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, 2012                                               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.

36,251,006 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  ¨

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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, 2012 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, 2012, including the report of the independent registered chartered accountants 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, 2012 is attached as Exhibit 99.3 to this Annual Report on Form 40-F and is incorporated herein by reference.

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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, 2012, 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, 2012, 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 chartered accountants on management’s assessment of internal control over financial reporting is included under the heading “Report of Independent Registered Chartered Accountants” on pages 1 and 2 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—Material Changes to the Internal Controls over Financial Reporting” included in the Registrant’s Management’s Discussion and Analysis for the fiscal year ended March 31, 2012, 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 such 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 such term is defined by the rules and regulations of the Securities and Exchange Commission), entitled the “Code of Conduct and Ethics Policy”, that applies to all employees the Registrant, including its President and Chief Executive Officer, its Chief Financial Officer and its Vice President, Finance. The Code of Conduct and Ethics Policy is available for viewing on the Registrant’s website at www.nacg.ca under “Investor Relations—Corporate Governance”. There were not any amendments to any provision of the Code of Conduct and Ethics Policy during the fiscal year ended March 31, 2012 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, 2012 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, 2012, 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, 2012, 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, 2012, 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, 2012, 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.

MINE SAFETY DISCLOSURE

Pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, issuers that are operators, or that have a subsidiary that is an operator, of a coal or other mine in the United States, and that is subject to regulation by the Federal Mine Safety and Health Administration (“MSHA”) under the Mine Safety and Health Act of 1977 (the “Mine Act”), are required to disclose in their periodic reports filed with the SEC information regarding specified health and safety violations, orders and citations, related assessments and legal actions, and mining-related fatalities. During the fiscal year ended March, 2012, the Registrant had no mines in the United States that were subject to regulation by the MSHA under the Mine Act.

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 6, 2012

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EXHIBIT INDEX

99.1	Annual Information Form for the fiscal year ended March 31, 2012.
99.2	Audited Annual Consolidated Financial Statements for the fiscal year ended March 31, 2012.
99.3	Management’s Discussion and Analysis for the fiscal year ended March 31, 2012.
99.4	Consent of KPMG LLP.
99.5	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934.
99.6	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934.
99.7	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.8	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	The following financial information from North American Energy Partners Inc.’s audited Consolidated Financial Statements, formatted in XBRL (eXtensible Business Reporting Language) and furnished electronically herewith: (i) the Consolidated Balance Sheets; (ii) the Consolidated Statements of Operations and Comprehensive (Loss) Income; (iii) the Consolidated Statements of Changes in Shareholders’ Equity; (iv) the Consolidated Statements of Cash Flows; and (v) Notes to the Consolidated Financial Statements, tagged as blocks of text.

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EX-99.1

NORTH AMERICAN ENERGY PARTNERS INC.

ANNUAL INFORMATION FORM

June 6, 2012

NOA

Table of Contents

A. Explanatory Notes		1
	Industry Data and Forecasts	1
	Caution Regarding Forward-Looking Information	1
	Non-GAAP Financial Measures	1
B. Corporate Structure		2
	North American Energy Partners Inc.	2
	Subsidiaries	3
C. Business Overview		4
	Business Overview	4
	History and Development of the Business	4
	Competitive Strengths	5
	Operations Overview	6
	Our Strategy	6
D. Projects, Competition and Major Suppliers		7
	Active Projects	7
	Recently Completed Projects	8
	Competition	9
	Major Suppliers	9
E. Resources and Key Trends		10
	Fleet and Equipment	10
	Credit Facilities	12
	Variability of Results	12
F. Legal and Labour Matters		12
	Laws and Regulations and Environmental Matters	12
	Legal Proceedings and Regulatory Actions	13
	Employees and Labour Relations	13
G. Description of Securities, Rights Plans and Agreements		13
	Capital Structure	13
	Shareholder Rights Plan	14
	Registration Rights Agreement	14
	9.125% Series 1 Debentures	15
H. Material Contracts		16
I. Directors and Officers		16
	Director and Officer Information	16
	Interest of Management and Others in Material Transactions	20
J. The Board and Board Committees		20
	Audit Committee	20
	Compensation Committee	20
	Governance Committee	21
	Health, Safety, Environment and Business Risk Committee	21
K. Forward-Looking Information, Assumptions and Risk Factors		21
	Forward-Looking Information	21
	Assumptions	22
	Business Risk Factors	22
	Risks Factors Related to Our Common Shares	28
	Risk Factors Relating to Debt Securities	30
	Quantitative and Qualitative Disclosures about Market Risk	31
L. General Matters		31
	Additional Information	31
	Transfer Agent and Registrar	32
	Experts	32
	Glossary of Terms	32
EXHIBIT A		33
	Audit Committee Charter	33

NOA

Annual Information Form

June 6, 2012

A. Explanatory Notes

The information in this Annual Information Form (AIF) is stated as at June 6, 2012, unless otherwise indicated. For an explanation of the capitalized terms and expressions and certain defined terms, please refer to the “Glossary of Terms” at the end of this AIF. All references in this AIF to “we”, “us”, “NAEPI” or the “Company”, unless the context otherwise requires, mean North American Energy Partners Inc. and its Subsidiaries (as defined below). Except where otherwise specifically indicated, all dollar amounts are expressed in Canadian dollars. For additional information and details, readers are referred to the audited consolidated financial statements for the year ended March 31, 2012 and notes there to, as well as the accompanying annual Management’s Discussion and Analysis (“annual MD&A”) which 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 website at www.nacg.ca.

Industry Data and Forecasts

This AIF 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 and current and scheduled projects in the Canadian oil sands was obtained from the Energy Resources Conservation Board (“ERCB”) 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.

Caution Regarding Forward-Looking Information

Our AIF is intended to enable readers to gain an understanding of our current results and financial position. To do so, we provide material information and analysis about the Company and our business at a point in time in the context of our historical and possible future development. 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, assumptions and uncertainties that could have a material impact on future prospects. Please refer to “Forward-Looking Information, Assumptions and Risk Factors” for a discussion of the risks, assumptions and uncertainties related to such information. Readers are cautioned that actual events and results may vary from those anticipated.

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 AIF, 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 fourth amended and restated credit agreement, 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, the impairment of goodwill, the amendment related to the $42.5 million revenue writedown on the Canadian Natural¹ overburden removal contract (described in the “Explanatory Notes - Significant Business Event” section of our annual MD&A, which section is expressly incorporated by reference into this AIF) and certain other non-cash items included in the calculation of net income.

¹  Canadian Natural Resources Limited (Canadian Natural), owner and operator of the Horizon Oil Sands mine site.

2012 Annual Information Form 1

We believe that EBITDA is a meaningful measure of the performance of our business because it excludes items, such as interest, income taxes, depreciation and amortization 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, both of which are calculated using Consolidated EBITDA. Non-compliance with these financial covenants could result in a requirement 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. For example, EBITDA and Consolidated EBITDA do not:

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

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

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

• include tax payments that represent a reduction in cash available to us; or

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

Consolidated EBITDA excludes certain unrealized losses, which may ultimately result in a liability that may need to be paid and in the case of certain excluded 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.

B. Corporate Structure

North American Energy Partners Inc.

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. (“NAEPI”).

2 2012 Annual Information Form

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Subsidiaries

NAEPI includes its wholly-owned subsidiaries North American Construction Group Inc. (“NACGI”), North American Construction Projects Inc., North American Fleet Company Ltd., NACG International Inc., North American Major Mining Projects Inc., NACG Properties Inc., North American Construction Management Inc. (“NACMI”) along with the wholly-owned operating subsidiaries of NACMI. The chart below depicts our current corporate structure with respect to each of our direct subsidiaries and indirect subsidiaries (collectively the “Subsidiaries”):

NAEPI and the Subsidiaries are all corporations subsisting under the Business Corporations Act (Alberta), except NACGI, NACG International Inc., North American Construction Ltd. and North American Foundation Engineering Inc., which are corporations subsisting under the Canada Business Corporations Act, Drillco Foundation Co. Ltd. and DF Investments Limited, which are corporations subsisting under the Business Corporations Act (Ontario) and Cyntech U.S. Inc., which is a corporation subsisting under the Texas Business Organizations Code.

2012 Annual Information Form 3

C. Business Overview

Business Overview

We provide a wide range of heavy construction and mining, piling and pipeline installation services to customers in the Canadian oil sands, industrial construction, commercial and public construction and pipeline construction markets. Our primary market is the Canadian 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. For the year ended March 31, 2012, recurring services represented 87% of our oil sands business. Our principal oil sands customers include all four producers that are currently mining bitumen in Alberta: Syncrude², Suncor³, Shell⁴, and Canadian Natural. We focus on building long-term relationships with our customers and have provided services to each of them since inception of their respective projects. In the case of Syncrude and Suncor, these relationships span 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 (owned, leased and rented) includes approximately 900 pieces of diversified heavy construction equipment supported by over 750 pieces of ancillary equipment. While our expertise covers mining, heavy construction, tailings management and mine reclamation services, underground services installation (fire lines, sewer, water, etc.) for industrial projects and piling and pipeline installation in many different locations, we have a specific capability operating in the harsh climate and difficult terrain of northern Canada, particularly in the Canadian oil sands.

We believe that our excellent safety record, coupled with our significant oil sands knowledge, experience, long-term customer relationships, equipment capacity, scale of operations and broad service offering, differentiate us from our competition. As such, our capabilities enable us to support our customers’ recurring services needs with respect to their new oil sands mining developments and expansions.^¿

While our mining services are primarily focused on the oil sands, we believe that we have demonstrated our ability to successfully apply our oil sands knowledge and technology and put it to work in other resource development projects. We believe we are positioned to respond to the needs of a wide range of other resource developers and we remain committed to expanding our operations outside of the Canadian oil sands.

History and Development of the Business

We completed an Initial Public Offering (“IPO”) of our common shares and a related reorganization in November 2006 in order to reduce the leverage on 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.

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

• In the oil sands, the economic downturn during fiscal 2009 contributed to a temporary reduction in demand for project development services supporting new construction. The economy began to stabilize in the second half of fiscal 2010 and by the end of fiscal 2011, commodity prices had largely recovered. Oil sands producers began announcing plans to restart construction on previously postponed expansions and greenfield projects, signalling a return to growth in the oil sands. In fiscal 2012, the announcements started translating into contracts, strengthening our project backlog with awards at new and existing oil sands mines and various steam assisted, gravity drainage (“SAGD”) developments. In the Heavy Construction and Mining segment, we were awarded construction contracts with major oil sands customers including:

• contracts for the shear key and MSE wall for the Muskeg River Mine Relocation Project;

• the initial earthworks contract for the Joslyn North Mine Project;

• the initial site development contract for the BlackGold SAGD Project;

• the initial site development contract for the Kirby SAGD Project; and

• the initial site development contract for the MacKay River SAGD Project.

²  Syncrude Canada Ltd. (Syncrude) – operator of the oil sands mining and extraction operations for the Syncrude Project, a joint venture amongst Canadian Oil Sands Limited (37%), Imperial Oil Resources (25%), Suncor Energy Oil and Gas Partnership (12%), Sinopec Oil Sands Partnership (9%), Nexen Oil Sands Partnership (7%), Murphy Oil Company Ltd. (5%) and Mocal Energy Limited (5%).

³  Suncor Energy Inc. (Suncor).

⁴  Shell Canada Energy (Shell), a division of Shell Canada Limited, which is the operator of the 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 Corporation (20%).

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

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• Demand for recurring services in the oil sands remained steady throughout the downturn, reflecting the inherent stability of operational oil sands mines. In the Heavy Construction and Mining segment, we were awarded multi-year agreements with major oil sands customers including:

• a three-year master services agreement with Shell;

• a three-year muskeg removal contract with Shell;

• a four-year master services agreement with Syncrude; and

• a five-year master services agreement with Suncor.

• In addition to these master services contracts, we recently reached an agreement with Canadian Natural on amendments to our 10-year overburden removal and tailings dyke construction services contract with Canadian Natural (“the Canadian Natural contract”). The amending agreement included a $34.1 million settlement of past claims under the original contract. The general terms of the original contract related to work scope remained in place, however, these services will now be performed under a revised payment structure that carries less risk to us than the unit-rate structure it replaces. The new payment structure carries a base margin and provides for the opportunity to enhance margins, by meeting mutually agreed upon performance targets.

• We also identified a service opportunity related to new regulations governing tailings pond management (Directive 74) and moved quickly to develop and market a capability that supports our clients’ requirements. While this industry development is still in its early stages, we have already been involved in the construction of several pilot plants and some of the initial commercial developments.

• In the industrial sector outside of the oil sands, we have seen activity strengthening over the last three years. This has benefitted both our Piling segment and our Heavy Construction and Mining segment. In Saskatchewan, refinery and mine development projects have continued to generate opportunities for piling and light industrial services. Strong demand for industrial services in Western Canada has also created opportunities for us to expand our light industrial services to above-ground construction. As an example, we are currently erecting 7,000 tons of structural steel for the Mt. Milligan Copper/Gold Project in British Columbia.

• In the commercial construction sector, activity levels began to recover in fiscal 2011 and continued to build momentum in fiscal 2012. This is reflected in the revenue and margin growth achieved by our Piling segment over the past three years. In addition to benefitting from improving market conditions, we have continued to position ourselves for the future by expanding our geographic reach and service offering with the acquisition of two piling companies. In fiscal 2010, we completed the acquisition of DF Investments Inc. and its subsidiary, Drillco Foundation Co. Ltd. This transaction established our presence in the large Ontario construction market. We followed up with the acquisition of Cyntech Corporation⁵ in fiscal 2011. Cyntech provided us with screw piling capabilities, a patented pipeline anchoring system and maintenance capabilities for above-ground storage tanks, while also bringing us international business opportunities.

• In the pipeline sector, the recession led to a scaling back of plans for new pipeline construction and expansion projects. While companies in the late planning stages of specific projects opted to move forward, competition for these projects became intense and was characterized by a high number of bidders willing to assume more risk at lower margins. During fiscal 2010 and fiscal 2011, we secured a number of unit-price contracts, but were unable to achieve reasonable margins or risk levels on this work. We ultimately posted losses, or at best, break-even performance on our pipeline work during this period. While the contracting environment has begun to improve, we have altered our strategy to consider only cost-reimbursable contracts going forward. We are also pursuing stable maintenance pipeline work and are currently providing integrity services to Enbridge under a multi-year master services agreement with a cost-reimbursable structure.

• On a company-wide basis, we have undertaken several strategic initiatives over the past three years to help us respond to changing market conditions and prepare for the future. Our initiatives include strengthening our financial position with a debt refinancing, capital spending reductions, organizational restructuring, cost-reduction initiatives and focused cash management.

Competitive Strengths

We believe our competitive strengths are as follows:

Leading market position

We believe we are the largest provider of contract mining services in the Canadian 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 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.

⁵  We acquired the assets of Cyntech Corporation, a private Alberta-based company and Cyntech Anchor System LLC, its US based subsidiary (collectively “Cyntech Corporation”), as at November 1, 2010. To facilitate the acquisition of Cyntech Corporation’s assets, we established two Canadian subsidiaries: Cyntech Canada Inc.; and Cyntech Services Inc.; and one US subsidiary, Cyntech U.S. Inc. (collectively “Cyntech”).

2012 Annual Information Form 5

Large, well-maintained equipment fleet

As of March 31, 2012, we had a heavy equipment fleet of approximately 900 owned, leased and rented 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 $318.3 million in our fleet including upgrades, new equipment purchases and equipment leases. As a result, we believe we have an unmatched, modern 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 some of 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 with respect to both skill base and equipment availability. The size and diversity of our fleet provides us with the potential 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 three 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 administrative offices 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 maintenance and 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 review of constructability, engineering and budgeting. This leads into the construction phase during which we provide a fuller 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 has enabled 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 Canada 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, where business lead times are short and the work is usually conducted outside of long-term contracts. This serves as a barrier to 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 enables us to continue bidding profitably on new contracts. This has helped us through the recent economic downturn.

Operations Overview

Our business is organized into three operating segments: (i) Heavy Construction and Mining, (ii) Piling and (iii) Pipeline. For a discussion of our operations overview, see the “Operations Overview” section of our annual MD&A, which section is expressly incorporated by reference into this AIF.

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:

• Enhance safety culture: We are committed to elevating the standard of excellence in health, safety and environmental protection with continuous improvement along with greater accountability and compliance.

• Increase our recurring revenue base: It is our intention to expand our recurring services business to provide a larger base of stable revenue.

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

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• 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 kinds of business opportunities. 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, increase our recurring revenues and / or reduce the overall capital intensity of the business.

• Enhance operating efficiencies to improve revenues and margins: We seek to increase the availability and utilization of our equipment through enhanced maintenance and fleet management, providing the opportunity for increased revenue and margins.

• Increase operational flexibility: We intend to structure our business in a way that enables us to adjust to changing market conditions while maintaining our profitability.

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

D. Projects, Competition and Major Suppliers

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 BPD from Phase 1. Canadian Natural has plans to ultimately increase total production capacity to 500,000 barrels per day (“BPD”) through future expansions. Phases 2 and 3 of the mine expansion plan are currently in the planning stages.

We have been working at the Horizon mine since 2005 under a 10-year contract with Canadian Natural to remove approximately 400 million bank cubic meters (“BCM”) of overburden and use 300 million BCM of that material to build a tailings dyke at the site. This work was suspended for approximately seven months in 2011 following a fire at the main processing plant that temporarily shut down mine operations. Our overburden removal operations resumed on January 2, 2012. This contract was amended in March 2012. The 10-year contract was amended in March 2012 and is worth approximately $1.3 billion with approximately $417.8 million in backlog revenue allotted over the remaining life of the contract. For further description of the Canadian Natural contract and amendment, see “Explanatory Notes – Significant Business Event” in our annual MD&A, which section is expressly incorporated by reference into this AIF.

We also perform time-and-materials work for Canadian Natural for its mine operations and projects groups.

The Canadian Natural overburden removal contract expires June 30, 2015.

Shell: Muskeg River and Jackpine Mines

Shell’s operations at the Athabasca Oil Sands Project include the Muskeg River Mine, which has a target production capacity of 155,000 BPD and the Jackpine Mine, which has a target production capacity of 100,000 BPD. Future planned mining expansions, while not imminent, are expected to potentially increase total production capacity to 500,000 BPD.^¿

We signed a three-year earthmoving and mine support master services agreement with Shell which expires March 31, 2013. The agreement covers the provision of recurring services including construction, earthmoving and mine support and replaced an expiring two-year master services agreement. 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.

We signed an additional three-year master services agreement to provide muskeg removal services at Shell’s Jackpine Mine. This is a time-and-materials contract, which expires October 31, 2013 and is in addition to the agreement mentioned above.

Suncor: Steepbank, Millennium and Other Mines

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 their merger with Petro-Canada and a strategic alliance with Total, Suncor’s minable assets have expanded to include a 40.8% interest in the Fort Hills oil sands project and a 36.8% interest in the Total-operated Joslyn North Mine Project.

We are currently in the first year of a five-year master services agreement to provide reclamation, civil construction and mine services at Suncor’s Steepbank and Millennium oil sands mine operations with volumes and rates to be renegotiated after two and a half years to reflect changing market conditions. The Suncor overburden master services agreement expires December 31, 2015 and the Suncor civil works master services agreement expires May 31, 2015.

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

2012 Annual Information Form 7

Syncrude: Base Mine and Aurora Mine

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 planned expansions include the development of a new mine (Aurora South), which is expected to potentially increase total production capacity to 600,000 BPD by 2020.^¿

In November 2010, Imperial Oil Ltd. awarded us a new four-year master services agreement, which 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-price arrangements and are generally not reflected in our reported backlog.

Syncrude: Mildred Lake Mine Relocation

We are currently undertaking construction of a shear key foundation as part of the first phase of a mine relocation project at Syncrude’s Base Mine. We were recently awarded the second phase of this relocation project, which includes construction of a mechanically stabilized earth (MSE) wall. We expect to transition to this second phase as work on the shear key foundation nears completion this summer.^¿

Total E&P Canada⁶: Joslyn North Mine Project

The Joslyn North Mine Project is in the initial construction phase and is not expected to commence production until 2018.^¿

We are currently completing the initial earthworks at the Joslyn North Mine Project, including clearing the site and establishing access (roads, drainage etc.) in preparation for the planned future construction of the mine and extraction facility. This contract was awarded in November 2011 and is expected to be completed in July 2013.^¿

Thompson Creek⁷: Mt Milligan Copper/Gold Project

We are currently completing facilities construction work at the Mt. Milligan Copper/Gold Project in northern British Columbia. The contract covers the erection of more than 7,000 tons of structural steel, as well as the installation of cladding, insulated roofing panels, cranes and lighting for new mill concentrator facilities at the mine. The work is an expansion of NAEPI’s industrial capabilities into above-ground construction and will be carried out by a combination of NAEPI personnel and specialized subcontractors. This contract was awarded in November 2011 and is targeted to be completed by October 2012.^¿

PetroChina⁸ Dover: (Mackay River Central)

In November 2011, we were awarded two separate contracts for the MacKay River SAGD project, located 60 kms northwest of Ft. McMurray, AB. The contract with MacKay Operating Corp⁹ covers the plant site grading and gravel work, as well as construction of the water well road and well pads. Construction began in February 2012 and is scheduled to be completed in Fall 2012.^¿

Enbridge¹⁰: Integrity Dig Program

We are currently providing pipeline testing and maintenance services for Enbridge under a two-year contract. This work is currently being performed on a time-and-materials basis in Manitoba and could possibly extend into Saskatchewan.^¿

Recently Completed Projects

Syncrude: Reclamation

Between January 2012 and March 2012, we completed a winter reclamation project moving 2.6 million BCM of reclamation material at Syncrude’s Base Mine.

Suncor: Reclamation

Between December 2011 and March 2012, we completed a winter reclamation project, moving 3.4 million BCM of material in Suncor’s Millennium Mine.

Shell: Reclamation

Between November 2011 and February 2012, we completed a winter reclamation project, moving 2.5 million BCM of material in Shell’s Jackpine Mine and Muskeg River Mine.

Consumer’s Co-operative Refinery Limited: Tank Farm Project

In July 2009, we were awarded the Consumer’s Co-operative Refinery Limited¹¹ heavy oil upgrader revamp and expansion project in Regina, Saskatchewan. Work continues on this site as we complete 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 also installing piling foundations inside the operating facility and outside of the plant limits in the new expansion areas.

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

⁶  Total E&P Canada Ltd. (Total), a wholly owned subsidiary of Total SA.

⁷  Thompson Creek Metals Company Inc., owner of the Mt. Milligan Copper / Gold project in Central British Columbia.

⁸  PetroChina Dover SAGD project (PetroChina Dover) is owned by PetroChina International Investment Ltd. The project is operated by Dover Operating Corp, a joint venture between Cretaceous Oilsands Holdings Ltd, a wholly owned subsidiary of PetroChina (60%) and Alberta Oil Sands Corp. (AOSC) (40%).

⁹  Mackay Operating Corp is a private company categorized under Oil and Gas Exploration and Development and located in Calgary, AB, Canada.

¹⁰  Enbridge (Enbridge Inc.) is a publicly traded energy transportation and distribution company.

¹¹  Consumers Co-operative Refinery Limited (CCRL) is a wholly owned subsidiary of Federation Co-operatives Limited.

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TransCanada Pipelines¹²: Gordondale, Karr North & Nosehill Creek Project

During fiscal 2012, we completed the installation of 44 kilometers of 42-inch pipeline in Northern Alberta for TransCanada.

TransCanada Pipelines: Cutbank Area Expansion Projects

During fiscal 2012, we completed the installation of ten kilometers of 24-inch pipeline and an additional 16 kilometres of NPS 20-inch pipeline for TransCanada.

Spectra Energy¹³: South Maxhamish Loop Project

During fiscal 2012, we completed the installation of 44 kilometers of 36-inch pipeline in British Columbia.

Competition

We operate businesses in highly competitive service and geographic markets in Canada, the United States and internationally. We compete with other major contractors, as well as many mid-size and smaller companies, across a range of industry segments. In addition, an increase in the number of international companies entering into the Canadian marketplace has also made the market more competitive. 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.

We have seen a change in our competitive environment and customer behavior in the oil sands over the past three years. Several competitors were acquired over the past three years following the economic downturn in 2009. In addition, following the economic downturn, oil sands operators shifted their focus from controlling schedules to controlling costs which has resulted in some of our customers delaying planned mine development to re-engineer mine plans and insourcing mine services activity that would previously have been exclusively outsourced. These cost saving measures by our customers have resulted in a noticeable reduction in tendered mine support services and an increase in competition on oil sands project bids during the year ended March 31, 2012.

Our principal competitors in the Heavy Construction and Mining segment include Klemke Mining Corporation, Aecon Group Inc., Graham Construction Ltd, Ledcor Construction Limited (“Ledcor”), Peter Kiewit and Sons Co. Ltd., Tercon Contractors Ltd., Sureway Construction Ltd. and Thompson Bros. (Constr.) Ltd. In underground utilities installation and mechanical / structural construction (parts of our Heavy Construction and Mining segment), Voice Construction Ltd., Ledcor and IGL Canada, KBR Inc., JV Driver Projects Inc. and PCL Constructors Inc. are our major competitors.

In the private sector, the main competition to our deep foundation piling operations in Western Canada comes from Pacer Industries Inc., Ledcor, Agra Foundations Limited, Bauer Foundations Canada, Graham Construction, Beck Drilling & Environmental Services Ltd, Double Star Drilling and Midwest Caissons Inc. In Eastern Canada our main competitors include Deep Foundations, Anchor Shoring & Caissons Ltd., Birmingham Foundation Solutions and RUMBLE Foundations (Ontario) Ltd. 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 respective 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.

With the acquisition of Cyntech in November 2010, we now compete in the anchor system manufacturing and installation market with from Almita Piling Inc., Hydraulic Power Systems, Inc. and Roterra Screw Piling Ltd., while competition in our tank maintenance and fabrication services comes from Horton CBI Ltd., Matrix Oil Corporation, TIW Canada Ltd. and G.L.M. Industries.

The primary competitors in the pipeline installation business include Ledcor, O.J. Pipelines Canada, Michels Canada (Michels), Louisbeurg Pipelines Inc., Bannister Pipeline Construction Co., Surerus Pipeline Inc. and Robert B. Somerville Co. Limited, while competitors in the pipeline maintenance and integrity business include Ledcor, Michels Canada, Willbros Group, Inc., and Summit Pipeline Services.

Major Suppliers

We have long-term relationships with the following equipment suppliers: Finning International Inc. (over 45 years), Wajax Income Fund (over 20 years), Brandt Tractor Ltd. (over 30 years) and SMS Equipment (over five years). Finning is a major Caterpillar heavy equipment dealer for Canada and Caterpillar equipment makes up the bulk of our fleet. 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. SMS Equipment is a major Komatsu equipment supplier for our large mining trucks. In addition to the supply of new equipment, each of these companies is a major supplier for equipment rentals, parts and service labour. We are also actively working with these suppliers to identify cost savings opportunities, including opportunities to reduce our rental fleet and focus on parts management.

¹²  TransCanada Pipelines Limited (TransCanada).

¹³  Spectra Energy Partners, LP (Spectra Energy).

2012 Annual Information Form 9

Tire contracts with Bridgestone and Goodyear plus allocation from Michelin have allowed us to maintain tire inventories to keep our fleet fully operational. Tire availability has tightened with global shortages occurring in larger sizes and the reselling of tires at prices far greater than new price has resumed in the mining industry. We have increased inventory and with our contracts and allocations as such we do not anticipate a tire shortfall.^¿

E. Resources And Key Trends

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 is secured by liens on substantially all of our equipment. We lease some of this equipment under lease terms that include purchase options.

We acquire our equipment in three ways: capital expenditures, capital leases and operating leases (for a discussion on our equipment additions see the “Summary of Consolidated Equipment Additions”, section of our annual MD&A) The following table sets forth our owned and leased heavy equipment fleet (does not include rental equipment) as at March 31, 2012:

Category	Capacity Range	Horsepower Range		Number Owned		Number Leased
Heavy Construction and Mining:
Articulating trucks	30 to 40 tons		305 - 406		20		10
Mining trucks	40 to 330 tons		476 - 2,700		108		65
Shovels	35 - 80 cubic yards		2,600 - 3,760		3		2
Excavators	1 to 29 cubic yards		90 - 1,944		82		27
Dozers	20,741 lbs to 230,100 lbs		96 - 850		75		44
Graders	14 to 24 feet		150 - 500		19		9
Loaders	1.5 to 16 cubic yards		110 - 690		91		3
Packers	14,175 to 68,796 lbs		216 - 315		7		–
Articulating Water Trucks	8,000 gallon		406		3		–
Scraper Water Wagons	10,000 gallon		462		2		–
Float Trucks	250 tons		703		4		–
Heavy Oil Recovery Barge	30,000 US gal per hour		125		9		–
Tractors	43,000 lbs		460		3		–
Pipeline:
Trenchers	60,000 lbs		165		2		–
Pipe layers	20,000 to 202,000 lbs		78 - 265		36		–
Piling:
Drill rigs	Up to 267 feet (drill depth)		210 - 1,500		55		8
Cranes	25 to 150 tons		200 - 263		24		–
Total					543		168

For the fiscal years ended March 31, 2012, 2011 and 2010 we incurred expenses of $220.7 million, $234.9 million and $209.4 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 some of 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 three 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 position, while concurrently increasing our equipment utilization and thereby improving our profitability.

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

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Facilities

We own and lease a number of buildings and properties for use in our business, the locations of which were chosen for their geographic proximity to our major customers. Our corporate offices are located in Calgary, Alberta. Our primary administrative functions are carried out from offices in Edmonton, Alberta and Acheson, Alberta, where we also have a major equipment maintenance facility. Additional project management and equipment maintenance functions are carried out from leased and owned regional facilities in Calgary and Fort McMurray, Alberta; New Westminster, British Columbia; Regina and Martensville, Saskatchewan; and Milton, Ontario. The operations of our U.S. subsidiary, Cyntech U.S. Inc., are carried out in Plantersville, Texas. 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)	Corporate head office	Leased	1/31/2022
Calgary, Alberta (Piling Office)	Regional office for piling operations and major equipment repair facility	Leased	9/30/2020
Calgary, Alberta (Cyntech Office)	Regional office for piling operations and manufacturing facility	Leased	10/31/2013
Edmonton, Alberta (Mayfield)	Administrative and operations support office	Leased	3/31/2017
Edmonton, Alberta (Stone)	Administrative office and regional office for piling operations	Leased	2/28/2013
Fort McMurray, Alberta (Timberlea)	Regional office for mining operations	Leased	2/28/2022
Fort McMurray, Alberta (Canadian Natural site)	Site office and maintenance facility	Building and land provided	Term of Canadian Natural contract (6/30/2015)
Fort McMurray, Alberta (Shell Canada Muskeg River Mine site)	Site office and maintenance facility	Building leased, land provided	Term of Shell MSA contract (10/31/2013)
Fort McMurray, Alberta (Syncrude Ruth Lake site)	Regional office and maintenance facility for all operations	Building owned, land provided	8/31/2021
New Westminster, BC	Regional office and equipment repair facility for piling operations	Leased	12/31/2014
New Westminster, BC (Water Rights)	Water rights adjacent to piling office premises	Leased	3/31/2015
Martensville, Saskatchewan	Regional office and equipment repair facility for piling operations	Leased	4/30/2013
Regina, Saskatchewan	Regional office and equipment repair facility for piling operations	Leased	3/14/2013
Milton, Ontario (Drillco)	Regional office and equipment repair facility for piling operations	Owned	N/A
Plantersville, Texas (Cyntech US)	Regional office for piling operations and manufacturing facility	Leased	10/31/2013

2012 Annual Information Form 11

Credit Facilities

For a description of our credit facilities, see the “Credit Facilities” section of our annual MD&A, which section is expressly incorporated by reference into this AIF.

Variability of Results

A number of factors have the potential to contribute to variations in our quarterly financial results between periods, including:

• the timing and size of capital projects undertaken by our customers on large oil sands projects;

• seasonal weather and ground conditions;

• 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.

For a description of our variability of results, see the “Summary of Quarterly Results” section of our annual MD&A, which section is expressly incorporated by reference into this AIF.

F. 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:

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

• building and similar codes and zoning ordinances;

• laws and regulations relating to consumer protection; and

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

We believe 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. 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, administer these laws and regulations. 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 in relation to 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 that 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 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, 2010, 2011 and 2012 were not material. We do not currently anticipate any material adverse effect on our business or financial position because 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.

12 2012 Annual Information Form

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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 or know to be contemplated could reasonably be or could likely be considered important to a reasonable investor in making an investment decision, 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 that could have such a material adverse effect.^¿

Employees and Labour Relations

As of March 31, 2012, we had 743 salaried employees and approximately 2,270 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 3,500 employees depending on the time of year and duration of awarded projects. We also utilize the services of subcontractors in our construction business. Subcontractors perform an estimated 8% to 10% of the construction work we undertake. As of March 31, 2012, approximately 2,050 employees are members of various unions and work under collective bargaining agreements.

The majority of our work is carried out by employees governed by our mining overburden collective bargaining agreement with the International Union of Operating Engineers (IUOE) Local 955, the primary term of which expires on March 31, 2015. 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, 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. The provincial collective agreement between the IUOE Local 955 and the Alberta Roadbuilders and Heavy Construction Association (ARBHCA) expires February 28, 2013.

We believe that our relationships with all our employees, both union and non-union, are strong. We have not experienced a strike or lockout.

G. Description of Securities, Rights Plans and Agreements

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 windingup. A copy of our articles of amalgamation can be found on www.sedar.com.

Capital Structure

We are authorized under our articles of amalgamation to issue an unlimited number of Voting Common Shares and an unlimited number of Non-Voting Common Shares. As at March 31, 2012, there were 36,251,006 voting Common Shares outstanding. We had no Non-Voting Common Shares outstanding as at March 31, 2012.

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.

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.

Non-Voting Common Shares

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.

Options

Other than the exercise of options under the stock option plan, there have been no issuances of shares.

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 Series 1 Debentures (as defined herein).^¿

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

2012 Annual Information Form 13

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 (“TSX”) (in Canadian dollars) and on the New York Stock Exchange (“NYSE”) (in US dollars) on a monthly basis from April 1, 2011 to May 31, 2012:

Toronto Stock Exchange
Date	High ($)		Low ($)		Volume
May 2012		4.00		2.31		435,648
April 2012		5.03		3.85		143,510
March 2012		6.19		4.38		305,460
February 2012		6.42		5.05		492,558
January 2012		6.99		6.27		306,744
December 2011		7.18		5.30		257,455
November 2011		8.10		6.28		112,988
October 2011		7.21		5.00		112,801
September 2011		6.49		5.25		389,323
August 2011		6.32		4.74		460,128
July 2011		7.49		5.75		308,685
June 2011		9.30		6.80		614,777
May 2011		11.06		6.89		752,857
April 2011		12.05		9.89		231,050
New York Stock Exchange
Date	High ($)		Low ($)		Volume
May 2012		4.06		2.23		2,314,440
April 2012		4.98		3.86		1,755,320
March 2012		6.03		4.40		2,632,786
February 2012		6.47		5.06		2,362,775
January 2012		6.92		6.24		1,576,720
December 2011		7.05		5.10		2,412,652
November 2011		8.03		6.09		1,980,394
October 2011		7.27		4.70		1,920,929
September 2011		6.36		5.09		4,372,029
August 2011		6.55		4.75		7,610,196
July 2011		7.82		5.95		6,072,520
June 2011		9.50		6.87		10,932,599
May 2011		11.64		7.15		12,381,080
April 2011		12.51		10.25		5,536,502

Shareholder Rights Plan

On October 7, 2011, our Board of Directors adopted a Shareholder Rights Plan Agreement, dated October 7, 2011 (the “Rights Plan”) designed to encourage the fair and equal treatment of shareholders in connection with any takeover bid for our outstanding Common Shares. The Rights Plan was included as an exhibit to our Form 8-A, filed with the Securities and Exchange Commission on October 7, 2011. The Rights Plan terminated in accordance with its terms on April 7, 2012.

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 (“Securities Act 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 1933, referred to as a “demand registration,” so long as the amount of common shares to be registered has an aggregate fair market value of at least US$5.0 million and, at such time, the SEC has ordered or declared effective fewer than four demand registrations initiated by us pursuant to the registration rights agreement. If the aggregate number of common shares that 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.

14 2012 Annual Information Form

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

• up to 120 days following a request for a demand registration if:

• we have decided to file a registration statement for an underwritten public offering of our common shares, from which we expect to receive net proceeds of at least US$20.0 million; or

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

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

Our right to delay the filing of a registration statement if we possess information that we deem advisable not to disclose does not obviate any disclosure obligations which we may have under The Securities Exchange Act of 1934 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 covenant to indemnify and 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 1933. 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.

9.125% Series 1 Debentures

On April 7, 2010, we closed a private placement of 9.125% Series 1 Debentures (as defined below) due 2017 (the “Series 1 Debentures”) for gross proceeds of $225.0 million and net proceeds after commissions and related expenses of $218.1 million as part of a debt restructuring plan. Financing fees of $6.9 million were incurred in connection with the Series 1 Debentures and were recorded as deferred financing costs. A more detailed discussion on the debt restructuring can be found in the “Long-term debt restructuring” section of our annual MD&A.

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 Series 1 Debentures, with the net cash proceeds of one or more of our public equity offerings (as defined in the trust indenture that governs the Series 1 Debentures) 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 Series 1 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 Series 1 Debentures, in whole or in part, at a redemption price which is equal to the greater of:

i. the Canada Yield Price (as defined in the trust indenture that governs the Series 1 Debenture); and

ii. 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 Series 1 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 Series 1 Debentures are also subject to covenants limiting our ability and the ability of most or all of its subsidiaries: to incur additional debt; pay dividends or distributions on our common shares or repurchase our common shares; make various investments; create liens on our assets to secure debt; enter into transactions with affiliates; consolidate, merge or transfer all or substantially all of our property and assets and the property and assets of our subsidiaries on a consolidated basis; transfer and sell assets; and enter into sale and leaseback transactions. These covenants are subject to exceptions and qualifications that are detailed in the indenture governing the Series 1 Debentures.

2012 Annual Information Form 15

We are also required to meet a financial covenant with respect to our Series 1 Debentures that restricts the amount of additional debt that we and our subsidiaries can incur. Specifically, on a pro forma basis taking such additional debt into account, on a consolidated basis our “Consolidated Fixed Charge Coverage Ratio” must be greater than 2.0 to 1.0. The “Consolidated Fixed Charge Coverage Ratio” is approximately the same calculation as the “Interest Coverage” covenant found in our Credit Facility.

The Series 1 Debentures were rated B- by Standard & Poor’s and Caa1 by Moody’s (see “Debt Ratings”).

Debt Ratings

For a discussion of our debt ratings, see the “Debt Ratings” section of our annual MD&A, which section is expressly incorporated by reference in this AIF.

H. Material Contracts

We are party to the following material contracts, which are contracts other than those entered into in the ordinary course of our business, as the same have been amended from time to time:

• 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;

• 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 Certain Indebtedness – 9.125% Series 1 Debentures” for details;

• 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;

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

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

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

• Overburden Removal and Mining Services Contract, dated November 17, 2004, between Canadian Natural Resources Ltd. and Noramac Ventures Inc., with the latter’s interest having been assigned to North American Construction Group Inc. by an Assignment Agreement dated February 27, 2006, all as amended by an Amending Agreement dated March 19, 2012. Please see “Projects – Active Projects – Canadian Natural: Overburden Removal Project;

• 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

• 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 thereto from time to time, as amended by that First Amending Agreement dated June 8, 2011, that Second Amending Agreement dated September 30, 2011, and that Third Amending Agreement dated March 27, 2012. Please refer to “Liquidity – Credit facilities” in our annual MD&A for details.

I. Directors and Officers

Director and Officer Information

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 at May 31, 2012, the directors and executive officers of the Company, as a group, beneficially owned, directly or indirectly, or exercised control or direction over 800,405 common shares of the Company (representing approximately 2.2% of all issued and outstanding common shares).

16 2012 Annual Information Form

NOA

The following table sets forth information about our directors and executive officers. Ages reflected are as at May 31, 2012.

Name and Municipality of Residence	Age		Position	Director Since
Rodney J. Ruston *		61	President & Chief Executive Officer	June 15, 2005
Calgary, Alberta, Canada
David Blackley		51	Chief Financial Officer
Calgary, Alberta, Canada
Joseph C. Lambert		47	Vice-President, Operations Support
Calgary, Alberta, Canada
Bernard T. Robert		45	Vice-President, Corporate
Calgary, Alberta, Canada
Christopher R. Yellowega		41	Vice-President, Construction
Airdrie, Alberta, Canada
Barry W. Palmer		51	Vice-President, Oil Sands Operations
Morinville, Alberta, Canada
Ronald A. McIntosh		70	Chairman of the Board	May 20, 2004
Calgary, Alberta, Canada
George R. Brokaw		44	Director	June 28, 2006
New York, NY, United States
John A. Brussa		55	Director	November 26, 2003
Calgary, Alberta, Canada
Peter R. Dodd		62	Director	June 11, 2009 (Retired)
Sydney, Australia
Carl Giesler Jr.		40	Director	April 24, 2012
Houston, Texas United States
John D. Hawkins		48	Director	October 17, 2003
Houston, Texas, United States
William C. Oehmig		62	Director	May 20, 2004
Houston, Texas, United States
Allen R. Sello		72	Director	January 26, 2006
West Vancouver, British Columbia, Canada
Peter W. Tomsett		54	Director	September 19, 2006
West Vancouver, British Columbia, Canada
K. Rick Turner Houston, Texas, United States		54	Director	November 26, 2003

* Effective June 7, 2012, Martin Ferron will join the Company as President and Chief Executive Officer and a Director of the Board. Mr. Ferron will be succeeding Rodney J. Ruston who is retiring from the Company and the Board. Mr. Ferron's previous experience includes serving as Director, President and Chief Executive Officer of Helix Energy Solutions Inc., an international energy services company. Prior to joining Helix, Mr. Ferron worked in successively more senior management positions with oil services and construction companies including McDermott Marine Construction, Oceaneering International and Comex Group.

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.

Joseph C. Lambert joined us in 2008 as General Manager of Mining after an extensive career in the mining industry. Joe was promoted to Vice President, Oil Sands Operations in September of 2010 and accepted the position of VP Operations Support in January 2012. Prior to that, Joe's career began in the gold industry where he spent 17 years in roles of increasing responsibility in engineering and operations both open pit and underground. Joe's more recent contracting and oil sands experience included positions as General Manager with Ledcor and Mine Development Manager, Oil Sands with Shell. Joe graduated from the South Dakota School of Mines and Technology with a B.S. in Mining Engineering in 1986.

2012 Annual Information Form 17

Barry W. Palmer joined NACG in 1982 as a Heavy Equipment Operator. Since then Barry has advanced through the company holding positions of Operations Foreman, General Foreman, Superintendent, Project Manager, Operations Manager and General Manager of HC&M prior to being promoted into his current role of Vice President, Oil Sands Operations in December of 2011. Over the course of his 34 years within the construction industry Barry has worked in aggregate, road building, civil and heavy construction and mining. Before joining NACG, Barry worked for PCL and Steels of Canada

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 Partner 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 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 Petroleum Ltd. 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 a director of NAEPI on April 24, 2012. Mr. 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.

Carl F. Giesler, Jr. became a Director on April 24, 2012. Mr. Giesler is Managing Director of Investments at Harbinger Group Inc. (“HGI”) and previously served as Vice President and Director of Investments at Harbinger Capital Partners LLC (“Harbinger Capital”), an affiliate of HGI. Prior to joining Harbinger Capital in 2008, Mr. Giesler was a Managing Director at AIG Financial Products Corp. (“AIG FP”), where he held a leadership role in pursuing principal investment opportunities in the oil and gas sector. Prior to joining AIG FP, he worked as an investment banker in Morgan Stanley’s Global Energy Group. Mr. Giesler is a CFA charter holder and a graduate of Harvard Law School and the University of Virginia.

