40-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 40-F

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

OR                         

x ANNUAL REPORT PURSUANT TO SECTION 13(A) OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended March 31, 2010                                                             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))

Suite 2400, 500 4^th Avenue SW

Calgary, Alberta T2P 2V6

(403) 767–4825

(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:

x  Annual information form x  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.

36,049,276 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  ¨             No  x

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  x             No  ¨

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).

Yes  ¨             No  ¨

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, 2010 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, 2010, including the report of the independent registered public accounting firm with respect thereto, 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, 2010 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, 2010, 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, 2010, 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 management’s assessment of internal control over financial reporting is included under the heading “Report of Independent Registered Public Accounting Firm” on page 3 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—Remediation Plans” included in the Registrant’s Management’s Discussion and Analysis for the fiscal year ended March 31, 2010, 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 and its Chief Financial Officer. 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, 2010 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, 2010 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” included in the Registrant’s Annual Information Form for the fiscal year ended March 31, 2010, 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, 2010, 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, 2010, 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, 2010, which is attached as Exhibit 99.1 to this Annual Report on Form 40-F and is incorporated herein by reference.

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.

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 previously filed with the Commission a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises.

Any change to the name or address of the Registrant’s agent for service shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of the Registrant.

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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 10, 2010

EXHIBIT INDEX

99.1	Annual Information Form for the fiscal year ended March 31, 2010.
99.2	Audited Annual Consolidated Financial Statements for the fiscal year ended March 31, 2010.
99.3	Management’s Discussion and Analysis for the fiscal year ended March 31, 2010.
99.4	Canadian Supplement to: Annual Management’s Discussion and Analysis for the fiscal year ended March 31, 2010.
99.5	Consent of KPMG LLP.
99.6	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934.
99.7	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934.
99.8	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.
99.9	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 10, 2010

TABLE OF CONTENTS

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

Explanatory Notes

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

Industry Data and Forecasts

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

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

Forward-Looking Information

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Adoption of United States generally accepted accounting principles (GAAP)

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

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

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

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

Non-GAAP financial measures

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

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

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

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

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

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

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

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

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

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Corporate Structure

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

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

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Description of Our Business

Business Overview

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

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

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

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

History and Development of the Business

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

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

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

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

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

² Suncor Energy Inc. (Suncor).

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

⁴ Canadian Natural Resources Limited (Canadian Natural).

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

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

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

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

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

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

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

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

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

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

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Our Competitive Strengths

We believe our competitive strengths are as follows:

Leading market position

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

Large, well-maintained equipment fleet

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

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

Broad service offering across a project’s lifecycle

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

Long-term customer relationships

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

Operational flexibility

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

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

Our Strategy

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

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

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

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

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

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

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

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

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

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

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

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Our Operations and Segments

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

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

Heavy Construction and Mining

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

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

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

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

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

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

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

Piling

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

Pipeline

Our Pipeline segment installs transmission, distribution and gathering systems made of steel, fiberglass and/or plastic pipe in sizes up to 52” in diameter. Penstock installation services are also provided. This segment has successfully completed jobs of varying magnitude for some of Canada’s largest energy companies, including Kinder Morgan’s⁶ Trans Mountain Expansion (TMX) Anchor Loop pipeline, which involved the installation of 160 kilometres of large-diameter pipe through extremely challenging and ecologically sensitive terrain. The segment also provides recurring services to specific customers. As an example, we have a three-year contract to complete pipeline integrity excavations and hydrostatic retest on TransCanada Pipelines’⁷ mainline system in British Columbia, Saskatchewan, Manitoba and Ontario.

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

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

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

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

Our Markets

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

Canadian Oil Sands

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

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

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

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

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

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

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

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

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

Current Canadian Oil Sands Business Conditions

Project Development: Although last year saw a general slowdown in project development activity in the oil sands, we also saw construction on two projects, Exxon’s $8 billion Kearl mining project⁸ and Shell Albian’s $12 billion Jackpine mine expansion project, continue without any delay as these operators remained focused on the long term oil price as the project driver. As economic conditions have strengthened, oil prices have stabilized and producers are reaffirming their commitment to oil sands development with new construction approval announcements, including Husky Energy Inc.’s Sunrise⁹ in situ project and ConocoPhillips’ Surmont¹⁰ in situ project. Canadian Natural has indicated strong interest in proceeding with its Horizon Mine Phase 2/3 expansion and development of the Kirby in situ project, while Suncor is proceeding with additional stages of its Firebag in situ project as it completes the integration process of the Fort Hills¹¹ mining project from its recent acquisition of Petro-Canada Limited. While capital spending in the oil sands declined from $18 billion in calendar 2008 to $11 billion in 2009, CAPP forecasts a recovery in capital spending to $13 billion in 2010.

Further positive indicators that investor interest in the oil sands is strengthening include PetroChina’s¹² recent $2 billion investment in Athabasca Oil Sands, followed by a $1.35 billion initial public offering by Athabasca Oil Sands Corp., the largest in oil sands history. China’s Sinopec Corp.¹³ recently announced plans to buy ConocoPhillips’ stake in the Syncrude project for $4.65 billion. This is China’s largest investment in North America to date.

While the overall trend is positive, environmental activism opposing oil sands development has been increasing and receiving broad media coverage. Environmental costs to producers are rising as a result of increasing regulatory requirements. As an example, the recently released ERCB Directive 074¹⁴ requires producers to invest in new research, development, technology and services to address the reclamation of tailings ponds in a significantly accelerated time span. Although this adds costs to the process, it also creates opportunities for service providers like ourselves to create new lines of business to support the construction and operation of these new reclamation processes.

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

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

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

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

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

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

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

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

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

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

Commercial and Public Construction

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

Current Commercial and Public Construction Business Conditions

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

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

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

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

Conventional Oil and Gas

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

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

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

Current Conventional Oil and Gas Business Conditions

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

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

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

Minerals Mining

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

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

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

Current Minerals Mining Business Conditions

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

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

Our Revenue Sources

Revenue by Category

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

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

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

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

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

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

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

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

Revenue by End Market

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

Our Contract Types

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

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

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

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

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

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

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

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

PROJECTS

Active Projects

Canadian Natural: Overburden Removal Project

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

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

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

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

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

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

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

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

Suncor Energy: Equipment Supply Agreement

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

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

Syncrude: Base Plant: Labour & Equipment Supply

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

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

Exxon’s Kearl: Crusher MSE Wall Construction Project

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

Canadian Cooperative Refinery Limited: Tank Farm Project

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

Recently Completed Projects

Spectra Maxhamish Loop – North

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

Shell Albian: Jackpine Compensation Lake Project

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

Suncor (formerly Petro Canada): Fort Hills Project

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

Syncrude: Reclamation Project

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

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Kinder Morgan: TMX Anchor Loop Project

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

University of Saskatchewan – Hospital Expansion Project

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

Anthony Henday – North Loop Caissons Project

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

Suncor: Voyageur Project

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

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

Suncor: Millennium Naphtha Unit (“MNU”) Project

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

Joint Venture

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

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Resources and Key Trends

Our Fleet and Equipment

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

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

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

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

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

Capital Expenditures

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

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

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Facilities

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

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

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

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Competition

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

Major Suppliers

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

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

Variability of Results

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

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

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

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Legal and Labour Matters

Laws, Regulations and Environmental Matters

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

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

Ÿ building and similar codes and zoning ordinances;

Ÿ laws and regulations relating to consumer protection; and

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

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

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

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

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

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

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

Employees and Labour Relations

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

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

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

The IPO and Reorganization

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

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

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

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

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

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

Description of Share Capital

General

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

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

Voting Common Shares

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

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

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Non-Voting Common Shares

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

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

Dividends

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

Trading Price and Volume

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

Toronto Stock Exchange

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

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Description of Certain Indebtedness

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

9.125% Series 1 Debentures

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

8  ³/4% Senior Notes Redemption

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

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

Termination of Cross-Currency and Interest Rate Swaps

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

$50.0 million Term Facility and Use of Cash

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

Credit Facility (Including April 2010 Subsequent Event)

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

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

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

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

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

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

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

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

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

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

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

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

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

Covenants:

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

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

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

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

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

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

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

Ÿ create or allow to exist liens or other encumbrances;

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

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

Ÿ make investments, including acquisitions;

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

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

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

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

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

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

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

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

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

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

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

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Swap Agreements (Terminated April 2010)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Letters of Credit

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

Debt Ratings

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

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

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

⁽¹⁾ Loss Given Default

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

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

Standard & Poor’s

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

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

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

Moody’s

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

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

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

Directors and Officers

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The Board and Board Committees

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

Our board has established the following committees:

Audit Committee

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

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

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

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

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

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

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

Compensation Committee

The Compensation Committee is charged with the responsibility for supervising executive compensation policies for us and our Subsidiaries, administering the employee incentive plans, reviewing officers’ salaries, approving significant changes in executive employee benefits and recommending to the board such other forms of remuneration as it deems appropriate. In accordance with the listing requirements of the New York Stock Exchange applicable to domestic listed companies and applicable Canadian securities laws, our board of directors has affirmatively determined that our Compensation Committee is composed solely of independent directors. Our board of directors has adopted a written charter for the Compensation Committee that is available on our website. The Compensation Committee is currently composed by Messrs. Brussa, Oehmig, Sello and Tomsett, with Mr. Tomsett serving as Chairman. None of the members of the Compensation Committee is or has been one of our officers or employees, and none of our executive officers served during fiscal 2010 on a board of directors of another entity which has employed any of the members of the Compensation Committee.

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Governance Committee

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

Health, Safety, Environment and Business Risk Committee

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

Interest of Management and Others in Material Transactions

Voting and Corporate Governance Agreement

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

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

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

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

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

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

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

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

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

Registration Rights Agreement

We are party to a registration rights agreement with certain shareholders, including affiliates of each of the significant shareholders, Paribas North America, Inc. and Mr. William Oehmig, one of our directors. The shareholders party to the agreement and their permitted transferees are entitled, subject to certain limitations, to include their common shares in a registration of common shares we initiate under the Securities Act of 1933, as amended. In addition, after the 120th day following our IPO, any one or more shareholders party to the agreement has the right to require us to effect the registration of all or any part of such shareholders’ common shares under the Securities Act, referred to as a “demand registration,” so long as the amount of common shares to be registered has an aggregate fair market value of at least US$5.0 million and, at such time, the SEC has ordered or declared effective fewer than four demand registrations

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

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

Ÿ up to 120 days if:

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

^¡ initiated discussions with underwriters in preparation for a public offering of our common shares as to which we expect to receive net proceeds of at least US$20.0 million and the demand registration, in the underwriters’ opinion, would have a material adverse effect on the offering; or

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

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

The registration rights agreement contains customary provisions whereby we and the shareholders party to the agreement indemnify and agree to contribute to each other with regard to losses caused by the misstatement of any information or the omission of any information required to be provided in a registration statement filed under the Securities Act. The registration rights agreement requires us to pay the expenses associated with any registration other than sales discounts, commissions, transfer taxes and amounts to be borne by underwriters or as otherwise required by law.

Legal Proceedings and Regulatory Actions

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

Transfer Agent and Registrar

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

Material Contracts

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

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

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

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

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

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

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

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

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

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

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

Risks and Uncertainties

Risks Related to our Business

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

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

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

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

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

Ÿ lack of sufficient governmental infrastructure funding to support growth;

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

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

Ÿ cost overruns on announced projects.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Significant labour disputes could adversely affect our business.

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

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

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

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

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

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

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

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

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

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

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

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

Ÿ scope modifications during the execution of the project;

Ÿ the availability and cost of skilled workers;

Ÿ the availability and proximity of materials;

Ÿ unfavourable weather conditions hindering productivity;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Ÿ issue equity securities of subsidiaries;

Ÿ make certain investments or acquisitions;

Ÿ create liens on our assets;

Ÿ enter into transactions with affiliates;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Risks Related to Our Common Shares

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

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

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

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

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

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

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

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

Ÿ reaction to our public announcements;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Quantitative and Qualitative Disclosures about Market Risk

Foreign exchange risk

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

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

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

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

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

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

Interest rate risk

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

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

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

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

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

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

45

Additional Information

Experts

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

Additional Information

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

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

46

Glossary

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

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

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

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

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

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

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

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

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

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

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

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

47

Exhibit A

Audit Committee Charter

1. MANDATE & AUTHORITY

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

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

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

c) monitor the disclosure controls and procedures;

d) oversee the work of the external auditor;

e) monitor the internal audit function;

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

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

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

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

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

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

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

2. MEMBERSHIP

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

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

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

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

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

i

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

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

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

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

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

3. MEETINGS

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

ii

4. RESPONSIBILITIES

4.1 General

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

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

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

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

4.2 Financial reporting and internal controls

4.2.1 Annual financial statements

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

4.2.2 Interim financial statements

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

4.2.3 Accounting policies

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

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

4.2.4 Internal controls over financial reporting

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

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

4.2.5 Disclosure controls and procedures

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

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

4.2.6 Other public disclosures

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

a) management’s discussion and analysis;

b) any prospectus or offering document;

iii

c) annual reports or annual information forms;

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

e) any related party transactions;

f) any off balance sheet structures;

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

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

4.3 External Auditor

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

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

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

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

4.3.5 The external auditor shall report directly to the Committee.

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

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

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

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

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

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

f) the summary of adjusted and unadjusted differences;

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

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

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

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

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

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

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

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

iv

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

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

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

4.4 Internal Audit Function

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

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

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

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

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

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

4.5 Risk Management

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

4.6 Ethics Reporting

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

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

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

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

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

4.7 Legal and Regulatory Compliance

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

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

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

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

v

Appendix A: Audit Committee Financial Expert

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

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

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

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

4. An understanding of internal control over financial reporting;

5. An understanding of audit committee functions;

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

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

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

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

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

(d) other relevant experience.

vi

EX-99.2

Exhibit 99.2

NORTH AMERICAN ENERGY PARTNERS INC.

Consolidated Financial Statements

For the years ended March 31, 2010, 2009 and 2008

(Expressed in thousands of Canadian Dollars)

    KPMG LLP Chartered Accountants 10125 – 102 Street Edmonton AB T5J 3V8 Canada     Telephone Fax Internet     (780) 429-7300 (780) 429-7379 www.kpmg.ca

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors

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, 2010 and 2009 and the related consolidated statements of operations and comprehensive income (loss), shareholders’ equity and cash flows for each of the years in the three-year period ended March 31, 2010. 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, 2010 and 2009 and the results of its operations and its cash flows for each of the years in the three-year period ended March 31, 2010 in conformity with U.S. generally accepted accounting principles.

As discussed in Note 3 bb) iii) to the consolidated financial statements, the Company adopted new accounting pronouncements related to business combinations in 2010.

U.S. generally accepted accounting principles vary in certain significant respects from Canadian generally accepted accounting principles. Information relating to the nature and effect of such differences is presented in Note 34 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, 2010, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated June 9, 2010 expressed our opinion that the Company did not maintain effective internal control over financial reporting as of March 31, 2010.

Chartered Accountants

Edmonton, Canada

June 9, 2010

KPMG LLP, is a Canadian limited liability partnership and a member firm of the KPMG

network of independent member firms affiliated with KPMG International, a Swiss cooperative.

KPMG Canada provides services to KPMG LLP.

2  Report of Independent Registered Public Accounting Firm  North American Energy Partners Inc.

    KPMG LLP Chartered Accountants 10125 – 102 Street Edmonton AB T5J 3V8 Canada     Telephone Fax Internet     (780) 429-7300 (780) 429-7379 www.kpmg.ca

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and 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, 2010, 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, 2010. 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.

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. A material weakness in revenue recognition has been identified and included in management’s assessment. 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 2010 consolidated financial statements of the Company. The material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2010 consolidated financial statements, and this report does not affect our report dated June 9, 2010, which expressed an unqualified opinion on those consolidated financial statements.

In our opinion, because of the effect of the aforementioned material weakness 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, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Chartered Accountants

Edmonton, Canada

June 9, 2010

KPMG LLP, is a Canadian limited liability partnership and a member firm of the KPMG

network of independent member firms affiliated with KPMG International, a Swiss cooperative.

KPMG Canada provides services to KPMG LLP.

North American Energy Partners Inc.  Report of Independent Registered Public Accounting Firm  3

Consolidated Balance Sheets

As at March 31 (Expressed in thousands of Canadian Dollars)

	2010		2009
Assets
Current assets:
Cash and cash equivalents	$103,005		$98,880
Accounts receivable, net (note 6)	111,884		78,323
Unbilled revenue (note 7)	84,702		55,907
Inventories (note 8)	5,659		11,814
Prepaid expenses and deposits (note 9)	6,881		4,781
Deferred tax assets (note 20)	3,481		7,033
	315,612		256,738
Prepaid expenses and deposits (note 9)	4,005		3,504
Assets held for sale (note 10)	838		2,760
Property, plant and equipment, net (note 11)	328,743		316,115
Intangible assets (note 12)	7,669		5,944
Deferred financing costs (note 13)	6,725		7,910
Investment in and advances to unconsolidated joint ventures (note 14)	2,917		–
Goodwill (note 4)	25,111		23,872
Deferred tax assets (note 20)	10,997		12,432
Total assets	$702,617		$629,275
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$66,876		$56,204
Accrued liabilities (note 16)	47,191		45,001
Billings in excess of costs incurred and estimated earnings on uncompleted contracts (note 7)	1,614		2,155
Current portion of capital lease obligations (note 17)	5,053		5,409
Current portion of derivative financial instruments (note 24(a))	22,054		11,439
Current portion of long term debt (note 18(a))	6,072		–
Deferred tax liabilities (note 20)	16,781		7,749
	165,641		127,957
Deferred lease inducements (note 15)	761		836
Long term accrued liabilities (note 16)	14,943		7,134
Capital lease obligations (note 17)	8,340		12,075
Long term debt (note 18(a))	22,374		–
Senior notes (note 18(b))	203,120		255,756
Director deferred stock unit liability (note 30(d))	2,548		546
Restricted share unit liability (note 30(c))	1,030		–
Derivative financial instruments (note 24(a))	75,001		43,048
Asset retirement obligation (note 19)	360		386
Deferred tax liabilities (note 20)	27,441		30,745
	521,559		478,483
Shareholders’ equity:
Common shares (authorized – unlimited number of voting and non-voting common shares; issued and outstanding – March 31, 2010 – 36,049,276 voting common shares (March 31, 2009 – 36,038,476 voting common shares) (note 21(a))	303,505		303,431
Additional paid-in capital (note 21(b))	7,439		5,466
Deficit	(129,886	)	(158,105	)
	181,058		150,792
Total liabilities and shareholders’ equity	$702,617		$629,275
Commitments (note 28)
Contingencies (note 31)
Subsequent event (note 33)
United States and Canadian accounting policy differences (note 34)

See accompanying notes to consolidated financial statements.

Approved on behalf of the Board

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

4  Financial Statements  North American Energy Partners Inc.

Consolidated Statements of Operations and Comprehensive Income (Loss)

For the years ended March 31 (Expressed in thousands of Canadian Dollars, except per share amounts)

	2010	2009	2008
Revenue	$758,965	$972,536	$989,696
Project costs	301,307	505,026	592,458
Equipment costs	209,408	217,120	176,190
Equipment operating lease expense	66,329	43,583	22,319
Depreciation	42,636	36,389	35,720
Gross profit	139,285	170,418	163,009
General and administrative costs	62,530	74,460	69,806
Loss on disposal of property, plant and equipment	1,233	5,325	179
Loss on disposal of assets held for sale	373	24	493
Amortization of intangible assets (note 12)	1,719	1,501	804
Equity in earnings of unconsolidated joint venture (note 14)	(44)	–	–
Impairment of goodwill (note 4)	–	176,200	–
Operating income (loss) before the undernoted	73,474	(87,092)	91,727
Interest expense, net (note 22)	26,080	29,612	29,080
Foreign exchange (gain) loss	(48,901)	47,272	(25,660)
Realized and unrealized loss (gain) on derivative financial instruments (note 24(a))	54,411	(37,250)	30,075
Other income (note 24(c)(i))	(14)	(5,955)	(418)
Income (loss) before income taxes	41,898	(120,771)	58,650
Income taxes (note 20):
Current income taxes	3,803	5,546	80
Deferred income taxes	9,876	9,087	17,036
Net income (loss) and comprehensive income (loss) for the year	28,219	(135,404)	41,534
Net income (loss) per share – basic (note 21(c))	$0.78	$(3.76)	$1.16
Net income (loss) per share – diluted (note 21(c))	$0.77	$(3.76)	$1.13

See accompanying notes to consolidated financial statements.

North American Energy Partners Inc.  Financial Statements  5

Consolidated Statements of Changes in Shareholders’ Equity

(Expressed in thousands of Canadian Dollars)

	Common shares	Common non-voting shares		Additional paid-in capital		Deficit		Total
Balance at March 31, 2007	$297,594	$2,062		$3,606		$(64,235	)	$239,027
Net income	–	–		–		41,534		41,534
Conversion to common voting shares	2,062	(2,062	)	–		–		–
Stock-based compensation	–	–		1,937		–		1,937
Reclassification on exercise of stock options	611	–		(611	)	–		–
Cash settlement of stock options	–	–		(581	)	–		(581	)
Issued upon exercise of stock options	1,627	–		–		–		1,627
Balance at March 31, 2008	$301,894	$–		$4,351		$(22,701	)	$283,544
Net loss	–	–		–		(135,404	)	(135,404	)
Stock-based compensation	–	–		1,888		–		1,888
Deferred performance share unit plan	–	–		61		–		61
Reclassification on exercise of stock options	834	–		(834	)	–		–
Issued upon exercise of stock options	703	–		–		–		703
Balance at March 31, 2009	$303,431	$–		$5,466		$(158,105	)	$150,792
Net income	–	–		–		28,219		28,219
Stock-based compensation	–	–		2,135		–		2,135
Deferred performance share unit plan	–	–		123		–		123
Reclassified to restricted share unit liability	–	–		(20	)	–		(20	)
Reclassification on exercise of stock options	21	–		(21	)	–		–
Cash settlement of stock options	–	–		(244	)	–		(244	)
Issued upon exercise of stock options	53	–		–		–		53
Balance at March 31, 2010	$303,505	$–		$7,439		$(129,886	)	$181,058

See accompanying notes to consolidated financial statements.

6  Financial Statements  North American Energy Partners Inc.

Consolidated Statements of Cash Flows

For the years ended March 31 (Expressed in thousands of Canadian Dollars)

Cash provided by (used in):	2010		2009			2008
Operating activities:
Net income (loss) for the year	$28,219		$	(135,404	)	$41,534
Items not affecting cash:
Depreciation	42,636			36,389		35,720
Equity in earnings of unconsolidated joint venture (note 14)	(44	)		–		–
Amortization of intangible assets	1,719			1,501		804
Impairment of goodwill (note 4)	–			176,200		–
Amortization of deferred lease inducements	(107	)		(105	)	(104	)
Amortization of deferred financing costs (note 22)	3,348			2,970		2,899
Loss on disposal of property, plant and equipment	1,233			5,325		179
Loss on disposal of assets held for sale	373			24		493
Unrealized foreign exchange (gain) loss on senior notes	(48,920	)		46,466		(25,006	)
Unrealized loss (gain) on derivative financial instruments measured at fair value	38,852			(39,921	)	27,406
Stock-based compensation expense (note 30)	5,270			2,305		2,127
Accretion of asset retirement obligation (note 19)	5			155		–
Deferred income taxes	9,876			9,087		17,036
Net changes in non-cash working capital (note 25(b))	(39,591	)		46,193		(8,291	)
	42,869			151,185		94,797
Investing activities:
Acquisition, net of cash acquired (note 5(a))	(5,410	)		–		(1,581	)
Purchase of property, plant and equipment	(51,989	)		(84,437	)	(52,805	)
Addition to intangible assets	(3,362	)		(3,102	)	(2,274	)
Additions to assets held for sale	(1,739	)		(2,035	)	(3,499	)
Investment in and advances to unconsolidated joint venture (note 14)	(2,873	)		–		–
Proceeds on disposal of property, plant and equipment	1,440			11,164		6,862
Proceeds of disposal of assets held for sale	2,482			325		10,200
Net changes in non-cash working capital (note 25(b))	1,840			(630	)	(2,835	)
	(59,611	)		(78,715	)	(45,932	)
Financing activities:
Repayment of long term debt	(6,906	)		–		(20,500	)
Increase in long term debt (note 18(a))	34,700			–		–
Cash settlement of stock options (note 21(b))	(244	)		–		(581	)
Proceeds from stock options exercised (note 21(a))	53			703		1,627
Financing costs (note 13)	(1,123	)		–		(776	)
Repayment of capital lease obligations	(5,613	)		(6,156	)	(3,762	)
	20,867			(5,453	)	(23,992	)
Increase in cash and cash equivalents	4,125			67,017		24,873
Cash and cash equivalents, beginning of year	98,880			31,863		6,990
Cash and cash equivalents, end of year	$103,005			$98,880		$31,863
Supplemental cash flow information (note 25(a))

See accompanying notes to consolidated financial statements.

North American Energy Partners Inc.  Financial Statements  7

Notes to Consolidated Financial Statements

For the years ended March 31, 2010, 2009 and 2008

(Expressed 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 Norama Ltd. which had been operating continuously in Western Canada since 1953. The Company had no operations prior to November 26, 2003. The Company undertakes several types of projects including heavy construction, industrial and commercial site development and pipeline and piling installations in Canada.

2. Change in generally accepted accounting principles

As a Canadian-based company, the Company historically prepared its consolidated financial statements in conformity with accounting principles generally accepted in Canada (Canadian GAAP) and also provided reconciliation to United States generally accepted accounting principles (U.S. GAAP).

The Accounting Standards Board of the Canadian Institute of Chartered Accountants previously announced its decision to require all publicly accountable enterprises to report under International Financial Reporting Standards (IFRS) for years beginning on or after January 1, 2011. However, National Instrument 52-107 allows Securities and Exchange Commission (“SEC”) registrants, such as the Company, to file financial statements with Canadian securities regulators that are prepared in accordance with U.S. GAAP. It is proposed that SEC registrants would be permitted to continue to report under U.S. GAAP beyond 2011. As such, the Company has decided to adopt U.S. GAAP instead of IFRS as its primary basis of financial reporting commencing in fiscal 2010.

The decision to adopt U.S. GAAP was also made to enhance communication with shareholders and improve the comparability of financial information reported with competitors and peer group. All comparative financial information contained herein has been revised to reflect the Company’s results as if they had been historically reported in accordance with U.S. GAAP.

3. Significant accounting policies

a) Basis of presentation

These consolidated financial statements are prepared in accordance with U.S. 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 Canadian GAAP are outlined in note 34.

These consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, North American Construction Group Inc. (“NACGI”) and North American Fleet Company Ltd. (“NAFCL”), and the following 100% owned subsidiaries of NACGI:

_ŸNorth American Caisson Ltd. _ŸNorth American Construction Ltd. _ŸNorth American Engineering Inc. _ŸNorth American Enterprises Ltd. _ŸNorth American Industries Inc. _ŸNorth American Maintenance Ltd. _ŸNorth American Mining Inc. _ŸNorth American Pipeline Inc. _ŸNorth American Road Inc. _ŸNorth American Services Inc. _ŸNorth American Site Development Ltd. _ŸNorth American Site Services Inc. _ŸNorth American Pile Driving Inc. _ŸDF Investments Limited _ŸDrillco Foundation Co. Ltd.

b) Use of estimates

The preparation of financial statements in conformity with U.S. 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 revenue contracts, assumptions used to value free standing derivatives and other financial instruments, assumptions used in periodic impairment testing, and estimates and assumptions used in the determination of the allowance for doubtful accounts, the recoverability of deferred tax assets and the useful lives of property, plant and equipment. Actual results could differ materially from those estimates.

8  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

The accuracy of the Company’s revenue and profit recognition in a given period is dependent, in part, on the accuracy of its estimates of the cost to complete each time-and-materials, unit-price, or lump-sum project. The Company’s 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 its experience allows it to produce materially reliable estimates. However, the Company’s projects can be highly complex. Profit margin estimates for a project may either increase or decrease 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 the Company’s 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 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 resulting percent complete methodology is applied to the approved contract value to determine the revenue recognized. Customer payment milestones typically occur on a periodic basis over the period of contract completion.

The 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 unapproved change orders and claims are recognized when they are incurred. Revenues related to unapproved change orders and claims are included in total estimated contract revenue when they are approved.

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

_Ÿ a bona fide addition to contract value; and

_Ÿ revenues can be reliably estimated.

These two conditions are satisfied when:

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

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

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

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

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.

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.

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

Revenue recognition from equipment rentals occurs when there is a written arrangement in the form of a contract or purchase order with the customer, a fixed or determinable sales price is established with the customer, performance

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  9

requirements are achieved, and ultimate collection of the revenue is reasonably assured. Equipment rental revenue is recognized as performance requirements are achieved in accordance with the terms of the relevant agreement with the customer, either at a monthly fixed rate or on a usage basis dependent on the number of hours that the equipment is used.

d) Balance sheet classifications

Included in current assets and liabilities are amounts receivable and payable under construction contracts (principally holdbacks) that may extend beyond one year. A one-year time period is used as the basis for classifying all other current assets and liabilities.

e) 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.

f) Accounts receivable and unbilled revenue

Accounts receivable in the accompanying Consolidated Balance Sheets are primarily comprised of amounts billed to clients for services already provided, but which have not yet been collected. Unbilled revenue represents revenue recognized in advance of amounts invoiced.

g) Billings in excess of costs incurred and estimated earnings on uncompleted contracts

Billings in excess of costs incurred and estimated earnings on uncompleted contracts represent amounts invoiced in excess of revenue recognized.

h) 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.

i) Inventories

Inventories are carried at the lower of weighted average cost and market, and consist primarily of spare parts and tires.

j) Property, plant and equipment

Property, 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:

Assets	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.

k) Capitalized interest

The Company capitalizes interest incurred on debt during the construction of assets for the Company’s own use. The capitalization period covers the duration of the activities required to get the asset ready for its intended use, provided that expenditures for the asset have been made and interest cost incurred. Interest capitalization continues as long as those activities and the incurrence of interest cost continue. The capitalized interest is amortized at the same rate as the respective asset.

l) Goodwill

Goodwill is an asset representing the future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. 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. Goodwill is assigned, as of the date of the business combination, to reporting units that are expected to benefit from the business combination. The impairment test is carried out in two steps. In the first step, the carrying amount of the

10  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

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 performs its annual goodwill assessment on October 1 of each year and when a triggering event occurs between annual impairment tests.

m) Intangible assets

Intangible assets include:

_Ÿ customer contracts in process and related relationships, which are being amortized over the remaining lives of the related contracts and relationships;

_Ÿ trade names, which are being amortized on a straight-line basis over their estimated useful lives of five and ten years;

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

_Ÿ capitalized computer software and development costs.

The Company expenses or capitalizes costs associated with the development of internal-use software as follows:

Preliminary project stage: Both internal and external costs incurred during this stage are expensed as incurred.

Application development stage: Both internal and external costs incurred to purchase and develop computer software are capitalized after the preliminary project stage is completed and management authorizes the computer software project. However, training costs and the process of data conversion from the old system to the new system, which includes purging or cleansing of existing data, reconciliation or balancing of old data to the converted data in the new system, are expensed as incurred.

Post implementation/operation stage: All training costs and maintenance costs incurred during this stage are expensed as incurred.

Costs of upgrades and enhancements are capitalized if the expenditures will result in adding functionality to the software. Capitalized software costs are depreciated using the straight-line method over the estimated useful life of the related software, which may be up to four years.

n) Impairment of long-lived assets

Long-lived assets or asset groups held and used including plant, equipment 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. If the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of an asset or group of assets is less than its carrying amount, it is considered to be impaired. The Company measures the impairment loss as the amount by which the carrying amount of the asset or group of assets exceeds its fair value, which is charged to depreciation expense. In determining whether an impairment exists, the Company makes assumptions about the future cash flows expected from the use of its long-lived assets, such as: applicable industry performance and prospects; general business and economic conditions that prevail and are expected to prevail; expected growth; maintaining its customer base; and, achieving cost reductions. There can be no assurance that expected future cash flows will be realized, or will be sufficient to recover the carrying amount of long-lived assets. Furthermore, the process of determining fair values is subjective and requires management to exercise judgment in making assumptions about future results, including revenue and cash flow projections and discount rates.

o) Assets held for sale

Long-lived assets are classified as held for sale when certain criteria are met, which include:

_Ÿ Management, having the authority to approve the action, commits to a plan to sell the assets;

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

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

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

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

_Ÿ 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 disclosed separately on the Consolidated Balance Sheets. These assets are not depreciated.

p) Asset retirement obligations

Asset retirement obligations are legal obligations associated with the retirement of property, plant and equipment that result from their acquisition, lease, construction, development or normal operations. The Company recognizes its contractual obligations for the retirement of certain tangible long-lived assets. The fair value of a liability for an asset

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  11

retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of a liability for an asset retirement obligation is the amount at which that liability could be settled in a current transaction between willing parties, that is, other than in a forced or liquidation transaction and, in the absence of observable market transactions, is determined as the present value of expected cash flows. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset and then amortized using a systematic and rational method over its estimated useful life. In subsequent reporting periods, the liability is adjusted for the passage of time through an accretion charge and any changes in the amount or timing of the underlying future cash flows are recognized as an additional asset retirement cost.

q) 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, denominated in foreign currencies, are translated into Canadian Dollars at the rate of exchange prevailing at the balance sheet date. Foreign exchange gains and losses are included in the determination of earnings.

r) Fair value measurement

Financial instruments are categorized using a valuation hierarchy for disclosure of the inputs used to measure fair value, which prioritizes the inputs into three broad levels. Fair value of financial assets and financial liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Financial assets and financial liabilities in Level 2 include valuations using inputs based on observable market data, either directly or indirectly other than the quoted prices. Level 3 valuations are based on inputs that are not based on observable market data. The classification of a financial asset or liability within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.

s) 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 Statements of Operations and Comprehensive Income (Loss).

t) Income taxes

The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the deferred tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using 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 deferred tax assets and liabilities from a change in tax rates is recognized in income in the period of enactment. The Company recognizes the effect of income tax positions only if those positions are more likely than not (greater than 50%) of being sustained. Changes in recognition or measurement are reflected in the period in which the change in judgement occurs. The Company accrues interest and penalties for uncertain tax positions in the period in which these uncertainties are identified. Interest and penalties are included in “Other income” in the Consolidated Statements of Operations and Comprehensive Income (Loss). A valuation allowance is recorded against any deferred tax asset if it is more likely than not that the asset will not be realized.

u) Stock-based compensation

The Company accounts for all stock-based compensation payments that are settled by the issuance of equity instruments at fair value. 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 additional paid-in capital. Upon exercise of a stock option, share capital is recorded at the sum of proceeds received and the related amount of additional paid-in capital.

The Company has a Deferred Performance Share Unit (“DPSU”) plan, which is described in note 30(b). This compensation plan is settled, at the Company’s option, either by the issuance of equity instruments or by cash payment. 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 additional paid-in capital. The vesting of awards under the DPSU is contingent upon certain performance criteria being achieved. The fair value of each share option grant under the DPSU plan assumes that the relevant performance criteria will be achieved and compensation cost is recorded to the extent that vesting of the award is considered probable. When it is determined that such criteria are not probable of being achieved, no compensation cost is recognized and any previously recognized compensation cost is reversed.

12  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

The Company has a Restricted Share Unit (“RSU”) plan which is described in note 30(c). RSUs will be granted effective April 1 of each fiscal year with respect to services to be provided in that fiscal year and the following two fiscal years. The RSUs vest at the end of a three-year term. The Company classifies RSUs as a liability as the Company has the ability and intent to settle the awards in cash. The compensation expense is calculated based on the fair value of each RSU as determined by the number of RSUs vested and the closing value of the Company’s common shares on each period end date.

The Company has a Director’s Deferred Stock Unit (“DDSU”) plan, which is described in note 30(d). The DDSU plan enables directors to receive all or a portion of their fee for that fiscal year in the form of deferred stock units. The deferred stock units are settled in cash and are classified as a liability on the Consolidated Balance Sheets. The measurement of the liability and compensation costs for these awards is based on the fair 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.

v) Net income (loss) per share

Basic net income (loss) per share is computed by dividing net income available to common shareholders by the weighted average number of shares outstanding during the year (see note 21(c)). Diluted per share amounts are calculated using the treasury stock method. The treasury stock method increases the diluted weighted average shares outstanding to include additional shares from the assumed exercise of stock options, if dilutive. The number of additional shares is calculated by assuming outstanding in-the-money stock options were exercised and the proceeds from such exercises, including any unamortized stock-based compensation cost, were used to acquire shares of common stock at the average market price during the year.

w) Leases

Leases entered into by the Company in which substantially all the benefits and risks of ownership transferred to the Company are recorded as obligations under capital leases, and under the corresponding category of property, plant and equipment. Obligations under capital leases reflect the present value of future lease payments, discounted at an appropriate interest rate, and are reduced by rental payments net of imputed interest. All other leases are classified as operating leases and leasing costs, including any rent holidays, leasehold incentives, and rent concessions, are amortized on a straight line basis over the lease term.

x) Deferred financing costs

Underwriting, legal and other direct costs incurred in connection with the issuance of debt not measured under the fair value option is presented as deferred financing costs. The deferred financing costs related to the senior notes and the revolving and term loan facilities are amortized over the term of the related debt using the effective interest method.

y) Investments in unconsolidated joint ventures or affiliates

Investments in unconsolidated joint ventures or affiliates over which the Company has significant influence including the Company’s investment in Noramac Ventures Inc. are accounted for under the equity method of accounting, whereby the investment is carried at the cost of acquisition, including subsequent capital contributions and loans from the Company, plus the Company’s equity in undistributed earnings or losses since acquisition. Investments in unconsolidated joint ventures are included as investment in and advances to unconsolidated joint venture in the Company’s Consolidated Balance Sheets.

z) Business combinations

The Company accounts for all business combinations using the acquisition method. Acquisition related costs which include finder’s fees, advisory, legal, accounting, valuation, other professional or consulting fees, and administrative costs are expensed as incurred.

aa) Adjustments related to prior year financial statements

The financial statements for fiscal 2009 and fiscal 2008 as initially reconciled to U.S. GAAP have been amended to correct the following errors identified during the preparation of the Company’s 2010 financial statements under U.S. GAAP:

(i) Adoption of CICA Handbook Section 3031, “Inventories”. The Company identified an error related to the adoption of Canadian Handbook Section 3031, “Inventories” in fiscal 2009. The change in accounting policy was accounted for on a retrospective basis, without restatement of prior periods under Canadian GAAP resulting in a decrease to deficit of $991, net of taxes of $392, to reverse a tire impairment recorded in fiscal 2008. This decrease in deficit should have been adjusted for in the reconciliation to U.S. GAAP as the tire impairment should not have been recorded in fiscal 2008 under U.S. GAAP. As a result of this error, net income under U.S. GAAP for fiscal 2008 increased by $991 and the deficit under U.S. GAAP as of March 31, 2008 decreased by $991;

(ii) Reclassification of accrued liabilities. The financial statements for fiscal 2009 have been amended to correct a classification error with respect to accrued liabilities identified during the preparation of the Company’s fiscal 2010 consolidated financial statements. Certain operating lease agreements provide a maximum hourly usage limit,

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  13

above which the Company will be required to pay for the over hour usage. These contingent rentals are recognized when payment is considered probable and are due at the end of the lease term. The Company has historically classified the contingent rentals as a current liability; however, certain of the amounts are due beyond one year from the balance sheet date. In the current year, the Company has reclassified amounts due beyond one year, from the balance sheet date, as a long term liability and has reclassified comparative figures accordingly. The amount reclassified on the Consolidated Balance Sheet was $7,134 as at March 31, 2009;

(iii) Buy-out of leased assets. The financial statements for fiscal 2008 have been amended under U.S. GAAP to correct an error related to the method of accounting for an incentive at the time of buying a previously leased asset, which was identified during the preparation of the Company’s fiscal 2010 consolidated financial statements. When an asset is leased under an operating lease agreement, as stated in the paragraph above, contingent rentals are recognized when payment is considered probable and are due at the end of the lease term. The Company can buy the asset at the end of the lease term at a pre-determined market price at which point the liability is extinguished since the lease agreement is cancelled. The Company has been traditionally extinguishing the liability for such lease buyouts by reducing equipment costs related to leased equipment, instead of considering the extinguishment of the liability as an incentive to purchase the asset and therefore reducing the cost of the asset. The correction of this error increased “Equipment costs” by $2,700, reduced “Depreciation” by $120, reduced “Deferred income taxes” by $774 and reduced “Net income and comprehensive income for the year” by $1,806 from the amounts originally reported in the Consolidated Statements of Operations and Comprehensive Income for the year ended March 31, 2008. It also reduced “Property, plant and equipment” by $2,580, reduced long term “Deferred tax liabilities” by $774 and increased “Deficit” for the year by $1,806 from the amounts originally reported in the Consolidated Balance Sheet as at March 31, 2008. The financial statements for fiscal 2009 have also been amended under U.S. GAAP to correct an error related to the method of accounting for an incentive at time of buying a previously leased asset, which was identified during the preparation of the Company’s fiscal 2010 consolidated financial statements as stated above. The correction of this error increased “Equipment costs” by $6,600, reduced “Depreciation” by $600, reduced “Deferred income taxes” by $1,800 and increased “Net loss and comprehensive loss for the year” by $4,200 from the amounts originally reported in the Consolidated Statements of Operations and Comprehensive Income (Loss) for the year ended March 31, 2009. It also reduced “Property, plant and equipment” by $8,580, reduced long term “Deferred tax liabilities” by $2,574 and increased “Deficit” for the year by $6,006 from the amounts originally reported in the Consolidated Balance Sheet as at March 31, 2009.

