UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 6-K
Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16
under the Securities Exchange Act of 1934
For the month of June 2012
Commission File Number 001-33161
NORTH AMERICAN ENERGY PARTNERS INC.
Suite 2400, 500 4th Avenue SW
Calgary, Alberta T2P 2V6
(Address of principal executive offices)
Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.
Form 20-F ¨ Form 40-F x
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):
Documents Included as Part of this Report
| 1. | 2012 Annual Report to Shareholders. |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| NORTH AMERICAN ENERGY PARTNERS INC. | ||
| By: | /s/ David Blackley | |
| Name: | David Blackley | |
| Title: | Chief Financial Officer | |
Date: June 20, 2012
NORTH AMERICAN
ENERGY PARTNERS INC.
innovation
North American Energy Partners Inc. 2012 Annual Report
at work
five-years Performance Review
(in thousands of dollars except ratio and per share amounts)
Year ended March 31,
2012
2011
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
(390)
(10,725)
73,488
(87,092)
91,727
Net (loss) income
(21,162)
(34,650)
28,219
(135,404)
41,534
Consolidated EBITDA
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
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 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.
Table of Contents
02 At a Glance 04 Letter to Shareholders 06 Operations Review 18 Management’s Discussion and Analysis
61 Management’s Report 62/63 Report of Independent Registered Public Accounting Firm 64 Consolidated Financial Statements
68 Notes to the Consolidated Financial Statements 96 Board of Directors 96 Senior Management inside back cover Corporate and Investor Information
at a glance
For more than 50 years, North American Energy Partners has provided mining and construction services to oil, natural gas and resource companies, specializing in the Alberta oil sands region. We are one of the largest providers of heavy construction and mining, piling and pipeline services in Western Canada and we maintain one of the largest independently owned equipment fleets in the region.
REVENUE DATA FOR FISCAL 012
By Segment
Heavy Construction and Mining
67%
Piling
18%
Pipeline
15%
By End Market
Canadian Oil Sands
63%
Industrial Construction
10%
Commercial & Public Construction
12%
Pipeline Construction
15%
Segment Revenues (in thousands)
Heavy Construction & Mining
2012
$670,720
2011
$667,037
2010
$665,514
Piling
2012
$185,321
2011
$105,559
2010
$68,531
Pipeline
2012
$150,504
2011
$85,452
2010
$24,920
02 NOA Annual Report 2012
SERVICE OFFERING
Heavy Construction and Mining
Surface mining for oil sands and other natural resources
Construction of infrastructure associated with mining operations and reclamation activities
Clearing, stripping, excavating and grading for mining operations
Industrial site construction for megaprojects
Underground utility installation for plant, refinery and commercial building construction
Tailings pond remediation, tailings management and tailings system maintenance
Tailings dam and dyke construction, pipeline co-corridor construction
Piling
Installation of all types of driven and drilled piles
Design and installation of shoring/earth retention and stabilization systems for industrial and commercial projects (secant pile, sheet pile and soldier pile and lagging walls)
Design, fabrication and supply of helical (screw) piles
Design, fabrication and supply of micro piles
Pipeline
Infrastructure development for oil and gas pipeline systems, including gathering and processing, transmission, storage and distribution, related maintenance and other specialty services
Handling and installation of pipe ranging from 2 inches to 60 inches in diameter
Operate in numerous remote geographical locations simultaneously
OPERATIONAL HIGHLIGHTS
Secured a five-year master services agreement with an indicative value of $500 million, covering civil construction and mining services for Suncor Energy Inc. (Suncor).
Awarded major construction projects with combined contract values of approximately $324 million, including:
two contracts covering both the shear key foundation and the mechanically stabilized earth (MSE) wall for Syncrude Canada Limited’s (Syncrude) mine relocation project, the initial earthworks contract for the Joslyn North Mine Project, two site development contracts at PetroChina’s Dover steam-assisted gravity drainage (SAGD) project and, an above-ground industrial construction contract for the Mt. Milligan Copper/Gold Mine in Northern British Columbia.
Reached final agreement with Canadian Natural
Resources Limited (Canadian Natural) on amendments to the long-term overburden removal and mining services contract (“the Canadian Natural contract”) resulting in:
A total of $38.4 million in payments in recognition of past costs, $47.0 million in net proceeds from the accelerated sale of certain contract-related assets to Canadian Natural and, an amended target-price contract structure, which includes a positive base margin and the mechanism for NAEP to earn additional margin by achieving mutually agreed upon productivity and safety targets.
Achieved record consolidated revenues of $1 billion.
Achieved a 76% year-over-year increase in Piling segment revenue, together with a 149% increase in Piling segment profit, reflecting improving commercial and industrial construction market demand and favourable winter weather conditions.
Toronto and New York Stock Exchanges NOA
The construction and mining contractor that everyone wants to work for, everyone wants to hire and everyone wants to own.
To deliver high-value mining, construction and environmental remediation services and expertise to Canadian resource and construction industries.
construction industries.
Vision mission
NOA Annual Report 2012 03
to our shareholders
Fiscal 2012 brought continued revenue growth, important achievements and innovative solutions that together, are setting the stage for improved performance going forward. However, the year also brought significant weather and operating challenges that hampered our margins and resulted in weak bottom-line results.
Growth Amidst Challenges
The 17% year-over-year increase in our consolidated revenues reflects improving economic conditions and renewed investment in the Company’s primary operating arena, the Canadian oil sands. After several years of slower growth, project activity accelerated with new oil sands mines and SAGD projects, pipelines and a diverse range of commercial and industrial construction projects receiving the green light. This, in turn, supported a significant increase in our project development revenues.
In our Heavy Construction and Mining division, an important achievement of the year was the successful conclusion of negotiations to amend our long-term overburden removal and mining services contract with one of our largest customers, Canadian Natural. The amendments were undertaken to recognize significant changes in oil sands operating costs and economic conditions that have occurred since the original contract was signed in 2004. The amending agreement settled all past cost claims related to the original contract and resulted in cash payments totaling $38.4 million to NAEP. Under the new structure, NAEP is also ensured a positive base margin for all future work, with opportunities to earn additional margin by achieving mutually agreed-upon productivity and safety targets. Canadian Natural also exercised its buyout option on certain contract assets, resulting in additional net proceeds of approximately $47.0 million to NAEP. These transactions strengthened our balance sheet, while the resumption of operations on the site as of January 2, 2012, together with a secure margin, is expected to have a positive impact on our financial performance going forward.
Recurring services revenues, which are driven by day-to-day mining, reclamation and other repeat operations, grew in 2012, but fell short of expectations. While the fiscal year began strongly with a high level of activity and the award of a five-year, $500 million master services agreement with Suncor, operations were subsequently interrupted by wildfires in the Fort McMurray area which caused multi-week evacuations on several oil sands sites. Canadian Natural, also experienced a major plant fire, resulting in a seven-month suspension of our work on their site as repairs were carried out. During the third and fourth quarter, we encountered additional unexpected work stoppages as some customers recalibrated plans, and unseasonably warm winter impacted muskeg removal and reclamation work that depends on frozen ground conditions. The year also saw some customers insourcing recurring services in a bid to lower costs. Ultimately, our profitability was negatively affected as we incurred high fixed lease costs to have equipment ready for a large volume of recurring services work that was delayed or cancelled on short notice.
The Piling division achieved excellent results with the warm winter and improved construction market demand supporting strong results in every region. Piling revenues grew 76% year-over-year and margin increased 149%. The division also benefited from a full year’s operation of the new Cyntech business, which has expanded our service roster with screw piling and tank servicing capabilities. By cross-selling Cyntech’s services to our existing customer base, we more than doubled this operation’s revenues from pre-acquisition performance, while maintaining margins. We see continued growth potential for this business.
In contrast, the Pipeline division had one of its most challenging years on record with significant losses on two large-diameter pipeline projects contributing to our consolidated net loss for the year. In light of continuing risks in the current contract environment, we have shifted to a strategy that emphasizes lower-risk, time-and-material, and cost-reimbursable contracts. During the fourth quarter, we began work on a pipeline maintenance and integrity contract that is generating profitable recurring revenue on a time-and-material basis. We expect to grow this business further in fiscal 2013.
04 NOA Annual Report 2012
Looking Forward
We anticipate market challenges in the oil sands as a result of the ongoing global economic uncertainty and weaker oil prices. In our recurring services business, we expect to see a continuation of insourcing, project
delays and deferrals as producers focus on controlling costs. However, continued strong demand for reclamation and tailings services, combined with mine expansion projects and the resumption of overburden removal activity at Canadian Natural, should help to offset most of these impacts.
On the project development side of our business, our work at the Joslyn North Mine Project and Mt. Milligan Copper/Gold project continues and we have begun work on a new contract at PetroChina’s Dover SAGD project. Demand could be further supported by new opportunities for site development work at Suncor’s Fort Hills project and at other new projects in the oil sands.
The outlook for our Piling division remains positive with strong industry fundamentals and a large project backlog supporting our expectation of excellent performance from this segment again 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. However, the division will continue executing its pipeline integrity dig program. It will also consider opportunities to construct mid-to-large diameter pipelines, provided they are on a cost-reimbursable or time-and-materials basis.
On a company-wide basis, our focus in fiscal 2013 will be on addressing risk in our contracts and evaluating the cost structure of our business. We have already initiated a strategy of right sizing our equipment fleet in light of more volatile demand. We are also evaluating alternatives to operating lease financing in order to further reduce risk, while maintaining our operating flexibility in periods of fluctuating demand.
New Leadership
Our steps forward will be guided by Martin Ferron, who was appointed President, CEO and a Director of NAEP effective June 7, 2012.
Martin is a proven leader with over 30 years’ experience in the oil services and construction industries, and direct experience in both piling and pipeline. He has a long track record of successfully leading capital-intensive businesses with a large maintenance cost component, a proven ability to maximize the utilization of assets, and significant knowledge of how to negotiate and manage large oil and gas industry contracts.
At Helix Energy Solutions, an international energy services company where he served as President, CEO and Director, Martin implemented a strategy that achieved a compound annual growth rate of over 30% during his 11 years with the company and transformed Helix into an industry leader in profit performance. Prior to joining Helix, he worked with oil services and construction companies including McDermott Construction, Oceaneering International and Comex Group. He holds a B.Sc. in Civil Engineering from City University, London, an M.Sc. in Marine Technology from Strathclyde University, Glasgow, and an MBA from Aberdeen University.
Martin succeeds Rod Ruston who is stepping down after seven years as the Company’s President and CEO. He will be returning to his native Australia to take up a new business opportunity. On behalf of the Board, I thank Rod for his contributions to NAEP.
In other corporate developments, we announced two changes to the Board of Directors in recent months, including the departure of Peter Dodd in April and John Brussa in June. I thank both gentlemen for their wise counsel. We are very pleased to welcome new directors Carl Giesler, a CFA and Vice-President and Director of Investments at Harbinger Capital Partners and Jay Thornton, a senior oil and gas industry executive with 28 years’ experience with Suncor and Shell Canada. It is an exciting time for NAEP and the addition of individuals with such diverse experience and strong track records will be an asset.
In closing, I want to thank our over 3,000 employees for their dedicated response to the challenges of the past year and for their contribution in helping us achieve the best safety performance in our history. Finally, I thank you, our shareholders, for your ongoing confidence in NAEP. As fiscal 2013 progresses, we will continue to bring a spirit of innovation to bear on reshaping the company for improved performance, efficiency and risk management.
Ron A. McIntosh
Chairman, Board of Directors
NOA Annual Report 2012 05
Innovation at work
Innovation is driven by many forces. Thomas Edison, one of history’s most prolific inventors, was inspired by the simple directive: “There’s a way to do it better—find it. Innovation can equally arise from times of challenge, when the need to solve a problem or respond to change leads to important breakthroughs.
At North American Energy Partners, innovation is the result of many factors, including an intense focus on meeting customers’ changing needs. We believe our long-term success is predicated upon providing solutions...whether it’s a better way of managing tailings ponds, a contract structure that results in people working harder and smarter, a pipeline product that lowers costs and enhances reliability, or a new piling method that gets the job done faster and with less ground disturbance. Innovation helps us build a strong and sustainable competitive advantage and it was at work throughout our business in fiscal 2012.
06 NOA Annual Report 2012
greater efficiency and flexibility in the oil sands
Our Heavy Construction and Mining division operates primarily in the Canadian Oil Sands where changing customer philosophies have sparked significant changes in the way we operate.
In the past, oil sands operators were predominantly schedule focused, willing to incur higher costs if it meant getting the job done sooner. As a service provider, our advantage lay in being the company that could respond instantly. We built an operating model based on a large and diverse equipment fleet that enabled us to meet peak demand levels, and we were rewarded with growing volumes of work at attractive margins.
Today’s customers have become more conservative in their approach, with cost control becoming an increasingly important factor in operating decisions. During fiscal 2012, we, along with other oil sands suppliers, experienced sudden work delays and stoppages as customers recalibrated plans to better manage costs.
