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 2009

Commission File Number 001-33161

NORTH AMERICAN ENERGY PARTNERS INC.

Zone 3 Acheson Industrial Area

2-53016 Highway 60

Acheson, Alberta

Canada T7X 5A7

(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 þ

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): ¨

Indicate by check mark whether by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes ¨ No þ

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): .

Documents Included as Part of this Report

1.	2009 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 26, 2009

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NORTH AMERICAN ENERGY PARTNERS INC. 2009 ANNUAL REPORT

what if? A Story of Stability in Turbulent Times

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The world has changed in recent months. Commodity prices have plummeted and credit has become both more expensive and difficult to secure. Development projects in the oil sands have been delayed and commercial construction has slowed. In the midst of all this, changing political winds are blowing in new ideas about how and where we will source our energy in the future. For North American Energy Partners, these events raise critical questions: What if oil sands development is changing? What if tougher economic conditions are with us for a long time? What if the future of energy looks dramatically different than it does today? The simple answer to these key questions for North American Energy Partners is that we believe our business would continue to thrive. Our 2009 annual report is devoted to explaining why.

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2009 Performance Highlights References to 2009 refer to the fiscal period April 1, 2008 to March 31, 2009 (in thousands of dollars except ratio and per share amounts)

2009 2008 2007

Operating Data

Revenue 972,536 989,696 629,446 Gross profit 175,305 163,317 92,436 Gross profit per cent 18.0% 16.5% 14.7% Operating (loss) income (1) (81,712) 92,397 51,126 Net (loss) income (1) (139,515) 39,784 21,079 Per share information Net (loss) income – basic (3.87) 1.11 0.87 Net (loss) income – diluted (3.87) 1.08 0.83 Consolidated EBITDA (2) 146,046 135,094 90,235

Balance Sheet Data

Total assets 630,052 793,598 710,736 Shareholders’ equity 147,437 283,364 244,278 Net debt (3) to total shareholders’ equity 1.6:1 1.0:1 1.3:1

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

(2) For a definition of Consolidated EBITDA (as defined within the revolving credit agreement) and reconciliation to net income, see “Non-GAAP Financial Measures.” (3) Net debt is calculated as senior notes, current and non-current portions of derivative financial instruments and capital lease obligations and borrowing under our revolving credit facility, less cash and cash equivalents.

Table of Contents

02 At a Glance 04 Letter to Shareholders 08 What if? 17 Management’s Discussion and Analysis

63 Management’s Report 64/65 Report of Independent Registered Public Accounting Firm

66 Consolidated Financial Statements 69 Notes to the Consolidated Financial Statements

107 Board of Directors 108 Senior Management inside back cover Corporate and Investor Information

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About North American Energy Partners

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.

In November 2006, our common shares began trading on the Toronto and New York Stock Exchanges under the ticker symbol NOA.

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

> Everyone wants to own

Revenue by Segment (Fiscal 2009) 74% Heavy Construction and Mining 16% Piling 10% Pipeline

Revenue by End Market (Fiscal 2009) 83% Canadian Oil Sands 10% Conventional Oil & Gas

7% Commercial and Public Construction

Revenue Mix for Oil Sands (Fiscal 2009) 65% Recurring Services 35% Project Development

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

> Caisson and earth retention and stabilization systems for industrial and commercial projects

Pipeline Installation Expertise

> Installation of transmission and distribution pipe made of various materials

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NORTH AMERICAN

ENERGY PARTNERS INC.

Revenue (in millions) 24.3% CAGR(1) since 2007

2009 $972.5 2008 $989.7 2007 $629.4

Gross profit (in millions) 37.7% CAGR(1) since 2007

2009 $175.3 2008 $163.3 2007 $92.4

Consolidated EBITDA (in millions)

27.2% CAGR(1) since 2007

2009 $146.0 2008 $135.1 2007 $90.2

(1) Refers to compound annual growth rate.

Heavy Equipment Fleet

March 31, 2009

211 Haul Trucks

121 Shovels and Excavators 124 Dozers 102 Drill Rigs, Cranes and Pipelayers 170 Other Heavy Equipment 728 Fleet Total

Our Short-Term Strategy

> Pursue long-term strategic partnerships

> Carefully manage costs and liquidity

Our Long-Term Strategy

> Leverage and expand our integrated service offering

> Enhance our competitive position by increasing our operating efficiencies

> Continue to emphasize safety culture

> Position for growth

> Increase presence outside of the oil sands

North American Energy Partners Inc At A Glance 03

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04 Letter to Shareholders North American Energy Partners Inc. North American Energy Partners turned in strong operating performance in fiscal 2009, achieving revenue of $972.5 million and the best gross profit and Consolidated EBITDA results in our history.

The impact of these events led to a $176.2 million writedown of goodwill, which in turn created a net loss for the year. I want to emphasize that the writedown was a non-cash charge undertaken in line with required accounting principles and related to the decline in our market capitalization. It does not reflect the performance of our operating divisions, which was generally very good. Heavy Construction and Mining Our Heavy Construction and Mining division performed exceptionally well in fiscal 2009, with a growing volume of recurring services business helping to drive segment revenue of $716.1 million and segment profit of $115.7 million – both record results for this division. Recurring services include mining, overburden removal, hauling and other services that we provide to support the daily operations of active mine sites. These services tend The strength of our first three quarters played a significant role in these results, as did continuing strong demand for the recurring services that support our customers’ ongoing oil sands mining operations. Our solid operating performance, coupled with prudent cash management, resulted in a cash balance of $98.9 million at March 31, 2009, compared to $31.9 million a year ago. These results were achieved despite a sharp downturn in economic conditions, which included significantly lower prices for oil and a severe tightening of credit markets. By the end of calendar 2008, a number of oil sands companies announced reductions to their capital spending budgets, leading to delays and deferrals on a number of development projects. Commercial construction activity also slowed with a negative impact on our Piling segment. Letter to Shareholders

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North American Energy Partners Inc. Letter to Shareholders 05 to be immune to changing oil prices because active oil sands mines can only achieve competitive unit production costs if they are running near full capacity. To do that, they must maintain feed from the mine to the plant. While we have seen some fluctuation in production levels in response to maintenance requirements, all of the existing mines have continued to produce, even through the downturn in oil prices. The strength and stability of our recurring services business was particularly evident in the fourth quarter when tougher economic conditions severely reduced opportunities for work on new construction projects. Unrelated to the economic environment, we were also asked to temporarily stop work on our long-term overburden removal contract while our client, Canadian Natural Resources Limited, went through the start-up phase of their processing plant following completion of construction. Despite these impacts, our fourth quarter recurring services revenue continued to climb, thanks to increased demand from other projects like Albian’s Jackpine and Muskeg River mines. Full-year recurring services revenue increased 39% compared to fiscal 2008 and represented 73% of our Heavy Construction and Mining revenue. The balance came from project development work, which was strong through the first three quarters. In particular, our work on Petro-Canada’s Fort Hills project and Suncor’s Voyageur and Millennium Naphtha Unit projects contributed to our results. The momentum slowed in the fourth quarter after our work on the Voyageur project wrapped up and the Fort Hills project was put on hold. However, we are encouraged by some recent developments. The proposed merger between Suncor and Petro-Canada is expected to have a positive impact on oil sands investment by creating a single entity with the resources to support the continued development of these large capital projects. In addition, Imperial Oil has recently announced it will proceed with the Kearl project. We anticipate an overall improvement in the market for oil-sands related construction services as a result of these announcements. Since year-end, we have also secured several industrial construction contracts totaling approximately $65 million. Two of these contracts take us into Saskatchewan to support the construction of a new refinery. The other contracts continue to build on our existing relationships in the oil sands. While these contracts will not counteract the impact of reduced project development in the near term, we believe they provide a strong signal that development of economically sound projects is on the way back. We also remain very positive about our recurring services business. Although we anticipate some near-term variability in demand, we expect growth to resume in the second half of fiscal 2010 as our overburden removal contract with Canadian Natural ramps up again, financial markets stabilize and cost-effective funding becomes more readily available to promote business growth. In the meantime, we are benefiting from several new recurring services agreements. We recently initiated some new mine support services to Suncor, a development that we believe carries additional potential. At the same time, with the commencement of oil production at Canadian Natural’s Horizon Project, we have begun to provide mine support services in addition to our overburden removal contract. This is an excellent example of our “First On, Last Off” oil sands strategy. We first established our relationship with Canadian Natural while providing the initial construction services for the Horizon project. We have since transitioned into the provision of overburden removal and with the mine now up and running, we have begun to provide mine support services as well.

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Piling Our Piling division had a mixed year in fiscal 2009, closely mirroring events in the general economy. During the first six months, this segment performed strongly as robust economic conditions continued to support a high level of commercial and industrial construction activity. However, this division quickly felt the impact of the downturn that emerged in the second half. Segment revenue of $155.1 million and segment profit of $38.8 million were down 4.5% and 14.5% respectively, year-over-year. While Piling has been the part of our business most immediately affected by the change in economic conditions, it is also the part of our business most likely to benefit from increased infrastructure spending as governments work to stimulate the economy. Between 2009 and 2012, the government of Alberta plans to spend $7.7 billion annually on capital projects. The Ontario government recently announced $27.5 billion of infrastructure spending over the next two years. Additionally, Canada’s federal government has unveiled a budget which includes $12 billion of new infrastructure spending. As one of Western Canada’s largest and most experienced piling companies, we expect to benefit from this infusion of investment. We have also recently opened an office in Toronto and are now actively bidding projects in the Ontario market. In addition, we are continuing to benefit from our market lead with continuous flight auger (CFA) piling technology, a highly efficient and environmentally sensitive piling technique that is gaining momentum in Canada. We recently won a significant piling contract in Saskatchewan based on our ability to bid CFA technology. Overall, while we expect demand for piling services will remain constrained by the reduction in commercial construction and oil sands development activity, the new pool of infrastructure projects and our expansion into new regions and technologies should help to create important offsets. Pipeline One of the highlights of the fiscal 2009 year was our successful completion of the TMX Anchor Loop project for our client, Kinder Morgan Canada. This 160-kilometer-long pipeline project was one of the most environmentally demanding pipeline installations ever undertaken in Canada and it furthered our reputation for being able to take on highly complex projects and manage them effectively. The TMX project also had a highly positive financial impact on our Pipeline division. That benefit was greatest in fiscal 2008 when the project was in full swing, however, the completion period in fiscal 2009 also provided a significant contribution. The Pipeline segment achieved revenue of $101.4 million and segment profit of $22.5 million in fiscal 2009, primarily due to this contract. As is typical of our Pipeline business, revenues have declined sharply following completion of this major contract as we assess opportunities for profitable new projects. We are currently reviewing a number of new opportunities. However, the competitive landscape has changed in both the number of bidders competing for work and the margins and risk that our competitors are willing to accept. Given our emphasis on maintaining acceptable levels of profitability, we anticipate that it could take some time to find a project that meets our criteria. Importantly, the holding cost of this division is very low and unlike some organizations, we are not compelled to take on low-value work. Moving Forward in the New Business Environment As we move forward in a less certain economic environment, our focus remains on solid execution, tight cost control and increased cash flow generation. The new business processes we introduced in recent years have greatly improved our ability to manage our equipment and people resources in a flexible manner. We are putting this to work as we find the most efficient and cost-effective ways to provide services for our customers. On the cash flow front, we are benefiting from the major investments made in our equipment fleet during the past three or four years, when economic conditions were stronger. We are now moving forward with a large and well-maintained fleet that requires few additional capital investments to support current business levels. This enabled us to strengthen our cash position last year and we expect to make continued progress in fiscal 2010. Our improved cash position has strengthened our balance sheet by reducing our net debt, an important consideration in a business environment where new credit is hard to come by and expensive to secure. We have two and a half years before our senior notes mature and with our demand for capital reduced compared to prior years, we expect to be well positioned to refinance this facility when the time comes. 06 Letter to Shareholders North American Energy Partners Inc.

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Overall, while we are facing challenging times, we have reason for optimism. We occupy market niches that will provide ongoing demand and we are encouraged by our recent contract wins and by our new venture into the Ontario market. We are also moving forward with significant business strengths that enhance our ability to compete effectively. Most importantly, we have talented and experienced people, who help us succeed in all kinds of business environments. One of these people, Peter Dodd, retired as Chief Financial Officer effective June 10, 2009. Peter joined North American Energy Partners at a time when we were experiencing unprecedented growth and needed a seasoned financial and strategic leader who could assist in managing that growth. Peter has more than met the challenge and we have attained a new level of financial sophistication under his watch. I am delighted to report that Peter has now joined the Company’s Board of Directors, ensuring we will continue to benefit from his wise counsel. We are also fortunate to have a highly capable and respected financial executive in place, who immediately assumed the CFO position following Peter’s retirement. David Blackley, previously Vice President Finance, joined the Company in early 2008, bringing seasoned financial acumen and an impressive array of accomplishments. I am fully confident that David has the right leadership and financial skills to support our strategic goals going forward. In closing, I want to thank all of our employees for their exceptionally hard work and hands-on role in driving our continued success. My appreciation also goes to our talented and engaged board of directors, who have supported and advised management throughout the good and not-so-good times of the past 12 months. Finally, I thank you, our shareholders, for your continued support through these challenging times. We see a strong future for North American Energy Partners and we hope you will stay involved. Rod Ruston President & Chief Executive Officer what if oil sands page 08 development is changing? what if tougher economic page 12 conditions are with us for a long time? what if the future of energy page 14 looks dramatically different than it does today?

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what oil sands if development is changing? The past year brought dramatic changes to Alberta’s oil sands. After years of rampant growth, the pace of expansion slowed abruptly as oil demand and prices weakened and the global financial crisis put pressure on credit supply. Several projects that were well advanced continued to move forward but many in earlier stages of development were delayed or cancelled as major oil sands producers assessed their future plans. being located in a politically stable and secure country next door to the United States. Most experts agree this resource will necessarily play an important role in future global energy supply. As demand continues to grow, the need for new solutions to meet the world’s ever-increasing appetite for energy has never been greater. Alternative energy sources are expected to eventually supply a growing portion of this demand but the majority will almost certainly continue to come from fossil fuels. These changes created questions for investors. Is the future of the oil sands changing? If so, what does that mean for North American Energy Partners? The Role of the Oil Sands in World Oil Supply Our outlook for the oil sands and particularly our role in it remains positive. Canada’s oil sands contain the world’s second largest proven reserves of oil, second only to Saudi Arabia. At a time when conventional oil sources are declining, the oil sands hold an estimated 173 billion barrels of recoverable oil. They also have the advantage of

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North American Energy Partners Inc. Operations Review 09 Currently Canada’s oil sands contribute about 1.2 million barrels of oil per day, which supplies about 19% of US oil imports. According to IHS Cambridge Energy Research Associates (CERA), one of North America’s premier energy research firms, the potential exists for oil sands output to rise to 6.3 million barrels a day, or 37% of US oil imports, by 2035. CERA acknowledges that this level of growth could be hampered by continuing economic malaise, low oil prices and environmental concerns over the oil sands’ carbon footprint but even in its most pessimistic projection, CERA still predicts that oil sands production will rise to 2.3 million barrels by 2035. The reason? There is a large and growing base of existing oil sands operations and these mines are not likely to reduce production under any foreseeable circumstance. Operational Mines Keep Operating Oil sands projects are mega projects that require billions of dollars and an intense three to four-year development phase to bring to life. Once up and running, they have an average 30 to 40-year operational life and few will undergo any significant production slowdown during that period. The fact is, there are powerful financial and technical reasons encouraging operational oil sands mines to keep on producing. With respect to the financial motivation, oil sands projects are high fixed-cost, low operating cost businesses. Once the massive capital investment is made, producers need to maximize production in order to minimize their cost per barrel and remain competitive. What’s more, average cash operating costs have historically remained comfortably below the average price of oil, making these operations cash flow positive over the long run. On the technical front, oil sands projects operate in a region where temperatures range from -50°C to +33°C (-60°F to +90°F) and employ over 1,200 people. An extended plant shutdown leaves the owner at significant risk of either freezing the plant or losing skilled employees, or both, and the cost of repairs and/or retraining if these events come to fruition are prohibitive. These plants are built to run continously and they need ongoing mining and construction services to ensure a constant, good-quality feed can be directed to the processing facility.

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For evidence of the durability of operational oil sands projects, consider producers like Suncor and Syncrude. Both companies have maintained production through three decades of fluctuating market conditions, including the sustained low oil prices of the 1990s. In addition, none of the existing oil sands operators have reduced production targets since oil prices fell last year. All of the existing projects are operating at normal levels and creating a very stable demand for recurring services. Growing Demand for Recurring Services Recurring services include surface mining services such as land clearing and overburden removal; general support services such as road building and repair and maintenance services; and reclamation activities when mining in one area is completed and the operator wants to restore the land back to its natural state. This is North American Energy Partners’ core business and it is a growing business. Our revenue from recurring services has climbed from $217 million in fiscal 2007 to $524 million in fiscal 2009, reflecting both the new projects coming online and the expansion of existing projects. Our strong relationships with all of the oil sands producers have been established over years of building a reputation for delivering on time and on budget. Our customers know that we have the vital know-how to deliver a quality result in this harsh operating environment. As new projects like Syncrude’s Aurora, Suncor’s Steep Bank, Albian’s Muskeg River Mine and Canadian Natural’s Horizon mine have come on line, we have secured site services agreements with each of them. And there are more projects to come, including Albian’s Jackpine and Imperial Oil’s Kearl. As these mines mature, their need for recurring services will grow. That’s because operational mines must extend their geographic footprints as they deplete bitumen. This extension involves more overburden removal, additional road construction and longer haul distances, until a site becomes uneconomic and the operator relocates mine infrastructure in order to reduce haul distances. NAEP provides services as the mine expands, provides services to relocate the infrastructure and then provides services as the mine expands away from the new infrastructure location. Because we are on all operating sites, we are able to move our equipment to and from the sites to meet the fluctuating demands of the various customers. What About Project Development? While our recurring services business is expected to provide strong and growing volumes over the next few Ongoing Operations Phases – Overburden removal – Mine infrastructure development – Reclamation – Equipment and labour supply Time Frame = 30 to 40 Years Project Development Phases – Explore and design – Initial mine site development – Project site development including airstrips and pipeline construction Time Frame = 3 to 4 Years Recurring Revenue Operation and Ongoing Services accounts for 65% of NAEP’s Oil Sands Revenue 10 Operations Review North American Energy Partners Inc.

years, we are aware that it will not replace the industrial construction business lost as a result of project delays and deferrals. Our view is that this part of the business will eventually recover and that the correction currently taking place will ultimately be good for the industry. While the rampant growth phase of the past five years created plenty of momentum, it also brought escalating project costs and operational, infrastructure and environmental strains. The slowdown is now supporting a more orderly oil sands development, whereby both producers and suppliers can better control costs and efficiency, while addressing environmental concerns. This new discipline is already providing a more attractive environment for producers. Imperial Oil, for example, has recently decided the time is right to proceed with its Kearl project. Others will follow. Over time, we believe the project development side of our business will regain strength and together with our growing volume of recurring services work will LOGO create a more sustainable level of momentum for North American Energy Partners.

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tougher economic conditions are with us for a long time?

While our outlook for recurring services is positive and we expect to see new oil sands project activity recover eventually, the outlook for the global economy remains uncertain. How would North American Energy Partners fare if the recession were prolonged? Our analysis suggests we would make our way safely through. Here’s why:

Stability and Scalability

We believe that one of the greatest risks during a prolonged recession comes from the need to sustain adequate cashflows. For companies that lack a stable revenue base or a strong financial footing, the urgent need for cash flow can lead to underbidding contracts and the assumption of higher-than-normal levels of risk. Commonly, this is a pattern that leads to business failure.

At North American, our cash flow needs are secured by our large and stable recurring services base. As the largest part of our business, the stability provided by recurring services supports our ability to maintain margin and risk discipline in all other parts of our business. Meanwhile, we have kept those parts of our business that are most exposed to volume fluctuations as smaller overall contributors to our results and we have also structured them to be highly scalable.

Pipeline, which represents about 10% of our revenues, is a good example. Due to the fact that we work on just one or two large projects at a time, Pipeline is traditionally a “lumpy” business. We have structured the business accordingly, using an equipment rental strategy to help us maintain production flexibility and minimize our investment capital. We can also quickly pare down to just our core team of seasoned managers between contracts as pipeline workers tend to follow projects rather than companies.

Our Piling business, representing 16% of 2009 revenue, is similar in its ability to ramp up to meet the demands of large projects and ramp back down again when those projects finish. Like Pipeline, we can downsize this

12 Operations Review North American Energy Partners Inc.

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business without incurring significant costs or damaging our future productive capacity. Accordingly, while a pro-longed recession and a disciplined approach to bidding could certainly lead to lower revenues, we would remain profitable and cash positive overall. This fact alone would enhance our chances of survival through even a lengthy downturn.

The Potential for Increased Competition

Another key risk in a prolonged recession is increased competition for the available business. We have already seen this in the pipeline industry where 15 or more contractors are now bidding projects, compared to only a few bidding in the past when work was more plentiful. Piling is subject to similar pressures.

One part of our business that has seen almost no new competitive pressure is our oil sands business. All through the up cycle and now through the downturn, not a single new competitor entered the sector. Given the high barriers to entry and our significant competitive advantages, we do not see this changing in the near term.

North American Energy Partners has been operating in the oil sands for over 30 years and in the construction business for even longer. Over this time, we have built strong customer relationships and a broad service offering, while also gaining in-depth knowledge of how to operate in the harsh conditions of Northern Canada. We have also built the largest equipment fleet of any contract service provider in this region, with an emphasis on large mining trucks and shovels. No competitor could match our fleet in the boom years; we believe that it will be even harder to duplicate now. As an added strength, the combination of our equipment fleet and multiple customer relationships give us significant operating flexibility. A case in point: when Canadian Natural asked us to temporarily stop work on its overburden removal contract in the fourth quarter, we simply moved some of our people and equipment from that site to other sites. This not only helped our customer save money, it allowed us to assist two other customers while protecting our own revenue stream.

While it is always possible that new competitors could emerge in the oil sands, they would need to have very deep pockets and the patience to gradually build the customer relationships and expertise we already enjoy. In the interim, we are busy extending our market-leading position by putting our existing strengths to work for the benefit of our clients. At the end of the day, the most effective competitive advantage in any kind of market is a highly satisfied customer.

Outsourcing and the Benefits of a Large and Modern Fleet

During lengthy recessions, some types of business can actually benefit from weaker economic conditions. Third-party service and equipment suppliers are among these businesses, because customers intent on conserving cash will often increase their use of outsourcing to lower capital expenditures and reduce workforce size.

Our substantial fleet of 200-ton and larger mining truck sand large mining shovels makes the outsourcing decision all the easier for customers. Compared to the smaller 100 and 150-ton trucks, larger equipment enhances productivity and reduces site congestion. As one of the very few sources of temporary, third-party access to this type of equipment, our equipment fleet enhances our position with customers interested in outsourcing and creates a strong counter-cyclical revenue stream for us.

Interestingly, outsourcing relationships established during downturns often continue even after economic conditions normalize. That’s because the value and flexibility of third-party services has been recognized and accepted by the customer. The end result for the third party service and equipment supplier is a stable source of revenue through the recession and a well-developed customer relationship to build on when better times return.

North American Energy Partners Inc. Operations Review13

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the future of energy

looks dramatically different than it does today?

While we believe the oil sands will remain a core part of the worlds’ energy future, there are growing trends toward alternative and more renewable energy sources. How will this affect North American Energy Partners as these trends develop?

We are a Service Company

The key point to keep in mind is that we are a service company, not an oil company. We have a diverse service offering that ranges from site preparation, to piling, to construction, to maintenance, to reclamation. Virtually every type of large-scale industrial and commercial project in this country involves some of the services we provide, including projects designed to produce clean and renewable energy. Far from being threatened by these alternative energies, we see significant opportunity in them. The new windfarms and hydro projects slated for construction in Canada will require site clearing and construction services, while the new transmission lines will require significant piling support. We intend to be an active bidder on these projects.

While these alternative energy sources are under develop-meant, we believe that our oil sands customers will be simultaneously pursuing innovative new techniques that address concerns about environmental impact. This could lead to new methods of tailings management and the use of extraction techniques that reduce the carbon footprint. Far from diminishing our business opportunities, we believe these new methods will increase them. As an example, proposed new tailings techniques require significantly more earth moving and construction support than current methods do.

Tackling Environmentally Sensitive Projects

Hypotheses about future energy sources aside, one of the things we know for certain is that many of our customers are already finding ways to minimize the environmental impact of their industrial activity. We are actively engage din helping them.

The TMX Anchor Loop pipeline project for Kinder Morgan Canada is a case in point. In fiscal 2009, we completed the installation of this 160-kilometer stretch of pipeline across a remarkable piece of Canadian geography that included Jasper National Park, BC’s Mount Robson Provincial Park, the town of Jasper, Alberta and the world-renowned Rocky

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Mountains. This pristine area of the country is designated as a World Heritage Site by UNESCO and is home to many carefully protected ecosystems.

The project involved crossing over 125 environmentally sensitive, fish bearing rivers, including the Athabasca River (a Canadian Heritage River). We traversed the habitat of grizzly bears, elk, bighorn sheep and rams, mountain lions and wolves, as well as countless small animals, birds and rare plants and vegetation. Highly sensitive treatment of the area’s wildlife, river life and plant life was a foremost consideration. We also had to protect the beauty of one of the world’s most visually stunning parks, while respecting the people and communities we interacted with along the way.

The project was a success on all fronts. Parks Canada praised the way in which we conducted the work. The National Energy Board now uses the project as a training ground for its inspectors. Visually, it is nearly impossible to tell that a pipeline runs through these mountains. We also developed positive relationships with the local communities and our relationship with the Simpcw First Nation became so strong that that we are now discussingfuture collaborative projects.

The capabilities demonstrated on the TMX pipeline should serve us well as environmental expectations increase. We believe that those customers intent on reducing their environment impact will increasingly partner with service providers that have earned their credentials with success-ful, low-impact projects. We are that partner.

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The answer to the what if question – we’reready

Management’s Discussion and Analysis

The following discussion and analysis is as of June 9, 2009 and should be read in conjunction with the attached audited consolidated financial statements for the year ended March 31, 2009. These statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP) and reconciled to US GAAP. Except where otherwise specifically indicated, all dollar amounts are expressed in Canadian dollars. These consolidated financial statements and additional information relating to our business, including our Annual Information Form (AIF), are available on the Canadian Securities Administrators’ SEDAR System at www.sedar.com and the Securities and Exchange Commission’s IDEA System at www.sec.gov.

A. Business overview and strategy

Business Overview

We provide a wide range of heavy construction and mining, piling and pipeline installation services to customers in the Canadian oil sands, minerals mining, commercial and public construction and conventional oil and gas markets. Our primary market is the Alberta oil sands, where we support our customers’ mining operations and capital projects. While we provide services through all stages of an oil sands project’s lifecycle, our core focus is on providing recurring services, such as contract mining, during the operational phase. On a trailing 12-months basis to March 31, 2009, recurring services represented 65% of our oil sands business. Our principal oil sands customers include all four of the producers that are currently mining bitumen in Alberta: Syncrude Canada Ltd.¹ (Syncrude), Suncor Energy Inc. (Suncor) and Albian Sands Energy Inc.² (Albian) and Canadian Natural Resources Limited (Canadian Natural). We focus on building long-term relationships with our customers. For example, we have been providing services to Syncrude and Suncor for over 30 years.

We believe that we operate the largest fleet of equipment of any contract resource services provider in the oil sands. Our total fleet includes 728 pieces of diversified heavy construction equipment supported by over 900 ancillary vehicles. While our expertise covers mining, heavy construction, underground services (fire lines, sewer, water, etc.) for industrial projects, and piling and pipeline installation in many different types of locations, we have a specific capability operating in the harsh climate and difficult terrain of Northern Canada, particularly in the oil sands in Alberta.

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

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

Operations Overview

Our business is organized into three interrelated, yet distinct, operating segments: (i) Heavy Construction and Mining, (ii) Piling and (iii) Pipeline.

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

²	Joint venture amongst Shell Canada Limited (60%), Chevron Canada Limited (20%) and Marathon Oil Canada Corporation (20%).

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


				17

Management’s Discussion and Analysis

Revenue generated from these three segments for the year ended March 31, 2009 can be seen in the chart below³:

LOGO

Heavy Construction and Mining

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

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

the supply of labour and equipment to be operated within the customers’ mining fleet directly 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 including site development and construction of infrastructure; and

reclamation of completed mine sites to stringent environmental standards.

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

Piling

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

Pipeline

Our Pipeline segment installs transmission, distribution and gathering systems made of steel, fiberglass and/or plastic pipe in sizes up to 52” in diameter. Penstock installation services are also provided. This segment has successfully completed jobs of varying magnitude for some of Canada’s largest energy companies. The most recent project was Kinder Morgan’s Trans Mountain Expansion (TMX) Anchor Loop pipeline, which involved the installation of 160 km of large-diameter pipe through extremely challenging and ecologically sensitive terrain. The project, which runs from Hinton, Alberta through Jasper National Park, across the Rocky Mountains and through to Mt. Robson Provincial Park in British Columbia, was successfully completed with minimal impact to the environment.

³	Please refer to “Analysis of Annual Results” for a discussion on segment results.


		18

Management’s Discussion and Analysis

End Markets Overview

We provide services to four distinct end markets: Canadian oil sands, conventional oil and gas, commercial and public construction and minerals mining. Revenue generated from these four end markets for the year ended March 31, 2009, can be seen in the chart below⁴:

LOGO

Canadian Oil Sands

Our core market is the Alberta oil sands, where we generated 83% of our fiscal 2009 revenue. According to the Canadian Association of Petroleum Producers (CAPP), the oil sands represent 97% of Canada’s recoverable oil reserves. At 173 billion barrels, the Canadian oil sands deposits are second only to those of Saudi Arabia. The oil sands are located in three regions of northern Alberta: Athabasca, Cold Lake and Peace River. In 2008, oil sands production reached 1.2 million barrels per day (“bpd”), representing 44.8% of Canada’s total oil production.

Oil sands are grains of sand covered by a thin layer of water and coated by heavy oil or bitumen. Bitumen, because of its structure, does not flow and therefore requires non-conventional extraction techniques to separate it from the sand and other foreign matter. There are currently two main methods of extraction: (i) open pit mining, where bitumen deposits are sufficiently close to the surface to make it economically viable to recover the bitumen by treating mined sand in a surface plant; and (ii) in situ, where bitumen deposits are buried too deep for open pit mining to be cost effective and operators instead inject steam into the deposit so that the bitumen can be separated from the sand and pumped to the surface. CAPP estimates that approximately 20% of the oil sands are recoverable through open pit mining.

We currently provide most of our services to customers that access the oil sands through open pit mines. These customers utilize our services at various stages of their projects. The three-to-four year initial construction and development phase of a new mine creates demand for our project development services, such as clearing, site preparation, piling and underground utilities installation. As the mine moves into the 30-40 year operational phase, 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 65% of our oil sands-related revenue, for the year ended March 31, 2009, comes from the provision of recurring services to existing oil sands projects, with the balance coming from project development.

LOGO

⁴	For the year ended March 31, 2009 we did not generate revenues by minerals mining.

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


				19

Management’s Discussion and Analysis

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

Production increases in the oil sands occur through the elimination of bottlenecks and / or expansion of existing oil sands operations, as well as through new mines that have entered their production phase. In both cases, 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 and mine maintenance services.*

The requirement for recurring services also typically grows as mines age. Mine operators tend to construct their plants closest to the easy-to-access bitumen deposits to maximize profitability and cash-flow at the beginning of their project. As the mines move through their typical 30-40 year life cycle, easy-to-access bitumen deposits are depleted and operators must go greater distances and move more material to access their ore reserves. Over this period, haulage distances progressively increase and the amount of overburden to be removed per cubic meter of exposed oil sand grows. As a result, the total capacity of digging and hauling equipment must increase together with an increase in ancillary equipment and services 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, which we also provide. 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.*

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 2007, over $70.9 billion of capital has been invested into the oil sands, the core market for our project development services.*

Current Canadian Oil Sands Business Conditions

Recurring Services: In 2008, oil prices dropped significantly from record highs, leading to a view that the oil sands had become less viable. However, there was little change in production activity at operational oil sands projects as these mines are largely insensitive to short-term changes in oil prices. This is due to the immense up-front capital investment associated with these projects and the need to operate them at full capacity to achieve low per-unit operating costs. In addition, oil sands plants are not designed for temporary production shutdowns and the costs, delays and potential risks associated with a temporary production stoppage virtually eliminate this option for oil sands producers. For these reasons, we believe that oil sands operators will continue to maintain stable production activity through short-term declines in oil prices.*

Moreover, we believe that demand for recurring services in the oil sands will continue to grow over the long-term as existing oil sands mines progress and as new mines entering or nearing production, such as Canadian Natural’s Horizon mine and Albian’s Jackpine mine, come on-line.*

Project Development: In contrast to our recurring services business, demand for project development services is more sensitive to a downturn in the global economy. As an example, several oil sands producers adjusted their near-term capital spending plans during 2008 in response to weaker commodity, equity and credit market conditions. Petro-Canada has deferred the Fort Hills project in order to re-evaluate costs. Suncor announced a reduction in spending on both the Voyageur and Firebag developments and several customers have announced they are deferring decisions about upgrader projects. More recently, Total has deferred the Joslyn project, citing a re-evaluation of costs.