John D. Hawkins became one of our Directors on October 17, 2003. Mr. Hawkins joined The Sterling Group, L.P., a private equity investment firm, in 1992 and has been a Partner since 1999. An affiliate of The Sterling Group is a holder of our common shares. (See our most recent information circular that involved the elections of directors for details.) Mr. Hawkins currently serves as chairman of the board of Saxco Holdings International and serves on the board of directors of Liqui-Box Corporation, Velcon Filters and B&G Crane. 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 Vanderbilt University.

18 2012 Annual Information Form

NOA

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. In 1984, Mr. Oehmig became a Partner with The Sterling Group, a private equity investment firm in Houston, Texas. The Sterling Group L.P., 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). Mr. Oehmig has announced that as of July 1, 2012, he will become an Advisor to the Sterling Group. 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 RoysterClark, 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 and Chaired 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 director of Sterling Shoes Inc., former director of software development companies Infowave Software Inc. and Braintech Inc., and former Chair of the Vancouver Board of Trade Government Budget and Finance Committee. Mr. Sello received his Bachelor of Commerce from the University of Manitoba and his Masters of Business Administration from the University of Toronto.

Peter W. Tomsett became one of our Directors 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 Chairman of Silver Standard Resources Inc., and a director of Talisman Energy Inc.

K. Rick Turner became one of our Directors on November 26, 2003. Mr. Turner, 54, recently retired from the Stephens’ family entities. Prior to his retirement, Mr. Turner was a private equity principal of the Stephens Group, LLC, a private, family-owned investment firm, since 1990. Mr. Turner is currently active with several private equity groups, most particularly, Maxim Partners, LLC. Mr. Turner has extensive experience investing in companies focused on oil and gas exploration, energy services, natural gas gathering and processing, and power technology. Prior to joining Stephens in 1983, he was employed by Peat, Marwick, Mitchell and Company. Mr. Turner currently serves as a board member for several private companies and two other publicly held companies: Energy Transfer Equity, L.P., and AmeriGas Propane Inc., general partner of AmeriGas Partners, L.P. He formerly served on the board of Energy Transfer Partners, L.P. for over 10 years. Mr. Turner earned his B.S.B.A. from the University of Arkansas and is a non-practicing Certified Public Accountant.

Corporate Cease Trade Orders, Bankruptcies, Penalties or Sanctions

Ronald A. McIntosh is a director of Fortress Energy Inc. (“Fortress”). On March 2, 2011, the Court of Queen’s Bench of Alberta granted an order (the “Order”) under the Companies’ Creditors Arrangement Act (Canada) (“CCAA”) staying all claims and actions against Fortress and its assets and allowing Fortress to prepare a plan of arrangement for its creditors if necessary. Fortress took such step in order to enable Fortress to challenge a reassessment issued by the Canada Revenue Agency (“CRA”). As a result of the reassessment, if Fortress had not taken any action, it would have been compelled to immediately remit one half of the reassessment to the CRA and Fortress did not have the necessary liquid funds to remit, although Fortress had assets in excess of its liabilities with sufficient liquid assets to pay all other liabilities and trade payables. Fortress believed that the CRA’s position was not sustainable and vigorously disputed the CRA’s claim. Fortress filed a Notice of Objection to the reassessment and on October 20, 2011 announced that its Notice of Objection was successful, CRA having confirmed there were no taxes payable. As the CRA claim had been vacated and no taxes or penalties were owing Fortress no longer required the protection of the Order under the CCAA and on October 28,2011 the Order was removed. On March 3, 2011 the TSX suspended trading in the securities of Fortress due to Fortress having been granted a stay under the CCAA. In addition the securities regulatory authorities in Alberta, Ontario and Quebec issued a cease trade order with respect to Fortress for failure to file its annual financial statements for the year ended December 31, 2010 by March 31, 2011. The delay in filing was due to Fortress being granted the CCAA order on March 2, 2011 and the resulting additional time required by its auditors to deliver their audit opinion. The required financial statements and other continuous disclosure documents were filed on April 29, 2011 and the cease trade order was subsequently removed. On September 1, 2010 Fortress closed the sale of substantially all of its oil and gas assets. As a result of the sale Fortress was delisted from the TSX on March 30, 2011 as it no longer met minimum listing requirements.

2012 Annual Information Form 19

William C. Oehmig served as a director of Propex Inc., which voluntarily filed for protection under Chapter 11 of the U.S. Bankruptcy Code on January 18, 2008 in order to allow it to restructure its US operations. Mr. Oehmig also served as director of Panolam Industries Inc., which voluntarily filed a petition under Chapter 11 of the U.S. Bankruptcy Code on November 4, 2009 to implement a Debt Restructuring Plan.

Allen R. Sello is a director of Sterling Shoes Inc. (“Sterling”). On October 21, 2011 the TSX suspended trading in the securities of Sterling having been granted a stay under the Companies’ Creditors Arrangement Act (Canada) in order to restructure its operations. Sterling securities were delisted on November 25, 2011.

Interest of Management and Others in Material Transactions

Other than as disclosed in the “Related Parties” section of our annual MD&A, which section is expressly incorporated by reference into this AIF, there are no interests of management or others in material transactions.

J. 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 year ended March 31, 2012. The fees we have paid to KPMG for services rendered by them include:

• Audit Fees – KPMG billed us $1,139,900, $1,130,800 and $1,862,800 for audit fees during the years ended March 31, 2012, 2011 and 2010, 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.

• Audit Related Fees – KPMG billed us $nil, $nil and $394,645 during the years ended March 31, 2012, 2011 and 2010, respectively, for professional services related to the conversion of US GAAP and for planning and scoping work and advice relating to internal controls over financial reporting.

• Tax Fees – KPMG billed us for $nil, $nil and $7,500 for the years ended March 31, 2012, 2011 and 2010, respectively, for income tax advisory and compliance services.

Compensation Committee

The Compensation Committee is responsible 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 at www.nacg.ca. The Compensation Committee is currently comprised of 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 comprised 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 comprised of Messrs. Brokaw, McIntosh, Oehmig and Tomsett, with Mr. Oehmig serving as Chairman.

K. Forward-looking Information, Assumptions 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, uncertainties, assumptions 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 including those listed in the “Forward-Looking Information, Assumptions and Risk Factors” section of our annual MD&A, which section is expressly incorporated by reference into this AIF. 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 that may prove to be incorrect:

1. Future planned mining expansions, while not imminent, are expected to potentially increase total production capacity to 500,000 BPD.

2. Future planned expansions of Syncrude’s operations include the development of a new mine (Aurora South), which is expected to potentially increase total production capacity of 600,000 BPD.

3. Our expectation to transition to the second phase of a mine relocation project at Syncrude’s Base Mine as work on the shear key foundation nears completion this summer.

4. The Joslyn Mine Project is not expected to commence production until 2018.

5. The earthworks contract for the Joslyn North Mine Project is expected to be completed over a period of about 12 months.

6. The Mt. Milligan Copper/Gold Project contract is targeted to be completed by October 2012.

7. The construction for the contract with MacKay Operating Corp. is scheduled to be completed in Fall 2012.

8. The work under the Enbridge contract could possibly extend into Saskatchewan.

9. We do not currently anticipate any material adverse effect on our business or financial position because of future compliance with applicable environmental laws and regulations; and future events such as changes in existing laws and regulations may require us to make additional expenditures which may or may not be material.

10. We believe that, taking into account reserves and insurance coverage, none of the litigation or legal proceedings in which we are currently involved or know to be contemplated could reasonably be expected to have a material adverse effect on our business, financial condition or results of operations or could likely be considered important to a reasonable investor in making an investment decision; however, we may become involved in material legal proceedings in the future that could have such a material adverse effect.

11. We do not anticipate a tire shortfall.

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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 or the forward-looking information and related risks, assumptions or other information expressly incorporated by reference into this AIF, except as required by applicable securities laws. Such 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 assumptions and factors that could affect us. See “Assumptions” and “Business 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 MD&A.

Assumptions

In addition to those listed in the “Forward-Looking Information, Assumptions and Risk Factors” section of our annual MD&A, the material factors or assumptions used to develop the above forward-looking statements include, but are not limited to:

1. The work on the shear key foundations will near completion this summer.

2. Our tire contracts, allocations and inventory will meet our tire supply needs.

Business Risk Factors

The risks and uncertainties that could cause actual results to differ materially from the information presented in the above forward-looking statements and assumptions include, but are not limited to the risks detailed below.

• Short-notice customer communication of reduction in their mine development or support service requirements, in which we are participating, could lead to our inability to secure replacement work for our dormant equipment and could subject us to non-recoverable costs.

We allocate and mobilize our equipment and hire personnel based on estimated equipment and service plans supplied by our customers. At the start of each new project, we incur significant start-up costs related to the mobilization and maintenance configuration of our heavy equipment along with personnel hiring, orientation, training and housing costs for staff ramp-ups and redeployments. We expect to recover these start-up costs over the planned volumes of the projects we are awarded. Significant reductions in our customer’s required equipment and service needs, with short notice, could result in our inability to redeploy our equipment and personnel in a cost effective manner. Our ability to maintain revenues and margins may be adversely affected to the extent these events cause reductions in the utilization of equipment and we can no longer recover our start-up costs over the reduced volume plan of our customers.

• 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 credit agreement provides for the issuance of letters of credit up to the undrawn balance of our Revolving Facility and at March 31, 2012, we had $15.0 million of issued letters of credit outstanding. One of our major contracts allows the customer to require up to $15.0 million in letters of credit, although at March 31, 2012 there are zero letters of credit issued to this customer. If our capacity to issue letters of credit under our Revolving Facility and our cash on hand is insufficient to satisfy our customer’s requirements, our business and results of operations could be adversely affected.

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

Approximately, 68%, 63% and 39% of our revenue for the fiscal years ended March 31, 2012, 2011 and 2010, 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 including those that are beyond our control. Factors that may contribute to actual costs exceeding estimated costs and which therefore affect profitability include, without limitation:

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

• scope modifications during the execution of the project;

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• the availability and cost of skilled workers;

• the availability and proximity of materials;

• unfavourable weather conditions hindering productivity;

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

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

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

When we are unable to accurately estimate and adjust for 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 affect our results of operations, financial condition and cash flow.

• 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 67%, 78% and 88% of our revenues in each of the years ended March 31, 2012, 2011 and 2010, 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 if they believe they can perform this work in a more cost effective and efficient manner using their internal resources.

• 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 on 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 adversely affected to the extent these events cause reductions in the utilization of equipment.

• An unfavourable resolution to our significant project claims could result in a revenue write down in future periods.

Included in our revenues is a total of $23.4 million relating to disputed claims or unapproved change orders ($21.2 million of which is in respect of the Pipeline segment). Although we believe that we are entitled to such revenue and that we will collect such revenue, if we are not able to resolve these claims and undertake legal action in respect of these claims, there is no guarantee that a court will rule in our favour.

There is also the possibility that we could choose to accept less than the full amount of a claim as a settlement to avoid legal action. In either such case, a resolution or settlement of the claims in an amount less than the amount recognized as claims revenue could lead to a future write down of revenue and profit.

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

Because our operations are located across Canada, including Northern British Columbia, Northern Alberta (Fort McMurray), Nunavut and Ontario, we are subject to extreme weather conditions. While our operations are not significantly affected by normal seasonal weather patterns, extreme weather conditions, including heavy rain, snow, spring thaw, flooding, forest fires or dry forest fire conditions can cause delays in our project work, which could adversely affect our results of operations. Additionally, as we perform work in environmentally sensitive nature reserve areas we may be subject to seasonal reductions of our operating hours related to fish or wildlife restrictions set by the Government of Canada’s Environment Canada or Fisheries and Oceans Canada departments.

• Our ability to maintain planned project margins on projects with longer-term contracts with fixed or indexed price escalators may be hampered by the price escalators not accurately reflecting increases in our costs over the life of the contract.

Our ability to maintain planned project margins on longer-term contracts with contracted price escalators is dependent on the contracted price escalators accurately reflecting increases in our costs. If the contracted price escalators do not reflect actual increases in our costs, we will experience reduced project margins over the remaining life of these longer-term contracts.

In strong economic times, the cost of labour, equipment, materials and sub-contractors is driven by the market demand for these project inputs. The level of increased demand for project inputs may not have been foreseen at the inception of the longer-term contracts with fixed or indexed price escalators resulting in reduced margins over the remaining life of the longer-term contracts. Certain of these price escalators could be considered derivative financial instruments (see “Significant Accounting Policies – Derivative Financial Instruments” in our audited consolidated financial statements for the year ended March 31, 2012).

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• Our customer base is concentrated, and the loss of or a significant reduction in business from a major customer could adversely affect 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 67%, 77% and 89% of our total revenue for the fiscal years ended March 31, 2012, 2011 and 2010, respectively, and those customers are expected to continue to account for a significant percentage of our revenues in the future. In addition, the majority of our Pipeline revenues in previous fiscal years resulted from work performed for one customer. If we lose or experience a significant reduction of business or profit from one or more of our significant customers, we may not be able to replace the lost work or income with work or income from other customers. Our long-term contracts typically allow our customers to unilaterally reduce or eliminate the work that 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 of 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.

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

More than 48% of our revenue for the year ended March 31, 2012 was derived from projects that 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. There is no guarantee that the Company will find additional sources for generating non-recurring services revenue in fiscal 2012.

• 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:

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

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

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

• lack of sufficient governmental infrastructure funding to support growth;

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

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

• cost overruns on announced projects.

• 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.

• 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. 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.

• We may not be able to access sufficient funds to finance a growth in our working capital or equipment requirements.

We have a substantial amount of debt outstanding and significant debt service requirements. As of March 31, 2012, we had outstanding $547.9 million of debt¹⁴, including $10.7 million of capital leases. Our substantial indebtedness restricts our flexibility, consequently it:

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

¹⁴ Debt includes all liabilities with the exception of deferred income taxes.

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

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

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

• increases our vulnerability to, and reduces our flexibility in planning for, adverse changes in economic, industry and competitive conditions; and

• increases 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.

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.

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

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

Approximately 80% of the major projects that we pursue are awarded to us based on bid proposals, and projects are typically awarded based in large part on price. We often compete for these projects against companies that have substantially greater financial and other resources than we do and therefore can better bear the risk of underpricing projects. We also compete against smaller competitors that may have lower overhead cost structures and 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 adversely affect our business and results of operations.

• 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.

Significant economic growth can result in a shortage of skilled labour and other qualified personnel. New mining projects in the area could make it more difficult for us and our customers to find and hire all the employees needed to work on these projects. If the economy experiences significant 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.

• 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. In the second half of 2009, the market price of oil decreased significantly which led to a slowdown of the world economy and a lower international demand for oil. As a result of those developments, many of our customers decided to temporarily scale back their capital development plans on oil sands projects until there was a clearer picture on the timing of the recovery of the world economy. Recent events related to the increases in the market price of oil and assertions by many of our customers about renewed confidence in the long-term growth in the oil sands has led to new announcements regarding oil sands capital investment. If there had not been signs of recovery of the world economy there would have been continuing delays, reductions or cancellations of major oil sands projects that 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 that 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, affecting their returns. If cost overruns continue to challenge our customers, they could reassess future projects and expansions that could adversely affect the amount of work we receive from our customers.

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• Because most of our customers are Canadian energy companies, a downturn in the Canadian energy industry or a global reduction in the demand for oil and related commodities 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 has previously led our customers to slow down or curtail their future capital expansions that, in turn, reduced our revenue from those customers on their capital projects. Another economic downturn in the Canadian energy industry or a global reduction in the demand for oil 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.

• 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 affecting demand for our services.

• 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.

• 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 affected by a wide array of regulations in the jurisdictions where they operate, including regulations directly impacting mining activities and 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 industry, including the mining industry, 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 affecting the energy industry.

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

Our operations are subject to numerous environmental protection laws and regulations that are complex and stringent. We regularly perform work in and around sensitive environmental areas such as rivers, lakes and forests. Significant fines and penalties may be imposed on us or our customers for 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.

• 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 governmental 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”) 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.

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• 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.

• 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 allow us to make required payments on our indebtedness.

• 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 credit agreement and the trust indenture governing our Series 1 Debentures limits, among other things, our ability and the ability of our subsidiaries to:

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

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

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

• issue equity securities of subsidiaries;

• make certain investments or acquisitions;

• create liens on our assets;

• enter into transactions with affiliates;

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

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

Our credit agreement also requires us, and our future credit agreements may require us, to maintain specified financial ratios and satisfy specified financial tests. 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 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 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.

2012 Annual Information Form 27

• Aboriginal peoples may make claims against our customers or their projects regarding the lands on which customer 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 could have an adverse effect on our customers that may, in turn, negatively affect our business.

• 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.

Risks Factors Related to Our Common Shares

• 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:

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

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

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

• reaction to our public announcements;

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

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

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

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

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

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

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

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

• 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.

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• 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 approximately 45% 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 – Advisory 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.

• 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.

• We currently do not intend to-pay 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 to us and Canadian law.

We have never paid cash dividends on our common shares. 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 Securities, Rights Plan and Agreements - Dividends”.

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.

• 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 for investors to effect service of process within the United States upon those persons. Furthermore, it may not be possible for you to enforce against us or them, in or outside the United States, judgments obtained in 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.

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Risk Factors Relating to Debt Securities

• Unsecured nature of the Series 1 Debentures

Our Series 1 Debentures are direct unsecured obligations of the Company ranking equally and pari passu with all other unsecured and unsubordinated indebtedness of the Company. Our Series 1 Debentures are effectively subordinated to all existing and future secured debt of the Company, to the extent of the assets securing such debt. If the Company is involved in any bankruptcy, dissolution, liquidation, reorganization or other insolvency proceeding, the secured debt holders would be paid before the holders of Series 1 Debentures receive any amounts due under the terms of the trust indenture governing such Series 1 Debentures (the “Debenture Indenture”) to the extent of the assets securing the secured debt. In that event, a holder of our Series 1 Debentures may not be able to recover any principal or interest due to it under the terms of the Debenture Indenture.

• Unsecured nature of obligations under guarantees

Our Series 1 Debentures are guaranteed. The obligations under the guarantees are direct unsecured obligations of each of the guarantors ranking equally and pari passu with all other unsecured and unsubordinated indebtedness of the guarantors. The obligations under such guarantees will be effectively subordinated to all existing and future secured debt of the guarantors, to the extent of the assets securing such debt. If the applicable guarantor is involved in any bankruptcy, dissolution, liquidation, reorganization or other insolvency proceeding when the Guarantee is called upon, the secured debt holders would be paid before the holders of any of our Series 1 Debentures receive any amounts due under the Debenture Indenture, pursuant to the guarantee, to the extent of the assets securing the secured debt. In that event, a holder of such Series 1 Debentures may not be able to recover any principal or interest due to it under the Debenture Indenture, pursuant to the guarantee.

• Lack of liquidity

There is no public market for our Series 1 Debentures. The market price and value of our Series 1 Debentures may be affected by changes in general market conditions, fluctuations in the market for equity and debt securities, prevailing interest rates and numerous other factors beyond the Company’s control.

• Credit risk

The likelihood that purchasers of our Series 1 Debentures will receive payments owing to them under the terms of the Debenture Indenture will depend on the financial health of NAEPI and its creditworthiness.

• Restrictions on our ability to incur debt

The terms of our Series 1 Debentures and our credit facility contain restrictions on our ability to raise capital through issuing or incurring additional debt. Failure to raise capital when required could have a material adverse effect on our business, financial condition and results of operations.

• Change of control

NAEPI may be required to repurchase all of our outstanding Series 1 Debentures upon the occurrence of a change of control. If a change of control were to occur, NAEPI may lack sufficient funds to pay the purchase price for all tendered Series 1 Debentures. NAEPI’s failure to purchase tendered debentures would constitute an event of default under the Debenture Indenture, which, without consent, might constitute a default under the terms of NAEPI’s other indebtedness.

• Credit ratings may not reflect all risks of an investment in debt securities and may change

Credit ratings may not reflect all risks associated with an investment in our Series 1 Debentures. The credit ratings applied to our Series 1 Debentures will be an assessment by the relevant ratings agency of NAEPI’s ability to pay its obligations as of the respective dates the ratings are assigned. Consequently, real or anticipated changes in the credit ratings will generally affect the market value of our Series 1 Debentures. The credit ratings, however, may not reflect the potential impact of risks related to structure, market or other factors discussed herein on the value of our Series 1 Debentures. Credit ratings are intended to provide investors with an independent measure of the credit quality of an issue of securities. The credit ratings accorded to our Series 1 Debentures are not a recommendation to purchase, hold or sell our Series 1 Debentures, because ratings do not comment as to market price or suitability for a particular investor. There is no assurance that the ratings accorded to our Series 1 Debentures will remain in effect for any given period of time or that the ratings will not be revised or withdrawn entirely in the future by the relevant rating agency. Real or anticipated changes in credit ratings on our Series 1 Debentures may affect the market value of our Series 1 Debentures. In addition, real or anticipated changes in credit ratings can affect the cost of or terms on which the Company can issue debentures or incur other debt.

• Interest rates

Prevailing interest rates will affect the market value of our Series 1 Debentures, which may have a fixed interest rate. Assuming all other factors remain unchanged, the market value of fixed rate debt instruments such as our Series 1 Debentures will normally decline during such period as prevailing interest rates for similar debt instruments rise, and increase as prevailing interest rates for comparable debt instruments decline.

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• Exchange rates

Purchasers should consult their financial and legal advisors as to any specific risks entailed by an investment in securities that are denominated or payable in a currency other than the currency of the country in which they are resident or in which they conduct business (the “home currency”). Our Series 1 Debentures are denominated and payable in Canadian dollars. Depreciation of the currency in which our Series 1 Debentures are payable against a holder’s home currency would result in a decrease in the effective yield of our Series 1 Debentures or in their payout and could result in an overall loss on a home currency basis. Fluctuations in any particular exchange rate that have occurred in the past are not necessarily indicative of fluctuations that may occur.

Quantitative and Qualitative Disclosures about 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 we are exposed at any point in time varies depending on market conditions, expectations of future price or market rate movements and composition of our financial assets and liabilities held, non-trading physical assets and contract portfolios.

To manage the exposure related to changes in market risk, we use 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.

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. We regularly transact in foreign currencies when purchasing equipment and 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.

At March 31, 2012, with other variables unchanged, the impact of a $0.01 increase (decrease) in exchange rates of the Canadian dollar to the US dollar on short-term exposures would not have a significant impact to other comprehensive income.

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 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.

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.

At March 31, 2012, we held $78.8 million of floating rate debt pertaining to our Credit Facilities within our credit agreement (March 31, 2011 – $72.0 million). As at March 31, 2012, holding all other variables constant, a 100 basis point increase (decrease) to interest rates on floating rate debt would result in a $0.8 million increase (decrease) in effective annual interest costs. This assumes that the amount of floating rate debt remains unchanged from that which was held at March 31, 2012.

L. General Matters

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, 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, 2012. Additional financial information is provided in our audited consolidated financial statements for the year ended March 31, 2012.

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, the Securities and Exchange Commission’s Electronic Data Gathering, Analysis and Retrieval (EDGAR) system at www.sec.gov and our Company’s website at www.nacg.ca.

2012 Annual Information Form 31

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.

Experts

KPMG LLP are the auditors of the Company and have confirmed that they are independent with respect to the Company within the meaning of the Rules of Professional Conduct of Institute of Chartered Accountants of Alberta and within the meaning of the U.S. Securities Act of 1933 and the applicable rules and regulations thereunder adopted by the Securities and Exchange Commission and the Public Company Accounting Oversight Board (United States).

Glossary of Terms

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.

“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.

“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.

“pipeline anchor” is a foundation element used to resist buoyant forces of buried pipelines, consisting of a solid, square central shaft with at least one helix plate located on the shaft with its axis positioned parallel to the shaft’s length.

“screw pile” is a foundation element consisting of a hollow, round central shaft with at least one helix plate located on the shaft with its axis positioned parallel to the shaft’s length.

“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).

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EXHIBIT A

Audit Committee Charter

1. PURPOSE

The Board of Directors (the “Board”) of North American Energy Partners Inc. (the “Company”) has established the Audit Committee (the “Committee”) for the purpose of assisting the Board in meeting its oversight responsibilities in relation to: (a) the integrity of the Company’s accounting and financial reporting processes; (b) internal controls over financial reporting; (c) controls and procedures related to disclosure; (d) the internal audit function; (e) the qualifications, independence and performance of the Company’s external auditors; (f) identification and monitoring of financial risks; (g) the processes for monitoring compliance with legal and regulatory requirements (other than those related to health, environment and safety matters); and (h) establishment and monitoring of the Company’s codes of conduct and ethics.

2. AUTHORITY

The Committee has the authority to:

(a) conduct or authorize investigations into any matter within its scope of responsibility;

(b) retain and compensate independent counsel, accountants and others to advise the Committee or assist it with respect to its responsibilities;

(c) pre-approve all audit services and permitted non-audit services performed by the Company’s external auditors and negotiate the compensation to be paid for such services;

(d) resolve any disagreements between management and the Company’s external auditors regarding financial reporting;

(e) seek any information it requires from employees of the Company, all of whom will be directed by management to co-operate with the Committee’s requests;

(f) meet and communicate directly with the Company’s officers, external auditors, internal auditor, outside counsel and consultants, all as the Committee may deem necessary;

(g) direct the Company’s internal auditor to carry out such activities as the Committee may require;

(h) access all documents of the Company that the Committee may deem relevant to it in carrying out its responsibilities; and

(i) undertake any other activity that may be reasonably necessary in order for the Committee to carry out its responsibilities as set out in this Charter.

3. COMPOSITION

3.1. The Board will appoint annually, from among its members, the Committee and its Chair. The Committee will consist of at least three and not more than six members.

3.2. Each member of the Committee must 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.

3.3. Each member of the Committee must be “financially literate” in that he or she has the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to that which can reasonably be expected to be raised by the Company’s financial statements.

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

3.5. No director currently serving on the Committee will serve on the audit committees of more than two additional public companies.

4. MEETINGS

4.1. The Committee will meet at least once each fiscal quarter, with authority to convene additional meetings as circumstances require. A meeting may be convened by the Chair, any member of the Committee, the external auditors, the internal auditor, the chief executive officer of the Company or the chief financial officer of the Company. The Chair will determine the time, place and procedures for calling and conducting Committee meetings, subject to the requirements of the bylaws of the Company, of this Charter and of the Canada Business Corporations Act.

4.2. A majority of the members of the Committee will constitute a quorum. 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.

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

4.4. A resolution signed (including signatures communicated by fax or electronic mail) 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.

4.5. The Committee may invite such officers, directors and employees of the Company as it may see fit from time to time to attend at meetings and provide information pertinent to any matter being discussed. Any director of the Company is entitled to attend Committee meetings, however, only members of the Committee are eligible to vote or establish a quorum. The external auditors will be entitled to receive notice of every meeting of the Committee and to attend and be heard at the same. The Committee will periodically meet in camera alone and separately with each of the external auditors, the internal auditor and management.

4.6. The Chair will ensure that meeting agendas are prepared and provided in advance to members of the Committee, along with appropriate briefing materials. The Committee will keep and approve minutes of each meeting which record the decisions reached by the Committee. Once approved, the minutes will be distributed to Committee members with copies provided to the Board, the chief executive officer of the Company, the chief financial officer of the Company, the external auditors and the internal auditor.

5. RESPONSIBILITIES

The Committee will carry out the following responsibilities:

5.1. Financial Reporting

(a) Review with management and the external auditors any issues of concern with respect to financial reporting, including proposed changes in the selection or application of major accounting policies and the reasons for such changes, any complex or unusual transactions, any issues depending on management’s judgment, proposed changes to or adoption of disclosure practices, and the effects of any recent or proposed regulatory or accounting initiatives or pronouncements, all to the extent that the foregoing may be material to financial reporting.

(b) Review with management and the external auditors their qualitative judgments about the appropriateness, not just the acceptability, of accounting principles and accounting disclosure practices used or proposed to be used, particularly the degree of aggressiveness or conservatism of the Company’s accounting principles and underlying estimates.

(c) In reviewing with management and the external auditors the results of their year-end audit and quarterly reviews, and management's responses, review any problems or difficulties experienced by the external auditors in performing the audit and reviews, including any restrictions or limitations imposed by management and resolve any disagreements between management and the external auditors regarding these matters.

(d) Review with management, the external auditors and legal counsel, as necessary, any litigation, claim or other contingency, including tax assessments, that could have a material effect on the financial position or operating results of the Company, and the manner in which these matters have been disclosed or reflected in the financial statements.

(e) Review with management and the external auditors the annual audited financial statements and the related management discussion and analysis (“MD&A”) and press release; make recommendations to the Board with respect to approval thereof before being released to the public, and obtain an explanation from management of all significant variances between comparable reporting periods. Obtain confirmation from management and the external auditors that any GAAP reconciliation complies with the requirements of applicable securities laws.

(f) Approve the quarterly unaudited financial statements and the related MD&A and press release prior to their release to the public.

(g) Review with management and the external auditors any other matter required to be communicated to the Committee by the external auditors under applicable generally accepted auditing standards, applicable law and listing standards.

5.2. Internal Controls

(a) Review and consider the adequacy and effectiveness of the Company’s internal controls over accounting and financial reporting, including information technology security and control, and any material non-compliance with such controls.

(b) Understand the scope of internal audits and the external auditors’ review of internal control over financial reporting and obtain reports on significant findings and recommendations, together with management’s responses.

(c) Review management’s internal control report and the related attestation by the external auditors and discuss the same with management, the internal auditor and external auditors.

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(d) Obtain from the chief financial officer and chief executive officer confirmation that each is prepared to sign all required annual and quarterly certificates under applicable securities law in relation to internal controls over accounting and financial reporting. Review any disclosures made by the chief financial officer and chief executive officer regarding significant deficiencies or material weaknesses in the design or operation of internal controls or any fraud that involves management or other employees who have a significant role in the Company’s internal controls.

(e) Consider any special audit steps to be taken in light of any material internal control deficiencies.

5.3. Disclosure Controls

(a) Review and consider the adequacy and effectiveness of the Company’s disclosure controls and procedures, including any material non-compliance with such controls and procedures.

(b) Review and approve the disclosure policy of the Company and periodically assess the adequacy of such policy for completeness and accuracy.

(c) 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.

(d) Monitor the activities of the Company’s Disclosure Committee.

(e) Review and approve, and in some instances recommend approval to the Board, material financial disclosures prior to their public release or filing with securities regulators that are contained within the following documents:

(i) any prospectus or offering document;

(ii) annual information forms;

(iii) 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);

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

(v) 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.

(f) Review and approve, and in some instances recommend approval to the Board, material financial disclosures prior to their public release or filing with securities regulators that relate to related-party transactions or off balance sheet structures.

5.4. Internal Audit

(a) Review with management, the internal auditor and the external auditors the charter, activities, budget, staffing and organizational structure of the internal audit function.

(b) Review management’s proposed appointment, termination or replacement of the internal auditor.

(c) Review and approve the annual internal audit plan and scope of work and ensure that the internal audit plan is coordinated with the activities of the external auditors.

(d) Review all internal audit reports and management’s responses.

(e) Ensure that the internal auditor has direct and open communication with the Committee and that the internal auditor meets at least twice annually with the Committee without the presence of management to discuss any matters that the Committee or the internal auditor believe should be discussed privately, such as problems or difficulties encountered in the course of internal audit work, any unjustified restrictions or limitations imposed on the internal auditor or any other disagreements with management.

(f) Review the effectiveness of the internal audit function on an annual basis, including a review of reporting relationships, resources, qualifications of internal audit staff, the internal auditor’s independence from management, the internal auditor’s working relationship with the external auditors and compliance by the internal auditor with the relevant codes and standards of The Institute of Internal Auditors. The internal auditor currently reports functionally to the Chair of the Audit Committee and administratively to the Chief Financial Officer.

5.5. External Audit

(a) Advise the board with respect to the selection, appointment, retention, compensation and replacement of the external auditors. In the event of a change of external auditors, 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.

2012 Annual Information Form 35

(b) Oversee the work and evaluate the qualifications and performance of the external auditors, in the course of which evaluation the Committee will:

(i) annually obtain and review a report by the external auditors describing: (A) the external auditors’ internal quality control procedures; (B) any material issues raised by the most recent internal quality control review, or peer review, of the external auditors or by any inquiry or investigation by government or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the external auditors and any steps taken to deal with such issues; and (C) all relationships between the external auditors and the Company (in order to assess the auditors’ independence);

(ii) annually review and evaluate senior members of the external audit team, including their expertise and qualifications and take into consideration the opinions of management and the internal auditor in that regard; and

(iii) report all of its findings and conclusions with respect to the external auditors to the Board.

(c) Annually review and confirm with management and the external auditors the independence of the external auditors, which review will include but will not be limited to:

(i) ensuring receipt at least annually from the external auditors of a formal written statement delineating all relationships between the external auditors and the Company, including non-audit services provided to the Company, and outlining the extent to which the compensation of the audit partners of the external auditors is based upon selling non-audit services;

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

(iii) enquiring into and determining the appropriate resolution of any conflict of interest in respect of the external auditors;

(iv) reviewing the timing and process for implementing the rotation of the lead audit partner, the reviewing partner and other partners providing audit services to the Company;

(v) considering whether there should be a regular rotation of the audit firm itself;

(vi) 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 auditors and ensuring a “cooling off” period of at least one year before any such persons can become employees of the Company in a financial oversight role.

(d) Ensure that the external auditors report directly to the Committee and that they are ultimately accountable to the Committee and to the Board as representatives of the shareholders of the Company.

(e) Review and approve the annual audit plan prior to the annual audit of the Company’s financial statements being undertaken by the external auditors, including review of the proposed scope and approach of the external auditors and the coordination of effort with internal audit.

(f) Ensure that the external auditors have direct and open communication with the Committee and that the external auditors meet regularly with the Committee without the presence of management to discuss any matters that the Committee or the external auditors believe should be discussed privately.

(g) Review and approve the basis and amount of the external auditors’ fees with respect to the annual audit and the quarterly reviews.

(h) Review and pre-approve all non-audit services to be provided to the Company or its subsidiaries by the external auditors and the engagement fees in respect to such services, provided that the Chair of the Committee, on behalf of the Committee, is authorized to pre-approve any non-audit services and the related engagement fees up to an amount of $20,000 per engagement. At the next Committee meeting, the Chair will report to the Committee any such pre-approval given.

5.6. Financial Risk Management

(a) Review the Company’s major financial risk exposures and approve the Company’s policies to manage such financial risk.

(b) Monitor management of hedging, debt and credit, make recommendations to the Board respecting management of such risks and review the Company’s compliance with the same.

(c) Monitor management’s communication and implementation of the Anti-Fraud Policy and review compliance with such Policy by, among other things, receiving reports from management on:

(i) any investigations of fraudulent activity;

(ii) monitoring activities in relation to fraud risks and controls; and

(iii) assessments of fraud risk.

36 2012 Annual Information Form

NOA

(d) Periodically review and approve the adequacy and appropriateness of the Anti-Fraud Policy and management’s implementation of the same.

5.7. Code of Conduct and Ethics Reporting

(a) Review the policies and procedures established by management for:

(i) the receipt, retention and treatment of complaints received by the Company regarding financial reporting, accounting, internal accounting controls or auditing matters; and

(ii) the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters.

(b) Monitor management’s communication and implementation of the Code of Conduct and Ethics Policy and review compliance with such Policy by, among other things:

(i) reviewing on a timely basis serious violations of the Code of Conduct and Ethics Policy; and

(ii) reviewing on a summary basis at least quarterly all reported violations of the Code of Conduct and Ethics Policy.

(c) Periodically review the adequacy and appropriateness of the Code of Conduct and Ethics Policy and management’s implementation of the same and make recommendations to the Board in that regard.

5.8. Legal and Regulatory Compliance

(a) Review the effectiveness of the system for monitoring compliance with laws and regulations (other than those related to health, environment and safety matters) and the results of management’s investigation and follow-up (including disciplinary action) of any instances of non-compliance. Review the findings of any examination by regulatory authorities and any external auditors’ observations relating to such matters.

(b) Obtain regular updates from management and legal counsel regarding compliance matters, including compliance with applicable financial, tax or securities regulations and the accuracy and timeliness of filings with regulators.

(c) Review any litigation, claim or other contingent liability, including any tax reassessment that could have a material effect on the financial statements.

(d) Monitor compliance by the Company with all payments and remittances required to be made in accordance with applicable law, where the failure to make such payments could render the directors of the Company personally liable.

5.9. Other Responsibilities

(a) Regularly report to the Board about Committee activities, issues and related recommendations, including such matters as the Board may from time to time refer or delegate to the Committee.

(b) Annually assess the adequacy of this Charter, submit such evaluation to the Governance Committee and recommend any proposed changes to the Governance Committee to bring forward to the Board for approval.

(c) Evaluate the performance and effectiveness of the Committee on an annual basis.

(d) Provide an open avenue of communication between internal audit, the external auditors and the Board.

(e) Perform any other activities consistent with the Committee’s mandate, the Company’s governing laws and the regulations of relevant stock exchanges as he Committee or the Board deems necessary or appropriate.

6. GENERAL

6.1. While the Committee will have the responsibilities and powers set forth in this Charter, it will 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 auditors in accordance with their respective roles.

6.2. 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, regulations or Company policies.

2012 Annual Information Form 37

Prepared By:	Approved By:	Date of Approval and Issue:
/s/ Jordan Slator	/s/ Allen Sello	December 1, 2011
Jordan Slator	Allen Sello, Chair
General Counsel	Audit Committee
and Secretary

Appendix A: Audit Committee Financial Expert

At least one member of the Committee will be an “audit committee financial expert” who will 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; and

5. An understanding of audit committee functions.

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.

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.

38 2012 Annual Information Form

EX-99.2

Exhibit 99.2

NORTH AMERICAN ENERGY PARTNERS INC.

Consolidated Financial Statements

For the years ended March 31, 2012, 2011 and 2010

(Expressed in thousands of Canadian Dollars)

2012 Annual Report 1

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

INDEPENDENT AUDITORS’ REPORT OF 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.’s internal control over financial reporting as of March 31, 2012, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). North American Energy Partners Inc.’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, 2012. Our responsibility is to express an opinion on North American Energy Partners Inc.’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.

In our opinion, North American Energy Partners Inc. maintained, in all material respects, effective internal control over financial reporting as of March 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

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 consolidated balance sheets of North American Energy Partners Inc. as at March 31, 2012 and 2011, and the consolidated statements of operations and comprehensive (loss) income, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended March 31, 2012, and our report dated June 6, 2012, expressed an unqualified opinion on those consolidated financial statements.

Chartered Accountants

Edmonton, Canada

June 6, 2012

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 2012 Annual Report

NOA

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

INDEPENDENT AUDITORS’ REPORT OF REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated financial statements of North American Energy Partners Inc., which comprise the consolidated balance sheets as at March 31, 2012 and 2011, and the consolidated statements of operations and comprehensive (loss) income, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended March 31, 2012, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with U.S. generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

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 comply with ethical requirements and plan and perform an audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the company’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances.

An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of North American Energy Partners Inc. as at March 31, 2012 and 2011 and its consolidated results of operations and its consolidated cash flows for each of the years in the three-year period ended March 31, 2012 in accordance with U.S. generally accepted accounting principles.

Other Matter

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), North American Energy Partners Inc.’s internal control over financial reporting as of March 31, 2012, 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 6, 2012 expressed an unqualified opinion on the effectiveness of North American Energy Partners Inc.’s internal control over financial reporting.

Chartered Accountants

Edmonton, Canada

June 6, 2012

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.

2012 Annual Report 3

Consolidated Balance Sheets

As at March 31

(Expressed in thousands of Canadian Dollars)

	2012			2011
Assets
Current assets
Cash and cash equivalents		$1,400			$722
Accounts receivable, net (note 7 and 21(d))		214,129			128,482
Unbilled revenue (note 8)		86,859			102,939
Inventories (note 9)		11,855			7,735
Prepaid expenses and deposits (note 10)		6,315			8,269
Investment in and advances to unconsolidated joint venture (note 11)		1,574			1,488
Deferred tax assets (note 17)		2,991			1,729
		325,123			251,364
Property, plant and equipment, net (note 13)		312,775			321,864
Other assets (note 12(a))		21,743			26,908
Goodwill (note 5)		32,901			32,901
Deferred tax assets (note 17)		57,451			49,920
Total Assets		$749,993			$682,957
Liabilities and Shareholders' Equity
Current liabilities
Accounts payable		$171,130			$86,053
Accrued liabilities (note 14)		36,795			32,814
Billings in excess of costs incurred and estimated earnings on uncompleted contracts (note 8)		7,514			2,004
Current portion of long term debt (note 15(a))		14,402			14,862
Current portion of derivative financial instruments (note 21(a))		3,220			2,474
Deferred tax liabilities (note 17)		21,512			27,612
		254,573			165,819
Long term debt (note 15(a))		300,066			290,801
Derivative financial instruments (note 21(a))		5,926			9,054
Other long term obligations (note 16(a))		8,860			25,576
Deferred tax liabilities (note 17)		52,788			44,441
		622,213			535,691
Shareholders' equity
Common shares (authorized – unlimited number of voting common shares; issued and outstanding – March 31, 2012 – 36,251,006 (March 31, 2011 – 36,242,526) (note 18(a))		304,908			304,854
Additional paid-in capital		8,711			7,007
Deficit		(185,820	)		(164,536	)
Accumulated other comprehensive loss		(19	)		(59	)
		127,780			147,266
Total liabilities and shareholders' equity		$749,993			$682,957
Commitments (note 25)
Contingencies (note 28)

Approved on behalf of the Board

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

See accompanying notes to consolidated financial statements.

4 2012 Annual Report

NOA

Consolidated Statements of Operations and

Comprehensive (Loss) Income

For the years ended March 31

(Expressed in thousands of Canadian Dollars, except per share amounts)

	2012			2011			2010
Revenue		$1,006,545			$858,048			$758,965
Project costs		610,821			456,119			301,307
Equipment costs		220,738			234,933			209,408
Equipment operating lease expense		65,185			69,420			66,329
Depreciation		48,900			39,440			42,636
Gross profit		60,901			58,136			139,285
General and administrative expenses		54,400			59,828			62,516
Loss on disposal of property, plant and equipment		1,741			1,948			1,233
(Gain) loss on disposal of assets held for sale (note 12(b))		(466	)		825			373
Amortization of intangible assets (note 12(c))		5,702			3,540			1,719
Equity in (earnings) loss of unconsolidated joint venture (note 11)		(86	)		2,720			(44	)
Operating (loss) income before the undernoted		(390	)		(10,725	)		73,488
Interest expense, net (note 19)		30,325			29,991			26,080
Foreign exchange loss (gain)		52			(1,659	)		(48,901	)
Realized and unrealized (gain) loss on derivative financial instruments (note 21(a))		(2,382	)		(2,305	)		54,411
Loss on debt extinguishment (note 15(d))		–			4,346			–
(Loss) income before income taxes		(28,385	)		(41,098	)		41,898
Income tax (benefit) expense (note 17):
Current		(677	)		2,892			3,803
Deferred		(6,546	)		(9,340	)		9,876
Net (loss) income		(21,162	)		(34,650	)		28,219
Other comprehensive income (loss)
Unrealized foreign currency translation gain (loss)		40			(59	)		–
Comprehensive (loss) income		(21,122	)		(34,709	)		28,219
Net (loss) income per share – basic (note 18(b))		$(0.58	)		$(0.96	)		$0.78
Net (loss) income per share – diluted (note 18(b))		$(0.58	)		$(0.96	)		$0.77

See accompanying notes to consolidated financial statements.

