.

Acquisition

On May 1, 2007, the Company acquired all of the assets of Active Auger Services 2001 Ltd., a piling company specializing in the design and installation of screw piles in north central Saskatchewan, for total cash consideration and acquisition costs of $1,581. The transaction has been accounted for by the purchase method with the results of operations included in the financial statements from the date of acquisition. The goodwill acquired is deductible for tax purposes. The purchase price allocation is as follows:

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

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

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

5. Accounts receivable

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

20

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

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

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

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

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

7. Prepaid expenses and deposits

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

8.

Asset held for sale

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

21

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

9. Plant and equipment

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

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

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

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

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

22

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

During the year ended March 31, 2008, financing fees totaling $776 paid in connection with an amendment of the revolving credit facility (note 12) were recorded as financing costs. These costs, together with the existing unamortized financing costs, will be amortized on a straight-line basis over the term of the amended revolving credit facility consistent with accounting for the amendment of the revolving credit facility as a modification.

Amortization of intangible assets for the year ended March 31, 2008 was $1,071 (2007 — $582; 2006 — $730).

The estimated amortization expense for future years is as follows:

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

11.	Deferred financing costs
	Deferred financing costs related to the senior notes that were previously presented as a separate asset on the consolidated balance sheet are now included in the carrying value of the senior notes (see notes 3(q)(i) and 16). Transaction costs incurred in connection with the Company’s revolving credit facility of $1,622 were reclassified from deferred financing costs to intangible assets effective April 1, 2007 (notes 3(q)(i) and 10).
	For the year ended March 31, 2007, fees of $275 were paid to the holders of the 83/4% senior notes in connection with an amendment of the indenture governing the 83/4% senior notes (note 16). The amendment has been accounted for as a modification, and the fees paid to the note holders, together with the existing unamortized deferred financing costs, were deferred and amortized on a straight-line basis over the remaining term of the 8 3/4% senior notes.
	During the year ended March 31, 2007, financing fees totaling $1,071 paid in connection with amendment of the revolving credit facility (note 12) were recorded as deferred financing costs. These costs, together with the existing unamortized deferred financing costs, were deferred and amortized over the term of the amended revolving credit facility consistent with accounting for the amendment of the revolving credit facility as a modification.
	In connection with the retirement of the 9% senior secured notes on November 28, 2006, the Company wrote off deferred financing costs of $4,342 (notes 2 and 16) during the year ended March 31, 2007.
	For the year ended March 31, 2006, financing costs of $7,546 were incurred in connection with the issue of the 9% senior secured notes and revolving credit facility and were recorded as deferred financing costs. In addition, financing costs of $321 were incurred in connection with the issue of the NAEPI Series A redeemable preferred shares and expensed in the year ended March 31, 2006.
	On May 19, 2005, the Company repaid its entire indebtedness under a previous revolving credit facility and term loan using the net proceeds from the issue of the 9% senior secured noted and the NAEPI Series B preferred shares. In connection with the repayment of the secured credit facility on May 19, 2006, the

23

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

	Company wrote-off deferred financing costs of $1,774 during the year ended March 31, 2006. Amortization of the deferred financing costs for the year ended March 31, 2007 was $3,436 (2006 — $3,338).
12.	Revolving credit facility
	On June 7, 2007, the Company modified its amended and restated credit agreement to provide for borrowings of up to $125.0 million (previously $55.0 million) under which revolving loans and letters of credit may be issued. Based upon the Company’s current credit rating, prime rate and swing line revolving loans under the agreement will bear interest at the Canadian prime rate plus 0.25% per annum, Canadian bankers’ acceptances have stamping fees equal to 1.75% per annum and letters of credit are subject to a fee of 1.25% per annum. Standby fees are calculated at a rate per annum equal to the applicable pricing margin applied to the amount by which the amount of the outstanding principal owing to each lender under the credit facility for each day is less than the commitment of such lender and accrue daily from the first day to the last day of each fiscal quarter. In each case, the applicable pricing margin depends on our credit rating. Interest rates are increased by 2% per annum in excess of the rate otherwise payable on any amount not paid when due.
	The credit facility is secured by a first priority lien on substantially all the Company’s existing and after-acquired property and contains certain restrictive covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions or to pay dividends or redeem shares of capital stock. The Company is also required to meet certain financial covenants under the new credit agreement. The Company was in compliance with all the covenants under this agreement as at and through out the year ended March 31, 2008.
	As of March 31, 2008, the Company had nil outstanding borrowings under the revolving credit facility and had issued $20.0 million in letters of credit to support performance guarantees associated with a customer contract. The Company’s unused borrowing availability under the facility was $105.0 million at March 31, 2008. The credit facility matures June 7, 2010. During the twelve months ended March 31, 2008, financing fees of $776, were incurred in connection with the modifications to the amended and restated credit agreement and were recorded as an intangible asset.
	As of March 31, 2007, the Company had outstanding borrowings of $20.5 million (2006 — $nil) under the revolving credit facility and had issued $25.0 million in letters of credit to support performance guarantees associated with customer contracts. The Company’s borrowing availability under the facility was $9.5 million at March 31, 2007.
13.	Deferred lease inducements
	Lease inducements applicable to lease contracts are deferred and amortized as a reduction of general and administrative costs on a straight-line basis over the lease term, which includes the initial lease term and renewal periods only where renewal is determined to be reasonably assured. During the year ended March 31, 2008, the Company received inducements from a lessor in the form of leasehold improvements to an office facility of $1,045. Amortization of deferred lease inducements of $104 was recorded for the year ended March 31, 2008.
14.	Accrued liabilities

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

24

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

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

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

16. Senior notes

	March 31,			March 31,
	2008			2007
83/4% senior unsecured notes due 2011 ($US)	$	200,000		$	200,000
Unrealized foreign exchange		5,574			30,580
Unamortized financing costs and premiums, net		(3,059	)		—
Fair value of embedded prepayment and early redemption options (note 20(a))		(4,270	)		—
	$	198,245		$	230,580

The 8³/4% senior notes were issued on November 26, 2003 in the amount of US$200 million (Canadian $263 million). These notes mature on December 1, 2011 with interest payable semi-annually on June 1 and December 1 of each year.

The 8³/4% senior notes are unsecured senior obligations and rank equally with all other existing and future unsecured senior debt and senior to any subordinated debt that may be issued by the Company or any of its subsidiaries. The notes are effectively subordinated to all secured debt to the extent of the outstanding amount of such debt.

The 8³/4% senior notes are redeemable at the option of the Company, in whole or in part, at any time on or after: December 1, 2007 at 104.375% of the principal amount; December 1, 2008 at 102.188% of the principal amount; December 1, 2009 at 100.00% of the principal amount; plus, in each case, interest accrued to the redemption date.

If a change of control occurs, the Company will be required to offer to purchase all or a portion of each holder’s 8³/4% senior notes, at a purchase price in cash equal to 101% of the principal amount of the notes offered for repurchase plus accrued interest to the date of purchase.

As at March 31, 2008, the Company’s effective weighted average interest rate on its 8 ³/4 senior notes, including the effect of financing costs and premiums, was approximately 8.94%.