While the current conditions have reduced the amount of capital spending likely to be invested in the region in the near term, we believe that the lower input costs and industry consolidation that are resulting from the slowdown will ultimately lead to a more sustainable environment for oil sands development. As an example, Suncor and Petro-Canada have announced merger plans which are expected to create an entity that can better support capital investments. In addition, Petro-Canada has announced a 30% reduction in cost estimates for its Fort Hills mine as a result of the more competitive conditions in the oil sands.*

We are encouraged by independent economic forecasts indicating a global economic recovery beginning in late 2009, the current strength in oil prices and the recent announcement that Imperial Oil Ltd. will proceed with the development of their Kearl oil sands project in Alberta at an estimated capital cost of $8 billion.

Longer term, industry forecasts for oil sands project development remain positive. Major producers continue to reiterate that their investment in the oil sands is driven by expected long-term demand and prices for oil and not by short-term oil prices. This is consistent with the minimum three-to-four year development lead time required to build oil sands mines and the 30-40 year operating life of these projects.

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


		20

Management’s Discussion and Analysis

Commercial and Public Construction

According to Statistics Canada, the value of non-residential building permits in 2008 was $29.6 billion, up 58% from 2004. Ontario accounted for 39% of the total value over the four-year period, followed by Alberta at 21%, Quebec at 17%, British Columbia at 14% and the rest of the provinces and territories accounting for the remaining 9%. We provide commercial and public construction services in Alberta, British Columbia, Saskatchewan and we recently opened an office in Ontario.

Current Commercial and Public Construction Business Conditions

Currently, commercial construction activity is experiencing a slowdown in Western Canada, reflecting tighter credit markets, declining real estate values and other impacts of the economic recession. While we expect that the number of commercial construction projects will decline in 2009, government-sponsored infrastructure projects should offset some of this impact.*

The increase in infrastructure spending is being driven in part by population demands. In recent years, activity in the energy sector has created significant economic and population growth in Western Canada, which has strained public facilities and infrastructure across the province. The Alberta government has responded by allocating approximately $120 billion over 20 years to improvement and expansion projects. From 2009 to 2012, the government of Alberta plans to spend $7.7 billion annually on capital projects. The renewed interest in infrastructure investment is also being supported by government efforts to stimulate the economy. In Ontario, the government recently announced $27.5 billion of infrastructure spending over the next two years as part of its stimulus package. Additionally, Canada’s federal government recently unveiled a budget which includes $12 billion of new infrastructure spending.*

We believe that the demand for new infrastructure to support a larger population and government investment in infrastructure to stimulate the economy provides a strong outlook for infrastructure spending in Western Canada and in Ontario. We believe that our ability to meet many of the construction and piling needs of core infrastructure customers, along with our strong local presence and significant regional experience, position us to capitalize on the expected growth in infrastructure projects.*

Conventional Oil and Gas

According to the Canadian Energy Pipeline Association (CEPA), Canada is the world’s third largest natural gas producer and the seventh largest crude oil producer, with an output of approximately 16.8 billion cubic feet of natural gas per day and 2.8 million barrels of oil per day. Canada also has the world’s largest pipeline network for crude oil, however, this network is nearing capacity, particularly in Western Canada. According to CEPA, pipeline assets must double by 2015 to support projected supply. Pipeline projects that are currently underway and are expected to be in service by the end of 2010 will provide capacity until 2013, at which time a further capacity increase will be required. It generally takes four-to-five years to put a new pipeline into service.

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

Current Conventional Oil and Gas Business Conditions

While there has been an overall decrease in oil and gas investment as a result of weaker economic conditions and the downturn in oil and gas prices, companies involved in the transmission of oil and gas do not appear to be delaying investment in new pipeline development. With current pipelines at capacity and long lead times involved in securing project approvals and procuring materials, pipeline operators appear committed to proceeding with the construction of their pipelines.

Minerals Mining

According to the government agency, Natural Resources Canada (“NRC”), Canada is one of the largest mining nations in the world, producing more than 60 different minerals and metals. The value of minerals produced (i.e. excluding petroleum and natural gas) reached $45.3 billion in 2008, up 11.7% from $40.5 billion in 2007. Canada was also the top destination for mineral exploration capital from worldwide sources in 2008, with expenditures close to $3 billion for a second year in a row.

Outside the oil sands, we have identified the Canadian diamond mining industry as one of our targets for new business opportunities. The diamond mining industry in Canada is relatively new, having operated for only nine years. According to NRC, Canada continues to rank as the third largest diamond producing country in the world by value after Botswana and Russia. We intend to leverage the experience and skills gained through the successful completion of the construction of the DeBeers Victor diamond mine to pursue other opportunities in this area.*

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


				21

Management’s Discussion and Analysis

Canada is also the world leader in uranium mining. The two largest high-grade deposits of uranium in the world have been discovered in Canada. According to NRC, 80% of Canada’s recoverable reserve base is categorized as “low cost”. Historically, exploration and production have taken place primarily in Saskatchewan. Recently, however, significant exploration efforts are underway in the Northwest Territories, Yukon, Nunavut, Quebec, Newfoundland and Labrador, Ontario, Manitoba and Alberta.*

Current Minerals Mining Business Conditions

The effects of the global economic downturn have weakened demand for base metals and minerals in recent months, causing prices to drop significantly. This devaluation of commodities, together with limited access to capital, has slowed new mine development. Exploration capital expenditures are expected to fall by 50% in 2009 according to the NRC and certain projects that were slated to start construction in 2009 have been deferred. It is anticipated that commodity prices will remain low until the world economy improves.*

Revenue Sources

Revenue by Category

We have experienced steady growth in recurring revenue from operating oil sands projects over the past few years. Project development revenue, by contrast, has recently declined reflecting the impact of economic conditions on large-scale capital projects. Future growth in our recurring revenue will be reflective of increased activities at current operational mines along with the start-up of new operational mines as oil sands projects move from the capital development stage into the operational phase.

The following graph displays the breakdown between recurring services revenue and project development revenue for the trailing 12-months at three month intervals from March 31, 2007 to March 31, 2009:

LOGO

Recurring Services Revenue: Recurring services revenue is derived from long-term contracts and master services agreements 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 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.

Master Services Agreements. This category of revenue is generated from the master services agreements in place with Syncrude and Albian. This revenue is typically generated by supporting the operations of our customers and is therefore considered to be recurring. This revenue is not guaranteed under contract and is not included in our calculation of backlog. This revenue is primarily generated under time-and-materials contracts. This work is generally funded from our customers’ operating or maintenance capital budgets.

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


		22

Management’s Discussion and Analysis

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

Revenue by End Market

Growth in both recurring services and capital projects increased our oil sands work volumes during 2007 and 2008. The pipeline installation project for Kinder Morgan increased our revenues in the conventional oil and gas sector. The declining contribution of minerals mining revenue reflects the completion of the DeBeers diamond mine project in early 2008. The following graph displays the breakdown between revenues from each end market for the trailing 12-month period at three-month intervals from March 31, 2007 to March 31, 2009:

LOGO

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:

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 forms of business. We intend to build on our “first-in” position to cross-sell our many services, while also pursuing selective acquisition opportunities that expand our complementary service offerings.*

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 occur.*

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

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


				23

Management’s Discussion and Analysis

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

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;

cash conservation to ensure liquidity for operational circumstances;

continuing to improve our working capital management;

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

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

B. Financial results

Consolidated Annual Results


	Year Ended March 31,

(dollars in thousands, except per share information)								2009 vs 2008			2009 vs 2007
(dollars in thousands, except per share information)	2009		% of Revenue	2008	% of Revenue	2007	% of Revenue	Change		% Change	Change		% Change
Revenue	$972,536		100.0%	$989,696	100.0%	$629,446	100.0%	$(17,160	)	-1.7%	$343,090		54.5%
Project costs	505,026		51.9%	592,458	59.9%	363,930	57.8%	(87,432	)	-14.8%	141,096		38.8%
Equipment costs	210,520		21.6%	174,873	17.7%	122,306	19.4%	35,647		20.4%	88,214		72.1%
Equipment operating lease expense	43,583		4.5%	22,319	2.3%	19,740	3.1%	21,264		95.3%	23,843		120.8%
Depreciation	38,102		3.9%	36,729	3.7%	31,034	4.9%	1,373		3.7%	7,068		22.8%
Gross profit	175,305		18.0%	163,317	16.5%	92,436	14.7%	11,988		7.3%	82,869		89.7%
General & administrative costs	74,405		7.7%	69,670	7.0%	39,769	6.3%	4,735		6.8%	34,636		87.1%
Operating (loss) income	(81,712	)	-8.4%	92,397	9.3%	51,126	8.1%	(174,109	)	-188.4%	(132,838	)	-259.8%
Net (loss) income	(139,515	)	-14.3%	39,784	4.0%	21,079	3.3%	(179,299	)	-450.7%	(160,594	)	-761.9%
Per share information
Net (loss) income –basic	$(3.87	)		$1.11		$0.87		$(4.98	)		$(4.74	)
Net (loss) income –diluted	(3.87	)		1.08		0.83		(4.95	)		(4.70	)
EBITDA⁽¹⁾	$(58,153	)	-6.0%	$121,982	12.3%	$87,351	13.9%	$(180,135	)	-147.7%	$(145,504	)	-166.6%
Consolidated EBITDA⁽¹⁾(as defined within the revolving credit agreement)	146,046		15.0%	135,094	13.7%	90,235	14.3%	10,952		8.1%	55,811		61.9%

⁽¹⁾	Non GAAP Financial measures

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

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

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

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

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

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. Our use of the term, “Consolidated EBITDA (as defined within the revolving credit agreement)”, replaces the term “Consolidated EBITDA (per bank)” used in prior filings but the definition of Consolidated EBITDA has not changed.


		24

Management’s Discussion and Analysis

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


	Year Ended March 31,
(dollars in thousands)	2009		2008		2007
Net (loss) income	$(139,515)		$39,784		$21,079
Adjustments:
Interest expense	27,450		27,019		37,249
Income taxes	14,723		17,379		(2,593	)
Depreciation	38,102		36,729		31,034
Amortization of intangible assets	1,087		1,071		582

EBITDA	$(58,153)		$121,982		$87,351

Adjustments:
Unrealized foreign exchange loss (gain) on senior notes	45,860		(24,788	)	(5,017	)
Realized and unrealized (gain) loss on derivative financial instruments	(25,081	)	34,075		(196	)
Loss on disposal of plant and equipment	5,325		179		959
Stock-based compensation	2,251		1,991		2,101
Director deferred stock unit expense	(356	)	(190	)	–
Write-off of deferred financing costs	–		–		4,342
Write-down of other assets to replacement cost	–		1,845		695
Impairment of goodwill	176,200		–		–

Consolidated EBITDA	$146,046		$135,094		$90,235

Analysis of Annual Results

Revenue

For the year ended March 31, 2009, revenues of $972.5 million were $17.2 million or 1.7% lower than in the last year ended March 31, 2008. The modest decline in annual revenues reflects the impacts of a fourth-quarter slow down in commercial construction markets, a temporary work stoppage on a large mining contract as well as the windup of the TMX pipeline project. These impacts were largely offset by stronger volumes in Heavy Construction and Mining as a result of the completion of work on oil sands capital projects at Petro-Canada’s Fort Hills site and Suncor’s Voyageur site as well as the continued increase in demand for recurring services from oil sands customers. Compared to the year ended March 31, 2007, revenues in the year ended March 31, 2009 improved by $343.1 million or 54.5% and were the second best results in our history. A significantly stronger contribution from the Pipeline segment through the first nine months of the fiscal year, a higher level of construction and oil sands capital projects activity and continued growth in oil sands related recurring services revenues were the key factors in the improvement.

Gross Profit

Gross profit for the year ended March 31, 2009 increased to $175.3 million, a $12.0 million or a 7.3% improvement compared to gross profit in the year ended March 31, 2008. The higher volumes in Heavy Construction and Mining and the improved margins in the Pipeline segment were the key factors in this improvement. The improvement of the current years’ gross profit compared to fiscal 2007 reflects the Pipeline segment’s return to profitability after incurring losses on specific projects in the year ended March 31, 2007. Gross margins in the current year also benefitted from the partial recovery of prior year Pipeline losses through our claims process and significant improvements in the costs for large truck tires.

A change in the current year’s cost mix between project costs and equipment costs compared to prior years reflects a shift to more equipment-focused work within Heavy Construction and Mining in the year ended March 31, 2009. Additions to the fleet to support a long-term overburden removal contract, including the commissioning of a new electric cable shovel in March 2008, led to increases in operating leases. We commissioned a second electric cable shovel for this contract in December 2008.

Operating (Loss) Income

We recorded an operating loss of $81.7 million in the year ended March 31, 2009, compared to operating income of $92.4 million (9.3% of revenue) in the year ended March 31, 2008 and operating income of $51.1 million (8.1% of revenue) for the year ended March 31, 2007. The current year operating loss reflects the non-cash impact of a $176.2 million impairment of goodwill. Excluding this impairment charge, operating income would have been $94.5 million (9.7% of revenue) for the current year. General and administrative (G&A) expense increased $4.7 million to $74.4 million, representing 7.7% of revenue. This compares to $69.7 million (7.0% of revenue) and $39.8 million (6.3% of revenue) in the years ended March 31, 2008 and 2007 respectively. The current year increase in G&A levels reflects higher staffing levels needed to support increased operations activity as well as inflationary pressures in the oil sands through the first nine months. The increases were partially offset by the benefits of reorganization and cost reduction initiatives implemented in the last three months of the current year along with process improvements implemented earlier in the year.


				25

Management’s Discussion and Analysis

Net (Loss) Income

We recorded a net loss of $139.5 million (basic loss per share of $3.87) in the year ended March 31, 2009, compared to net income of $39.8 million (basic income per share of $1.11 and diluted income per share of $1.08) in the year ended March 31, 2008 and net income of $21.1 million (basic income per share of $0.87 and diluted income per share of $0.83) in the year ended March 31, 2007. The net loss primarily reflects the receipt of a cancellation premium (see our “Foreign currency risk” discussion in Quantitative and Qualitative Disclosures about Market Risk) and non-cash items such as $176.2 million goodwill impairment (no tax effect), the negative impact of a depreciating Canadian dollar on our 8³/4% senior notes and non-cash losses on embedded derivatives. This was partially mitigated by a gain in the cross currency and interest rate swaps along with a gain in the embedded derivative in a long-term customer contract. Excluding these non-cash items for each year, current year net income would have been $49.4 million resulting in basic income per share of $1.37 and diluted income per share of $1.35, up from $1.27 per share and $1.23 per share, respectively, for the year ended March 31, 2008 and $0.62 per share and $0.59 per share, respectively for the year ended March 31, 2007.

Impairment of Goodwill

We recognized a $176.2 million impairment of goodwill in the year ended March 31, 2009. In accordance with our accounting policy, a goodwill impairment test is completed annually on October 1st of each year or whenever events or changes in circumstances indicate that goodwill impairment may exist. We conducted our annual goodwill impairment test on October 1, 2008 and concluded that the fair value of each of our reporting units exceeded their carrying amounts. However, at both December 31, 2008 and March 31, 2009 we concluded that an interim test for impairment of goodwill was appropriate given adverse changes in our principal markets, the recent decline in our market capitalization and the accounting requirements related to goodwill under such circumstances.

At December 31, 2008: In performing the goodwill assessment on December 31, 2008, we considered discounted cash flows, market capitalization and other factors including observable market data to determine fair value. Although implied market comparable valuation multiples and transaction premiums from a set of selected comparable companies were considered in our analysis, we concluded that there are significant differences in the services and operating characteristics of our reporting units as compared to these companies. As a result, we relied primarily on the discounted cash flow method, using our projections for each of our reporting units and risk adjusted discount rates. Expected cash flows for each of our reporting units were discounted using estimated discount rates ranging from 18% to 27% and a terminal growth rate of 3.0% to calculate fair value. We considered this method to be most reflective of a market participant’s view of fair value given the current market conditions.

As a result of our analysis, we concluded that the carrying value of goodwill assigned to the Pipeline operating segment (also a separate reporting unit) exceeded its fair value and we recorded an impairment charge of $32.8 million. The goodwill impairment charge was calculated as the difference between the carrying value of goodwill of the Pipeline operating segment and its implied fair value of $nil at December 31, 2008. The implied fair value of the goodwill for the Pipeline operating segment was determined in the same manner as the value of goodwill is determined in a business combination. The impairment charge is included in the caption “Impairment of goodwill” in the Consolidated Statement of Operations, Comprehensive (Loss) Income and Deficit for the year ended March 31, 2009.

At December 31, 2008, we determined that there was no impairment to any other reporting units as their fair values exceeded their carrying values. The goodwill impairment charge reduced our carrying value for goodwill from $200.1 million to $167.3 million as at December 31, 2008.

At March 31, 2009: During the three months ended March 31, 2009, we observed further deterioration in industry conditions, a further decline in our market capitalization and weak global economic and credit conditions. The current economic environment has impacted our ability to forecast future demand and has in turn resulted in the use of higher discount rates, reflecting the risk and uncertainty in the current market. Furthermore, we experienced a significant and sustained quarter-over-quarter decline in our market capitalization due primarily to challenging market conditions. As a result, we concluded that events had occurred and circumstances had changed that required us to perform an additional interim goodwill impairment test for the Heavy Construction and Mining and Piling segments (also separate reporting units) as at March 31, 2009. This was corroborated by a combination of factors including a significant and sustained decline in our market capitalization, which was appreciably below our book value and deteriorating economic conditions in Canada and globally which has resulted in a decline in expected future demand.

As part of the March 31, 2009 goodwill impairment test, we updated our discounted cash flow analysis for the Heavy Construction and Mining and Piling reportable business segments. We used estimated discount rates ranging from 22.0% to 32.0% and a decreased terminal growth rate from 3.0% to 2.5% to calculate fair value. These updates were based on the current economic volatility we experienced during the three months ended March 31, 2009 and took into account our views of economic conditions and trends, estimated future operating results, sector growth rates, anticipated future economic conditions and our strategic alternatives to respond to these conditions.

As a result of this analysis, we concluded that the carrying value of the Heavy Construction and Mining and Piling reporting units exceeded their fair value and we recorded an impairment charge of $125.4 million and $18.0 million,


		26

Management’s Discussion and Analysis

respectively. This was calculated as the difference between the carrying value of goodwill of the two segments and the implied fair value of goodwill of each reporting unit at March 31, 2009. The implied fair value of goodwill was determined in the same manner that the value of goodwill is determined in a business combination. The impairment charge is included in the caption “Impairment of goodwill” in the Consolidated Statement of Operations, Comprehensive (Loss) Income and Deficit for the year ended March 31, 2009.

There was no goodwill impairment recorded for the years ended March 31, 2008 and 2007.

Segment Annual Results

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

Segment results for the year ended March 31, 2009 compared to the years ended March 31, 2008 and March 31, 2007 are summarized below:

Heavy Construction and Mining


	Year Ended March 31,
(dollars in thousands)	2009	% of Revenue	2008	% of Revenue	2007	% of Revenue	2009 vs. 2008		2009 vs. 2007
(dollars in thousands)	2009	% of Revenue	2008	% of Revenue	2007	% of Revenue	Change	% Change	Change	% Change
Segment revenue	$716,053		$626,582		$473,179		$89,471	14.3%	$242,874	51.3%
Segment profit	$115,698	16.2%	$105,378	16.8%	$71,062	15.0%	$10,320	9.8%	$44,636	62.8%

For the year ended March 31, 2009, the Heavy Construction and Mining segment achieved revenues of $716.1 million, an $89.5 million improvement over last year and a $242.9 million improvement over the year ended March 31, 2007. Project closeout activities at the Petro-Canada Fort Hills’ site preparation project and Suncor’s Voyageur and Millennium Naphtha Unit projects, combined with strong demand for recurring site services work, including master services work at Albian’s Jackpine mine and Muskeg River mine, were the primary factors in this revenue growth. Recurring services have become an increasingly significant contributor to our revenues as more oil sands projects move into the stable, operational phase of their lifecycles. Ongoing operational work represented 73.2% of Heavy Construction and Mining’s revenues in the year ended March 31, 2009 compared to 60.3% and 46.0% for the years ended March 31, 2008 and 2007, respectively.

Segment profit margin for the year ended March 31, 2009 was 16.2%. This was slightly lower than the segment margin of 16.8% achieved during the same period last year but a significant improvement over segment margin of 15.0% in the year ended March 31, 2007. An increased proportion of high volume Heavy Construction and Mining projects, the redeployment of equipment from the Canadian Natural project to other projects and the positive impact of change orders associated with project close-outs helped to offset the impact of reduced industrial construction and minerals mining work compared to the year ended March 31, 2008.

Piling


	Year Ended March 31,

(dollars in thousands)	2009	% of Revenue	2008	% of Revenue	2007	% of Revenue	2009 vs. 2008		2009 vs. 2007
(dollars in thousands)	2009	% of Revenue	2008	% of Revenue	2007	% of Revenue	Change	% Change	Change	% Change
Segment revenue	$155,076		$162,397		$109,266		$(7,321)	-4.5%	$45,810	41.9%
Segment profit	$38,776	25.0%	$45,362	27.9%	$34,395	31.5%	$(6,586)	-14.5%	$4,381	12.7%

The Piling segment achieved revenues of $155.1 million for the year ended March 31, 2009, a decrease of $7.3 million compared to a year ago. This change reflects declining activity levels in the Western Canadian commercial construction market. Work on a major oil sands-related plant and upgrader project combined with continued growth in Saskatchewan were significant contributors to the revenue in the current year and prior year as compared to the year ended March 31, 2007.

For the year ended March 31, 2009, segment profit margin decreased to 25.0%, from 27.9% last year and 31.5% for the year ended March 31, 2007, reflecting the impact of weaker commercial construction market conditions and an increased number of lower margin time-and-materials oil sands projects. Margins for the year ended March 31, 2007 included a larger proportion of higher-margin, fixed price contracts.


				27

Management’s Discussion and Analysis

Pipeline


	Year Ended March 31,

								2009 vs. 2008		2009 vs. 2007
(dollars in thousands)	2009	% of Revenue	2008	% of Revenue	2007		% of Revenue	Change	% Change	Change	% Change
Segment revenue	$101,407		$200,717		$47,001			$(99,310)	-49.5%	$54,406	115.8%
Segment profit	$22,470	22.2%	$25,465	12.7%	$(10,539	)	-22.4%	$(2,995)	-11.8%	$33,009	-313.2%

Pipeline revenues for the year ended March 31, 2009 were $101.4 million, a decline of $99.3 million from a year ago, reflecting the successful and on-schedule completion of the TMX project in October 2008.

Although Pipeline profit for the year ended March 31, 2009 decreased as a result of the lower revenue, margins increased to 22.2%, from 12.7% last year as a result of closeout activities and final change orders for the TMX project. Current year margins benefitted from the negotiated settlement of $5.3 million in claims while margins last year were negatively affected by $2.0 million in additional costs related to a fixed-priced contract. Excluding these impacts in both years, margins would have been 16.9% compared to 13.7% a year ago.

Consolidated Three-Month Results


	Three Months Ended March 31,
(dollars in thousands, except per share information)	2009		% of Revenue	2008	% of Revenue	Change		% Change
Revenue	$174,700		100.0%	$323,600	100.0%	$(148,900	)	-46.0%
Project costs	71,522		40.9%	195,196	60.3%	(123,674	)	-63.4%
Equipment costs	48,374		27.7%	43,291	13.4%	5,083		11.7%
Equipment operating lease expense	13,266		7.6%	9,990	3.1%	3,276		32.8%
Depreciation	9,074		5.2%	12,550	3.9%	(3,476	)	-27.7%
Gross profit	32,464		18.6%	62,573	19.3%	(30,109	)	-48.1%
General & administrative costs	16,688		9.6%	20,674	6.4%	(3,986	)	-19.3%
Operating (loss) income	(129,483	)	-74.1%	42,581	13.2%	(172,064	)	-404.1%
Net (loss) income	(142,690	)	-81.7%	20,484	6.3%	(163,174	)	-796.6%
Per share information
Net (loss) income – basic	$(3.96	)		$0.57		$(4.53	)
Net (loss) income – diluted	(3.96	)		0.56		(4.52	)
EBITDA⁽²⁾	$(123,210	)	-70.5%	$50,424	15.6%	$(173,634	)	-344.3%
Consolidated EBITDA⁽²⁾(as defined within the revolving credit agreement)	25,191		14.4%	55,435	17.1%	(30,244	)	-54.6%

⁽¹⁾	Prior Year Comparison

In preparing the financial statements for the year ended March 31, 2008, we determined that the previously issued interim unaudited consolidated financial statements did not properly account for an embedded derivative with respect to price escalation features in a supplier maintenance contract. As disclosed in the Audited Consolidated Financial Statements for the year ended March 31, 2008, we restated our original April 1, 2007 transition adjustment on adoption of CICA Handbook Section 3855, “Financial Instruments – Recognition and Measurement”. We recorded the full fiscal year accounting treatment of the embedded derivative in the Audited Consolidated Balance Sheet and Audited Consolidated Statement of Operations and Comprehensive (Loss) and Deficit for the year and three-month period ended March 31, 2008. Subsequently, for each interim unaudited consolidated financial statement during the current fiscal year we have restated the prior year’s three-month period to reflect the restatement of the April 1, 2007 transition adjustment and the effects of the restatement on the prior year consolidated balance sheet and consolidated statement of operations for the appropriate three-month prior period. With the restatement of the Audited Consolidated Statement of Operations and Comprehensive (Loss) and Deficit for the three months ended March 31, 2008, the effect of the restated April 1, 2007 transition adjustment has been appropriately recorded in each of the individual three month prior periods.

The embedded derivative has been measured at fair value and included in derivative financial instruments on the consolidated balance sheet with changes in fair value recognized in net income. The impact of this restatement on the Audited Consolidated Statement of Operations and Comprehensive (Loss) and Deficit for the year ended March 31, 2008 is an adjustment, for the three-month period ended March 31, 2008, to unrealized income on derivative financial instruments and income tax expense. This resulted in a reduction to net income of $2.2 million (restated as net income of $20.5 million), a reduction to basic income per share of $0.06 per share (restated as $0.57 income per share) and a reduction to diluted income per share of $0.06 per share (restated as $0.56 income per share). There was no restatement required for the Audited Consolidated Statement of Operations and Comprehensive (Loss) and Deficit for the year ended March 31, 2008 nor for the Audited Consolidated Balance Sheet for the year ended March 31, 2008.

⁽²⁾	Non-GAAP Financial measures – see footnote for “Consolidated Annual Results”.


		28

Management’s Discussion and Analysis

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


	Three Months Ended March 31,
(dollars in thousands)	2009		2008
	(Restated)
Net (loss) income	$(142,690)		$20,484
Adjustments:
Interest expense	7,787		6,686
Income taxes	2,354		10,399
Depreciation	9,074		12,550
Amortization of intangible assets	265		305

EBITDA	$(123,210)		$50,424

Adjustments:
Unrealized foreign exchange loss on senior notes	7,035		7,838
Realized and unrealized (gain) loss on derivative financial instruments	(3,910	)	(2,615	)
Loss (gain) on disposal of plant and equipment	1,547		(990	)
Stock-based compensation	448		968
Director deferred stock unit expense	(166	)	(190	)
Impairment of goodwill	143,447		–

Consolidated EBITDA	$25,191		$55,435

Analysis of Three-Month Results

Revenue

For the three months ended March 31, 2009, revenues of $174.7 million were $148.9 million lower than in the same period last year. As we anticipated, continued weakness in commercial construction markets, the temporary slowdown in our overburden removal activities during Canadian Natural’s production start-up period and a sharp decline in Pipeline segment revenues following our completion of the TMX pipeline project contributed to the reduction in revenues. These declines were partially offset by our growing volume of recurring services business.

Gross Profit

Gross profit for the three months ended March 31, 2009 decreased by $30.1 million, primarily as a result of lower revenue. Margins remained solid at 18.6% of revenue compared to 19.3% a year ago, reflecting the benefits of project close out activities, higher-margin site services work and company-wide efforts to improve efficiency and reduce expenses.

A shift to more equipment focused work within Heavy Construction and Mining in the three months ended March 31, 2009 led to a change in the current period’s cost mix between project costs and equipment costs compared to the prior year. The current period addition of new Heavy Construction and Mining equipment secured under operating leases led to a 42.1% or $1.9 million, three-month period increase in tire expenses year-over-year (equipment is not delivered with tires). Higher equipment leasing expense as a result of the March 2008 commissioning of a new electric cable shovel for a long-term overburden removal contract along with higher costs related to the year-over-year growth in the size of our leased equipment fleet contributed to the year-over-year differences. We commissioned a second electric cable shovel for this contract in December 2008. Increased Heavy Construction and Mining activity and a reduction in the use of rental equipment resulted in an increase of 1.3% in depreciation as a percent of revenue for the three month period ended March 31, 2009 compared to the previous year. Included in the prior three month period was a $1.8 million charge for accelerated depreciation. The current three month period had no accelerated depreciation recorded.

Operating (Loss) Income

For the three months ended March 31, 2009 we recorded an operating loss of $129.5 million compared to operating income of $42.6 million or 13.2% of revenue, during the same period last year. The change in operating profit reflects the non-cash impact of a $143.4 million impairment of goodwill, as discussed in the “Analysis of Annual Results”. Excluding this impairment, operating income would have been $13.9 million or 8.0% of revenue for the current year. General and administrative (G&A) expense decreased by $4.0 million, reflecting the benefits of reorganization and cost reduction initiatives implemented in the three months ended March 31, 2009 and process improvements implemented earlier in the year.

Net (Loss) Income

We recorded a net loss of $142.7 million (basic loss per share of $3.96) for the three months ended March 31, 2009, compared to net income of $20.5 million (basic income per share of $0.57 and diluted income per share of $0.56) during the same period last year. Non-cash items negatively affecting the net loss included the impact of goodwill


				29

Management’s Discussion and Analysis

impairment (no tax effect), the negative impact of a depreciating Canadian dollar on our 8³/4% senior notes and non-cash losses on embedded derivatives. This was partially mitigated by a gain in the cross currency and interest rate swaps along with a gain in the embedded derivative in a long-term customer contract. Excluding these non-cash items in the current and prior period, net income would have been $2.1 million (basic income per share of $0.06 / diluted income per share of $0.06) down from net income of $23.7 million (basic income per share of $0.66 / diluted income per share of $0.65).

Segment Three-Month Results

Heavy Construction and Mining


(dollars in thousands)	Three Months Ended March 31,

	2009		% of Revenue	2008		% of Revenue	2009 vs. 2008
	2009		% of Revenue	2008		% of Revenue	Change		% Change
Segment revenue	$151,95	2		$195,44	2		$(43,490	)	-22.3%
Segment profit	$29,282		19.3%	$36,747		18.8%	$(7,465)		-20.3%

For the three months ended March 31, 2009, the Heavy Construction and Mining segment achieved revenues of $152.0 million, a $43.5 million decrease compared to the same period last year. A temporary shutdown in overburden activity at the Canadian Natural site during their operation start-up contributed to the reduced revenues for the current three-month period. Partially offsetting this decline in revenue was increased recurring site services work, including master services work at Albian’s Jackpine mine and Muskeg River mine combined with project closeout activities at Suncor’s Voyageur and Millennium Naphtha Unit (MNU) projects. By comparison, results in the three months ended March 31, 2008 included revenue from the Petro-Canada Fort Hills site and active projects at Suncor’s Voyageur and MNU sites.

Recurring services represented 87.6% of Heavy Construction and Mining’s revenues in the three-month period ended March 31, 2009 compared to 64.5% in the same period last year.

Segment margins, for the three months ended March 31, 2009, were 19.3%, which was a slight increase over the 18.8% achieved during the same period last year. A redeployment of equipment from the overburden project to other sites combined with change orders associated with project close-outs led to the improvement in margins.

Piling


	Three Months Ended March 31,

	2009		% of Revenue	2008		% of Revenue	2009 vs. 2008
(dollars in thousands)	2009		% of Revenue	2008		% of Revenue	Change	% Change
Segment revenue	$22,36	7		$40,69	9		$(18,332)	-45.0%
Segment profit	$6,331		28.3%	$13,637		33.5%	$(7,306)	-53.6%

The Piling segment achieved revenues of $22.4 million in the three months ended March 31, 2009, a decrease of $18.3 million compared to the same period last year. The change in Piling revenues reflects declining activity levels in the commercial construction market as well as a reduction in high-volume oil sands projects.

