Edgar Filing: North American Energy Partners Inc.

Form 6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16

under the Securities Exchange Act of 1934

For the month of June 2011

Commission File Number 001-33161

NORTH AMERICAN ENERGY PARTNERS INC.

Suite 2400, 500 4^th Avenue SW

Calgary, Alberta T2P 2V6

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F ¨ Form 40-F x

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

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

Documents Included as Part of this Report

1.	2011 Annual Report to Shareholders.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


NORTH AMERICAN ENERGY PARTNERS INC.

By:		/s/ David Blackley
Name:		David Blackley
Title:		Chief Financial Officer

Date: June 29, 2011

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North American Energy Partners Inc.

2011 Annual Report

fundamental

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market-leading expertise and safety

large and specialized fleet

service through the project lifecycle

operational flexibility

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2011 Performance

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

Year ended March 31,

Operating Data 2011 2010 2009

Revenue 858,048 758,965 972,536 Gross profit 58,136 139,285 170,418 Gross profit margin 6.8% 18.4% 17.5% Operating (loss) income (1) (10,829) 73,474 (87,092) Net (loss) income (1) (34,650) 28,219 (135,404)

Per Share Information 2011 2010 2009

Net (loss) income – basic (0.96) 0.78 (3.76) Net (loss) income – diluted (0.96) 0.77 (3.76) Consolidated EBITDA (2) 84,101 121,644 139,446

Balance Sheet Data 2011 2010 2009

Total assets 682,957 706,920 629,275 Total shareholders’ equity 147,266 181,058 150,792 Net debt (3) to total shareholders’ equity 2.1:1 1.2:1 1.4:1

(1) Fiscal 2009 operating loss and net loss reflect a goodwill impairment charge of $176.2 million.

(2) For a definition of Consolidated EBITDA and reconciliation to net income, see “Non-GAAP Financial Measures” and “Consolidated EBITDA.” (3) Net debt is calculated as series 1 debentures, senior notes, current and non-current portion of swap liability, capital lease obligations and credit facilities, less cash and cash equivalents.

Table of Contents

02 At a Glance 04 Letter to Shareholders 08 Operations Review 18 Management’s Discussion and Analysis

67 Management’s Report 68/69 Report of Independent Registered Public Accounting Firm 70 Consolidated Financial Statements

74 Notes to the Consolidated Financial Statements 115 Board of Directors 116 Senior Management inside back cover Corporate and Investor Information

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Toronto and New York Stock Exchanges: NOA

at a glance

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

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Focus

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

2. Strategic prioritization of our capital expenditures to minimize cash out-flows while maintaining the flexibility to take advantage of profitable opportunities; and

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

Mission

To deliver high value mining, site preparation, piling and pipeline construction services and expertise to Canadian resources and construction industries.

Vision

The construction and mining contractor that everyone wants to work for, everyone wants to hire and everyone wants to own.

Revenue (fiscal 2011)

By Segment

78% Heavy Construction and Mining 12% Piling 10% Pipeline

By End Market

78% Canadian Oil Sands

5% Industrial Construction

8% Commercial and Public Construction

9% Pipeline Construction

Heavy Construction and Mining (in thousands)

2011 $667,037 2010 $665,514 2009 $716,053

Piling (in thousands)

2011 $105,559 2010 $68,531 2009 $155,076

Pipeline (in thousands)

2011 $85,452 2010 $24,920 2009 $101,407

Strategy

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:

– Increase our recurring revenue base

– Leverage our long-term relationships with customers

– Leverage and expand our complementary services

– Enhance operating efficiencies to improve revenues and margins

– Pursue growth both organically and through acquisitions

– Increase our presence outside the oil sands

Service Offering

Heavy Construction and Mining Expertise

– Surface mining for oil sands and other natural resources

– Construction of infrastructure associated with mining operations and reclamation activities

– Clearing, stripping, excavating and grading for mining operations

– Industrial site construction for mega projects

– Underground utility installation for plant, refinery and commercial building construction

Piling Expertise

– Installation of all types of driven and drilled piles

– Design and installation of shoring/earth retention and stabilization systems for industrial and commercial projects (secant pile, sheet pile and soldier pile and lagging walls

– Design, fabrication and supply of helical (screw) piles

– Design, fabrication and supply of micro piles

Pipeline Installation Expertise

– Infrastructure development for oil and gas pipeline systems, including gathering and processing, transmission, storage and distribution; related maintenance and other specialty services.

– Installation of pipe ranging from 2 inches to 60 inches in diameter

– Operate effectively in remote locations

– Proven ability to meet demanding environmental protection requirements

Tailings and Environmental Construction

– Tailings pond remediation, tailings management and tailings system maintenance

– Tailings dam and dyke construction, pipeline co-corridor construction

2011 Annual Report | NOA | 03

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to our shareholders

In a year when many competitors struggled and some left the market, we leveraged our strengths to win new business and expand market share across all three of our businesses.

Our Heavy Construction and Mining division entered fiscal 2011 with strong relationships and work programs with our long-term customers, Shell and Canadian Natural and a small but important relationship-building truck rental contract with Suncor. However, we had failed to secure the renewal of our long-term master services agreement with Syncrude. One year later, we had the same good relationship with Canadian Natural, an additional three-year mine reclamation contract with Shell, a new four-year master services agreement with Syncrude and we were in the final stages of negotiating a five-year master services agreement with Suncor.

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Our Piling segment had a particularly strong year, growing market share in Ontario and Saskatchewan, while also winning a number of sizeable industrial contracts. These included a 2,000 pile project at Exxon’s Kearl site near Fort McMurray and continued work on the CCRL Refinery expansion in Regina. In addition, we completed the acquisition of Cyntech Corporation during the year, adding tank services, pipeline anchors and screw piling to our service offering. Our new screw piling capabilities are expected to help us compete more effectively on SAGD oil sands and power transmission construction projects. Our Pipeline division also increased its base of business in 2011, winning two contracts we had targeted. Although weather and scope issues resulted in losses on these projects, we met our objective of establishing our presence in the shale gas fields of Northeastern BC and successfully demonstrated our mechanized welding capability on a large-diameter pipe project.

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Financial Performance

The increased activity levels helped us grow year-over-year revenues by 13.1% to $858.0 million for the 12 months ended March 31, 2011. This was achieved despite a $42.5 million revenue writedown relating to our overburden removal contract with Canadian Natural. This long-term contract, which was initiated in 2005, includes certain escalation indices designed to adjust contract pricing. We believe these indices have become significantly misaligned with the Fort McMurray marketplace. We have formed a joint working committee with Canadian Natural to review the indices and to provide recommendations, with a target of having any adjustments to the contract incorporated by August 31, 2011.

This decision triggered the $42.5 million revenue writedown, which represents our profit on the contract since inception and lowered our net income by $31.8 million. Our bottom-line results were further affected by increased volumes of lower-margin overburden removal work in the project mix and the loss incurred on our Pipeline projects, as well as the lingering impact of lower-margin contracts, signed during the economic downturn of the previous two years.

While our fiscal 2011 financial performance was disappointing because of these factors, I want to emphasize that this in no way diminishes our future outlook for the business. With market conditions improving, customer relationships strengthening,

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The Canadian Association of Petroleum Producers predicts that capital expenditures alone will reach a new annual high of $26 billion by 2012.

a clear trend toward better margins and more reasonable risk levels in many of our recent contracts and many more opportunities on the horizon, we believe North American Energy Partners is on the verge of a sustained period of growth and improving profitability.

The New Opportunities

According to the Canadian Energy Research Institute, an estimated $2.1 trillion will be spent to build and maintain the oil sands over the next 25 years. The Canadian Association of Petroleum Producers predicts that capital expenditures alone will reach a new annual high of $26 billion in 2012, with continued capital spending growth in the years to follow. Recent announcements by the major oil sands producers support this view. Syncrude has announced capital spending plans that include four mine-train relocations between now and 2014, as well as the future development of the Aurora South mine. In addition, Suncor and Total have announced a partnership which will proceed with the immediate development of Joslyn Mine, for which initial earthworks tenders are already under consideration. They also plan to move forward with the near-future development of the Fort Hills Mine and the Voyageur upgrader, both of which have regulatory approval. These projects are all in addition to major new oil sands investments announced by Husky, Shell, Cenovus and others.

On the recurring services side of the oil sands business, demand could be modestly weaker in the first half of fiscal 2012 due to the temporary suspension of overburden removal activity at Canadian Natural’s Horizon mine project. The suspension is in response to a plant fire at the site in January 2011 and is expected to last until January 2012. In the interim, our new contracts with Syncrude and Shell are providing a strong base of business and our longer-term prospects for recurring services remain very positive. Exxon is planning to commence production at Kearl in 2012 and with Canadian Natural announcing its intention to be back on line by August 2011, five active producers will be creating a growing market for recurring services as of next year.

Growing demand for tailings management services is expected to provide added opportunities for our company. Over the past 12 months our Heavy Construction and Mining division carried out approximately $115 million of work specifically related to new tailings legislation. This included a range of activities from assisting with trials, to preparing tailings drying areas. Having now completed considerable preparatory work, we believe that most of the major oil sands operators are now ready to more fully implement tailings management strategies that will help them respond to the new environmental regulations. Suncor and Syncrude, for example, have announced plans to invest $670 million and $480 million respectively on tailings management in calendar 2011. Our new Tailings and Environmental Construction business unit is already benefiting from these developments.

Opportunities in the piling market look even more promising. The resurgence of oil sands infrastructure projects is increasing demand for large-scale piling contractors like us. Stronger economic conditions have also dramatically increased the number of commercial and institutional projects up for tender. Our Piling division has already secured work on a number of large new projects, including Mosaic’s K3 and Colonsay potash mines and the Boundary Dam Power Station. We anticipate continued growth through fiscal 2012.

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Our competitive strengths helped us maintain and grow customer relationships through the economic downturn of the past two years.

Pipeline market opportunities are also improving with a much wider range of opportunities and more favourable contract terms. Subsequent to the year-end, we were awarded pipeline contracts with two separate customers for a combined value of $72.4 million. These projects include the construction of 88 kilometres of 36” and 42” diameter pipelines in Alberta and British Columbia, with work expected to commence in August 2011 and be substantially completed by March 2012.

Overall, market conditions are strengthening across all of our markets and we believe we are well positioned to compete effectively for the new business we see on the horizon. Our competitive strengths helped us maintain and grow customer relationships through the economic downturn of the past two years. Now these strengths promise to generate even greater benefits for us as we leverage them in an expanding market.

Fundamental Strengths

One of the strengths that matters most to our customers is our ability to provide a safe working environment on their sites. I am proud to say we continued to improve on our safety performance in fiscal 2011 by expanding our frontline supervision and ensuring employees have the tools and decision-making authority to stay safe. We are now considered a top safety performer in our industry.

Expertise also matters and we have been successful in demonstrating the advantages of more than a half century of experience. In the oil sands, we routinely help customers enhance efficiency and cost effectiveness with more tactical approaches to project planning and execution. In our piling operations, we have acquired expertise in a diverse range of piling technologies to ensure customers have the right installation method for their site. Meanwhile in Pipeline, we have added modern techniques like mechanized welding to provide a more cost-effective and reliable form of large pipe installation.

Our capabilities are enhanced by our large and flexible equipment fleet. We have one of the largest and best equipment fleets in the business, enabling us to provide customers with the equipment they need, when they need it.

This combination of safety, expertise, technical skill and equipment fleet forms a core and distinctive set of strengths that sets us apart from our competitors. It is backed with a growing professionalism that has emerged as we complete a multi-year transition to new systems and processes throughout our organization. We are maturing in every aspect of our business and executing more successfully because of it.

Along the way we are clearly demonstrating to our customers that our strengths become their strengths. A contractor that truly understands the business, that knows how to work safely and efficiently under demanding conditions and that comes equipped with the right service offering and equipment fleet, ends up saving customers money in the long run. We are that contractor.

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In closing, I want to acknowledge our greatest strength: our employees. These are the more than 2,600 people who deliver our service and ensure we execute professionally and safely on our customers’ sites. I thank each of them for their hard work and daily contribution to our success.

I thank our board of directors for their ongoing commitment to ensuring our company’s continued success. We benefit greatly from their knowledge and wise counsel.

Finally, I thank you our shareholders for your continued support of North American Energy Partners. We have been through a challenging two years but we foresee a significantly stronger period with many new opportunities going forward. I look forward to reporting to you on our achievements.

Rod Ruston

President and Chief Executive Officer

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C O M P E T I T I V E S T R E N G T H S

market-leading expertise and safety

In the oil sands, experience matters. Harsh weather conditions, short seasonal operating windows, high costs and long traveling distances are realities. Service providers like NAEP that know how to work safely and efficiently within these constraints offer customers a significant operational and economic advantage.

Consider a basic earthmoving assignment. For less experienced contractors, this is a simple matter of moving dirt from one location to another. For us, it’s an opportunity to first separate valuable construction material from the non-useable waste dirt, knowing that our customer will need the construction material at a later point in their project. While this might cost more in the short term, it’s a small fraction of what it will cost if the customer has to eventually purchase and ship in construction material from an outside source.

Says Barry Palmer, General Manager of Heavy Construction and Mining, “The sooner the client gets us in and embeds us in their operations, the sooner we can help them engineer a plan that will save them money.”

In a recent example of this, we were able to show Syncrude how a mechanically stabilized earth (MSE) wall project could be completed in less time and for less money than our client had originally anticipated. Drawing on our experience with over 30 similar projects, we suggested using larger trucks, which lessened congestion, increased site safety and reduced costs. We also modified the volumes and timing of certain construction phases. The end result was more cost efficient and timely project completion for our client and an enhanced client relationship for us.

The ability to maintain a safe worksite is another critical area of expertise that has grown from our extensive oil sands experience. “Today, customers consider safety to be the crucial skill set. Our demonstrated ability to operate safe sites and steadily reduce disabling injury rates has been a major factor in recent contract awards,” says Joe Lambert, Vice President, Oil Sands Operations. “We’ve leveraged our knowledge of oil sands operations to become one of the safest operators in the region.”

Engineering Earth

In the oil sands, mechanically stabilized earth (MSE)

walls are used to support huge haul trucks as they

deliver ore to the crusher. Challenging to build, yet

essential to safe and efficient mine operations, this is

a job customers entrust to one company above all

others: North American Energy Partners. In the past

10 years, we have built every one of the MSE walls

constructed in the Fort McMurray region.

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C O M P E T I T I V E S T R E N G T H S

large and specialized fleet

With over 780 pieces of heavy mobile equipment, including over 244 mining trucks, NAEP owns and operates one of the largest and the most flexible equipment fleets in the industry. It’s a major strength that separates us from our competitors and gives us significant operational flexibility.

“We don’t have to put in two 240-ton trucks to handle a job that a single 300-ton truck could do,” says Joe Lambert, Vice President, Oil Sands Operations. “We can save our customers time and money by assigning the right equipment to each job.” Keeping the fleet aligned with changing technologies and customer requirements is another priority for us. Over the past three years, we have invested over $479 million to provide customers with larger mining shovels, a broader range of truck sizes and sophisticated new equipment to support initiatives like our Tailings and Environmental Construction initiative. Our new tailings fleet includes a highly specialized range of pond dredgers, bitumen skimmers and tailings dozers, which together have created one of the most impressive tailings equipment fleets in the oil sands.

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Says Warren Borysuk, General Manager of Tailings and Environmental Construction. “Through NAEP, our customers gain access to specialized technology, without having to buy equipment that will only be used at certain times. In the process, we increase our ability to be a key supplier in the fast-growing market for tailings and environmental services.” Our commercial and industrial construction customers also benefit from our commitment to investing in innovative technologies and equipment. Our Piling division has become an industry leader in alternative techniques like Continuous Flight Auger (CFA), micropiling and screwpiling, all of which facilitate cost-effective foundation work in demanding situations.

“With these different types of piling equipment and installation methods, we can bring the right approach to every site,” says Jim Humphries, General Manager of Piling. “This saves our customers time and money and in some cases, determines whether the job can be done at all. The right types of equipment, paired with the expertise to use it effectively, creates a major competitive advantage for us.”

Heavy Equipment Fleet March 31, 2011

Haul Trucks 244 Shovels and Excavators 125 Dozers 131 Drill Rigs, Cranes, Graders and Pipelayers 155 Other Heavy Equipment 127 Total 782

Fit to Purpose

Assigning the right-sized truck to a job has a major impact on efficiency. Smaller 100 to 150-ton haul trucks are ideal for major construction on oil sands projects, while larger 240 to 300-ton trucks enhance productivity and reduce congestion on high-production mine sites. With the largest and most diverse haul truck fleet in the oil sands, we are uniquely equipped to ensure our customers get the trucks they need.

Cat 785C / 150-ton Cat 789C / 195-ton Cat 793 / 240-ton

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C O M P E T I T I V E S T R E N G T H S

service through the project lifecycle

We are considered to be a “first-in, last-out” service provider because we provide services through the entire lifecycle of an oil sands project. We typically start long before construction begins by providing advice on budgets, planning and constructability based on our experience and expertise.

During the site preparation phase, we are there to handle the heavy earthmoving work including site clearing, muskeg removal, site grading and road construction. When it’s time to lay the groundwork for the processing plant, we install the underground drainage systems, utilities and pipelines, install the pilings and build up the foundation in preparation for construction. Then we start on mine construction activities including building the crusher pockets, dykes, tailings ponds and other necessary infrastructure.

As mining operations get underway, we provide overburden removal to reveal bitumen deposits, install and operate giant shovels and move material in our huge haul trucks. We also provide ongoing tailings pond management to the processing plants. Once mining wraps up in one area and moves to another, we also provide reclamation work to return mine sites and tailings ponds to their natural state.

Our ability to assist customers through the many different phases of a mine’s lifecycle contributes to strong, long-term customer partnerships. For example, our relationship with Syncrude dates back more than 30 years, while our relationship with Shell has been building over 12 years. Along the way, we gain an in-depth understanding of our customers’ operations and specific needs, which gives us a considerable competitive advantage. “Typically, producers want to work with a contractor they know and trust and one that understands their business. The fact that we’re already onsite makes the decision that much easier,” says Chris Yellowega, Vice President, Business Services and Construction.

Our diverse service offering also provides considerable stability to our business. Even in periods when new oil sands investment has slowed, operating mines have continued to generate ongoing demand for recurring services, helping us maintain a strong base of business.

Oil Sands Project Timeline

Our broad menu of planning, project development and recurring services

keeps us active through every phase of the mine’s lifecycle

Pre-Planning (occurring from year 0 to 5) Project Development (occurring from year 5 to 10)

Constructability reviews Clearing Facilities site prep

Budgetary cost estimates Muskeg removal Overburden removal

Design Site grading Tailings dyke construction

Mine construction Haul road construction

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First In, Last Out

From initial mine planning through to final site

reclamation, we are typically one of the first

contractors on the oil sands mine site…

and one of the last to leave.

Tailings Pond Management Expertise

We continually adjust our service offering to keep pace with customer needs. In fiscal 2011,

we further expanded our Tailings and Environmental Construction business unit with invest-

ment in a highly specialized fleet of pond dredgers, bitumen skimmers and other specialized

equipment that helps our customers respond to new environmental legislation.

Recurring Services and Ongoing Capital Projects (occurring from year 10 to 50)

Supplement owner’s fleet requirements

Overburden removal

Muskeg removal

Haul roads

Mine expansion

Mine relocation

Tailings projects

Tailings operations support

Reclamation

YEARS

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C O M P E T I T I V E S T R E N G T H S

operational flexibility

In the end, our individual strengths work together to create one greater strength, which is operational flexibility.

Our combination of 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 new recurring services business. It also minimizes downtime for costly equipment and helps maintain a more consistent supply of work for our employees.

As an example of this flexibility in action, we are currently working to redeploy equipment from the Canadian Natural mine site while our customer completes repairs following a plant fire last January. For contractors with fewer oil sands relationships, such a suspension of activity could mean the difference between success and failure. For us, it creates an opportunity to support growing demand at other sites in the oil sands and continue to generate cash flows and margins while our customer gets back up and running.

The ability to be where our customers need us, when they need us, greatly enhances our attractiveness as a third-party service provider and adds to the stability and success of our business.

Active on Every Oil Sands Mining Site

We have active relationships with every mining

customer in the oil sands, including long-term

contracts with all four of the operational producers.

Current Producers

Canadian Natural

10-year overburden removal contract, various construction projects

Fort Hills

Shell/Albian

Horizon Kearl

3-year master services agreement and a 3-year muskeg removal contract

Aurora North

Syncrude

4-year master services agreement Joslyn Jackpine and Muskeg River covering mining services and construction

Suncor

Anticipated 5-year master services agreement covering mining services and construction.

Mildred Lake

Future Producers

Exxon

MSE wall construction Millennium and Steepbank

Total

Voyageur

Constructability reviews

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2011

Management’s Discussion and Analysis

A. EXPLANATORY NOTES

June 2, 2011

The following discussion and analysis is as of June 2, 2011 and should be read in conjunction with the attached audited consolidated financial statements for the year ended March 31, 2011 and notes that follow. These statements have been prepared in accordance with United States (US) generally accepted accounting principles (GAAP) and reconciled to Canadian GAAP. Except where otherwise specifically indicated, all dollar amounts are expressed in Canadian dollars. For additional information and details, readers are referred to the unaudited consolidated financial statements, notes that follow and the accompanying interim period Management’s Discussion and Analysis (MD&A) for each interim period of fiscal 2011. The audited consolidated financial statements and additional information relating to our business, including our Annual Information Form, are available on the Canadian Securities Administrators’ SEDAR System at www.sedar.com, the Securities and Exchange Commission’s website at www.sec.gov and our company web site at www.nacg.ca.

CAUTION REGARDING FORWARD-LOOKING INFORMATION

Our MD&A is intended to enable readers to gain an understanding of our current results and financial position. To do so, we provide information and analysis comparing results of operations and financial position for the current year to those of 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 and uncertainties that could have a material impact on future prospects. Please refer to “Forward-Looking Information and Risk Factors” for a discussion of the risks and uncertainties related to such information. Readers are cautioned that actual events and results may vary.

NON-GAAP FINANCIAL MEASURES

The body of generally accepted accounting principles applicable to us is commonly referred to as “GAAP”. A non-GAAP financial measure is generally defined by the Securities and Exchange Commission (SEC) and by the Canadian securities regulatory authorities as one that purports to measure historical or future financial performance, financial position or cash flows, but excludes or includes amounts that would not be so adjusted in the most comparable GAAP measures. In our MD&A, we use non-GAAP financial measures such as “net income before interest expense, income taxes, depreciation and amortization” (EBITDA) and “Consolidated EBITDA” (as defined in our 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 Natural overburden removal contract (described in the “Explanatory Notes — Significant Business Event” section of this MD&A, below) and certain other non-cash items included in the calculation of net income. We believe that EBITDA is a meaningful measure of the performance of our business because it excludes items, such as depreciation and amortization, interest and taxes that are not directly related to the operating performance of our business. Management reviews EBITDA to determine whether plant and equipment are being allocated efficiently. In addition, our credit facility requires us to maintain a minimum interest coverage ratio and a maximum senior leverage ratio, both of which are calculated using Consolidated EBITDA. Non-compliance with these financial covenants could result in our being required to immediately repay all amounts outstanding under our credit facility. As EBITDA and Consolidated EBITDA are non-GAAP financial measures, our computations of EBITDA and Consolidated EBITDA may vary from others in our industry. EBITDA and Consolidated EBITDA should not be considered as alternatives to operating income or net income as measures of operating performance or cash flows as measures of liquidity. EBITDA and Consolidated EBITDA have important limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under US GAAP or Canadian GAAP. For example, EBITDA and Consolidated EBITDA do not:

•

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


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NAEP

ADOPTION OF UNITED STATES GAAP

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

After significant analysis and consideration regarding the merits of reporting under IFRS or US GAAP, we decided to adopt US GAAP, commencing in fiscal 2010, as our primary reporting standard for our consolidated financial statements. Our audited consolidated financial statements for the year ended March 31, 2011, including related notes and this MD&A have therefore been prepared based on US GAAP. All comparative figures contained in these documents have been restated to reflect our results as if they had been historically reported in accordance with US GAAP as our reporting standard.

As required by National Instrument 52-107, for the fiscal year of adoption of US GAAP and one subsequent fiscal year, we will provide a Canadian Supplement to our MD&A that restates, based on financial information reconciled to Canadian GAAP, those parts of our MD&A that would contain material differences if they were based on financial statements prepared in accordance with Canadian GAAP. In support of the adoption of US GAAP commencing in fiscal 2010, we provided a Canadian Supplement MD&A for our audited consolidated financial statements, related notes and accompanying MD&A for the year ended March 31, 2010. As well, we provided Canadian Supplement MD&A’s for each of the restated interim periods for fiscal 2010 and each of the interim periods for fiscal 2011.

SIGNIFICANT BUSINESS EVENT

As announced in our press release, issued on May 18, 2011, we applied a writedown to the long-term overburden removal contract between our subsidiary, North American Construction Group Inc. (NACG) and Canadian Natural¹, for the Horizon Oil Sands mine near Fort McMurray, Alberta.

The unit-price contract with Canadian Natural includes certain escalation indices, determined at the time of the initial negotiations, which were intended to adjust pricing annually to reflect changes in economic conditions over the ten-year term of the contract. The contract specifically states that the indices were not intended to benefit either party at the expense of the other party and includes a mechanism for reviewing the indices if they are deemed not to be representative of the actual market over time. It is our position that the actual inflationary environment in Fort McMurray has varied significantly as compared to the indices per the contract, resulting in a negative financial impact to us. Accordingly, we have met with Canadian Natural and formed a joint working group that will be responsible for identifying indices that will more closely reflect the inflationary conditions that have occurred in the market place. We expect this group will deliver recommendations by August 31, 2011 and that the new indices will apply both prospectively and retrospectively.

Revenue on unit-price 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. As the scope of the work to be done under the contract has been agreed upon but we have not yet agreed upon the exact adjustments to the indices, we reduced Heavy Construction and Mining segment revenue by $42.5 million on this contract for the three months and fiscal year ended March 31, 2011. The reduction of revenue on this contract (the “revenue writedown”) reduced the total contract revenue to the extent of total costs incurred, representing a zero profit margin on the contract and reduced unbilled revenue by the same amount. Deferred tax expense was credited by $10.7 million with a corresponding reduction in our long-term deferred tax liability resulting in a $31.8 million reduction to net income. The accounting treatment was based on un-priced change order guidance found in FASB ASC 605-35-25-87, from which we have determined that it is probable that the costs will be recovered through an increase in the contract price for the escalation indices.

We anticipate that, if the new escalation indices recommended by the working group are adjusted as expected and we are assured beyond a reasonable doubt that the recommended indices have been authorized by Canadian Natural, all or a portion of the fiscal 2011 revenue writedown may be recognized as profit. None-the-less, until we are assured beyond a reasonable doubt that the escalation indices have been authorized by Canadian Natural, revenue will continue to be recognized only to the extent of costs incurred. ¿

Although we believe the acceptance of the revised indices to be probable, if the review of the indices being undertaken by the working group does not support our position or if the parties are not able to agree upon the appropriate adjustments, a further revenue writedown may be required in respect of all or a portion of unbilled revenue of up to $72.0 million related to the contract, in which event we will pursue any remedies we may have available to us.

¹	Canadian Natural Resources Limited (Canadian Natural).

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


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Following our announcement of the revenue writedown to the market, on May 18, 2011, all our major oil sands customers were contacted and we believe they understood the reason for the revenue writedown and were not concerned that this issue would affect our ability to fulfill our contractual obligations to them.

On May 18, 2011 we were notified by Canadian Natural that we were to suspend overburden removal activities at their Horizon mine while Canadian Natural undertakes repairs to its primary upgrading facility, which was damaged in a fire in January 2011. The suspension of work notice is effective until January 2, 2012.