25

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

	On December 21, 2006, the indenture governing the 83/4% senior notes was amended to remove the requirement to provide reconciliation from Canadian GAAP to United States GAAP in the Company’s interim consolidated financial statements.
	The Company issued 9% senior secured notes on May 19, 2005 in the amount of US$60.481 million (Canadian $76.345 million). In connection with the IPO (note 2), the Company repurchased the 9% senior secured notes for $74,748 plus accrued interest of $3,027 on November 28, 2006. These notes were redeemed at a premium of 109.26% on November 28, 2006 resulting in a loss on extinguishment of $6,338. The loss on settlement, along with the write-off of deferred financing fees of $4,342 and third party transaction costs of $255, was recorded as a loss on extinguishment of debt in the consolidated statement of operations for the year ended March 31, 2007.
17.	Income taxes
	Income tax provision (recovery) differs from the amount that would be computed by applying the Federal and provincial statutory income tax rate to income from continuing operations. The reasons for the differences are as follows:

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

Classified as:

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

26

NORTH AMERICAN ENERGY PARTNERS INC.

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

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

Classified as:

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

The Company and its subsidiaries file income tax returns in the Canadian federal jurisdiction, and several provincial jurisdictions. Taxation years ending 2004 through 2008 in all jurisdictions remain open for potential examination by the tax authorities.

The Company has accrued no amounts as of April 1, 2007 and March 31, 2008, for uncertain tax positions. Additionally, for the year ended March 31, 2008, the Company has not recognized any amounts in respect of potential interest and penalties associated with uncertain tax positions.

27

NORTH AMERICAN ENERGY PARTNERS INC.

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

At March 31, 2008, the Company has non-capital losses for income tax purposes of approximately $68,663 which expire as follows:

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

18. Shares

a) Redeemable preferred shares

i. NACG Preferred Corp. preferred shares

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

NACG Preferred Corp. was authorized to issue an unlimited number of Series A preferred shares. The NACG Preferred Corp. Series A preferred shares accrued dividends at a rate of $80.00 per share annually if earnings before interest, taxes, depreciation and amortization (“EBITDA”) for NAEPI was in excess of $75.0 million for the year. The dividends were payable in cash, additional NACG Preferred Corp. Series A preferred shares, or any combination of cash and shares as determined by the Company. The number of shares issuable was .001 of a whole NACG Preferred Corp. Series A preferred share for each $1.00 of dividend declared.

The NACG Preferred Corp. Series A preferred shares, which were issued in connection with the acquisition described in note 1 and were recorded at their guaranteed redemption amount, were redeemable at any time at the option of the Company, and were required to be redeemed on or before November 26, 2012. On November 28, 2006, the Company acquired the NACG Preferred Corp. Series A preferred shares for a promissory note in the amount of $27,000 and accrued dividends of $1,400 at that time were forfeited resulting in a gain on settlement of $9,400. The promissory note was subsequently repaid with the proceeds from the IPO as described in note 2.

ii. NAEPI Series A preferred shares

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

28

NORTH AMERICAN ENERGY PARTNERS INC.

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

NAEPI was authorized to issue an unlimited number of Series A preferred shares. The NAEPI Series A preferred shares were non-voting and were not entitled to any dividends. The NAEPI Series A preferred shares were mandatorily redeemable at $1,000 per share on the earlier of (1) December 31, 2011 and (2) an Accelerated Redemption Event, specifically (i) the occurrence of a change of control, or (ii) if there is an initial public offering of common shares, the later of (a) the consummation of the initial public offering or (b) the date on which all of the Company’s 8 ³/4% senior notes and the Company’s 9% senior secured notes are no longer outstanding. NAEPI had the right to redeem the NAEPI Series A preferred shares, in whole or in part, at $1,000 per share at any time.

The NAEPI Series A preferred shares were issued to one of the counterparties to NAEPI’s swap agreements on May 19, 2005 in connection with obtaining a new revolving credit facility. These shares were not entitled to dividends. The NAEPI Series A preferred shares were initially recorded at their fair value on the date of issue, which was estimated to be $321 based on the present value of the required cash flows using the discount rate implicit at inception. Each reporting period, the accretion of the carrying value to the present value of the redemption amount at each balance sheet date was recorded as interest expense. For the year ended March 31, 2007, the Company recognized $625 of accretion as interest expense (2006 — $54).

On October 6, 2006, the Board of Directors approved the purchase of the NAEPI Series A preferred shares for $1,000 effective with the consummation of the IPO (note 2), and these shares were purchased on November 28, 2006 pursuant to an affiliate purchase right under the terms of the NAEPI Series A preferred shares. Accordingly, the Company recorded the additional accretion charge and the extinguishment of the obligation in the year ended March 31, 2007.

iii. NAEPI Series B preferred shares

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

NAEPI was authorized to issue an unlimited number of Series B preferred shares. The NAEPI Series B preferred shares were non-voting and were entitled to cumulative dividends at an annual rate of 15% of the issue price of each share. No dividends were payable on NAEPI common shares or other classes of preferred shares (defined as Junior Shares) unless all cumulative dividends had been paid on the NAEPI Series B preferred shares and NAEPI declared a NAEPI Series B preferred share dividend equal to 25% of the Junior Share dividend (except for dividends paid as part of employee and officer arrangements, intercompany administrative charges of up to $1 million annually and tax sharing arrangements). The payment of dividends and the redemption of the NAEPI Series B preferred shares were prohibited by the Company’s revolving credit facility agreement. The payment of dividends and the redemption of the NAEPI Series B preferred shares was also restricted by the indenture agreements governing the Company’s 9% senior secured notes and 8³/4% senior notes.

29

NORTH AMERICAN ENERGY PARTNERS INC.

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

7,500 NAEPI Series B preferred shares were issued to non-employee shareholders of the Company for cash proceeds of $7.5 million on May 19, 2005. The NAEPI Series B preferred shares were initially issued to certain non-employee shareholders with the agreement that an offer to purchase these NAEPI Series B preferred shares would also be extended to other shareholders of the Company on a pro rata basis to their interest in the common shares of the Company.

On June 15, 2005, the NAEPI Series B preferred shares were split 10-for-1.

On August 31, 2005, NAEPI issued 8,218 NAEPI Series B preferred shares for cash consideration of $851 to certain shareholders of the Company as a result of this offer. On November 1, 2005, NAEPI repurchased and cancelled 8,218 of the NAEPI Series B preferred shares held by the original non-employee shareholders for cash consideration of $851.

On October 6, 2005, an additional 244 NAEPI Series B preferred shares were issued for cash consideration of $25.

Initially, the redemption price of the NAEPI Series B preferred shares was an amount equal to the greatest of (i) two times the issue price($1,000), less the amount, if any, of dividends previously paid in cash on the NAEPI Series B preferred shares; (ii) an amount, not to exceed $100 million which, after taking into account any dividends previously paid in cash on such NAEPI Series B preferred shares, provides the holder with a 40% rate of return, compounded annually, on the issue price from the date of issue; and (iii) an amount, not to exceed $100 million, which is equal to 25% of the arm’s length fair market value of NAEPI’s common shares without taking into account the NAEPI Series B preferred shares.

