NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the year ended March 31, 2012

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Table of Contents

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

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Management’s Discussion and Analysis

For the year ended March 31, 2012

A. EXPLANATORY NOTES

June 6, 2012

The following Management’s Discussion and Analysis (MD&A) is as of June 6, 2012 and should be read in conjunction with the attached audited consolidated financial statements for the year ended March 31, 2012 and notes that follow. These statements have been prepared in accordance with United States (US) generally accepted accounting principles (GAAP). Except where otherwise specifically indicated, all dollar amounts are expressed in Canadian dollars. For additional information and details, readers are referred to the unaudited consolidated financial statements and notes there to, as well as the accompanying interim period MD&A for each interim period of fiscal 2012. The audited consolidated financial statements and additional information relating to our business, including our most recent Annual Information Form (AIF), are available on the Canadian Securities Administrators’ SEDAR System at www.sedar.com, the Securities and Exchange Commission’s website at www.sec.gov and our company website at www.nacg.ca.

Caution Regarding Forward-Looking Information

Our MD&A is intended to enable readers to gain an understanding of our current results and financial position. To do so, we provide information and analysis comparing results of operations and financial position for the current year to those of the preceding two fiscal years. We also provide analysis and commentary that we believe is necessary to assess our future prospects. Accordingly, certain sections of this report contain forward-looking information that is based on current plans and expectations. This forward-looking information is affected by risks, assumptions and uncertainties that could have a material impact on future prospects. Please refer to “Forward-Looking Information, Assumptions and Risk Factors” for a discussion of the risks, assumptions and uncertainties related to such information. Readers are cautioned that actual events and results may vary.

Non-GAAP Financial Measures

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

Consolidated EBITDA is defined as EBITDA, excluding the effects of unrealized foreign exchange gain or loss, realized and unrealized gain or loss on derivative financial instruments, non-cash stock-based compensation expense, gain or loss on disposal of plant and equipment, the impairment of goodwill, the amendment related to the fiscal 2011 $42.5 million revenue writedown on the Canadian Natural¹ overburden removal contract (described in the “Explanatory Notes–Significant Business Event” section of this MD&A) and certain other non-cash items included in the calculation of net income.

We believe that EBITDA is a meaningful measure of the performance of our business because it excludes items, such as interest, income taxes, depreciation and amortization that are not directly related to the operating performance of our business. Management reviews EBITDA to determine whether plant and equipment are being allocated efficiently. In addition, our credit facility requires us to maintain a minimum interest coverage ratio and a maximum senior leverage ratio, both of which are calculated using Consolidated EBITDA. Non-compliance with these financial covenants could result in a requirement to immediately repay all amounts outstanding under our credit facility.

As EBITDA and Consolidated EBITDA are non-GAAP financial measures, our computations of EBITDA and Consolidated EBITDA may vary from others in our industry. EBITDA and Consolidated EBITDA should not be considered as alternatives to operating income or net income as measures of operating performance or cash flows as measures of liquidity. EBITDA and Consolidated EBITDA have important limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under US GAAP. For example, EBITDA and Consolidated EBITDA do not:

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

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

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

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

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

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

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Consolidated EBITDA excludes unrealized foreign exchange gains and losses and realized unrealized gains and losses on derivative financial instruments, which, in the case of unrealized losses may ultimately result in a liability that may need to be paid and in the case of realized losses, represents an actual use of cash during the period.

Where relevant, particularly for earnings-based measures, we provide tables in this document that reconcile non-GAAP measures used to amounts reported on the face of the consolidated financial statements.

Significant Business Event

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

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

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

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

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

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

• $8.5 million reduction in inventory.

• $16.5 million reduction of unbilled revenue.

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

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

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

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

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

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

B. Business Overview

Business Overview

We provide a wide range of heavy construction and mining, piling and pipeline installation services to customers in the Canadian oil sands, industrial construction, commercial and public construction and pipeline construction markets. Our primary market is the Canadian oil sands, where we support our customers’ mining operations and capital projects. While we provide services through all stages of an oil sands project’s lifecycle, our core focus is on providing recurring services, such as contract mining, during the operational phase. For the year ended March 31, 2012, recurring services represented 87% of our oil sands business. Our principal oil sands customers include all four producers that are currently mining bitumen in Alberta: Syncrude², Suncor³, Shell⁴ and Canadian Natural. We focus on building long-term relationships with our customers and have provided services to each of them since inception of their respective projects. In the case of Syncrude and Suncor, these relationships span over 30 years.

We believe that we operate the largest fleet of equipment of any contract resource services provider in the oil sands. Our total fleet (owned, leased and rented) includes approximately 900 pieces of diversified heavy construction equipment supported by over 750 pieces of ancillary equipment. While our expertise covers mining, heavy construction, tailings management and mine reclamation services, underground services installation (fire lines, sewer, water, etc.) for industrial projects and piling and pipeline installation in many different locations, we have a specific capability operating in the harsh climate and difficult terrain of northern Canada, particularly in the Canadian oil sands.

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

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

Five Year Business Performance

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

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

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

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

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

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

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

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

³  Suncor Energy Inc. (Suncor).

⁴  Shell Canada Energy (Shell), a division of Shell Canada Limited, which is the operator of the oil sands mining and extraction operations on behalf of Athabasca Oil Sands Project (AOSP), a joint venture amongst Shell Canada Limited (60%), Chevron Canada Limited (20%) and Marathon Oil Corporation (20%).

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

Our Strategy

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

Operations Overview

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

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

Heavy Construction and Mining

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

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

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

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

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

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

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

Piling

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

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

Pipeline

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

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

Revenue by Source

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

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

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

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

Project Development Services Revenue

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

Recurring Services Revenue

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

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

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

Revenue by End Market

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

i. Canadian oil sands;

ii. Commercial and public construction;

iii. Industrial construction; and

iv. Pipeline construction.

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

Canadian Oil Sands Market

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

Oil sands are grains of sand covered by a thin layer of water and coated by heavy oil or bitumen. Bitumen, because of its structure, requires extraction techniques to separate it from the sand and other foreign matter. There are currently two main methods of extraction: (i) open pit mining, where bitumen deposits are sufficiently close to the surface to make it economically viable to recover the bitumen by treating mined sand in a surface plant; and (ii) in situ technology, where bitumen deposits are buried too deep for open pit mining to be cost effective. Operators instead inject steam into the deposit, lowering the viscosity of the bitumen so that the bitumen can be separated from the sand and pumped to the surface, leaving the sand in place. The choice of extraction method is entirely based on the geographic features of the land and the two methods are not interchangeable.

CAPP estimates that approximately half of 2011 oil sands production was extracted from five active mining projects, while the remaining half was extracted from approximately 17 active in situ projects. While the number of active and planned in situ projects far exceeds the number of mining projects, future total production from mining and in situ technology is expected to remain approximately equal according to CAPP and other industry estimates. This reflects the significantly larger size and higher production of the mining projects.

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

The requirement for recurring services typically grows as mines age. Mine operators tend to construct their plants closest to the easy-to-access bitumen deposits (less overburden and/or higher quality bitumen) to maximize profitability and cash flow at the beginning of their projects. As the mines move through their lifecycle, easy-to-access, high-quality bitumen deposits are depleted and operators must go greater distances and move more material to secure the required volume of oil sand to feed the plant at capacity.⁶ As a result, the total capacity of digging and hauling equipment must increase, together with an increase in the ancillary equipment and services needed to support these activities. In addition, as the mine extends to new areas, operators will often relocate mine infrastructure in order to reduce haul distances. This creates demand for mine construction services in the expansion area, as well as reclamation services to remediate the mined-out area. Accordingly, the demand for recurring oil sands services grows even during periods of stable production because the geographical footprints of existing mines expands under normal operation.