As a result of the revenue writedown on the Canadian Natural long-term overburden removal contract, we were not in compliance with certain existing financial covenants, as at March 31, 2011 on our credit agreement. On May 20, 2011, we received an amendment to our credit agreement, from our lenders, to exclude the $42.5 million revenue writedown on our long-term overburden removal contract with Canadian Natural when determining Consolidated EBITDA (as defined in our credit agreement) related covenant compliance. This amendment ensures that this writedown will not result in a breach of Consolidated EBITDA (as defined in our credit agreement) related covenant compliance at March 31, 2011 or any future date.

This isolated issue is not expected to negatively impact any of our other operations and despite the writedown on this contract our current financial position is not materially affected.¿

B. BUSINESS OVERVIEW AND STRATEGY

BUSINESS OVERVIEW

We provide a wide range of heavy construction and mining, piling and pipeline installation services to customers in the Canadian oil sands, 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, 2011, recurring services represented 81% 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, having provided services to each of these customers since inception of their respective projects, which equates to over 30 years of providing service to Syncrude and Suncor.

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 780 pieces of diversified heavy construction equipment supported by over 750 ancillary vehicles. 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 types of 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. In addition, we believe that these capabilities will enable us to support our customers’ new oil sands developments and expansions, as well as the ever-increasing volume of recurring services generated by existing oil sands mines.¿

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.

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 and Risk Factors” for a discussion of the risks and uncertainties related to such information.


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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, 2011 is represented in the chart below:

LOGO

A complete discussion on segment results can be found in “Segment Annual Results” in the Financial 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. Complementing these services, the Heavy Construction and Mining segment also provides industrial site construction for mega-projects and underground utility installation for plant, refinery and commercial building construction.

Piling

Our Piling segment 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 established experience in both small-scale 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 small manufacturing facility in Texas and a small but well-established customer base for screw pile and pipeline anchor supply in the US, 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, complete with related maintenance and other specialty services. Our Pipeline segment is respected in the industry and is known for its ability to execute technically and environmentally challenging projects for Canada’s largest energy companies. The Pipeline segment has capacity and resources to handle pipe ranging in size from 2-inch to 60-inches in diameter and operates across numerous remote geographical locations simultaneously.

This segment’s volume is currently being driven by high activity related to the Canadian oil sands, and shale gas plays such as the Horn River and Muskwa formations in North East British Columbia; some of the world’s largest proven reserves. Further, aging infrastructure demands regular recurring pipeline and related facility maintenance to ensure regulatory and production requirements are sustained. Canada continues to be a strong energy market due to it having a low perceived political risk and a secure, reliable source of energy and the ability to continually attract capital for infrastructure development in the oil & gas pipeline industry.

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.


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REVENUE SOURCES

Revenue by Category

Historically, we have experienced steady growth in recurring services revenue from operating oil sands projects, although production at some of our customers’ operations has recently been negatively impacted by a string of unique events which has negatively affected our recurring services revenue. Going forward, we expect to see a return to growth in recurring services revenue as activity levels increase at existing mines and new oil sands projects move from construction into the operational phase. Project development revenue, by contrast, declined significantly after September 2008, reflecting the impact of economic conditions on large-scale capital projects. However, as economic conditions have strengthened, several major oil sands projects have returned to the active planning and development stages and bidding activity level in the commercial and industrial construction markets and pipeline construction sector are strong.^¿

The following graph displays the breakdown of recurring services revenue and project development services revenue for the rolling, trailing 12-month periods at three-month intervals, from March 31, 2009 to March 31, 2011:

LOGO

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 of revenue consists of revenue generated from long-term contracts (greater than one year) with total contract values greater than $20.0 million. These contracts are for work that supports the operations of our customers and include long-term contracts for overburden removal and reclamation. Revenue in this category is typically generated under unit-price contracts and is included in our calculation of backlog. This work is generally funded from our customers’ operating budgets.

•

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


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END MARKETS OVERVIEW

Revenue by End Market

During the fiscal year ended March 31, 2011, we provided services to four distinct end markets: Canadian oil sands; commercial and public construction, industrial construction and pipeline construction.

The following graph displays the breakdown of revenue by end market for the rolling, trailing 12-month periods at three-month intervals, from March 31, 2009 to March 31, 2011:

LOGO

Canadian Oil Sands Market

Our core market is the Canadian oil sands, where we generated 78% of our fiscal 2011 revenue. According to the Canadian Association of Petroleum Producers (CAPP), the oil sands represent 97% of Canada’s recoverable oil reserves. At 170 billion barrels, the Canadian oil sands deposits are second only to those of Saudi Arabia. The oil sands are located primarily in three regions of northern Alberta: Athabasca, Cold Lake and Peace River. In 2010, oil sands production reached 1.5 million barrels per day (“bpd”), representing 52.9% of Canada’s total oil production for that same year.

Oil sands are grains of sand covered by a thin layer of water and coated by heavy oil or bitumen. Bitumen, because of its structure, does not flow and therefore requires non-conventional extraction techniques to separate it from the sand and other foreign matter. There are currently two main methods of extraction: (i) open pit mining, where bitumen deposits are sufficiently close to the surface to make it economically viable to recover the bitumen by treating mined sand in a surface plant; and (ii) in situ technology, where bitumen deposits are buried too deep for open pit mining to be cost effective and operators instead inject steam into the deposit, lowering the viscosity of the bitumen so that the bitumen can be separated from the sand and pumped to the surface, leaving the sand in place. Steam Assisted Gravity Drainage (typically known as “SAGD”) is a type of in situ technology that uses horizontal drilling to produce bitumen. CAPP estimates that approximately 20% of the oil sands are recoverable through open pit mining. Open pit mining projects tend to have greater production capacity than in situ technology. For example, approximately 52% of 2010 oil sands production was extracted from five active mining projects, while the remaining 48% was extracted from approximately 17 active in situ projects. While the number of active and planned in situ projects far exceeds the number of mining projects, according to CAPP and other industry forecasts, future total production from mining and in situ technology is expected to remain approximately equal.

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

Approximately 81% of our oil sands-related revenue for the year ended March 31, 2011 came from the provision of recurring services to existing oil sands projects, with the balance coming from project development services.

Project Development Services: Demand for project development services in the oil sands is primarily driven by new developments and expansions. We support our customers’ new development and expansion projects by providing construction services such as clearing, site preparation, piling and underground utilities installation. Between 2000 and 2010, over $113 billion of capital was invested into the oil sands, the core market for our project development services.

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


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Recurring Services: Demand for recurring oil sands services enjoys a high degree of stability due to the immense up-front capital investment associated with oil sands operations and the consequent need to operate at full capacity to achieve low per-unit operating costs. In addition, the harsh climate of northern Alberta makes it difficult for producers to shut down for extended periods of time. The costs and operational risks associated with a production stoppage longer than a single summer season (such as a planned maintenance shutdown) make an extended shutdown economically unviable for oil sands producers.

Growth in demand for our recurring services business, excluding the recent reduction in this category as a result of the Canadian Natural revenue writedown, is driven by both increased production levels in the oil sands and the inherent need for additional support services through the lifecycle of a mine. Increases in production levels are achieved when new mines enter the production phase and when existing mines eliminate bottlenecks and/or expand their existing operations. In each case, the required output from the extraction process increases, resulting in higher demand for the recurring services we provide, such as overburden removal, equipment and labour supply, mine maintenance and reclamation services.

The requirement for recurring services also typically grows as mines age. Mine operators tend to construct their plants closest to the easy-to-access bitumen deposits (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 typical 40+ year life cycle, 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 of the lease, operators will often relocate mine infrastructure in order to reduce haul distances. This creates demand for mine construction services in the expansion area, as well as reclamation services to remediate the mined-out area. Accordingly, the demand for recurring oil sands services continues to grow even during periods of stable production because the geographical footprints of existing mines continue to expand under normal operation.

Current Canadian Oil Sands Business Conditions

Project Development: As economic conditions have strengthened, several oil sands projects have returned to the active planning and development stages. Suncor and Total⁷ are pooling their manpower and capital resources and sharing risk with a strategic alliance to develop Suncor’s Fort Hills⁸ mine and Voyageur⁹ upgrader project and Total’s Joslyn¹⁰ mine project. Exxon continues with construction of its Kearl¹¹ mine as the project moves to the above ground construction and mine development phase of the project and Syncrude is planning a number of major mining projects, including the relocation of four mine trains.

A number of in-situ projects are also proceeding, including Husky Energy’s Sunrise¹², ConocoPhillips’ Surmont¹³, Cenovus Energy’s Foster Creek and Christina Lake¹⁴, as well as Devon Canada’s¹⁵ Jackfish projects. In addition, Suncor is proceeding with additional stages of its Firebag in situ project. The increase in activity is reflected in CAPP’s revised estimate of industry capital spending for oil sands development, which increased to $13 billion for 2010, compared to $11 billion in 2009.

Oil sands operators are also increasing spending on tailings and reclamation projects in response to new environmental regulations. Suncor and Syncrude have announced 2011 capital spending plans that include investments of $670 million and $480 million respectively in tailings management. We expect these investments to create opportunities for our new Tailings and Environmental Construction division to support the construction and operation of the new reclamation processes.¿

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

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

¹⁰	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.

¹¹

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

¹²	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.

¹³	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.

¹⁴	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.

¹⁵	Devon Canada Corporation (Devon Canada) is a wholly owned subsidiary of Devon Energy Corporation. Devon Canada is the operator of the Jackfish projects.

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


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Recurring Services: With the commissioning of Canadian Natural’s Horizon mine and Shell’s Jackpine mine, oil sands mining production capacity has increased and expanded the market for recurring services. While production at our customers’ operations has been negatively impacted by a string of unique events, including start-up delays at Horizon, a plant fire at Suncor and most recently, a plant fire at Canadian Natural, overall demand for our recurring services has remained stable over this period. Currently all mines, other than Canadian Natural’s Horizon mine, are producing at planned capacity. The Horizon project is expected to recommence oil production in a number of stages, returning to full capacity by the end of 2011 when repairs are completed. However, our overburden removal activities, having continued at full operational capacity for some four and a half months following the fire, have now been shut down and will not be required to recommence work before January 2, 2012.

With three of the four active oil sands mines expected to be operating throughout this year and Exxon’s Kearl mine and Canadian Natural’s Horizon mine scheduled to be producing in early 2012, the outlook for recurring services demand remains positive.^¿

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 has been strengthening as evidenced by the 33% year-over-year increase in the value of industrial building permits and the 11% rise in the value of commercial building permits in 2010 compared to 2009. The recovery is being led by institutional and governmental construction, which according to Statistics Canada, experienced a 10% year-over-year increase in value of building permits issued in calendar 2010, compared to 2009. We also expect to benefit from increased construction spending in the private sector over the coming years as the economy continues to recover.¿

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 presents a special interest for us, with Canada being one of the largest mining nations in the world, producing more than 60 different minerals and metals. In particular, Canada is the world’s largest producer of potash, accounting for more than one third of the world’s potash production and exports. We have recently begun providing 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 growing market for our construction services.^¿

While potash deposits are mainly located in Saskatchewan, minerals such as copper, gold, coal and cobalt are prevalent in British Columbia. There are approximately 24 mine development projects under consideration for permits and environmental approvals in British Columbia and we expect this to create strong demand for mining services. This rising demand outside the oil sands not only creates opportunities for us to compete for this work but also potentially reduces the number of competitors looking for work in the oil sands.^¿

The conventional oil and gas industry is another source of industrial construction projects. Currently, we are providing industrial and piling services to CCRL’s¹⁶ heavy oil upgrader revamp and expansion project in Regina. Through our recent acquisition of Cyntech, we have also added screw piling, pipeline anchors and tank services capabilities, all of which have expanded our presence in the conventional oil and gas industry. We believe our newly acquired screw piling capabilities will also position us to service Canada’s power transmission sector, which is expected to experience significant investment over the next decade.^¿

Current Industrial Construction Business Conditions

Despite continued economic uncertainty, Canada’s resource mining sector performance improved in 2010 as evidenced by a 35% increase in exploration spending compared to 2009. Higher commodity prices, ownership changes and major capital investments contributed to this recovery. Looking forward, resource mining development activity is expected to return to the robust levels that prevailed prior to the economic downturn, with capital investment in exploration and development expected to reach increased levels in 2011.^¿

As economic conditions improve, many refinery projects are also returning to the active state. We plan to build on our experience with CCRL to pursue opportunities within the refinery construction market. As outlined above, we are also pursuing opportunities in the power distribution industry as we leverage the new capabilities acquired through the Cyntech acquisition.

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

¹⁶	Consumers Co-operative Refinery Limited is a wholly owned subsidiary of Federated Co-operatives Limited.


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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 has over 580,000 kilometers of pipeline, which transports approximately 2.7 million barrels of crude oil and equivalents per day and 15.1 billion cubic feet of natural gas per day to various distribution points in Canada and the US. CAPP reports that a number of pipeline expansions were completed and started operating in 2010, extending Canadian capacity by 885,000 barrels per day. An additional 855,000 barrels per day of pipeline capacity has been approved and could go into service over the next few years.

Current Pipeline Construction Business Conditions

While depressed economic conditions created a highly competitive market environment in fiscal 2010 and 2011, conditions are expected to improve following the announcement of various new pipeline projects in Western Canada. These new projects are designed to address expected increases in oil and gas production in the region. Toward the end of fiscal 2011, we began to see a sharp increase in bidding activity. In addition, the need for maintenance of existing pipelines has come under greater scrutiny in the last 12 months, following a number of significant incidents where pipeline leaks have cause damage to the environment. Accordingly, we anticipate increasing near-term demand for small and large pipeline projects and expansions and for large maintenance contracts, all of which should in turn, support improved pricing and reduced risk on new contracts.¿

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, greater accountability and compliance.

•

Increase our recurring revenue base: It is our intention to continue expanding 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 a substantial share of the heavy construction and mining, piling and pipeline services outsourced in connection with their projects.

•

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 aim to increase the availability and efficiency of our equipment through enhanced maintenance, providing the opportunity for improved revenue, margins and profitability.

•

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

•

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.

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


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C. FINANCIAL RESULTS

SUMMARY OF CONSOLIDATED ANNUAL RESULTS


	Year Ended March 31,
(dollars in thousands, except per share amounts)	2011			% of Revenue		2010		% of Revenue		2009			% of Revenue		2011 vs 2010 Change			2011 vs 2009 Change
Revenue		$858,048			100.0%		$758,965		100.0%		$972,536			100.0%		$99,083			$(114,488	)
Project costs		456,119			53.2%		301,307		39.7%		505,026			51.9%		154,812			(48,907	)
Equipment costs		234,933			27.4%		209,408		27.6%		217,120			22.3%		25,525			17,813
Equipment operating lease expense		69,420			8.1%		66,329		8.7%		43,583			4.5%		3,091			25,837
Depreciation		39,440			4.6%		42,636		5.6%		36,389			3.7%		(3,196	)		3,051
Gross profit		58,136			6.8%		139,285		18.4%		170,418			17.5%		(81,149	)		(112,282	)
General and administrative expenses		59,932			7.0%		62,530		8.2%		74,460			7.7%		(2,598	)		(14,528	)
Operating (loss) income		(10,829	)		-1.3%		73,474		9.7%		(87,092	)		-9.0%		(84,303	)		76,263
Net (loss) income		(34,650	)		-4.0%		28,219		3.7%		(135,404	)		-13.9%		(62,869	)		100,754
Per share information
Net (loss) income – basic		$(0.96	)				$0.78				$(3.76	)				$(1.74	)		$2.80
Net (loss) income – diluted		(0.96	)				0.77				(3.76	)				(1.73	)		2.80
EBITDA⁽¹⁾		$31,873			3.7%		$112,333		14.8%		$(53,269	)		-5.5%		$(80,460	)		$85,142
Consolidated EBITDA⁽¹⁾(as definedwithin the credit agreement)		$84,101			9.8%		$121,644		16.0%		$139,446			14.3%		$(37,543	)		$(55,345	)

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


	Year Ended March 31,
(dollars in thousands)	2011			2010			2009
Net (loss) income		$(34,650	)		$28,219			$(135,404	)
Adjustments:
Interest expense		29,991			26,080			29,612
Income taxes (benefit)		(6,448	)		13,679			14,633
Depreciation		39,440			42,636			36,389
Amortization of intangible assets		3,540			1,719			1,501
EBITDA		$31,873			$112,333			$(53,269	)
Adjustments:
Unrealized foreign exchange (gain) loss on senior notes		–			(48,920	)		46,466
Realized and unrealized (gain) loss on derivative financial instruments		(2,305	)		54,411			(37,250	)
Loss on disposal of property, plant and equipment and assets held for sale		2,773			1,606			5,349
Stock-based compensation expense		2,191			2,258			1,950
Equity in loss (earnings) of unconsolidated joint venture		2,720			(44	)		–
Loss on debt extinguishment		4,324			–			–
Revenue writedown on Canadian Natural project		42,525			–			–
Impairment of goodwill		–			–			176,200
Consolidated EBITDA		$84,101			$121,644			$139,446

ANALYSIS OF ANNUAL CONSOLIDATED RESULTS

Revenue

For the year ended March 31, 2011, revenues were $858.0 million, $99.1 million higher than in the year ended March 31, 2010 and $114.5 million lower than in the year ended March 31, 2009. The current year increase in revenues was achieved despite a $42.5 million revenue writedown resulting from the revenue writedown on our long-term overburden removal contract with Canadian Natural, discussed in the “Explanatory Notes—Significant Business Event” section of this MD&A. The year-over-year revenue growth reflects increased mining services provided to Suncor, Syncrude and Canadian Natural in the oil sands, increased project development activity provided to Shell, Suncor, Exxon and Canadian Natural, a significant increase in Pipeline segment revenues and a resurgence of activity in the commercial and industrial construction markets. Recurring services volumes at Shell’s sites declined as a result of the ramp up of production at their Jackpine site and a major maintenance program undertaken by this customer at their Muskeg River Mine site during the first half of the year.


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Gross profit

For the year ended March 31, 2011, gross profit was $58.1 million, a decrease of $81.1 million from the previous year and a decrease of $112.3 million from the year ended March 31, 2009. Gross profit would have been $100.7 million (11.2% of revenue), excluding the effect of the $42.5 million revenue writedown on the Canadian Natural long-term overburden removal project. The change in gross profit primarily reflects an increased proportion of lower-margin overburden removal activity as part of our overall project mix, losses incurred on two Pipeline projects along with competitive pressures on pricing in contracts signed in the prior-year. As a percentage of revenue, gross profit margin dropped to 6.8% compared to 18.4% at the year ended March 31, 2010 and 17.5% for the year ended March 31, 2009.

Project costs, as a percentage of revenue, were 53.2% during the year ended March 31, 2011, compared to 39.7% for the year ended March 31, 2010 and 51.9% for the year ended March 31, 2009. Increased project development activity in the oil sands and increases in labour and material-intensive piling and pipeline activity were contributing factors in this increase. Equipment costs represented 27.4% of revenue during the year ended March 31, 2011, compared to 27.6% in 2010 and 22.3% in 2009. The small reduction compared to the same period in 2010 reflects a decrease in equipment-intensive recurring services activity, partially offset by increased use of higher-cost rental equipment to support project development activity in the oil sands and increased activity in our Pipeline segment. The increase over 2009 reflects the change in project mix from the less equipment intensive project development activity and the use of higher-cost rental equipment in the current year.

Equipment operating lease expense was $69.4 million during the year ended March 31, 2011 compared to $66.3 million and $43.6 million in fiscal 2010 and 2009. The increase from the 2009 fiscal year reflects the full-year impact of overburden removal equipment acquired late in the year ended March 31, 2009 to support full production on our long-term contract with Canadian Natural.

Operating (loss) income

For the year ended March 31, 2011, we recorded an operating loss of $10.8 million, compared to operating income of $73.5 million, or 9.7% of revenue during the year ended March 31, 2010 and an operating loss of $87.1 million during the year ended March 31, 2009. Excluding the revenue writedown on our long-term overburden removal contract with Canadian Natural, operating income for the year ended March 31, 2011 would have been $31.7 million, or 3.5% of revenue. The operating loss for the year ended March 31, 2009 included a charge of $176.2 million for goodwill impairment. Excluding this impairment, operating income for fiscal 2009 would have been $89.1 million or 9.2% of revenue. General and administrative (“G&A”) expense of $59.9 million for the year ended March 31, 2011 was $2.6 million and $14.5 million lower than in the years ended March 31, 2010 and March 31, 2009, respectively. The decrease compared to fiscal 2010 reflects a reduction in the estimated payout of the short-term profit sharing program, partially offset by a $2.9 million year-over-year increase to stock-based compensation expense. This increase in stock-based compensation expense reflects a partial restructuring of the stock option and executive compensation plans, along with the impact of share price increases on the stock-based compensation. The decrease compared to fiscal 2009 reflects the benefits of reorganization and cost reduction initiatives implemented in late fiscal 2009 and a reduction in the estimated payout of the short-term profit sharing program, partially offset by the increase in stock-based compensation expense.

Net (loss) income

For the year ended March 31, 2011, we recorded a net loss of $34.7 million (basic loss per share of $0.96), compared to 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 and a net loss of $135.4 million (basic loss per share of $3.76) for the year ended March 31, 2009. As discussed in the “Explanatory Notes—Significant Business Event” section of this MD&A, revenue and gross profit for the fiscal year ended March 31, 2011 were reduced by a $42.5 million revenue writedown ($31.8 million after tax loss) related to the long-term overburden removal project with Canadian Natural. Excluding the revenue writedown, net loss would have been $2.9 million (basic loss per share of $0.08) for the year ended March 31, 2011. Non-cash items affecting the current year results included unrealized gains on embedded derivatives in certain supplier contracts and a long term customer contract. These gains were offset by the write-off of deferred financing costs on the settlement of the 8³/4% senior notes and losses on the cross-currency and interest rate swaps. Excluding the non-cash items and the revenue writedown, net loss would have been $0.7 million (basic loss per share of $0.02) for the year ended March 31, 2011.

Net income for the year ended March 31, 2010 was positively affected by the foreign exchange impact of the strengthening Canadian dollar on our 8³/4% senior notes, gains on the interest rate swaps, gains relating to embedded derivatives in long-term supplier contracts and redemption option in our 8³/4% 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). Net income for the year ended March 31, 2009 was negatively affected by the non-cash impact of the goodwill impairment charge as described above, foreign exchange impact of the weakening of the Canadian dollar on our 8³/4% senior notes, loss on our interest rate swap, loss related to embedded derivatives in a long-term customer contract, long-term supplier contracts and a redemption option in our 8³/4% senior notes. These losses were partially offset by the gain on our cross-currency swaps. Excluding these items, net income for the year ended March 31, 2009 would have been $44.4 million (basic income per share of $1.23 and diluted income per share of $1.21).


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SEGMENT ANNUAL RESULTS

Heavy Construction and Mining


	Year Ended March 31,						Changes
(dollars in thousands)	2011		2010		2009		2011 vs 2010			2011 vs 2009
Segment revenue		$667,037		$665,514		$716,053		$1,523			$(49,016	)
Segment profit		$50,703		$111,016		$109,580		$(60,313	)		$(58,877	)
Segment margin		7.6%		16.7%		15.3%

For the year ended March 31, 2011, the Heavy Construction and Mining segment reported revenue of $667.0 million, comparable to the $665.5 million in the same period last year and a $49.0 million decrease from the year ended March 31, 2009. As discussed in the “Explanatory Notes—Significant Business Event” section of this MD&A, revenue for the fiscal year ended March 31, 2011 was reduced by a $42.5 revenue writedown related to the Canadian Natural overburden removal contract. In addition, the commissioning of Shell’s Jackpine mine and a major upgrader maintenance program undertaken by this customer earlier this year reduced demand for our site support services. Offsetting these factors was increased recurring services demand from Suncor and Canadian Natural and higher project development revenues from Exxon, Shell and Canadian Natural. Revenue for the year ended March 31, 2010 was negatively affected by the commissioning of Canadian Natural’s Horizon Mine, a fire at Suncor’s upgrading facility, a major upgrader maintenance program undertaken by Syncrude and increased competition for work at the Syncrude sites.

For the year ended March 31, 2011, Heavy Construction and Mining segment margin decreased to 7.6% of revenue from 16.7% of revenue during the same period last year and 15.3% of revenue for the year ended March 31, 2009. Excluding the revenue writedown, segment profit was $93.2 million (13.1% of revenue). The reduction in this adjusted segment margin, compared to the prior two years reflects increased volumes of lower-margin overburden removal activity in our project mix, a significant increase in the use of higher-cost rental equipment to support increased project development activity and impact of reduced pricing due to increased competitive pressure in the oil sands during the recession. In contrast, during fiscal 2010 and fiscal 2009, we experienced significantly reduced volumes of lower-margin overburden removal activity in our project mix as a result of a temporary work suspension at Canadian Natural’s site while they commissioned their production facility. This reduction in the lower-margin overburden removal activity and a strong contribution from higher margin contracts negotiated prior to the recession bolstered Heavy Construction and Mining segment margins in the prior two fiscal years.

Piling


	Year Ended March 31,						Changes
(dollars in thousands)	2011		2010		2009		2011 vs 2010		2011 vs 2009
Segment revenue		$105,559		$68,531		$155,076		$37,028		$(49,517	)
Segment profit		$18,455		$11,288		$38,776		$7,167		$(20,321	)
Segment margin		17.5%		16.5%		25.0%

For the year ended March 31, 2011, Piling revenue was $105.6 million, up $37.0 million compared to the year ended March 31, 2010, a decrease of $49.5 million compared to the year ended March 31, 2009. The improvement in the Piling segment revenue during the most recent period reflects the resurgence of activity in the commercial and industrial construction markets and an increase in project development activity on oil sands projects. Revenue for the current fiscal year includes a $7.3 million contribution from Cyntech, acquired in November 2010. Revenues in the year ended March 31, 2009 reflect the benefit of significant project development activity in the oil sands.

For the year ended March 31, 2011, the Piling segment margin represented 17.5% of revenue, compared to 16.5% of revenue and 25.0% of revenue for the years ended March 31, 2010 and 2009, respectively. The increase in segment margin as compared to the year ended March 31, 2010 reflects the benefit of improved conditions in the commercial and industrial construction markets, which offset the negative profit impact of adverse weather conditions that delayed project start-ups earlier in the current fiscal year. The Cyntech acquisition contributed $0.9 million to current fiscal year profit. Segment margins in the year ended March 31, 2009 benefitted from higher margins on project development activity in the oil sands.

Pipeline


	Year Ended March 31,								Changes
(dollars in thousands)	2011			2010			2009		2011 vs 2010		2011 vs 2009
Segment revenue		$85,452			$24,920			$101,407		$60,532		$(15,955)
Segment (loss) profit		$(3,034	)		$(3,851	)		$22,470		$817		$(25,504)
Segment margin		-3.6%			-15.5%			22.2%

For the year ended March 31, 2011, the Pipeline segment reported revenues of $85.5 million, a $60.5 million increase over a year ago. The increased segment revenues primarily reflect the execution of two large diameter pipeline projects in northern British Columbia, both of which were substantially completed in the year ended March 31, 2011. Complementing these substantial projects was revenue from pipeline construction to support tailings management projects in the oil sands. Pipeline segment revenue decreased by $16.0 million compared to the year ended March 31, 2009, when the segment benefitted from the Kinder Morgan TMX Anchor Loop project in northern British Columbia.


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The Pipeline segment recorded a current year loss of $3.0 million, reflecting highly competitive market conditions during the recession and reduced productivity on a single lump-sum project as a result of unanticipated weather and ground conditions. Segment loss for the year ended March 31, 2010 was $3.9 million, again reflecting highly competitive market conditions during the recession and production impacts related to unfavourable weather, changes in construction methodology due to unfavourable environmental conditions, as well as a higher percentage of rental versus owned equipment. We are currently working on a number of requests for change orders regarding weather and environmental impacts and significant changes to project scope in accordance with the terms of the two contracts substantially completed in the current year. Segment profit for the year ended March 31, 2009 was $22.5 million, which included the benefit of a $5.3 million settlement of claims revenue. Excluding this settlement, Pipeline segment margin would have been 16.9% of revenue.