On March 30, 2006, the terms of the NAEPI Series B preferred shares were amended to eliminate option (iii) from the calculation of the redemption price of the shares.

Prior to the amendment to the terms of the NAEPI Series B preferred shares on March 30, 2006, the NAEPI Series B preferred shares were considered mandatorily redeemable and the Company was required to measure the NAEPI Series B preferred shares at the amount of cash that would be paid under the conditions specified in the contract if settlement occurred at each reporting date prior to the amendment. At March 30, 2006, management estimated the redemption amount to be $42,193. As a result, the Company has recognized the increase of $34,668 in the carrying value as an increase in interest expense for the year ended March 31, 2006.

Concurrent with the amendment to the NAEPI Series B preferred shares, NACG entered into a Put/Call Agreement with the holders of the NAEPI Series B preferred shares. The Put/Call Agreement granted to each holder of the NAEPI Series B preferred shares the right (the “Put/Call Right”) to require NACG to exchange each of the holder’s NAEPI Series B preferred shares for 100 common shares (on a post-split basis — note 18(b)) of NACG. The Put/Call Right could only be exercised upon delivery by NACG of an “Event Notice”, being either: (i) a redemption or purchase call for the redemption or purchase of the NAEPI Series B preferred shares in connection with (A) a redemption on December 31, 2011, or (B) an Accelerated Redemption Event (as defined in note 18(a)(ii)); or (ii) a notice in connection with a Liquidation Event (defined as a liquidation, winding-up or dissolution of NAEPI, whether voluntary or involuntary).

The Put/Call Agreement also granted NACG the right to require the holders of the NAEPI Series B preferred shares to exchange each of their NAEPI Series B preferred shares for 100 common shares (on a post-split basis — note 18(b)) of NACG upon delivery of a call notice to shareholders within five business days of an Event Notice.

As a result of the March 30, 2006 amendment to the terms of the NAEPI Series B preferred shares and the concurrent execution of the Put/Call Agreement, the Company accounted for the amendment as a related

30

NORTH AMERICAN ENERGY PARTNERS INC.

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

party transaction at carrying amount. No value was ascribed to the equity classified Put/Call Right as it was a related party transaction. The NAEPI Series B preferred shares were being accreted from their carrying value of $42.2 million on the date of amendment to their redemption value of $69.6 million on December 31, 2011 through a charge to interest expense using the effective interest method over the period to December 31, 2011. For the year ended March 31, 2007, the Company recognized $2,489 of interest expense for this accretion.

On October 6, 2006, the Board of Directors approved the exercise of the call option to acquire all of the issued and outstanding NAEPI Series B preferred shares in exchange for 7,524,400 common shares of NACG and the option was exercised on November 28, 2006. The Company recorded the exchange by transferring the carrying value of the Series B preferred shares on the exercise date of $44,682 to common shares.

b)	Common shares
	On November 3, 2006, the Board of Directors and common shareholders approved a 20-for-1 share split of NACG’s voting and non-voting common shares. All information relating to the exchange of the NAEPI Series B preferred shares (note 18(a)), the issued and outstanding common shares (below), basic and diluted net income (loss) per share data (note 18(d)), stock options (note 28), and basic and diluted net income (loss) per share data under U.S. GAAP (note 30) have been adjusted retroactively to reflect the impact of the share split in these financial statements. The share split was effective November 3, 2006.
	Authorized:

Unlimited number of common voting shares

Unlimited number of common non-voting shares

Issued and outstanding:

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

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

31

NORTH AMERICAN ENERGY PARTNERS INC.

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

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

c) Contributed surplus

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

d) Net income (loss) per share

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

32

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

For the year ended March 31, 2008, weighted average stock options of 283,674 (March 31, 2007 — 98,767) were excluded from the calculation of diluted net income per share as the options’ average exercise price was greater than the average market price of the common shares for the year.

For the year ending March 31, 2006, the effect of outstanding stock options and convertible securities on net loss per share was anti-dilutive. As such, the effect of outstanding stock options and convertible securities used to calculate the diluted net loss per share has not been disclosed for this year.

19. Interest expense

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

20. Derivative financial instruments

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

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

33

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

b) Fair value of derivative financial instruments

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

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

21. Other information

a) Supplemental cash flow information

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

34

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

b) Net change in non-cash working capital

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

22. Segmented information

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

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

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

35

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

b) Results by business segment:

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

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

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

36

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

c) Reconciliations

i. Income (loss) before income taxes

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

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

ii. Total assets

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

The Company’s goodwill is assigned to the Mining and Site Preparation, Piling and Pipeline segments in the amounts of $125,447, $41,872, and $32,753, respectively.

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

iii. Depreciation of plant and equipment

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

37

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

iv. Capital expenditures for plant and equipment

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

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

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

The revenue by major customer was earned in Heavy Construction and Mining, Piling and Pipeline segments.

23.	Guarantee
	At March 31, 2008, in connection with a heavy equipment financing agreement, the Company has guaranteed $18.5 million of debt owed to the equipment manufacturer by a third party finance company. The Company’s guarantee of this indebtedness will expire when the equipment is commissioned, which is expected to be November 1, 2008. The Company has determined that the fair value of this financial instrument at inception and at March 31, 2008 was not significant.
24.	Related Party Transactions
	The Company may receive consulting and advisory services provided by the Sponsors (principals or employees of such Sponsors are directors of the Company) with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters, and no fee is charged for these consulting and advisory services.
	In order for the Sponsors to provide such advice and consulting we provide reports, financial data and other information. This permits them to consult with and advise our management on matters relating to our operations, company affairs and finances. In addition this permits them to visit and inspect any of our

38

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

	properties and facilities. The transactions are in the normal course of operations and are measured at the exchange amount of consideration established and agreed to by the related parties.
	Prior to the reorganization and IPO described in Note 2, the Company had a consulting and advisory services agreement with the Sponsors, under which the Company and certain of its subsidiaries received consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. An advisory fee of $400 for the year ended March 31, 2007 (2006 - $400) was paid for these services and was recorded as part of general and administrative costs in the consolidated statement of operations.
	On November 28, 2006, upon closing of the IPO described in Note 2, the consulting and advisory services agreement was cancelled. The consideration paid by the Company on the closing of the offering to cancel the agreement was $2,000, which was recorded as part of general and administrative expense during the year ended March 31, 2007. In addition, the Sponsors also received a fee of $854, 0.5% of the aggregate gross proceeds to the Company from the IPO, which was recorded as a share issue cost.
	Pursuant to several office lease agreements, for the year ended March 31, 2007 the Company paid $572 (2006 — $836) to a company owned, indirectly and in part, by one of the directors. Effective November 28, 2006 the director resigned from the board. Accordingly, the lease agreement is no longer considered to be with a related party.
	During the year ended March 31, 2006, 75,000 NAEPI Series B preferred shares (on a post-split basis — note 18(a)(iii)) were issued to the above Sponsor group in exchange for cash of $7.5 million (note 18(a)).
	All related party transactions described above were measured at the exchange amount, being the consideration established and agreed to by the related parties.
25.	Financial instruments and risk management