Current Canadian Oil Sands Business Conditions

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

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

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

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

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

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

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

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

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

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

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

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

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

Commercial and Public Construction Market

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

Current Commercial and Public Construction Business Conditions

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

Industrial Construction Market

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

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

¹¹  Husky Energy Inc.’s (Husky Energy) Sunrise Oil Sand project is a 50/50 joint venture with BP Canada Energy Company (BP), a wholly owned subsidiary of BP PLC. The Sunrise project is operated by Husky Energy.

¹²  ConocoPhillips Canada Resources Corporation’s (ConocoPhillips) Surmount Oil Sand in situ project is a 50/50 joint venture between ConocoPhillips Canada, a wholly owned subsidiary of ConocoPhillips Company and Total. ConocoPhillips Canada is the project operator.

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

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

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

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

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

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

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

Current Industrial Construction Business Conditions

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

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

Pipeline Construction Market

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

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

Current Pipeline Construction Business Conditions

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

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

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

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

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

¹⁹  TransCanada Pipelines Limited (TransCanada)

8 2012 Annual Report

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C. Financial Results

Summary of Consolidated Annual Results

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

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

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

Revenue

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

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

2012 Annual Report 9

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

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

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

Gross profit

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

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

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

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

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

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

Operating (loss) income

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

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Net (loss) income

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

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

Net income of $28.2 million for the year ended March 31, 2010 was positively affected by the foreign exchange impact of the strengthening Canadian dollar on our 8 ³/4% senior notes, gains on the interest rate swaps, gains relating to embedded derivatives in long-term supplier contracts and the redemption option in our 8 ³/4% senior notes. These items were partially offset by a loss on our cross-currency swaps and a loss relating to embedded derivatives in a long-term customer contract. Excluding the non-cash items, net income for the year ended March 31, 2010 would have been $20.9 million (basic income per share of $0.58 and diluted income per share of $0.57).

Segment Annual Results

Heavy Construction and Mining

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

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

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

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

• increased site services and overburden removal activity at Syncrude;

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

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

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

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

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

• a high volume of summer muskeg removal activity.

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

2012 Annual Report 11

These gains were partially offset by:

• the negative impact of wildfires in the first quarter;

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

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

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

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

Piling

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

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

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

Pipeline

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

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

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

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

Summary of Consolidated Three Month Results

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

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

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

Revenue

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

2012 Annual Report 13

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

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

Gross profit (loss)

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

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

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

Operating loss

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

Net loss

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

Segment Three Month Results

Heavy Construction and Mining

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

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

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

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

Piling

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

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

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

Pipeline

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

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

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

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Non-Operating Income and Expense

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

Interest expense

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

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

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

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

Foreign exchange (gain) loss

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

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Realized and unrealized (gain) loss on derivative financial instruments

The realized and unrealized (gain) loss on derivative financial instruments reflects changes in the fair value of derivatives embedded in our previously outstanding US dollar denominated 8 ³/4% senior notes, as well as changes in the fair value of the cross-currency and interest rate swaps that we employed to provide an economic hedge for those senior notes. Realized and unrealized gains and losses also include changes in the value of embedded derivatives in long-term customer contracts and in supplier maintenance agreements. The realized and unrealized gains and losses on these derivative financial instruments, for the three months and years ended March 31, 2012 and 2011, respectively and the year ended March 31, 2010, are detailed in the table below:

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

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

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

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

With respect to the supplier contracts, the fair value of the embedded derivative related to long-term supplier contracts decreased as a result of the strengthening of the Canadian dollar against the US dollar during the three months ended March 31, 2012 and 2011, respectively. Included in the embedded derivative valuation was the impact of fluctuations in provisions that require a price adjustment to reflect changes in the Canadian/US dollar exchange rate and the United States government published Producers’ Price Index (US-PPI) for Mining Machinery and Equipment from the original contract amount.

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

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

Income tax (benefit) expense

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

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For the three months and year ended March 31, 2012, income tax expense as a percentage of income before income taxes differed from the statutory rate of 26.25%. This difference is primarily due to the impact of changes in enacted tax rates, CRA audit adjustments from 2007 and 2008, which flow through the current and deferred income tax accounts, and an increase in the permanent differences in stock-based compensation resulting from a partial restructuring of the stock option plan. For the three months ended March 31, 2011, income tax expense as a percentage of income before income taxes differed from the statutory rate of 27.75% primarily due to the changes in the timing of the reversal of temporary differences. For the year ended March 31, 2011, income tax expense as a percentage of income before income taxes differed from the statutory rate of 27.75%, largely due to the same factors affecting the year ended March 31, 2012. For the year ended March 31, 2010, income tax as a percentage of income before income taxes differed from the statutory rate of 28.91% primarily due to the impact of income tax adjustments and reassessments, non-deductible items and changes in the timing of reversal of temporary differences.

Backlog

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

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

Our measure of backlog does not define what we expect our future workload to be. We work with our customers using cost-plus, time-and-materials, unit-price and lump-sum contracts. This mix of contract types varies year-by-year. Our definition of backlog results in the exclusion of a range of services to be provided under cost-plus and time-and-material contracts performed under master services agreements where scope is not clearly defined. For the three months and year ended March 31, 2012, the total amount of revenue earned from time-and-material contracts performed under our master services agreements, which are not in backlog, was approximately $38.8 million and $249.2 million respectively.

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

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

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

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

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

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

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Claims and Change Orders

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

• changes in client requirements, specifications and design;

• changes in materials and work schedules; and

• changes in ground and weather conditions.

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

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

For the three months and year ended March 31, 2012, the Heavy Construction and Mining segment had approximately $1.4 million and $11.2 million respectively in claims revenue recognized to the extent of costs incurred, the Piling segment had $0.2 million and $2.6 million respectively in claims revenue recognized to the extent of costs incurred and the Pipeline segment had $6.4 million and $21.4 million respectively in claims revenue recognized to the extent of costs incurred.

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

Summary of Consolidated Quarterly Results

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

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

• seasonal weather and ground conditions;

• the timing of equipment maintenance and repairs;

• claims and change-orders; and

• the accounting for unrealized non-cash gains and losses related to foreign exchange and derivative financial instruments.

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

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

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

We generally experience a decline in revenues during the first three months of each fiscal year due to seasonality, as weather conditions make performance in our operating regions difficult during this period. The level of activity in the Heavy Construction and Mining and Pipeline segments declines when frost leaves the ground and many secondary roads are rendered temporarily incapable of supporting the weight of heavy equipment. The duration of this period, which can vary considerably from year to year, is referred to as “spring breakup” and has a direct impact on our activity levels. Revenues during the three months ended March 31 of each fiscal year are traditionally highest as ground conditions are most favourable in our operating regions. It should be noted that weather conditions during this period in each of the past two fiscal years have been unusual, causing results to deviate from this pattern. Overall, full-year results are not likely to be a direct multiple or combination of any one quarter or quarters. In addition to revenue variability, gross margins can be negatively impacted in less active periods because we are likely to incur higher maintenance and repair costs due to our equipment being available for servicing.