SUMMARY OF CONSOLIDATED THREE MONTH RESULTS


	Three Months Ended March 31,
(dollars in thousands, except per share amounts)	2011			% of Revenue		2010			% of Revenue		Change
Revenue		$174,510			100.0%		$220,569			100.0%		$(46,059	)
Project costs		98,383			56.4%		92,401			41.9%		5,982
Equipment costs		64,753			37.1%		61,493			27.9%		3,260
Equipment operating lease expense		16,080			9.2%		22,009			10.0%		(5,929	)
Depreciation		12,682			7.3%		11,943			5.4%		739
Gross (loss) profit		(17,388	)		-10.0%		32,723			14.8%		(50,111	)
General and administrative expenses		14,435			8.3%		19,104			8.7%		(4,669	)
Operating (loss) income		(35,452	)		-20.3%		13,127			6.0%		(48,579	)
Net loss		(30,452	)		-17.5%		(943	)		-0.4%		(29,509	)
Per share information												–
Net loss—basic		$(0.84	)				$(0.03	)				$(0.81	)
Net loss—diluted		(0.84	)				(0.03	)				(0.81	)
EBITDA (1)		$(19,426	)		-11.1%		$20,914			9.5%		$(40,340	)
Consolidated EBITDA (1) (as defined within the credit agreement)		$24,004			13.8%		$26,428			12.0%		$(2,424	)

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


	Three Months Ended March 31,
(dollars in thousands)	2011			2010
Net loss		$(30,452	)		$(943	)
Adjustments:
Interest expense		7,361			6,355
Income taxes (benefit)		(10,305	)		3,278
Depreciation		12,682			11,943
Amortization of intangible assets		1,288			281
EBITDA		$(19,426	)		$20,914
Adjustments:
Unrealized foreign exchange gain on senior notes		–			(6,200	)
Realized and unrealized (gain) loss on derivative financial instruments		(1,965	)		11,226
Loss on disposal of property, plant and equipment and assets held for sale		497			189
Stock-based compensation expense		529			277
Equity in loss of unconsolidated joint venture		1,844			22
Revenue writedown on Canadian Natural project		42,525			–
Consolidated EBITDA		$24,004			$26,428

ANALYSIS OF THREE MONTH RESULTS

Revenue

For the three months ended March 31, 2011, revenue was $174.5 million, $46.1 million lower than in the same period last year. As discussed in the “Explanatory Notes—Significant Business Event” section of this MD&A, this decrease was largely accounted for by the $42.5 million revenue writedown related to the long-term overburden removal contract with Canadian Natural. In addition, a slight drop in both recurring services and project development activity in the Heavy Construction and Mining segment and the completion of a project in our Pipeline segment offset higher revenues in our Piling segment. The decrease in recurring services activity reflects the slowdown in operations at Shell’s two oil sands mines during the period. This was partially offset by increased activity at Suncor and Syncrude operations. During the prior-year period, recurring services revenues in the Heavy Construction and Mining segment were negatively affected by a temporary slowdown of overburden removal activities during Canadian Natural’s production start-up period.


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Gross (loss) profit

Gross margin for the three months ended March 31, 2011 decreased to -10.0% of revenue compared to 14.8% during the same period last year. Gross profit margin would have been 11.6% excluding the revenue writedown related to the long term overburden removal project with Canadian Natural, the year-to-year decline reflects a loss on one lump-sum Pipeline project and lower margins in the Piling segment due to project losses and start-up delays. Margins recorded last year reflected the benefits of project close-out activities and higher margin site services work.

Operating (loss) income

For the three months ended March 31, 2011, we recorded an operating loss of $35.5 million or -20.3% of revenue, compared to operating income of $13.1 million, during the same period last year. This change is primarily a result of the impact of the revenue writedown as discussed above. General and administrative (G&A) expense for the three months ended March 31, 2011 decreased by $4.7 million, reflecting a reduction in the employee short-term incentive plan liability in the current period, which was offset by the year-over-year increase to stock-based compensation expense.

Net loss

For the three months ended March 31, 2011, we recorded a net loss of $30.5 million (basic loss per share of $0.84), compared to a net loss of $0.9 million (basic loss per share of $0.03) during the same period last year. Excluding the $31.8 million after tax impact of the revenue writedown on the long-term overburden removal contract, net income would have been $1.3 million (basic and diluted income per share of $0.04) for the three months ended March 31, 2011. Non-cash items affecting net income included non-cash gains on embedded derivatives in a long-term customer contract and certain long-term supplier contracts. Non-cash items affecting net income for the same period last year included the positive foreign exchange effect of the strengthening Canadian dollar on our 8³/4% senior notes, a gain on the interest rate swap and a gain on the redemption option embedded derivative on the 8³/4% senior notes. This positive effect was partly offset by the loss on the cross currency swap and losses on embedded derivatives in a long-term customer contract and certain long-term supplier contracts. Excluding these non-cash items and the revenue writedown in the current and prior-year periods, net loss would have been $0.2 million (basic loss per share of $0.01) down from net income of nil (basic and diluted income per share of nil).

SEGMENT THREE MONTH RESULTS

Heavy Construction and Mining


	Three Months Ended March 31,
(dollars in thousands)	2011			2010		Change
Segment revenue		$146,475			$196,002		$(49,527	)
Segment (loss) profit		$(14,071	)		$29,286		$(43,357	)
Segment margin		-9.6%			14.9%

For the three months ended March 31, 2011, the Heavy Construction and Mining segment reported revenues of $146.5 million, a $49.5 million decrease from the same period last year. As discussed in the “Explanatory Notes—Significant Business Event” section of this MD&A, the decline in revenue primarily reflects the $42.5 million revenue writedown related to the long-term overburden removal contract with Canadian Natural. Recurring services revenues also decreased by 24.7% compared to a year ago which reflects reduced customer activity at both Shell mines offset by higher recurring services revenues at Suncor and Syncrude. Higher volumes with Syncrude reflect increased activity levels under our recent four-year master services agreement and increased activity with Suncor reflects increased demand for our mine support services with this customer. Activity at Shell in the prior periods benefitted from significant mine support services at both mines in preparation of the Jackpine production start-up.

Recurring services revenue represented 88.6% of Heavy Construction and Mining’s revenue in the three month period ended March 31, 2011 compared to 87.9% in the same period last year.

For the three months ended March 31, 2011, we reported a negative segment margin compared to a segment margin of 14.9% during the same period last year. The reduction in segment margin reflects the revenue writedown on the long-term removal overburden contract. Segment profit margin would have been 15.0% excluding this writedown.

Piling


	Three Months Ended March 31,
(dollars in thousands)	2011		2010		Change
Segment revenue		$22,256		$18,263		$3,993
Segment profit		$1,955		$2,149		$(194	)
Segment margin		8.8%		11.8%

The Piling segment achieved revenues of $22.3 million in the three months ended March 31, 2011, an increase of $4.0 million compared to the same period last year. The increase in Piling revenues reflects a $3.9 million revenue contribution from our November 2010 acquisition of Cyntech.

For the three months ended March 31, 2011 segment margins decreased to 8.8%, from 11.8% in the same period last year. Project start-up delays resulting from an abnormally long and cold winter in Alberta and Saskatchewan and a margin


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reduction on a larger lump-sum contract were key contributors to this decline. Segment margins for the prior year period also benefitted from the processing of change orders related to large projects completed in the period. The Cyntech acquisition contributed $0.1 million to current period profit.

Pipeline


	Three Months Ended March 31,
(dollars in thousands)	2011			2010			Change
Segment revenue		$5,779			$6,304			$(525	)
Segment loss		$(1,549	)		$(5,152	)		$3,603
Segment margin		-26.8%			-81.7%

Pipeline revenues for the three months ended March 31, 2011 were $5.8 million, a $0.5 million decrease from last year. Revenue in the current period was driven primarily by project close-out activity on two large diameter pipeline jobs completed earlier in the fiscal year.

The segment loss for the three months ended March 31, 2011 reflects an increase in the estimated cost to complete for the summer clean-up work for both projects which were substantially completed earlier in the current year.

NON-OPERATING INCOME AND EXPENSE


	Three Months Ended March 31,						Year Ended March 31,
(dollars in thousands)	2011		2010		Change		2011		2010		2009		2011 vs 2010 Change		2011 vs 2009 Change
Interest expense
Long term debt
Interest on 8³/4% senior notes and swaps		$–		$4,573		$(4,573)		$1,238		$19,041		$25,379		$(17,803)		$(24,141)
Interest on Series 1 Debentures		5,133		–		5,133		20,132		–		–		20,132		20,132
Interest on credit facilities		1,681		990		691		5,361		2,375		298		2,986		5,063
Interest on capital lease obligations		144		227		(83)		689		1,032		1,234		(343)		(545)
Amortization of deferred financing costs		366		859		(493)		1,609		3,348		2,970		(1,739)		(1,361)
Interest on long term debt		$7,324		$6,649		$675		$29,029		$25,796		$29,881		$3,233		$(852)
Other interest		37		(294)		331		962		284		(269)		678		1,231
Total Interest expense		$7,361		$6,355		$1,006		$29,991		$26,080		$29,612		$3,911		$379
Foreign exchange loss (gain)		31		(5,971)		6,002		(1,659)		(48,901)		47,272		47,242		(48,931)
Realized and unrealized (gain) loss on derivative financial instruments		(1,965)		11,226		(13,191)		(2,305)		54,411		(37,250)		(56,716)		34,945
Loss on debt extinguishment		–		–		–		4,346		–		–		4,346		4,346
Other income		(122)		(818)		696		(104)		(14)		(5,955)		(90)		5,851
Income taxes (benefit)		(10,305)		3,278		(13,583)		(6,448)		13,679		14,633		(20,127)		(21,081)

Interest expense

Total interest expense increased $1.0 million in the three months ended March 31, 2011 and $3.9 million in the year ended March 31, 2011, compared to the corresponding periods in the prior year. In April 2010, we closed a private placement of 9.125% Series 1 Debentures (Series 1 Debentures) due April 7, 2017 for gross proceeds of $225.0 million. On April 28, 2010, we redeemed and cancelled all outstanding 8³/4% senior notes. The redemption amount included the US$200.0 million principal outstanding and US$7.1 million of accrued interest. On April 8, 2010, we also terminated the cross currency and interest rate swaps used to hedge interest rate and currency exposure on the US dollar denominated 8³/4% senior notes. The interest expense of $1.2 million on our 8³/4% senior notes during the current year reflects interest costs to the redemption date. The interest expense of $20.1 million on our Series 1 Debentures for the year ended March 31, 2011 reflects interest for the partial period that followed the issuance of the Series 1 Debentures on April 7, 2010. 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”. Prior-year interest hedge costs were $4.2 million and $15.6 million, respectively, for the three months and year ended March 31, 2010. The refinancing of the senior notes in April 2010 resulted in an overall decrease in financing costs, including interest and swap costs, of $3.2 million compared to the previous three months ended March 31, 2010 and a reduction of $11.3 million compared to the year ended March 31, 2010. The cancellation of one leg of the swap agreement on February 2, 2009, one of the three swap agreements hedging the interest and currency risk associated with our US dollar denominated 8³/4% senior notes, led to


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increased interest expense for that fiscal year, as shown in the “Realized and unrealized loss (gain) on derivative financial instruments” section, below. A more detailed discussion on the restructuring of our long-term debt can be found under “Liquidity and Capital Resources”.

On April 30, 2010, we entered into a fourth amended and restated credit agreement to extend the term of the credit agreement and to add borrowing capacity of up to $50.0 million through a second term facility within the credit agreement. At March 31, 2011, the second term facility was fully drawn. The new term facility, along with the existing term facility, matures on April 30, 2013. At March 31, 2011, we had $72.0 million outstanding under the Term Facilities and Revolving Facility, which together have a capacity of $163.4 million ($28.4 million outstanding at March 31, 2010). Interest expense for the credit facilities was $1.7 million and $5.4 million for the three months and year ended March 31, 2011, respectively, reflecting the cost of the higher amounts borrowed on the credit facilities to fund working capital growth.

Foreign exchange loss (gain)

The foreign exchange gains recognized in the three months and 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 8³/4% 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 8³/4% senior notes were redeemed, resulted in a realized foreign exchange gain for the current year. The Canadian dollar weakened during the year ended March 31, 2009, resulting in unrealized foreign exchange losses for the period. A more detailed discussion about our foreign currency risk can be found under “Quantitative and Qualitative Disclosures about Market Risk – Foreign exchange risk”.

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 held US dollar denominated 8³/4% 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 year ended March 31, 2011 and 2010, respectively, are detailed in the table below:


	Three Months Ended March 31,									Year Ended March 31,
(dollars in thousands)	2011			2010			Change			2011			2010			2009			2011 vs 2010 Change			2011 vs 2009 Change
Swap liability loss (gain)		$ –			$6,344			$(6,344)			$1,783			$49,078			$(49,613)			$(47,295)			$51,396
Redemption option embedded derivative (gain) loss		–			(118	)		118			–			(3,716	)		3,331			3,716			(3,331	)
Supplier contracts embedded derivatives (gain) loss		(1,686	)		643			(2,329	)		(3,812	)		(13,315	)		21,509			9,503			(25,321	)
Customer contract embedded derivative (gain) loss		(279	)		190			(469	)		(604	)		6,805			(15,145	)		(7,409	)		14,541
Swap interest payment		–			4,167			(4,167	)		328			15,559			2,668			(15,231	)		(2,340	)
Total		$(1,965	)		$11,226			$(13,191	)		$(2,305	)		$54,411			$(37,250	)		$(56,716	)		$34,945

The measurement of embedded derivatives, as required by GAAP, causes our reported net income to fluctuate as Canadian/US dollar exchange rates, interest rates and the US-PPI for Mining Machinery and Equipment change. The accounting for these derivatives has no impact on operations, Consolidated EBITDA (as defined within our credit agreement) or how we evaluate performance.

The 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 held US dollar denominated 8³/4% senior notes. Changes in the fair value of these swaps generally had an offsetting effect to changes in the value of our previously held 8³/4% 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 prior year reflects changes in the fair value of a derivative embedded in our previously held US dollar denominated 8³/4% senior notes. Changes in fair value resulted from changes in long-term bond interest rates during a reporting period.


2011 Annual Report		\| NOA \|			33

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, 2011. Included in the embedded derivative valuation was the impact of fluctuations in provisions that require a price adjustment to reflect changes in the Canadian/US dollar exchange rate and the United States government published Producers’ Price Index (US-PPI) for Mining Machinery and Equipment from the original contract amount.

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

The measurement of swap interest payment for the year ended March 31, 2011 reflects the realized loss on our previously held interest rate swaps. As of February 2, 2009, one of three swap agreements hedging the interest and currency risk associated with our previously held US dollar denominated 8³/4% senior notes was cancelled by the counterparties which resulted in us incurring higher interest expense until we terminated the cross currency and interest rate swaps on April 8, 2010.

Income taxes (benefit)

For the three months ended March 31, 2011, we recorded a current income tax benefit of $1.5 million and a deferred income tax benefit of $8.8 million for a total income tax benefit of $10.3 million. This is as compared to combined income tax expense of $3.3 million for the same period last year. For the three months ended March 31, 2011, income tax expense as a percentage of income before taxes differs from the statutory rate of 27.75% primarily due to the changes in the timing of the reversal of temporary differences. Some of the temporary differences are reversing at rates different from the opening deferred tax rates that had been set up. For the three months ended March 31, 2010, income tax expense as a percentage of income before income taxes differs from the statutory rate of 28.91% primarily due to the impact of income tax adjustments and reassessments, non-deductible items and changes in the timing of the reversal of temporary differences.

For the year ended March 31, 2011, we recorded current income taxes of $2.9 million and deferred income taxes benefit of $9.3 million for a total income tax benefit of $6.4 million. This compares to combined income tax expense of $13.7 million for the same period last year. For the year ended March 31, 2011, income tax expense as a percentage of income before income taxes differs from the statutory rate of 27.75%, primarily due to the impact of changes in enacted tax rates, CRA audit adjustments from 2007 and 2008, which are flowing through the current and deferred income tax accounts and an increase in the permanent differences in stock-based compensation as a result of a partial restructuring of the stock option plan. For the year ended March 31, 2010, income tax expense as a percentage of income before income taxes differs from the statutory rate of 28.91% primarily due to the impact of income tax adjustments and reassessments, non-deductible items and changes in the timing of the reversal of temporary differences. For the year ended March 31, 2009, income tax expense as a percentage of income before income taxes differed from the statutory rate of 29.38% primarily due to non-deductible items, as well as a permanent difference relating to the $176.2 million non-deductible goodwill impairment.

BACKLOG

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

We define backlog as work that has a high certainty of being performed as evidenced by the existence of a signed contract, 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, 2011, the total amount of revenue earned from time-and-material contracts performed under our master services agreements, which are not in backlog, was approximately $66.8 million and $265.3 million respectively.


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Our estimated backlog by segment and contract type as at March 31, 2011, December 31, 2010 and March 31, 2010 was:


(dollars in thousands)	March 31, 2011		December 31, 2010		March 31, 2010
By Segment
Heavy Construction & Mining		$568,717		$694,867		$800,751
Piling		12,558		12,435		16,423
Pipeline		1,427		5,294		6,861
Total		$582,702		$712,596		$824,035
By Contract Type
Unit-Price		$567,062		$693,102		$797,694
Lump-Sum		11,861		16,921		18,429
Time-and-Material, Cost-Plus		3,779		2,573		7,912
Total		$582,702		$712,596		$824,035

The long-term overburden removal contract with Canadian Natural represented approximately $539.4 million of the March 31, 2011 backlog compared to $655.3 million in our interim MD&A for the three and nine months ended December 31, 2010 and $781.7 million reported as backlog in our annual MD&A for the year ended March 31, 2010.

We expect that approximately $133.4 million of total backlog will be performed and realized in the 12 months ending March 31, 2012, which includes a backlog reduction of $62.0 million as a result of the suspension of overburden removal activities at Canadian Natural’s Horizon Oil Sands mine, as discussed in the “Explanatory Notes—Significant Business Event” section of this MD&A.¿

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, 2011, due to the timing of receipt of signed change orders, the Heavy Construction and Mining segment had approximately $0.2 million and $1.3 million respectively in claims revenue recognized to the extent of costs incurred, the Piling segment had $0.4 million and $2.7 million respectively in claims revenue recognized to the extent of costs incurred and the Pipeline segment had $1.2 million and $1.3 million respectively in claims revenue recognized to the extent of costs incurred. We are working with our customers to come to resolution on additional amounts, if any to be paid to us with respect to these additional costs.

For the three months and year ended March 31, 2011, the Heavy Construction and Mining segment applied the accounting treatment guidance described in the “Explanatory Notes—Significant Business Event” section of this MD&A to record a $42.5 million revenue writedown to reduce the total contract revenue to the extent of total costs incurred on the long-term overburden removal contract with Canadian Natural. The scope of the work to be done under the contract has been agreed upon but we have not yet agreed upon the exact adjustments to the price escalation indices. We have formed a joint working group with Canadian Natural to identify new escalation indices for this contract which is expected to provide its recommendations by August 31, 2011. We have determined that it is probable that the costs will be recovered through an increase in the contract price for the escalation indices.

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


2011 Annual Report		\| NOA \|			35

SUMMARY OF CONSOLIDATED QUARTERLY RESULTS


	Three Month Period Ended
(dollars in millions, except per share amounts)	March 31, 2011		Dec 31, 2010		Sep 30, 2010		Jun 30, 2010		Mar 31, 2010		Dec 31, 2009		Sep 30, 2009		Jun 30, 2009
(dollars in millions, except per share amounts)	Fiscal 2011								Fiscal 2010
Revenue		$174.5		$265.1		$234.9		$183.6		$220.6		$221.2		$170.7		$146.5
Gross (loss) profit		(17.4)		30.8		29.1		15.6		32.7		47.6		33.8		25.1
Operating (loss) income		(35.5)		11.3		12.3		1.1		13.1		31.3		18.9		10.1
Net (loss) income		(30.5)		3.7		2.4		(10.3)		(0.9)		14.9		4.3		9.9
Net (loss) income per share—basic		$(0.84)		$0.10		$0.07		$(0.29)		$(0.03)		$0.41		$0.12		$0.28
Net (loss) income per share—diluted		(0.84)		$0.10		$0.06		$(0.29)		$(0.03)		$0.41		$0.12		$0.27

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

A number of factors have the potential to contribute to variations in our quarterly financial results between periods, including the capital project-based nature of our project development revenue, seasonal weather and ground conditions, capital spending decisions by our customers on large oil sands projects, the timing of equipment maintenance and repairs, claims and change-orders and the accounting for unrealized non-cash gains and losses related to foreign exchange and derivative financial instruments.

We generally experience a decline in revenues during the first three months of each fiscal year due to seasonality, as weather conditions make performance in our operating regions difficult during this period. The level of activity in the Heavy Construction and Mining and Pipeline segments declines when frost leaves the ground and many secondary roads are 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 it has a direct impact on our activity levels. Revenues during the three months ended March 31 of each fiscal year are typically highest as ground conditions are most favourable in our operating regions. As a result, full-year results are not likely to be a direct multiple or combination of a 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.

The timing of large projects can influence quarterly revenues. For example, in the past two fiscal years, Pipeline segment revenues were as low as $0.1 million in the three months ended June 30, 2009 and as high as $42.2 million for the three months ended December 31, 2010. The Heavy Construction and Mining segment experienced reduced volumes in the three months ended March 31, 2009 as a result of the temporary shut-down of overburden removal at the Horizon project while Canadian Natural prepared for operations start-up. Subsequent periods reflect the ramp up of overburden removal activities at the Horizon project through the three months ended December, 2010, where activity returned to planned activity levels. The revenue writedown on the overburden removal contract with this customer negatively affected results for the three months ended March 31, 2011. Changes in demand under our master services agreements with Shell positively affected fiscal 2010 results due to increased demand for mine services during the commissioning of Shell’s Jackpine mine. Activity subsequently declined in fiscal 2011 as Shell commissioned the Jackpine mine and concurrently undertook related integration activities at the Muskeg River mine.

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.

Profitability also varies from quarter-to-quarter as a result of claims and change-orders. Claims and change-orders are a normal aspect of the contracting business but can cause variability in profit margin due to the unmatched recognition of costs and revenues. For further explanation, see “Claims and Change Orders”.

We have also experienced net income variability in all periods up to the three months ended June 30, 2010 due to the recognition of unrealized non-cash gains and losses on both derivative financial instruments and our previously held US dollar denominated 8³/4% senior notes, primarily driven by changes in the Canadian/US dollar exchange rate. The 8³/4% senior notes were redeemed on April 28, 2010 and the associated currency and interest rate swaps were terminated on April 8, 2010.


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SUMMARY OF CONSOLIDATED FINANCIAL POSITION


	Year Ended March 31,
(dollars in thousands)	2011			2010			2009			2011 vs 2010 Change			2011 vs 2009 Change
Cash		$722			$103,005			$98,880			$(102,283)			$(98,158)
Current assets (excluding cash)		250,642			209,995			157,858			40,647			92,784
Current liabilities		(165,819	)		(165,641	)		(127,957	)		(178	)		(37,862	)
Net working capital		$85,545			$147,359			$128,781			$(61,814	)		$(43,236	)
Property, plant and equipment		321,864			331,355			316,115			(9,491	)		5,749
Total assets		682,957			706,920			629,275			(23,963	)		53,682
Capital Lease obligations (including current portion)		(8,693	)		(13,393	)		(17,484	)		4,700			8,791
Total long term financial liabilities		(324,382	)		(327,356	)		(318,559	)		2,974			(5,823	)

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, 2011, net working capital (current assets less current liabilities) was $85.5 million, down $61.8 million from March 31, 2010 and down $43.2 million from March 31, 2009.

The cash balance at March 31, 2011 was $102.3 million lower than at March 31, 2010, reflecting the Cyntech acquisition ($23.5 million), redemption of the 8³/4% senior notes and associated cross-currency and interest rate swaps ($26.5 million), scheduled principal repayments on our Term Facilities ($10.0 million), the purchase of equipment and intangible assets ($41.2 million) and an increase in non-cash working capital. During the three months ended March 31, 2011, we had borrowings of $3.5 million against our Revolving Facility.

Current assets excluding cash, increased $40.6 million between March 31, 2010 and March 31, 2011, reflecting an $18.2 million increase in unbilled revenue, a $16.6 million increase in trade receivables and holdbacks and a $4.7 million increase in inventory, related to an increase in tire inventory and the addition of Cyntech raw materials during the year ended March 31, 2011. Contributing to the increase in unbilled revenue is our Heavy Construction and Mining segment’s long-term overburden removal contract with Canadian Natural along with delays in closeout billing on our current year Pipeline contracts, as the execution of final payment certificates on two projects require the completion of spring clean-up activities while the execution of the final payment certificate on a third Pipeline project is dependent on completion of a final contractual milestone. Current assets excluding cash, increased $92.8 million between March 31, 2009 and March 31, 2011, reflecting a $50.2 million increase in trade receivables and holdbacks, a $47.0 million increase in unbilled revenue and $3.5 million in prepaid expenses and deposits partially offset by a $4.1 million decrease in inventory and a $5.3 million decrease in deferred tax assets.

Current liabilities increased by $0.2 million between March 31, 2010 and March 31, 2011, reflecting a $19.2 million increase in accounts payable which was offset by a $19.6 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 8³/4% senior notes. Equipment purchases of $2.4 million, which are scheduled to be paid after March 31, 2011, are included in accounts payable as of March 31, 2011. current liabilities increased by $37.9 million between March 31, 2009 and March 31, 2011, reflecting a $29.8 million increase in accounts payable, a $10.0 million increase in current portion of long term debt and a $19.9 million increase in deferred tax liabilities partially offset by a $12.2 million decrease in accrued liabilities and a $9.0 million decrease in current portion of embedded derivatives in financial instruments.

Property, plant and equipment net book value for the year ended March 31, 2011 decreased $9.5 million and increased $5.7 million compared to the year ended March 31, 2010 and March 31, 2009 respectively. This reflects the capital investment of $32.6 million of equipment purchases and new capital leases during the current year compared to $56.7 million during the year ended March 31, 2010 and $93.3 million during the year ended March 31, 2009.

Total long-term financial liabilities were substantially unchanged between the years ended March 31, 2011, 2010 and 2009, however, the make-up of our long-term financial liabilities were significantly changed due largely to our debt refinancing, described in more detail in “Liquidity and Capital Resources — Long-term debt restructuring”.

SUMMARY OF CONSOLIDATED CAPITAL EXPENDITURES

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. Capital leases, while not considered capital expenditures, are restricted under the terms of our credit agreement to a maximum of $30.0 million. Operating leases are not considered capital expenditures and are not restricted under the terms of our credit agreement.

We define our equipment requirements as either:

•

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

•

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


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A summary of equipment additions by nature and by period is shown in the table below:


	Three Months Ended March 31,							Year Ended March 31,
(dollars in thousands)	2011		2010		Change			2011		2010		2009		2011 vs 2010 Change			2011 vs 2009 Change
Capital Expenditures
Sustaining		$2,611		$4,823		$(2,212	)		$16,380		$13,644		$13,467		$2,736			$2,913
Growth		2,892		2,489		403			20,577		44,861		74,072		(24,284	)		(53,495	)
Total		5,503		7,312		(1,809	)		36,957		58,505		87,539		(21,548	)		(50,582	)

Capital Leases
Sustaining		–		418		(418	)		–		867		3,056		(867	)		(3,056	)
Growth		336		–		336			427		656		5,807		(229	)		(5,380	)
Total		336		418		(82	)		427		1,523		8,863		(1,096	)		(8,436	)

Total sustaining capital additions		2,611		5,241		(2,630	)		16,380		14,511		16,523		1,869			(143	)
Total growth capital additions		3,228		2,489		739			21,004		45,517		79,879		(24,513	)		(58,875	)
Operating Leases		32,160		28,530		3,630			46,284		93,090		125,133		(46,806	)		(78,849	)

The changes in sustaining capital additions for both the three months and the year ended March 31, 2011 compared to the same periods in the prior years is reflective of the timing of scheduled capital maintenance activities.