a)	Fair value of financial instruments
	The fair values of the Company’s cash and cash equivalents, accounts receivable, unbilled revenue, accounts payable and accrued liabilities approximate their carrying amounts due to the relatively short periods to maturity for the instruments.
	The fair value of amounts due under the revolving credit facility and capital lease obligations are based on management estimates which are determined by discounting cash flows required under the instruments at the interest rate currently estimated to be available for loans with similar terms. Based on these estimates, the fair value of amounts due under the revolving credit facility and the Company’s capital lease obligations as at March 31, 2008 and March 31, 2007 are not significantly different than their carrying values. The fair value of the 83/4% notes, based upon their year end trading value as at March 31, 2008, is $209,178 (March 31, 2007 — $239,803) compared to their carrying value of $198,245 (March 31, 2007 — $230,580).
	The methods used to determine fair value of embedded derivatives are described in note 3(q)(i) and the method used to determine fair value of cross-currency and interest rate swaps is disclosed in note 25(b)(i).

39

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

b) Risk management

The Company is exposed to market risks related to interest rate and foreign currency fluctuations. To mitigate these risks, the Company uses derivative financial instruments such as foreign currency and interest rate swap contracts.

i. Foreign currency risk and derivative financial instruments

The Company has 8³/4% senior notes denominated in U.S. dollars in the amount of US$200 million. In order to reduce its exposure to changes in the U.S. to Canadian dollar exchange rate, the Company entered into a cross-currency swap agreement to manage this foreign currency exposure for both the principal balance due on December 1, 2011 as well as the semi-annual interest payments through the whole period beginning from the issue date to the maturity date. In conjunction with the cross-currency swap agreement, the Company also entered into a U.S. dollar interest rate swap and a Canadian dollar interest rate swap with the net effect of economically converting the 8.75% rate payable on the 8³/4% senior notes into a fixed rate of 9.765% for the duration that the 8³/4% senior notes are outstanding. On May 19, 2005 in connection with the Company’s new revolving credit facility at that time, this fixed rate was increased to 9.889%. These derivative financial instruments were not designated as a hedge for accounting purposes. At March 31, 2008, the Company’s derivative financial instruments are carried on the consolidated balance sheets at their fair value of $97,739 (March 31, 2007 - $60,863). The fair values of the Company’s cross-currency and interest rate swap agreements are based on values quoted by the counterparties to the agreements.

At March 31, 2008, the notional principal amount of the cross-currency swap was US$200 million. The notional principal amounts of the interest rate swaps were US$200 million and Canadian $263 million.

The Company is also exposed to foreign currency risk on U.S. dollar operating lease commitments as the Company has not entered into forward foreign exchange contracts or similar instruments to manage this foreign currency exposure.

ii. Interest rate risk

The Company is exposed to interest rate risk on the revolving credit facility and its capital lease obligations. The Company does not use derivative financial instruments to reduce its exposure to these risks.

iii. Credit risk

The Company is exposed to credit risk in the event of non-payment by customers in connection with its accounts receivable and unbilled revenue. Reflective of its normal business, a majority of the Company’s accounts receivable are due from large companies operating in the resource sector. The Company regularly monitors the activities and balances in these accounts to manage its credit risk and to assess the need for an allowance for any doubtful accounts.

At March 31, 2008 and March 31, 2007, the following customers represented 10% or more of accounts receivable and unbilled revenue:

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

40

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

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

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

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

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

41

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

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

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

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

At March 31, 2008, the weighted average remaining contractual life of outstanding options is 7.6 years (March 31, 2007 — 7.7 years). The Company recorded $1,801 of compensation expense related to stock options in the year ended March 31, 2008 (2007 - $2,101; 2006 — $923) with such amount being credited to contributed surplus. At March 31, 2008 the total compensation costs related to nonvested awards not yet recognized was $5,553 and these costs are expected to be recognized over a weighted average period of 3.0 years.

The fair value of each option granted by the Company was estimated on the grant date using the Black-Scholes option-pricing model with the following assumptions:

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

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

As a result of the filing of a preliminary prospectus on July 21, 2006 with the various Canadian and U.S. securities commissions in preparation for the public sale of common shares, the Company is no longer eligible to use the minimum value method for measuring stock-based compensation. Accordingly, the Company considered the effect of expected volatility in its assumptions using the Black-Scholes option pricing model for options granted after this date. The Company determined its expected volatility based on a

42

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

statistical analysis of historical volatility for a peer group of companies, which was prepared by an independent valuation firm.

During the year ended March 31, 2007, the Company offered to accelerate the vesting of 222,080 options held by certain members of its Board of Directors, providing for the options to become immediately exercisable on the condition that such options were exercised by September 30, 2006. On July 31, 2006, 27,760 options were exercised pursuant to this offer resulting in additional compensation cost of $24 for the year ended March 31, 2007. The vesting period remained unchanged for stock options held by Directors who did not accept the Company’s offer.

On October 6, 2006, the Company approved the Amended and Restated 2004 Share Option Plan. The amended plan was approved by the shareholders on November 3, 2006 and became effective on the closing of the IPO described in note 2. Option grants under the amended option plan may be made to directors, officers, employees and service providers selected by the Compensation Committee of the Company’s Board of Directors. The Compensation Committee may provide that any options granted will vest immediately or in increments over a period of time. Options to be granted under the amended option plan will have an exercise price of not less than the volume weighted average trading price of the common shares on the Toronto Stock Exchange or the New York Stock Exchange at the time of grant. The amended option plan provides that up to 10% of the Company’s issued and outstanding common shares from time to time may be reserved for issue or issued from treasury under the amended option plan.

In the event of certain change of control events as defined in the amended option plan, all outstanding options will become immediately vested and exercisable. The amended option plan provides that the Company’s Board of Directors can make certain specified amendments to the option plan subject to receipt of shareholder and regulatory approval, and further authorizes the Board of Directors to make all other amendments to the plan, subject only to regulatory approval but without shareholder approval. The amendments the Board of Directors may make without shareholder approval include amendments of a housekeeping nature, changes to the vesting provisions of an option or the option plan, changes to the termination provisions of an option or the option plan which do not entail an extension beyond the original expiry date, the discontinuance of the option plan, and the addition of provisions relating to phantom share units, such as restricted share units and deferred share units which result in participants receiving cash payments, and the terms governing such features.

The amended option plan provides that each option includes a cashless exercise alternative which provides a holder of an option with the right to elect to receive cash in lieu of purchasing the number of shares under the option. Notwithstanding such right, the amended option plan provides that the Company may elect, at its sole discretion, to net settle the option in common stock.

All outstanding options granted under the 2004 Stock Option Plan remained outstanding after the amended and restated plan became effective.