For the three months ended March 31, 2009 segment margins decreased to 28.3%, from 33.5% in the same period last year. The negative effect of the declining commercial construction market on margins year-over-year was partially offset by project close-out activities and the processing of change orders during the current period.

Pipeline


	Three Months Ended March 31,

	2009		% of Revenue	2008		% of Revenue	2009 vs. 2008
(dollars in thousands)	2009		% of Revenue	2008		% of Revenue	Change	% Change
Segment revenue	$38	1		$87,45	9		$(87,078)	-99.6%
Segment profit	$6		1.6%	$11,311		12.9%	$(11,305)	-99.9%

Pipeline revenues for the three months ended March 31, 2009 declined $87.1 million compared to the same period a year ago, reflecting completion of the TMX project in October 2008.


		30

Management’s Discussion and Analysis

Non-Operating Income and Expense


	Three Months Ended March 31,				Year Ended March 31,
(dollars in thousands)	2009		2008		2009		2008		2007
			(Restated)
Interest expense
Interest on 8³/4% senior notes	$13,186		$5,835		$30,689		$23,338		$27,417
Interest on revolving credit facility and other interest	(667	)	399		29		2,063		1,157
Interest on capital lease obligations	347		283		1,234		780		725
Interest on NACG Preferred Corp. Series A preferred shares	–		–		–		–		1,400
Accretion and change in redemption value of mandatorily redeemable preferred shares	–		–		–		–		3,114
Amortization of deferred bond issue costs	231		169		808		838		–
Amortization of deferred financing costs	–		–		–		–		3,436
Interest income	(5,310	)	–		(5,310	)	–		–

Total Interest expense	$7,787		$6,686		$27,450		$27,019		$37,249


Foreign exchange loss (gain) on senior notes	$7,567		$7,694		$46,666		$(25,442	)	$(5,044	)
Realized and unrealized (gain) loss on derivative financial instruments	(3,910	)	(2,615	)	(25,081	)	34,075		(196	)
Other income	(591	)	(67	)	(5,955	)	(418	)	(904	)
Income tax expense (recovery)	2,354		10,399		14,723		17,379		(2,593	)

Interest Expense

Total interest expense of $27.5 million for the year ended March 31, 2009 increased marginally from the same period last year. Lower utilization of the revolving credit facility offset the increase in the interest on capital lease obligations. Total interest expense for the current year is $9.8 million less than the year ended March 31, 2007 primarily due to the retirement of the senior secured 9% notes with proceeds from our Initial Public Offering (IPO) and the exchange of the Series B redeemable preferred shares for common shares as part of the amalgamation that occurred prior to the IPO.

As a result of the counterparty cancellation of our US dollar interest rate swap, we are now exposed to interest rate risk. As described in more detail under “Qualitative and Quantitative Disclosures about Market Risk — Interest rate risk”, our three swap counterparties under the swap exercised this cancellation option effective February 2, 2009. As part of the swap cancellation, we now receive floating quarterly interest payments from our swap counterparties at a rate of 4.2% over three-month LIBOR, which we record as interest income. This partially offsets the impact of increased interest resulting from the cancellation of the US dollar interest rate swap. These floating interest payments occur quarterly every March 1, June 1, September 1 and December 1 until the notes mature on December 1, 2011.

As a result of the US dollar interest rate swap termination, our annual interest expense at current LIBOR rates will increase by a net of US$6.8 million. In addition, we are now exposed to interest rate risk where a 100 basis point increase (decrease) in the three-month LIBOR rate will result in a US$2.0 million decrease (increase) in the net annual interest expense.

Total interest expense of $7.8 million for the three months ended March 31, 2009 increased $1.1 million from the same period in the prior year. Lower utilization of the revolving credit facility offset the small increases in the amortization of bond issue costs and interest on capital lease obligations. As described in more detail under “Qualitative and Quantitative Disclosures about Market Risk — Interest rate risk”, our three swap counterparties under the US dollar interest rate swap exercised their cancellation option effective February 2, 2009. As part of the swap cancellation we now receive floating quarterly interest payments from our swap counterparties at a rate of 4.2% over three-month LIBOR, which we record as interest income partially offsetting the increased interest resulting from the cancellation of the US dollar interest rate swap. These floating interest payments occur quarterly every March 1, June 1, September 1 and December 1 until the notes mature on December 1, 2011.

Foreign Exchange Loss (Gain) on Senior Notes

The foreign exchange losses and gains recognized in the current and prior-year periods relate primarily to changes in the strength of the Canadian dollar against the US dollar on conversion of the US$200 million 8³/4% senior notes. A significant decline in the Canadian dollar from 0.9729 CAN/US at March 31, 2008 to 0.7935 CAN/US at March 31, 2009 resulted in a significant unrealized exchange loss. The Canadian dollar strengthened during the years ended March 31, 2008 and March 31, 2007, resulting in an unrealized exchange gain in the prior years. In the three months ended March 31, 2009, a decline in the value of the Canadian dollar, which dropped from 0.8166 CAN/US to 0.7935 CAN/US resulted in an unrealized exchange loss.


				31

Management’s Discussion and Analysis

Realized and Unrealized (Gain) Loss on Derivative Financial Instruments

The realized and unrealized gains and losses on derivative financial instruments reflect changes in the fair value of the cross-currency and interest rate swaps that we employ to provide an economic hedge for our US dollar denominated 8³/4% senior notes. Changes in the fair value of these swaps generally have an offsetting effect to changes in the value of our 8³/4% senior notes (and resulting foreign exchange gains and losses), with both being triggered by variations in the Canadian/US foreign exchange rate. However, the valuations of the derivative financial instruments are also impacted by changes in interest rates and the remaining present value of scheduled interest payments on the 8³/4% senior notes, which occur in June and December of each year until maturity.

Due to our April 1, 2007 adoption of the CICA standards regarding financial instruments, realized and unrealized gains and losses on derivative financial instruments for the three months and year ended March 31, 2009 and 2008 include changes in the fair value of derivatives embedded in our US dollar denominated 8³/4% senior notes, in a long-term construction contract and in supplier maintenance agreements. The change in the realized and unrealized gain / loss of the cross-currency and interest swaps resulted in a gain of $39.4 million in the year ended March 31, 2009 compared to a loss of $23.5 million in the year ended March 31, 2008. The new CICA standard did not apply to the year ended March 31, 2007. For the three months ended March 31, 2009, the change in the realized and unrealized gain / loss of the cross-currency and interest rate swaps resulted in a gain of $5.1 million compared to a loss of $2.8 million in the same period of last year. The balance of the realized and unrealized gains and losses on derivative financial instruments resulted from gains and losses on derivatives embedded in our 8³/4% senior notes, in a long-term construction contract and in supplier maintenance agreements.

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

With respect to the long-term construction contract, there is a provision that requires an adjustment to 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.

With respect to the supplier maintenance contracts, there are provisions that require a price adjustment to reflect the actual Canadian versus US dollar exchange rate and the United States government published Producers’ Price Index for Mining Machinery and Equipment (US-PPI) changes versus the contract amount. The embedded derivative instrument takes into account the impact of fluctuations in these measures on costs.

The measurement of embedded derivatives, as required by GAAP, causes our reported earnings to fluctuate as Canadian versus 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 revolving credit agreement) or how we evaluate performance.

Other Income

For the year ended March 31, 2009, other income includes a swap cancellation premium of $5.3 million. On December 17, 2008, we received notice that all three swap counterparties had exercised the cancellation option on the US dollar interest rate swap. Effective February 2, 2009, the US dollar interest rate swap was terminated. The counterparties paid a cancellation premium of 2.1875% on the notional amount of US$200.0 million or US$4.4 million (equivalent to CAN$5.3 million). We recognized the premium as other income in the three months ended December 31, 2008.

Income Tax Expense (Recovery)

For the year ended March 31, 2009, we recorded current income tax expense of $5.5 million along with future income tax expense of $9.2 million for a combined income tax expense of $14.7 million. This compares to a combined income tax expense of $17.4 million last year and a $2.6 million income tax recovery for the year ended March 31, 2007.

For the three months ended March 31, 2009, we recorded current income tax expense of $3.7 million and future income tax recovery of $1.4 million for a combined income tax expense of $2.3 million compared to combined income tax expense of $10.4 million (restated) for the same period last year.

For the year and three months ended March 31, 2009, income tax expense as a percentage of income before income taxes differs from the statutory rate of 29.38% primarily due to the impact of the impairment of goodwill (a non-deductible item) of $176.2 million and $143.4 million, respectively, and the impact of changes in enacted tax rates during the period. For the year and the three month period ended March 31, 2008, income tax expense as a percentage of income before income taxes differed from the statutory rate of 31.47% primarily due to the impact of enacted rate changes during the period and the impact of new accounting standards for the recognition and measurement of financial instruments as certain embedded derivatives are considered capital in nature for income tax purposes.


		32

Management’s Discussion and Analysis

Summary of Quarterly Results


	Fiscal 2009							Fiscal 2008 ⁽¹⁾
	Q4		Q3		Q2		Q1	Q4	Q3	Q2	Q1
(dollars in millions, except per share amounts)								(Restated)	(Restated)	(Restated)	(Restated)
Revenue	$174.7		$258.6		$280.3		$259.0	$323.6	$274.9	$223.6	$167.6
Gross profit	32.5		51.0		44.3		47.6	62.6	50.6	35.2	14.9
Operating (loss) income	(129.5	)	(2.2	)	23.0		26.9	42.6	33.2	17.1	(0.4	)
Net (loss) income	(142.7	)	(14.7	)	(1.2	)	19.1	20.5	24.7	3.2	(8.6	)
(Loss) income per share – Basic ⁽²⁾	$(3.96	)	$(0.41	)	$(0.03	)	$0.53	$0.57	$0.69	$0.09	$(0.24	)
(Loss) income per share – Diluted ⁽²⁾	(3.96	)	(0.41	)	(0.03	)	0.52	0.56	0.67	0.09	(0.24	)

⁽¹⁾

Restatements for each three month period of fiscal 2008 are a result of not properly accounting for an embedded derivative with respect to price escalation features in a supplier maintenance contract as at April 1, 2008. The improper embedded derivative accounting was only detected and corrected in the three months and year ended March 31, 2008. The restatements reflect each three-month period’s consolidated operating results as if the embedded derivative was properly accounted for as at April 1, 2008. For further discussion on the restatement of the prior year comparisons see the footnote to the “Consolidated Three Month Results”.

⁽²⁾	Net (loss) income per share for each quarter has been computed based on the weighted average number of shares issued and outstanding during the respective quarter; therefore, quarterly amounts may not add to the annual total. Per share calculations are based on full dollar and share amounts.

A number of factors have the potential to contribute to variations in our quarterly results between periods, including weather, capital spending by our customers on large oil sands projects, our ability to manage our project-related business so as to avoid or minimize periods of relative inactivity and the strength of the Canadian and world economies. For a more detailed discussion regarding seasonality and its impact on our business, see “Key Trends”.

The timing of large projects can influence quarterly revenues. For example, Pipeline segment revenues were as high as $87.5 million in the fourth quarter of fiscal 2008 and as low as $0.4 million in the fourth quarter of fiscal 2009. The Heavy Construction and Mining segment experienced increased revenues from the second quarter of fiscal 2008 through the first quarter of fiscal 2009 related to the execution of work at the Suncor Millennium Naphtha Unit project under our five-year site services agreement, the construction of an aerodrome for Albian during the third and fourth quarters of fiscal 2008 and increased demand under our master service agreements with Albian and Syncrude. Timing of work under the site services agreements can vary based on our customers’ production and project activities.

In addition to revenue variability, gross margins can be negatively impacted by the timing of maintenance costs. Timing of these costs is dependant on when management can make the equipment available for maintenance without adversely affecting billable equipment hours. Profitability also varies from period-to-period 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”. During the first quarter of fiscal 2009, a $5.3 million claim was recognized causing gross margins for the Pipeline segment to increase above what they would otherwise have been. The additional costs relating to the claim were incurred in fiscal 2007 and in the first quarter of fiscal 2008.

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 income. This reflects the impact of relatively fixed costs, such as general and administrative expenses, being spread over higher revenue levels. If activity decreases, these same fixed costs are spread over lower revenue levels. Net income and income per share are also subject to operating leverage as provided by fixed interest expense.

We have experienced earnings variability in all periods due to unrealized non-cash gains and losses on derivative financial instruments and foreign exchange primarily driven by changes in the Canadian and US dollar exchange rates. The current period non-cash goodwill impairment charge has added to the earnings variability between periods.

Consolidated Financial Position


	Year ended March 31,
(dollars in thousands)	2009		2008		Change		% Change
Current assets	$256,738		$291,086		$(34,348	)	-11.8%
Current liabilities	(135,091	)	(183,353	)	48,262		-26.3%

Net working capital	121,647		107,733		13,914		12.9%
Plant and equipment	329,705		281,039		48,666		17.3%
Total assets	630,052		793,598		(163,546	)	-20.6%
Capital Lease obligations (including current portion)	(17,484	)	(14,776	)	(2,708	)	18.3%
Total long-term financial liabilities ⁽¹⁾	(316,082	)	(301,497	)	(14,585	)	4.8%

⁽¹⁾	Total long-term financial liabilities exclude the current portions of capital lease obligations, current portions of derivative financial instruments, long-term lease inducements, asset retirement obligation and both current and non-current future income tax balances.


				33

Management’s Discussion and Analysis

At March 31, 2009, net working capital (current assets less current liabilities) was $121.6 million compared to $107.7 million at March 31, 2008, an increase of $13.9 million.

Current assets decreased during the period as a result of improved billing and collections reducing both trade receivables and holdbacks (reduced by $81.7 million since March 31, 2008) and unbilled revenue (reduced by $15.0 million since March 31, 2008). Offsetting these reductions was a $67.0 million increase in cash and $11.7 million increase in inventory since March 31, 2008. The inventory increase reflects the new Canadian GAAP standard for inventory which now requires that tires be reported as inventory (tires valued at $5.1 million were moved from other assets as at April 1, 2008). Tire requirements for new leased haul trucks (haul trucks do not arrive with tires included) has contributed to the high inventory levels.

Current liabilities decreased by $48.3 million as a result of decreased accounts payable (down by $56.9 million since March 31, 2008) offset by increased accrued liabilities (up by $7.1 million since March 31, 2008). Equipment purchases of $0.6 million, which are scheduled to be paid after the quarter end, are included in accounts payable as of March 31, 2009.

Plant and equipment increased by $48.7 million between March 31, 2009 and March 31, 2008. This reflects the capital investment of $103.0 million (including capital leases) during the current fiscal year, offset by equipment disposals of $17.1 million (net book value) and depreciation.

Total long-term financial liabilities increased by $14.6 million between March 31, 2009 and March 31, 2008 due largely to a $54.7 million increase in the carrying amount of our 8³/4% senior notes and a $21.5 million increase related to the derivative financial instruments from long-term supplier contracts. This was partially offset by a reduction of $42.1 million related to the cross-currency and interest rate swap agreements and a reduction of $15.1 million in the value of the derivative financial instruments from the long-term revenue construction contract.

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 unapproved change orders and claims are met. This can, and often does, lead to costs being recognized in one period and revenue being recognized in subsequent periods.

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

At March 31, 2009, we had approximately $2.8 million in costs for claims and unsigned change orders from project inception, with no associated increase in contract value or revenue. Due to the timing of receipt of signed change orders, Heavy Construction and Mining had approximately $3.2 million in claims revenue recognized to the extent of costs incurred while the Piling segment had $1.6 million of claims revenue for the same period. We are working with our customers to come to resolution on additional amounts, if any, to be paid to us in respect to these additional costs.

In December 2008, the Pipeline segment successfully settled a claim related to the TMX project completed during fiscal 2009. The claim was settled for $16.2 million which had previously been recognized as revenue in the three months ended September 30, 2008. Additionally, our Heavy Construction and Mining segment had $5.3 million of claims revenue for three months ended December 31, 2008 while our Piling segment had $2.9 million of claims revenue for the same period. Both segments’ claims revenue related to unsigned change orders.

For the three months ended September 30, 2008, our Heavy Construction and Mining segment had $13.1 million of claims revenue while our Piling segment had $0.6 million of claims revenue for the same period. Both segments’ claims revenue related to unsigned change orders.

In June 2008, the Pipeline segment successfully settled a claim related to a project completed in the 2008 fiscal year. The claim was settled for $8.0 million, of which $5.3 million was recognized as revenue in the three months ended June 30, 2008. The balance of $2.7 million was previously recognized as revenue in the three months ended September 30, 2007. Additionally, our Heavy Construction and Mining segment had $7.7 million of claims revenue for the three months ended June 30, 2008. This claims revenue related to unsigned change orders.


		34

Management’s Discussion and Analysis

Of the claims revenue recognized during fiscal 2009, $45.7 million of claims revenue has been collected as of March 31, 2009.

C. Key trends

Seasonality

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

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

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

Backlog

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

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

Our measure of backlog does not define what we expect our future workload to be. We work with our customers using cost-plus, time-and-materials, unit-price and lump-sum contracts. This mix of contract types varies year-by-year. Our definition of backlog results in the exclusion of cost-plus and time-and-material contracts performed under master service agreements where scope is not clearly defined. While contracts exist for a range of services to be provided under these service agreements, the work scope and value are not clearly defined. For the three months ended March 31, 2009, the total amount of revenue earned under our master services agreements was approximately $86.1 million and for the year ended March 31, 2009 was $371.3 million.

Our estimated backlog by segment and contract type as at March 31, 2009 and 2008 was:


By Segment	March 31,
(dollars in thousands)	2009	2008
Heavy Construction and Mining	$667,674	$896,269
Piling	8,538	20,554
Pipeline	–	65,477

Total	$676,212	$982,300

By Contract Type	March 31,
(dollars in thousands)	2009	2008
Unit-Price	$672,725	$905,196
Lump-Sum	3,487	11,627
Time-and-Material, Cost-Plus	–	65,477

Total	$676,212	$982,300

A contract with a single customer represented approximately $664.1 million of the March 31, 2009 backlog compared to $611.6 million reported as backlog in our Management’s Discussion and Analysis for the three and nine months ended December 31, 2008. The increase in the five-year backlog for this customer relates to the timing of scheduled volumes through the life of the contract.


				35

Management’s Discussion and Analysis

We expect that approximately $115.1 million of total backlog will be performed and realized in the 12 months ending March 31, 2010.*

Major Suppliers

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

Tire supply has been a challenge for our haul truck fleet over the past few years. We prefer to use radial tires from proven manufacturers, but the shortage of supply has forced us to use bias tires and source radial tires from new manufacturers. Bias tires have a shorter usage life and are of a lower quality than radial tires. This affects operations as we are forced to reduce operating speeds and loads to compensate for the quality of the tires. Tire supply has continued to improve over the last few months. The reduction in demand for tires has resulted in a decline in the premium pricing from these non-dealer sources. Given this reduction in price, combined with the improved tire supply, we will reduce our inventory levels over the coming months and eliminate the purchase of any bias tires. This is expected to improve our near-term cash management of purchases while we draw down on our inventory of higher-cost tire inventory.

Contracts

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

The following table demonstrates our revenue by contract type:

LOGO

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

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

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

Cost-plus. A cost-plus contract is a contract in which all the work is completed based on actual costs incurred to complete the work. These costs include all labour, equipment, materials and any subcontractors’ costs. In addition to

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


		36

Management’s Discussion and Analysis

these direct costs, all site and corporate overhead costs are charged to the job. An agreed-upon fee that represents a profit in the form of a fixed percentage is then applied to all costs charged to the project. This type of contract is utilized where the project involves a large amount of risk or the scope of the project cannot be readily determined.

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

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

Competition

Our industry is highly competitive in each of our markets and competition increased during the year ended March 31, 2009 as a result of weaker economic conditions. Historically, the majority of our new business was awarded to us based on past client relationships without a formal bidding process. However, to generate new business with new customers, we have had to participate in formal bidding processes. As new major projects arise, we expect to have to participate in bidding processes on a meaningful portion of the work available to us on these projects. Factors that impact competition include price, safety, reliability, scale of operations, equipment and labour availability and quality of service. Most of our clients and potential clients in the oil sands area operate their own heavy mining equipment fleet. However, these operators have historically outsourced a significant portion of their mining and site preparation operations and other construction services.*

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

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

D. Outlook

With investment in new oil sands development constrained by macro-economic conditions and some near-term variability anticipated in our recurring services revenue, our expectations for the first half of fiscal 2010 remain cautious. Overall, however, we are beginning to see positive developments, that improve our longer-term outlook.*

In the area of oil sands project development, we believe that reductions in project costs and a gradual strengthening of oil prices are creating a more attractive environment for investment. Imperial Oil Ltd.’s approval of the Kearl project is an example of this. In addition, the announced merger between Suncor and Petro-Canada is expected to have a positive impact on oil sands investment by creating a single entity with the resources to support large capital projects.*

On the recurring services front, we expect to see growth resuming in the second half of fiscal 2010 as a result of increased volumes under service agreements and a gradual ramp up of service on our overburden removal contract with Canadian Natural. We began to mobilize equipment back to the Horizon Project on April 1, 2009 and volumes should gradually return to normal levels over the next six months. As discussed in “Current Canadian Oil Sands Business Conditions” of the Operations Overview section of this Management’s Discussion and Analysis, demand for recurring services is largely unaffected by changes in oil prices as operational oil sands mines must operate at full capacity in order to defray the high fixed cost and maintain low unit costs. Furthermore, demand for recurring services typically grows as new mines come on-line and maturing mines expand their geographic footprint.*

Our near-term outlook for the industrial construction market has improved marginally with several relatively small contract wins, including our Heavy Construction and Mining segment’s first entry into the Saskatchewan industrial construction market.

Our Piling division has recently opened an office in Toronto, Ontario and is actively bidding piling work in this market, which is expected to benefit from $32.5 billion in announced federal and provincial government spending over the next two years.*

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


				37

Management’s Discussion and Analysis

While these are positive developments, commercial and industrial construction activity in Canada remains well below fiscal 2007 and 2008 levels. In addition, with the TMX project completed, pipeline revenues are expected to be significantly below fiscal 2008 and 2009 levels. We continue to review new pipeline opportunities to replace this revenue but we do not expect to be involved in a major pipeline project in the near term.*

As we work through the current market conditions, we intend to continue to leverage our strong market position, high-quality equipment fleet and experienced management team to secure profitable business. We will also continue to focus on strengthening our balance sheet through careful management of capital spending, working capital management and tight cost control.*

E. Legal and labour matters

Laws and Regulations and Environmental Matters

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

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

building and similar codes and zoning ordinances;

laws and regulations relating to consumer protection; and

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

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

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

The nature of our operations and our ownership or operation of property exposes us to the risk of claims with respect to environmental matters and there can be no assurance that material costs or liabilities will not be incurred with such claims. For example, some laws can impose strict, joint and several liability on past and present owners or operators of facilities at, from or to which a release of hazardous substances has occurred, on parties who generated hazardous substances that were released at such facilities and on parties who arranged for the transportation of hazardous substances to such facilities. If we were found to be a responsible party under these statutes, we could be held liable for all investigative and remedial costs associated with addressing such contamination, even though the releases were caused by a prior owner or operator or third party. We are not currently named as a responsible party for any environmental liabilities on any of the properties on which we 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, 2007, 2008 and 2009 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, 2009, we had over 295 salaried employees and over 1,300 hourly employees. Our hourly workforce fluctuates according to the seasonality of our business and the staging and timing of projects by our customers. The hourly workforce typically ranges in size from 1,000 employees to approximately 2,100 employees depending on the time of year and duration of awarded projects. We also utilize the services of subcontractors in our construction business. An estimated 8% to 10% of the construction work we do is performed by subcontractors. Approximately 1,000 employees are members of various unions and work under collective bargaining agreements. The majority of our work is

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


		38

Management’s Discussion and Analysis

done through employees governed by our mining overburden collective bargaining agreement with the International Union of Operating Engineers Local 955, the primary term of which expires on October 31, 2009. A small portion of our employees work under a collective bargaining agreement with the Alberta Road Builders and Heavy Construction Association and the International Union of Operating Engineers Local 955, the primary term of which expired February 28, 2009. These negotiations are ongoing as of the date of writing and we expect that a deal will be reached later in the year without issue. In June 2008, we signed an agreement with the International Union of Operating Engineers Local 955 covering the small group of employees working in our Acheson shop, which will expire June 30, 2011. We are subject to other industry and specialty collective agreements under which we complete work and the primary terms of all of these agreements are currently in effect. We believe that our relationships with all our employees, both union and non-union, are satisfactory. We have not experienced a strike or lockout.*

F. Resources and systems

Outstanding Share Data

We are authorized to issue an unlimited number of common voting shares and an unlimited number of common non-voting shares. As at June 9, 2009, there were 36,038,476 common voting shares outstanding (36,038,476 as at March 31, 2009). In comparison, 35,929,476 common voting shares were outstanding as at March 31, 2008. We had no non-voting common shares outstanding on any of the foregoing dates.

Liquidity

Liquidity Requirements

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

We maintain a significant equipment and vehicle fleet comprised of units with remaining useful lives covering a variety of time spans. It is important to adequately maintain our large revenue-producing fleet in order to avoid equipment downtime, which can impact our revenue stream and inhibit our ability to satisfactorily perform on our projects. Once units reach the end of their useful lives, they are replaced as it becomes cost prohibitive to continue to maintain them. As a result, we are continually acquiring new equipment both to replace retired units and to support our growth as we take on new projects. In order to maintain a balance of owned and leased equipment, we have financed a portion of our heavy construction fleet through operating leases. In addition, we continue to lease our motor vehicle fleet through our capital lease facilities.

We require between $30 million and $40 million annually for sustaining capital expenditures and our total capital requirements typically range from $125 million to $200 million depending on our growth capital requirements. Given the current slow down in capital projects and our previous investment in equipment, we expect to see this capital requirement decline to approximately $75 million. We typically finance approximately 30% to 50% of our total capital requirements through our operating lease facilities, 5% to 10% through our capital lease facilities and the remainder out of cash flow from operations. We believe our operating and capital lease facilities and cash flow from operations will be sufficient to meet these requirements. Our equipment is currently split among owned (41%), leased (42%) and rented equipment (17%). This equipment mix is a change from the mix reported in previous periods as a result of the closeout of projects that operated with significant amounts of rental equipment. This mix allows us to respond to variations in construction activity and still maintain positive cash flow from operations. Approximately 43% of our leased fleet is specific to one long-term overburden removal project. We are currently evaluating our capital needs given the rapid decline in capital projects by our major customers. We have already cancelled orders for equipment due for delivery towards the end of calendar 2009. We are monitoring equipment lead times and working closely with suppliers to ensure that we limit our capital spending going forward.*

As at December 31, 2008, we received lease financing for the second cable shovel that was commissioned for the long-term overburden removal project. We continue to receive interest from finance companies to support our current lease requirements and we have availability under one of our supplier’s leasing program to meet our current equipment needs from this supplier. We are currently negotiating with these finance companies to secure financing for our other equipment needs over the next two quarters.

Our long-term debt includes US$200 million of 8³/4% senior notes due in December 2011. Prior to February 2, 2009, the foreign currency risk relating to both the principal and interest portions of these 8³/4% senior notes was managed with a cross-currency swap and interest rate swaps, which went into effect concurrent with the issuance of the notes on November 26, 2003. The swap agreements were an economic hedge but had not been designated as hedges for accounting purposes. Interest totaling C$13.0 million on the 8³ /4% senior notes and the swap is payable semi-annually in June and December of each year until the notes mature on December 1, 2011. The US$200 million principal amount was fixed at C$1.315=US$1.000, resulting in a principal repayment of $263 million due on December 1, 2011. There are no principal repayments required on the 8³/4 % senior notes until maturity.

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


				39

Management’s Discussion and Analysis

On December 17, 2008, we received notice that all three swap counterparties had exercised the cancellation option on the US dollar interest rate swap and, effective February 2, 2009, the US dollar interest rate swap was terminated. As of February 2, 2009, our interest expense increased by US$6.8 million per annum (based on current LIBOR rates) for the remaining life of the 8³/4% senior notes. A more detailed discussion of this cancellation can be found below in the “Foreign currency risk” and “Interest rate risk” sections of Quantitative and Qualitative Disclosures about Market Risk.

One of our major contracts allows the customer to require that we provide up to $50 million in letters of credit. As at March 31, 2009, we had $20.8 million in letters of credit outstanding in connection with this contract. Any change in the amount of the letters of credit required by this customer must be requested by November 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 $125 million revolving credit facility. As at March 31, 2009, we had approximately $104.2 million of available borrowings under our revolving credit facility after taking into account $20.8 million of outstanding and undrawn letters of credit to support performance guarantees associated with customer contracts.

As at March 31, 2009 we had $16.0 million in trade receivables that were more than 30 days past due compared to $13.2 million as at March 31, 2008. We have currently provided for $2.6 million ($0.7 million at March 31, 2008) through our allowance for doubtful accounts. We continue to monitor the credit worthiness of our customers. To date our exposure to potential write-downs in trade receivables has been limited to the financial condition of developers of condominiums and high rise developments.

Working Capital Fluctuations Effect on Cash

The seasonality of our work may result in a slow down in cash collections between December and early February, which may result in an increase in our working capital requirements. Our working capital is also significantly affected by the timing of completion of projects. 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 usually defined by the contract and in some cases provincial legislation). This amount acts as a form of security for our customers and is referred to as a holdback. We are only entitled to collect payment on holdbacks once substantial completion of the contract is performed, there are no outstanding claims by subcontractors or others related to work performed by us and we have met the time period specified by the contract (usually 45 days after completion of the work). As at March 31, 2009, holdbacks totaled $9.4 million, down from $35.0 million as at March 31, 2008. Holdbacks represent 12.0% of our total accounts receivable as at March 31, 2009 (21.0% as at March 31, 2008). This decrease is attributable to the reduction of revenue for the three months ended March 31, 2009 and December 31, 2008 compared to the same periods in the prior year along with the collection of holdbacks outstanding as at March 31, 2008, including the DeBeers holdback for $11.0 million. As at March 31, 2009, we carried $2.0 million in holdbacks for three large customers.

Cash Requirements

As at March 31, 2009, our cash balance of $98.9 million was $67.0 million higher than our cash balance at March 31, 2008, as a result of the timing of capital expenditures and the timing of processing change orders and payment certificates. We anticipate that we will continue to generate a net cash surplus through June 30, 2009 from cash generated from operations. In the event that we require additional funding, we believe that any such funding requirements would be satisfied by the funds available from our revolving credit facility described immediately below.*

Revolving Credit Facility

We entered into an amended and restated credit agreement on June 7, 2007 with a syndicate of lenders that provides us with a $125.0 million revolving credit facility. Our revolving credit facility provides for an original principal amount of up to $125.0 million under which revolving loans may be made and under which letters of credit may be issued. The facility will mature on June 7, 2010, subject to possible extension. We are currently finalizing our negotiations with a banking syndicate to extend the term of our credit facility by one year. We expect to have this agreement in place by the middle of June 2009. The credit facility is secured by a first priority lien on substantially all of our and our subsidiaries’ existing and after-acquired property (tangible and intangible) including, without limitation, accounts receivable, inventory, equipment, intellectual property and other personal property and real property, whether owned or leased, and a pledge of the shares of our subsidiaries, subject to various exceptions.*

The facility bears interest on each prime loan at variable rates based on the Canadian prime rate plus the applicable pricing margin (as defined within the revolving credit agreement). Interest on US base rate loans is paid at a rate per annum equal to the US base rate plus the applicable pricing margin. Interest on prime and US base rate loans is payable monthly in arrears and computed on the basis of a 365-day or 366-day year, as the case may be. Interest on LIBOR loans is paid during each interest period at a rate per annum, calculated on a 360-day year, equal to the LIBOR rate with respect to such interest period plus the applicable pricing margin.

Our revolving credit facility contains covenants that restrict our activities including, but not limited to: incurring additional debt that doesn’t qualify as “Permitted Debt”; transferring or selling assets other than “Permitted Dispositions”; and

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


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Management’s Discussion and Analysis

making investments, including acquisitions. Permitted Debt includes, but is not limited to, debt in respect to capital leases aggregating not in excess of $30.0 million as well as an additional $25.0 million in permitted debt that may also be in the form of capital leases. Permitted Dispositions include the sale or disposition of assets in the ordinary course of business and in accordance with sound industry practice but are limited such that the disposition does not result in a material adverse affect on our business.

Under the revolving credit facility, Consolidated Capital Expenditures (as defined within the revolving credit agreement) during any applicable period cannot exceed 120% of the amount in the capital expenditure plan. In addition, we are required to satisfy certain financial covenants, including a minimum interest coverage ratio and a maximum senior leverage ratio, both of which are calculated using Consolidated EBITDA (as defined within the revolving credit agreement), as well as a minimum current ratio.