The reduction in growth capital additions for the year ended March 31, 2011, compared to the years ended March 31, 2010 and 2009, respectively, reflects the impact of fewer major customer development projects as a result of the economic slowdown experienced at the end of fiscal 2009 and through fiscal 2010. In the latter half of the current year we have experienced an increased customer demand for equipment to support project development activity. In the short-term, we have managed this increased demand for this type of equipment through improved utilization from our owned fleet complemented with an increase in rental equipment. 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 operating leases for the year ended March 31, 2011, compared to the same periods in the previous years, reflects the timing of scheduled equipment additions related to the Canadian Natural overburden removal project along with the impact of fewer development projects as a result of the economic slowdown experienced at the end of fiscal 2009 and through fiscal 2010. The increase in operating leases for the three months ended March 31, 2011, compared to the same period in the prior year, reflects the difference in timing of scheduled equipment additions between the two periods.

SUMMARY OF CONSOLIDATED CASH FLOWS


							Three Months Ended March 31,
(dollars in thousands)							2011			2010			Change
Cash provided by operating activities								$13,531			$16,299			$(2,768)
Cash used in investing activities								(13,736	)		(5,312	)		(8,424	)
Cash provided by (used in) financing activities								211			(2,859	)		3,070
Foreign currency translation loss on cash								(32	)		–			(32	)
Net decrease (increase) in cash and cash equivalents								$(26)			$8,128			$(8,154)

	Year Ended March 31,									Change
(dollars in thousands)	2011			2010			2009			2011 vs 2010			2011 vs 2009
Cash (used in) provided by operating activities		$(497)			$42,625			$151,185			$(43,122)			$(151,682)
Cash used in investing activities		(64,632	)		(59,611	)		(78,715	)		(5,021	)		14,083
Cash (used in) provided by financing activities		(37,095	)		21,111			(5,453	)		(58,206	)		(31,642	)
Foreign currency translation loss on cash		(59	)		–			–			(59	)		(59	)
Net (decrease) increase in cash and cash equivalents		$(102,283)			$4,125			$67,017			$(106,408)			$(169,300)


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Operating activities

Cash provided by operating activities for the three months ended March 31, 2011 was $13.5 million, compared to $16.3 million for the three months ended March 31, 2010. The lower cash flow in the current period is primarily a result of lower gross profit offset by decreased non-cash net working capital.

Cash used in operating activities during the year ended March 31, 2011 was $0.5 million, compared to cash provided by operations of $42.6 million and $151.2 million for the years ended March 31, 2010 and 2009 respectively. This is primarily a result of lower gross profit and increased non-cash working capital. The cash inflow for the year ended March 31, 2009 benefitted from significant project closeout activities.

Investing activities

Cash used in investing activities for the three months ended March 31, 2011 was $13.7 million, compared with $5.3 million for the same period a year ago. Investing activities this current period included $2.7 million for the acquisition of Cyntech Corporation and capital and intangible asset expenditures of $11.2 million. Cash used in investing activities for the three months ended March 31, 2010 included capital and intangible asset expenditures of $5.8 million, less proceeds from asset dispositions of $0.5 million.

Cash used in investing activities for the year ended March 31, 2011 was $64.6 million compared with $59.6 million and $78.7 million for the years ended March 31, 2010 and 2009, respectively. Current period investing activities included capital and intangible expenditures of $41.2 million along with $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 prior year included capital and intangible expenditures of $55.3 million along with $5.4 million for the acquisition of DF Investments Limited, less cash proceeds from asset dispositions of $3.9 million.

Financing activities

Cash provided by financing activities during 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 used in financing activities for the three month period ended March 31, 2010 was $2.9 million due to a repayment of $1.5 million to our term credit facilities and a $1.4 million repayment of capital lease obligations.

Cash provided by financing activities during the year ended March 31, 2011 was $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 during the year ended March 31, 2010 totaled $21.1 million. Capital expenditure financing of $27.8 million (net of term credit facilities repayments), 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. Cash used in financing activities for the year ended March 31, 2009 of $5.5 million was a result of the $6.2 million repayment of capital lease obligations partially offset by the proceeds from stock options exercised.

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, 2011.

D. OUTLOOK

While we may experience some near term reduction to revenue as a result of the recently announced work suspension on our long-term overburden removal contract with Canadian Natural, the anticipated redeployment of resources to higher-margin projects could help to offset some of this revenue reduction, while also having a positive impact on margins and cash flow. We also anticipate some negative impact to first quarter results due to the recent wild fires near Fort McMurray, which have impacted our ability to work at several customer sites during the past two weeks. However, our outlook continues to improve as a result of strengthening general economic conditions, recently awarded and anticipated long-term contracts with Shell, Syncrude and Suncor and increasing investment in the oil sands.¿

Suncor and Total have formed a strategic alliance to develop the Fort Hills mine, Voyageur upgrader and Joslyn mine. Exxon continues with construction of its Kearl project and Syncrude is planning a number of major mining projects, including the relocation of four mine trains. The resurgence of project development activity is resulting in growing demand for the industrial construction, site preparation and piling services we provide.

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


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Oil sands operators are also increasing spending on tailings and reclamation projects in response to new environmental regulations. This, in turn, is creating opportunities for our new Tailings and Environmental Construction division to support the construction and operation of the new reclamation processes.

At the same time, demand for recurring services is growing with three of the four existing oil sands mines expected to be fully operating this year and Canadian Natural’s Horizon mine and Exxon’s Kearl mine scheduled to begin production in early 2012. Indicative of the growing demand, our Heavy Construction and Mining segment has recently been awarded two major multi-year recurring services contracts, including:

•

A four-year master services agreement with Syncrude, which replaces the master services agreement with this customer that expired in November 2010; and

•

A three-year master services agreement with Shell, which includes the removal of a minimum of 2.5 million metres of muskeg at the Jackpine mine in the first year of the contract. Shell is currently reviewing its requirements and the work scope could be increased. This new contract is in addition to our existing three-year master services contract with this customer.^¿

In addition to these recurring services contracts, we anticipate the awarding of a new five-year master services agreement with Suncor to supply reclamation, mine services and light and heavy civil construction services to the Millennium and Steepbank mines.^¿

While the sharp increase in demand for oil sands services is providing relief from the competitive margin pressure experienced over the past two years, it is important to note that we continue to work on several older contracts negotiated at lower margins. Accordingly, we expect that revenue growth will continue to outpace margin growth in the near term but margin growth should improve as older contracts expire and are replaced with new, higher-margin business.^¿

In the Piling segment, activity levels are expected to increase in fiscal 2012 as a result of the growing project development activity in the oil sands and an upsurge in commercial construction opportunities in markets like Toronto and Calgary. Given the shorter-term, project-specific nature of piling contracts, margins are expected to recover more quickly for this division than for other parts of our business. We are anticipating a strong year for this segment in fiscal 2012.^¿

In the Pipeline division, business conditions are expected to improve following the recent announcement of various new pipeline projects in Western Canada. These new projects are designed to address expected increases in oil and gas production in the region. Toward the end of fiscal 2011, we began to see a sharp increase in bidding activity, which has continued in early fiscal 2012. Accordingly, we anticipate increasing near-term demand for small and large pipeline projects and expansions, which should in turn support improved pricing and reduced risk on new contracts. ^¿

Overall, our long-term outlook for the business remains positive. We are also continuing to pursue acquisitions that strategically broaden our services, with a focus on smaller-scale opportunities that fit well with our current service offering and that can be integrated quickly.

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. These laws and regulations are administered by federal, provincial and municipal authorities, such as Alberta Environment, Saskatchewan Environment, the British Columbia Ministry of Environment, Ontario Ministry of the Environment and other governmental agencies. The requirements of these laws and regulations are becoming increasingly complex and stringent and meeting these requirements can be expensive.

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


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

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

Capital expenditures relating to environmental matters during the fiscal years ended March 31, 2009, 2010 and 2011 were not material. We do not currently anticipate any material adverse effect on our business or financial position as a result of future compliance with applicable environmental laws and regulations. Future events, however, such as changes in existing laws and regulations or their interpretation, more vigorous enforcement policies of regulatory agencies or stricter or different interpretations of existing laws and regulations may require us to make additional expenditures which may or may not be material.

EMPLOYEES AND LABOUR RELATIONS

As of March 31, 2011, we had 533 salaried employees and approximately 2,279 hourly employees. The growth in our salaried employee work force can be primarily attributed to our conversion of hourly site supervision staff to salaried employees during the fiscal year. 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 3,000 employees depending on the time of year and duration of awarded projects. We also utilize the services of subcontractors in our construction business. An estimated 8% to 10% of the construction work we do is performed by subcontractors. Approximately 2,000 employees are members of various unions and work under collective bargaining agreements. The majority of our work is done through employees governed by our mining overburden collective bargaining agreement with the International Union of Operating Engineers Local 955, the primary term of which expires on 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 International Union of Operating Engineers (IUOE) Local 955 and the Alberta Roadbuilders and Heavy Construction Association (ARBHCA) expired February 28, 2011 and the Association is currently amidst negotiations with the Operating Engineers for the renewal of this Agreement. NACG has a representative on the ARBHCA bargaining committee. Management expects that a settlement will be reached without disruption. We believe that our relationships with all our employees, both union and non-union, are strong. We have not experienced a strike or lockout. ¿

F. RESOURCES AND SYSTEMS

OUTSTANDING SHARE DATA

We are authorized to issue an unlimited number of voting Common Shares and an unlimited number of Non-Voting Common Shares. As at March 31, 2011, there were 36,242,526 voting Common Shares outstanding (36,049,276 as at March 31, 2010). We had no Non-Voting Common Shares outstanding on any of the foregoing dates.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity requirements

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

We maintain a significant equipment and vehicle fleet comprised of units with remaining useful lives covering a variety of time spans. It is important to adequately maintain our large revenue-producing fleet in order to avoid equipment downtime, which can impact our revenue stream and inhibit our ability to satisfactorily perform on our projects. Once units reach the end of

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


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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 (44%), leased (49%) and rented equipment (7%). Approximately 33% of our leased fleet value is specific to the long-term overburden removal contract with Canadian Natural. This equipment mix is a change from the mix reported in previous periods as a result of an increasing demand for specific types of rental equipment to support project development activity along with the conversion of some rental equipment to operating leases to meet specific volume demands. Our equipment ownership strategy allows us to meet our customers’ variable service requirements while balancing the need to maximize equipment utilization with the need to achieve the lowest ownership costs.¿

We require between $30 million and $60 million annually for sustaining capital expenditures and our total capital requirements typically range from $75 million to $150 million depending on our growth capital requirements. With the renewed commitment to Canadian oil sands development by the oil sands producers, we are continuing to assess our growth capital needs for the coming fiscal year. Our preliminary estimate of our capital needs for the next fiscal year is approximately $90 million to $140 million.¿

We typically finance approximately 30% to 50% of our total capital requirements 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.

We continue to receive interest from finance companies to support our current lease requirements. We anticipate having sufficient lease capacity to meet our capital requirements in fiscal year 2012.^¿

Long-term Debt

In April 2010, we issued C$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 8³/4% 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 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. A more detailed discussion on the Series 1 Debentures can be found under “9.125% Series 1 Debentures” in the “Liquidity and Capital Resources” section of this MD&A.

8³/4% Senior Notes Redemption

Beginning December 1, 2009, our 8³/4% 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 8³/4% 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 8³/4% 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 8³/4% 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. The new term facility, along with the existing term facility, matures on April 30, 2013. A more detailed discussion on the April 30, 2010 fourth amended and restated credit agreement can be found under “Credit facilities” in this “Liquidity and Capital Resources” section of this MD&A.

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


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Letters of credit

One of our major contracts allows the customer to require that we provide up to $50.0 million in letters of credit. As at March 31, 2011, we had $10.0 million in letters of credit outstanding in connection with this contract (we had $12.3 million in letters of credit outstanding in total for all customers as of March 31, 2011). Any change in the amount of the letters of credit required by this customer must be requested by November 1st in each year for an issue date of January 1st following the date of such request, for the remaining life of the contract.

Sources of liquidity

Our principal sources of cash are funds from operations and borrowings under our credit facility. As of March 31, 2011, there were outstanding borrowings of $3.5 million and issued and undrawn letters of credit of $12.3 million under the $85.0 million Revolving Facility and outstanding borrowings of $68.4 million ($28.4 million at March 31, 2010) under the Term Facilities.

As at March 31, 2011, we had $10.1 million in trade receivables that were more than 30 days past due compared to $7.5 million as at March 31, 2010. We have currently provided an allowance for doubtful accounts related to our trade receivables of $nil ($1.7 million at March 31, 2010). We continue to monitor the credit worthiness of our customers. To date our exposure to potential writedowns in trade receivables has been limited to the financial condition of developers of condominiums and high-rise developments in our Piling segment.

Borrowing activity under the Revolving Facility

During the year ended March 31, 2011, we used our Revolving Facility to finance our working capital requirements. At March 31, 2011, we had $3.5 million of borrowings outstanding on our Revolving Facility. For the three months ended March 31, 2011, the weighted average amount of our borrowing on the Revolving Facility was $24.4 million with a weighted average interest rate of 6.5%. For the year ended March 31, 2011, the weighted average amount of our borrowing on the Revolving Facility was $8.1 million with a weighted average interest rate of 6.5%. The weighted 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, 2011 was $30.0 million.

As of March 31, 2011, we had issued $12.3 million ($10.4 million at March 31, 2010) in letters of credit under the Revolving Facility to support performance guarantees associated with customer contracts. As at March 31, 2011, our unused borrowing availability under the Revolving Facility was $69.2 million.

Working capital fluctuations effect on cash

The seasonality of our business usually causes a higher accounts receivable balance and a peak in activity levels between December and early February, which can result in an increase in our working capital requirements. Our working capital is also significantly affected by the timing of the completion of projects. In some cases, our customers are permitted to withhold payment of a percentage of the amount owing to us for a stipulated period of time (such percentage and time period is usually defined by the contract and in some cases provincial legislation). This amount acts as a form of security for our customers and is referred to as a “holdback”. Typically, we are only entitled to collect payment on holdbacks provided that 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 time period specified by the contract (usually 45 days after completion of the work). However, in some cases, we are able to negotiate the progressive release of holdbacks as the job reaches various stages of completion. As at March 31, 2011, holdbacks totaled $12.0 million, up from $3.9 million as at March 31, 2010. Holdbacks represent 9.4% of our total accounts receivable as at March 31, 2011 (3.5% as at March 31, 2010).

Cash requirements

As at March 31, 2011, our cash balance of $0.7 million was $102.3 million lower than our cash balance at March 31, 2010. The change in cash balance reflects the April 2010 settlement of our 8³/4% senior notes and the associated cross-currency and interest rate swaps, funded in part by our Series 1 Debentures and the addition of an additional term facility secured through our fourth amended and restated credit facility. The reduction in the cash balance also reflects the Cyntech acquisition, capital expenditures and the impact of increased working capital balances. We anticipate that we will have generated a net cash surplus from operations for the year ended March 31, 2012. In the event that we require additional funding, we believe that any such funding requirements would be satisfied by the funds available from our credit facilities described immediately below. ^*

Credit facilities

On April 30, 2010, we entered into a fourth amended and restated credit agreement to extend the term of the credit facilities and increase the amount of the term loans. The new credit facilities provide for total borrowings of up to $163.4 million (previously $125.0 million) under which revolving loans, term loans and letters of credit may be issued. The Revolving Facility of $85.0 million (previously $90.0 million) was undrawn at closing. The new agreement includes two term facilities providing

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


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for borrowings of up to $78.4 million. At April 30, 2010, the Term A Facility and Term B Facility, as defined in the credit agreement (the Term Facilities), were both fully drawn at $28.4 million and $50.0 million, respectively. The new Term Facilities mature on April 30, 2013.

Advances under the Revolving Facility may be repaid from time to time at our option. The Term Facilities include scheduled repayments totaling $10.0 million per year with $2.5 million paid on the last day of each quarter commencing June 30, 2010. In addition, we must make annual payments within 120 days of the end of our fiscal year in the amount of 50% of Consolidated Excess Cash Flow (as defined in the credit agreement) to a maximum of $4.0 million. Based on the calculation of Consolidated Excess Cash Flow at March 31, 2011, we will not be required to make an additional principal payment in fiscal year 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 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 and US base rate loans is payable monthly in arrears and computed on the basis of a 365-day or 366-day year, as the case may be. Interest on US dollar LIBOR loans is paid during each interest period at a rate per annum, calculated on a 360-day year, equal to the US dollar LIBOR rate with respect to such interest period plus the applicable pricing margin. 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. If our credit rating were to be downgraded by this rating agency, we would receive a 1% increase in our applicable pricing margin (as defined within the credit agreement).

The new 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, transferring or selling assets, making investments including acquisitions or paying dividends or redeeming shares of capital stock. We are also required to meet certain financial covenants defined in the credit agreement including: (i) Senior Leverage Ratio (Senior Leverage to Consolidated EBITDA) which must be less than 2.0 times, (ii) Consolidated Interest Coverage Ratio (Consolidated EBITDA to Consolidated Cash Interest Expense) which must be greater than 2.5 times, and (iii) Current Ratio (Current Assets to Current Liabilities) which must be greater than 1.25 times. 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. As a result of the revenue writedown on the Canadian Natural long-term overburden removal contract, discussed in the “Explanatory Notes—Significant Business Event” section of this MD&A, we were not in compliance with certain existing financial covenants as at March 31, 2011 on our credit agreement. On May 20, 2011, we received an amendment to our credit agreement, from our lenders, to exclude the $42.5 million revenue writedown on our long-term overburden removal contract with Canadian Natural when determining Consolidated EBITDA (as defined in our credit agreement) related covenant compliance. This amendment ensures that this revenue writedown will not result in a breach of Consolidated EBITDA (as defined in our credit agreement) related covenant compliance at March 31, 2011 or any future date. As a result of this amendment, we remain in compliance with all of the financial covenants on our credit agreement.

Financing fees of $1.0 million were incurred in connection with the fourth amended and restated credit agreement, dated April 30, 2010 and were recorded as deferred financing costs.

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), 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.


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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. Financing fees of $6.9 million were incurred in connection with the Series 1 Debentures and were recorded as deferred financing costs.

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

CAPITAL 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, 2011.


	Payments due by fiscal year
(dollars in thousands)	Total		2012		2013		2014		2015		2016 and after
Series 1 Debentures		$225,000		$ –		$ –		$ –		$ –		$225,000
Term facilities		68,446		10,000		10,000		48,446		–		–
Revolving facilities		3,524		–		–		3,524
Capital leases (including interest)		9,257		5,267		3,087		562		270		71
Equipment and building operating leases		190,125		71,399		51,896		38,508		21,871		6,451
Supplier contracts		51,956		14,997		14,997		19,489		2,473		–
Total contractual obligations		$548,308		$101,663		$79,980		$110,529		$24,614		$231,522

Off-balance sheet arrangements

We have no off-balance sheet arrangements in place at this time.

DEBT RATINGS

On May 25, 2011, following the announcement that we would take a revenue writedown on the long-term overburden removal contract with Canadian Natural Standard and Poor’s Ratings Services (“S&P”) affirmed our ‘B+’ long-term corporate credit rating and affirmed the senior unsecured debt rating of ‘B+’ and recovery rating of ‘3’ on our Series 1 Debentures. However, S&P did revise its outlook on our corporate rating to ‘Negative’ from ‘Stable’.

Moody’s Investor Services, Inc. (“Moody’s”) affirmed our corporate credit ratings in March 2010 and rated our Series 1 Debentures in April 2010. Moody’s is currently conducting its annual review of our ratings.


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Our credit ratings from these two agencies are as follows:


Category	Standard & Poor’s		Moody’s
Corporate Rating		B+ (‘negative’ outlook)		B2 (‘stable’ outlook)
Series 1 Debentures		B+ (recovery rating of “3”)		B3 (LGD^# rating of “5”)

#	Loss Given Default

A change in our credit ratings, particularly the rating issued by S&P, will affect the interest rate payable on borrowings under our credit agreement. 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.

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 as outlined below.¹⁷

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 “3” for the Series 1 Debentures indicates an expectation for an average of 50% to 70% recovery in the event of a payment default.

A Standard & Poor’s rating outlook assesses the potential direction of a long-term credit rating over the intermediate term (typically nine months to two years). In determining a rating outlook, consideration is given to any changes in the 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.

Moody’s

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

LGD assessments are opinions about expected loss given default on fixed income obligations expressed as a percent of principal and accrued interest at the resolution of the default. An LGD assessment (or rate) is the expected LGD divided

by the expected amount of principal and interest due at resolution. A LGD rating of “5” indicates a loss range of greater than or equal to 70% and less than 90%.

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

¹⁷	This information is current as of this report and we undertake no obligation to provide investors with updated information.


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RELATED PARTIES

The Sterling Group, L.P., Perry Strategic Capital Inc., and SF Holding Corp. are collectively “our Sponsors”. We may receive consulting and advisory services provided by our Sponsors (principals or employees of such Sponsors are directors of our company) with respect to the organization of our companies, employee benefit and compensation arrangements, and other matters, and no fee is charged for these consulting and advisory services.

In order for our Sponsors to provide such advisory and consulting services, we provide reports, financial data and other information to our Sponsors. This permits them to consult with and advise us on matters relating to our operations, company affairs and finances. In addition, this permits our Sponsors to visit and inspect any of our properties and facilities.

We provided shared service support for our joint venture nominee, Noramac Ventures Inc. for the first nine months of the fiscal year ended March 31, 2011.

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 time 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.

As of March 31, 2011, an evaluation was carried out under the supervision of and with the participation of management, including the President and Chief Executive Officer and the Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) under the US Securities Exchange Act of 1934, as amended, and in National Instrument 52-109 under the Canadian Securities Administrators Rules and Policies. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of the Evaluation Date such disclosure controls and procedures were effective.

Management’s Report on Internal Control over Financial Reporting

Internal control over financial reporting is a process designed to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and of the preparation of financial statements for external purposes in accordance with US GAAP. Management, including the President and Chief Executive Officer and Chief Financial Officer, are responsible for establishing and maintaining adequate internal control over financial reporting (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 statements will not be prevented or detected on a timely basis.

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

As of March 31, 2011, 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, 2011, our internal control over financial reporting is effective. Our independent auditor, KPMG LLP, has issued an audit report that we, as at March 31, 2011, 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

For the year ended March 31, 2010, we identified a material weakness in our ICFR, which was remediated during the year ended March 31, 2011, as follows:

In the year ended March 31, 2010, we did not maintain effective processes and controls specific to revenue recognition. We did not effectively develop, communicate and implement sufficient monitoring controls over the completeness and accuracy of forecasts, including the consideration of project changes subsequent to the end of each reporting period.

To remediate this material weakness in the current fiscal year we established a dedicated project team, led by a senior member of our Finance team. The project team developed and implemented standardized business practices and detection controls specific to improving the accuracy of forecasts. These remedies also integrated consideration of project changes subsequent to the end of each reporting period. The project team also established and implemented a revenue recognition policy and rolled out a training program and detection controls to improve the understanding and performance of timely cost recognition. Management is satisfied that these new practices and controls have remedied the issue and corrected our ICFR deficiencies.

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.


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Significant estimates made by us include the 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 impacting 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.

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, 2011 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 that 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


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to approve both the scope and price of the change. Occasionally, however, disagreements arise regarding changes, their nature, measurement, timing and other characteristics that impact costs and revenue under the contract. When a change becomes a point of dispute between us and a customer, we will then consider it as a claim.

Costs related to unapproved change orders and claims are recognized when they are incurred.

Revenues related to unapproved change orders and claims are included in total estimated contract revenue 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 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 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 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.

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.


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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, 2010. This impairment test showed that the fair value of the Piling reporting unit exceeded its carrying value.

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.

RECENTLY ADOPTED ACCOUNTING POLICIES

Improvements to financial reporting by enterprises involved with variable interest entities

In December 2009, the FASB issued ASU No. 2009-17, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities”, which amends ASC 810, “Consolidation”. The amendments give guidance and clarification of how to determine when a reporting entity should include the assets, liabilities, non-controlling interests and results of activities of a variable interest entity in its consolidated financial statements. We adopted this ASU effective April 1, 2010. The adoption of this standard did not have a material effect on our interim consolidated financial statements.

Embedded credit derivatives

In March 2010, the FASB issued ASU No. 2010-11, “Scope Exception Related to Embedded Credit Derivatives”, which clarifies that financial instruments that contain embedded credit-derivative features related only to the transfer of credit risk in the form of subordination of one instrument to another are not subject to bifurcation and separate accounting. The scope exception only applies to an embedded derivative feature that relates to subordination between tranches of debt issued by an entity and other features that relate to another type of risk must be evaluated for separation as an embedded derivative. We adopted this ASU effective July 1, 2010. The adoption of this standard did not have a material effect on our interim consolidated financial statements.


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RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

Revenue recognition

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

Share based payment awards

In April 2010, the FASB issued ASU No. 2010-13, “Effect of Denominating the Exercise Price of Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades”, which clarifies that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. This ASU will amend ASC 718, “Compensation-Stock Compensation” and it is effective for us beginning on April 1, 2011. We are currently evaluating the effect of this ASU on our interim 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. This ASU is effective for our fiscal year and interim periods beginning April 1, 2011. Early adoption is not permitted. The amendments in this ASU will have no 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. This ASU is effective prospectively for our business combinations for which the acquisition date is on or after April 1, 2011. Early adoption is permitted. This standard will impact disclosures made for our business combinations completed after the effective date.

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.