Director’s deferred stock unit plan:

On November 27, 2007, the Company approved a Directors’ Deferred Stock Unit (“DDSU”) Plan, which became effective January 1, 2008. Under the DDSU Plan, non-employee or officer directors of the Company shall receive 50% of their annual fixed remuneration (which is included in general and administrative expenses in the consolidated statement of operations) in the form of DDSUs and may elect to receive all or a part of their annual fixed remuneration in excess of 50% in the form of DDSUs. The DDSUs vest immediately upon grant and are redeemable, in cash, equal to the difference between the market value of the Company’s common stock at maturity and the market value of the Company’s common stock on the grant date (maturity occurs when the director resigns or retires). DDSUs must be redeemed within 60 days

43

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

	following maturity. Directors, who are not US taxpayers, may elect to defer the maturity date until a date no later than December 1st of the calendar year following the year in which the actual maturity date occurred. As at March 31, 2008, an expense and liability of $190 was recorded relating to 11,807 outstanding units that were granted during the year.
29.	Comparative figures
	The comparative consolidated financial statements have been reclassified from statements previously presented to conform to the presentation of the current year consolidated financial statements.
30.	United States generally accepted accounting principles
	These consolidated financial statements have been prepared in accordance with Canadian GAAP, which differs in certain respects from U.S. GAAP. If U.S. GAAP were employed, the Company’s net income (loss) would be adjusted as follows:

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

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

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

44

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

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

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

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

45

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

The areas of material difference between Canadian and U.S. GAAP and their impact on the Company’s consolidated financial statements are described below:

a)	Capitalization of interest
	U.S. GAAP requires capitalization of interest costs as part of the historical cost of acquiring certain qualifying assets that require a period of time to prepare for their intended use. This is not required under Canadian GAAP. The capitalized amount is subject to depreciation in accordance with the Company’s policies when the asset is placed into service.
b)	Financing costs, discounts and premiums

Prior to April 1, 2007, transaction costs incurred in connection with the Company’s senior notes were recorded as a deferred asset under Canadian GAAP and these deferred financing costs were being amortized on a straight-line basis over the term of the debt. For US GAAP purposes, these deferred financing costs are being amortized over the term of the related debt using the effective interest method in accordance with Accounting Principles Board Opinion No. 21 (“APB 21”).

Effective April 1, 2007, the Company adopted CICA Handbook Section 3855, “Financial Instruments — Recognition and Measurement” on a retrospective basis without restatement as described in note 3(q)(i). Although Section 3855 also requires the use of the effective interest method to account for the amortization of finance costs, the requirement to bifurcate the issuer’s early prepayment option on issuance of the debt (which is not required under US GAAP) resulted in an additional premium that is being amortized over the term of the debt under Canadian GAAP. In addition, foreign denominated transaction costs, discounts and premiums are considered as part of the carrying value of the related financial liability under Canadian GAAP and are subject to foreign currency gains or losses resulting from periodic translation procedures as they are treated as a monetary item under Canadian GAAP. Under US GAAP, foreign denominated transaction costs are considered non-monetary and are not subject to foreign currency gains and losses resulting from periodic translation procedures.

In connection with the adoption of Section 3855, transaction costs incurred in connection with the Company’s revolving credit facility of $1,622 were reclassified from deferred financing costs to intangible assets on April 1, 2007 under Canadian GAAP and these costs continue to be amortized on a straight-line basis over the term of the facility. Under U.S. GAAP, the Company continues to amortize these transaction costs over the stated term of the related debt using the effective interest method under APB 21.

46

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

c)	Stock-based compensation
	Up until April 1, 2006, the Company followed the provisions of Statement of Financial Accounting Standards No. 123, “Stock-Based Compensation” for U.S. GAAP purposes. As the Company uses the fair value method of accounting for all stock-based compensation payments under Canadian GAAP there were no differences between Canadian and U.S. GAAP prior to April 1, 2006. On April 1, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment” (“SFAS 123R”). As the Company used the minimum value method for purposes of complying with Statement of Financial Accounting Standards No. 123, it was required to adopt SFAS 123(R) prospectively. Under Canadian GAAP the Company was permitted to exclude volatility from the determination of the fair value of stock options granted until the filing of it’s initial registration statement relating to the initial public offering of voting shares on July 21, 2006. As a result, for options issued between April 1, 2006 and July 21, 2006, there is a difference between Canadian and U.S. GAAP relating to the determination of the fair value of options granted.
d)	Derivative financial instruments
	Effective April 1, 2007, the Company adopted the CICA Handbook Section 3855, “Financial Instruments — Recognition and Measurement”, and Handbook Section 3865, “Hedges”.
	Under Canadian GAAP, the Company determined that the issuer’s early prepayment option included in the senior notes should be bifurcated from the host contract, along with a contingent embedded derivative in the senior notes that provide for accelerated redemption by the holders in certain instances. These embedded derivatives were measured at fair value at the inception of the senior notes and the residual amount of the proceeds was allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of the senior notes is accreted to par value over the term of the notes using the effective interest method and is recognized as interest expense as discussed in b) above. Prior to April 1, 2007 under Canadian GAAP, separate accounting of embedded derivatives from the host contract was not permitted by EIC-117.

47

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

	Under U.S. GAAP, Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”) establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts and debt instruments) be recorded in the balance sheet as either an asset or liability measured at its fair value. The contingent embedded derivative in the senior notes that provide for accelerated redemption by the holders in certain instances met the criteria for bifurcation from the debt contract and separate measurement at fair value. The embedded derivatives have been measured at fair value and changes in fair value recorded in net income for all periods presented. The issuer’s early prepayment option included in the senior notes does not meet the criteria as an embedded derivative under SFAS 133 and was not bifurcated from the host contract and measured at fair value resulting in a U.S. GAAP difference for all periods presented.
	On adoption of CICA Handbook Section 3855, “Financial Instruments — Recognition and Measurement”, the Company reviewed the accounting treatment of a number of outstanding contracts and determined that a price escalation feature in a revenue construction contract and a supplier contract entered into prior to April 1, 2007 contained embedded derivatives that are not closely related to the host contract under both Canadian and U.S. GAAP. The Company recorded the fair value of these embedded derivatives on April 1, 2007 of $9,720, with a corresponding increase in opening deficit of $6,950, net of future income taxes of $2,770 for Canadian GAAP purposes. The Company has restated its U.S. GAAP reconciliation to account for these embedded derivatives since inception of the related contracts resulting in a reduction of shareholders’ equity under U.S. GAAP at April 1, 2005 of $6,797, net of deferred income taxes of nil. This also resulted in an increase in net loss of $3,449, net of deferred income taxes of nil for the year ended March 31, 2006 and an increase in net income of $3,296 for the year ended March 31, 2007 including a deferred income tax recovery of $2,770.
e)	NAEPI Series B Preferred Shares
	Prior to the modification of the terms of the NAEPI Series B preferred shares March 30, 2006, there were no differences between Canadian GAAP and U.S. GAAP related to the NAEPI Series B preferred shares. As a result of the modification of terms of NAEPI’s Series B preferred shares , under Canadian GAAP, NACG continued to classify the NAEPI Series B preferred shares as a liability and was accreting the carrying amount of $42.2 million on the amendment date (March 30, 2006) to their December 31, 2011 redemption value of $69.6 million using the effective interest method. Under U.S. GAAP, NACG recognized the fair value of the amended NAEPI Series B preferred shares as minority interest as such amount was recognized as temporary equity in the accounts of NAEPI in accordance with EITF Topic D-98 and recognized a charge of $3.7 million to retained earnings for the difference between the fair value and the carrying amount of the Series B preferred shares on the amendment date. Under U.S. GAAP, NACG was accreting the initial fair value of the amended NAEPI Series B preferred shares of $45.9 million recorded on their amendment date (March 30, 2006) to the December 31, 2011 redemption value of $69.6 million using the effective interest method, which