2012 Annual Report 5

Consolidated Statements of Changes in Shareholders’

Equity

(Expressed in thousands of Canadian Dollars)

	Common shares		Additional paid-in capital			Deficit			Accumulated other comprehensive loss			Total
Balance at March 31, 2009		$303,431		$5,466			$(158,105	)		$–			$150,792
Net income		–		–			28,219			–			28,219
Share option plan		–		2,135			–			–			2,135
Deferred performance share unit plan		–		123			–			–			123
Reclassified to restricted share unit liability		–		(20	)		–			–			(20	)
Cash settlement of stock options		–		(244	)		–			–			(244	)
Exercised stock options		74		(21	)		–			–			53
Balance at March 31, 2010		$303,505		$7,439			$(129,886	)		$–			$181,058
Net loss		–		–			(34,650	)		–			(34,650	)
Unrealized foreign currency translation loss		–		–			–			(59	)		(59	)
Share option plan		–		1,455			–			–			1,455
Deferred performance share unit plan		–		(44	)		–			–			(44	)
Stock award plan		–		780			–			–			780
Exercised stock options		1,349		(386	)		–			–			963
Senior executive stock option plan		–		(2,237	)		–			–			(2,237	)
Balance at March 31, 2011		$304,854		$7,007			$(164,536	)		$(59	)		$147,266
Net loss		–		–			(21,162	)		–			(21,162	)
Unrealized foreign currency translation gain		–		–			–			40			40
Share option plan		–		1,373			–			–			1,373
Reclassified to restricted share unit liability		–		(121	)		–			–			(121	)
Stock award plan		–		256			–			–			256
Exercised stock options		54		(19	)		–			–			35
Repurchase of shares to settle stock award plan		–		(700	)		(122	)		–			(822	)
Senior executive stock option plan		–		915			–			–			915
Balance at March 31, 2012		$304,908		$8,711			$(185,820	)		$(19	)		$127,780

See accompanying notes to consolidated financial statements.

6 2012 Annual Report

NOA

Consolidated Statements of Cash Flows

For the years ended March 31

(Expressed in thousands of Canadian Dollars)

	2012			2011			2010
Cash (used in) provided by:
Operating activities:
Net (loss) income for the period		$(21,162	)		$(34,650	)		$28,219
Items not affecting cash:
Depreciation		48,900			39,440			42,636
Equity in (earnings) loss of unconsolidated joint venture (note 11)		(86	)		2,720			(44	)
Amortization of intangible assets (note 12(c))		5,702			3,540			1,719
Amortization of deferred lease inducements (note 16(b))		(107	)		(107	)		(107	)
Amortization of deferred financing costs (note 12(d))		1,591			1,609			3,348
Loss on disposal of property, plant and equipment		1,741			1,948			1,233
(Gain) loss on disposal of assets held for sale (note 12(b))		(466	)		825			373
Realized and unrealized foreign exchange gain on 8 3/4% senior notes		–			(732	)		(48,920	)
Realized and unrealized (gain) loss on derivative financial instruments		(2,382	)		(2,305	)		38,852
Loss on debt extinguishment (note 15(d))		–			4,346			–
Stock-based compensation (reversal) expense (note 27(a))		(2,263	)		8,156			5,270
Cash settlement of restricted share unit plan (note 27(e))		(318	)		–			–
Cash settlement of stock options (note 27(b))		–			–			(244	)
Settlement of stock award plan (note 27(g))		(822	)		–			–
Accretion of asset retirement obligation (note 16(c))		39			35			5
Deferred income tax (benefit) expense (note 17)		(6,546	)		(9,340	)		9,876
Net changes in non-cash working capital (note 22(b))		39,452			(15,982	)		(39,591	)
		63,273			(497	)		42,625
Investing activities:
Acquisition, net of cash acquired (note 6)		–			(23,501	)		(5,410	)
Purchase of property, plant and equipment		(61,759	)		(36,417	)		(51,888	)
Additions to intangible assets (note 12(c))		(3,537	)		(4,748	)		(3,362	)
Investment in and advances to unconsolidated joint venture (note 11)		–			(1,291	)		(2,873	)
Proceeds on disposal of property, plant and equipment		176			499			1,440
Proceeds on disposal of assets held for sale		920			826			2,482
		(64,200	)		(64,632	)		(59,611	)
Financing activities:
Repayment of credit facilities		(196,203	)		(85,000	)		(6,906	)
Increase in credit facilities		203,000			128,524			34,700
Financing costs (note 12(d))		(60	)		(7,920	)		(1,123	)
Redemption of 8 3/4% senior notes (note 15(d))		–			(202,410	)		–
Issuance of Series 1 Debentures (note 15(e))		–			225,000			–
Settlement of swap liabilities (note 21(a))		–			(91,125	)		–
Proceeds from stock options exercised (note 27(b))		35			963			53
Repayment of capital lease obligations		(5,207	)		(5,127	)		(5,613	)
		1,565			(37,095	)		21,111
Increase (decrease) in cash and cash equivalents		638			(102,224	)		4,125
Effect of exchange rate on changes in cash and cash equivalents		40			(59	)		–
Cash and cash equivalents, beginning of year		722			103,005			98,880
Cash and cash equivalents, end of year		$1,400			$722			$103,005

Supplemental cash flow information (note 22(a))

See accompanying notes to consolidated financial statements.

2012 Annual Report 7

Notes to Consolidated Financial Statements

For the years ended March 31, 2012, 2011, 2010

(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., 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 mining and environmental services, heavy construction, industrial and commercial site development and pipeline and piling installations. The Company also designs and manufactures screw piles, provides tank maintenance services to the petro-chemical industry across Canada and the United States and sells pipeline anchoring systems globally.

2. Significant accounting policies

a) Basis of presentation

These consolidated financial statements are prepared in accordance with United States generally accepted accounting principles (“US GAAP”). Material inter-company transactions and balances are eliminated upon consolidation.

These consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, NACGI, North American Fleet Company Ltd., North American Construction Projects Inc., NACG International Inc., North American Major Mining Projects Inc., North American Construction Management Inc. (“NACMI”) and NACG Properties Inc., and the following 100% owned subsidiaries of NACMI:

• North American Caisson Ltd.	• North American Services Inc.
• North American Construction Ltd.	• North American Site Development Ltd.
• North American Engineering Inc.	• North American Site Services Inc.
• North American Enterprises Ltd.	• North American Tailings and Environmental Ltd.
• North American Industries Inc.	• DF Investments Limited
• North American Maintenance Ltd.	• Drillco Foundation Co. Ltd.
• North American Mining Inc.	• Cyntech Canada Inc.
• North American Pile Driving Inc.	• Cyntech Services Inc.
• North American Pipeline Inc.	• Cyntech U.S. Inc.
• North American Road Inc.

b) Use of estimates

The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures reported in these consolidated financial statements and accompanying notes and the reported amounts of revenues and expenses during the reporting period.

Significant estimates made by management include the assessment of the percentage of completion on time-and-materials, unit-price, lump-sum and cost-plus 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 and embedded 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 and intangible assets. Actual results could differ materially from those estimates.

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 expenses are charged to expense as incurred. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined.

The accuracy of the Company’s revenue and profit recognition in a given period is dependent on the accuracy of its estimates of the cost to complete each project. Cost estimates for all of significant projects use a detailed “bottom up” approach and the Company believes its experience allows it to provide reasonably dependable estimates. There are a number of factors that can contribute to changes in estimates of contract cost and profitability that are recognized to the extent contract remedies are unavailable in the period in which such adjustments are determined. The most significant of these include:

• the completeness and accuracy of the original bid;

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• costs associated with added scope changes;

• extended overhead due to owner, weather and other delays;

• subcontractor performance issues;

• changes in economic indices used for the determination of escalation or de-escalation for contractual rates on long-term contracts;

• changes in productivity expectations;

• site conditions that differ from those assumed in the original bid;

• contract incentive and penalty provisions;

• the availability and skill level of workers in the geographic location of the project; and

• a change in the availability and proximity of equipment and materials.

The foregoing factors as well as the mix of contracts at different margins may cause fluctuations in gross profit between periods. 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 is 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 expenses 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 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:

• a bona fide addition to contract value; and

• revenues can be reliably estimated.

These two conditions are satisfied when:

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

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

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

• 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.

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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.

The Company recognizes revenue from the sale of its other products and services as follows:

• 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 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;

• Revenue from tank services is provided based upon orders and contracts with the customer that include fixed or determinable prices based upon daily, hourly or job rates and is recognized as the services are provided to the customer; and

• Revenue from anchor manufacturing and product sales is recognized when the products are shipped to the customer.

The Company recognizes revenue from the foregoing activities once persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, fees are fixed and determinable and collectability is reasonably assured.

d) Balance sheet classifications

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

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 billed to clients.

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 tires, job materials, manufacturing raw materials and finished goods. Finished goods cost includes raw materials, labour and a reasonable allocation of appropriate overhead costs.

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 drive trains 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

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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 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:

• Customer relationships and backlog, which are being amortized over the remaining lives of the related contracts and relationships;

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

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

• capitalized computer software and development costs, which are being amortized on a straight-line basis over a maximum period of four years; and

• patents, which are being amortized on a straight-line basis over estimated useful lives of up to six years.

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.

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 or amortization 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.

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o) Assets held for sale

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

• management, having the authority to approve the action, commits to a plan to sell the assets;

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

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

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

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

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

Assets to be disposed of by sale are reported at the lower of their carrying amount or fair value less costs to sell and are 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 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 and the majority of its subsidiaries 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.

Accounts of the Company’s US-based subsidiary, which has a US Dollar functional currency, are translated into Canadian Dollars using the current rate method. Assets and liabilities are translated at the rate of exchange in effect at the balance sheet date, and revenue and expense items (including depreciation and amortization) are translated at the average rate of exchange for the period. The resulting unrealized exchange gains and losses from these translation adjustments are included as a separate component of shareholders’ equity in Accumulated Other Comprehensive Income (Loss). The effect of exchange rate changes on cash balances held in foreign currencies is separately reported as part of the reconciliation of the change in cash and cash equivalents for the period.

r) Fair value measurement

Fair value measurements 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 values included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Fair values included 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 fair value 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.

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 based on the 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

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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 “General and administrative expenses” in the Consolidated Statements of Operations. 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 has a Share Option Plan which is described in note 27(b). 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 Senior Executive Stock Option Plan which is described in note 27(c). This compensation plan allows the option holder the right to settle options in cash. The liability is measured at fair value using the Black-Scholes model at the modification date and subsequently at each period end date. Changes in fair value of the liability are recognized in the Consolidated Statements of Operations.

The Company has a Deferred Performance Share Unit (“DPSU”) Plan which is described in note 27(d). 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 plan 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. The company has no outstanding DPSUs at this time.

The Company has a Restricted Share Unit (“RSU”) Plan which is described in note 27(e). RSUs are 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 number of vested shares multiplied by the fair market value of each RSU as determined by the volume weighted average trading price of the Company’s common shares for the five trading days immediately preceding the day on which the fair market value is to be determined. The Company recognizes compensation expense over the three-year term of the RSU in the Consolidated Statements of Operations.

The Company has a Director’s Deferred Stock Unit (“DDSU”) Plan which is described in note 27(f). 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 unit and is recorded as a charge to operating income when issued. Subsequent changes in the Company’s payment obligation after issuing the unit and prior to the settlement date are recorded as a charge to operating income in the period such changes occur.

The Company has a Stock Award Plan which is described in note 27(g). The stock awards are settled at the Company’s option, either by the issuance of equity instruments if all necessary shareholder approvals and regulatory approvals are obtained or by cash payment. Compensation cost is measured using the market price of the Company’s common shares 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.

v) Net (loss) income per share

Basic net (loss) income 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 18(b)). 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 are 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.

Certain operating lease and rental agreements provide a maximum hourly usage limit, above which the Company will be required to pay for the over hour usage as a contingent rent expense. These contingent expenses are recognized when the likelihood of exceeding the usage limit is considered probable and are due at the end of the lease term or rental period. The contingent rental expenses are included in “Equipment operating lease expense” in the Consolidated Statements of Operations.

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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 are presented as deferred financing costs. The deferred financing costs related to the senior notes, debentures 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.

3. Accounting pronouncements recently adopted

a) 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. The Company adopted this ASU effective April 1, 2011. The adoption of this standard did not have a material effect on the Company’s consolidated financial statements.

b) Share based payment awards

In April 2010, the FASB issued ASU No. 2010-13, “Effect of Denominating the Exercise Price of a 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. The Company adopted this ASU effective April 1, 2011 as an amendment to ASC 718, “Compensation – Stock Compensation”. The adoption of this standard did not have a material effect on the Company’s consolidated financial statements.

c) Intangibles – Goodwill and Other

In December 2010, the FASB issued ASU No. 2010-28, “When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts”, which amends ASC 350, “Intangibles-Goodwill and Other” to modify step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts, to require an entity to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that impairment may exist. The Company adopted this ASU effective April 1, 2011. The adoption of this standard did not have a material effect on the Company’s consolidated financial statements.

d) Business Combinations

In December 2010, the FASB issued ASU No. 2010-29, “Disclosure of Supplementary Pro Forma Information for Business Combinations”, which amends ASC 805, “Business Combinations”, to require that pro-forma information be presented as if the business combination occurred at the beginning of the prior annual reporting period for the purposes of calculating both the current reporting period and the prior reporting period pro forma financial information. The ASU also requires the disclosure be accompanied by a narrative description of the nature and amount of material, nonrecurring pro forma adjustments. The Company adopted this ASU prospectively effective April 1, 2011 for business combinations for which the acquisition date is on or after April 1, 2011. The adoption of this standard did not have a material effect on the Company’s consolidated financial statements.

e) Fair value measurement

In May 2011, the FASB issued ASU 2011-04, “Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRS”, which generally represent clarifications of Topic 820, but also include some instances where a particular principle or requirement for measuring fair value or disclosing information about fair value measurements has changed. This ASU results in common principles and requirements for measuring fair value and for disclosing information about fair value measurements in accordance with US GAAP and IFRSs. The Company adopted this ASU prospectively effective January 1, 2012. The adoption of this standard did not have a material effect on the Company’s consolidated financial statements.

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4. Recent United States accounting pronouncements not yet adopted

a) Goodwill Impairment

In September 2011, the FASB issued ASU 2011-08, “Intangibles – Goodwill and Other – Testing Goodwill for Impairment”, which amended the guidance on the annual testing of goodwill for impairment. The amended guidance will allow companies to assess qualitative factors to determine if it is more-likely-than-not that goodwill might be impaired and whether it is necessary to perform the two-step goodwill impairment test required under current accounting standards. This guidance will be effective for the Company’s fiscal year ending March 31, 2013, with early adoption permitted. The Company has determined that this new guidance will not have a material impact on its consolidated financial statements.

b) Offsetting Assets and Liabilities

In December 2011, the FASB issued ASU 2011-11, “Balance Sheet”, which amends the disclosure requirements on offsetting in Section 210-20-50. The amendments require enhanced disclosures by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with either Section 210-20-45 or Section 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either Section 210-20-45 or Section 815-10-45. This guidance will be effective for the Company’s fiscal year ending March 31, 2014. This standard does not amend the existing guidance on when it is appropriate to offset. The adoption of this standard is not anticipated to have a material effect on the Company’s consolidated financial statements.

c) Comprehensive income

In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. This ASU requires the presentation of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements rather than as a footnote to the consolidated financial statements, where it is currently disclosed. The ASU also requires the presentation of reclassification adjustments for items that are reclassified from other comprehensive income to net income in the financial statements where the components of net income and the components of other comprehensive income are presented. The option under current guidance that permits the presentation of components of other comprehensive income as part of the statement of changes in shareholders’ equity will be eliminated. In December 2011, the FASB further amended its guidance to defer changes related to the presentation of reclassification adjustments indefinitely as a result of concerns raised by stakeholders that the new presentation requirements would be difficult for preparers and add unnecessary complexity to financial statements. This guidance will be effective for the Company’s fiscal year ending March 31, 2013. The Company has determined that this new guidance will not have a material impact on its consolidated financial statements.

5. Goodwill

In accordance with the Company’s accounting policy, a goodwill impairment test is completed 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 tests on October 1, 2011, 2010 and 2009 and concluded that there was no goodwill impairment as the fair value of the Piling reporting unit exceeded its carrying value. There were no triggering events between October 1, 2011 and March 31, 2012.

The changes in goodwill during the years ended March 31, 2012, 2011 and 2010 are as follows:

Balance at March 31, 2009	$23,872
Acquisition of goodwill (assigned to the Piling segment) (note 6(b))	1,239
Balance at March 31, 2010	25,111
Acquisition of goodwill (assigned to the Piling segment) (note 6(a))	7,790
Balance at March 31, 2011 and March 31, 2012	$32,901

6. Acquisitions

a) Acquisitions in fiscal 2011

On November 1, 2010, the Company acquired all of the assets of Cyntech Corporation and its wholly-owned subsidiary Cyntech Anchor Systems LLC (collectively “Cyntech”), for consideration of $23,501. Cyntech is based in Calgary, Alberta and designs and manufactures screw piles and pipeline anchoring systems, and provides tank maintenance services to the petro-chemical industry. As a result of this acquisition, the Company gained access to screw piling, pipeline anchor design and manufacturing capabilities in Canada and the United States. The Company also gained oil and gas storage tank repair and maintenance capabilities which complement the Company’s existing service offering. The transaction was accounted for using the acquisition method with the results of operations included in the financial statements from the date of acquisition. Acquisition related costs were recorded in general and administrative expenses. The goodwill acquired is deductible for tax purposes.

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The following table summarizes the recognized amounts of the assets acquired and liabilities assumed at the acquisition date:

Accounts receivable	$7,064
Inventories	1,646
Prepaid expenses and deposits	45
Plant and equipment	1,346
Intangible assets	7,284
Accounts payable	(1,674	)
Total identifiable net assets	$15,711
Goodwill	7,790
Total consideration	$23,501

b) Acquisitions in fiscal 2010

On August 1, 2009, the Company acquired all of the issued and outstanding shares of DF Investments Limited and its subsidiary Drillco Foundation Co. Ltd., a piling company based in Milton, Ontario, for consideration of $5,410. This acquisition provided the Company access to piling markets and customers in the Toronto area. The transaction was 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 following table summarizes the recognized amounts of the assets acquired and liabilities assumed at the acquisition date:

Accounts receivable	$4,101
Inventories	59
Prepaid expenses and deposits	11
Property, plant and equipment	2,873
Land	281
Intangible assets	547
Accounts payable and accrued liabilities	(2,211	)
Deferred tax liabilities	(838	)
Long term debt	(652	)
Total identifiable net assets	$4,171
Goodwill	1,239
Total consideration	$5,410

7. Accounts receivable

	March 31, 2012			March 31, 2011
Accounts receivable – trade		$180,917			$115,660
Accounts receivable – holdbacks		32,134			12,018
Income and other taxes receivable		–			397
Accounts receivable – other		1,288			437
Allowance for doubtful accounts (note 21(d))		(210	)		(30	)
		$214,129			$128,482

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. Holdbacks include $6,038 as of March 31, 2012 (March 31, 2011– $587) which relate to contracts whereby the normal operating cycle is greater than one year and therefore are not expected to be collected within a year.

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

	March 31, 2012			March 31, 2011
Costs incurred and estimated earnings on uncompleted contracts		$587,220			$946,482
Less billings to date		(509,511	)		(845,547	)
		$77,709			$100,935

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

	March 31, 2012			March 31, 2011
Unbilled revenue		$86,859			$102,939
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		(7,514	)		(2,004	)
		$79,345			$100,935

16 2012 Annual Report

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Unbilled revenue related to non-construction activities amounted to $1,636 (March 31, 2011– $nil).

An amount of $18,080 (March 31, 2011 – $72,025) is recognized within unbilled revenue relating to a single long-term customer contract, whereby the normal operating cycle for this project is greater than one year. As described in Note 2(b) the estimated balances within unbilled revenue are subject to uncertainty concerning ultimate realization.

9. Inventories

	March 31, 2012		March 31, 2011
Spare tires		$6,620		$3,794
Job materials		2,188		2,118
Manufacturing raw materials		1,669		926
Finished goods		1,378		897
		$11,855		$7,735

10. Prepaid expenses and deposits

Current:
	March 31, 2012		March 31, 2011
Prepaid insurance and property taxes		$1,257		$1,022
Prepaid lease payments		4,624		6,203
Prepaid interest		434		1,044
		$6,315		$8,269
Long term:
	March 31, 2012		March 31, 2011
Prepaid lease payments (note 12(a))		$895		$2,354

11. Investment in and advances to unconsolidated joint venture

The Company was engaged in a joint venture, Noramac Joint Venture (JV), of which the Company had joint control (50% proportionate interest). The JV was formed for the purpose of expanding the Company’s market opportunities and establishing strategic alliances in Northern Alberta. The Company owned a 49% interest in Noramac Ventures Inc., a nominee company established by the two joint venture partners. On March 25, 2011, the Company and its joint venture partner decided to wind up Noramac Ventures Inc. and terminate the joint venture. At March 31, 2012 and 2011, the assets and liabilities of the joint venture are stated at the lower of carrying value and fair market value less costs to sell. The difference between carrying value and fair market value of assets and liabilities was recognized in the income statement of the joint venture during the years ended March 31, 2012 and 2011.

As of March 31, 2012, the Company’s investment in and advances to the unconsolidated joint venture totalled $1,574 (2011 – $1,488; 2010 – $2,917). The condensed financial data for investment in and advances to unconsolidated joint venture is summarized as follows:

				March 31, 2012		March 31, 2011
Current assets					$6,556		$8,328
Current liabilities					10,716		13,875
Year ended March 31,	2012			2011		2010
Gross revenues		$1,922			$12,196		$8,774
Gross (profit) loss		1,922			2,483		(1,610	)
Net (income) loss		(172	)		5,440		(87	)
Equity in (earnings) loss of unconsolidated joint venture		($86	)		$2,720		$(44	)

12. Other assets

a) Other assets are as follows:

	March 31, 2012		March 31, 2011
Prepaid lease payments (note 10)		$895		$2,354
Assets held for sale (note 12(b) and 21(a))		1,841		721
Intangible assets (note 12(c))		12,866		16,161
Deferred financing costs (note 12(d))		6,141		7,672
		$21,743		$26,908

2012 Annual Report 17

b) Assets held for sale

Equipment disposal decisions are made using an approach in which a target life 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 target operating cost for the fleet or if the expected reliability is lower than the target reliability of the fleet, the unit is considered for disposal. 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, 2012, impairment of assets held for sale amounting to $8,748, largely due to the writedown of several haul trucks to fair value, have been included in depreciation expense in the Consolidated Statements of Operations (2011 – $141; 2010 – $806). The impairment charge is the amount by which the carrying value of the related assets exceeded their fair value less costs to sell. Gain on disposal of assets held for sale was $466 for the year ended March 31, 2012 (2011 – loss of $825; 2010 – loss of $373).

c) Intangible assets

March 31, 2012	Cost		Accumulated Amortization		Net Book Value
Customer relationships and backlog		$4,442		$1,445		$2,997
Other intangible assets		2,364		1,204		1,160
Internal-use software		16,825		9,644		7,181
Patents		2,017		489		1,528
		$25,648		$12,782		$12,866
March 31, 2011	Cost		Accumulated Amortization		Net Book Value
Customer relationships and backlog		$4,442		$755		$3,687
Other intangible assets		2,364		779		1,585
Internal-use software		15,469		6,441		9,028
Patents		2,017		156		1,861
		$24,292		$8,131		$16,161

During the year ended March 31, 2012, the Company capitalized $3,537 (2011 – $4,748; 2010 – $3,362) related to internally developed computer software. Internal use software with a cost of $607 and accumulated amortization of $358 was written off and the net book value of $249 was included in amortization of intangible assets during the year ended March 31, 2012 (2011 – $nil; 2010 – $208).

Amortization of intangible assets for the year ended March 31, 2012 was $5,702 (2011 – $3,540; 2010 – $1,719). The estimated amortization expense for future years is as follows:

For the year ending March 31,
2013	$4,325
2014	3,625
2015	2,474
2016	1,574
2017 and thereafter	868
	$12,866

During the year ended March 31, 2011, $7,284 in additions were made to intangible assets as a result of the acquisition of the assets of Cyntech Corporation and its wholly-owned subsidiary Cyntech Anchor Systems LLC (note 6(a)).

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 6(b)).

18 2012 Annual Report

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d) Deferred financing costs

March 31, 2012	Cost		Accumulated Amortization		Net Book Value
Term and revolving facilities		$5,422		$4,652		$770
Series 1 Debentures		6,886		1,515		5,371
		$12,308		$6,167		$6,141
March 31, 2011	Cost		Accumulated Amortization		Net Book Value
Term and revolving facilities		$5,362		$3,855		$1,507
Series 1 Debentures		6,886		721		6,165
		$12,248		$4,576		$7,672

During the year ended March 31, 2012, financing fees of $60 were incurred in connection with the modifications made to the amended and restated credit agreement (2011 – $1,034; 2010 – $1,123) (note 15(b)). During the year ended March 31, 2012, financing fees of $nil were incurred in connection with the Series 1 Debentures (2011 – $5,846) (note 15(e)). These fees have been recorded as deferred financing costs and are being amortized using the effective interest method over the term of the credit agreement and the series 1 Debentures, respectively.

Amortization of deferred financing costs included in interest expense for the year ended March 31, 2012 was $1,591 (2011–$1,609; 2010 – $3,348). Upon redemption of the 8 ³/4% senior notes on April 28, 2010, the unamortized deferred financing costs related to the 8 ³/4% senior notes of $4,324 were expensed and included in the loss on debt extinguishment (note 15(d)). In addition, $183 related to amortization of deferred financing costs incurred up to the redemption date was included in interest expense.

13. Property, plant and equipment

March 31, 2012	Cost		Accumulated Deprecation		Net Book Value
Heavy equipment		$347,699		$124,982		$222,717
Major component parts in use		74,444		28,741		45,703
Other equipment		35,736		17,017		18,719
Licensed motor vehicles		27,120		19,775		7,345
Office and computer equipment		13,438		8,977		4,461
Buildings		4,355		3,235		1,120
Land		281		–		281
Leasehold improvements		6,620		2,232		4,388
Assets under capital lease		16,579		8,538		8,041
		$526,272		$213,497		$312,775

March 31, 2011	Cost		Accumulated Deprecation		Net Book Value
Heavy equipment		$341,734		$108,051		$233,683
Major component parts in use		47,248		15,593		31,655
Other equipment		31,877		14,136		17,741
Licensed motor vehicles		21,368		16,592		4,776
Office and computer equipment		12,128		5,899		6,229
Buildings		21,657		8,176		13,481
Land		281		–		281
Leasehold improvements		9,422		3,856		5,566
Assets under capital lease		19,506		11,054		8,452
		$505,221		$183,357		$321,864

Assets under capital lease are comprised predominately of licensed motor vehicles.

During the year ended March 31, 2012, additions to property, plant and equipment included $7,215 of assets that were acquired by means of capital leases (2011 – $427; 2010 – $1,523). Depreciation of equipment under capital lease of $2,005 (2011 – $2,723; 2010 – $4,081) was included in depreciation expense.

2012 Annual Report 19

14. Accrued liabilities

	March 31, 2012		March 31, 2011
Accrued interest payable		$9,866		$9,866
Payroll liabilities		15,228		11,412
Liabilities related to equipment leases		4,238		7,518
Income and other taxes payable		7,463		4,018
		$36,795		$32,814

15. Long term debt

a) Long term debt are as follows:

Current:
	March 31, 2012			March 31, 2011
Credit facilities (note 15(b))		$10,000			$10,000
Capital lease obligations (note 15(c))		4,402			$4,862
		$14,402			$14,862
Long term:
	March 31, 2012			March 31, 2011
Credit facilities (note 15(b))		$68,767			$61,970
Capital lease obligations (note 15(c))		6,299			3,831
Series 1 Debentures (note 15(e))		225,000			225,000
		$300,066			$290,801
b) Credit Facilities
	March 31, 2012			March 31, 2011
Term A Facility		$20,950			$24,698
Term B Facility		37,496			43,748
Total term facilities		$58,446			$68,446
Revolving Facility		20,321			3,524
Total credit facilities		$78,767			$71,970
Less: current portion of term facilities		(10,000	)		(10,000	)
		$68,767			$61,970

As of March 31, 2012, the Company had outstanding borrowings of $58.4 million (March 31, 2011 – $68.4 million) under the term facilities, $20.3 million (March 31, 2011 – $3.5 million) under the Revolving Facility and had issued $15.0 million (March 31, 2011 – $12.3 million) in letters of credit under the Revolving Facility to support performance guarantees associated with customer contracts. The funds available for borrowing under the Revolving Facility are reduced by any outstanding letters of credit.

Effective September 30, 2011, the Company entered into a Second Amending Agreement to the Fourth Amended and Restated Credit Agreement to provide a temporary increase in the amount available under the Revolving Facility from $85 million to $110.0 million. This increase, which was to remain in effect until March 31, 2012, provided additional borrowing availability to meet working capital requirements and to accommodate the issuance of letters of credit. The receipt of proceeds resulting from the settlement of the Canadian Natural Resources Limited (Canadian Natural) contract negotiations were to be used to repay amounts outstanding on the Revolving Facility and the amount available for borrowing under the temporary addition was to be permanently reduced by the amount of the settlement proceeds received on December 22, 2011. The amount available under the temporary increase was reduced by the $4.3 million received from Canadian Natural, resulting in a reduction in the total amount available under the Revolving Facility to $105.7 million.

In March 2012, the Company entered into a Third Amending Agreement to the Fourth Amended and Restated Credit Agreement to extend the maturity date of the credit agreement by six months to October 31, 2013 and temporarily amended Consolidated EBITDA related covenants as defined within the credit agreement to maintain covenant compliance at year end. The amendment also extended the term of the temporary increase to the Company’s revolving credit facility to June 30, 2012. The Company’s unused borrowing availability under the Revolving Facility was $70.4 million at March 31, 2012. As defined in the agreement, 55% of the proceeds received from Canadian Natural will be used to prepay the outstanding principal and accrued interest under the temporary addition.

20 2012 Annual Report

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Interest on Canadian prime rate loans is paid at variable rates based on the Canadian prime rate plus the applicable pricing margin (as defined in 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 Canadian prime rate 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. Stamping fees and interest related to the issuance of Bankers’ Acceptances is paid in advance upon the issuance of such Bankers’ Acceptance. The weighted average interest rate on Revolving Facility and Term Facility borrowings at March 31, 2012 was 6.92%.

The credit facilities are secured by a first priority lien on substantially all of the Company’s existing and after-acquired property and contain certain restrictive covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions, paying dividends or redeeming shares of capital stock.

c) 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:

2013	$4,693
2014	2,230
2015	1,938
2016	2,209
2017	651
Subtotal:	$11,721
Less: amount representing interest	(1,020	)
Present value of minimum lease payments	$10,701
Less: current portion	(4,402	)
Long term portion	$6,299

d) 8 ³/4% Senior Notes

The 8 ³/4% senior notes were issued on November 26, 2003 in the amount of US $200.0 million (Canadian $263.0 million). On April 28, 2010, the Company redeemed the 8 ³/4% senior notes for $202,410 and recorded a $4,346 loss on debt extinguishment including a $4,324 write off of deferred financing costs (note 12(d)).

e) Series 1 Debentures

On April 7, 2010, the Company issued $225.0 million of 9.125% Series 1 Debentures (the “Series 1 Debentures”). The Series 1 Debentures mature on April 7, 2017. The Series 1 Debentures bear interest at 9.125% per annum and such interest is payable in equal instalments semi-annually in arrears on April 7 and October 7 in each year, commencing on October 7, 2010.

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 the Company or any of its subsidiaries. The Series 1 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 Series 1 Debentures with the net cash proceeds of one or more 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 Series 1 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 Series 1 Debentures, in whole or in part, at a redemption price which is equal to the greater of (a) the Canada Yield Price (as defined in the trust indenture) and (b) 100% of the aggregate principal amount of Series 1 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 Series 1 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 Series 1 Debentures, at a purchase price in cash equal to 101% of the principal amount of the Series 1 Debentures offered for repurchase plus accrued interest to the date of purchase.

2012 Annual Report 21

16. Other long term obligations

a) Other long term obligations are as follows:

	March 31, 2012			March 31, 2011
Long term portion of liabilities related to equipment leases		$3,169			$12,747
Deferred lease inducements (note 16(b))		547			654
Asset retirement obligation (note 16(c))		434			395
Senior executive stock option plan (note 27(c))		1,322			5,115
Restricted share unit plan (note 27(e))		3,170			2,633
Director’s deferred stock unit plan (note 27(f))		2,284			4,032
		$10,926			$25,576
Less: current portion of restricted share unit plan (note 27(e))		(2,066	)		–
		$8,860			$25,576

b) Deferred lease inducements

Lease inducements applicable to lease contracts are deferred and amortized as a reduction of general and administrative expenses 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, 2012			March 31, 2011
Balance, beginning of year		$654			$761
Amortization of deferred lease inducements		(107	)		(107	)
Balance, end of year		$547			$654

c) 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.

The following table presents a continuity of the liability for the asset retirement obligation:

	March 31, 2012		March 31, 2011
Balance, beginning of year		$395		$360
Accretion expense		39		35
Balance, end of year		$434		$395

At March 31, 2012, estimated undiscounted cash flows required to settle the obligation were $1,084 (March 31, 2011 – $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.

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17. Income taxes

Income tax (benefit) provision 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,	2012			2011			2010
(Loss) income before income taxes	$	(28,385	)		$(41,098	)		$41,898
Tax rate		26.25%			27.75%			28.91%
Expected (benefit) expense		$(7,451	)		$(11,405	)		$12,113
Increase (decrease) related to:
Impact of enacted future statutory income tax rates		278			164			(673	)
Income tax adjustments and reassessments		313			909			1,442
Valuation allowance		(91	)		962			–
Stock-based compensation		(393	)		1,443			617
Non deductible portion of capital losses		–			1,063			–
Other		121			416			180
Income tax (benefit) expense		$(7,223	)		$(6,448	)		$13,679
Classified as:
		2012			2011			2010
Year ended March 31,
Current income tax (benefit) expense		$(677	)		$2,892			$3,803
Deferred income tax (benefit) expense		(6,546	)		(9,340	)		9,876
		$(7,223	)		$(6,448	)		$13,679

The deferred tax assets and liabilities are summarized below:

	March 31, 2012			March 31, 2011
Deferred tax assets:
Non-capital losses carried forward		$51,614			$41,581
Derivative financial instruments		2,296			2,895
Billings in excess of costs on uncompleted contracts		1,887			508
Capital lease obligations		2,689			2,247
Intangible assets		–			473
Long term portion of liabilities related to equipment leases		–			2,029
Deferred lease inducements		134			161
Stock-based compensation		1,402			1,656
Other		420			99
		$60,442			$51,649
	March 31, 2012			March 31, 2011
Deferred tax liabilities:
Unbilled revenue and uncertified revenue included in accounts receivable		$13,039			$24,418
Assets held for sale		462			189
Accounts receivable – holdbacks		8,071			3,154
Property, plant and equipment		52,323			44,105
Deferred financing costs		224			71
Intangible assets		8			76
Other		173			40
		$74,300			$72,053
Net deferred income tax liability		$(13,858	)		$(20,404	)

Classified as:

	March 31, 2012			March 31, 2011
Current asset		$2,991			$1,729
Long term asset		57,451			49,920
Current liability		(21,512	)		(27,612	)
Long term liability		(52,788	)		(44,441	)
		$(13,858	)		$(20,404	)

2012 Annual Report 23

The Company and its subsidiaries file income tax returns in the Canadian federal jurisdiction, five provincial jurisdictions and US federal and Texas state jurisdiction. For years before 2007, the Company is no longer subject to Canadian federal or provincial examinations.

The Company has a full valuation allowance against capital losses in deferred tax benefits of $962 as at March 31, 2012 (2011 – $962; 2010 – $nil). At March 31, 2012, the Company has non-capital losses for income tax purposes of $205,565 which predominately expire after 2027.

	March 31, 2012
2027		$2,973
2028		7,222
2029		13,676
2030		25,707
2031		93,267
2032		62,720
		$205,565

18. Shares

a) Common shares

Authorized:

Unlimited number of voting common shares

Unlimited number of non-voting common shares

Issued and outstanding:

	Number of Shares		Amount
Voting common shares
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
Issued upon exercise of stock options		193,250		963
Transferred from additional paid-in capital on exercise of stock options		–		386
Issued and outstanding at March 31, 2011		36,242,526		$304,854
Issued upon exercise of stock options		8,480		35
Transferred from additional paid-in capital on exercise of stock options		–		19
Issued and outstanding at March 31, 2012		36,251,006		$304,908

b) Net (loss) income per share

	2012			2011			2010
Year ended March 31,
Net (loss) income available to common shareholders		$(21,122	)		$(34,709	)		$28,219
Weighted average number of common shares		36,249,082			36,119,356			36,040,857
Basic net (loss) income per share		$(0.58	)		$(0.96	)		$0.78
	2012			2011			2010
Year ended March 31,
Net (loss) income available to common shareholders		$(21,122	)		$(34,709	)		$28,219
Weighted average number of common shares		36,249,082			36,119,356			36,040,857
Dilutive effect of stock options, deferred performance share units and stock award plan		–			–			680,169
Weighted average number of diluted common shares		36,249,082			36,119,356			36,721,026
Diluted net (loss) income per share		$(0.58	)		$(0.96	)		$0.77

For the year ended March 31, 2012, there were 1,834,794 and 50,000 stock options and stock awards, respectively, which were anti-dilutive (March 31, 2011 – 1,647,474, 75,591 and 150,000 stock options, deferred performance share units and stock awards, respectively; March 31, 2010 – 820,641 and 57,311 stock options and deferred performance share units, respectively) and therefore were not considered in computing diluted earnings per share.

24 2012 Annual Report

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19. Interest expense

	2012		2011		2010
Year ended March 31,
Interest on 8 3/4% senior notes and swaps		$–		$1,238		$19,041
Interest on capital lease obligations		445		689		1,032
Amortization of deferred financing costs		1,591		1,609		3,348
Interest on credit facilities		7,430		5,361		2,375
Interest on Series 1 Debentures		20,531		20,132		–
Interest on long term debt		$29,997		$29,029		$25,796
Other interest		328		962		284
		$30,325		$29,991		$26,080

20. Claims revenue

	2012		2011		2010
Year ended March 31,
Claims revenue recognized		$35,211		$5,278		$4,541
Claims revenue uncollected (classified as unbilled revenue)		22,759		2,174		785

21. Financial instruments and risk management

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. Standard market conventions and techniques, such as discounted cash flow analysis and option pricing models, are used to determine the fair value of the Company’s financial instruments, including derivatives. All methods of fair value measurement result in a general approximation of value and such value may never actually be realized.

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 Credit Facilities 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 $78.8 million at March 31, 2012 and $72.0 million at March 31, 2011 (note 15 (b)), the fair value of amounts due under the Credit Facilities as at March 31, 2012 and March 31, 2011 are not significantly different than their carrying value.

Financial instruments with carrying amounts that differ from their fair values are as follows:

	March 31, 2012				March 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Capital lease obligations (i)		$10,701		$10,657		$8,693		$8,658
Series 1 Debentures (ii)		225,000		203,624		225,000		238,651

(i) 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.

(ii) The fair value of the Series 1 Debentures is based upon the expected discounted cash flows and the period end market price of similar financial instruments.

a) Fair value measurements

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.

The fair values of 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 including foreign currency rates, implied volatilities and discount factors 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 futures 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 effect of such variations could be material.

2012 Annual Report 25

At March 31, 2012, the Company had no financial assets or financial liabilities measured at fair value on a recurring basis which were 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, these fair value measurements are classified as Level 2 of the fair value hierarchy. Financial assets and liabilities measured at fair value net of accrued interest on a recurring basis, all of which are classified as “Derivative financial instruments” on the Consolidated Balance Sheets are summarized below:

March 31, 2012	Carrying Amount
Embedded price escalation features in certain long term supplier contracts		$9,146
Less: current portion		(3,220	)
		$5,926
March 31, 2011	Carrying Amount
Embedded price escalation features in a long term customer construction contract		$5,877
Embedded price escalation features in certain long term supplier contracts		5,651
		$11,528
Less: current portion		(2,474	)
		$9,054

On April 8, 2010, the Company settled the cross-currency and interest rate swaps, including accrued interest for a total of $91,125 in conjunction with the settlement of the 8 ³/4% senior notes (note 15 (d)).

The realized and unrealized (gain) loss on derivative financial instruments is comprised as follows:

Year ended March 31,	2012			2011			2010
Realized and unrealized loss on cross-currency and interest rate swaps		$–			$2,111			$64,637
Unrealized (gain) loss on embedded price escalation features in a long term customer construction contract		(5,877	)		(604	)		6,805
Unrealized loss (gain) on embedded price escalation features in certain long term supplier contracts		3,495			(3,812	)		(13,315	)
Unrealized gain on early redemption option on 8 3/4% senior notes		–			–			(3,716	)
		$(2,382	)		$(2,305	)		$54,411

Non-financial assets that were measured at fair value on a non-recurring basis as at March 31, 2012 and 2011 in the financial statements are summarized below:

	March 31, 2012					March 31, 2011
	Carrying Amount		Change in Fair Value			Carrying Amount		Change in Fair Value
Assets held for sale		$1,841		$(8,748	)		$721		$(141	)

Assets held for sale are measured at fair value less cost to sell on a non-recurring basis. For the year ended March 31, 2012, assets held for sale with a carrying amount of $10,589 (2011 – $862) were written down to their fair value less cost to sell of $1,841 (2011 – $721), resulting in a loss of $8,748 (2011 – $141), which was included in depreciation expense in the Consolidated Statements of Operations. The fair value less cost to sell of the assets held for sale is determined internally by analyzing recent auction prices for equipment with similar specifications and hours used, 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.

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.

26 2012 Annual Report

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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

The Company regularly transacts in foreign currencies when purchasing equipment and 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 US Dollar for these short term transactions, if material.

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. Interest expense on borrowings with floating interest rates, including the Company’s Credit Facilities, varies as market interest rates change. At March 31, 2012, the Company held $78.8 million of floating rate debt pertaining to its Credit Facilities (March 31, 2011 – $72.0 million). As at March 31, 2012, holding all other variables constant, a 100 basis point change to interest rates on floating rate debt will result in $0.8 million corresponding change in annual interest expense. This assumes that the amount of floating rate debt remains unchanged from that which was held at March 31, 2012.

The fair value of financial instruments with fixed interest rates, such as the Company’s Series 1 Debentures, fluctuate with changes in market interest rates. However, these fluctuations 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.

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.

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 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, 2012 and March 31, 2011, the following customers represented 10% or more of accounts receivable and unbilled revenue:

	March 31, 2012		March 31, 2011
Customer A		31%		40%
Customer B		11%		5%
Customer C		10%		14%
Customer D		3%		12%

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 project costs in the Consolidated Statements of Operations 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, 2012		March 31, 2011
Trade accounts receivables		$213,051		$127,678
Other receivables		1,078		804
Total accounts receivable		$214,129		$128,482
Unbilled revenue		$86,859		$102,939

2012 Annual Report 27

On a geographic basis as at March 31, 2012, approximately 95% (March 31, 2011 – 95%) 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, 2012 and 2011, trade receivables are aged as follows:

	March 31, 2012		March 31, 2011
Not past due		$166,362		$98,626
Past due 1-30 days		27,617		18,911
Past due 31-60 days		8,476		3,444
More than 61 days (including holdbacks of $nil (2011 $nil))		10,596		6,697
Total		$213,051		$127,678

As at March 31, 2012, the Company has recorded an allowance for doubtful accounts of $210 (March 31, 2011 – $30) of which 100% relates to amounts that are more than 61 days past due.

The allowance is an estimate of the March 31, 2012 trade receivable balances that are considered uncollectible. Changes to the allowance are as follows:

Year ended March 31,	2012		2011			2010
Opening balance		$30		$1,691			$2,597
Payments received on provided balances		–		(682	)		(846	)
Current year allowance		180		518			334
Write-offs		–		(1,497	)		(394	)
Ending balance		$210		$30			$1,691

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.