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

(a)	The expectation that the new escalation indices recommendation by the working group in the Canadian Natural long-term overburden removal contract will be made by August 31, 2011;

(b)	The expectation that it is probable that costs related to the Canadian Natural long-term overburden removal contract will be recovered;

(c)	The expectation that the acceptance by Canadian Natural of the adjustments to the long-term overburden removal contract indices is probable;

(d)	The expectation that upon resolution of the pricing issue with Canadian Natural it will be possible to reverse part or all of any profit writedown made;


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(e)	The expectation that the revenue writedown on the Canadian Natural long-term overburden contract will not have a negative impact on any of our other operations or have a material impact on our financial position;

(f)	The expectation that our capabilities will enable us to support our customers’ new oil sands developments and expansions and increasing volume of recurring services generated by existing oil sands mines;

(g)	The expectation that we will continue to provide construction services to in situ projects;

(h)	The expectation that demand for recurring oil sands services will continue to grow;

(i)	The expectation that the investment plans of Suncor and Syncrude could create opportunities for our new Tailings and Environmental Construction division;

(j)	The expectation that three of the four active oil sands mines will be operating throughout this year;

(k)	The expectation that we will benefit from increased construction spending in the private sector over the coming years as the economy continues to recover;

(l)	The expectation that rising demand outside the oil sands potentially reduces competitors looking for work in the oil sands;

(m)	The expectation that the mine development projects under consideration for permits and environmental approvals in British Columbia will create strong demand for mining and facility construction services;

(n)	The expectation that Canada’s power transmission sector will experience significant investment over the next decade;

(o)	The expectation that resource mining development activity will return to levels that prevailed prior to the economic downturn and capital investment will reach increased levels;

(p)	The expectation that economic conditions are expected to improve;

(q)	The expectation that near-term demand will increase, supporting improved pricing and reducing risk on new contracts;

(r)	The expectation that we will see a return to growth in recurring services revenue at existing mines as activity levels increase and projects move from construction to the operational phase;

(s)	The expectation that approximately $133.4 million of total backlog will be performed and realized in the 12 months ending March 31, 2012;

(t)	The expectation that we may experience some near-term impact to revenue as a result of the recently announced work suspension;

(u)	The expectation that we will work with Canadian Natural to identify any contract-related equipment that can be redeployed to other projects in the region;

(v)	The expectation that the redeployment of resources could partially offset the expected decline in revenues and positively impact margins and cash flow in the near-term;

(w)	The expectation that our outlook will continue to improve as a result of increasing investment in the oil sands, awarded and anticipated major contracts and strengthening of general economic conditions;

(x)	The expectation that the work scope under the three-year master services agreement with Shell could increase;

(y)	The expectation that we will be awarded a new five-year master services agreement by Suncor;

(z)	The expectation that revenue growth will continue to outpace margin growth in the near term but should improve as older contracts eventually expire and are replaced;

(aa)	The expectation that activity levels in the Piling segment will increase in fiscal 2012, that margins will recover more quickly for this division compared to other parts of our business and that fiscal 2012 will be a strong year for this segment;

(bb)	The expectation that business conditions relating to the Pipeline division will improve;

(cc)	The expectation that a settlement between IUOE and ARBHCA will be reached without disruption;

(dd)	The expectation that our capital needs in the current fiscal year will be approximately $90 million to $140 million;

(ee)

The expectation that our operating and capital lease facilities and cash flow from operations will be sufficient to meet our funding requirements, including capital requirements, debt service requirements and business operations requirements, and will allow us the flexibility to respond to adverse changes, including changes in interest rates as well as economic, industry and competitive conditions; and

(ff)	The expectation that we will generate a cash surplus from operations for the year ended March 31, 2012 to satisfy funding requirements, but if additional funding is needed, this would be satisfied by the funds available from our credit facilities;

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


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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” 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 Annual Information Form.

ASSUMPTIONS

The material factors or assumptions used to develop the above forward-looking statements include, but are not limited to:

•

The timely settlement of negotiations with Canadian Natural related to the escalation indices on the long-term overburden removal contract;

•

The demand for recurring services remaining strong;

•

The oil sands continuing to be an economically viable source of energy;

•

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;

•

Our clients have accurately gauged the impact of the delays related to the Suncor and Canadian Natural plant fires;

•

The Western Canadian economy continuing to develop and to receive additional investment in public construction;

•

The mine projects in British Columbia will generally be approved;

•

Our ability to benefit from increased recurring services revenue and projected development revenue tied to the operational activities of the oil sands;

•

Our ability to secure specific types of rental equipment to support project development activity will allow us to meet our customers’ variable service requirements while balancing the need to maximize utilization of our own equipment;

•

Our ability to access sufficient funds to meet our funding requirements will not be significantly impaired; and

•

Our success in executing our growth strategy, 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.

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. For further information on risks, including “Risks Related to Our Common Shares”, please refer to “Risks and Uncertainties” in our most recent Annual Information Form.

•

Negotiations with Canadian Natural for the changes in escalation indices on the long term overburden removal contract may not be successful, potentially leading to claims under the contract or termination of the contract.

As discussed in more detail in the “Explanatory Notes – Significant Business Event” section of this MD&A, we have formed a joint working group with Canadian Natural to establish revised indices on the long term overburden removal contract this customer. Although we believe the acceptance of the revised indices to be probable, if the review of the indices being undertaken by the working group does not support our position or if the parties are not able to agree upon the appropriate adjustments, there is the potential of claims under the contract or termination of the contract. This could lead to a further revenue writedown in respect of all or a portion of unbilled revenue of up to $72.0 million related to the contract, in which event we will pursue any remedies we may have available to us.¿

•

The suspension of work on Canadian Natural’s Horizon Oil Sands site may continue longer than anticipated.

As discussed in more detail in the “Explanatory Notes – Significant Business Event” section of this MD&A, we were notified on May 18, 2011 by Canadian Natural that we were to suspend overburden removal activities at their Horizon mine while Canadian Natural undertakes repairs to its primary upgrading facility, which was damaged in a fire in January 2011. The suspension of work notice is effective until January 2, 2012.

If Canadian Natural is not able to complete their repairs as scheduled or bring their primary upgrading facility back to full capacity by the end of 2011 it is possible that the Canadian Natural’s suspension of our overburden removal activity may extend beyond the original suspension notice date.

•

There can be no assurance that equipment or personnel on the Canadian Natural Horizon Oil Sands site can be redeployed on a cost-effective basis.

As a result of the recently announced work suspension on our long-term overburden removal contract with Canadian Natural, we intend to work with Canadian Natural to identify any equipment or personnel we can redeploy to other higher-margin projects in the region.

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


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While we believe that there is a demand for this equipment on our other operational sites, there can be no assurance that equipment or personnel on the Canadian Natural Horizon Oil Sands site can be redeployed on a cost-effective basis during the Canadian Natural work suspension.

•

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

Approximately 63%, 39% and 29% of our revenue for the fiscal years ended March 31, 2011, 2010 and 2009, 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 which 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 impact our results of operations, financial condition and cash flow.

•

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, 2011).

One such long term contract that contained price indices is our long term overburden removal contract with Canadian Natural. As a result of price escalators in this contract not accurately reflecting increases in our costs, we reduced revenue to total costs on the contract, reducing our operating income by $42.5 million for the three months and year ended March 31, 2011.

•

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.

•

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 impact


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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 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 our capital growth.

We have a substantial amount of debt outstanding and significant debt service requirements. As of March 31, 2011, we had outstanding $463.6 million of debt¹⁸, including $8.7 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.

•

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

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

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

•

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

¹⁸	Debt includes all liabilities with the exception of deferred income taxes


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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.

•

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 believe 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 which would adversely affect our prospects for revenues from capital projects and could have an adverse impact on our financial condition and results of operations.

•

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

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

•

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

Outsourced Heavy Construction and Mining services constitute a large portion of the work we perform for our customers. For example, our mining and site preparation project revenues constituted approximately 78%, 88% and 74% of our revenues in each of the years ended March 31, 2011, 2010 and 2009, respectively. The election by one or more of our customers to perform some or all of these services themselves, rather than outsourcing the work to us, could have a material adverse impact on our business and results of operations. Certain customers perform some of this work internally and may choose to expand on the use of internal resources to complete this work. Additionally, the recent tightening of the credit market and worldwide economic downturn may result in our customers reducing their spending on outsourced mining and site preparation services if they believe they can perform this work in a more cost effective and efficient manner using their internal resources.

•

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

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


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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.

•

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 which, 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 impacting 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 impacted 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 impacting the energy industry.

•

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

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

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


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•

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.

•

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.

•

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 $85.0 million, and at March 31, 2011, we had $12.3 million of issued letters of credit outstanding. One of our major contracts allows the customer to require up to $50.0 million in letters of credit. If we were unable to provide letters of credit in the amount requested by this customer, we could lose business from such customer and our business and cash flow would be adversely affected. If our capacity to issue letters of credit under our revolving credit facility and our cash on hand is insufficient to satisfy our customer’s requirements, our business and results of operations could be adversely affected.

•

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

More than 37% of our revenue for the year ended March 31, 2011 was derived from projects which we consider to be non-recurring. This revenue primarily relates to site preparation and piling services provided for the construction of extraction, upgrading and other oil sands mining infrastructure projects. There is no guarantee that the Company will find additional sources for generating non-recurring services revenue in fiscal 2012.

•

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

Most of our revenue comes from the provision of services to a small number of major oil sands mining companies. Revenue from our five largest customers represented approximately 77%, 89% and 92% of our total revenue for the fiscal years ended March 31, 2011, 2010 and 2009, respectively, and those customers are expected to continue to account for a significant percentage of our revenues in the future. In addition, the majority of our Pipeline revenues in the previous fiscal years resulted from work performed for one customer. If we lose or experience a significant reduction of business 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 which we are to perform under the contract. Our contracts also generally allow the customer to terminate the contract without cause and, in many cases, with minimal or no notice to us. Additionally, certain of these contracts provide for limited compensation following such suspension or termination 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.


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•

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 limit, among other things, our ability and the ability of our subsidiaries to:

•

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

•

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

•

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

•

issue equity securities of subsidiaries;

•

make certain investments or acquisitions;

•

create liens on our assets;

•

enter into transactions with affiliates;

•

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

•

transfer or sell assets, including shares of our subsidiaries.

Our 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.

•

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 which may, in turn, negatively impact 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.


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•

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.

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, 2011, 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, 2011, we held $72.0 million of floating rate debt pertaining to our Credit Facilities within our credit agreement (March 31, 2010 – $28.4 million). As at March 31, 2011, holding all other variables constant, a 100 basis point increase (decrease) to interest rates on floating rate debt would result in a $0.7 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, 2011.

H. 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 relating to us, including our Annual Information Form dated June 2, 2011, 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.


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North American Energy Partners Inc.

Canadian Supplement to Management’s Discussion and Analysis

For the year ended March 31, 2011

June 2, 2011

Summary of differences between US GAAP and Canadian GAAP

The annual consolidated financial statements for the year ended March 31, 2011 and the accompanying annual Management’s Discussion and Analysis (MD&A) have been prepared in accordance with United States (US) generally accepted accounting principles (GAAP). As required by National Instrument 52-107, for the fiscal year of adoption of US GAAP and one subsequent fiscal year, we are required to provide a Canadian Supplement to our MD&A that restates, based on financial information reconciled to Canadian GAAP, those parts of our MD&A that would contain material differences if they were based on financial statements prepared in accordance with Canadian GAAP. The Canadian Supplement to the MD&A should be read in conjunction with our annual financial statements and annual MD&A included in our annual report for the year ended March 31, 2011 prepared in accordance with US GAAP.

The material differences between US GAAP and Canadian GAAP on our financial position and results of operations for the year ended March 31, 2011 are explained and quantified in note 31 to our consolidated financial statements for the year ended March 31, 2011.

The “Consolidated Three Month Results” and “Consolidated Annual Results” tables in this supplement highlight the differences between Canadian and US GAAP. The tables in this supplement reporting the “Reconciliation of Net Income (Loss) to EBITDA and Consolidated EBITDA”, “Non-Operating Income and Expense” and “Realized and Unrealized (Gain) Loss on Derivative Financial Instruments” for the three months and year ended March 31, 2011 and “Summary of Consolidated Quarterly Results” are prepared in accordance with Canadian GAAP. Amounts included in this supplement are in millions of Canadian dollars, except per share information and amounts included in the tables.


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Consolidated Three Month Results


	Three Months Ended March 31,
(dollars in thousands, except per share information)	2011 (Canadian GAAP)			Adjustments			2011 (US GAAP)			2010 (Canadian GAAP)			Adjustments			2010 (US GAAP)
Revenue (e)		$176,599			$(2,089	)		$174,510			$222,374			$(1,805	)		$220,569
Project costs (e)		102,131			(3,748	)		98,383			94,015			(1,614	)		92,401
Equipment costs		64,753						64,753			61,493						61,493
Equipment operating lease expense		16,080						16,080			22,009						22,009
Depreciation (a)		12,654			28			12,682			11,912			31			11,943
Gross (loss) profit		(19,019	)		1,631			(17,388	)		32,945			(222	)		32,723
General and administrative expense (c) and (e)		14,740			(305	)		14,435			19,308			(204	)		19,104
Operating (loss) income		(35,724	)		272			(35,452	)		12,959			168			13,127
Net loss		$(29,441	)		$(1,011	)		$(30,452	)		$(2,963	)		$2,020			$(943	)
Per share information
Net loss–basic		$(0.81	)		$(0.03	)		$(0.84	)		$(0.08	)		$0.05			$(0.03	)
Net loss–diluted		$(0.81	)		$(0.03	)		$(0.84	)		$(0.08	)		$0.05			$(0.03	)
EBITDA		$(18,374	)		$(1,052	)		$(19,426	)		$18,157			$2,757			$20,914
Consolidated EBITDA (as defined within our credit agreement)		$23,871			$133			$24,004			$26,428			$ –			$26,428

Consolidated Annual Results


	Year Ended March 31,
(dollars in thousands, except per share information)	2011 (Canadian GAAP)			Adjustments			2011 (US GAAP)			2010 (Canadian GAAP)		Adjustments			2010 (US GAAP)
Revenue (e)		$864,146			$(6,098	)		$858,048			$763,301		$(4,336	)		$758,965
Project costs (e)		463,458			(7,339	)		456,119			304,849		(3,542	)		301,307
Equipment costs		234,933			–			234,933			209,408		–			209,408
Equipment operating lease expense		69,420			–			69,420			66,329		–			66,329
Depreciation (a)		39,329			111			39,440			42,512		124			42,636
Gross profit		57,006			1,130			58,136			140,203		(918	)		139,285
General and administrative expense (c) and (e)		60,043			(111	)		59,932			63,236		(706	)		62,530
Operating (loss) income		(10,056	)		(773	)		(10,829	)		72,811		663			73,474
Net (loss) income		$(25,686	)		$(8,964	)		$(34,650	)		$29,174		$(955	)		$28,219
Per share information
Net (loss) income–basic		$(0.71	)		$(0.25	)		$(0.96	)		$0.81		$(0.03	)		$0.78
Net (loss) income–diluted		$(0.71	)		$(0.25	)		$(0.96	)		$0.79		$(0.02	)		$0.77
EBITDA		$41,927			$(10,054	)		$31,873			$111,881		$452			$112,333
Consolidated EBITDA (as defined within our credit agreement)		$85,421			$(1,320	)		$84,101			$121,644		$ –			$121,644


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Reconciliation of Net (Loss) Income to EBITDA and Consolidated EBITDA (Canadian GAAP)


	Three Months Ended March 31,
(dollars in thousands)	2011			2010
Net loss		$(29,441	)		$(2,963	)
Adjustments:
Interest expense		7,086			5,709
Income taxes (benefit)		(10,141	)		3,010
Depreciation		12,654			11,912
Amortization of intangible assets		1,468			489
EBITDA		$(18,374	)		$18,157
Adjustments:
Unrealized foreign exchange gain on 8³/4% senior notes		–			(6,154	)
Realized and unrealized (gain) loss on derivative financial instruments		(3,137	)		13,946
Loss on disposal of property, plant and equipment and assets held for sale		497			189
Stock-based compensation expense		516			268
Equity in loss of unconsolidated joint venture		1,844			22
Revenue writedown on Canadian Natural project		42,525			–
Consolidated EBITDA (as defined within our credit agreement)		$23,871			$26,428


	Year Ended March 31,
(dollars in thousands)	2011			2010			2009
Net (loss) income		$(25,686	)		$29,174			$(137,877	)
Adjustments:
Interest expense		28,798			23,594			27,450
Income taxes (benefit)		(4,760	)		14,051			14,599
Depreciation		39,329			42,512			36,227
Amortization of intangible assets		4,246			2,550			2,338
EBITDA		$41,927			$111,881			$(57,263	)
Adjustments:
Unrealized foreign exchange (gain) loss on 8³/4% senior notes		–			(48,424	)		45,860
Realized and unrealized (gain) loss on derivative financial instruments		(8,107	)		54,411			(32,595	)
Loss on disposal of property, plant and equipment and assets held for sale		2,773			1,606			5,349
Stock-based compensation expense		2,144			2,214			1,895
Equity in loss (earnings) of unconsolidated joint venture		2,720			(44	)		–
Impairment of goodwill		–			–			176,200
Loss on debt extinguishment		1,439			–			–
Revenue writedown on Canadian Natural Project		42,525			–			–
Consolidated EBITDA (as defined within our credit agreement)		$85,421			$121,644			$139,446

Non-Operating Income and Expense (Canadian GAAP)


	Three Months Ended March 31,
(dollars in thousands)	2011			2010			Change
Interest expense
Interest on 8³/4% senior notes and swaps		$ –			$4,573			$(4,573	)
Interest on capital lease obligations		144			227			(83	)
Amortization of deferred financing costs		187			213			(26	)
Amortization of premium on Series 1 Debentures		(96	)		–			(96	)
Interest on credit facilities		1,681			990			691
Interest on Series 1 Debentures		5,133			–			5,133
Interest on long term debt		$7,049			$6,003			$1,046
Other interest		37			(294	)		331
Total interest expense		$7,086			$5,709			$1,377
Foreign exchange loss (gain)		31			(5,925	)		5,956
Realized and unrealized (gain) loss on derivative financial instruments		(3,137	)		13,946			(17,083	)
Other income		(122	)		(818	)		696
Income taxes (benefit)		(10,141	)		3,010			(13,151	)


2011 Annual Report		\| NOA \|			63


	Year Ended March 31
(dollars in thousands)	2011			2010			Change
Interest expense
Interest on 8³/4% senior notes and swaps		$1,238			$19,041			$(17,803	)
Interest on capital lease obligations		689			1,032			(343	)
Amortization of deferred financing costs		786			862			(76	)
Amortization of premium on Series 1 Debentures		(370	)		–			(370	)
Interest on credit facilities		5,361			2,375			2,986
Interest on Series 1 Debentures		20,132			–			20,132
Interest on long term debt		$27,836			$23,310			$4,526
Other interest		962			284			678
Total interest expense		$28,798			$23,594			$5,204
Foreign exchange gain		(1,659	)		(48,405	)		46,746
Realized and unrealized (gain) loss on derivative financial instruments		(8,107	)		54,411			(62,518	)
Loss on debt extinguishment		1,462			–			1,462
Other income		(104	)		(14	)		(90	)
Income taxes (benefit)		(4,760	)		14,051			(18,811	)

Realized and Unrealized (Gain) Loss on Derivative Financial Instruments (Canadian GAAP)


	Three Months Ended March 31,
(dollars in thousands)	2011			2010		Change
Swap liability loss		$ –			$6,344		$(6,344	)
Redemption option embedded derivative loss on 8³/4% senior notes		–			2,602		(2,602	)
Redemption options embedded derivatives gain on the Series 1 Debentures		(1,172	)		–		(1,172	)
Supplier contracts embedded derivatives (gain) loss		(1,686	)		643		(2,329	)
Customer contract embedded derivative (gain) loss		(279	)		190		(469	)
Swap interest payment		–			4,167		(4,167	)
Total		$(3,137	)		$13,946		$(17,083	)


	Year Ended March 31
(dollars in thousands)	2011			2010			Change
Swap liability loss		$1,783			$49,078			$(47,295)
Redemption option embedded derivative gain on 8³/4% senior notes		—			(3,716	)		3,716
Redemption options embedded derivatives gain on the Series 1 Debentures		(5,802	)		—			(5,802	)
Supplier contracts embedded derivatives gain		(3,812	)		(13,315	)		9,503
Customer contract embedded derivative (gain) loss		(604	)		6,805			(7,409	)
Swap interest payment		328			15,559			(15,231	)
Total		$(8,107)			$54,411			$(62,518)

Summary of Consolidated Quarterly Results (Canadian GAAP)


(dollars in millions)	March 31, 2011			Dec 31, 2010		Sept 30, 2010		June 30, 2010			March 31, 2010			Dec 31, 2009		Sept 30, 2009		June 30, 2009
	Fiscal 2011										Fiscal 2010
Revenue		$176.6			$266.1		$235.7		$185.8			$222.4			$222.7		$171.1		$147.1
Gross (loss) profit		(19.0	)		30.9		29.3		15.8			32.9			48.1		33.7		25.5
Operating (loss) income		(35.7	)		11.3		13.4		0.9			13.0			31.1		18.8		10.0

Net (loss) income		(29.4	)		5.4		5.6		(7.3	)		(3.0	)		15.6		6.5		10.1
Net (loss) income per share – Basic		$(0.81)			$0.15		$0.16		$(0.20	)		$(0.08	)		$0.43		$0.18		$0.28
Net (loss) income per share – Diluted		$(0.81)			$0.15		$0.15		$(0.20	)		$(0.08	)		$0.43		$0.18		$0.28

Canadian and United States accounting policies differences

A detailed reconciliation of our results for the years ended March 31, 2011, 2010 and 2009 are included in note 31 to our consolidated financial statements for the years ended March 31, 2011, 2010 and 2009.


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The differences between US GAAP and Canadian GAAP that have the most significant impact on our financial position and results of operations for the three months and year ended March 31, 2011, include accounting for: capitalization of interest, financing costs, discounts and premiums, derivative financial instruments and stock-based compensation.

a) Capitalization of interest

US GAAP requires capitalization of interest costs as part of the historical cost of acquiring certain qualifying assets that require a period of time to prepare for their intended use. This is not required under Canadian GAAP. The capitalized amount is subject to depreciation in accordance with our policies when the asset is placed into service.

b) Financing costs, discounts and premiums

Under US GAAP, deferred financing costs incurred in connection with our 9.125% Series 1 Debentures and our 8³/4% senior notes were being amortized over the term of the related debt using the effective interest method. Prior to April 1, 2007, the transaction costs on the 8³/4% senior notes were recorded as a deferred asset under Canadian GAAP and these deferred financing costs were being amortized on a straight-line basis over the term of the debt.

Effective April 1, 2007, we adopted CICA Handbook Section 3855, “Financial Instruments — Recognition and Measurement”, on a retrospective basis without restatement. Although Section 3855 also requires the use of the effective interest method to account for the amortization of finance costs, the requirement to bifurcate the issuer’s early prepayment option on issuance of debt (which is not required under US GAAP) resulted in an additional premium of $3.5 million on the Series 1 Debentures that is being amortized over the term of the Series 1 Debentures under Canadian GAAP. The same was being done on the extinguished 8³/4% senior notes. The unamortized premium is disclosed as part of the carrying amount of the “Series 1 Debentures” in the Consolidated Balance Sheets. Foreign denominated transaction costs, discounts and premiums on the 8³/4% senior notes were considered as part of the carrying value of the related financial liability under Canadian GAAP and were subject to foreign currency gains or losses resulting from periodic translation procedures as they were treated as a monetary item under Canadian GAAP. Under US GAAP, foreign denominated transaction costs are considered non-monetary and are not subject to foreign currency gains and losses resulting from periodic translation procedures. The unamortized discounts and premiums on the 8³/4% senior notes were expensed on the settlement of the 8³/4% senior notes under both Canadian and US GAAP with a difference of $2.9 million.

In connection with the adoption of Section 3855, transaction costs incurred in connection with our amended and restated credit agreement of $1.6 million were reclassified from deferred financing costs to intangible assets on April 1, 2007 under Canadian GAAP and these costs continued to be amortized on a straight-line basis over the term of the credit facilities. Under US GAAP, we continue to amortize these transaction costs over the stated term of the related facilities using the effective interest method. We disclose the unamortized deferred financing costs related to the Series 1 Debentures, the 8³/4% senior notes and the credit facilities as “Deferred financing costs” on the Consolidated Balance Sheets (March 31, 2011—$7.7 million; March 31, 2010—$6.7 million) with the amortization charge classified as “Interest expense” on the Consolidated Statement of Operations and Comprehensive (Loss) Income. Under Canadian GAAP, the unamortized financing costs related to the Series 1 Debentures (March 31, 2011—$6.2 million) and the 8³/4% senior notes (March 31, 2010—$1.5 million) are included in “Series 1 Debentures” and “8³/4% senior notes” respectively whilst the unamortized deferred financing costs in connection with the credit facilities (March 31, 2011—$1.4 million; March 31, 2010—$1.1 million) are included in “Intangible assets” on the Consolidated Balance Sheets resulting in a Canadian and US GAAP presentation difference.

c) Stock-based compensation

Up until April 1, 2006, we followed the provisions of ASC 718, “Compensation-Stock Compensation”, for US GAAP purposes. As we use the fair value method of accounting for all stock-based compensation payments under Canadian GAAP, there were no differences between Canadian and US GAAP prior to April 1, 2006. On April 1, 2006, we adopted the provisions of SFAS No. 123(R), “Share-Based Payment”, which is now a part of ASC 718. As we used the minimum value method for purposes of complying with ASC 718, we were required to adopt the provisions under the revised guidance prospectively. Under Canadian GAAP, we were permitted to exclude volatility from the determination of the fair value of stock options granted until the filing of our initial registration statement relating to our initial public offering of voting shares on July 21, 2006. As a result, for options issued between April 1, 2006 and July 21, 2006, there is a difference between Canadian and US GAAP relating to the determination of the fair value of options granted.

On September 22, 2010, we 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 changing classification from equity to a long term liability. Under US GAAP, such modification is measured at fair value using a model such as Black-Scholes. Under Canadian GAAP, stock options that are cash settled are measured at the amount by which the quoted market value of the shares of our stock covered by the grant exceeds the option price. This resulted in a measurement difference between US and Canadian GAAP. At March 31, 2011, the liability under US GAAP was measured at $5.1 million of which $2.2 million was transferred from additional paid-in capital and the difference of $2.9 million was recognized as incremental compensation cost in the Consolidated Statements of Operations under General and administrative expense. Under Canadian GAAP, the liability was measured at $3.8 million resulting in a transfer of the same amount from additional paid-in capital and the difference of $1.6 million was recognized as incremental compensation cost.


2011 Annual Report		\| NOA \|			65

d) Derivative financial instruments

Under Canadian GAAP, we determined that the issuer’s early prepayment option included in the Series 1 Debentures of $3.9 million should be bifurcated from the host contract, along with a contingent embedded derivative liability of $0.4 million in the Series 1 Debentures that provide for accelerated redemption by the holders in certain instances (as defined in the trust indenture that governs the Series 1 Debentures). These embedded derivatives were measured at fair value at April 7, 2010, the inception date of the Series 1 Debentures and the residual amount of the proceeds was allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of the Series 1 Debentures is accreted to par value over the term of the Series 1 Debentures using the effective interest method and is recognized as interest expense as discussed in b) above. The same accounting treatment was used on the extinguished 8³/4% senior notes.

Under US GAAP, ASC 815, “Derivatives and Hedging”, establishes accounting and reporting standards requiring that every derivative instrument, including certain derivative instruments embedded in other contracts and debt instruments, be recorded on the balance sheet as either an asset or liability measured at its fair value. The contingent embedded derivative in the Series 1 Debentures that provides for accelerated redemption by the holders in certain instances (as defined in the trust indenture that governs the Series 1 Debentures) did not meet the criteria for bifurcation from the debt contract and separate measurement at fair value and was not bifurcated from the host contract and measured at fair value resulting in a US GAAP and Canadian GAAP difference. The contingent embedded derivative in the 8³/4% senior notes that provide for accelerated redemption by the holders in certain instances met the criteria for bifurcation from the debt contract and separate measurement at fair value. The embedded derivative was measured at fair value and changes in fair value recorded in net income for all periods presented. The issuer’s early prepayment option included in both the Series 1 Debentures (as defined in the trust indenture that governs the Series 1 Debentures) and the 8³/4% senior notes did not meet the criteria as an embedded derivative under ASC 815 and was not bifurcated from the host contract resulting in a US GAAP and Canadian GAAP difference.

e) Joint venture

Under US GAAP, we record our share of earnings of the JV using the equity method of accounting. Under Canadian GAAP, we use the proportionate consolidation method of accounting for the JV. Under the proportionate consolidation method, we recognize our share of the results of operations, cash flows, and financial position of the JV on a line-by-line basis in our consolidated financial statements. While there is no impact on net income or earnings per share as a result of the US GAAP treatment of the joint venture, as compared to Canadian GAAP, there are presentation differences affecting the disclosures in the consolidated financial statements and supporting notes.

f) Other matters

Other adjustments relate to the tax effect of items (a) through (d) above. The tax effects of temporary differences are described as future income taxes under Canadian GAAP whereas in these financial statements such amounts are described as deferred income taxes under US GAAP. In addition, Canadian GAAP generally refers to additional paid-in capital as contributed surplus for financial statement presentation purposes.