Consolidated EBITDA, as defined within the revolving credit agreement, is the sum, without duplication, of (1) consolidated net income, (2) consolidated interest expense, (3) provision for taxes based on income, (4) total depreciation expense, (5) total amortization expense, (6) costs and expenses incurred by us in entering into the credit facility, (7) accrual of stock-based compensation expense to the extent not paid in cash or if satisfied by the issue of new equity and (8) other non-cash items (other than any such non-cash item to the extent it represents an accrual of or reserve for cash expenditure in any future period) but only, in the case of clauses (2)-(8), to the extent deducted in the calculation of consolidated net income, less other non-cash items added in the calculation of consolidated net income (other than any such non-cash item to the extent it will result in the receipt of cash payments in any future period), all of the foregoing as determined on a consolidated basis for us in conformity with Canadian GAAP.

Interest coverage is determined based on a ratio of Consolidated EBITDA to consolidated cash interest expense and the senior leverage is determined as a ratio of senior debt to Consolidated EBITDA. Measured as of the last day of each fiscal quarter on a trailing four-quarter basis, Consolidated EBITDA shall not be less than 2.5 times consolidated cash interest expense (2.35 times at June 30, 2007). Also, measured as of the last day of each fiscal quarter on a trailing four-quarter basis, senior leverage shall not exceed 2.0 times Consolidated EBITDA. We believe Consolidated EBITDA is an important measure of our performance and liquidity.

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.

Debt Ratings

Our debt ratings were last assessed in December 2007 by Standard & Poor’s and Moody’s. Standard & Poor’s upgraded our debt rating from the previous rating of “B”. Moody’s maintained the rating of our debt.

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


Standard & Poor’s		B+ (stable outlook)
Moody’s		B2 (stable outlook)

Our 8¾% senior notes are rated as follows:


Standard & Poor’s		B+ (recovery rating of “4”)
Moody’s		B3 (loss given default rating of “5”)

In December 2008, Standard & Poor’s affirmed our B+ rating.

A credit rating is a current opinion of the creditworthiness of an obligor with respect to a specific financial obligation, a specific class of financial obligations, or a specific financial program (including ratings on medium-term note programs and commercial paper programs). It takes into consideration the creditworthiness of guarantors, insurers, or other forms of credit enhancement on the obligation and takes into account the currency in which the obligation is denominated. The opinion evaluates the obligor’s capacity and willingness to meet its financial commitments as they come due, and may assess terms, such as collateral security and subordination, which could affect ultimate payment in the event of default. The issue 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 issue’s market price or suitability for a particular investor.


				41

Management’s Discussion and Analysis

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

Standard and Poor’s

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

A recovery rating of “4” for the senior notes indicates an expectation for an average of 30% to 50% recovery in the event of a payment default.

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

Moody’s

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

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

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

Cash Flow and Capital Resources


	Three Months Ended March 31,				Year Ended March 31,
(dollars in thousands)	2009		2008		2009		2008		2007

Cash provided by operating activities	$70,291		$36,080		$157,785		$97,497		$1,225
Cash (used in) investing activities	(11,276	)	(2,746	)	(85,315	)	(48,632	)	(100,050	)
Cash (used in) provided by financing activities	(1,436	)	(21,809	)	(5,453	)	(23,992	)	63,011

Net increase (decrease) in cash and cash equivalents	$57,579		$11,525		$67,017		$24,873		$(35,814	)

Operating Activities

Cash provided by operating activities for the year ended March 31, 2009 was an inflow of $157.8 million compared to a cash inflow of $97.5 million for the year ended March 31, 2008 and a cash inflow of $1.2 million for the year ended March 31, 2007. For the three months ended March 31, 2009, cash provided by operating activities was an inflow of $70.3 million compared to an inflow of $36.1 million during the same period last year. Cash provided by operating activities for the year ended March 31, 2009 benefited from improved collections as we worked with our customers to process change orders and progress payment certificates. We continue to work with our customers to address delays so that we can stay current with change orders and progress payment certificates.

Investing Activities

Sustaining capital expenditures are those that are required to keep our existing fleet of equipment at its optimal useful life through capital maintenance or replacement. Growth capital expenditures relate to equipment additions required to perform larger or a greater number of projects.


		42

Management’s Discussion and Analysis

Capital leases, while not considered capital expenditures are restricted under the terms of our revolving credit agreement in the same manner as capital expenditures. Operating leases also are not considered capital expenditures but they are not restricted under the terms of our revolving credit agreement. A summary of equipment additions by nature and by period is shown on the table below:


	Three Months Ended March 31,					Year Ended March 31,
(all dollars in thousands)	2009		% of Total	2008	% of Total	2009	% of Total	2008	% of Total	2007	% of Total
Capital Expenditures
Sustaining	2,919		32%	1,517	24%	20,067	21%	21,260	37%	7,779	7%
Growth	6,325		68%	4,696	76%	74,072	79%	36,519	63%	102,240	93%

Total	$9,244		100%	$6,213	100%	$94,139	100%	$57,779	100%	$110,019	100%
Capital Leases
Sustaining	–		0%	1,088	25%	3,056	34%	7,727	88%	4,544	98%
Growth	(4,244	)	100%	3,188	75%	5,807	66%	1,102	12%	109	2%

Total	$(4,244	)	100%	$4,276	100%	$8,863	100%	$8,829	100%	$4,653	100%

Operating Leases	$42,204			$44,137		$127,410		$88,733		$47,647

For the year ended March 31, 2009, the reduction in sustaining capital expenditures compared to the prior year is reflective of an increase in funding for equipment requirements through operating leases during the earlier three month periods of the current fiscal year. The increase in growth capital additions for the current year was to meet the scheduled equipment requirements of the Canadian Natural overburden project.

Current year proceeds from asset disposals of $11.2 million ($6.9 million for the year ended March 31, 2008) and net outflow from non-cash working capital of $0.6 million (outflow of $2.8 million in the year ended March 31, 2008) lessened the effect of capital purchases. Net investment activities were an outflow of $85.3 million for the year ended March 31, 2009, compared with an outflow of $48.6 million a year ago and $100.1 million for the year ended March 31, 2007.

During the three months ended March 31, 2009, capital lease additions was reduced by $4.7 million due to the renegotiation of a capital lease to an operating lease. The tightening capital market has also had a negative effect on the cost to finance equipment additions through operating leases for the current period.

Financing activities

Financing activities for the year ended March 31, 2009 resulted in a cash outflow of $5.5 million due to a repayment of capital lease obligations partially offset by share issuances related to the exercise of stock options. Cash outflow for the year ended March 31, 2008 of $24.0 million was a result of a $20.5 million repayment to the revolving credit facility, cash settlement of stock options, repayment of capital lease obligations and financing costs partially offset by the issuance of common shares. Cash inflow for the year ended March 31, 2007 was a result of the IPO which generated an inflow of $171.1 million from the issuance of common shares offset by outflows for the $74.7 million repayment of the 9% senior secured notes, $28.0 million repurchase of preferred shares (NAEPI Series A and NACG Preferred Corp Series A) and $18.5 million for share issue costs. Other cash inflows were from a $20.5 million drawdown on the revolving credit facility, which was offset by the repayment of capital lease obligations and financing costs.

Financing activities in the three months ended March 31, 2009 resulted in a cash outflow of $1.4 million due to repayments under capital leases.

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, 2009.


	Payments due by fiscal year
(dollars in thousands)	Total	2010	2011	2012	2013	2014 and after

Senior notes ⁽¹⁾	$263,000	$ –	$ –	$263,000	$ –	$ –
Capital leases (including interest)	19,478	6,395	5,455	4,844	2,598	186
Operating leases	161,621	51,306	41,998	32,892	19,676	15,749
Supplier contracts	31,300	5,979	8,178	9,796	7,347	–

Total contractual obligations	$475,399	$63,680	$55,631	$310,532	$29,621	$15,935

⁽¹⁾

We have entered into cross-currency and interest rate swaps, which represent an economic hedge of the 8³/4% senior notes (see “Interest rate risk” in Quantitative and Qualitative Disclosures about Market Risk regarding the cancellation of the US dollar interest rate swap effective February 2, 2009). At maturity,


				43

Management’s Discussion and Analysis

we will be required to pay $263.0 million in order to retire these senior notes and the swaps. This amount reflects the fixed exchange rate of C$1.315=US$1.00 established as of November 26, 2003, the inception date of the swap contracts. At March 31, 2009, the carrying value of the derivative financial instruments was $39.5 million, inclusive of the interest components.

Off-Balance Sheet Arrangements

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

Internal Systems and Processes

Overview of Information Systems

We currently use JDE (Enterprise One) as our Enterprise Resource Planning (ERP) tool and deploy the financial system, payroll, procurement, job-costing and equipment maintenance modules from this tool. We supplement this functionality with either third-party software (for our estimating system) or in-house developed tools (for project management).

The proper identification of costs is a critical part of our ability to recognize revenues and provide accurate management information for decision-making. We continue to focus resources to address this in our ERP system through the automation of transactional activities. We continue to work on improving the process for tracking and reporting equipment and maintenance costs. We have seen some improvements in the identification and tracking of our procurement costs.

During the year ended March 31, 2009, we completed a user-needs analysis and compared this to the functionality of our ERP system. As part of this analysis, we determined if we could implement additional modules in JDE or whether we needed to commence a review of industry-specific software to supplement our existing ERP functionality. We have started plans for the implementation of specific JDE modules based on the analysis.

Also during the year ended March 31, 2009, we realized the benefits from new staff hires in the corporate finance group. Additional procedures were developed and implemented during the year to address the material weaknesses in complex and non-routine transactions and period end controls identified in the year ended March 31, 2008.

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 and include controls and procedures designed to ensure that information is accumulated and communicated to management, including the President and Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosure.

As of March 31, 2009, an evaluation was carried out under the supervision of and with the participation of management, including the President and Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) under the US Securities Exchange Act of 1934, as amended, and in National Instrument 52-109 under the Canadian Securities Administrators Rules and Policies. Based on that evaluation, the President and Chief Executive Officer and Chief Financial Officer concluded that as a result of the material weaknesses in our internal control over financial reporting discussed below the disclosure controls and procedures were not effective as of March 31, 2009.

Management’s Report on Internal Controls over Financial Reporting (ICFR)

Internal control over financial reporting is a process designed to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and of the preparation of financial statements for external purposes in accordance with Canadian GAAP and reconciled to US GAAP. Management, including the President and Chief Executive Officer and Chief Financial Officer, are responsible for establishing and maintaining adequate ICFR, as such term is defined in Rule 13a-15(e) under the US Securities Exchange Act of 1934 and in National Instrument 52-109 under the Canadian Securities Administrators Rules and Policies to provide reasonable, but not absolute, assurance regarding the reliability of our financial reporting. A material weakness in ICFR exists if the deficiency is such that there is reasonable possibility that a material misstatement of our annual or interim consolidated financial statements will not be prevented or detected on a timely basis.

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

As of March 31, 2009, we assessed the effectiveness of the Company’s ICFR. In making this assessment, we used the criteria set forth in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). During this process we identified a material weakness in internal controls over financial reporting as described below and, as a result, we concluded that the Company’s ICFR is ineffective as of March 31, 2009.

We did not maintain effective processes and controls specific to revenue recognition. We did not effectively develop, communicate and implement an appropriate revenue recognition policy, a formal process to track claims and unapproved change orders and sufficient monitoring controls over the completeness and accuracy of forecasts, including


		44

Management’s Discussion and Analysis

the consideration of project changes subsequent to the end of each reporting period. The accounts that could be affected by these deficiencies are revenue, project costs, unbilled revenue and billings in excess of costs incurred and estimated earnings on uncompleted contracts. This material weakness in ICFR, which is pervasive in nature, resulted in material errors in the financial statements that were corrected prior to release of the financial statements. Further, there is a reasonable possibility that a material misstatement of our financial statements will not be prevented or detected on a timely basis. Notwithstanding the above mentioned weakness, we have concluded that the Consolidated Financial Statements included in this report fairly present the Company’s consolidated financial position and consolidated results of operations as of and for the fiscal year ending March 31, 2009.

KPMG LLP, the registered public accounting firm that audited the financial statements included in the annual report containing this disclosure has issued an attestation report on the registrant’s internal control over financial reporting.

Remediation Plans

In response to the material weakness identified above, during the three months ended and subsequent to March 31, 2009, we formalized our revenue recognition policy to assist in the understanding and consistent application of GAAP, initiated the development of a procedural manual to assist with applying the revenue recognition policy, designed new process-level controls and conducted staff training. We will evaluate the effectiveness of these controls during the next fiscal year to determine if they adequately address our ability to recognize revenue in accordance with GAAP.

Changes to Internal Control over Financial Reporting

As of March 31, 2008, we identified the following additional material weaknesses in our ICFR. These weaknesses were remediated in the year ended March 31, 2009 as follows:

Complex and non-routine transactions and period end controls: There was a lack of sufficient accounting and finance personnel with an appropriate level of technical accounting knowledge and training commensurate with the complexity of our financial accounting and reporting requirements. Complex and non routine financial reporting matters identified, in the year ended March 31, 2008, included the identification of embedded derivatives and preparation of our US GAAP reconciliation note. Additionally we did not adequately perform controls related to the review and approval of account analysis, verification of inputs and reconciliations. We rectified the complex and non-routine transactions and period end control weaknesses in fiscal 2009 by reorganizing the corporate accounting group and recruiting new staff with the appropriate experience and technical skills to prevent a reoccurrence of these issues.

Accounts payable and procurement: We did not have an effectively implemented procurement process to track purchase commitments, reconcile vendor accounts and accurately accrue costs not invoiced by vendors at each reporting date. To rectify the accounts payable and procurement weakness we implemented additional monitoring and detective controls to address these deficiencies, including reconciliation of supplier accounts and review of payments made to suppliers and supplier invoices received subsequent to March 31, 2009.

There were no other changes to our internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s ICFR.

Significant Accounting Policies

Critical Accounting Estimates

Certain accounting policies require management to make significant estimates and assumptions about future events that affect the amounts reported in our financial statements and the accompanying notes. Therefore, the determination of estimates requires the exercise of management’s judgment. Actual results could differ from those estimates and any differences may be material to our financial statements.

Revenue Recognition

Our contracts with customers fall under the following contract types: cost-plus, time-and-materials, unit-price and lump-sum. While contracts are generally less than one year in duration, we do have several long-term contracts. The mix of contract types varies year-by-year. For the three months ended March 31, 2009, our revenue mix was made up of 60.6% time-and-materials contracts, 31.7% unit-price contracts, 7.5% lump-sum contracts and 0.2% cost-plus contracts.

Profit for each type of contract is included in revenue when its realization is reasonably assured. Estimated contract losses are recognized in full when determined. Claims and unapproved change orders are included in total estimated contract revenue only to the extent that contract costs related to the claim or unapproved change order have been incurred, when it is probable that the claim or unapproved change order will result in a bona fide addition to contract value and the amount of revenue can be reliably estimated.

The accuracy of our revenue and profit recognition in a given period is dependent, in part, on the accuracy of our estimates of the cost to complete each unit-price and lump-sum project. Our cost estimates use a detailed “bottom-up” approach, using inputs such as labour and equipment hours, detailed drawings and material lists. These estimates are updated monthly. We have implemented monitoring and review controls to assist with the determination of our cost estimates. These controls require a significant review of our payable activities after the month-end to ensure that we have identified project costs in the correct period. Given the time delay in identifying costs, we may misstate revenues.


				45

Management’s Discussion and Analysis

However, we believe our experience allows us to produce materially reliable estimates. Our projects can be highly complex and in almost every case, the profit margin estimates for a project will either increase or decrease to some extent from the amount that was originally estimated at the time of the related bid. Because we have many projects of varying levels of complexity and size in process at any given time, these changes in estimates can offset each other without materially impacting our profitability. However, sizable changes in cost estimates, particularly in larger, more complex projects, can have a significant effect on profitability. Factors that can contribute to changes in estimates of contract cost and profitability include, without limitation:*

changes in site conditions that differ from those assumed in the original bid, to the extent that contract remedies are unavailable;

changes in identification and evaluation of scope modifications during the execution of the project;

changes in the availability and cost of skilled workers in the geographic location of the project;

changes in the availability and proximity of materials;

changes in unfavorable weather conditions hindering productivity;

changes in equipment productivity and timing differences resulting from project construction not starting on time; and

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

The foregoing factors, as well as the stage of completion of contracts in process and the mix of contracts at different margins, may cause fluctuations in gross profit between periods and these fluctuations may be significant. These changes in cost estimates and revenue recognition impact all three business segments.

Once contract performance is underway, we will often experience changes in conditions, client requirements, specifications, designs, materials and work schedule. Generally, a “change order” will be negotiated with the customer to modify the original contract to approve both the scope and price of the change. Occasionally, however, disagreements arise regarding changes, their nature, measurement, timing and other characteristics that impact costs and revenue under the contract. When a change becomes a point of dispute between a customer and us, we then consider it as a claim.

Costs related to unapproved change orders and claims are recognized when they are incurred. Unapproved change orders and claims are included in total estimated contract revenue when it is probable that the unapproved change order or claim will result in a bona fide addition to contract value and can be reliably estimated and only to the extent that contract costs related to the claim have been incurred. Those two conditions are satisfied when (1) the contract or other evidence provides a legal basis for the claim or a legal opinion is obtained providing a reasonable basis to support the unapproved change order or claim, (2) additional costs incurred were caused by unforeseen circumstances and are not the result of deficiencies in our performance, (3) costs associated with the unapproved change order or claim are identifiable and reasonable in view of the work performed and (4) evidence supporting the unapproved change order or claim is objective and verifiable. No profit is recognized on unapproved change orders or claims until final settlement occurs. This can lead to a situation where costs are recognized in one period and revenue is recognized when customer agreement is obtained or unapproved change order or claim resolution occurs, which can be in subsequent periods. Historical unapproved change order or claim recoveries should not be considered indicative of future unapproved change order or claim recoveries.

Plant and Equipment

The most significant estimates in accounting for plant and equipment are the expected useful life of the asset and the expected residual value. Most of our property, plant and equipment have long lives that can exceed 20 years with proper repair work and preventative maintenance. Useful life is measured in operating hours, excluding idle hours, and a depreciation rate is calculated for each type of unit. Depreciation expense is determined monthly based on daily actual operating hours. 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 plant and equipment, which could result in a higher depreciation expense in future periods or we may record an impairment charge to write down the value of plant and equipment.

Another key estimate is the expected cash flows from the use of an asset and the expected disposal proceeds in applying the Canadian Institute of Chartered Accountants (CICA) Handbook Section 3063 “Impairment of Long-Lived Assets” and CICA Handbook Section 3475 “Disposal of Long-Lived Assets and Discontinued Operations”. These standards require the recognition of an impairment loss for a long-lived asset when changes in circumstances cause its carrying value to exceed the total undiscounted cash flows expected from its use. An impairment loss, if any, is determined as the excess of the carrying value of the asset over its fair value. The valuation of long-lived assets requires


		46

Management’s Discussion and Analysis

us to exercise judgment in the determination of an asset group and in making assumptions about future results, including revenue and cash flow projections for an asset group.

Allowance for Doubtful Accounts Receivable

We regularly review our accounts receivable balances for each of our customers and we write down these balances to their expected realizable value when outstanding amounts are determined not to be fully collectible. This generally occurs when our customer has indicated an inability to pay, we were unable to communicate with our customer over an extended period of time and we have considered other methods to obtain payment without success. We determine estimates of the allowance for doubtful accounts on a customer-by-customer evaluation of collectability at each reporting date, taking into consideration the following factors: the length of time the receivable has been outstanding, specific knowledge of each customer’s financial condition and historical experience.

Goodwill Impairment

Impairment is tested at the reporting unit level by comparing the reporting unit’s carrying amount to its fair value. The process of determining fair value is subjective and requires us to exercise judgment in making assumptions about future results, including revenue and cash flow projections at the reporting unit level and discount rates. We previously tested goodwill annually on December 31. Starting in fiscal year 2008 we completed the annual goodwill impairment testing on October 1. This change in timing was made to reduce conflict between the impairment testing and our financial reporting close process for the fiscal period ending December 31 of each calendar year. It is our intention to continue to complete subsequent goodwill impairment testing on October 1 going forward or whenever events or changes in circumstances indicate that impairment may exist. This change in accounting policy was applied on a retrospective basis and had no impact on the consolidated financial statements. We completed our most recent annual goodwill impairment testing on October 1, 2008. On December 31, 2008, we performed an interim goodwill impairment test due to recent economic events which adversely affected the value of our Pipeline reporting unit. We concluded that neither the fair value of our Heavy Construction and Mining reporting unit nor our Piling reporting unit had fallen below their carrying values as a result of the interim testing. During the three months ended March 31, 2009, we observed a further deterioration in industry conditions. As a result we concluded that events had occurred and circumstances had changed that required us to perform an additional interim goodwill impairment test for the Heavy Construction and Mining and Piling reporting units as at March 31, 2009. This impairment test showed that the fair values of both the Heavy Construction and Mining and the Piling reporting units had fallen below their carrying values. For a more detailed discussion on our goodwill impairment testing as at October 1, 2008, as at December 31, 2008 and as at March 31, 2008, see “Impairment of Goodwill” in the Analysis of Annual Results discussion above.

Financial Instruments

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

Related Parties

We may receive consulting and advisory services provided by the principals or employees of companies owned or operated by certain of our directors (the Sponsors) with respect to the organization of our employee benefit and compensation arrangements, and other matters, and no fee is charged for these consulting and advisory services.

In order for the Sponsors to provide such advice and consulting, we provide the Sponsors with reports, financial data and other information. This permits them to consult with and advise our management on matters relating to our operations, company affairs and finances. In addition, this permits them to visit and inspect any of our properties and facilities. These services are provided in the normal course of operations and are measured at the value of consideration established and agreed to by the related parties.

Canadian Recently Adopted Accounting Policies (Canadian GAAP)

Financial Instruments – Disclosure and Presentation

Effective April 1, 2008, we prospectively adopted the CICA Handbook Section 3862, “Financial Instruments – Disclosures”, which replaces disclosure guidance in CICA Handbook Section 3861 and provides expanded disclosure requirements that enable users to evaluate the significance of financial instruments on our financial position and our performance and the nature and extent of risks arising from financial instruments to which we are exposed during the period and at the balance sheet date, and how we manage those risks. This standard harmonizes disclosures with International Financial Reporting Standards. We have provided the required disclosures in note 22 to our consolidated financial statements for the year ended March 31, 2009.

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


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Management’s Discussion and Analysis

Effective April 1, 2008, we adopted CICA Handbook Section 3863, “Financial Instruments – Presentation”, which carries forward presentation guidance in CICA Handbook Section 3861. This Section establishes standards for presentation of financial instruments and non-financial derivatives. It deals with the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, gains and losses, and the circumstances in which financial assets and financial liabilities are offset. The adoption of this standard did not have a material impact on the presentation of financial instruments in our consolidated financial statements.

Capital Disclosures

Effective April 1, 2008, we prospectively adopted CICA Handbook Section 1535, “Capital Disclosures”, which requires disclosure of qualitative and quantitative information that enables users to evaluate our objectives, policies and process for managing capital, including disclosures of any externally imposed capital requirements and the consequences of non-compliance. We have provided the required disclosures in note 23 to our consolidated financial statements for the year ended March 31, 2009.

Inventories

Effective April 1, 2008, we retrospectively adopted CICA Handbook Section 3031, “Inventories” without restatement of prior periods. This standard requires inventories to be measured at the lower of cost and net realizable value and provides guidance on the determination of cost, including the allocation of overheads and other costs to inventories, the requirement for an entity to use a consistent cost formula for inventory of a similar nature and use, and the reversal of previous write-downs to net realizable value when there is 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. To adopt this new standard, we reversed a tire impairment of $1.4 million that was previously recorded at March 31, 2008 in other assets with a corresponding decrease to opening deficit of $1.0 million net of future taxes of $0.4 million. We then reclassified $5.1 million of tires and spare component parts from ‘Other assets’ to ‘Inventory’. As at March 31, 2009, inventory is comprised of spare tires of $10.5 million and job materials of $1.3 million. We carry inventory at the lower of weighted average cost and net realizable value. The carrying amount of inventory pledged as security for borrowings under the revolving credit facility is approximately $11.8 million as at March 31, 2009. The adoption of this standard did not have a material impact on net (loss) income for the year ended March 31, 2009.

Credit Risk and the Fair Value of Financial Assets and Financial Liabilities

In January 2009, the CICA issued EIC Abstract 173, “Credit Risk and the Fair Value of Financial Assets and Financial Liabilities”. This EIC requires us to take into account our own credit risk and the credit risk of the counterparty in determining the fair value of financial assets and financial liabilities, including derivative instruments. The adoption of this abstract in the three months ended March 31, 2009, did not have a material impact on our consolidated financial statements.

Canadian Recent Accounting Pronouncements Not Yet Adopted (Canadian GAAP)

Goodwill and Intangible Assets

In February 2008, the CICA issued Handbook Section 3064, “Goodwill and Intangible Assets”, which replaces Section 3062, Goodwill and Intangible Assets, and Section 3450, Research and Development Costs and establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The provisions relating to the definition and initial recognition of intangible assets, including internally generated intangible assets, are equivalent to the corresponding provisions of International Accounting Standard IAS 38, Intangible Assets. This new standard is effective for our interim and annual consolidated financial statements commencing April 1, 2009. We are currently evaluating the impact of this standard.

Business Combinations

In January 2009, the CICA issued Handbook Section 1582, “Business Combinations,” which replaces the existing standard. This section establishes standards for the accounting of business combinations, and states that all assets and liabilities of an acquired business will be recorded at fair value. Obligations for contingent considerations and contingencies will also be recorded at fair value at the acquisition date. The standard also states that acquisition related costs will be expensed as incurred, that restructuring charges will be expensed in the periods after the acquisition date and that non-controlling interest should be measured at fair value at the date of acquisition. This standard is equivalent to International Financial Reporting Standards on business combinations. This standard is to be applied prospectively to business combinations with acquisition dates on or after January 1, 2011 and earlier adoption is permitted. We are currently evaluating the impact of this standard.

Consolidated Financial Statements

In January 2009, the CICA issued Handbook Section 1601, “Consolidated Financial Statements,” which replaces CICA 1600 – Consolidated Financial Statements. This Section carries forward existing Canadian guidance for preparing consolidated financial statements other than guidance for non-controlling interests. This standard is effective for interim and annual financial statements beginning on January 1, 2011 and earlier adoption is permitted. We are currently evaluating the impact of this standard.


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Management’s Discussion and Analysis

Non-controlling Interests

In January 2009, the CICA issued Handbook Section 1602, “Non-Controlling Interests”, which establishes standards for the accounting of non-controlling interests of a subsidiary in the preparation of consolidated financial statements subsequent to a business combination. This standard is equivalent to International Financial Reporting Standards on consolidated and separate financial statements. This standard is effective for interim and annual financial statements beginning on January 1, 2011 and earlier adoption is permitted. We are currently evaluating the impact of this standard.

United States Recently Adopted Accounting Pronouncements (US GAAP)

As a Canadian public company which is also a Securities and Exchange Commission (“SEC”) registrant we are required by the SEC to provide a reconciliation of the differences between our audited annual consolidated financial statements presented in accordance with Canadian GAAP and our audited consolidated financial statements if they were presented in accordance with US GAAP. As such, we are required to monitor US GAAP pronouncements and assess how they differ from Canadian GAAP.

In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109” (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This Interpretation also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition requirements. FIN 48 was effective for our fiscal year ended March 31, 2008. The adoption of this standard did not have a material impact on our financial statements and disclosures required under the standard are provided in note 19 to our consolidated financial statements.

In May 2007, the FASB issued FASB Staff Position No. FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48”, which provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. This FASB Staff Position is effective upon the initial adoption of FIN 48. The adoption of this standard did not have a material impact on our consolidated financial statements.

Effective April 1, 2008, we adopted Statement of Financial Accounting Standard (“SFAS”) No. 157, “Fair Value Measurements” which defines fair value, establishes a framework and prescribes methods for measuring fair value and outlines the additional disclosure requirements on the use of fair value measurements. Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for an asset or liability in an orderly transaction between market participants at the measurement date. SFAS No. 157 establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs market participants would use in valuing the asset or liability developed based on market data obtained from sources independent of the company. Unobservable inputs are inputs that reflect our assumptions about the factors market participants would use in valuing the asset or liability developed based upon the best information available in the circumstances. SFAS No. 157 establishes a three-level fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of fair value hierarchy based on the reliability of inputs are as follows:

Level I inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities;

Level II inputs are significant observable inputs other than quoted prices included in level I, such as quoted prices for similar assets and liabilities in active markets; quoted prices for identical or similar assets and liabilities in markets that are not active; or other inputs that are observable or can be corroborated by observable market data; and

Level III inputs are significant unobservable inputs that reflect the reporting entity’s own assumptions and are supported by little or no market activity.

We have segregated all financial assets and 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 in the table below. FASB Staff Position (“FSP”) No. 157-2 delayed the effective date of the provisions of SFAS 157 for non-financial assets and liabilities that are not re-measured at fair value on a recurring basis until April 1, 2009. Financial assets and liabilities measured at fair value as at March 31, 2009 in the financial statements on a recurring basis are summarized below:


Description	Carrying value		Level I	Level II		Level III
Cross currency and interest rate swaps for US dollar 8³/4% senior notes	$39,547		$ –	$39,547		$ –
Embedded price escalation features in a long term revenue construction contract	(324	)	–	(324	)	–
Embedded price escalation features in long term supplier contract	22,778		–	22,778		–
Embedded prepayment and early redemption options on senior notes	3,716		–	3,716		–

	$65,717		$ –	$65,717		$ –


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Management’s Discussion and Analysis

We have determined that the fair value of our US dollar 8³/4% senior notes are considered a Level I measurement as these notes are traded in an active market.

Since we primarily use observable inputs in our valuation of our derivative financial instruments, they are valued using Level II inputs. The fair values of our cross-currency and interest rate swap agreements and our embedded derivatives are based on appropriate price modeling commonly used by market participants to estimate fair value. Such modeling includes option pricing models and discounted cash flow analysis, using observable market based inputs to estimate fair value. We consider our 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 our best estimates using external readily observable market data such as future prices, interest rate yield curves, foreign exchange rates and discount rates for time value. It is possible that the assumptions used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be material. We used the following inputs to estimate the fair value of each class of Level II financial instruments:

The fair values of our cross-currency and interest rate swap agreements are based on appropriate price modeling commonly used by market participants to estimate fair value. The fair values of our interest rate swap agreements are estimated using discounted cash flow analysis with inputs of observable market data including future interest rates, implied volatilities and the credit risk of the counterparties or ourselves, as appropriate, with resulting valuations periodically validated through third-party or counterparty quotes. The fair values of cross-currency swaps are estimated using discounted cash flow analysis with inputs of observable market data including foreign currency exchange rates, implied volatilities, interest rates and our credit risk or that of our counterparties, as appropriate, with resulting valuations periodically validated through third-party or counterparty quotes;

The fair value of our optional redemption rights included in the senior notes have been estimated using discounted cash flow analysis with input of observable market data including foreign currency exchange rates, implied volatilities and interest rates; and

The fair value of price escalation features in revenue and maintenance service contracts containing embedded derivatives have been estimated using generally accepted valuation models based on discounted cash flows with inputs of observable market data, including foreign currency exchange rates and discount factors.

Currently, we have not measured the fair value of any financial instruments using Level III (significant unobservable) inputs.

In early October 2008, the FASB issued FSP No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active”, which amended SFAS No. 157 to illustrate key considerations in determining the fair value of a financial asset in an inactive market. This FSP was effective for periods beginning with the quarter ended September 30, 2008. The adoption of this standard did not have a material impact on our consolidated financial statements.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”) was issued in February 2007. The statement permits entities to choose to measure many financial instruments and certain other items at fair value, providing the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without the need to apply hedge accounting provisions. SFAS 159 is effective for fiscal years beginning after November 15, 2007, specifically April 1, 2008 for us. The adoption of this standard did not have a material impact on our consolidated financial statements.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement 133” (“SFAS 161”) was issued March 2008. SFAS 161 is effective for interim or annual periods beginning after November 15, 2008. The statement requires companies with derivative instruments to disclose information about how and why a company uses derivative instruments, how derivative instruments and related hedged items are accounted for under Statement 133, and how derivative instruments and related hedged items affect its financial position, financial performance and cash flows. The required disclosures include the fair value of derivative instruments and their gains or losses in tabular format, information about credit-risk-related contingent features in derivative agreements, counterparty credit risk, and our strategies and objectives for using derivative instruments. The Statement expands the current disclosure framework in Statement 133. The adoption of this standard did not have a material impact on our consolidated financial statements.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles”. The statement identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements in accordance with US GAAP. This statement was effective for us on November 15, 2008, which is 60 days after the SEC’s approval of Auditing Standard No. 6, “Evaluating Consistency of Financial Statements”. The adoption of this standard did not have a material impact on our consolidated financial statements.


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Management’s Discussion and Analysis

United States Recent Accounting Pronouncements Not Yet Adopted (US GAAP)

SFAS No. 141R, “Business Combinations” (“SFAS 141R”) was issued December 2007. SFAS No. 141R is effective for the fiscal year beginning April 1, 2009. The statement establishes principles and requirements for how we, as an acquirer, recognize and measure in our financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and any goodwill. This statement establishes disclosure requirements that will enable users of our financial statements to evaluate the nature and financial effects of the business combination. We are currently evaluating the impact of this standard on our consolidated financial statements.