22. Other information

a) Supplemental cash flow information

Year ended March 31,	2012			2011			2010
Cash paid during the year for:
Interest, including realized interest on interest rate swap		$27,521			$33,559			$49,999
Income taxes		1,415			4,149			10,395
Cash received during the year for:
Interest		1			1,168			10,998
Income taxes		5,347			2,260			453
Non-cash transactions:
Acquisition of property, plant and equipment by means of capital leases		7,215			427			1,523
Additions to assets held for sale		(10,322	)		(1,675	)		(1,739	)
Net increase (decrease) in accounts payable related to purchase of property, plant and equipment		1,380			(3,879	)		1,840
Disposition of property, plant and equipment related to the buyout of contract-related assets		(27,063	)		–			–
Disposition of intangible assets related to the buyout of contract-related assets		(1,119	)		–			–
Increase in accounts receivable related to the buyout of contract-related assets		66,055			–			–
Decrease in unbilled revenue related to the buyout of contract-related assets		(16,457	)		–			–
Decrease in inventory related to the buyout of contract-related assets		(8,483	)		–			–
Increase in accounts payable related to the buyout of contract-related assets		12,933			–			–
Increase in accrued liabilities related to current portion of RSU liability		2,066			–			–

b) Net change in non-cash working capital

Year ended March 31,	2012			2011			2010
Operating activities:
Accounts receivable, net		$(19,592	)		$(9,534	)		$(29,428	)
Unbilled revenue		(377	)		(18,237	)		(28,795	)
Inventories		(12,603	)		(2,661	)		6,214
Prepaid expenses and deposits		3,413			308			(2,620	)
Accounts payable		70,764			21,382			6,620
Accrued liabilities		1,915			(5,434	)		1,150
Long term portion of liabilities related to equipment leases		(9,578	)		(2,196	)		7,809
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		5,510			390			(541	)
		$39,452			$(15,982	)		$(39,591	)

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23. Segmented information

a) General overview

The Company operates in the following reportable business segments, which follow the organization, management and reporting structure within the Company:

• Heavy Construction and Mining:

The Heavy Construction and Mining segment provides mining and site preparation services, including overburden removal and reclamation services, project management, underground utility construction, equipment rental to a variety of customers, environmental services including construction and modification of tailing ponds and reclamation of completed mine sites to environmental standards throughout Canada.

• Piling:

The Piling segment provides deep foundation construction and design build services to a variety of industrial and commercial customers throughout Western Canada and Ontario. It also designs and manufactures screw piles and pipeline anchoring systems and provides tank maintenance services to the petro-chemical industry across Canada and the United States and sells pipeline anchoring systems globally.

• 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 2. Certain business units of the Company have been aggregated into the Heavy Construction and Mining segment as they have similar economic characteristics based on 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, 2012	Heavy Construction and Mining		Piling		Pipeline			Total
Revenue from external customers		$670,720		$185,321		$150,504			$1,006,545
Depreciation of property, plant and equipment		35,804		3,912		1,045			40,761
Segment profits (loss)		86,567		46,012		(11,322	)		121,257
Segment assets		426,625		142,131		70,602			639,358
Capital expenditures		42,001		12,570		4,110			58,681
For the year ended March 31, 2011	Heavy Construction and Mining		Piling		Pipeline			Total
Revenue from external customers		$667,037		$105,559		$85,452			$858,048
Depreciation of property, plant and equipment		28,832		3,636		550			33,018
Segment profits (loss)		50,703		18,455		(3,034	)		66,124
Segment assets		423,947		116,623		37,053			577,623
Capital expenditures		29,577		2,560		1,124			33,261
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 (loss)		111,016		11,288		(3,851	)		118,453
Segment assets		435,098		92,980		14,765			542,843
Capital expenditures		40,431		1,081		948			42,460

2012 Annual Report 29

c) Reconciliations

i) Income (loss) before income taxes

Year ended March 31,	2012			2011			2010
Total profit for reportable segments		$121,257			$66,124			$118,453
Less: Unallocated equipment costs (recoveries) (i)		60,356			7,988			(20,832	)
Gross profit		$60,901			$58,136			$139,285
Less: unallocated corporate items:
General and administrative expenses		54,400			59,828			62,516
Loss on disposal of property, plant and equipment		1,741			1,948			1,233
(Gain) loss on disposal of assets held for sale		(466	)		825			373
Amortization of intangible assets		5,702			3,540			1,719
Equity in (earnings) loss of unconsolidated joint venture		(86	)		2,720			(44	)
Interest expense, net		30,325			29,991			26,080
Foreign exchange loss (gain)		52			(1,659	)		(48,901	)
Realized and unrealized (gain) loss on derivative financial instruments		(2,382	)		(2,305	)		54,411
Loss on debt extinguishment		–			4,346			–
(Loss) income before income taxes		$(28,385	)		$(41,098	)		$41,898

(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 the reportable segment exceed actual equipment costs incurred.

ii) Total assets

	March 31, 2012		March 31, 2011
Corporate assets:
Cash and cash equivalents		$1,400		$722
Property, plant and equipment		23,017		24,831
Deferred tax assets		60,442		51,649
Other		25,776		28,132
Total corporate assets		$110,635		$105,334
Total assets for reportable segments		639,358		577,623
Total assets		$749,993		$682,957

The Company’s goodwill of $32,901 is assigned to the Piling segment. All of the Company’s assets are located in Canada and the United States.

iii) Depreciation of property, plant and equipment

Year ended March 31,	2012		2011		2010
Total depreciation for reportable segments		$40,761		$33,018		$37,414
Depreciation for corporate assets		8,139		6,422		5,222
Total depreciation		$48,900		$39,440		$42,636

iv) Capital expenditures for long-lived assets

Year ended March 31,	2012		2011		2010
Total capital expenditures for reportable segments		$58,681		$33,261		$42,460
Capital expenditures for corporate assets		6,615		7,904		12,790
Total capital expenditures for long-lived assets		$65,296		$41,165		$55,250

d) Customers

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

Year ended March 31,	2012		2011		2010
Customer A		21%		29%		51%
Customer B		16%		8%		5%
Customer C		11%		10%		9%
Customer D		10%		24%		19%

The revenue by major customer was earned mainly by the Heavy Construction and Mining segment.

30 2012 Annual Report

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e) Geographic information

i) The geographic revenue distribution for the Company is as follows:

Year ended March 31,	2012		2011		2010
Canada		$996,916		$855,963		$758,965
International		6,935		1,046		–
United States		2,694		1,039		–
		$1,006,545		$858,048		$758,965

ii) The geographic distribution of long-lived assets is as follows:

	March 31, 2012		March 31, 2011
Canada		$367,240		$381,577
United States		179		96
		$367,419		$381,673

24. Related party transactions

Sterling Group Partners I, L.P., Perry Partners, L.P. and Perry Partners International, Inc. 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.

There were no material related party transactions during the years ended March 31, 2012, 2011 and 2010. 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.

25. 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,
2013	$54,542
2014	38,553
2015	19,014
2016	4,248
2017 and thereafter	–
	$116,357

Total contingent rentals on operating leases consisting principally of usage (recoveries) charges in excess of minimum contracted amounts for the years ended March 31, 2012, 2011 and 2010 amounted to $(8,449), $1,881 and $10,246 respectively.

26. Employee benefit plans

The Company and its subsidiaries match voluntary contributions made by 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, 2012 were $2,083 (2011 – $1,689; 2010 — $1,393).

27. Stock-based compensation

a) Stock-based compensation expenses

Stock-based compensation expenses included in general and administrative expenses are as follows:

Year ended March 31,	2012			2011			2010
Share option plan (note 27(b))		$1,373			$1,455			$2,135
Senior executive stock option plan (note 27(c))		(2,878	)		2,878			–
Deferred performance share unit plan (note 27(d))		–			(44	)		123
Restricted share unit plan (note 27(e))		733			1,603			1,010
Director’s deferred stock unit plan (note 27(f))		(1,747	)		1,484			2,002
Stock award plan (note 27(g))		256			780			–
		$(2,263	)		$8,156			$5,270

2012 Annual Report 31

b) Share option plan

Under the 2004 Amended and Restated Share Option Plan, which was approved and became effective in 2006, 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, 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
Granted		260,000			9.77
Exercised(i)		(193,250	)		4.98
Forfeited		(120,080	)		10.30
Modified(ii)		(550,000	)		5.00
Outstanding at March 31, 2011		1,647,474			9.25
Granted		287,700			6.56
Exercised(i)		(8,480	)		4.15
Forfeited		(91,900	)		10.42
Outstanding at March 31, 2012		1,834,794			8.79

(i) All stock options exercised resulted in new common shares being issued (note 18(a));

(ii) 550,000 stock options were modified as senior executive stock options on September 22, 2010 (note 27(c)).

Cash received from the option exercises for the year ended March 31, 2012 was $35 (2011—$963; 2010 – $53). Cash paid for options settled for cash for the year ended March 31, 2012 was $nil (2011 – $nil; 2010 – $244).The total intrinsic value of options exercised, calculated as market value at the exercise date less exercise price, multiplied by the number of units exercised, for the years ended March 31, 2012, 2011 and 2010 was $48, $1,084 and $277, respectively.

The following table summarizes information about stock options outstanding at March 31, 2012:

	Options outstanding						Options exercisable
Exercise price	Number		Weighted average remaining life		Weighted average exercise price		Number		Weighted average remaining life		Weighted average exercise price
$3.69		127,320		6.7 years		$3.69		73,840		6.7 years		$3.69
$5.00		437,294		2.7 years		$5.00		437,294		2.7 years		$5.00
$6.56		277,100		9.7 years		$6.56		–		–		–
$8.28		130,000		7.2 years		$8.28		52,000		7.2 years		$8.28
$8.58		60,000		8.5 years		$8.58		12,000		8.5 years		$8.58
$9.33		159,280		7.9 years		$9.33		64,720		7.9 years		$9.33
$10.13		174,480		8.7 years		$10.13		35,440		8.7 years		$10.13
$13.21		75,000		5.8 years		$13.21		60,000		5.8 years		$13.21
$13.50		201,560		5.7 years		$13.50		161,720		5.7 years		$13.50
$15.37		40,000		6 years		$15.37		32,000		6 years		$15.37
$16.01		75,000		6 years		$16.01		45,000		6 years		$16.01
$16.46		50,000		6 years		$16.46		30,000		6 years		$16.46
$16.75		27,760		4.5 years		$16.75		27,760		4.5 years		$16.75
		1,834,794		6.3 years		$8.79		1,031,774		4.8 years		$8.82

At March 31, 2012, the weighted average remaining contractual life of outstanding options is 6.3 years (March 31, 2011 – 6.8 years). The fair value of options vested during the year ended March 31, 2012 was $1,652 (March 31, 2011 – $1,892). At March 31, 2012, the Company had 1,031,774 exercisable options (March 31, 2011 – 830,482) with a weighted average exercise price of $8.82 (March 31, 2011 – $8.52).

At March 31, 2012, the total compensation costs related to non-vested awards not yet recognized was $2,655 (March 31, 2011 – $2,973) and these costs are expected to be recognized over a weighted average period of 3.2 years (March 31, 2011 – 3.4 years).

32 2012 Annual Report

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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,	2012		2011		2010
Number of options granted		287,700		260,000		375,700
Weighted average fair value per option granted ($)		4.38		6.79		6.25
Weighted average assumptions:
Dividend yield		Nil%		Nil%		Nil%
Expected volatility		75.22%		78.59%		76.27%
Risk-free interest rate		1.32%		2.65%		3.39%
Expected life (years)		6.3		6.1		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.

c) Senior executive stock option plan

On September 22, 2010, the Company modified a senior executive employment agreement to allow the option holder the right to settle options in cash which resulted in 550,000 stock options (senior executive stock options) changing classification from equity to a long term liability. The liability is measured at fair value using the Black-Scholes model at the modification date and subsequently at each period end date. Previously recognized compensation cost related to the senior executive stock option plan of $2,237 was transferred from additional paid-in capital to the senior executive stock option liability on the modification date. The fair value of the compensation liability is calculated using the Black-Scholes model at each period end. Changes in fair value of the liability are recognized in the Consolidated Statements of Operations.

The weighted average assumptions used in estimating the fair value of the senior executive stock options as at March 31, 2012 are as follows:

Year ended March 31,	2012		2011
Number of senior executive stock options		550,000		550,000
Weighted average fair value per option granted ($)		2.40		9.3
Weighted average assumptions:
Dividend yield		Nil%		Nil%
Expected volatility		74.99%		76.74%
Risk-free interest rate		0.54%		1.77%
Expected life (years)		3.11		4.10

d) Deferred performance share unit plan

The company has no outstanding Deferred Performance Share Units (“DPSUs”) at this time. DPSUs were granted each fiscal year with respect of services to be provided in that fiscal year and the following two fiscal years. The DPSUs vested the end of a three-year term and were subject to the performance criteria approved by the Compensation Committee of the Board of Directors at the date of grant. Such performance criterion included the passage of time and was based upon return on invested capital calculated as operating income divided by average operating assets. The maturity date for such DPSUs was the last day of the third fiscal year following the grant date. At the maturity date, the Compensation Committee assesses the participant against the performance criteria and determines the number of DPSUs that were earned (earned DPSUs).

The settlement of the participant’s entitlement was made at the Company’s option either in cash, in an amount equivalent to the number of earned DPSUs multiplied by the fair market value of the Company’s common shares as determined by the volume weighted average trading price of the Company’s common shares for the five trading days immediately preceding 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 were purchased on the open market or through the issuance of shares from treasury.

The fair value of each unit under the DPSU Plan was estimated on the date of the grant using Black-Scholes option pricing model. There were no DPSUs granted in fiscal 2011 and 2012. The weighted average assumptions used in estimating the fair value of the share options issued under the DPSU Plan during the year ended March 31, 2010 is as follows:

Number of units granted	908,165
Weighted average fair value per unit granted ($)	4.71
Weighted average assumptions:
Dividend yield	Nil%
Expected volatility	96.89%
Risk-free interest rate	1.47%
Expected life (years)	3.00

2012 Annual Report 33

	Number of units
Outstanding at March 31, 2009		91,005
Granted		908,165
Forfeited		(102,671	)
Converted to RSUs (note 27(e))		(389,204	)
Outstanding at March 31, 2010		507,295
Forfeited		(74,776	)
Outstanding at March 31, 2011		432,519
Expired		(41,117	)
Converted to RSUs (note 27(e))		(391,402	)
Outstanding at March 31, 2012		–

On April 1, 2011, the Company converted 262,737 and 128,665 Deferred Performance Share Units (“DPSUs”) into Restricted Share Units (“RSUs”) for the April 1, 2009 and March 31, 2010 grants at a conversion factor of 50% and 75% respectively (note 27(e)).

At March 31, 2012 there were nil outstanding DPSUs. At March 31, 2011, there were 111,020 units vested and the weighted average remaining contractual life of outstanding DPSU units was 1.2 years. 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, 2011, there was approximately $242 of total unrecognized compensation cost related to non-vested share-based payment arrangements under the DPSU Plan, which was expected to be recognized over a weighted average period of 1.2 years and was subject to performance adjustments. On December 18, 2009, the Company converted 26,059 and 363,145 DPSUs into RSUs for the April 1, 2008 and April 1, 2009 grants respectively at a conversion factor of 80% (note 27(e)).

e) Restricted share unit plan

Restricted Share Units (“RSUs”) are granted 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 number of vested shares multiplied by the fair market value of each RSU as determined by the volume weighted average trading price of the Company’s common shares for the five trading days immediately preceding the day on which the fair market value is to be determined. The Company recognizes compensation expense over the three-year term of the RSU in the Consolidated Statements of Operations.

On April 1, 2011, the Company converted the April 1, 2009 and March 31, 2010 DPSUs (note 27(d)) into RSUs at a conversion factor of 50% and 75% respectively. On December 18, 2009, the Company converted certain middle manager’s DPSUs (note 27(d)) into RSUs at a conversion factor of 80%.

	Number of units
Outstanding at March 31, 2009		–
Converted from DPSUs (note 27(d))		311,358
Granted		169,489
Forfeited		(12,032	)
Outstanding at March 31, 2010		468,815
Forfeited		(86,339	)
Outstanding at March 31, 2011		382,476
Granted		695,086
Settled		(27,850	)
Forfeited		(102,022	)
Converted from DPSUs (note 27(d))		227,875
Outstanding at March 31, 2012		1,175,565

At March 31, 2012, the $2,066 current portion of RSU liabilities were included in accrued liabilities (March 31, 2011 - $nil) and long term portion of RSU liabilities of $1,104 were included in other long term obligations (March 31, 2011 — $2,633) in the Consolidated Balance Sheets. During the year ended March 31, 2012, 27,850 units vested and were settled in cash for $318.

At March 31, 2012, there were 329,901 units vested and the redemption value of these units was $4.91/unit (March 31, 2011 – $11.96/unit). At March 31, 2012, the weighted average remaining contractual life of the RSUs outstanding was 1.4 years (March 31, 2011 – 1.3 years).

34 2012 Annual Report

NOA

Using the redemption value of $4.91/unit at March 31, 2012, there was approximately $2,576 of total unrecognized compensation cost related to non–vested share–based payment arrangements under the RSU Plan and these costs are expected to be recognized over the weighted average remaining contractual life of the RSUs of 1.4 years (March 31, 2011 – 1.3 years). On approval of the RSU Plan in 2009, 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.

f) 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 expenses) 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 is determined by dividing the amount of the participant’s deferred remuneration by the Canadian Dollar equivalent of the volume weighted average trading price of the Company’s common shares for the five trading days immediately preceding the date that participants’ remuneration becomes payable. The DDSUs vest immediately upon issuance 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 five trading days immediately preceding death or retirement. Directors, who are not US taxpayers, may elect to defer the redemption date until a date no later than December 1st of the calendar year following the year in which the retirement or death occurred.

	Number of units
Outstanding at March 31, 2009		139,691
Issued		123,575
Outstanding at March 31, 2010		263,266
Issued		73,752
Outstanding at March 31, 2011		337,018
Issued		128,248
Outstanding at March 31, 2012		465,266

At March 31, 2012, the redemption value of these units was $4.91/unit (March 31, 2011 – $11.96/unit). There is no unrecognized compensation expense related to the DDSUs, since these awards vest immediately when issued.

g) Stock award plan

On September 24, 2009, the Chief Executive Officer’s (CEO) employment agreement was extended by the Board of Directors for a further period of two years, to May 8, 2012. In addition to the existing conditions in his employment agreement, as of September 24, 2010, the effective date, the CEO was granted the right to receive 150,000 common shares of the Company as follows:

• 50,000 shares on May 8, 2011;

• 50,000 shares on November 8, 2011; and

• 50,000 shares on May 8, 2012.

These shares, or at the discretion of the company, the cash equivalent thereof, will be awarded to the CEO provided he remains employed on the award dates above.

The CEO’s entitlement, upon the above release dates, shall be settled in common shares purchased on the open market or through the issuance of common shares from treasury, in each case net of required withholdings. The CEO’s entitlement may be settled with newly issued common shares from treasury, if all necessary shareholder approvals and regulatory approvals, if any, are obtained. The Company has no intention to settle in cash.

The estimate of the fair value of the stock award on the grant date is equal to the market price of the Company’s common shares.

During the year ended March 31, 2012, 100,000 stock awards vested and were settled in common shares purchased on the open market for $822. The weighted average remaining contractual life of outstanding Stock Award Plan units is 0.1 years (March 31, 2011 – 0.6 years). As at March 31, 2012, there was approximately $14 (March 31, 2011 – $270) of total unrecognized compensation cost related to non–vested share–based payment arrangements under the stock award plan, which is expected to be recognized over a weighted average period of 0.1 years (March 31, 2011 – 0.6 years).

28. 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.

29. Comparative figures

Certain of the comparative figures have been reclassified from statements previously presented to conform to the presentation of the current period consolidated financial statements.

2012 Annual Report 35

EX-99.3

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the year ended March 31, 2012

NOA

Table of Contents

A. Explanatory Notes		1
	Caution Regarding Forward-Looking Information	1
	Non-GAAP Financial Measures	1
	Significant Business Event	2
B. Business Overview		3
	Business Overview	3
	Five Year Business Performance	3
	Operations Overview	4
	Revenue by Source	4
	Revenue by End Market	5
C. Financial Results		9
	Summary of Consolidated Annual Results	9
	Segment Annual Results	11
	Summary of Consolidated Three Month Results	13
	Segment Three Month Results	14
	Non-operating Income And Expense	16
	Backlog	18
	Claims and Change Orders	19
	Summary of Consolidated Quarterly Results	19
	Summary of Consolidated Financial Position	20
	Summary of Consolidated Equipment Additions	21
	Summary of Consolidated Cash Flows	22
D. Outlook		24
E. Legal And Labour Matters		24
	Laws and Regulations and Environmental Matters	24
	Employees and Labour Relations	25
F. Resources And Systems		25
	Liquidity	25
	Long-term Commitments	28
	Securities, Rights Plans and Agreements	29
	Debt Ratings	30
	Related Parties	31
	Internal Systems and Processes	32
	Critical Accounting Estimates	32
	Accounting Pronouncements Recently Adopted	35
	Issued Accounting Pronouncements Not Yet Adopted	36
G. Forward-Looking Information, Assumptions And Risk Factors		36
	Forward-Looking Information	36
	Assumptions	38
	Risk Factors	38
H. General Matters		42
	Experts	42
	Additional Information	42

NOA

Management’s Discussion and Analysis

For the year ended March 31, 2012

A. EXPLANATORY NOTES

June 6, 2012

The following Management’s Discussion and Analysis (MD&A) is as of June 6, 2012 and should be read in conjunction with the attached audited consolidated financial statements for the year ended March 31, 2012 and notes that follow. These statements have been prepared in accordance with United States (US) generally accepted accounting principles (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 and notes there to, as well as the accompanying interim period MD&A for each interim period of fiscal 2012. The audited consolidated financial statements and additional information relating to our business, including our most recent 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 website 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 the 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, assumptions and uncertainties that could have a material impact on future prospects. Please refer to “Forward-Looking Information, Assumptions and Risk Factors” for a discussion of the risks, assumptions 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 fourth amended and restated credit agreement, 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, the impairment of goodwill, the amendment related to the fiscal 2011 $42.5 million revenue writedown on the Canadian Natural¹ overburden removal contract (described in the “Explanatory Notes–Significant Business Event” section of this MD&A) 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 interest, income taxes, depreciation and amortization 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, both of which are calculated using Consolidated EBITDA. Non-compliance with these financial covenants could result in a requirement 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. For example, EBITDA and Consolidated EBITDA do not:

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

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

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

• include tax payments that represent a reduction in cash available to us; or

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

¹  Canadian Natural Resources Limited (Canadian Natural), owner and operator of the Horizon Oil Sands mine site.

2012 Annual Report 1

Consolidated EBITDA excludes unrealized foreign exchange gains and losses and realized unrealized gains and losses on derivative financial instruments, which, in the case of unrealized losses may ultimately result in a liability that may 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.

Significant Business Event

As discussed in the “Explanatory Notes–Significant Business Event” section of our annual MD&A for the year ended March 31, 2011, we recorded a $42.5 million revenue writedown (the “revenue writedown”) for the three months and year ended March 31, 2011. This revenue writedown was related to the long-term overburden removal and mining services contract (“the Canadian Natural contract”) between our subsidiary, North American Construction Group Inc. (NACG) and our customer, Canadian Natural, at the Horizon Oil Sands mine near Fort McMurray, Alberta. The revenue writedown reduced total revenue related to the contract to the extent of total costs incurred, representing a zero profit margin and reduced unbilled revenue by the same amount. Revenue related to the Canadian Natural contract for the three and nine months ended December 31, 2011 was similarly recorded only to the extent of costs incurred, representing a zero profit margin for such periods.

On December 22, 2011, we signed a Memorandum of Understanding (“MOU”) with Canadian Natural that outlined new contractual terms to be incorporated into an amending agreement for the Canadian Natural contract. The MOU also established temporary contractual terms to guide both parties as we resumed overburden operations at the Horizon site on January 2, 2012. In addition, under the terms of the MOU, we received compensation from Canadian Natural of $4.3 million for outstanding change orders and $3.0 million for mobilization costs relating to the work suspension initiated by Canadian Natural on May 18, 2011. Canadian Natural also reduced its letter of credit requirement from $10.0 million to $5.0 million as part of the MOU.

On March 27, 2012, we reached an agreement with Canadian Natural on amendments to the Canadian Natural contract. The amending agreement included a $34.1 million settlement of past claims under the original contract. As a result, we did not record any additional revenue writedown. The $34.1 million payment was recorded as an increase in cash and cash equivalents with a corresponding reduction of the unbilled revenue balance for this customer, for the year ended March 31, 2012. Canadian Natural also eliminated its remaining $5.0 million letter of credit requirement for 2012 as part of the contract amendment.

The general terms of the original contract related to work scope remained in place, which includes providing overburden removal and tailings dyke construction services to Canadian Natural. However, the previous higher-risk unit-rate payment structure has now been replaced with a target-price contract structure, which includes both a minimum margin and a mechanism to earn additional margin by achieving mutually agreed upon productivity and safety targets. Accordingly, revenue from January 1, 2012 to the completion of the contract will be recognized under the amended contract structure. The amended contract revenue treatment will remain separate from the original contract revenue treatment.^¿

In addition to the amending agreement, Canadian Natural committed to accelerate the buyout of approximately 30% of our assets that are contractually tied to the Canadian Natural contract (“contract-related assets”), some of which we owned outright and some of which we leased, along with all of the parts and tire-related inventory used by us on the Horizon site. As of March 27, 2012, Canadian Natural acquired approximately 85% of the identified contract-related assets with the remaining asset sales scheduled to occur as equipment leases expire later in 2012. The sale of the contract-related assets had the following effect on our audited consolidated financial statements for the year ended March 31, 2012:

• $28.2 million reduction of property, plant and equipment and intangible assets.

• $8.5 million reduction in inventory.

• $16.5 million reduction of unbilled revenue.

• The remaining $18.1 million unbilled revenue balance for this contract will be invoiced over the remaining life of the contract, unless Canadian Natural exercises its right to accelerate the purchase of further contract specific leased equipment, in which case the appropriate unbilled revenue amount will be applied against the proceeds of any such asset sale.

• $66.1 million increase in accounts receivable for the proceeds of the contract-related asset sale, of which $47.9 million was paid on April 30, 2012.

• $12.9 million increase in accounts payable, reflecting the outstanding balance of planned contract-related operating lease buyouts after the $6.2 million in operating lease buyouts executed on March 30, 2012.

We anticipate $47.0 million of net proceeds upon final closing of the sale of the assets related to the Canadian Natural contract.^¿

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

2 2012 Annual Report

NOA

Because of the above transactions, we anticipate a reduction of approximately $8.0 million to $10.0 million in Canadian Natural contract-related operating lease and depreciation costs during fiscal 2013 and an equivalent reduction of contract revenue.^¿

B. Business Overview

Business Overview

We provide a wide range of heavy construction and mining, piling and pipeline installation services to customers in the Canadian oil sands, industrial construction, commercial and public construction and pipeline construction markets. Our primary market is the Canadian 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. For the year ended March 31, 2012, recurring services represented 87% of our oil sands business. Our principal oil sands customers include all four producers that are currently mining bitumen in Alberta: Syncrude², Suncor³, Shell⁴ and Canadian Natural. We focus on building long-term relationships with our customers and have provided services to each of them since inception of their respective projects. In the case of Syncrude and Suncor, these relationships span 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 (owned, leased and rented) includes approximately 900 pieces of diversified heavy construction equipment supported by over 750 pieces of ancillary equipment. While our expertise covers mining, heavy construction, tailings management and mine reclamation services, underground services installation (fire lines, sewer, water, etc.) for industrial projects and piling and pipeline installation in many different locations, we have a specific capability operating in the harsh climate and difficult terrain of northern Canada, particularly in the Canadian oil sands.

We believe that our excellent safety record, coupled with our significant oil sands knowledge, experience, long-term customer relationships, equipment capacity, scale of operations and broad service offering, differentiate us from our competition. As such, our capabilities enable us to support our customers’ recurring services needs with respect to their new oil sands mining developments and expansions.^¿

While our mining services are primarily focused on the oil sands, we believe that we have demonstrated our ability to successfully apply our oil sands knowledge and technology and put it to work in other resource development projects. We believe we are positioned to respond to the needs of a wide range of other resource developers and we remain committed to expanding our operations outside of the Canadian oil sands.

Five Year Business Performance

The table below represents select financial data related to our business performance for the past five fiscal years:

	Year ended March 31,
(dollars in thousands except ratios and per share amounts)	2012			2011(1)			2010		2009			2008
Operating Data
Revenue		$1,006,545			$858,048			$758,965		$972,536			$989,696
Gross profit		60,901			58,136			139,285		170,418			163,009
Gross profit margin		6.1%			6.8%			18.4%		17.5%			16.5%
Operating (loss) income(2)		(390	)		(10,725	)		73,488		(87,092	)		91,727
Net (loss) income(2)		(21,162	)		(34,650	)		28,219		(135,404	)		41,534
Consolidated EBITDA(3)		56,978			84,101			121,644		139,446			131,932
Per Share Information
Net (loss) income - basic		$(0.58	)		$(0.96	)		$0.78		$(3.76	)		$1.16
Net (loss) income - diluted		(0.58	)		(0.96	)		0.77		(3.76	)		1.13
Balance Sheet Data
Total assets		$749,993			$682,957			$706,920		$629,275			$802,336
Total shareholders’ equity		127,780			147,266			181,058		150,792			283,544
Net debt to shareholders' equity(4)		2.5:1			2.1:1			1.2:1		1.4:1			1.0:1

1 Financial results for the year ended March 31, 2011 include a $42.5 million revenue writedown related to the Canadian Natural contract.

2 Financial results for the year ended March 31, 2009 include a goodwill impairment charge of $176.2 million.

3 For a definition of Consolidated EBITDA and reconciliation to net income see “Non-GAAP Financial Measures” and “Consolidated EBITDA” in this MD&A.

4 Net debt is calculated as the net of Series 1 Debentures, 8  ³/4% senior notes, current and non-recurring portion of swap liability, capital lease obligations and credit facilities, less cash equivalents.

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

²  Syncrude Canada Ltd. (Syncrude) – operator of the oil sands mining and extraction operations for the Syncrude Project, a joint venture amongst Canadian Oil Sands Limited (37%), Imperial Oil Resources (25%), Suncor Energy Oil and Gas Partnership (12%), Sinopec Oil Sands Partnership (9%), Nexen Oil Sands Partnership (7%), Murphy Oil Company Ltd. (5%) and Mocal Energy Limited (5%).

³  Suncor Energy Inc. (Suncor).

⁴  Shell Canada Energy (Shell), a division of Shell Canada Limited, which is the operator of the 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 Corporation (20%).

2012 Annual Report 3

An analysis of results for each of these fiscal years can be found in the annual MD&A for each corresponding year.

Our Strategy

For a discussion on our strategy see the “Our Strategy” section of our most recent AIF, which section is expressly incorporated by reference into this MD&A.

Operations Overview

Our business is organized into three operating segments: (i) Heavy Construction and Mining, (ii) Piling and (iii) Pipeline. Revenue generated from these three segments for the year ended March 31, 2012 is represented in the chart below:

A complete discussion on segment results can be found in “Financial Results–Segment Annual Results” section of this 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 resource developers. This includes activities such as:

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

• the supply of labour and equipment to supplement customers’ mining fleets supporting the mining of ore;

• 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;

• construction related to the expansion of existing projects, site development and infrastructure; and

• environmental and tailings management services, including construction and modification of tailing ponds and reclamation of mined-out areas.

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

Piling

Our Piling segment focuses primarily on the installation of various types of driven, drilled and screw piles, caissons and earth retention and stabilization systems. Our piling experience includes industrial projects in the oil sands and related petrochemical and refinery complexes. We have also been involved in a diverse range of commercial and community infrastructure projects. Through this work, we have gained experience in both small and large-scale projects.

Our Canadian piling operations extend from British Columbia to Ontario and more recently, into the US and abroad. The international operations acquired as part of our November 2010 acquisition of Cyntech Corporation⁵ include a manufacturing facility in Texas and an established customer base for screw pile and pipeline anchor supply in the US, Columbia, Malaysia, Indonesia, Thailand and Russia.

Pipeline

Our Pipeline segment focuses on infrastructure development for oil and gas pipeline systems, including gathering and processing, transmission, storage and distribution, related maintenance and other specialty services. Known for its ability to execute technically and environmentally challenging projects, the Pipeline segment has the capacity and resources to handle pipe diameters ranging from two to 60 inches and operates across numerous remote geographical locations simultaneously.

This segment’s volume is currently being driven by activity related to the Canadian oil sands, as well as shale gas plays such as the Horn River and Muskwa formations in Northeast British Columbia, which represent some of the world’s largest proven reserves. The segment has also built significant new business in mainline pipe integrity testing and maintenance, which involves identifying weak portions of existing pipelines and carrying out repairs to reduce the risk of future leaks or ruptures.

Revenue by Source

Historically we have experienced steady growth in recurring services revenue from operating oil sands projects, with demand for these services largely unaffected by economic conditions. Over the past year, however, production at a number of our customers’ operations was disrupted by a series of unique events, including wildfires in Northern Alberta and a plant fire at Canadian Natural’s main processing plant. This, in turn, temporarily reduced demand for recurring services.

⁵  We acquired the assets of Cyntech Corporation, a private Alberta-based company and Cyntech Anchor Systems LLC, its US based subsidiary, (collectively Cyntech) as at November 1, 2010. To facilitate the acquisition of Cyntech’s assets, we established two Canadian subsidiaries, namely Cyntech Canada Inc. and Cyntech Services Inc.; and one US subsidiary, Cyntech U.S. Inc.

4 2012 Annual Report

NOA

Project development services revenue, meanwhile, has begun to recover from the recessionary conditions that prevailed from late 2008 through to the middle of 2011. As economic conditions have strengthened, several major oil sands projects have returned to the planning and development stages and activity levels in the commercial and industrial construction markets and pipeline construction sector have increased. This has helped to strengthen our project development revenues over the past 12-18 months.

The following graph displays the revenue generated from recurring services and project development services on a trailing 12-month basis at three-month intervals, from June 30, 2009 to March 31, 2012:

Project Development Services Revenue

Project development services revenue is typically related to 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.

Recurring Services Revenue

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

• Long-term contracts. This category 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 reclamation. Revenue in this category is typically generated under a unit-price contract structure 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 our master services agreements with Suncor, Syncrude and Shell, longer-term equipment rental contracts and ad hoc work undertaken for our customers on an as-needed basis, such as work being done on a time-and-materials basis for Canadian Natural. This revenue is typically generated by supporting the ongoing operations of our customers and is therefore considered to be recurring. It is generated under either time-and-materials or unit-rate contracts depending on such things as the degree of complexity the completeness of engineering and the required schedule. Generally the more complex, less engineered or shorter notice type projects will be more likely be executed using a time-and-materials contract structure and because the work is not guaranteed, its potential revenue is not included in our calculation of backlog. This work is generally funded from our customers’ operating or maintenance capital budgets.

Revenue by End Market

During the fiscal year ended March 31, 2012, we provided services to four distinct end markets:

i. Canadian oil sands;

ii. Commercial and public construction;

iii. Industrial construction; and

iv. Pipeline construction.

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The following graph displays the breakdown of revenue by end market on a trailing 12-month basis at three-month intervals, from June 30, 2009 to March 31, 2012:

Canadian Oil Sands Market

Our core end-market is the Canadian oil sands, where we generated 63% of our fiscal 2012 revenue. According to the Canadian Association of Petroleum Producers (CAPP), in 2011 the oil sands represented 97% of Canada’s recoverable oil reserves with proven reserves of 169 billion barrels. This is the third largest proven oil reserve in the world, next to Saudi Arabia and Venezuela. It is also the world’s largest reserve open to private sector investment. In 2011, oil sands production reached 1.6 million barrels per day (“bpd”), representing 53.6% of Canada’s total oil production for that same year. CAPP estimates that oil sands production will grow by about 130% to 3.7 million bpd by 2025. CAPP further estimated that between 2001 and 2011, over $115 billion of capital was invested into the Canadian oil sands.

Oil sands are grains of sand covered by a thin layer of water and coated by heavy oil or bitumen. Bitumen, because of its structure, requires 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. 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. The choice of extraction method is entirely based on the geographic features of the land and the two methods are not interchangeable.

CAPP estimates that approximately half of 2011 oil sands production was extracted from five active mining projects, while the remaining half 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, future total production from mining and in situ technology is expected to remain approximately equal according to CAPP and other industry estimates. This reflects the significantly larger size and higher production of the mining projects.

We support both in situ and mine development projects by providing project development services such as clearing, site preparation, piling and underground utilities installation during the three-to-four-year development and construction phase. The majority of our recurring services work is provided to customers operating oil sands mines, reflecting the additional support services required through the typical 40-year lifecycle of these projects. Our recurring services range from overburden removal to tailings management to site reclamation.

The requirement for recurring services typically grows as mines age. Mine operators tend to construct their plants closest to the easy-to-access bitumen deposits (less overburden and/or higher quality bitumen) to maximize profitability and cash flow at the beginning of their projects. As the mines move through their lifecycle, easy-to-access, high-quality bitumen deposits are depleted and operators must go greater distances and move more material to secure the required volume of oil sand to feed the plant at capacity.⁶ 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, 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 grows even during periods of stable production because the geographical footprints of existing mines expands under normal operation.

Current Canadian Oil Sands Business Conditions

Project Development: Sustained favorable oil prices have set the stage for record levels of oil sands capital investment in 2012. CAPP estimates that 2012 capital expenditures will reach $20 billion, surpassing the previous record of $18.1 billion in 2008.

Part of the growth in oil sands capital spending is expected be driven by the development of new mines and the expansion of existing mine operations. Suncor and Total⁷ have announced aggressive growth plans under their recently formed strategic alliance. Early earthworks activities are already under way at the Joslyn North Mine Project⁸ and Suncor is set to commence construction at both their Voyageur⁹ upgrader and Fort Hills¹⁰ mine locations. Canadian Natural and Syncrude have also announced plans to increase spending on mine expansion and production improvement projects in 2012.^¿

⁶  As oil sand quality declines (lower quantity of oil per m³ of sand), it is necessary to mine a greater volume to achieve the same volume of produced oil; as overburden thickens (the oil sands seam generally dips to the south), it is necessary to mine a greater volume of overburden to expose the mineable oil sands.

⁷  Total E&P Canada Ltd. (Total), a wholly owned subsidiary of Total SA.

⁸  Joslyn North Mine Project (Total Joslyn), a joint venture amongst Total (38.25%), Suncor (36.75%), Occidental Petroleum Corporation (15%) and Inpex Corporation (10%). Total is the operator oil sands mining and extraction operations of the Joslyn North Mine Project.

⁹  Voyageur Upgrader Project (Suncor Voyageur), a joint venture amongst Suncor (51%) and Total (49%). Suncor is the operator of the project.

¹⁰  Fort Hills LP (Suncor Fort Hills), a limited partnership between Suncor Energy Inc. (40.8%), Total (39.2%) and Teck Resources Ltd. (20%). Suncor is the operator of the oil sands mining operations of Fort Hills.

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

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A number of in-situ projects are also proceeding, including Husky Energy’s Sunrise¹¹, ConocoPhillips’ Surmont¹², Cenovus Energy’s¹³ Foster Creek and Christina Lake projects, as well as Devon Canada’s¹⁴ Jackfish projects. In addition, Suncor is proceeding with additional stages of its Firebag in situ project.

Spending on Energy Resources Conservation Board (ERCB) Directive 074¹⁵-related tailings projects is expected to increase during the remainder of 2012. Suncor has committed to spend more than $1 billion on its new TRO¹⁶ tailings management approach while Canadian Natural plans to spend $215 million on tailings management projects in 2012, compared to $45 million in 2011. We expect the increased focus on tailings management could create further opportunities for our Heavy Construction and Mining segment in fiscal 2013.^¿

Recurring Services: According to CAPP, oil production from mining projects is forecasted to rise 13% in 2012 compared to 2011, reflecting the production start-up at Exxon’s Kearl project and resumption of normal production at all operating mines. While this is expected to support increased demand for recurring services, it has become more challenging to predict when specific work will be performed. Following the 2008 economic downturn, oil sands operators shifted their focus from controlling schedules to controlling costs. Some producers re-engineered mine plans to reduce costs, causing last-minute delays in planned work, while others intentionally deferred planned work. We believe that the impact of these cost-control measures will be likely short-term as the delayed and deferred activities are ultimately required for the continued operation of the mine.^¿

In addition to scheduling delays, some customers may continue to attempt to insource services that would have otherwise been outsourced. Our past experience suggests that producers who experiment with insourcing mining services eventually return to outsourcing due to the increased flexibility and overall lower cost of the contracting model.

In the short term, these variables have reduced visibility on upcoming demand for third-party mining support services. However, demand for other types of recurring service, such as overburden removal and both wet tailings and mine reclamation activities, is expected to improve in fiscal 2013. This view is supported by the resumption of overburden removal activity at the Canadian Natural Horizon Mine site in January 2012 under our amended contract, as well as by the increased reclamation activity at new and existing oil sands mining operations.^¿

Commercial and Public Construction Market

We provide construction services, primarily piling and shoring wall construction, to the commercial and public construction markets in British Columbia, Alberta, Saskatchewan and Ontario.

Current Commercial and Public Construction Business Conditions

Construction activity in Canada remains strong, according to the Government of Canada’s Construction Sector Council, with $36.8 billion in planned commercial, institutional and government construction projects in 2012. In its five-year forecast, the Council anticipates construction spending of approximately $200 billion, with commercial construction leading the way. British Columbia, Alberta, Saskatchewan and Ontario account for over 65% of total planned spending in the Council’s forecast.

Industrial Construction Market

In addition to commercial and public construction and beyond our oil sands construction activities, we pursue a variety of industrial construction opportunities.

The resource mining industry is of special interest to us with Canada being one of the largest mining nations in the world. In particular, Canada is the largest producer of potash, accounting for more than one-third of the world’s potash production and exports. We currently provide services to this sector through our Piling segment. With several potash mine expansions and new developments in the planning stages, we believe this is a potential growth market for our construction services.^¿

¹¹  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.

¹²  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. ConocoPhillips Canada is the project operator.

¹³  Cenovus Energy Inc. (Cenovus Energy) is the operator of the Foster Creek and Christina Lake Oil Sands Projects. Both projects are 50/50 joint ventures with ConocoPhillips.

¹⁴  Devon Canada Corporation (Devon Canada) is a wholly owned subsidiary of Devon Energy Corporation. Devon Canada is the operator of the Jackfish projects.

¹⁵  Directive 074: “Tailings Performance Criteria and Requirements for Oil Sands Mining Schemes”, released February 3, 2009 by the Energy Resources Conservation Board (ERCB), an independent, quasi-judicial agency of the Government of Alberta, established to regulate the safe, responsible, and efficient development of Alberta's energy resources: oil, natural gas, oil sands, coal, and pipelines.

¹⁶  Suncor’s TRO (registered trade mark) process is designed to accelerate the settling and drying of mature fine tailings (MFT) materials to allow for a more timely reclamation process to meet ERCB Directive 74 requirements.

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

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While potash deposits are mainly located in Saskatchewan, minerals such as copper, gold, coal and cobalt are prevalent in British Columbia. The BC government has recently approved the expansion of nine existing mines and the opening of eight new mines in the province by 2015. These projects not only create new opportunities for us to compete for work, they also potentially reduce the number of our current competitors seeking work in the oil sands.^¿

The conventional oil and gas industry is another source of industrial construction projects. For example, we have been providing industrial and piling services to CCRL’s¹⁷ heavy oil upgrader revamp and expansion project in Regina for the past three years.

Current Industrial Construction Business Conditions

Canada’s resource sector continues to strengthen as evidenced by a record $3.9 billion in exploration and deposit appraisal expenditures in 2011. Precious metals have been the main target for exploration as economic uncertainty in the United States and Europe has elevated gold prices. Mine development activity is also expected to track at high levels, supported by strong prices and demand from emerging markets.

We believe we are in a position to benefit from the resurgence in mineral resource spending. For example, we are currently executing a contract to erect structural steel at Thompson Creek’s¹⁸ Mt. Milligan Copper/Gold Project. This is our first contract of this nature and we plan to build on this experience to pursue further opportunities within the resource mining sector.^¿

Pipeline Construction Market

We provide pipeline installation and facility construction 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 the Canadian Energy Pipeline Association (CEPA), Canada contains over 100,000 km of liquids and natural gas transmission pipeline, which transports approximately 3.2 million barrels of crude oil and equivalents per day and 15 billion cubic feet of natural gas per day to various distribution points in Canada and the US. In addition to these large transmission lines, there are 725,000km of gathering and delivery lines that spread throughout the country. According to CAPP, current pipeline capacity of 3.5 million barrels per day to the US Midwest is in excess of the refining capacity in that area, most notably at Cushing, Oklahoma. As a result, various major pipeline projects have been announced that will transport oil to available refining capacity in other areas of the US and China.