Management’s Discussion and Analysis under US GAAP

Please refer to our annual report for March 31, 2011 for our corresponding MD&A under US GAAP. The differences between US GAAP and Canadian GAAP, described above, affect the discussion and analysis in several sections of our annual MD&A.

Additional information

Additional information relating to our business, including our Annual Information Form (AIF) dated June 2, 2011, are available on the Canadian Securities Administrators’ SEDAR System at www.sedar.com, the Securities and Exchange Commission’s website at www.sec.gov and our company web site at www.nacg.ca.


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MANAGEMENT’S REPORT

The accompanying consolidated financial statements and all of the information in Management’s Discussion and Analysis (MD&A) are the responsibility of management of the Company. The consolidated financial statements were prepared by management in accordance with generally accepted accounting principles. Where alternative accounting methods exist, management has chosen those it considers most appropriate in the circumstances. The significant accounting policies used are described in note 2 to the consolidated financial statements. Certain amounts in the financial statements are based on estimates and judgments relating to matters not concluded by year end. The integrity of the information presented in the consolidated financial statements is the responsibility of management.

The Board of Directors is responsible for ensuring that management fulfills its responsibilities and for approval of the consolidated financial statements. The board carries out this responsibility through its Audit Committee. The Board has appointed an Audit Committee comprising three independent directors. The Audit Committee meets at least four times each year to discharge its responsibilities under a written mandate from the Board of Directors. The Audit Committee meets with management and with external auditors to satisfy itself that they are properly discharging their responsibilities; reviews the consolidated financial statements, MD&A, and the Report of Independent Registered Public Accounting Firm on the financial statements; and examines other auditing and accounting matters. The Audit Committee has reviewed the consolidated financial statements with management and discussed the quality of the accounting principles as applied and significant judgments affecting the consolidated financial statements. The Audit Committee has discussed with the external auditors, the external auditors’ judgments of the quality of those principles as applied and the judgments noted above. The consolidated financial statements and the MD&A have been reviewed by the Audit Committee and approved by the Board of Directors of North American Energy Partners Inc.

The consolidated financial statements have been examined by the shareholders’ auditors, KPMG LLP, Chartered Accountants. The Report of Independent Registered Public Accounting Firm on the financial statements outlines the nature of their examination and their opinion on the consolidated financial statements of the Company. The external auditors have full and unrestricted access to the Audit Committee.

Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining an adequate system of internal control over financial reporting. The 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. Management conducted an evaluation of the effectiveness of the system of internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that the Company’s system of internal control over financial reporting was effective as of March 31, 2011. The details of this evaluation and conclusion are documented in the MD&A.

KPMG LLP, which has audited the consolidated financial statements of the Company for the year ended March 31, 2011, has also issued a report stating its opinion that the Company has maintained effective internal control over financial reporting as of March 31, 2011 based on the criteria established in Internal Control – Integrated Framework issued by the COSO.





Rodney J. Ruston				David Blackley
President and Chief Executive Officer				Chief Financial Officer
June 2, 2011				June 2, 2011


2011 Annual Report		\| NOA \|			67

KPMG LLP

Chartered Accountants

10125 – 102 Street

Edmonton AB T5J 3V8

Canada

Telephone

Fax

Internet

(780) 429-7300

(780) 429-7379

www.kpmg.ca

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, 2011, 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, 2011. 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, 2011, 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, 2011 and 2010, 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, 2011, and our report dated June 2, 2011, expressed an unqualified opinion on those consolidated financial statements.

LOGO

Chartered Accountants

Edmonton, Canada

June 2, 2011

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.


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NAEP

KPMG LLP

Chartered Accountants

10125 – 102 Street

Edmonton AB T5J 3V8

Canada

Telephone

Fax

Internet

(780) 429-7300

(780) 429-7379

www.kpmg.ca

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, 2011 and 2010, 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, 2011, 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 entity’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 financial position of North American Energy Partners Inc. as at March 31, 2011 and 2010 and its consolidated results of operations and its consolidated cash flows for each of the years in the three-year period ended March 31, 2011 in accordance with US generally accepted accounting principles.

Other Matter

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the North American Energy Partners Inc.’s internal control over financial reporting as of March 31, 2011, 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 2, 2011 expressed an unmodified opinion on the effectiveness of the North American Energy Partners Inc.’s internal control over financial reporting.

LOGO

Chartered Accountants

Edmonton, Canada

June 2, 2011

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.


2011 Annual Report		\| NOA \|			69

Consolidated Balance Sheets

As at March 31

(Expressed in thousands of Canadian Dollars)


	2011			2010
Assets
Current assets
Cash and cash equivalents		$722			$103,005
Accounts receivable, net (note 7 and 22(d))		128,482			111,884
Unbilled revenue (note 8)		102,939			84,702
Inventories (note 9)		7,735			3,047
Prepaid expenses and deposits (note 10)		8,269			6,881
Investment in and advances to unconsolidated joint venture (note 11)		1,488			–
Deferred tax assets (note 18)		1,729			3,481
		251,364			313,000
Property, plant and equipment, net (note 13)		321,864			331,355
Other assets (note 12(a))		26,908			22,154
Goodwill (note 5)		32,901			25,111
Deferred tax assets (note 18)		49,920			15,300
Total Assets		$682,957			$706,920
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable		$86,053			$66,876
Accrued liabilities (note 14)		32,814			47,191
Billings in excess of costs incurred and estimated earnings on uncompleted contracts
(note 8)		2,004			1,614
Current portion of capital lease obligations (note 15)		4,862			5,053
Current portion of term facilities (note 16(b))		10,000			6,072
Current portion of derivative financial instruments (note 22(a))		2,474			22,054
Deferred tax liabilities (note 18)		27,612			16,781
		165,819			165,641
Capital lease obligations (note 15)		3,831			8,340
Long term debt (note 16(a))		286,970			225,494
Derivative financial instruments (note 22(a))		9,054			75,001
Other long term obligations (note 17(a))		25,576			19,642
Deferred tax liabilities (note 18)		44,441			31,744
		535,691			525,862
Shareholders’ equity
Common shares (authorized – unlimited number of voting common shares; issued and outstanding – March 31, 2011 – 36,242,526 (March 31, 2010 – 36,049,276) (note 19(a))		304,854			303,505
Additional paid-in capital		7,007			7,439
Deficit		(164,536	)		(129,886	)
Accumulated other comprehensive loss		(59	)		–
		147,266			181,058
Total liabilities and shareholders’ equity		$682,957			$706,920
Commitments (note 26)
Contingencies (note 29)

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.


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Consolidated Statements of Operations and Comprehensive (Loss) Income

For the years ended March 31

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


	2011			2010			2009
Revenue		$858,048			$758,965			$972,536
Project costs		456,119			301,307			505,026
Equipment costs		234,933			209,408			217,120
Equipment operating lease expense		69,420			66,329			43,583
Depreciation		39,440			42,636			36,389
Gross profit		58,136			139,285			170,418
General and administrative expenses		59,932			62,530			74,460
Loss on disposal of property, plant and equipment		1,948			1,233			5,325
Loss on disposal of assets held for sale (note 12(b))		825			373			24
Amortization of intangible assets (note 12(c))		3,540			1,719			1,501
Equity in loss (earnings) of unconsolidated joint venture (note 11)		2,720			(44	)		–
Impairment of goodwill (note 5)		–			–			176,200
Operating (loss) income before the undernoted		(10,829	)		73,474			(87,092	)
Interest expense, net (note 20)		29,991			26,080			29,612
Foreign exchange (gain) loss		(1,659	)		(48,901	)		47,272
Realized and unrealized (gain) loss on derivative financial instruments (note 22(a))		(2,305	)		54,411			(37,250	)
Loss on debt extinguishment (note 16(c))		4,346			–			–
Other income		(104	)		(14	)		(5,955	)
(Loss) income before income taxes		(41,098	)		41,898			(120,771	)
Income taxes (note 18):
Current		2,892			3,803			5,546
Deferred		(9,340	)		9,876			9,087
Net (loss) income		(34,650	)		28,219			(135,404	)
Other comprehensive loss
Unrealized foreign currency translation loss		59			–			–
Comprehensive (loss) income		(34,709	)		28,219			(135,404	)
Net (loss) income per share – basic (note 19(b))		$(0.96	)		$0.78			$(3.76	)
Net (loss) income per share – diluted (note 19(b))		$(0.96	)		$0.77			$(3.76	)

See accompanying notes to consolidated financial statements.


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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, 2008

$301,894

$4,351

$(22,701

)

$–

$283,544

Net loss

–

(135,404

)

–

(135,404

)

Share option plan

–

1,888

–

1,888

Deferred performance share unit plan

–

Reclassification on exercise of stock options

834

(834

)

–

Issued upon exercise of stock options

703

–

703

Balance at March 31, 2009

$303,431

$5,466

$(158,105)

$–

$150,792

Net income

–

28,219

–

28,219

Share option plan

–

2,135

–

2,135

Deferred performance share unit plan

–

123

–

123

Reclassified to restricted share unit liability

–

(20

)

–

(20

)

Reclassification on exercise of stock options

(21

)

–

Cash settlement of stock options

–

(244

)

–

(244

)

Issued upon exercise of stock options

–

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

Reclassification on exercise of stock options

386

(386

)

–

Issued upon exercise of stock options

963

–

963

Senior executive stock option plan

–

(2,237

)

–

(2,237

)

Balance at March 31, 2011

$304,854

$7,007

$(164,536)

$(59)

$147,266

See accompanying notes to consolidated financial statements.


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Consolidated Statements of Cash Flows

For the years ended March 31

(Expressed in thousands of Canadian Dollars)


	2011			2010			2009
Cash (used in) provided by:
Operating activities:
Net (loss) income for the period		$(34,650	)		$28,219			$(135,404	)
Items not affecting cash:		–			–			–
Depreciation		39,440			42,636			36,389
Equity in loss (earnings) of unconsolidated joint venture (note 11)		2,720			(44	)		–
Amortization of intangible assets (note 12(c))		3,540			1,719			1,501
Impairment of goodwill (note 5)		–			–			176,200
Amortization of deferred lease inducements (note 17(b))		(107	)		(107	)		(105	)
Amortization of deferred financing costs (note 12(d))		1,609			3,348			2,970
Loss on disposal of property, plant and equipment		1,948			1,233			5,325
Loss on disposal of assets held for sale (note 12(b))		825			373			24
Realized and unrealized foreign exchange (gain) loss on 8³/4% senior notes		(732	)		(48,920	)		46,466
Unrealized (gain) loss on derivative financial instruments measured at fair value		(2,305	)		38,852			(39,921	)
Loss on debt extinguishment (note 16(c))		4,346			–			–
Stock-based compensation expense (note 28(a))		8,156			5,270			2,305
Cash settlement of stock options (note 28(b))		–			(244	)		–
Accretion of asset retirement obligation (note 17(c))		35			5			155
Deferred income taxes (benefit) (note 18)		(9,340	)		9,876			9,087
Net changes in non-cash working capital (note 23(b))		(15,982	)		(39,591	)		46,193
		(497	)		42,625			151,185
Investing activities:
Acquisition, net of cash acquired (note 6)		(23,501	)		(5,410	)		–
Purchase of property, plant and equipment		(36,417	)		(51,888	)		(87,102	)
Additions to intangible assets (note 12(c))		(4,748	)		(3,362	)		(3,102	)
Investment in and advances to unconsolidated joint venture (note 11)		(1,291	)		(2,873	)		–
Proceeds on disposal of property, plant and equipment		499			1,440			11,164
Proceeds on disposal of assets held for sale		826			2,482			325
		(64,632	)		(59,611	)		(78,715	)
Financing activities:
Repayment of credit facilities		(85,000	)		(6,906	)		–
Increase in credit facilities		128,524			34,700			–
Financing costs (note 16(b) and (d))		(7,920	)		(1,123	)		–
Redemption of 8³/4% senior notes (note 16(c))		(202,410	)		–			–
Issuance of Series 1 Debentures (note 16(d))		225,000			–			–
Settlement of swap liabilities (note 22(a))		(91,125	)		–			–
Proceeds from stock options exercised (note 28(b))		963			53			703
Repayment of capital lease obligations		(5,127	)		(5,613	)		(6,156	)
		(37,095	)		21,111			(5,453	)
(Decrease) increase in cash and cash equivalents		(102,224	)		4,125			67,017
Effect of exchange rate on changes in cash		(59	)		–			–
Cash and cash equivalents, beginning of year		103,005			98,880			31,863
Cash and cash equivalents, end of year		$722			$103,005			$98,880

Supplemental cash flow information (note 23(a))

See accompanying notes to consolidated financial statements.


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Notes to Consolidated Financial Statements

For the years ended March 31, 2011, 2010, 2009

(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. Material items that give rise to measurement and disclosure differences to the consolidated financial statements under Canadian GAAP are outlined in note 31.

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., North American Major Mining Projects Inc., North American Construction Management Inc. and NACG Properties Inc., and the following 100% owned subsidiaries of NACGI:


• 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 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 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 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);


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•

extended overhead due to owner, weather and other delays (to the extent contract remedies are unavailable);

•

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 (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. 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.

•

a bona fide addition to contract value; and

•

revenues can be reliably estimated.

These two conditions are satisfied when:

•

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.


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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 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
Assets under capital lease	Declining balance	30%


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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.


2011 Annual Report		\| NOA \|			77

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


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period of enactment. The Company recognizes the effect of income tax positions only if those positions are more likely than not (greater than 50%) of being sustained. Changes in recognition or measurement are reflected in the period in which the change in judgement occurs. The Company accrues interest and penalties for uncertain tax positions in the period in which these uncertainties are identified. Interest and penalties are included in “Other income” in the Consolidated Statements of Operations. 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 28(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 28(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 28(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 a Restricted Share Unit (“RSU”) Plan which is described in note 28(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 28(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 28(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 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.

v) Net income (loss) per share

Basic net income (loss) per share is computed by dividing net income available to common shareholders by the weighted average number of shares outstanding during the year (see note 19(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


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achievement of specified targets 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.

3. United States accounting pronouncements recently adopted

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

In December 2009, the FASB issued ASU No. 2009-17, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities”, which amends ASC 810, “Consolidation”. The amendments give guidance and clarification on how to determine when a reporting entity should include the assets, liabilities, non-controlling interests and results of activities of a variable interest entity in its consolidated financial statements. The Company adopted this ASU effective April 1, 2010. The adoption of this standard did not have a material effect on the Company’s consolidated financial statements.

b) Embedded credit derivatives

In March 2010, the FASB issued ASU No. 2010-11, “Scope Exception Related to Embedded Credit Derivatives”, which clarifies that financial instruments that contain embedded credit-derivative features related only to the transfer of credit risk in the form of subordination of one instrument to another are not subject to bifurcation and separate accounting. The scope exception only applies to an embedded derivative feature that relates to subordination between tranches of debt issued by an entity and other features that relate to another type of risk must be evaluated for separation as an embedded derivative. The Company adopted this ASU effective July 1, 2010. The adoption of this standard did not have a material effect on the Company’s consolidated financial statements.

4. Recent United States accounting pronouncements not yet 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. For the Company, this ASU is effective prospectively for revenue arrangements entered into or materially modified on or after April 1, 2011. The adoption of this ASU will 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. This ASU will amend ASC 718, “Compensation – Stock Compensation” and it is effective for the Company beginning on April 1, 2011. The adoption of this ASU will not have a material effect on the Company’s consolidated financial statements.

c) Intangibles – Goodwill and Other


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qualitative factors indicating that impairment may exist. For the Company, this ASU is effective for the fiscal year and interim periods beginning April 1, 2011. The adoption of this ASU will 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. For the Company, this ASU is effective prospectively for business combinations for which the acquisition date is on or after April 1, 2011. This standard will impact disclosures made for business combinations completed by the Company after the effective date.

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, 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, 2010 and March 31, 2011.

The changes in goodwill during the years ended March 31, 2011, 2010 and 2009 are as follows:


Balance at March 31, 2008	$200,072
Impairment of goodwill (assigned to Pipeline segment)	(32,753	)
Impairment of goodwill (assigned to Heavy Construction and Mining segment)	(125,447	)
Impairment of goodwill (assigned to Piling segment)	(18,000	)
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	$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 gains access to screw piling, pipeline anchor design and manufacturing capabilities in Canada and the United States. The Company also gains 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

The revenue and net loss of Cyntech since acquisition on November 1, 2010 included in the Consolidated Statements of Operations and Comprehensive (Loss) Income for the year ended March 31, 2011 are $7,286 and $(1,588) respectively.

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 gives the Company access to piling markets and customers in the Toronto area. The transaction was accounted


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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 recognized amounts of assets acquired and liabilities assumed at the acquisition date are as follows:


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

c) Acquisitions in fiscal 2009

The Company did not acquire any businesses in fiscal 2009.

7. Accounts receivable


	March 31, 2011			March 31, 2010
Accounts receivable – trade		$115,660			$103,311
Accounts receivable – holdbacks		12,018			3,899
Income and other taxes receivable		397			4,486
Accounts receivable – other		437			1,879
Allowance for doubtful accounts (note 22(d))		(30	)		(1,691	)
		$128,482			$111,884

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 $587 as of March 31, 2011 (March 31, 2010—$727) 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, 2011			March 31, 2010
Costs incurred and estimated earnings on uncompleted contracts		$946,482			$1,193,821
Less billings to date		(845,547	)		(1,110,733	)
		$100,935			$83,088

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


	March 31, 2011			March 31, 2010
Unbilled revenue		$102,939			$84,702
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		(2,004	)		(1,614	)
		$100,935			$83,088

An amount of $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, 2011		March 31, 2010
Spare tires		$3,794		$1,868
Job materials		2,118		1,179
Manufacturing raw materials		926		–
Finished goods		897		–
		$7,735		$3,047


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10. Prepaid expenses and deposits


Current:
	March 31, 2011		March 31, 2010
Prepaid insurance and property taxes		$1,022		$920
Prepaid lease payments		6,203		5,678
Prepaid interest		1,044		283
		$8,269		$6,881
Long term:
	March 31, 2011		March 31, 2010
Prepaid lease payments (note 12(a))		$2,354		$4,005

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, 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 year ended March 31, 2011.

As of March 31, 2011, the Company’s investment in and advances to the unconsolidated joint venture totalled $1,488 (2010 – $2,917; 2009 – $nil). The condensed financial data for investment in and advances to unconsolidated joint venture is summarized as follows:


	March 31, 2011		March 31, 2010
Current assets		$8,328		$8,952
Long term assets		–		153
Current liabilities		13,875		3,271
Long term liabilities		–		5,940


Year ended March 31,	2011		2010
Gross revenues		$12,196		$8,774
Gross loss (profit)		2,483		(1,610	)
Net loss (income)		5,440		(87	)
Equity in loss (earnings) of unconsolidated joint venture		$2,720		$(44	)

12. Other assets

a) Other assets are as follows:


	March 31, 2011		March 31, 2010
Prepaid lease payments (note 10)		$2,354		$4,005
Assets held for sale (note 12(b))		721		838
Intangible assets (note 12(c))		16,161		7,669
Deferred financing costs (note 12(d))		7,672		6,725
Investment in and advances to unconsolidated joint venture (note 11)		–		2,917
		$26,908		$22,154

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 average operating cost for the fleet, the unit is deemed ready for disposal. Also, if the expected reliability is lower than the average reliability of the fleet, the unit is deemed ready for disposal. If either of these conditions is met the unit is disposed. Expected operating costs and reliability are based on the past history of the unit and experience in the various operating environments. Assets held for sale are sold on the Company’s used equipment website and syndicated on third party equipment sale websites. If a sale is not realized after a reasonable length of time, the equipment will be sent to auction for disposal.


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During the year ended March 31, 2011, impairments of assets held for sale amounting to $141 have been included in depreciation expense in the Consolidated Statements of Operations (2010 – $806; 2009 – $883). The impairment charge is the amount by which the carrying value of the related assets exceeded their fair value less costs to sell. Loss on disposal of assets held for sale was $825 for the year ended March 31, 2011 (2010 – $373; 2009 – $24).

c) Intangible assets


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


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

During the year ended March 31, 2011, the Company capitalized $4,748 (2010 – $3,362) related to internally developed computer software. There was no write off of internal-use software included in amortization of intangible assets during the year ended March 31, 2011 (2010 – $208; 2009 – $nil).

Amortization of intangible assets for the year ended March 31, 2011 was $3,540 (2010 – $1,719; 2009 – $1,501). The estimated amortization expense for future years is as follows:


For the year ending March 31,
2012			$4,576
2013			4,217
2014			3,564
2015			2,039
2016 and thereafter			1,765
			$16,161

During the year ended March 31, 2011, $7,284 in additions, summarized in the table below, 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)).


Patents			$2,017
Customer relationships			3,818
Non-compete agreements			592
Cyntech brand name			857
			$7,284

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, 2011	Cost		Accumulated Amortization		Net Book Value
8³/4% senior notes		$16,521		$16,521		$–
Term and revolving facilities		5,362		3,855		1,507
Series 1 Debentures		6,886		721		6,165
		$28,769		$21,097		$7,672


March 31, 2010	Cost		Accumulated Amortization		Net Book Value
8³/4% senior notes		$16,521		$12,014		$4,507
Term and revolving facilities		4,328		3,150		1,178
Series 1 Debentures		1,040		–		1,040
		$21,889		$15,164		$6,725


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Amortization of deferred financing costs included in interest expense for the year ended March 31, 2011 was $1,609 (2010 – $3,348; 2009 – $2,970).

Upon redemption of the 8³/4% senior notes on April 28, 2010, the unamortized deferred financing costs related to the 8³/4% senior notes of $4,324 were expensed and included in the loss on debt extinguishment (note 16(c)). In addition, $183 related to amortization of deferred financing costs incurred up to the redemption date was included in interest expense.

During the year ended March 31, 2011, financing fees of $5,846 were incurred in connection with the issuance of the Series 1 Debentures (2010 – $1,040) (note 16(d)) and financing fees of $1,034 were incurred in connection with the modifications made to the amended and restated credit agreement (2010 – $1,123; 2009 – $nil) (note 16(b)).

13. Property, plant and equipment


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


March 31, 2010	Cost		Accumulated Deprecation		Net Book Value
Heavy equipment		$339,312		$95,473		$243,839
Major component parts in use		36,064		8,297		27,767
Other equipment		25,666		10,910		14,756
Licensed motor vehicles		16,296		10,692		5,604
Office and computer equipment		9,746		3,786		5,960
Buildings		21,710		6,832		14,878
Land		281		–		281
Leasehold improvements		9,314		2,960		6,354
Assets under capital lease		24,304		12,388		11,916
		$482,693		$151,338		$331,355

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

During the year ended March 31, 2011, additions to property, plant and equipment included $427 of assets that were acquired by means of capital leases (2010 – $1,523; 2009 – $8,863). Depreciation of equipment under capital lease of $2,723 (2010 – $4,081; 2009 – $5,138) was included in depreciation expense.

14. Accrued liabilities


	March 31, 2011		March 31, 2010
Accrued interest payable		$9,866		$14,725
Payroll liabilities		11,412		21,741
Liabilities related to equipment leases		7,518		4,720
Income and other taxes payable		4,018		6,005
		$32,814		$47,191


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15. Capital lease obligations

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


2012	$5,267
2013	3,087
2014	562
2015	270
2016	71
Subtotal:	$9,257
Less: amount representing interest – weighted average interest rate of 6.5%	(564	)
Present value of minimum lease payments	$8,693
Less: current portion	(4,862	)
Long term portion	$3,831

16. Long term debt

a) Long term debt are as follows:


	March 31, 2011		March 31, 2010
Credit facilities (note 16(b))		$61,970		$22,374
8³/4% senior notes (note 16(c))		—		203,120
Series 1 Debentures (note 16(d))		225,000		—
		$286,970		$225,494

b) Credit Facilities


	March 31, 2011			March 31, 2010
Term A Facility		$24,698			$28,446
Term B Facility		43,748			—
Revolving Facility		3,524			—
Total credit facilities		$71,970			$28,446
Less: current portion of term facilities		(10,000	)		(6,072	)
		$61,970			$22,374

On April 30, 2010, the Company entered into an amended and restated credit agreement to extend the term of the credit facilities and increase the amount of the term loans. These facilities mature on April 30, 2013.

The new credit facilities include an $85.0 million Revolving Facility (previously $90.0 million), a $28.4 million Term A Facility and a $50.0 million Term B Facility. Advances under the Revolving Facility may be repaid from time to time at the Company’s option. The term facilities include scheduled repayments totalling $10.0 million per year with $2.5 million paid on the last day of each quarter commencing June 30, 2010. In addition, the Company must make annual payments within 120 days of the end of its fiscal year in the amount of 50% of Consolidated Excess Cash Flow (as defined in the credit agreement) to a maximum of $4.0 million. The Company will not be required to make an additional principal payment in July 2011 related to the 2011 fiscal year.

As of March 31, 2011, the Company had outstanding borrowings of $68.4 million (March 31, 2010 – $28.4 million) under the term facilities, $3.5 million (March 31, 2010—$nil) under the Revolving Facility and had issued $12.3 million (March 31, 2010 – $10.4 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. The Company’s unused borrowing availability under the Revolving Facility was $69.2 million at March 31, 2011.

During the year ended March 31, 2011, financing fees of $1,034 were incurred in connection with the modifications made to the amended and restated credit agreement (2010 – $1,123; 2009 – $nil). 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 (note 12(d)).

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, 2011 was 5.87%.


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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. The Company is also required to meet certain financial covenants under the credit agreement and is expected to remain in compliance throughout the fiscal year ending March 31, 2012. As at March 31, 2011, the Company was in violation of certain financial covenants as defined within the credit agreement. On May 20, 2011, the Company obtained an amendment in connection with such covenants from its lenders resulting in compliance as at March 31, 2011. The Company considers it probable that they will be in compliance with these covenants throughout the fiscal year ending March 31, 2012.

c) 8³/4% Senior Notes


	March 31, 2011		March 31, 2010
8³/4% senior unsecured notes due 2011 ($US)		$—		$200,000
Unrealized foreign exchange		—		3,120
		$—		$203,120

The 8³/4% 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 8³/4% 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)).

d) 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:

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.

During the year ended March 31, 2011, financing fees of $5,846 were incurred in connection with the issuance of the Series 1 Debentures in addition to $1,040 that was incurred in March 2010. These fees have been recorded as deferred financing costs and are being amortized using the effective interest method over the term of the Series 1 Debentures (note 12(d)).