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

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

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

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

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

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

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

Variations in quarterly results can also be caused by changes in our operating leverage. During periods of higher activity, we have experienced improvements in operating margin. This reflects the impact of relatively fixed costs, such as G&A, being spread over higher revenue levels. If activity decreases, these same fixed costs are spread over lower revenue levels. Both net income and income per share are also subject to financial leverage as provided by fixed interest expense.

Summary of Consolidated Financial Position

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

‡ Total long-term financial liabilities exclude the current portions of capital lease obligations, current portions of derivative financial instruments, long-term lease inducements, asset retirement obligations and both current and non-current deferred income tax balances.

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

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

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

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

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

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

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

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

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

• $34.1 million for contract settlement

• $4.3 million for outstanding change-order settlement

• $3.0 million for mobilization costs

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

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

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

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

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

Summary of Consolidated Equipment Additions

We acquire our equipment in three ways: capital expenditures, capital leases and operating leases. Capital expenditures require the outflow of cash for the full value of the equipment at the time of purchase while capital leases and operating leases are varying ways of financing those capital expenditures.

We define our equipment requirements as either:

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

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

2012 Annual Report 21

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

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

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

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

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

Summary of Consolidated Cash Flows

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

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

Operating activities

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

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

Investing activities

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

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

Financing activities

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

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

Foreign currency translation loss on cash

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

2012 Annual Report 23

D. OUTLOOK

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

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

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

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

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

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

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

E. LEGAL AND LABOUR MATTERS

Laws and Regulations and Environmental Matters

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

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

• building and similar codes and zoning ordinances;

• laws and regulations relating to consumer protection; and

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

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

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

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

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The nature of our operations and our ownership or operation of property exposes us to the risk of claims with respect to environmental matters and there can be no assurance that material costs or liabilities will not be incurred in relation to such claims. For example, some laws can impose strict joint and several liability on past and present owners or operators of facilities at, from or to which a release of hazardous substances has occurred, on parties who generated hazardous substances that were released at such facilities and on parties who arranged for the transportation of hazardous substances to such facilities. If we were found to be a responsible party under these statutes, we could be held liable for all investigative and remedial costs associated with addressing such contamination, even though the releases were caused by a prior owner or operator or third party. We are not currently named as a responsible party for any environmental liabilities on any of the properties on which we currently perform or have performed services. However, our leases typically include covenants that obligate us to comply with all applicable environmental regulations and to remediate any environmental damage caused by us to the leased premises. In addition, claims alleging personal injury or property damage may be brought against us if we cause the release of or any exposure to harmful substances.

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

Capital expenditures relating to environmental matters during the fiscal years ended March 31, 2010, 2011 and 2012 were not material. We do not currently anticipate any material adverse effect on our business or financial position because of future compliance with applicable environmental laws and regulations. Future events, however, such as changes in existing laws and regulations or their interpretation, more vigorous enforcement policies of regulatory agencies or stricter or different interpretations of existing laws and regulations may require us to make additional expenditures which may or may not be material.

Employees and Labour Relations

As of March 31, 2012, we had 743 salaried employees and approximately 2,270 hourly employees. Our hourly workforce fluctuates according to the seasonality of our business and the staging and timing of projects by our customers. The hourly workforce typically ranges in size from 1,000 employees to approximately 3,500 employees depending on the time of year and duration of awarded projects. We also utilize the services of subcontractors in our construction business. Subcontractors perform an estimated 8% to 10% of the construction work we undertake. As of March 31, 2012, approximately 2,050 employees are members of various unions and work under collective bargaining agreements.

The majority of our work is carried out by employees governed by our mining overburden collective bargaining agreement with the International Union of Operating Engineers (IUOE) Local 955, the primary term of which expires on March 31, 2015. Other collective agreements in operation include the provincial Industrial, Commercial and Institutional (ICI) agreements in Alberta and Ontario with both the Operating Engineers and Labourers Unions, Piling sector collective agreements in Saskatchewan with the Operating Engineers, Pipeline sector agreements in both British Columbia and Alberta with the Christian Labour Association of Canada (CLAC) as well as an all-sector agreement with CLAC in Ontario. We are subject to other industry and specialty collective agreements under which we complete work and the primary terms of all of these agreements are currently in effect. The provincial collective agreement between the IUOE Local 955 and the Alberta Roadbuilders and Heavy Construction Association (ARBHCA) expires February 28, 2013.

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

F. RESOURCES AND SYSTEMS

Liquidity

Sources of liquidity

Our principal sources of cash are funds from operations and borrowings under our credit facility. As at March 31, 2012, our cash balance of $1.4 million was $0.7 million higher than our cash balance at March 31, 2011. We supplemented our cash requirements during the year ended March 31, 2012 through drawings from our Revolving Facility. As of March 31, 2012 there were outstanding borrowings of $20.3 million and issued and undrawn letters of credit of $15.0 million under the $105.7 million Revolving Facility and outstanding borrowings of $58.4 million ($68.4 million and $28.4 million at March 31, 2011 and 2010, respectively under the Term Facilities A more detailed discussion on the Revolving Facility and our Term Facilities can be found in “Credit facilities”, below.

We anticipate that we will likely have enough cash from operations to fund our expenses and capital additions for fiscal 2013. In the event that we require additional funding, we believe that any such funding requirements could be satisfied by the funds available from our Revolving Facility.^¿

Liquidity requirements

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

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

2012 Annual Report 25

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

Our equipment fleet value is currently split among owned (49%), leased (38%) and rented equipment (13%). Approximately 33.3% of our leased fleet value is specific to the Canadian Natural contract. This equipment mix is a change from the mix reported in previous periods because of the sale of contract-related assets to Canadian Natural and an increasing demand for specific types of rental equipment to support project development activity. Our equipment ownership strategy allows us to meet our customers’ variable service requirements while balancing the need to maximize equipment utilization with the need to achieve the lowest ownership costs.

We require between $50 million and $70 million annually for sustaining equipment additions and our total equipment additions typically range from $60 million to $130 million depending on our growth equipment requirements. We believe that our current fleet size and mix is in alignment with the current equipment demands from the commitment to Canadian oil sands development by the oil sands producers along with the commercial and industrial construction markets. We have continued to assess and adjust the size and mix of our fleet and we have assessed our growth capital needs for the coming fiscal year as we monitor the progress of start-up delays on oil sands development projects. Our estimate of our capital needs for the next fiscal year is approximately $70 million to $90 million.^¿

We typically finance approximately 20% to 30% of our total equipment additions through our operating and capital lease facilities and the remainder from cash flow from operations. We believe our operating and capital lease facilities and cash flow from operations will be sufficient to meet these requirements.^¿

Working capital fluctuations effect on liquidity

As at March 31, 2012, we had $19.1 million in trade receivables that were more than 30 days past due compared to $10.1 million as at March 31, 2011 and $7.5 million as at March 31, 2010. We have currently provided an allowance for doubtful accounts related to our trade receivables of $0.2 million ($nil at March 31, 2011 and $1.7 million at March 31, 2010). We continue to monitor the credit worthiness of our customers. To date our exposure to potential write downs in trade receivables has been limited to the financial condition of developers of condominiums and high-rise developments in our Piling segment.

As of March 31, 2012, an amount of $18.1 million ($72.0 million at March 31, 2011 and $52.6 million at March 31, 2010) is recognized within unbilled revenue relating to the Canadian Natural contract, whereby the normal operating cycle for this project is greater than one year. The unbilled balance will be invoiced to Canadian Natural over the life of the amended contract. The customer maintains the right to accelerate the purchase of contract-related assets and if such right is exercised, the unbilled amount related to the equipment purchased becomes due in full at such time.