(iv) Valuation of derivative financial instruments. The financial statements for fiscal 2009 have also been amended under U.S. GAAP to correct an error related to the determination of the fair value of the cross-currency and interest rate swap liabilities (collectively, the “swap liability”) which was identified on settlement of the swap liability on April 8, 2010. The Company recorded the fair value of the swap liability and in addition recorded accrued interest on the swap liability. This resulted in the swap liability being misstated and the changes in the fair value of the swap liability being misstated by the change in the amount of the accrued interest at each reporting period from March 31, 2009. The periods before March 31, 2009 were not materially impacted because prior to February 2, 2009, the U.S. Dollar interest rate swap was still in place (note 24(c)(ii)), and therefore the net accrued interest payable under the swap liability was not material. The error increased “Realized and unrealized gain on derivative financial instruments” by $7,514, increased income tax expense by $1,676 and reduced net loss by $5,838 from amounts originally reported in the Consolidated Statements of Operations and Comprehensive Income (loss) for the year ended March 31, 2009. It also reduced “Derivative financial instruments” by $7,514, increased long term “Deferred tax liabilities” by $1,676 and reduced “Deficit” by $5,838 in the Consolidated Balance Sheet as at March 31, 2009.

The impact of the above corrections under U.S. GAAP on the Consolidated Statements of Operations and Comprehensive Income (Loss) for the years ended March 31, 2009 and March 31, 2008 are as follows:

For the year ended March 31, 2009	As previously reported		Adjustments		As amended
Equipment costs	$210,520		$6,600		$217,120
Depreciation	36,989		(600	)	36,389
Realized and unrealized gain on derivative financial instruments	$(29,736	)	$(7,514	)	$(37,250	)
Deferred income taxes	9,211		(124	)	9,087
Net loss and comprehensive loss for the year	(137,042	)	1,638		(135,404	)
Deficit, end of year	(157,937	)	(168	)	(158,105	)
Net loss per share – basic	$(3.80	)	$0.04		$(3.76	)
Net loss per share – diluted	$(3.80	)	$0.04		$(3.76	)

14  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

For the year ended March 31, 2008	As previously reported		Adjustments		As amended
Equipment costs	$174,873		$1,317		$176,190
Depreciation	35,840		(120	)	35,720
Deferred income taxes	17,418		(382	)	17,036
Net income and comprehensive income for the year	42,349		(815	)	41,534
Deficit, end of year	(21,886	)	(815	)	(22,701	)
Net income per share – basic	$1.18		$(0.02	)	$1.16
Net income per share – diluted	$1.15		$(0.02	)	$1.13

The impact of the above corrections under U.S. GAAP on the Consolidated Balance Sheets as at March 31, 2009 is as follows:

March 31, 2009	As previously reported		Adjustments		As amended
Property, plant and equipment	$324,695		$(8,580	)	$316,115
Accrued liabilities	52,135		(7,134	)	45,001
Long term accrued liabilities	–		7,134		7,134
Derivative financial instruments	50,562		(7,514	)	43,048
Deferred tax liabilities	31,643		(898	)	30,745
Deficit, end of period	(157,937	)	(168	)	(158,105	)

The impact of the above corrections under U.S. GAAP on the Consolidated Statements of Cash Flows for the years ended March 31, 2009 and March 31, 2008 are as follows:

For the year ended March 31, 2009	As previously reported		Adjustments		As amended
Net loss for the year	$(137,042	)	$1,638		$(135,404	)
Depreciation	36,989		(600	)	36,389
Unrealized gain on derivative financial instruments measured at fair value	(32,407	)	(7,514	)	(39,921	)
Deferred income taxes	9,211		(124	)	9,087
Cash flow from operating activities	157,785		(6,600	)	151,185
Purchase of property, plant and equipment	(91,037	)	6,600		(84,437	)
Cash flow from investing activities	(85,315	)	6,600		(78,715	)

For the year ended March 31, 2008	As previously reported		Adjustments		As amended
Net income for the year	$42,349		$(815	)	$41,534
Depreciation	35,840		(120	)	35,720
Deferred income taxes	17,418		(382	)	17,036
Write-down of other assets to replacement cost	1,383		(1,383	)	0
Cash flow from operating activities	97,497		(2,700	)	94,797
Purchase of property, plant and equipment	(55,505	)	2,700		(52,805	)
Cash flow from investing activities	(48,632	)	2,700		(45,932	)

bb) United States accounting pronouncements recently adopted

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

In June 2009, the Financial Accounting Standards Board (FASB) issued the FASB Accounting Standards Codification (ASC) 105. The ASC amended the hierarchy of generally accepted accounting principles (GAAP) such that the ASC became the single source of authoritative nongovernmental U.S. GAAP, except for SEC rules and interpretative releases which, for the Company, are also authoritative U.S. GAAP. The ASC did not change current U.S. GAAP, but was intended to simplify user access to all authoritative U.S. GAAP by providing all the authoritative literature related to a particular topic in one place. All previously existing accounting standard documents were superseded and all other accounting literature not included in the ASC is considered non-authoritative. The ASC identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements in accordance with U.S. GAAP. The Company adopted this standard during the quarter ended September 30, 2009.

ii) Fair value measurements

In September 2006, the FASB issued an accounting standard codified in ASC 820, “Fair Value Measurements and Disclosures”. This standard established a single definition of fair value and a framework for measuring fair value, set out a fair value hierarchy to be used to classify the source of information used in fair value measurements, and required disclosures of assets and liabilities measured at fair value based on their level in the hierarchy. This standard applies under other accounting standards that require or permit fair value measurements. One of the amendments deferred the

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  15

effective date for one year relative to nonfinancial assets and liabilities that are measured at fair value, but are recognized or disclosed at fair value on a nonrecurring basis. This deferral applied to such items as nonfinancial assets and liabilities initially measured at fair value in a business combination (but not measured at fair value in subsequent periods) or nonfinancial long-lived asset groups measured at fair value for an impairment assessment. These remaining aspects of the fair value measurement standard were adopted by the Company prospectively beginning April 1, 2009. Refer to Note 24(a) for additional disclosures of assets and liabilities that are measured at fair value on a non-recurring basis as a result of this adoption.

iii) Business combinations

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS 141(R)”), and, in April 2009, issued FAS 141 (R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies”, to amend and clarify SFAS No. 141(R), “Business Combinations”, now part of ASC 805, “Business Combinations”. Effective for the Company beginning on April 1, 2009, the standard establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree, and any goodwill and establishes disclosure requirements that enable users of the Company’s financial statements to evaluate the nature and financial effects of the business combination. This new standard was applied to the acquisition of DF Investments Limited and its subsidiary Drillco Foundation Co. Ltd. (note 5(a)).

iv) Non-controlling interests in consolidated financial statements

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

v) Determination of the useful life of intangible assets

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

vi) Equity method investment accounting considerations

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

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

In April 2009, the FASB issued FSP No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”. The guidance, now part of ASC 820, “Fair Value Measurements and Disclosures”, provides additional guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased. It also includes guidance on identifying circumstances that indicate a transaction is not orderly. The Company adopted this standard effective April 1, 2009. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

16  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

viii) Subsequent events

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

ix) Measuring liabilities at fair value

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

x) Accounting and reporting for decreases in ownership of a subsidiary

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

xi) Equity

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

xii) Improving disclosures about fair value measurements

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

cc) Recent United States accounting pronouncements not yet adopted

i) Revenue recognition

In October 2009, the FASB issued ASU No. 2009-13, “Revenue Recognition: Multiple-Deliverable Revenue Arrangements”, which addresses the accounting for multiple-deliverable arrangements to enable vendors to account for products or services separately rather than as a combined unit. The amendments establish a selling price hierarchy for determining the selling price of a deliverable. The amendments also eliminate the residual method of allocation and require that arrangement consideration be allocated at the inception of the arrangement to all deliverables using the relative selling price method. For the Company, this ASU is effective prospectively for revenue arrangements entered into or materially modified on or after April 1, 2011. The Company is currently evaluating the impact of this ASU on its consolidated financial statements.

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  17

ii) Improvements to financial reporting by enterprises involved with variable interest entities

In December 2009, the FASB issued ASU No. 2009-17, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities”, which amends ASC 810, “Consolidation”. The amendments give guidance and clarification of how to determine when a reporting entity should include the assets, liabilities, non-controlling interests and results of activities of a variable interest entity in its consolidated financial statements. The amendments in this ASU are effective for the Company beginning on April 1, 2010. The Company is currently evaluating the impact of this ASU on its consolidated financial statements.

iii) Embedded credit derivatives

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

iv) Share based payment awards

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

4. Goodwill

In accordance with the Company’s accounting policy, a goodwill impairment test is completed annually on October 1 of each fiscal year or whenever events or changes in circumstances indicate that impairment may exist. The Company conducted its annual goodwill impairment test on October 1, 2009 and concluded that there was no goodwill impairment as the fair value of the Piling reporting unit exceeded its carrying value. There have been no triggering events between October 1, 2009 and March 31, 2010.

For the year ended March 31, 2009, the Company conducted its annual goodwill impairment test on October 1, 2008 and concluded that the fair value of each of its reporting units exceeded its carrying amount. However, at December 31, 2008 and at March 31, 2009, based on adverse changes in the Company’s principal markets, the decline in the Company’s market capitalization and updated long term financial forecasts, which resulted in lower near-term and longer-term revenues and cash flows for each reporting unit, the Company concluded that an interim test for impairment of goodwill was appropriate.

In performing the goodwill assessment at December 31, 2008, the Company considered discounted cash flows, market capitalization and other factors, including observable market data to determine the fair value of each reporting unit. Although implied market comparable valuation multiples and transaction premiums were considered in the analysis, there were significant differences in the products, services, and operating characteristics of the reporting units as compared to a set of selected comparable companies. As a result, the Company relied primarily on the discounted cash flow method, using management projections for each reporting unit and risk-adjusted discount rates to determine fair value. Expected cash flows of each of the reporting units were discounted using estimated discount rates ranging from 18.0% to 27.0% to calculate fair value and a terminal growth rate of 3.0% was used. Based on this analysis, the Company concluded that the carrying value of the Pipeline Operating Segment (also a separate reporting unit) exceeded its fair value and the Company recorded an impairment charge of $32,753, calculated as the difference between the carrying value of goodwill of the Pipeline Operating Segment and the implied fair value of the Pipeline Operating Segment of $nil at December 31, 2008.

During the three months ended March 31, 2009, the Company observed further deterioration in industry conditions, global economic and credit conditions. The economic environment had impacted the Company’s ability to forecast future demand and in turn resulted in the use of higher discounts rates, reflecting the risk and uncertainty in the current market. Furthermore, the Company experienced a significant and sustained quarter over quarter decline in its operating results due primarily to challenging market conditions. As a result, the Company concluded that events had occurred and circumstances had changed that required it to perform an additional interim goodwill impairment test for the Heavy Construction and Mining and Piling Operating Segments (also separate reporting units) as at March 31, 2009, which was corroborated by a combination of factors including a significant and sustained decline in the Company’s market capitalization, which was significantly below its book value, and a deteriorating environment, which resulted in a decline in expected future demand.

18  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

As part of the March 31, 2009 goodwill impairment test, the Company updated its discounted cash flow (“DCF”) analysis for the Heavy Construction and Mining and Piling reporting segments using estimated discount rates ranging from 22.0% to 32.0% and a decreased terminal growth rate of 2.5% to calculate fair value. The Company also updated its forecasted cash flows. These updates were based on the economic volatility experienced during the three months ended March 31, 2009 and considered management’s view of economic conditions and trends, estimated future operating results, sector growth rates, anticipated future economic conditions and the Company’s strategic alternatives to respond to these conditions. Although implied market comparable valuation multiples and transaction premiums were considered in the analysis, there are significant differences in the products, services and operating characteristics of the reporting units as compared to a set of selected comparable companies. The fair value utilizing the DCF model was determined to be reasonable when compared to the market capitalization at the end of the year plus a reasonable control premium. The process of determining fair value is subjective and requires management to exercise a significant amount of judgment in determining future growth rates, discount and tax rates and other factors.

As a result of this analysis, the Company concluded that the carrying value of the Heavy Construction and Mining and Piling reporting units exceeded their fair value and the Company recorded an impairment charge of $125,447 and $18,000 respectively, calculated as the difference between the carrying value of goodwill of the Heavy Construction and Mining reporting unit of $125,447 and of the Piling reporting unit of $46,372 and the implied fair value of goodwill at March 31, 2009 of $nil for the Heavy Construction and Mining reporting unit and $28,372 for the Piling reporting unit.

The implied fair value of goodwill was determined in the same manner as the value of goodwill is determined in a business combination. The impairment charge is included in the caption “Impairment of goodwill” in the Consolidated Statements of Operations and Comprehensive Income (Loss) for the year ended March 31, 2009.

There was no goodwill impairment recorded for the years ended March 31, 2008 and March 31, 2010.

The change in goodwill during the years ended March 31, 2010 and 2009 are as follows:

Balance at March 31, 2008	$200,072
Impairment of goodwill (assigned to the Pipeline segment)	(32,753	)
Impairment of goodwill (assigned to the Heavy Construction and Mining segment)	(125,447	)
Impairment of goodwill (assigned to the Piling segment)	(18,000	)
Balance at March 31, 2009	$23,872
Acquisition of goodwill (assigned to the Piling segment) (note 5(a))	1,239
Balance at March 31, 2010	$25,111

5. Acquisitions

a) Acquisitions in fiscal 2010

On August 1, 2009, the Company acquired all of the issued and outstanding shares of DF Investments Limited (the holding company) and its subsidiary Drillco Foundation Co. Ltd., a piling company based in Milton, Ontario, for a consideration of $5,410. This acquisition gives the Company access to piling markets and customers in the Toronto area. The transaction has been accounted for using the acquisition method with the results of operations included in the financial statements from the date of acquisition. The goodwill acquired is not deductible for tax purposes. The purchase price allocation is as follows:

Accounts receivable	$4,101
Inventories	59
Prepaid expenses and deposits	11
Property, plant and equipment	2,873
Land	281
Intangible assets	547
Goodwill (assigned to the Piling segment)	1,239
Accounts payable and accrued liabilities	(2,211	)
Deferred tax liabilities	(838	)
Long term debt	(652	)
	$5,410

The amount of revenue and net loss since acquisition on August 1, 2009 included in the Consolidated Statements of Operations and Comprehensive Income (Loss) for the year ended March 31, 2010 are $4,158 and $(2,287) respectively.

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  19

b) Acquisitions in fiscal 2009

The Company did not acquire any businesses in fiscal 2009.

c) Acquisitions in fiscal 2008

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 was accounted for using 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 was as follows:

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

6. Accounts receivable

	March 31, 2010		March 31, 2009
Accounts receivable – trade	$103,067		$67,123
Accounts receivable – holdbacks	3,899		9,376
Income and other taxes receivable	4,486		2,651
Accounts receivable – other	2,123		1,770
Allowance for doubtful accounts (note 24(d))	(1,691	)	(2,597	)
	$111,884		$78,323

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.

7. Costs incurred and estimated earnings net of billings on uncompleted contracts

	March 31, 2010		March 31, 2009
Costs incurred and estimated earnings on uncompleted contracts	$1,193,821		$955,763
Less billings to date	(1,110,733	)	(902,011	)
	$83,088		$53,752

Costs incurred and estimated earnings net of billings on uncompleted contracts is presented in the Consolidated Balance Sheets under the following captions:

	March 31, 2010		March 31, 2009
Unbilled revenue	$84,702		$55,907
Billings in excess of costs incurred and estimated earnings on uncompleted contracts	(1,614	)	(2,155	)
	$83,088		$53,752

8. Inventories

	March 31, 2010	March 31, 2009
Spare tires	$1,868	$10,533
Job materials and other	3,791	1,281
	$5,659	$11,814

9. Prepaid expenses and deposits

Current:

	March 31, 2010	March 31, 2009
Prepaid insurance and property taxes	$1,203	$1,535
Prepaid lease payments	5,678	3,246
	$6,881	$4,781

20  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

Long term:

	March 31, 2010	March 31, 2009
Prepaid lease payments	4,005	3,504

10. Assets held for sale

Equipment disposal decisions are made using an approach in which a target is set for each type of equipment. The target life is based on the manufacturer’s recommendations and the Company’s past experience in the various operating environments. Once a piece of equipment reaches its target life it is evaluated to determine if disposal is warranted based on its expected operating cost and reliability in its current state. If the expected operating cost exceeds the average operating cost for the fleet, the unit is deemed ready for disposal. Also if the expected reliability is lower than the average reliability of the fleet, the unit is deemed ready for disposal. If either of these conditions is met the unit is disposed. Expected operating costs and reliability are based on the past history of the unit and experience in the various operating environments. Assets held for sale are sold on the Company’s used equipment website and syndicated on third party equipment sale websites. If a sale is not realized after a reasonable length of time, the equipment will be sent to auction for disposal.

During the year ended March 31, 2010, impairments of assets held for sale amounting to $806 have been included in depreciation expense in the Consolidated Statements of Operations and Comprehensive Income (Loss) (2009 – $883; 2008 – $1,564). The impairment charge is the amount by which the carrying value of the related assets exceeded their fair value less costs to sell. Included in depreciation expense for the year ended March 31, 2010, is a loss on disposal of assets held for sale of $373 (2009 – $24; 2008 – $493) relating to the decision to dispose of heavy construction assets held by the Heavy Construction & Mining segment.

11. Property, plant and equipment

March 31, 2010	Cost	Accumulated Depreciation	Net Book Value
Heavy equipment	$339,312	$95,473	$243,839
Major component parts in use	33,452	8,297	25,155
Other equipment	25,666	10,910	14,756
Licensed motor vehicles	16,296	10,692	5,604
Office and computer equipment	9,746	3,786	5,960
Buildings	21,710	6,832	14,878
Land	281	–	281
Leasehold improvements	9,314	2,960	6,354
Assets under capital lease	24,304	12,388	11,916
	$480,081	$151,338	$328,743

March 31, 2009	Cost	Accumulated Depreciation	Net Book Value
Heavy equipment	$310,406	$75,410	$234,996
Major component parts in use	25,187	2,535	22,652
Other equipment	22,056	8,268	13,788
Licensed motor vehicles	12,760	7,445	5,315
Office and computer equipment	6,759	3,459	3,300
Buildings	20,823	5,308	15,515
Leasehold improvements	6,589	1,929	4,660
Assets under capital lease	27,953	12,064	15,889
	$432,533	$116,418	$316,115

During the year ended March 31, 2010, additions to property, plant and equipment included $1,523 of assets that were acquired by means of capital leases (2009 – $8,863; 2008 – $8,829). Depreciation of equipment under capital lease of $4,081 (2009 – $5,138; 2008 – $2,928) was included in depreciation expense.

12. Intangible assets

March 31, 2010	Cost	Accumulated Amortization	Net Book Value
Customer contracts in progress and related relationships	$624	$329	$295
Other intangible assets	915	531	384
Internal-use software	10,721	3,731	6,990
	$12,260	$4,591	$7,669

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  21

March 31, 2009	Cost	Accumulated Amortization	Net Book Value
Customer contracts in progress and related relationships	$340	$260	$80
Other intangible assets	721	527	194
Internal-use software	7,855	2,185	5,670
	$8,916	$2,972	$5,944

During the year ended March 31, 2010, the Company capitalized $3,362 (2009 – $3,102) related to the development of internally developed computer software. Internal-use software with a cost of $496 and accumulated amortization of $288 were written off and the net book value of $208 was included in amortization of intangible assets during the year ended March 31, 2010.

Amortization of intangible assets for the year ended March 31, 2010 was $1,719 (2009 – $1,501; 2008 – $804).The estimated amortization expense for future years is as follows:

For the year ending March 31,
2011	$2,720
2012	2,405
2013	1,651
2014	824
2015 and thereafter	69
	$7,669

During the year ended March 31, 2010, $547 in additions were made to intangible assets as a result of the acquisition of DF Investments Limited and its subsidiary, Drillco Foundation Co. Ltd. (note 5(a)).

13. Deferred financing costs

March 31, 2010	Cost	Accumulated Amortization	Net Book Value
Senior notes	$16,521	$12,014	$4,507
Term Facility and Revolving Facility	4,328	3,150	1,178
9.125% debentures	1,040	–	1,040
	$21,889	$15,164	$6,725

March 31, 2009	Cost	Accumulated Amortization	Net Book Value
Senior notes	$16,521	$9,613	$6,908
Term Facility and Revolving Facility	3,205	2,203	1,002
	$19,726	$11,816	$7,910

Amortization of deferred financing costs included in interest expense for the year ended March 31, 2010 was $3,348 (2009 – $2,970; 2008 – $2,899).

During the year ended March 31, 2010, financing fees totalling $1,123 (2009 – $nil; 2008 – $776) paid in connection with an amendment of the Revolving Facility (note 18(a)) were recorded as deferred financing costs.

During the year ended March 31, 2010, financing fees totalling $1,040 were incurred and accrued in connection with the 9.125% Debenture issuance subsequent to year-end (note 33).

14. Investment in and advances to unconsolidated joint venture

The Company is engaged in one joint venture, “Noramac Ventures Inc.”. The joint venture is with Fort McKay Construction Ltd. and was formed for the purpose of expanding the Company’s market opportunities and establishing strategic alliances in Northern Alberta. The Company has a 50% proportionate interest in the Noramac Joint Venture.

As of March 31, 2010, the Company’s investment in and advances to unconsolidated joint venture totaled $2,917 (March 31, 2009 – $nil). Condensed financial data as at and for the year ended March 31, 2010 is as follows:

	March 31, 2010
Current assets	$8,952
Long term assets	153
Current liabilities	3,271
Long term liabilities	5,940

22  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

Year ended March 31,	2010
Gross revenues	$8,774
Gross profit	1,610
Net income	87
Equity in earnings of unconsolidated joint venture	$44

15. 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.

	March 31, 2010		March 31, 2009
Balance, beginning of year	$836		$941
Additions	32		–
Amortization of deferred lease inducements	(107	)	(105	)
Balance, end of year	$761		$836

16. Accrued liabilities

Current

Current	March 31, 2010	March 31, 2009
Accrued interest payable	$14,725	$16,022
Payroll liabilities	21,741	15,083
Liabilities related to equipment leases	4,720	5,047
Income and other taxes payable	6,005	8,849
	$47,191	$45,001

Long term

	March 31, 2010	March 31, 2009
Long term liabilities related to equipment leases	14,943	7,134

17. 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:

2011	$5,734
2012	5,209
2013	2,987
2014	462
2015	169
Subtotal:	$14,561
Less: amount representing interest – weighted average interest rate of 8.7%	(1,168	)
Present value of minimum lease payments	$13,393
Less: current portion	(5,053	)
Long term portion	$8,340

18. Debt

a) Long term debt

On June 24, 2009, the Company entered into an amended and restated credit agreement which matures on June 8, 2011 to provide for borrowings of up to $125.0 million under which revolving loans, term loans and letters of credit may be issued. This facility includes a $75.0 million Revolving Facility and a $50.0 million Term Facility. The Term Facility commitments were available until August 31, 2009 and aggregate borrowings under this facility had to exceed $25.0 million. Any undrawn amount under the Term Facility, up to a maximum of $15.0 million, could be reallocated to the Revolving Facility. On August 31, 2009, the maximum undrawn portion of the Term Facility totaling $15.0 million was reallocated to the Revolving Facility resulting in Revolving Facility commitments of $90.0 million.

As of March 31, 2010, the Company had issued $10.4 million (March 31, 2009 – $20.8 million) in letters of credit under the Revolving Facility to support performance guarantees associated with customer contracts. The total credit

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  23

facility commitments are $118.4 million at March 31, 2010 and include the $90.0 million Revolving Facility and the outstanding borrowings of $28.4 million, (March 31, 2009 – $nil) under the Term Facility after mandatory principal repayments of $4.6 million in the year. The funds available under the Revolving Facility are reduced by any outstanding letters of credit. The Company’s unused borrowing availability under the Revolving Facility was $79.6 million at March 31, 2010.

Borrowings under the Revolving Facility may be repaid and borrowed from time to time at the option of the Company. The Term Facility is fully utilized and requires quarterly principal repayments. At March 31, 2010, there were no borrowings under the Revolving Facility.

Beginning September 30, 2009, and at the end of each fiscal quarter thereafter, the Company must make quarterly repayments on the Term Facility of $1,518 through June 2011, with the balance due at that time. The credit facility bears interest at Canadian prime rate, U.S. Dollar Base Rate, Canadian bankers’ acceptance rate or London interbank offered rate (LIBOR) (all such terms as used or defined in the credit facility), plus applicable margins. In each case, the applicable pricing margin depends on the Company’s credit rating.

The credit facility is secured by a first priority lien on substantially all of 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 credit agreement and was in compliance with these covenants at March 31, 2010.

Financing fees of $1,123 paid in connection with an amendment of the Revolving Facility was recorded during the year ended March 31, 2010 (March 31, 2009 – $nil, 2008 – $776). These fees have been recorded as deferred financing costs (note 13).

During the year ended March 31, 2010, the Company extinguished $652 of long term debt acquired through its August 1, 2009 acquisition of DF Investments Limited and its subsidiary Drillco Foundations Co. Ltd. (note 5(a)).

b) Senior notes

	March 31, 2010	March 31, 2009
8  3/4% senior unsecured notes due 2011 ($U.S.)	$200,000	$200,000
Unrealized foreign exchange	3,120	52,040
Fair value of embedded early redemption option (note 24(a))	–	3,716
	$203,120	$255,756

The 8 ³/4% senior notes were issued on November 26, 2003 in the amount of U.S. $200.0 million (Canadian $263.0 million). These notes mature on December 1, 2011 with interest payable semi-annually on June 1 and December 1 of each year.

The 8 ³/4% senior notes are unsecured senior obligations and rank equally with all other existing and future unsecured senior debt and senior to any subordinated debt that may be issued by the Company or any of its subsidiaries. The notes are effectively subordinated to all secured debt to the extent of the outstanding amount of such debt.

The 8 ³/4% senior notes are redeemable at the option of the Company, in whole or in part, at any time on or after December 1, 2009 at 100% of the principal amount plus interest accrued to the redemption date.

If a change of control occurs, the Company will be required to offer to purchase all or a portion of each holder’s 8 ³/4% senior notes, at a purchase price in cash equal to 101% of the principal amount of the notes offered for repurchase plus accrued interest to the date of purchase.

In March 2010, the Company elected to redeem all the outstanding 8 ³/4% senior notes. In accordance with the terms of the 8 ³/4% senior notes, the Company will redeem them at 100% of the principal amount plus interest accrued to the redemption date of April 28, 2010. The Company financed the repayment of the 8 ³/4% senior notes by issuing a new long term obligation subsequent to year-end (note 33) and therefore; has continued to classify the 8 ³/4% senior notes as a long term obligation.

19. Asset retirement obligation

The Company recorded an asset retirement obligation related to the future retirement of a facility on leased land. Accretion expense associated with this obligation is included in equipment costs in the Consolidated Statements of Operations and Comprehensive Income (Loss).

24  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

The following table presents a continuity of the liability for the asset retirement obligation:

Balance at March 31, 2008	$–
Obligation relating to the future retirement of a facility on leased land	231
Accretion expense	155
Balance at March 31, 2009	$386
Obligation relating to the future retirement of a facility on leased land	(31	)
Accretion expense	5
Balance at March 31, 2010	$360

At March 31, 2010, estimated undiscounted cash flows required to settle the obligation were $1,084. The credit adjusted risk-free rate assumed in measuring the asset retirement obligation was 9.42%. The Company expects to settle this obligation in 2021.

20. Income taxes

Income tax provision (recovery) differs from the amount that would be computed by applying the Federal and Provincial statutory income tax rates to income before income taxes. The reasons for the differences are as follows:

Year ended March 31,	2010		2009		2008
Income (loss) before income taxes statutory	$41,898		$(120,771)		$58,650
Tax rate	28.91%		29.38%		31.47%
Expected provision (recovery) at statutory tax rate	$12,113		$(35,483)		$18,457
Decrease related to:
Impact of enacted future statutory income tax rates	(673	)	(1,005	)	(1,287	)
Income tax adjustments and reassessments	1,442		–		–
Impairment of goodwill	–		51,767		–
Other	797		(646	)	(54	)
Income tax provision	$13,679		$14,633		$17,116

Classified as:

Year ended March 31,	2010	2009	2008
Current income taxes	$3,803	$5,546	$80
Deferred income taxes	9,876	9,087	17,036
	$13,679	$14,633	$17,116

	March 31, 2010	March 31, 2009
Deferred tax assets:
Non-capital losses carried forward	$2,205	$2,867
Deferred financing costs	12	–
Derivative financial instruments and senior notes	8,892	13,813
Billings in excess of costs on uncompleted contracts	448	620
Capital lease obligations	3,692	4,961
Intangible assets	104	–
Long term over hour accrual	1,965	360
Deferred lease inducements	199	214
Other	370	420
DSU/DPSU/RSU compensation costs	894	105
	$18,781	$23,360

	March 31, 2010	March 31, 2009
Deferred tax liabilities:
Unbilled revenue and uncertified revenue included in accounts receivable	$15,975	$7,081
Assets held for sale	233	794
Accounts receivable – holdbacks	1,083	2,696
Property, plant and equipment	31,234	30,856
Deferred financing costs	–	950
Intangible assets	–	12
	48,525	42,389
Net deferred income taxes	$(29,744)	$(19,029)

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  25

Classified as:

	March 31, 2010		March 31, 2009
Current asset	$3,481		$7,033
Long term asset	10,997		12,432
Current liability	(16,781	)	(7,749	)
Long term liability	(27,441	)	(30,745	)
	$(29,744)		$(19,029)

The Company and its subsidiaries file income tax returns in the Canadian federal jurisdiction, and several provincial jurisdictions. For years before 2006, the Company is no longer subject to Canadian federal or provincial examinations.

The Company has no unrecognized tax benefits as at March 31, 2010 or March 31, 2009. At March 31, 2010, the Company has non-capital losses for income tax purposes of $7,913 which expire as follows and are expected to be fully used in 2011.

2015	$11
2026	3
2027	3,095
2029	464
2030	4,340
	$7,913

21. Shares

a) Common shares

Authorized:

Unlimited number of common voting shares

Unlimited number of common non-voting shares

Issued and outstanding:

	Number of Shares		Amount
Common voting shares
Issued and outstanding at March 31, 2007	35,192,260		$297,594
Issued upon exercise of stock options	324,816		1,627
Transferred from additional paid-in capital 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		$301,894
Issued upon exercise of stock options	109,000		703
Transferred from additional paid-in capital on exercise of stock options	–		834
Issued and outstanding at March 31, 2009	36,038,476		$303,431
Issued upon exercise of stock options	10,800		53
Transferred from additional paid-in capital on exercise of stock options	–		21
Issued and outstanding at March 31, 2010	36,049,276		$303,505
Common non-voting shares
Issued and outstanding at March 31, 2007	412,400		$2,062
Conversion to common voting shares	(412,400	)	(2,062	)
Issued and outstanding at March 31, 2010, 2009 and 2008	–		$–

26  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

b) Additional paid-in capital

Balance at March 31, 2007	$3,606
Stock-based compensation (note 30(a))	1,937
Transferred to common shares on exercise of stock options	(611	)
Cash settlement of stock options	(581	)
Balance at March 31, 2008	$4,351
Stock-based compensation (note 30(a))	1,888
Deferred performance share unit plan (note 30(b))	61
Transferred to common shares on exercise of stock options	(834	)
Balance at March 31, 2009	$5,466
Stock-based compensation (note 30(a))	2,135
Deferred performance share unit plan (note 30(b))	123
Reclassified to restricted share unit liability (note 30(c))	(20	)
Transferred to common shares on exercise of stock options	(21	)
Cash settlement of stock options	(244	)
Balance at March 31, 2010	$7,439

c) Net income (loss) per share

Year ended March 31,	2010	2009		2008
Net income (loss) available to common shareholders	$28,219	$(135,404	)	$41,534
Weighted average number of common shares	36,040,857	36,020,763		35,788,776
Basic net income (loss) per share	$0.78	$(3.76	)	$1.16

Year ended March 31,	2010	2009		2008
Net income (loss) available to common shareholders	$28,219	$(135,404	)	$41,534
Weighted average number of common shares	36,040,857	36,020,763		35,788,776
Dilutive effect of stock options and performance units	680,169	–		1,126,859
Weighted average number of diluted common shares	36,721,026	36,020,763		36,915,635
Diluted net income (loss) per share	$0.77	$(3.76	)	$1.13

For the year ended March 31, 2010, there were 820,641 and 57,311 options and performance units respectively which were anti-dilutive and therefore were not considered in computing diluted earnings per share (March 31, 2009 – 2,071,884 and 91,005; March 31, 2008 – 283,674 and nil options and performance units respectively).

For the year ended March 31, 2009, the effect of outstanding stock options on net loss per share was anti-dilutive. As such, the effect of outstanding stock options used to calculate the diluted net loss per share was not disclosed.

22. Interest expense

Year ended March 31,	2010	2009		2008
Interest expense on 8 3/4% senior notes and swaps	$19,041	$25,379		$23,338
Interest on capital lease obligations	1,032	1,234		780
Amortization of deferred financing costs	3,348	2,970		2,899
Interest on credit facility	2,375	298		769
Interest on long term debt	$25,796	$29,881		$27,786
Other interest	284	(269	)	1,294
	$26,080	$29,612		$29,080

23. Claims Revenue

Year ended March 31,	2010	2009	2008
Claims revenue recognized	$4,541	$55,999	$–
Claims revenue uncollected (classified as unbilled revenue)	$785	$1,768	$3,124

24. Financial instruments and risk management

a) Fair value of 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

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  27

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.

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 values of amounts due under the Revolving Facility and the Term Facility 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 instruments with similar terms. Based on these estimates and by using the outstanding balance of $28.4 million at March 31, 2010 and $nil at March 31, 2009, the fair value of amounts due under the Revolving Facility and the Term Facility as at March 31, 2010 and March 31, 2009 are not significantly different than their carrying value.

The fair values of the Company’s cross-currency and interest rate swap agreements and the Company’s embedded derivatives are based on appropriate price modeling commonly used by market participants to estimate fair value. Such modeling includes option pricing models and discounted cash flow analysis, using observable market based inputs to estimate fair value. Fair value determined using valuation models requires the use of assumptions concerning the amount and timing of future cash flows. Fair value amounts reflect management’s best estimates using external readily observable market data such as future prices, interest rate yield curves, foreign exchange rates and discount rates for time value. It is possible that the assumptions used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be material.

Financial instruments with carrying amounts that differ from their fair values are as follows:

	March 31, 2010		March 31, 2009
	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Senior notes (i)	$203,120	$203,526	$255,756	$181,469
Capital lease obligations (ii)	13,393	13,291	17,484	17,345

(i) The fair value of the U.S. Dollar denominated 8 ³/4% senior notes is based upon their period end closing market price translated into Canadian Dollars at period end exchange rates as at March 31, 2010 and March 31, 2009.

(ii) The fair values of amounts due under capital leases are based on management estimates which are determined by discounting cash flows required under the instruments at the interest rates currently estimated to be available for instruments with similar terms.

Derivative financial instruments that are used for risk management purposes, as described in note 24(b) under – Risk Management consist of the following:

March 31, 2010	Derivative Financial Instruments		Senior Notes
Cross-currency and interest rate swaps	$81,111		$–
Embedded price escalation features in a long term revenue construction contract	6,481		–
Embedded price escalation features in certain long term supplier contracts	9,463		–
Total fair value of derivative financial instruments	$97,055		$–
Less: current portion	(22,054	)	–
	$75,001		$–

March 31, 2009	Derivative Financial Instruments		Senior Notes
Cross-currency and interest rate swaps	$32,033		$–
Embedded price escalation features in a long term revenue construction contract	(324	)	–
Embedded price escalation features in certain long term supplier contracts	22,778		–
Embedded early redemption option on senior notes	–		3,716
Total fair value of derivative financial instruments	$54,487		$3,716
Less: current portion	(11,439	)	–
	$43,048		$3,716

Fair value hierarchy of financial instruments

The Company has segregated all financial assets and financial liabilities that are measured at fair value on a recurring basis into the most appropriate level within the fair value hierarchy based on the inputs used to determine the fair value at the measurement date. Effective April 1, 2009, the Company adopted the remaining aspects of the new fair value measurement standards codified in ASC 820-10 for non-financial assets and liabilities that are not re-measured at fair value on a recurring basis.