To be successful in this changing environment, we are moving to a more efficient and flexible equipment fleet model that enables us to respond to customers’ needs, but in a way that lowers our fixed costs. Our asset management team is optimizing the fleet with a weighting toward equipment that has high utilization and demand rates, while developing strategic partnerships and alliances with key suppliers for access to equipment that is more seasonal.
Another part of our strategy involves increasing our use of innovative technologies to improve productivity and efficiency. We recently implemented sophisticated GPS-based fleet management systems to monitor our mining equipment at the Canadian Natural site. The new system enables us to accurately record activity, location, time and production information for every dozer, truck and shovel onsite, and position and guide that equipment for maximum productivity.
NOA Annual Report 2012 07
Similarly, we have introduced GPS grade control systems into our construction operations. Instead of laying out stakes, waiting for the grader to make a pass and then repeating the process to correct over or under grading, surveyors now simply program desired elevations into an onboard computer. The computer guides the height of the grader’s blade to precisely cut existing ground. The system is so accurate that equipment operators achieve the right grade on the first attempt, significantly reducing equipment and operator time and freeing surveyors to move on to the next site.
During fiscal 2012, we boosted our training capability by introducing an Immersive Technologies equipment simulator at our training centre in Fort McMurray, Alberta. Featuring screens on three sides of the cockpit and realistic cab movement in response to operator commands, the new system enables operators to gain experience on virtually any piece of equipment in our fleet, while simultaneously becoming familiar with actual mine layouts which are programmed into the simulator.
Our in-house trainers can test the abilities of both new and experienced operators with a series of operational hazards – from engine fires to stalling on a steep grade. After learning to deal with these challenges in the safe but realistic simulation setting, our operators can then apply their knowledge in the field to reduce safety incidents and increase production.
To be successful in this changing environment, we are moving to a more efficient and flexible equipment fleet model
08 NOA Annual Report 2012
environmental innovation
A key area of change for customers in the oil sands has been the need to address the environmental challenges posed by tailings ponds.
Oil sands mines produce tailings, which are left over material produced during the extraction process that separates bitumen from the oil sand. When tailings are released into a pond, the heaviest material, mostly sand, settles to the bottom, while water rises to the top. The middle layer, the mature fine tailings (MFT) is made up of fine clay particles suspended in water. Some of these particles settle, but much remains suspended for long periods of time, resulting in more and larger oil sands tailings ponds over the years. There are currently more than 170 square kilometers of tailings ponds in the Canadian oil sands. In 2009, the Alberta government issued Directive 74, which implemented aggressive criteria for dramatically reducing the inventory of these ponds.
We repurposed existing agricultural technology such as mud masters to safely dewater tailings and speed up reclamation
10 NOA Annual Report 2012
NAEP saw this as an opportunity to develop a service offering of specialized technologies and equipment that could speed up the transformation of these ponds into reclaimed land. We started by partnering with the largest dredging company in the world, Bosklais International, to gain the knowledge of a world-class dredger, fluids transfer and hydraulic transport contractor. We identified and acquired the exclusive rights for innovative bitumen skimmers capable of rapidly removing bitumen from the surface of tailings ponds, as well as smaller, portable skimmers that remove bitumen from tight, shallow areas. We also developed an oil sands marine fleet with tug boats, ice breakers, and rescue boats capable of safely carrying out a diverse range of tailings pond-related work.
In its first year, our new tailings and environmental construction (TEC) operation focused on assembling a specialized equipment fleet and working with oil sands customers to test this equipment as part of their pilot projects. By fiscal 2012, we had secured tailings contracts with Suncor, Syncrude and Shell, and our TEC business went on to generate revenues of $22.5 million. This does not include the significant incremental revenue we secured by providing more traditional services such as muskeg removal, reclamation, and tailings infrastructure construction and maintenance to support our customers’ tailings management programs. Going forward, we expect this business will continue to grow as oil sands producers move more aggressively to meet their environmental requirements under Directive 74. We expect to be a key source of ideas, equipment and innovation for these customers as we bring our new tailings and environmental construction business to this fast-growing service area.
NOA Annual Report 2012 11
solution-oriented piling operations
Innovation is at the very heart of our piling business, which has built a richly deserved reputation as one of Canada’s most solutions-oriented piling contractors.
The division long ago took the position that there is no one-size-fits-all solution when it comes to structural foundations. The needs of a processing plant in the muskeg of Northern Alberta are vastly different from those of a high-rise office tower in downtown Toronto. NAEP has become an industry leader in adopting and introducing innovative technologies like continuous flight auger (CFA), micropiling, screwpiling and many other non-conventional piling methods that enable us to pair the right technique to the right site.
During fiscal 2012, we continued to build on our reputation by becoming the first company to use CFA in an oil sands project. The project required installation of a low water permeability cut-off wall adjacent to a major haul road. By using our minimal-impact, small-footprint CFA method, haul road traffic was able to continue without disruption. We were also able to complete work inside a highway overpass by modifying our 70-foot drill rig to work under the 33-foot highway overpass. Through the use of non-conventional technologies and innovative thinking, we not only met all of our customer’s requirements, but we also saved them money and time compared to using a conventional piling method.
Our Piling division continued to build on its technology base in fiscal 2012 by identifying, testing and ultimately adopting a new full-displacement drilled pile technology. This innovative vibration-free piling method provides a much-needed solution for developers of high-rise
Through the use of non-conventional technologies and innovative thinking we met all of our customer’s requirements
condominium and office towers that need to install high-load capacity piles without disrupting neighbouring buildings. The new technology is expected to help us expand our already strong presence in urban markets like Toronto, Calgary and Vancouver when we roll it out in fiscal 2013.
To ensure customers can fully benefit from our growing array of piling technologies, we continued our “Lunch and Learn” series in fiscal 2012 to build awareness for alternative piling methods in the engineering and construction communities. We also launched our own engineering unit to provide in-house design/build capability directly to customers. The new unit not only provides us with a competitive advantage by expanding the range of services we can offer our customers, it is also helping us achieve faster industry acceptance for innovative new technologies.
Our unique approach to the piling business continued to pay off in strong results in fiscal 2012. The division leveraged improving commercial construction markets and a longer construction season to achieve revenue growth of 76% and profit growth of 149% compared to fiscal 2011.
realigning pipeline
For our Pipeline segment, recent challenges on large projects and the need to improve profitability are culminating in fundamental changes in the way we approach this business.
In order to strengthen our performance, the Pipeline division has begun pursuing new opportunities that deliver more stable returns. One promising area is pipeline integrity and maintenance work. Canada’s 700,000 kilometers of gas and oil pipelines, together with increasing regulation around pipeline safety, has led to demand for contractors that can assess and repair existing lines.
During fiscal 2012, we secured our first pipeline integrity contract with a leading Canadian pipeline distribution company and successfully carried out work at numerous locations throughout Manitoba and Saskatchewan. As part of these assignments, crews are mobilized to areas of the line which the customer has determined can benefit from additional protection against corrosion. With the line still operating, our Pipeline division physically locates the section and installs reinforcement. Typically work is performed on oil supply lines that are nationally strategic either for internal consumption or for export. Our Pipeline division was chosen for this work because of our demonstrated ability to perform on challenging projects. We continue to target similar opportunities with other gas and oil distribution companies.
We have further expanded the ways we serve pipeline customers by growing our pipeline anchoring system business. Acquired as part of our November 2010 acquisition of Cyntech Corporation and reported under the Piling division’s results, the patented technology provides an alternative to conventional pipeline buoyancy control with significant cost and installation benefits. Bouyancy control is required on pipelines of a certain diameter through wet and swampy areas. In certain circumstances, the Cyntech anchor technology can provide up to 80% in cost savings over traditional methods, while trimming budgets on personnel and equipment hours, materials, storage and transportation costs. During fiscal 2012, we were successful in building business for the system not only in Canada, but also internationally.
14 NOA Annual Report 2012
While our increased focus on lower-risk, non-traditional areas of the pipeline business should help to improve segment results in the near term, it does not mean we are giving up pipeline construction. With a large volume of new pipeline projects forecast to be built in Canada over the next five years and a diminishing number of contractors willing to accept high-risk unit-price contracts, we believe the pipeline construction industry will eventually become more attractive and rewarding to contractors. Until then, we will continue to direct our focus to opportunities that ensure more stable and profitable returns.
we will continue to direct our focus to opportunities that ensure more stable and profitable returns
NOA Annual Report 2012 15
new approaches to safety
Innovative thinking drives solutions all across NAEP’s business, but nowhere is it more evident than in our approach to safety.
Ten years ago, there was a certain level of acceptance that injuries were part and parcel of the mining and construction industries in Canada. North American Energy Partners was one of the first contractors to challenge this assumption and to make safety a key performance indicator. To begin, rather than just looking at lost time injuries as a measure of our safety performance, we started using leading indicators to improve our performance. This included keeping track of all reportable incidences…everything from close calls to medical aid events. The idea was to recognize, prevent and predict situations and practices that could lead to an injury, before they occurred. Our new Slips, Trips and Falls initiative is a good example of this strategy in action. Every year during the winter months, we see a spike of injuries resulting from people losing their footing in slippery conditions. During fiscal 2012 we launched a campaign which included education, presentations and awareness on the subject for employees. We also required mandatory traction aids be worn by employees in slippery conditions. As a result of these changes, we achieved a 30% decrease in slips, trips and fall injuries.
We have further increased safety awareness throughout our operations with frontline supervisors engaging employees in safety discussions as part of daily morning meetings. We also carry out more frequent field visits and audits. Training also plays a major role in our commitment to enhanced safety, with new employees undergoing longer and more rigorous training prior to taking up their duties in the field.
During fiscal 2012, we continued to build on our safety culture with the initiation of Innovation Awards to provide safety solutions collaboratively. We also initiated a President’s Safety Award to recognize the contributions and innovation of our employees. The first President’s Safety Award went to General Manager Harold Gudmundsen and his Asset Management team who developed a safer process for adding “ice lugs” to dozers. Every year, the treads of NAEP’s dozers have lugs welded on to provide improved traction during the winter months. This procedure used to involve a dangerous “live work” element in which an operator sat in the cab and rotated the tracks of the dozer while the welder attached lugs. A safer solution was proposed by a team of employees who developed a mechanical Dozer Inching Drive that enables the welder to safely advance the drive track without needing to run the machine. The new procedure has not only significantly decreased risk, it simultaneously increased efficiency by reducing the time it takes to ice lug a machine by 25-40%.
We believe our commitment to safety and our proven approaches to embedding it in our culture have made NAEP one of the safest mining service providers in the oil sands. Statistics bear this out, with our performance continuing to improve. During fiscal 2012 we achieved our best-ever safety statistics, with a 60% reduction in reportable incidents. Our motto is “Everybody gets home safe.” Thanks to the effort of our employees and our own commitment to innovative safety approaches, we are living up to our words.
“everybody
16 NOA Annual Report 2012
gets home safe”
NOA Annual Report 2012 17
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. |
| 18 | 2012 Annual Report |
NOA
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. |
| ¿ | 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 | 19 |
We anticipate $47.0 million of net proceeds upon final closing of the sale of the assets related to the Canadian Natural contract.¿
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.
| ¿ | 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%). |
| 20 | 2012 Annual Report |
NOA
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. |
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.
| 2012 Annual Report | 21 |
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.
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. |
| 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. |
| 22 | 2012 Annual Report |
NOA
| • | 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. |
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.
| 2012 Annual Report | 23 |
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. ¿
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.¿
| 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. |
| 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. |
| 24 | 2012 Annual Report |
NOA
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.¿
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.¿
| ¿ | 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) |
| 2012 Annual Report | 25 |
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.¿
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) |
$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 | |||||||||||||
| ¿ | 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 |
NOA
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.
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.
| 2012 Annual Report | 27 |
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.
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; |
| 28 | 2012 Annual Report |
NOA
| • | 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. |
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,
| 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 | 29 |
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.
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: |
| 30 | 2012 Annual Report |
NOA
| 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.
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,
| 2012 Annual Report | 31 |
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.
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.
| 32 | 2012 Annual Report |
NOA
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.
Non-Operating Income and Expense
| Three Months Ended March 31, | Year Ended March 31, | |||||||||||||||||||||||||||||||||||||||||||||||
| (dollars in thousands) | 2012 | 2011 | Change | 2012 | 2011 | 2010 | Change 2011 |
Change 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
| 2012 Annual Report | 33 |
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”.
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.
| 34 | 2012 Annual Report |
NOA
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.
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
| 2012 Annual Report | 35 |
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.¿
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. |
| ¿ | 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. |
| 36 | 2012 Annual Report |
NOA
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.
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.
| 2012 Annual Report | 37 |
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); |
| • | 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. |
| 38 | 2012 Annual Report |
NOA
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 | ) | ||||||||||||
| 2012 Annual Report | 39 |
| 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.
| 40 | 2012 Annual Report |
NOA
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. |
| 2012 Annual Report | 41 |
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.¿
| ¿ | 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. |
| 42 | 2012 Annual Report |
NOA
Liquidity requirements
Our primary uses of cash are for plant and equipment purchases, to fulfill debt repayment and interest payment obligations, to fund operating and capital lease obligations and to finance working capital requirements.