Contract change management processes often lead to a timing difference between project disbursements and our ability to invoice our customers for executed change orders. Until the time of invoice, revenue for unexecuted change orders is recorded only to the extent of costs incurred within unbilled revenue. As of March 31, 2012, we had $22.8 million of unresolved claims and change orders recorded in unbilled revenue. This compares to $2.2 million and $0.8 million for the years ended March 31, 2011 and 2010, respectively. For a more detailed discussion on claims revenue refer to “Claims and Change Orders”.

The seasonality of our business usually causes a peak in activity levels between December and early February that can result in an increase in our working capital requirements from higher accounts receivable and unbilled revenue balances. Our working capital is also significantly affected by the timing of the completion of projects. In some cases, our customers are permitted to withhold payment of a percentage of the amount owing to us for a stipulated period of time (such percentage and time period is usually defined by the contract and in some cases provincial legislation). This amount acts as a form of security for our customers and is referred to as a “holdback”. Typically, we are only entitled to collect payment on holdbacks if substantial completion of the contract has been performed, there are no outstanding claims by subcontractors or others related to work performed by us and we have met the period specified by the contract (usually 45 days after completion of the work). However, in some cases, we are able to negotiate the progressive release of holdbacks as the job reaches various stages of completion. As at March 31, 2012, holdbacks totaled $32.1 million, up from $12.0 million and $3.9 million as at March 31, 2011 and 2010, respectively. Holdbacks represent 15.0% of our total accounts receivable as at March 31, 2012 (9.4% and 3.5% as at March 31, 2011 and 2010, respectively). The current year increase in holdbacks represents an increase in Piling and Pipeline segment projects and the timing of substantial completion.

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

26 2012 Annual Report

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Credit facilities

On April 30, 2010, as part of a debt restructuring plan we entered into a Fourth Amended and Restated Credit Agreement, which provides credit facilities in the form of two Term Facilities and an $85.0 million Revolving Facility, under which letters of credit may also be issued. A more detailed discussion on the debt restructuring can be found below in “Securities, Rights Plans and Agreements–Long-term debt restructuring”, below.

On September 30, 2011, we entered into a Second Amending Agreement to the Fourth Amended and Restated Credit Agreement to provide a temporary revolving credit facility addition of $25.0 million through March 31, 2012. This temporary addition increased the total revolving credit facility commitments from $85.0 million to $110.0 million and provided additional borrowing availability to meet working capital requirements and to accommodate the issuance of letters of credit. The amendment required that the receipt of contract settlement proceeds from Canadian Natural would be used to repay amounts outstanding on the temporary credit facility addition and permanently reduce available borrowing under this temporary facility addition by the amount of the repayment. In December of 2011, $4.3 million of settlement proceeds reduced borrowing available under the Revolving Facility to $105.7 million.

On March 27, 2012, we entered into a Third Amending Agreement to the Fourth Amended and Restated Credit Agreement to extend the maturity date of the credit agreement by six months to October 31, 2013. The amendment also provides relief from the agreement’s Consolidated EBITDA related covenants by temporarily amending the covenants. The amendment also extended the term of the temporary addition to our revolving credit facility to June 30, 2012. The new amendment eliminated the permanent reduction of the temporary credit facility by the receipt of proceeds from the Canadian Natural contract settlement. However, terms were added requiring that 55% of any proceeds from asset sales to Canadian Natural will be used to repay amounts outstanding on the temporary credit facility addition and permanently reduce the amount available for borrowing to $85.0 million. Asset sale proceeds were received from Canadian Natural on April 30, 2012, which permanently eliminated the $20.7 million temporary addition to our revolving credit facility on that date.

The Term Facilities include scheduled principal repayments totaling $10.0 million per year with $2.5 million paid on the last day of each quarter commencing June 30, 2010. Advances under the Revolving Facility may be repaid from time to time at our option. In addition, we must make annual payments within 120 days of the end of our fiscal year for 50% of Consolidated Excess Cash Flow (as defined in the credit agreement) to a maximum of $4.0 million. Based on the calculation of Consolidated Excess Cash Flow at March 31, 2012, we will not be required to make an additional principal payment. Outstanding aggregate borrowing on our two Term Facilities is $58.4 million as of March 31, 2012.

The facilities bear interest at variable rates, based on the Canadian prime rate plus the applicable pricing margin (as defined within the credit agreement). Interest on Canadian prime rate loans is payable monthly in arrears. Stamping Fees (as defined in the credit agreement) and interest on advances of Bankers’ Acceptances (as defined in the credit agreement) are paid in advance, at the time of issuance.

The applicable pricing margin (as defined within the credit agreement) is connected to our credit rating from Standard & Poor’s. As our credit rating was downgraded by this credit agency, there was a 1.5% increase in our pricing margin (as defined within the credit agreement) (see “Debt Ratings”, below).

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

Permitted debt and contingent obligations under the credit agreement covenants include, but are not limited to:

• 9.125% Series 1 Debentures at an aggregate principle amount not to exceed $225.0 million (see “9.125% Series 1 Debentures”, below);

• Capital leases aggregating to a maximum of $30.0 million at any one time;

• Operating leases entered into in the normal course of business; and

• Contingent obligations under our performance bonding program.

We are also required to meet certain financial covenants defined in the credit agreement including:

i. Senior Leverage Ratio (Senior Leverage to Consolidated EBITDA) which must be less than 2.0 times (temporarily increased to less than 2.75 times for March 31, 2012);

ii. Consolidated Interest Coverage Ratio (Consolidated EBITDA to Consolidated Cash Interest Expense) which must be greater than 2.5 times (temporarily reduced to greater than: 1.75 times for March 31, 2012; 2.00 times for June 30, 2012; 2.00 times for September 30, 2012; and 2.25 times for December 31, 2012); and

iii. Current Ratio (Current Assets to Current Liabilities) which must be greater than 1.25 times.

2012 Annual Report 27

Continued access to the facilities is not contingent on the maintenance of a specific credit rating. The definition of these covenants is unchanged from the previous Third Amended and Restated Credit Agreement. Based on the latest amended credit agreement we remain in compliance with all of the financial covenants on our credit agreement as of March 31, 2012.

Consolidated EBITDA is defined within the credit agreement to be the sum, without duplication, of (a) consolidated net income, (b) consolidated interest expense, (c) provision for taxes based on income, (d) total depreciation expense, (e) total amortization expense, (f) costs and expenses incurred by us in entering into the credit facility, (g) accrual of stock-based compensation expense to the extent not paid in cash or if satisfied by the issuance of new equity, (h) the non-cash currency translation losses or mark-to-market losses on any hedge agreement (defined in the credit agreement) or any embedded derivative, and (i) other non-cash items including goodwill impairment (other than any such non-cash item to the extent it represents an accrual of or reserve for cash expenditures in any future period) but only, in the case of clauses (b)-(i), to the extent deducted in the calculation of consolidated net income, less (i) the non-cash currency translation gains or mark-to-market gains on any hedge agreement or any embedded derivative to the extent added in the calculation of consolidated net income, and (ii) other non-cash items added in the calculation of consolidated net income (other than any such non-cash item to the extent it will result in the receipt of cash payments in any future period), (iii) the one-time $42.5 million March 31, 2011 revenue writedown of the Canadian Natural contract, all of the foregoing as determined on a consolidated basis in conformity with GAAP.