SFAS No. 160 “Non-controlling Interests in Consolidated Financial Statements – An Amendment of ARB No. 51” (“SFAS 160”) was issued December 2007. SFAS 160 is effective for the fiscal year beginning April 1, 2009. This statement changes the accounting and reporting for ownership interests in subsidiaries held by parties other than the parent. These non-controlling interests are to be presented in the consolidated statement of financial position within equity but separate from the parent’s equity. The amount of consolidated net income attributable to the parent and to the non-controlling interest is to be clearly identified and presented on the face of the consolidated statement of operations. In addition, this statement establishes standards for a change in a parent’s ownership interest in a subsidiary and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. The statement also establishes reporting requirements for providing sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. We are currently evaluating the impact of this standard on our consolidated financial statements.

SFAS No. 165, “Subsequent Events” (“SFAS 165’) was issued in May 2009. SFAS 165 is effective for interim or annual financial periods ending after June 15, 2009 and should be applied prospectively. This statement addresses accounting and disclosure requirements related to subsequent events. This statement also requires us to evaluate subsequent events through to the date the financial statements are either issued or available to be issued, depending on our expectation of whether we will widely distribute our financial statements to our shareholders and other financial statement users. We will be required to disclose the date through which subsequent events have been evaluated. We are currently evaluating the impact of this standard on our consolidated financial statements.

In April 2008, the FASB issued FSP No. FAS 142-3, “Determination of the Useful Life of Intangible Assets”, which amends the list of factors an entity should consider in developing renewal or extension assumptions used in determining the useful life of recognized intangible assets under SFAS No. 142, “Goodwill and Other Intangible Assets.” The new guidance applies to (1) intangible assets that are acquired individually or with a group of other assets and (2) intangible assets acquired in both business combinations and asset acquisitions. Under FSP No. FAS 142-3, entities estimating the useful life of a recognized intangible asset must consider their historical experience in renewing or extending similar arrangements or, in the absence of historical experience, must consider assumptions that market participants would use about renewal or extension. This FSP will require certain additional disclosures beginning April 1, 2009 and application to useful life estimates prospectively for intangible assets acquired after March 31, 2009. We are currently evaluating the impact of this standard on our consolidated financial statements.

In April 2009, the FASB issued FSP No. FAS 107-1 and APB 28-1 “Interim Disclosures about Fair Value of Financial Instruments”, which amends FASB Statement No. 107 “Disclosures about Fair Value of Financial Statements” to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. It also amends APB Opinion No. 28 “Interim Financial Reporting” to require those disclosures in summarized financial information at interim reporting periods. The FSP is effective for interim and annual periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009, in certain circumstances. This FSP is effective for our three-month period ending June 30, 2009. We are currently evaluating the impact of this standard on our consolidated financial statements.

In April 2009, the FASB issued FSP No. FAS 157-4, “Determining Fair Value when the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”, which provides additional guidance for estimating fair value in accordance with FASB Statement No. 157, “Fair Value Measurements”, when the volume and level of activity for the asset or liability have significantly decreased. It also includes guidance on identifying circumstances that indicate a transaction is not orderly. FSP No. FAS 157-4 requires that:

we should disclose in interim and annual periods the inputs and valuation techniques used to measure fair value and a discussion of changes in valuation techniques and related inputs, if any, during the period; and

we define a major category for equity securities and debt securities to be major security types as per FAS 115 and FAS 124-2.

The FSP shall be effective for interim and annual periods ending after June 15, 2009 and shall be applied prospectively. For us, this FSP is effective for the three-month period ending June 30, 2009. Early adoption is permitted for periods ending after March 15, 2009 in certain circumstances. We are currently evaluating the impact of this FSP on our consolidated financial statements.

In April 2009, the FASB issued FSP No. FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments”, which amends the other-than-impairment guidance in US GAAP for debt securities to make the


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Management’s Discussion and Analysis

guidance more operational and to improve the presentation and disclosure of the other-than-temporary impairments on debt and equity securities in the financial statements. The FSP applies to debt securities classified as available-for-sale and held-to-maturity that are subject to other than temporary impairment guidance within FAS 115. The FSP is effective for interim and annual reporting periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009, in certain circumstances. The FSP is effective for our three-month period ending June 30, 2009. We are currently evaluating the impact of this standard on our consolidated financial statements.

In April 2009, the FASB issued FSP No. FAS 141R – 1 “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies”, to amend and clarify FAS 141R, “Business Combinations”. It addresses the application issues on initial recognition and measurement, subsequent measurement and accounting and disclosure of assets and liabilities arising from contingencies in a business combination. This FSP is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after April 1, 2009. We are currently evaluating the impact of this standard on our consolidated financial statements.

G. Forward-looking information and risk factors

Forward-Looking Information

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

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

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

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

(c)	the market for our recurring services will expand due to new mines nearing production coming on-line or entering their production phases and the expansion of activities at current operational mines;

(d)	existing oil sands projects will continue to be less sensitive than conventional oil operations to changes in oil prices and oil sands operators will continue to maintain stable production activity;

(e)	commodity prices will continue to remain low and mine development in the minerals mining sector will continue to remain below normal levels;

(f)	our intention to leverage our market position, equipment fleet and management team to respond to new opportunities and to secure profitable business;

(g)	our intention to pursue selective acquisition opportunities will materialize that will expand our complementary service offerings which we will be able to cross-sell with our existing services;

(h)	our intention to build on our relationships with our existing oil sands customers to win a substantial share of the heavy construction and mining, piling and pipeline services outsourced in connection with these projects;

(i)	our intention to increase our presence outside the oil sands and extend our services to other resource industries across Canada;

(j)	the success of the enhancements to maintenance practices resulting in improved availability through reduced repair time and increased utilization of our equipment with a consequent improvement in our revenue, margins and profitability;

(k)	the amount of our backlog expected to be performed and realized in the twelve months ending March 31, 2010;

(l)	that infrastructure spending will remain robust, that we will benefit from government spending and that we will be in a good position to capitalize on infrastructure spending;

(m)	the arrival of new major projects and our required participation in the bidding process for work on these projects;

(n)	the increased variability in recurring services revenue in 2009;

(o)	the anticipated reduction in our pipeline segment revenues, the anticipated reduction in our heavy construction, mining and piling operating segment revenues and the expected lack of involvement in a major pipeline project in the near-term;


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Management’s Discussion and Analysis

(p)	the demand for our mine construction services through the life of a mine and our ability to provide such services;

(q)	our operating and capital lease facilities and cash flow from operations are sufficient to meet capital expenditure requirements;

(r)	the expected agreement with a banking syndicate to extend our credit facility one year;

(s)	our ability to produce materially reliable estimates;

(t)	the demand for our recurring oil sands services remaining strong, the resumption of growth in the second half of fiscal 2009 and the return of volumes on the Horizon project over the next six months;

(u)	the expected agreement between our employees party to the collective bargaining agreement which expired February 28, 2009 and us;

(v)	future events such as changes in existing laws and regulations possibly require us to make additional expenditures;

(w)	the expected improvement to our near-term cash management, our draw down of our inventory of higher-cost tire inventory and a reduction in our tire inventory over the coming months;

(x)	lower input costs and industry consolidation in the oil sands will lead to more substantive development in the oil sands industry and reductions in project costs and gradual strengthening of oil prices will create a more attractive environment for investment; and

(y)	the decline in commercial construction projects will be offset by an expected increase in infrastructure-related construction activity infrastructure projects.

Some of the risks and other factors which could cause results to differ materially from those expressed in the forward-looking statements contained in this Management’s Discussion and Analysis include, but are not limited to:

The forward-looking information in paragraphs (a), (b), (c), (d), (e), (f), (g), (l), (m), (n), (o), (r), (t), (u), (v), (w), (x) and (y) rely on certain market conditions and demand for our services and are based on the assumptions that: despite the slow down in the global economy and tightening of credit conditions combined with short term declines in oil prices, which will slow capital development of Canada’s natural resources, in particular the oil sands, we still expect to see strong demand for our recurring services as the oil sands continue to be an economically viable source of energy, our customers and potential customers continue to invest in the oil sands and other natural resources developments; our customers and potential customers will continue to outsource the type of activities for which we are capable of providing service; and the Western Canadian economy continues to develop with additional investment in public construction; and are subject to the following risks and uncertainties that:

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

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

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

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

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

we are unable to extend our revolving credit facility for one year;

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

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

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

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

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

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

The forward-looking information in paragraphs (a), (b), (c), (f), (g), (h), (i), (j), (k), (l), (p), (q), (r), (s), (t), (u), (v), (w), (x) and (y) rely on our ability to execute our growth strategy and are based on the assumptions that the management team can successfully manage the business; we can maintain and develop our relationships with our current customers; we will be successful in developing relationships with new customers; we will be successful in the competitive bidding process


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Management’s Discussion and Analysis

to secure new projects; that we will identify and implement improvements in our maintenance and fleet management practices; we will be able to benefit from increased recurring revenue base tied to the operational activities of the oil sands; we will be able to access sufficient funds to finance our capital growth; and are subject to the risks and uncertainties that:

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

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

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

we are unable to extend our revolving credit facility for one year;

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

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

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

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

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

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

Risk Factors

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

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

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.

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

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


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Management’s Discussion and Analysis

customers would also likely result in increased competition among oil sands service providers, which could also reduce our ability to successfully bid for new capital projects.

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

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

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

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

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

Outsourced Heavy Construction and Mining services constitute a large portion of the work we perform for our customers. For example, our mining and site preparation project revenues constituted approximately 74%, 63% and 75% of our revenues in each of fiscal years 2009, 2008 and 2007, respectively. The election by one or more of our customers to perform some or all of these services themselves, rather than outsourcing the work to us, could have a material adverse impact on our business and results of operations. Certain customers perform some of this work internally and may choose to expand on the use of internal resources to complete this work. Additionally, the recent tightening of the credit market and worldwide economic downturn may result in our customers reducing their spending on outsourced mining and site preparation services if they believe they can perform this work in a more cost effective and efficient manner using their internal resources.

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

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

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

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


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Management’s Discussion and Analysis

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 83%, 81% and 55% of our total revenue for 2009, 2008 and 2007, respectively, and those customers are expected to continue to account for a significant percentage of our revenues in the future. In addition, the majority of our Pipeline revenues in the current and previous fiscal years resulted from work performed for one customer. If we lose or experience a significant reduction of business from one or more of our significant customers, we may not be able to replace the lost work with work from other customers. Our long-term contracts typically allow our customers to unilaterally reduce or eliminate the work which we are to perform under the contract. Our contracts also generally allow the customer to terminate the contract without cause. The loss of or significant reduction in business with one or more of our major customers, whether as a result of completion of a contract, early termination or failure or inability to pay amounts owed to us, could have a material adverse effect on our business and results of operations.

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

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

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

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

Significant labour disputes could adversely affect our business.

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

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

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

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

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


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Management’s Discussion and Analysis

or general conditions in the surety bond market, our bonding capacity becomes insufficient to satisfy our future bonding requirements, our business and results of operations could be adversely affected.

Some of our customers require letters of credit to secure our performance commitments. Our second amended and restated revolving credit facility provides for the issuance of letters of credit up to $125.0 million, and at March 31, 2009, we had $20.8 million of issued letters of credit outstanding. One of our major contracts allows the customer to require up to $50.0 million in letters of credit. If we were unable to provide letters of credit in the amount requested by this customer, we could lose business from such customer and our business and cash flow would be adversely affected. If our capacity to issue letters of credit under our revolving credit facility and our cash on hand is insufficient to satisfy our customers requirements or we are unable to renew our revolving credit facility for one year, our business and results of operations could be adversely affected.

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

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

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

Approximately 30%, 45% and 66% of our revenue for 2009, 2008 and 2007, respectively, was derived from lump-sum and unit-price contracts. Lump-sum and unit-price contracts require us to guarantee the price of the services we provide and thereby expose us to losses if our estimates of project costs are lower than the actual project costs we incur. Our profitability under these contracts is dependent upon our ability to accurately predict the costs associated with our services. The costs we actually incur may be affected by a variety of factors beyond our control. Factors that may contribute to actual costs exceeding estimated costs and which therefore affect profitability include, without limitation:

site conditions differing from those assumed in the original bid;

scope modifications during the execution of the project;

the availability and cost of skilled workers;

the availability and proximity of materials;

unfavorable weather conditions hindering productivity;

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

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

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

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

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

We have a substantial amount of debt outstanding and significant debt service requirements. As of March 31, 2009, we had outstanding $444.6 million of debt⁵, including $17.5 million of capital leases. We also had cross-currency and interest rate swaps with a balance sheet liability of $39.5 million as of March 31, 2009. These swaps are secured equally and ratably with our revolving credit facility. Our substantial indebtedness could have serious consequences, such as:

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

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

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

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

⁵	Debt includes all liabilities with the exception of future income taxes.


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Management’s Discussion and Analysis

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

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

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

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

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

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

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

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

issue equity securities of subsidiaries;

make certain investments or acquisitions;

create liens on our assets;

enter into transactions with affiliates;

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

transfer or sell assets, including shares of our subsidiaries.

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

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

Availability or increased cost of leasing

A portion of our equipment fleet is currently leased from third parties. Further, we anticipate leasing substantial amounts of equipment to meet equipment acquisition commitments related to our long-term overburden removal contract in the upcoming year. Other future projects may require us to lease additional equipment. If equipment lessors are unable or unwilling to provide us with reasonable lease terms within our expectations it will significantly increase the cost of leasing equipment or may result in more restrictive lease terms that require recognition of the lease as a capital lease. To mitigate this risk we have secured an increased leasing facility with one of our existing equipment lessors, expanding our leasing capacity by approximately 30%. Our current lease commitments with this supplier now represent 80% of the total capacity available. We are actively pursuing new lessor relationships to dilute our exposure to the loss of one or more of our lessors.

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.


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Management’s Discussion and Analysis

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

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

More than 37% of our revenue for 2009 was derived from projects which we consider to be non-recurring. This revenue primarily relates to site preparation and Piling services provided for the construction of extraction, upgrading and other oil sands mining infrastructure projects.

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

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

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

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

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

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

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

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

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

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

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

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


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Management’s Discussion and Analysis

remediation costs in relation to releases of harmful substances. These laws may impose liability without regard to negligence or fault. We also may be subject to claims alleging personal injury or property damage if we cause the release of, or any exposure to, harmful substances.

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

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

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

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

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

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

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

Quantitative and Qualitative Disclosures about Market Risk

Foreign Exchange Risk

We are subject to currency exchange risk as our 8³/4% senior notes are denominated in US dollars and all of our revenues and most of our expenses are denominated in Canadian dollars. To manage the foreign currency risk and potential cash flow impact on our $200 million in US dollar-denominated notes, we have entered into currency swap and interest rate swap agreements. These financial instruments consist of three components: a US dollar interest rate swap; a US dollar-Canadian dollar cross-currency basis swap; and a Canadian dollar interest rate swap. Of the three components, only the US dollar interest rate swap could be cancelled at the counterparty’s option at any time after December 1, 2007 if the counterparty pays a cancellation premium. The premium is equal to 2.2% if exercised between December 1, 2008 and December 1, 2009; and nil% if cancelled after December 1, 2009.

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

As a result of this cancellation of the US dollar interest rate swap, we are exposed to changes in the value of the Canadian dollar versus the US dollar. To the extent that 3-month LIBOR is less than 4.6% (the difference between the 8.75% coupon on our 8³/4% senior notes and the 4.2% spread over 3-month LIBOR on the cross currency basis swap), we will have to acquire US dollars to fund a portion of the semi-annual coupon payment on our 8³/4% senior notes. At the 3-month LIBOR rate of 1.192% at March 31, 2009, a $0.01 increase (decrease) in the Canadian dollar would result in an insignificant decrease (increase) in the amount of Canadian dollars required to fund each semi-annual coupon payment.

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


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Management’s Discussion and Analysis

The impact of the exchange rate fluctuation may also affect any embedded derivatives included in our revenue or parts and maintenance contracts with price escalators tied to either foreign exchange rates or foreign cost indices.

Interest Rate Risk

We are exposed to interest rate risk on the revolving credit facility, capital lease obligations and certain operating leases with a variable payment that is tied to prime rates. We do not use derivative financial instruments to reduce our exposure to these risks. The estimated financial impact as a result of fluctuations in interest rates is not significant for the revolving credit facility, capital lease obligations and certain operating leases.

In conjunction with the cross-currency swap agreement, we entered into a US dollar interest rate swap and a Canadian dollar interest rate swap with the net effect of economically converting the 8.75% rate payable on the 8³/4% senior notes into a fixed rate of 9.889% for the duration that the 8³/4% senior notes are outstanding. These derivative financial instruments were not designated as a hedge for accounting purposes.

As a result of the US dollar interest swap cancelation described in “Foreign currency risk”, above, we are exposed to changes in interest rates. We have a fixed semi-annual coupon payment of 8.75% on our US$200.0 million 8³/4% senior notes. With the termination of the US dollar interest rate swap, we no longer receive fixed US dollar payments from the counterparties to offset the coupon payment on our 8³/4% senior notes. As a result, we have interest rate exposure to changes in the 3-month LIBOR rate (1.192% at March 31, 2009). As at the effective date of the cancellation, at the current LIBOR rate, our interest expense increased by US$6.8 million per annum over the remaining term of the 8 ³/4% senior notes. A 100 basis point increase (decrease) in the 3-month LIBOR rate will result in a US$2.0 million increase (decrease) in the annual floating rate payment received from the swap counterparties

At March 31, 2009 and March 31, 2008, the notional principal amounts of the interest rate swaps were US$200 million and Canadian $263 million, respectively.

As at March 31, 2009, holding all other variables constant, a 100 basis point increase (decrease) to Canadian interest rates would impact the fair value of the interest rate swaps by $5.0 million, net of tax, with this change in fair value being recorded in net income. As at March 31, 2009, holding all other variables constant, a 100 basis point increase (decrease) to US interest rates would impact the fair value of the interest rate swaps by $0.5 million, net of tax, with this change in fair value being recorded in net income. As at March 31, 2009, holding all other variables constant, a 100 basis point increase (decrease) to Canadian to US interest rate volatility would impact the fair value of the interest rate swaps by $nil with this change in fair value being recorded in net income.

Inflation

Inflation can have a material impact on our operations due to increasing parts, equipment replacement and labour costs; however, many of our contracts contain provisions for annual price increases. Inflation can have a material impact on our operations if the rate of inflation and cost increases remains above levels that we are able to pass to our customers.

Credit Risk

Credit risk is the risk of financial loss to us if a customer or counterparty to a financial instrument fails to meet its contractual obligations. We are exposed to credit risk through our cash and cash equivalents, accounts receivable and unbilled revenue. We manage the credit risk associated with our cash and cash equivalents by holding our funds with reputable financial institutions. Credit risk for trade and other accounts receivables and unbilled revenue are managed through established credit monitoring activities. We review our trade receivable accounts regularly for collectability and payment performance.

We have a concentration of customers in the oil and gas sector. The concentration risk is mitigated by the customers being large investment grade organizations. The key risk related to oil and gas customers is the effect the economic conditions and tightening credit market have on their cash flows. Lower revenues from a declining per-barrel price of oil; increasing per-barrel operating costs and fixed debt commitments for capital projects can have an adverse effect on their operating cash flows.

Customers outside of the oil and gas sector include both developers and general contractors. Developers are more vulnerable to changes in economic conditions and tightening credit markets as they rely heavily on financing to complete their commercial property projects. General contractors are vulnerable to their customer’s ability to pay. Both developers and general contractors are more closely monitored for changes in their payment behavior and credit worthiness.

Losses related to trade accounts receivable for oil and gas customers have historically been insignificant. Losses related to trade accounts receivable for developers or general contractors have historically been more pronounced, depending on the change in economic conditions. Decisions to extend credit to new customers are approved by management.

In the event that recent economic conditions adversely impact our customers’ or counterparties’ cash flows or their credit worthiness generally resulting in such parties failing to meet their payment obligations to us, such failure could have a material adverse effect on our business and our results of operations.


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Management’s Discussion and Analysis

H. General matters

History and Development of the Company

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

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

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

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

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

As of March 31, 2009, our authorized capital consists of an unlimited number of voting and non-voting common shares, of which 36,038,476 voting common shares were issued and outstanding (35,929,476 as at March 31, 2008).

Our head office is located at Zone 3, Acheson Industrial Area, #2, 53016 Hwy 60, Acheson, Alberta, T7X 5A7. Our telephone and facsimile numbers are (780) 960-7171 and (780) 960-7103, respectively.

Transition To International Financial Reporting Standards (IFRS)

In 2006, the Canadian Accounting Standards Board (“AcSB”) published a new strategic plan that significantly affects financial reporting requirements for Canadian public companies. The AcSB strategic plan outlines the convergence of Canadian GAAP with IFRS over an expected five-year transitional period. In February 2008, the AcSB confirmed that IFRS will be mandatory in Canada for profit-oriented publicly accountable entities for fiscal periods beginning on or after January 1, 2011, unless, as permitted by Canadian securities regulations, we were to adopt US GAAP on or before this date. Should we decide to adopt IFRS, our first annual IFRS financial statements would be for the year ending March 31, 2012 and would include the comparative period of the year ending March 31, 2011. Our first interim IFRS financial statements would be for the three months ending June 30, 2011, which would include unaudited consolidated financial information in accordance with IFRS including comparative figures for the three months ending June 30, 2010. We have completed a preliminary assessment of the accounting and reporting differences under IFRS, Canadian GAAP and US GAAP however, we have not yet finalized our determination of these differences on our consolidated financial statements. This assessment will, in part, determine whether we adopt IFRS or US GAAP once Canadian GAAP ceases to exist.

We are also closely monitoring standard-setting activity and regulatory developments in Canada, the United States and internationally that may affect the timing of our adoption of either IFRS or US GAAP in future periods.

Additional Information

Additional information relating to us, including our Annual Information Form dated June 9, 2009, 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 Interactive Data Electronics Application (IDEA) system at www.sec.gov.


		62

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 3 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 not effective as of March 31, 2009. The details of this evaluation, conclusion and remediation plans are documented in the MD&A.

KPMG LLP, which has audited the consolidated financial statements of the Company for the year ended March 31, 2009, has also issued a report stating its opinion that the Company has not maintained effective internal control over financial reporting as of March 31, 2009 based on the criteria established in Internal Control – Integrated Framework issued by the COSO.



Rodney J. Ruston		Peter Dodd
President & Chief Executive Officer		Chief Financial Officer
June 9, 2009		June 9, 2009


				63

KPMG LLP

Chartered Accountants

10125 – 102 Street

Edmonton AB T5J 3V8

Canada

Telephone

Fax

Internet

(780) 429-7300

(780) 429-7379

www.kpmg.ca

Report of independent registered public accounting firm

To the Shareholders and Board of Directors

of North American Energy Partners Inc.

We have audited the accompanying consolidated balance sheets of North American Energy Partners Inc. (the “Company”) as of March 31, 2009 and 2008 and the related consolidated statements of operations, comprehensive (loss) income and deficit and cash flows for each of the years in the three-year period ended March 31, 2009. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of March 31, 2009 and 2008 and the results of its operations and its cash flows for each of the years in the three-year period ended March 31, 2009 in conformity with Canadian generally accepted accounting principles.

As discussed in Note 3 (s) and 3 (r) to the consolidated financial statements, the Company adopted new accounting pronouncements related to inventories in 2009 and the recognition and measurement of financial instruments in 2008.

Canadian generally accepted accounting principles vary in certain significant respects from U.S. generally accepted accounting principles. Information relating to the nature and effect of such differences is presented in Note 32 to the consolidated financial statements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of March 31, 2009, 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 8, 2009 expressed our opinion that the Company did not maintain effective internal control over financial reporting as of March 31, 2009.

LOGO

Chartered Accountants

Edmonton, Canada

June 8, 2009, except as to note 33, which is as of June 24, 2009

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.


		64

KPMG LLP

Chartered Accountants

10125 – 102 Street

Edmonton AB T5J 3V8

Canada

Telephone

Fax

Internet

(780) 429-7300

(780) 429-7379

www.kpmg.ca

Report of independent registered public accounting firm

To the Shareholders and Board of Directors

of North American Energy Partners Inc.

We have audited North American Energy Partners Inc. (the “Company”)’s internal control over financial reporting as of March 31, 2009, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in Management’s Report on Internal Control over Financial Reporting in the accompanying Management’s Discussion and Analysis for the year ended March 31, 2009. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

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

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

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

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s financial statements will not be prevented or detected on a timely basis. A material weakness in revenue recognition has been identified and included in management’s assessment. We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the 2009 consolidated financial statements of the Company. The material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2009 consolidated financial statements, and this report does not affect our report dated June 8, 2009, except as to note 33, which is as of June 24, 2009, which expressed an unqualified opinion on those consolidated financial statements.

In our opinion, because of the effect of the aforementioned material weakness on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of March 31, 2009, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

LOGO

Chartered Accountants

Edmonton, Canada

June 8, 2009

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.


				65

LOGO

Consolidated Balance Sheets

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


	2009		2008
Assets
Current assets:
Cash and cash equivalents	$98,880		$31,863
Accounts receivable (note 6)	78,323		167,010
Unbilled revenue (note 7)	55,907		70,883
Inventories (note 3 (s)(iii))	11,814		110
Prepaid expenses and deposits (note 8)	4,781		9,300
Other assets (note 3(g) and note 3(s)(iii))	–		3,703
Future income taxes (note 19)	7,033		8,217

	256,738		291,086
Future income taxes (note 19)	12,432		18,199
Assets held for sale (note 9)	2,760		1,074
Prepaid expenses and deposits (note 8)	3,504		–
Plant and equipment (note 10)	329,705		281,039
Goodwill (note 4)	23,872		200,072
Intangible assets (note 11)	1,041		2,128

	$630,052		$793,598

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$56,204		$113,143
Accrued liabilities (note 15)	52,135		45,078
Billings in excess of costs incurred and estimated earnings on uncompleted contracts (note 7)	2,155		4,772
Current portion of capital lease obligations (note 16)	5,409		4,733
Current portion of derivative financial instruments (note 22)	11,439		4,720
Future income taxes (note 19)	7,749		10,907

	135,091		183,353
Deferred lease inducements (note 14)	836		941
Capital lease obligations (note 16)	12,075		10,043
Senior notes (note 17)	252,899		198,245
Director deferred stock unit liability (note 29(c))	546		190
Derivative financial instruments (note 22)	50,562		93,019
Asset retirement obligation (note 18)	386		–
Future income taxes (note 19)	30,220		24,443

	482,615		510,234

Shareholders’ equity:
Common shares (authorized – unlimited number of voting and non-voting common shares; issued and outstanding – March 31, 2009 – 36,038,476 voting common shares (March 31, 2008 – 35,929,476 voting common shares) (note 20(b))	299,973		298,436
Contributed surplus (note 20(c))	5,275		4,215
Deficit	(157,811	)	(19,287	)

	147,437		283,364

	$630,052		$793,598

Revolving credit facility (note 13)

Commitments (note 27)

Contingencies (note 30)

Canadian and United States accounting policy differences (note 32)

Subsequent event (note 33)

See accompanying notes to consolidated financial statements.

Approved on behalf of the Board



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


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Consolidated Statements of Operations, Comprehensive (Loss) Income and Deficit

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


	2009		2008		2007
Revenue	$972,536		$989,696		$629,446
Project Costs	505,026		592,458		363,930
Equipment costs	210,520		174,873		122,306
Equipment operating lease expense	43,583		22,319		19,740
Depreciation	38,102		36,729		31,034

Gross profit	175,305		163,317		92,436
General and administrative costs	74,405		69,670		39,769
Loss on disposal of plant and equipment	5,325		179		959
Amortization of intangible assets	1,087		1,071		582
Impairment of goodwill (note 4)	176,200		–		–

Operating (loss) income before the undernoted	(81,712	)	92,397		51,126
Interest expense, net (note 21)	27,450		27,019		37,249
Foreign exchange loss (gain)	46,666		(25,442	)	(5,044	)
Realized and unrealized (gain) loss on derivative financial instruments (note 22(a))	(25,081	)	34,075		(196	)
Gain on repurchase of NACG Preferred Corp. Series A preferred shares (notes 2 and 20(a))	–		–		(9,400	)
Loss on extinguishment of debt (notes 2 and 17)	–		–		10,935
Other income (note 22(c)(i))	(5,955	)	(418	)	(904	)

(Loss) income before income taxes	(124,792	)	57,163		18,486
Income taxes (note 19):
Current income taxes	5,546		80		(2,975	)
Future income taxes	9,177		17,299		382

Net (loss) income and comprehensive (loss) income for the year	(139,515	)	39,784		21,079
Deficit, beginning of period – as previously reported	(19,287	)	(55,526	)	(76,546	)
Change in accounting policy related to financial instruments (note 3(r)(iii))	–		(3,545	)	–
Change in accounting policy related to inventories (note 3(s)(iii))	991		–		–
Premium on repurchase of common shares (note 20(b))	–		–		(59	)

Deficit, end of period	$(157,811	)	$(19,287	)	$(55,526	)

Net (loss) income per share – basic (note 20(d))	$(3.87	)	$1.11		$0.87

Net (loss) income per share – diluted (note 20(d))	$(3.87	)	$1.08		$0.83

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)


	2009		2008		2007
Cash provided by (used in):
Operating activities:
Net (loss) income for the year	$(139,515	)	$39,784		$21,079
Items not affecting cash:
Depreciation	38,102		36,729		31,034
Write-down of other assets to replacement cost (note 3(g))	–		1,845		695
Amortization of intangible assets	1,087		1,071		582
Impairment of goodwill (note 4)	176,200		–		–
Amortization of deferred lease inducements (note 14)	(105	)	(104	)	–
Amortization of bond issue costs, premiums and financing costs (note 21)	808		838		3,436
Loss on disposal of plant and equipment	5,325		179		959
Unrealized foreign exchange loss (gain) on senior notes	45,860		(24,788	)	(5,017	)
Unrealized change in the fair value of derivative financial instruments	(27,752	)	31,406		(2,748	)
Stock-based compensation expense (note 29)	2,251		1,991		2,101
Gain on repurchase of NACG Preferred Corp. Series A preferred shares (notes 2 and 20(a))	–		–		(8,000	)
Loss on extinguishment of debt (notes 2 and 17)	–		–		10,680
Change in redemption value and accretion of redeemable preferred shares	–		–		3,114
Accretion of asset retirement obligation (note 18)	155		–		–
Future income taxes	9,177		17,299		382
Net changes in non-cash working capital (note 24(b))	46,192		(8,753	)	(57,072	)

	157,785		97,497		1,225

Investing activities:
Acquisition, net of cash acquired (note 5)	–		(1,581	)	(1,517	)
Purchase of plant and equipment	(94,139	)	(57,779	)	(110,019	)
Additions to assets held for sale	(2,035	)	(3,499	)	–
Proceeds on disposal of plant and equipment	11,164		6,862		3,564
Proceeds of disposal of assets held for sale	325		10,200		–
Net changes in non-cash working capital (note 24(b))	(630	)	(2,835	)	7,922

	(85,315	)	(48,632	)	(100,050	)

Financing activities:
(Decrease) increase in revolving credit facility	–		(20,500	)	20,500
Repayment of 9% senior secured notes (note 17)	–		–		(74,748	)
Repurchase of NAEPI Series A preferred shares (notes 2 and 20(a)(ii))	–		–		(1,000	)
Repurchase of NACG Preferred Corp. Series A preferred shares (notes 2 and 20(a)(i))	–		–		(27,000	)
Cash settlement of stock options (note 20(c))	–		(581	)	–
Stock options exercised (note 20(b))	703		1,627		139
Financing costs (notes 11, 12, and 13)	–		(776	)	(1,346	)
Repayment of capital lease obligations	(6,156	)	(3,762	)	(6,033	)
Issue of common shares (note 2 and 20(b))	–		–		171,165
Share issue costs (notes 2 and 20(b))	–		–		(18,582	)
Repurchase of common shares for cancellation (note 20(b))	–		–		(84	)

	(5,453	)	(23,992	)	63,011

Increase (decrease) in cash and cash equivalents	67,017		24,873		(35,814	)
Cash and cash equivalents, beginning of year	31,863		6,990		42,804

Cash and cash equivalents, end of year	$98,880		$31,863		$6,990

Supplemental cash flow information (note 24 (a))

See accompanying notes to consolidated financial statements


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Notes to Consolidated Financial Statements

For the years ended March 31, 2009, 2008 and 2007

(Expressed in thousands of Canadian Dollars, except per share amounts or unless otherwise specified)

1. Nature of operations

North American Energy Partners Inc. (the “Company”), formerly NACG Holdings Inc. (“NACG”), was incorporated under the Canada Business Corporations Act on October 17, 2003. On November 26, 2003, the Company purchased all the issued and outstanding shares of North American Construction Group Inc. (“NACGI”), including subsidiaries of NACGI, from Norama Ltd. which had been operating continuously in Western Canada since 1953. The Company had no operations prior to November 26, 2003. The Company undertakes several types of projects including heavy construction, industrial and commercial site development and pipeline and piling installations in Canada.