We maintain a significant equipment and vehicle fleet comprised of units with remaining useful lives covering a variety of time spans. It is important 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.
| ¿ | 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 | 43 |
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.
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); |
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| 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. |
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. |
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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 | ||||||||||||||||||||||||||||
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. |
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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.
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.
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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.
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%.
| 21 | Standard and Poor’s Ratings Services (S&P), a division of The McGraw-Hill Companies, Inc. |
| 22 | This debt rating information is current as of this report and we undertake no obligation to provide investors with updated information. |
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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 |
| • | 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.
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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.
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); |
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| • | extended overhead due to owner, weather and other delays (to the extent contract remedies are unavailable); |
| • | subcontractor performance issues; |
| • | changes in economic indices used 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. |
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.
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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.
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.
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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.
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.¿
| ¿ | 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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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.
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. |
| ¿ | 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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| 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. |
| 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.
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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.
| • | 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
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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.
| • | Our ability to maintain planned project margins on projects with longer-term contracts with fixed or indexed price escalators may be hampered by the price escalators not accurately reflecting increases in our costs over the life of the contract. |
Our ability to maintain planned project margins on longer-term contracts with contracted price escalators is dependent on the contracted price escalators accurately reflecting increases in our costs. If the contracted price escalators do not reflect actual increases in our costs, we will experience reduced project margins over the remaining life of these longer-term contracts.
In strong economic times, the cost of labour, equipment, materials and sub-contractors is driven by the market demand for these project inputs. The level of increased demand for project inputs may not have been foreseen at the inception of the longer-term contracts with fixed or indexed price escalators resulting in reduced margins over the remaining life of the longer-term contracts. Certain of these price escalators could be considered derivative financial instruments (see “Significant Accounting Policies – Derivative Financial Instruments” in our audited consolidated financial statements for the year ended March 31, 2012).
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| • | Our customer base is concentrated, and the loss of or a significant reduction in business from a major customer could adversely affect our financial condition. |
Most of our revenue comes from the provision of services to a small number of major oil sands mining companies. Revenue from our five largest customers represented approximately 67%, 77% and 89% of our total revenue for the fiscal years ended March 31, 2012, 2011 and 2010, respectively, and those customers are expected to continue to account for a significant percentage of our revenues in the future. In addition, the majority of our Pipeline revenues in previous fiscal years resulted from work performed for one customer. If we lose or experience a significant reduction of business or profit from one or more of our significant customers, we may not be able to replace the lost work or income with work or income from other customers. Our long-term contracts typically allow our customers to unilaterally reduce or eliminate the work that we are to perform under the contract. Our contracts also generally allow the customer to terminate the contract without cause and, in many cases, with minimal or no notice to us. Additionally, certain of these contracts provide for limited compensation following such suspension or termination of operations and we can provide no assurance that we could replace the lost work with work from other customers. The loss of or significant reduction in business with one or more of our major customers, whether as a result of the completion, early termination or suspension of a contract, or failure or inability to pay amounts owed to us, could have a material adverse effect on our business and results of operations.
| • | A significant amount of our revenue is generated by providing non-recurring services. |
More than 48% of our revenue for the year ended March 31, 2012 was derived from projects that we consider to be non-recurring. This revenue primarily relates to site preparation and piling services provided for the construction of extraction, upgrading and other oil sands mining infrastructure projects. There is no guarantee that the Company will find additional sources for generating non-recurring services revenue in fiscal 2012.
| • | 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. |
| • | 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.
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| • | Reduced availability or increased cost of leasing our equipment fleet could adversely affect our results. |
A portion of our equipment fleet is currently leased from third parties. Other future projects may require us to lease additional equipment. If equipment lessors are unable or unwilling to provide us with reasonable lease terms within our expectations, it will significantly increase the cost of leasing equipment or may result in more restrictive lease terms that require recognition of the lease as a capital lease. We are actively pursuing new lessor relationships to dilute our exposure to the loss of one or more of our lessors.
| • | We may not be able to access sufficient funds to finance a growth in our working capital or equipment requirements. |
We have a substantial amount of debt outstanding and significant debt service requirements. As of March 31, 2012, we had outstanding $547.9 million of debt23, including $10.7 million of capital leases. Our substantial indebtedness restricts our flexibility, consequently it:
| • | limits our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements, potential growth or other purposes; |
| • | limits our ability to use operating cash flow in other areas of our business; |
| • | limits our ability to post surety bonds required by some of our customers; |
| • | places us at a competitive disadvantage compared to competitors with less debt; |
| • | increases our vulnerability to, and reduces our flexibility in planning for, adverse changes in economic, industry and competitive conditions; and |
| • | increases our vulnerability to increases in interest rates because borrowings under our revolving credit facility and payments under some of our equipment leases are subject to variable interest rates. |
Further, if we do not have sufficient earnings to service our debt, we would need to refinance all or part of our existing debt, sell assets, borrow more money or sell securities, none of which we can guarantee we will be able to achieve on commercially reasonable terms, if at all.
| • | Cost overruns by our customers on their projects may cause our customers to terminate future projects or expansions that could adversely affect the amount of work we receive from those customers. |
Oil sands development projects require substantial capital expenditures. In the past, several of our customers’ projects have experienced significant cost overruns, affecting their returns. If cost overruns continue to challenge our customers, they could reassess future projects and expansions that could adversely affect the amount of work we receive from our customers.
| • | Because most of our customers are Canadian energy companies, a downturn in the Canadian energy industry or a global reduction in the demand for oil and related commodities could result in a decrease in the demand for our services. |
Most of our customers are Canadian energy companies. A downturn in the Canadian energy industry has previously led our customers to slow down or curtail their future capital expansions that, in turn, reduced our revenue from those customers on their capital projects. Another economic downturn in the Canadian energy industry or a global reduction in the demand for oil could have an adverse impact on our financial condition and results of operations. In addition, a reduction in the number of new oil sands capital projects by customers would also likely result in increased competition among oil sands service providers, which could also reduce our ability to successfully bid for new capital projects.
| • | Significant labour disputes could adversely affect our business. |
Substantially all of our hourly employees are subject to collective bargaining agreements to which we are a party or are otherwise subject. Any work stoppage resulting from a strike or lockout could have a material adverse effect on our business, financial condition and results of operations. In addition, our customers employ workers under collective bargaining agreements. Any work stoppage or labour disruption experienced by our key customers could significantly reduce the amount of our services that they need.
| 23 | Debt includes all liabilities with the exception of deferred income taxes. |
| 2012 Annual Report | 59 |
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 4th 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.
| 60 | 2012 Annual Report |
NOA
Exhibit 99.2
MANAGEMENT’S REPORT
The accompanying consolidated financial statements and all of the information in Management’s Discussion and Analysis (MD&A) are the responsibility of management of the Company. The consolidated financial statements were prepared by management in accordance with U.S. generally accepted accounting principles. Where alternative accounting methods exist, management has chosen those it considers most appropriate in the circumstances. The significant accounting policies used are described in note 2 to the consolidated financial statements. Certain amounts in the consolidated financial statements are based on estimates and judgments relating to matters not concluded by year end. The integrity of the information presented in the consolidated financial statements is the responsibility of management.
The Board of Directors is responsible for ensuring that management fulfills its responsibilities and for approval of the consolidated financial statements. The board carries out this responsibility through its Audit Committee. The Board has appointed an Audit Committee comprising all independent directors. The Audit Committee meets at least four times each year to discharge its responsibilities under a written mandate from the Board of Directors. The Audit Committee meets with management and with external auditors to satisfy itself that they are properly discharging their responsibilities; reviews the consolidated financial statements, MD&A, and the Report of Independent Registered Public Accounting Firm on the financial statements; and examines other auditing and accounting matters. The Audit Committee has reviewed the consolidated financial statements with management and discussed the appropriateness of the accounting principles as applied and significant judgments and estimates affecting the consolidated financial statements. The Audit Committee has discussed with the external auditors, the appropriateness of those principles as applied and the judgments and estimates noted above. The consolidated financial statements and the MD&A have been reviewed by the Audit Committee and approved by the Board of Directors of North American Energy Partners Inc.
The consolidated financial statements have been examined by the shareholders’ auditors, KPMG LLP, Chartered Accountants. The Report of Independent Registered Public Accounting Firm on the financial statements outlines the nature of their examination and their opinion on the consolidated financial statements of the Company. The external auditors have full and unrestricted access to the Audit Committee.
Management’s Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining an adequate system of internal control over financial reporting. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Management conducted an evaluation of the effectiveness of the system of internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that the Company’s system of internal control over financial reporting was effective as of March 31, 2012. The details of this evaluation and conclusion are documented in the MD&A.
KPMG LLP has audited the consolidated financial statements of the Company for the year ended March 31, 2012 and, has also issued a report stating its opinion that the Company has maintained effective internal control over financial reporting as of March 31, 2012 based on the criteria established in Internal Control – Integrated Framework issued by the COSO.
|
| |||
| Ronald A. McIntosh | David Blackley | |||
| Chairman, Board of Directors | Chief Financial Officer | |||
| June 6, 2012 | June 6, 2012 | |||
| 2012 Annual Report | 61 |
|
|
||||||
| KPMG LLP |
Telephone | (780) 429-7300 | ||||
| Chartered Accountants |
Fax | (780) 429-7379 | ||||
| 10125 – 102 Street |
Internet | www.kpmg.ca | ||||
| Edmonton AB T5J 3V8 |
||||||
| Canada |
INDEPENDENT AUDITORS’ REPORT OF REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of North American Energy Partners Inc.
We have audited North American Energy Partners Inc.’s internal control over financial reporting as of March 31, 2012, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). North American Energy Partners Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting in the accompanying Management’s Discussion and Analysis for the year ended March 31, 2012. Our responsibility is to express an opinion on North American Energy Partners Inc.’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, North American Energy Partners Inc. maintained, in all material respects, effective internal control over financial reporting as of March 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of North American Energy Partners Inc. as at March 31, 2012 and 2011, and the consolidated statements of operations and comprehensive (loss) income, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended March 31, 2012, and our report dated June 6, 2012, expressed an unqualified opinion on those consolidated financial statements.
Chartered Accountants
Edmonton, Canada
June 6, 2012
KPMG LLP, is a Canadian limited liability partnership and a member firm of the KPMG
network of independent member firms affiliated with KPMG International, a Swiss cooperative.
KPMG Canada provides services to KPMG LLP.
| 62 | 2012 Annual Report |
NOA
|
|
||||||
| KPMG LLP |
Telephone | (780) 429-7300 | ||||
| Chartered Accountants |
Fax | (780) 429-7379 | ||||
| 10125 – 102 Street |
Internet | www.kpmg.ca | ||||
| Edmonton AB T5J 3V8 |
||||||
| Canada |
INDEPENDENT AUDITORS’ REPORT OF REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of North American Energy Partners Inc.
We have audited the accompanying consolidated financial statements of North American Energy Partners Inc., which comprise the consolidated balance sheets as at March 31, 2012 and 2011, and the consolidated statements of operations and comprehensive (loss) income, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended March 31, 2012, and notes, comprising a summary of significant accounting policies and other explanatory information.
Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with U.S. generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform an audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the company’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances.
An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of North American Energy Partners Inc. as at March 31, 2012 and 2011 and its consolidated results of operations and its consolidated cash flows for each of the years in the three-year period ended March 31, 2012 in accordance with U.S. generally accepted accounting principles.
Other Matter
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), North American Energy Partners Inc.’s internal control over financial reporting as of March 31, 2012, based on the criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated June 6, 2012 expressed an unqualified opinion on the effectiveness of North American Energy Partners Inc.’s internal control over financial reporting.
Chartered Accountants
Edmonton, Canada
June 6, 2012
KPMG LLP, is a Canadian limited liability partnership and a member firm of the KPMG
network of independent member firms affiliated with KPMG International, a Swiss cooperative.