The credit facility may be prepaid in whole or in part without penalty, except for bankers’ acceptances, which are not pre-payable prior to their maturity. However, the credit facility requires prepayments under various circumstances, such as:

i. 100% of the net cash proceeds of certain asset dispositions;

ii. 100% of the net cash proceeds from our issuance of equity (unless the use of such securities’ proceeds is otherwise designated by the applicable offering document); and

iii. 100% of all casualty insurance and condemnation proceeds, subject to exceptions.

Borrowing activity under the Revolving Facility

As at March 31, 2012, our unused borrowing availability under the Revolving Facility was $70.4 million ($69.2 million at March 31, 2011 and $79.6 million at March 31, 2010).

i. Cash drawn under the revolving facility: During the year ended March 31, 2012, we used our Revolving Facility to finance our working capital requirements. At March 31, 2012, we had $20.3 million of borrowings outstanding on our Revolving Facility. For the three months ended March 31, 2012, the average amount of our borrowing on the Revolving Facility was $57.1 million with a weighted average interest rate of 6.8%. For the year ended March 31, 2012, the average amount of our borrowing on the Revolving Facility was $40.4 million with a weighted average interest rate of 6.6%. The average amount of our borrowing on the Revolving Facility is calculated based on the weighted average of the outstanding balances in the three month and year periods, respectively. The maximum end of month balance for any single month during the three months and year ended March 31, 2012 was $63.0 million.

ii. Letters of credit drawn under the revolving facility: As of March 31, 2012, we had issued $15.0 million ($12.3 million at March 31, 2011 and $10.4 million at March 31, 2010) in letters of credit under the Revolving Facility to support performance guarantees associated with customer contracts. One of our major long-term contracts allows the customer to require that we provide up to $15.0 million in letters of credit. As at March 31, 2012, we had no letters of credit outstanding in connection with this contract. This customer must provide a 60-day prior written notice to request any change in their letter of credit requirements.

Long-term Commitments

Contractual obligations and other commitments

Our principal contractual obligations relate to our long-term debt, capital and operating leases and supplier contracts. The following table summarizes our future contractual obligations, excluding interest payments, unless otherwise noted, as of March 31, 2012.

	Payments due by fiscal year
(dollars in thousands)	Total		2013		2014		2015		2016		2017 and after
Series 1 Debentures		$225,000		$          –		$            –		$          –		$        –		$225,000
Term facilities		58,446		10,000		48,446		–		–		–
Revolving facility		20,321		–		20,321		–		–		–
Capital leases (including interest)		11,721		4,693		2,230		1,938		2,209		651
Equipment and building operating leases		127,569		56,921		40,774		21,218		6,452		2,204
Supplier contracts		42,881		17,615		22,484		2,782		–		–
Total contractual obligations		$485,938		$89,229		$134,255		$25,938		$8,661		$227,855

28 2012 Annual Report

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The buyout of the operating leases related to the sale of contract-related assets to Canadian Natural, discussed under the “Explanatory Notes–Significant Business Event” section of our annual MD&A for the year ended March 31, 2012, did not reduce the future contractual obligations reported under “Equipment and building operating leases” in this table as the contract-related operating leases are scheduled to be bought out at the expiry of their lease terms.

For a discussion on term facilities and revolving facility see “Liquidity – Credit facilities”, above and for a discussion on Series 1 Debentures see “Securities, Rights Plans and Agreements – 9.125% Series 1 Debentures”, below.

Off-balance sheet arrangements

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

Securities, Rights Plans and Agreements

Capital structure

We are authorized to issue an unlimited number of Voting Common Shares and an unlimited number of Non-Voting Common Shares. As at March 31, 2012, there were 36,251,006 voting Common Shares outstanding. We had no Non-Voting Common Shares outstanding as at March 31, 2012. For a more detailed discussion of our share data, see “Outstanding Share Data ” in our most recent AIF, which section is expressly incorporated by reference into this MD&A.

Shareholder Rights Plan and Registration Rights Agreement

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

9.125% Series 1 Debentures

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

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

At any time prior to April 7, 2013, we may redeem up to 35% of the aggregate principal amount of the Series 1 Debentures, with the net cash proceeds of one or more of our public equity offerings (as defined in the trust indenture that governs the Series 1 Debentures) at a redemption price equal to 109.125% of the principal amount plus accrued and unpaid interest to the date of redemption, so long as:

i. at least 65% of the original aggregate amount of the Series 1 Debentures remains outstanding after each redemption; and

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

At any time prior to April 7, 2013, we may on one or more occasions redeem the Series 1 Debentures, in whole or in part, at a redemption price which is equal to the greater of:

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

b. 100% of the aggregate principal amount of Debentures redeemed, plus, in each case, accrued and unpaid interest to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

The Series 1 Debentures are redeemable at our option, in whole or in part, at any time on or after: April 7, 2013 at 104.563% of the principal amount; April 7, 2014 at 103.042% of the principal amount; April 7, 2015 at 101.520% of the principal amount; April 7, 2016 and thereafter at 100% of the principal amount; plus, in each case, interest accrued to the redemption date.

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

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

2012 Annual Report 29

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

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

Long-term debt restructuring

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

9.125% Series 1 Debentures

On April 7, 2010, we closed a private placement of Series 1 Debentures for gross proceeds of $225.0 million and net proceeds after commissions and related expenses of $218.1 million.

8 ³/4% Senior Notes Redemption

Beginning December 1, 2009, our 8 ³/4% senior notes were redeemable at 100% of the principal amount. On March 29, 2010, we issued a redemption notice to holders of the notes to redeem all outstanding 8 ³/4% senior notes and, on April 28, 2010, the notes were redeemed and cancelled. The redemption amount included the US$200.0 million principal outstanding and US$7.1 million of accrued interest.

In connection with the redemption of our 8 ³/4% senior notes, we wrote off unamortized deferred financing costs of $4.3 million.

Termination of Cross-Currency and Interest Rate Swaps

On April 8, 2010, we terminated the cross-currency and interest rate swaps associated with the 8 ³/4% senior notes. The payment to the counterparties required to terminate the swaps was $91.1 million and represented the fair value of the swap agreements, including accrued interest. A more detailed discussion of this cancellation can be found below in the “Foreign exchange risk” and “Interest rate risk” sections of “Quantitative and Qualitative Disclosures about Market Risk”.

$50.0 million Term Facility

On April 30, 2010, we entered into a fourth amended and restated credit agreement to extend the term of the credit agreement and also to add additional borrowings of up to $50.0 million through a second term facility within the credit facilities. At April 30, 2010, the second term facility was fully drawn at $50.0 million.

Debt Ratings

On March 5, 2012, Standard and Poor’s Ratings Services (“S&P”)²¹ downgraded our long-term corporate credit rating from ‘B+’ to ‘B-’ and the senior unsecured debt rating from ‘B+’ to ‘B-’. S&P changed the outlook on the corporate rating from ‘stable’ to ‘developing’ and the recovery rating on our Series 1 Debentures from ‘3’ to ‘4’. As part of its annual review, S&P updated its analysis on both our long-term corporate credit rating and the senior unsecured debt rating on May 30, 2012 and re-affirmed its previous ratings.