48

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

	was consistent with the treatment of the NAEPI Series B preferred shares as temporary equity in the financial statements of NAEPI. The accretion charge was recognized by NACG as a charge to minority interest (as opposed to retained earnings in the accounts of NAEPI) under US GAAP and interest expense in NACG’s financial statements under Canadian GAAP.
	On November 28, 2006, NACG exercised a call option to acquire all of the issued and outstanding NAEPI Series B preferred shares in exchange for 7,524,400 common shares of NACG. For Canadian GAAP purposes, NACG recorded the exchange by transferring the carrying value of the NAEPI Series B preferred shares on the exercise date of $44,682 to common shares. For U.S. GAAP purposes, the conversion has been accounted for as a combination of entities under common control as all of the shareholders of the NAEPI Series B preferred shares are also common shareholders of NACG resulting in the reclassification of the carrying value of the minority interest on the exercise date of $48,140 to common shares.
f)	Other matters
	The tax effects of temporary differences under Canadian GAAP are described as future income taxes in these financial statements whereas such amounts are described as deferred income taxes under U.S. GAAP.
g)	United States accounting pronouncements recently adopted
	In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109” (“FIN 48”) which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This Interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition requirements. FIN 48 was effective for the Company’s 2008 fiscal year. The adoption of this standard did not have a material impact on the Company’s financial statements and disclosures required under the standard are provided in note 17 to the financial statements.
	In May 2007, the FASB issued FASB Staff Position No. FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48”, which provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. This FASB Staff Position is effective upon the initial adoption of FIN 48. The adoption of this standard did not have a material impact on the Company’s financial statements.
	Statement of Financial Accounting Standards No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140” (“SFAS 155”) was issued February 2006. This Statement is effective for all financial instruments acquired, issued, or subject to a remeasurement (new basis) event occurring after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The fair value election provided for in paragraph 4(c) of this Statement may also be applied upon adoption of this Statement for hybrid financial instruments that had been bifurcated

49

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

	under paragraph 12 of Statement 133 prior to the adoption of this Statement. This states that an entity that initially recognizes a host contract and a derivative instrument may irrevocably elect to initially and subsequently measure that hybrid financial instrument, in its entirety, at fair value with changes in fair value recognized in earnings. SFAS 155 is applicable for all financial instruments acquired or issued in the Company’s 2008 fiscal year. The adoption of this standard did not have a material impact on the Company’s financial statements.
h)	Recent United States accounting pronouncements not yet adopted
	Statement of Financial Accounting Standards No. 157, “Fair Value Measurement” (“SFAS 157”) was issued September 2006. The Statement provides guidance for using fair value to measure assets and liabilities. The Statement also expands disclosures about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurement on earnings. This Statement applies under other accounting pronouncements that require or permit fair value measurements. This Statement does not expand the use of fair value measurements in any new circumstances. Under this Statement, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. SFAS 157 is effective for fair value measurements and disclosures made by the Company in its fiscal year beginning on April 1, 2008. The Company is currently evaluating the impact of this standard.
	Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”) was issued in February 2007. The statement permits entities to choose to measure many financial instruments and certain other items at fair value, providing the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without the need to apply hedge accounting provisions. SFAS 159 is effective for fiscal years beginning after November 15, 2007, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.
	Statement of Financial Accounting Standards No. 141R, “Business Combinations” (“SFAS 141R”) was issued December 2007. SFAS No. 141R is effective for the fiscal year beginning April 1, 2009. The statement establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree, and any goodwill. This statement establishes disclosure requirements that will enable users of the Company’s financial statements to evaluate the nature and financial effects of the business combination. The Company is currently evaluating the impact of this standard.
	Statement of Financial Accounting Standards No. 160 “Noncontrolling Interests in Consolidated Financial Statements-An Amendment of ARB No. 51 (“SFAS 160”), was issued December 2007. SFAS 160 is effective for the fiscal year beginning April 1, 2009. This statement changes the accounting and reporting for ownership interests in subsidiaries held by parties other than the parent. These non-

50

NORTH AMERICAN ENERGY PARTNERS INC.
Notes to Consolidated Financial Statements
For the years ended March 31, 2008, 2007 and 2006
(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

controlling interests are to be presented in the consolidated statement of financial position within equity but separate from the parent’s equity. The amount of consolidated net income attributable to the parent and to the non-controlling interest is to be clearly identified and presented on the face of the consolidated statement of operations. In addition, this statement establishes standards for a change in a parent’s ownership interest in a subsidiary and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. The statement also establishes reporting requirements for providing sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. The Company is currently evaluating the impact of this standard.

Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement 133” (“SFAS 161”) was issued March 2008. SFAS 161 is effective for the fiscal year beginning April 1, 2009. The statement requires companies with derivative instruments to disclose information about how and why a company uses derivative instruments, how derivative instruments and related hedged items are accounted for under Statement 133, and how derivative instruments and related hedged items affect the company’s financial position, financial performance and cash flows. The required disclosures include the fair value of derivative instruments and their gains or losses in tabular format, information about credit-risk-related contingent features in derivative agreements, counterparty credit risk, and the company’s strategies and objectives for using derivative instruments. The Statement expands the current disclosure framework in Statement 133. The Company is currently evaluating the impact of this standard.

51

EX-99.3

Exhibit 99.3

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the year ended March 31, 2008

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

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

June 20, 2008

Prior Year Comparisons

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

A. Business Overview and Strategy

Business Overview

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

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

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

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

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

1

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

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

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

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

Canadian Oil Sands

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

Oil Sands Outlook

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

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

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

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

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

2

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

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

Strategy

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

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

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

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

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

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

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

Operations

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

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

3

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

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

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

B. Financial Results

Consolidated Results

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

(1) Non GAAP Financial measures

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

4

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

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

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

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

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

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

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

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

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

5

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

     Analysis of Results:

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

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

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

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

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

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

6

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

Consolidated Results (Fourth Quarter)

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

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

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

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

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

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

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

Segment results

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

7

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

     Heavy Construction and Mining

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

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

     Piling

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

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

     Pipeline

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

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

8

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

Fourth Quarter Segment Results

     Heavy Construction and Mining

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

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

      Piling

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

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

     Pipeline

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

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

9

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

Non — operating expense (income)

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

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

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

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

10

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

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

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

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

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

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

     With respect to the customer contract, there is a provision that requires an adjustment to billings to our customer to reflect actual exchange rate and price index changes versus the contract amount. The embedded derivative instrument takes into account the impact on revenues but does not consider the impact on costs as a result of fluctuations in these measures.