KPMG Canada provides services to KPMG LLP.
| 2012 Annual Report | 63 |
Consolidated Balance Sheets
As at March 31
(Expressed in thousands of Canadian Dollars)
| 2012 | 2011 | |||||||||
| Assets |
||||||||||
| Current assets |
||||||||||
| Cash and cash equivalents |
$1,400 | $722 | ||||||||
| Accounts receivable, net (note 7 and 21(d)) |
214,129 | 128,482 | ||||||||
| Unbilled revenue (note 8) |
86,859 | 102,939 | ||||||||
| Inventories (note 9) |
11,855 | 7,735 | ||||||||
| Prepaid expenses and deposits (note 10) |
6,315 | 8,269 | ||||||||
| Investment in and advances to unconsolidated joint venture (note 11) |
1,574 | 1,488 | ||||||||
| Deferred tax assets (note 17) |
2,991 | 1,729 | ||||||||
| 325,123 | 251,364 | |||||||||
| Property, plant and equipment, net (note 13) |
312,775 | 321,864 | ||||||||
| Other assets (note 12(a)) |
21,743 | 26,908 | ||||||||
| Goodwill (note 5) |
32,901 | 32,901 | ||||||||
| Deferred tax assets (note 17) |
57,451 | 49,920 | ||||||||
| Total Assets |
$749,993 | $682,957 | ||||||||
| Liabilities and Shareholders' Equity |
||||||||||
| Current liabilities |
||||||||||
| Accounts payable |
$171,130 | $86,053 | ||||||||
| Accrued liabilities (note 14) |
36,795 | 32,814 | ||||||||
| Billings in excess of costs incurred and estimated earnings on uncompleted contracts (note 8) |
7,514 | 2,004 | ||||||||
| Current portion of long term debt (note 15(a)) |
14,402 | 14,862 | ||||||||
| Current portion of derivative financial instruments (note 21(a)) |
3,220 | 2,474 | ||||||||
| Deferred tax liabilities (note 17) |
21,512 | 27,612 | ||||||||
| 254,573 | 165,819 | |||||||||
| Long term debt (note 15(a)) |
300,066 | 290,801 | ||||||||
| Derivative financial instruments (note 21(a)) |
5,926 | 9,054 | ||||||||
| Other long term obligations (note 16(a)) |
8,860 | 25,576 | ||||||||
| Deferred tax liabilities (note 17) |
52,788 | 44,441 | ||||||||
| 622,213 | 535,691 | |||||||||
| Shareholders' equity |
||||||||||
| Common shares (authorized – unlimited number of voting common shares; issued and |
304,908 | 304,854 | ||||||||
| Additional paid-in capital |
8,711 | 7,007 | ||||||||
| Deficit |
(185,820 | ) | (164,536 | ) | ||||||
| Accumulated other comprehensive loss |
(19 | ) | (59 | ) | ||||||
| 127,780 | 147,266 | |||||||||
| Total liabilities and shareholders' equity |
$749,993 | $682,957 | ||||||||
| Commitments (note 25) |
||||||||||
| Contingencies (note 28) |
||||||||||
Approved on behalf of the Board
| /s/ Ronald A. McIntosh | /s/ Allen R. Sello | |||||||
| Ronald A. Mclntosh, Director | Allen R. Sello, Director | |||||||
See accompanying notes to consolidated financial statements.
| 64 | 2012 Annual Report |
NOA
Consolidated Statements of Operations and Comprehensive (Loss) Income
Consolidated Statements of Operations and
Comprehensive (Loss) Income
For the years ended March 31
(Expressed in thousands of Canadian Dollars, except per share amounts)
| 2012 | 2011 | 2010 | ||||||||||||||
| Revenue |
$1,006,545 | $858,048 | $758,965 | |||||||||||||
| Project costs |
610,821 | 456,119 | 301,307 | |||||||||||||
| Equipment costs |
220,738 | 234,933 | 209,408 | |||||||||||||
| Equipment operating lease expense |
65,185 | 69,420 | 66,329 | |||||||||||||
| Depreciation |
48,900 | 39,440 | 42,636 | |||||||||||||
| Gross profit |
60,901 | 58,136 | 139,285 | |||||||||||||
| General and administrative expenses |
54,400 | 59,828 | 62,516 | |||||||||||||
| Loss on disposal of property, plant and equipment |
1,741 | 1,948 | 1,233 | |||||||||||||
| (Gain) loss on disposal of assets held for sale (note 12(b)) |
(466 | ) | 825 | 373 | ||||||||||||
| Amortization of intangible assets (note 12(c)) |
5,702 | 3,540 | 1,719 | |||||||||||||
| Equity in (earnings) loss of unconsolidated joint venture (note 11) |
(86 | ) | 2,720 | (44 | ) | |||||||||||
| Operating (loss) income before the undernoted |
(390 | ) | (10,725 | ) | 73,488 | |||||||||||
| Interest expense, net (note 19) |
30,325 | 29,991 | 26,080 | |||||||||||||
| Foreign exchange loss (gain) |
52 | (1,659 | ) | (48,901 | ) | |||||||||||
| Realized and unrealized (gain) loss on derivative financial instruments (note 21(a)) |
(2,382 | ) | (2,305 | ) | 54,411 | |||||||||||
| Loss on debt extinguishment (note 15(d)) |
– | 4,346 | – | |||||||||||||
| (Loss) income before income taxes |
(28,385 | ) | (41,098 | ) | 41,898 | |||||||||||
| Income tax (benefit) expense (note 17): |
||||||||||||||||
| Current |
(677 | ) | 2,892 | 3,803 | ||||||||||||
| Deferred |
(6,546 | ) | (9,340 | ) | 9,876 | |||||||||||
| Net (loss) income |
(21,162 | ) | (34,650 | ) | 28,219 | |||||||||||
| Other comprehensive income (loss) |
||||||||||||||||
| Unrealized foreign currency translation gain (loss) |
40 | (59 | ) | – | ||||||||||||
| Comprehensive (loss) income |
(21,122 | ) | (34,709 | ) | 28,219 | |||||||||||
| Net (loss) income per share – basic (note 18(b)) |
$(0.58 | ) | $(0.96 | ) | $0.78 | |||||||||||
| Net (loss) income per share – diluted (note 18(b)) |
$(0.58 | ) | $(0.96 | ) | $0.77 | |||||||||||
See accompanying notes to consolidated financial statements.
| 2012 Annual Report | 65 |
Consolidated Statements of Changes in Shareholders' Equity
Consolidated Statements of Changes in Shareholders’
Equity
(Expressed in thousands of Canadian Dollars)
| Common shares |
Additional paid-in capital |
Deficit | Accumulated other comprehensive loss |
Total | ||||||||||||||||||||||||
| Balance at March 31, 2009 |
$303,431 | $5,466 | $(158,105 | ) | $– | $150,792 | ||||||||||||||||||||||
| Net income |
– | – | 28,219 | – | 28,219 | |||||||||||||||||||||||
| Share option plan |
– | 2,135 | – | – | 2,135 | |||||||||||||||||||||||
| Deferred performance share unit plan |
– | 123 | – | – | 123 | |||||||||||||||||||||||
| Reclassified to restricted share unit liability |
– | (20 | ) | – | – | (20 | ) | |||||||||||||||||||||
| Cash settlement of stock options |
– | (244 | ) | – | – | (244 | ) | |||||||||||||||||||||
| Exercised stock options |
74 | (21 | ) | – | – | 53 | ||||||||||||||||||||||
| Balance at March 31, 2010 |
$303,505 | $7,439 | $(129,886 | ) | $– | $181,058 | ||||||||||||||||||||||
| Net loss |
– | – | (34,650 | ) | – | (34,650 | ) | |||||||||||||||||||||
| Unrealized foreign currency translation loss |
– | – | – | (59 | ) | (59 | ) | |||||||||||||||||||||
| Share option plan |
– | 1,455 | – | – | 1,455 | |||||||||||||||||||||||
| Deferred performance share unit plan |
– | (44 | ) | – | – | (44 | ) | |||||||||||||||||||||
| Stock award plan |
– | 780 | – | – | 780 | |||||||||||||||||||||||
| Exercised stock options |
1,349 | (386 | ) | – | – | 963 | ||||||||||||||||||||||
| Senior executive stock option plan |
– | (2,237 | ) | – | – | (2,237 | ) | |||||||||||||||||||||
| Balance at March 31, 2011 |
$304,854 | $7,007 | $(164,536 | ) | $(59 | ) | $147,266 | |||||||||||||||||||||
| Net loss |
– | – | (21,162 | ) | – | (21,162 | ) | |||||||||||||||||||||
| Unrealized foreign currency translation gain |
– | – | – | 40 | 40 | |||||||||||||||||||||||
| Share option plan |
– | 1,373 | – | – | 1,373 | |||||||||||||||||||||||
| Reclassified to restricted share unit liability |
– | (121 | ) | – | – | (121 | ) | |||||||||||||||||||||
| Stock award plan |
– | 256 | – | – | 256 | |||||||||||||||||||||||
| Exercised stock options |
54 | (19 | ) | – | – | 35 | ||||||||||||||||||||||
| Repurchase of shares to settle stock award plan |
– | (700 | ) | (122 | ) | – | (822 | ) | ||||||||||||||||||||
| Senior executive stock option plan |
– | 915 | – | – | 915 | |||||||||||||||||||||||
| Balance at March 31, 2012 |
$304,908 | $8,711 | $(185,820 | ) | $(19 | ) | $127,780 | |||||||||||||||||||||
See accompanying notes to consolidated financial statements.
| 66 | 2012 Annual Report |
NOA
Consolidated Statements of Cash Flows
For the years ended March 31
(Expressed in thousands of Canadian Dollars)
| 2012 | 2011 | 2010 | ||||||||||||||
| Cash (used in) provided by: | ||||||||||||||||
| Operating activities: |
||||||||||||||||
| Net (loss) income for the period |
$(21,162 | ) | $(34,650 | ) | $28,219 | |||||||||||
| Items not affecting cash: |
||||||||||||||||
| Depreciation |
48,900 | 39,440 | 42,636 | |||||||||||||
| Equity in (earnings) loss of unconsolidated joint venture (note 11) |
(86 | ) | 2,720 | (44 | ) | |||||||||||
| Amortization of intangible assets (note 12(c)) |
5,702 | 3,540 | 1,719 | |||||||||||||
| Amortization of deferred lease inducements (note 16(b)) |
(107 | ) | (107 | ) | (107 | ) | ||||||||||
| Amortization of deferred financing costs (note 12(d)) |
1,591 | 1,609 | 3,348 | |||||||||||||
| Loss on disposal of property, plant and equipment |
1,741 | 1,948 | 1,233 | |||||||||||||
| (Gain) loss on disposal of assets held for sale (note 12(b)) |
(466 | ) | 825 | 373 | ||||||||||||
| Realized and unrealized foreign exchange gain on 8 3/4% senior notes |
– | (732 | ) | (48,920 | ) | |||||||||||
| Realized and unrealized (gain) loss on derivative financial instruments |
(2,382 | ) | (2,305 | ) | 38,852 | |||||||||||
| Loss on debt extinguishment (note 15(d)) |
– | 4,346 | – | |||||||||||||
| Stock-based compensation (reversal) expense (note 27(a)) |
(2,263 | ) | 8,156 | 5,270 | ||||||||||||
| Cash settlement of restricted share unit plan (note 27(e)) |
(318 | ) | – | – | ||||||||||||
| Cash settlement of stock options (note 27(b)) |
– | – | (244 | ) | ||||||||||||
| Settlement of stock award plan (note 27(g)) |
(822 | ) | – | – | ||||||||||||
| Accretion of asset retirement obligation (note 16(c)) |
39 | 35 | 5 | |||||||||||||
| Deferred income tax (benefit) expense (note 17) |
(6,546 | ) | (9,340 | ) | 9,876 | |||||||||||
| Net changes in non-cash working capital (note 22(b)) |
39,452 | (15,982 | ) | (39,591 | ) | |||||||||||
| 63,273 | (497 | ) | 42,625 | |||||||||||||
| Investing activities: |
||||||||||||||||
| Acquisition, net of cash acquired (note 6) |
– | (23,501 | ) | (5,410 | ) | |||||||||||
| Purchase of property, plant and equipment |
(61,759 | ) | (36,417 | ) | (51,888 | ) | ||||||||||
| Additions to intangible assets (note 12(c)) |
(3,537 | ) | (4,748 | ) | (3,362 | ) | ||||||||||
| Investment in and advances to unconsolidated joint venture (note 11) |
– | (1,291 | ) | (2,873 | ) | |||||||||||
| Proceeds on disposal of property, plant and equipment |
176 | 499 | 1,440 | |||||||||||||
| Proceeds on disposal of assets held for sale |
920 | 826 | 2,482 | |||||||||||||
| (64,200 | ) | (64,632 | ) | (59,611 | ) | |||||||||||
| Financing activities: |
||||||||||||||||
| Repayment of credit facilities |
(196,203 | ) | (85,000 | ) | (6,906 | ) | ||||||||||
| Increase in credit facilities |
203,000 | 128,524 | 34,700 | |||||||||||||
| Financing costs (note 12(d)) |
(60 | ) | (7,920 | ) | (1,123 | ) | ||||||||||
| Redemption of 8 3/4% senior notes (note 15(d)) |
– | (202,410 | ) | – | ||||||||||||
| Issuance of Series 1 Debentures (note 15(e)) |
– | 225,000 | – | |||||||||||||
| Settlement of swap liabilities (note 21(a)) |
– | (91,125 | ) | – | ||||||||||||
| Proceeds from stock options exercised (note 27(b)) |
35 | 963 | 53 | |||||||||||||
| Repayment of capital lease obligations |
(5,207 | ) | (5,127 | ) | (5,613 | ) | ||||||||||
| 1,565 | (37,095 | ) | 21,111 | |||||||||||||
| Increase (decrease) in cash and cash equivalents |
638 | (102,224 | ) | 4,125 | ||||||||||||
| Effect of exchange rate on changes in cash and cash equivalents |
40 | (59 | ) | – | ||||||||||||
| Cash and cash equivalents, beginning of year |
722 | 103,005 | 98,880 | |||||||||||||
| Cash and cash equivalents, end of year |
$1,400 | $722 | $103,005 | |||||||||||||
Supplemental cash flow information (note 22(a))
See accompanying notes to consolidated financial statements.
| 2012 Annual Report | 67 |
Notes to Consolidated Financial Statements
For the years ended March 31, 2012, 2011, 2010
(Expressed in thousands of Canadian Dollars, except per share amounts or unless otherwise specified)
1. Nature of operations
North American Energy Partners Inc. (the “Company”), formerly NACG Holdings Inc., was incorporated under the Canada Business Corporations Act on October 17, 2003. On November 26, 2003, the Company purchased all the issued and outstanding shares of North American Construction Group Inc. (“NACGI”), including subsidiaries of NACGI, from Norama Ltd. which had been operating continuously in Western Canada since 1953. The Company had no operations prior to November 26, 2003. The Company undertakes several types of projects including mining and environmental services, heavy construction, industrial and commercial site development and pipeline and piling installations. The Company also designs and manufactures screw piles, provides tank maintenance services to the petro-chemical industry across Canada and the United States and sells pipeline anchoring systems globally.