28  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

Financial assets and liabilities measured at fair value net of accrued interest in the financial statements on a recurring basis are summarized below:

March 31, 2010	Location on Balance Sheet	Carrying Value	Level 2
Cross-currency swaps for U.S. dollar 8 3 /4% senior notes	Derivative financial instruments	$66,268	$66,268
Interest rate swaps for U.S. dollar 8 3/4% senior notes	Derivative financial instruments	14,843	14,843
Cross-currency and interest rate swaps for U.S. dollar 8 3/4% senior notes	Derivative financial instruments	$81,111	$81,111
Embedded price escalation features in a long term revenue construction contract	Derivative financial instruments	6,481	6,481
Embedded price escalation features in certain long term supplier contracts	Derivative financial instruments	9,463	9,463
		$97,055	$97,055

March 31, 2009	Location on Balance Sheet	Carrying Value		Level 2
Cross-currency swaps for U.S. dollar 8 3 /4% senior notes	Derivative financial instruments	$11,573		$11,573
Interest rate swaps for U.S. dollar 8 3/4% senior notes	Derivative financial instruments	20,460		20,460
Cross-currency and interest rate swaps for U.S. dollar 8 3/4% senior notes	Derivative financial instruments	$32,033		$32,033
Embedded price escalation features in a long term revenue construction contract	Derivative financial instruments	(324	)	(324	)
Embedded price escalation features in certain long term supplier contracts	Derivative financial instruments	22,778		22,778
Embedded early redemption option on 8 3/4% senior notes	Senior notes	3,716		3,716
		$58,203		$58,203

At March 31, 2010, the Company has no financial assets or financial liabilities classified as Level 1 or Level 3 under the fair value hierarchy. Since the Company primarily uses observable inputs of similar instruments and discounted cash flows in its valuation of its derivative financial instruments, it has been concluded that the valuation of derivatives is a Level 2. The fair values of the Company’s cross-currency and interest rate swap agreements and the Company’s embedded derivatives are based on appropriate price modeling commonly used by market participants to estimate fair value. Such modeling includes option pricing models and discounted cash flow analysis, using observable market based inputs to estimate fair value. The Company considers its own credit risk or the credit risk of the counterparty in determining fair value, depending on whether the fair values are in an asset or liability position. Fair value determined using valuation models requires the use of assumptions concerning the amount and timing of future cash flows. Fair value amounts reflect management’s best estimates using external readily observable market data such as future prices, interest rate yield curves, foreign exchange rates and discount rates for time value. It is possible that the assumptions used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be material.

The Company used the following methodologies and inputs to estimate the fair value of each class of Level 2 financial instruments:

_Ÿ To determine fair value of the Company’s cross-currency and interest rate swap agreements, discounted cash flow analysis with inputs of observable market data including foreign currency exchange rates, implied volatilities, interest rates and the credit risk of the Company or the counterparties were used as appropriate, with resulting valuations periodically validated through third-party or counterparty quotes;

_Ÿ To determine fair value of the Company’s optional redemption rights included in the senior notes, discounted cash flow analysis with input of observable market data including foreign currency exchange rates, implied volatilities and interest rates were used as appropriate; and

_Ÿ To determine fair value of the price escalation features in revenue and maintenance service contracts containing embedded derivatives, generally accepted valuation models based on discounted cash flows with inputs of observable market data, including foreign currency rates and discount factors were used.

Non-financial assets that were re-measured at fair value on a non-recurring basis as at March 31, 2010 in the financial statements are summarized below:

March 31, 2010	Carrying Value	Level 3	Change in Fair Value
Assets held for sale	838	838	(125	)

Long-lived assets held for sale with a carrying amount of $963 were written down to their fair value of $838, resulting in a loss of $(125), which was included in depreciation expense in the Consolidated Statements of Operations and

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  29

Comprehensive Income (Loss) for the year ended March 31, 2010. The fair value of the assets held for sale is determined internally by analyzing recent auction prices for equipment with similar specifications and hours used, the net book value, the residual value of the asset and the useful life of the asset. The inputs to estimate the fair value of the assets held for sale are classified under level 3 of the fair value hierarchy.

The Company did not re-measure non-financial liabilities to fair value as at March 31, 2010.

The realized and unrealized loss (gain) on derivative financial instruments is comprised as follows:

Year ended March 31,	2010		2009		2008
Realized and unrealized loss (gain) on cross-currency and interest rate swaps	$64,637		$(46,945)		$23,456
Unrealized loss (gain) on embedded price escalation features in a long term revenue construction contract	6,805		(15,145	)	7,575
Unrealized (gain) loss on embedded price escalation features in certain long term supplier contracts	(13,315	)	21,509		(1,205	)
Unrealized (gain) loss on embedded early redemption option on senior notes	(3,716	)	3,331		249
	$54,411		$(37,250)		$30,075

b) Risk Management

The Company is exposed to market and credit risks associated with its financial instruments. The Company will from time to time use various financial instruments to reduce market risk exposures from changes in foreign currency exchange rates and interest rates. The Company does not hold or use any derivative instruments for trading or speculative purposes.

Overall, the Company’s Board of Directors has responsibility for the establishment and approval of the Company’s risk management policies. Management performs a risk assessment on a continual basis to help ensure that all significant risks related to the Company and its operations have been reviewed and assessed to reflect changes in market conditions and the Company’s operating activities.

c) Market Risk

Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices such as foreign currency exchange rates and interest rates. The level of market risk to which the Company is exposed at any point in time varies depending on market conditions, expectations of future price or market rate movements and composition of the Company’s financial assets and liabilities held, non-trading physical assets and contract portfolios.

To manage the exposure related to changes in market risk, the Company uses various risk management techniques including the use of derivative instruments. Such instruments may be used to establish a fixed price for a commodity, an interest bearing obligation or a cash flow denominated in a foreign currency.

The sensitivities provided below are hypothetical and should not be considered to be predictive of future performance or indicative of earnings on these contracts.

i) Foreign exchange risk

Foreign exchange risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to changes in foreign exchange rates. The Company has 8 ³/4% senior notes denominated in U.S. Dollars in the amount of U.S. $200.0 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 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 as discussed in note 24(c)(ii) below. These derivative financial instruments were not designated as hedges for accounting purposes. At March 31, 2010 and March 31, 2009, the notional principal amount of the cross-currency swap was U.S. $200.0 million and Canadian $263.0 million.

On December 17, 2008, the Company received notice that all three swap counterparties had exercised the cancellation option on the U.S. Dollar interest rate swap and, effective February 2, 2009, the U.S. Dollar interest rate swap was terminated. In addition to net accrued interest to the termination date of U.S. $0.7 million, the counterparties paid a cancellation premium of 2.2% on the notional amount of U.S. $200.0 million or U.S. $4.4 million (equivalent to Canadian $5.3 million), which is included in the caption “Other income” in the Consolidated Statements of Operations and Comprehensive (Loss) Income for the year ended March 31, 2009.

The Company’s Canadian Dollar interest rate swap and cross-currency swap agreements are not cancellable at the option of the counterparties and remained in effect at March 31, 2010. The Company will continue to pay the counterparties an average fixed rate of 9.889% on the notional amount of Canadian $263.0 million or Canadian $13.0 million semi-annually until December 1, 2011. Beginning March 1, 2009, the Company received quarterly floating rate payments in U.S. Dollars on the cross-currency swap agreement at the prevailing three month LIBOR rate plus a spread of 4.2% on the notional amount of U.S. $200.0 million.

30  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

As a result of the cancellation of the U.S. Dollar interest rate swap, the Company is exposed to changes in the value of the Canadian Dollar versus the U.S. Dollar. To the extent that the three month LIBOR rate is less than 4.6% (the difference between the 8 ³/4% senior notes coupon and the 4.2% spread over the three month LIBOR on the cross-currency swap agreement), the Company will have to acquire U.S. Dollars to fund a portion of its semi-annual coupon payment on its senior notes. At the three month U.S. Dollar LIBOR rate of 0.2684% at March 31, 2010, a $0.01 increase (decrease) in exchange rates in the Canadian Dollar would result in an insignificant decrease (increase) in the amount of Canadian Dollars required to fund each semi-annual coupon payment.

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

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

ii) Interest rate risk

The Company is exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of its financial instruments. Amounts outstanding under the Company’s Revolving Facility are subject to a floating rate. The Company’s senior notes are subject to a fixed rate. The Company’s interest risk arises from long term borrowings issued at fixed rates that create fair value interest rate risk and variable borrowings that create cash flow interest rate risk. Changes in market interest rates cause the fair value of long term debt with fixed interest rates to fluctuate but do not affect earnings, as the Company’s debt is carried at amortized cost and the carrying value does not change as interest rates change.

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

In conjunction with the cross-currency swap agreement discussed in note 24(c)(i) above, 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 ³/4% rate payable on the 8 ³/4% senior notes into a fixed rate of 9.889% for the duration that the 8 ³/4% senior notes are outstanding. These derivative financial instruments were not designated as hedges for accounting purposes.

As a result of the U.S. Dollar interest swap cancellation described in note 24(c)(i), the Company is exposed to changes in interest rates. The Company has a fixed semi-annual coupon payment of 8 ³/4% on its U.S. $200.0 million senior notes. With the termination of the U.S. Dollar interest rate swap, the Company will no longer receive fixed U.S. Dollar payments from the counterparties to offset the coupon payment on its senior notes. As a result of this termination, the Company’s effective annual interest costs at the current LIBOR rate will increase by U.S. $8.6 million. In addition, the Company is now exposed to interest rate risk where a 100 basis point increase (decrease) in the three month U.S. Dollar LIBOR rate will result in a U.S. $2.0 million decrease (increase) in effective annual interest costs.

At March 31, 2010 and March 31, 2009, the notional principal amounts of the interest rate swaps were U.S. $200.0 million and Canadian $263.0 million.

As at March 31, 2010, holding all other variables constant, a 100 basis point increase (decrease) to Canadian interest rates would impact the fair value of the interest rate swaps by $2.4 million with this change in fair value being recorded in net income. As at March 31, 2010, holding all other variables constant, a 100 basis point increase (decrease) to U.S. interest rates would impact the fair value of the interest rate swaps by $0.2 million with this change in fair value being recorded in net income. As at March 31, 2010, holding all other variables constant, a 100 basis point increase (decrease) of Canadian to U.S. interest rate volatility would impact the fair value of the interest rate swaps by $nil million with this change in fair value being recorded in net income.

At March 31, 2010, the Company held $28.4 million of floating rate debt pertaining to its Term Facility (March 31, 2009 – $nil). As at March 31, 2010, holding all other variables constant, a 100 basis point increase (decrease) to interest rates on floating rate debt will result in $0.3 million increase (decrease) in annual interest expense. This assumes that the amount of floating rate debt remains unchanged from that which was held at March 31, 2010.

d) Credit Risk

Credit risk is the risk that financial loss to the Company may be incurred if a customer or counterparty to a financial instrument fails to meet its contractual obligations. The Company manages the credit risk associated with its cash by

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  31

holding its funds with what it believes to be reputable financial institutions. The Company is also exposed to credit risk through its accounts receivable and unbilled revenue. Credit risk for trade and other accounts receivables, and unbilled revenue are managed through established credit monitoring activities.

The Company has a concentration of customers in the oil and gas sector. The concentration risk is mitigated primarily by the customers being large investment grade organizations. The credit worthiness of new customers is subject to review by management through consideration of the type of customer and the size of the contract.

At March 31, 2010 and March 31, 2009, the following customers represented 10% or more of accounts receivable and unbilled revenue:

	March 31, 2010	March 31, 2009
Customer A	38%	29%
Customer B	36%	17%
Customer C	4%	13%
Customer D	3%	11%

The Company reviews its accounts receivable amounts regularly and amounts are written down to their expected realizable value when outstanding amounts are determined not to be fully collectible. This generally occurs when the customer has indicated an inability to pay, the Company is unable to communicate with the customer over an extended period of time, and other methods to obtain payment have been considered and have not been successful. Bad debt expense is charged to net income in the period that the account is determined to be doubtful. Estimates of the allowance for doubtful accounts are determined on a customer-by-customer evaluation of collectability at each reporting date taking into consideration the following factors: the length of time the receivable has been outstanding, specific knowledge of each customer’s financial condition and historical experience.

The Company’s maximum exposure to credit risk for accounts receivable and unbilled revenue is as follows:

	March 31, 2010	March 31, 2009
Trade accounts receivables	$106,966	$76,499
Other receivables	4,918	1,824
Total accounts receivable	$111,884	$78,323
Unbilled revenue	$84,702	$55,907

On a geographic basis as at March 31, 2010, approximately 98% (March 31, 2009 – 99%) of the balance of trade accounts receivable (before considering the allowance for doubtful accounts) was due from customers based in Western Canada.

Payment terms are generally net 30 days. As at March 31, 2010 and March 31, 2009, trade receivables are aged as follows:

	March 31, 2010	March 31, 2009
Not past due	$83,797	$47,197
Past due 1-30 days	15,635	13,282
Past due 31-60 days	1,543	2,085
More than 61 days	5,991	13,935
Total	$106,966	$76,499

As at March 31, 2010, the Company has recorded an allowance for doubtful accounts of $1,691 (March 31, 2009 – $2,597) of which 100% relates to amounts that are more than 61 days past due.

The allowance is an estimate of the March 31, 2010 trade receivable balances that are considered uncollectible. Changes to the allowance are as follows:

Year ended March 31,	2010		2009		2008
Opening balance	$2,597		$742		$87
Payments received on provided balances	(846	)	(100	)	(184	)
Current year allowance	334		4,324		950
Write-offs	(394	)	(2,369	)	(111	)
Ending balance	$1,691		$2,597		$742

Credit risk on derivative financial instruments arises from the possibility that the counterparties to the agreements may default on their respective obligations under the agreements. This credit risk only arises in instances where these agreements have positive fair value for the Company.

32  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

25. Other information

a) Supplemental cash flow information

Year ended March 31,	2010	2009	2008
Cash paid during the year for:
Interest (including realized interest on interest rate swap)	$49,999	$29,336	$29,568
Income taxes	10,395	52	80
Cash received during the year for:
Interest	10,998	477	345
Income taxes	453	2,734	300
Non-cash transactions:
Acquisition of property, plant and equipment by means of capital leases	1,523	8,863	8,829

b) Net change in non-cash working capital

Year ended March 31,	2010			2009		2008
Operating activities:
Accounts receivable	$	(28,522	)	$86,832		$(59,415	)
Allowance for doubtful accounts		(906	)	1,855		654
Unbilled revenue		(28,795	)	14,976		(2,174	)
Inventories		6,214		(6,617	)	(1,337	)
Prepaid expenses and deposits		(2,620	)	1,015		2,632
Other assets		–		–		6,461
Accounts payable		6,620		(56,308	)	21,430
Accrued liabilities		1,150		5,626		18,802
Long term accrued liabilities		7,809		1,431		2,883
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		(541	)	(2,617	)	1,773
	$	(39,591	)	$46,193		$(8,291	)
Investing activities:
Accounts payable		$1,840		$(630)		$(2,835	)

26. 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:

_Ÿ Heavy Construction and Mining:

The Heavy Construction and Mining segment provides mining and site preparation services, including overburden removal and reclamation services, project management underground utility construction and equipment rental, to a variety of customers throughout Canada.

_Ÿ Piling:

The Piling segment provides deep foundation construction and design build services to a variety of industrial and commercial customers throughout Western Canada and Ontario.

_Ÿ Pipeline:

The Pipeline segment provides both small and large diameter pipeline construction and installation services as well as equipment rental to energy and industrial clients throughout Western Canada.

The accounting policies of the reportable operating segments are the same as those described in the significant accounting policies in note 3. 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 resources used to provide these services.

b) Results by business segment

For the year ended March 31, 2010	Heavy Construction and Mining	Piling	Pipeline		Total
Revenue from external customers	$665,514	$68,531	$24,920		$758,965
Depreciation of property, plant and equipment	34,419	2,842	153		37,414
Segment profits	111,016	11,288	(3,851	)	118,453
Segment assets	435,098	92,980	14,765		542,843
Capital expenditures	40,532	1,081	948		42,561

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  33

For the year ended March 31, 2009	Heavy Construction and Mining		Piling		Pipeline		Total
Revenue from external customers	$716,053		$155,076		$101,407		$972,536
Depreciation of property, plant and equipment	25,690		3,380		581		29,651
Segment profits	109,580		38,776		22,470		170,826
Impairment of goodwill	(125,447	)	(18,000	)	(32,753	)	(176,200	)
Segment assets	373,861		88,908		7,898		470,667
Capital expenditures	73,689		8,679		75		82,443

For the year ended March 31, 2008	Heavy Construction and Mining	Piling	Pipeline	Total
Revenue from external customers	$626,582	$162,397	$200,717	$989,696
Depreciation of property, plant and equipment	23,260	3,340	969	27,569
Segment profits	102,686	45,362	25,465	173,513
Segment assets	498,722	110,288	88,143	697,153
Capital expenditures	35,216	12,945	5,229	53,390

c) Reconciliations

i) Income (loss) before income taxes

Year ended March 31,	2010		2009		2008
Total profit for reportable segments	$118,453		$170,826		$173,513
Less: unallocated corporate items:
General and administrative costs	62,530		74,460		69,806
Loss on disposal of property, plant and equipment	1,233		5,325		179
Loss on disposal of assets held for sale	373		24		493
Amortization of intangible assets	1,719		1,501		804
Equity in earnings of unconsolidated joint venture	(44	)	–		–
Impairment of goodwill	–		176,200		–
Interest expense, net	26,080		29,612		29,080
Foreign exchange (gain) loss	(48,901	)	47,272		(25,660	)
Realized and unrealized loss (gain) on derivative financial instruments	54,411		(37,250	)	30,075
Other income	(14	)	(5,955	)	(418	)
Unallocated equipment (recoveries) costs (i)	(20,832	)	408		10,504
Income (loss) before income taxes	$41,898		$(120,771)		$58,650

(i) Unallocated equipment costs represent actual equipment costs, including non-cash items such as depreciation which have not been allocated to reportable segments. Unallocated equipment recoveries arise when actual equipment costs charged to reported segment exceed actual equipment costs incurred.

ii) Total assets

	March 31, 2010	March 31, 2009
Total assets for reportable segments	$542,843	$470,667
Corporate assets:
Cash	$103,005	$98,880
Property, plant and equipment	17,883	19,890
Deferred tax assets	14,478	19,465
Other	24,408	20,373
Total corporate assets	$159,774	$158,608
Total assets	$702,617	$629,275

The Company’s goodwill of $25,111 is assigned to the Piling segment. All of the Company’s assets are located in Canada.

iii) Depreciation of property, plant and equipment

Year ended March 31,	2010	2009	2008
Total depreciation for reportable segments	$37,414	$29,651	$27,569
Depreciation for corporate assets	5,222	6,738	8,151
Total depreciation	$42,636	$36,389	$35,720

34  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

iv) Capital expenditures for property, plant and equipment

Year ended March 31,	2010	2009	2008
Total capital expenditures for reportable segments	$42,561	$82,443	$53,390
Capital expenditures for corporate assets	12,790	5,096	1,689
Total capital expenditures including additions to intangible assets	$55,351	$87,539	$55,079

d) Customers

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

Year ended March 31,	2010	2009	2008
Customer A	51%	31%	23%
Customer B	19%	9%	13%
Customer C	9%	18%	13%
Customer D	5%	15%	13%
Customer E	0%	10%	19%

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

27. Related party transactions

The Sterling Group, L.P., Perry Strategic Capital Inc., and SF Holding Corp. are collectively the “Sponsors” of the Company. 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 advisory and consulting services, the Company provides reports, financial data and other information to the Sponsors. This permits them to consult with and advise the Company’s management on matters relating to its operations, company affairs and finances. In addition, this permits them to visit and inspect any of the Company’s properties and facilities.

Additionally, the Company entered into a shared service agreement with its joint venture, Noramac Ventures Inc. There have been no transactions under this agreement during the year ended March 31, 2010. (note 14).

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

28. Commitments

The annual future minimum lease payments for heavy equipment, office equipment and premises in respect of operating leases, excluding contingent rentals, for the next five years and thereafter are as follows:

For the year ending March 31,
2011	$62,862
2012	52,999
2013	37,899
2014	25,942
2015 and thereafter	15,965
	$195,667

Contingent rental expense is recognized when the achievement of specified targets is considered probable. The contingent rental expenses are included in “Equipment operating lease expense and equipment costs” in the Consolidated Statements of Operations and Comprehensive Income (Loss). Total contingent rentals on operating leases consisting principally of usage charges in excess of minimum contracted amounts for the years ended March 31, 2010, 2009 and 2008 amounted to $10,246, $7,665 and $15,482 respectively.

29. 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, 2010 were $1,393 (2009 – $2,540; 2008 – $2,053).

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  35

30. Stock-based compensation plan

Stock-based compensation expenses included in general and administrative costs are as follows:

Year ended March 31,	2010	2009	2008
Share option plan	$2,135	$1,888	$1,937
Deferred performance share unit plan	123	61	–
Restricted share unit plan	1,010	–	–
Director’s share unit plan	2,002	356	190
	$5,270	$2,305	$2,127

a) Share option plan

Under the 2004 Amended and Restated Share Option Plan, directors, officers, employees and certain service providers to the Company are eligible to receive stock options to acquire voting common shares in the Company. Each stock option provides the right to acquire one common share in the Company and expires ten years from the grant date or on termination of employment. Options may be exercised at a price determined at the time the option is awarded, and vest as follows: no options vest on the award date and twenty percent vest on each subsequent anniversary date.

	Number of options		Weighted average exercise price $ per share
Outstanding at March 31, 2007	2,146,840		6.03
Granted	481,600		13.80
Exercised (i)	(324,816	)	(5.00	)
Options settled for cash	(62,760	)	(5.00	)
Forfeited	(204,500	)	(11.56	)
Outstanding at March 31, 2008	2,036,364		7.54
Granted	344,800		8.22
Exercised (i)	(109,000	)	(6.45	)
Forfeited	(200,280	)	(9.40	)
Outstanding at March 31, 2009	2,071,884		7.53
Granted	375,700		8.88
Exercised (i)	(10,800	)	(4.90	)
Options settled for cash	(95,720	)	(4.95	)
Forfeited	(90,260	)	(8.53	)
Outstanding at March 31, 2010	2,250,804		7.84

(i) All stock options exercised resulted in new common shares being issued (note 21(a)).

Cash received from the option exercises for the year ended March 31, 2010 was $53 (March 31, 2009 –$703, March 31, 2008 – $1,627). Cash paid for options settled for cash for the year ended March 31, 2010 was $244 (March 31, 2009 – $nil, March 31, 2008 – $581). The total intrinsic value of options exercised for the years ended March 31, 2010, 2009 and 2008 was $277, $1,238, and $4,855 respectively.

The following table summarizes information about stock options outstanding at March 31, 2010:

	Options outstanding			Options exercisable
Exercise price	Number	Weighted average remaining life	Weighted average exercise price	Number	Weighted average remaining life	Weighted average exercise price
$5.00	1,171,504	4.8 years	$5.00	1,015,952	4.7 years	$5.00
$16.75	27,760	6.5 years	$16.75	16,656	6.5 years	$16.75
$13.50	230,960	7.7 years	$13.50	93,800	7.7 years	$13.50
$13.21	75,000	7.8 years	$13.21	30,000	7.8 years	$13.21
$15.37	81,500	8.0 years	$15.37	32,600	8.0 years	$15.37
$16.01	75,000	8.0 years	$16.01	15,000	8.0 years	$16.01
$16.46	50,000	8.0 years	$16.46	10,000	8.0 years	$16.46
$3.69	163,380	8.7 years	$3.69	30,900	8.7 years	$3.69
$8.28	160,000	9.2 years	$8.28	–	–	–
$9.33	215,700	9.9 years	$9.33	–	–	–
	2,250,804	6.6 years	$7.84	1,244,908	5.3 years	$6.46

At March 31, 2010, the weighted average remaining contractual life of outstanding options is 6.6 years (March 31, 2009 – 7.0 years). The fair value of options vested during the year ended March 31, 2010 was $1,594.

At March 31, 2010, the total compensation costs related to non-vested awards not yet recognized was $3,351 and these costs are expected to be recognized over a weighted average period of 3.4 years.

36  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

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,	2010	2009	2008
Number of options granted	375,700	344,800	481,600
Weighted average fair value per option granted ($)	6.25	4.53	4.92
Weighted average assumptions:
Dividend yield	Nil%	Nil%	Nil%
Expected volatility	76.27%	59.01%	38.80%
Risk-free interest rate	3.39%	3.24%	4.25%
Expected life (years)	6.5	6.5	6.5

The Company uses company specific historical data to estimate the expected life of the option, such as employee option exercise and employee post-vesting departure behaviour. Since the Company’s shares have been publicly traded for a period that is shorter than the expected life of the share option, expected volatility is estimated based on the historical volatility of a peer group of similar entities in addition to its own historical volatility.

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. 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 shares.

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

b) Deferred performance share unit plan

On March 19, 2008, the Company approved a Deferred Performance Share Unit (“DPSU”) Plan which became effective April 1, 2008.

DPSUs will be granted effective April 1 of each fiscal year in respect of services to be provided in that fiscal year and the following two fiscal years. The DPSUs vest at the end of a three-year term and are subject to the performance criteria approved by the Compensation Committee of the Board of Directors at the date of grant. Such performance criterion includes the passage of time and is based upon return on invested capital calculated on operating income and average operating assets. The date of the third fiscal year-end following the date of the grant of DPSUs is the maturity date for such DPSUs. At the maturity date, the Compensation Committee assesses the participant against the performance criteria and determines the number of DPSUs that have been earned (earned DPSUs).

The settlement of the participant’s entitlement is made either in cash in an amount equivalent to the number of earned DPSUs multiplied by the value of the Company’s common shares at the date of maturity or in a number of common shares equal to the number of earned DPSUs. If settled in common shares, the common shares are purchased on the open market or through the issuance of shares from treasury.

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  37

The fair value of each unit under the DPSU Plan was estimated on the date of the grant using Black-Scholes option pricing model. The weighted average assumptions used in estimating the fair value of the share options issued under the DPSU Plan at April 1, 2009 and April 1, 2008 are as follows:

Year ended March 31,	2010	2009
Number of units granted	908,165	111,020
Weighted average fair value per unit granted ($)	4.71	12.34
Weighted average assumptions:
Dividend yield	Nil%	Nil%
Expected volatility	96.89%	56.25%
Risk-free interest rate	1.47%	2.83%
Expected life (years)	3.00	3.00

Since the Company’s shares have been publicly traded for a period that is shorter than the expected life of the DPSU, expected volatility is estimated based on the average historical volatility of a peer group of similar entities in addition to its own historical volatility.

	Number of units
Outstanding at March 31, 2008	–
Granted	111,020
Exercised	–
Forfeited	(20,015	)
Outstanding at March 31, 2009	91,005
Granted	908,165
Exercised	–
Forfeited	(102,671	)
Converted to RSUs (note 30 (c))	(389,204	)
Outstanding at March 31, 2010	507,295

The weighted average exercise price per unit is $nil.

None of the DPSUs have vested as of March 31, 2010. At March 31, 2010, the weighted average remaining contractual life of outstanding DPSU Plan units is 2.2 years (March 31, 2009 – 2.0 years). For the years ended March 31, 2010 and March 31, 2009, respectively, the Company granted 908,165 and 111,020 units under the Plan. Compensation expense was adjusted based upon management’s assessment of performance against return on invested capital targets and the ultimate number of units expected to be issued. As at March 31, 2010, there was approximately $792 of total unrecognized compensation cost related to non-vested share-based payment arrangements under the DPSU Plan, which is expected to be recognized over a weighted average period of 2.2 years and is subject to performance adjustments. On December 18, 2009, the Company converted 389,204 DPSUs into RSUs (note 30(c)).

c) Restricted share unit plan

On December 3, 2009, the Company approved a Restricted Share Unit (“RSU”) Plan which became effective December 18, 2009.

RSUs will be granted effective April 1 of each fiscal year with respect to services to be provided in that fiscal year and the following two fiscal years. The RSUs vest at the end of a three-year term. The Company classifies RSUs as a liability as the Company has the ability and intent to settle the awards in cash.

Compensation expense is calculated based on the fair value of each RSU as determined by the closing value of the Company’s common shares on each period end date. The Company recognizes compensation expense over the vesting period of the RSU term.

On December 18, 2009, the Company converted certain middle manager’s DPSUs (note 30(b)) into RSUs at a conversion factor of 80%.

	Number of units
Outstanding at March 31, 2009
Converted from DPSUs at a conversion factor of 80%	311,358
Granted	169,489
Exercised
Forfeited	(12,032	)
Outstanding at March 31, 2010	468,815

None of the RSUs have vested as of March 31, 2010. At March 31, 2010, the weighted average remaining contractual life of the RSUs outstanding was 2.3 years.

38  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

At March 31, 2010, the redemption value of these units was $9.68/unit (March 31, 2009 – $nil/unit).

Using the redemption value of $9.68/unit at March 31, 2010, there was approximately $3,508 of total unrecognized compensation cost related to non-vested share-based payment arrangement under the RSU Plan and these costs are expected to be recognized over a weighted average period of 2.3 years. On approval of the RSU Plan, the Company reclassified $20 from additional paid-in capital to restricted share unit liability related to the conversion of those employees converted from the DPSU Plan to the RSU Plan.

d) 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-officer directors of the Company receive 50% of their annual fixed remuneration (which is included in general and administrative costs in the Consolidated Statements of Operations and Comprehensive Income (Loss)) 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 number of DDSUs to be credited to the participants deferred unit account shall be determined by dividing the amount of the participant’s deferred remuneration by the fair market value per common share on the date the DDSUs are credited to the participant (the date the services are rendered by the participant). The DDSUs vest immediately upon grant and are only redeemable upon death or retirement of the participant for cash determined by the market price of the Company’s common shares for the 5 trading days immediately preceding death or retirement. Directors, who are not U.S. 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.

	Number of units
Outstanding at March 31, 2007	–
Granted	11,807
Outstanding at March 31, 2008	11,807
Granted	127,884
Outstanding at March 31, 2009	139,691
Granted	123,575
Outstanding at March 31, 2010	263,266

At March 31, 2010, the redemption value of these units was $9.68/unit (March 31, 2009 – $3.91/unit). There is no unrecognized compensation expense related to deferred share units, since these awards vest immediately when granted.

31. Contingencies

During the normal course of the Company’s operations, various legal and tax matters are pending. In the opinion of management, these matters will not have a material effect on the Company’s consolidated financial position or results of operations.

32. Comparative figures

Certain of the comparative figures have been reclassified from statements previously presented to conform to the presentation of the current year consolidated financial statements.

33. Subsequent event

On April 7, 2010, the Company issued, through private placement in Canada and the U.S. $225.0 million of 9.125% Series 1 Senior Unsecured Debentures (the “Debentures”). The Debentures mature on April 7, 2017. The Debentures will bear interest from the date of issue at 9.125% per annum and such interest is payable in equal installments semi-annually in arrears on April 7 and October 7 in each year, commencing on October 7, 2010.

The Debentures are unsecured senior obligations and rank equally with all other existing and future unsecured senior debt and senior to any subordinated debt that may be issued by the Company or any of its subsidiaries. The Debentures are effectively subordinated to all secured debt to the extent of collateral on such debt.

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

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

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

At any time prior to April 7, 2013, the Company may on one or more occasions redeem the Debentures, in whole or in part, at a redemption price which is equal to the greater of (a) the Canada Yield Price and (b) 100% of the aggregate

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  39

principal amount of Debentures redeemed, plus, in each case, accrued and unpaid interest to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

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

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

On April 8, 2010, the Company settled the cross-currency and interest rate swaps for a total of $92.5 million. On April 28, 2010, the Company redeemed the 8 ³/4% senior notes for a total of $207.6 million and wrote off deferred financing costs of $4.5 million. These payments were funded by the net proceeds received from the issuance of the Debentures and available cash on hand.

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

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

Interest on Canadian base rate loans is paid at variable rates based on the Canadian prime rate plus the applicable pricing margin (as defined within the credit agreement). Interest on US base rate loans is paid at a rate per annum equal to the US base rate plus the applicable pricing margin. Interest on prime and US base rate loans is payable monthly in arrears and computed on the basis of a 365 day or 366 day year, as the case may be. Interest on 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.

Subsequent to March 31, 2010, the Company recorded additional financing costs on the Debentures and the amended credit agreement of $6.9 million and $1.0 million respectively. These additional costs will be recorded as deferred financing costs in the Interim Consolidated Balance Sheets.

40  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

34. United States and Canadian accounting policy differences

These consolidated financial statements have been prepared in accordance with U.S. GAAP, which differs in certain respects from Canadian GAAP. If Canadian GAAP were employed, the Company’s net income (loss) would be adjusted as follows:

Consolidated Statements of Operations, Comprehensive Income and Deficit - for the year ended March 31, 2010	U.S. GAAP			Adjustments		Canadian GAAP
Revenue (g)		$758,965		$4,336			$763,301
Project costs (g)		301,307		3,542			304,849
Equipment costs		209,408		–			209,408
Equipment operating lease expense		66,329		–			66,329
Depreciation (a)		42,636		(124	)		42,512
Gross profit		139,285		918			140,203
General and administrative costs (c) and (g)		62,530		706			63,236
Loss on disposal of property, plant and equipment		1,233		–			1,233
Loss on disposal of assets held for sale		373		–			373
Amortization of intangible assets (b)		1,719		831			2,550
Equity in earnings of unconsolidated joint venture (g)		(44	)	44			–
Operating income before the undernoted		73,474		(663	)		72,811
Interest expense, net (b)		26,080		(2,486	)		23,594
Foreign exchange gain (b)		(48,901	)	496			(48,405	)
Realized and unrealized loss on derivative financial instruments (d)		54,411		–			54,411
Other income		(14	)	–			(14	)
Income before income taxes		41,898		1,327			43,225
Income taxes:
Current income taxes		3,803		–			3,803
Deferred income taxes (h)		9,876		372			10,248
Net income and comprehensive income for the year		28,219		955			29,174
Deficit, beginning of year		(158,105	)	126			(157,979	)
Deficit, end of year	$	(129,886	)	$1,081		$	(128,805	)
Net income per share – basic		$0.78		$0.03			$0.81
Net income per share – diluted		$0.77		$0.02			$0.79

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  41

Consolidated Statements of Operations, Comprehensive Loss and Deficit – for the year ended March 31, 2009	U.S. GAAP		Adjustments		Canadian GAAP
Revenue	$972,536		$–		$972,536
Project costs	505,026		–		505,026
Equipment costs	217,120		–		217,120
Equipment operating lease expense	43,583		–		43,583
Depreciation (a)	36,389		(162	)	36,227
Gross profit	170,418		162		170,580
General and administrative costs (c)	74,460		(55	)	74,405
Loss on disposal of property, plant and equipment	5,325		–		5,325
Loss on disposal of assets held for sale	24		–		24
Amortization of intangible assets (b)	1,501		837		2,338
Impairment of goodwill	176,200		–		176,200
Operating loss before the undernoted	(87,092	)	(620	)	(87,712	)
Interest expense, net (b)	29,612		(2,162	)	27,450
Foreign exchange loss (b)	47,272		(606	)	46,666
Realized and unrealized gain on derivative financial instruments (d)	(37,250	)	4,655		(32,595	)
Other income	(5,955	)	–		(5,955	)
Loss before income taxes	(120,771	)	(2,507	)	(123,278	)
Income taxes:
Current income taxes	5,546		–		5,546
Deferred income taxes (h)	9,087		(34	)	9,053
Net loss and comprehensive loss for the year	(135,404	)	(2,473	)	(137,877	)
Deficit, beginning of year	(22,701	)	1,608		(21,093	)
Change in accounting policy related to inventories (f)	–		991		991
Deficit, end of year	$(158,105)		$126		$(157,979)
Net loss per share – basic	$(3.76)		$(0.07)		$(3.83)
Net loss per share – diluted	$(3.76)		$(0.07)		$(3.83)

Consolidated Statements of Operations, Comprehensive Income and Deficit - for the year ended March 31, 2008	U.S. GAAP		Adjustments		Canadian GAAP
Revenue	$989,696		$–		$989,696
Project costs	592,458		–		592,458
Equipment costs (f)	176,190		1,383		177,573
Equipment operating lease expense	22,319		–		22,319
Depreciation (a)	35,720		(131	)	35,589
Gross profit	163,009		(1,252	)	161,757
General and administrative costs (c)	69,806		(136	)	69,670
Loss on disposal of property, plant and equipment	179		–		179
Loss on disposal assets held for sale	493		–		493
Amortization of intangible assets (b)	804		794		1,598
Operating income before the undernoted	91,727		(1,910	)	89,817
Interest expense, net (b)	29,080		(2,061	)	27,019
Foreign exchange gain (b)	(25,660	)	218		(25,442	)
Realized and unrealized loss on derivative financial instruments (d)	30,075		4,000		34,075
Other income	(418	)	–		(418	)
Income before income taxes	58,650		(4,067	)	54,583
Income taxes:
Current income taxes	80		–		80
Deferred income taxes (h)	17,036		(511	)	16,525
Net income and comprehensive income for the year	41,534		(3,556	)	37,978
Deficit, beginning of year – as previously reported	(64,235	)	8,709		(55,526	)
Change in accounting policy related to financial instruments (j)	–		(3,545	)	(3,545	)
Deficit, end of year	$(22,701)		$1,608		$(21,093)
Net income per share – basic	$1.16		$(0.10)		$1.06
Net income per share – diluted	$1.13		$(0.10)		$1.03

42  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

The cumulative effect of material differences between U.S. and Canadian GAAP on the consolidated balance sheets of the Company is as follows:

Consolidated Balance Sheets as at March 31, 2010	U.S. GAAP		Adjustments		Canadian GAAP
Assets
Current assets:
Cash and cash equivalents (g)	$103,005		$1,240		$104,245
Accounts receivable (g)	111,884		1,432		113,316
Unbilled revenue (g)	84,702		1,794		86,496
Inventories	5,659		–		5,659
Prepaid expenses and deposits (g)	6,881		87		6,968
Deferred taxes assets	3,481		–		3,481
	315,612		4,553		320,165
Prepaid expenses and deposits	4,005		–		4,005
Assets held for sale	838		–		838
Property, plant and equipment (a)	328,743		(536	)	328,207
Intangible assets (b)	7,669		1,051		8,720
Deferred financing costs (b)	6,725		(5,685	)	1,040
Investment in and advances to unconsolidated joint venture (g)	2,917		(2,917	)	–
Goodwill	25,111		–		25,111
Deferred taxes assets	10,997		–		10,997
	$702,617		$(3,534	)	$699,083
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable (g)	$66,876		$1,637		$68,513
Accrued liabilities	47,191		–		47,191
Billings in excess of costs incurred and estimated earnings on uncompleted contracts	1,614		–		1,614
Current portion of capital lease obligations	5,053		–		5,053
Current portion of derivative financial instruments	22,054		(1,506	)	20,548
Current portion of long term debt	6,072		–		6,072
Deferred taxes liabilities	16,781		–		16,781
	165,641		131		165,772
Deferred lease inducements	761		–		761
Long term accrued liabilities	14,943		–		14,943
Capital lease obligations	8,340		–		8,340
Long term debt	22,374		–		22,374
Senior notes (b)  and (d)	203,120		(1,506	)	201,614
Director deferred stock unit liability	2,548		–		2,548
Restricted share unit liability	1,030		–		1,030
Derivative financial instruments	75,001		1,506		76,507
Asset retirement obligation	360		–		360
Deferred taxes liabilities (h)	27,441		(1,052	)	26,389
	521,559		(921	)	520,638
Shareholders’ equity:
Common shares (authorized – unlimited number of voting and non-voting common shares; issued and outstanding – March 31, 2010 – 36,049,276 voting common shares) (e)	303,505		(3,458	)	300,047
Additional paid-in capital (c) and (h)	7,439		(236	)	7,203
Deficit (a – h)	(129,886	)	1,081		(128,805	)
	181,058		(2,613	)	178,445
	$702,617		$(3,534	)	$699,083

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  43

Consolidated Balance Sheets as at March 31, 2009	U.S. GAAP		Adjustments			Canadian GAAP
Assets
Current assets:
Cash and cash equivalents	$98,880			$–		$98,880
Accounts receivable	78,323			–		78,323
Unbilled revenue	55,907			–		55,907
Inventories	11,814			–		11,814
Prepaid expenses and deposits	4,781			–		4,781
Deferred taxes assets	7,033			–		7,033
	256,738			–		256,738
Prepaid expenses and deposits	3,504			–		3,504
Assets held for sale	2,760			–		2,760
Property, plant and equipment (a)	316,115			(660	)	315,455
Intangible assets (b)	5,944			767		6,711
Deferred financing costs (b)	7,910			(7,910	)	–
Goodwill	23,872			–		23,872
Deferred taxes assets	12,432			–		12,432
	$629,275		$	(7,803	)	$621,472
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$56,204			$–		$56,204
Accrued liabilities	45,001			–		45,001
Billings in excess of costs incurred and estimated earnings on uncompleted contracts	2,155			–		2,155
Current portion of capital lease obligations	5,409			–		5,409
Current portion of derivative financial instruments	11,439			–		11,439
Deferred taxes liabilities	7,749			–		7,749
	127,957			–		127,957
Deferred lease inducements	836			–		836
Long term accrued liabilities	7,134			–		7,134
Capital lease obligations	12,075			–		12,075
Senior notes (b)  and (d)	255,756			(2,857	)	252,899
Director deferred stock unit liability	546			–		546
Derivative financial instruments	43,048			–		43,048
Asset retirement obligation	386			–		386
Deferred taxes liabilities (h)	30,745			(1,423	)	29,322
	478,483			(4,280	)	474,203
Shareholders’ equity:
Common shares (authorized – unlimited number of voting and non-voting common shares; issued and outstanding – March 31, 2009 – 36,038,476 voting common shares) (e)	303,431			(3,458	)	299,973
Additional paid-in capital (c) and (h)	5,466			(191	)	5,275
Deficit (a – h)	(158,105	)		126		(157,979	)
	150,792			(3,523	)	147,269
	$629,275		$	(7,803	)	$621,472

44  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

Consolidated Statements of Cash Flows – for the year ended March 31, 2010
Cash provided by (used in):	U.S. GAAP		Adjustments		Canadian GAAP
Operating activities:
Net income for the year	$28,219		$955		$29,174
Items not affecting cash:
Depreciation	42,636		(124	)	42,512
Equity in earnings of unconsolidated joint venture	(44	)	44		–
Amortization of intangible assets	1,719		831		2,550
Amortization of deferred lease inducements	(107	)	–		(107	)
Amortization of deferred financing costs	3,348		(2,486	)	862
Loss on disposal of property, plant and equipment	1,233		–		1,233
Loss on disposal of assets held for sale	373		–		373
Unrealized foreign exchange gain on senior notes	(48,920	)	496		(48,424	)
Unrealized loss on derivative financial instruments measured at fair value	38,852		–		38,852
Stock-based compensation expense	5,270		(46	)	5,224
Accretion of asset retirement obligation	5		–		5
Deferred income taxes	9,876		372		10,248
Net changes in non-cash working capital	(39,591	)	(1,675	)	(41,266	)
	42,869		(1,633	)	41,236
Investing activities:
Acquisition, net of cash acquired	(5,410	)	–		(5,410	)
Purchase of property, plant and equipment	(51,989	)	–		(51,989	)
Purchase of intangible assets	(3,362	)	–		(3,362	)
Additions to assets held for sale	(1,739	)	–		(1,739	)
Investment in and advances to unconsolidated joint venture	(2,873	)	2,873		–
Proceeds on disposal of property, plant and equipment	1,440		–		1,440
Proceeds of disposal of assets held for sale	2,482		–		2,482
Net changes in non-cash working capital	1,840		–		1,840
	(59,611	)	2,873		(56,738	)
Financing activities:
Repayment of long term debt	(6,906	)			(6,906	)
Increase in long term debt	34,700		–		34,700
Cash settlement of stock options	(244	)	–		(244	)
Proceeds from stock options exercised	53		–		53
Financing costs	(1,123	)	–		(1,123	)
Repayment of capital lease obligations	(5,613	)	–		(5,613	)
	20,867		–		20,867
Increase in cash and cash equivalents	4,125		1,240		5,365
Cash and cash equivalents, beginning of year	98,880		–		98,880
Cash and cash equivalents, end of year	$103,005		$1,240		$104,245

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  45

Consolidated Statements of Cash Flows – for the year ended March 31, 2009
Cash provided by (used in):	U.S. GAAP		Adjustments		Canadian GAAP
Operating activities:
Net loss for the year	$(135,404	)	$(2,473	)	$(137,877	)
Items not affecting cash:
Depreciation	36,389		(162	)	36,227
Amortization of intangible assets	1,501		837		2,338
Impairment of goodwill	176,200		–		176,200
Amortization of deferred lease inducements	(105	)	–		(105	)
Amortization of deferred financing costs	2,970		(2,162	)	808
Loss on disposal of property, plant and equipment	5,325		–		5,325
Loss on disposal of assets held for sale	24		–		24
Unrealized foreign exchange loss on senior notes	46,466		(606	)	45,860
Unrealized gain on derivative financial instruments measured at fair value	(39,921	)	4,655		(35,266	)
Stock-based compensation expense	2,305		(55	)	2,250
Accretion of asset retirement obligation	155		–		155
Deferred income taxes	9,087		(34	)	9,053
Net changes in non-cash working capital	46,193		–		46,193
	151,185		–		151,185
Investing activities:
Purchase of property, plant and equipment	(84,437	)	–		(84,437	)
Purchase of intangible assets	(3,102	)	–		(3,102	)
Additions to assets held for sale	(2,035	)	–		(2,035	)
Proceeds on disposal of property, plant and equipment	11,164		–		11,164
Proceeds of disposal of assets held for sale	325		–		325
Net changes in non-cash working capital	(630	)	–		(630	)
	(78,715	)	–		(78,715	)
Financing activities:
Proceeds from stock options exercised	703		–		703
Repayment of capital lease obligations	(6,156	)	–		(6,156	)
	(5,453	)	–		(5,453	)
Increase in cash and cash equivalents	67,017		–		67,017
Cash and cash equivalents, beginning of year	31,863		–		31,863
Cash and cash equivalents, end of year	$98,880		$–		$98,880

46  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

Consolidated Statements of Cash Flows – for the year ended March 31, 2008
Cash provided by (used in):	U.S. GAAP		Adjustments		Canadian GAAP
Operating activities:
Net income for the year	$41,534		$(3,556	)	$37,978
Items not affecting cash:
Depreciation	35,720		(131	)	35,589
Write-down of other assets to replacement cost	–		1,845		1,845
Amortization of intangible assets	804		794		1,598
Amortization of deferred lease inducements	(104	)	–		(104	)
Amortization of deferred financing costs	2,899		(2,061	)	838
Loss on disposal of property, plant and equipment	179		–		179
Loss on disposal of assets held for sale	493		–		493
Unrealized foreign exchange gain on senior notes	(25,006	)	218		(24,788	)
Unrealized loss on derivative financial instruments measured at fair value	27,406		4,000		31,406
Stock-based compensation expense	2,127		(136	)	1,991
Deferred income taxes	17,036		(511	)	16,525
Net changes in non-cash working capital	(8,291	)	(462	)	(8,753	)
	94,797		–		94,797
Investing activities:
Acquisition, net of cash acquired	(1,581	)	–		(1,581	)
Purchase of property, plant and equipment	(52,805	)	–		(52,805	)
Purchase of intangible assets	(2,274	)	–		(2,274	)
Additions to assets held for sale	(3,499	)	–		(3,499	)
Proceeds on disposal of property, plant and equipment	6,862		–		6,862
Proceeds of disposal of assets held for sale	10,200		–		10,200
Net changes in non-cash working capital	(2,835	)	–		(2,835	)
	(45,932	)	–		(45,932	)
Financing activities:
Repayment of long term debt	(20,500	)	–		(20,500	)
Cash settlement of stock options	(581	)	–		(581	)
Proceeds from stock options exercised	1,627		–		1,627
Financing costs	(776	)	–		(776	)
Repayment of capital lease obligations	(3,762	)	–		(3,762	)
	(23,992	)	–		(23,992	)
Increase in cash and cash equivalents	24,873		–		24,873
Cash and cash equivalents, beginning of year	6,990		–		6,990
Cash and cash equivalents, end of year	$31,863		$–		$31,863

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

Under U.S. GAAP, deferred financing costs incurred in connection with the Company’s senior notes are being amortized over the term of the related debt using the effective interest method. Prior to April 1, 2007, for Canadian GAAP purposes, these transaction costs were recorded as a deferred asset under Canadian GAAP and these deferred financing costs were being amortized on a straight-line basis over the term of the debt.

Effective April 1, 2007, the Company adopted CICA Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, on a retrospective basis without restatement as described below. Although Section 3855 also requires the use of the effective interest method to account for the amortization of finance costs, the requirement to bifurcate the issuer’s early prepayment option on issuance of the debt (which is not required under U.S. 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 U.S. GAAP, foreign denominated transaction costs are considered non-monetary and are not subject to foreign currency gains and losses resulting from periodic translation procedures.

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  47

In connection with the adoption of Section 3855, transaction costs incurred in connection with the Company’s Revolving 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. The Company discloses the financing costs for both the senior notes and the Revolving Facility as deferred financing costs on the Consolidated Balance Sheets with the amortization charge classified as interest on the Consolidated Statements of Operations and Comprehensive Income (Loss). Under Canadian GAAP, the financing costs related to the senior notes are included in the “senior notes” balance on the Consolidated Balance Sheets.

c) Stock-based compensation

Up until April 1, 2006, the Company followed the provisions of ASC 718, “Share-Based Payment” (formerly 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”), which is now a part of ASC 718. 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 the provisions under the revised guidance 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 its 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

Under Canadian GAAP, the Company determined that the issuer’s early prepayment option included in the senior notes should be bifurcated from the host contract, along with a contingent embedded derivative in the senior notes that provide for accelerated redemption by the holders in certain instances. These embedded derivatives were measured at fair value at the inception of the senior notes and the residual amount of the proceeds was allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of the senior notes is accreted to par value over the term of the notes using the effective interest method and is recognized as interest expense as discussed in b) above. Prior to April 1, 2007 under Canadian GAAP, separate accounting of embedded derivatives from the host contract was not permitted by EIC-117.

Under U.S. GAAP, ASC 815 (formerly Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”)) establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts and debt instruments) be recorded in the balance sheet as either an asset or liability measured at its fair value. The contingent embedded derivative in 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 derivative has been measured at fair value and changes in fair value recorded in net income for all periods presented. The issuer’s early prepayment option included in the senior notes does not meet the criteria as an embedded derivative under ASC 815 (formerly SFAS 133) and was not bifurcated from the host contract and measured at fair value resulting in a U.S. GAAP and Canadian GAAP difference.

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 supplier contracts entered into prior to April 1, 2007 contained embedded derivatives that are not closely related to the host contract under Canadian 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. Under U.S. GAAP, the Company had recognized and measured these embedded derivatives since inception of the related contracts.

e) NAEPI Series B Preferred Shares

Prior to the modification of the terms of the North American Energy Partners Inc. (“NAEPI”) Series B preferred shares on March 30, 2006, there were no differences between Canadian GAAP and 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

48  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

interest method, which was consistent with the treatment of the NAEPI Series B preferred shares as temporary equity in the financial statements of NAEPI. The accretion charge was recognized by NACG as a charge to minority interest (as opposed to retained earnings in the accounts of NAEPI) under U.S. 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. NACG and NAEPI were amalgamated later in 2006 and the amalgamated entity continued as NAEPI.

f) Inventories

Effective April 1, 2008, the Company retrospectively adopted CICA Handbook Section 3031, “Inventories”, without restatement of prior periods. This standard requires inventories to be measured at the lower of cost and net realizable value and provides guidance on the determination of cost, including the allocation of overheads and other costs to inventories, the requirement for an entity to use a consistent cost formula for inventory of a similar nature and use, and the reversal of previous write-downs to net realizable value when there are subsequent increases in the value of inventories. This new standard also clarifies that spare component parts that do not qualify for recognition as property, plant and equipment should be classified as inventory. In adopting this new standard, the Company reversed a tire impairment that was previously recorded at March 31, 2008 in other assets of $1,383 with a corresponding decrease to opening deficit of $991 net of future taxes of $392.

During the year ended March 31, 2008, the replacement cost (i.e. market) of spare tire inventory was lower than the original carrying amount of inventory. As a result, the Company recorded an inventory write-down of $1.4 million under Canadian GAAP. Under U.S. GAAP, market means current replacement cost. However, market under U.S. GAAP should not exceed the net realizable value nor should it be less than net realizable value reduced by an allowance for a normal profit margin. The Company established that the net realizable value and net realizable value less an allowance for a normal profit margin was greater than or equal to cost and as such a write-down of spare tires was not appropriate under U.S. GAAP for the year ended March 31, 2008. Please refer to note 3 aa).

g) Joint venture

The Company owns a 49% interest in Noramac Ventures Inc., a nominee company for the Company’s Noramac Joint Venture (JV) and the Company has joint control of this entity. Under U.S. GAAP, the Company records its share of earnings of the JV using the equity method of accounting. Under Canadian GAAP, the Company uses the proportionate consolidation method of accounting for the JV. Under the proportionate consolidation method the Company recognizes its share of the results of operations, cash flows, and financial position of the JV on a line-by-line basis in its consolidated financial statements and eliminates its share of all material intercompany transactions with the JV. While there is no impact on net income or earnings per share as a result of the U.S. GAAP treatment of the joint venture, as compared to Canadian GAAP, there are presentation differences affecting the disclosures in the consolidated financial statements and supporting notes. Under Canadian GAAP, the following assets, liabilities, revenues, expenses and cash flows would be recorded using the proportionate consolidation method.

	March 31, 2010
Current assets	$4,476
Long term assets	77
Current liabilities	1,636
Long term liabilities	2,970
Net equity	$(53)

Year ended	March 31, 2010
Gross revenues	$4,387
Gross profit	805
Expenses	(761	)
Net income	$44

Year ended	March 31, 2010
Cash flow from operating activities	$1,240
Cash flow from investing activities	–
Cash flow from financing activities	–
Increase in cash and cash equivalents	$1,240

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  49

h) Other matters

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

i) Adjustments related to prior year financial statements

The financial statements for fiscal 2009 and fiscal 2008 under Canadian GAAP have been amended to correct the following errors identified during the preparation of the Company’s fiscal 2010 financial statements:

(i) Reclassification of accrued liabilities. The financial statements for fiscal 2009 have been amended to correct a classification error with respect to accrued liabilities identified during the preparation of the Company’s fiscal 2010 consolidated financial statements. Certain operating lease agreements provide a maximum hourly usage limit, above which the Company will be required to pay for the over hour usage. These contingent rentals are recognized when payment is considered probable and are due at the end of the lease term. The Company has historically classified the contingent rentals as a current liability; however, certain of the amounts are due beyond one year from the balance sheet date. In the current year, the Company has reclassified amounts due beyond one year, from the balance sheet date, as a long term liability and has reclassified comparative figures accordingly. The amount reclassified on the Consolidated Balance Sheet was $7,134 as at March 31, 2009;

(ii) Buy-out of leased assets. The financial statements for fiscal 2008 have been amended under Canadian GAAP to correct an error related to the method of accounting for an incentive at the time of buying previously leased assets, which was identified during the preparation of the Company’s fiscal 2010 consolidated financial statements. When an asset is leased under an operating lease agreement, as stated in the paragraph above, contingent rentals are recognized when payment is considered probable and are due at the end of the lease term. The Company can buy the asset at the end of the lease term at a pre-determined market price at which point the liability is extinguished since the lease agreement is cancelled. The Company has been traditionally extinguishing the liability for such lease buyouts by reducing equipment costs related to leased equipment, instead of considering the extinguishment of the liability as an incentive to purchase the asset and therefore reducing the cost of the asset. The correction of this error increased “Equipment costs” by $2,700, reduced “Depreciation” by $120, reduced “Future income taxes” by $774 and reduced “Net income and comprehensive income for the year” by $1,806 from the amounts originally reported in the Consolidated Statements of Operations and Comprehensive Income (Loss) for the year ended March 31, 2008. It also reduced “Property, plant and equipment” by $2,580, reduced long-term future income tax liabilities by $774 and increased “Deficit” for the year by $1,806 from the amounts originally reported in the Consolidated Balance Sheet as at March 31, 2008. The financial statements for fiscal 2009 have also been amended under Canadian GAAP to correct an error related to the method of accounting for an incentive at time of buying previously leased assets, which was identified during the preparation of the Company’s fiscal 2010 consolidated financial statements as stated above. The correction of this error increased “Equipment costs” by $6,600, reduced “Depreciation” by $600, reduced “Future income taxes” by $1,800 and increased “Net loss and comprehensive loss for the year” by $4,200 from the amounts originally reported in the Consolidated Statements of Operations and Comprehensive Income (Loss) for the year ended March 31, 2009. It also reduced “Property, plant and equipment” by $8,580, reduced long-term future income tax liabilities by $2,574 and increased “Deficit” for the year by $6,006 from the amounts originally reported in the Consolidated Balance Sheet as at March 31, 2009.

(iii) Valuation of derivative financial instruments. The financial statements for fiscal 2009 have also been amended under Canadian GAAP to correct an error related to the determination of the fair value of the cross-currency and interest rate swap liabilities (collectively, the “swap liability”) which was identified on settlement of the swap liability on April 8, 2010. The Company recorded the fair value of the swap liability and in addition recorded accrued interest on the swap liability. This resulted in the swap liability being misstated and the changes in the fair value of the swap liability being misstated by the change in the amount of the accrued interest at each reporting period from March 31, 2009. The periods before March 31, 2009 were not materially impacted because prior to February 2, 2009, the Canadian Dollar interest rate swap was still in place (note 24(c)(ii)), and therefore the net accrued interest payable under the swap liability was not material. The error increased “Realized and unrealized gain on derivative financial instruments” by $7,514, increased income tax expense by $1,676 and reduced net loss by $5,838 from amounts originally reported in the Consolidated Statements of Operations and Comprehensive Income (Loss) for the year ended March 31, 2009. It also reduced “Derivative financial instruments” by $7,514, increased long term future income taxes liabilities by $1,676 and reduced “Deficit” by $5,838 in the Consolidated Balance Sheet as at March 31, 2009.

50  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

The impact of the above corrections under Canadian GAAP on the Consolidated Statements of Operations and Comprehensive Income (Loss) for the years ended March 31, 2009 and March 31, 2008 are as follows:

For the year ended March 31, 2009	As previously reported	Adjustments	As amended
Equipment costs	$210,520	$6,600	$217,120
Depreciation	36,827	(600)	36,227
Realized and unrealized gain on derivative financial instruments	(25,081)	(7,514)	(32,595)
Future income taxes	9,177	(124)	9,053
Net loss and comprehensive loss for the year	(139,515)	1,638	(137,877)
Deficit, end of year	(157,811)	(168)	(157,979)
Net loss per share – basic	$(3.87)	$0.04	$(3.83)
Net loss per share – diluted	$(3.87)	$0.04	$(3.83)

For the year ended March 31, 2008	As previously reported	Adjustments	As amended
Equipment costs	$174,873	$2,700	$177,573
Depreciation	35,709	(120)	35,589
Future income taxes	17,299	(774)	16,525
Net income and comprehensive income for the year	39,784	(1,806)	37,978
Deficit, end of year	(19,287)	(1,806)	(21,093)
Net income per share – basic	$1.11	$(0.05)	$1.06
Net income per share – diluted	$1.08	$(0.05)	$1.03

The impact of the above corrections under Canadian GAAP on the Consolidated Balance Sheet as at March 31, 2009 is as follows:

March 31, 2009	As previously reported	Adjustments	As amended
Property, plant and equipment	$324,035	$(8,580)	$315,455
Accrued liabilities	52,135	(7,134)	45,001
Long term accrued liabilities	–	7,134	7,134
Derivative financial instruments	50,562	(7,514)	43,048
Future income taxes	30,220	(898)	29,322
Deficit	(157,811)	(168)	(157,979)

The impact of the above corrections under Canadian GAAP on the Consolidated Statements of Cash Flows for the years ended March 31, 2009 and March 31, 2008 are as follows:

For the year ended March 31, 2009	As previously reported	Adjustments	As amended
Net loss for the year	$(139,515)	$1,638	$(137,877)
Depreciation	36,827	(600)	36,227
Unrealized gain on derivative financial instruments measured at fair value	(27,752)	(7,514)	(35,266)
Future income taxes	9,177	(124)	9,053
Cash flow from operating activities	157,785	(6,600)	151,185
Purchase of property, plant and equipment	(91,037)	6,600	(84,437)
Cash flow from investing activities	(85,315)	6,600	(78,715)

For the year ended March 31, 2008	As previously reported	Adjustments	As amended
Net income for the year	$39,784	$(1,806)	$37,978
Depreciation	35,709	(120)	35,589
Future income taxes	17,299	(774)	16,525
Cash flow from operating activities	97,497	(2,700)	94,797
Purchase of property, plant and equipment	(55,505)	2,700	(52,805)
Cash flow from investing activities	(48,632)	2,700	(45,932)

j) 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”.

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  51

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 assets	3,293
Senior notes	(12,634)
Derivative financial instruments	9,720
Long term future income tax liabilities	18
Opening deficit	3,545

The adoption of these standards resulted in the following adjustments as of April 1, 2007 in accordance with the transition provisions:

_Ÿ 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;

_Ÿ Transaction costs incurred in connection with the Company’s Revolving 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.

_Ÿ The Company determined that the issuer’s early prepayment option included in the senior notes should be bifurcated from the host contract, along with a contingent embedded derivative in the senior notes that provide for accelerated redemption by the holders in certain instances. These embedded derivatives were measured at fair value at the inception of the senior notes and the residual amount of the proceeds was allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of the senior notes is accreted to par value over the term of the notes using the effective interest method and is recognized as interest expense. At transition on April 1, 2007, the Company recorded the fair value of $8,519 related to these embedded derivatives and a corresponding decrease in opening deficit of $7,305, net of future income taxes of $1,214. The impact of the bifurcation of these embedded derivatives at issuance of the senior notes resulted in an increase of senior notes of $5,700 and an increase in opening deficit of $3,963, net of income taxes of $1,737 after applying the effective interest method to the premium resulting from the bifurcation of these embedded derivatives to April 1, 2007; and

_Ÿ The Company determined that price escalation features in certain revenue and maintenance service contracts contain embedded derivatives that are not closely related to the host contracts. The embedded derivatives have 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 $9,720 related to these embedded derivatives on April 1, 2007, with a corresponding increase in opening deficit of $6,950, net of future income taxes of $2,770.

k) Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company manages liquidity risk through management of its capital structure and financial leverage, as outlined in note 34(l). It also manages liquidity risk by continuously monitoring actual and projected cash flows to ensure that it will have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to the Company’s reputation. The Company believes that forecasted cash flows from operating activities, along with amounts available under the Revolving Facility, will provide sufficient cash requirements to cover the Company’s forecasted normal operating and budgeted capital expenditures.

The Company’s Revolving Facility contains covenants that restrict its activities, including, but not limited to, incurring additional debt, transferring or selling assets and making investments including acquisitions. Under the revolving credit agreement, Consolidated Capital Expenditures, as defined in the revolving credit agreement, during any applicable period cannot exceed 120% of the amount in the capital expenditure plan. In addition, the Company is required to satisfy certain financial covenants, including a minimum interest coverage ratio and a maximum senior leverage ratio, both of which are calculated using Consolidated EBITDA, as defined in the revolving credit agreement, as well as a minimum current ratio.

At March 31, 2010, the Company was in compliance with its senior leverage, its interest coverage, and working capital covenants.

52  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

The following are the undiscounted contractual cash flows of financial liabilities and other contractual cash flows measured at period end exchange rates:

Fiscal year
	Carrying Amount	Contractual Cash Flows	2011	2012	2013	2014	2015 and Thereafter
Accounts payable and accrued liabilities	$100,979	$100,979	$100,979	$–	$–	$–	$–
Long term accrued liabilities	14,943	14,943	–	7,537	3,989	783	$2,634
Capital lease obligations (including interest)	13,393	14,561	5,734	5,209	2,987	462	169
Long term debt	28,446	31,242	7,637	23,605	–	–	–
Senior notes (i)	201,614	203,120	203,120	–	–	–	–
Interest on senior notes (i)	6,099	7,405	7,405	–	–	–	–
Cross-currency and interest rate swaps (ii)	89,013	92,519	92,519	–	–	–	–

(i) Based on the early redemption option exercised by the Company, the senior notes were redeemed subsequent to year end (note 33).

(ii) At March 31, 2010, the cross-currency and interest rate swaps remained contractually payable until December 1, 2011; however, these were subsequently extinguished on April 8, 2010 (note 33).

l) Capital disclosures

The Company’s objectives in managing capital are to help ensure sufficient liquidity to pursue its strategy of organic growth combined with strategic acquisitions and to provide returns to its shareholders. The Company defines capital that it manages as the aggregate of its shareholders’ equity, which is comprised of issued capital, additional paid-in capital, accumulated other comprehensive income (loss). The Company manages its capital structure and makes adjustments to it in light of general economic conditions, the risk characteristics of the underlying assets and the Company’s working capital requirements. In order to maintain or adjust its capital structure, the Company, upon approval from its Board of Directors, may issue or repay long term debt, issue shares, repurchase shares through a normal course issuer bid, pay dividends or undertake other activities as deemed appropriate under the specific circumstances. The Board of Directors reviews and approves any material transactions out of the ordinary course of business, including proposals on acquisitions or other major investments or divestitures, as well as capital and operating budgets.

The Company monitors debt leverage ratios as part of the management of liquidity and shareholders’ return and to sustain future development of the business. The Company is also subject to externally imposed capital requirements under its Revolving Facility and indenture agreement governing the U.S. Dollar denominated 8 ³/4% senior notes, which 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’s overall strategy with respect to capital risk management remains unchanged from the year ended March 31, 2009.

In September 2009, the Company filed a base shelf prospectus covering the public offering of common shares in each of the provinces and territories of Canada and a related registration statement with the United States Securities and Exchange Commission. These filings allow the Company to offer and issue common shares to the public by way of one or more prospectus supplements at any time during the 25 month period following the filing of the prospectus with gross proceeds to the Company not to exceed $150.0 million. The prospectus also allows certain shareholders of the Company to offer all or part of their common shares to the public by way of one or more prospectus supplements.

m) Recently adopted Canadian accounting pronouncements

i) Goodwill and intangible assets

Effective April 1, 2009, the Company adopted, on a retrospective basis, CICA Handbook Section 3064, “Goodwill and Intangible Assets”, which replaces Section 3062, “Goodwill and Other Intangible Assets”, and Section 3450, “Research and Development Costs” and establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The provisions relating to the definition and initial recognition of intangible assets, including internally generated intangible assets, are equivalent to the corresponding provisions of International Accounting Standard IAS 38, “Intangible Assets”. The adoption of this standard resulted in the reclassification of certain qualifying assets related to software from property, plant and equipment to intangible assets for all periods presented.

ii) Business combinations

On July 1, 2009, the Company early adopted CICA Handbook Section 1582, “Business Combinations”, effective April 1, 2009. This section establishes standards for the accounting of business combinations, and states that all assets and liabilities of an acquired business will be recorded at fair value. Obligations for contingent consideration and contingencies will also be recorded at fair value at the acquisition date. The standard also states that acquisition related costs will be expensed as incurred, that restructuring charges will be expensed in periods after the acquisition date and that non-controlling interests should be measured at fair value at the date of acquisition. This standard is to be applied prospectively to business combinations with acquisition dates on or after April 1, 2009. This new standard was applied to the acquisition of DF Investments Limited and its subsidiary Drillco Foundation Co. Ltd. (note 5(a)).

North American Energy Partners Inc.  Notes to Consolidated Financial Statements  53

iii) Consolidated financial statements

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

iv) Non-controlling interests

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

v) Equity

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

vi) Financial instruments – recognition and measurement

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

vii) Financial instruments – disclosure

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

n) Recent Canadian accounting pronouncements not yet adopted

i) Accounting changes

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

ii) Financial instruments – recognition and measurement

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

iii) Comprehensive revaluation of assets and liabilities

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

iv) Multiple deliverable arrangements

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

54  Notes to Consolidated Financial Statements  North American Energy Partners Inc.

EX-99.3

EXHIBIT 99.3

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the year ended March 31, 2010

Table of Contents

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

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

Management’s Discussion and Analysis

For the year ended March 31, 2010

A. Explanatory Notes

June 10, 2010

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

Caution Regarding Forward-Looking Information

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

Non-GAAP Financial Measures

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

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

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

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

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

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

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

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

Adoption of United States GAAP

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

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

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

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

B. Business Overview and Strategy

Business Overview

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

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

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

While our mining services are primarily focused on the oil sands, we believe that we have demonstrated our ability to successfully export knowledge and technology gained in the oil sands and put it to work in other resource development projects across Canada. As an example, in fiscal 2008 we successfully completed the development of a diamond mine site in Northern Ontario. This three-year project required us to operate effectively in a remote location in the extreme

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

² Suncor Energy Inc. (Suncor).

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

⁴ Canadian Natural Resources Limited (Canadian Natural).

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

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

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

Operations Overview

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

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

Heavy Construction and Mining

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

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

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

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

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

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

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

Piling

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

Pipeline

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

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

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

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

End Markets Overview

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

Canadian Oil Sands

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

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

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

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

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

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

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

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

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

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

Current Canadian Oil Sands Business Conditions

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Commercial and Public Construction

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

Current Commercial and Public Construction Business Conditions

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

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

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

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

Conventional Oil and Gas

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

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

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

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

Current Conventional Oil and Gas Business Conditions

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

Minerals Mining

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

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

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

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

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

Current Minerals Mining Business Conditions

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

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

Revenue Sources

Revenue by Category

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

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

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

_Ÿ Long-term contracts. This category of revenue consists of revenue generated from long-term contracts (greater than one year) with total contract values greater than $20 million. These contracts are for work that supports the operations of our customers and include long-term contracts for overburden removal and reclamation. Revenue in this category is typically generated under unit-price contracts and is included in our calculation of backlog. This work is generally funded from our customers’ operating budgets.

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

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

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

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

Revenue by End Market

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

Our Strategy

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

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

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

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

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

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

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

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

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

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

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

C. Financial Results

Adjustments related to prior year financial statements

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

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

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

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

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

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

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

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

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

Differences between US and Canadian GAAP

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

Capitalization of interest

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

Financing costs, discounts and premiums

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

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

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

Stock-based compensation

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

Derivative financial instruments

Under Canadian GAAP, we determined that our early prepayment option included in the senior notes should be bifurcated from the host contract, along with a contingent embedded derivative in our 8 ³/4% senior notes that provides for accelerated redemption by the holders in certain instances. These embedded derivatives were measured at fair value at the inception of the senior notes and the residual amount of the proceeds was allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of our 8 ³/4% senior notes is accreted to par value over the term of the notes using the effective interest method and is recognized as interest expense. Prior to April 1, 2007 under Canadian GAAP, separate accounting of embedded derivatives from the host contract was not permitted by EIC-117.

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

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

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

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

NAEPI Series B Preferred Shares

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

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

Inventories

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

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

Joint venture

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

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

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

Other matters

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

Summary of differences between US and Canadian GAAP

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

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

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

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

Consolidated Annual Results

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

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

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

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

Analysis of Annual Consolidated Results

Revenue

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

Gross Profit

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

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

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

Operating income (loss)

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

Net income (loss)

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

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

Segment Annual Results

Heavy Construction and Mining

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

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

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

Piling

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

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

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

Pipeline

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

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

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

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

Consolidated Three Month Results

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

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

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

Analysis of Three Month Results

Revenue

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

Gross Profit

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

Operating income (loss)

For the three months ended March 31, 2010, we recorded operating income of $13.1 million, or 6.0% of revenue, compared to an operating loss of $129.2 million, during the same period last year. Last year’s operating loss reflects the non-cash impact of a $143.4 million impairment of goodwill. Excluding this impairment, operating income would have been $14.2 million or 8.1% of revenue for the three months ended March 31, 2009. General and administrative (G&A)

North American Energy Partners Inc.  Management’s Discussion and Analysis  17

expense for the three months ended March 31, 2010 increased by $2.4 million, reflecting a change in value of the employee short-term incentive plan liability in the current year and the year-over-year increase to stock-based compensation expense, resulting from the impact of the increased value in our share price that impacted on the valuation of our deferred director share units and restricted share units.

Net loss

We recorded net loss of $0.9 million (basic and diluted loss per share of $0.03) for the three months ended March 31, 2010, compared to net loss of $137.1 million (basic loss per share of $3.80) during the same period last year. Non-cash items negatively affecting net income included non-cash losses on embedded derivatives in long-term customer contracts, losses on embedded derivatives in long-term supplier contracts and losses on the cross currency. This was partially mitigated by gains on the redemption options on the derivative within the 8 ³/4% senior notes, gain on the interest rate swap and the foreign exchange gain on the 8 ³/4% senior notes which resulted from the appreciation of the Canadian dollar. Excluding these non-cash items in the current and prior period, we would have had an impact of nil (basic income per share of nil) down from net income of $2.2 million (basic and diluted income per share of $0.06).

Segment Three Month Results

Heavy Construction and Mining

	Three months ended March 31,
(dollars in thousands)	2010	2009	Change
Segment revenue	$196,002	$151,952	$44,050
Segment profit	29,286	29,314	(28	)
Profit margin	14.9%	19.3%

For the three months ended March 31, 2010, the Heavy Construction and Mining segment achieved revenues of $196.0 million, a $44.1 million increase from the same period last year. A 32.8% increase in recurring services compared to a year ago, reflects increased volumes with Canadian Natural, Shell Albian and Suncor, partially offset by reduced volumes with Syncrude due to increased competition. Higher overburden removal volumes at Canadian Natural’s Horizon mine in the current period reflect normal production levels, compared to the same period last year when activity was delayed during the commissioning of the Horizon project. Higher volumes with Shell Albian reflect continued strong activity levels under our three year earthmoving and mine support services agreement signed earlier in the year and increased activity with Suncor reflects work performed under our recently renewed 12 month mining services contract with this customer.

Recurring services represented 87.9% of Heavy Construction and Mining’s revenues in the three month period ended March 31, 2010 compared to 85.5% in the same period last year.

Segment margins, for the three months ended March 31, 2010, were 14.9%, compared to 19.3% during the same period last year, reflecting the return to normal segment margins in the current period. Segment margins in the prior year period benefitted from a redeployment of equipment from the overburden project to other sites as well as the processing of change orders related to several large projects completed in the period.

Piling

	Three months ended March 31,
(dollars in thousands)	2010	2009	Change
Segment revenue	$18,263	$22,367	$(4,104)
Segment profit	2,149	6,331	(4,182	)
Profit margin	11.8%	28.3%

The Piling segment achieved revenues of $18.3 million in the three months ended March 31, 2010, a decrease of $4.1 million compared to the same period last year. The change in Piling revenues reflects the lower level of activity in the commercial construction market as well as a reduction in high-volume oil sands projects.

For the three months ended March 31, 2010 segment margins decreased to 11.8%, from 28.3% in the same period last year. The negative effect of the declining commercial construction market, delays in processing change orders and productivity issues on a larger lump-sum job were key contributors to this decline. Profit margins for the prior year period also benefitted from the processing of change orders related to large projects completed in the period.

18  Management’s Discussion and Analysis  North American Energy Partners Inc.

Pipeline

	Three months ended March 31,
(dollars in thousands)	2010		2009	Change
Segment revenue	$6,304		$381	$5,923
Segment (loss) profit	(5,152	)	6	(5,158)
Profit margin	(81.7)%		1.6%

Pipeline revenues for the three months ended March 31, 2010 increased $5.9 million from the same period a year ago, reflecting an increase in project activity.

The segment loss for the three months ended March 31, 2010 reflects the negative impact of unfavourable weather conditions and reduced productivity on a single lump-sum Pipeline project.

Non-Operating Income and Expense

	Three Months Ended March 31,				Year Ended March 31,
(dollars in thousands)	2010		2009		2010		2009		2008
Interest expense
Interest on 8 3/4% senior notes and swaps	$4,573		$7,876		$19,041		$25,379		$23,338
Interest on capital lease obligations	227		347		1,032		1,234		780
Amortization of deferred financing costs	859		780		3,348		2,970		2,899
Interest on credit facilities	990		92		2,375		298		769
Interest on long-term debt	$6,649		$9,095		$25,796		$29,881		$27,786
Other Interest	(294	)	(759	)	284		(269	)	1,294
Total Interest expense	$6,355		$8,336		$26,080		$29,612		$29,080
Foreign exchange (gain) loss	$(5,971	)	$7,651		$(48,901	)	$47,272		$(25,660	)
Realized and unrealized loss (gain) on derivative financial instruments	11,226		(11,424	)	54,411		(37,250	)	30,075
Other income	(818	)	(591	)	(14	)	(5,955	)	(418	)
Income tax expense	3,278		3,936		13,679		14,633		17,116

Interest expense

The cancellation of one leg of the swap agreement on February 2, 2009, one of three swap agreements hedging the interest and currency risk associated with our US dollar denominated 8 ³/4% senior notes, led to an increase in the interest rate swap payment as shown in the “Realized and unrealized loss (gain) on derivative financial instruments” section below. The combination of our interest expense on 8 ³/4% senior notes and the swap interest payment loss reflects the higher cost to us as a result of the counterparty’s cancellation of this US dollar interest rate swap. With the cancellation of this US dollar interest rate swap, by the counterparties, we also became exposed to currency risk and interest rate risk on the coupon payment. A more detailed discussion about our currency and interest rate risk can be found under “Quantitative and Qualitative Disclosures about Market Risk”.