     The new accounting guidelines for embedded derivatives will cause our reported earnings to fluctuate as currency exchange and interest rates change. The accounting for these derivatives will have no impact on operations, Consolidated EBITDA per bank or how we will evaluate performance.

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

11

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

Consolidated Financial Position

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

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

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

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

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

Claims and change orders

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

• Client requirements, specifications and design;

• Materials and work schedules; and

• Changes in ground and weather conditions.

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

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

     As a result of certain projects experiencing the changed conditions discussed above, at March 31, 2008 we had recognized approximately $13.0 million in additional contract costs from project inception to date, with no associated increase in contract value. We are working with our customers to come to resolution on additional amounts, if any, to be paid to us in respect to these additional costs.

     Quarterly Operating Results

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

(1) Net income (loss) per share for each quarter has been computed based on the weighted average number of shares issued and outstanding during the respective quarter; therefore, quarterly amounts may not add to the annual total. Per share calculations are based on full dollar and share amounts.

     A number of factors contribute to variations in our quarterly results between periods, including weather, capital spending by our customers on large oil sands projects, our ability to manage our project-

12

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

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

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

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

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

     Profitability also varies from period to period due to claims and change orders. Claims and change orders are a normal aspect of the contracting business but can cause variability in profit margin due to the unmatched recognition of costs and revenues. For further explanation see Claims and Change Orders. During the first quarter of fiscal 2007, a $6.1 million dollar claim was recognized causing gross margins to increase above normal levels. The additional costs relating to the claim were incurred in fiscal 2005. During the fourth quarter of fiscal 2007 and the first half of fiscal 2008 we recognized additional costs related to fixed-price contracts in the Pipeline segment and as a result, we are currently working with our clients through the claims process.

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

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

13

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

C. Key Trends

Seasonality

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

     In addition to revenue variability, gross margins can be negatively impacted in less active periods because we are likely to incur higher maintenance and repair costs due to our equipment being available for scheduled maintenance. Profitability also varies from period to period due to claims and change orders. Claims and change orders are a normal aspect of the contracting business but can cause variability in profit margin due to the unmatched recognition of costs and revenues. For further explanation see “Claims and Change Orders”.

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

Backlog

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

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

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

14

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

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

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

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

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

Revenue Sources:

     This section contains new disclosures.

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

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

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

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

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

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

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

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

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

Contracts

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

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

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

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

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

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

Major Suppliers

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

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

Competition

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

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

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

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

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

D. Outlook

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

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

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

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

     Overall, our outlook for fiscal 2009 remains positive.

E. Legal and Labour Matters

Laws and Regulations and Environmental Matters

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

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

• building and similar codes and zoning ordinances;

• laws and regulations relating to consumer protection; and

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

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

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

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

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

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

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

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

Employees and Labor Relations

     As of March 31, 2008, we had over 280 salaried employees and over 2,100 hourly employees. During fiscal 2008 we welcomed 71 new salaried employees and 581 new hourly employees, bringing our total number of employees to 2,410 at March 31, 2008. Our hourly workforce will fluctuate according to the seasonality of our business from an estimated low of 1,500 employees in the spring to a high of approximately 2,400 employees over the winter. We also utilize the services of subcontractors in our construction business. An estimated 8% to 10% of the construction work we do is performed by subcontractors. Approximately 2,000 employees are members of various unions and work under collective bargaining agreements. The majority of our work is done through employees governed by our Mining Overburden collective bargaining agreement with the International Union of Operating Engineers Local 955, the primary term of which expires on October 31, 2009. A small portion of our employees work under an Industrial collective bargaining agreement with the Alberta Road Builders and Heavy Construction Association and the International Union of Operating Engineers Local 955, the primary term of which expires February 28, 2009. We are subject to other industry and specialty collective agreements under which we complete work, and the primary terms of all of these agreements are currently in effect. We believe that our relationships with all our employees, both union and non-union, are satisfactory. We have not yet experienced a strike or lockout.

F. Resources and Systems

Outstanding Share Data

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

Liquidity

     Liquidity requirements

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

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

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

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

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

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

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

     We require between $30 million and $40 million for sustaining capital expenditures and our total capital requirements will typically range from $125 million to $200 million depending on our growth capital requirements. We typically finance approximately 30% to 50% of our total capital requirements through our operating lease facilities, 5% to 10% through capital lease facilities and the remainder out of cash flow from operations. We believe our operating and capital lease facilities and cash flow from operations will be sufficient to meet these requirements.

     Sources of liquidity

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

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

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

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

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

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

      Revolving credit facility

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

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

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

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

      Working capital fluctuations effect on cash

     The seasonality of our work may result in a slow down in cash collections between December and early February which may result in an increase in our working capital requirements. Our working capital is also significantly affected by the timing of completion of projects. Our customers are permitted to withhold payment of a percentage (defined by the contract and in some cases provincial legislation) of the amount owing to us for a stipulated period of time (usually defined by the contract and in some cases provincial legislation). This amount acts as a form of security for our customers and is referred to as a holdback. We are only entitled to collect payment on holdbacks once substantial completion of the contract is performed, there are no outstanding claims by subcontractors or others related to work performed by us and we have met the time period specified by the contract (usually 45 days after completion of the work). As at March 31, 2008 we saw holdbacks increase to $35 million from $19.5 million in 2007. This represents 21% (18% for 2007) of our total Accounts Receivable outstanding as at March 31, 2008. This increase is attributable to the stronger revenues in the last half of fiscal 2008 with a corresponding increase in work in progress resulting in more holdbacks at year end. As at March 31, 2008 we carried $22.4 million in holdbacks for two large projects (the DeBeers Victor Diamond Mine and the Kinder Morgan pipeline project). The holdback for DeBeers was subsequently collected in May 2008 reducing holdbacks by $11 million. As at March 31, 2007 we carried $5.2 million in holdbacks for the DeBeers project.

      Debt Ratings

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

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

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

Cash Flow

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

     Operating activities

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

     Investing activities

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

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

     Financing activities

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

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

Capital commitments

     Contractual Obligations and Other Commitments

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

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

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

Off-Balance Sheet Arrangements

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

Cash Requirements

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

Internal Systems and Processes

     Overview of information systems

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

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

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

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

     Evaluation of Disclosure Controls and Procedures

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

24

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

     Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by the Company is recorded, processed, summarized and reported within the time periods specified under Canadian and U.S. securities laws and include controls and procedures designed to ensure that information is accumulated and communicated to management, including the President and Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosure.

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

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

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

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

     As of March 31, 2008 we assessed the effectiveness of the Company’s ICFR. In making this assessment we used the criteria set forth in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). During this process we identified material weaknesses in internal controls over financial reporting as described below.