2. Significant accounting policies
a) Basis of presentation
These consolidated financial statements are prepared in accordance with United States generally accepted accounting principles (“US GAAP”). Material inter-company transactions and balances are eliminated upon consolidation.
These consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, NACGI, North American Fleet Company Ltd., North American Construction Projects Inc., NACG International Inc., North American Major Mining Projects Inc., North American Construction Management Inc. (“NACMI”) and NACG Properties Inc., and the following 100% owned subsidiaries of NACMI:
| • North American Caisson Ltd. |
• North American Services Inc. | |
| • North American Construction Ltd. |
• North American Site Development Ltd. | |
| • North American Engineering Inc. |
• North American Site Services Inc. | |
| • North American Enterprises Ltd. |
• North American Tailings and Environmental Ltd. | |
| • North American Industries Inc. |
• DF Investments Limited | |
| • North American Maintenance Ltd. |
• Drillco Foundation Co. Ltd. | |
| • North American Mining Inc. |
• Cyntech Canada Inc. | |
| • North American Pile Driving Inc. |
• Cyntech Services Inc. | |
| • North American Pipeline Inc. |
• Cyntech U.S. Inc. | |
| • North American Road Inc. |
b) Use of estimates
The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures reported in these consolidated financial statements and accompanying notes and the reported amounts of revenues and expenses during the reporting period.
Significant estimates made by management include the assessment of the percentage of completion on time-and-materials, unit-price, lump-sum and cost-plus contracts (including estimated total costs and provisions for estimated losses) and the recognition of claims and change orders on revenue contracts; assumptions used to value free standing and embedded derivatives and other financial instruments; assumptions used in periodic impairment testing; and, estimates and assumptions used in the determination of the allowance for doubtful accounts, the recoverability of deferred tax assets and the useful lives of property, plant and equipment and intangible assets. Actual results could differ materially from those estimates.
The length of the Company’s contracts varies from less than one year for typical contracts to several years for certain larger contracts. Contract project costs include all direct labour, material, subcontract and equipment costs and those indirect costs related to contract performance such as indirect labour, supplies, and tools. General and administrative expenses are charged to expense as incurred. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined.
The accuracy of the Company’s revenue and profit recognition in a given period is dependent on the accuracy of its estimates of the cost to complete each project. Cost estimates for all of significant projects use a detailed “bottom up” approach and the Company believes its experience allows it to provide reasonably dependable estimates. There are a number of factors that can contribute to changes in estimates of contract cost and profitability that are recognized to the extent contract remedies are unavailable in the period in which such adjustments are determined. The most significant of these include:
| • | the completeness and accuracy of the original bid; |
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| • | costs associated with added scope changes; |
| • | extended overhead due to owner, weather and other delays; |
| • | subcontractor performance issues; |
| • | changes in economic indices used for the determination of escalation or de-escalation for contractual rates on long-term contracts; |
| • | changes in productivity expectations; |
| • | site conditions that differ from those assumed in the original bid; |
| • | contract incentive and penalty provisions; |
| • | the availability and skill level of workers in the geographic location of the project; and |
| • | a change in the availability and proximity of equipment and materials. |
The foregoing factors as well as the mix of contracts at different margins may cause fluctuations in gross profit between periods. With many projects of varying levels of complexity and size in process at any given time, changes in estimates can offset each other without materially impacting the Company’s profitability. Major changes in cost estimates, particularly in larger, more complex projects, can have a significant effect on profitability.
c) Revenue recognition
The Company performs its projects under the following types of contracts: time-and-materials; cost-plus; unit-price; and lump-sum. Revenue is recognized as costs are incurred for time-and-materials and cost-plus service contracts with no clearly defined scope. Revenue on cost-plus, unit-price, lump-sum and time-and-materials contracts with defined scope is recognized using the percentage-of-completion method, measured by the ratio of costs incurred to date to estimated total costs. The estimated total cost of the contract and percent complete is determined based upon estimates made by management. The costs of items that do not relate to performance of contracted work, particularly in the early stages of the contract, are excluded from costs incurred to date. The resulting percent complete methodology is applied to the approved contract value to determine the revenue recognized. Customer payment milestones typically occur on a periodic basis over the period of contract completion.
The length of the Company’s contracts varies from less than one year for typical contracts to several years for certain larger contracts. Contract project costs include all direct labour, material, subcontract and equipment costs and those indirect costs related to contract performance such as indirect labour, supplies, and tools. General and administrative expenses are charged to expense as incurred. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Changes in project performance, project conditions, and estimated profitability, including those arising from contract penalty provisions and final contract settlements, may result in revisions to costs and revenue that are recognized in the period in which such adjustments are determined. Profit incentives are included in revenue when their realization is reasonably assured.
Once a project is underway, the Company will often experience changes in conditions, client requirements, specifications, designs, materials and work schedule. Generally, a “change order” will be negotiated with the customer to modify the original contract to approve both the scope and price of the change. Occasionally, however, disagreements arise regarding changes, their nature, measurement, timing and other characteristics that impact costs and revenue under the contract. When a change becomes a point of dispute between the Company and a customer, the Company will then consider it as a claim.
Costs related to unapproved change orders and claims are recognized when they are incurred.
Revenues related to unapproved change orders and claims are included in total estimated contract revenue only to the extent that contract costs related to the claim have been incurred and when it is probable that the unapproved change order or claim will result in:
| • | a bona fide addition to contract value; and |
| • | revenues can be reliably estimated. |
These two conditions are satisfied when:
| • | the contract or other evidence provides a legal basis for the unapproved change order or claim or a legal opinion is obtained providing a reasonable basis to support the unapproved change order or claim; |
| • | additional costs incurred were caused by unforeseen circumstances and are not the result of deficiencies in the Company’s performance; |
| • | costs associated with the unapproved change order or claim are identifiable and reasonable in view of work performed; and |
| • | evidence supporting the unapproved change order or claim is objective and verifiable. |
This can lead to a situation where costs are recognized in one period and revenue is recognized when customer agreement is obtained or claim resolution occurs, which can be in subsequent periods. Historical claim recoveries should not be considered indicative of future claim recoveries.
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The Company’s long term contracts typically allow its customers to unilaterally reduce or eliminate the scope of the work as contracted without cause. These long term contracts represent higher risk due to uncertainty of total contract value and estimated costs to complete; therefore, potentially impacting revenue recognition in future periods.
A contract is regarded as substantially completed when remaining costs and potential risks are insignificant in amount.
The Company recognizes revenue from the sale of its other products and services as follows:
| • | Revenue recognition from equipment rentals occurs when there is a written arrangement in the form of a contract or purchase order with the customer, a fixed or determinable sales price is established with the customer, performance requirements are achieved, and ultimate collection of the revenue is reasonably assured. Equipment rental revenue is recognized as performance requirements are achieved in accordance with the terms of the relevant agreement with the customer, either at a monthly fixed rate or on a usage basis dependent on the number of hours that the equipment is used; |
| • | Revenue from tank services is provided based upon orders and contracts with the customer that include fixed or determinable prices based upon daily, hourly or job rates and is recognized as the services are provided to the customer; and |
| • | Revenue from anchor manufacturing and product sales is recognized when the products are shipped to the customer. |
The Company recognizes revenue from the foregoing activities once persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, fees are fixed and determinable and collectability is reasonably assured.
d) Balance sheet classifications
A one-year time period is typically used as the basis for classifying all other current assets and liabilities. However, included in current assets and liabilities are amounts receivable and payable under construction contracts (principally holdbacks) that may extend beyond one year.
e) Cash and cash equivalents
Cash and cash equivalents include cash on hand, bank balances net of outstanding cheques and short-term investments with maturities of three months or less when purchased.
f) Accounts receivable and unbilled revenue
Accounts receivable in the accompanying Consolidated Balance Sheets are primarily comprised of amounts billed to clients for services already provided, but which have not yet been collected. Unbilled revenue represents revenue recognized in advance of amounts billed to clients.
g) Billings in excess of costs incurred and estimated earnings on uncompleted contracts
Billings in excess of costs incurred and estimated earnings on uncompleted contracts represent amounts invoiced in excess of revenue recognized.
h) Allowance for doubtful accounts
The Company evaluates the probability of collection of accounts receivable and records an allowance for doubtful accounts, which reduces accounts receivable to the amount management reasonably believes will be collected. In determining the amount of the allowance, the following factors are considered: the length of time the receivable has been outstanding, specific knowledge of each customer’s financial condition and historical experience.
i) Inventories
Inventories are carried at the lower of weighted average cost and market, and consist primarily of spare tires, job materials, manufacturing raw materials and finished goods. Finished goods cost includes raw materials, labour and a reasonable allocation of appropriate overhead costs.
j) Property, plant and equipment
Property, plant and equipment are recorded at cost. Major components of heavy construction equipment in use such as engines and drive trains are recorded separately. Equipment under capital lease is recorded at the present value of minimum lease payments at the inception of the lease. Depreciation is not recorded until an asset is available for use. Depreciation for each category is calculated based on the cost, net of the estimated residual value, over the estimated useful life of the assets on the following bases and annual rates:
| Assets | Basis | Rate | ||
| Heavy equipment |
Straight-line | Operating hours | ||
| Major component parts in use |
Straight-line | Operating hours | ||
| Other equipment |
Straight-line | 5 – 10 years | ||
| Licensed motor vehicles |
Declining balance | 30% | ||
| Office and computer equipment |
Straight-line | 4 years | ||
| Buildings |
Straight-line | 10 years | ||
| Leasehold improvements |
Straight-line | Over shorter of estimated useful life and lease term |
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The costs for periodic repairs and maintenance are expensed to the extent the expenditures serve only to restore the assets to their normal operating condition without enhancing their service potential or extending their useful lives.
k) Capitalized interest
The Company capitalizes interest incurred on debt during the construction of assets for the Company’s own use. The capitalization period covers the duration of the activities required to get the asset ready for its intended use, provided that expenditures for the asset have been made and interest cost incurred. Interest capitalization continues as long as those activities and the incurrence of interest cost continue. The capitalized interest is amortized at the same rate as the respective asset.
l) Goodwill
Goodwill is an asset representing the future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is not amortized but instead is tested for impairment annually or more frequently if events or changes in circumstances indicate that it may be impaired. Goodwill is assigned, as of the date of the business combination, to reporting units that are expected to benefit from the business combination. The impairment test is carried out in two steps. In the first step, the carrying amount of the reporting unit, including goodwill, is compared to its fair value. When the fair value of the reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to be impaired and the second step of the impairment test is unnecessary. The second step is carried out when the carrying amount of a reporting unit exceeds its fair value, in which case, the implied fair value of the reporting unit’s goodwill, determined in the same manner as the value of goodwill is determined in a business combination, is compared with its carrying amount to measure the amount of the impairment loss, if any.
The Company performs its annual goodwill assessment on October 1 of each year and when a triggering event occurs between annual impairment tests.
m) Intangible assets
Intangible assets include:
| • | Customer relationships and backlog, which are being amortized over the remaining lives of the related contracts and relationships; |
| • | trade names, which are being amortized on a straight-line basis over their estimated useful lives of between five and ten years; |
| • | non-competition agreements, which are being amortized on a straight-line basis between the three and five-year terms of the respective agreements; |
| • | capitalized computer software and development costs, which are being amortized on a straight-line basis over a maximum period of four years; and |
| • | patents, which are being amortized on a straight-line basis over estimated useful lives of up to six years. |
The Company expenses or capitalizes costs associated with the development of internal-use software as follows:
Preliminary project stage: Both internal and external costs incurred during this stage are expensed as incurred.
Application development stage: Both internal and external costs incurred to purchase and develop computer software are capitalized after the preliminary project stage is completed and management authorizes the computer software project. However, training costs and the process of data conversion from the old system to the new system, which includes purging or cleansing of existing data, reconciliation or balancing of old data to the converted data in the new system, are expensed as incurred.
Post implementation/operation stage: All training costs and maintenance costs incurred during this stage are expensed as incurred.