On March 2, 2012, Moody’s Investor Services, Inc. (Moody’s) downgraded both our Corporate Rating from B2 to B3 and our Series 1 Debentures Rating from B3 to Caa1. Moody’s has also changed its outlook on our corporate rating from ‘Stable’ to ‘Rating Under Review’ and its outlook on our Series 1 Debentures Rating from LDG5 to LDG4.

Our credit ratings from these two agencies are as follows:

Category	Standard & Poor’s	Moody’s
Corporate Rating	B-(‘developing’ outlook)	B3 (‘Rating Under Review’ outlook)
Series 1 Debentures	B-(recovery rating of “4”)	Caa1 (LGD≠ rating of “4”)

≠ Loss Given Default

A downgrade in our credit ratings, particularly the rating issued by S&P, will increase the interest rate payable on borrowings under our credit agreement, (see “Credit facilities”, above). Additionally, counterparties to certain agreements may require additional security or other changes in business terms if our credit ratings are downgraded. Furthermore, these ratings are required for us to access the public debt markets, and they affect the pricing of such debt. Any downgrade in our credit ratings from current levels could adversely affect our long-term financing costs, which in turn could adversely affect our ability to pursue business opportunities.

²¹  Standard and Poor’s Ratings Services (S&P), a division of The McGraw-Hill Companies, Inc.

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A credit rating is a current opinion of the credit worthiness of an obligor with respect to a specific financial obligation, a specific class of financial obligations, or a specific financial program (including ratings on medium-term note programs and commercial paper programs). It takes into consideration the credit worthiness of guarantors, insurers, or other forms of credit enhancement on the obligation and takes into account the currency in which the obligation is denominated. The opinion evaluates the obligor’s capacity and willingness to meet its financial commitments as they come due, and may assess terms, such as collateral security and subordination, which could affect ultimate payment in the event of default. A credit rating is not a statement of fact or recommendation to purchase, sell, or hold a financial obligation or make any investment decisions nor is it a comment regarding an issuer’s market price or suitability for a particular investor. A credit rating speaks only as of the date it is issued and can be revised upward or downward or withdrawn at any time by the issuing rating agency if it decides circumstances warrant a revision. Definitions of the categories of each rating and the factors considered during the evaluation of each rating have been obtained from each respective rating organization’s website.²²

Standard and Poor’s

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

A recovery rating of “4” for the Series 1 Debentures indicates an expectation for an average of 30% to 50% recovery in the event of a payment default.

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

economic and/or fundamental business conditions. An outlook is not necessarily a precursor of a rating change or future CreditWatch action. A Stable outlook means that a rating is not likely to change. A Negative outlook means that a rating may be lowered. A Developing outlook means there is a one-in-three chance the rating could be raised or lowered during the two-year outlook horizon.

Moody’s

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

LGD assessments are opinions about expected loss given default on fixed income obligations expressed as a percent of principal and accrued interest at the resolution of the default. An LGD assessment (or rate) is the expected LGD divided by the expected amount of principal and interest due at resolution. A LGD rating of “4” indicates a loss range of greater than or equal to 50% and less than 70%.

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

Related Parties

Advisory Agreements

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

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

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

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

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

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

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

²²  This debt rating information is current as of this report and we undertake no obligation to provide investors with updated information.

2012 Annual Report 31

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

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

Internal Systems and Processes

Evaluation of disclosure controls and procedures

Our disclosure controls and procedures are designed to provide reasonable assurance that information we are required to disclose is recorded, processed, summarized and reported within the periods specified under Canadian and US securities laws. They include controls and procedures designed to ensure that information is accumulated and communicated to management, including the President and Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosures.

An evaluation was carried out under the supervision of and with the participation of management, including the President and Chief Executive Officer and the Chief Financial Officer, regarding the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) under the US Securities Exchange Act of 1934, as amended, and in National Instrument 52-109 under the Canadian Securities Administrators Rules and Policies. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of March 31, 2012 such disclosure controls and procedures were effective.

Management’s report on internal control over financial reporting

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

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

As of March 31, 2012, we assessed the effectiveness of our ICFR. In making this assessment, we used the criteria set forth in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management has concluded that, as of March 31, 2012, our internal control over financial reporting is effective. Our independent auditor, KPMG LLP, has issued an audit report stating that we, as at March 31, 2012, maintained, in all material respects, effective internal control over financial reporting based on the criteria established in Internal Control-Integrated Framework issued by the COSO.

Material changes to internal controls over financial reporting

There have been no material changes to internal controls over financial reporting during the year ended March 31, 2012.

Critical Accounting Estimates

The preparation of financial statements in conformity with US GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period.

Significant estimates made by us include:

• Assessment of the percentage of completion on time-and-materials, unit-price and lump-sum contracts (including estimated total costs and provisions for estimated losses) and the recognition of claims and change orders on revenue contracts;

• Assumptions used to value free standing and embedded derivatives and other financial instruments;

• Assumptions used in periodic impairment testing; and

• Estimates and assumptions used in the determination of the allowance for doubtful accounts, the recoverability of deferred tax assets and the useful lives of property, plant and equipment and intangible assets.

Actual results could differ materially from those estimates.

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

32 2012 Annual Report

NOA

The complex judgments and estimates most critical to an investor’s understanding of our financial results and condition are contained within our significant accounting policies (described in detail in our audited consolidated financial statements for the year ended March 31, 2012 and notes that follow). Below is a summary of how we apply these critical accounting estimates in our significant accounting policies:

Revenue recognition policy

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

The length of our contracts varies from less than one year for typical contracts to several years for certain larger contracts. Contract project costs include all direct labour, material, subcontract and equipment costs and those indirect costs related to contract performance such as indirect labour, supplies, and tools. General and administrative expenses are charged to expense as incurred. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined.

The accuracy of our revenue and profit recognition in a given period is dependent on the accuracy of our estimates of the cost to complete each project. Cost estimates for all of our significant projects use a highly detailed “bottom up” approach and we believe our experience allows us to provide materially reliable estimates. There are a number of factors that can contribute to changes in estimates of contract cost and profitability. These changes are recognized in the period in which such adjustments are determined. The most significant of these include:

• the completeness and accuracy of the original bid;

• costs associated with added scope changes (to the extent contract remedies are unavailable);

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

• subcontractor performance issues;

• changes in economic indices used to estimate future costs-to-complete on longer-term contracts;

• changes in productivity expectations;

• site conditions that differ from those assumed in the original bid (to the extent contract remedies are unavailable);

• contract incentive and penalty provisions;

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

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

The foregoing factors as well as the mix of contracts at different margins may cause fluctuations in gross profit between periods. Substantial changes in cost estimates, particularly in our larger, more complex projects have had, and can in future periods have, a significant effect on our profitability.

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

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

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

i. a bona fide addition to contract value; and

ii. revenue that can be reliably estimated.

2012 Annual Report 33

These two conditions are satisfied when:

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

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

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

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

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

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

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

Our policy is to recognize revenue from the sale of our other products and services as follows:

• Revenue recognition from equipment rentals occurs when there is a written arrangement in the form of a contract or purchase order with the customer, a fixed or determinable sales price is established with the customer, performance requirements are achieved, and ultimate collection of the revenue is reasonably assured. Equipment rental revenue is recognized as performance requirements are achieved in accordance with the terms of the relevant agreement with the customer, either at a monthly fixed rate or on a usage basis dependent on the number of hours that the equipment is used;

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

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

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

Property, plant and equipment policy

The most significant estimates in accounting for property, plant and equipment are the expected useful life of the asset and the expected residual value. Most of our property, plant and equipment have long lives that can exceed 20 years with proper repair work and preventative maintenance. Useful life is measured in operating hours, excluding idle hours, and a depreciation rate is calculated for each type of unit. Depreciation expense is determined monthly based on daily actual operating hours. In determining the estimates of these useful lives, we take into account industry trends and company-specific factors, including changing technologies and expectations for the in-service period of certain assets. On an annual basis, we re-assess our existing estimates of useful lives to ensure they match the anticipated life of the equipment from a revenue-producing perspective. If technological change happens more quickly or in a different way than anticipated, we might have to reduce the estimated life of property, plant and equipment, which could result in a higher depreciation expense in future periods or we may record an impairment charge to writedown the value of property, plant and equipment.