On November 28, 2006, immediately prior to the closing of its Initial Public Offering (“IPO”) of common shares in Canada and the United States (note 2), NACG amalgamated with its wholly-owned subsidiaries, NACG Preferred Corp. and North American Energy Partners Inc. (“NAEPI”). The amalgamated entity was continued as North American Energy Partners Inc. The voting common shares of the new entity, North American Energy Partners Inc., include the shares offered in the IPO and outstanding common shares in North American Energy Partners Inc. that were not sold in the concurrent secondary offering.

2. Re-organization and initial public offering

On November 28, 2006, prior to the amalgamation referred to in note 1, NACG acquired the NACG Preferred Corp. Series A preferred shares with a carrying value of $35,000 in exchange for a promissory note in the amount of $27,000 and the forfeiture of accrued dividends of $1,400 (note 20(a)). The Company recorded a gain of $9,400 on the repurchase of the NACG Preferred Corp. Series A preferred shares.

On November 28, 2006, prior to the amalgamation referred to in note 1, NACG repurchased the NAEPI Series A preferred shares for their redemption value of $1,000. NACG also cancelled the consulting and advisory services agreement with The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc., and SF Holding Corp. (collectively, the “Sponsors”), under which NACG had received ongoing consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements and other matters. The consideration paid for the cancellation of the consulting and advisory services agreement on the closing of the offering was $2,000, which was recorded as general and administrative expense in the consolidated statement of operations. Under the consulting and advisory services agreement, the Sponsors also received a fee of $854, which approximates 0.5% of the aggregate gross proceeds to NACG from the IPO, which was recorded as a share issue cost.

On November 28, 2006, prior to the amalgamation referred to in note 1, each holder of NAEPI Series B preferred shares received 100 common shares of NACG for each NAEPI Series B preferred share held as a result of the Company exercising a call option to acquire the NAEPI Series B preferred shares (note 20(a)). Upon exchange, the carrying value of the NAEPI Series B preferred shares on the exercise date of $44,682 was transferred to share capital.

On November 28, 2006, the Company completed an IPO for the sale of 8,750,000 common voting shares for total gross proceeds of $158,549. Net proceeds from the IPO, after deducting underwriting fees and offering expenses, were $140,850. Subsequent to the IPO, the underwriters exercised their overallotment option to purchase 687,500 additional voting common shares of the Company for gross proceeds of $12,616. Net proceeds from the overallotment, after deducting underwriting fees and offering expenses, were $11,733. Total net proceeds from the IPO and subsequent overallotment were $152,583 (note 20 (b)).

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

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

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

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

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

For general corporate purposes.


				69

Notes to Consolidated Financial Statements

3. Significant accounting policies

a) Basis of presentation

These consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles (“GAAP”). Material inter-company transactions and balances are eliminated on consolidation. Material items that give rise to measurement differences to the consolidated financial statements under United States GAAP are outlined in note 32.

These consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, North American Construction Group Inc. (“NACGI”) and NACG Finance LLC, the Company’s joint venture, Noramac Ventures Inc. and the following 100% owned subsidiaries of NACGI:

Ÿ North American Caisson Ltd.

Ÿ North American Construction Ltd.

Ÿ North American Engineering Ltd.

Ÿ North American Enterprises Ltd.

Ÿ North American Industries Inc.

Ÿ North American Mining Inc.

Ÿ North American Maintenance Ltd.

Ÿ North American Pipeline Inc.

Ÿ North American Road Inc.

Ÿ North American Services Inc.

Ÿ North American Site Development Ltd.

Ÿ North American Site Services Inc.

Ÿ North American Pile Driving Inc.

b) Use of estimates

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

Significant estimates made by management include the assessment of the percentage of completion on time-and-materials, unit-price or lump-sum contracts (including estimated total costs and provisions for estimated losses) and the recognition of claims and change orders on contracts, assumptions used to value financial instruments, assumptions used to determine the redemption value of redeemable securities, assumptions used in periodic impairment testing, and estimates and assumptions used in the determination of the allowance for doubtful accounts, the recoverability of future income tax assets and the useful lives of plant and equipment. Actual results could differ materially from those estimates.

The accuracy of the Company's revenue and profit recognition in a given period is dependent, in part, on the accuracy of our estimates of the cost to complete each time-and-materials, unit-price, or lump-sum project. The Company’s cost estimates use a detailed “bottom up” approach, using inputs such as labour and equipment hours, detailed drawings and material lists. These estimates are reviewed and updated monthly. The Company believes our experience allows us to produce materially reliable estimates. However, our projects can be highly complex. Profit margin estimates for a project may either increase or decrease to some extent from the amount that was originally estimated at the time of the related bid. With many projects of varying levels of complexity and size in process at any given time, changes in estimates can offset each other without materially impacting our profitability. Major changes in cost estimates, particularly in larger, more complex projects, can have a significant effect on profitability.

c) Revenue recognition

The Company performs its projects under the following types of contracts: time-and-materials; cost-plus; unit-price; and lump sum. Revenue is recognized as costs are incurred for time-and-materials and cost-plus service contracts with no clearly defined scope. Revenue on cost plus, unit-price, lump sum and time-and-materials contracts with defined scope are recognized using the percentage-of-completion method, measured by the ratio of costs incurred to date to estimated total costs. The resulting percent complete methodology is applied to the approved contract value to determine the revenue recognized. The estimated total cost of the contract and percent complete is determined based upon estimates made by management. The costs of items that do not relate to performance of contracted work, particularly in the early stages of the contract, are excluded from costs incurred to date.

The length of the Company’s contracts varies from less than one year for typical contracts to several years for certain larger contracts. Contract project costs include all direct labour, material, subcontract and equipment costs and those indirect costs related to contract performance such as indirect labour, supplies, and tools. General and administrative costs are charged to expense as incurred. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Changes in project performance, project conditions, and estimated profitability, including those arising from contract penalty provisions and final contract settlements, may result in revisions to costs and revenue that are recognized in the period in which such adjustments are determined. Profit incentives are included in revenue when their realization is reasonably assured.

Once a project is underway, the Company will often experience changes in conditions, client requirements, specifications, designs, materials and work schedule. Generally, a “change order” will be negotiated with the customer to modify the original contract to approve both the scope and price of the change. Occasionally, however, disagreements


		70

Notes to Consolidated Financial Statements

arise regarding changes, their nature, measurement, timing and other characteristics that impact costs and revenue under the contract. When a change becomes a point of dispute between the Company and a customer, the Company will then consider it as a claim.

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

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

A bona fide addition to contract value; and

Revenues can be reliably estimated.

These two conditions are satisfied when:

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

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

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

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

This can lead to a situation where costs are recognized in one period and revenue is recognized when customer agreement is obtained or claim resolution occurs, which can be in subsequent periods. Historical claim recoveries should not be considered indicative of future claim recoveries.

Claims revenue recognized was $56.0 million for the year ended March 31, 2009 (2008 – $nil; 2007 – $14.5 million). Claims revenue of $1.8 million is included in unbilled revenue and remains uncollected at the end of the year (2008 – $3.1 million; 2007 – $8.4 million). $45.7 million of claims revenue was collected as of March 31, 2009.

The Company’s long-term contracts typically allow its customers to unilaterally reduce or eliminate the scope of the work as contracted without cause. These long-term contracts represent higher risk due to uncertainty of total contract value and estimated costs to complete; therefore, potentially impacting revenue recognition in future periods.

The asset entitled “unbilled revenue” represents revenue recognized in advance of amounts invoiced. The liability entitled “billings in excess of costs incurred and estimated earnings on uncompleted contracts” represents amounts invoiced in excess of revenue recognized.

d) Cash and cash equivalents

Cash and cash equivalents include cash on hand, bank balances net of outstanding cheques and short-term investments with maturities of three months or less when purchased.

e) Allowance for doubtful accounts

The Company evaluates the probability of collection of accounts receivable and records an allowance for doubtful accounts, which reduces accounts receivable to the amount management reasonably believes will be collected. In determining the amount of the allowance, the following factors are considered: the length of time the receivable has been outstanding, specific knowledge of each customer’s financial condition, and historical experience.

f) Inventories

Inventories are carried at the lower of cost and net realizable value, and consist primarily of tires (note 3(s)(iii)). Net realizable value represents the estimated selling price for inventories in the ordinary course of business less the estimated costs necessary to make the sale.

g) Other assets

For the year ended March 31, 2008, other assets consisted of tires and spare component parts, and were stated at the lower of weighted average cost or replacement cost. Other assets are charged to earnings when they are put into use. A write-down of other assets to reduce other assets to the lower of weighted average cost or replacement cost of $1,845 was included in equipment costs for the year ended March 31, 2008. On April 1, 2008, tires and spare parts components were reclassified from ‘other assets’ to inventories (note 3(s)(iii)).


				71

Notes to Consolidated Financial Statements

h) Plant and equipment

Plant and equipment are recorded at cost. Major components of heavy construction equipment in use such as engines and transmissions are recorded separately. Equipment under capital lease is recorded at the present value of minimum lease payments at the inception of the lease. Depreciation is not recorded until an asset is available for use. Depreciation for each category is calculated based on the cost, net of the estimated residual value, over the estimated useful life of the assets on the following bases and annual rates:


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

The costs for periodic repairs and maintenance are expensed to the extent the expenditures serve only to restore the assets to their normal operating condition without enhancing their service potential or extending their useful lives.

i) Goodwill

Goodwill represents the excess purchase price paid by the Company over the fair value of tangible and identifiable intangible assets and liabilities acquired as a result of purchasing a business entity. Goodwill is not amortized but instead is tested for impairment annually or more frequently if events or changes in circumstances indicate that it may be impaired. When the Company enters into a business combination, the purchase method of accounting is used. 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. In addition, the Company tested goodwill for impairment at December 31, 2008 and March 31, 2009 and determined that there was an impairment in its carrying value (note 4).

j) Intangible assets

Intangible assets include:

Customer contracts in process and related relationships, 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 life of 10 years;

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

Financing costs related to the revolving credit facility are amortized on a straight-line basis over the term of the agreement.

k) 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 a 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, and is charged to depreciation expense. The Company made 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.


		72

Notes to Consolidated Financial Statements

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

Management’s commitment to a plan to sell the assets;

The assets are available for immediate sale in their present condition;

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

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

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

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

Assets to be disposed of by sale are reported at the lower of their carrying amount or fair value less costs to sell and are disclosed separately on the Consolidated Balance Sheets. These assets are not depreciated.

l) Asset retirement obligations

Asset retirement obligations are legal obligations associated with the retirement of 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 and any changes in the amount or timing of the underlying future cash flows through charges to equipment costs (accretion) on the Consolidated Statements of Operations, Comprehensive (Loss) Income and Deficit.

m) Foreign currency translation

The functional currency of the Company is Canadian Dollars. Transactions denominated in foreign currencies are recorded at the rate of exchange on the transaction date. Monetary assets and liabilities, denominated in foreign currencies, are translated into Canadian Dollars at the rate of exchange prevailing at the balance sheet date. Foreign exchange gains and losses are included in the determination of earnings.

n) Derivative financial instruments

The Company uses derivative financial instruments to manage financial risks from fluctuations in exchange rates and interest rates. These instruments include cross-currency and interest rate swap agreements as well as embedded price escalation features in revenue and supplier contracts. All such instruments are only used for risk management purposes. The Company does not hold or issue derivative financial instruments for trading or speculative purposes. Derivative financial instruments are subject to standard credit terms and conditions, financial controls, management and risk monitoring procedures. These derivative financial instruments are not designated as hedges for accounting purposes and are recorded at fair value with realized and unrealized gains and losses recognized in the Consolidated Statement of Operations, Comprehensive (Loss) Income and Deficit.

o) Income taxes

The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, future income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Future income tax assets and liabilities are measured using enacted or substantively enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on future income tax assets and liabilities from a change in tax rates is recognized in income in the period of enactment or substantive enactment. The Company accrues interest and penalties for uncertain tax positions in the period in which these uncertainties are identified. A valuation allowance is recorded against any future income tax asset if it is more likely than not that the asset will not be realized.

p) Stock-based compensation plan

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 contributed surplus. Upon exercise of a stock option, share capital is recorded at the sum of proceeds received and the related amount of contributed surplus.

The Company has a Director’s Deferred Stock Unit (“DDSU”) plan, which is described in note 29(c). 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 intrinsic value of the award and


				73

Notes to Consolidated Financial Statements

is recorded as a charge to operating income over the vesting period of the award. Subsequent changes in the Company's payment obligation after vesting of the award and prior to the settlement date are recorded as a charge to operating income in the period such changes occur.

The Company has a Deferred Performance Share Unit (“DPSU”) plan, which is described in note 29(b). This compensation plan is settled, at the Company’s option, either by the issuance of equity instruments or by cash payment. Compensation cost is measured using the Black-Scholes model at the grant date and is expensed on a straight-line basis over the award's vesting period, with a corresponding increase to contributed surplus. The vesting of awards under the DPSU is contingent upon certain performance criteria being achieved. The fair value of each share option grant under the Performance 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.

q) Net (loss) income per share

Basic net (loss) income per share is computed by dividing net (loss) income available to common shareholders by the weighted average number of shares outstanding during the year (see note 20(d)). Diluted per share amounts are calculated using the treasury stock. 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.

r) Financial instruments:

i) Classification and measurement

All financial instruments, including derivatives, must initially be recognized at fair value on the balance sheet. The Company classifies financial instruments into one of five categories: held-for-trading, held-to-maturity, loans and receivables, available-for-sale financial assets, and other financial liabilities. Subsequent measurement and changes in fair value depend on the financial instrument’s initial classification. Loans and receivables, held-to-maturity investments and other financial liabilities are measured at amortized cost using the effective interest method. Held-for-trading financial instruments are measured at fair value with changes in fair value recognized in net income. Available-for-sale financial assets are measured at fair value with changes in fair value recorded in other comprehensive income until the investment is derecognized or impaired, at which time the amounts would be recorded in net income. The trade date is used to account for regular way purchase and sale contracts.

The Company has the following financial instruments and has selected the following classifications:

Cash and cash equivalents are classified as financial assets held for trading and are recorded at fair value, with realized and unrealized gains and losses reported in net income;

Accounts receivable and unbilled revenue are classified as loans and receivables and are initially recorded at fair value and subsequent to initial recognition are accounted for at amortized cost using the effective interest method;

The Company has classified amounts due under its revolving credit facility, accounts payable, accrued liabilities, and senior notes as other financial liabilities. Other financial liabilities are accounted for on initial recognition at fair value and subsequent to initial recognition at amortized cost using the effective interest method;

Derivative financial instruments, including non-financial derivatives, are classified as held-for-trading and are measured at fair value with realized and unrealized gains and losses recognized in the Consolidated Statement of Operations, Comprehensive (Loss) Income and Deficit, unless exempted from derivative treatment as a normal purchase or sale; and

The Company has not classified any of its financial assets as available-for-sale or held-to-maturity, nor have any of its financial liabilities been classified as held-for-trading.

ii) Transaction costs

Transaction costs are incremental costs that are directly related to the acquisition or issuance of financial assets or liabilities and are accounted for as part of the respective asset or liability’s carrying value at inception. The Company incurred transaction costs on the issuance of the unsecured U.S.$ denominated 8³/4% senior notes and classifies these costs as part of the carrying value of senior notes on the consolidated balance sheet. The costs capitalized within long-term debt are amortized over the expected life of the related debt using the effective interest method.

iii) Financial instruments – recognition and measurement

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


		74

Notes to Consolidated Financial Statements

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


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

The adoption of these standards resulted in the following adjustments as of April 1, 2007 in accordance with the transition provisions:

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

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

The Company determined that the issuer’s early prepayment option included in the senior notes should be bifurcated from the host contract, along with a contingent embedded derivative in the senior notes that provide for accelerated redemption by the holders in certain instances. These embedded derivatives were measured at fair value at the inception of the senior notes and the residual amount of the proceeds was allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of the senior notes is accreted to par value over the term of the notes using the effective interest method and is recognized as interest expense. At transition on April 1, 2007, the Company recorded the fair value of $8,519 related to these embedded derivatives and a corresponding decrease in opening deficit of $7,305, net of future income taxes of $1,214. The impact of the bifurcation of these embedded derivatives at issuance of the senior notes resulted in an increase of senior notes of $5,700 and an increase in opening deficit of $3,963, net of income taxes of $1,737 after applying the effective interest method to the premium resulting from the bifurcation of these embedded derivatives to April 1, 2007; and

The Company determined that price escalation features in certain revenue and maintenance service contracts contain embedded derivatives that are not closely related to the host contracts. The embedded derivatives have been measured at fair value and included in derivative financial instruments on the consolidated balance sheet, with changes in the fair value recognized in net income. The Company recorded the fair value of $9,720 related to these embedded derivatives on April 1, 2007, with a corresponding increase in opening deficit of $6,950, net of future income taxes of $2,770.

s) Recently adopted Canadian accounting pronouncements

i) Financial instruments – disclosure and presentation

Effective April 1, 2008, the Company prospectively adopted CICA Handbook Section 3862, “Financial Instruments –Disclosures”, which replaces disclosure guidance in CICA Handbook Section 3861 and provides expanded disclosure requirements that enable users to evaluate the significance of financial instruments on the entity’s financial position and its performance and the nature and extent of risks arising from financial instruments to which the entity is exposed during the period and at the balance sheet date, and how the entity manages those risks. This standard harmonizes disclosures with International Financial Reporting Standards. The Company has provided the required disclosures in note 22 to its consolidated financial statements for the year ended March 31, 2009.

Effective April 1, 2008, the Company adopted CICA Handbook Section 3863, “Financial Instruments – Presentation”, which carries forward presentation guidance in CICA Handbook Section 3861. This Section establishes standards for presentation of financial instruments and non-financial derivatives. It deals with the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, gains and losses, and the circumstances in which financial assets and financial liabilities are offset. The adoption of this standard did not have a material impact on the presentation of financial instruments in the Company’s financial statements.


				75

Notes to Consolidated Financial Statements

ii) Capital disclosures

Effective April 1, 2008, the Company prospectively adopted CICA Handbook Section 1535, “Capital Disclosures”, which requires disclosure of qualitative and quantitative information that enables users to evaluate the Company’s objectives, policies and process for managing capital, including disclosures of any externally imposed capital requirements and the consequences of non-compliance. The Company has provided the required disclosures in note 23 to its consolidated financial statements for the year ended March 31, 2009.

iii) 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. The Company then reclassified $5,086 of tires and spare component parts from ‘Other assets’ to ‘Inventory’. As at March 31, 2009, inventory is comprised of spare tires of $10,533 and job materials of $1,281. The Company carries inventory at the lower of weighted average cost and net realizable value. The carrying amount of inventory pledged as security for borrowings under the revolving credit facility (note 13) is approximately $11,814 as at March 31, 2009. The adoption of this standard did not have a material impact on net (loss) income for the year ended March 31, 2009.

iv) Credit risk and the fair value of financial assets and financial liabilities

In January 2009, the CICA issued EIC Abstract 173, “Credit Risk and the Fair Value of Financial Assets and Financial Liabilities”. This Abstract requires the Company to take into account the Company’s own credit risk and the credit risk of the counterparty in determining the fair value of financial assets and financial liabilities, including derivative instruments. The adoption of this abstract in the fourth quarter of 2009 did not have a material impact on the Company’s consolidated financial statements.

t) Recent Canadian accounting pronouncements not yet adopted

i) Goodwill and intangible assets

In February 2008, the CICA issued Handbook Section 3064, “Goodwill and Intangible Assets”, which replaces Section 3062, Goodwill and Intangible Assets, and Section 3450, Research and Development Costs, establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The provisions relating to the definition and initial recognition of intangible assets, including internally generated intangible assets, are equivalent to the corresponding provisions of International Accounting Standard IAS 38, Intangible Assets. This new standard is effective for the Company’s interim and annual consolidated financial statements commencing April 1, 2009. The Company is currently evaluating the impact of this standard.

ii) Business combinations

In January 2009, the CICA issued Handbook Section 1582, “Business Combinations”, which replaces the existing standard. This section establishes standards for the accounting of business combinations, and states that all assets and liabilities of an acquired business will be recorded at fair value. Obligations for contingent considerations and contingencies will also be recorded at fair value at the acquisition date. The standard also states that acquisition related costs will be expensed as incurred, that restructuring charges will be expensed in periods after the acquisition date and that non-controlling interests should be measured at fair value at the date of acquisition. This standard is equivalent to International Financial Reporting Standards on business combinations. This standard is to be applied prospectively to business combinations with acquisition dates on or after January 1, 2011 and earlier adoption is permitted. The Company is currently evaluating the impact of this standard.

iii) Consolidated financial statements

In January 2009, the CICA issued Handbook Section 1601, “Consolidated Financial Statements”, which replaces CICA 1600 – Consolidated Financial Statements. This Section carries forward existing Canadian guidance for preparing consolidated financial statements other than guidance for non-controlling interests. This standard is effective for interim and annual financial statements beginning on January 1, 2011 and earlier adoption is permitted. The Company is currently evaluating the impact of this standard.

iv) Non-controlling interests

In January 2009, the CICA issued Handbook Section 1602, “Non-Controlling Interests”, which establishes standards for the accounting of non-controlling interests of a subsidiary in the preparation of consolidated financial statements subsequent to a business combination. This standard is equivalent to the International Financial Reporting Standards on consolidated and separate financial statements. This standard is effective for interim and annual financial statements


		76

Notes to Consolidated Financial Statements

beginning on January 1, 2011 and earlier adoption is permitted. The Company is currently evaluating the impact of this standard.

v) International Financial Reporting Standards (IFRS)

In 2006, the Canadian Accounting Standards Board (“AcSB”) published a new strategic plan that significantly affects financial reporting requirements for Canadian public companies. The AcSB strategic plan outlines the convergence of Canadian GAAP with IFRS over an expected five-year transitional period. In February 2008, the AcSB confirmed that IFRS will be mandatory in Canada for profit-oriented publicly accountable entities for fiscal periods beginning on or after January 1, 2011, unless, as permitted by Canadian securities regulations, the Company was to adopt U.S. GAAP on or before this date. Should the Company decide to adopt IFRS, its first annual IFRS financial statements would be for the year ending March 31, 2012 and would include the comparative period of 2011 and starting in the first quarter of 2012, the Company would provide unaudited consolidated financial information in accordance with IFRS including comparative figures for 2011. The Company has completed a preliminary assessment of the accounting and reporting differences under IFRS, Canadian GAAP and U.S. GAAP, however, management has not yet finalized its determination of the impact of these differences on the consolidated financial statements. This assessment will, in part, determine whether the Company adopts IFRS or U.S. GAAP once Canadian GAAP ceases to exist.

The Company is also closely monitoring standard-setting activity and regulatory developments in Canada, the United States and internationally that may affect the timing of its adoption of either IFRS or U.S. GAAP in future periods.

4. Goodwill

In accordance with the Company’s accounting policy, a goodwill impairment test is completed annually on October 1 of each fiscal year or whenever events or changes in circumstances indicate that impairment may exist. The Company conducted its annual goodwill impairment test on October 1, 2008 and concluded that the fair value of each of its reporting units exceeded its carrying amount. However, at December 31, 2008 and at March 31, 2009, based on adverse changes in the Company’s principal markets, the recent decline in the Company’s market capitalization and updated long-term financial forecasts, which resulted in lower near-term and longer-term revenues and cash flows for each reporting unit, the Company concluded that an interim test for impairment of goodwill was appropriate.

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

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

As part of the March 31, 2009 goodwill impairment test, the Company updated its discounted cash flow (“DCF”) analysis for the Heavy Construction and Mining and Piling reportable business segments using estimated discount rates ranging from 22.0% to 32.0% and a decreased terminal growth rate from 3.0% to 2.5% to calculate fair value. The Company also updated its forecasted cash flows. These updates were based on the current economic volatility experienced during the three months ended March 31, 2009 and considered management’s view of economic conditions and trends, estimated future operating results, sector growth rates, anticipated future economic conditions and the Company’s strategic alternatives to respond to these conditions. Although implied market comparable valuation multiples and transaction premiums were considered in the analysis, there are significant differences in the products, services and operating characteristics of the reporting units as compared to a set of selected comparable companies. The fair value utilizing the DCF model was determined to be reasonable when compared to the market capitalization at the end of the year plus a reasonable control premium. The process of determining fair value is subjective and requires


				77

Notes to Consolidated Financial Statements

management to exercise a significant amount of judgment in determining future growth rates, discount and tax rates and other factors.

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

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

There was no goodwill impairment recorded for the years ended March 31, 2008 and 2007.

The change in goodwill during the year ended March 31, 2009 is as follows:


For the year ended	March 31, 2009
Balance, beginning of period	$200,072
Impairment of goodwill (assigned to the Pipeline Segment)	(32,753	)
Impairment of goodwill (assigned to the Heavy Construction and Mining Segment)	(125,447	)
Impairment of goodwill (assigned to the Piling Segment)	(18,000	)

Balance, end of period	$23,872

5. Acquisitions

i) Acquisitions in fiscal 2009

The Company did not acquire any businesses in fiscal 2009.

ii) Acquisitions in fiscal 2008

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


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

		$1,581

iii) Acquisitions in fiscal 2007

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


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

	$1,646


		78

Notes to Consolidated Financial Statements

6. Accounts receivable


	March 31, 2009		March 31, 2008
Accounts receivable – trade	$67,123		$123,249
Accounts receivable – holdbacks	9,376		34,996
Income and other taxes receivable	–		2,734
Accounts receivable – other	4,421		6,773
Allowance for doubtful accounts	(2,597	)	(742	)

	$78,323		$167,010

Accounts receivable – holdbacks represent amounts up to 10% under certain contracts that the customer is contractually entitled to withhold until completion of the project or until certain project milestones are achieved.

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


	March 31, 2009		March 31, 2008
Costs incurred and estimated earnings on uncompleted contracts	$955,763		$1,037,273
Less billings to date	(902,011	)	(971,162	)

	$53,752		$66,111

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


	March 31, 2009		March 31, 2008
Unbilled revenue	$55,907		$70,883
Billings in excess of costs incurred and estimated earnings on uncompleted contracts	(2,155	)	(4,772	)

	$53,752		$66,111

8. Prepaid expenses and deposits

Current:


	March 31, 2009	March 31, 2008
Prepaid insurance and property taxes	$1,535	$1,065
Prepaid lease payments	3,246	6,606
Deposits on other assets	–	1,629

	$4,781	$9,300

Non-current:


	March 31, 2009	March 31, 2008
Opening balance	$ –	$ –
Additions to non-current prepaid lease payments	3,504	–
Amortization of non-current prepaid lease payments	–	–

Ending balance	$3,504	$ –

9. Assets held for sale

Included in depreciation expense for the year ended March 31, 2009 is a loss on disposal of assets held for sale of $24 (2008 – $493; 2007 – $3,582) relating to a decision to dispose of heavy construction assets in the Heavy Construction & Mining segment. The impairment charge is the amount by which the carrying value of the related assets exceeded their fair value less costs to sell. The assets held for sale at March 31, 2009 have been reclassified from plant and equipment to long-term assets as the assets have not yet been sold.

During the year ended March 31, 2009, impairments of plant and equipment amounting to $883 have been included in depreciation expense in the Consolidated Statements of Operations, Comprehensive (Loss) Income and Deficit (2008 – $1,564; 2007 – $nil).


				79

Notes to Consolidated Financial Statements

10. Plant and equipment


March 31, 2009	Cost	Accumulated Depreciation	Net Book Value
Heavy equipment	$319,706	$76,130	$243,576
Major component parts in use	25,187	2,535	22,652
Other equipment	22,056	8,268	13,788
Licensed motor vehicles	12,760	7,445	5,315
Office and computer equipment	14,614	5,644	8,970
Buildings	19,822	4,956	14,866
Leasehold improvements	6,494	1,845	4,649
Assets under capital lease	27,953	12,064	15,889

	$448,592	$118,887	$329,705


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

	$378,422	$97,383	$281,039

During the year ended March 31, 2009, additions to plant and equipment included $8,863 of assets that were acquired by means of capital leases (2008 – $8,829; 2007 – $4,653). Depreciation of equipment under capital lease of $5,138 (2008 – $2,928; 2007 – $1,481) was included in depreciation expense.

11. Intangible assets


March 31, 2009	Cost	Accumulated Amortization	Net Book Value
Customer contracts in progress and related relationships	$340	$260	$80
Financing costs	3,205	2,438	767
Other intangible assets	721	527	194

	$4,266	$3,225	$1,041


March 31, 2008	Cost	Accumulated Amortization	Net Book Value
Customer contracts in progress and related relationships	$340	$160	$180
Financing costs	3,017	1,601	1,416
Other intangible assets	876	344	532

	$4,233	$2,105	$2,128

There were no financing fees paid during the year ended March 31, 2009. During the year ended March 31, 2008, financing fees totalling $776 paid in connection with an amendment of the revolving credit facility (note 13) were recorded as financing costs. These costs, together with the existing unamortized financing costs, are being amortized on a straight-line basis over the term of the amended revolving credit facility consistent with accounting for the amendment of the revolving credit facility as a modification.

Amortization of intangible assets for the year ended March 31, 2009 was $1,087 (2008 – $1,071; 2007 – $582). The estimated amortization expense for future years is as follows:


For the year ending March 31,
2010		$862
2011		55
2012		48
2013		43
2014 and thereafter		33

		$1,041


		80

Notes to Consolidated Financial Statements

12. Deferred financing costs

Deferred financing costs related to the senior notes that were previously presented as a separate asset on the consolidated balance sheet are now included in the carrying value of the senior notes (see note 2 and 17). Transaction costs incurred in connection with the Company's revolving credit facility of $1,622 were reclassified from deferred financing costs to intangible assets effective April 1, 2007.

For the year ended March 31, 2007, fees of $275 were paid to the holders of the 8³/4% senior notes in connection with an amendment of the indenture governing the 8³/4% senior notes (note 17). The amendment has been accounted for as a modification, and the fees paid to the note holders, together with the existing unamortized deferred financing costs, were deferred and amortized on a straight-line basis over the remaining term of the 8³/4% senior notes.

During the year ended March 31, 2007, financing fees totalling $1,071 paid in connection with amendment of the revolving credit facility (note 13) were recorded as deferred financing costs. These costs, together with the existing unamortized deferred financing costs, were deferred and amortized over the term of the amended revolving credit facility consistent with accounting for the amendment of the revolving credit facility as a modification.

In connection with the retirement of the 9% senior secured notes on November 28, 2006, the Company wrote off deferred financing costs of $4,342 (note 17) during the year ended March 31, 2007. Amortization of deferred financing costs for the year ended March 31, 2007 was $3,436 (2006 – $3,338).

13. Revolving credit facility

On June 7, 2007, the Company modified its amended and restated credit agreement to provide for borrowings of up to $125.0 million (previously $55.0 million) under which revolving loans and letters of credit may be issued. This facility matures on June 7, 2010. Advances under the revolving credit facility may be repaid from time to time at the option of the Company. Based upon the Company’s current credit rating, prime rate revolving loans under the agreement will bear interest at the Canadian prime rate plus 0.25% per annum, Canadian bankers’ acceptances have stamping fees equal to 1.75% per annum and letters of credit are subject to a fee of 1.25% per annum. Standby fees are calculated at a rate per annum equal to the applicable pricing margin applied to the amount by which the amount of the outstanding principal owing to each lender under the credit facility for each day is less than the commitment of such lender and accrue daily from the first day to the last day of each fiscal quarter. In each case, the applicable pricing margin depends on the Company’s credit rating. Interest rates are increased by 2% per annum in excess of the rate otherwise payable on any amount not paid when due.

This credit facility is secured by a first priority lien on substantially all the Company’s existing and after acquired property and contains certain restrictive covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions or to pay dividends or redeem shares of capital stock. The Company is also required to meet certain financial covenants under the credit agreement. The Company was in compliance with the covenants under its revolving credit facility as at and throughout the year ended March 31, 2009.

As of March 31, 2009, the Company had outstanding borrowings of $nil (March 31, 2008 – $nil) under the revolving credit facility and had issued $20.8 million (2008 – $20.0 million) in letters of credit to support performance guarantees associated with customer contracts. The funds available under the revolving credit facility are reduced for any outstanding letters of credit. The Company’s unused borrowing availability under the facility was $104.2 million at March 31, 2009.

During the twelve months ended March 31, 2008, financing fees of $776, were incurred in connection with the modifications to the amended and restated credit agreement and were recorded as an intangible asset.

14. Deferred lease inducements

Lease inducements applicable to lease contracts are deferred and amortized as a reduction of general and administrative costs on a straight-line basis over the lease term, which includes the initial lease term and renewal periods only where renewal is determined to be reasonably assured.