Compared to the corresponding periods in the prior years, interest on our 8 ³/4% senior notes decreased $3.3 million and $6.3 million for the three months and year ended March 31, 2010, respectively. The cancellation of the interest rate swap along with the strengthening of the Canadian dollar in the current year resulted in this decrease. The corresponding increases in swap interest payment loss of $3.5 million and $12.9 million for the three months and year ended March 31, 2010, respectively, reflects the combined impact of the counterparties’ cancellation of this US dollar interest rate swap.

Foreign exchange (gain) loss

The foreign exchange gains recognized in the current year and three month periods relate primarily to changes in the strength of the Canadian dollar against the US dollar on conversion of the US$200 million 8 ³/4% senior notes. A significant increase in the value of the Canadian dollar, from 0.7935 CAN/US at March 31, 2009 to 0.9555 CAN/US at December 31, 2009 and then to 0.9846 CAN/US at March 31, 2010, resulted in significant unrealized foreign exchange gains for both the current three month and annual periods, respectively. The Canadian dollar weakened during the three months and year ended March 31, 2009, resulting in unrealized foreign exchange losses for the respective periods. The Canadian dollar strengthened during the year ended March 31, 2008, resulting in an unrealized foreign exchange gain for the period. A more detailed discussion about our foreign currency risk can be found under “Quantitative and Qualitative Disclosures about Market Risk – Foreign exchange risk”.

North American Energy Partners Inc.  Management’s Discussion and Analysis  19

Realized and unrealized loss (gain) on derivative financial instruments

The realized and unrealized loss (gain) on derivative financial instruments reflect changes in the fair value of derivatives embedded in our US dollar denominated 8  ³/4% senior notes, as well as changes in the fair value of the cross-currency and interest rate swaps that we employ to provide an economic hedge for our US dollar denominated 8 ³/4% senior notes. Realized and unrealized gains and losses also include changes to embedded derivatives in a long-term construction contract and in supplier maintenance agreements. The realized and unrealized losses and (gains) on these derivative financial instruments, for the three and twelve months ended March 31, 2010, are detailed in the table below:

	Three months ended March 31,					Year ended March 31,
(dollars in thousands)	2010	2009		Change		2010		2009		2008		2010 vs. 2009 Change		2010 vs. 2008 Change
Swap liability loss (gain)	$6,344	$(13,303	)	$19,647		$49,078		$(49,613	)	$20,788		$98,691		$28,290
Redemption options embedded derivatives (gain) loss	(118)	1,420		(1,538	)	(3,716	)	3,331		249		(7,047	)	(3,965	)
Supplier contracts embedded derivatives loss (gain)	643	2,010		(1,367	)	(13,315	)	21,509		(1,205	)	(34,824	)	(12,110	)
Customer contract embedded derivative loss (gain)	190	(2,218	)	2,408		6,805		(15,145	)	7,575		21,950		(770	)
Swap interest payment	4,167	667		3,500		15,559		2,668		2,668		12,891		12,891
Total	$11,226	$(11,424	)	$22,650		$54,411		$(37,250	)	$30,075		$91,661		$24,336

The swap liability loss (gain) reflects changes in the fair value of the cross-currency and interest rate swaps that we employ to provide an economic hedge for our US dollar denominated 8 ³/4% senior notes. Changes in the fair value of these swaps generally have an offsetting effect to changes in the value of our 8  ³/4% senior notes (and resulting foreign exchange gains and losses), with both being triggered by variations in the Canadian/US exchange rate. However, the valuations of the derivative financial instruments are also impacted by changes in interest rates and the remaining present value of scheduled interest payments on the swaps, which occur in June and December of each year until maturity.

The redemption options embedded derivatives (gain) loss reflects changes in the fair value of the derivative embedded in our US dollar denominated 8  ³/4% senior notes. Changes in fair value result from changes in long-term bond interest rates during a reporting period.

With respect to the supplier contracts, the embedded derivative related to a long-term maintenance contract was increased due to changes in the underlying base price index in the three months ended March 31, 2010. For the year ended March 31, 2010, the embedded derivative related to the long-term maintenance contract was reduced with the commissioning of certain pieces of heavy equipment. Included in the embedded derivative valuation was the impact of fluctuations in provisions that require a price adjustment to reflect changes in the Canadian/US dollar exchange rate and the United States government published Producers’ Price Index (US-PPI) for Mining Machinery and Equipment from the original contract amount.

With respect to the long-term construction contract, there is a provision that requires an adjustment to customer billings to reflect actual exchange rates and price indices. The embedded derivative instrument takes into account the impact on revenues, but does not consider the impact on costs as a result of fluctuations in these measures.

The measurement of embedded derivatives, as required by GAAP, causes our reported net income to fluctuate as Canadian/US dollar exchange rates, interest rates and the US-PPI for Mining Machinery and Equipment change. The accounting for these derivatives has no impact on operations, Consolidated EBITDA (as defined within our credit agreement) or how we evaluate performance.

The measurement of swap interest payment loss reflects the realized loss on our swap interest payments. As of February 2, 2009, one of three swap agreements hedging the interest and currency risk associated with our US dollar denominated 8 ³/4% senior notes was cancelled by the counterparties. The counterparties’ cancellation of this US dollar interest rate swap increased swap interest payments and we are now exposed to interest rate and foreign currency risk. For the current year, we paid higher swap interest payments net of swap counterparty receipts.

As discussed in the interest expense discussion of this MD&A, the financial impact of the counterparties’ cancellation of this US dollar interest rate swap is reported in swap interest payment loss. The year-over-year increases in swap interest payment loss of $3.5 million and $12.9 million for the three months and year ended March 31, 2010, respectively, reflect the effect of the counterparties’ cancellation of this US dollar interest rate swap as the semi-annual fixed payments exceed the floating quarterly interest received from our swap counterparties.

20  Management’s Discussion and Analysis  North American Energy Partners Inc.

Income tax expense

For the three months ended March 31, 2010, we recorded current income taxes of $1.9 million and deferred income tax of $1.3 million for a total income tax expense of $3.3 million. This compares to combined income tax expense of $3.9 million for the same period last year. For the three months ended March 31, 2010, income tax expense as a percentage of income before income taxes differs from the statutory rate of 28.91% primarily due to the impact of income tax adjustments and reassessments, non-deductible items and changes in the timing of the reversal of temporary differences. For the three month period ended March 31, 2009, income tax expense as a percentage of income before income taxes differed from the statutory rate of 29.38% primarily due to non-deductible items, including a permanent difference relating to the $143.4 million non-deductible goodwill impairment.

For the year ended March 31, 2010, we recorded current income taxes of $3.8 million and deferred income tax expense of $9.9 million for a total income tax expense of $13.7 million. This compares to combined income tax expense of $14.6 million for the same period last year. For the year ended March 31, 2010, income tax expense as a percentage of income before income taxes differs from the statutory rate of 28.91% primarily due to the impact of income tax adjustments and reassessments, non-deductible items and changes in the timing of the reversal of temporary differences. For the year ended March 31, 2009, income tax expense as a percentage of income before income taxes differed from the statutory rate of 29.38% primarily due to non-deductible items, as well as a permanent difference relating to the $176.2 million non-deductible goodwill impairment. For the year ended March 31, 2008, income tax expense as a percentage of income before income taxes differed from the statutory rate of 31.47% primarily due to the impact of enacted rate changes during the period.

Backlog

Backlog is a measure of the amount of secured work we have outstanding and, as such, is an indicator of a base level of future revenue potential. Backlog is not a GAAP measure. As a result, the definition and determination of a backlog will vary among different organizations ascribing a value to backlog. Although backlog reflects business that we consider to be firm, cancellations or reductions may occur and may reduce backlog and future income.

We define backlog as work that has a high certainty of being performed as evidenced by the existence of a signed contract or work order specifying job scope, value and timing. We have also set a policy that our definition of backlog will be limited to contracts or work orders with values exceeding $500,000 and work that will be performed in the next five years, even if the related contracts extend beyond five years.

Our measure of backlog does not define what we expect our future workload to be. We work with our customers using cost-plus, time-and-materials, unit-price and lump-sum contracts. This mix of contract types varies year-by-year. Our definition of backlog results in the exclusion of a range of services to be provided under cost-plus and time-and-material contracts performed under master service agreements where scope is not clearly defined. For the three and twelve months ended March 31, 2010, the total amount of revenue earned from time-and-material contracts performed under our master services agreements was approximately $116.5 million and $422.6 million respectively.

Our estimated backlog by segment and contract type as at March 31, 2010, December 31, 2009 and March 31, 2009 was:

By Segment

(dollars in thousands)	March 31, 2010	December 31, 2009	March 31, 2009
Heavy Construction and Mining	$725,767	$718,418	$667,674
Piling	16,423	9,091	8,538
Pipeline	6,861	14,763	–
Total	$749,051	$742,272	$676,212
By Contract Type
(dollars in thousands)	March 31, 2010	December 31, 2009	March 31, 2009
Unit-Price	$722,710	$722,663	$672,725
Lump-Sum	18,429	9,102	3,487
Time-and-Material, Cost-Plus	7,912	10,507	–
Total	$749,051	$742,272	$676,212

A contract with a single customer represented approximately $706.7 million of the March 31, 2010 backlog compared to $681.4 million reported as backlog in our Management’s Discussion and Analysis for the three and nine months ended December 31, 2009. The change in the five year backlog for this customer relates to the timing of scheduled volumes through the life of the contract.

We expect that approximately $226.7 million of total backlog will be performed and realized in the 12 months ending March 31, 2011.^*

^* This paragraph contains forward-looking statements. Please refer to “Forward-Looking Information and Risk Factors” for a discussion of the risks and uncertainties related to such information.

North American Energy Partners Inc.  Management’s Discussion and Analysis  21

Claims and Change Orders

Due to the complexity of the projects we undertake, changes often occur after work has commenced. These changes include but are not limited to:

_Ÿ changes in client requirements, specifications and design;

_Ÿ changes in materials and work schedules; and

_Ÿ changes in ground and weather conditions.

Contract change management processes require that we prepare and submit change orders to the client requesting approval of scope and/or price adjustments to the contract. Accounting guidelines require that we consider changes in cost estimates that have occurred up to the release of the financial statements and reflect the impact of these changes in the financial statements. Conversely, potential revenue associated with increases in cost estimates is not included in financial statements until an agreement is reached with a client or specific criteria for the recognition of revenue from unapproved change orders and claims are met. This can, and often does, lead to costs being recognized in one period and revenue being recognized in subsequent periods.

Occasionally, disagreements arise regarding changes, their nature, measurement, timing and other characteristics that impact costs and revenue under the contract. If a change becomes a point of dispute between our customer and us, we then consider it to be a claim. Historical claim recoveries should not be considered indicative of future claim recoveries.

For the three months and year ended March 31, 2010, due to the timing of receipt of signed change orders, the Heavy Construction and Mining segment had approximately $0.1 million and $1.2 million respectively in claims revenue recognized to the extent of costs incurred, the Piling segment had $0.3 million and $1.3 million respectively in claims revenue recognized to the extent of costs incurred and the Pipeline segment had $0.4 million and $2.1 million respectively in claims revenue recognized to the extent of costs incurred. We are working with our customers to come to resolution on additional amounts, if any to be paid to us in respect to these additional costs.

Summary of Consolidated Quarterly Results

	Fiscal 2010					Fiscal 2009
(dollars in millions, except per share amounts)	Q4		Q3	Q2	Q1	Q4		Q3		Q2	Q1
Revenue	$220.6		$221.2	$170.7	$146.5	$174.7		$258.6		$280.3	$259.0
Gross profit	32.7		47.6	33.8	25.1	32.9		51.4		44.7	41.3
Operating income (loss)	13.1		31.3	18.9	10.1	(129.2	)	(1.9	)	23.4	20.6
Net income (loss)	(0.9	)	14.9	4.3	9.9	(137.1	)	(15.0	)	2.9	13.8
Net income (loss) per share – Basic(1)	$(0.03	)	$0.41	$0.12	$0.28	$(3.80	)	$(0.42	)	$0.08	$0.38
Net income (loss) per share – Diluted(1)	(0.03	)	0.41	0.12	0.27	(3.80	)	(0.42	)	0.08	0.37

⁽¹⁾ Net income (loss) per share for each quarter has been computed based on the weighted average number of shares issued and outstanding during the respective quarter; therefore, quarterly amounts may not add to the annual total. Per-share calculations are based on full dollar and share amounts.

A number of factors have the potential to contribute to variations in our quarterly financial results between periods, including the capital project-based nature of our project development revenue, seasonal weather and ground conditions, capital spending decisions by our customers on large oil sands projects, the timing of equipment maintenance and repairs, claims and change orders and the accounting for unrealized non-cash gains and losses related to foreign exchange and derivative financial instruments.

We generally experience a decline in revenues during the first three months of each fiscal year due to seasonality, as weather conditions make performance in our operating regions difficult during this period. The level of activity in the Heavy Construction and Mining and Pipeline segments declines when frost leaves the ground and many secondary roads are temporarily rendered incapable of supporting the weight of heavy equipment. The duration of this period is referred to as “spring breakup” and has a direct impact on our activity levels. Revenues during the three months ended March 31 of each fiscal year are typically highest as ground conditions are most favourable in our operating regions. As a result, full year results are not likely to be a direct multiple of any particular three month period or combination of three month periods. In addition to revenue variability, gross margins can be negatively impacted in less active periods because we are likely to incur higher maintenance and repair costs due to our equipment being available for servicing.

The timing of large projects can influence quarterly revenues. For example, Pipeline segment revenues were as high as $55.6 million in the three month period ended September 30, 2008, as low as $0.1 million in the three months ended June 30, 2009 and are currently at $6.3 million for the three month period ended March 31, 2010. The Heavy Construction and Mining segment experienced reduced volumes in the three month periods ending December 31, 2008 and March 31, 2009 as a result of the temporary shut-down of overburden removal at the Horizon project while Canadian Natural prepared for operations start-up. Subsequent three month periods reflected the ramp up of overburden removal activities at the Horizon project through to the current three month period where activity has returned to planned

22  Management’s Discussion and Analysis  North American Energy Partners Inc.

activity levels. Changes in demand under our master service agreements with Shell Albian and Syncrude had a positive effect on our revenues for the three month periods ended June 30, 2008, September 30, 2008 and December 31, 2008 respectively. Changes in demand from Syncrude had a negative effect on our revenues for the three month periods subsequent to December 31, 2008, while master service agreement demand from Shell Albian continues to positively affect period-over-period comparatives.

Variations in quarterly results can also be caused by changes in our operating leverage. During periods of higher activity, we have experienced improvements in operating margin. This reflects the impact of relatively fixed costs, such as G&A costs, being spread over higher revenue levels. If activity decreases, these same fixed costs are spread over lower revenue levels. Net income and income per share are also subject to operating leverage as provided by fixed interest expense.

Profitability also varies from quarter-to-quarter as a result of claims and change orders. Claims and change orders are a normal aspect of the contracting business but can cause variability in profit margin due to the unmatched recognition of costs and revenues. For further explanation, see “Claims and Change Orders”. As an example, during the three month period ending June 30, 2008, a $5.3 million claim was recognized causing gross margins for the Pipeline segment to be higher than normal. The additional costs relating to this claim were incurred and recognized in the year ended March 31, 2007 and in the three month period ended June 30, 2007.

We have also experienced net income variability in all periods due to the recognition of unrealized non-cash gains and losses on both derivative financial instruments and our 8 ³/4% senior notes, primarily driven by changes in the Canadian/ US dollar exchange rates.

Summary of Consolidated Financial Position

	Year ended March 31,
(dollars in thousands)	2010		2009		2008		2010 vs 2009 Change		2010 vs 2008 Change
Cash	$103,005		$98,880		31,863		4,125		71,142
Current assets (excluding cash)	212,607		157,858		260,606		54,749		(47,999	)
Current liabilities	(165,641	)	(127,957	)	(177,650	)	(37,684	)	12,009
Net working capital	149,971		128,781		114,819		21,190		35,152
Property, plant and equipment	328,743		316,115		276,319		12,628		52,424
Total assets	702,617		629,275		802,336		72,342		(99,719	)
Capital lease obligations (including current portion)	(13,393	)	(17,484	)	(14,776	)	4,091		1,383
Total long-term financial liabilities(1)	(327,356	)	(318,559	)	(314,751	)	(8,797	)	(12,605	)

⁽¹⁾ Total long-term financial liabilities exclude the current portions of capital lease obligations, current portions of derivative financial instruments, long-term lease inducements, asset retirement obligation and both current and non-current future income tax balances.

At March 31, 2010, net working capital (current assets less current liabilities) was $150.0 million compared to $128.8 million at March 31, 2009 and $114.8 million at March 31, 2008. This was an increase of $21.2 million and an increase of $35.2 million over March 31, 2009 and 2008, respectively.

Current assets excluding cash increased $54.7 million between March 31, 2009 and March 31, 2010. A $33.6 million increase in trade receivables and holdbacks along with a $28.8 million increase in unbilled revenue during the year ended March 31, 2010 was partially offset by a $6.2 million reduction of inventory from consumption of tires, previously stockpiled for new leased haul trucks (haul trucks do not arrive with tires included). The prior year trade receivables, holdbacks and unbilled revenue balances benefitted from the completion and settlement of projects at Suncor’s Fort Hills and Kinder Morgan’s TMX. Current assets excluding cash decreased $48.0 million between March 31, 2008 and March 31, 2010. A $55.1 million decrease in trade receivables and holdbacks along with a $3.7 million decrease in other assets, and a $2.4 million decrease in prepaid expenses and deposits during the year ended March 31, 2010 was partially offset by a $13.8 million increase in unbilled revenue and a $4.2 million increase in inventory.

Current liabilities during the year ended March 31, 2010 increased by $37.7 million, reflecting a $10.7 million increase in accounts payable, a $10.6 million increase in current portion of derivative financial instruments, a $6.1 million increase in current portion of long term debt, a $2.2 million increase in accrued liabilities and a $9.0 million increase in deferred tax liabilities. Equipment purchases of $6.3 million, which are scheduled to be paid after March 31, 2010, are included in accounts payable as of March 31, 2010. Current liabilities during the year ended March 31, 2010 were comparable to March 31, 2008, reflecting a $46.3 million decrease in accounts payable offset by $7.8 million increase in accrued liabilities and $6.1 million increase in current portion of long term debt, resulting from new term loans under our amended and restated credit agreement and $17.3 million re-class of the swap liability from long-term to current portion, due to the settlement of the swap liability on April 8, 2010. For a more detailed discussion of the swap liability settlement please refer to “Interest rate risk” in Quantitative and Qualitative disclosures about Market Risk.

North American Energy Partners Inc.  Management’s Discussion and Analysis  23

Property, plant and equipment increased by $12.6 million between March 31, 2009 and March 31, 2010. This reflects the capital investment of $56.7 million of equipment purchases and new capital leases during the year ended March 31, 2010, offset by equipment disposals of $2.7 million (net book value) and depreciation of $42.6 million. Property, plant and equipment increased by $52.4 million between March 31, 2008 and March 31, 2010.

Total long-term financial liabilities increased by $8.8 million between March 31, 2009 and March 31, 2010, due to a $32.0 million increase related to the cross-currency and interest rate swap agreements, an increase of $22.4 million in the long-term portion of our term loan resulting from new term loans under our amended and restated credit agreement, an increase in the long-term contingent rent liability on our operating leases and an increase of $5.4 million in the value of the long-term portion of the embedded derivatives in a long-term revenue construction contract. This was partially offset by a $52.6 million decrease in the carrying amount of our 8  ³/4% senior notes, a $5.6 million decrease related to the long-term portion of the embedded derivatives in long-term supplier contracts and a $3.7 million decrease in the non-current portion of our capital lease obligations. Total long-term financial liabilities increased by $12.6 million between March 31, 2008 and March 31, 2010, due to a $9.2 million increase in long-term accrued liabilities related to the contingent rent on operating leases, a $3.4 million increase in liabilities related to stock based compensation, an increase of $22.4 million in the long-term portion of our term loan resulting from new term loans under our amended and restated credit agreement. The increases were partially offset by a $17.3 re-class of swap liability to short term as stated above, a $2.7 million decrease in the carrying amount of senior notes related to the decrease in the exchange rate and a $1.7 million decrease in the non-current portion of our capital lease obligations.

Summary of Consolidated Cash Flows

	Three months ended March 31,						Year ended March 31,
(dollars in thousands)	2010		2009		Change		2010		2009	2008	2010 vs. 2009 Change		2010 vs. 2008 Change
Cash provided by operating activities	$16,477		$71,989		$(55,512	)	$42,869		$151,185	$94,797	$(108,316	)	$(51,928	)
Cash used in investing activities	(5,312	)	(11,276)		5,964		(59,611	)	(78,715)	(45,932)	19,104		(13,679	)
Cash (used in) provided by financing activities	(3,037	)	(1,436	)	(1,601	)	20,867		(5,453)	(23,992)	26,320		44,859
Increase in cash and cash equivalents	$8,128		$59,277		$(51,149)		$4,125		$67,017	$24,873	$(62,892	)	$(20,748	)

Operating activities

Cash provided by operating activities for the three months ended March 31, 2010 was an inflow of $16.5 million, compared to a cash inflow of $72.0 million for the three months ended March 31, 2009. The lower cash provided by operating activities in the current period is primarily a result of lower gross profit, higher effective interest costs and increased non-cash net working capital.

Cash provided by operating activities for the year ended March 31, 2010 was an inflow of $42.9 million, compared to cash inflows of $151.2 million and $94.8 million for the years ended March 31, 2009 and 2008 respectively. The lower cash provided by operating activities in the current period is primarily a result of lower gross profit, higher effective interest costs and increased non-cash net working capital. The cash inflow for the year ended March 31, 2009 benefitted from significant project closeout activities in the period.

Investing activities

Cash used in net investing activities for the three months ended March 31, 2010 was an outflow of $5.3 million compared with an outflow of $11.3 million for the same period a year ago. Investing activities this current period included capital and intangible asset expenditures of $7.3 million. Proceeds from asset dispositions of $0.5 million and a net inflow from non-cash working capital of $2.2 million lessened the effect of capital purchases. Cash used in investing activities last year included a net outflow from non-cash working capital of $3.8 million and capital and intangible asset expenditures of $9.2 million, offset by an inflow of proceeds from asset dispositions of $3.5 million.

Cash used in net investing activities for the year ended March 31, 2010 was an outflow of $59.6 million compared with outflows of $78.7 million and $45.9 million for the years ended March 31, 2009 and 2008, respectively. Current period investing activities included capital and intangible expenditures of $55.4 million along with $5.4 million for the acquisition of DF Investments Limited. A cash inflow of proceeds from asset dispositions of $3.9 million and a net inflow from non-cash working capital of $1.8 million lessened the effect of cash outflows for capital purchases and the acquisition. Cash used in investing activities last year included capital and intangible expenditures of $87.5 million, partially offset by proceeds from asset dispositions of $11.5 million and a net inflow from non-cash working capital of $0.6 million. Cash used in investing activities for the year ended March 31, 2008 included capital and intangible expenditures of $55.1 million along with $1.6 million for the acquisition of Active Auger Services 2001 Ltd., partially offset by proceeds from asset dispositions of $17.1 million.

24  Management’s Discussion and Analysis  North American Energy Partners Inc.

Financing activities

Cash used in financing activities during the three month period ended March 31, 2010 resulted in a cash outflow of $3.0 million as a result of a scheduled $1.5 million repayment on our term credit facility and a $1.4 million repayment of capital lease obligations. Cash used in financing activities for the three month period ended March 31, 2009 of $1.4 million was a result of the scheduled repayment of capital lease obligations.

Cash provided by financing activities during the year ended March 31, 2010 resulted in a cash inflow of $20.9 million. Capital expenditure financing of $28.4 million, through our new term credit facility (net of term credit facility repayments), was partially offset by the $5.6 million repayment of capital lease obligations, $1.1 million in financing costs for our amended and restated credit agreement and the repayment of debt assumed with the acquisition of DF Investments Limited. Cash used in financing activities for the year ended March 31, 2009 of $5.5 million was a result of the $6.2 million repayment of capital lease obligations partially offset by the cash settlement of stock options. Cash used in financing activities for the year ended March 31, 2008 of $24.0 million included a $20.5 million repayment to the revolving credit facility and the $3.8 million repayment of capital leases. The $1.6 million proceeds from exercised stock options was partially offset by the expenditure of $0.8 million for financing costs and $0.6 million for cash settlement of stock options.

D. Outlook

While our expectations for the 2011 fiscal year remain cautious, recent market and industry activity suggest we are now past the worst of the economic downturn and we expect to see demand for our services gradually strengthen as the year progresses.*

In the oil sands, we expect that project development opportunities will continue to expand with Exxon’s Kearl, ConocoPhillips’s Surmont and Suncor’s Firebag projects moving forward. We have been successful in securing piling and heavy construction-related projects on Exxon’s Kearl project and we intend to continue pursuing opportunities on this and other projects. ^*

In our recurring services business, we anticipate some short-term demand variability in early fiscal 2011 as Shell Albian completes a major maintenance program and Suncor repairs damage caused by a recent fire at its plant. Demand for recurring services at these sites is expected to recover during the second quarter of fiscal 2011 and remain stable through the balance of the year. Overburden removal activity at Canadian Natural’s Horizon is expected to remain at normal levels during the year and we expect to provide steady support to Syncrude after recently renewing our site services agreement with this customer.^*

We also see opportunities to continue building our oil sands business with new tailings pond management and reclamation services. The oil sands industry is currently responding to environmental concerns and more stringent requirements relating to the remediation of tailings ponds under the recently released Directive 74. In calendar 2010, the Alberta Energy Resources Conservation Board (ERCB) will review proposals from all of the oil sands producers to modify existing tailings disposal systems to meet the new requirements. Once these plans are approved, the producers will have to implement these new systems, which will involve anything from new and/or smaller ponds to drying lay down areas. We believe these and the associated infrastructure will generate opportunities for us to provide an expanded range of services in support of these initiatives. Given the aggressive timelines set out for producers to achieve regulatory compliance and the amount of tailings material that will need to be addressed, we believe this has the potential to become a significant revenue growth opportunity over time.^*

In the Pipeline division, we have recently been awarded two new contracts that we expect to complete during fiscal 2011. These include the second phase of Spectra Energy’s Maxhamish Loop project, which involves construction of a 30 km, 24 inch pipeline in British Columbia. We were awarded this follow-on contract after completing the first phase safely and on schedule, despite adverse operating conditions. We were able to adjust the forecast production rates to reduce risk because the customer recognized and understood the conditions we met in the first stage. We have also been awarded the contract for TransCanada Pipelines’ NPS Groundbirch Mainline project. This project involves construction of a 77 km, 36 inch pipeline, also in British Columbia. Overall, the Pipeline construction market remains highly competitive with an oversupply of contractor capacity in the marketplace. As a result, contracts continue to be negotiated with higher-than-normal contractor risk exposure and low margins. We believe we have mitigated our risk exposure in our new contracts and we expect a return to profitability in the Pipeline segment in fiscal 2011.^*

In our Piling division, we expect to see a gradual increase in opportunities as fiscal 2011 progresses. Demand has now begun to improve in the commercial and public construction market with the result that we have already secured significant work for the coming year. We expect this improvement to continue as the year progresses.^*

Overall, the markets we serve are experiencing gradually improving economic conditions and we expect this to be the trend in Canada, led by Alberta, for several years to come.^*

^* This paragraph contains forward-looking statements. Please refer to “Forward-Looking Information and Risk Factors” for a discussion of the risks and uncertainties related to such information.

North American Energy Partners Inc.  Management’s Discussion and Analysis  25

E. Legal and Labour Matters

Laws and Regulations and Environmental Matters

Many aspects of our operations are subject to various federal, provincial and local laws and regulations, including, among others:

_Ÿ permitting and licensing requirements applicable to contractors in their respective trades;

_Ÿ building and similar codes and zoning ordinances;

_Ÿ laws and regulations relating to consumer protection; and

_Ÿ laws and regulations relating to worker safety and protection of human health.

We believe that we have all material required permits and licenses to conduct our operations and are in substantial compliance with applicable regulatory requirements relating to our operations. Our failure to comply with the applicable regulations could result in substantial fines or revocation of our operating permits.

Our operations are subject to numerous federal, provincial and municipal environmental laws and regulations, including those governing the release of substances, the remediation of contaminated soil and groundwater, vehicle emissions and air and water emissions. These laws and regulations are administered by federal, provincial and municipal authorities, such as Alberta Environment, Saskatchewan Environment, the British Columbia Ministry of Environment, Ontario Ministry of the Environment and other governmental agencies. The requirements of these laws and regulations are becoming increasingly complex and stringent and meeting these requirements can be expensive.

The nature of our operations and our ownership or operation of property exposes us to the risk of claims with respect to environmental matters and there can be no assurance that material costs or liabilities will not be incurred with such claims. For example, some laws can impose strict joint and several liability on past and present owners or operators of facilities at, from or to which a release of hazardous substances has occurred, on parties who generated hazardous substances that were released at such facilities and on parties who arranged for the transportation of hazardous substances to such facilities. If we were found to be a responsible party under these statutes, we could be held liable for all investigative and remedial costs associated with addressing such contamination, even though the releases were caused by a prior owner or operator or third party. We are not currently named as a responsible party for any environmental liabilities on any of the properties on which we currently perform or have performed services. However, our leases typically include covenants which obligate us to comply with all applicable environmental regulations and to remediate any environmental damage caused by us to the leased premises. In addition, claims alleging personal injury or property damage may be brought against us if we cause the release of or any exposure to, harmful substances.

Our construction contracts require us to comply with all environmental and safety standards set by our customers. These requirements cover such areas as safety training for new hires, equipment use on site, visitor access on site and procedures for dealing with hazardous substances.

Capital expenditures relating to environmental matters during the fiscal years ended March 31, 2008, 2009 and 2010 were not material. We do not currently anticipate any material adverse effect on our business or financial position as a result of future compliance with applicable environmental laws and regulations. Future events, however, such as changes in existing laws and regulations or their interpretation, more vigorous enforcement policies of regulatory agencies or stricter or different interpretations of existing laws and regulations may require us to make additional expenditures which may or may not be material.

Employees and Labour Relations

As of March 31, 2010, the Company employed 412 salaried employees and over 1,815 hourly employees. Our hourly workforce fluctuates according to the seasonality of our business and the staging and timing of projects by our customers. The hourly workforce typically ranges in size from 1,000 employees to approximately 2,500 employees depending on the time of year and duration of awarded projects. We also utilize the services of subcontractors in our construction business. An estimated 8% to 10% of the construction work we do is performed by subcontractors. Approximately 1,693 employees are members of various unions and work under collective bargaining agreements. The majority of our work is done by employees governed by our mining overburden collective bargaining agreement (“Collective Agreement”) with the International Union of Operating Engineers Local 955. The Collective Agreement expired on October 31, 2009 and the Company has been involved in negotiations for the renewal of the Collective Agreement since that time. The parties reached a tentative agreement on May 27, 2010 and it is expected that it will be ratified by the union’s membership by the end of June, 2010. Other collective agreements in operation include the provincial Industrial, Commercial and Institutional (ICI) agreements in Alberta and Ontario with both the Operating Engineers and Labourers Unions, Piling sector collective agreements in Saskatchewan with the Operating Engineers and Labourers, Pipeline sector agreements in both British Columbia and Alberta with the Christian Labour Association of Canada (CLAC) as well as an all-sector agreement with CLAC in Ontario. We are subject to other industry and specialty collective agreements under which we complete work and the primary terms of all of these agreements are

26  Management’s Discussion and Analysis  North American Energy Partners Inc.

currently in effect. We believe that our relationships with all our employees, both union and non-union, are strong. We have not experienced a strike or lockout.*

F. Resources and Systems

Outstanding Share Data

We are authorized to issue an unlimited number of voting Common Shares and an unlimited number of Non-Voting Common Shares. As at June 8, 2010, there were 36,062,036 voting Common Shares outstanding (36,049,276 as at March 31, 2010). We had no Non-Voting Common Shares outstanding on any of the foregoing dates.

Liquidity and Capital Resources

Liquidity requirements

Our primary uses of cash are for plant and equipment purchases, to fulfill debt repayment and interest payment obligations, to fund operating lease obligations and to finance working capital requirements.

We maintain a significant equipment and vehicle fleet comprised of units with remaining useful lives covering a variety of time spans. It is important to adequately maintain our large revenue-producing fleet in order to avoid equipment downtime, which can impact our revenue stream and inhibit our ability to satisfactorily perform on our projects. Once units reach the end of their useful lives, they are replaced as it becomes cost prohibitive to continue to maintain them. As a result, we are continually acquiring new equipment both to replace retired units and to support our growth as we take on new projects. In order to maintain a balance of owned and leased equipment, we have financed a portion of our heavy construction fleet through operating leases. In addition, we continue to lease our motor vehicle fleet through our capital lease facilities.

We require between $30 million and $40 million annually for sustaining capital expenditures and our total capital requirements typically range from $75 million to $150 million depending on our growth capital requirements. With the potential future customer demand for larger-sized heavy equipment in the oil sands, we expect our capital needs in the next fiscal year to be approximately $50 to $75 million. We may, however increase our capital spend to approximately $100 million to take advantage of available equipment as a result of the recent declaration of bankruptcy by one of our competitors.^*

We typically finance approximately 30% to 50% of our total capital requirements through our operating lease facilities and the remainder from cash flow from operations. We believe our operating and capital lease facilities and cash flow from operations will be sufficient to meet these requirements. Our equipment fleet value is currently split among owned (43%), leased (49%) and rented equipment (8%). Approximately 38% of our leased fleet is specific to one long-term overburden removal project. This equipment mix is a change from the mix reported in previous periods as a result of our declining need for the same levels of rental equipment along with the conversion of some rental equipment to operating leases to meet specific volume demands. Our equipment ownership strategy allows us to meet our customers’ variable service requirements while balancing the need to maximize equipment utilization with the need to achieve the lowest ownership costs. We are continually evaluating our capital needs and continue to monitor equipment lead times with suppliers to ensure that we control our capital spending while still being in a position to respond to opportunities when they materialize.^*

We continue to receive interest from finance companies to support our current lease requirements and we have availability under one of our supplier’s leasing program to meet our current equipment needs from this supplier. We anticipate having sufficient lease capacity to meet our capital requirements in fiscal year 2011.^*

Long-term Debt

Our long-term debt, as at March 31, 2010, included US$200.0 million of 8 ³/4% senior unsecured notes due in December 2011 (the “8 ³/4% senior notes”). Prior to February 2, 2009, the foreign currency risk relating to both the principal and interest portions of these 8 ³/4% senior notes was managed with a cross-currency swap and interest rate swaps, which went into effect concurrent with the issuance of the notes on November 26, 2003. The swap agreements were an economic hedge but had not been designated as hedges for accounting purposes. Prior to the cancellation of the US dollar interest rate swap, interest totaling $13.0 million on the 8 ³/4% senior notes and the swap was payable semi-annually in June and December of each year until the notes would mature on December 1, 2011. The US$200.0 million principal amount was fixed at C$1.315=US$1.000, resulting in a principal repayment of $263.0 million due on December 1, 2011. There were no principal repayments required on the 8 ³/4% senior notes until maturity. Effective February 2, 2009, the US dollar interest rate swap was terminated by the counterparties and our effective interest expense increased by approximately US$6.8 million per annum (based on the then current US dollar LIBOR rates) for the remaining life of the 8 ³/4% senior notes. This increase was net of US dollar floating interest payments on the cross-currency swap agreement we received every March 1, June 1, September 1 and December 1, effective March 1, 2009 until the notes were to mature on December 1, 2011. The value of the quarterly floating rate US dollar payments we received was the prevailing 3-month US dollar LIBOR rate plus a spread of 4.2% on the notional amount of US$200.0 million. Our Canadian dollar interest rate swap and cross-currency swap agreements are not cancellable at the option of

^* This paragraph contains forward-looking statements. Please refer to “Forward-Looking Information and Risk Factors” for a discussion of the risks and uncertainties related to such information.

North American Energy Partners Inc.  Management’s Discussion and Analysis  27

the counterparties. A more detailed discussion of this cancellation can be found below in the “Foreign exchange risk” and “Interest rate risk” sections of “Quantitative and Qualitative Disclosures about Market Risk”.

In April 2010, we issued C$225.0 million of Series 1 Debentures and entered into an amended and restated credit agreement that extended the maturity of our credit facilities to April 2013 and provided a new $50.0 million term loan. The net proceeds of the Series 1 Debentures, combined with the new $50.0 million term loan and cash on hand were used to redeem all outstanding 8 ³/4% senior notes and terminate the associated swap agreements in April. The full details of this subsequent event are as follows:

9.125% Series 1 Debentures

In April 2010, we closed a private placement of 9.125% Series 1 Debentures due 2017 (the “Series 1 Debentures”) for gross proceeds of $225.0 million and net proceeds after commissions and related expenses of approximately $218.3 million.

The Series 1 Debentures are unsecured senior obligations and rank equally with all other existing and future unsecured senior debt and senior to any subordinated debt that may be issued by us or any of our subsidiaries. The Series 1 Debentures are effectively subordinated to all secured debt to the extent of the value of the collateral.

At any time prior to April 7, 2013, we may redeem up to 35% of the aggregate principal amount of the Debentures, with the net cash proceeds of one or more of our Public Equity Offerings at a redemption price equal to 109.125% of the principal amount; plus accrued and unpaid interest to the date of redemption, so long as:

i) at least 65% of the original aggregate amount of the Debentures remains outstanding after each redemption; and

ii) any redemption is made within 90 days of the equity offering.

At any time prior to April 7, 2013, we may on one or more occasions redeem the Debentures, in whole or in part, at a redemption price which is equal to the greater of (a) the Canada Yield Price and (b) 100% of the aggregate principal amount of Debentures redeemed, plus, in each case, accrued and unpaid interest to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

The Debentures are redeemable at our option, in whole or in part, at any time on or after: April 7, 2013 at 104.563% of the principal amount; April 7, 2014 at 103.042% of the principal amount; April 7, 2015 at 101.520% of the principal amount; April 7, 2016 and thereafter at 100% of the principal amount; plus, in each case, interest accrued to the redemption date.