Another key estimate is the expected cash flows from the use of an asset and the expected disposal proceeds in applying ASC 360, “Property, Plant and Equipment”, on the impairment and disposal of long-lived assets. This standard requires the recognition of an impairment loss for a long-lived asset when changes in circumstances cause its carrying value to exceed the total undiscounted cash flows expected from its use and disposition. An impairment loss, if any, is determined as the excess of the carrying value of the asset over its fair value. The valuation of long-lived assets requires us to exercise judgment in the determination of an asset group and in making assumptions about future results, including revenue and cash flow projections for an asset group.

Allowance for doubtful accounts receivable policy

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

Goodwill impairment policy

Impairment is tested at the reporting unit level by comparing the reporting unit’s carrying amount to its fair value. The process of determining fair value is subjective and requires us to exercise judgment in making assumptions about future results, including revenue and cash flow projections at the reporting unit level and discount rates. Generally, we test goodwill annually on October 1. It is our intention to continue to complete goodwill impairment testing annually on October 1 going forward or whenever events or changes in circumstances indicate that impairment may exist. We completed our most recent annual goodwill impairment testing on October 1, 2011. This impairment test showed that the fair value of the Piling reporting unit exceeded its carrying value.

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Financial instruments policy

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

We use derivative financial instruments to manage financial risks from fluctuations in exchange rates, interest rates and inflation. These instruments include embedded price escalation features in revenue and supplier contracts. In developing such escalators, we rely on industry standards, historical data and management’s experience. We use these price escalation features for risk management purposes only. We do not hold or issue derivative financial instruments for trading or speculative purposes. Derivative financial instruments are subject to standard credit terms and conditions, financial controls, management and risk monitoring procedures. These derivative financial instruments are not designated as hedges for accounting purposes and are recorded at fair value with realized and unrealized gains and losses recognized in the Consolidated Statement of Operations, Comprehensive Income (Loss) and Deficit.

Foreign currency translation policy

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

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

Accounting Pronouncements Recently Adopted

Revenue recognition

In October 2009, the FASB issued ASU No. 2009-13, “Revenue Recognition: Multiple-Deliverable Revenue Arrangements”, which addresses the accounting for multiple-deliverable arrangements to enable vendors to account for products or services separately rather than as a combined unit. The amendments establish a selling price hierarchy for determining the selling price of a deliverable. The amendments also eliminate the residual method of allocation and require that arrangement consideration be allocated at the inception of the arrangement to all deliverables using the relative selling price method. We adopted this ASU effective April 1, 2011. The adoption of this standard did not have a material effect on our consolidated financial statements.

Share based payment awards

In April 2010, the FASB issued ASU No. 2010-13, “Effect of Denominating the Exercise Price of Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades”, which clarifies that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. We adopted this ASU effective April 1, 2011. The adoption of this standard did not have a material effect on our consolidated financial statements.

Intangibles – goodwill and other

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

Business combinations

In December 2010, the FASB issued ASU No. 2010-29, “Disclosure of Supplementary Pro Forma Information for Business Combinations”, which amends ASC 805, “Business Combinations”, to require that pro-forma information be presented as if the business combination occurred at the beginning of the prior annual reporting period for the purposes of calculating both the current reporting period and the prior reporting period pro forma financial information. The ASU also requires the disclosure be accompanied by a narrative description of the nature and amount of material, nonrecurring pro forma adjustments. We adopted this ASU effective prospectively April 1, 2011. This standard will affect disclosures made for any business combinations on our consolidated financial statements for the interim periods and years after the effective date.

2012 Annual Report 35

Fair value measurement

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

Issued Accounting Pronouncements Not Yet Adopted

Goodwill impairment

In September 2011, the FASB amended the guidance on the annual testing of goodwill for impairment. The amended guidance will allow companies to assess qualitative factors to determine if it is more-likely-than-not that goodwill might be impaired and whether it is necessary to perform the two-step goodwill impairment test required under current accounting standards. The guidance will be effective for the year ending March 31, 2013, with early adoption permitted. We believe that this new guidance will not have a material impact on our consolidated financial statements.^¿

Offsetting Assets and Liabilities

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

Comprehensive income

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

G. Forward-Looking Information, Assumptions And Risk Factors

Forward-Looking Information

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

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

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

1. The anticipated $47.0 million of net proceeds from the sale of assets related to the Canadian Natural contract and the treatment of revenue recognition under the amended and original contract.

2. The anticipated $8 million to $10 million reduction in Canadian Natural contract-related lease and depreciation costs during fiscal 2013 and an equivalent reduction of contract revenue.

3. The expectation that part of the growth in oil sands capital spending will be driven by the development of new mines and the expansion of existing mine operations.

4. Canadian Natural and Syncrude are expected to increase spending on mine expansion, production improvement projects and tailing management projects in 2012, which could create further opportunities for our Heavy Construction and Mining segment in fiscal 2013.

5. CAPP’s forecast for oil production from oil projects is expected to support increased demand for recurring services.

6. Our belief that the impact of producers’ cost-control measures will likely be short-term.

7. Demand for certain types of recurring services, such as overburden removal and both wet tailings and mine reclamation activities, is expected to improve in fiscal 2013.

8. The expectation that TransCanada’s Keystone proposed southern extension to transport oil from Cushing to available refining capacity on the US Gulf Coast will be approved by the applicable US regulatory agencies.

9. Our belief that the construction of the southern extension will likely tie up available contractor capacity in the US and reduce bidding competition on pipeline projects that have been announced for Western Canada and that opportunities may arise from this to negotiate low-risk cost-plus or time-and-materials contracts, which could eliminate many of the risks posed by lump-sum contracts.

10. Our intention to pursue additional contract opportunities as they become available and the potential reduction in the number of competitors for certain of these contracts.

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

12. Our anticipation of steady activity levels and improved profitability.

13. The expected offset of continued demand for reclamation, tailings services, mine expansion projects and the resumption of overburden removal activity at Canadian Natural against a continued reduction in mine support activity.

14. Our expectations to maintain volumes with a variety of projects at Suncor and to ramp up production on the shear key foundation of the mine relocation project at Syncrude and the transition into the second phase of the relocation with construction of an MSE wall.

15. Our expectation to operate near full production throughout the year as a result of reaching final agreement on amendments to our Canadian Natural contract.

16. That Exxon’s Kearl project is expect to begin production in 2012 and create additional bidding opportunities for mine support services.

17. Our expectation to continue executing initial earthworks at the Joslyn North Mine Project.

18. Our intention to pursue opportunities for work at Fort Hills, PetroChina’s Dover SAGD project and on other SAGD projects, as such opportunities arise.