Costs of upgrades and enhancements are capitalized if the expenditures will result in adding functionality to the software.
n) Impairment of long-lived assets
Long-lived assets or asset groups held and used including plant, equipment and identifiable intangible assets subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of an asset or group of assets is less than its carrying amount, it is considered to be impaired. The Company measures the impairment loss as the amount by which the carrying amount of the asset or group of assets exceeds its fair value, which is charged to depreciation or amortization expense. In determining whether an impairment exists, the Company makes assumptions about the future cash flows expected from the use of its long-lived assets, such as: applicable industry performance and prospects; general business and economic conditions that prevail and are expected to prevail; expected growth; maintaining its customer base; and, achieving cost reductions. There can be no assurance that expected future cash flows will be realized, or will be sufficient to recover the carrying amount of long-lived assets. Furthermore, the process of determining fair values is subjective and requires management to exercise judgment in making assumptions about future results, including revenue and cash flow projections and discount rates.
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o) Assets held for sale
Long-lived assets are classified as held for sale when certain criteria are met, which include:
| • | management, having the authority to approve the action, commits to a plan to sell the assets; |
| • | the assets are available for immediate sale in their present condition; |
| • | an active program to locate buyers and other actions to sell the assets have been initiated; |
| • | the sale of the assets is probable and their transfer is expected to qualify for recognition as a completed sale within one year; |
| • | the assets are being actively marketed at reasonable prices in relation to their fair value; and |
| • | it is unlikely that significant changes will be made to the plan to sell the assets or that the plan will be withdrawn. |
Assets to be disposed of by sale are reported at the lower of their carrying amount or fair value less costs to sell and are disclosed separately on the Consolidated Balance Sheets. These assets are not depreciated.
p) Asset retirement obligations
Asset retirement obligations are legal obligations associated with the retirement of property, plant and equipment that result from their acquisition, lease, construction, development or normal operations. The Company recognizes its contractual obligations for the retirement of certain tangible long-lived assets. The fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of a liability for an asset retirement obligation is the amount at which that liability could be settled in a current transaction between willing parties, that is, other than in a forced or liquidation transaction and, in the absence of observable market transactions, is determined as the present value of expected cash flows. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset and then amortized using a systematic and rational method over its estimated useful life. In subsequent reporting periods, the liability is adjusted for the passage of time through an accretion charge and any changes in the amount or timing of the underlying future cash flows are recognized as an additional asset retirement cost.
q) Foreign currency translation
The functional currency of the Company and the majority of its subsidiaries is Canadian Dollars. Transactions denominated in foreign currencies are recorded at the rate of exchange on the transaction date. Monetary assets and liabilities, denominated in foreign currencies, are translated into Canadian Dollars at the rate of exchange prevailing at the balance sheet date. Foreign exchange gains and losses are included in the determination of earnings.
Accounts of the Company’s US-based subsidiary, which has a US Dollar functional currency, are translated into Canadian Dollars using the current rate method. Assets and liabilities are translated at the rate of exchange in effect at the balance sheet date, and revenue and expense items (including depreciation and amortization) are translated at the average rate of exchange for the period. The resulting unrealized exchange gains and losses from these translation adjustments are included as a separate component of shareholders’ equity in Accumulated Other Comprehensive Income (Loss). The effect of exchange rate changes on cash balances held in foreign currencies is separately reported as part of the reconciliation of the change in cash and cash equivalents for the period.
r) Fair value measurement
Fair value measurements are categorized using a valuation hierarchy for disclosure of the inputs used to measure fair value, which prioritizes the inputs into three broad levels. Fair values included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Fair values included in Level 2 include valuations using inputs based on observable market data, either directly or indirectly other than the quoted prices. Level 3 valuations are based on inputs that are not based on observable market data. The classification of a fair value within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.
s) Derivative financial instruments
The Company uses derivative financial instruments to manage financial risks from fluctuations in exchange rates and interest rates. These instruments include cross-currency and interest rate swap agreements as well as embedded price escalation features in revenue and supplier contracts. All such instruments are only used for risk management purposes. The Company does not hold or issue derivative financial instruments for trading or speculative purposes. Derivative financial instruments are subject to standard credit terms and conditions, financial controls, management and risk monitoring procedures. These derivative financial instruments are not designated as hedges for accounting purposes and are recorded at fair value with realized and unrealized gains and losses recognized in the Consolidated Statements of Operations.
t) Income taxes
The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized based on the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities from a change in tax rates is recognized in income in the period of enactment. The Company recognizes the effect of income tax positions only if those positions are more likely than not (greater than 50%) of
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being sustained. Changes in recognition or measurement are reflected in the period in which the change in judgement occurs. The Company accrues interest and penalties for uncertain tax positions in the period in which these uncertainties are identified. Interest and penalties are included in “General and administrative expenses” in the Consolidated Statements of Operations. A valuation allowance is recorded against any deferred tax asset if it is more likely than not that the asset will not be realized.
u) Stock-based compensation
The Company has a Share Option Plan which is described in note 27(b). The Company accounts for all stock-based compensation payments that are settled by the issuance of equity instruments at fair value. Compensation cost is measured using the Black-Scholes model at the grant date and is expensed on a straight-line basis over the award’s vesting period, with a corresponding increase to additional paid-in capital. Upon exercise of a stock option, share capital is recorded at the sum of proceeds received and the related amount of additional paid-in capital.
The Company has a Senior Executive Stock Option Plan which is described in note 27(c). This compensation plan allows the option holder the right to settle options in cash. The liability is measured at fair value using the Black-Scholes model at the modification date and subsequently at each period end date. Changes in fair value of the liability are recognized in the Consolidated Statements of Operations.
The Company has a Deferred Performance Share Unit (“DPSU”) Plan which is described in note 27(d). This compensation plan is settled, at the Company’s option, either by the issuance of equity instruments or by cash payment. Compensation cost is measured using the Black-Scholes model at the grant date and is expensed on a straight-line basis over the award’s vesting period, with a corresponding increase to additional paid-in capital. The vesting of awards under the DPSU plan is contingent upon certain performance criteria being achieved. The fair value of each share option grant under the DPSU plan assumes that the relevant performance criteria will be achieved and compensation cost is recorded to the extent that vesting of the award is considered probable. When it is determined that such criteria are not probable of being achieved, no compensation cost is recognized and any previously recognized compensation cost is reversed. The company has no outstanding DPSUs at this time.
The Company has a Restricted Share Unit (“RSU”) Plan which is described in note 27(e). RSUs are granted effective April 1 of each fiscal year with respect to services to be provided in that fiscal year and the following two fiscal years. The RSUs vest at the end of a three-year term. The Company classifies RSUs as a liability as the Company has the ability and intent to settle the awards in cash. Compensation expense is calculated based on the number of vested shares multiplied by the fair market value of each RSU as determined by the volume weighted average trading price of the Company’s common shares for the five trading days immediately preceding the day on which the fair market value is to be determined. The Company recognizes compensation expense over the three-year term of the RSU in the Consolidated Statements of Operations.
The Company has a Director’s Deferred Stock Unit (“DDSU”) Plan which is described in note 27(f). The DDSU plan enables directors to receive all or a portion of their fee for that fiscal year in the form of deferred stock units. The deferred stock units are settled in cash and are classified as a liability on the Consolidated Balance Sheets. The measurement of the liability and compensation costs for these awards is based on the fair value of the unit and is recorded as a charge to operating income when issued. Subsequent changes in the Company’s payment obligation after issuing the unit and prior to the settlement date are recorded as a charge to operating income in the period such changes occur.
The Company has a Stock Award Plan which is described in note 27(g). The stock awards are settled at the Company’s option, either by the issuance of equity instruments if all necessary shareholder approvals and regulatory approvals are obtained or by cash payment. Compensation cost is measured using the market price of the Company’s common shares at the grant date and is expensed on a straight-line basis over the award’s vesting period, with a corresponding increase to additional paid-in capital.
v) Net (loss) income per share
Basic net (loss) income per share is computed by dividing net income available to common shareholders by the weighted average number of shares outstanding during the year (see note 18(b)). Diluted per share amounts are calculated using the treasury stock method. The treasury stock method increases the diluted weighted average shares outstanding to include additional shares from the assumed exercise of stock options, if dilutive. The number of additional shares is calculated by assuming outstanding in-the-money stock options were exercised and the proceeds from such exercises, including any unamortized stock-based compensation cost, were used to acquire shares of common stock at the average market price during the year.
w) Leases
Leases entered into by the Company in which substantially all the benefits and risks of ownership are transferred to the Company are recorded as obligations under capital leases, and under the corresponding category of property, plant and equipment. Obligations under capital leases reflect the present value of future lease payments, discounted at an appropriate interest rate, and are reduced by rental payments net of imputed interest. All other leases are classified as operating leases and leasing costs, including any rent holidays, leasehold incentives, and rent concessions, are amortized on a straight-line basis over the lease term.
Certain operating lease and rental agreements provide a maximum hourly usage limit, above which the Company will be required to pay for the over hour usage as a contingent rent expense. These contingent expenses are recognized when the likelihood of exceeding the usage limit is considered probable and are due at the end of the lease term or rental period. The contingent rental expenses are included in “Equipment operating lease expense” in the Consolidated Statements of Operations.
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x) Deferred financing costs
Underwriting, legal and other direct costs incurred in connection with the issuance of debt not measured under the fair value option are presented as deferred financing costs. The deferred financing costs related to the senior notes, debentures and the revolving and term loan facilities are amortized over the term of the related debt using the effective interest method.
y) Investments in unconsolidated joint ventures or affiliates
Investments in unconsolidated joint ventures or affiliates over which the Company has significant influence including the Company’s investment in Noramac Ventures Inc. are accounted for under the equity method of accounting, whereby the investment is carried at the cost of acquisition, including subsequent capital contributions and loans from the Company, plus the Company’s equity in undistributed earnings or losses since acquisition. Investments in unconsolidated joint ventures are included as investment in and advances to unconsolidated joint venture in the Company’s Consolidated Balance Sheets.
z) Business combinations
The Company accounts for all business combinations using the acquisition method. Acquisition related costs which include finder’s fees, advisory, legal, accounting, valuation, other professional or consulting fees, and administrative costs are expensed as incurred.
3. Accounting pronouncements recently adopted
a) Revenue recognition
In October 2009, the FASB issued ASU No. 2009-13, “Revenue Recognition: Multiple-Deliverable Revenue Arrangements”, which addresses the accounting for multiple-deliverable arrangements to enable vendors to account for products or services separately rather than as a combined unit. The amendments establish a selling price hierarchy for determining the selling price of a deliverable. The amendments also eliminate the residual method of allocation and require that arrangement consideration be allocated at the inception of the arrangement to all deliverables using the relative selling price method. The Company adopted this ASU effective April 1, 2011. The adoption of this standard did not have a material effect on the Company’s consolidated financial statements.
b) Share based payment awards
In April 2010, the FASB issued ASU No. 2010-13, “Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades”, which clarifies that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. The Company adopted this ASU effective April 1, 2011 as an amendment to ASC 718, “Compensation – Stock Compensation”. The adoption of this standard did not have a material effect on the Company’s consolidated financial statements.
c) Intangibles – Goodwill and Other
In December 2010, the FASB issued ASU No. 2010-28, “When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts”, which amends ASC 350, “Intangibles-Goodwill and Other” to modify step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts, to require an entity to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that impairment may exist. The Company adopted this ASU effective April 1, 2011. The adoption of this standard did not have a material effect on the Company’s consolidated financial statements.
d) Business Combinations
In December 2010, the FASB issued ASU No. 2010-29, “Disclosure of Supplementary Pro Forma Information for Business Combinations”, which amends ASC 805, “Business Combinations”, to require that pro-forma information be presented as if the business combination occurred at the beginning of the prior annual reporting period for the purposes of calculating both the current reporting period and the prior reporting period pro forma financial information. The ASU also requires the disclosure be accompanied by a narrative description of the nature and amount of material, nonrecurring pro forma adjustments. The Company adopted this ASU prospectively effective April 1, 2011 for business combinations for which the acquisition date is on or after April 1, 2011. The adoption of this standard did not have a material effect on the Company’s consolidated financial statements.
e) Fair value measurement
In May 2011, the FASB issued ASU 2011-04, “Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRS”, which generally represent clarifications of Topic 820, but also include some instances where a particular principle or requirement for measuring fair value or disclosing information about fair value measurements has changed. This ASU results in common principles and requirements for measuring fair value and for disclosing information about fair value measurements in accordance with US GAAP and IFRSs. The Company adopted this ASU prospectively effective January 1, 2012. The adoption of this standard did not have a material effect on the Company’s consolidated financial statements.