If a change of control, as defined in the trust indenture, occurs we will be required to offer to purchase all or a portion of each holder’s Series 1 Debentures at a purchase price in cash equal to 101% of the principal amount of the debentures offered for repurchase plus accrued interest to the date of purchase.

The Debentures were rated B+ by Standard & Poor’s and B3 by Moody’s (see “Debt Ratings”).

8  ³/4% Senior Notes Redemption

Beginning December 1, 2009, our 8 ³/4% senior notes were redeemable at 100% of the principal amount. On March 29, 2010, we issued a redemption notice to holders of the notes to redeem all outstanding 8 ³/4% senior notes and, on April 28, 2010, the notes were redeemed and cancelled. The redemption amount included the US$200.0 million principal outstanding and US$7.1 million of accrued interest. The redemption and associated swap agreement terminations eliminates refinancing risk in December 2011 and significantly reduces our effective annual interest costs.

In connection with the redemption of our 8 ³/4% senior notes, we wrote off deferred financing costs of $4.5 million. The write off of these deferred financing costs will be recorded in our Interim Consolidated Statements of Operations and Comprehensive Income for the three months ended June 30, 2010.

Termination of Cross-Currency and Interest Rate Swaps

On April 8, 2010, we terminated the cross-currency and interest rate swaps associated with the 8 ³/4% senior notes. The payment to the counterparties required to terminate the swaps was approximately $92.5 million and represented the fair value of the swap agreements, including accrued interest.

New Term Facility

On April 30, 2010, we entered into an amended and restated credit agreement to extend the term of the credit agreement and also to add additional borrowings of up to $50.0 million through a second term facility within the credit agreement. At April 30, 2010, the second term facility was fully drawn at $50.0 million. The new term facility, along with the existing term facility, mature on April 30, 2013. A more detailed discussion on the April 30, 2010 amended and restated credit facility can be found under “Credit Agreement Renewal – April 2010” in the Liquidity and Capital Resources section of this Management’s Discussion and Analysis.

Letters of credit

One of our major contracts allows the customer to require that we provide up to $50.0 million in letters of credit. As at March 31, 2010, we had $10.0 million in letters of credit outstanding in connection with this contract (we had $10.4 million in letters of credit outstanding in total for all customers as of March 31, 2010). Any change in the amount of the

28  Management’s Discussion and Analysis  North American Energy Partners Inc.

letters of credit required by this customer must be requested by November 1st in each year for an issue date of January 1st following the date of such request, for the remaining life of the contract. In the event that we require additional letters of credit for either this major contract or other contracts, we have included an option in our June 24, 2009 amended and restated credit agreement to request an increase to the revolving portion of the credit facility, on a one-time basis, by an amount up to the lesser of $25.0 million or the requested increase to the letters of credit for this customer.

Sources of liquidity

Our principal sources of cash are funds from operations and borrowings under our credit facility. As at March 31, 2010, we had approximately $79.6 million of available borrowings under our Revolving Facility (as defined herein) provided for in our amended and restated credit agreement, after taking into account $10.4 million of outstanding and undrawn letters of credit to support performance guarantees associated with customer contracts. On December 1, 2009, we were notified by a major customer that it had reduced its letter of credit requirements from $20.0 million to $10.0 million, which became effective January 6, 2010.

As at March 31, 2010, we had $7.4 million in trade receivables that were more than 30 days past due compared to $16.0 million as at March 31, 2009. We have currently provided an allowance for doubtful accounts related to our trade receivables of $1.7 million ($2.6 million at March 31, 2009). We continue to monitor the credit worthiness of our customers. To date our exposure to potential write-downs in trade receivables has been limited to the financial condition of developers of condominiums and high-rise developments in our Piling segment.

Working capital fluctuations effect on cash

The seasonality of our business results in higher accounts receivable balances between December and early February during peak activity levels, which may result in an increase in our working capital requirements. Our working capital is also significantly affected by the timing of the completion of projects. In some cases, our customers are permitted to withhold payment of a percentage of the amount owing to us for a stipulated period of time (such percentage and time period is usually defined by the contract and in some cases provincial legislation). This amount acts as a form of security for our customers and is referred to as a “holdback”. Typically, we are only entitled to collect payment on holdbacks once substantial completion of the contract is performed, there are no outstanding claims by subcontractors or others related to work performed by us and we have met the time period specified by the contract (usually 45 days after completion of the work). However, in some cases, we are able to negotiate the progressive release of holdbacks as the job reaches various stages of completion. As at March 31, 2010, holdbacks totaled $3.9 million, down from $9.4 million as at March 31, 2009. Holdbacks represent 3.5% of our total accounts receivable as at March 31, 2010 (12.0% as at March 31, 2009). This decrease is attributable to the reduction of revenue in our Piling segment for the three months ended March 31, 2010 and March 31, 2009 compared to the same periods in the prior year. As at March 31, 2010, we carried $1.1 million in holdbacks for three large customers.^*

Cash requirements

As at March 31, 2010, our cash balance of $103.0 million was $4.1 million higher than our cash balance at March 31, 2009. The change in cash balance reflects the timing of capital expenditures and the timing of processing change orders and payment certificates. Offsetting these outflows of cash was the cash inflow of $28.4 million, net of term facility repayments, secured through our amended and restated credit facility. In the event that we require additional funding, we believe that any such funding requirements would be satisfied by the funds available from our credit facility described immediately below.

Credit facility

We entered into an amended and restated credit agreement on June 24, 2009 with a syndicate of lenders that provided us with a credit facility, under which revolving loans, term loans and letters of credit may be issued. The facility will mature on June 8, 2011. The total credit facility remained unchanged at $125.0 million and included a $75.0 million Revolving Facility (the “Revolving Facility”) and a $50.0 million Term Facility (the “Term Facility”). The Term Facility commitments were available until August 31, 2009 and aggregate borrowings under this facility had to exceed $25.0 million. Any undrawn amount under the Term Facility, up to a maximum of $15.0 million, could be reallocated to the Revolving Facility. On August 31, 2009, the maximum undrawn portion of the Term Facility totaling $15.0 million was reallocated to the Revolving Facility resulting in Revolving Facility commitments of $90.0 million. The Term Facility includes scheduled mandatory principal payments while the funds available under the Revolving Facility are reduced by any outstanding letters of credit.

As of March 31, 2010, the total credit facility included the $90.0 million Revolving Facility and the outstanding borrowings of $28.4 million (March 31, 2009 — $nil) under the non-revolving Term Facility, after the mandatory principal payments of $1.5 million in the quarter. As of March 31, 2010, we had issued $10.4 million (March 31, 2009 — $20.8 million) in letters of credit under the Revolving Facility to support performance guarantees associated with customer contracts. Our unused borrowing availability under the credit facility was $79.6 million at March 31, 2010.

^* This paragraph contains forward-looking information. Please refer to “Forward-Looking Information and Risk Factors” for a discussion of the risks and uncertainties related to such information.

North American Energy Partners Inc.  Management’s Discussion and Analysis  29

Advances under the Revolving Facility may be repaid from time to time at our option. Beginning September 30, 2009, and at the end of each fiscal quarter thereafter, we must make quarterly repayments on the Term Facility of $1.5 million through June 2011, with the balance due at that time. The credit facility, based on the type of borrowing, bears interest at the Canadian prime rate, the US dollar base rate, the Canadian bankers’ acceptance rate or the London interbank offered rate (US dollar LIBOR) (all such terms as used or defined in the credit facility) plus applicable margins. In each case, the applicable pricing margin depends on our current debt rating. For a discussion on our current debt rating refer to the “Debt Ratings” section of this Management’s Discussion and Analysis.

During the year ended March 31, 2010, financing fees of $1.1 million were incurred in connection with the modifications to the amended and restated credit agreement dated June 24, 2009. These fees were recorded as deferred financing costs and are amortized using the effective interest method over the remaining term of the agreement.

Included in the amended and restated credit agreement is an option to request an increase to the total revolving credit facility commitments if our requirements for providing letters of credit to our customers exceed $21.0 million. In that event we are permitted to request, on a one-time basis, an increase to the overall revolving credit facility by an amount up to the lesser of $25.0 million or the requested increase to the letters of credit by our customers.

Under the credit agreement, we are required to satisfy certain financial covenants, including an amended minimum interest coverage ratio. The interest coverage covenant is determined based on a ratio of Consolidated EBITDA (as defined within the credit agreement) to consolidated cash interest expense. Measured as of the last day of each fiscal quarter, on a trailing four-quarter basis, the interest coverage ratio shall not be less than 2.0 times at any time up to June 29, 2010 and shall not be less than 2.5 times any time thereafter.

Covenants remaining unchanged in the credit agreement include:

_Ÿ The senior leverage covenant, which is determined based on a ratio of senior debt to Consolidated EBITDA (as defined within the credit agreement). Measured as of the last day of each fiscal quarter on a trailing four-quarter basis, the senior leverage ratio shall not exceed 2.0 times.

_Ÿ The current ratio covenant is determined based on the ratio of current assets to current liabilities (as defined within the credit agreement). Measured as of the last day of each fiscal quarter, the current ratio shall not be less than 1.25 times.

Consolidated EBITDA is defined within the credit agreement. The amended and restated credit agreement clarifies the definition of Consolidated EBITDA to be the sum, without duplication, of (a) consolidated net income, (b) consolidated interest expense, (c) provision for taxes based on income, (d) total depreciation expense, (e) total amortization expense, (f) costs and expenses incurred by us in entering into the credit facility, (g) accrual of stock-based compensation expense to the extent not paid in cash or if satisfied by the issuance of new equity, (h) the non-cash currency translation losses or mark-to-market losses on any hedge agreement (defined in the credit agreement) or any embedded derivative, and (i) other non-cash items including goodwill impairment (other than any such non-cash item to the extent it represents an accrual of or reserve for cash expenditures in any future period) but only, in the case of clauses (b)-(i), to the extent deducted in the calculation of consolidated net income, less (i) the non-cash currency translation gains or mark-to-market gains on any hedge agreement or any embedded derivative to the extent added in the calculation of consolidated net income, and (ii) other non-cash items added in the calculation of consolidated net income (other than any such non-cash item to the extent it will result in the receipt of cash payments in any future period), all of the foregoing as determined on a consolidated basis in conformity with US GAAP. The clarification of the definition of Consolidated EBITDA (as defined within the credit agreement) did not change our measurement of Consolidated EBITDA.

The credit facility may be prepaid in whole or in part without penalty, except for bankers’ acceptances, which are not pre-payable prior to their maturity. However, the credit facility requires prepayments under various circumstances, such as with: (i) 100% of the net cash proceeds of certain asset dispositions, (ii) 100% of the net cash proceeds from our issuance of equity (unless the use of such securities’ proceeds is otherwise designated by the applicable offering document) and (iii) 100% of all casualty insurance and condemnation proceeds, subject to exceptions.

Credit Agreement Renewal – April 2010

On April 30, 2010, we entered into an amended and restated credit agreement to extend the term of the credit facilities and increase the amount of the term loans. The new credit facilities provide for total borrowings of up to $163.4 million (previously $125.0 million) under which revolving loans, term loans and letters of credit may be issued. The Revolving Facility of $85.0 million (previously $90.0 million) was undrawn at closing. The new agreement includes two term facilities providing for borrowings of up to $78.4 million. At April 30, 2010, the Term A Facility and Term B Facility were both fully drawn at $28.4 million and $50.0 million, respectively. The new facilities mature on April 30, 2013.

Advances under the revolving credit facility may be repaid from time to time at our option. The term facilities include mandatory repayments totaling $10.0 million per year with $2.5 million paid on the last day of each quarter commencing June 30, 2010. In addition, we must make annual payments within 120 days of the end of our fiscal year in the amount of 50% of Consolidated Excess Cash Flow (as defined in the credit agreement) to a maximum of $4.0 million.

30  Management’s Discussion and Analysis  North American Energy Partners Inc.

The facilities bear interest on each prime loan at variable rates based on the Canadian prime rate plus the applicable pricing margin (as defined within the credit agreement). Interest on US base rate loans is paid at a rate per annum equal to the US base rate plus the applicable pricing margin. Interest on prime and US base rate loans is payable monthly in arrears and computed on the basis of a 365-day or 366-day year, as the case may be. Interest on US dollar LIBOR loans is paid during each interest period at a rate per annum, calculated on a 360-day year, equal to the US dollar LIBOR rate with respect to such interest period plus the applicable pricing margin.

The new credit facilities are secured by a first priority lien on substantially all of our existing and after acquired property and contain customary covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions or paying dividends or redeeming shares of capital stock. We are also required to meet certain financial covenants under the new credit agreement including: (i) Senior Leverage Ratio (Senior Leverage to Consolidated EBITDA) must be less than 2.0 times, (ii) Consolidated Interest Coverage Ratio (Consolidated EBITDA to Consolidated Interest Expense) must be greater than 2.5 times, and (iii) Current Ratio (Current Assets to Current Liabilities) must be greater than 1.25 times. Continued access to the facilities is not contingent on the maintenance of a specific credit rating.

Financing fees of approximately $1.0 million were incurred in connection with the amended and restated credit agreement, dated April 30, 2010 and were recorded as deferred financing costs.

Capital resources

We acquire our equipment requirements in three ways: capital expenditures, capital leases and operating leases. Capital expenditures require the outflow of cash for the full value of the equipment at the time of purchase. Capital leases, while not considered capital expenditures, are restricted under the terms of our credit agreement to a maximum of $30.0 million. Operating leases are not considered capital expenditures and are not restricted under the terms of our credit agreement.

We define our equipment requirements as either sustaining capital additions, those that are needed to keep our existing fleet of equipment at its optimal useful life through capital maintenance or replacement, or growth capital additions, those that are needed to perform larger or a greater number of projects.

A summary of equipment additions by nature and by period is shown in the table below:

	Three months ended March 31,					Year ended March 31,
(dollars in thousands)	2010	2009		Change		2010	2009	2008	2010 vs. 2009 Change		2010 vs. 2008 Change
Capital Expenditures
Sustaining	$4,823	$2,803		$2,020		$13,644	$13,467	$18,560	$177		$(4,916	)
Growth	2,489	6,325		(3,836	)	44,861	74,072	36,519	(29,211	)	8,342
Total	$7,312	$9,128		$(1,816	)	$58,505	$87,539	$55,079	$(29,034	)	$3,426
Capital Leases
Sustaining	$418	$–		$418		$867	$3,056	$7,727	$(2,189	)	$(6,860	)
Growth	–	(4,244	)	4,244		656	5,807	1,102	(5,151	)	(446	)
Total	$418	$(4,244	)	$4,662		$1,523	$8,863	$8,829	$(7,340	)	$(7,306	)
Total Sustaining Capital Additions	$5,241	$2,803		$2,438		$14,511	$16,523	$26,287	$(2,012	)	$(11,776	)
Total Growth Capital Additions	$2,489	$2,081		$408		$45,517	$79,879	$37,621	$(34,362	)	$7,896
Operating Leases	$30,501	$42,204		$(11,703	)	$105,771	$127,410	$88,733	$(21,639	)	$17,038

The increase in sustaining capital additions for the three months ended March 31, 2010, compared to the same period in the previous year, is a result of the purchase of replacement maintenance equipment. The impact of the increase was mitigated by fewer equipment purchases due to lower activity volumes.

The reduction in growth capital expenditures for the three months and year ended March 31, 2010, compared to the same period in the prior year, reflects the impact of fewer development projects as a result of the current economic slowdown.

The decrease in operating leases, for both the three and twelve months ended March 31, 2010, compared to the same periods in the previous year, reflects the timing of scheduled equipment additions related to the Canadian Natural overburden project along with the impact of fewer development projects as a result of the current economic slowdown.

Capital Commitments

Contractual obligations and other commitments

Our principal contractual obligations relate to our long-term debt, capital and operating leases and supplier contracts.

North American Energy Partners Inc.  Management’s Discussion and Analysis  31

The following table summarizes our future contractual obligations, excluding interest payments, unless otherwise noted, as of March 31, 2010.

	Payments due by fiscal year
(dollars in thousands)	Total	2011	2012	2013	2014	2015 and after
Senior notes(1)	$203,120	$203,120	$–	$–	$–	$–
Term Facility	31,242	7,637	23,605	–	–	–
Capital leases (including interest)	14,561	5,734	5,209	2,987	462	169
Operating leases	195,667	62,862	52,999	37,899	25,942	15,965
Supplier contracts	54,185	11,467	13,616	13,616	13,226	2,260
Total contractual obligations	$498,775	$290,820	$95,429	$54,502	$39,630	$18,394

⁽¹⁾ We previously entered into cross-currency and interest rate swaps, which represented an economic hedge of the 8 ³/4% senior notes. At maturity, we were required to pay $263.0 million in order to retire these senior notes and the swaps. This amount reflected the fixed exchange rate of C$1.315=US$1.00 established as of November 26, 2003, the inception date of the swap contracts (see “Interest rate risk” in Quantitative and Qualitative Disclosures about Market Risk regarding the cancellation of the US dollar interest rate swap effective February 2, 2009). We decided to exercise our early redemption option rights on senior notes, and as such, the senior notes were redeemed on April 28, 2010 using the proceeds from the 9.125% Series 1 Debenture issue and the amended term loan facility as stated in the “Liquidity and Capital Resources” section. At March 31, 2010, the carrying value of the derivative financial instruments related to 8 ³/4% senior notes was $89.0 million, inclusive of the interest components.

Off-balance sheet arrangements

We have no off-balance sheet arrangements in place at this time.

Debt Ratings

Moody’s Investor Services, Inc. (“Moody’s”) and Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc. (“S&P”) affirmed our corporate credit ratings and the ratings on our 8 ³/4% senior notes in March 2010 and April 2010, respectively. S&P increased our Outlook from ‘negative’ to ‘stable’. Both agencies also provided a rating for our new 9.125% Series 1 Senior Unsecured Debentures issued on April 7, 2010.

Our corporate credit ratings from these two agencies are as follows:

Category	Standard & Poor’s	Moody’s
Corporate Rating	B+ (‘stable’ outlook)	B2 (‘stable’ outlook)
8  3/4% Senior Notes	B+ (recovery rating of “4”)	B3 (LGD(1) rating of “5”)
9.125% Series 1 Debentures	B+ (recovery rating of “3”)	B3 (LGD(1) rating of “5”)

⁽¹⁾ Loss Given Default

A credit rating is a current opinion of the credit worthiness of an obligor with respect to a specific financial obligation, a specific class of financial obligations, or a specific financial program (including ratings on medium-term note programs and commercial paper programs). It takes into consideration the creditworthiness of guarantors, insurers, or other forms of credit enhancement on the obligation and takes into account the currency in which the obligation is denominated. The opinion evaluates the obligor’s capacity and willingness to meet its financial commitments as they come due and may assess terms, such as collateral security and subordination, which could affect ultimate payment in the event of default. A credit rating is not a statement of fact or recommendation to purchase, sell, or hold a financial obligation or make any investment decisions nor is it a comment regarding an issuer’s market price or suitability for a particular investor. A credit rating speaks only as of the date it is issued and can be revised upward or downward or withdrawn at any time by the issuing rating agency if it decides circumstances warrant a revision. We undertake no obligation to maintain our credit ratings or to advise investors of a change in ratings.

A definition of the categories of each rating has been obtained from each respective rating organization’s website as outlined below:

Standard & Poor’s

An obligation rated B is regarded as having speculative characteristics, but the obligor currently has the capacity to meet its financial commitment on the obligation. Adverse business, financial, or economic conditions will likely impair the obligor’s capacity or willingness to meet its financial commitment on the obligation. The ratings from AA to CCC may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories.

A recovery rating of “4” for the 8 ³/4% Senior Notes indicates an expectation for an average of 30% to 50% recovery in the event of a payment default. A recovery rating of “3” for the 9.125% Series 1 Debentures indicates an expectation for an average of 50% to 70% recovery in the event of a payment default.

A Standard & Poor’s rating outlook assesses the potential direction of a long-term credit rating over the intermediate term (typically nine months to two years). In determining a rating outlook, consideration is given to any changes in the

32  Management’s Discussion and Analysis  North American Energy Partners Inc.

economic and/or fundamental business conditions. An outlook is not necessarily a precursor of a rating change or future CreditWatch action. A Stable outlook means that a rating is not likely to change.

Moody’s

Obligations rated B are considered speculative and are subject to high credit risk. Moody’s appends numerical modifiers to each generic rating classification from Aaa through C. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of that generic rating category.

Loss Given Default (LGD) assessments are opinions about expected loss given default on fixed income obligations expressed as a percent of principal and accrued interest at the resolution of the default. An LGD assessment (or rate) is the expected LGD divided by the expected amount of principal and interest due at resolution. A LGD rating of “5” indicates a loss range of greater than or equal to 70% and less than 90%.

A Moody’s rating outlook is an opinion regarding the likely direction of an issuer’s rating over the medium term. Where assigned, rating outlooks fall into the following four categories: Positive (POS), Negative (NEG), Stable (STA), and Developing (DEV – contingent upon an event). In the few instances where an issuer has multiple ratings with outlooks of differing directions, an “(m)” modifier (indicating multiple, differing outlooks) will be displayed and Moody’s written research will describe any differences and provide the rationale for these differences. A RUR (Rating(s) Under Review) designation indicates that the issuer has one or more ratings under review for possible change and thus overrides the outlook designation. When an outlook has not been assigned to an eligible entity, NOO (No Outlook) may be displayed. A Stable outlook means that a rating is not likely to change.

Related Parties

We may receive consulting and advisory services provided by the principals or employees of companies owned or operated by certain of our directors with respect to the organization of our employee benefit and compensation arrangements and other matters. No fee is charged for these consulting and advisory services.

In order for these individuals to provide such advice and consulting, we provide them with reports, financial data and other information. This permits them to consult with and advise our management on matters relating to our operations, company affairs and finances. In addition, this permits them to visit and inspect any of our properties and facilities. These services are provided in the normal course of operations and are measured at the value of consideration established and agreed to by the related parties.

Additionally, we entered into a shared service agreement with our joint venture, Noramac Ventures Inc. There have been no transactions under this agreement during the year ended March 31, 2010.

There were no material related party transactions during the years ended March 31, 2010, 2009 and 2008. All related party transactions were in the normal course of operations and were measured at the exchange amount, being the consideration established and agreed to by the related parties.

Internal Systems and Processes

Overview of information systems

We currently use JDE (Enterprise One) as our Enterprise Resource Planning (ERP) tool and deploy the financial system, payroll, procurement, job-costing and equipment maintenance modules from this tool. We supplement this functionality with either third-party software (for our estimating system) or in-house developed tools (for project management).

The proper identification of costs is a critical part of our ability to recognize revenues and provide accurate management information for decision making. We continue to focus resources to address this in our ERP system through the automation of transactional activities. We continue to work on improving the process for tracking and reporting equipment and maintenance costs. We have seen some improvements in the identification and tracking of our procurement costs.

During the fiscal year ended March 31, 2010, we started the implementation of specific JDE modules based on the user-needs analysis and ERP system functionality assessment we completed in the prior year. As part of this analysis, we determined if we could implement additional modules in JDE or whether we needed to commence a review of industry-specific software to supplement our existing ERP functionality. Based on this analysis, we decided to implement project management software that would complement the functionality of JDE. We are in the process of proving if this software can be fully integrated into our ERP system.

During each of the interim periods ended June 30, 2009, September 30, 2009 and December 31, 2009, we identified an additional material weakness in ICFR, which is described below.

We did not maintain effective processes and controls specific to our reliance on the accuracy of data provided from third-party valuations specialists that is used to prepare our consolidated financial statements. Specifically, we did not maintain effective controls to validate the accuracy of a third-party valuation of our cross-currency and interest rate swaps related to our 8¾% senior notes. The accounts that could be affected by this deficiency are current portion of derivative financial instruments liabilities on the balance sheet and realized and unrealized loss (gain) on derivative financial instruments on the

North American Energy Partners Inc.  Management’s Discussion and Analysis  33

consolidated statements of operations and comprehensive income (loss). This material weakness in ICFR, which is isolated in nature, resulted in material errors in our interim financial statements prepared under Canadian GAAP as at and for the interim periods ended June 30, 2009, September 30, 2009 and December 31, 2009 that were not corrected prior to the original release of these financial statements. These material errors have been corrected in the United States and Canadian accounting policies differences note in the restated interim financial statements released on June 10, 2010. The errors arising from this material weakness in internal controls were detected and corrected as at March 31, 2010 through detective controls applied to the settlement of the cross-currency and interest rate swaps related to our 8¾% senior notes in April 2010. The Company has no further material reliance on data provided by third-party valuations specialists.

As discussed in the section Adjustments related to prior year financial statements, the financial statements for fiscal 2008 and fiscal 2009 have been amended under Canadian GAAP to correct an error related to the method of accounting for an incentive at the time of buying a previously leased asset, which was identified during the preparation of our fiscal 2010 consolidated financial statements. This error arose as a result of the previously disclosed material weakness in ICFR related to the lack of sufficient accounting and finance personnel with an appropriate level of technical accounting knowledge and training commensurate with the complexity of our financial accounting and reporting requirements. We rectified this material weakness in fiscal 2009 by reorganizing the corporate accounting group and recruiting new staff with the appropriate experience and technical skills to prevent a reoccurrence of these issues.

Evaluation of disclosure controls and procedures

Our disclosure controls and procedures are designed to provide reasonable assurance that information we are required to disclose is recorded, processed, summarized and reported with the time periods specified under Canadian and US securities laws and include controls and procedures designed to ensure that information is accumulated and communicated to management, including the President and Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosures.

As of March 31, 2010, an evaluation was carried out under the supervision of and with the participation of management, including the President and Chief Executive Officer and the Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) under the US Securities Exchange Act of 1934, as amended, and in National Instrument 52-109 under the Canadian Securities Administrators Rules and Policies. Based on that evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that as a result of the material weaknesses in our internal control over financial reporting (ICFR) discussed below the disclosure controls and procedures were not effective as of March 31, 2010.

Management’s Report on Internal Control over Financial Reporting (ICFR)

Internal control over financial reporting is a process designed to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and of the preparation of financial statements for external purposes in accordance with US GAAP and reconciled to Canadian GAAP. Management, including the President and Chief Executive Officer and Chief Financial Officer, are responsible for establishing and maintaining adequate ICFR, as such term is defined in Rule 13a-15(e) under the US Securities Exchange Act of 1934 and in National Instrument 52-109 under the Canadian Securities Administrators Rules and Policies. A material weakness in ICFR exists if the deficiency is such that there is reasonable possibility that a material misstatement of our annual or interim consolidated financial statements will not be prevented or detected on a timely basis.

Because of its inherent limitations, ICFR may not prevent or detect misstatements. Also, projections or any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As of March 31, 2010, we assessed the effectiveness of the Company’s ICFR. In making this assessment, we used the criteria set forth in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). During this process we identified a continued material weakness in ICFR as described below and, as a result, we concluded that the Company’s ICFR is ineffective as of March 31, 2010.

Similar to the material weakness identified for the year ended March 31, 2009, we did not maintain effective processes and controls specific to revenue recognition. We did not effectively develop, communicate and implement sufficient monitoring controls over the completeness and accuracy of forecasts, including the consideration of project changes subsequent to the end of each reporting period. The accounts that could be affected by these deficiencies are revenue, project costs, unbilled revenue and billings in excess of costs incurred and estimated earnings on uncompleted contracts. This material weakness in ICFR, which is pervasive in nature, resulted in material errors in the financial statements that were corrected prior to release of the financial statements. Further, there is a reasonable possibility that a material misstatement of our financial statements will not be prevented or detected on a timely basis. Notwithstanding the above mentioned weakness, we have concluded that the Consolidated Financial Statements included in this report fairly present the Company’s consolidated financial position and consolidated results of operations as of and for the fiscal year ending March 31, 2010.

KPMG LLP, the registered public accounting firm that audited the financial statements included in the annual report containing this disclosure has issued an attestation report on our internal control over financial reporting.

34  Management’s Discussion and Analysis  North American Energy Partners Inc.

Material changes to internal controls over financial reporting and remediation plans

In response to the revenue recognition material weakness identified for the year ended March 31, 2009, we formalized our revenue recognition policy to assist in the understanding and consistent application of GAAP, developed and implemented a procedural manual to assist with applying the revenue recognition policy, designed new process-level controls and conducted staff training. These changes had a material effect on the Company’s ICFR during the year ended March 31, 2010.

In response to the continued material weakness in revenue recognition identified above, during the three months ended and subsequent to March 31, 2010, we put a dedicated project team in place, led by a senior member of our Finance team, to develop and implement standard business practices and controls specific to ensuring the accuracy of forecasts, including the consideration of project changes subsequent to the end of each reporting period. We will evaluate the effectiveness of these controls during the next fiscal year to determine if they adequately address our ability to recognize revenue in accordance with GAAP.

Significant Accounting Policies

Critical Accounting Estimates

Certain accounting policies require management to make significant estimates and assumptions about future events that affect the amounts reported in our financial statements and the accompanying notes. Therefore, the determination of estimates requires the exercise of management’s judgment. Actual results could differ from those estimates and any differences may be material to our financial statements.

Revenue recognition

We perform our projects under the following types of contracts: time-and-materials; cost-plus; unit-price; and lump sum. Revenue is recognized as costs are incurred for time-and-materials and cost-plus service contracts with no clearly defined scope. Revenue on cost-plus, unit-price, lump-sum and time-and-materials contracts with defined scope are recognized using the percentage-of-completion method, measured by the ratio of costs incurred to date to estimated total costs. The resulting percent complete methodology is applied to the approved contract value to determine the revenue recognized. Customer payment milestones typically occur on a periodic basis over the period of contract completion. The estimated total cost of the contract and percent complete is determined based upon estimates made by management. The costs of items that do not relate to performance of contracted work, particularly in the early stages of the contract, are excluded from costs incurred to date.

The length of our contracts varies from less than one year for typical contracts to several years for certain larger contracts. Contract project costs include all direct labour, material, subcontract and equipment costs and those indirect costs related to contract performance such as indirect labour, supplies and tools. General and administrative costs are charged to expense as incurred. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Changes in project performance, project conditions and estimated profitability, including those arising from contract penalty provisions and final contract settlements, may result in revisions to costs and revenue that are recognized in the period in which such adjustments are determined. Profit incentives are included in revenue when their realization is reasonably assured.

Once a project is underway, we will often experience changes in conditions, client requirements, specifications, designs, materials and work schedule. Generally, a “change order” will be negotiated with the customer to modify the original contract to approve both the scope and price of the change. Occasionally, however, disagreements arise regarding changes, their nature, measurement, timing and other characteristics that impact costs and revenue under the contract. When a change becomes a point of dispute between us and a customer, we will then consider it as a claim.

Costs related to unapproved change orders and claims are recognized when they are incurred. Revenues related to unapproved change orders and claims are included in total estimated contract revenue when they are approved.

Revenues related to unapproved change orders and claims are included in total estimated contract revenue only to the extent that contract costs related to the claim have been incurred and when it is probable that the unapproved change order or claim will result in:

_Ÿ a bona fide addition to contract value; and

_Ÿ revenues can be reliably estimated.

These two conditions are satisfied when:

_Ÿ the contract or other evidence provides a legal basis for the unapproved change order or claim or a legal opinion is obtained providing a reasonable basis to support the unapproved change order or claim;

_Ÿ additional costs incurred were caused by unforeseen circumstances and are not the result of deficiencies in our performance;

_Ÿ costs associated with the unapproved change order or claim are identifiable and reasonable in view of work performed; and

_Ÿ evidence supporting the unapproved change order or claim is objective and verifiable.

North American Energy Partners Inc.  Management’s Discussion and Analysis  35

This can lead to a situation where costs are recognized in one period and revenue is recognized when customer agreement is obtained or claim resolution occurs, which can be in subsequent periods. Historical claim recoveries should not be considered indicative of future claim recoveries.

Our long-term contracts typically allow our customers to unilaterally reduce or eliminate the scope of the work as contracted without cause. These long-term contracts represent higher risk due to uncertainty of total contract value and estimated costs to complete; therefore, potentially impacting revenue recognition in future periods.

A contract is regarded as substantially completed when remaining costs and potential risks are insignificant in amount.

Property, plant and equipment

The most significant estimates in accounting for property, plant and equipment are the expected useful life of the asset and the expected residual value. Most of our property, plant and equipment have long lives that can exceed 20 years with proper repair work and preventative maintenance. Useful life is measured in operating hours, excluding idle hours, and a depreciation rate is calculated for each type of unit. Depreciation expense is determined monthly based on daily actual operating hours. In determining the estimates of these useful lives, we take into account industry trends and company-specific factors, including changing technologies and expectations for the in-service period of certain assets. On an annual basis, we re-assess our existing estimates of useful lives to ensure they match the anticipated life of the equipment from a revenue-producing perspective. If technological change happens more quickly or in a different way than anticipated, we might have to reduce the estimated life of property, plant and equipment, which could result in a higher depreciation expense in future periods or we may record an impairment charge to write down the value of property, plant and equipment.

Another key estimate is the expected cash flows from the use of an asset and the expected disposal proceeds in applying ASC 360, “Property, Plant and Equipment”, on the impairment and disposal of long-lived assets. This standard requires the recognition of an impairment loss for a long-lived asset when changes in circumstances cause its carrying value to exceed the total undiscounted cash flows expected from its use and disposition. An impairment loss, if any, is determined as the excess of the carrying value of the asset over its fair value. The valuation of long-lived assets requires us to exercise judgment in the determination of an asset group and in making assumptions about future results, including revenue and cash flow projections for an asset group.

Allowance for doubtful accounts receivable

We regularly review our accounts receivable balances for each of our customers and we write down these balances to their expected realizable value when outstanding amounts are determined not to be fully collectible. This generally occurs when our customer has indicated an inability to pay, we were unable to communicate with our customer over an extended period of time and we have considered other methods to obtain payment without success. We determine estimates of the allowance for doubtful accounts on a customer-by-customer evaluation of collectability at each reporting date, taking into consideration the following factors: the length of time the receivable has been outstanding, specific knowledge of each customer’s financial condition and history.

Goodwill impairment

Impairment is tested at the reporting unit level by comparing the reporting unit’s carrying amount to its fair value. The process of determining fair value is subjective and requires us to exercise judgment in making assumptions about future results, including revenue and cash flow projections at the reporting unit level and discount rates. We test goodwill annually on October 1. It is our intention to continue to complete goodwill impairment testing annually on October 1 going forward or whenever events or changes in circumstances indicate that impairment may exist. We completed our most recent annual goodwill impairment testing on October 1, 2009. This impairment test showed that the fair value of the Piling reporting unit exceeded its carrying values.

Financial instruments

In determining the fair value of financial instruments, we use a variety of methods and assumptions that are based on market conditions and risks existing on each reporting date. Counterparty confirmations and standard market conventions and techniques, such as discounted cash flow analysis and option pricing models, are used to determine the fair value of our financial instruments, including derivatives. All methods of fair value measurement result in a general approximation of value and such value may never actually be realized.

Recently Adopted Accounting Policies

The FASB accounting standards codification and the hierarchy of generally accepted accounting principles

In June 2009, the Financial Accounting Standards Board (FASB) issued the FASB Accounting Standards Codification (ASC) 105. The ASC amended the hierarchy of generally accepted accounting principles (GAAP) such that the ASC became the single source of authoritative nongovernmental US GAAP, except for SEC rules and interpretative releases which, for our company, are also authoritative US GAAP. The ASC did not change current US GAAP, but was intended to simplify user access to all authoritative US GAAP by providing all the authoritative literature related to a particular topic in one place. All previously existing accounting standard documents were superseded and all other accounting literature not included in the ASC is considered non-authoritative. The ASC identifies the sources of accounting principles and the

36  Management’s Discussion and Analysis  North American Energy Partners Inc.

framework for selecting the principles to be used in the preparation of financial statements in accordance with US GAAP. The ASC was effective on September 15, 2009. The adoption of this standard did not have a material impact on our consolidated financial statements.

Fair value measurements

In September 2006, the FASB issued an accounting standard codified in ASC 820, “Fair Value Measurements and Disclosures”. This standard established a single definition of fair value and a framework for measuring fair value, set out a fair value hierarchy to be used to classify the source of information used in fair value measurements and required disclosures of assets and liabilities measured at fair value based on their level in the hierarchy. This standard applies under other accounting standards that require or permit fair value measurements. One of the amendments deferred the effective date for one year, relative to non-financial assets and liabilities that are measured at fair value, but are recognized or disclosed at fair value on a non-recurring basis. This deferral applied to such items as non-financial assets and liabilities initially measured at fair value in a business combination (but not measured at fair value in subsequent periods) or non-financial long-lived asset groups measured at fair value for an impairment assessment. These remaining aspects of the fair value measurement standard were adopted by us prospectively beginning April 1, 2009.

Business combinations

In December 2007, the FASB issued SFAS No. 141R, “Business Combinations” (“SFAS 141R”), and in April 2009, issued FAS 141 (R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies”, to amend and clarify SFAS No. 141(R), “Business Combinations”, now part of ASC 805, “Business Combinations”. Effective on April 1, 2009, the standard establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and any goodwill and establishes disclosure requirements that enable users of our financial statements to evaluate the nature and financial effects of the business combination. This new standard was applied to the acquisition of DF Investments Limited and its subsidiary Drillco Foundation Co. Ltd.

Non-controlling interests in consolidated financial statements

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements – An Amendment of ARB No. 51 (“SFAS 160”)”, which is now a part of ASC 810. The amendments to ASC 810 are effective for the fiscal year beginning April 1, 2009 and changes the accounting and reporting for ownership interests in subsidiaries held by parties other than the parent. These non-controlling interests are to be presented in the consolidated balance sheet within equity but separate from the parent’s equity. The amount of consolidated net income attributable to the parent and to the non-controlling interest is to be clearly identified and presented on the face of the consolidated statement of operations. In addition, this ASC establishes standards for a change in a parent’s ownership interest in a subsidiary and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. The ASC also establishes reporting requirements for providing sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. We prospectively adopted this ASC effective April 1, 2009. The adoption of this standard did not have a material impact on our consolidated financial statements.

Determination of the useful life of intangible assets

In April 2008, the FASB issued FSP No. FAS 142-3, “Determination of the Useful Life of Intangible Assets”, which amends the list of factors an entity should consider in developing renewal or extension assumptions used in determining the useful life of recognized intangible assets under SFAS No. 142, “Goodwill and Other Intangible Assets”. The guidance, now part of ASC 350, “Intangibles – Goodwill and Others”, and ASC 275, “Risks and Uncertainties”, applies to (i) intangible assets that are acquired individually or with a group of other assets and (ii) intangible assets acquired in both business combinations and asset acquisitions. Entities estimating the useful life of a recognized intangible asset must now consider their experience in renewing or extending similar arrangements or, in the absence of experience, must consider assumptions that market participants would use about renewal or extension. We adopted this standard effective April 1, 2009. The adoption of this standard did not have a material impact on our consolidated financial statements.