19. Our expectation that construction at the Mt. Milligan Copper/Gold Project will continue through the end of the year.

20. The positive outlook for our Piling business, including the expectation of continued strong performance from this segment in fiscal 2013.

21. The execution of the pipeline integrity dig program and our intention to pursue opportunities to construct mid-to-large inch diameter pipelines on a low-risk cost-plus or time-and-materials contract basis, which may reduce revenues but could possibly increase profitability significantly.

22. Our belief that opportunities for lower-risk pipeline projects will increase over time if contractor supply becomes more constrained.

23. Our intention to improve profitability and strengthen our balance sheet through a continued focus on performance, efficiency and risk management.

2012 Annual Report 37

24. Our estimate with respect to equipment additions and other capital needs; that our operating and capital lease facilities and capacity and cash flow from operations will likely be sufficient to meet these needs; but if we require additional funding for our expenses, this could be satisfied by our credit facilities.

25. Our belief that accounting pronouncements recently adopted or yet to be adopted, as discussed herein, will not have a material impact on our consolidated financial statements.

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

Assumptions

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

1. That we have the ability to affect the buyouts of the applicable equipment within the timelines contemplated under the contract with Canadian Natural.

2. That work will continue to be required under the contract with Canadian Natural.

3. That work will continue to be required under our master services agreements with various customers;

4. The demand for recurring services remaining strong;

5. The continuing development of new mines and the expansion of existing mines;

6. That potash mine expansions will lead to a decrease in current competitors in the oil sands;

7. The continuing resurgence in mineral resource spending;

8. Our customers’ ability to pay in timely fashion;

9. Our ability to successfully resolve all claims and unsigned change orders with our customers;

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

11. Our customers and potential customers continuing to invest in the oil sands and other resource developments and to outsource activities for which we are capable of providing services;

12. The Western Canadian economy continuing to develop and receiving additional investment in public construction;

13. The continuing construction of the southern pipeline extension;

14. Our ability to benefit from increased project development revenue and to maintain recurring services revenue tied to the operational activities of the oil sands;

15. Our ability to maintain the right size and mix of equipment in our fleet and to secure specific types of rental equipment to support project development activity enables us to meet our customers’ variable service requirements while balancing the need to maximize utilization of our own equipment;

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

17. Our success in executing our business strategy, identifying and capitalizing on opportunities, managing our business, maintaining and growing our relationships with customers, retaining new customers, integrating our acquisitions, competing in the bidding process to secure new projects and identifying and implementing improvements in our maintenance and fleet management practices.

18. Our success in improving profitability and continuing to strengthen our balance sheet through a focus on performance, efficiency and risk management.

Risk Factors

The risks and uncertainties that could cause actual results to differ materially from the information presented in the above forward-looking statements and assumptions include, but are not limited to the risks detailed below. For further information on risks, including “Business Risk Factors”, "Risk Factors Related to Our Common Shares", “Risk Factors Related to our Debt Securities” and “Quantitative and Qualitative Disclosure about Market Risk”, please refer to the “Forward-Looking Information, Assumptions and Risk Factors” section of our most recent AIF.

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

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

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

Approximately, 68%, 63% and 39% of our revenue for the fiscal years ended March 31, 2012, 2011 and 2010, respectively, was derived from lump-sum and unit-price contracts. Lump-sum and unit-price contracts require us to guarantee the price of the services we provide and thereby expose us to losses if our estimates of project costs are lower than the actual project costs we incur. Our profitability under these contracts is dependent upon our ability to accurately predict the costs associated with our services. The costs we actually incur may be affected by a variety of factors including those that are beyond our control. Factors that may contribute to actual costs exceeding estimated costs and which therefore affect profitability include, without limitation:

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

• scope modifications during the execution of the project;

• the availability and cost of skilled workers;

• the availability and proximity of materials;

• unfavourable weather conditions hindering productivity;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Most of our revenue comes from the provision of services to a small number of major oil sands mining companies. Revenue from our five largest customers represented approximately 67%, 77% and 89% of our total revenue for the fiscal years ended March 31, 2012, 2011 and 2010, respectively, and those customers are expected to continue to account for a significant percentage of our revenues in the future. In addition, the majority of our Pipeline revenues in previous fiscal years resulted from work performed for one customer. If we lose or experience a significant reduction of business or profit from one or more of our significant customers, we may not be able to replace the lost work or income with work or income from other customers. Our long-term contracts typically allow our customers to unilaterally reduce or eliminate the work that we are to perform under the contract. Our contracts also generally allow the customer to terminate the contract without cause and, in many cases, with minimal or no notice to us. Additionally, certain of these contracts provide for limited compensation following such suspension or termination of operations and we can provide no assurance that we could replace the lost work with work from other customers. The loss of or significant reduction in business with one or more of our major customers, whether as a result of the completion, early termination or suspension of a contract, or failure or inability to pay amounts owed to us, could have a material adverse effect on our business and results of operations.

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

More than 48% of our revenue for the year ended March 31, 2012 was derived from projects that we consider to be non-recurring. This revenue primarily relates to site preparation and piling services provided for the construction of extraction, upgrading and other oil sands mining infrastructure projects. There is no guarantee that the Company will find additional sources for generating non-recurring services revenue in fiscal 2012.

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

Outsourced Heavy Construction and Mining services constitute a large portion of the work we perform for our customers. For example, our mining and site preparation project revenues constituted approximately 67%, 78% and 88% of our revenues in each of the years ended March 31, 2012, 2011 and 2010, respectively. The election by one or more of our customers to perform some or all of these services themselves, rather than outsourcing the work to us, could have a material adverse impact on our business and results of operations. Certain customers perform some of this work internally and may choose to expand on the use of internal resources to complete this work if they believe they can perform this work in a more cost effective and efficient manner using their internal resources.

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

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

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

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

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

• lack of sufficient governmental infrastructure funding to support growth;

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

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

• cost overruns on announced projects.

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

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

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

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

A portion of our equipment fleet is currently leased from third parties. Other future projects may require us to lease additional equipment. If equipment lessors are unable or unwilling to provide us with reasonable lease terms within our expectations, it will significantly increase the cost of leasing equipment or may result in more restrictive lease terms that require recognition of the lease as a capital lease. We are actively pursuing new lessor relationships to dilute our exposure to the loss of one or more of our lessors.

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

We have a substantial amount of debt outstanding and significant debt service requirements. As of March 31, 2012, we had outstanding $547.9 million of debt²³, including $10.7 million of capital leases. Our substantial indebtedness restricts our flexibility, consequently it:

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

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

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

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

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

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

Further, if we do not have sufficient earnings to service our debt, we would need to refinance all or part of our existing debt, sell assets, borrow more money or sell securities, none of which we can guarantee we will be able to achieve on commercially reasonable terms, if at all.

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

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

• Because most of our customers are Canadian energy companies, a downturn in the Canadian energy industry or a global reduction in the demand for oil and related commodities could result in a decrease in the demand for our services.

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

• Significant labour disputes could adversely affect our business.

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

²³  Debt includes all liabilities with the exception of deferred income taxes.

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H. General Matters

Experts

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

Additional Information

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

For the definition of terms commonly used in our industry but not otherwise defined in this MD&A, please see “Glossary of Terms” in our most recent AIF.

Additional information relating to us, including our AIF dated June 6, 2012, can be found on the Canadian Securities Administrators System for Electronic Document Analysis and Retrieval (SEDAR) database at www.sedar.com and the Securities and Exchange Commission’s website at www.sec.gov.

42 2012 Annual Report