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4. Recent United States accounting pronouncements not yet adopted
a) Goodwill Impairment
In September 2011, the FASB issued ASU 2011-08, “Intangibles – Goodwill and Other – Testing Goodwill for Impairment”, which amended the guidance on the annual testing of goodwill for impairment. The amended guidance will allow companies to assess qualitative factors to determine if it is more-likely-than-not that goodwill might be impaired and whether it is necessary to perform the two-step goodwill impairment test required under current accounting standards. This guidance will be effective for the Company’s fiscal year ending March 31, 2013, with early adoption permitted. The Company has determined that this new guidance will not have a material impact on its consolidated financial statements.
b) Offsetting Assets and Liabilities
In December 2011, the FASB issued ASU 2011-11, “Balance Sheet”, which amends the disclosure requirements on offsetting in Section 210-20-50. The amendments require enhanced disclosures by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with either Section 210-20-45 or Section 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either Section 210-20-45 or Section 815-10-45. This guidance will be effective for the Company’s fiscal year ending March 31, 2014. This standard does not amend the existing guidance on when it is appropriate to offset. The adoption of this standard is not anticipated to have a material effect on the Company’s consolidated financial statements.
c) Comprehensive income
In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. This ASU requires the presentation of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements rather than as a footnote to the consolidated financial statements, where it is currently disclosed. The ASU also requires the presentation of reclassification adjustments for items that are reclassified from other comprehensive income to net income in the financial statements where the components of net income and the components of other comprehensive income are presented. The option under current guidance that permits the presentation of components of other comprehensive income as part of the statement of changes in shareholders’ equity will be eliminated. In December 2011, the FASB further amended its guidance to defer changes related to the presentation of reclassification adjustments indefinitely as a result of concerns raised by stakeholders that the new presentation requirements would be difficult for preparers and add unnecessary complexity to financial statements. This guidance will be effective for the Company’s fiscal year ending March 31, 2013. The Company has determined that this new guidance will not have a material impact on its consolidated financial statements.
5. Goodwill
In accordance with the Company’s accounting policy, a goodwill impairment test is completed on October 1 of each fiscal year or whenever events or changes in circumstances indicate that impairment may exist. The Company conducted its annual goodwill impairment tests on October 1, 2011, 2010 and 2009 and concluded that there was no goodwill impairment as the fair value of the Piling reporting unit exceeded its carrying value. There were no triggering events between October 1, 2011 and March 31, 2012.
The changes in goodwill during the years ended March 31, 2012, 2011 and 2010 are as follows:
| Balance at March 31, 2009 |
$23,872 | |||
| Acquisition of goodwill (assigned to the Piling segment) (note 6(b)) |
1,239 | |||
| Balance at March 31, 2010 |
25,111 | |||
| Acquisition of goodwill (assigned to the Piling segment) (note 6(a)) |
7,790 | |||
| Balance at March 31, 2011 and March 31, 2012 |
$32,901 |
6. Acquisitions
a) Acquisitions in fiscal 2011
On November 1, 2010, the Company acquired all of the assets of Cyntech Corporation and its wholly-owned subsidiary Cyntech Anchor Systems LLC (collectively “Cyntech”), for consideration of $23,501. Cyntech is based in Calgary, Alberta and designs and manufactures screw piles and pipeline anchoring systems, and provides tank maintenance services to the petro-chemical industry. As a result of this acquisition, the Company gained access to screw piling, pipeline anchor design and manufacturing capabilities in Canada and the United States. The Company also gained oil and gas storage tank repair and maintenance capabilities which complement the Company’s existing service offering. The transaction was accounted for using the acquisition method with the results of operations included in the financial statements from the date of acquisition. Acquisition related costs were recorded in general and administrative expenses. The goodwill acquired is deductible for tax purposes.
| 2012 Annual Report | 75 |
The following table summarizes the recognized amounts of the assets acquired and liabilities assumed at the acquisition date:
| Accounts receivable |
$7,064 | |||
| Inventories |
1,646 | |||
| Prepaid expenses and deposits |
45 | |||
| Plant and equipment |
1,346 | |||
| Intangible assets |
7,284 | |||
| Accounts payable |
(1,674 | ) | ||
| Total identifiable net assets |
$15,711 | |||
| Goodwill |
7,790 | |||
| Total consideration |
$23,501 |
b) Acquisitions in fiscal 2010
On August 1, 2009, the Company acquired all of the issued and outstanding shares of DF Investments Limited and its subsidiary Drillco Foundation Co. Ltd., a piling company based in Milton, Ontario, for consideration of $5,410. This acquisition provided the Company access to piling markets and customers in the Toronto area. The transaction was accounted for using the acquisition method with the results of operations included in the financial statements from the date of acquisition. The goodwill acquired is not deductible for tax purposes.
The following table summarizes the recognized amounts of the assets acquired and liabilities assumed at the acquisition date:
| Accounts receivable |
$4,101 | |||
| Inventories |
59 | |||
| Prepaid expenses and deposits |
11 | |||
| Property, plant and equipment |
2,873 | |||
| Land |
281 | |||
| Intangible assets |
547 | |||
| Accounts payable and accrued liabilities |
(2,211 | ) | ||
| Deferred tax liabilities |
(838 | ) | ||
| Long term debt |
(652 | ) | ||
| Total identifiable net assets |
$4,171 | |||
| Goodwill |
1,239 | |||
| Total consideration |
$5,410 |
7. Accounts receivable
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Accounts receivable – trade |
$180,917 | $115,660 | ||||||||
| Accounts receivable – holdbacks |
32,134 | 12,018 | ||||||||
| Income and other taxes receivable |
– | 397 | ||||||||
| Accounts receivable – other |
1,288 | 437 | ||||||||
| Allowance for doubtful accounts (note 21(d)) |
(210 | ) | (30 | ) | ||||||
| $214,129 | $128,482 | |||||||||
Accounts receivable – holdbacks represent amounts up to 10% under certain contracts that the customer is contractually entitled to withhold until completion of the project or until certain project milestones are achieved. Holdbacks include $6,038 as of March 31, 2012 (March 31, 2011– $587) which relate to contracts whereby the normal operating cycle is greater than one year and therefore are not expected to be collected within a year.
8. Costs incurred and estimated earnings net of billings on uncompleted contracts
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Costs incurred and estimated earnings on uncompleted contracts |
$587,220 | $946,482 | ||||||||
| Less billings to date |
(509,511 | ) | (845,547 | ) | ||||||
| $77,709 | $100,935 | |||||||||
Costs incurred and estimated earnings net of billings on uncompleted contracts is presented in the Consolidated Balance Sheets under the following captions:
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Unbilled revenue |
$86,859 | $102,939 | ||||||||
| Billings in excess of costs incurred and estimated earnings on uncompleted contracts |
(7,514 | ) | (2,004 | ) | ||||||
| $79,345 | $100,935 | |||||||||
| 76 | 2012 Annual Report |
NOA
Unbilled revenue related to non-construction activities amounted to $1,636 (March 31, 2011– $nil).
An amount of $18,080 (March 31, 2011 – $72,025) is recognized within unbilled revenue relating to a single long-term customer contract, whereby the normal operating cycle for this project is greater than one year. As described in Note 2(b) the estimated balances within unbilled revenue are subject to uncertainty concerning ultimate realization.
9. Inventories
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Spare tires |
$6,620 | $3,794 | ||||||||
| Job materials |
2,188 | 2,118 | ||||||||
| Manufacturing raw materials |
1,669 | 926 | ||||||||
| Finished goods |
1,378 | 897 | ||||||||
| $11,855 | $7,735 | |||||||||
10. Prepaid expenses and deposits
| Current: |
||||||||||
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Prepaid insurance and property taxes |
$1,257 | $1,022 | ||||||||
| Prepaid lease payments |
4,624 | 6,203 | ||||||||
| Prepaid interest |
434 | 1,044 | ||||||||
| $6,315 | $8,269 | |||||||||
| Long term: |
||||||||||
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Prepaid lease payments (note 12(a)) |
$895 | $2,354 | ||||||||
11. Investment in and advances to unconsolidated joint venture
The Company was engaged in a joint venture, Noramac Joint Venture (JV), of which the Company had joint control (50% proportionate interest). The JV was formed for the purpose of expanding the Company’s market opportunities and establishing strategic alliances in Northern Alberta. The Company owned a 49% interest in Noramac Ventures Inc., a nominee company established by the two joint venture partners. On March 25, 2011, the Company and its joint venture partner decided to wind up Noramac Ventures Inc. and terminate the joint venture. At March 31, 2012 and 2011, the assets and liabilities of the joint venture are stated at the lower of carrying value and fair market value less costs to sell. The difference between carrying value and fair market value of assets and liabilities was recognized in the income statement of the joint venture during the years ended March 31, 2012 and 2011.
As of March 31, 2012, the Company’s investment in and advances to the unconsolidated joint venture totalled $1,574 (2011 – $1,488; 2010 – $2,917). The condensed financial data for investment in and advances to unconsolidated joint venture is summarized as follows:
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Current assets |
$6,556 | $8,328 | ||||||||
| Current liabilities |
10,716 | 13,875 | ||||||||
| Year ended March 31, | 2012 | 2011 | 2010 | |||||||||||||
| Gross revenues |
$1,922 | $12,196 | $8,774 | |||||||||||||
| Gross (profit) loss |
1,922 | 2,483 | (1,610 | ) | ||||||||||||
| Net (income) loss |
(172 | ) | 5,440 | (87 | ) | |||||||||||
| Equity in (earnings) loss of unconsolidated joint venture |
($86 | ) | $2,720 | $(44 | ) | |||||||||||
12. Other assets
a) Other assets are as follows:
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Prepaid lease payments (note 10) |
$895 | $2,354 | ||||||||
| Assets held for sale (note 12(b) and 21(a)) |
1,841 | 721 | ||||||||
| Intangible assets (note 12(c)) |
12,866 | 16,161 | ||||||||
| Deferred financing costs (note 12(d)) |
6,141 | 7,672 | ||||||||
| $21,743 | $26,908 | |||||||||
| 2012 Annual Report | 77 |
b) Assets held for sale
Equipment disposal decisions are made using an approach in which a target life is set for each type of equipment. The target life is based on the manufacturer’s recommendations and the Company’s past experience in the various operating environments. Once a piece of equipment reaches its target life it is evaluated to determine if disposal is warranted based on its expected operating cost and reliability in its current state. If the expected operating cost exceeds the target operating cost for the fleet or if the expected reliability is lower than the target reliability of the fleet, the unit is considered for disposal. Expected operating costs and reliability are based on the past history of the unit and experience in the various operating environments. Assets held for sale are sold on the Company’s used equipment website and syndicated on third party equipment sale websites. If a sale is not realized after a reasonable length of time, the equipment will be sent to auction for disposal.
During the year ended March 31, 2012, impairment of assets held for sale amounting to $8,748, largely due to the writedown of several haul trucks to fair value, have been included in depreciation expense in the Consolidated Statements of Operations (2011 – $141; 2010 – $806). The impairment charge is the amount by which the carrying value of the related assets exceeded their fair value less costs to sell. Gain on disposal of assets held for sale was $466 for the year ended March 31, 2012 (2011 – loss of $825; 2010 – loss of $373).
c) Intangible assets
| March 31, 2012 | Cost | Accumulated Amortization |
Net Book Value | |||||||||||||||
| Customer relationships and backlog |
$4,442 | $1,445 | $2,997 | |||||||||||||||
| Other intangible assets |
2,364 | 1,204 | 1,160 | |||||||||||||||
| Internal-use software |
16,825 | 9,644 | 7,181 | |||||||||||||||
| Patents |
2,017 | 489 | 1,528 | |||||||||||||||
| $25,648 | $12,782 | $12,866 | ||||||||||||||||
| March 31, 2011 | Cost | Accumulated Amortization |
Net Book Value | |||||||||||||||
| Customer relationships and backlog |
$4,442 | $755 | $3,687 | |||||||||||||||
| Other intangible assets |
2,364 | 779 | 1,585 | |||||||||||||||
| Internal-use software |
15,469 | 6,441 | 9,028 | |||||||||||||||
| Patents |
2,017 | 156 | 1,861 | |||||||||||||||
| $24,292 | $8,131 | $16,161 | ||||||||||||||||
During the year ended March 31, 2012, the Company capitalized $3,537 (2011 – $4,748; 2010 – $3,362) related to internally developed computer software. Internal use software with a cost of $607 and accumulated amortization of $358 was written off and the net book value of $249 was included in amortization of intangible assets during the year ended March 31, 2012 (2011 – $nil; 2010 – $208).
Amortization of intangible assets for the year ended March 31, 2012 was $5,702 (2011 – $3,540; 2010 – $1,719). The estimated amortization expense for future years is as follows:
| For the year ending March 31, |
||||
| 2013 |
$4,325 | |||
| 2014 |
3,625 | |||
| 2015 |
2,474 | |||
| 2016 |
1,574 | |||
| 2017 and thereafter |
868 | |||
| $12,866 |
During the year ended March 31, 2011, $7,284 in additions were made to intangible assets as a result of the acquisition of the assets of Cyntech Corporation and its wholly-owned subsidiary Cyntech Anchor Systems LLC (note 6(a)).