Current Pipeline Construction Business Conditions

Development of pipeline infrastructure to new markets outside of the US Midwest has become critical to the success of Western Canadian oil and gas producers. Increased demand for new pipeline assets is starting to create a shift to more favourable market conditions for pipeline contractors. In response to the supply glut at Cushing, the US regulatory agencies are expected to approve TransCanada’s¹⁹ Keystone southern extension to transport oil from Cushing to available refining capacity on the US Gulf Coast. We believe the construction of the southern extension will likely tie up available contractor capacity in the US and reduce bidding competition on pipeline projects that have been announced for Western Canada. In anticipation of constrained contractor supply, we believe opportunities may arise to negotiate low-risk cost-plus or time-and-materials contracts, which eliminate many of the inherent risks of lump-sum contracts.^¿

In addition, we have seen increased demand for pipeline integrity services as spending on testing and maintenance of Canada’s aging pipeline infrastructure increases. Demand for integrity testing and maintenance services creates more steady recurring activity in our pipeline segment and the services are typically performed under low-risk cost-plus or time-and-materials contracts. We currently provide these services to a major Canadian pipeline company under a multi-year master services agreement and have seen demand increase in recent months. We intend to pursue additional contract opportunities in this field as they become available.^¿

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

¹⁷  Consumers Co-operative Refinery Limited (CCRL) is a wholly owned subsidiary of Federation Co-operatives Limited.

¹⁸  Thompson Creek Metals Company Inc., owner of the Mt. Milligan Copper / Gold project in Central British Columbia.

¹⁹  TransCanada Pipelines Limited (TransCanada)

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C. Financial Results

Summary of Consolidated Annual Results

	Year Ended March 31,
(dollars in thousands, except per share amounts)	2012			% of Revenue		2011			% of Revenue		2010		% of Revenue		2012 vs 2011 Change			2012 vs 2010 Change
Revenue		$1,006,545			100.0%		$858,048			100.0%		$758,965		100.0%		$148,497			$247,580
Project costs		610,821			60.7%		456,119			53.2%		301,307		39.7%		154,702			309,514
Equipment costs		220,738			21.9%		234,933			27.4%		209,408		27.6%		(14,195	)		11,330
Equipment operating lease expense		65,185			6.5%		69,420			8.1%		66,329		8.7%		(4,235	)		(1,144	)
Depreciation		48,900			4.9%		39,440			4.6%		42,636		5.6%		9,460			6,264
Gross profit		60,901			6.1%		58,136			6.8%		139,285		18.4%		2,765			(78,384	)
General and administrative expenses		54,400			5.4%		59,828			7.0%		62,516		8.2%		(5,428	)		(8,116	)
Operating (loss) income		(390	)		0.0%		(10,725	)		-1.2%		73,488		9.7%		10,335			(73,878	)
Net (loss) income		(21,162	)		-2.1%		(34,650	)		-4.0%		28,219		3.7%		13,488			(49,381	)
Per share information
Net (loss) income – basic		$(0.58	)				$(0.96	)				$0.78				$0.38			$(1.36	)
Net (loss) income – diluted		(0.58	)				(0.96	)				0.77				0.38			(1.35	)
EBITDA(1)		$56,542			5.6%		$31,873			3.7%		$112,333		14.8%		$24,669			$(55,791	)
Consolidated EBITDA(1) (as defined within the credit agreement)		$56,978			5.7%		$84,101			9.8%		$121,644		16.0%		$(27,123	)		$(64,666	)

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

	Year Ended March 31,
(dollars in thousands)	2012			2011			2010
Net (loss) income		$(21,162	)		$(34,650	)		$28,219
Adjustments:
Interest expense		30,325			29,991			26,080
Income tax (benefit) expense		(7,223	)		(6,448	)		13,679
Depreciation		48,900			39,440			42,636
Amortization of intangible assets		5,702			3,540			1,719
EBITDA		$56,542			$31,873			$112,333
Adjustments:
Unrealized foreign exchange (gain) loss on senior notes		–			–			(48,920	)
Realized and unrealized (gain) loss on derivative financial instruments		(2,382	)		(2,305	)		54,411
Loss on disposal of property, plant and equipment		1,741			1,948			1,233
(Gain) loss on disposal of assets held for sale		(466	)		825			373
Stock-based compensation expense		1,629			2,191			2,258
Equity in (earnings) loss of unconsolidated joint venture		(86	)		2,720			(44	)
Loss on debt extinguishment		–			4,324			–
Revenue writedown on Canadian Natural project		–			42,525			–
Consolidated EBITDA		$56,978			$84,101			$121,644

Revenue

For the year ended March 31, 2012, revenues increased to $1.0 billion, $148.5 million higher than in the year ended March 31, 2011 and $247.6 million higher than in the year ended March 31, 2010.

As discussed in the “Explanatory Notes–Significant Business Event” section of this MD&A, we signed an amending agreement for the Canadian Natural contract, which took effect January 1, 2012. The amended contract provides a revised payment structure that carries less risk for us than the unit-rate structure it replaces. We determined that contract-related revenue and profit generated under the Canadian Natural contract, after January 1, 2012, should reflect the amended payment terms. Revenue generated under the contract prior to December 31, 2011 is recognized only to the extent of costs.

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Excluding revenues related to the Canadian Natural contract from the current and prior-year periods, consolidated revenue would have been $921.2 million for the year ended March 31, 2012, from $686.6 million and $621.5 million for the years ended March 31, 2011 and 2010, respectively.

Project development revenue for the year ended March 31, 2012 increased $139.1 million and $281.6 million compared to the years ended March 31, 2011 and March 31, 2010, respectively. A surge in construction activity across Western Canada contributed to an increase in Piling and Pipeline revenues for the year ended March 31, 2012, compared to the prior two years. Project development revenue in the current year was further supported by increased heavy civil construction activity at Total’s Joslyn mine and increased light industrial construction activity at numerous sites across Western Canada. Increased tailings and environmental construction services for several oil sands customers also helped boost project development revenues in the current year. Customer budget concerns and extended design delays on certain oil sand projects dampened the current year heavy civil construction revenue improvements.

Recurring services revenue for the year ended March 31, 2012 climbed $95.5 million and $18.2 million over the years ended March 31, 2011 and March 31, 2010, respectively (excluding the Canadian Natural contract from both periods). This year’s growth compared to the growth in each of the prior two years was driven by increased demand for reclamation, overburden removal and site services under new contracts with Suncor and Syncrude, as well as by increased tank services work for Imperial Oil performed by our Piling segment. These gains were partially offset by a reduction in mine support services at Shell and wild fires and site evacuations during the first quarter of the current year. Unseasonably warm winter temperatures in the fourth quarter further affected recurring revenues by affecting our ability to perform muskeg removal and reclamation activities that require frozen ground conditions. In addition, we experienced unexpected work stoppages at two major oil sands sites in the third and fourth quarters as clients looked to redesign projects or defer project spending to reduce costs.

Gross profit

For the year ended March 31, 2012, we achieved gross profit of $60.9 million compared to $58.1 million in the previous year and $139.3 million in the year ended March 31, 2010. Excluding activity in each period under the Canadian Natural contract, gross profit would have been $57.7 million (6.3% of revenue) for the year ended March 31, 2012, $89.4 million (13.0% of revenue) for the year ended March 31, 2011 and $131.0 million (21.1% of revenue) for the year ended March 31, 2010.

The reduction in adjusted gross margin compared to the previous two years primarily reflects a high volume of Pipeline revenue at negative margin and reduced margins in our Heavy Construction and Mining segment as a result of weather-related productivity impacts in the first quarter of fiscal 2012 and a reduced volume of higher-margin mine support services throughout the year. Additionally, recoveries of maintenance and lease costs dropped in the current year due to the unexpected work stoppages and unfavorable weather conditions discussed above, which negatively affected utilization of our larger-sized equipment fleet during the winter period.

Project costs, as a percentage of revenue, were 60.7% during the year ended March 31, 2012, compared to 53.2% for the year ended March 31, 2011 and 39.7% for the year ended March 31, 2010. The increase in project costs reflects higher volumes of more labour-intensive pipeline, piling and civil construction activity and a corresponding reduction in mine support services during the period.

Equipment costs represented 21.9% of revenue during the year ended March 31, 2012, compared to 27.4% in the year ended March 31, 2011 and 27.6% for the year ended March 31, 2010. The reduction in equipment costs as a percentage of revenue in fiscal 2012 compared to fiscal 2011 reflects the work mix impact discussed above. The decrease in equipment costs as a percentage of revenue in fiscal 2012 compared to fiscal 2010 reflects the current year change in project mix and the use of higher-cost rental equipment.

Equipment operating lease expense was $65.2 million for the 2012 fiscal year, compared to $69.4 million and $66.3 million in the years ended March 31, 2011 and March 31, 2010, respectively. The decrease in operating lease expense in fiscal 2012 compared to fiscal 2011 reflects a $5.5 million reduction in accrued over-hour liability resulting from a $2.8 million benefit from lease amendments and lower operating hours on our large mining equipment. The decrease in operating lease expense in fiscal 2012, compared to fiscal 2010, reflects an $8.7 million benefit from lease amendments and reduced operating hours offset by increased lease costs from heavy equipment additions in support of the Canadian Natural contract.

We recorded depreciation of $48.9 million (4.9% of revenue) for the year ended March 31, 2012, compared to $39.4 million (4.6% of revenue) for the year ended March 31, 2011 and $42.6 million (5.6% of revenue) for the year ended March 31, 2010. We recorded a $9.8 million charge to depreciation, in the current year, specific to an asset impairment of an older fleet of trucks that was under-performing compared to our targeted reliability levels. This compares to the $1.0 million asset impairment charges to depreciation, recorded in each of the years ended March 31, 2011 and March 31, 2010.

Operating (loss) income

For the year ended March 31, 2012, we recorded an operating loss of $0.4 million, compared to an operating loss of $10.8 million during the year ended March 31, 2011 and operating income of $73.5 million during the year ended March 31, 2010. During the 2011 fiscal year, revenue and gross profit were reduced by the $42.5 million revenue writedown related to the Canadian Natural contract. Excluding the Canadian Natural contract, operating loss would have been $3.6 million for the year ended March 31, 2012 compared to operating income of $20.6 million (3.0% of revenue) and $65.2 million (10.5% of revenue), for the years ended March 31, 2011 and 2010, respectively. General and administrative (“G&A”) expense of $54.4 million for the year ended March 31, 2012 was $5.4 million and $8.1 million lower than in the years ended March 31, 2011 and March 31, 2010, respectively. The decrease in 2012 G&A expense reflects reductions in stock-based compensation expense resulting from a decrease in our share price year-over-year. Current year short-term incentive program costs were equivalent to fiscal 2011, but lower in fiscal 2010 because of reduced profitability.

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Net (loss) income

For the year ended March 31, 2012, we recorded a net loss of $21.2 million (basic and diluted loss per share of $0.58), compared to net loss of $34.7 million (basic and diluted loss per share of $0.96) for the year ended March 31, 2011 and net income of $28.2 million (basic income per share of $0.78 and diluted income per share of $0.77) for the year ended March 31, 2010. The non-cash, non-recurring items benefitting current-year results included the reversal of the embedded derivative in the Canadian Natural contract, resulting from changes to the pricing structure of the contract. This impact was partially offset by unrealized losses on embedded derivatives in certain long-term supplier contracts. Excluding the non-cash items, net loss would have been $23.0 million (basic and diluted loss per share of $0.63) for the year ended March 31, 2012.

In the 2011 fiscal year, the net loss was $34.7 million, largely due to the $42.5 million revenue writedown ($31.8 million after-tax loss) related to the Canadian Natural contract. Excluding only the revenue writedown, net loss would have been $2.9 million (basic and diluted loss per share of $0.08) for the year ended March 31, 2011. Non-cash, non-recurring items affecting results included unrealized gains on embedded derivatives in certain supplier contracts and our long-term overburden removal contract. These gains were offset by the write-off of deferred financing costs on the settlement of the 8 ³/4% senior notes and losses on the cross-currency and interest rate swaps. Excluding the non-cash items, net loss for the year ended March 31, 2011 would have been $0.7 million (basic and diluted loss per share of $0.02).

Net income of $28.2 million for the year ended March 31, 2010 was positively affected by the 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 the redemption option 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. Excluding the non-cash 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).

Segment Annual Results

Heavy Construction and Mining

	Year Ended March 31,						Change
(dollars in thousands)	2012		2011		2010		2012 vs 2011		2012 vs 2010
Segment revenue		$670,720		$667,037		$665,514		$3,683		$5,206
Segment profit		$86,567		$50,703		$111,016		$35,864		$(24,449	)
Segment margin		12.9%		7.6%		16.7%

For the year ended March 31, 2012, the Heavy Construction and Mining segment reported revenue of $670.7 million, a $3.7 million increase from fiscal 2011 and a $5.2 million increase from fiscal 2010. An otherwise strong start to the 2012 fiscal year was interrupted by wildfires in the Fort McMurray area, which necessitated the evacuation of all personnel from Shell’s site for two weeks and from Canadian Natural’s Horizon site for three weeks. Canadian Natural subsequently suspended our involvement in their overburden removal activity for a period of ten months as it repaired a processing plant damaged in a separate fire.

Excluding activity from the Canadian Natural contract, adjusted revenue increased to $585.4 million for the year ended March 31, 2012, from $495.6 million and $528.0 million for the years ended March 31, 2011 and 2010, respectively. The improvement in adjusted 2012 revenue compared to fiscal 2011 reflects:

• increased reclamation, overburden and heavy civil construction work at Suncor’s Base Mine under our five-year master services contract with this customer;

• increased site services and overburden removal activity at Syncrude;

• increased light civil construction work at several oil sands sites, CCRL’s Co-op refinery in Saskatchewan and Thompson River’s Mt. Milligan Copper/Gold Project in British Columbia;

• the provision of specialized tailings and environmental construction services to Suncor, Syncrude and Shell;

• the initiation of mine construction activity at Total’s Joslyn Mine;

• heavy civil construction work at the MacKay River site of the PetroChina Dover SAGD project²⁰;

• increased heavy civil construction work at Shell in support of this customer’s new Atmospheric Fines Drying (AFD) tailings technology; and

• a high volume of summer muskeg removal activity.

²⁰  PetroChina Dover SAGD project (PetroChina Dover) is owned by PetroChina International Investment Ltd. The project is operated by Dover Operating Corp, a joint venture between Cretaceous Oilsands Holdings Ltd, a wholly owned subsidiary of PetroChina (60%) and Alberta Oil Sands Corp. (AOSC) (40%).

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These gains were partially offset by:

• the negative impact of wildfires in the first quarter;

• unseasonably warm winter weather, which affected our ability to perform muskeg removal and reclamation during the fourth quarter; and

• an unexpected work stoppage at one client site related to the deferral of a major tailings project into the following year and a stoppage of overburden removal work at a second site related to changes in the client’s mine plan, resulting in reduced activity while our client identified alternate scopes of work.

The improvement in adjusted fiscal 2012 revenue compared to the adjusted fiscal 2010 revenue, reflects the benefits of a master services contract signed with Suncor and the start-up of mine preparation activity at Total’s Joslyn Mine late in the current fiscal year. At Shell, an increase in heavy civil construction work and summer muskeg removal activity could not offset the significant year-over-year decline in mine service activity and the completion of mine development work at Shell’s Jackpine mine, which was commissioned during fiscal 2010. Segment results for the year ended March 31, 2010 benefitted from a partial redeployment of our Canadian Natural-based fleet to support activity at other mines during the plant commissioning related shutdown of our overburden removal activity for Canadian Natural.

For the year ended March 31, 2012, Heavy Construction and Mining segment generated a margin of 12.9% of revenue, compared to 7.6% during the year ended March 31, 2011 and 16.7% for the year ended March 31, 2010. Excluding revenue and profit from the Canadian Natural contract, segment margin would have been 14.2% for the year ended March 31, 2012, compared to 16.5% and 19.5% for the years ended March 31, 2011 and 2010, respectively. The reduction in fiscal 2012 adjusted segment margin, compared to fiscal 2011, reflects continued pricing pressure due to the current oversupply of equipment capacity in the market, together with project start-up delays and unexpected work stoppages during the period. These impacts were partially offset by strong margins on our increased volume of heavy civil construction projects. The reduction in adjusted segment margin in fiscal 2012, compared to fiscal 2010, reflects the same negative effect of pricing pressures and a reduction in higher-margin mine services activity. The strong margin performance in fiscal 2010 also reflects the completion of higher-margin project development work at Shell’s Jackpine mine.

Piling

	Year Ended March 31,						Change
(dollars in thousands)	2012		2011		2010		2012 vs 2011		2012 vs 2010
Segment revenue		$185,321		$105,559		$68,531		$79,762		$116,790
Segment profit		$46,012		$18,455		$11,288		$27,557		$34,724
Segment margin		24.8%		17.5%		16.5%

For the year ended March 31, 2012, Piling segment revenue climbed to $185.3 million, a $79.8 million increase from the year ended March 31, 2011 and a $116.8 million increase compared to the year ended March 31, 2010. These improvements reflect the continued recovery of commercial and industrial construction markets which has helped drive piling demand across all regions. Additionally, fiscal 2012 revenue includes $35.8 million from a full year’s operation of the Cyntech business, acquired in November 2010, compared to a $7.3 million contribution during five months of operation in fiscal 2011. Fiscal 2010 Piling revenue reflects the negative impact of the economic downturn on commercial and industrial construction markets and reduced project development activity in the oil sands.

For the year ended March 31, 2012, Piling segment margins increased to 24.8% of revenue, up from 17.5% and 16.5% for the years ended March 31, 2011 and 2010, respectively. The significant improvement in fiscal 2012 results reflects increased volumes, improved pricing and above average productivity performance on a number of piling jobs completed during the period. It also reflects an $8.8 million profit contribution from Cyntech, compared to the $0.9 million part-year contribution in fiscal 2011. The strong fiscal 2012 segment results benefitted from the unseasonably warm weather during the fall / winter period, allowing them to complete work efficiently during this period compared to the higher-than-normal precipitation levels across Canada in the spring, which delayed the start-up of new projects and negatively affected production schedules.

Pipeline

	Year Ended March 31,									Change
(dollars in thousands)	2012			2011			2010			2012 vs 2011			2012 vs 2010
Segment revenue	$	150,504		$	85,452		$	24,920		$	65,052		$	125,584
Segment loss	$	(11,322	)	$	(3,034	)	$	(3,851	)	$	(8,288	)	$	(7,471	)

For the year ended March 31, 2012, the Pipeline segment reported revenues of $150.5 million, a $65.1 million increase over the year ended March 31, 2011 and a $125.6 million increase over the year ended March 31, 2010. The increase in fiscal 2012 revenue compared to fiscal 2011 primarily reflects the execution of two large-diameter pipeline projects in Northeast British Columbia and Northern Alberta. It also includes the start-up of pipeline maintenance activity under a cost-reimbursable contract covering integrity dig programs work in Saskatchewan and Manitoba. Activity during fiscal 2011 included the substantial completion of two large-diameter pipeline projects in Northern British Columbia, while activity during fiscal 2010 included one large-diameter pipeline project in Southern British Columbia.

12 2012 Annual Report

NOA

The Pipeline segment recorded a loss of $11.3 million in fiscal 2012 as a result of higher-than-anticipated cost escalation on materials and site overhead costs on the two large-diameter pipeline projects, along with an increase in estimated costs to complete spring clean-up and warranty work on the two prior-year projects in Northern British Columbia. Partially offsetting the segment loss was a positive margin on the new pipeline maintenance contract. The segment losses for the years ended March 31, 2011 and 2010 reflect the realization of risks undertaken as part of contracts negotiated during the recession, as well as the negative impact of weather delays on productivity.

The Pipeline segment currently has unsigned change orders for projects completed in each of the years ended March 31, 2012, 2011 and 2010. These relate to unfavorable weather beyond the risk assumed within the contracts, changes in construction methodology, changes in environmental compliance requirements and significant changes to project scope. Consistent with our normal method of accounting for claims, we have recognized $21.2 million of revenue for the current period, only to the extent of costs incurred until the outstanding claims are resolved. The Pipeline segment has been actively working with its customers to expedite the execution of these unsigned change orders.

Summary of Consolidated Three Month Results

		Three Months Ended March 31,
(dollars in thousands, except per share amounts)	2012			% of Revenue		2011			% of Revenue		Change
Revenue	$282,506			100.0%		$174,510			100.0%		$107,996
Project costs		183,489			65.0%		98,383			56.4%		85,106
Equipment costs		61,631			21.8%		64,753			37.1%		(3,122	)
Equipment operating lease expense		15,556			5.5%		16,080			9.2%		(524	)
Depreciation		20,961			7.4%		12,682			7.3%		8,279
Gross profit (loss)		869			0.3%		(17,388	)		-10.0%		18,257
General and administrative expenses		14,662			5.2%		14,313			8.2%		349
Operating loss		(15,812	)		-5.6%		(35,330	)		-20.2%		19,518
Net loss		(16,877	)		-6.0%		(30,452	)		-17.5%		13,575
Per share information
Net loss–basic		$(0.47	)				$(0.84	)				$0.37
Net loss–diluted		(0.47	)				(0.84	)				0.37
EBITDA(1)		$7,828			2.8%		$(19,426	)		-11.1%		$27,254
Consolidated EBITDA(1) (as defined within the credit agreement)		$7,561			2.7%		$24,004			13.8%		$(16,443	)

⁽¹⁾  A reconciliation of net loss to EBITDA and Consolidated EBITDA is as follows:

	Three Months Ended March 31,
(dollars in thousands)	2012			2011
Net loss		$(16,877	)		$(30,452	)
Adjustments:
Interest expense		7,801			7,361
Income tax benefit		(5,296	)		(10,305	)
Depreciation		20,961			12,682
Amortization of intangible assets		1,239			1,288
EBITDA		$7,828			$(19,426	)
Adjustments:
Realized and unrealized gain on derivative financial instruments		(1,422	)		(1,965	)
Loss on disposal of property, plant and equipment		1,040			520
Gain on disposal of assets held for sale		(10	)		(23	)
Stock-based compensation expense		375			529
Equity in (gain) loss on consolidated joint venture		(250	)		1,844
Revenue writedown on Canadian Natural project		–			42,525
Consolidated EBITDA		$7,561			$24,004

Revenue

For the three months ended March 31, 2012, consolidated revenue increased to $282.5 million, from $174.5 million in the same period last year. Excluding revenues related to the Canadian Natural contract from the current and prior-year periods, revenue would have increased to $252.0 million for the three months ended March 31, 2012, from $165.6 million during the same period last year.

2012 Annual Report 13

The $86.4 million year-over-year increase in adjusted revenue reflects higher project development activity primarily driven by stronger construction activity across Western Canada leading to a $30.7 million increase in Piling revenues and a $42.7 million increase in Pipeline revenues. Project development revenue was further supported by heavy civil construction volumes at the Joslyn North Mine Project and light industrial construction activity at the Thompson River Mt. Milligan Copper/Gold Project in British Columbia.

The improvement in project development revenues was partially offset by a year-over-year decline in recurring services revenue. While demand for reclamation, overburden removal and site services increased under our new contracts with Suncor and Syncrude, we experienced lower mine services activity at Shell, unexpected work stoppages at a major oil sands site and a fourth quarter slowdown in muskeg removal and reclamation activity as a result of an unusually warm winter.

Gross profit (loss)

Gross profit for the three months ended March 31, 2012 was $0.9 million or 0.3% of revenue compared to a gross loss of $17.4 million during the same period last year. Excluding activity from the Canadian Natural contract from both periods, gross loss would have been $2.3 million for the three months ended March 31, 2012 compared to gross profit of $22.1 million or 13.3% of revenue, for the three months ended March 31, 2011. The year-over-year decline in gross profit (excluding the Canadian Natural contract writedown) reflects Pipeline segment losses and reduced Heavy Construction and Mining segment margin. Additionally, recoveries of maintenance and lease costs were reduced in the current-year due to lower utilization of our larger-sized heavy equipment fleet. The unexpected work stoppages and unfavorable winter weather conditions discussed above negatively affected our ability to fully deploy our equipment fleet during the period. Partially offsetting this reduced profitability was a significant increase in Piling segment profitability. Margins in the prior-year period reflect a loss on one lump-sum Pipeline project and lower margins in the Piling segment due to project losses and start-up delays.

Project costs, as a percentage of revenue, were 65.0% during the three months ended March 31, 2012, compared to 56.4% for the three months ended March 31, 2011. The increase in project costs reflects increased volumes of more labour-intensive pipeline, piling and civil construction activity and a corresponding reduction in the more equipment-intensive mine support services during the period. Equipment costs represented 21.8% of revenue during the three months ended March 31, 2012, compared to 37.1% in same period last year. The reduction also reflects the work mix impact discussed above.

Equipment operating lease expense was $15.6 million during the three months ended March 31, 2012 compared to $16.1 million in the same period last year. Depreciation increased to $21.0 million (7.4% of revenue), from $12.7 million (7.3% of revenue) last year. We recorded a $9.7 million charge to depreciation, in the current period, specific to an asset impairment of an older fleet of trucks that was under-performing compared to our targeted reliability levels. This compares to the recording of a $0.9 million asset impairment charge to depreciation in the prior period.

Operating loss

For the three months ended March 31, 2012, we recorded an operating loss of $15.8 million, compared to an operating loss of $35.3 million during the same period last year. Revenue and gross profit in the prior-year period were reduced by the $42.5 million writedown related to the Canadian Natural contract. Excluding activity from the Canadian Natural contract, operating loss for the three-months ended March 31, 2012 would have been $19.0 million compared to operating income of $4.2 million, or 2.5% of revenue for the prior period. G&A expense for the three months ended March 31, 2012 increased by $0.3 million, reflecting higher employee costs, partially offset by reductions in stock-based compensation expense resulting from a decrease in our share price year-over-year.

Net loss

For the three months ended March 31, 2012, we recorded a loss of $16.9 million (basic and diluted loss per share of $0.47), compared to a net loss of $30.5 million (basic and diluted loss per share of $0.84) during the same period last year. Revenue and gross profit in the prior-year period were reduced by the $42.5 million writedown. Excluding this writedown, net loss would have been $2.9 million (basic and diluted loss per share of $0.08). Non-cash, non-recurring items affecting net income included non-cash gains on embedded derivatives. Non-cash, non -recurring items affecting net income for the same period last year included non-cash gains on embedded derivatives in a long-term customer contract and certain long-term supplier contracts. Excluding these non-cash items in the current and prior-year periods, net loss would have been $18.0 million (basic and diluted loss per share of $0.50) down from a net loss of $0.2 million (basic and diluted loss per share of $0.01).

Segment Three Month Results

Heavy Construction and Mining

	Three Months Ended March 31,
(dollars in thousands)	2012		2011			Change
Segment revenue		$181,094		$146,475			$34,619
Segment profit (loss)		$23,418		$(14,071	)		$37,489
Segment margin		12.9%		-9.6%

For the three months ended March 31, 2012, the Heavy Construction and Mining segment increased revenues to $181.1 million, up $34.6 million from the same period last year. Excluding the activity from the Canadian Natural overburden removal activity from both periods, segment revenue would have increased by $13.0 million to $150.6 million for the three months ended March 31, 2012.

14 2012 Annual Report

NOA

The segment achieved improved project development revenue during the period, reflecting the addition of heavy civil construction volumes at Total and light industrial construction activity at the Mt. Milligan Copper/Gold Project. These gains were partially offset by a reduction in recurring services revenue. While demand for reclamation, overburden removal and site services increased under new contracts with Suncor and Syncrude, lower mine services demand at Shell, unexpected work stoppages at two major oil sands sites and an unusually warm winter had a negative impact on recurring services results. The warm weather hampered our ability to perform muskeg removal and reclamation activities, both of which require frozen ground conditions. The unexpected work stoppages resulted firstly as a continuation of a third quarter stoppage, where the client ceased all work on a major tailings related project to allow time for reengineering and secondly when a second client’s changes to their mine plan resulted in reduced activity while the client identified alternate scopes of work.

For the three months ended March 31, 2012, Heavy Construction and Mining segment margin was 12.9% compared to negative 9.6% during the same period last year. Adjusting profit and margin results to exclude the impact of the Canadian Natural contract from both periods, Heavy Construction and Mining segment profit for the three months ended March 31, 2012 would have been $20.2 million or 13.4% of revenue compared to $25.4 million or 18.5% in the same period last year. The reduction in adjusted segment margin reflects continued pricing pressure, the effect of the unseasonably warm weather on muskeg removal and reclamation productivity and costs incurred as a result of the unexpected work stoppages. The reduction in adjusted segment margin was partially offset by the increase in higher-margin heavy civil activity during the period.

Piling

	Three Months Ended March 31,
(dollars in thousands)	2012		2011		Change
Segment revenue		$52,914		$22,256		$30,658
Segment profit		$13,447		$1,955		$11,492
Segment margin		25.4%		8.8%

The Piling segment achieved revenues of $52.9 million in the three months ended March 31, 2012, an increase of $30.7 million compared to the same period last year. The increase in Piling segment revenue reflects the strong recovery of commercial and industrial construction markets across Canada and its positive impact on piling demand. Favourable weather conditions contributed to the strong results by enabling completion of late-starting projects.

For the three months ended March 31, 2012, segment margin increased to 25.4% from 8.8% in the same period last year. Strong volumes across all regions and exceptional productivity during the unseasonably warm winter months led to the positive results for the current period. Segment margins for the prior-year period were negatively impacted by project start-up delays resulting from an abnormally long and cold winter in Alberta and Saskatchewan and margin reduction on a larger lump-sum contract.

Pipeline

	Three Months Ended March 31,
(dollars in thousands)	2012			2011			Change
Segment revenue		$48,498			$5,779			$42,719
Segment loss		$(9,360	)		$(1,549	)		$(7,811	)

Pipeline revenues for the three months ended March 31, 2012 were $48.5 million, a $42.7 million increase from last year. Revenue in the current period primarily reflects the execution of two large-diameter pipeline projects in Northeast British Columbia and Northern Alberta and the start-up of the new pipeline maintenance cost-reimbursable contract. Revenue in the prior-year period was driven primarily by project closeout activity on two large diameter pipeline jobs in Northeast BC.

The segment loss for the three months ended March 31, 2012 resulted from higher-than-anticipated cost escalations on materials and site overhead costs for the two large-diameter pipeline projects underway in the division. It also reflects an increase in the estimated costs to complete spring cleanup and warranty work on the two prior-year projects in Northern British Columbia. Partially offsetting this segment loss were strong margins on the new pipeline maintenance contract and a recovery of costs on a large-diameter pipeline project undertaken in Southern British Columbia in fiscal 2010. Segment losses for the prior-year period reflect the realization of risks undertaken as part of contracts negotiated during the recession, as well as the negative impact of weather delays on productivity.

2012 Annual Report 15

Non-Operating Income and Expense

	Three Months Ended March 31,									Year Ended March 31,
(dollars in thousands)	2012			2011			Change			2012			2011			2010			Change 2012 vs 2011			Change 2012 vs 2010
Interest expense
Long term debt
Interest on 8 3/4% senior notes and swaps		$–			$–			$–			$–			$1,238			$19,041			$(1,238	)		$(19,041	)
Interest on Series 1 Debentures		5,132			5,133			(1	)		20,531			20,132			–			399			20,531
Interest on credit facilities		2,141			1,681			460			7,430			5,361			2,375			2,069			5,055
Interest on capital lease obligations		99			144			(45	)		445			689			1,032			(244	)		(587	)
Amortization of deferred financing costs		393			366			27			1,591			1,609			3,348			(18	)		(1,757	)
Interest on long term debt		$7,765			$7,324			$441			$29,997			$29,029			$25,796			$968			$4,201
Other interest		36			37			(1	)		328			962			284			(634	)		44
Total Interest expense		$7,801			$7,361			$440			$30,325			$29,991			$26,080			$334			$4,245
Foreign exchange (gain) loss		(18	)		31			(49	)		52			(1,659	)		(48,901	)		1,711			48,953
Realized and unrealized (gain) loss on derivative financial instruments		(1,422	)		(1,965	)		543			(2,382	)		(2,305	)		54,411			(77	)		(56,793	)
Loss on debt extinguishment		–			–			–			–			4,346			–			(4,346	)		–
Income tax (benefit) expense		(5,296	)		(10,305	)		5,009			(7,223	)		(6,448	)		13,679			(775	)		(20,902	)

Interest expense

Total interest expense increased $0.4 million in the three months ended March 31, 2012 and increased $0.3 million in the year ended March 31, 2012, compared to the corresponding periods in fiscal 2011. Total interest expense increased $4.2 million in the year ended March 31, 2012 compared to the year ended March 31, 2010.

In April 2010, we completed a debt restructuring which included a private placement of 9.125% Series 1 Debentures (Series 1 Debentures), the redemption and cancellation of all our outstanding 8 ³/4% senior notes along with the termination of our cross currency and interest rate swaps. In addition, on April 30, 2010, we added borrowing capacity through a fourth amended and restated credit agreement and subsequently added a temporary increase to our revolving credit facility through second and third amending agreements, dated September 30, 2011 and March 27, 2012, respectively. A more detailed discussion on our Series 1 Debentures, our credit facilities and our debt restructuring can be found under “Capital Resources”.

At March 31, 2012, we had a total of $78.8 million outstanding under the credit facilities, compared to a total of $72.0 million outstanding under these facilities as at March 31, 2011 and $28.4 million as at March 31, 2010. Interest expense for the credit facilities was $2.1 million and $7.4 million for the three months and year ended March 31, 2012, respectively, compared to $1.7 million and $5.4 million, respectively, for the three months and year ended March 31, 2011 and $2.4 million for the year ended March 31, 2010. The increased interest expense in the current period reflects the cost of the higher amounts borrowed under the credit facilities.

The interest expense of $1.2 million on our 8 ³/4% senior notes for the year ended March 31, 2011 reflects interest costs to the redemption date. The senior notes redemption and associated swap agreement terminations eliminated the cost of hedging the foreign currency interest rate, which was reflected as a portion of “realized and unrealized (gain) loss on derivative financial instruments”. Foreign currency interest rate hedge costs were $15.6 million for the year ended March 31, 2010.

Foreign exchange (gain) loss

Our exposure to foreign currency risk was minimized with the redemption of our 8 ³/4% senior notes on April 28, 2010. The foreign exchange gains recognized in the year ended March 31, 2010 relate primarily to the effect of changes in the exchange rate of the Canadian dollar against the US dollar on the carrying value of the US$200 million 8 ³/4% senior notes. The increase in the value of the Canadian dollar, from 0.9846 CAN/US at March 31, 2010 to 0.9874 CAN/US at April 28, 2010 when the 8 ³/4% senior notes were redeemed, resulted in a realized foreign exchange gain for fiscal 2011. A more detailed discussion about our foreign currency risk can be found under “Quantitative and Qualitative Disclosures about Market Risk – Foreign exchange risk”.

16 2012 Annual Report

NOA

Realized and unrealized (gain) loss on derivative financial instruments

The realized and unrealized (gain) loss on derivative financial instruments reflects changes in the fair value of derivatives embedded in our previously outstanding 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 employed to provide an economic hedge for those senior notes. Realized and unrealized gains and losses also include changes in the value of embedded derivatives in long-term customer contracts and in supplier maintenance agreements. The realized and unrealized gains and losses on these derivative financial instruments, for the three months and years ended March 31, 2012 and 2011, respectively and the year ended March 31, 2010, are detailed in the table below:

	Three Months Ended March 31,								Year Ended March 31,
(dollars in thousands)	2012			2011			Change		2012			2011			2010			Change 2012 vs 2011			Change 2012 vs 2010
Swap liability (gain) loss		$–			$–			$–		$–			$1,783			$49,078			$(1,783	)		$(49,078	)
Redemption option embedded derivative (gain) loss		–			–			–		–			–			(3,716	)		–			3,716
Supplier contract embedded derivative (gain) loss		(1,422	)		(1,686	)		264		3,495			(3,812	)		(13,315	)		7,307			16,810
Customer contract embedded derivative (gain) loss		–			(279	)		279		(5,877	)		(604	)		6,805			(5,273	)		(12,682	)
Swap interest payment		–			–			–		–			328			15,559			(328	)		(15,559	)
Total		$(1,422	)		$(1,965	)		$543		$(2,382	)		$(2,305	)		$54,411			$(77	)		$(56,793	)

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 operating performance.

The swap liability loss reflects the changes in the fair value of the cross-currency and interest rate swaps that we employed to provide an economic hedge for our previously outstanding US dollar denominated 8 ³/4% senior notes. Changes in the fair value of these swaps generally had an offsetting effect to changes in the value of our previously outstanding 8 ³/4% senior notes (and resulting foreign exchange gains and losses), with both being triggered by variations in the Canadian/US dollar exchange rate. However, the valuations of the derivative financial instruments were also impacted by changes in interest rates and the remaining present value of scheduled interest payments on the swaps, which occurred in June and December of each year until termination of the swap agreements on April 8, 2010.

The redemption option embedded derivative gain in the year ended March 31, 2010 reflects changes in the fair value of a derivative embedded in our previously outstanding US dollar denominated 8  ³/4% senior notes. Changes in the fair value resulted from changes in long-term bond interest rates during a reporting period.

With respect to the supplier contracts, the fair value of the embedded derivative related to long-term supplier contracts decreased as a result of the strengthening of the Canadian dollar against the US dollar during the three months ended March 31, 2012 and 2011, respectively. 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.

As a result of the Memorandum of Understanding signed with Canadian Natural, a provision in the original contract that required adjustments to customer billings to reflect changes in exchange rates and price indices was eliminated. This effectively removed an embedded derivative from the contract and led to the reversal of the associated embedded derivate liability in the year ended March 31, 2012. Results from the three months and year periods in the prior year and for the year ended March 31, 2010, reflect changes in the measurement of this embedded derivative in the original contract.

The measurement of the swap interest payment for the years ended March 31, 2011 and 2010, respectively, reflects the realized loss on our previously outstanding interest rate swaps.

Income tax (benefit) expense

For the three months ended March 31, 2012, we recorded a current income tax expense of $0.8 million and a deferred income tax benefit of $6.1 million, for a total income tax benefit of $5.3 million. This compares to a combined income tax benefit of $10.3 million for the same period last year. For the year ended March 31, 2012, we recorded a current income tax benefit of $0.7 million and a deferred income tax benefit of $6.5 million for a total income tax benefit of $7.2 million. This compares to a combined income tax benefit of $6.4 million for the same period last year and a combined income tax expense of $13.7 for the year ended March 31, 2010.

2012 Annual Report 17

For the three months and year ended March 31, 2012, income tax expense as a percentage of income before income taxes differed from the statutory rate of 26.25%. This difference is primarily due to the impact of changes in enacted tax rates, CRA audit adjustments from 2007 and 2008, which flow through the current and deferred income tax accounts, and an increase in the permanent differences in stock-based compensation resulting from a partial restructuring of the stock option plan. For the three months ended March 31, 2011, income tax expense as a percentage of income before income taxes differed from the statutory rate of 27.75% primarily due to the changes in the timing of the reversal of temporary differences. For the year ended March 31, 2011, income tax expense as a percentage of income before income taxes differed from the statutory rate of 27.75%, largely due to the same factors affecting the year ended March 31, 2012. For the year ended March 31, 2010, income tax as a percentage of income before income taxes differed 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 reversal of temporary differences.

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 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, work order or change 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 services agreements where scope is not clearly defined. For the three months and year ended March 31, 2012, the total amount of revenue earned from time-and-material contracts performed under our master services agreements, which are not in backlog, was approximately $38.8 million and $249.2 million respectively.

Our estimated backlog by segment and contract type as at March 31, 2012, December 31, 2011 and March 31, 2011 was:

(dollars in thousands)	March 31, 2012		December 31, 2011		March 31, 2011		March 31, 2010
By Segment
Heavy Construction & Mining		$654,284		$768,664		$568,717		$800,751
Piling		73,997		43,141		12,558		16,423
Pipeline		5,297		26,758		1,427		6,861
Total		$733,578		$838,563		$582,702		$824,035
By Contract Type
Unit-Price		$291,192		$801,056		$567,062		$797,694
Lump-Sum		11,396		23,855		11,861		18,429
Time-and-Material, Cost-Plus		430,990		13,652		3,779		7,912
Total		$733,578		$838,563		$582,702		$824,035

The Canadian Natural contract represented approximately $417.8 million of the March 31, 2012 backlog. The backlog amount for this customer represents our estimates of future revenues taking into consideration the March 27, 2012 contract amendment that defined new target price terms, minimum yearly overburden removal volumes and the reduction in future revenues because of the contract-related asset sales to Canadian Natural. This compares to $484.7 million in our interim MD&A for the three and nine months ended December 31, 2011, which estimated backlog based on estimated pricing defined in the terms of the memorandum of understanding, signed with this customer on December 22, 2011. The $539.4 million and $781.7 million backlog estimates for this customer, in our annual MD&A for the years ended March 31, 2011 and 2010, respectively, assumed original contract volumes and forecasted margins.

The ability to complete overburden removal backlog volumes under the fixed term Canadian Natural contract is dependent on contract fleet capacity and access to the Horizon mine site. Thus, any suspension of work on the Canadian Natural site, such as that which occurred as a result of wildfires and a production facility fire in fiscal 2012, will result in a reduction of the backlog volumes that we can complete by the end of the contract term.

We expect that approximately $424.7 million of total backlog will likely be performed and realized in the 12 months ending March 31, 2013, together with a significant volume of work available but not included in the backlog calculation.^¿

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

18 2012 Annual Report

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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:

• changes in client requirements, specifications and design;

• changes in materials and work schedules; and

• changes in ground and weather conditions.

Contract change management processes require that we prepare and submit change orders to the client requesting approval of scope and/or price adjustments to the contract. Accounting guidelines require that 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 claims and unapproved or un-priced change orders 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, 2012, the Heavy Construction and Mining segment had approximately $1.4 million and $11.2 million respectively in claims revenue recognized to the extent of costs incurred, the Piling segment had $0.2 million and $2.6 million respectively in claims revenue recognized to the extent of costs incurred and the Pipeline segment had $6.4 million and $21.4 million respectively in claims revenue recognized to the extent of costs incurred.

As at March 31, 2012, we had $23.4 million of unresolved claims and change orders recorded on our balance sheet. These consisted of $1.9 million, $0.3 million and $21.2 million, respectively, for the Heavy Construction and Mining, Piling and Pipeline segments. This compares to $2.5 million of unresolved claims and change-orders recorded on our balance sheet for the year ended March 31, 2011, consisting of $0.6 million, $0.7 million and $1.2 million, respectively, for the Heavy Construction and Mining, Piling and Pipeline segments. We are actively working with our customers to expedite the execution of unsigned change orders and to resolve our claims.

Summary of Consolidated Quarterly Results

A number of factors have the potential to contribute to variations in our quarterly financial results between periods, including:

• the timing and size of capital projects undertaken by our customers on large oil sands projects;

• seasonal weather and ground conditions;

• 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.

The table, below, summarizes our consolidated results for the preceding eight quarters:

	March 31, 2012			Dec 31, 2011			Sep 30, 2011		Jun 30, 2011			March 31, 2011			Dec 31, 2010		Sep 30, 2010		Jun 30, 2010
(dollars in millions, except per share amounts)	Fiscal 2012											Fiscal 2011
Revenue		$282.5			$284.6			$245.4		$194.0			$174.5			$265.1		$234.9		$183.6
Gross profit (loss)		0.9			20.0			33.4		6.6			(17.4	)		30.8		29.1		15.6
Operating (loss) income		(15.8	)		2.8			18.3		(5.7	)		(35.5	)		11.3		12.3		1.1
Net (loss) income		(16.9	)		(1.9	)		6.6		(9.0	)		(30.5	)		3.7		2.4		(10.3	)
Net (loss) income per share – basic ‡		$(0.47	)		$(0.05	)		$0.18		$(0.25	)		$(0.84	)		$0.10		$0.07		$(0.29	)
Net (loss) income per share – diluted ‡		$(0.47	)		$(0.05	)		$0.18		$(0.25	)		$(0.84	)		$0.10		$0.06		$(0.29	)

‡ Net (loss) income 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.