	March 31, 2009		March 31, 2008
Balance, beginning of period	$941		$ –
Additions	–		1,045
Amortization of deferred lease inducements	(105	)	(104	)

Balance, end of period	$836		$941

Amortization of deferred lease inducements of $105 was recorded for the year ended March 31, 2009 (March 31, 2008 – $104, 2007 – $nil) and is included in general and administration costs in the Consolidated Statements of Operations, Comprehensive (Loss) Income and Deficit.


				81

Notes to Consolidated Financial Statements

15. Accrued liabilities


	March 31, 2009	March 31, 2008
Accrued interest payable	$16,021	$8,693
Payroll liabilities	15,083	19,564
Liabilities related to equipment leases	12,182	14,617
Income and other taxes payable	8,849	2,204

	$52,135	$45,078

16. 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:


2010	$6,395
2011	5,455
2012	4,844
2013	2,598
2014	186

Subtotal:	$19,478
Less: amount representing interest – weighted average interest rate of 11.40%	(1,994	)

Present value of minimum lease payments	17,484
Less: current portion	(5,409	)

Long-term portion	$12,075

17. Senior notes


	March 31, 2009		March 31, 2008
8³/4% senior unsecured notes due 2011 ($US)	$200,000		$200,000
Unrealized foreign exchange	52,040		5,574
Unamortized financing costs and premiums, net	(2,857	)	(3,059	)
Fair value of embedded prepayment and early redemption options (note 22(a))	3,716		(4,270	)

	$252,899		$198,245

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

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

The 8³/4% senior notes are redeemable at the option of the Company, in whole or in part, at any time on or after: December 1, 2007 at 104.375% of the principal amount; December 1, 2008 at 102.188% of the principal amount; December 1, 2009 at 100% of the principal amount; plus, in each case, interest accrued to the redemption date.

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

As at March 31, 2009, the Company’s effective weighted average interest rate on its 8³/4% senior notes, including the effect of financing costs and premiums, was approximately 9.42%.


		82

Notes to Consolidated Financial Statements

The Company issued 9% senior secured notes on May 19, 2005 in the amount of US$60.5 million (Canadian $76.3 million). In connection with the IPO (note 2), the Company repurchased the 9% senior secured notes for $74,748 plus accrued interest of $3,027 on November 28, 2006. These notes were redeemed at a premium of 109.26% on November 28, 2006 resulting in a loss on extinguishment of $6,338. The loss on settlement, along with the write-off of deferred financing fees of $4,342 and third party transaction costs of $255, was recorded as a loss on extinguishment of debt in the Consolidated Statements of Operations, Comprehensive (Loss) Income and Deficit for the year ended March 31, 2007.

18. Asset retirement obligation

During the year ended March 31, 2009, 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, Comprehensive (Loss) Income and Deficit.

The following table presents a roll-forward of the liability for the asset retirement obligation:


Year-ended March 31, 2009		Amount
Balance, beginning of period		$ –
Obligation relating to the future retirement of a facility on leased land		231
Accretion expense		155

Balance, end of period		$386

At March 31, 2009, estimated undiscounted cash flows required to settle the obligation were $1,078. 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.

19. Income taxes

Income tax provision (recovery) differs from the amount that would be computed by applying the Federal and Provincial statutory income tax rate to income from continuing operations. The reasons for the differences are as follows:


Year ended March 31,	2009		2008		2007
(Loss) income before income taxes statutory	$(124,792	)	$57,163		$18,486
tax rate	29.38%		31.47%		32.12%

Expected (recovery) provision at statutory tax rate	$(36,664	)	$17,989		$5,938

Decrease related to:
Impact of enacted future statutory income tax rates	(473	)	(1,287	)	(2,106	)
Change in redemption value and accretion of redeemable preferred shares	–		–		1,000
Change in future income tax liability, resulting from valuation allowance	–		–		(5,858	)
Non-taxable gain on repurchase of NACG Preferred Corp. Series A preferred shares	–		–		(3,019	)
Non-deductible financing transactions	–		–		1,196
Large corporations tax	–		–		(136	)
Impairment of goodwill	51,767		–		–
Other	93		677		392

Income tax provision (recovery)	$14,723		$17,379		$(2,593	)

Classified as:


Year ended March 31,	2009	2008	2007
Current income taxes (recovery)	$5,546	$80	$(2,975	)
Future income taxes	9,177	17,299	382

	$14,723	$17,379	$(2,593	)


				83

Notes to Consolidated Financial Statements


	March 31, 2009	March 31, 2008
Future income tax assets:
Non-capital losses carried forward	$2,867	$19,985
Deferred share issue costs	2,300	3,312
Deferred premium on senior notes	487	1,002
Derivative financial instruments	16,980	8,448
Unrealized foreign exchange loss on senior notes	–	1,805
Billings in excess of costs on uncompleted contracts	620	1,402
Capital lease obligations	4,961	3,594
Intangible assets	243	1,560
Deferred lease inducements	214	244
Other	885	–

	$29,557	$41,352


	March 31, 2009		March 31, 2008
Future income tax liabilities:
Unbilled revenue and uncertified revenue included in accounts receivable	$7,081		$8,978
Asset held for sale	794		316
Accounts receivable – holdbacks	2,696		10,239
Plant and equipment	33,240		27,009
Intangible assets	255		568
Unrealized foreign exchange loss on senior notes	1,491		–
Embedded derivatives and financing costs on senior notes	2,504		3,176

	48,061		50,286

Net future income taxes	$(18,504	)	$(8,934	)

Classified as:


	March 31, 2009		March 31, 2008
Current asset:	$7,033		$8,217
Long-term asset	12,432		18,199
Current liability	(7,749	)	(10,907	)
Long-term liability	(30,220	)	(24,443	)

	$(18,504	)	$(8,934	)

The Company and its subsidiaries file income tax returns in the Canadian federal jurisdiction, and several provincial jurisdictions. Taxation years ending 2005 through 2009 in all jurisdictions remain open for potential examination by the tax authorities.

The Company has accrued no amounts as of March 31, 2009, for uncertain tax positions. Additionally, for the year ended March 31, 2009, the Company has not recognized any amounts in respect of potential interest and penalties associated with uncertain tax positions.

At March 31, 2009, the Company has non-capital losses for income tax purposes of approximately $9,963 which expire as follows:


2010		$ –
2011		1
2015		10
2026		3
2027		5,381
2028		284
2029		4,285


		84

Notes to Consolidated Financial Statements

20. Shares

a) Redeemable preferred shares

i) NACG Preferred Corp. preferred shares


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

Issued and outstanding March 31, 2007, 2008 and 2009	–		$ –

NACG Preferred Corp. was authorized to issue an unlimited number of Series A preferred shares. The NACG Preferred Corp. Series A preferred shares accrued dividends at a rate of $80.00 per share annually when earnings before interest, taxes, depreciation and amortization (“EBITDA”) for NAEPI were in excess of $75 million for the year. The dividends were payable in cash, additional NACG Preferred Corp. Series A preferred shares, or any combination of cash and shares as determined by the Company. The number of shares issuable was 0.001 of a whole NACG Preferred Corp. Series A preferred share for each $1.00 of dividend declared.

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

ii) NAEPI Series A preferred shares


	Number of Shares		Amount
Issued and outstanding March 31, 2006	1,000		$375
Accretion	–		625
Repurchase and cancellation	(1,000	)	(1,000	)

Issued and outstanding March 31, 2007, 2008 and 2009	–		$ –

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

The NAEPI Series A preferred shares were issued to one of the counterparties to NAEPI’s swap agreements on May 19, 2005 in connection with obtaining a new revolving credit facility. The NAEPI Series A preferred shares were initially recorded at their fair value on the date of issue, which was estimated to be $321 based on the present value of the required cash flows using the discount rate implicit at inception. Each reporting period, the accretion of the carrying value to the present value of the redemption amount at each balance sheet date was recorded as interest expense.

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

iii) NAEPI Series B preferred shares


	Number of Shares		Amount
Issued and outstanding March 31, 2006	75,244		$42,193
Accretion	–		2,489
Repurchase and cancellation	(75,244	)	(44,682	)

Issued and outstanding March 31, 2007, 2008 and 2009	–		$ –

NAEPI was authorized to issue an unlimited number of Series B preferred shares. The NAEPI Series B preferred shares were non-voting and were entitled to cumulative dividends at an annual rate of 15% of the issue price of each share. No dividends were payable on NAEPI common shares or other classes of preferred shares (defined as Junior Shares) unless all cumulative dividends had been paid on the NAEPI Series B preferred shares and NAEPI declared a NAEPI Series B


				85

Notes to Consolidated Financial Statements

preferred share dividend equal to 25% of the Junior Share dividend (except for dividends paid as part of employee and officer arrangements, intercompany administrative charges of up to $1 million annually and tax sharing arrangements). The payment of dividends and the redemption of the NAEPI Series B preferred shares were prohibited by the Company’s revolving credit facility agreement. The payment of dividends and the redemption of the NAEPI Series B preferred shares were also restricted by the indenture agreements governing the Company’s 9% senior secured notes and 8³/4% senior notes.

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

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

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

On October 6, 2005, an additional 244 NAEPI Series B preferred shares were issued for cash consideration of $25. Initially, the redemption price of the NAEPI Series B preferred shares was an amount equal to the greatest of (i) two times the issue price ($1,000), less the amount, if any, of dividends previously paid in cash on the NAEPI Series B preferred shares; (ii) an amount, not to exceed $100 million which, after taking into account any dividends previously paid in cash on such NAEPI Series B preferred shares, provides the holder with a 40% rate of return, compounded annually, on the issue price from the date of issue; and (iii) an amount, not to exceed $100 million, which is equal to 25% of the arm’s length fair market value of NAEPI’s common shares without taking into account the NAEPI Series B preferred shares.

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

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

Concurrent with the amendment to the NAEPI Series B preferred shares, NACG entered into a Put/Call Agreement with the holders of the NAEPI Series B preferred shares. The Put/Call Agreement granted to each holder of the NAEPI Series B preferred shares the right (the “Put/Call Right”) to require NACG to exchange each of the holder’s NAEPI Series B preferred shares for 100 common shares (on a post-split basis – note 20(b)) of NACG. The Put/Call Right could only be exercised upon delivery by NACG of an “Event Notice”, being either: (i) a redemption or purchase call for the redemption or purchase of the NAEPI Series B preferred shares in connection with (A) a redemption on December 31, 2011, or (B) an Accelerated Redemption Event (as defined in note 20(a)(ii)); or (ii) a notice in connection with a Liquidation Event (defined as a liquidation, winding-up or dissolution of NAEPI, whether voluntary or involuntary).

The Put/Call Agreement also granted NACG the right to require the holders of the NAEPI Series B preferred shares to exchange each of their NAEPI Series B preferred shares for 100 common shares (on a post-split basis – note 20(b)) of NACG upon delivery of a call notice to shareholders within five business days of an Event Notice.

As a result of the March 30, 2006 amendment to the terms of the NAEPI Series B preferred shares and the concurrent execution of the Put/Call Agreement, the Company accounted for the amendment as a related party transaction at carrying amount. No value was ascribed to the equity classified Put/Call Right as it was a related party transaction. The NAEPI Series B preferred shares were being accreted from their carrying value of $42.2 million on the date of amendment to their redemption value of $69.6 million on December 31, 2011 through a charge to interest expense using the effective interest method over the period to December 31, 2011. For the year ended March 31, 2007, the Company recognized $2,489 of interest expense for this accretion.

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


		86

Notes to Consolidated Financial Statements

b) Common shares

On November 3, 2006, the Board of Directors and common shareholders approved a 20-for-1 share split of NACG’s voting and non-voting common shares. All information relating to the exchange of the NAEPI Series B preferred shares (note 20(a)(iii)), the issued and outstanding common shares (below), basic and diluted net income (loss) per share data (note 20(d)), stock options (note 29), and basic and diluted net income (loss) per share data under U.S. GAAP (note 32) have been adjusted retroactively to reflect the impact of the share split in these financial statements. The share split was effective November 3, 2006.

Authorized:

Unlimited number of common voting shares

Unlimited number of common non-voting shares

Issued and outstanding:


	Number of Shares¹		Amount
Common voting shares

Issued and outstanding at March 31, 2006	18,207,600		$91,038
Issued upon exercise of stock options	27,760		139
Transferred from contributed surplus on exercise of stock options	–		52
Repurchased and cancelled prior to initial public offering	(5,000	)	(25	)
Conversion of NAEPI Series B preferred shares	7,524,400		44,682
Initial public offering (note 2)	9,437,500		171,165
Share issue costs (net of future income tax recovery of $5,667)	–		(12,915	)

Issued and outstanding at March 31, 2007	35,192,260		294,136
Issued upon exercise of stock options	324,816		1,627
Transferred from contributed surplus on exercise of stock options	–		611
Conversion of common non voting shares	412,400		2,062

Issued and outstanding at March 31, 2008	35,929,476		298,436
Issued upon exercise of stock options	109,000		703
Transferred from contributed surplus on exercise of stock options	–		834

Issued and outstanding at March 31, 2009	36,038,476		299,973

Common non-voting shares

Issued and outstanding at March 31, 2007 and 2006	412,400		2,062
Conversion to common voting shares	(412,400	)	(2,062	)

Issued and outstanding at March 31, 2009 and 2008	36,038,476		$299,973

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

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


				87

Notes to Consolidated Financial Statements

c) Contributed surplus


Balance, March 31, 2006	$1,557
Stock-based compensation (note 29)	2,101
Transferred to common shares on exercise of stock options	(52	)

Balance, March 31, 2007	$3,606
Stock-based compensation (note 29)	1,801
Transferred to common shares on exercise of stock options	(611	)
Cash settlement of stock options	(581	)

Balance, March 31, 2008	$4,215
Stock-based compensation (note 29)	1,833
Deferred performance share unit plan (note 29(b))	61
Transferred to common shares on exercise of stock options	(834	)

Balance, March 31, 2009	$5,275

d) Net (loss) income per share


Year ended March 31,	2009		2008	2007
Net (loss) income available to common shareholders	$(139,515	)	$39,784	$21,079
Weighted average number of common shares	36,020,763		35,788,776	24,352,156

Basic net (loss) income per share	$(3.87	)	$1.11	$0.87


Year ended March 31,	2009		2008	2007
Net (loss) income available to common shareholders	$(139,515	)	$39,784	$21,079
Weighted average number of common shares	36,020,763		35,788,776	24,352,156
Dilutive effect of stock options	–		1,126,859	1,091,751
Weighted average number of diluted common shares	36,020,763		36,915,635	25,443,907

Diluted net (loss) income per share	$(3.87	)	$1.08	$0.83

For the year ended March 31, 2009, weighted average stock options of 614,010 (March 31, 2008 – 283,674) were excluded from the calculation of diluted net income per share as the options’ average exercise price was greater than the average market price of the common shares for the year.

For the year ended March 31, 2009, the effect of outstanding stock options on net loss per share was anti-dilutive. As such, the effect of outstanding stock options used to calculate the diluted net loss per share has not been disclosed for the current year.

21. Interest expense


Year ended March 31,	2009		2008	2007
Interest on senior notes	$30,689		$23,338	$27,417
Interest on capital lease obligations	1,234		780	725
Interest on senior secured/revolving credit facility	298		769	346
Interest on NACG Preferred Corp. Series A preferred shares	–		–	1,400
Accretion and change in redemption value of NAEPI Series B preferred shares	–		–	2,489
Accretion of NAEPI Series A preferred shares	–		–	625
Interest income ⁽ⁱ⁾	(5,310	)	–	–

Interest on long-term debt	26,911		24,887	33,002
Amortization of deferred financing costs	–		–	3,436
Amortization of bond issue costs and premiums	808		838	–
Other interest	(269	)	1,294	811

	$27,450		$27,019	$37,249

(i)

As a result of the U.S. Dollar interest swap cancellation described in note 22(c)(i), the Company now receives floating quarterly interest payments from its SWAP counterparties at a rate of 4.2% over 3-month LIBOR. These floating interest payments occur quarterly every March 1, June 1, September 1 and December 1 until the notes mature on December 1, 2011.


		88

Notes to Consolidated Financial Statements

22. Financial instruments and risk management

a) Fair value and classification of financial instruments

In determining the fair value of financial instruments, the Company uses a variety of methods and assumptions that are based on market conditions and risks existing on each reporting date. Counterparty confirmations and standard market 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 accounts receivable, unbilled revenue, accounts payable and accrued liabilities approximate their carrying amounts due to the relatively short periods to maturity for the instruments.

The fair values of amounts due under the revolving credit facility are based on management estimates which are determined by discounting cash flows required under the instruments at the interest rate currently estimated to be available for instruments with similar terms. Based on these estimates and by using the outstanding balance of $nil at March 31, 2009 and March 31, 2008, the fair value of amounts due under the revolving credit facility as at March 31, 2009 and March 31, 2008 are not significantly different than their carrying value.

The fair values of the Company’s cross-currency and interest rate swap agreements and the Company’s embedded derivatives are based on appropriate price modeling commonly used by market participants to estimate fair value. Such modeling includes option pricing models and discounted cash flow analysis, using observable market based inputs to estimate fair value. Fair value determined using valuation models requires the use of assumptions concerning the amount and timing of future cash flows. Fair value amounts reflect management’s best estimates using external readily observable market data such as future prices, interest rate yield curves, foreign exchange rates and discount rates for time value. It is possible that the assumptions used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be material.

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


	March 31, 2009		March 31, 2008
	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Senior notes ⁽ⁱ⁾	$252,899	$181,469	$198,245	$209,178
Capital lease obligations ⁽ⁱⁱ⁾	17,484	17,345	14,776	15,228

(i)	The fair value of the US Dollar denominated 8³/4% senior notes is based upon their period end closing market price translated into Canadian Dollars at period end exchange rates as at March 31, 2009 and March 31, 2008.

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

Derivative financial instruments that are used for risk management purposes, as described in Note 22(b) under – Risk Management consist of the following:


March 31, 2009	Derivative Financial Instruments		Senior Notes
Cross-currency and interest rate swaps	$39,547		$ –
Embedded price escalation features in a long-term revenue construction contract	(324	)	–
Embedded price escalation features in certain long-term supplier contracts	22,778		–
Embedded prepayment and early redemption options on senior notes	–		3,716

Total fair value of derivative financial instruments	62,001		3,716
Less: current portion	11,439		–

	$50,562		$3,716


March 31, 2008	Derivative Financial Instruments	Senior Notes
Cross-currency and interest rate swaps	$81,649	$ –
Embedded price escalation features in a long-term revenue construction contract	14,821	–
Embedded price escalation features in certain long-term supplier contracts	1,269	–
Embedded prepayment and early redemption options on senior notes	–	(4,270	)

Total fair value of derivative financial instruments	97,739	(4,270	)
Less: current portion	4,720	–

	$93,019	$(4,270	)


				89

Notes to Consolidated Financial Statements

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


	2009		2008		2007
Realized and unrealized (gain)/loss on cross-currency and interest rate swaps	$(39,431	)	$23,456		$(196	)
Unrealized (gain)/loss on embedded price escalation features in a long-term revenue construction contract	(15,145	)	7,575		–
Unrealized loss/(gain) on embedded price escalation features in certain long-term supplier contracts	21,509		(1,205	)	–
Unrealized loss on embedded prepayment and early redemption options on senior notes	7,986		4,249		–

	$(25,081	)	$34,075		$(196	)

b) Risk management

The Company is exposed to market, credit and liquidity risks associated with its financial instruments. The Company will from time to time use various financial instruments to reduce market risk exposures from changes in foreign currency exchange rates and interest rates. The Company does not hold or use any derivative instruments for trading or speculative purposes.

Overall, the Company’s Board of Directors has responsibility for the establishment and approval of the Company’s risk management policies. Management performs a risk assessment on a continual basis to help ensure that all significant risks related to the Company and its operations have been reviewed and assessed to reflect changes in market conditions and the Company’s operating activities.

c) Market risk

Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices such as foreign currency exchange rates and interest rates. The level of market risk to which the Company is exposed at any point in time varies depending on market conditions, expectations of future price or market rate movements and composition of the Company’s financial assets and liabilities held, non-trading physical assets and contract portfolios.

To manage the exposure related to changes in market risk, the Company uses various risk management techniques including the use of derivative instruments. Such instruments may be used to establish a fixed price for a commodity, an interest-bearing obligation or a cash flow denominated in a foreign currency.

The sensitivities provided below are hypothetical and should not be considered to be predictive of future performance or indicative of earnings on these contracts.

i) Foreign exchange risk

Foreign exchange risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to changes in foreign exchange rates. The Company has 8³/ 4% Senior Notes denominated in U.S. Dollars in the amount of U.S. $200 million. In order to reduce its exposure to changes in the U.S. to Canadian Dollar exchange rate, the Company entered into a cross-currency swap agreement to manage this foreign currency exposure for both the principal balance due on December 1, 2011 as well as the semi-annual interest payments from the issue date to the maturity date. In conjunction with the cross-currency swap agreement, the Company also entered into a U.S. Dollar interest rate swap and a Canadian Dollar interest rate swap as discussed in note 22(c)(ii) below. These derivative financial instruments were not designated as hedges for accounting purposes. At March 31, 2009 and March 31, 2008, the notional principal amount of the cross-currency swap was U.S. $200 million and Canadian $263 million.

On December 17, 2008, the Company received notice that all three swap counterparties had exercised the cancellation option on the U.S. Dollar interest rate swap and, effective February 2, 2009, the U.S. Dollar interest rate swap was terminated. In addition to net accrued interest to the termination date of U.S.$0.7 million, the counterparties paid a cancellation premium of 2.2% on the notional amount of U.S. $200 million or U.S. $4.4 million (equivalent to Canadian $5.3 million), which is included in the caption ‘Other income’ in the Consolidated Statement of Operations, Comprehensive (Loss) Income and Deficit for the year ended March 31, 2009.

The Company’s Canadian Dollar interest rate swap and cross-currency swap agreements are not cancellable at the option of the counterparties and remain in effect. The Company will continue to pay the counterparties an average fixed rate of 9.889% on the notional amount of Canadian $263 million or Canadian $13 million semi-annually until December 1, 2011. Beginning March 1, 2009, the Company received quarterly floating rate payments in U.S. Dollars on the cross-currency swap agreement at the prevailing 3-month LIBOR rate plus a spread of 4.2% on the notional amount of U.S.$200 million.


		90

Notes to Consolidated Financial Statements

As a result of the cancellation of the U.S. Dollar interest rate swap, the Company is exposed to changes in the value of the Canadian Dollar versus the U.S. Dollar. To the extent that 3-month LIBOR rate is less than 4.6% (the difference between the 8³/4% Senior Notes coupon and the 4.2% spread over 3-month LIBOR on the cross-currency swap agreement), the Company will have to acquire U.S. Dollars to fund a portion of its semi-annual coupon payment on its Senior Notes. At the 3-month U.S. LIBOR rate of 1.192% at March 31, 2009, a $0.01 increase (decrease) in exchange rates in the Canadian Dollar would result in an insignificant decrease (increase) in the amount of Canadian Dollars required to fund each semi-annual coupon payment.

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

At March 31, 2009, with other variables unchanged, a $0.01 increase (decrease) in exchange rates of the Canadian Dollar to the U.S. Dollar related to the U.S. Dollar denominated senior notes would decrease (increase) net income and decrease (increase) equity by approximately $1.7 million. With other variables unchanged, a $0.01 increase (decrease) in exchange rates in the Canadian to the U.S. Dollar related to the cross-currency swap would increase (decrease) net income and increase (decrease) equity by approximately $1.5 million. The impact of similar exchange rate changes on short-term exposures would be insignificant and there would be no impact to other comprehensive income.

ii) Interest rate risk

The Company is exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of its financial instruments. Amounts outstanding under the Company’s revolving credit facility are subject to a floating rate. The Company’s senior notes are subject to a fixed rate. The Company’s interest risk arises from long-term borrowings issued at fixed rates that create fair value interest rate risk and variable borrowings that create cash flow interest rate risk. Changes in market interest rates cause the fair value of long-term debt with fixed interest rates to fluctuate but do not affect earnings, as the Company’s debt is carried at amortized cost and the carrying value does not change as interest rates change.

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

In conjunction with the cross-currency swap agreement discussed in note 22(c)(i) above, the Company also entered into a U.S. Dollar interest rate swap and a Canadian Dollar interest rate swap with the net effect of economically converting the 8³/4% rate payable on the 8³/4% senior notes into a fixed rate of 9.889% for the duration that the 8³/4% senior notes are outstanding. These derivative financial instruments were not designated as hedges for accounting purposes.

As a result of the U.S. Dollar interest swap cancellation described in note 22(c)(i), the Company is exposed to changes in interest rates. The Company has a fixed semi-annual coupon payment of 8³/4% on its U.S. $200 million Senior Notes. With the termination of the U.S. Dollar interest rate swap, the Company will no longer receive fixed U.S. Dollar payments from the counterparties to offset the coupon payment on its Senior Notes. As a result of this termination, our annual interest expense at the current LIBOR rate will increase U.S. $6.8 million. In addition, we are now exposed to interest rate risk where a 100 basis point increase (decrease) in the 3-month U.S. LIBOR rate will result in a U.S. $2.0 million decrease (increase) in annual interest expense.

At March 31, 2009 and March 31, 2008, the notional principal amounts of the interest rate swaps were U.S.$200 million and Canadian $263 million.

As at March 31, 2009, holding all other variables constant, a 100 basis point increase (decrease) to Canadian interest rates would impact the fair value of the interest rate swaps by $5.0 million with this change in fair value being recorded in net income. As at March 31, 2009, holding all other variables constant, a 100 basis point increase (decrease) to U.S. interest rates would impact the fair value of the interest rate swaps by $0.5 million with this change in fair value being recorded in net income. As at March 31, 2009, holding all other variables constant, a 100 basis point increase (decrease) of Canadian to U.S. interest rate volatility would impact the fair value of the interest rate swaps by $nil million with this change in fair value being recorded in net income.

At March 31, 2009, the Company held $nil of floating rate debt pertaining to its revolving credit facility (March 31, 2008 – $nil). As at March 31, 2009, holding all other variables constant, a 100 basis point increase (decrease) to interest rates on floating rate debt would not have a significant impact on net income or equity. This assumes that the amount of floating rate debt remains unchanged from that which was held at March 31, 2009.

d) Credit risk

Credit risk is the risk that financial loss to the Company maybe increased 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


				91

Notes to Consolidated Financial Statements

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, 2009 and March 31, 2008, the following customers represented 10% or more of accounts receivable and unbilled revenue:


	March 31, 2009	March 31, 2008
Customer A	29%	8%
Customer B	17%	9%
Customer C	13%	19%
Customer D	11%	11%
Customer E	1%	11%
Customer F	0%	18%

The Company reviews its accounts receivable amounts regularly and amounts are written down to their expected realizable value when outstanding amounts are determined not to be fully collectible. This generally occurs when the customer has indicated an inability to pay, the Company is unable to communicate with the customer over an extended period of time, and other methods to obtain payment have been considered and have not been successful. Bad debt expense is charged to net income in the period that the account is determined to be doubtful. Estimates of the allowance for doubtful accounts are determined on a customer-by-customer evaluation of collectability at each reporting date taking into consideration the following factors: the length of time the receivable has been outstanding, specific knowledge of each customer’s financial condition and historical experience.

The Company’s maximum exposure to credit risk for accounts receivable and unbilled revenue is as follows:


	March 31, 2009	March 31, 2008
Trade accounts receivables	$76,499	$158,245
Other receivables	1,824	8,765

Total accounts receivable	78,323	167,010

Unbilled revenue	55,907	70,833

On a geographic basis as at March 31, 2009, approximately 99% (March 31, 2008 – 89%) 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, 2009 and March 31, 2008 trade receivables are aged as follows:


	March 31, 2009	March 31, 2008
Not past due	$47,197	$125,219
Past due 1-30 days	13,282	19,790
Past due 31-60 days	2,085	1,896
More than 61 days	13,935	11,340

Total	$76,499	$158,245

As at March 31, 2009, the Company has recorded an allowance for doubtful accounts of $2,597 (March 31, 2008 – $742) of which 85% relates to amounts that are more than 61 days past due.

The allowance is an estimate of the March 31, 2009 trade receivable balances that are considered uncollectible. Changes to the allowance are as follows:


Year ended March 31,	2009		2008		2007
Opening balance	$742		$87		$69
Payments received on provided balances	(100	)	(184	)	(205	)
Current year allowance	4,324		950		223
Write-offs	(2,369	)	(111	)	–

Ending balance	2,597		742		87

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.


		92

Notes to Consolidated Financial Statements

e) 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 23. 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 credit facility, will provide sufficient cash requirements to cover the Company’s forecasted normal operating and budgeted capital expenditures.

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

At March 31, 2009, the Company was in compliance with its senior leverage, its interest coverage, and working capital covenants.

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


			Fiscal year
	Carrying Amount	Contractual Cash Flows	2010	2011	2012	2013	2013 and Thereafter
Accounts payable and accrued liabilities	$92,318	$92,318	$92,318	$ –	$ –	$ –	$ –

Capital lease obligations (including interest)	17,484	19,478	6,395	5,455	4,844	2,598	186

Senior notes ⁽ⁱ⁾	252,899	263,000	–	–	263,000	–	–

Interest on senior notes	7,351	66,159	22,053	22,053	22,053	–	–

Cross-currency and interest rate swaps ⁽ⁱ⁾	48,217	37,407	12,469	12,469	12,469	–	–

	$418,269	$478,362	$133,235	$39,977	$302,366	$2,598	$186

(i)	The contractual cash flows of the senior notes include the impact of the cross currency swap agreement which fixes the obligation related to the senior notes and cross currency swap at the $263 million payable at the December 1, 2011 maturity date.

23. 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, contributed surplus, accumulated other comprehensive income (loss) and deficit. The Company manages its capital structure and makes adjustments to it in light of general economic conditions, the risk characteristics of the underlying assets and the Company’s working capital requirements. In order to maintain or adjust its capital structure, the Company, upon approval from its Board of Directors, may issue or repay long-term debt, issue shares, repurchase shares through a normal course issuer bid, pay dividends or undertake other activities as deemed appropriate under the specific circumstances. The Board of Directors reviews and approves any material transactions out of the ordinary course of business, including proposals on acquisitions or other major investments or divestitures, as well as capital and operating budgets.

The Company monitors debt leverage ratios as part of the management of liquidity and shareholders’ return and to sustain future development of the business. The Company is also subject to externally imposed capital requirements under its revolving credit facility and indenture agreement governing the U.S. Dollar denominated 8³/4% senior notes, which contains certain restrictive covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions or to pay dividends or redeem shares of capital stock. The Company’s overall strategy with respect to capital risk management remains unchanged from the year ended March 31, 2008.


				93

Notes to Consolidated Financial Statements

The Company is subject to restrictive covenants under its banking agreements with its principal lenders related to its revolving credit facility (note 13), its capital lease obligations (note 16) and senior notes (note 17) that are measured on a quarterly basis. These covenants include, but are not limited to, a current ratio, senior leverage ratio, and interest coverage ratio as specifically defined in the respective agreements. As at March 31, 2009, the Company was in compliance with all externally imposed capital requirements.

24. Other information

a) Supplemental cash flow information


Year ended March 31,	2009		2008		2007
Cash paid during the year for:
Interest	$29,336		$29,568		$34,061
Income taxes	52		80		342
Cash received during the year for:
Interest	477		345		1,156
Income taxes	2,734		300		160
Non-cash transactions:
Acquisition of plant and equipment by means of capital leases	8,863		8,829		4,653
Lease inducements	–		1,045		–


b) Net change in non-cash working capital
Year ended March 31,	2009		2008		2007
Operating activities:
Accounts receivable	$86,832		$(59,415	)	$(26,183	)
Allowance for doubtful accounts	1,855		654		18
Unbilled revenue	14,976		(2,174	)	(39,339	)
Inventory	(6,617	)	46		(99	)
Prepaid expenses and deposits	1,015		2,632		(10,133	)
Other assets	–		4,616		(9,855	)
Accounts payable	(56,309	)	21,430		32,073
Accrued liabilities	7,057		21,685		(1,429	)
Billings in excess of costs incurred and estimated earnings on uncompleted contracts	(2,617	)	1,773		(2,125	)

	$46,192		$(8,753	)	$(57,072	)
Investing activities:
Accounts payable	$(630	)	$(2,835	)	$7,922

25. Segmented information

a) General overview

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

Heavy Construction and Mining:

The Heavy Construction and Mining segment provides mining and site preparation services, including overburden removal and reclamation services, project management and underground utility construction, to a variety of customers throughout Canada.

Piling:

The Piling segment provides deep foundation construction and design build services to a variety of industrial and commercial customers throughout Western Canada.

Pipeline:

The Pipeline segment provides both small and large diameter pipeline construction and installation services to energy and industrial clients throughout Western Canada.

The accounting policies of the reportable operating segments are the same as those described in the significant accounting policies in note 3. Certain business units of the Company have been aggregated into the Heavy Construction and Mining segment as they have similar economic characteristics. These business units are considered to have similar economic characteristics based on similarities in the nature of the services provided, the customer base and the similarities in the production process and the resources used to provide these services.