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17. Other long term obligations

a) Other long term obligations are as follows:


	March 31, 2011		March 31, 2010
Long term portion of liabilities related to equipment leases		$12,747		$14,943
Deferred lease inducements (note 17(b))		654		761
Asset retirement obligation (note 17(c))		395		360
Senior executive stock option plan (note 28(c))		5,115		—
Restricted share unit plan (note 28(e))		2,633		1,030
Director’s deferred stock unit plan (note 28(f))		4,032		2,548
		$25,576		$19,642

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, 2011			March 31, 2010
Balance, beginning of year		$761			$836
Additions		—			32
Amortization of deferred lease inducements		(107	)		(107	)
Balance, end of year		$654			$761

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, 2011		March 31, 2010
Balance, beginning of year		$360		$386
Change in the present value of the obligation		—		(31	)
Accretion expense		35		5
Balance, end of year		$395		$360

At March 31, 2011, estimated undiscounted cash flows required to settle the obligation were $1,084 (March 31, 2010 – $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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18. Income taxes

Income tax provision (benefit) 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,	2011			2010			2009
(Loss) income before income taxes statutory tax rate		$(41,098	)		$41,898			$(120,771	)
Tax rate		27.75%			28.91%			29.38%
Expected provision (benefit) at statutory tax rate		$(11,405	)		$12,113			$(35,483	)
Increase (decrease) related to:
Impact of enacted future statutory income tax rates		164			(673	)		(1,005	)
Income tax adjustments and reassessments		909			1,442			—
Valuation allowance		962			—			—
Impairment of goodwill		—			—			51,767
Stock-based compensation		1,443			617			555
Non deductible portion of capital losses		1,063			—			—
Other		416			180			(1,201	)
Income tax provision		$(6,448	)		$13,679			$14,633

Classified as:


	2011			2010		2009
Year ended March 31,
Current income taxes		$2,892			$3,803		$5,546
Deferred income taxes		(9,340	)		9,876		9,087
		$(6,448	)		$13,679		$14,633


	March 31, 2011		March 31, 2010
Deferred tax assets:
Non-capital losses carried forward		$41,581		$2,205
Deferred financing costs		—		12
Derivative financial instruments and 8³/4% senior notes		2,895		8,892
Billings in excess of costs on uncompleted contracts		508		448
Capital lease obligations		2,247		3,692
Intangible assets		473		104
Long term portion of liabilities related to equipment leases		2,029		1,965
Deferred lease inducements		161		199
Stock-based compensation		1,656		894
Other		99		370
		$51,649		$18,781


	March 31, 2011			March 31, 2010
Deferred tax liabilities:
Unbilled revenue and uncertified revenue included in accounts receivable		$24,418			$15,975
Assets held for sale		189			233
Accounts receivable – holdbacks		3,154			1,083
Property, plant and equipment		44,105			31,234
Deferred financing costs		71			—
Intangible assets		76			—
Other		40			—
		72,053			48,525
Net deferred income taxes		$(20,404	)		$(29,744	)

Classified as:


	March 31, 2011			March 31, 2010
Current asset		$1,729			$3,481
Long term asset		49,920			15,300
Current liability		(27,612	)		(16,781	)
Long term liability		(44,441	)		(31,744	)
		$(20,404	)		$(29,744	)


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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 had unrecognized tax benefits in capital losses of $962 as at March 31, 2011 (2010 – $nil; 2009 – $nil). At March 31, 2011, the Company has non-capital losses for income tax purposes of $164,661 which predominately expire after 2027.


	March 31, 2011
2027		$2,968
2028		7,094
2029		13,676
2030		32,363
2031		108,560
		$164,661

19. 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, 2008		35,929,476		$301,894
Issued upon exercise of stock options		109,000		703
Transferred from additional paid-in capital on exercise of stock options		—		834
Issued and outstanding at March 31, 2009		36,038,476		$303,431
Issued upon exercise of stock options		10,800		53
Transferred from additional paid-in capital on exercise of stock options		—		21
Issued and outstanding at March 31, 2010		36,049,276		$303,505
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

b) Net (loss) income per share


	2011			2010		2009
Year ended March 31,
Net (loss) income available to common shareholders		$(34,709	)		$28,219		$(135,404	)
Weighted average number of common shares		36,119,356			36,040,857		36,020,763
Basic net (loss) income per share		$(0.96	)		$0.78		$(3.76	)


	2011			2010		2009
Year ended March 31,
Net (loss) income available to common shareholders		$(34,709	)		$28,219		$(135,404	)
Weighted average number of common shares		36,119,356			36,040,857		36,020,763
Dilutive effect of stock options, deferred performance share units and stock award plan		—			680,169		—
Weighted average number of diluted common shares		36,119,356			36,721,026		36,020,763
Diluted net (loss) income per share		$(0.96	)		$0.77		$(3.76	)

For the year ended March 31, 2011, there were 1,647,474, 75,591 and 150,000 stock options, deferred performance share units and stock awards respectively which were anti-dilutive and therefore were not considered in computing diluted earnings per share (March 31, 2010 – 820,641 and 57,311 stock options and deferred performance share units respectively; March 31, 2009 – 2,071,884 and 91,005, stock options and deferred performance share units respectively).


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20. Interest expense


	2011		2010		2009
Year ended March 31,
Interest on 8³/4% senior notes and swaps		$1,238		$19,041		$25,379
Interest on capital lease obligations		689		1,032		1,234
Amortization of deferred financing costs		1,609		3,348		2,970
Interest on credit facilities		5,361		2,375		298
Interest on Series 1 Debentures		20,132		–		–
Interest on long term debt		$29,029		$25,796		$29,881
Other interest		962		284		(269	)
		$29,991		$26,080		$29,612

21. Claims revenue


	2011		2010		2009
Year ended March 31,
Claims revenue recognized		$5,278		$4,541		$55,999
Claims revenue uncollected (classified as unbilled revenue)		2,174		785		1,768

22. 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 $72.0 million at March 31, 2011 and $28.4 million at March 31, 2010, the fair value of amounts due under the Credit Facilities as at March 31, 2011 and March 31, 2010 are not significantly different than their carrying value.

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

March 31, 2011

March 31, 2010

Carrying
Amount

Fair
Value

Carrying
Amount

Fair

Value

8³/4% senior notes ⁽ⁱ⁾

$–

$203,120

$203,526

Capital lease obligations ⁽ⁱⁱ⁾

8,693

8,658

13,393

13,291

Series 1 Debentures ⁽ⁱⁱⁱ⁾

225,000

238,651

–

(i)

The US Dollar denominated 8³/4% senior notes were redeemed during the year ended March 31, 2011. The fair value of the 8³/4% senior notes on March 31, 2010 was based upon the period end closing market price translated into Canadian Dollars at period end exchange rates as at March 31, 2010. Expected discounted cash flows were not included in the fair value calculation.

(ii)	The fair values of amounts due under capital leases are based on management estimates which are determined by discounting cash flows required under the instruments at the interest rates currently estimated to be available for instruments with similar terms.

(iii)

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.


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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, 2011, 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, 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


March 31, 2010	Carrying Amount
Cross-currency swaps for US dollar 8³/4% senior notes		$66,268
Interest rate swaps for US dollar 8³/4% senior notes		14,843
Cross-currency and interest rate swaps for US dollar 8³/4% senior notes		$81,111
Embedded price escalation features in a long term customer construction contract		6,481
Embedded price escalation features in certain long term supplier contracts		9,463
		$97,055
Less: current portion		(22,054	)
		$75,001

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 8³/4% senior notes (note 16(c)).

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


Year ended March 31,	2011			2010			2009
Realized and unrealized loss (gain) on cross-currency and interest rate swaps		$2,111			$64,637			$(46,945	)
Unrealized (gain) loss on embedded price escalation features in a long term revenue construction contract		(604	)		6,805			(15,145	)
Unrealized (gain) loss on embedded price escalation features in certain long term supplier contracts		(3,812	)		(13,315	)		21,509
Unrealized (gain) loss on early redemption option on 8³/4% senior notes		–			(3,716	)		3,331
		$(2,305	)		$54,411			$(37,250	)

Non-financial assets that were re-measured at fair value on a non-recurring basis as at March 31, 2011 and 2010 in the financial statements are summarized below:


	March 31, 2011					March 31, 2010
	Carrying Amount		Change in Fair Value			Carrying Amount		Change in Fair Value
Assets held for sale		$721		$(141	)		$838		$(806	)


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Assets held for sale are re-measured at fair value less cost to sell on a non-recurring basis. For the year ended March 31, 2011, assets held for sale with a carrying amount of $862 (2010 – $1,644) were written down to their fair value less cost to sell of $721 (2010 – $838), resulting in a loss of $141 (2010 – $806), 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 net book value, the residual value of the asset and the useful life of the asset. The inputs to estimate the fair value of the assets held for sale are classified under Level 3 of the fair value hierarchy.

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, 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, 2011, the Company held $72.0 million of floating rate debt pertaining to its Credit Facilities (March 31, 2010 – $28.4 million). As at March 31, 2011, holding all other variables constant, a 100 basis point increase (decrease) to interest rates on floating rate debt will result in $0.7 million increase (decrease) in annual interest expense. This assumes that the amount of floating rate debt remains unchanged from that which was held at March 31, 2011.

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.


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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, 2011 and March 31, 2010, the following customers represented 10% or more of accounts receivable and unbilled revenue:


	March 31, 2011		March 31, 2010
Customer A		40%		40%
Customer B		14%		4%
Customer C		12%		38%

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, 2011		March 31, 2010
Trade accounts receivables		$127,678		$107,210
Other receivables		804		4,674
Total accounts receivable		$128,482		$111,884
Unbilled revenue		$102,939		$84,702

On a geographic basis as at March 31, 2011, approximately 95% (March 31, 2010 – 98%) 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, 2011 and 2010, trade receivables are aged as follows:


	March 31, 2011		March 31, 2010
Not past due		$98,626		$84,041
Past due 1-30 days		18,911		15,635
Past due 31-60 days		3,444		1,543
More than 61 days		6,697		5,991
Total		$127,678		$107,210

As at March 31, 2011, the Company has recorded an allowance for doubtful accounts of $30 (March 31, 2010 – $1,691) of which 100% relates to amounts that are more than 61 days past due.

The allowance is an estimate of the March 31, 2011 trade receivable balances that are considered uncollectible. Changes to the allowance are as follows:


Year ended March 31,	2011			2010			2009
Opening balance		$1,691			$2,597			$742
Payments received on provided balances		(682	)		(846	)		(100	)
Current year allowance		518			334			4,324
Write-offs		(1,497	)		(394	)		(2,369	)
Ending balance		$30			$1,691			$2,597

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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23. Other information

a) Supplemental cash flow information


Year ended March 31,	2011			2010			2009
Cash paid during the year for:
Interest, including realized interest on interest rate swap		$33,559			$49,999			$29,336
Income taxes		4,149			10,395			52
Cash received during the year for:
Interest		1,168			10,998			477
Income taxes		2,260			453			2,734
Non-cash transactions:
Acquisition of property, plant and equipment by means of capital leases		427			1,523			8,863
Additions to assets held for sale		(1,675	)		(1,739	)		(2,035	)
Net change in accounts payable related to purchase of property, plant and equipment		$(3,879	)		$1,840			$(630	)

b) Net change in non-cash working capital


Year ended March 31,	2011			2010			2009
Operating activities:
Accounts receivable, net		$(9,534	)		$(29,428	)		$88,687
Unbilled revenue		(18,237	)		(28,795	)		14,976
Inventories		(2,661	)		6,214			(6,617	)
Prepaid expenses and deposits		308			(2,620	)		1,015
Accounts payable		21,382			6,620			(56,308	)
Accrued liabilities		(5,434	)		1,150			5,626
Long term portion of liabilities related to equipment leases		(2,196	)		7,809			1,431
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		390			(541	)		(2,617	)
		$(15,982	)		$(39,591	)		$46,193

24. 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.


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b) Results by business segment


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		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		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

For the year ended March 31, 2009	Heavy Construction and Mining			Piling			Pipeline			Total
Revenue from external customers		$716,053			$155,076			$101,407			$972,536
Depreciation of property, plant and equipment		25,690			3,380			581			29,651
Segment profits		109,580			38,776			22,470			170,826
Impairment of goodwill		(125,447	)		(18,000	)		(32,753	)		(176,200	)
Segment assets		373,861			88,908			7,898			470,667
Capital expenditures		76,354			8,679			75			85,108

c) Reconciliations

i) Income (loss) before income taxes


Year ended March 31,	2011			2010			2009
Total profit for reportable segments		$66,124			$118,453			$170,826
Less: unallocated corporate items:
General and administrative expenses		59,932			62,530			74,460
Loss on disposal of property, plant and equipment		1,948			1,233			5,325
Loss on disposal of assets held for sale		825			373			24
Amortization of intangible assets		3,540			1,719			1,501
Equity in loss (earnings) of unconsolidated joint venture		2,720			(44	)		–
Impairment of goodwill		–			–			176,200
Interest expense, net		29,991			26,080			29,612
Foreign exchange (gain) loss		(1,659	)		(48,901	)		47,272
Realized and unrealized (gain) loss on derivative financial instruments		(2,305	)		54,411			(37,250	)
Loss on debt extinguishment		4,346			–			–
Other income		(104	)		(14	)		(5,955	)
Unallocated equipment costs (recoveries)⁽ⁱ⁾		7,988			(20,832	)		408
(Loss) income before income taxes		$(41,098	)		$41,898			$(120,771	)

(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.


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ii) Total assets


	March 31, 2011		March 31, 2010
Corporate assets:
Cash and cash equivalents		$722		$103,005
Property, plant and equipment		24,831		17,883
Deferred tax assets		51,649		18,781
Other		28,132		24,408
Total corporate assets		$105,334		$164,077
Total assets for reportable segments		577,623		542,843
Total assets		$682,957		$706,920

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,	2011		2010		2009
Total depreciation for reportable segments		$33,018		$37,414		$29,651
Depreciation for corporate assets		6,422		5,222		6,738
Total depreciation		$39,440		$42,636		$36,389

iv) Capital expenditures for long-lived assets


Year ended March 31,	2011		2010		2009
Total capital expenditures for reportable segments		$33,261		$42,460		$85,108
Capital expenditures for corporate assets		7,904		12,790		5,096
Total capital expenditures for long-lived assets		$41,165		$55,250		$90,204

d) Customers

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


Year ended March 31,	2011		2010		2009
Customer A		29%		51%		31%
Customer B		24%		19%		15%
Customer C		10%		9%		18%
Customer D		8%		5%		15%
Customer E		0%		0%		10%

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

e) Geographic information

The geographic information for the Company as at and for the year ended March 31, 2011 is as follows:


	Revenue		Long-lived assets
Canada		$857,009		$381,577
United States		1,039		96
		$858,048		$381,673


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25. Related party transactions

The Sterling Group, L.P., Perry Strategic Capital Inc., and SF Holding Corp. are collectively “the Sponsors” of the Company. The Company may receive consulting and advisory services provided by the Sponsors (principals or employees of such Sponsors are directors of the Company) with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters, and no fee is charged for these consulting and advisory services.

In order for the Sponsors to provide such advisory and consulting services, the Company provides reports, financial data and other information to the Sponsors. This permits them to consult with and advise the Company’s management on matters relating to its operations, company affairs and finances. In addition, this permits them to visit and inspect any of the Company’s properties and facilities.

Additionally, the Company provided shared service support for its joint venture nominee, Noramac Ventures Inc. (note 11).

There were no material related party transactions during the years ended March 31, 2011, 2010 and 2009. 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.

26. 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,
2012			$68,964
2013			49,603
2014			36,287
2015			19,667
2016 and thereafter			4,248
			$178,769

Total contingent rentals on operating leases consisting principally of usage charges in excess of minimum contracted amounts for the years ended March 31, 2011, 2010 and 2009 amounted to $1,881, $10,246 and $7,665 respectively.

27. 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, 2011 were $1,689 (2010 – $1,393; 2009 – $2,540).

28. 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,	2011			2010		2009
Share option plan (note 28(b))		$1,455			$2,135		$1,888
Senior executive stock option plan (note 28(c))		2,878			–		–
Deferred performance share unit plan (note 28(d))		(44	)		123		61
Restricted share unit plan (note 28(e))		1,603			1,010		–
Director’s deferred stock unit plan (note 28(f))		1,484			2,002		356
Stock award plan (note 28(g))		780			–		–
		$8,156			$5,270		$2,305

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.


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	Number of options			Weighted average exercise price $ per share
Outstanding at March 31, 2008		2,036,364			7.54
Granted		344,800			8.22
Exercised (i)		(109,000	)		(6.45	)
Forfeited		(200,280	)		(9.40	)
Outstanding at March 31, 2009		2,071,884			7.53
Granted		375,700			8.88
Exercised (i)		(10,800	)		(4.90	)
Options settled for cash		(95,720	)		(4.95	)
Forfeited		(90,260	)		(8.53	)
Outstanding at March 31, 2010		2,250,804			7.84
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

(i)	All stock options exercised resulted in new common shares being issued (note 19(a));

(ii)	550,000 stock options were modified as senior executive stock options on September 22, 2010 (note 28(c)).

Cash received from the option exercises for the year ended March 31, 2011 was $963 (2010 – $53, 2009 – $703). Cash paid for options settled for cash for the year ended March 31, 2011 was $nil (2010 – $244, 2009 – $nil).The total intrinsic value of options exercised for the years ended March 31, 2011, 2010 and 2009 was $1,084, $277 and $1,238 respectively.

The following table summarizes information about stock options outstanding at March 31, 2011:


	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		140,040		7.7 years		$3.69		53,220		7.7 years		$3.69
$5.00		440,294		3.7 years		$5.00		420,294		3.6 years		$5.00
$8.28		136,000		8.2 years		$8.28		32,000		8.2 years		$8.28
$8.58		60,000		9.5 years		$8.58		–		–		–
$9.33		178,280		8.9 years		$9.33		34,840		8.9 years		$9.33
$10.13		192,100		9.7 years		$10.13		–		–		–
$13.21		75,000		6.8 years		$13.21		45,000		6.8 years		$13.21
$13.50		216,200		6.7 years		$13.50		132,440		6.7 years		$13.50
$15.37		56,800		7.0 years		$15.37		40,480		7.0 years		$15.37
$16.01		75,000		7.0 years		$16.01		30,000		7.0 years		$16.01
$16.46		50,000		7.0 years		$16.46		20,000		7.0 years		$16.46
$16.75		27,760		5.5 years		$16.75		22,208		5.5 years		$16.75
		1,647,474		6.8 years		$9.25		830,482		5.4 years		$8.52

At March 31, 2011, the weighted average remaining contractual life of outstanding options is 6.8 years (March 31, 2010 – 6.6 years). The fair value of options vested during the year ended March 31, 2011 was $1,892 (March 31, 2010 – $1,594). At March 31, 2011, the Company had 830,482 exercisable options (March 31, 2010 –1,244,908) with a weighted average exercise price of $8.52 (March 31, 2010 – $6.46).

At March 31, 2011, the total compensation costs related to non-vested awards not yet recognized was $2,973 (March 31, 2010 – $3,351) and these costs are expected to be recognized over a weighted average period of 3.4 years (March 31, 2010 – 3.4 years).


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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,	2011		2010		2009
Number of options granted		260,000		375,700		344,800
Weighted average fair value per option granted ($)		6.79		6.25		4.53
Weighted average assumptions:
Dividend yield		Nil%		Nil%		Nil%
Expected volatility		78.59%		76.27%		59.01%
Risk-free interest rate		2.65%		3.39%		3.24%
Expected life (years)		6.1		6.5		6.5

The Company uses company specific historical data to estimate the expected life of the option, such as employee option exercise and employee post-vesting departure behaviour. Since the Company’s shares have been publicly traded for a period that is shorter than the expected life of the share option, expected volatility is estimated based on the historical volatility of a peer group of similar entities in addition to its own historical volatility.

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. Incremental compensation cost of $2,878 which was measured as the excess of the modification date fair value of the modified award over the modification date fair value of the original award was recognized for the year ended March 31, 2011. 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, 2011 are as follows:


Number of senior executive stock options			550,000
Weighted average fair value per option granted ($)			9.30
Weighted average assumptions:
Dividend yield			Nil%
Expected volatility			76.74%
Risk-free interest rate			1.77%
Expected life (years)			4.10

d) Deferred performance share unit plan

Deferred Performance Share Units (“DPSUs”) are granted each fiscal year with respect of services to be provided in that fiscal year and the following two fiscal years. The DPSUs vest at the end of a three-year term and are subject to the performance criteria approved by the Compensation Committee of the Board of Directors at the date of grant. Such performance criterion includes the passage of time and is based upon return on invested capital calculated as operating income divided by average operating assets. The maturity date for such DPSUs is 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 have been earned (earned DPSUs).

The settlement of the participant’s entitlement is 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 are 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. The weighted average assumptions used in estimating the fair value of the share options issued under the DPSU Plan in fiscal 2010 and 2009 are as follows:


Year ended March 31,	2010		2009
Number of units granted		908,165		111,020
Weighted average fair value per unit granted ($)		4.71		12.34
Weighted average assumptions:
Dividend yield		Nil%		Nil%
Expected volatility		96.89%		56.25%
Risk-free interest rate		1.47%		2.83%
Expected life (years)		3.00		3.00


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	Number of units
Outstanding at March 31, 2008		–
Granted		111,020
Forfeited		(20,015	)
Outstanding at March 31, 2009		91,005
Granted		908,165
Forfeited		(102,671	)
Converted to RSUs (note 28(e))		(389,204	)
Outstanding at March 31, 2010		507,295
Forfeited		(74,776	)
Outstanding at March 31, 2011		432,519

The weighted average exercise price per unit is $nil.

At March 31, 2011, there were 111,020 units vested and the weighted average remaining contractual life of outstanding DPSU units is 1.2 years (March 31, 2010 – 2.2 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 (March 31, 2010 – $792), which is expected to be recognized over a weighted average period of 2.0 years (March 31, 2010 – 2.2 years) and is 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 28(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 percentage of the fair market value of RSUs that is accrued at the end of each period. The fair market value of each RSU is 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 RSUs.

On December 18, 2009, the Company converted certain middle manager’s DPSUs (note 28(d)) into RSUs at a conversion factor of 80%.


	Number of units
Outstanding at March 31, 2009		–
Converted from DPSUs at a conversion factor of 80%		311,358
Granted		169,489
Forfeited		(12,032	)
Outstanding at March 31, 2010		468,815
Forfeited		(86,339	)
Outstanding at March 31, 2011		382,476

At March 31, 2011, there were 17,320 units vested and the weighted average remaining contractual life of the RSUs outstanding was 1.3 years (March 31, 2010 – 2.3 years).

At March 31, 2011, the redemption value of these units was $11.96/unit (March 31, 2010 – $9.68/unit).

Using the redemption value of $11.96/unit at March 31, 2011, there was approximately $1,914 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 1.3 years (March 31, 2010 – 2.3 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 issurance and are only redeemable upon death or retirement of the participant for cash determined by the market price of the


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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 maturity date until a date no later than December 1st of the calendar year following the year in which the actual maturity date occurred.


	Number of units
Outstanding at March 31, 2008		11,807
Issued		127,884
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

At March 31, 2011, the redemption value of these units was $11.96/unit (March 31, 2010 – $9.68/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, the CEO was awarded 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 will be awarded to the CEO provided he remains employed on the award dates above. As of September 24, 2010, the effective date, the CEO was granted a right to receive 150,000 common shares of the Company or at the discretion of the Company, the cash equivalent thereof.

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.

At March 31, 2011, none of the stock awards have vested and the weighted average remaining contractual life of outstanding Stock Award Plan units is 0.6 years (March 31, 2010 – 1.6 years). As at March 31, 2011, there was approximately $270 (March 31, 2010 – $784) 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 0.6 years (March 31, 2010 – 1.6 years).

29. 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.

30. 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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31. United States and Canadian accounting policy differences

These consolidated financial statements have been prepared in accordance with US GAAP, which differs in certain respects from Canadian GAAP. If Canadian GAAP were employed, the Company’s comprehensive income (loss) would be adjusted as follows:

Consolidated Statements of Operations, Comprehensive Loss and Deficit – for the year ended March 31, 2011


	US GAAP			Adjustments			Canadian GAAP
Revenue ^(g)		$858,048			$ 6,098			$864,146
Project costs ^(g)		456,119			7,339			463,458
Equipment costs		234,933			–			234,933
Equipment operating lease expense		69,420			–			69,420
Depreciation ^(a)		39,440			(111	)		39,329
Gross profit		58,136			(1,130	)		57,006
General and administrative expenses ^(c)^(g)		59,932			111			60,043
Loss on disposal of property, plant and equipment		1,948			–			1,948
Loss on disposal of assets held for sale		825			–			825
Amortization of intangible assets ^(b)		3,540			706			4,246
Equity in loss of unconsolidated joint venture ^(g)		2,720			(2,720	)		–
Operating loss before the undernoted		(10,829	)		773			(10,056	)
Interest expense, net ^(b)		29,991			(1,193	)		28,798
Foreign exchange gain		(1,659	)		–			(1,659	)
Realized and unrealized gain on derivative financial instruments ^(d)		(2,305	)		(5,802	)		(8,107	)
Loss on debt extinguishment ^(b)		4,346			(2,884	)		1,462
Other income		(104	)		–			(104	)
Loss before income taxes		(41,098	)		10,652			(30,446	)
Income taxes (benefit):
Current		2,892			–			2,892
Deferred ^(h)		(9,340	)		1,688			(7,652	)
Net loss		(34,650	)		8,964			(25,686	)
Other comprehensive loss
Unrealized foreign currency translation loss		59			–			59
Comprehensive loss		(34,709	)		8,964			(25,745	)
Deficit, beginning of year		(129,886	)		1,081			(128,805	)
Deficit, end of year		$(164,536	)		$10,045			$(154,491	)
Net loss per share – basic		$(0.96	)		$0.25			$(0.71	)
Net loss per share – diluted		$(0.96	)		$0.25			$(0.71	)


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Consolidated Statements of Operations, Comprehensive Income and Deficit – for the year ended March 31, 2010


	US GAAP			Adjustments			Canadian GAAP
Revenue ^(g)		$758,965			$4,336			$763,301
Project costs ^(g)		301,307			3,542			304,849
Equipment costs		209,408			–			209,408
Equipment operating lease expense		66,329			–			66,329
Depreciation ^(a)		42,636			(124	)		42,512
Gross profit		139,285			918			140,203
General and administrative expenses ^(c)^(g)		62,530			706			63,236
Loss on disposal of property, plant and equipment		1,233			–			1,233
Loss on disposal of assets held for sale		373			–			373
Amortization of intangible assets ^(b)		1,719			831			2,550
Equity in earnings of unconsolidated joint venture ^(g)		(44	)		44			–
Operating income before the undernoted		73,474			(663	)		72,811
Interest expense, net ^(b)		26,080			(2,486	)		23,594
Foreign exchange gain ^(b)		(48,901	)		496			(48,405	)
Realized and unrealized loss on derivative financial instruments ^(d)		54,411			–			54,411
Other income		(14	)		–			(14	)
Income before income taxes		41,898			1,327			43,225
Income taxes:
Current		3,803			–			3,803
Deferred ^(h)		9,876			372			10,248
Net income and comprehensive income for the year		28,219			955			29,174
Deficit, beginning of year		(158,105	)		126			(157,979	)
Deficit, end of year		$(129,886	)		$1,081			$(128,805	)
Net income per share – basic		$0.78			$0.03			$0.81
Net income per share – diluted		$0.77			$0.02			$0.79


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Consolidated Statements of Operations, Comprehensive Loss and Deficit – for the year ended March 31, 2009


	US GAAP			Adjustments			Canadian GAAP
Revenue		$972,536			$ –			$972,536
Project costs		505,026			–			505,026
Equipment costs		217,120			–			217,120
Equipment operating lease expense		43,583			–			43,583
Depreciation ^(a)		36,389			(162	)		36,227
Gross profit		170,418			162			170,580
General and administrative expenses ^(c)		74,460			(55	)		74,405
Loss on disposal of property, plant and equipment		5,325			–			5,325
Loss on disposal of assets held for sale		24			–			24
Amortization of intangible assets ^(b)		1,501			837			2,338
Impairment of goodwill		176,200			–			176,200
Operating loss before the undernoted		(87,092	)		(620	)		(87,712	)
Interest expense, net ^(b)		29,612			(2,162	)		27,450
Foreign exchange loss ^(b)		47,272			(606	)		46,666
Realized and unrealized gain on derivative financial instruments ^(d)		(37,250	)		4,655			(32,595	)
Other income		(5,955	)		–			(5,955	)
Loss before income taxes		(120,771	)		(2,507	)		(123,278	)
Income taxes:
Current		5,546			–			5,546
Deferred ^(h)		9,087			(34	)		9,053
Net loss and comprehensive loss for the year		(135,404	)		(2,473	)		(137,877	)
Deficit, beginning of year		(22,701	)		1,608			(21,093	)
Change in accounting policy related to inventories ^(f)		–			991			991
Deficit, end of year		$(158,105	)		$126			$(157,979	)
Net loss per share – basic		$(3.76	)		$(0.07	)		$(3.83	)
Net loss per share – diluted		$(3.76	)		$(0.07	)		$(3.83	)


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The cumulative effect of material differences between US and Canadian GAAP on the Consolidated Balance Sheets of the Company is as follows:

Consolidated Balance Sheets – March 31, 2011


	US GAAP			Adjustments			Canadian GAAP
Assets
Current assets
Cash and cash equivalents		$722			$–			$722
Accounts receivable, net ^(g)		128,482			1,734			130,216
Unbilled revenue ^(g)		102,939			1,973			104,912
Inventories		7,735			–			7,735
Prepaid expenses and deposits ^(g)		8,269			4			8,273
Investment in and advances to unconsolidated joint venture		1,488			(1,488	)		–
Assets held for sale		–			453			453
Deferred tax assets		1,729			–			1,729
		251,364			2,676			254,040
Property, plant and equipment, net ^(a) (g)		321,864			(425	)		321,439
Other assets ^{(b) (f) (g)}		26,908			(6,293	)		20,615
Goodwill		32,901			–			32,901
Deferred tax assets		49,920			–			49,920
Total Assets		$682,957			$(4,042	)		$678,915
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable ^(g)		$86,053			$2,670			$88,723
Accrued liabilities ^(g)		32,814			6			32,820
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		2,004			–			2,004
Current portion of capital lease obligations		4,862			–			4,862
Current portion of term facilities		10,000			–			10,000
Current portion of derivative financial instruments		2,474			–			2,474
Deferred tax liabilities		27,612			–			27,612
		165,819			2,676			168,495
Capital lease obligations		3,831			–			3,831
Long term debt ^(b) (d)		286,970			(12,338	)		274,632
Derivative financial instruments		9,054			–			9,054
Other long term obligations		25,576			(1,320	)		24,256
Deferred tax liabilities ^(h)		44,441			636			45,077
		535,691			(10,346	)		525,345
Shareholders’ equity
Common shares (authorized – unlimited number of voting common shares; issued and outstanding – March 31, 2011 – 36,242,526) ^(e)		304,854			(3,458	)		301,396
Additional paid-in capital ^(c) (h)		7,007			(283	)		6,724
Deficit ^(a-h)		(164,536	)		10,045			(154,491	)
Accumulated other comprehensive loss		(59	)		–			(59	)
		147,266			6,304			153,570
Total liabilities and shareholders’ equity		$682,957			$(4,042	)		$678,915


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Consolidated Balance Sheets – March 31, 2010


	US GAAP			Adjustments			Canadian GAAP
Assets
Current assets
Cash and cash equivalents ^(g)		$103,005			$1,240			$104,245
Accounts receivable, net ^(g)		111,884			1,432			113,316
Unbilled revenue ^(g)		84,702			1,794			86,496
Inventories		3,047			–			3,047
Prepaid expenses and deposits ^(g)		6,881			87			6,968
Deferred tax assets		3,481			–			3,481
		313,000			4,553			317,553
Property, plant and equipment, net ^(a) (g)		331,355			(536	)		330,819
Other asset ^{(b) (f) (g)}		22,154			(7,551	)		14,603
Goodwill		25,111			–			25,111
Deferread tax assets		15,300			–			15,300
Total Assets		$706,920			$(3,534)			$703,386
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable ^(g)		$66,876			$1,637			$68,513
Accrued liabilities		47,191			–			47,191
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		1,614			–			1,614
Current portion of capital lease obligations		5,053			–			5,053
Current portion of term facilities		6,072			–			6,072
Current portion of derivative financial instruments ^(b) (d)		22,054			(1,506	)		20,548
Deferred tax liabilities		16,781			–			16,781
		165,641			131			165,772
Capital lease obligations		8,340			–			8,340
Long term debt ^(b) (d)		225,494			(1,506	)		223,988
Derivative financial instruments ^(b) (d)		75,001			1,506			76,507
Other long term obligations		19,642			–			19,642
Deferred tax liabilities ^(h)		31,744			(1,052	)		30,692
		525,862			(921	)		524,941
Shareholders’ equity
Common shares (authorized – unlimited number of voting common shares; issued and outstanding – March 31, 2010 – 36,049,276) ^(e)		303,505			(3,458	)		300,047
Additional paid-in capital ^(c) (h)		7,439			(236	)		7,203
Deficit ^(a-h)		(129,886	)		1,081			(128,805	)
		181,058			(2,613	)		178,445
Total liabilities and shareholders’ equity		$706,920			$(3,534	)		$703,386


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The cumulative effect of material differences between US and Canadian GAAP on the consolidated statement of cash flows of the Company is as follows:

Consolidated Statements of Cash Flows – for the year ended March 31, 2011


	US GAAP			Adjustments			Canadian GAAP
Cash (used in) provided by:
Operating activities:
Net loss for the period		$(34,650	)		$8,964			$(25,686	)
Items not affecting cash:
Depreciation		39,440			(111	)		39,329
Equity in loss of unconsolidated joint venture		2,720			(2,720	)		–
Amortization of intangible assets		3,540			706			4,246
Amortization of deferred lease inducements		(107	)		–			(107	)
Amortization of deferred financing costs		1,609			(823	)		786
Amortization of premium on Series 1 Debentures		–			(370	)		(370	)
Loss on disposal of property, plant and equipment		1,948			–			1,948
Loss on disposal of assets held for sale		825			–			825
Realized foreign exchange gain on 8³/4% senior notes		(732	)		–			(732	)
Unrealized gain on derivative financial instruments measured at fair value		(2,305	)		(5,802	)		(8,107	)
Loss on debt extinguishment		4,346			(2,884	)		1,462
Stock-based compensation expense		8,156			(1,367	)		6,789
Accretion of asset retirement obligation		35			–			35
Deferred income taxes benefit		(9,340	)		1,688			(7,652	)
Net changes in non-cash working capital		(15,982	)		641			(15,341	)
		(497	)		(2,078	)		(2,575	)
Investing activities:
Acquisition, net of cash acquired		(23,501	)		–			(23,501	)
Purchase of property, plant and equipment		(36,417	)		(453	)		(36,870	)
Additions to intangible assets		(4,748	)		–			(4,748	)
Investment in and advances to unconsolidated joint venture		(1,291	)		1,291			–
Proceeds on disposal of property, plant and equipment		499			–			499
Proceeds on disposal of assets held for sale		826			–			826
		(64,632	)		838			(63,794	)
Financing activities:
Repayment of credit facilities		(85,000	)		–			(85,000	)
Increase in credit facilities		128,524			–			128,524
Financing costs		(7,920	)		–			(7,920	)
Redemption of 8³/4% senior notes		(202,410	)		–			(202,410	)
Issuance of Series 1 Debentures		225,000			–			225,000
Settlement of swap liabilities		(91,125	)		–			(91,125	)
Proceeds from stock options exercised		963			–			963
Repayment of capital lease obligations		(5,127	)		–			(5,127	)
		(37,095	)		–			(37,095	)
Decrease in cash and cash equivalents		(102,224	)		(1,240	)		(103,464	)
Effect of exchange rate on changes in cash		(59	)		–			(59	)
Cash and cash equivalents, beginning of year		103,005			1,240			104,245
Cash and cash equivalents, end of year		$722			$–			$722


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Consolidated Statements of Cash Flows – for the year ended March 31, 2010


	US GAAP			Adjustments			Canadian GAAP
Cash provided by (used in):
Operating activities:
Net income for the period		$28,219			$955			$29,174
Items not affecting cash:
Depreciation		42,636			(124	)		42,512
Equity in earnings of unconsolidated joint venture		(44	)		44			–
Amortization of intangible assets		1,719			831			2,550
Amortization of deferred lease inducements		(107	)		–			(107	)
Amortization of deferred financing costs		3,348			(2,486	)		862
Loss on disposal of property, plant and equipment		1,233			–			1,233
Loss on disposal of assets held for sale		373			–			373
Unrealized foreign exchange gain on 8³/4% senior notes		(48,920	)		496			(48,424	)
Unrealized loss on derivative financial instruments measured at fair value		38,852			–			38,852
Stock-based compensation expense		5,270			(46	)		5,224
Cash settlement of stock options		(244	)		–			(244	)
Accretion of asset retirement obligation		5			–			5
Deferred income taxes		9,876			372			10,248
Net changes in non-cash working capital		(39,591	)		(1,675	)		(41,266	)
		42,625			(1,633	)		40,992
Investing activities:
Acquisition, net of cash acquired		(5,410	)		–			(5,410	)
Purchase of property, plant and equipment		(51,888	)		–			(51,888	)
Additions to intangible assets		(3,362	)		–			(3,362	)
Investment in and advances to unconsolidated joint venture		(2,873	)		2,873			–
Proceeds on disposal of property, plant and equipment		1,440			–			1,440
Proceeds on disposal of assets held for sale		2,482			–			2,482
		(59,611	)		2,873			(56,738	)
Financing activities:
Repayment of long term debt		(6,906	)		–			(6,906	)
Increase in long term debt		34,700			–			34,700
Financing costs		(1,123	)		–			(1,123	)
Proceeds from stock options exercised		53			–			53
Repayment of capital lease obligations		(5,613	)		–			(5,613	)
		21,111			–			21,111
Increase in cash and cash equivalents		4,125			1,240			5,365
Cash and cash equivalents, beginning of year		98,880			–			98,880
Cash and cash equivalents, end of year		$103,005			$1,240			$104,245


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Consolidated Statements of Cash Flows – for the year ended March 31, 2009


	US GAAP			Adjustments			Canadian GAAP
Cash provided by (used in):
Operating activities:
Net loss for the period		$(135,404	)		$(2,473	)		$(137,877	)
Items not affecting cash:
Depreciation		36,389			(162	)		36,227
Amortization of intangible assets		1,501			837			2,338
Impairment of goodwill		176,200			–			176,200
Amortization of deferred lease inducements		(105	)		–			(105	)
Amortization of deferred financing costs		2,970			(2,162	)		808
Loss on disposal of property, plant and equipment		5,325			–			5,325
Loss on disposal of assets held for sale		24			–			24
Unrealized foreign exchange loss on 8³/4% senior notes		46,466			(606	)		45,860
Unrealized gain on derivative financial instruments measured at fair value		(39,921	)		4,655			(35,266	)
Stock-based compensation expense		2,305			(55	)		2,250
Accretion of asset retirement obligation		155			–			155
Deferred income taxes		9,087			(34	)		9,053
Net changes in non-cash working capital		46,193			–			46,193
		151,185			–			151,185
Investing activities:
Purchase of property, plant and equipment		(87,102	)		–			(87,102	)
Additions to intangible assets		(3,102	)		–			(3,102	)
Proceeds on disposal of property, plant and equipment		11,164			–			11,164
Proceeds on disposal of assets held for sale		325			–			325
		(78,715	)		–			(78,715	)
Financing activities:
Proceeds from stock options exercised		703			–			703
Repayment of capital lease obligations		(6,156	)		–			(6,156	)
		(5,453	)		–			(5,453	)
Increase in cash and cash equivalents		67,017			–			67,017
Cash and cash equivalents, beginning of year		31,863			–			31,863
Cash and cash equivalents, end of year		$98,880			$–			$98,880


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The areas of material difference between Canadian and US GAAP and their effect on the Company’s consolidated financial statements are described below:

a) Capitalization of interest

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

b) Financing costs, discounts and premiums

Under US GAAP, deferred financing costs incurred in connection with the Company’s 9.125% Series 1 Debentures and 8³/4% senior notes were being amortized over the term of the related debt using the effective interest method. Prior to April 1, 2007, the transaction costs on the 8³/4% senior notes were recorded as a deferred asset under Canadian GAAP and these deferred financing costs were being amortized on a straight–line basis over the term of the debt.

Effective April 1, 2007, the Company adopted CICA Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, on a retrospective basis without restatement. Although Section 3855 also requires the use of the effective interest method to account for the amortization of finance costs, the requirement to bifurcate the issuer’s early prepayment option on issuance of debt (which is not required under US GAAP) resulted in an additional premium of $3,497 on the Series 1 Debentures that is being amortized over the term of the Series 1 Debentures under Canadian GAAP. The same was being done on the extinguished 8³/4% senior notes. The unamortized premium is disclosed as part of the carrying amount of the “Series 1 Debentures” in the Consolidated Balance Sheets. Foreign denominated transaction costs, discounts and premiums on the 8³/4% senior notes were considered as part of the carrying value of the related financial liability under Canadian GAAP and were subject to foreign currency gains or losses resulting from periodic translation procedures as they were treated as a monetary item under Canadian GAAP. Under US GAAP, foreign denominated transaction costs are considered non–monetary and are not subject to foreign currency gains and losses resulting from periodic translation procedures. The unamortized discounts and premiums on the 8³/4% senior notes were expensed on the settlement of the 8³/4% senior notes under both Canadian and US GAAP with a difference of $2,884.

In connection with the adoption of Section 3855, transaction costs incurred in connection with the Company’s amended and restated credit agreement of $1,622 were reclassified from deferred financing costs to intangible assets on April 1, 2007 under Canadian GAAP and these costs continued to be amortized on a straight–line basis over the term of the credit facilities. Under US GAAP, the Company continues to amortize these transaction costs over the stated term of the related facilities using the effective interest method. The Company discloses the unamortized deferred financing costs related to the Series 1 Debentures, the 8³/4% senior notes and the credit facilities as “Deferred financing costs” on the Consolidated Balance Sheets (March 31, 2011 – $7,672; March 31, 2010 – $6,725) with the amortization charge classified as “Interest expense” on the Consolidated Statement of Operations and Comprehensive (Loss) Income. Under Canadian GAAP, the unamortized financing costs related to the Series 1 Debentures (March 31, 2011 – $6,165) and the 8³/4% senior notes (March 31, 2010 – $1,506) are included in “Series 1 Debentures” and “8³/4% senior notes” respectively whilst the unamortized deferred financing costs in connection with the credit facilities (March 31, 2011 – $1,378; March 31, 2010 – $1,051) are included in “Intangible assets” on the Consolidated Balance Sheets resulting in a Canadian and US GAAP presentation difference.

c) Stock–based compensation

Up until April 1, 2006, the Company followed the provisions of ASC 718, “Compensation-Stock Compensation”, for US GAAP purposes. As the Company uses the fair value method of accounting for all stock–based compensation payments under Canadian GAAP, there were no differences between Canadian and US GAAP prior to April 1, 2006. On April 1, 2006, the Company adopted the provisions of SFAS No. 123(R), “Share–Based Payment”, which is now a part of ASC 718. As the Company used the minimum value method for purposes of complying with ASC 718, it was required to adopt the provisions under the revised guidance prospectively. Under Canadian GAAP, the Company was permitted to exclude volatility from the determination of the fair value of stock options granted until the filing of its initial registration statement relating to the initial public offering of voting shares on July 21, 2006. As a result, for options issued between April 1, 2006 and July 21, 2006, there is a difference between Canadian and US GAAP relating to the determination of the fair value of options granted.

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 changing classification from equity to a long term liability. Under US GAAP, such modification is measured at fair value using a model such as Black–Scholes. Under Canadian GAAP, stock options that are cash settled are measured at the amount by which the quoted market value of the shares of the Company’s stock covered by the grant exceeds the option price. This resulted in a measurement difference between US and Canadian GAAP. At March 31, 2011, the liability under US GAAP was measured at $5,115 of which $2,237 was transferred from additional paid-in capital and the difference of $2,878 was recognized as incremental compensation cost in the Consolidated Statements of Operations under general and administrative expenses. Under Canadian GAAP, the liability was measured at $3,795 resulting in a transfer of the same amount from additional paid-in capital and the difference of $1,558 was recognized as incremental compensation cost.


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d) Derivative financial instruments

Under Canadian GAAP, the Company determined that the issuer’s early prepayment option included in the Series 1 Debentures of $3,895 should be bifurcated from the host contract, along with a contingent embedded derivative liability of $398 in the Series 1 Debentures that provides for accelerated redemption by the holders in certain instances. These embedded derivatives were measured at fair value at April 7, 2010, the inception date of the Series 1 Debentures with the residual amount of the proceeds being allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of the Series 1 Debentures is accreted to par value over the term of the Series 1 Debentures using the effective interest method and is recognized as interest expense as discussed in b) above. The same accounting treatment was used on the extinguished 8³/4% senior notes.

Under US GAAP, ASC 815, “Derivatives and Hedging”, establishes accounting and reporting standards requiring that every derivative instrument, including certain derivative instruments embedded in other contracts and debt instruments, be recorded on the Balance Sheet as either an asset or liability measured at its fair value. The contingent embedded derivative in the Series 1 Debentures that provides for accelerated redemption by the holders in certain instances did not meet the criteria for bifurcation from the debt contract and separate measurement at fair value and was not bifurcated from the host contract and measured at fair value resulting in a US GAAP and Canadian GAAP difference. The contingent embedded derivative in the 8³/4% senior notes that provide for accelerated redemption by the holders in certain instances met the criteria for bifurcation from the debt contract and separate measurement at fair value. The embedded derivative in the 8³/4% senior notes was measured at fair value and changes in fair value recorded in net income for all periods presented. The issuer’s early prepayment option included in both the Series 1 Debentures and the 8³/4% senior notes did not meet the criteria as an embedded derivative under ASC 815 and was not bifurcated from the host contract resulting in a US GAAP and Canadian GAAP difference.

e) NAEPI Series B Preferred Shares

Prior to the modification of the terms of the NAEPI Series B preferred shares on March 30, 2006, there were no differences between Canadian GAAP and US GAAP related to the NAEPI Series B preferred shares. As a result of the modification of terms of NAEPI’s Series B preferred shares, under Canadian GAAP, NACG continued to classify the NAEPI Series B preferred shares as a liability and was accreting the carrying amount of $42.2 million on the amendment date (March 30, 2006) to their December 31, 2011 redemption value of $69.6 million using the effective interest method. Under US GAAP, NACG recognized the fair value of the amended NAEPI Series B preferred shares as noncontrolling interest as such amount was recognized as temporary equity in the accounts of NAEPI in accordance with ASC 480-10-599, “Distinguishing Liabilities from Equity – SEC Materials” and recognized a charge of $3.7 million to retained earnings for the difference between the fair value and the carrying amount of the Series B preferred shares on the amendment date. Under US GAAP, NACG was accreting the initial fair value of the amended NAEPI Series B preferred shares of $45.9 million recorded on their amendment date (March 30, 2006) to the December 31, 2011 redemption value of $69.6 million using the effective interest method, which was consistent with the treatment of the NAEPI Series B preferred shares as temporary equity in the financial statements of NAEPI. The accretion charge was recognized by NACG as a charge to noncontrolling interest (as opposed to retained earnings in the accounts of NAEPI) under US GAAP and interest expense in NACG’s financial statements under Canadian GAAP.

On November 28, 2006, NACG exercised a call option to acquire all of the issued and outstanding NAEPI Series B preferred shares in exchange for 7,524,400 common shares of NACG. For Canadian GAAP purposes, NACG recorded the exchange by transferring the carrying value of the NAEPI Series B preferred shares on the exercise date of $44,682 to common shares. For US GAAP purposes, the conversion has been accounted for as a combination of entities under common control as all of the shareholders of the NAEPI Series B preferred shares are also common shareholders of NACG resulting in the reclassification of the carrying value of the noncontrolling interest on the exercise date of $48,140 to common shares.

f) Inventories

Effective April 1, 2008, the Company retrospectively adopted CICA Handbook Section 3031, “Inventories”, without restatement of prior periods. This standard requires inventories to be measured at the lower of cost and net realizable value and provides guidance on the determination of cost, including the allocation of overheads and other costs to inventories, the requirement for an entity to use a consistent cost formula for inventory of a similar nature and use, and the reversal of previous write-downs to net realizable value when there are subsequent increases in the value of inventories. This new standard also clarifies that spare component parts that do not qualify for recognition as property, plant and equipment should be classified as inventory. In adopting this new standard, the Company reversed a tire impairment that was previously recorded at March 31, 2008 in other assets of $1,383 with a corresponding decrease to opening deficit of $991 net of future taxes of $392.

g) Joint venture

Under US GAAP, the Company records its share of earnings of the JV using the equity method of accounting. Under Canadian GAAP, the Company uses the proportionate consolidation method of accounting for the JV. Under the proportionate consolidation method the Company recognizes its share of the results of operations, cash flows, and financial position of the JV on a line–by–line basis in its consolidated financial statements. While there is no effect on net income or earnings per share as a result of the US GAAP treatment of the joint venture, as compared to Canadian GAAP, there are


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presentation differences affecting the disclosures in the consolidated financial statements and the supporting notes. Under Canadian GAAP, the following assets, liabilities, revenues and expenses and cash flows would be recorded using the proportionate consolidation method:


	March 31, 2011		March 31, 2010
Current assets		$4,164		$4,476
Long term assets		–		77
Current liabilities		6,937		1,636
Long term liabilities		–		2,970
Net equity		$(2,773)		$(53)


Year ended March 31	2011		2010			2009
Gross revenues		$6,098		$4,336			$–
Gross loss (profit)		1,241		(805	)		–
Expenses		1,479		761			–
Net loss (income)		$2,720		$(44)			$–


Year ended March 31	2011		2010		2009
Cash flow resulting from operating activities		$(2,078)		$(1,633)		$–
Cash flow resulting from investing activities		838		2,873		–
(Decrease) increase in cash and cash equivalents		$(1,240)		$1,240		$–

h) Other matters

Other adjustments relate to the tax effect of items (a) through (f) above. The tax effects of temporary differences are described as future income taxes under Canadian GAAP whereas in these financial statements such amounts are described as deferred income taxes under US GAAP. In addition, Canadian GAAP generally refers to additional paid–in capital as contributed surplus for financial statement presentation purposes.

i) Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company manages liquidity risk through management of its capital structure and financial leverage, as outlined in note 32(j). It also manages liquidity risk by continuously monitoring actual and projected cash flows to ensure that it will have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to the Company’s reputation. The Company believes that forecasted cash flows from operating activities, along with amounts available under the Revolving Facility, will provide sufficient cash requirements to cover the Company’s forecasted normal operating and budgeted capital expenditures.

The Company’s credit agreement contain covenants that restrict its activities, including, but not limited to, incurring additional debt, transferring or selling assets and making investments including acquisitions. Under credit agreement, Consolidated Capital Expenditures, as defined in the revolving credit agreement, during any applicable period cannot exceed 120% of the amount in the capital expenditure plan. In addition, the Company is required to satisfy certain financial covenants, including a minimum interest coverage ratio and a maximum senior leverage ratio, both of which are calculated using Consolidated EBITDA, as defined in the credit agreement, as well as a minimum current ratio.

As at March 31, 2011, the Company was in violation of certain financial covenants as defined within the credit agreement. On May 20, 2011, the Company obtained an amendment in connection with such covenants from its lenders resulting in compliance as at March 31, 2011. The Company considers it probable that they will be in compliance with these covenants throughout the fiscal year ending March 31, 2012.

The following are the undiscounted contractual cash flows of financial liabilities and other contractual cash flows measured at period end exchange rates:


	Carrying Amount		Contractual Cash Flows		Fiscal year
	Carrying Amount		Contractual Cash Flows		2012		2013		2014		2015		2016 and Thereafter
Accounts payable and accrued liabilities (excluding liabilities related to equipment lease)		$104,159		$104,159		$104,159		$–		$–		$–		$–
Liabilities related to equipment lease		20,265		20,265		7,518		5,345		3,657		3,726		19
Capital lease obligations (including interest)		8,693		9,257		5,267		3,087		562		270		71
Term facilities		68,446		68,446		10,000		10,000		48,446		–		–
Revolving facility		3,524		3,524		–		–		3,524		–		–
Series 1 Debentures		225,000		225,000		–		–		–		–		225,000
Accrued interest on Series 1 Debentures		9,866		102,656		20,531		20,531		20,531		20,531		20,531


2011 Annual Report		\| NOA \|			113

j) Capital disclosures

The Company’s objectives in managing capital are to help ensure sufficient liquidity to pursue its strategy of organic growth combined with strategic acquisitions and to provide returns to its shareholders. The Company defines capital that it manages as the aggregate of its shareholders’ equity, which is comprised of issued capital, additional paid-in capital, accumulated other comprehensive income (loss). The Company manages its capital structure and makes adjustments to it in light of general economic conditions, the risk characteristics of the underlying assets and the Company’s working capital requirements. In order to maintain or adjust its capital structure, the Company, upon approval from its Board of Directors, may issue or repay long term debt, issue shares, repurchase shares through a normal course issuer bid, pay dividends or undertake other activities as deemed appropriate under the specific circumstances. The Board of Directors reviews and approves any material transactions out of the ordinary course of business, including proposals on acquisitions or other major investments or divestitures, as well as capital and operating budgets.

The Company monitors debt leverage ratios as part of the management of liquidity and shareholders’ return and to sustain future development of the business. The Company is also subject to externally imposed capital requirements under its Credit Facilities and indenture agreement governing the 9.125% Series 1 Debentures, which contain certain restrictive covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions or to pay dividends or redeem shares of capital stock. As at March 31, 2011, the Company was in violation of certain financial covenants as defined within the credit agreement. On May 20, 2011, the Company obtained an amendment in connection with such covenants from its lenders resulting in compliance as at March 31, 2011. The Company considers it probable that they will be in compliance with these covenants throughout the fiscal year ending March 31, 2012. The Company’s overall strategy with respect to capital risk management remains unchanged from the year ended March 31, 2010.

In September 2009, the Company filed a base shelf prospectus covering the public offering of common shares in each of the provinces and territories of Canada and a related registration statement with the United States Securities and Exchange Commission. These filings allow the Company to offer and issue common shares to the public by way of one or more prospectus supplements at any time during the 25 month period following the filing of the prospectus with gross proceeds to the Company not to exceed $150.0 million. The prospectus also allows certain shareholders of the Company to offer all or part of their common shares to the public by way of one or more prospectus supplements.


114		\| NOA \|		2011 Annual Report

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Board of Directors

Ronald A. McIntosh George R. Brokaw John A. Brussa Peter R. Dodd

Director since May 2004 Director since June 2006 Director since Director since June 2009

Chair of the November 2003

Board of Directors

John D. Hawkins William C. Oehmig Rodney J. Ruston Allen R. Sello

Director since Director since Director since May 2005 Director since

October 2003 November 2003 President and CEO January 2006

Chair of the Governance Chair of the HS&E and Chair of the Audit Committee

Committee Business Risk Committee

Peter W. Tomsett K. Rick Turner

Director since Director since

September 2006 November 2006

Chair of the Compensation

Committee

2011 Annual Report | NOA | 115

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Senior Management

Rodney J. Ruston David Blackley Bernard T. Robert

President and Chief Financial Officer Vice President,

Chief Executive Officer Corporate Services

Christopher R. Yellowega Joseph C. Lambert

Vice President, Business Vice President, Oil Sands

Services and Construction Operations

116 | NOA | 2011 Annual Report

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Corporate Information Investor Information

Corporate Headquarters Investor Relations

2400, 500-4th Avenue SW Kevin Rowand

Calgary, Alberta T2P 2V6 Phone: 780.969.5528

Phone: 403.767.4825 Fax: 780.969.5599

Fax: 403.767.4849 Email: IR@nacg.ca

Auditors Web: www.nacg.ca

KPMG LLP

Edmonton, Alberta Annual General Meeting

Solicitors The Annual General Meeting of

Bracewell & Giuliani LLP North American Energy Partners Inc.

Houston, Texas will be held:

September 27, 2011 at 3:00 p.m.

Borden Ladner Gervais LLP Calgary Petroleum Club

Toronto, Ontario 319-5th Avenue SW, Calgary, Alberta

Exchange Listings

Toronto Stock Exchange

New York Stock Exchange

Ticker Symbol: NOA

Transfer Agent

CIBC Mellon Trust Company

600 The Dome Tower

333-7th Avenue SW

Calgary, Alberta T2P 2Z1

Phone: 403.232.2400

Email: inquiries@cibcmellon.com

Web: www.cibcmellon.com

LOGO

NORTH AMERICAN

ENERGY PARTNERS INC.

Printed in Canada