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

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

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

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

25

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

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

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

          Remediation plans

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

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

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

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

     Changes to Internal Control over Financial Reporting

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

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

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

Significant Accounting Policies

     Critical Accounting Estimates

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

26

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

          Revenue recognition

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

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

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

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

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

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

• the availability and proximity of materials;

• unfavorable weather conditions hindering productivity;

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

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

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

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

27

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

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

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

     Plant and equipment

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

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

     Goodwill impairment

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

     Financial Instruments

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

Related Parties

     We may receive consulting and advisory services provided by the Sponsors (principals or employees of such Sponsors are our directors) with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters, and no fee is charged for these consulting and advisory services.

     In order for the Sponsors to provide such advice and consulting we provide reports, financial data and other information. This permits them to consult with and advise our management on matters relating to our operations, company affairs and finances.

28

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

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

Recently adopted Accounting Policies

     Financial Instruments

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

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

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

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

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

     The details of the transitional adjustments are noted below.

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

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

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

29

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

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

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

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

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

     Embedded derivatives:

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

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

     Effective interest method:

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

30

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

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

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

     Comprehensive Income and Equity

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

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

     Accounting Changes

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

     Accounting Policy Choice For Transaction Costs

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

31

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

Recent Accounting pronouncements not yet adopted

     Capital disclosures

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

     Financial Instruments — disclosure and presentation

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

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

     Inventories

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

     Going concern

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

32

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

     Goodwill and intangible assets

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

G. Forward-Looking Information and Risk Factors

     Forward-Looking Information

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

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

(a)	the limited risk that royalty changes will cause our customers to cancel, delay or reduce the scope of any significant mining developments presently underway;
(b)	the expected continued rapid growth of operators in the oil sands business, their planned projects and our intention to pursue business opportunities from these projects;
(c)	our intention to increase our fleet size to be ready to meet the challenges from the projected growth in oil sands;
(d)	that acquisition opportunities will materialize that will allow us to expand our complementary service offerings which we will be able to cross-sell with our existing services;
(e)	our intention to increase our presence outside the oil sands and extend our services to other resource industries across Canada;
(f)	the success of the enhancements to maintenance practices resulting in improved availability through reduced repair time and increased utilization of our equipment with a consequent improvement in our revenue, margins and profitability;
(g)	the amount of our backlog expected to be performed and realized in the 12 months ending March 31, 2009 (such estimates assist us in planning our activity level and may not be suitable for other purposes);
(h)	the expected growth in Master Services Agreements through 2009;

33

(i)	the arrival of new projects and our required participation in the bidding process for work on such projects;
(j)	the continued development of the oil sands and the expectation that it will drive a significant portion of our 2009 revenue;
(k)	our commencement of work in the latter half of fiscal 2009 at Imperial Oil’s upcoming Kearl project;
(l)	the anticipated increased demand for our services at Petro-Canada’s Fort Hills site;
(m)	our expected increased involvement with Baffinland Iron Mines Corp.;
(n)	the demand for our piling services remaining strong in fiscal 2009;
(o)	the anticipated temporary slowdown in our pipeline activity once the TMX project concludes in October 2008 and significant long-term opportunities for this division; and
(p)	our expected generation of a net cash surplus in fiscal 2009.

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

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

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

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

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

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

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

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

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

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

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

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

34

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

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

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

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

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

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

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

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

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

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

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

35

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

Risk Factors

     Anticipated major projects in the oil sands may not materialize.

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

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

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

• lack of sufficient governmental infrastructure to support growth;

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

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

• cost overruns on announced projects.

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

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

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

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

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

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

36

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

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

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

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

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

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

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

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

37

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• scope modifications during the execution of the project;

• the availability and cost of skilled workers;

• the availability and proximity of materials;

• unfavorable weather conditions hindering productivity;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• issue equity securities of subsidiaries;

• make certain investments or acquisitions;

• create liens on our assets;

• enter into transactions with affiliates;

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

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

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

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

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

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

40

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

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

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

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

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

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

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

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

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

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

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

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

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

41

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

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

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

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

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

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

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

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

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

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

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

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

42

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

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

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

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

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

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

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

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

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

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

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

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

H. General Matters

History and Development of the Company

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

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

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

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

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

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

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

Transition to IFRS

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

44

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

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

• Information technology and data systems

• Internal controls over financial reporting

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

• Sufficiency of financial reporting expertise, including training requirements

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

45

EX-99.4

Exhibit 99.4

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of North American Energy Partners Inc.

We consent to the inclusion in this annual report on Form 40-F of:

– our Report of Independent Registered Public Accounting Firm dated June 20, 2008 on the consolidated balance sheets of North American Energy Partners Inc. (“the Company”) as at March 31, 2008 and 2007, and the consolidated statements of operations, comprehensive income (loss) and deficit and cash flows for each of the years in three-year period ended March 31, 2008

– our Report of Independent Registered Public Accounting Firm dated June 20, 2008 on the Company’s internal control over financial reporting as of March 31, 2008

each of which is incorporated by reference in this annual report on Form 40-F of the Company for the fiscal year ended March 31, 2008.

/s/ KPMG LLP

Chartered Accountants

Edmonton, Canada

June 23, 2008

EX-99.5

Exhibit 99.5

CERTIFICATION OF FORM 40-F
REQUIRED BY RULE 13a-14(a)
OR RULE 15D-14(a), PURSUANT TO SECTION 302
OF THE SARBANES–OXLEY ACT OF 2002

I, Rodney J. Ruston, the President and Chief Executive Officer of North American Energy Partners Inc., certify that:

1.	I have reviewed this annual report on Form 40-F for the fiscal year ended March 31, 2008 of North American Energy Partners Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.	The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date:  June 20, 2008

/s/  Rodney J. Ruston
Name:	Rodney J. Ruston
Title:	President and Chief Executive Officer

EX-99.6

Exhibit 99.6

CERTIFICATION OF FORM 40-F
REQUIRED BY RULE 13a-14(a)
OR RULE 15D-14(a), PURSUANT TO SECTION 302
OF THE SARBANES–OXLEY ACT OF 2002

I, Peter R. Dodd, the Chief Financial Officer of North American Energy Partners Inc., certify that:

1.	I have reviewed this annual report on Form 40-F for the fiscal year ended March 31, 2008 of North American Energy Partners Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.	The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date:  June 20, 2008

/s/  Peter R. Dodd
Name:	Peter R. Dodd
Title:	Chief Financial Officer

EX-99.7

Exhibit 99.7

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ENACTED PURSUANT TO

SECTION 906 OF THE SARBANES–OXLEY ACT OF 2002

In connection with the Annual Report on Form 40-F for the fiscal year ended March 31, 2008 (the “Report”) of North American Energy Partners Inc. (the “Company”), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  June 20, 2008

/s/  Rodney J. Ruston
Name:	Rodney J. Ruston
Title:	President and Chief Executive Officer

EX-99.8

Exhibit 99.8

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ENACTED PURSUANT TO

SECTION 906 OF THE SARBANES–OXLEY ACT OF 2002

In connection with the Annual Report on Form 40-F for the fiscal year ended March 31, 2008 (the “Report”) of North American Energy Partners Inc. (the “Company”), the undersigned, in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  June 20, 2008

/s/  Peter R. Dodd
Name:	Peter R. Dodd
Title:	Chief Financial Officer