Equity method investment accounting considerations

In November 2008, the FASB issued EITF 08-06, “Equity Method Investment Accounting Considerations”, now part of ASC 323, “Investments – Equity Method and Joint Ventures”, which clarifies the accounting for certain transactions and impairment considerations involving equity method investments. The intent is to provide guidance on: (i) determining the initial measurement of an equity method investment, (ii) recognizing other-than-temporary impairments of an equity method investment and (iii) accounting for an equity method investee’s issuance of shares. We adopted this standard effective April 1, 2009. The adoption of this standard did not have a material impact on our consolidated financial statements.

Determining fair value when the volume and level of activity for the asset or liability have significantly decreased and identifying transactions that are not orderly

In April 2009, the FASB issued FSP No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”. The guidance, now

North American Energy Partners Inc.  Management’s Discussion and Analysis  37

part of ASC 820, “Fair Value Measurements and Disclosures”, provides additional guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased. It also includes guidance on identifying circumstances that indicate a transaction is not orderly. We adopted this standard effective July 1, 2009. The adoption of this standard did not have a material impact on our consolidated financial statements.

Subsequent events

In May 2009, the FASB issued ASC 855, “Subsequent Events” (formerly SFAS No. 165 “Subsequent Events”) which requires SEC filers to evaluate subsequent events through the date the financial statements are issued. In February 2010, the FASB issued ASU 2010-09, “Amendments to Certain Recognition and Disclosure Requirements”, which amended the guidance in ASC 855 to remove the requirement to disclose the date through which subsequent events have been evaluated in originally issued and revised financial statements. The adoption of this guidance did not have a material impact on our consolidated financial statements.

Measuring liabilities at fair value

In August 2009, the FASB issued ASU No. 2009-05, “Measuring Liabilities at Fair Value”, which provides additional guidance on how companies should measure liabilities at fair value under ASC 820, “Fair Value Measurements and Disclosures”. The ASU clarifies that the quoted price for an identical liability should be used; however, if such information is not available, an entity may use the quoted price of an identical liability when traded as an asset, quoted prices for similar liabilities or similar liabilities traded as assets, or another valuation technique (such as the market or income approach). The ASU also indicates that the fair value of a liability is not adjusted to reflect the impact of contractual restrictions that prevent its transfer and indicates circumstances in which quoted prices for an identical liability or quoted price for an identical liability traded as an asset may be considered Level 1 fair value measurements. We adopted this ASU effective October 1, 2009. The adoption of this standard did not have a material impact on our consolidated financial statements.

Accounting and reporting for decreases in ownership of a subsidiary

In January 2010, the FASB issued ASU 2010-02, “Consolidation (Topic 810) – Accounting and Reporting for Decreases in Ownership of a Subsidiary – A Scope Clarification”. The ASU clarifies that the scope of the decrease in ownership provisions included in ASC 810, “Consolidations” and related guidance applies to: (i) a subsidiary or a group of assets that is a business or a non-profit activity; (ii) a subsidiary that is a business or a non-profit activity that is transferred to an equity method investee or a joint venture; and (iii) an exchange of a group of assets that constitutes a business or non-profit activity for a non-controlling interest in an entity. The standard also clarifies that the decrease in ownership guidance does not apply to certain transactions, such as sales of in substance real estate or conveyance of oil and gas properties. We adopted this standard effective April 1, 2009 in conjunction with adoption of the non-controlling interest standard. The adoption of this standard did not have a material impact on our consolidated financial statements.

Equity

In January 2010, the FASB issued ASU No. 2010-01, “Equity”, which clarifies that the stock portion of a distribution to shareholders that allows them to elect to receive cash or shares with a potential limitation on the total amount of cash that all shareholders can elect to receive in the aggregate is considered a share issuance that is reflected in EPS prospectively and is not a stock dividend for purposes of earnings per share calculations. We adopted this ASU effective December 31, 2009. The adoption of this standard did not have a material impact on our consolidated financial statements.

Improving disclosures about fair value measurements

In January 2010, the FASB issued ASU No. 2010-06, “Improving Disclosures About Fair Value Measurements”, that amends existing disclosure requirements under ASC 820 by adding required disclosures about items transferring into and out of Level 1 and Level 2 in the fair value hierarchy; adding separate disclosures about purchase, sales, issuances and settlements relative to Level 3 measurements; and clarifying, among other things, the existing fair value disclosures about the level of disaggregation. The ASU is effective beginning on January 1, 2010, except for disclosures about purchases, sales, issuances and settlements in the roll forward of activity in Level 3 fair value measurements, which is effective beginning on April  1, 2011. The adoption of this standard did not have a material impact on our consolidated financial statements.

Recent Accounting Pronouncements Not Yet Adopted

Revenue recognition

In October 2009, the FASB issued ASU No. 2009-13, “Revenue Recognition: Multiple-Deliverable Revenue Arrangements”, which addresses the accounting for multiple-deliverable arrangements to enable vendors to account for products or services separately rather than as a combined unit. The amendments establish a selling price hierarchy for determining the selling price of a deliverable. The amendments also eliminate the residual method of allocation and require that arrangement consideration be allocated at the inception of the arrangement to all deliverables using the relative selling price method. This ASU is effective prospectively for revenue arrangements entered into or materially modified on or after April 1, 2010. We are currently evaluating the impact of this ASU on our consolidated financial statements.

38  Management’s Discussion and Analysis  North American Energy Partners Inc.

Improvements to financial reporting by enterprises involved with variable interest entities

In December 2009, the FASB issued ASU No. 2009-17, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities”, which amends ASC 810, “Consolidation”. The amendments give guidance and clarification of how to determine when a reporting entity should include the assets, liabilities, non-controlling interests and results of activities of a variable interest entity in its consolidated financial statements. The amendments in this ASU are effective beginning on April 1, 2011. We are currently evaluating the impact of this ASU on our consolidated financial statements.

Embedded credit derivatives

In March 2010, the FASB issued ASU No. 2010-11, “Scope Exception Related to Embedded Credit Derivatives”, which clarifies that financial instruments that contain embedded credit-derivative features related only to the transfer of credit risk in the form of subordination of one instrument to another are not subject to bifurcation and separate accounting. The scope exception only applies to an embedded derivative feature that relates to subordination between tranches of debt issued by an entity and other features that relate to another type of risk must be evaluated for separation as an embedded derivative. The ASU is effective beginning on July 1, 2010, with early adoption permitted in first fiscal quarter beginning after March 5, 2010. We are currently evaluating the impact of this ASU on our consolidated financial statements.

Share based payment awards

In April 2010, the FASB issued ASU No. 2010-13, “Effect of Denominating the Exercise Price of Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades” which clarifies that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. This ASU will amend ASC 718, “Compensation - Stock Compensation” and it is effective beginning on April 1, 2011. We are currently evaluating the impact of this ASU on our consolidated financial statements.

Recently Adopted Accounting Policies (Canadian GAAP)

Goodwill and intangible assets

Effective April 1, 2009, we adopted, on a retrospective basis, CICA Handbook Section 3064, “Goodwill and Intangible Assets”, which replaces Section 3062, “Goodwill and Other Intangible Assets” and Section 3450, “Research and Development Costs” and establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The provisions relating to the definition and initial recognition of intangible assets, including internally generated intangible assets, are equivalent to the corresponding provisions of International Accounting Standard IAS 38, “Intangible Assets”. The adoption of this standard resulted in the reclassification for certain qualifying assets related to software from property, plant and equipment to intangible assets for all periods presented.

Business combinations

On July 1, 2009, we early adopted CICA Handbook Section 1582, “Business Combinations”, effective April 1, 2009. This section establishes standards for the accounting of business combinations and states that all assets and liabilities of an acquired business will be recorded at fair value. Obligations for contingent consideration and contingencies will also be recorded at fair value at the acquisition date. The standard also states that acquisition related costs will be expensed as incurred, that restructuring charges will be expensed in periods after the acquisition date and that non-controlling interests should be measured at fair value at the date of acquisition. This standard is to be applied prospectively to business combinations with acquisition dates on or after April 1, 2009. This new standard was applied to the acquisition of DF Investments Limited and its subsidiary Drillco Foundation Co. Ltd.

Consolidated financial statements

On July 1, 2009, we early adopted CICA Handbook Section 1601, “Consolidated Financial Statements”, effective April 1, 2009. The new standard replaces Section 1600 “Consolidated Financial Statements”. This Section carries forward existing Canadian guidance for preparing consolidated financial statements other than guidance for non-controlling interests. The adoption of this standard did not have a material impact on our consolidated financial statements.

Non-controlling interests

On July 1, 2009, we early adopted CICA Handbook Section 1602, “Non-Controlling Interests”, effective April 1, 2009. The new standard establishes standards for the accounting of non-controlling interests of a subsidiary in the preparation of consolidated financial statements subsequent to a business combination. The adoption of this standard did not have a material impact on our consolidated financial statements.

Equity

In August 2009, the CICA amended presentation requirements of Handbook Section 3251, “Equity”, as a result of issuing Section 1602, “Non-Controlling Interests”. The amendments apply only to entities that have adopted Section 1602. We early adopted this standard effective April 1, 2009. The adoption of this standard did not have a material impact on our consolidated financial statements.

North American Energy Partners Inc.  Management’s Discussion and Analysis  39

Financial instruments – recognition and measurement

Effective July 1, 2009, we adopted CICA amendments to Handbook Section 3855, “Financial Instruments – Recognition and Measurement” which add guidance concerning the assessment of embedded derivatives upon reclassification of a financial asset out of the held-for-trading category. These amendments apply to reclassifications made on or after July 1, 2009. The adoption of these amendments did not have a material impact on our consolidated financial statements.

Financial instruments – disclosure

In June 2009, the CICA amended Handbook Section 3862, “Financial Instruments – Disclosures”, to include additional disclosure requirements about fair value measurements of financial instruments and to enhance liquidity risk disclosure requirements. The amendments apply to annual financial statements relating to fiscal years ending after September 30, 2009. The adoption of these amendments did not have a material impact on our consolidated financial statements.

Recent Accounting Pronouncements Not Yet Adopted (Canadian GAAP)

Accounting changes

In June 2009, the CICA amended Handbook Section 1506, “Accounting Changes”, to exclude from its scope changes in accounting policies upon the complete replacement of an entity’s primary basis of accounting. The amendment applies to interim and annual financial statements relating to fiscal years beginning on or after July 1, 2009. We are currently evaluating the impact of the amendments to the standard.

Financial instruments – recognition and measurement

In June 2009, the CICA amended Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, to clarify the application of the effective interest method after a debt instrument has been impaired. The Section has also been amended to clarify when an embedded prepayment option is separated from its host instrument for accounting purposes. The amendments apply to interim and annual financial statements relating to fiscal years beginning on or after May 1, 2009 for the amendments relating to the effective interest method and on or after January 1, 2011 for the amendments relating to embedded prepayment options. We are currently evaluating the impact of the amendments to the standard.

Comprehensive revaluation of assets and liabilities

In August 2009, the CICA amended Handbook Section 1625, “Comprehensive Revaluation of Assets and Liabilities”, as a result of issuing Section 1582, “Business Combinations”, Section 1601, “Consolidated Financial Statements” and Section 1602, “Non-Controlling Interests”, in January 2009. The amendments apply prospectively to comprehensive revaluations of assets and liabilities occurring in fiscal years beginning on or after January 1, 2011. Earlier adoption is permitted as of the beginning of a fiscal year, provided that Section 1582 is also adopted. We are currently evaluating the impact of the amendments to the standard.

Multiple deliverable arrangements

In December 2009, the CICA issued Emerging Issues Committee (EIC) 175, “Multiple deliverable arrangements”. This abstract addresses how to determine whether an arrangement involving multiple deliverables contains more than one unit of accounting. It also addresses how arrangement consideration should be measured and allocated to the separate units of accounting in the arrangement. For us, this abstract is effective on prospective basis to all revenue arrangements with multiple deliverables entered into or materially modified in the fiscal period beginning April 1, 2011. We are currently evaluating the impact of this abstract on our consolidated financial statements.

G. Forward-Looking Information and Risk Factors

Forward-Looking Information

This document contains forward-looking information that is based on expectations and estimates as of the date of this document. Our forward-looking information is information that is subject to known and unknown risks and other factors that may cause future actions, conditions or events to differ materially from the anticipated actions, conditions or events expressed or implied by such forward-looking information. Forward-looking information is information that does not relate strictly to historical or current facts and can be identified by the use of the future tense or other forward-looking words such as “believe”, “expect”, “anticipate”, “intend”, “plan”, “estimate”, “should”, “may”, “could”, “would”, “target”, “objective”, “projection”, “forecast”, “continue”, “strategy”, “intend”, “position” or the negative of those terms or other variations of them or comparable terminology.

Examples of such forward-looking information in this document include, but are not limited to, statements with respect to the following, each of which is subject to significant risks and uncertainties and is based on a number of assumptions which may prove to be incorrect:

(a) our expectation that demand for recurring services will continue to be stable in the improving economic environment and that demand for recurring services will continue to grow, over the long-term, as existing oil sands mines progress and as new mines, such as Canadian Natural’s Horizon mine and Albian’s Jackpine mine, come on-line;

40  Management’s Discussion and Analysis  North American Energy Partners Inc.

(b) our expectation that the demand for new infrastructure to support a larger population coupled with government investment in infrastructure to stimulate the economy provides a strong outlook for infrastructure spending in Western Canada and in Ontario and our belief of our ability to capitalize on the expected growth in infrastructure projects;

(c) our expectation that we will benefit from increased spending in the private sector, over the coming years, as the economy recovers from the downturn;

(d) our expectation that in the near term the market for smaller pipeline projects and expansions will remain highly competitive given the current oversupply of contracting capacity and steady demand;

(e) our expectation that commodity prices will continue improving in 2010;

(f) our expectation for continued steady growth in recurring revenue from operating oil sands projects as activity levels increase at existing mines and new oil sands projects move from the capital development stage into the operational phase;

(g) the amount of our expected backlog (which estimate assists us in planning our activity levels and may not be suitable for other purposes), to be performed and realized in the twelve months ending March 31, 2011;

(h) we expect to see demand for our services will gradually strengthen as the year progresses;

(i) our expectation that development opportunities will continue to expand with Exxon’s Kearl, ConocoPhillips’s Surmont and Suncor’s Firebag projects moving forward;

(j) our expectation that there will some short-term variability in the demand for recurring services in early fiscal 2011 and our expectation that demand will recover during the three months ending September 30, 2010 and remain stable through the balance of the year;

(k) our expectation that the infrastructure associated with modifications to tailings disposal systems will generate opportunities for us to provide an expanded range of services in support of these initiatives and will become a significant revenue growth opportunity for us over time;

(l) our expectation that we will be able complete our two new Pipeline contracts during fiscal 2011 and that we have mitigated our risk exposure in our new contracts;

(m) our expectation that our Pipeline segment will return to profitability in fiscal 2011;

(n) our expectation that we will see a gradual increase in opportunities for our Piling division as fiscal 2011 progresses and our expectation that demand improvement will continue in the commercial and public construction market as the year progresses;

(o) our expectation that the economic conditions in Canada, led by Alberta, will continue to improve for several years to come;

(p) our expectation that a renewal Collective Agreement will be ratified without any disruption to the Company’s operations;

(q) our expectation that our capital needs in fiscal 2011 will be approximately $50-$75 million, but we could also increase our capital spend to approximately $100 million as a result of the availability of equipment from the recent bankruptcy of one of our competitors;

(r) our operating and lease facilities and cash flow from operations will be sufficient to meet our capital requirements;

(s) our lease capacity will be sufficient to meet our capital requirements in fiscal 2011; and

(t) the seasonality of our business results may result in an increase in working capital requirements.

The forward-looking information in paragraphs (a), (b), (c), (d), (e), (f), (g), (h), (i), (j), (k), (m), (n), (o), (q), (r), (s), and (t) rely on certain market conditions and demand for our services and are based on the assumptions that: despite the slowdown in the global economy and tightening of credit conditions, we still expect to see strong demand for our recurring services as the oil sands continue to be an economically viable source of energy, our customers and potential customers continue to invest in the oil sands and other natural resource developments; our customers and potential customers will continue to outsource the type of activities for which we are capable of providing service; and the Western Canadian economy continues to develop with additional investment in public construction; and are subject to the following risks and uncertainties, which could cause results to differ materially from those expressed in the forward-looking information contained in this MD&A, but are not limited to:

_Ÿ anticipated new major capital projects in the oil sands may not materialize;

_Ÿ demand for our services may be adversely impacted by regulations affecting the energy industry;

_Ÿ failure by our customers to obtain required permits and licenses may affect the demand for our services;

North American Energy Partners Inc.  Management’s Discussion and Analysis  41

_Ÿ changes in our customers’ perception of oil prices over the long-term could cause our customers to defer, reduce or stop their capital investment in oil sands projects, which would, in turn, reduce our revenue from those customers;

_Ÿ reduced financing as a result of the tightening credit markets may affect our customers’ decisions to invest in infrastructure projects;

_Ÿ insufficient pipeline, upgrading and refining capacity or lack of sufficient governmental infrastructure to support growth in the oil sands region could cause our customers to delay, reduce or cancel plans to construct new oil sands projects or expand existing projects, which would, in turn, reduce our revenue from those customers;

_Ÿ a change in strategy by our customers to reduce outsourcing could adversely affect our results;

_Ÿ cost overruns by our customers on their projects may cause our customers to terminate future projects or expansions which could adversely affect the amount of work we receive from those customers;

_Ÿ because most of our customers are Canadian energy companies, a further downturn in the Canadian energy industry could result in a decrease in the demand for our services;

_Ÿ shortages of qualified personnel or significant labour disputes could adversely affect our business; and

_Ÿ unanticipated short term shutdowns of our customers’ operating facilities may result in temporary cessation or cancellation of projects in which we are participating.

The forward-looking information in paragraphs (a), (b), (c), (d), (f), (g), (h), (i), (j), (k), (l), (m), (n), (p), (q), (r), (s) and (t) rely on our ability to execute our growth strategy and are based on the assumptions that the management team can successfully manage the business; we can maintain and develop our relationships with our current customers; we will be successful in developing relationships with new customers; we will be successful in the competitive bidding process to secure new projects; we will identify and implement improvements in our maintenance and fleet management practices; we will be able to benefit from increased recurring revenue base tied to the operational activities of the oil sands; we will be able to access sufficient funds to finance our capital growth; and are subject to the risks and uncertainties that:

_Ÿ continued reduced demand for oil and other commodities as a result of slowing market conditions in the global economy may result in reduced oil production and a decline in oil prices;

_Ÿ if we are unable to obtain surety bonds or letters of credit required by some of our customers, our business could be impaired;

_Ÿ we are dependent on our ability to lease equipment and a tightening of this form of credit could adversely affect our ability to bid for new work and/or supply some of our existing contracts;

_Ÿ our business is highly competitive and competitors may outbid us on major projects that are awarded based on bid proposals;

_Ÿ our customer base is concentrated and the loss of or a significant reduction in business from a major customer could adversely impact our financial condition;

_Ÿ lump-sum and unit-price contracts expose us to losses when our estimates of project costs are lower than actual costs;

_Ÿ our operations are subject to weather-related factors that may cause delays in our project work; and

_Ÿ environmental laws and regulations may expose us to liability arising out of our operations or the operations of our customers.

While we anticipate that subsequent events and developments may cause our views to change, we do not have an intention to update this forward-looking information, except as required by applicable securities laws. This forward-looking information represents our views as of the date of this document and such information should not be relied upon as representing our views as of any date subsequent to the date of this document. We have attempted to identify important factors that could cause actual results, performance or achievements to vary from those current expectations or estimates expressed or implied by the forward-looking information. However, there may be other factors that cause results, performance or achievements not to be as expected or estimated and that could cause actual results, performance or achievements to differ materially from current expectations. There can be no assurance that forward-looking information will prove to be accurate, as actual results and future events could differ materially from those expected or estimated in such statements. Accordingly, readers should not place undue reliance on forward-looking information. These factors are not intended to represent a complete list of the factors that could affect us. See “Risk Factors” below and risk factors highlighted in materials filed with the securities regulatory authorities filed in the United States and Canada from time to time, including, but not limited to, our most recent Annual Information Form.

42  Management’s Discussion and Analysis  North American Energy Partners Inc.

Risk Factors

Anticipated new major capital projects in the oil sands may not materialize.

Notwithstanding the National Energy Board’s estimates regarding new capital investment and growth in the Canadian oil sands, planned and anticipated capital projects in the oil sands may not materialize. The underlying assumptions on which the capital projects are based are subject to significant uncertainties, and actual capital investments in the oil sands could be significantly less than estimated. Projected investments in new capital projects may be postponed or cancelled for any number of reasons, including among others:

_Ÿ reductions in available credit for customers to fund capital projects;

_Ÿ changes in the perception of the economic viability of these projects;

_Ÿ shortage of pipeline capacity to transport production to major markets;

_Ÿ lack of sufficient governmental infrastructure funding to support growth;

_Ÿ delays in issuing environmental permits or refusal to grant such permits;

_Ÿ shortage of skilled workers in this remote region of Canada; and

_Ÿ cost overruns on announced projects.

Because most of our customers are Canadian energy companies, a downturn in the Canadian energy industry could result in a decrease in the demand for our services.

Most of our customers are Canadian energy companies. A downturn in the Canadian energy industry is leading our customers to slow down or curtail their future capital expansion which, in turn, has reduced our revenue from those customers on their capital projects. The continuation of such a delay or curtailment could have an adverse impact on our financial condition and results of operations. In addition, a reduction in the number of new oil sands capital projects by customers would also likely result in increased competition among oil sands service providers, which could also reduce our ability to successfully bid for new capital projects.

Changes in our customers’ perception of oil prices over the long-term could cause our customers to defer, reduce or stop their investment in oil sands capital projects, which would, in turn, reduce our revenue from capital projects from those customers.

Due to the amount of capital investment required to build an oil sands project, or construct a significant capital expansion to an existing project, investment decisions by oil sands operators are based upon long-term views of the economic viability of the project. Economic viability is dependent upon the anticipated revenues the capital project will produce, the anticipated amount of capital investment required and the anticipated fixed cost of operating the project. The most important consideration is the customer’s view of the long-term price of oil which is influenced by many factors, including the condition of developed and developing economies and the resulting demand for oil and gas, the level of supply of oil and gas, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political conditions in oil producing nations, including those in the Middle East, war or the threat of war in oil producing regions and the availability of fuel from alternate sources. If our customers believe the long-term outlook for the price of oil is not favourable, or believes oil-sands projects are not viable for any other reason, they may delay, reduce or cancel plans to construct new oil sands capital projects or capital expansions to existing projects. Recently, the market price of oil decreased significantly. In addition, the slowing world economy is leading to lower international demand for oil, which could continue to suppress oil prices. As a result of these developments, many of our customers have decided to scale back their capital development plans and are significantly reducing their capital expenditures on oil sands projects. Delays, reductions or cancellations of major oil sands projects would adversely affect our prospects for revenues from capital projects and could have an adverse impact on our financial condition and results of operations.

Cost overruns by our customers on their projects may cause our customers to terminate future projects or expansions which could adversely affect the amount of work we receive from those customers.

Oil sands development projects require substantial capital expenditures. In the past, several of our customers’ projects have experienced significant cost overruns, impacting their returns. If cost overruns continue to challenge our customers, they could reassess future projects and expansions which could adversely affect the amount of work we receive from our customers.

A change in strategy by our customers to reduce outsourcing could adversely affect our results.

Outsourced Heavy Construction and Mining services constitute a large portion of the work we perform for our customers. For example, our mining and site preparation project revenues constituted approximately 88%, 74% and 63% of our revenues in each of the years ended March 31, 2010, 2009 and 2008, respectively. The election by one or more of our customers to perform some or all of these services themselves, rather than outsourcing the work to us, could have a material adverse impact on our business and results of operations. Certain customers perform some of this work internally and may choose to expand on the use of internal resources to complete this work. Additionally, the recent tightening of the credit market and worldwide economic downturn may result in our customers reducing their spending

North American Energy Partners Inc.  Management’s Discussion and Analysis  43

on outsourced mining and site preparation services if they believe they can perform this work in a more cost effective and efficient manner using their internal resources.

Until we establish and maintain effective internal controls over financial reporting, we cannot assure you that we will have appropriate procedures in place to eliminate future financial reporting inaccuracies and avoid delays in financial reporting.

We have identified a material weakness in our financial reporting processes and internal controls specific to revenue recognition in our most recent “Management’s Report on Internal Controls over Financial Reporting (ICFR)”. As a result, there can be no assurance that we will be able to generate accurate financial reports in a timely manner. Failure to do so would cause us to violate the US and Canadian securities regulations with respect to reporting requirements in the future, as well as the covenants applicable to our indebtedness. This could, in turn, have a material adverse effect on our business and financial condition. Until we establish and maintain effective internal controls and procedures for financial reporting, we may not have appropriate measures in place to eliminate financial statement inaccuracies and avoid delays in financial reporting.

Demand for our services may be adversely impacted by regulations affecting the energy industry.

Our principal customers are energy companies involved in the development of the oil sands and in natural gas production. The operations of these companies, including their mining operations in the oil sands, are subject to or impacted by a wide array of regulations in the jurisdictions where they operate, including those directly impacting mining activities and those indirectly affecting their businesses, such as applicable environmental laws and climate change laws. As a result of changes in regulations and laws relating to the energy production industry, including the operation of mines, our customers’ operations could be disrupted or curtailed by governmental authorities or the market for their products could be adversely impacted. The high cost of compliance with applicable regulations or the reduction and demand for our customers’ products may cause customers to discontinue or limit their operations, and may discourage companies from continuing development activities. As a result, demand for our services could be substantially affected by regulations adversely impacting the energy industry.

Our customer base is concentrated, and the loss of or a significant reduction in business from a major customer could adversely impact our financial condition.

Most of our revenue comes from the provision of services to a small number of major oil sands mining companies. Revenue from our five largest customers represented approximately 88%, 74% and 63% of our total revenue for 2010, 2009 and 2008, respectively, and those customers are expected to continue to account for a significant percentage of our revenues in the future. In addition, the majority of our Pipeline revenues in the previous fiscal years resulted from work performed for one customer. If we lose or experience a significant reduction of business from one or more of our significant customers, we may not be able to replace the lost work with work from other customers. Our long-term contracts typically allow our customers to unilaterally reduce or eliminate the work which we are to perform under the contract. Our contracts also generally allow the customer to terminate the contract without cause and, in many cases, with minimal or no notice to us. Additionally, certain of these contracts provide for limited compensation following such suspension or termination operations and we can provide no assurance that we could replace the lost work with work from other customers. The loss of or significant reduction in business with one or more of our major customers, whether as a result of the completion, early termination or suspension of a contract, or failure or inability to pay amounts owed to us, could have a material adverse effect on our business and results of operations.

Failure by our customers to obtain required permits and licenses due to complex and stringent environmental protection laws and regulations may affect the demand for our services.

The development of the oil sands requires our customers to obtain regulatory and other permits and licenses from various governmental licensing bodies. Our customers may not be able to obtain all necessary permits and licenses that may be required for the development of the oil sands on their properties. In such a case, our customers’ projects will not proceed, thereby adversely impacting demand for our services.

Lack of sufficient governmental infrastructure to support the growth in the oil sands region could cause our customers to delay, reduce or cancel their future expansions, which would, in turn, reduce our revenue from those customers.

The development in the oil sands region has put a great strain on the existing government infrastructure, necessitating substantial improvements to accommodate growth in the region. The local government having responsibility for a majority of the oil sands region has been exceptionally impacted by this growth and is not currently in a position to provide the necessary additional infrastructure. In an effort to delay further development until infrastructure funding issues are resolved, the local governmental authority has previously intervened in hearings considering applications by major oil sands companies to the Energy Resources Conservation Board (“ERCB”), formerly the Energy and Utilities Board (EUB), for approval to expand their operations. Similar action could be taken with respect to any future applications. The ERCB has indicated that it believes that additional infrastructure investment in the oil sands region is needed and that there is a short window of opportunity to make these investments in parallel with continued oil sands development. If the necessary infrastructure is not put in place, future growth of our customers’ operations could be delayed, reduced or cancelled which could in turn adversely affect our prospects and could have a material adverse impact on our financial condition and results of operations.

44  Management’s Discussion and Analysis  North American Energy Partners Inc.

Significant labour disputes could adversely affect our business.

Substantially all of our hourly employees are subject to collective bargaining agreements to which we are a party or are otherwise subject. Any work stoppage resulting from a strike or lockout could have a material adverse effect on our business, financial condition and results of operations. In addition, our customers employ workers under collective bargaining agreements. Any work stoppage or labour disruption experienced by our key customers could significantly reduce the amount of our services that they need.

An upturn in the Canadian economy, resulting in an increased demand for our services from the Canadian energy industry, could lead to a new shortage of qualified personnel.

From fiscal 2007 through the first nine months of fiscal 2009, Alberta, and in particular the oil sands area, experienced significant economic growth which resulted in a shortage of skilled labour and other qualified personnel. New mining projects in the area made it more difficult for us and our customers to find and hire all the employees required to work on these projects. If the economy returns to these previous growth levels and we are not able to recruit and retain sufficient numbers of employees with the appropriate skills, we may not be able to satisfy an increased demand for our services. This in turn, could have a material adverse effect on our business, financial condition and results of operation. If our customers are not able to recruit and retain enough employees with the appropriate skills, they may be unable to develop projects in the oils sands area.

If we are unable to obtain surety bonds or letters of credit required by some of our customers, our business could be impaired.

We are at times required to post a bid or performance bond issued by a financial institution, known as a surety, to secure our performance commitments. The surety industry experiences periods of unsettled and volatile markets, usually in the aftermath of substantial loss exposures or corporate bankruptcies with significant surety exposure. Historically, these types of events have caused reinsurers and sureties to re-evaluate their committed levels of underwriting and required returns. If for any reason, whether because of our financial condition, our level of secured debt or general conditions in the surety bond market, our bonding capacity becomes insufficient to satisfy our future bonding requirements, our business and results of operations could be adversely affected.

Some of our customers require letters of credit to secure our performance commitments. Our April 30, 2010 amended and restated credit agreement provides for the issuance of letters of credit up to $85.0 million, and at June 10, 2010, we had $14.4 million of issued letters of credit outstanding. One of our major contracts allows the customer to require up to $50.0 million in letters of credit. If we were unable to provide letters of credit in the amount requested by this customer, we could lose business from such customer and our business and cash flow would be adversely affected. If our capacity to issue letters of credit under our revolving credit facility and our cash on hand is insufficient to satisfy our customer’s requirements, our business and results of operations could be adversely affected.

Insufficient pipeline, upgrading and refining capacity could cause our customers to delay, reduce or cancel plans to construct new oil sands projects or expand existing projects, which would, in turn, reduce our revenue from those customers.

For our customers to operate successfully in the oil sands, they must be able to transport the bitumen produced to upgrading facilities and transport the upgraded oil to refineries. Some oil sands projects have upgraders at mine site and others transport bitumen to upgraders located elsewhere. While current pipeline and upgrading capacity is sufficient for current production, future increases in production from new oil sands projects and expansions to existing projects will require increased upgrading and pipeline capacity. If these increases do not materialize, whether due to inadequate economics for the sponsors of such projects, shortages of labour or materials or any other reason, our customers may be unable to efficiently deliver increased production to market and may therefore delay, reduce or cancel planned capital investment. Such delays, reductions or cancellations of major oil sands projects would adversely affect our prospects and could have a material adverse impact on our financial condition and results of operations.

Lump-sum and unit-price contracts expose us to losses when our estimates of project costs are lower than actual costs.

Approximately 39%, 29% and 44% of our revenue for the years ended March 31, 2010, 2009 and 2008, respectively, was derived from lump-sum and unit-price contracts. Lump-sum and unit-price contracts require us to guarantee the price of the services we provide and thereby expose us to losses if our estimates of project costs are lower than the actual project costs we incur. Our profitability under these contracts is dependent upon our ability to accurately predict the costs associated with our services. The costs we actually incur may be affected by a variety of factors beyond our control. Factors that may contribute to actual costs exceeding estimated costs and which therefore affect profitability include, without limitation:

_Ÿ site conditions differing from those assumed in the original bid;

_Ÿ scope modifications during the execution of the project;

_Ÿ the availability and cost of skilled workers;

_Ÿ the availability and proximity of materials;

_Ÿ unfavourable weather conditions hindering productivity;

North American Energy Partners Inc.  Management’s Discussion and Analysis  45

_Ÿ inability or failure of our customers to perform their contractual commitments;

_Ÿ equipment availability, productivity and timing differences resulting from project construction not starting on time; and

_Ÿ the general coordination of work inherent in all large projects we undertake.

When we are unable to accurately estimate the costs of lump-sum and unit-price contracts, or when we incur unrecoverable cost overruns, the related projects result in lower margins than anticipated or may incur losses, which could adversely impact our results of operations, financial condition and cash flow.

Our substantial debt could adversely affect us, make us more vulnerable to adverse economic or industry conditions and prevent us from fulfilling our debt obligations.

We have a substantial amount of debt outstanding and significant debt service requirements. As of March 31, 2010, we had outstanding $477.3 million of debt ¹⁴, including $13.4 million of capital leases. We also had cross-currency and interest rate swaps with a balance sheet liability of $81.1 million as of March 31, 2010. These swaps are secured equally and ratably with our Revolving Facility. Our substantial indebtedness could have serious consequences, such as:

_Ÿ limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements, potential growth or other purposes;

_Ÿ limiting our ability to use operating cash flow in other areas of our business;

_Ÿ limiting our ability to post surety bonds required by some of our customers;

_Ÿ placing us at a competitive disadvantage compared to competitors with less debt;

_Ÿ increasing our vulnerability to, and reducing our flexibility in planning for, adverse changes in economic, industry and competitive conditions; and

_Ÿ increasing our vulnerability to increases in interest rates because borrowings under our revolving credit facility and payments under some of our equipment leases are subject to variable interest rates.

The potential consequences of our substantial indebtedness make us more vulnerable to defaults and place us at a competitive disadvantage. Further, if we do not have sufficient earnings to service our debt, we would need to refinance all or part of our existing debt, sell assets, borrow more money or sell securities, none of which we can guarantee we will be able to achieve on commercially reasonable terms, if at all.

The terms of our debt agreements may restrict our current and future operations, particularly our ability to respond to changes in our business or take certain actions.

Our amended and restated credit agreement facility and the trust indenture governing our Series 1 Debentures limit, among other things, our ability and the ability of our subsidiaries to:

_Ÿ incur or guarantee additional debt, issue certain equity securities or enter into sale and leaseback transactions;

_Ÿ pay dividends or distributions on our shares or repurchase our shares, redeem subordinated debt or make other restricted payments;

_Ÿ incur dividend or other payment restrictions affecting certain of our subsidiaries;

_Ÿ issue equity securities of subsidiaries;

_Ÿ make certain investments or acquisitions;

_Ÿ create liens on our assets;

_Ÿ enter into transactions with affiliates;

_Ÿ consolidate, merge or transfer all or substantially all of our assets; and

_Ÿ transfer or sell assets, including shares of our subsidiaries.

Our credit agreement also requires us, and our future credit agreements may require us, to maintain specified financial ratios and satisfy specified financial tests, some of which become more restrictive over time. Our ability to meet these financial ratios and tests can be affected by events beyond our control, and we may be unable to meet those tests.

As a result of these covenants, our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be significantly restricted, and we may be prevented from engaging in transactions that might otherwise be considered beneficial to us. The breach of any of these covenants could result in an event of default under our revolving credit facility or any future credit facilities or under the indenture governing our notes. Under our credit agreement, our failure to pay certain amounts when due to other creditors, including to certain equipment lessors, or the acceleration of such other indebtedness, would also result in an event of default. Upon the occurrence of an event of default under our revolving credit facility or future credit facilities, the lenders could elect to stop lending to us or declare all amounts outstanding under such credit facilities to be immediately due and payable. Similarly, upon the occurrence of an event of default under the trust indenture governing our Series 1 Debentures the outstanding principal

¹⁴   Debt includes all liabilities with the exception of future income taxes

46  Management’s Discussion and Analysis  North American Energy Partners Inc.

and accrued interest on the notes may become immediately due and payable. If amounts outstanding under such credit agreements and the trust indenture were to be accelerated, or if we were not able to borrow under our revolving credit facility, we could become insolvent or be forced into insolvency proceedings and you could lose your investment in us.

Our business is highly competitive and competitors may outbid us on major projects that are awarded based on bid proposals.

We compete with a broad range of companies in each of our markets. Many of these competitors are substantially larger than we are. In addition, we expect the anticipated growth in the oil sands region will attract new and sometimes larger competitors to enter the region and compete against us for projects. This increased competition may adversely affect our ability to be awarded new business.

Approximately 80% of the major projects that we pursue are awarded to us based on bid proposals, and projects are typically awarded based in large part on price. We often compete for these projects against companies that have substantially greater financial and other resources than we do and therefore can better bear the risk of under pricing projects. We also compete against smaller competitors that may have lower overhead cost structures and, therefore, may be able to provide their services at lower rates than we can. Our business may be adversely impacted to the extent that we are unable to successfully bid against these companies. The loss of existing customers to our competitors or the failure to win new projects could materially and adversely affect our business and results of operations.

A significant amount of our revenue is generated by providing non-recurring services.

More than 27% of our revenue for the year ended March 31, 2010 was derived from projects which we consider to be non-recurring. This revenue primarily relates to site preparation and Piling services provided for the construction of extraction, upgrading and other oil sands mining infrastructure projects.

Unanticipated short term shutdowns of our customers’ operating facilities may result in temporary cessation or cancellation of projects in which we are participating.

The majority of our work is generated from the development, expansion and ongoing maintenance of oil sands mining, extraction and upgrading facilities. Unplanned shutdowns of these facilities due to events outside our control or the control of our customers, such as fires, mechanical breakdowns and technology failures, could lead to the temporary shutdown or complete cessation of projects in which we are working. When these events have happened in the past, our business has been adversely affected. Our ability to maintain revenues and margins may be affected to the extent these events cause reductions in the utilization of equipment.

Our ability to grow our operations in the future may be hampered by our inability to obtain long lead time equipment and tires, which can be in limited supply during strong economic times.

Our ability to grow our business is, in part, dependent upon obtaining equipment on a timely basis. Due to the long production lead times of suppliers of large mining equipment during strong economic times, we may have to forecast our demand for equipment many months or even years in advance. If we fail to forecast accurately, we could suffer equipment shortages or surpluses, which could have a material adverse impact on our financial condition and results of operations.

In strong economic times, global demand for tires of the size and specifications we require can exceed the available supply. Our inability to procure tires to meet the demands for our existing fleet as well as to meet new demand for our services could have an adverse effect on our ability to grow our business.

We may not be able to generate sufficient cash flow to meet our debt service and other obligations due to events beyond our control.