		94

Notes to Consolidated Financial Statements

b) Results by business segment


For the year ended March 31, 2009	Heavy Construction and Mining		Piling		Pipeline		Total
Revenues from external customers	$716,053		$155,076		$101,407		$972,536
Depreciation of plant and equipment	26,213		3,380		581		30,174
Segment profits (excluding goodwill impairment)	115,698		38,776		22,470		176,944
Impairment of goodwill	(125,447	)	(18,000	)	(32,753	)	(176,200	)
Segment assets	381,791		88,908		7,898		478,597
Expenditures of segment plant and equipment	80,289		8,679		75		89,043


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


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

c) Reconciliations

i) (Loss) income before income taxes


Year ended March 31,	2009		2008		2007
Total profit for reportable segments	$176,944		$176,205		$94,918
Unallocated corporate expenses:
General and administrative expense	(74,405	)	(69,670	)	(39,769	)
Loss on disposal of plant and equipment	(5,325	)	(179	)	(959	)
Amortization of intangibles	(1,087	)	(1,071	)	(582	)
Impairment of goodwill	(176,200	)	–		–
Interest expense	(27,450	)	(27,019	)	(37,249	)
Foreign exchange (loss) gain	(46,666	)	25,442		5,044
Realized and unrealized gain (loss) on derivative financial instruments	25,081		(34,075	)	196
Gain on repurchase of NACG Preferred Corp. preferred shares	–		–		9,400
Loss on extinguishment of debt	–		–		(10,935	)
Other income	5,955		418		904
Unallocated equipment costs ⁽ⁱ⁾	(1,639	)	(12,888	)	(2,482	)

(Loss) income before income taxes	$(124,792	)	$57,163		$18,486

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

ii) Total assets


	March 31, 2009	March 31, 2008
Total assets for reportable segments	$478,597	$698,966
Corporate assets:
Cash	98,880	31,863
Plant and equipment	25,549	26,785
Future income taxes	19,465	26,416
Other	7,561	9,568

Total corporate assets	151,455	94,632

Total assets	$630,052	$793,598


				95

Notes to Consolidated Financial Statements

The Company's goodwill of $23,872 is assigned to the Piling segment. All of the Company's assets are located in Canada.

iii) Depreciation of plant and equipment


Year ended March 31,	2009	2008	2007
Total depreciation for reportable segments	$30,174	$28,070	$25,780
Depreciation for corporate assets	7,928	8,659	5,254

Total depreciation	$38,102	$36,729	$31,034

iv) Capital expenditures for plant and equipment


Year ended March 31,	2009	2008	2007
Total capital expenditures for reportable segments	$89,043	$56,090	$106,687
Capital expenditures for corporate assets	5,096	1,689	3,332

Total capital expenditures	$94,139	$57,779	$110,019

d) Customers

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


Year ended March 31,	2009	2008	2007
Customer A	31%	23%	16%
Customer B	18%	13%	12%
Customer C	15%	13%	10%
Customer D	10%	19%	0%
Customer E	9%	13%	17%
Customer F	0%	4%	10%

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

26. Related party transactions

The Company may receive consulting and advisory services provided by the Sponsors (principals or employees of such Sponsors are directors of the Company) with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters, and no fee is charged for these consulting and advisory services.

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

Prior to the reorganization and IPO described in Note 2, the Company had a consulting and advisory services agreement with the Sponsors, under which the Company and certain of its subsidiaries received consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. An advisory fee of $400 for the year ended March 31, 2007 was paid for these services and was recorded as part of general and administrative costs in the consolidated statement of operations.

On November 28, 2006, upon closing of the IPO described in Note 2, the consulting and advisory services agreement was cancelled. The consideration paid by the Company on the closing of the offering to cancel the agreement was $2,000, which was recorded as part of general and administrative expense during the year ended March 31, 2007. In addition, the Sponsors also received a fee of $854, 0.5% of the aggregate gross proceeds to the Company from the IPO, which was recorded as a share issue cost.

Pursuant to several office lease agreements, for the year ended March 31, 2007 the Company paid $572 (2006 – $836) to a company owned, indirectly and in part, by one of the directors. Effective November 28, 2006 the director resigned from the Board. Accordingly, the lease agreement is no longer considered to be with a related party.

All related party transactions described above 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.


		96

Notes to Consolidated Financial Statements

27. Commitments

The annual future minimum lease payments for heavy equipment, office equipment and premises in respect of operating leases for the next five years and thereafter are as follows:


For the year ending March 31,
2010		$51,306
2011		41,998
2012		32,892
2013		19,675
2014 and thereafter		15,749

		$161,620

28. Employee benefit plans

The Company and its subsidiaries match voluntary contributions made by the employees to their Registered Retirement Savings Plans to a maximum of 5% of base salary for each employee. Contributions made by the Company during the year ended March 31, 2009 were $2,540 (2008 – $2,053; 2007 – $1,125).

29. Stock-based compensation plan

a) Share option plan

Under the 2004 Amended and Restated Share Option Plan, directors, officers, employees and certain service providers to the Company are eligible to receive stock options to acquire voting common shares in the Company. Each stock option provides the right to acquire one common share in the Company and expires ten years from the grant date or on termination of employment. Options may be exercised at a price determined at the time the option is awarded, and vest as follows: no options vest on the award date and twenty percent vest on each subsequent anniversary date.


	Number of options²		Weighted average exercise price $ per share
Outstanding at March 31, 2006	2,066,360		5.00
Granted	315,520		11.99
Exercised	(27,760	)	(5.00	)
Forfeited	(207,280	)	(5.00	)

Outstanding at March 31, 2007	2,146,840		6.03
Granted	481,600		13.80
Exercised	(324,816	)	(5.00	)
Cancelled³	(62,760	)	(5.00	)
Forfeited	(204,500	)	(11.56	)

Outstanding at March 31, 2008	2,036,364		7.54
Granted	344,800		8.22
Exercised	(109,000	)	(6.45	)
Forfeited	(200,280	)	(9.40	)

Outstanding at March 31, 2009	2,071,884		7.53

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

³	Options settled for cash.


				97

Notes to Consolidated Financial Statements

The following table summarizes information about stock options outstanding at March 31, 2009:


	Options outstanding			Options exercisable
Exercise price	Number	Weighted average remaining life	Weighted average exercise price ($)	Number	Weighted average exercise price ($)
$5.00	1,281,504	5.8 years	$5.00	957,400	$5.00
$16.75	27,760	7.5 years	$16.75	11,104	$16.75
$13.50	264,920	8.7 years	$13.50	54,520	$13.50
$15.37	89,500	9.0 years	$15.37	17,900	$15.37
$13.21	75,000	8.8 years	$13.21	15,000	$13.21
$16.01	75,000	9.0 years	$16.01	–	–
$16.46	50,000	9.0 years	$16.46	–	–
$3.69	208,200	9.7 years	$3.69	–	–

	2,071,884	7.0 years	$7.53	1,055,924	$5.85

At March 31, 2009, the weighted average remaining contractual life of outstanding options is 7.0 years (March 31, 2008 – 7.6 years). The Company recorded $1,834 of compensation expense related to stock options in the year ended March 31, 2009 (2008 – $1,801; 2007 – $2,101) with such amount being credited to contributed surplus. At March 31, 2009 the total compensation costs related to non-vested awards not yet recognized was $3,902 and these costs are expected to be recognized over a weighted average period of 3.2 years.

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


Year ended March 31,	2009	2008	2007
Number of options granted⁴	344,800	481,600	315,520
Weighted average fair value per option granted ($)	4.53	4.92	9.91
Weighted average assumptions
Dividend yield	nil%	nil%	nil%
Expected volatility	59.01%	38.80%	24.73%
Risk-free interest rate	3.24%	4.25%	4.30%
Expected life (years)	6.5	6.5	6.4

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

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

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

In the event of certain change of control events as defined in the amended option plan, all outstanding options will become immediately vested and exercisable. The amended option plan provides that the Company’s Board of Directors can make certain specified amendments to the option plan subject to receipt of shareholder and regulatory approval, and further authorizes the Board of Directors to make all other amendments to the plan, subject only to regulatory

⁴	The number of options and the weighted average fair value per option granted have been retroactively adjusted to reflect the impact of the 20-for-1 share split disclosed in note 20(b).


		98

Notes to Consolidated Financial Statements

approval but without shareholder approval. The amendments the Board of Directors may make without shareholder approval include amendments of a housekeeping nature, changes to the vesting provisions of an option or the option plan, changes to the termination provisions of an option or the option plan which do not entail an extension beyond the original expiry date, the discontinuance of the option plan, and the addition of provisions relating to phantom share units, such as restricted share units and deferred share units which result in participants receiving cash payments, and the terms governing such features.

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

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

b) Deferred performance share unit plan

On March 19, 2008, the Company approved a Deferred Performance Share Unit (“DPSU”) Plan which became effective April 1, 2008.

DPSUs will be granted effective April 1 of each fiscal year in respect of services to be provided in that fiscal year and the following two fiscal years. The DPSUs vest at the end of a three-year term and are subject to the performance criteria approved by the Compensation Committee of the Board of Directors at the date of grant. Such performance criterion includes the passage of time and is based upon return on invested capital calculated on operating income and average operating assets. The date of the third fiscal year-end following the date of the grant of DPSUs shall be the maturity date for such DPSUs. At the maturity date, the Compensation Committee shall assess the participant against the performance criteria and determine the number of DPSUs that have been earned (earned DPSUs).

The settlement of the participant’s entitlement shall be made in either cash at the value of the earned DPSUs equivalent to the number of earned DPSUs at the value of the Company’s common shares at the date of maturity or in a number of common shares equal to the number of earned DPSUs. If settled in common shares, the common shares shall be 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. The weighted average assumptions used in estimating the fair value of the share options issued under the DPSU Plan at April 1, 2008 are as follows:


Number of units granted		111,020
Weighted average fair value per option granted ($)		12.34
Weighted average assumptions:
Dividend yield		–
Expected volatility		56.25%
Risk-free interest rate		2.83%
Expected life (years)		3.00


	Year Ended March 31, 2009
	Number of Units		Weighted Average Exercise Price ($ per share)
Outstanding, beginning of period	–		–
Granted	111,020		–
Exercised	–		–
Forfeited	(20,015	)	–

Outstanding, end of period	91,005		–

At March 31, 2009, the weighted average remaining contractual life of outstanding DPSU Plans is 2.0 years. For the year ended March 31, 2009, the Company granted 111,020 units under the Plan and recorded compensation expense of $61 (March 31, 2008 – $nil) which is included in general and administrative costs. This 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, 2009, there was approximately $829 of total unrecognized compensation cost related to non-vested share-based payment arrangements under the DPSU Plan, which is expected to be recognized over a weighted average period of 2.0 years and is subject to performance adjustments.


				99

Notes to Consolidated Financial Statements

c) Directors’ deferred stock unit plan

On November 27, 2007, the Company approved a Directors’ Deferred Stock Unit (“DDSU”) Plan, which became effective January 1, 2008. Under the DDSU Plan, non-employee or officer directors of the Company shall receive 50% of their annual fixed remuneration (which is included in general and administrative expenses in the Consolidated Statement of Operations, Comprehensive (Loss) Income and Deficit) 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 share unit account shall be determined by dividing the amount of the participant’s deferred remuneration by the fair market value per common share on the date the DDSUs are credited to the Participant (the date the services are rendered by the participant). The DDSUs vest immediately upon grant and are only redeemable upon death or retirement of the participant for cash determined by the market price of the Company’s common shares for the 5 trading day’s 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. For the year ended March 31, 2009, the Company recorded an expense of $356 (March 31, 2008 – $190, March 31, 2007 – $nil) related to the grant of the DDSUs.


Year ended March 31,	2009	2008
Outstanding, beginning of period	11,807	–
Granted	127,884	11,807
Exercised	–	–
Forfeited	–	–

Outstanding, end of period	139,691	11,807

At March 31, 2009, the redemption value of these units was $3.91/unit (March 31, 2008 – $16.01/unit). There is no unrecognized compensation expense related to deferred share units, since these awards vest immediately when granted.

30. 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.

31. Comparative figures

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

32. United States generally accepted accounting principles

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


Year ended March 31,	2009		2008		2007
Net (loss) income – as reported under Canadian GAAP	$(139,515	)	$39,784		$21,079
Capitalized interest on assets held for construction (a)					249
Depreciation of capitalized interest (a)	(162	)	(131	)	(143	)
Differences in accounting for financing costs, discounts and premiums (b)	(1,931	)	(1,049	)	1,246
Difference in fair value of stock options under U.S. GAAP (c)	(55	)	(136	)	–
Unrealized gain on embedded price escalation features in a long-term revenue construction contract and supplier contract (d)	–		–		526
Unrealized gain on embedded redemption rights on senior notes (d)	4,655		4,000		348
Difference between accretion of NAEPI Series B preferred shares under Canadian GAAP and U.S. GAAP (e)	–		–		249

(Loss) income before income taxes	(137,008	)	42,468		23,554
Income taxes:
Deferred income taxes (f)	(34	)	(119	)	1,816

Net (loss) income – U.S. GAAP	$(137,042	)	$42,349		$25,370

Net (loss) income per share – basic – U.S. GAAP	$(3.80	)	$1.18		$1.04

Net (loss) income per share – diluted – U.S. GAAP⁵	$(3.80	)	$1.15		$1.00

⁵	Basic net income (loss) per share – U.S. GAAP and diluted net income (loss) per share – U.S. GAAP have been retroactively adjusted to reflect the company’s 20-for-1 share split effected on November 3, 2006 (see note 18(a)).


		100

Notes to Consolidated Financial Statements

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


Year ended March 31,	2009		2008		2007
Shareholders’ equity (as reported) – Canadian GAAP	$147,437		$283,364		$244,278
Capitalized interest (a)	1,096		1,096		1,096
Depreciation of capitalized interest (a)	(436	)	(274	)	(143	)
Differences in accounting for finance costs, discounts and premiums (b)	4,286		6,217		1,836
Unrealized loss on embedded price escalation features in a long-term revenue construction contract and supplier contract (d)	–		–		(9,720	)
Unrealized loss on embedded redemption rights on senior notes (d)	–		(4,655	)	(136	)
Deferred income taxes (f)	(1,423	)	(1,389	)	1,816

Shareholders’ equity – U.S. GAAP	$150,960		$284,359		$239,027

A continuity schedule of each component of the Company’s shareholders’ equity under U.S. GAAP for the year ended March 31, 2009 is as follows:


	Common shares		Contributed surplus		Deficit		Total
March 31, 2006	$93,100		$1,557		$(89,546	)	$5,111
Net income	–		–		25,370		25,370
Stock based compensation	–		2,101		–		2,101
Issued upon exercise of stock options	139		–		–		139
Share issues	171,165		–		–		171,165
Share issue costs	(12,915	)	–		–		(12,915	)
Repurchase of common shares	(25	)	–		(59	)	(84	)
Conversion of NAEPI Series B preferred shares (e)	48,140		–		–		48,140
Reclassification on exercise of stock options	52		(52	)	–		–

March 31, 2007 – U.S. GAAP	$299,656		$3,606		$(64,235	)	$239,027
Net income	–		–		42,349		42,349
Stock based compensation (c)	–		1,937		–		1,937
Reclassification on exercise of stock options	611		(611	)	–		–
Cash settlement of stock options	–		(581	)	–		(581	)
Issued upon the exercise of stock options	1,627		–		–		1,627

March 31, 2008 – U.S. GAAP	$301,894		$4,351		$(21,886	)	$284,359
Net loss	–		–		(137,042	)	(137,042	)
Stock based compensation (c)	–		1,949		–		1,949
Write up of tire impairment on adoption of CICA 3031 (note 3 (s) (iii))	–		–		991		991
Reclassification on exercise of stock options	834		(834	)	–		–
Issued upon the exercise of stock options	703		–		–		703

March 31, 2009 – U.S. GAAP	$303,431		$5,466		$(157,937	)	$150,960

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

a) Capitalization of interest

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

b) Financing costs, discounts and premiums

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

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


				101

Notes to Consolidated Financial Statements

translation procedures as they are treated as a monetary item under Canadian GAAP. Under U.S. GAAP, foreign denominated transaction costs are considered non-monetary and are not subject to foreign currency gains and losses resulting from periodic translation procedures.

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

c) Stock-based compensation

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

d) Derivative financial instruments

Effective April 1, 2007, the Company adopted the CICA Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, and Handbook Section 3865, “Hedges”.

Under Canadian GAAP, the Company determined that the issuer’s early prepayment option included in the senior notes should be bifurcated from the host contract, along with a contingent embedded derivative in the senior notes that provide for accelerated redemption by the holders in certain instances. These embedded derivatives were measured at fair value at the inception of the senior notes and the residual amount of the proceeds was allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of the senior notes is accreted to par value over the term of the notes using the effective interest method and is recognized as interest expense as discussed in b) above. Prior to April 1, 2007 under Canadian GAAP, separate accounting of embedded derivatives from the host contract was not permitted by EIC-117.

Under U.S. GAAP, Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”) establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts and debt instruments) be recorded in the balance sheet as either an asset or liability measured at its fair value. The contingent embedded derivative in the senior notes that provide for accelerated redemption by the holders in certain instances met the criteria for bifurcation from the debt contract and separate measurement at fair value. The embedded derivatives have been measured at fair value and changes in fair value recorded in net income for all periods presented. The issuer’s early prepayment option included in the senior notes does not meet the criteria as an embedded derivative under SFAS 133 and was not bifurcated from the host contract and measured at fair value resulting in a U.S. GAAP difference for all periods presented.

On adoption of CICA Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, the Company reviewed the accounting treatment of a number of outstanding contracts and determined that a price escalation feature in a revenue construction contract and supplier contracts entered into prior to April 1, 2007 contained embedded derivatives that are not closely related to the host contract under both Canadian and U.S. GAAP. The Company recorded the fair value of these embedded derivatives on April 1, 2007 of $9,720, with a corresponding increase in opening deficit of $6,950, net of future income taxes of $2,770 for Canadian GAAP purposes. Under U.S. GAAP, the Company has recognized and measured these embedded derivatives since inception of the related contracts.

e) NAEPI Series B Preferred Shares

Prior to the modification of the terms of the NAEPI Series B preferred shares on March 30, 2006, there were no differences between Canadian GAAP and U.S. GAAP related to the NAEPI Series B preferred shares. As a result of the modification of terms of NAEPI’s Series B preferred shares, under Canadian GAAP, NACG continued to classify the NAEPI Series B preferred shares as a liability and was accreting the carrying amount of $42.2 million on the amendment date (March 30, 2006) to their December 31, 2011 redemption value of $69.6 million using the effective interest method. Under U.S. GAAP, NACG recognized the fair value of the amended NAEPI Series B preferred shares as minority interest as such amount was recognized as temporary equity in the accounts of NAEPI in accordance with EITF Topic D-98 and recognized a charge of $3.7 million to retained earnings for the difference between the fair value and the carrying amount of the Series B preferred shares on the amendment date. Under U.S. GAAP, NACG was accreting the initial fair value of the amended NAEPI Series B preferred shares of $45.9 million recorded on their amendment date (March 30,


		102

Notes to Consolidated Financial Statements

2006) to the December 31, 2011 redemption value of $69.6 million using the effective interest method, which was consistent with the treatment of the NAEPI Series B preferred shares as temporary equity in the financial statements of NAEPI. The accretion charge was recognized by NACG as a charge to minority interest (as opposed to retained earnings in the accounts of NAEPI) under U.S. GAAP and interest expense in NACG’s financial statements under Canadian GAAP.

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

f) Other matters

The tax effects of temporary differences under Canadian GAAP are described as future income taxes in these financial statements whereas such amounts are described as deferred income taxes under U.S. GAAP.

g) United States accounting pronouncements recently adopted

In June 2006, the Financial Accounting and Standards Board (“FASB”) issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109” (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition requirements. FIN 48 was effective for the Company’s fiscal year ended March 31, 2008. The adoption of this standard did not have a material impact on the Company’s financial statements and disclosures required under the standard are provided in note 19 to the consolidated financial statements.

Effective April 1, 2008, the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements”, which defines fair value, establishes a framework and prescribes methods for measuring fair value and outlines the additional disclosure requirements on the use of fair value measurements. Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for an asset or liability in an orderly transaction between market participants at the measurement date. SFAS 157 establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs market participants would use in valuing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions about the factors market participants would use in valuing the asset or liability developed based upon the best information available in the circumstances. SFAS 157 establishes a three-level fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of fair value hierarchy based on the reliability of inputs are as follows:

Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities;

Level 2 inputs are significant observable inputs other than quoted prices included in level 1, such as quoted prices for similar assets and liabilities in active markets; quoted prices for identical or similar assets and liabilities in markets that are not active; or other inputs that are observable or can be corroborated by observable market data; and

Level 3 inputs are significant unobservable inputs that reflect the reporting entity’s own assumptions and are supported by little or no market activity.


				103

Notes to Consolidated Financial Statements

The Company has segregated all financial assets and 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 in the table below. FASB Staff Position (“FSP”) No. 157-2 delayed the effective date of the provisions of SFAS No. 157 for non-financial assets and liabilities that are not re-measured at fair value on a recurring basis until April 1, 2009. Financial assets and liabilities measured at fair value as at March 31, 2009 in the financial statements on a recurring basis are summarized below:


Description	Carrying value		Level I	Level II		Level III
Cross currency and interest rate swaps for US dollar 8³/4% senior notes	$39,547		$ –	$39,547		$ –
Embedded price escalation features in a long term revenue construction contract	(324	)	–	(324	)	–
Embedded price escalation features in long term supplier contract	22,778		–	22,778		–
Embedded prepayment and early redemption options on senior notes	3,716		–	3,716		–

	$65,717		$ –	$65,717		$ –

The Company has determined that the fair value of its U.S. $ denominated senior notes are considered a level 1 measurement as these are traded in an active market.

Since the Company primarily uses observable inputs in its valuation of its derivative financial instruments, they are valued using Level 2 inputs. The fair values of the Company’s cross-currency and interest rate swap agreements and the Company’s embedded derivatives are based on appropriate price modeling commonly used by market participants to estimate fair value. Such modeling includes option pricing models and discounted cash flow analysis, using observable market based inputs to estimate fair value. The Company considers its own credit risk or the credit risk of the counterparty in determining fair value, depending on whether the fair values are in an asset or liability position. Fair value determined using valuation models requires the use of assumptions concerning the amount and timing of future cash flows. Fair value amounts reflect management’s best estimates using external readily observable market data such as future prices, interest rate yield curves, foreign exchange rates and discount rates for time value. It is possible that the assumptions used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be material. We used the following inputs to estimate the fair value of each class of Level II financial instruments:

The fair values of the Company’s cross-currency and interest rate swap agreements are based on appropriate price modeling commonly used by market participants to estimate fair value. The fair values the Company’s interest rate swap agreements are estimated using discounted cash flow analysis with inputs of observable market data including future interest rates, implied volatilities and the credit risk of the Company or the counterparties as appropriate with resulting valuations periodically validated through third-party or counterparty quotes. The fair values of cross-currency swaps are estimated using discounted cash flow analysis with inputs of observable market data including foreign currency exchange rates, implied volatilities, interest rates and the credit risk of the Company or the counterparties as appropriate, with resulting valuations periodically validated through third-party or counterparty quotes;

The fair value of the Company’s optional redemption rights included in the senior notes have been estimated using discounted cash flow analysis with input of observable market data including foreign currency exchange rates, implied volatilities and interest rates; and

Currently, the Company has not measured the fair value of any financial instruments using Level 3 (significant unobservable) inputs.

In early October 2008, the FASB issued FSP No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active,” which amended SFAS No. 157 to illustrate key considerations in determining the fair value of a financial asset in an inactive market. This FSP was effective for the Company beginning with the quarter ended September 30, 2008. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”) was issued in February 2007. The statement permits entities to choose to measure many financial instruments and certain other items at fair value, providing the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without the need to apply hedge accounting provisions. SFAS 159 is effective for fiscal years beginning after November 15, 2007, specifically April 1, 2008 for the Company. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.


		104

Notes to Consolidated Financial Statements

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement 133” (“SFAS 161”) was issued March 2008. SFAS 161 is effective for interim or annual periods beginning after November 15, 2008. The statement requires companies with derivative instruments to disclose information about how and why a company uses derivative instruments, how derivative instruments and related hedged items are accounted for under Statement 133, and how derivative instruments and related hedged items affect our financial position, financial performance and cash flows. The required disclosures include the fair value of derivative instruments and their gains or losses in tabular format, information about credit-risk-related contingent features in derivative agreements, counterparty credit risk, and the Company’s strategies and objectives for using derivative instruments. The Statement expands the current disclosure framework in Statement 133. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles”. The statement identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements in accordance with U.S. GAAP. This statement was effective for the Company on November 15, 2008, which is 60 days after the Securities and Exchange Commission’s approval of Auditing Standard No. 6, Evaluating Consistency of Financial Statements. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

i) Recent United States accounting pronouncements not yet adopted (US GAAP)

SFAS No. 141R, “Business Combinations” (“SFAS 141R”) was issued December 2007. SFAS No. 141R is effective for the fiscal year beginning April 1, 2009. The statement establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree, and any goodwill. This statement establishes disclosure requirements that will enable users of the Company’s financial statements to evaluate the nature and financial effects of the business combination. The Company is currently evaluating the impact of this standard on its consolidated financial statements.

SFAS No. 160 “Non-controlling Interests in Consolidated Financial Statements – An Amendment of ARB No. 51” (“SFAS 160”) was issued December 2007. SFAS 160 is effective for the fiscal year beginning April 1, 2009. This statement changes the accounting and reporting for ownership interests in subsidiaries held by parties other than the parent. These non-controlling interests are to be presented in the consolidated statement of financial position within equity but separate from the parent’s equity. The amount of consolidated net income attributable to the parent and to the non-controlling interest is to be clearly identified and presented on the face of the consolidated statement of operations. In addition, this statement establishes standards for a change in a parent’s ownership interest in a subsidiary and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. The statement also establishes reporting requirements for providing sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. The Company is currently evaluating the impact of this standard on its consolidated financial statements.

SFAS No. 165 “Subsequent Events” (“SFAS 165”) was issued in May 2009. SFAS 165 is effective for interim or annual financial periods ending after June 15, 2009 and should be applied prospectively. This statement addresses accounting and disclosure requirements related to subsequent events. This statement also requires the Company to evaluate subsequent events through the date the financial statements are either issued or available to be issued, depending on the Company’s expectation of whether it will widely distribute its financial statements to its shareholders and other financial statement users. Companies will be required to disclose the date through which subsequent events have been evaluated. The Company is currently evaluating the impact of this standard on its consolidated financial statements.

In April 2008, the FASB issued FSP No. FAS 142-3, “Determination of the Useful Life of Intangible Assets,” which amends the list of factors an entity should consider in developing renewal or extension assumptions used in determining the useful life of recognized intangible assets under SFAS No. 142, “Goodwill and Other Intangible Assets.” The new guidance applies to (1) intangible assets that are acquired individually or with a group of other assets and (2) intangible assets acquired in both business combinations and asset acquisitions. Under FSP No. FAS 142-3, entities estimating the useful life of a recognized intangible asset must consider their historical experience in renewing or extending similar arrangements or, in the absence of historical experience, must consider assumptions that market participants would use about renewal or extension. For the Company, this FSP will require certain additional disclosures beginning April 1, 2009 and application to useful life estimates prospectively for intangible assets acquired after March 31, 2009. The Company is currently evaluating the impact of this standard on its consolidated financial statements.

In April 2009, the FASB issued FSP No. FAS 107-1 and APB 28-1 “Interim Disclosures about Fair Value of Financial Instruments” which amends FASB Statement No. 107 “Disclosures about Fair Value of Financial Statements” to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. It also amends APB Opinion No. 28 “Interim Financial Reporting” to require those disclosures in summarized financial information at interim reporting periods. The FSP is effective for interim and annual periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009 in certain circumstances. This FSP is effective for our quarter ending June 30, 2009. The Company is currently evaluating the impact of this FSP on its consolidated financial statements.


				105

Notes to Consolidated Financial Statements

In April 2009, the FASB issued FSP No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”, which provides additional guidance for estimating fair value in accordance with FASB Statement No. 157, “Fair Value Measurements”, when the volume and level of activity for the asset or liability have significantly decreased. It also includes guidance on identifying circumstances that indicate a transaction is not orderly. FSP No. FAS 157-4 requires that:

The Company should disclose in interim and annual periods the inputs and valuation techniques used to measure fair value and a discussion of changes in valuation techniques and related inputs, if any, during the period.

Define major category for equity securities and debt securities to be major security types as per FAS 115 and FAS 124-2.

The FSP shall be effective for interim and annual periods ending after June 15, 2009 and shall be applied prospectively. For the Company this Statement is effective for the quarter ending June 30, 2009. Early adoption is permitted for periods ending after March 15, 2009 in certain circumstances. The Company is currently evaluating the impact of this FSP on its consolidated financial statements.

In April 2009, the FASB issued FSP No. FAS 115-2 and FAS 124-2 “Recognition and Presentation of Other-Than-Temporary Impairments”, which amends the other-than-impairment guidance in U.S. GAAP for debt securities to make the guidance more operational and to improve the presentation and disclosure of the other- than-temporary impairments on debt and equity securities in the financial statements. The FSP applies to debt securities classified as available-for-sale and held-to-maturity that are subject to other than temporary impairment guidance within FAS 115. The FSP is effective for interim and annual reporting periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009 in certain circumstances. This FSP is effective for our quarter ending June 30, 2009. The Company is currently evaluating the impact of this standard on its consolidated financial statements.

In April 2009, the FASB issued FSP No. FAS 141 (R)-1 “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies”, to amend and clarify SFAS No. 141(R) “Business Combinations”. It addresses the application issues on initial recognition and measurement, subsequent measurement and accounting and disclosure of assets and liabilities arising from contingencies in a business combination. This FSP is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after April 1, 2009. The Company is currently evaluating the impact of this standard on its consolidated financial statements.

33. Subsequent event

On June 24, 2009, the Company entered into an amended and restated credit agreement with a syndicate of Canadian financial institutions. The amended facility extends the maturity date of the prior facility by an additional year to June 8, 2011.

The total amount of the credit facility remains unchanged at $125 million and includes a $75 million revolving facility and a $50 million non-revolving term facility. The term facility commitments are available until August 31, 2009. Any undrawn amount under the term facility, up to a maximum of $15 million, may be reallocated to the revolving facility.

The credit facility is secured by a first priority lien on substantially all of the Company’s existing and after-acquired property and contains certain restrictive covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions or to pay dividends or redeem share of capital stock. The Company is also required to meet certain financial covenants under the new credit agreement.


		106

LOGO

Ronald A. McIntosh

Director since

May 2004

Chair of the Board

of Directors

North American Energy Partners Inc. Corporate Information 107

Board of Directors

John D. Hawkins

Director since

October 2003

Chair of the

Governance Committee

William C. Oehmig

Director since

November 2003

Chair of the

Risk Committee

George R. Brokaw

Director since

June 2006

John A. Brussa

Director since

November 2003

Peter R. Dodd

Director since

June 2009

Peter W. Tomsett

Director since

September 2006

Chair of the

Compensation Committee

Rodney J. Ruston

Director since

May 2005

President and CEO

Allen R. Sello

Director since

January 2006

Chair of the

Audit Committee

K. Rick Turner

Director since

November 2006

LOGO

Rodney J. Ruston

President and

Chief Executive Officer

Bernard T. Robert

Vice President,

Corporate Affairs and

Business Strategy

108 Corporate Information North American Energy Partners Inc.

Senior Management

David Blackley

Chief Financial Officer

Robert G. Harris

Vice President,

Human Resources,

Health, Safety &

Environment

Kevin R. Mather

Vice President,

Supply Chain and

Estimating

Christopher R. Yellowega

Vice President,

Operations

LOGO

Corporate Headquarters

Zone 3

Acheson Industrial Area

2 - 53016 - Hwy. 60

Acheson, Alberta T7X 5A7

Phone: 780.960.7171

Fax: 780.960.7103

Auditors

KPMG LLP

Edmonton, Alberta

Solicitors

Bracewell & Giuliani LLP

Houston, Texas

Borden Ladner Gervais LLP

Toronto, Ontario

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 S.W

Calgary, Alberta

Phone: 403.232.2400

Email: inquiries@cibcmellon.com

Web: www.cibcmellon.com

Investor Relations

Kevin Rowand

Phone: 780.960.4531

Fax: 780.960.7103

E-mail: IR@nacg.ca

Web: www.nacg.ca

Annual General Meeting

The Annual General Meeting of

North American Energy Partners Inc.

will be held at:

The Calgary Petroleum Club,

319 - 5th Avenue SW, Calgary, Alberta

Thursday, September 24, 2009

at 4:00 p.m.

Corporate Information Investor Information

LOGO

Printed in Canada

NORHT AMERICAN