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 rendered temporarily incapable of supporting the weight of heavy equipment. The duration of this period, which can vary considerably from year to year, 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 traditionally highest as ground conditions are most favourable in our operating regions. It should be noted that weather conditions during this period in each of the past two fiscal years have been unusual, causing results to deviate from this pattern. Overall, full-year results are not likely to be a direct multiple or combination of any one quarter or quarters. 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.

2012 Annual Report 19

The timing of large projects can also influence quarterly revenues. For example, Pipeline segment revenues were near zero for the three months ended June 30, 2011 but reached $66.4 million for the three months ended December 31, 2011.

The Heavy Construction and Mining segment experienced significant swings in overburden removal volumes on Canadian Natural’s Horizon site.

• In the six months ended September 30, 2010, overburden removal volumes were ramping up from the temporary shutdown of the Horizon project while Canadian Natural prepared for operations start-up;

• In the six months ended March 31, 2011, overburden removal volumes returned to normal; and

• In the three months ended June 30, 2011 volumes were negatively affected by wildfires in the region and an unrelated production facility fire. Canadian Natural issued a work suspension notice during this period and we did not resume overburden removal activities until the start of the three months ended March 31, 2012.

In addition to the swings in volume for this customer, we recorded a revenue writedown on the Canadian Natural contract, which negatively affected results for the three months ended March 31, 2011. During contract negotiations with Canadian Natural, revenue on the Canadian Natural contract was only reported to the extent of costs incurred for the nine months ended December 31, 2011. Revenue reported for the three months ended March 31, 2012 reflected the pricing structure negotiated under the amended Canadian Natural contract.

Profitability also varies from quarter-to-quarter as a result of claims and change-orders. While claims and change-orders are a normal aspect of the contracting business, they can cause variability in profit margin due to delayed recognition of revenues. During fiscal 2011 and 2012, the Pipeline segment reported significant swings in profit and margins because of delays in executing change-orders with a customer related to scope and design changes on several large-diameter pipeline construction projects. Because the customer has not yet executed the change orders, the segment reported revenue only to the extent of the $21.2 million in costs incurred for these change events. Additionally, the Pipeline segment recognized a $3.0 million forecasted loss for on a single lump-sum project for the three months ended December 31, 2011 and a further $9.4 million in losses on its large-diameter pipeline construction projects for the three months ended March 31, 2012. For further explanation, see “Claims and Change Orders”.

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, being spread over higher revenue levels. If activity decreases, these same fixed costs are spread over lower revenue levels. Both net income and income per share are also subject to financial leverage as provided by fixed interest expense.

Summary of Consolidated Financial Position

	Year Ended March 31,
(dollars in thousands)	2012			2011			2010			Change 2012 vs 2011			Change 2012 vs 2010
Cash		$1,400			$722			$103,005			$678			$(101,605	)
Current assets (excluding cash)		323,723			250,642			209,995			73,081			113,728
Current liabilities		(254,573	)		(165,819	)		(165,641	)		(88,754	)		(88,932	)
Net working capital		$70,550			$85,545			$147,359			$(14,995	)		$(76,809	)
Property, plant and equipment		312,775			321,864			331,355			(9,089	)		(18,580	)
Total assets		749,993			682,957			706,920			67,036			43,073
Capital Lease obligations (including current portion)		(10,701	)		(8,693	)		(13,393	)		(2,008	)		2,692
Total long term financial liabilites ‡		(313,871	)		(324,382	)		(327,356	)		10,511			13,485

‡ 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 obligations and both current and non-current deferred income tax balances.

At March 31, 2012, net working capital (current assets less current liabilities) was $70.6 million, down $15.0 million from March 31, 2011 and down $76.8 million from March 31, 2010.

The cash balance at March 31, 2012 was $0.7 million higher than at March 31, 2011 and $101.6 million lower than at March 31, 2010. The significant reduction in our current cash position, compared to fiscal 2010, was driven by:

• The acquisition of Cyntech ($23.5 million cash outflow);

• Debt restructuring which included the redemption of the 8 ³/4% senior notes and associated cross-currency and interest rate swaps, the issuance of Series 1 Debentures and associated financing costs (net $76.5 million cash outflow);

• Net increase in borrowing through the term facilities of $50.0 million, combined with scheduled repayments of $20.0 million (net $30.0 million cash inflow);

• Net increase in borrowings through the revolving facilities (net $20.3 million);

• Purchase of equipment and intangible assets ($106.5 million cash outflow);

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• Repayment of capital lease obligations ($10.3 million cash outflow);

• Cash generated from operating activities ($62.8 million cash inflow) which included Canadian Natural contract receipts of:

• $34.1 million for contract settlement

• $4.3 million for outstanding change-order settlement

• $3.0 million for mobilization costs

As at March 31, 2012, we had borrowings of $20.3 million against our Revolving Facility compared to $3.5 million and zero as at March 31, 2011 and 2010, respectively.

Current assets, excluding cash, increased $73.1 million between March 31, 2011 and March 31, 2012. The increase reflects an $85.6 million increase in trade receivables and holdbacks and a $4.1 million increase in inventory, partially offset by a decrease in unbilled revenue of $16.1 million. Canadian Natural’s exercise of its right to purchase contract-related assets during the year ended March 31, 2012 contributed $66.1 million to the increase in trade accounts receivables and holdbacks with the majority of the proceeds received in April 2012. The same transaction resulted in the decrease in unbilled revenue of $16.5 million and the decrease in inventory of $8.5 million. Current assets, excluding cash, increased $113.7 million between March 31, 2010 and March 31, 2012, reflecting a $102.2 million increase in trade receivables and holdbacks, a $2.2 million increase in unbilled revenue and an $8.8 million increase in inventory. The increase in trade receivables reflects the Canadian Natural equipment buyout while the increased inventory reflects the acquisition of Cyntech and an increase in tire inventory.

Current liabilities increased by $88.8 million between March 31, 2011 and March 31, 2012, reflecting an $85.1 million increase in accounts payable, a $5.5 million increase in billings in excess of costs, offset by a $6.1 million decrease in the deferred tax liabilities. Equipment purchases of $3.8 million, which are scheduled to be paid after March 31, 2012, are included in accounts payable as of March 31, 2012. The current year accounts payable increase reflects an increase in fourth quarter activity and the timing of vendor payments. Contributing to the increase in accounts payable during the current year is the $12.9 million planned operating lease buyouts associated with the Canadian Natural buyout. Current liabilities increased by $88.9 million between March 31, 2010 and March 31, 2012, reflecting a $104.3 million increase in accounts payable due to increased current fourth quarter volumes, timing of vendor payments and the Canadian Natural buyout. This was partly offset by a $18.8 million decrease in the current portion of embedded derivatives in financial instruments compared to the year ended March 31, 2010, as a result of the redemption of cross-currency and interest rate swaps related to our 8 ³/4% senior notes.

Property, plant and equipment net book value decreased $9.1 million and $18.6 million between March 31, 2012 and the years ended March 31, 2011 and 2010, respectively. This reflects the $60.0 million of capitalized maintenance and equipment purchases during the current-year period, offset by the $27.1 million sale of contract-related assets to Canadian Natural, depreciation of $40.2 million and net book value of disposals worth $1.9 million in the current-year period.

Total long-term financial liabilities decreased by $10.5 million and $13.5 million between the March 31, 2012 and March 31, 2011 and 2010, respectively, largely due to a decrease in the long-term portion of accrued over-hour liabilities under operating lease agreements. The make-up of our long-term financial liabilities was significantly changed during the fiscal year ended March 31, 2011, due largely to our debt refinancing which is described in more detail in “Capital Resources – Long-term debt restructuring”.

Summary of Consolidated Equipment Additions

We acquire our equipment 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 while capital leases and operating leases are varying ways of financing those capital expenditures.

We define our equipment requirements as either:

• sustaining additions – those that are needed to keep our existing fleet of equipment at its optimal useful life through capital maintenance or replacement; or

• growth additions – those that are needed to perform larger or a greater number of projects.

2012 Annual Report 21

A summary of tangible and intangible asset additions by nature and by period is shown in the table below:

	Three Months Ended March 31,							Year Ended March 31,
(dollars in thousands)	2012		2011		Change			2012		2011		2010		Change 2012 vs 2011			Change 2012 vs 2010
PP&E – Capital Expenditures
Sustaining		$13,663		$1,444		$12,219			$34,617		$16,853		$14,536		$17,764			$20,081
Growth		6,613		2,038		4,575			18,862		17,031		42,346		1,831			(23,484	)
Total		20,276		3,482		16,794			53,479		33,884		56,882		19,595			(3,403	)
Capital Leases
Sustaining		4,320		–		4,320			4,361		–		867		4,361			3,494
Growth		2,467		336		2,131			2,853		427		656		2,426			2,197
Total		6,787		336		6,451			7,214		427		1,523		6,787			5,691
PP&E – Operating lease additions
Sustaining		–		26,739		(26,739	)		8,102		30,118		–		(22,016	)		8,102
Growth		–		5,421		(5,421	)		5,735		16,166		93,090		(10,431	)		(87,355	)
Total		–		32,160		(32,160	)		13,837		46,284		93,090		(32,447	)		(79,253	)
Intangible assets – Capital expenditures
Sustaining		252		1,139		(887	)		418		1,202		847		(784	)		(429	)
Growth		999		854		145			3,119		3,546		2,515		(427	)		604
Total		1,251		1,993		(742	)		3,537		4,748		3,362		(1,211	)		175
Total sustaining equipment additions		18,235		29,322		(11,087	)		47,498		48,173		16,250		(675	)		31,248
Total growth equipment additions		10,079		8,649		1,430			30,569		37,170		138,607		(6,601	)		(108,038	)

The change in sustaining additions for the three months ended March 31, 2012 compared to the prior period is reflective of the timing of scheduled capital maintenance activities. Sustaining additions for the year ended March 31, 2012 were similar to the year ended March 31, 2011, but were $31.2 million higher than the year ended March 31, 2010, resulting from a large increase in the level of capitalized maintenance required for the significant growth in our heavy equipment fleet in 2009 and 2010.

Growth additions for the three months ended March 31, 2012 is reflective of our investment in equipment for the Piling segment and maintenance support equipment required to support our expanded activities across more customer sites. Included in the growth capital additions for the three months ended March 31, 2011 is $1.3 million related to the Cyntech acquisition. The decrease in growth equipment additions for the year ended March 31, 2012, compared to the previous two years, reflects the completion of contractual equipment additions, primarily funded through operating leases, related to the Canadian Natural contract, part way through fiscal 2011. Additionally we reduced spending on growth equipment in the years ended March 31, 2012 and 2011, respectively, compared to the year ended March 31, 2010, as equipment demand was reduced due to project start-up delays for new mine development activities. We are meeting short-term increases to equipment demand, to support our mine expansion and development work mix, through an increased use of rental equipment.

The decrease in equipment additions funded through operating leases for the three months ended March 31, 2012, compared to the same period in the prior year, resulted from a change to financing equipment additions through cash from operations as opposed to operating leases. The decrease in equipment additions financed through operating leases for the year ended March 31, 2012 compared to the same periods in 2011 and 2010, respectively, reflects this same change in equipment financing along with the above mentioned completion of the contractual Canadian Natural fleet additions part way through 2011.

Summary of Consolidated Cash Flows

	Three Months Ended March 31,
(dollars in thousands)	2012			2011			Change
Cash provided by operating activities		$53,574			$13,531			$40,043
Cash used in investing activities		(32,675	)		(13,736	)		(18,939	)
Cash (used in) provided by financing activities		(21,272	)		211			(21,483	)
Foreign currency translation loss on cash		(24	)		(32	)		8
Net decrease in cash and cash equivalents		$(397	)		$(26	)		$(371	)

22 2012 Annual Report

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	Year Ended March 31,									Change
(dollars in thousands)	2012			2011			2010			2012 vs 2011		2012 vs 2010
Cash provided by (used in) operating activities		$63,273			$(497	)		$42,625			$63,770		$20,648
Cash used in investing activities		(64,200	)		(64,632	)		(59,611	)		432		(4,589	)
Cash provided by (used in) financing activities		1,565			(37,095	)		21,111			38,660		(19,546	)
Foreign currency translation gain (loss) on cash		40			(59	)		–			99		40
Net increase (decrease) in cash and cash equivalents		$678			$(102,283	)		$4,125			$102,961		$(3,447	)

Operating activities

Cash provided by operating activities for the three months ended March 31, 2012 increased to $53.6 million, compared to $13.5 million for the three months ended March 31, 2011, primarily as a result of increased gross profit and lower non-cash net working capital.

Cash provided by operating activities during the year ended March 31, 2012 was $63.3 million, compared to cash used in operating activities of $0.5 million and cash provided by operations of $42.6 million for the years ended March 31, 2011 and 2010 respectively. Activity in the current year benefitted from the $38.4 million reduction in non-cash net working capital, from the Canadian Natural settlement of past work price escalators and change orders, offsetting the low gross profits in the period. The growth in non-cash working capital on this same contract along with low gross profit negatively affected activity in the year ended March 31, 2011, while strong gross profit mitigated the growth in non-cash working capital in the year ended March 31, 2010.

Investing activities

Cash used by investing activities for the three months ended March 31, 2012 was $32.7 million, compared to $13.7 million for the same period a year ago. Investing activities in the current period included capital and intangible asset expenditures of $32.7 million. Cash used in investing activities for the three months ended March 31, 2011 included $2.7 million for Cyntech and capital and intangible asset expenditures of $11.2 million.

Cash used by investing activities for the year ended March 31, 2012 was $64.2 million compared with $64.6 million and $59.6 million for the years ended March 31, 2011 and 2010, respectively. Current period investing activities primarily included capital and intangible asset expenditures of $65.3 million, partially offset by disposal of capital assets. Cash used in investing activities in the prior-year included capital and intangible expenditures of $41.2 million and $23.5 million for the acquisition of Cyntech Corporation, less cash proceeds from asset dispositions of $1.3 million. Cash used in investing activities during the year ended March 31, 2010 included capital and intangible expenditures of $55.3 million, $5.4 million for Cyntech and $2.9 million for advances to our unconsolidated joint venture, less cash proceeds from asset dispositions of $3.9 million.

Financing activities

Cash used in financing activities during the three-month period ended March 31, 2012 was $21.3 million as a result of a decrease in the Revolving Facility of $17.7 million, a scheduled $2.5 million repayment on our term credit facilities and a $1.1 million repayment of capital lease obligations. Cash provided by financing activities for the three-month period ended March 31, 2011 was $0.2 million as a result of an increase in the Revolving Facility of $3.5 million, a scheduled $2.5 million repayment on our term credit facilities and a $1.1 million repayment of capital lease obligations.

Cash provided by financing activities during the year ended March 31, 2012 was $1.6 million, primarily a result of an increase in the revolving facility of $16.8 million, offset by $10.0 million in scheduled repayments on our term facilities and a $5.2 million repayment of capital lease obligations. Cash provided by financing activities during the year ended March 31, 2011 totaled $37.1 million. This was primarily a result of the debt refinancing and swap cancellation activities, which included $7.9 million of financing costs for the credit agreement and the Series 1 Debentures. Additional activities included scheduled repayments on our Term Facilities and repayment of capital lease obligations. Cash provided by financing activities of $21.1 million for the year ended March 31, 2010 reflects capital expenditure financing of $27.8 million (net of term credit facilities repayments). This was partially offset by the $5.6 million repayment of capital lease obligations, $1.1 million in financing costs for the amendment of the credit agreement and the repayment of debt assumed with the acquisition of DF Investments Limited.

Foreign currency translation loss on cash

During the year ended March 31, 2011, we established a US-based subsidiary, “Cyntech U.S. Inc.”, which has a US dollar functional currency. The accounts of this subsidiary are translated into Canadian dollars using the current rate method. Assets and liabilities are translated at the rate of exchange in effect at the balance sheet date and revenue and expense items (including depreciation and amortization) are translated at the average rate of exchange for the period. The resulting unrealized exchange gains and losses from these translation adjustments are included as a separate component of shareholders’ equity in unrealized foreign currency translation loss. The effect of exchange rate changes on cash balances held in foreign currencies is separately reported as part of the reconciliation of the change in cash and cash equivalents for the period. This effect was not material for the three months and year ended March 31, 2012.

2012 Annual Report 23

D. OUTLOOK

We anticipate steady activity levels and improved profitability throughout fiscal 2013.^¿

In our recurring services business, near-term demand for certain mine support services could continue to be impacted by insourcing, project delays and project deferrals as producers focus on cost control. However demand for reclamation and tailings services, combined with mine expansion projects and the resumption of overburden removal activity at Canadian Natural following last year’s seven-month shutdown, should help to offset these impacts. At Suncor, we expect to maintain volumes with a variety of projects under our five-year master services agreement, while at Syncrude, we plan to ramp up the construction of the shear key foundation as part of the first phase of the mine relocation project at Base Mine. As this project nears its anticipated completion this summer, we are scheduled to transition into the second phase of the relocation with construction of a mechanically stabilized earth (MSE) wall.^¿

At Canadian Natural, we expect to operate near full production throughout the year under our amended contract. The amended contract includes a revised payment structure that carries less risk for us than the unit-rate structure it replaces. It also ensures a base margin on all work performed with the opportunity to enhance margins by meeting mutually agreed-upon performance targets. Exxon’s Kearl project is expected to begin production in 2012 and to create additional bidding opportunities for both mine support and overburden removal services. ^¿

On the project development side of our business, we expect to continue executing initial earthworks at the Joslyn North Mine Project under our recently announced contract. Suncor has also announced 2012 capital spending plans for initial site development at Fort Hills and we intend to pursue opportunities for work on this site as they arise. Our industrial construction work at the Mt. Milligan Copper/Gold Project in Northern British Columbia is expected to continue through to the end of the year. In addition, we were recently awarded a site development contract at PetroChina’s Dover SAGD project and we intend to pursue site development opportunities on other SAGD projects.^¿

The outlook for our Piling business remains positive with strong industry fundamentals and a large project backlog supporting our expectation of continued strong performance from this segment in fiscal 2013.^¿

We do not anticipate a significant contribution from the Pipeline division in fiscal 2013 as a result of our decision to downsize the segment and reduce risk. The division will continue to focus on executing a pipeline integrity dig program under a multi-year, cost-reimbursable contract with a major Canadian pipeline company. The Pipeline division will also continue to pursue small oil sands projects and will consider opportunities to construct mid-to-large inch diameter pipelines on a cost-reimbursable or time-and-materials basis. We believe opportunities for lower-risk projects could increase over time if contractor supply becomes more constrained.^¿

Overall, we have a healthy backlog of work and solid opportunities heading into the next fiscal year. We have addressed the losses in the Pipeline division and we have resolved the Canadian Natural contract issue with a very positive outcome that has provided benefits for both our client and us. With a continued focus on performance, efficiency and risk management, we intend to improve profitability and continue to strengthen our balance sheet in fiscal 2013.^¿

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:

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

• building and similar codes and zoning ordinances;

• laws and regulations relating to consumer protection; and

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

We believe 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. 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, administer these laws and regulations. The requirements of these laws and regulations are becoming increasingly complex and stringent and meeting these requirements can be expensive.

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

24 2012 Annual Report

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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 in relation to 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 that 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 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, 2010, 2011 and 2012 were not material. We do not currently anticipate any material adverse effect on our business or financial position because 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, 2012, we had 743 salaried employees and approximately 2,270 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 3,500 employees depending on the time of year and duration of awarded projects. We also utilize the services of subcontractors in our construction business. Subcontractors perform an estimated 8% to 10% of the construction work we undertake. As of March 31, 2012, approximately 2,050 employees are members of various unions and work under collective bargaining agreements.

The majority of our work is carried out by employees governed by our mining overburden collective bargaining agreement with the International Union of Operating Engineers (IUOE) Local 955, the primary term of which expires on March 31, 2015. 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, 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. The provincial collective agreement between the IUOE Local 955 and the Alberta Roadbuilders and Heavy Construction Association (ARBHCA) expires February 28, 2013.

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

Liquidity

Sources of liquidity

Our principal sources of cash are funds from operations and borrowings under our credit facility. As at March 31, 2012, our cash balance of $1.4 million was $0.7 million higher than our cash balance at March 31, 2011. We supplemented our cash requirements during the year ended March 31, 2012 through drawings from our Revolving Facility. As of March 31, 2012 there were outstanding borrowings of $20.3 million and issued and undrawn letters of credit of $15.0 million under the $105.7 million Revolving Facility and outstanding borrowings of $58.4 million ($68.4 million and $28.4 million at March 31, 2011 and 2010, respectively under the Term Facilities A more detailed discussion on the Revolving Facility and our Term Facilities can be found in “Credit facilities”, below.

We anticipate that we will likely have enough cash from operations to fund our expenses and capital additions for fiscal 2013. In the event that we require additional funding, we believe that any such funding requirements could be satisfied by the funds available from our Revolving Facility.^¿

Liquidity requirements

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

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

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We maintain a significant equipment and vehicle fleet comprised of units with remaining useful lives covering a variety of time spans. It is important for us to have an effective maintenance program to support our large revenue-producing fleet in order to avoid equipment downtime, which can affect our revenue stream and inhibit our project profits. 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.

Our equipment fleet value is currently split among owned (49%), leased (38%) and rented equipment (13%). Approximately 33.3% of our leased fleet value is specific to the Canadian Natural contract. This equipment mix is a change from the mix reported in previous periods because of the sale of contract-related assets to Canadian Natural and an increasing demand for specific types of rental equipment to support project development activity. 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 require between $50 million and $70 million annually for sustaining equipment additions and our total equipment additions typically range from $60 million to $130 million depending on our growth equipment requirements. We believe that our current fleet size and mix is in alignment with the current equipment demands from the commitment to Canadian oil sands development by the oil sands producers along with the commercial and industrial construction markets. We have continued to assess and adjust the size and mix of our fleet and we have assessed our growth capital needs for the coming fiscal year as we monitor the progress of start-up delays on oil sands development projects. Our estimate of our capital needs for the next fiscal year is approximately $70 million to $90 million.^¿

We typically finance approximately 20% to 30% of our total equipment additions through our operating and capital 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.^¿

Working capital fluctuations effect on liquidity

As at March 31, 2012, we had $19.1 million in trade receivables that were more than 30 days past due compared to $10.1 million as at March 31, 2011 and $7.5 million as at March 31, 2010. We have currently provided an allowance for doubtful accounts related to our trade receivables of $0.2 million ($nil at March 31, 2011 and $1.7 million at March 31, 2010). 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.

As of March 31, 2012, an amount of $18.1 million ($72.0 million at March 31, 2011 and $52.6 million at March 31, 2010) is recognized within unbilled revenue relating to the Canadian Natural contract, whereby the normal operating cycle for this project is greater than one year. The unbilled balance will be invoiced to Canadian Natural over the life of the amended contract. The customer maintains the right to accelerate the purchase of contract-related assets and if such right is exercised, the unbilled amount related to the equipment purchased becomes due in full at such time.

Contract change management processes often lead to a timing difference between project disbursements and our ability to invoice our customers for executed change orders. Until the time of invoice, revenue for unexecuted change orders is recorded only to the extent of costs incurred within unbilled revenue. As of March 31, 2012, we had $22.8 million of unresolved claims and change orders recorded in unbilled revenue. This compares to $2.2 million and $0.8 million for the years ended March 31, 2011 and 2010, respectively. For a more detailed discussion on claims revenue refer to “Claims and Change Orders”.

The seasonality of our business usually causes a peak in activity levels between December and early February that can result in an increase in our working capital requirements from higher accounts receivable and unbilled revenue balances. 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 if substantial completion of the contract has been performed, there are no outstanding claims by subcontractors or others related to work performed by us and we have met the 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, 2012, holdbacks totaled $32.1 million, up from $12.0 million and $3.9 million as at March 31, 2011 and 2010, respectively. Holdbacks represent 15.0% of our total accounts receivable as at March 31, 2012 (9.4% and 3.5% as at March 31, 2011 and 2010, respectively). The current year increase in holdbacks represents an increase in Piling and Pipeline segment projects and the timing of substantial completion.

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

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Credit facilities

On April 30, 2010, as part of a debt restructuring plan we entered into a Fourth Amended and Restated Credit Agreement, which provides credit facilities in the form of two Term Facilities and an $85.0 million Revolving Facility, under which letters of credit may also be issued. A more detailed discussion on the debt restructuring can be found below in “Securities, Rights Plans and Agreements–Long-term debt restructuring”, below.

On September 30, 2011, we entered into a Second Amending Agreement to the Fourth Amended and Restated Credit Agreement to provide a temporary revolving credit facility addition of $25.0 million through March 31, 2012. This temporary addition increased the total revolving credit facility commitments from $85.0 million to $110.0 million and provided additional borrowing availability to meet working capital requirements and to accommodate the issuance of letters of credit. The amendment required that the receipt of contract settlement proceeds from Canadian Natural would be used to repay amounts outstanding on the temporary credit facility addition and permanently reduce available borrowing under this temporary facility addition by the amount of the repayment. In December of 2011, $4.3 million of settlement proceeds reduced borrowing available under the Revolving Facility to $105.7 million.

On March 27, 2012, we entered into a Third Amending Agreement to the Fourth Amended and Restated Credit Agreement to extend the maturity date of the credit agreement by six months to October 31, 2013. The amendment also provides relief from the agreement’s Consolidated EBITDA related covenants by temporarily amending the covenants. The amendment also extended the term of the temporary addition to our revolving credit facility to June 30, 2012. The new amendment eliminated the permanent reduction of the temporary credit facility by the receipt of proceeds from the Canadian Natural contract settlement. However, terms were added requiring that 55% of any proceeds from asset sales to Canadian Natural will be used to repay amounts outstanding on the temporary credit facility addition and permanently reduce the amount available for borrowing to $85.0 million. Asset sale proceeds were received from Canadian Natural on April 30, 2012, which permanently eliminated the $20.7 million temporary addition to our revolving credit facility on that date.

The Term Facilities include scheduled principal repayments totaling $10.0 million per year with $2.5 million paid on the last day of each quarter commencing June 30, 2010. Advances under the Revolving Facility may be repaid from time to time at our option. In addition, we must make annual payments within 120 days of the end of our fiscal year for 50% of Consolidated Excess Cash Flow (as defined in the credit agreement) to a maximum of $4.0 million. Based on the calculation of Consolidated Excess Cash Flow at March 31, 2012, we will not be required to make an additional principal payment. Outstanding aggregate borrowing on our two Term Facilities is $58.4 million as of March 31, 2012.

The facilities bear interest at variable rates, based on the Canadian prime rate plus the applicable pricing margin (as defined within the credit agreement). Interest on Canadian prime rate loans is payable monthly in arrears. Stamping Fees (as defined in the credit agreement) and interest on advances of Bankers’ Acceptances (as defined in the credit agreement) are paid in advance, at the time of issuance.

The applicable pricing margin (as defined within the credit agreement) is connected to our credit rating from Standard & Poor’s. As our credit rating was downgraded by this credit agency, there was a 1.5% increase in our pricing margin (as defined within the credit agreement) (see “Debt Ratings”, below).

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

Permitted debt and contingent obligations under the credit agreement covenants include, but are not limited to:

• 9.125% Series 1 Debentures at an aggregate principle amount not to exceed $225.0 million (see “9.125% Series 1 Debentures”, below);

• Capital leases aggregating to a maximum of $30.0 million at any one time;

• Operating leases entered into in the normal course of business; and

• Contingent obligations under our performance bonding program.

We are also required to meet certain financial covenants defined in the credit agreement including:

i. Senior Leverage Ratio (Senior Leverage to Consolidated EBITDA) which must be less than 2.0 times (temporarily increased to less than 2.75 times for March 31, 2012);

ii. Consolidated Interest Coverage Ratio (Consolidated EBITDA to Consolidated Cash Interest Expense) which must be greater than 2.5 times (temporarily reduced to greater than: 1.75 times for March 31, 2012; 2.00 times for June 30, 2012; 2.00 times for September 30, 2012; and 2.25 times for December 31, 2012); and

iii. Current Ratio (Current Assets to Current Liabilities) which must be greater than 1.25 times.

2012 Annual Report 27

Continued access to the facilities is not contingent on the maintenance of a specific credit rating. The definition of these covenants is unchanged from the previous Third Amended and Restated Credit Agreement. Based on the latest amended credit agreement we remain in compliance with all of the financial covenants on our credit agreement as of March 31, 2012.

Consolidated EBITDA is defined within the 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 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), (iii) the one-time $42.5 million March 31, 2011 revenue writedown of the Canadian Natural contract, all of the foregoing as determined on a consolidated basis in conformity with GAAP.

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:

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.

Borrowing activity under the Revolving Facility

As at March 31, 2012, our unused borrowing availability under the Revolving Facility was $70.4 million ($69.2 million at March 31, 2011 and $79.6 million at March 31, 2010).

i. Cash drawn under the revolving facility: During the year ended March 31, 2012, we used our Revolving Facility to finance our working capital requirements. At March 31, 2012, we had $20.3 million of borrowings outstanding on our Revolving Facility. For the three months ended March 31, 2012, the average amount of our borrowing on the Revolving Facility was $57.1 million with a weighted average interest rate of 6.8%. For the year ended March 31, 2012, the average amount of our borrowing on the Revolving Facility was $40.4 million with a weighted average interest rate of 6.6%. The average amount of our borrowing on the Revolving Facility is calculated based on the weighted average of the outstanding balances in the three month and year periods, respectively. The maximum end of month balance for any single month during the three months and year ended March 31, 2012 was $63.0 million.

ii. Letters of credit drawn under the revolving facility: As of March 31, 2012, we had issued $15.0 million ($12.3 million at March 31, 2011 and $10.4 million at March 31, 2010) in letters of credit under the Revolving Facility to support performance guarantees associated with customer contracts. One of our major long-term contracts allows the customer to require that we provide up to $15.0 million in letters of credit. As at March 31, 2012, we had no letters of credit outstanding in connection with this contract. This customer must provide a 60-day prior written notice to request any change in their letter of credit requirements.

Long-term Commitments

Contractual obligations and other commitments

Our principal contractual obligations relate to our long-term debt, capital and operating leases and supplier contracts. The following table summarizes our future contractual obligations, excluding interest payments, unless otherwise noted, as of March 31, 2012.

	Payments due by fiscal year
(dollars in thousands)	Total		2013		2014		2015		2016		2017 and after
Series 1 Debentures		$225,000		$          –		$            –		$          –		$        –		$225,000
Term facilities		58,446		10,000		48,446		–		–		–
Revolving facility		20,321		–		20,321		–		–		–
Capital leases (including interest)		11,721		4,693		2,230		1,938		2,209		651
Equipment and building operating leases		127,569		56,921		40,774		21,218		6,452		2,204
Supplier contracts		42,881		17,615		22,484		2,782		–		–
Total contractual obligations		$485,938		$89,229		$134,255		$25,938		$8,661		$227,855

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The buyout of the operating leases related to the sale of contract-related assets to Canadian Natural, discussed under the “Explanatory Notes–Significant Business Event” section of our annual MD&A for the year ended March 31, 2012, did not reduce the future contractual obligations reported under “Equipment and building operating leases” in this table as the contract-related operating leases are scheduled to be bought out at the expiry of their lease terms.

For a discussion on term facilities and revolving facility see “Liquidity – Credit facilities”, above and for a discussion on Series 1 Debentures see “Securities, Rights Plans and Agreements – 9.125% Series 1 Debentures”, below.

Off-balance sheet arrangements

We have no off-balance sheet arrangements at this time.

Securities, Rights Plans and Agreements

Capital structure

We are authorized to issue an unlimited number of Voting Common Shares and an unlimited number of Non-Voting Common Shares. As at March 31, 2012, there were 36,251,006 voting Common Shares outstanding. We had no Non-Voting Common Shares outstanding as at March 31, 2012. For a more detailed discussion of our share data, see “Outstanding Share Data ” in our most recent AIF, which section is expressly incorporated by reference into this MD&A.

Shareholder Rights Plan and Registration Rights Agreement

On October 7, 2011, our Board of Directors adopted a Shareholder Rights Plan Agreement, dated October 7, 2011 (the “Rights Plan”) designed to encourage the fair and equal treatment of shareholders in connection with any takeover bid for our outstanding Common Shares. The Rights Plan was included as an exhibit to our Form 8-A, filed with the Securities and Exchange Commission on October 7, 2011. The Rights Plan terminated in accordance with its terms on April 7, 2012. For a discussion of our registration rights agreement, see “Registration Rights Agreement” in our most recent AIF.

9.125% Series 1 Debentures

On April 7, 2010, we closed a private placement of 9.125% Series 1 Debentures (as defined below) due 2017 (the “Series 1 Debentures”) for gross proceeds of $225.0 million and net proceeds after commissions and related expenses of $218.1 million as part of a debt restructuring plan. Financing fees of $6.9 million were incurred in connection with the Series 1 Debentures and were recorded as deferred financing costs. A more detailed discussion on the debt restructuring can be found in “Long-term debt restructuring”, below.

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 Series 1 Debentures, with the net cash proceeds of one or more of our public equity offerings (as defined in the trust indenture that governs the Series 1 Debentures) 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 Series 1 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 Series 1 Debentures, in whole or in part, at a redemption price which is equal to the greater of:

a. the Canada Yield Price (as defined in the trust indenture that governs the Series 1 Debenture); 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 Series 1 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 Series 1 Debentures are also subject to covenants limiting our ability and the ability of most or all of its subsidiaries: to incur additional debt; pay dividends or distributions on our common shares or repurchase our common shares; make various investments; create liens on our assets to secure debt; enter into transactions with affiliates; consolidate, merge or transfer all or substantially all of our property and assets and the property and assets of our subsidiaries on a consolidated basis; transfer and sell assets; and enter into sale and leaseback transactions. These covenants are subject to exceptions and qualifications that are detailed in the indenture governing the Series 1 Debentures.

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We are also required to meet a financial covenant with respect to our Series 1 Debentures that restricts the amount of additional debt that we and our subsidiaries can incur. Specifically, on a pro forma basis taking such additional debt into account, on a consolidated basis our “Consolidated Fixed Charge Coverage Ratio” must be greater than 2.0 to 1.0. The “Consolidated Fixed Charge Coverage Ratio” is approximately the same calculation as the “Interest Coverage” covenant found in our Credit Facility.

The Series 1 Debentures were rated B- by Standard & Poor’s and Caa1 by Moody’s (see “Debt Ratings”).

Long-term debt restructuring

In April 2010, we issued $225.0 million of Series 1 Debentures and entered into a fourth 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 2010. The full details of this debt restructuring are as follows:

9.125% Series 1 Debentures

On April 7, 2010, we closed a private placement of Series 1 Debentures for gross proceeds of $225.0 million and net proceeds after commissions and related expenses of $218.1 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 outstanding and US$7.1 million of accrued interest.

In connection with the redemption of our 8 ³/4% senior notes, we wrote off unamortized deferred financing costs of $4.3 million.

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 $91.1 million and represented the fair value of the swap agreements, including accrued interest. 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”.

$50.0 million Term Facility

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 facilities. At April 30, 2010, the second term facility was fully drawn at $50.0 million.

Debt Ratings

On March 5, 2012, Standard and Poor’s Ratings Services (“S&P”)²¹ downgraded our long-term corporate credit rating from ‘B+’ to ‘B-’ and the senior unsecured debt rating from ‘B+’ to ‘B-’. S&P changed the outlook on the corporate rating from ‘stable’ to ‘developing’ and the recovery rating on our Series 1 Debentures from ‘3’ to ‘4’. As part of its annual review, S&P updated its analysis on both our long-term corporate credit rating and the senior unsecured debt rating on May 30, 2012 and re-affirmed its previous ratings.

On March 2, 2012, Moody’s Investor Services, Inc. (Moody’s) downgraded both our Corporate Rating from B2 to B3 and our Series 1 Debentures Rating from B3 to Caa1. Moody’s has also changed its outlook on our corporate rating from ‘Stable’ to ‘Rating Under Review’ and its outlook on our Series 1 Debentures Rating from LDG5 to LDG4.

Our credit ratings from these two agencies are as follows:

Category	Standard & Poor’s	Moody’s
Corporate Rating	B-(‘developing’ outlook)	B3 (‘Rating Under Review’ outlook)
Series 1 Debentures	B-(recovery rating of “4”)	Caa1 (LGD≠ rating of “4”)

≠ Loss Given Default

A downgrade in our credit ratings, particularly the rating issued by S&P, will increase the interest rate payable on borrowings under our credit agreement, (see “Credit facilities”, above). Additionally, counterparties to certain agreements may require additional security or other changes in business terms if our credit ratings are downgraded. Furthermore, these ratings are required for us to access the public debt markets, and they affect the pricing of such debt. Any downgrade in our credit ratings from current levels could adversely affect our long-term financing costs, which in turn could adversely affect our ability to pursue business opportunities.

²¹  Standard and Poor’s Ratings Services (S&P), a division of The McGraw-Hill Companies, Inc.

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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 credit worthiness 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. Definitions of the categories of each rating and the factors considered during the evaluation of each rating have been obtained from each respective rating organization’s website.²²

Standard and 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 Series 1 Debentures indicates an expectation for an average of 30% to 50% 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

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. A Negative outlook means that a rating may be lowered. A Developing outlook means there is a one-in-three chance the rating could be raised or lowered during the two-year outlook horizon.

Moody’s

Obligations rated “Caa”: are considered to be in poor standing and are subject to very 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.

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 “4” indicates a loss range of greater than or equal to 50% and less than 70%.

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

Advisory Agreements

We have entered into a letter agreement with each of Sterling Group Partners I, L.P., Perry Partners, L.P. and Perry Partners International, Inc. (the “significant shareholders”) pursuant to which we have engaged each significant shareholder to provide their 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:

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

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

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

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

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

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

²²  This debt rating information is current as of this report and we undertake no obligation to provide investors with updated information.

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• 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.

Internal Systems and Processes

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 within the periods specified under Canadian and US securities laws. They 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.

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, regarding 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 this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of March 31, 2012 such disclosure controls and procedures were effective.

Management’s report on internal control over financial reporting

Internal control over financial reporting (ICFR) 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. Management, including the President and Chief Executive Officer and Chief Financial Officer, are responsible for establishing and maintaining ICFR, as such term is defined in Rule 13(a)-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 reports will not be prevented or detected on a timely basis.

Because of its inherent limitations, ICFR may not prevent or detect misstatements. In addition, 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, 2012, we assessed the effectiveness of our 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). Based on this assessment, management has concluded that, as of March 31, 2012, our internal control over financial reporting is effective. Our independent auditor, KPMG LLP, has issued an audit report stating that we, as at March 31, 2012, maintained, in all material respects, effective internal control over financial reporting based on the criteria established in Internal Control-Integrated Framework issued by the COSO.

Material changes to internal controls over financial reporting

There have been no material changes to internal controls over financial reporting during the year ended March 31, 2012.

Critical Accounting Estimates

The preparation of financial statements in conformity with US GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period.

Significant estimates made by us include:

• Assessment of the percentage of completion on time-and-materials, unit-price and 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 and embedded 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 and intangible assets.

Actual results could differ materially from those estimates.

The accuracy of our revenue and profit recognition in a given period is dependent, in part, on the accuracy of our estimates of the cost to complete each time-and-materials, unit-price, and lump-sum project. Our cost estimates use a detailed "bottom up" approach, using inputs such as labour and equipment hours, detailed drawings and material lists. These estimates are reviewed and updated monthly. We believe our experience allows us to produce materially reliable estimates. However, some of our 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 affecting our profitability. Major changes in cost estimates, particularly in larger, more complex projects, such as those performed in our Heavy Construction and Mining segment can have a significant effect on profitability.

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The complex judgments and estimates most critical to an investor’s understanding of our financial results and condition are contained within our significant accounting policies (described in detail in our audited consolidated financial statements for the year ended March 31, 2012 and notes that follow). Below is a summary of how we apply these critical accounting estimates in our significant accounting policies:

Revenue recognition policy

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 is 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 our estimates. 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 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 expenses are charged to expense as incurred. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined.

The accuracy of our revenue and profit recognition in a given period is dependent on the accuracy of our estimates of the cost to complete each project. Cost estimates for all of our significant projects use a highly detailed “bottom up” approach and we believe our experience allows us to provide materially reliable estimates. There are a number of factors that can contribute to changes in estimates of contract cost and profitability. These changes are recognized in the period in which such adjustments are determined. The most significant of these include:

• the completeness and accuracy of the original bid;

• costs associated with added scope changes (to the extent contract remedies are unavailable);

• extended overhead due to owner, weather and other delays (to the extent contract remedies are unavailable);

• subcontractor performance issues;

• changes in economic indices used to estimate future costs-to-complete on longer-term contracts;

• changes in productivity expectations;

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

• contract incentive and penalty provisions;

• the availability and skill level of workers in the geographic location of the project; and

• a change in the availability and proximity of equipment and materials.

The foregoing factors as well as the mix of contracts at different margins may cause fluctuations in gross profit between periods. Substantial changes in cost estimates, particularly in our larger, more complex projects have had, and can in future periods have, a significant effect on our profitability.

Once a project is underway, we 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 affect costs and revenue under the contract. When a change becomes a point of dispute between a customer and us, 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 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:

i. a bona fide addition to contract value; and

ii. revenue that can be reliably estimated.

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These two conditions are satisfied when:

• 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;

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

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

• 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.

Our long-term contracts typically allow 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 affecting revenue recognition in future periods.

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

Our policy is to recognize revenue from the sale of our other products and services as follows:

• 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 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;

• Revenue from tank services is provided based upon orders and contracts with the customer that include fixed or determinable prices based upon daily, hourly or job rates and is recognized as the services are provided to the customer; and

• Revenue from anchor manufacturing and product sales is recognized when the products are shipped to the customer.

We recognize revenue from the foregoing activities once persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, fees are fixed and determinable and collectability is reasonably assured.

Property, plant and equipment policy

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 writedown 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 policy

We regularly review our accounts receivable balances for each of our customers and we writedown 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 length of time the receivable has been outstanding and specific knowledge of each customer’s financial condition and history.

Goodwill impairment policy

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. Generally, 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, 2011. This impairment test showed that the fair value of the Piling reporting unit exceeded its carrying value.

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Financial instruments policy

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.

We use derivative financial instruments to manage financial risks from fluctuations in exchange rates, interest rates and inflation. These instruments include embedded price escalation features in revenue and supplier contracts. In developing such escalators, we rely on industry standards, historical data and management’s experience. We use these price escalation features for risk management purposes only. We do not hold or issue derivative financial instruments for trading or speculative purposes. Derivative financial instruments are subject to standard credit terms and conditions, financial controls, management and risk monitoring procedures. These derivative financial instruments are not designated as hedges for accounting purposes and are recorded at fair value with realized and unrealized gains and losses recognized in the Consolidated Statement of Operations, Comprehensive Income (Loss) and Deficit.

Foreign currency translation policy

Accounts of our US-based subsidiary, which has a US dollar functional currency, are translated into Canadian dollars using the current rate method. Assets and liabilities are translated at the rate of exchange in effect at the balance sheet date, and revenue and expense items (including depreciation and amortization) are translated at the average rate of exchange for the period. The resulting unrealized exchange gains and losses from these translation adjustments are included as a separate component of shareholders' equity in Accumulated Other Comprehensive Income (Loss). The effect of exchange rate changes on cash balances held in foreign currencies is separately reported as part of the reconciliation of the change in cash and cash equivalents for the period.

Our functional currency for the majority of our subsidiaries 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.

Accounting Pronouncements Recently 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. We adopted this ASU effective April 1, 2011. The adoption of this standard did not have a material effect 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. We adopted this ASU effective April 1, 2011. The adoption of this standard did not have a material effect on our consolidated financial statements.

Intangibles – goodwill and other

In December 2010, the FASB issued ASU No. 2010-28, “When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts”, which amends ASC 350, “Intangibles-Goodwill and Other” to modify step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts, to require an entity to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that impairment may exist. We adopted this ASU effective April 1, 2011. The adoption of this standard did not have a material effect on our consolidated financial statements.