Our ability to generate sufficient operating cash flow to make scheduled payments on our indebtedness and meet other capital requirements will depend on our future operating and financial performance. Our future performance will be impacted by a range of economic, competitive and business factors that we cannot control, such as general economic and financial conditions in our industry or the economy generally.

A significant reduction in operating cash flows resulting from changes in economic conditions, increased competition, reduced work or other events could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on our business, financial condition, results of operations, prospects and our ability to service our debt and other obligations. If we are unable to service our indebtedness, we will be forced to adopt an alternative strategy that may include actions such as selling assets, restructuring or refinancing our indebtedness, seeking additional equity capital or reducing capital expenditures. We may not be able to affect any of these alternative strategies on satisfactory terms, if at all, or they may not yield sufficient funds to make required payments on our indebtedness.

Our operations are subject to weather-related factors that may cause delays in our project work.

Because our operations are located in Western Canada and Northern Ontario, we are often subject to extreme weather conditions. While our operations are not significantly affected by normal seasonal weather patterns, extreme weather, including heavy rain and snow, can cause delays in our project work, which could adversely impact our results of operations.

North American Energy Partners Inc.  Management’s Discussion and Analysis  47

Environmental laws and regulations may expose us to liability arising out of our operations or the operations of our customers.

Our operations are subject to numerous environmental protection laws and regulations that are complex and stringent. We regularly perform work in and around sensitive environmental areas such as rivers, lakes and forests. Significant fines and penalties may be imposed on us or our customers for noncompliance with environmental laws and regulations, and our contracts generally require us to indemnify our customers for environmental claims suffered by them as a result of our actions. In addition, some environmental laws impose strict, joint and several liability for investigative and remediation costs in relation to releases of harmful substances. These laws may impose liability without regard to negligence or fault. We also may be subject to claims alleging personal injury or property damage if we cause the release of, or any exposure to, harmful substances.

We own or lease, and operate, several properties that have been used for a number of years for the storage and maintenance of equipment and other industrial uses. Fuel may have been spilled, or hydrocarbons or other wastes may have been released on these properties. Any release of substances by us or by third parties who previously operated on these properties may be subject to laws which impose joint and several liability for clean-up, without regard to fault, on specific classes of persons who are considered to be responsible for the release of harmful substances into the environment.

Our projects expose us to potential professional liability, product liability, warranty or other claims.

We install deep foundations, often in congested and densely populated areas, and provide construction management services for significant projects. Notwithstanding the fact that we generally will not accept liability for consequential damages in our contracts, any catastrophic occurrence in excess of insurance limits at projects where our structures are installed or services are performed could result in significant professional liability, product liability, warranty or other claims against us. Such liabilities could potentially exceed our current insurance coverage and the fees we derive from those services. A partially or completely uninsured claim, if successful and of a significant magnitude, could result in substantial losses.

We may not be able to achieve the expected benefits from any future acquisitions, which would adversely affect our financial condition and results of operations.

We intend to pursue selective acquisitions as a method of expanding our business. However, we may not be able to identify or successfully bid on businesses that we might find attractive. If we do find attractive acquisition opportunities, we might not be able to acquire these businesses at a reasonable price. If we do acquire other businesses, we might not be able to successfully integrate these businesses into our then-existing business. We might not be able to maintain the levels of operating efficiency that acquired companies will have achieved or might achieve separately. Successful integration of acquired operations will depend upon our ability to manage those operations and to eliminate redundant and excess costs. Because of difficulties in combining operations, we may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve through these acquisitions. Any of these factors could harm our financial condition and results of operations.

Aboriginal peoples may make claims against our customers or their projects regarding the lands on which their projects are located.

Aboriginal peoples have claimed aboriginal title and rights to a substantial portion of Western Canada. Any claims that may be asserted against our customers, if successful, could have an adverse effect on our customers which may, in turn, negatively impact our business.

Reduced availability or increased cost of leasing our equipment fleet could adversely affect our results

A portion of our equipment fleet is currently leased from third parties. Further, we anticipate leasing substantial amounts of equipment to meet equipment acquisition commitments related to our long-term overburden removal contract in the upcoming fiscal year. Other future projects may require us to lease additional equipment. If equipment lessors are unable or unwilling to provide us with reasonable lease terms within our expectations, it will significantly increase the cost of leasing equipment or may result in more restrictive lease terms that require recognition of the lease as a capital lease. We are actively pursuing new lessor relationships to dilute our exposure to the loss of one or more of our lessors.

Quantitative and Qualitative Disclosures about Market Risk

Foreign exchange risk

Foreign exchange risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to changes in foreign exchange rates. At March 31, 2010 we had 8 ³/4% senior notes denominated in US dollars in the amount of US$200.0 million. In order to reduce our exposure to changes in the United States to Canadian dollar exchange rate, we entered into a cross-currency swap agreement to manage this foreign currency exposure for both the principal balance due on December 1, 2011 as well as the semi-annual interest payments from the issue date to the maturity date. In conjunction with the cross-currency swap agreement, we also entered into a US dollar interest rate swap and a Canadian dollar interest rate swap. These derivative financial instruments were not designated as hedges for accounting purposes. At March 31, 2010 and March 31, 2009, the notional principal amount of the cross-currency swap was US$200.0 million and Canadian $263.0 million.

48  Management’s Discussion and Analysis  North American Energy Partners Inc.

On December 17, 2008, we received notice that all three swap counterparties had exercised the cancellation option on the US dollar interest rate swap and, effective February 2, 2009, the US dollar interest rate swap was terminated. Our Canadian dollar interest rate swap and cross-currency swap agreements are not cancellable at the option of the counterparties and remained in effect at March 31, 2010. We will continue to pay the counterparties an average fixed rate of 9.889% on the notional amount of Canadian $263.0 million or Canadian $13.0 million semi-annually until December 1, 2011. Beginning March 1, 2009, we received quarterly floating rate payments in US dollars on the cross-currency swap agreement at the prevailing three month US dollar LIBOR rate plus a spread of 4.2% on the notional amount of US $200.0 million.

As a result of the cancellation of the US dollar interest rate swap, we are exposed to changes in the value of the Canadian dollar versus the US dollar. To the extent that the three month US dollar LIBOR rate is less than 4.6% (the difference between the 8 ³/4% senior notes coupon and the 4.2% spread over three month US dollar LIBOR on the cross-currency swap agreement), we will have to acquire US dollars to fund a portion of our semi-annual coupon payment on our 8 ³/4% senior notes. At the three-month US dollar LIBOR rate of 0.268% at March 31, 2010, a $0.01 increase (decrease) in exchange rates in the Canadian dollar would result in an insignificant decrease (increase) in the amount of Canadian dollars required to fund each semi-annual coupon payment.

At March 31, 2010, with other variables unchanged, a $0.01 increase (decrease) in exchange rates of the Canadian dollar to the US dollar related to the US dollar denominated 8 ³/4% senior notes would decrease (increase) net income and decrease (increase) equity by approximately $1.9 million, net of tax. With other variables unchanged, a $0.01 increase (decrease) in exchange rates in the Canadian to the US dollar related to the cross-currency swap would increase (decrease) net income and increase (decrease) equity by approximately $1.9 million, net of tax. The impact of similar exchange rate changes on short-term exposures would be insignificant and there would be no impact to other comprehensive income.

As discussed in the “Liquidity and Capital Resources” section, all of our US dollar denominated 8 ³/4% senior notes were redeemed in April 2010 and the associated swap agreements were terminated. As a result of these transactions, we are no longer exposed to foreign exchange risk with respect to our long-term debt, interest payments or cross-currency and interest rate swap obligations.

We also regularly transact in foreign currencies when purchasing equipment, spare parts as well as certain general and administrative goods and services. These exposures are generally of a short-term nature and the impact of changes in exchange rates has not been significant in the past. We may fix our exposure in either the Canadian dollar or the US dollar for these short-term transactions, if material.

Interest rate risk

We are exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of our financial instruments. Amounts outstanding under our amended credit facilities are subject to a floating rate. Our 8 ³/4% senior notes and 9.125% Series 1 Debentures are subject to a fixed rate. Our interest rate risk arises from long-term borrowings issued at fixed rates that create fair value interest rate risk and variable rate borrowings that create cash flow interest rate risk. Changes in market interest rates cause the fair value of long-term debt with fixed interest rates to fluctuate but do not affect earnings, as our debt is carried at amortized cost and the carrying value does not change as interest rates change.

In some circumstances, floating rate funding may be used for short-term borrowings and other liquidity requirements. We may use derivative instruments to manage interest rate risk. We manage our interest rate risk exposure by using a mix of fixed and variable rate debt and may use derivative instruments to achieve the desired proportion of variable to fixed-rate debt.

We also entered into a US dollar interest rate swap and a Canadian dollar interest rate swap with the net effect of economically converting the 8.75% rate payable on the 8 ³/4% senior notes into a Canadian fixed rate of 9.889% for the duration that the 8 ³/4% senior notes are outstanding. These derivative financial instruments were not designated as hedges for accounting purposes. As a result of the US dollar interest rate swap cancellation, we are exposed to changes in interest rates. We have a fixed semi-annual coupon payment of 8.75% on our US$200.0 million senior notes. With the termination of the US dollar interest rate swap, we no longer receive fixed US dollar payments from the counterparties to offset the coupon payment on our 8 ³/4% senior notes. As a result of this termination, our effective annual interest costs at the current US dollar LIBOR rate will increase US$8.6 million. In addition, we are now exposed to interest rate risk where a 100 basis point increase (decrease) in the three month US dollar LIBOR rate will result in a US$2.0 million decrease (increase) in effective annual interest costs. As at March 31, 2010, holding all other variables constant, a 100 basis point increase (decrease) to Canadian interest rates would impact the fair value of the interest rate swaps by $2.4 million, net of tax, with this change in fair value being recorded in net income. As at March 31, 2010, holding all other variables constant, a 100 basis point increase (decrease) to US interest rates would impact the fair value of the interest rate swaps by $0.2 million, net of tax, with this change in fair value being recorded in net income. As at March 31, 2010, holding all other variables constant, a 100 basis point increase (decrease) of Canadian to US interest rate volatility would have no impact on the fair value of the interest rate swaps.

North American Energy Partners Inc.  Management’s Discussion and Analysis  49

As discussed in the “Liquidity and Capital Resources” section, our US dollar denominated 8 ³/4% senior notes were fully redeemed in April 2010 and the associated swap agreements were terminated. As a result of these transactions, we are no longer exposed to cash flow interest rate risk with respect to the interest payments associated with our swap agreements.

At March 31, 2010, we held $28.4 million of floating rate debt pertaining to our term facility within our amended and restated credit agreement dated June 24, 2009 (March 31, 2009 – $nil). As at March 31, 2010, holding all other variables constant, a 100 basis point increase (decrease) to interest rates on floating rate debt would result in a $0.3 million increase (decrease) in annual interest expense. This assumes that the amount of floating rate debt remains unchanged from that which was held at March 31, 2010.

As discussed in the “Liquidity and Capital Resources” section, we entered into an amended and restated credit agreement effective April 30, 2010. In addition to extending the maturity of the facility to April 2013, the new credit facilities included an $85.0 million Revolving Facility, a $28.4 million Term A Facility and a $50.0 million Term B Facility. At April 30, 2010, the Revolving Facility had no borrowings outstanding and $10.4 million of issued and undrawn letters of credit. The Term A Facility and Term B Facility were fully drawn, resulting in $78.4 million of floating rate debt. Holding all other variables constant, a 100 basis point increase (decrease) to interest rates on this floating rate debt would result in a $0.8 million increase (decrease) in annual interest expense.

H. General Matters

History and Development of the Company

NACG Holdings Inc. (NACG) was formed in October 2003 in connection with the Acquisition discussed below. Prior to the Acquisition, NACG had no operations or significant assets and the Acquisition was primarily a change of ownership of the businesses acquired.

On October 31, 2003, two wholly owned subsidiaries of NACG, as the buyers, entered into a purchase and sale agreement with Norama Ltd. and one of its subsidiaries, as the sellers. On November 26, 2003, pursuant to the purchase and sale agreement, Norama Ltd. sold to the buyers the businesses comprising North American Construction Group. The businesses we acquired from Norama Ltd. have been in operation since 1953. Subsequent to the Acquisition, we have operated the businesses in substantially the same manner as prior to the Acquisition.

On November 28, 2006, prior to the consummation of the IPO discussed below, NACG amalgamated with its wholly-owned subsidiaries, NACG Preferred Corp. and North American Energy Partners Inc. The amalgamated entity continued under the name North American Energy Partners Inc. The voting common shares of the new entity, North American Energy Partners Inc., were the shares sold in the IPO and related secondary offering. On November 28, 2006, we completed the IPO in the United States and Canada of 8,750,000 voting common shares and a secondary offering of 3,750,000 voting common shares for $18.38 per share (US $16.00 per share).

On November 22, 2006, our common shares commenced trading on the New York Stock Exchange and on the Toronto Stock Exchange on an “if, as and when issued” basis. On November 28, 2006, our common shares became fully tradable on the Toronto Stock Exchange.

On December 6, 2006, the underwriters exercised their option to purchase an additional 687,500 common shares from us.

Additional Information

Our corporate office is located at Suite 2400, 500 4^th Avenue SW, Calgary, Alberta, T2P 2V6. Our corporate head office telephone and facsimile numbers are 403-767-4825 and 403-767-4849, respectively.

Additional information relating to us, including our Annual Information Form dated June 10, 2010, can be found on the Canadian Securities Administrators System for Electronic Document Analysis and Retrieval (SEDAR) database at www.sedar.com and the Securities and Exchange Commission’s website at www.sec.gov.

50  Management’s Discussion and Analysis  North American Energy Partners Inc.

EX-99.4

Exhibit 99.4

NORTH AMERICAN ENERGY PARTNERS INC.

CANADIAN SUPPLEMENT TO:

Annual Management’s Discussion and Analysis

For the year ended March 31, 2010

This document supplements the Management’s Discussion and Analysis for the three months and year ended March 31, 2010 and has been prepared pursuant to Section 5.2 of National Instrument 51-102- Continuous Disclosure Obligations

Canadian Supplement to Management’s Discussion and Analysis

For the year ended March 31, 2010

Summary of differences between US GAAP and Canadian GAAP

June 10, 2010

The annual consolidated financial statements for the three months and year ended March 31, 2010 and the accompanying annual Management’s Discussion and Analysis (MD&A) have been prepared in accordance with US generally accepted accounting principles (GAAP). As required by the National instrument 52-107, for the fiscal year of adoption of US GAAP and one subsequent fiscal year, we are required to provide a Canadian Supplement to our MD&A (Canadian Supplement) that states, based on financial information reconciled to Canadian GAAP, those parts of our MD&A that would contain material differences if they were based on financial statements prepared in accordance with Canadian GAAP. The Canadian Supplement should be read in conjunction with our annual financial statements and annual MD&A included in our annual report for the year ended March 31, 2010 prepared in accordance with US GAAP. Note 34 of our annual financial statements explains and quantifies the material differences between US GAAP and Canadian GAAP on our financial position and results of operations.

The tables in this supplement highlight the differences between Canadian and US GAAP. We have shown the Consolidated Statements of Operations, Comprehensive Income (Loss) and Deficit for the three months and year ended March 31, 2010 and an extract of the Consolidated Balance Sheets as at March 31, 2010, so that the areas impacted by the GAAP differences can be clearly identified. Figures included in this supplement are in thousands of Canadian dollars, except per share information.

2  Canadian Supplement to Management’s Discussion and Analysis  North American Energy Partners Inc.

Consolidated Statements of Operations, Comprehensive Income (Loss) and Deficit

	Three months ended March 31,
(dollars in thousands, except per share information)	2010 (Canadian GAAP)		Adjustments		2010 (US GAAP)		2009 (Amended (j) Canadian GAAP)		Adjustments		2009 (Amended (j) US GAAP)
Revenue (g)	$222,374		$(1,805	)	$220,569		$174,700		$–		$174,700
Project costs (g)	94,015		(1,614	)	92,401		71,522		–		71,522
Equipment costs	61,493		–		61,493		48,374		–		48,374
Equipment operating lease expense	22,009		–		22,009		13,266		–		13,266
Depreciation (a)	11,912		31		11,943		8,527		69		8,596
Gross profit	32,945		(222	)	32,723		33,011		(69	)	32,942
General and administrative costs (c) and (g)	19,308		(204	)	19,104		16,688		12		16,700
Loss on disposal of property, plant and equipment	189		–		189		1,547		–		1,547
Loss on disposal of assets held for sale	–		–		–		–		–		–
Amortization of intangible assets (b)	489		(208	)	281		662		(210	)	452
Equity in loss of unconsolidated joint venture (g)	–		22		22		–		–		–
Impairment of goodwill	–		–		–		143,447		–		143,447
Operating income (loss) before the undernoted	12,959		168		13,127		(129,333	)	129		(129,204	)
Interest expense, net (b)	5,709		646		6,355		7,787		549		8,336
Foreign exchange (gain) loss (b)	(5,925	)	(46	)	(5,971	)	7,567		84		7,651
Realized and unrealized loss (gain) on derivative financial instruments (d)	13,946		(2,720	)	11,226		(11,424	)	–		(11,424	)
Other income	(818	)	–		(818	)	(591	)	–		(591	)
Income (loss) before income taxes	47		2,288		2,335		(132,672	)	(504	)	(133,176	)
Current income taxes	1,948		–		1,948		3,704		–		3,704
Deferred income taxes (h)	1,062		268		1,330		371		(139	)	232
Net loss and comprehensive loss for the period	(2,963	)	2,020		(943	)	(136,747	)	(365	)	(137,112	)
Deficit, beginning of the period	(125,842	)	(3,101	)	(128,943	)	(21,232	)	239		(20,993	)
Deficit, end of the period	$(128,805	)	$(1,081	)	$(129,886	)	(157,979	)	(126	)	(158,105	)
Per share information
Net loss – basic	$(0.08	)	$0.05		$(0.03	)	$(3.79	)	$(0.01	)	$(3.80	)
Net loss – diluted	$(0.08	)	$0.05		$(0.03	)	$(3.79	)	$(0.01	)	$(3.80	)
EBITDA	$18,157		$2,757		$20,914		$(115,696	)	$(96	)	$(115,792	)
Consolidated EBITDA(as defined within our credit agreement) (i)	$26,428		$–		$26,428		$25,191		$–		$25,191

North American Energy Partners Inc.  Canadian Supplement to Management’s Discussion and Analysis  3

	Year ended March 31,
(dollars in thousands, except per share information)	2010 (Canadian GAAP)	Adjustments	2010 (US GAAP)	2009 (Canadian GAAP – Amended (j))	Adjustments	2009 (US GAAP – Amended (j))
Revenue (g)	$763,301	(4,336)	758,965	972,536	$–	972,536
Project costs (g)	304,849	(3,542)	301,307	505,026	–	505,026
Equipment costs	209,408	–	209,408	217,120	–	217,120
Equipment operating lease expense	66,329	–	66,329	43,583	–	43,583
Depreciation (a)	42,512	124	42,436	36,227	162	36,389
Gross profit	140,203	(918)	139,285	170,580	(162)	170,418
General and administrative costs (c) and (g)	63,236	(706)	62,530	74,405	55	74,460
Loss on disposal of property, plant and equipment	1,233	–	1,233	5,325	–	5,325
Loss on disposal of assets held for sale	373	–	373	24	–	24
Amortization of intangible assets (b)	2,550	(831)	1,719	2,338	(837)	1,501
Equity in earnings of unconsolidated joint venture (g)	–	(44)	(44)	–	–	–
Impairment of goodwill	–	–	–	176,200	–	176,200
Operating income (loss) before the undernoted	72,811	663	73,474	(87,712)	620	(87,092)
Interest expense, net (b)	23,594	2,486	26,080	27,450	2,162	29,612
Foreign exchange (gain) loss (b)	(48,405)	(496)	(48,901)	46,666	606	47,272
Realized and unrealized loss (gain) on derivative financial instruments (d)	54,411	–	54,411	(32,595)	(4,655)	(37,250)
Other income	(14)	–	(14)	(5,955)	–	(5,955)
Income (loss) before income taxes	43,225	(1,327)	41,898	(123,278)	2,507	(120,771)
Current income taxes	3,803	–	3,803	5,546	–	5,546
Deferred income taxes (h)	10,248	(372)	9,876	9,053	34	9,087
Net income (loss) and comprehensive income (loss) for the period	29,174	(955)	28,219	(137,877)	2,473	(135,404)
Deficit, beginning of the period	(157,979)	(126)	(158,105)	(21,093)	(1,608)	(22,701)
Change in accounting policies related to inventories (f)	–	–	–	991	(991)	–
Deficit, end of the period	$(128,805)	$(1,081)	$(129,886)	(157,979)	(126)	(158,105)
Per share information
Net income (loss) – basic	$0.81	$(0.03)	$0.78	(3.83)	0.07	(3.76)
Net income (loss) – diluted	$0.79	$(0.02)	$0.77	(3.83)	$0.07	(3.76)
EBITDA	111,881	$452	112,333	$(49,275)	3,994	$(53,269)
Consolidated EBITDA(as defined within our credit agreement) (i)	$121,644	$–	$121,644	$139,446	$–	$139,446

4  Canadian Supplement to Management’s Discussion and Analysis  North American Energy Partners Inc.

Extract of the Annual Consolidated Balance Sheets

The following table highlights the differences between Canadian and US GAAP on the Annual Consolidated Balance Sheets. We have focused on the line items that have been impacted by the GAAP differences.

(dollars in thousands, except per share information)	March 31, 2010 (Canadian GAAP)	Adjustments	March 31, 2010 (US GAAP)	March 31, 2009 (Canadian GAAP - - Amended(j))	Adjustments	March 31, 2009 (US GAAP - - Amended(j))
Cash and cash equivalents(g)	$104,245	$(1,240)	$103,005	$98,880	$–	$98,880
Accounts receivable, net(g)	113,316	(1,432)	111,884	78,323	–	78,323
Unbilled revenue(g)	86,496	(1,794)	84,702	55,907	–	55,907
Prepaid expenses and deposits(g)	6,968	(87)	6,881	4,781	–	4,781
Property, plant and equipment(a)	328,207	536	328,743	315,455	660	316,115
Intangible assets(b)	8,720	(1,051)	7,669	6,711	(767)	5,944
Deferred financing costs(b)	1,040	5,685	6,725	–	7,910	7,910
Investment in and advances to unconsolidated joint venture(g)	–	2,917	2,917	–	–	–
Accounts payable(g)	(68,513)	1,637	(66,876)	(56,204)	–	(56,204)
Senior notes(b)  and(d)	(201,614)	(1,506)	(203,120)	(252,899)	(2,857)	(255,756)
Deferred tax liabilities(h)	(26,389)	(1,052)	(27,441)	(29,322)	(1,423)	(30,745)
Common shares(e)	(300,047)	(3,458)	(303,505)	(299,973)	(3,458)	(303,431)
Additional paid-in capital(c)  and(h)	(7,203)	(236)	(7,439)	(5,275)	(191)	(5,466)
Deficit(a) – (d) and(f) – (h)	128,805	1,081	129,886	157,979	126	158,105

Canadian and United States accounting policies differences

A detailed reconciliation of our results for the years ended March 31, 2010, 2009 and 2008 is included in note 34 of our consolidated financial statements for the years ended March 31, 2010, 2009 and 2008.

The differences between US GAAP and Canadian GAAP that have the most significant impact on our financial position and results of operations for the three months and year ended March 31, 2010, include accounting for: capitalization of interest, financing costs, discounts and premiums, derivative financial instruments, stock-based compensation, and modification of Series B Preferred Shares.

a) Capitalization of interest

US GAAP requires capitalization of interest costs as part of the historical cost of acquiring certain qualifying assets that require a period of time to prepare for their intended use. This is not required under Canadian GAAP. The capitalized amount is subject to depreciation in accordance with our policies when the asset is placed into service.

b) Financing costs, discounts and premiums

Under US GAAP, deferred financing costs incurred in connection with our senior notes are being amortized over the term of the related debt using the effective interest method. Prior to April 1, 2007, for Canadian GAAP purposes, these transaction costs were recorded as a deferred asset under Canadian GAAP and these deferred financing costs were being amortized on a straight-line basis over the term of the debt.

Effective April 1, 2007, we adopted CICA Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, on a retrospective basis without restatement as described below. Although Section 3855 also requires the use of the effective interest method to account for the amortization of finance costs, the requirement to bifurcate the issuer’s early prepayment option on issuance of the debt (which is not required under US GAAP) resulted in an additional premium that is being amortized over the term of the debt under Canadian GAAP. In addition, foreign denominated transaction costs, discounts and premiums are considered as part of the carrying value of the related financial liability under Canadian GAAP and are subject to foreign currency gains or losses resulting from periodic translation procedures as they are treated as a monetary item under Canadian GAAP. Under US GAAP, foreign denominated transaction costs are considered non-monetary and are not subject to foreign currency gains and losses resulting from periodic translation procedures.

In connection with the adoption of Section 3855, transaction costs incurred in connection with our Revolving 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 US GAAP, we continue to amortize these transaction costs over the stated term of the related debt using the effective interest method. We disclose the financing costs for both the senior notes and the Revolving Facility as deferred financing costs on the Consolidated Balance Sheets with the amortization charge classified as interest on the Consolidated Statements of

North American Energy Partners Inc.  Canadian Supplement to Management’s Discussion and Analysis  5

Operations and Comprehensive Income (Loss). Under Canadian GAAP, the financing costs related to the senior notes are included in the “senior notes” balance on the Consolidated Balance Sheets.

c) Stock-based compensation

Up until April 1, 2006, we followed the provisions of ASC 718, “Share-Based Payment” (formerly Statement of Financial Accounting Standards No. 123, “Stock-Based Compensation”), for US GAAP purposes. As we use the fair value method of accounting for all stock-based compensation payments under Canadian GAAP, there were no differences between Canadian and US GAAP prior to April 1, 2006. On April 1, 2006, we adopted the provisions of Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment” (“SFAS 123R”), which is now a part of ASC 718. As we used the minimum value method for purposes of complying with Statement of Financial Accounting Standards No. 123, we were required to adopt the provisions under the revised guidance prospectively. Under Canadian GAAP, we were permitted to exclude volatility from the determination of the fair value of stock options granted until the filing of our initial registration statement relating to our initial public offering of voting shares on July 21, 2006. As a result, for options issued between April 1, 2006 and July 21, 2006, there is a difference between Canadian and US GAAP relating to the determination of the fair value of options granted.

d) Derivative financial instruments

Under Canadian GAAP, 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 provide for accelerated redemption by the holders in certain instances. These embedded derivatives were measured at fair value at the inception of the senior notes and the residual amount of the proceeds was allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of the senior notes is accreted to par value over the term of the notes using the effective interest method and is recognized as interest expense as discussed in b) above. Prior to April 1, 2007 under Canadian GAAP, separate accounting of embedded derivatives from the host contract was not permitted by EIC-117.

Under US GAAP, ASC 815 (formerly Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”)) establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts and debt instruments) be recorded in the balance sheet as either an asset or liability measured at its fair value. The contingent embedded derivative in 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 derivative has been measured at fair value and changes in fair value recorded in net income for all periods presented. The issuer’s early prepayment option included in the senior notes does not meet the criteria as an embedded derivative under ASC 815 (formerly SFAS 133) and was not bifurcated from the host contract and measured at fair value resulting in a US GAAP and Canadian GAAP difference.

On adoption of CICA Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, we reviewed the accounting treatment of a number of outstanding contracts and determined that a price escalation feature in a revenue construction contract and supplier contracts entered into prior to April 1, 2007 contained embedded derivatives that are not closely related to the host contract under Canadian GAAP. We recorded the fair value of these embedded derivatives on April 1, 2007 of $9.7 million, with a corresponding increase in opening deficit of $7.0 million, net of future income taxes of $2.8 million for Canadian GAAP purposes. Under US GAAP, we had recognized and measured these embedded derivatives since inception of the related contracts.

e) NAEPI Series B Preferred Shares

Prior to the modification of the terms of the North American Energy Partners Inc. (“NAEPI”) Series B preferred shares on March 30, 2006, there were no differences between Canadian GAAP and US GAAP related to the NAEPI Series B preferred shares. As a result of the modification of terms of NAEPI’s Series B preferred shares, under Canadian GAAP, 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 US 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 US GAAP, NACG was accreting the initial fair value of the amended NAEPI Series B preferred shares of $45.9 million recorded on their amendment date (March 30, 2006) to the December 31, 2011 redemption value of $69.6 million using the effective interest method, which was consistent with the treatment of the NAEPI Series B preferred shares as temporary equity in the financial statements of NAEPI. The accretion charge was recognized by NACG as a charge to minority interest (as opposed to retained earnings in the accounts of NAEPI) under US GAAP and interest expense in NACG’s financial statements under Canadian GAAP.

On November 28, 2006, NACG exercised a call option to acquire all of the issued and outstanding NAEPI Series B preferred shares in exchange for 7,524,400 common shares of NACG. For Canadian GAAP purposes, NACG recorded the exchange by transferring the carrying value of the NAEPI Series B preferred shares on the exercise date of $44.7 million to common

6  Canadian Supplement to Management’s Discussion and Analysis  North American Energy Partners Inc.

shares. For US GAAP purposes, the conversion has been accounted for as a combination of entities under common control as all of the shareholders of the NAEPI Series B preferred shares are also common shareholders of NACG resulting in the reclassification of the carrying value of the minority interest on the exercise date of $48.1 million to common shares. NACG and NAEPI were amalgamated later in 2006 and the amalgamated entity continued as NAEPI.

f) Inventories

Effective April 1, 2008, we retrospectively adopted CICA Handbook Section 3031, “Inventories”, without restatement of prior periods. This standard requires inventories to be measured at the lower of cost and net realizable value and provides guidance on the determination of cost, including the allocation of overheads and other costs to inventories, the requirement for an entity to use a consistent cost formula for inventory of a similar nature and use, and the reversal of previous write-downs to net realizable value when there are subsequent increases in the value of inventories. This new standard also clarifies that spare component parts that do not qualify for recognition as property, plant and equipment should be classified as inventory. In adopting this new standard, we reversed a tire impairment that was previously recorded at March 31, 2008 in other assets of $1.4 million with a corresponding decrease to opening deficit of $1.0 million net of future taxes of $0.4 million.

During the year ended March 31, 2008, the replacement cost (i.e. market) of spare tire inventory was lower than the original carrying amount of inventory. As a result, we recorded an inventory write-down of $1.4 million under Canadian GAAP. Under US GAAP, market means current replacement cost. However, market under US GAAP should not exceed the net realizable value nor should it be less than net realizable value reduced by an allowance for a normal profit margin. We established that the net realizable value and net realizable value less an allowance for a normal profit margin was greater than or equal to cost and as such a write-down of spare tires was not appropriate under US GAAP for the year ended March 31, 2008. Please refer to note 3 aa) of our annual consolidated financial statements for the year ended March 31, 2010.

g) Joint venture

We own a 49% interest in Noramac Ventures Inc., a nominee company for our Noramac Joint Venture (JV) and we have joint 50/50 control of this entity. Under US GAAP, we record our share of earnings (loss) of the JV using the equity method of accounting. Under Canadian GAAP, we use the proportionate consolidation method of accounting for the JV. Under the proportionate consolidation method, we recognize our share of the results of operations, cash flows, and financial position of the JV on a line-by-line basis in our consolidated financial statements and eliminate our share of all material intercompany transactions with the JV. While there is no impact on net income or earnings per share as a result of the US GAAP treatment of the joint venture, as compared to Canadian GAAP, there are presentation differences affecting the disclosures in the consolidated financial statements and supporting notes.

h) Other matters

Other adjustments relate to the tax effect of items (a) through (f) above. The tax effects of temporary differences are described as future income taxes under Canadian GAAP whereas in our US GAAP financial statements such amounts are described as deferred income taxes. In addition, Canadian GAAP generally refers to additional paid-in capital as contributed surplus for financial statement presentation purposes.

i) Consolidated EBITDA

A difference arises in computing EBITDA for the three months and year ended March 31, 2010 and March 31, 2009 respectively as result of US GAAP and Canadian GAAP differences stated above (a) to (d) and (f). Under US GAAP, equity in earnings (loss) of unconsolidated joint venture is added back in computing consolidated EBITDA for the three months and years ended March 31, 2010 and March 31, 2009 respectively.

j) Adjustments related to prior year financial statements

The financial statements for fiscal 2009 and fiscal 2008 under Canadian GAAP have been amended to correct the following errors identified during the preparation of our fiscal 2010 financial statements:

i. Reclassification of accrued liabilities. The financial statements for fiscal 2009 have been amended to correct a classification error with respect to accrued liabilities identified during the preparation of our fiscal 2010 consolidated financial statements. Certain operating lease agreements provide a maximum hourly usage limit, above which we will be required to pay for the over hour usage. These contingent rentals are recognized when payment is considered probable and are due at the end of the lease term. We have historically classified the contingent rentals as a current liability; however, certain of the amounts are due beyond one year from the balance sheet date. In the current year, we reclassified amounts due beyond one year, from the balance sheet date, as a long term liability and has reclassified comparative figures accordingly. The amount reclassified on the Consolidated Balance Sheet was $7.1 million as at March 31, 2009;

ii. Buy-out of leased assets. The financial statements for fiscal 2008 have been amended under Canadian GAAP to correct an error related to the method of accounting for an incentive at the time of buying previously leased assets, which was identified during the preparation of our fiscal 2010 consolidated financial statements. When an asset is leased under an operating lease agreement, as stated in the paragraph above, contingent rentals are recognized when payment is considered probable and are due at the end of the lease term. We can buy the asset at the end

North American Energy Partners Inc.  Canadian Supplement to Management’s Discussion and Analysis  7

of the lease term at a pre-determined market price at which point the liability is extinguished since the lease agreement is cancelled. We have been traditionally extinguishing the liability for such lease buyouts by reducing equipment costs related to leased equipment, instead of considering the extinguishment of the liability as an incentive to purchase the asset and therefore reducing the cost of the asset. The correction of this error increased “Equipment costs” by $2.7 million, reduced “Depreciation” by $0.1 million, reduced “Future income taxes” by $0.8 million and reduced “Net income and comprehensive income for the year” by $1.8 million from the amounts originally reported in the Consolidated Statements of Operations and Comprehensive Income (Loss) for the year ended March 31, 2008. It also reduced “Property, plant and equipment” by $2.6 million, reduced long term future income taxes liabilities by $0.8 million and increased “Deficit” for the year by $1.8 million from the amounts originally reported in the Consolidated Balance Sheet as at March 31, 2008. The financial statements for fiscal 2009 have also been amended under Canadian GAAP to correct an error related to the method of accounting for an incentive at time of buying previously leased assets, which was identified during the preparation of our fiscal 2010 consolidated financial statements as stated above. The correction of this error increased “Equipment costs” by $6.6 million, reduced “Depreciation” by $0.6 million, reduced “Future income taxes” by $1.8 million and increased “Net loss and comprehensive loss for the year” by $4.2 million from the amounts originally reported in the Consolidated Statements of Operations and Comprehensive Income (Loss) for the year ended March 31, 2009. It also reduced “Property, plant and equipment” by $8.6 million, reduced long term future income taxes liabilities by $2.6 million and increased “Deficit” for the year by $6.0 million from the amounts originally reported in the Consolidated Balance Sheet as at March 31, 2009.

iii. Valuation of derivative financial instruments. The financial statements for fiscal 2009 have also been amended under Canadian GAAP to correct an error related to the determination of the fair value of the cross-currency and interest rate swap liabilities (collectively, the “swap liability”) which was identified on settlement of the swap liability on April 8, 2010. We recorded the fair value of the swap liability and in addition recorded accrued interest on the swap liability. This resulted in the swap liability being misstated and the changes in the fair value of the swap liability being misstated by the change in the amount of the accrued interest at each reporting period from March 31, 2009. The periods before March 31, 2009 were not materially impacted because prior to February 2, 2009, the Canadian Dollar interest rate swap was still in place (see “Interest rate risk” in Quantitative and Qualitative Disclosures about Market Risk section in our annual MD&A) and therefore the net accrued interest payable under the swap liability was not material. The error increased “Realized and unrealized gain on derivative financial instruments” by $7.5 million, increased income tax expense by $1.7 million and reduced net loss by $5.8 million from amounts originally reported in the Consolidated Statements of Operations and Comprehensive Income (Loss) for the year ended March 31, 2009. It also reduced “Derivative financial instruments” by $7.5 million, increased long term future income taxes liabilities by $1.7 million and reduced “Deficit” by $5.8 million in the Consolidated Balance Sheet as at March 31, 2009.

Management’s discussion and analysis under US GAAP

Please refer to the annual report for March 31, 2010 for our corresponding Management’s Discussion and Analysis (MD&A) under US GAAP. The differences between US GAAP and Canadian GAAP, described above, impact the discussion and analysis several sections of our annual MD&A.

Additional information

Additional information relating to us, including our Annual Information Form dated June 10, 2010, can be found on the Canadian Securities Administrators System for Electronic Document Analysis and Retrieval (SEDAR) database at www.sedar.com and the Securities and Exchange Commission’s website at www.sec.gov.

8  Canadian Supplement to Management’s Discussion and Analysis  North American Energy Partners Inc.

EX-99.5

Exhibit 99.5

    KPMG LLP Chartered Accountants 10125 – 102 Street Edmonton AB T5J 3V8 Canada     Telephone Fax Internet     (780) 429-7300 (780) 429-7379 www.kpmg.ca

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:

_Ÿ our Report of Independent Registered Public Accounting Firm dated June 9, 2010 on the consolidated balance sheets of North American Energy Partners Inc. (the “Company”) as at March 31, 2010 and 2009 and the consolidated statements of operations and comprehensive income (loss), shareholders’ equity and cash flows for each of the years in three-year period ended March 31, 2010;

_Ÿ our Report of Independent Registered Public Accounting Firm dated June 9, 2010 on the Company’s internal control over financial reporting as of March 31, 2010

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, 2010.

Chartered Accountants

Edmonton, Canada

June 9, 2010

KPMG LLP, is a Canadian limited liability partnership and a member firm of the KPMG

network of independent member firms affiliated with KPMG International, a Swiss cooperative.

KPMG Canada provides services to KPMG LLP.

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, 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, 2010 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 10, 2010

/s/ Rodney J. Ruston, CEO

Name: Rodney J. Ruston

Title: President and Chief Executive Officer

EX-99.7

Exhibit 99.7

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, David Blackley, 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, 2010 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 10, 2010

/s/ David Blackley, CFO

Name: David Blackley

Title: Chief Financial 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, 2010 (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 10, 2010

/s/ Rodney J. Ruston, CEO

Name: Rodney J. Ruston

Title: President and Chief Executive Officer

EX-99.9

Exhibit 99.9

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, 2010 (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 10, 2010

/s/ David Blackley, CFO

Name: David Blackley

Title: Chief Financial Officer