Business combinations

In December 2010, the FASB issued ASU No. 2010-29, “Disclosure of Supplementary Pro Forma Information for Business Combinations”, which amends ASC 805, “Business Combinations”, to require that pro-forma information be presented as if the business combination occurred at the beginning of the prior annual reporting period for the purposes of calculating both the current reporting period and the prior reporting period pro forma financial information. The ASU also requires the disclosure be accompanied by a narrative description of the nature and amount of material, nonrecurring pro forma adjustments. We adopted this ASU effective prospectively April 1, 2011. This standard will affect disclosures made for any business combinations on our consolidated financial statements for the interim periods and years after the effective date.

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Fair value measurement

In May 2011, the FASB issued ASU 2011-04, “Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRS”, which generally represent clarifications of Topic 820, but also include some instances where a particular principle or requirement for measuring fair value or disclosing information about fair value measurements has changed. This ASU results in common principles and requirements for measuring fair value and for disclosing information about fair value measurements in accordance with US GAAP and IFRS. We adopted this ASU prospectively effective January 1, 2012. The adoption of this standard did not have a material effect on our consolidated financial statements.

Issued Accounting Pronouncements Not Yet Adopted

Goodwill impairment

In September 2011, the FASB amended the guidance on the annual testing of goodwill for impairment. The amended guidance will allow companies to assess qualitative factors to determine if it is more-likely-than-not that goodwill might be impaired and whether it is necessary to perform the two-step goodwill impairment test required under current accounting standards. The guidance will be effective for the year ending March 31, 2013, with early adoption permitted. We believe that this new guidance will not have a material impact on our consolidated financial statements.^¿

Offsetting Assets and Liabilities

In December 2011, the FASB issued ASU 2011-11, “Balance Sheet”, which amends the disclosure requirements on offsetting in Section 210-20-50. The amendments require enhanced disclosures by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with either Section 210-20-45 or Section 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either Section 210-20-45 or Section 815-10-45. This guidance will be effective for the Company’s fiscal year ending March 31, 2014. This standard does not amend the existing guidance on when it is appropriate to offset. We believe that this new guidance will not have a material impact on our consolidated financial statements.^¿

Comprehensive income

In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. This ASU requires the presentation of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements rather than as a footnote to the consolidated financial statements, where it is currently disclosed. The ASU also requires the presentation of reclassification adjustments for items that are reclassified from other comprehensive income to net income in the financial statements where the components of net income and the components of other comprehensive income are presented. The option under current guidance that permits the presentation of components of other comprehensive income as part of the statement of changes in shareholders’ equity will be eliminated. In December 2011, the FASB further amended its guidance to defer changes related to the presentation of reclassification adjustments indefinitely as a result of concerns raised by stakeholders that the new presentation requirements would be difficult for preparers and add unnecessary complexity to financial statements. This guidance will be effective for the Company’s fiscal year ending March 31, 2013. We have determined that this new guidance will not have a material impact on our consolidated financial statements. ^¿

G. Forward-Looking Information, Assumptions 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.

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

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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, uncertainties and assumptions is based on a number of assumptions that may prove to be incorrect:

1. The anticipated $47.0 million of net proceeds from the sale of assets related to the Canadian Natural contract and the treatment of revenue recognition under the amended and original contract.

2. The anticipated $8 million to $10 million reduction in Canadian Natural contract-related lease and depreciation costs during fiscal 2013 and an equivalent reduction of contract revenue.

3. The expectation that part of the growth in oil sands capital spending will be driven by the development of new mines and the expansion of existing mine operations.

4. Canadian Natural and Syncrude are expected to increase spending on mine expansion, production improvement projects and tailing management projects in 2012, which could create further opportunities for our Heavy Construction and Mining segment in fiscal 2013.

5. CAPP’s forecast for oil production from oil projects is expected to support increased demand for recurring services.

6. Our belief that the impact of producers’ cost-control measures will likely be short-term.

7. Demand for certain types of recurring services, such as overburden removal and both wet tailings and mine reclamation activities, is expected to improve in fiscal 2013.

8. The expectation that TransCanada’s Keystone proposed southern extension to transport oil from Cushing to available refining capacity on the US Gulf Coast will be approved by the applicable US regulatory agencies.

9. Our belief that the construction of the southern extension will likely tie up available contractor capacity in the US and reduce bidding competition on pipeline projects that have been announced for Western Canada and that opportunities may arise from this to negotiate low-risk cost-plus or time-and-materials contracts, which could eliminate many of the risks posed by lump-sum contracts.

10. Our intention to pursue additional contract opportunities as they become available and the potential reduction in the number of competitors for certain of these contracts.

11. Our expectation that approximately $424.7 million of total backlog will likely be performed and realized in the 12 months ending March 31, 2013, together with a significant volume of work available but not included in the backlog calculation.

12. Our anticipation of steady activity levels and improved profitability.

13. The expected offset of continued demand for reclamation, tailings services, mine expansion projects and the resumption of overburden removal activity at Canadian Natural against a continued reduction in mine support activity.

14. Our expectations to maintain volumes with a variety of projects at Suncor and to ramp up production on the shear key foundation of the mine relocation project at Syncrude and the transition into the second phase of the relocation with construction of an MSE wall.

15. Our expectation to operate near full production throughout the year as a result of reaching final agreement on amendments to our Canadian Natural contract.

16. That Exxon’s Kearl project is expect to begin production in 2012 and create additional bidding opportunities for mine support services.

17. Our expectation to continue executing initial earthworks at the Joslyn North Mine Project.

18. Our intention to pursue opportunities for work at Fort Hills, PetroChina’s Dover SAGD project and on other SAGD projects, as such opportunities arise.

19. Our expectation that construction at the Mt. Milligan Copper/Gold Project will continue through the end of the year.

20. The positive outlook for our Piling business, including the expectation of continued strong performance from this segment in fiscal 2013.

21. The execution of the pipeline integrity dig program and our intention to pursue opportunities to construct mid-to-large inch diameter pipelines on a low-risk cost-plus or time-and-materials contract basis, which may reduce revenues but could possibly increase profitability significantly.

22. Our belief that opportunities for lower-risk pipeline projects will increase over time if contractor supply becomes more constrained.

23. Our intention to improve profitability and strengthen our balance sheet through a continued focus on performance, efficiency and risk management.

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24. Our estimate with respect to equipment additions and other capital needs; that our operating and capital lease facilities and capacity and cash flow from operations will likely be sufficient to meet these needs; but if we require additional funding for our expenses, this could be satisfied by our credit facilities.

25. Our belief that accounting pronouncements recently adopted or yet to be adopted, as discussed herein, will not have a material impact on our consolidated financial statements.

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 “Assumptions”, “Risk Factors” and “Quantitative and Qualitative Disclosure about Market Risk”, 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, risk factors that appear in the “Forward-Looking Information, Assumptions and Risk Factors” section of our most recent AIF, which section is expressly incorporated by reference in this MD&A.

Assumptions

The material factors or assumptions used to develop the above forward-looking statements include, but are not limited to:

1. That we have the ability to affect the buyouts of the applicable equipment within the timelines contemplated under the contract with Canadian Natural.

2. That work will continue to be required under the contract with Canadian Natural.

3. That work will continue to be required under our master services agreements with various customers;

4. The demand for recurring services remaining strong;

5. The continuing development of new mines and the expansion of existing mines;

6. That potash mine expansions will lead to a decrease in current competitors in the oil sands;

7. The continuing resurgence in mineral resource spending;

8. Our customers’ ability to pay in timely fashion;

9. Our ability to successfully resolve all claims and unsigned change orders with our customers;

10. The oil sands continuing to be an economically viable source of energy;

11. Our customers and potential customers continuing to invest in the oil sands and other resource developments and to outsource activities for which we are capable of providing services;

12. The Western Canadian economy continuing to develop and receiving additional investment in public construction;

13. The continuing construction of the southern pipeline extension;

14. Our ability to benefit from increased project development revenue and to maintain recurring services revenue tied to the operational activities of the oil sands;

15. Our ability to maintain the right size and mix of equipment in our fleet and to secure specific types of rental equipment to support project development activity enables us to meet our customers’ variable service requirements while balancing the need to maximize utilization of our own equipment;

16. Our ability to access sufficient funds to meet our funding requirements will not be significantly impaired; and

17. Our success in executing our business strategy, identifying and capitalizing on opportunities, managing our business, maintaining and growing our relationships with customers, retaining new customers, integrating our acquisitions, competing in the bidding process to secure new projects and identifying and implementing improvements in our maintenance and fleet management practices.

18. Our success in improving profitability and continuing to strengthen our balance sheet through a focus on performance, efficiency and risk management.

Risk Factors

The risks and uncertainties that could cause actual results to differ materially from the information presented in the above forward-looking statements and assumptions include, but are not limited to the risks detailed below. For further information on risks, including “Business Risk Factors”, "Risk Factors Related to Our Common Shares", “Risk Factors Related to our Debt Securities” and “Quantitative and Qualitative Disclosure about Market Risk”, please refer to the “Forward-Looking Information, Assumptions and Risk Factors” section of our most recent AIF.

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• Short-notice customer communication of reduction in their mine development or support service requirements, in which we are participating, could lead to our inability to secure replacement work for our dormant equipment and could subject us to non-recoverable costs.

We allocate and mobilize our equipment and hire personnel based on estimated equipment and service plans supplied by our customers. At the start of each new project, we incur significant start-up costs related to the mobilization and maintenance configuration of our heavy equipment along with personnel hiring, orientation, training and housing costs for staff ramp-ups and redeployments. We expect to recover these start-up costs over the planned volumes of the projects we are awarded. Significant reductions in our customer’s required equipment and service needs, with short notice, could result in our inability to redeploy our equipment and personnel in a cost effective manner. Our ability to maintain revenues and margins may be adversely affected to the extent these events cause reductions in the utilization of equipment and we can no longer recover our start-up costs over the reduced volume plan of our customers.

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

Approximately, 68%, 63% and 39% of our revenue for the fiscal years ended March 31, 2012, 2011 and 2010, 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 including those that are beyond our control. Factors that may contribute to actual costs exceeding estimated costs and which therefore affect profitability include, without limitation:

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

• scope modifications during the execution of the project;

• the availability and cost of skilled workers;

• the availability and proximity of materials;

• unfavourable weather conditions hindering productivity;

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

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

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

When we are unable to accurately estimate and adjust for 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 affect our results of operations, financial condition and cash flow.

• 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 on 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 adversely affected to the extent these events cause reductions in the utilization of equipment.

• An unfavourable resolution to our significant project claims could result in a revenue write down in future periods.

Included in our revenues is a total of $23.4 million relating to disputed claims or unapproved change orders ($21.2 million of which is in respect of the Pipeline segment). Although we believe that we are entitled to such revenue and that we will collect such revenue, if we are not able to resolve these claims and undertake legal action in respect of these claims, there is no guarantee that a court will rule in our favour.

There is also the possibility that we could choose to accept less than the full amount of a claim as a settlement to avoid legal action. In either such case, a resolution or settlement of the claims in an amount less than the amount recognized as claims revenue could lead to a future write down of revenue and profit.

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

Because our operations are located across Canada, including Northern British Columbia, Northern Alberta (Fort McMurray), Nunavut and Northern Ontario, we are subject to extreme weather conditions. While our operations are not significantly affected by normal seasonal weather patterns, extreme weather conditions, including heavy rain, snow, spring thaw, flooding, forest fires or dry forest fire conditions can cause delays in our project work, which could adversely affect our results of operations. Additionally, as we perform work in environmentally sensitive nature reserve areas we may be subject to seasonal reductions of our operating hours related to fish or wildlife restrictions set by the Government of Canada’s Environment Canada or Fisheries and Oceans Canada departments.

2012 Annual Report 39

• Our ability to maintain planned project margins on projects with longer-term contracts with fixed or indexed price escalators may be hampered by the price escalators not accurately reflecting increases in our costs over the life of the contract.

Our ability to maintain planned project margins on longer-term contracts with contracted price escalators is dependent on the contracted price escalators accurately reflecting increases in our costs. If the contracted price escalators do not reflect actual increases in our costs, we will experience reduced project margins over the remaining life of these longer-term contracts.

In strong economic times, the cost of labour, equipment, materials and sub-contractors is driven by the market demand for these project inputs. The level of increased demand for project inputs may not have been foreseen at the inception of the longer-term contracts with fixed or indexed price escalators resulting in reduced margins over the remaining life of the longer-term contracts. Certain of these price escalators could be considered derivative financial instruments (see “Significant Accounting Policies – Derivative Financial Instruments” in our audited consolidated financial statements for the year ended March 31, 2012).

• Our customer base is concentrated, and the loss of or a significant reduction in business from a major customer could adversely affect 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 67%, 77% and 89% of our total revenue for the fiscal years ended March 31, 2012, 2011 and 2010, respectively, and those customers are expected to continue to account for a significant percentage of our revenues in the future. In addition, the majority of our Pipeline revenues in previous fiscal years resulted from work performed for one customer. If we lose or experience a significant reduction of business or profit from one or more of our significant customers, we may not be able to replace the lost work or income with work or income from other customers. Our long-term contracts typically allow our customers to unilaterally reduce or eliminate the work that 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 of 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.

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

More than 48% of our revenue for the year ended March 31, 2012 was derived from projects that 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. There is no guarantee that the Company will find additional sources for generating non-recurring services revenue in fiscal 2012.

• 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 67%, 78% and 88% of our revenues in each of the years ended March 31, 2012, 2011 and 2010, 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 if they believe they can perform this work in a more cost effective and efficient manner using their internal resources.

• 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:

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

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

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

• lack of sufficient governmental infrastructure funding to support growth;

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

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

• cost overruns on announced projects.

40 2012 Annual Report

NOA

• 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.

• 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. 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.

• We may not be able to access sufficient funds to finance a growth in our working capital or equipment requirements.

We have a substantial amount of debt outstanding and significant debt service requirements. As of March 31, 2012, we had outstanding $547.9 million of debt²³, including $10.7 million of capital leases. Our substantial indebtedness restricts our flexibility, consequently it:

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

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

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

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

• increases our vulnerability to, and reduces our flexibility in planning for, adverse changes in economic, industry and competitive conditions; and

• increases 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.

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.

• Cost overruns by our customers on their projects may cause our customers to terminate future projects or expansions that 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, affecting their returns. If cost overruns continue to challenge our customers, they could reassess future projects and expansions that could adversely affect the amount of work we receive from our customers.

• Because most of our customers are Canadian energy companies, a downturn in the Canadian energy industry or a global reduction in the demand for oil and related commodities 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 has previously led our customers to slow down or curtail their future capital expansions that, in turn, reduced our revenue from those customers on their capital projects. Another economic downturn in the Canadian energy industry or a global reduction in the demand for oil 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.

• 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.

²³  Debt includes all liabilities with the exception of deferred income taxes.

2012 Annual Report 41

H. General Matters

Experts

KPMG LLP are our auditors and have confirmed that they are independent with respect to the Company within the meaning of the Rules of Professional Conduct of Institute of Chartered Accountants of Alberta and within the meaning of the U.S. Securities Act of 1933 and the applicable rules and regulations thereunder adopted by the Securities and Exchange Commission and the Public Company Accounting Oversight Board (United States)

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.

For the definition of terms commonly used in our industry but not otherwise defined in this MD&A, please see “Glossary of Terms” in our most recent AIF.

Additional information relating to us, including our AIF dated June 6, 2012, 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.

42 2012 Annual Report

EX-99.4

Exhibit 99.4

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

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of North American Energy Partners Inc.

We consent to the use of our reports, each dated June 6, 2012, with respect to the consolidated financial statements and the effectiveness of internal control over financial reporting included in this annual report on Form 40-F.

Chartered Accountants

Edmonton, Canada

June 6, 2012

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-99.5

Exhibit 99.5

CERTIFICATION OF FORM 40-F

REQUIRED BY RULE 13a-14(a)

OR RULE 15D-14(a), PURSUANT TO SECTION 302

OF THE SARBANES–OXLEY ACT OF 2002

I, Rodney J. Ruston, the President and Chief Executive Officer of North American Energy Partners Inc., certify that:

1.    I have reviewed this annual report on Form 40-F for the fiscal year ended March 31, 2012 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 6, 2012

/s/ Rodney J. Ruston

Name: Rodney J. Ruston

Title: President and Chief Executive Officer

EX-99.6

Exhibit 99.6

CERTIFICATION OF FORM 40-F

REQUIRED BY RULE 13a-14(a)

OR RULE 15D-14(a), PURSUANT TO SECTION 302

OF THE SARBANES–OXLEY ACT OF 2002

I, 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, 2012 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 6, 2012

/s/ David Blackley

Name: David Blackley

Title: Chief Financial Officer

EX-99.7

Exhibit 99.7

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ENACTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 40-F for the fiscal year ended March 31, 2012 (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 6, 2012

/s/ Rodney J. Ruston

Name: Rodney J. Ruston

Title: President and Chief Executive Officer

EX-99.8

Exhibit 99.8

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ENACTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 40-F for the fiscal year ended March 31, 2012 (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 6, 2012

/s/ David Blackley

Name: David Blackley

Title: Chief Financial Officer

XML

Employee benefit plans

12 Months Ended

Mar. 31, 2012

Employee benefit plans [Abstract]

Employee benefit plans

26. Employee benefit plans

The Company and its subsidiaries match voluntary contributions made by 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, 2012 were $2,083 (2011 – $1,689; 2010 — $1,393).

XML

Shares

12 Months Ended

Mar. 31, 2012

Shares [Abstract]

Shares

18. Shares

a) Common shares

Authorized:

Unlimited number of voting common shares

Unlimited number of non-voting common shares

Issued and outstanding:

	Number of Shares		Amount
Voting common shares
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
Issued upon exercise of stock options		193,250		963
Transferred from additional paid-in capital on exercise of stock options		–		386
Issued and outstanding at March 31, 2011		36,242,526		$304,854
Issued upon exercise of stock options		8,480		35
Transferred from additional paid-in capital on exercise of stock options		–		19
Issued and outstanding at March 31, 2012		36,251,006		$304,908

b) Net (loss) income per share

	2012			2011			2010
Year ended March 31,
Net (loss) income available to common shareholders		$(21,122	)		$(34,709	)		$28,219
Weighted average number of common shares		36,249,082			36,119,356			36,040,857
Basic net (loss) income per share		$(0.58	)		$(0.96	)		$0.78
	2012			2011			2010
Year ended March 31,
Net (loss) income available to common shareholders		$(21,122	)		$(34,709	)		$28,219
Weighted average number of common shares		36,249,082			36,119,356			36,040,857
Dilutive effect of stock options, deferred performance share units and stock award plan		–			–			680,169
Weighted average number of diluted common shares		36,249,082			36,119,356			36,721,026
Diluted net (loss) income per share		$(0.58	)		$(0.96	)		$0.77

For the year ended March 31, 2012, there were 1,834,794 and 50,000 stock options and stock awards, respectively, which were anti-dilutive (March 31, 2011 – 1,647,474, 75,591 and 150,000 stock options, deferred performance share units and stock awards, respectively; March 31, 2010 – 820,641 and 57,311 stock options and deferred performance share units, respectively) and therefore were not considered in computing diluted earnings per share.

XML

Significant Accounting Policies

12 Months Ended

Mar. 31, 2012

Significant Accounting Policies [Abstract]

Significant accounting policies

2. Significant accounting policies

a) Basis of presentation

These consolidated financial statements are prepared in accordance with United States generally accepted accounting principles (“US GAAP”). Material inter-company transactions and balances are eliminated upon consolidation.

These consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, NACGI, North American Fleet Company Ltd., North American Construction Projects Inc., NACG International Inc., North American Major Mining Projects Inc., North American Construction Management Inc. (“NACMI”) and NACG Properties Inc., and the following 100% owned subsidiaries of NACMI:

• North American Caisson Ltd.	• North American Services Inc.
• North American Construction Ltd.	• North American Site Development Ltd.
• North American Engineering Inc.	• North American Site Services Inc.
• North American Enterprises Ltd.	• North American Tailings and Environmental Ltd.
• North American Industries Inc.	• DF Investments Limited
• North American Maintenance Ltd.	• Drillco Foundation Co. Ltd.
• North American Mining Inc.	• Cyntech Canada Inc.
• North American Pile Driving Inc.	• Cyntech Services Inc.
• North American Pipeline Inc.	• Cyntech U.S. Inc.
• North American Road Inc.

b) Use of estimates

The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures reported in these consolidated financial statements and accompanying notes and the reported amounts of revenues and expenses during the reporting period.

Significant estimates made by management include the assessment of the percentage of completion on time-and-materials, unit-price, lump-sum and cost-plus 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 and embedded 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 and intangible assets. Actual results could differ materially from those estimates.

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 expenses are charged to expense as incurred. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined.

The accuracy of the Company’s revenue and profit recognition in a given period is dependent on the accuracy of its estimates of the cost to complete each project. Cost estimates for all of significant projects use a detailed “bottom up” approach and the Company believes its experience allows it to provide reasonably dependable estimates. There are a number of factors that can contribute to changes in estimates of contract cost and profitability that are recognized to the extent contract remedies are unavailable in the period in which such adjustments are determined. The most significant of these include:

• the completeness and accuracy of the original bid;

• costs associated with added scope changes;

• extended overhead due to owner, weather and other delays;

• subcontractor performance issues;

• changes in economic indices used for the determination of escalation or de-escalation for contractual rates on long-term contracts;

• changes in productivity expectations;

• site conditions that differ from those assumed in the original bid;

• contract incentive and penalty provisions;

• the availability and skill level of workers in the geographic location of the project; and

• a change in the availability and proximity of equipment and materials.

The foregoing factors as well as the mix of contracts at different margins may cause fluctuations in gross profit between periods. 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 is 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 expenses 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 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:

• a bona fide addition to contract value; and

• revenues can be reliably estimated.

These two conditions are satisfied when:

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

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

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

• 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.

The Company recognizes revenue from the sale of its other products and services as follows:

• 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 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;

• Revenue from tank services is provided based upon orders and contracts with the customer that include fixed or determinable prices based upon daily, hourly or job rates and is recognized as the services are provided to the customer; and

• Revenue from anchor manufacturing and product sales is recognized when the products are shipped to the customer.

The Company recognizes revenue from the foregoing activities once persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, fees are fixed and determinable and collectability is reasonably assured.

d) Balance sheet classifications

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

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 billed to clients.

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 tires, job materials, manufacturing raw materials and finished goods. Finished goods cost includes raw materials, labour and a reasonable allocation of appropriate overhead costs.

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 drive trains 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

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 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:

• Customer relationships and backlog, which are being amortized over the remaining lives of the related contracts and relationships;

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

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

• capitalized computer software and development costs, which are being amortized on a straight-line basis over a maximum period of four years; and

• patents, which are being amortized on a straight-line basis over estimated useful lives of up to six years.

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.

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 or amortization 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:

• management, having the authority to approve the action, commits to a plan to sell the assets;

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

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

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

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

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

Assets to be disposed of by sale are reported at the lower of their carrying amount or fair value less costs to sell and are 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 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 and the majority of its subsidiaries 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.

Accounts of the Company’s US-based subsidiary, which has a US Dollar functional currency, are translated into Canadian Dollars using the current rate method. Assets and liabilities are translated at the rate of exchange in effect at the balance sheet date, and revenue and expense items (including depreciation and amortization) are translated at the average rate of exchange for the period. The resulting unrealized exchange gains and losses from these translation adjustments are included as a separate component of shareholders’ equity in Accumulated Other Comprehensive Income (Loss). The effect of exchange rate changes on cash balances held in foreign currencies is separately reported as part of the reconciliation of the change in cash and cash equivalents for the period.

r) Fair value measurement

Fair value measurements 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 values included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Fair values included 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 fair value 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.

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 based on the 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 “General and administrative expenses” in the Consolidated Statements of Operations. 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 has a Share Option Plan which is described in note 27(b). 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 Senior Executive Stock Option Plan which is described in note 27(c). This compensation plan allows the option holder the right to settle options in cash. The liability is measured at fair value using the Black-Scholes model at the modification date and subsequently at each period end date. Changes in fair value of the liability are recognized in the Consolidated Statements of Operations.

The Company has a Deferred Performance Share Unit (“DPSU”) Plan which is described in note 27(d). 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 plan 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. The company has no outstanding DPSUs at this time.

The Company has a Restricted Share Unit (“RSU”) Plan which is described in note 27(e). RSUs are 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 number of vested shares multiplied by the fair market value of each RSU as determined by the volume weighted average trading price of the Company’s common shares for the five trading days immediately preceding the day on which the fair market value is to be determined. The Company recognizes compensation expense over the three-year term of the RSU in the Consolidated Statements of Operations.

The Company has a Director’s Deferred Stock Unit (“DDSU”) Plan which is described in note 27(f). 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 unit and is recorded as a charge to operating income when issued. Subsequent changes in the Company’s payment obligation after issuing the unit and prior to the settlement date are recorded as a charge to operating income in the period such changes occur.

The Company has a Stock Award Plan which is described in note 27(g). The stock awards are settled at the Company’s option, either by the issuance of equity instruments if all necessary shareholder approvals and regulatory approvals are obtained or by cash payment. Compensation cost is measured using the market price of the Company’s common shares 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.

v) Net (loss) income per share

Basic net (loss) income 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 18(b)). 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 are 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.

Certain operating lease and rental agreements provide a maximum hourly usage limit, above which the Company will be required to pay for the over hour usage as a contingent rent expense. These contingent expenses are recognized when the likelihood of exceeding the usage limit is considered probable and are due at the end of the lease term or rental period. The contingent rental expenses are included in “Equipment operating lease expense” in the Consolidated Statements of Operations.

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 are presented as deferred financing costs. The deferred financing costs related to the senior notes, debentures 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.

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Other information

12 Months Ended

Mar. 31, 2012

Nature of Operations/Other information [Abstract]

Other information

22. Other information

a) Supplemental cash flow information

Year ended March 31,	2012			2011			2010
Cash paid during the year for:
Interest, including realized interest on interest rate swap		$27,521			$33,559			$49,999
Income taxes		1,415			4,149			10,395
Cash received during the year for:
Interest		1			1,168			10,998
Income taxes		5,347			2,260			453
Non-cash transactions:
Acquisition of property, plant and equipment by means of capital leases		7,215			427			1,523
Additions to assets held for sale		(10,322	)		(1,675	)		(1,739	)
Net increase (decrease) in accounts payable related to purchase of property, plant and equipment		1,380			(3,879	)		1,840
Disposition of property, plant and equipment related to the buy-out of contract-related assets		(27,063	)		–			–
Disposition of intangible assets related to the buyout of contract-related assets		(1,119	)		–			–
Increase in accounts receivable related to the buyout of contract-related assets		66,055			–			–
Decrease in unbilled revenue related to the buyout of contract-related assets		(16,457	)		–			–
Decrease in inventory related to the buyout of contract-related assets		(8,483	)		–			–
Increase in accounts payable related to the buyout of contract-related assets		12,933			–			–
Increase in accrued liabilities related to current portion of RSU liability		2,066			–			–

b) Net change in non-cash working capital

Year ended March 31,	2012			2011			2010
Operating activities:
Accounts receivable, net		$(19,592	)		$(9,534	)		$(29,428	)
Unbilled revenue		(377	)		(18,237	)		(28,795	)
Inventories		(12,603	)		(2,661	)		6,214
Prepaid expenses and deposits		3,413			308			(2,620	)
Accounts payable		70,764			21,382			6,620
Accrued liabilities		1,915			(5,434	)		1,150
Long term portion of liabilities related to equipment leases		(9,578	)		(2,196	)		7,809
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		5,510			390			(541	)
		$39,452			$(15,982	)		$(39,591	)

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Financial instruments and risk management

12 Months Ended

Mar. 31, 2012

Financial instruments and risk management [Abstract]

Financial instruments and risk management

21. Financial instruments and risk management

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. Standard market conventions and techniques, such as discounted cash flow analysis and option pricing models, are used to determine the fair value of the Company’s financial instruments, including derivatives. All methods of fair value measurement result in a general approximation of value and such value may never actually be realized.

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 Credit Facilities 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 $78.8 million at March 31, 2012 and $72.0 million at March 31, 2011 (note 15 (b)), the fair value of amounts due under the Credit Facilities as at March 31, 2012 and March 31, 2011 are not significantly different than their carrying value.

Financial instruments with carrying amounts that differ from their fair values are as follows:

	March 31, 2012				March 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Capital lease obligations (i)		$10,701		$10,657		$8,693		$8,658
Series 1 Debentures (ii)		225,000		203,624		225,000		238,651

(i) 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.

(ii) The fair value of the Series 1 Debentures is based upon the expected discounted cash flows and the period end market price of similar financial instruments.

a) Fair value measurements

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.

The fair values of 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 including foreign currency rates, implied volatilities and discount factors 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 futures 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 effect of such variations could be material.

At March 31, 2012, the Company had no financial assets or financial liabilities measured at fair value on a recurring basis which were 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, these fair value measurements are classified as Level 2 of the fair value hierarchy. Financial assets and liabilities measured at fair value net of accrued interest on a recurring basis, all of which are classified as “Derivative financial instruments” on the Consolidated Balance Sheets are summarized below:

March 31, 2012	Carrying Amount
Embedded price escalation features in certain long term supplier contracts		$9,146
Less: current portion		(3,220	)
		$5,926
March 31, 2011	Carrying Amount
Embedded price escalation features in a long term customer construction contract		$5,877
Embedded price escalation features in certain long term supplier contracts		5,651
		$11,528
Less: current portion		(2,474	)
		$9,054

On April 8, 2010, the Company settled the cross-currency and interest rate swaps, including accrued interest for a total of $91,125 in conjunction with the settlement of the 8  ³/4 % senior notes (note 15 (d)).

The realized and unrealized (gain) loss on derivative financial instruments is comprised as follows:

Year ended March 31,	2012			2011			2010
Realized and unrealized loss on cross-currency and interest rate swaps		$–			$2,111			$64,637
Unrealized (gain) loss on embedded price escalation features in a long term customer construction contract		(5,877	)		(604	)		6,805
Unrealized loss (gain) on embedded price escalation features in certain long term supplier contracts		3,495			(3,812	)		(13,315	)
Unrealized gain on early redemption option on 8  3/4% senior notes		–			–			(3,716	)
		$(2,382	)		$(2,305	)		$54,411

Non-financial assets that were measured at fair value on a non-recurring basis as at March 31, 2012 and 2011 in the financial statements are summarized below:

	March 31, 2012					March 31, 2011
	Carrying Amount		Change in Fair Value			Carrying Amount		Change in Fair Value
Assets held for sale		$1,841		$(8,748	)		$721		$(141	)

Assets held for sale are measured at fair value less cost to sell on a non-recurring basis. For the year ended March 31, 2012, assets held for sale with a carrying amount of $10,589 (2011 – $862) were written down to their fair value less cost to sell of $1,841 (2011 – $721), resulting in a loss of $8,748 (2011 – $141), which was included in depreciation expense in the Consolidated Statements of Operations. The fair value less cost to sell of the assets held for sale is determined internally by analyzing recent auction prices for equipment with similar specifications and hours used, 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.

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

The Company regularly transacts in foreign currencies when purchasing equipment and 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 US Dollar for these short term transactions, if material.

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. Interest expense on borrowings with floating interest rates, including the Company’s Credit Facilities, varies as market interest rates change. At March 31, 2012, the Company held $78.8 million of floating rate debt pertaining to its Credit Facilities (March 31, 2011 – $72.0 million). As at March 31, 2012, holding all other variables constant, a 100 basis point change to interest rates on floating rate debt will result in $0.8 million corresponding change in annual interest expense. This assumes that the amount of floating rate debt remains unchanged from that which was held at March 31, 2012.

The fair value of financial instruments with fixed interest rates, such as the Company’s Series 1 Debentures, fluctuate with changes in market interest rates. However, these fluctuations 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.

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.

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 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, 2012 and March 31, 2011, the following customers represented 10% or more of accounts receivable and unbilled revenue:

	March 31, 2012		March 31, 2011
Customer A		31%		40%
Customer B		11%		5%
Customer C		10%		14%
Customer D		3%		12%

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 project costs in the Consolidated Statements of Operations 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, 2012		March 31, 2011
Trade accounts receivables		$213,051		$127,678
Other receivables		1,078		804
Total accounts receivable		$214,129		$128,482
Unbilled revenue		$86,859		$102,939

On a geographic basis as at March 31, 2012, approximately 95% (March 31, 2011 – 95%) 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, 2012 and 2011, trade receivables are aged as follows:

	March 31, 2012		March 31, 2011
Not past due		$166,362		$98,626
Past due 1-30 days		27,617		18,911
Past due 31-60 days		8,476		3,444
More than 61 days (including holdbacks of $nil (2011 $nil))		10,596		6,697
Total		$213,051		$127,678

As at March 31, 2012, the Company has recorded an allowance for doubtful accounts of $210 (March 31, 2011 – $30) of which 100% relates to amounts that are more than 61 days past due.

The allowance is an estimate of the March 31, 2012 trade receivable balances that are considered uncollectible. Changes to the allowance are as follows:

Year ended March 31,	2012		2011			2010
Opening balance		$30		$1,691			$2,597
Payments received on provided balances		–		(682	)		(846	)
Current year allowance		180		518			334
Write-offs		–		(1,497	)		(394	)
Ending balance		$210		$30			$1,691

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.

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Segmented information

12 Months Ended

Mar. 31, 2012

Segmented information [Abstract]

Segmented information

23. Segmented information

a) General overview

The Company operates in the following reportable business segments, which follow the organization, management and reporting structure within the Company:

• Heavy Construction and Mining:

The Heavy Construction and Mining segment provides mining and site preparation services, including overburden removal and reclamation services, project management, underground utility construction, equipment rental to a variety of customers, environmental services including construction and modification of tailing ponds and reclamation of completed mine sites to environmental standards throughout Canada.

• Piling:

The Piling segment provides deep foundation construction and design build services to a variety of industrial and commercial customers throughout Western Canada and Ontario. It also designs and manufactures screw piles and pipeline anchoring systems and provides tank maintenance services to the petro-chemical industry across Canada and the United States and sells pipeline anchoring systems globally.

• 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 2. Certain business units of the Company have been aggregated into the Heavy Construction and Mining segment as they have similar economic characteristics based on 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, 2012	Heavy Construction and Mining		Piling		Pipeline		Total
Revenue from external customers		$670,720		$185,321		$150,504		$1,006,545
Depreciation of property, plant and equipment		35,804		3,912		1,045		40,761
Segment profits (loss)		86,567		46,012		(11,322)		121,257
Segment assets		426,625		142,131		70,602		639,358
Capital expenditures		42,001		12,570		4,110		58,681
For the year ended March 31, 2011	Heavy Construction and Mining		Piling		Pipeline		Total
Revenue from external customers		$667,037		$105,559		$85,452		$858,048
Depreciation of property, plant and equipment		28,832		3,636		550		33,018
Segment profits (loss)		50,703		18,455		(3,034)		66,124
Segment assets		423,947		116,623		37,053		577,623
Capital expenditures		29,577		2,560		1,124		33,261
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 (loss)		111,016		11,288		(3,851)		118,453
Segment assets		435,098		92,980		14,765		542,843
Capital expenditures		40,431		1,081		948		42,460

c) Reconciliations

i) Income (loss) before income taxes

Year ended March 31,	2012			2011			2010
Total profit for reportable segments		$121,257			$66,124			$118,453
Less: Unallocated equipment costs (recoveries) (i)		60,356			7,988			(20,832	)
Gross profit		$60,901			$58,136			$139,285
Less: unallocated corporate items:
General and administrative expenses		54,400			59,828			62,516
Loss on disposal of property, plant and equipment		1,741			1,948			1,233
(Gain) loss on disposal of assets held for sale		(466	)		825			373
Amortization of intangible assets		5,702			3,540			1,719
Equity in (earnings) loss of unconsolidated joint venture		(86	)		2,720			(44	)
Interest expense, net		30,325			29,991			26,080
Foreign exchange loss (gain)		52			(1,659	)		(48,901	)
Realized and unrealized (gain) loss on derivative financial instruments		(2,382	)		(2,305	)		54,411
Loss on debt extinguishment		–			4,346			–
(Loss) income before income taxes		$(28,385	)		$(41,098	)		$41,898

(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 the reportable segment exceed actual equipment costs incurred.

ii) Total assets

	March 31, 2012		March 31, 2011
Corporate assets:
Cash and cash equivalents		$1,400		$722
Property, plant and equipment		23,017		24,831
Deferred tax assets		60,442		51,649
Other		25,776		28,132
Total corporate assets		$110,635		$105,334
Total assets for reportable segments		639,358		577,623
Total assets		$749,993		$682,957

The Company’s goodwill of $32,901 is assigned to the Piling segment. All of the Company’s assets are located in Canada and the United States.

iii) Depreciation of property, plant and equipment

Year ended March 31,	2012		2011		2010
Total depreciation for reportable segments		$40,761		$33,018		$37,414
Depreciation for corporate assets		8,139		6,422		5,222
Total depreciation		$48,900		$39,440		$42,636

iv) Capital expenditures for long-lived assets

Year ended March 31,	2012		2011		2010
Total capital expenditures for reportable segments		$58,681		$33,261		$42,460
Capital expenditures for corporate assets		6,615		7,904		12,790
Total capital expenditures for long-lived assets		$65,296		$41,165		$55,250

d) Customers

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

Year ended March 31,	2012		2011		2010
Customer A		21%		29%		51%
Customer B		16%		8%		5%
Customer C		11%		10%		9%
Customer D		10%		24%		19%

The revenue by major customer was earned mainly by the Heavy Construction and Mining segment.

e) Geographic information

i) The geographic revenue distribution for the Company is as follows:

Year ended March 31,	2012		2011		2010
Canada		$996,916		$855,963		$758,965
International		6,935		1,046		–
United States		2,694		1,039		–
		$1,006,545		$858,048		$758,965

ii) The geographic distribution of long-lived assets is as follows:

	March 31, 2012		March 31, 2011
Canada		$367,240		$381,577
United States		179		96
		$367,419		$381,673

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Related party transactions

12 Months Ended

Mar. 31, 2012

Related party transactions [Abstract]

Related party transactions

24. Related party transactions

Sterling Group Partners I, L.P., Perry Partners, L.P. and Perry Partners International, Inc. 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.

There were no material related party transactions during the years ended March 31, 2012, 2011 and 2010. 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.

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Nature of Operations

12 Months Ended

Mar. 31, 2012

Nature of Operations/Other information [Abstract]

Nature of operations

1. Nature of operations

North American Energy Partners Inc. (the “Company”), formerly NACG Holdings Inc., 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 mining and environmental services, heavy construction, industrial and commercial site development and pipeline and piling installations. The Company also designs and manufactures screw piles, provides tank maintenance services to the petro-chemical industry across Canada and the United States and sells pipeline anchoring systems globally.

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Commitments

12 Months Ended

Mar. 31, 2012

Contingencies/Commitments [Abstract]

Commitments

25. 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,
2013	$54,542
2014	38,553
2015	19,014
2016	4,248
2017 and thereafter	–
	$116,357

Total contingent rentals on operating leases consisting principally of usage (recoveries) charges in excess of minimum contracted amounts for the years ended March 31, 2012, 2011 and 2010 amounted to $(8,449), $1,881 and $10,246 respectively.

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Consolidated Balance Sheets (CAD) In Thousands, unless otherwise specified	Mar. 31, 2012	Mar. 31, 2011
Current assets
Cash and cash equivalents	1,400	722
Accounts receivable, net (note 7 and 21(d))	214,129	128,482
Unbilled revenue (note 8)	86,859	102,939
Inventories (note 9)	11,855	7,735
Prepaid expenses and deposits (note 10)	6,315	8,269
Investment in and advances to unconsolidated joint venture (note 11)	1,574	1,488
Deferred tax assets (note 17)	2,991	1,729
Total current assets	325,123	251,364
Property, plant and equipment, net (note 13)	312,775	321,864
Other assets (note 12(a))	21,743	26,908
Goodwill (note 5)	32,901	32,901
Deferred tax assets (note 17)	57,451	49,920
Total Assets	749,993	682,957
Current liabilities
Accounts payable	171,130	86,053
Accrued liabilities (note 14)	36,795	32,814
Billings in excess of costs incurred and estimated earnings on uncompleted contracts (note 8)	7,514	2,004
Current portion of long term debt (note 15(a))	14,402	14,862
Current portion of derivative financial instruments (note 21(a))	3,220	2,474
Deferred tax liabilities (note 17)	21,512	27,612
Total current liabilities	254,573	165,819
Long term debt (note 15(a))	300,066	290,801
Derivative financial instruments (note 21(a))	5,926	9,054
Other long term obligations (note 16(a))	8,860	25,576
Deferred tax liabilities (note 17)	52,788	44,441
Total liabilities	622,213	535,691
Shareholders' equity
Common shares (authorized - unlimited number of voting common shares; issued and outstanding - March 31, 2012 - 36,251,006 (March 31, 2011 - 36,242,526) (note 18(a))	304,908	304,854
Additional paid-in capital	8,711	7,007
Deficit	(185,820)	(164,536)
Accumulated other comprehensive loss	(19)	(59)
Total shareholders' equity	127,780	147,266
Total liabilities and shareholders' equity	749,993	682,957
Commitments (note 25)
Contingencies (note 28)

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Consolidated Statements of Cash Flows (CAD) In Thousands, unless otherwise specified	12 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2010
Operating activities:
Net (loss) income for the period	(21,162)	(34,650)	28,219
Items not affecting cash:
Depreciation	48,900	39,440	42,636
Equity in (earnings) loss of unconsolidated joint venture (note 11)	(86)	2,720	(44)
Amortization of intangible assets (note 12(c))	5,702	3,540	1,719
Amortization of deferred lease inducements (note 16(b))	(107)	(107)	(107)
Amortization of deferred financing costs (note 12(d))	1,591	1,609	3,348
Loss on disposal of property, plant and equipment	1,741	1,948	1,233
(Gain) loss on disposal of assets held for sale (note 12(b))	(466)	825	373
Realized and unrealized foreign exchange gain on 8 3/4% senior notes		(732)	(48,920)
Realized and unrealized (gain) loss on derivative financial instruments	(2,382)	(2,305)	38,852
Loss on debt extinguishment (note 15(d))		4,346
Stock-based compensation (reversal) expense (note 27(a))	(2,263)	8,156	5,270
Cash settlement of restricted share unit plan (note 27(e))	(318)
Cash settlement of stock options (note 27(b))			(244)
Settlement of stock award plan (note 27(g))	(822)
Accretion of asset retirement obligation (note 16(c))	39	35	5
Deferred income tax (benefit) expense (note 17)	(6,546)	(9,340)	9,876
Net changes in non-cash working capital (note 22(b))	39,452	(15,982)	(39,591)
Total operating activities	63,273	(497)	42,625
Investing activities:
Acquisition, net of cash acquired (note 6)		(23,501)	(5,410)
Purchase of property, plant and equipment	(61,759)	(36,417)	(51,888)
Additions to intangible assets (note 12(c))	(3,537)	(4,748)	(3,362)
Investment in and advances to unconsolidated joint venture (note 11)		(1,291)	(2,873)
Proceeds on disposal of property, plant and equipment	176	499	1,440
Proceeds on disposal of assets held for sale	920	826	2,482
Total investing activities	(64,200)	(64,632)	(59,611)
Financing activities:
Repayment of credit facilities	(196,203)	(85,000)	(6,906)
Increase in credit facilities	203,000	128,524	34,700
Financing costs (note 12(d))	(60)	(7,920)	(1,123)
Redemption of 8 3/4 % senior notes (note 15(d))		(202,410)
Issuance of Series 1 Debentures (note 15(e))		225,000
Settlement of swap liabilities (note 21(a))		(91,125)
Proceeds from stock options exercised (note 27(b))	35	963	53
Repayment of capital lease obligations	(5,207)	(5,127)	(5,613)
Total financing activities	1,565	(37,095)	21,111
Increase (decrease) in cash and cash equivalents	638	(102,224)	4,125
Effect of exchange rate on changes in cash and cash equivalents	40	(59)
Cash and cash equivalents, beginning of year	722	103,005	98,880
Cash and cash equivalents, end of year	1,400	722	103,005

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Contingencies

12 Months Ended

Mar. 31, 2012

Contingencies/Commitments [Abstract]

Contingencies

28. 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.

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Long term debt

12 Months Ended

Mar. 31, 2012

Long term debt [Abstract]

Long term debt

15. Long term debt

a) Long term debt are as follows:

Current:
	March 31, 2012		March 31, 2011
Credit facilities (note 15(b))		$10,000		$10,000
Capital lease obligations (note 15(c))		4,402		$4,862
		$14,402		$14,862
Long term:
	March 31, 2012		March 31, 2011
Credit facilities (note 15(b))		$68,767		$61,970
Capital lease obligations (note 15(c))		6,299		3,831
Series 1 Debentures (note 15(e))		225,000		225,000
		$300,066		$290,801

b) Credit Facilities

	March 31, 2012			March 31, 2011
Term A Facility		$20,950			$24,698
Term B Facility		37,496			43,748
Total term facilities		$58,446			$68,446
Revolving Facility		20,321			3,524
Total credit facilities		$78,767			$71,970
Less: current portion of term facilities		(10,000	)		(10,000	)
		$68,767			$61,970

As of March 31, 2012, the Company had outstanding borrowings of $58.4 million (March 31, 2011 – $68.4 million) under the term facilities, $20.3 million (March 31, 2011 – $3.5 million) under the Revolving Facility and had issued $15.0 million (March 31, 2011 – $12.3 million) in letters of credit under the Revolving Facility to support performance guarantees associated with customer contracts. The funds available for borrowing under the Revolving Facility are reduced by any outstanding letters of credit.

Effective September 30, 2011, the Company entered into a Second Amending Agreement to the Fourth Amended and Restated Credit Agreement to provide a temporary increase in the amount available under the Revolving Facility from $85 million to $110.0 million. This increase, which was to remain in effect until March 31, 2012, provided additional borrowing availability to meet working capital requirements and to accommodate the issuance of letters of credit. The receipt of proceeds resulting from the settlement of the Canadian Natural Resources Limited (Canadian Natural) contract negotiations were to be used to repay amounts outstanding on the Revolving Facility and the amount available for borrowing under the temporary addition was to be permanently reduced by the amount of the settlement proceeds received on December 22, 2011. The amount available under the temporary increase was reduced by the $4.3 million received from Canadian Natural, resulting in a reduction in the total amount available under the Revolving Facility to $105.7 million.

In March 2012, the Company entered into a Third Amending Agreement to the Fourth Amended and Restated Credit Agreement to extend the maturity date of the credit agreement by six months to October 31, 2013 and temporarily amended Consolidated EBITDA related covenants as defined within the credit agreement to maintain covenant compliance at year end. The amendment also extended the term of the temporary increase to the Company’s revolving credit facility to June 30, 2012. The Company’s unused borrowing availability under the Revolving Facility was $70.4 million at March 31, 2012. As defined in the agreement, 55% of the proceeds received from Canadian Natural will be used to prepay the outstanding principal and accrued interest under the temporary addition.

Interest on Canadian prime rate loans is paid at variable rates based on the Canadian prime rate plus the applicable pricing margin (as defined in 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 Canadian prime rate 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. Stamping fees and interest related to the issuance of Bankers’ Acceptances is paid in advance upon the issuance of such Bankers’ Acceptance. The weighted average interest rate on Revolving Facility and Term Facility borrowings at March 31, 2012 was 6.92%.

The credit facilities are secured by a first priority lien on substantially all of the Company’s existing and after-acquired property and contain certain restrictive covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions, paying dividends or redeeming shares of capital stock.

c) 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:

2013	$4,693
2014	2,230
2015	1,938
2016	2,209
2017	651
Subtotal:	$11,721
Less: amount representing interest	(1,020	)
Present value of minimum lease payments	$10,701
Less: current portion	(4,402	)
Long term portion	$6,299

d) 8 ³ /4% Senior Notes

The 8  ³/4% senior notes were issued on November 26, 2003 in the amount of US $200.0 million (Canadian $263.0 million). On April 28, 2010, the Company redeemed the 8 ³/4 % senior notes for $202,410 and recorded a $4,346 loss on debt extinguishment including a $4,324 write off of deferred financing costs (note 12(d)).

e) Series 1 Debentures

On April 7, 2010, the Company issued $225.0 million of 9.125% Series 1 Debentures (the “Series 1 Debentures”). The Series 1 Debentures mature on April 7, 2017. The Series 1 Debentures bear interest at 9.125% per annum and such interest is payable in equal instalments semi-annually in arrears on April 7 and October 7 in each year, commencing on October 7, 2010.

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 the Company or any of its subsidiaries. The Series 1 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 Series 1 Debentures with the net cash proceeds of one or more 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 Series 1 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 Series 1 Debentures, in whole or in part, at a redemption price which is equal to the greater of (a) the Canada Yield Price (as defined in the trust indenture) and (b) 100% of the aggregate principal amount of Series 1 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 Series 1 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 Series 1 Debentures, at a purchase price in cash equal to 101% of the principal amount of the Series 1 Debentures offered for repurchase plus accrued interest to the date of purchase.

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Comparative figures

12 Months Ended

Mar. 31, 2012

Comparative figures [Abstract]

Comparative figures

29. Comparative figures

Certain of the comparative figures have been reclassified from statements previously presented to conform to the presentation of the current period consolidated financial statements.

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Income taxes

12 Months Ended

Mar. 31, 2012

Income taxes [Abstract]

Income taxes

17. Income taxes

Income tax (benefit) provision 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,	2012			2011			2010
(Loss) income before income taxes	$	(28,385	)		$(41,098	)		$41,898
Tax rate		26.25%			27.75%			28.91%
Expected (benefit) expense		$(7,451	)		$(11,405	)		$12,113
Increase (decrease) related to:
Impact of enacted future statutory income tax rates		278			164			(673	)
Income tax adjustments and reassessments		313			909			1,442
Valuation allowance		(91	)		962			–
Stock-based compensation		(393	)		1,443			617
Non deductible portion of capital losses		–			1,063			–
Other		121			416			180
Income tax (benefit) expense		$(7,223	)		$(6,448	)		$13,679
Classified as:
		2012			2011			2010
Year ended March 31,
Current income tax (benefit) expense		$(677	)		$2,892			$3,803
Deferred income tax (benefit) expense		(6,546	)		(9,340	)		9,876
		$(7,223	)		$(6,448	)		$13,679

The deferred tax assets and liabilities are summarized below:

	March 31, 2012			March 31, 2011
Deferred tax assets:
Non-capital losses carried forward		$51,614			$41,581
Derivative financial instruments		2,296			2,895
Billings in excess of costs on uncompleted contracts		1,887			508
Capital lease obligations		2,689			2,247
Intangible assets		–			473
Long term portion of liabilities related to equipment leases		–			2,029
Deferred lease inducements		134			161
Stock-based compensation		1,402			1,656
Other		420			99
		$60,442			$51,649
	March 31, 2012			March 31, 2011
Deferred tax liabilities:
Unbilled revenue and uncertified revenue included in accounts receivable		$13,039			$24,418
Assets held for sale		462			189
Accounts receivable – holdbacks		8,071			3,154
Property, plant and equipment		52,323			44,105
Deferred financing costs		224			71
Intangible assets		8			76
Other		173			40
		$74,300			$72,053
Net deferred income tax liability		$(13,858	)		$(20,404	)

Classified as:

	March 31, 2012			March 31, 2011
Current asset		$2,991			$1,729
Long term asset		57,451			49,920
Current liability		(21,512	)		(27,612	)
Long term liability		(52,788	)		(44,441	)
		$(13,858	)		$(20,404	)

The Company and its subsidiaries file income tax returns in the Canadian federal jurisdiction, five provincial jurisdictions and US federal and Texas state jurisdiction. For years before 2007, the Company is no longer subject to Canadian federal or provincial examinations.

The Company has a full valuation allowance against capital losses in deferred tax benefits of $962 as at March 31, 2012 (2011 – $962; 2010 – $nil). At March 31, 2012, the Company has non-capital losses for income tax purposes of $205,565 which predominately expire after 2027.

	March 31, 2012
2027		$2,973
2028		7,222
2029		13,676
2030		25,707
2031		93,267
2032		62,720
		$205,565

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Consolidated Statements of Cash Flows (Parenthetical)	Mar. 31, 2011	Mar. 31, 2010
Consolidated Statements of Cash Flows [Abstract]
Senior notes, interest rate	8.75%	8.75%

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Consolidated Balance Sheets (Parenthetical)	Mar. 31, 2012	Mar. 31, 2011
Consolidated Balance Sheets [Abstract]
Common shares, authorized	unlimited	unlimited
Common shares, issued	36,251,006	36,242,526
Common shares, outstanding	36,251,006	36,242,526

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Prepaid expenses and deposits

12 Months Ended

Mar. 31, 2012

Prepaid expenses and deposits/Other assets [Abstract]

Prepaid expenses and deposits

10. Prepaid expenses and deposits

Current:
	March 31, 2012		March 31, 2011
Prepaid insurance and property taxes		$1,257		$1,022
Prepaid lease payments		4,624		6,203
Prepaid interest		434		1,044
		$6,315		$8,269
Long term:
	March 31, 2012		March 31, 2011
Prepaid lease payments (note 12(a))		$895		$2,354

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Document and Entity Information	12 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Document and Entity Information [Abstract]
Entity Registrant Name	North American Energy Partners Inc.
Entity Central Index Key	0001368519
Document Type	40-F
Document Period End Date	Mar. 31, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--03-31
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding		36,242,526

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Investment in and advances to unconsolidated joint venture

12 Months Ended

Mar. 31, 2012

Investment in and advances to unconsolidated joint venture [Abstract]

Investment in and advances to unconsolidated joint venture

11. Investment in and advances to unconsolidated joint venture

The Company was engaged in a joint venture, Noramac Joint Venture (JV), of which the Company had joint control (50% proportionate interest). The JV was formed for the purpose of expanding the Company’s market opportunities and establishing strategic alliances in Northern Alberta. The Company owned a 49% interest in Noramac Ventures Inc., a nominee company established by the two joint venture partners. On March 25, 2011, the Company and its joint venture partner decided to wind up Noramac Ventures Inc. and terminate the joint venture. At March 31, 2012 and 2011, the assets and liabilities of the joint venture are stated at the lower of carrying value and fair market value less costs to sell. The difference between carrying value and fair market value of assets and liabilities was recognized in the income statement of the joint venture during the years ended March 31, 2012 and 2011.

As of March 31, 2012, the Company’s investment in and advances to the unconsolidated joint venture totalled $1,574 (2011 – $1,488; 2010 – $2,917). The condensed financial data for investment in and advances to unconsolidated joint venture is summarized as follows:

	March 31, 2012		March 31, 2011
Current assets		$6,556		$8,328
Current liabilities		10,716		13,875

Year ended March 31,	2012			2011		2010
Gross revenues		$1,922			$12,196		$8,774
Gross (profit) loss		1,922			2,483		(1,610	)
Net (income) loss		(172	)		5,440		(87	)
Equity in (earnings) loss of unconsolidated joint venture		($86	)		$2,720		$(44	)

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Consolidated Statements of Operations and Comprehensive (Loss) Income (CAD) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2010
Consolidated Statements of Operations and Comprehensive (Loss) Income [Abstract]
Revenue	1,006,545	858,048	758,965
Project costs	610,821	456,119	301,307
Equipment costs	220,738	234,933	209,408
Equipment operating lease expense	65,185	69,420	66,329
Depreciation	48,900	39,440	42,636
Gross profit	60,901	58,136	139,285
General and administrative expenses	54,400	59,828	62,516
Loss on disposal of property, plant and equipment	1,741	1,948	1,233
(Gain) loss on disposal of assets held for sale (note 12(b))	(466)	825	373
Amortization of intangible assets (note 12(c))	5,702	3,540	1,719
Equity in (earnings) loss of unconsolidated joint venture (note 11)	(86)	2,720	(44)
Operating (loss) income before the undernoted	(390)	(10,725)	73,488
Interest expense, net (note 19)	30,325	29,991	26,080
Foreign exchange loss (gain)	52	(1,659)	(48,901)
Realized and unrealized (gain) loss on derivative financial instruments (note 21(a))	(2,382)	(2,305)	54,411
Loss on debt extinguishment (note 15(d))		4,346
(Loss) income before income taxes	(28,385)	(41,098)	41,898
Income tax (benefit) expense (note 17):
Current	(677)	2,892	3,803
Deferred	(6,546)	(9,340)	9,876
Net (loss) income	(21,162)	(34,650)	28,219
Other comprehensive income (loss)
Unrealized foreign currency translation gain (loss)	40	(59)
Comprehensive (loss) income	(21,122)	(34,709)	28,219
Net (loss) income per share - basic (note 18(b))	(0.58)	(0.96)	0.78
Net (loss) income per share - diluted (note 18(b))	(0.58)	(0.96)	0.77

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Goodwill

12 Months Ended

Mar. 31, 2012

Goodwill [Abstract]

Goodwill

5. Goodwill

In accordance with the Company’s accounting policy, a goodwill impairment test is completed 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 tests on October 1, 2011, 2010 and 2009 and concluded that there was no goodwill impairment as the fair value of the Piling reporting unit exceeded its carrying value. There were no triggering events between October 1, 2011 and March 31, 2012.

The changes in goodwill during the years ended March 31, 2012, 2011 and 2010 are as follows:

Balance at March 31, 2009	$23,872
Acquisition of goodwill (assigned to the Piling segment) (note 6(b))	1,239
Balance at March 31, 2010	25,111
Acquisition of goodwill (assigned to the Piling segment) (note 6(a))	7,790
Balance at March 31, 2011 and March 31, 2012	$32,901

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Recent United States accounting pronouncements not yet adopted

12 Months Ended

Mar. 31, 2012

Accounting pronouncements recently adopted/Recent United States accounting pronouncements not yet adopted [Abstract]

Recent United States accounting pronouncements not yet adopted

4. Recent United States accounting pronouncements not yet adopted

a) Goodwill Impairment

In September 2011, the FASB issued ASU 2011-08, “Intangibles – Goodwill and Other – Testing Goodwill for Impairment”, which amended the guidance on the annual testing of goodwill for impairment. The amended guidance will allow companies to assess qualitative factors to determine if it is more-likely-than-not that goodwill might be impaired and whether it is necessary to perform the two-step goodwill impairment test required under current accounting standards. This guidance will be effective for the Company’s fiscal year ending March 31, 2013, with early adoption permitted. The Company has determined that this new guidance will not have a material impact on its consolidated financial statements.

b) Offsetting Assets and Liabilities

In December 2011, the FASB issued ASU 2011-11, “Balance Sheet”, which amends the disclosure requirements on offsetting in Section 210-20-50. The amendments require enhanced disclosures by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with either Section 210-20-45 or Section 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either Section 210-20-45 or Section 815-10-45. This guidance will be effective for the Company’s fiscal year ending March 31, 2014. This standard does not amend the existing guidance on when it is appropriate to offset. The adoption of this standard is not anticipated to have a material effect on the Company’s consolidated financial statements.

c) Comprehensive income

In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. This ASU requires the presentation of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements rather than as a footnote to the consolidated financial statements, where it is currently disclosed. The ASU also requires the presentation of reclassification adjustments for items that are reclassified from other comprehensive income to net income in the financial statements where the components of net income and the components of other comprehensive income are presented. The option under current guidance that permits the presentation of components of other comprehensive income as part of the statement of changes in shareholders’ equity will be eliminated. In December 2011, the FASB further amended its guidance to defer changes related to the presentation of reclassification adjustments indefinitely as a result of concerns raised by stakeholders that the new presentation requirements would be difficult for preparers and add unnecessary complexity to financial statements. This guidance will be effective for the Company’s fiscal year ending March 31, 2013. The Company has determined that this new guidance will not have a material impact on its consolidated financial statements.

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Other long term obligations

12 Months Ended

Mar. 31, 2012

Other long term obligations [Abstract]

Other long term obligations

16. Other long term obligations

a) Other long term obligations are as follows:

	March 31, 2012			March 31, 2011
Long term portion of liabilities related to equipment leases		$3,169			$12,747
Deferred lease inducements (note 16(b))		547			654
Asset retirement obligation (note 16(c))		434			395
Senior executive stock option plan (note 27(c))		1,322			5,115
Restricted share unit plan (note 27(e))		3,170			2,633
Director’s deferred stock unit plan (note 27(f))		2,284			4,032
		$10,926			$25,576
Less: current portion of restricted share unit plan (note 27(e))		(2,066	)		–
		$8,860			$25,576

b) Deferred lease inducements

Lease inducements applicable to lease contracts are deferred and amortized as a reduction of general and administrative expenses 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, 2012			March 31, 2011
Balance, beginning of year		$654			$761
Amortization of deferred lease inducements		(107	)		(107	)
Balance, end of year		$547			$654

c) 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.

The following table presents a continuity of the liability for the asset retirement obligation:

	March 31, 2012		March 31, 2011
Balance, beginning of year		$395		$360
Accretion expense		39		35
Balance, end of year		$434		$395

At March 31, 2012, estimated undiscounted cash flows required to settle the obligation were $1,084 (March 31, 2011 – $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.

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Other assets

12 Months Ended

Mar. 31, 2012

Prepaid expenses and deposits/Other assets [Abstract]

Other assets

12. Other assets

a) Other assets are as follows:

	March 31, 2012		March 31, 2011
Prepaid lease payments (note 10)		$895		$2,354
Assets held for sale (note 12(b) and 21(a))		1,841		721
Intangible assets (note 12(c))		12,866		16,161
Deferred financing costs (note 12(d))		6,141		7,672
		$21,743		$26,908

b) Assets held for sale

Equipment disposal decisions are made using an approach in which a target life 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 basedon its expected operating cost and reliability in its current state. If the expected operating cost exceeds the target operating cost for the fleet or if the expected reliability is lower than the target reliability of the fleet, the unit is considered for disposal. 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, 2012, impairment of assets held for sale amounting to $8,748, largely due to the writedown of several haul trucks to fair value, have been included in depreciation expense in the Consolidated Statements of Operations (2011 – $141; 2010 – $806). The impairment charge is the amount by which the carrying value of the related assets exceeded their fair value less costs to sell. Gain on disposal of assets held for sale was $466 for the year ended March 31, 2012 (2011 – loss of $825; 2010 – loss of $373).

c) Intangible assets

March 31, 2012	Cost		Accumulated Amortization		Net Book Value
Customer relationships and backlog		$4,442		$1,445		$2,997
Other intangible assets		2,364		1,204		1,160
Internal-use software		16,825		9,644		7,181
Patents		2,017		489		1,528
		$25,648		$12,782		$12,866

March 31, 2011	Cost		Accumulated Amortization		Net Book Value
Customer relationships and backlog		$4,442		$755		$3,687
Other intangible assets		2,364		779		1,585
Internal-use software		15,469		6,441		9,028
Patents		2,017		156		1,861
		$24,292		$8,131		$16,161

During the year ended March 31, 2012, the Company capitalized $3,537 (2011 – $4,748; 2010 – $3,362) related to internally developed computer software. Internal use software with a cost of $607 and accumulated amortization of $358 was written off and the net book value of $249 was included in amortization of intangible assets during the year ended March 31, 2012 (2011 – $nil; 2010 – $208).

Amortization of intangible assets for the year ended March 31, 2012 was $5,702 (2011 – $3,540; 2010 – $1,719). The estimated amortization expense for future years is as follows:

For the year ending March 31,
2013	$4,325
2014	3,625
2015	2,474
2016	1,574
2017 and thereafter	868
	$12,866

During the year ended March 31, 2011, $7,284 in additions were made to intangible assets as a result of the acquisition of the assets of Cyntech Corporation and its wholly-owned subsidiary Cyntech Anchor Systems LLC (note 6(a)).

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 6(b)).

d) Deferred financing costs

March 31, 2012	Cost		Accumulated Amortization		Net Book Value
Term and revolving facilities		$5,422		$4,652		$770
Series 1 Debentures		6,886		1,515		5,371
		$12,308		$6,167		$6,141
March 31, 2011	Cost		Accumulated Amortization		Net Book Value
Term and revolving facilities		$5,362		$3,855		$1,507
Series 1 Debentures		6,886		721		6,165
		$12,248		$4,576		$7,672

During the year ended March 31, 2012, financing fees of $60 were incurred in connection with the modifications made to the amended and restated credit agreement (2011 – $1,034; 2010 – $1,123) (note 15(b)). During the year ended March 31, 2012, financing fees of $nil were incurred in connection with the Series 1 Debentures (2011 – $5,846) (note 15(e)). These fees have been recorded as deferred financing costs and are being amortized using the effective interest method over the term of the credit agreement and the series 1 Debentures, respectively.

Amortization of deferred financing costs included in interest expense for the year ended March 31, 2012 was $1,591 (2011–$1,609; 2010 – $3,348). Upon redemption of the 8 ³/4% senior notes on April 28, 2010, the unamortized deferred financing costs related to the 8 ³/4 % senior notes of $4,324 were expensed and included in the loss on debt extinguishment (note 15(d)). In addition, $183 related to amortization of deferred financing costs incurred up to the redemption date was included in interest expense.

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Costs incurred and estimated earnings net of billings on uncompleted contracts

12 Months Ended

Mar. 31, 2012

Costs incurred and estimated earnings net of billings on uncompleted contracts [Abstract]

Costs incurred and estimated earnings net of billings on uncompleted contracts

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

	March 31, 2012			March 31, 2011
Costs incurred and estimated earnings on uncompleted contracts		$587,220			$946,482
Less billings to date		(509,511	)		(845,547	)
		$77,709			$100,935

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

	March 31, 2012			March 31, 2011
Unbilled revenue		$86,859			$102,939
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		(7,514	)		(2,004	)
		$79,345			$100,935

Unbilled revenue related to non-construction activities amounted to $1,636 (March 31, 2011– $nil).

An amount of $18,080 (March 31, 2011 – $72,025) is recognized within unbilled revenue relating to a single long-term customer contract, whereby the normal operating cycle for this project is greater than one year. As described in Note 2(b) the estimated balances within unbilled revenue are subject to uncertainty concerning ultimate realization.

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Acquisitions

12 Months Ended

Mar. 31, 2012

Acquisitions [Abstract]

Acquisitions

6. Acquisitions

a) Acquisitions in fiscal 2011

On November 1, 2010, the Company acquired all of the assets of Cyntech Corporation and its wholly-owned subsidiary Cyntech Anchor Systems LLC (collectively “Cyntech”), for consideration of $23,501. Cyntech is based in Calgary, Alberta and designs and manufactures screw piles and pipeline anchoring systems, and provides tank maintenance services to the petro-chemical industry. As a result of this acquisition, the Company gained access to screw piling, pipeline anchor design and manufacturing capabilities in Canada and the United States. The Company also gained oil and gas storage tank repair and maintenance capabilities which complement the Company’s existing service offering. The transaction was accounted for using the acquisition method with the results of operations included in the financial statements from the date of acquisition. Acquisition related costs were recorded in general and administrative expenses. The goodwill acquired is deductible for tax purposes.

The following table summarizes the recognized amounts of the assets acquired and liabilities assumed at the acquisition date:

Accounts receivable	$7,064
Inventories	1,646
Prepaid expenses and deposits	45
Plant and equipment	1,346
Intangible assets	7,284
Accounts payable	(1,674	)
Total identifiable net assets	$15,711
Goodwill	7,790
Total consideration	$23,501

b) Acquisitions in fiscal 2010

On August 1, 2009, the Company acquired all of the issued and outstanding shares of DF Investments Limited and its subsidiary Drillco Foundation Co. Ltd., a piling company based in Milton, Ontario, for consideration of $5,410. This acquisition provided the Company access to piling markets and customers in the Toronto area. The transaction was 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 following table summarizes the recognized amounts of the assets acquired and liabilities assumed at the acquisition date:

Accounts receivable	$4,101
Inventories	59
Prepaid expenses and deposits	11
Property, plant and equipment	2,873
Land	281
Intangible assets	547
Accounts payable and accrued liabilities	(2,211	)
Deferred tax liabilities	(838	)
Long term debt	(652	)
Total identifiable net assets	$4,171
Goodwill	1,239
Total consideration	$5,410

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Accounts receivable

12 Months Ended

Mar. 31, 2012

Accounts receivable [Abstract]

Accounts receivable

7. Accounts receivable

	March 31, 2012			March 31, 2011
Accounts receivable – trade		$180,917			$115,660
Accounts receivable – holdbacks		32,134			12,018
Income and other taxes receivable		–			397
Accounts receivable – other		1,288			437
Allowance for doubtful accounts (note 21(d))		(210	)		(30	)
		$214,129			$128,482

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. Holdbacks include $6,038 as of March 31, 2012 (March 31, 2011– $587) which relate to contracts whereby the normal operating cycle is greater than one year and therefore are not expected to be collected within a year.

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Inventories

12 Months Ended

Mar. 31, 2012

Inventories [Abstract]

Inventories

9. Inventories

	March 31, 2012		March 31, 2011
Spare tires		$6,620		$3,794
Job materials		2,188		2,118
Manufacturing raw materials		1,669		926
Finished goods		1,378		897
		$11,855		$7,735

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Stock-based compensation

12 Months Ended

Mar. 31, 2012

Stock-based compensation [Abstract]

Stock-based compensation

27. Stock-based compensation

a) Stock-based compensation expenses

Stock-based compensation expenses included in general and administrative expenses are as follows:

Year ended March 31,	2012			2011			2010
Share option plan (note 27(b))		$1,373			$1,455			$2,135
Senior executive stock option plan (note 27(c))		(2,878	)		2,878			–
Deferred performance share unit plan (note 27(d))		–			(44	)		123
Restricted share unit plan (note 27(e))		733			1,603			1,010
Director’s deferred stock unit plan (note 27(f))		(1,747	)		1,484			2,002
Stock award plan (note 27(g))		256			780			–
		$(2,263	)		$8,156			$5,270

b) Share option plan

Under the 2004 Amended and Restated Share Option Plan, which was approved and became effective in 2006, 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, 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
Granted		260,000			9.77
Exercised(i)		(193,250	)		4.98
Forfeited		(120,080	)		10.30
Modified (ii)		(550,000	)		5.00
Outstanding at March 31, 2011		1,647,474			9.25
Granted		287,700			6.56
Exercised(i)		(8,480	)		4.15
Forfeited		(91,900	)		10.42
Outstanding at March 31, 2012		1,834,794			8.79

(i) All stock options exercised resulted in new common shares being issued (note 18(a));

(ii) 550,000 stock options were modified as senior executive stock options on September 22, 2010 (note 27(c)).

Cash received from the option exercises for the year ended March 31, 2012 was $35 (2011—$963; 2010 – $53). Cash paid for options settled for cash for the year ended March 31, 2012 was $nil (2011 – $nil; 2010 – $244).The total intrinsic value of options exercised, calculated as market value at the exercise date less exercise price, multiplied by the number of units exercised, for the years ended March 31, 2012, 2011 and 2010 was $48, $1,084 and $277, respectively.

The following table summarizes information about stock options outstanding at March 31, 2012:

	Options outstanding						Options exercisable
Exercise price	Number		Weighted average remaining life		Weighted average exercise price		Number		Weighted average remaining life		Weighted average exercise price
$3.69		127,320		6.7 years		$3.69		73,840		6.7 years		$3.69
$5.00		437,294		2.7 years		$5.00		437,294		2.7 years		$5.00
$6.56		277,100		9.7 years		$6.56		–		–		–
$8.28		130,000		7.2 years		$8.28		52,000		7.2 years		$8.28
$8.58		60,000		8.5 years		$8.58		12,000		8.5 years		$8.58
$9.33		159,280		7.9 years		$9.33		64,720		7.9 years		$9.33
$10.13		174,480		8.7 years		$10.13		35,440		8.7 years		$10.13
$13.21		75,000		5.8 years		$13.21		60,000		5.8 years		$13.21
$13.50		201,560		5.7 years		$13.50		161,720		5.7 years		$13.50
$15.37		40,000		6 years		$15.37		32,000		6 years		$15.37
$16.01		75,000		6 years		$16.01		45,000		6 years		$16.01
$16.46		50,000		6 years		$16.46		30,000		6 years		$16.46
$16.75		27,760		4.5 years		$16.75		27,760		4.5 years		$16.75
		1,834,794		6.3 years		$8.79		1,031,774		4.8 years		$8.82

At March 31, 2012, the weighted average remaining contractual life of outstanding options is 6.3 years (March 31, 2011 – 6.8 years). The fair value of options vested during the year ended March 31, 2012 was $1,652 (March 31, 2011 – $1,892). At March 31, 2012, the Company had 1,031,774 exercisable options (March 31, 2011 – 830,482) with a weighted average exercise price of $8.82 (March 31, 2011 – $8.52).

At March 31, 2012, the total compensation costs related to non-vested awards not yet recognized was $2,655 (March 31, 2011 – $2,973) and these costs are expected to be recognized over a weighted average period of 3.2 years (March 31, 2011 – 3.4 years).

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

Year ended March 31,	2012		2011		2010
Number of options granted		287,700		260,000		375,700
Weighted average fair value per option granted ($)		4.38		6.79		6.25
Weighted average assumptions:
Dividend yield		Nil%		Nil%		Nil%
Expected volatility		75.22%		78.59%		76.27%
Risk-free interest rate		1.32%		2.65%		3.39%
Expected life (years)		6.3		6.1		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.

c) Senior executive stock option plan

On September 22, 2010, the Company modified a senior executive employment agreement to allow the option holder the right to settle options in cash which resulted in 550,000 stock options (senior executive stock options) changing classification from equity to a long term liability. The liability is measured at fair value using the Black-Scholes model at the modification date and subsequently at each period end date. Previously recognized compensation cost related to the senior executive stock option plan of $2,237 was transferred from additional paid-in capital to the senior executive stock option liability on the modification date. The fair value of the compensation liability is calculated using the Black-Scholes model at each period end. Changes in fair value of the liability are recognized in the Consolidated Statements of Operations.

The weighted average assumptions used in estimating the fair value of the senior executive stock options as at March 31, 2012 are as follows:

Year ended March 31,	2012		2011
Number of senior executive stock options		550,000		550,000
Weighted average fair value per option granted ($)		2.40		9.3
Weighted average assumptions:
Dividend yield		Nil%		Nil%
Expected volatility		74.99%		76.74%
Risk-free interest rate		0.54%		1.77%
Expected life (years)		3.11		4.10

d) Deferred performance share unit plan

The company has no outstanding Deferred Performance Share Units (“DPSUs”) at this time. DPSUs were granted each fiscal year with respect of services to be provided in that fiscal year and the following two fiscal years. The DPSUs vested the end of a three-year term and were subject to the performance criteria approved by the Compensation Committee of the Board of Directors at the date of grant. Such performance criterion included the passage of time and was based upon return on invested capital calculated as operating income divided by average operating assets. The maturity date for such DPSUs was the last day of the third fiscal year following the grant date. At the maturity date, the Compensation Committee assesses the participant against the performance criteria and determines the number of DPSUs that were earned (earned DPSUs).

The settlement of the participant’s entitlement was made at the Company’s option either in cash, in an amount equivalent to the number of earned DPSUs multiplied by the fair market value of the Company’s common shares as determined by the volume weighted average trading price of the Company’s common shares for the five trading days immediately preceding 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 were purchased on the open market or through the issuance of shares from treasury.

The fair value of each unit under the DPSU Plan was estimated on the date of the grant using Black-Scholes option pricing model. There were no DPSUs granted in fiscal 2011 and 2012. The weighted average assumptions used in estimating the fair value of the share options issued under the DPSU Plan during the year ended March 31, 2010 is as follows:

Number of units granted	908,165
Weighted average fair value per unit granted ($)	4.71
Weighted average assumptions:
Dividend yield	Nil%
Expected volatility	96.89%
Risk-free interest rate	1.47%
Expected life (years)	3.00

	Number of units
Outstanding at March 31, 2009		91,005
Granted		908,165
Forfeited		(102,671	)
Converted to RSUs (note 27(e))		(389,204	)
Outstanding at March 31, 2010		507,295
Forfeited		(74,776	)
Outstanding at March 31, 2011		432,519
Expired		(41,117	)
Converted to RSUs (note 27(e))		(391,402	)
Outstanding at March 31, 2012		–

On April 1, 2011, the Company converted 262,737 and 128,665 Deferred Performance Share Units (“DPSUs”) into Restricted Share Units (“RSUs”) for the April 1, 2009 and March 31, 2010 grants at a conversion factor of 50% and 75% respectively (note 27(e)).

At March 31, 2012 there were nil outstanding DPSUs. At March 31, 2011, there were 111,020 units vested and the weighted average remaining contractual life of outstanding DPSU units was 1.2 years. 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, 2011, there was approximately $242 of total unrecognized compensation cost related to non-vested share-based payment arrangements under the DPSU Plan, which was expected to be recognized over a weighted average period of 1.2 years and was subject to performance adjustments. On December 18, 2009, the Company converted 26,059 and 363,145 DPSUs into RSUs for the April 1, 2008 and April 1, 2009 grants respectively at a conversion factor of 80% (note 27(e)).

e) Restricted share unit plan

Restricted Share Units (“RSUs”) are granted 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 number of vested shares multiplied by the fair market value of each RSU as determined by the volume weighted average trading price of the Company’s common shares for the five trading days immediately preceding the day on which the fair market value is to be determined. The Company recognizes compensation expense over the three-year term of the RSU in the Consolidated Statements of Operations.

On April 1, 2011, the Company converted the April 1, 2009 and March 31, 2010 DPSUs (note 27(d)) into RSUs at a conversion factor of 50% and 75% respectively. On December 18, 2009, the Company converted certain middle manager’s DPSUs (note 27(d)) into RSUs at a conversion factor of 80%.

	Number of units
Outstanding at March 31, 2009		–
Converted from DPSUs (note 27(d))		311,358
Granted		169,489
Forfeited		(12,032	)
Outstanding at March 31, 2010		468,815
Forfeited		(86,339	)
Outstanding at March 31, 2011		382,476
Granted		695,086
Settled		(27,850	)
Forfeited		(102,022	)
Converted from DPSUs (note 27(d))		227,875
Outstanding at March 31, 2012		1,175,565

At March 31, 2012, the $2,066 current portion of RSU liabilities were included in accrued liabilities (March 31, 2011 - $nil) and long term portion of RSU liabilities of $1,104 were included in other long term obligations (March 31, 2011 — $2,633) in the Consolidated Balance Sheets. During the year ended March 31, 2012, 27,850 units vested and were settled in cash for $318.

At March 31, 2012, there were 329,901 units vested and the redemption value of these units was $4.91/unit (March 31, 2011 – $11.96/unit). At March 31, 2012, the weighted average remaining contractual life of the RSUs outstanding was 1.4 years (March 31, 2011 – 1.3 years).

Using the redemption value of $4.91/unit at March 31, 2012, there was approximately $2,576 of total unrecognized compensation cost related to non–vested share–based payment arrangements under the RSU Plan and these costs are expected to be recognized over the weighted average remaining contractual life of the RSUs of 1.4 years (March 31, 2011 – 1.3 years). On approval of the RSU Plan in 2009, 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.

f) 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 expenses) 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 is determined by dividing the amount of the participant’s deferred remuneration by the Canadian Dollar equivalent of the volume weighted average trading price of the Company’s common shares for the five trading days immediately preceding the date that participants’ remuneration becomes payable. The DDSUs vest immediately upon issuance 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 five trading days immediately preceding death or retirement. Directors, who are not US taxpayers, may elect to defer the redemption date until a date no later than December 1st of the calendar year following the year in which the retirement or death occurred.

	Number of units
Outstanding at March 31, 2009		139,691
Issued		123,575
Outstanding at March 31, 2010		263,266
Issued		73,752
Outstanding at March 31, 2011		337,018
Issued		128,248
Outstanding at March 31, 2012		465,266

At March 31, 2012, the redemption value of these units was $4.91/unit (March 31, 2011 – $11.96/unit). There is no unrecognized compensation expense related to the DDSUs, since these awards vest immediately when issued.

g) Stock award plan

On September 24, 2009, the Chief Executive Officer’s (CEO) employment agreement was extended by the Board of Directors for a further period of two years, to May 8, 2012. In addition to the existing conditions in his employment agreement, as of September 24, 2010, the effective date, the CEO was granted the right to receive 150,000 common shares of the Company as follows:

• 50,000 shares on May 8, 2011;

• 50,000 shares on November 8, 2011; and

• 50,000 shares on May 8, 2012.

These shares, or at the discretion of the company, the cash equivalent thereof, will be awarded to the CEO provided he remains employed on the award dates above.

The CEO’s entitlement, upon the above release dates, shall be settled in common shares purchased on the open market or through the issuance of common shares from treasury, in each case net of required withholdings. The CEO’s entitlement may be settled with newly issued common shares from treasury, if all necessary shareholder approvals and regulatory approvals, if any, are obtained. The Company has no intention to settle in cash.

The estimate of the fair value of the stock award on the grant date is equal to the market price of the Company’s common shares.

During the year ended March 31, 2012, 100,000 stock awards vested and were settled in common shares purchased on the open market for $822. The weighted average remaining contractual life of outstanding Stock Award Plan units is 0.1 years (March 31, 2011 – 0.6 years). As at March 31, 2012, there was approximately $14 (March 31, 2011 – $270) of total unrecognized compensation cost related to non–vested share–based payment arrangements under the stock award plan, which is expected to be recognized over a weighted average period of 0.1 years (March 31, 2011 – 0.6 years).

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Accrued liabilities

12 Months Ended

Mar. 31, 2012

Accrued liabilities [Abstract]

Accrued liabilities

14. Accrued liabilities

	March 31, 2012		March 31, 2011
Accrued interest payable		$9,866		$9,866
Payroll liabilities		15,228		11,412
Liabilities related to equipment leases		4,238		7,518
Income and other taxes payable		7,463		4,018
		$36,795		$32,814

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Interest expense

12 Months Ended

Mar. 31, 2012

Interest Expense [Abstract]

Interest expense

19. Interest expense

	2012		2011		2010
Year ended March 31,
Interest on 8 3/4% senior notes and swaps		$–		$1,238		$19,041
Interest on capital lease obligations		445		689		1,032
Amortization of deferred financing costs		1,591		1,609		3,348
Interest on credit facilities		7,430		5,361		2,375
Interest on Series 1 Debentures		20,531		20,132		–
Interest on long term debt		$29,997		$29,029		$25,796
Other interest		328		962		284
		$30,325		$29,991		$26,080

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Consolidated Statements of Changes in Shareholders' Equity (CAD) In Thousands	Total	Common shares	Additional paid-in capital	Deficit	Accumulated other comprehensive loss
Balance at Mar. 31, 2009	150,792	303,431	5,466	(158,105)
Net (loss) income	28,219			28,219
Share option plan	2,135		2,135
Deferred performance share unit plan	123		123
Reclassified to restricted share unit liability	(20)		(20)
Cash settlement of stock options	(244)		(244)
Exercised stock options	53	74	(21)
Balance at Mar. 31, 2010	181,058	303,505	7,439	(129,886)
Net (loss) income	(34,650)			(34,650)
Unrealized foreign currency translation gain (loss)	(59)				(59)
Share option plan	1,455		1,455
Deferred performance share unit plan	(44)		(44)
Stock award plan	780		780
Exercised stock options	963	1,349	(386)
Senior executive stock option plan	(2,237)		(2,237)
Balance at Mar. 31, 2011	147,266	304,854	7,007	(164,536)	(59)
Net (loss) income	(21,162)			(21,162)
Unrealized foreign currency translation gain (loss)	40				40
Share option plan	1,373		1,373
Reclassified to restricted share unit liability	(121)		(121)
Stock award plan	256		256
Exercised stock options	35	54	(19)
Repurchase of shares to settle stock award plan	(822)		(700)	(122)
Senior executive stock option plan	915		915
Balance at Mar. 31, 2012	127,780	304,908	8,711	(185,820)	(19)

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Accounting Pronouncements Recently Adopted

12 Months Ended

Mar. 31, 2012

Accounting pronouncements recently adopted/Recent United States accounting pronouncements not yet adopted [Abstract]

Accounting pronouncements recently adopted

3. Accounting pronouncements recently adopted

a) 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. The Company adopted this ASU effective April 1, 2011. The adoption of this standard did not have a material effect on the Company’s consolidated financial statements.

b) Share based payment awards

In April 2010, the FASB issued ASU No. 2010-13, “Effect of Denominating the Exercise Price of a 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. The Company adopted this ASU effective April 1, 2011 as an amendment to ASC 718, “Compensation – Stock Compensation”. The adoption of this standard did not have a material effect on the Company’s consolidated financial statements.

c) Intangibles – Goodwill and Other

In December 2010, the FASB issued ASU No. 2010-28, “When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts”, which amends ASC 350, “Intangibles-Goodwill and Other” to modify step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts, to require an entity to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that impairment may exist. The Company adopted this ASU effective April 1, 2011. The adoption of this standard did not have a material effect on the Company’s consolidated financial statements.

d) Business Combinations

In December 2010, the FASB issued ASU No. 2010-29, “Disclosure of Supplementary Pro Forma Information for Business Combinations”, which amends ASC 805, “Business Combinations”, to require that pro-forma information be presented as if the business combination occurred at the beginning of the prior annual reporting period for the purposes of calculating both the current reporting period and the prior reporting period pro forma financial information. The ASU also requires the disclosure be accompanied by a narrative description of the nature and amount of material, nonrecurring pro forma adjustments. The Company adopted this ASU prospectively effective April 1, 2011 for business combinations for which the acquisition date is on or after April 1, 2011. The adoption of this standard did not have a material effect on the Company’s consolidated financial statements.

e) Fair value measurement

In May 2011, the FASB issued ASU 2011-04, “Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRS”, which generally represent clarifications of Topic 820, but also include some instances where a particular principle or requirement for measuring fair value or disclosing information about fair value measurements has changed. This ASU results in common principles and requirements for measuring fair value and for disclosing information about fair value measurements in accordance with US GAAP and IFRSs. The Company adopted this ASU prospectively effective January 1, 2012. The adoption of this standard did not have a material effect on the Company’s consolidated financial statements.

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Claims revenue

12 Months Ended

Mar. 31, 2012

Claims revenue [Abstract]

Claims revenue

20. Claims revenue

	2012		2011		2010
Year ended March 31,
Claims revenue recognized		$35,211		$5,278		$4,541
Claims revenue uncollected (classified as unbilled revenue)		22,759		2,174		785

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Property, plant and equipment

12 Months Ended

Mar. 31, 2012

Property, plant and equipment [Abstract]

Property, plant and equipment

13. Property, plant and equipment

March 31, 2012	Cost		Accumulated Deprecation		Net Book Value
Heavy equipment		$347,699		$124,982		$222,717
Major component parts in use		74,444		28,741		45,703
Other equipment		35,736		17,017		18,719
Licensed motor vehicles		27,120		19,775		7,345
Office and computer equipment		13,438		8,977		4,461
Buildings		4,355		3,235		1,120
Land		281		–		281
Leasehold improvements		6,620		2,232		4,388
Assets under capital lease		16,579		8,538		8,041
		$526,272		$213,497		$312,775

March 31, 2011	Cost		Accumulated Deprecation		Net Book Value
Heavy equipment		$341,734		$108,051		$233,683
Major component parts in use		47,248		15,593		31,655
Other equipment		31,877		14,136		17,741
Licensed motor vehicles		21,368		16,592		4,776
Office and computer equipment		12,128		5,899		6,229
Buildings		21,657		8,176		13,481
Land		281		–		281
Leasehold improvements		9,422		3,856		5,566
Assets under capital lease		19,506		11,054		8,452
		$505,221		$183,357		$321,864

Assets under capital lease are comprised predominately of licensed motor vehicles.

During the year ended March 31, 2012, additions to property, plant and equipment included $7,215 of assets that were acquired by means of capital leases (2011 – $427; 2010 – $1,523). Depreciation of equipment under capital lease of $2,005 (2011 – $2,723; 2010 – $4,081) was included in depreciation expense.