During the year ended March 31, 2010, $547 in additions were made to intangible assets as a result of the acquisition of DF Investments Limited and its subsidiary, Drillco Foundation Co. Ltd. (note 6(b)).
| 78 | 2012 Annual Report |
NOA
d) Deferred financing costs
| March 31, 2012 | Cost | Accumulated Amortization |
Net Book Value | |||||||||||||
| Term and revolving facilities |
$5,422 | $4,652 | $770 | |||||||||||||
| Series 1 Debentures |
6,886 | 1,515 | 5,371 | |||||||||||||
| $12,308 | $6,167 | $6,141 | ||||||||||||||
| March 31, 2011 | Cost | Accumulated Amortization |
Net Book Value | |||||||||||||
| Term and revolving facilities |
$5,362 | $3,855 | $1,507 | |||||||||||||
| Series 1 Debentures |
6,886 | 721 | 6,165 | |||||||||||||
| $12,248 | $4,576 | $7,672 | ||||||||||||||
During the year ended March 31, 2012, financing fees of $60 were incurred in connection with the modifications made to the amended and restated credit agreement (2011 – $1,034; 2010 – $1,123) (note 15(b)). During the year ended March 31, 2012, financing fees of $nil were incurred in connection with the Series 1 Debentures (2011 – $5,846) (note 15(e)). These fees have been recorded as deferred financing costs and are being amortized using the effective interest method over the term of the credit agreement and the series 1 Debentures, respectively.
Amortization of deferred financing costs included in interest expense for the year ended March 31, 2012 was $1,591 (2011–$1,609; 2010 – $3,348). Upon redemption of the 8 3/4% senior notes on April 28, 2010, the unamortized deferred financing costs related to the 8 3/4% senior notes of $4,324 were expensed and included in the loss on debt extinguishment (note 15(d)). In addition, $183 related to amortization of deferred financing costs incurred up to the redemption date was included in interest expense.
13. Property, plant and equipment
| March 31, 2012 | Cost | Accumulated Deprecation |
Net Book Value | |||||||||||||
| Heavy equipment |
$347,699 | $124,982 | $222,717 | |||||||||||||
| Major component parts in use |
74,444 | 28,741 | 45,703 | |||||||||||||
| Other equipment |
35,736 | 17,017 | 18,719 | |||||||||||||
| Licensed motor vehicles |
27,120 | 19,775 | 7,345 | |||||||||||||
| Office and computer equipment |
13,438 | 8,977 | 4,461 | |||||||||||||
| Buildings |
4,355 | 3,235 | 1,120 | |||||||||||||
| Land |
281 | – | 281 | |||||||||||||
| Leasehold improvements |
6,620 | 2,232 | 4,388 | |||||||||||||
| Assets under capital lease |
16,579 | 8,538 | 8,041 | |||||||||||||
| $526,272 | $213,497 | $312,775 | ||||||||||||||
| March 31, 2011 | Cost | Accumulated Deprecation |
Net Book Value | |||||||||||||
| Heavy equipment |
$341,734 | $108,051 | $233,683 | |||||||||||||
| Major component parts in use |
47,248 | 15,593 | 31,655 | |||||||||||||
| Other equipment |
31,877 | 14,136 | 17,741 | |||||||||||||
| Licensed motor vehicles |
21,368 | 16,592 | 4,776 | |||||||||||||
| Office and computer equipment |
12,128 | 5,899 | 6,229 | |||||||||||||
| Buildings |
21,657 | 8,176 | 13,481 | |||||||||||||
| Land |
281 | – | 281 | |||||||||||||
| Leasehold improvements |
9,422 | 3,856 | 5,566 | |||||||||||||
| Assets under capital lease |
19,506 | 11,054 | 8,452 | |||||||||||||
| $505,221 | $183,357 | $321,864 | ||||||||||||||
Assets under capital lease are comprised predominately of licensed motor vehicles.
During the year ended March 31, 2012, additions to property, plant and equipment included $7,215 of assets that were acquired by means of capital leases (2011 – $427; 2010 – $1,523). Depreciation of equipment under capital lease of $2,005 (2011 – $2,723; 2010 – $4,081) was included in depreciation expense.
| 2012 Annual Report | 79 |
14. Accrued liabilities
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Accrued interest payable |
$9,866 | $9,866 | ||||||||
| Payroll liabilities |
15,228 | 11,412 | ||||||||
| Liabilities related to equipment leases |
4,238 | 7,518 | ||||||||
| Income and other taxes payable |
7,463 | 4,018 | ||||||||
| $36,795 | $32,814 | |||||||||
15. Long term debt
a) Long term debt are as follows:
| Current: |
||||||||||
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Credit facilities (note 15(b)) |
$10,000 | $10,000 | ||||||||
| Capital lease obligations (note 15(c)) |
4,402 | $4,862 | ||||||||
| $14,402 | $14,862 | |||||||||
| Long term: |
||||||||||
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Credit facilities (note 15(b)) |
$68,767 | $61,970 | ||||||||
| Capital lease obligations (note 15(c)) |
6,299 | 3,831 | ||||||||
| Series 1 Debentures (note 15(e)) |
225,000 | 225,000 | ||||||||
| $300,066 | $290,801 | |||||||||
b) Credit Facilities
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Term A Facility |
$20,950 | $24,698 | ||||||||
| Term B Facility |
37,496 | 43,748 | ||||||||
| Total term facilities |
$58,446 | $68,446 | ||||||||
| Revolving Facility |
20,321 | 3,524 | ||||||||
| Total credit facilities |
$78,767 | $71,970 | ||||||||
| Less: current portion of term facilities |
(10,000 | ) | (10,000 | ) | ||||||
| $68,767 | $61,970 | |||||||||
As of March 31, 2012, the Company had outstanding borrowings of $58.4 million (March 31, 2011 – $68.4 million) under the term facilities, $20.3 million (March 31, 2011 – $3.5 million) under the Revolving Facility and had issued $15.0 million (March 31, 2011 – $12.3 million) in letters of credit under the Revolving Facility to support performance guarantees associated with customer contracts. The funds available for borrowing under the Revolving Facility are reduced by any outstanding letters of credit.
Effective September 30, 2011, the Company entered into a Second Amending Agreement to the Fourth Amended and Restated Credit Agreement to provide a temporary increase in the amount available under the Revolving Facility from $85 million to $110.0 million. This increase, which was to remain in effect until March 31, 2012, provided additional borrowing availability to meet working capital requirements and to accommodate the issuance of letters of credit. The receipt of proceeds resulting from the settlement of the Canadian Natural Resources Limited (Canadian Natural) contract negotiations were to be used to repay amounts outstanding on the Revolving Facility and the amount available for borrowing under the temporary addition was to be permanently reduced by the amount of the settlement proceeds received on December 22, 2011. The amount available under the temporary increase was reduced by the $4.3 million received from Canadian Natural, resulting in a reduction in the total amount available under the Revolving Facility to $105.7 million.
In March 2012, the Company entered into a Third Amending Agreement to the Fourth Amended and Restated Credit Agreement to extend the maturity date of the credit agreement by six months to October 31, 2013 and temporarily amended Consolidated EBITDA related covenants as defined within the credit agreement to maintain covenant compliance at year end. The amendment also extended the term of the temporary increase to the Company’s revolving credit facility to June 30, 2012. The Company’s unused borrowing availability under the Revolving Facility was $70.4 million at March 31, 2012. As defined in the agreement, 55% of the proceeds received from Canadian Natural will be used to prepay the outstanding principal and accrued interest under the temporary addition.
| 80 | 2012 Annual Report |
NOA
Interest on Canadian prime rate loans is paid at variable rates based on the Canadian prime rate plus the applicable pricing margin (as defined in the credit agreement). Interest on US base rate loans is paid at a rate per annum equal to the US base rate plus the applicable pricing margin. Interest on Canadian prime rate and US base rate loans is payable monthly in arrears and computed on the basis of a 365 day or 366 day year, as the case may be. Interest on LIBOR loans is paid during each interest period at a rate per annum, calculated on a 360 day year, equal to the LIBOR rate with respect to such interest period plus the applicable pricing margin. Stamping fees and interest related to the issuance of Bankers’ Acceptances is paid in advance upon the issuance of such Bankers’ Acceptance. The weighted average interest rate on Revolving Facility and Term Facility borrowings at March 31, 2012 was 6.92%.
The credit facilities are secured by a first priority lien on substantially all of the Company’s existing and after-acquired property and contain certain restrictive covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions, paying dividends or redeeming shares of capital stock.
c) Capital lease obligations
The Company’s capital leases primarily relate to licensed motor vehicles. The minimum lease payments due in each of the next five fiscal years are as follows:
| 2013 |
$4,693 | |||
| 2014 |
2,230 | |||
| 2015 |
1,938 | |||
| 2016 |
2,209 | |||
| 2017 |
651 | |||
| Subtotal: |
$11,721 | |||
| Less: amount representing interest |
(1,020 | ) | ||
| Present value of minimum lease payments |
$10,701 | |||
| Less: current portion |
(4,402 | ) | ||
| Long term portion |
$6,299 |
d) 8 3/4% Senior Notes
The 8 3/4% senior notes were issued on November 26, 2003 in the amount of US $200.0 million (Canadian $263.0 million). On April 28, 2010, the Company redeemed the 8 3/4% senior notes for $202,410 and recorded a $4,346 loss on debt extinguishment including a $4,324 write off of deferred financing costs (note 12(d)).
e) Series 1 Debentures
On April 7, 2010, the Company issued $225.0 million of 9.125% Series 1 Debentures (the “Series 1 Debentures”). The Series 1 Debentures mature on April 7, 2017. The Series 1 Debentures bear interest at 9.125% per annum and such interest is payable in equal instalments semi-annually in arrears on April 7 and October 7 in each year, commencing on October 7, 2010.
The Series 1 Debentures are unsecured senior obligations and rank equally with all other existing and future unsecured senior debt and senior to any subordinated debt that may be issued by the Company or any of its subsidiaries. The Series 1 Debentures are effectively subordinated to all secured debt to the extent of collateral on such debt.
At any time prior to April 7, 2013, the Company may redeem up to 35% of the aggregate principal amount of the Series 1 Debentures with the net cash proceeds of one or more public equity offerings at a redemption price equal to 109.125% of the principal amount, plus accrued and unpaid interest to the date of redemption, so long as:
| i) | at least 65% of the original aggregate amount of the Series 1 Debentures remains outstanding after each redemption; and |
| ii) | any redemption by the Company is made within 90 days of the equity offering. |
At any time prior to April 7, 2013, the Company may on one or more occasions redeem the Series 1 Debentures, in whole or in part, at a redemption price which is equal to the greater of (a) the Canada Yield Price (as defined in the trust indenture) and (b) 100% of the aggregate principal amount of Series 1 Debentures redeemed, plus, in each case, accrued and unpaid interest to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).
The Series 1 Debentures are redeemable at the option of the Company, in whole or in part, at any time on or after: April 7, 2013 at 104.563% of the principal amount; April 7, 2014 at 103.042% of the principal amount; April 7, 2015 at 101.520% of the principal amount; April 7, 2016 and thereafter at 100% of the principal amount; plus, in each case, interest accrued to the redemption date.
If a change of control occurs, the Company will be required to offer to purchase all or a portion of each debenture holder’s Series 1 Debentures, at a purchase price in cash equal to 101% of the principal amount of the Series 1 Debentures offered for repurchase plus accrued interest to the date of purchase.
| 2012 Annual Report | 81 |
16. Other long term obligations
a) Other long term obligations are as follows:
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Long term portion of liabilities related to equipment leases |
$3,169 | $12,747 | ||||||||
| Deferred lease inducements (note 16(b)) |
547 | 654 | ||||||||
| Asset retirement obligation (note 16(c)) |
434 | 395 | ||||||||
| Senior executive stock option plan (note 27(c)) |
1,322 | 5,115 | ||||||||
| Restricted share unit plan (note 27(e)) |
3,170 | 2,633 | ||||||||
| Director’s deferred stock unit plan (note 27(f)) |
2,284 | 4,032 | ||||||||
| $10,926 | $25,576 | |||||||||
| Less: current portion of restricted share unit plan (note 27(e)) |
(2,066 | ) | – | |||||||
| $8,860 | $25,576 | |||||||||
b) Deferred lease inducements
Lease inducements applicable to lease contracts are deferred and amortized as a reduction of general and administrative expenses on a straight-line basis over the lease term, which includes the initial lease term and renewal periods only where renewal is determined to be reasonably assured.
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Balance, beginning of year |
$654 | $761 | ||||||||
| Amortization of deferred lease inducements |
(107 | ) | (107 | ) | ||||||
| Balance, end of year |
$547 | $654 | ||||||||
c) Asset retirement obligation
The Company recorded an asset retirement obligation related to the future retirement of a facility on leased land. Accretion expense associated with this obligation is included in equipment costs in the Consolidated Statements of Operations.
The following table presents a continuity of the liability for the asset retirement obligation:
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Balance, beginning of year |
$395 | $360 | ||||||||
| Accretion expense |
39 | 35 | ||||||||
| Balance, end of year |
$434 | $395 | ||||||||
At March 31, 2012, estimated undiscounted cash flows required to settle the obligation were $1,084 (March 31, 2011 – $1,084). The credit adjusted risk-free rate assumed in measuring the asset retirement obligation was 9.42%. The Company expects to settle this obligation in 2021.
| 82 | 2012 Annual Report |
NOA
17. Income taxes
Income tax (benefit) provision differs from the amount that would be computed by applying the Federal and Provincial statutory income tax rates to income before income taxes. The reasons for the differences are as follows:
| Year ended March 31, | 2012 | 2011 | 2010 | |||||||||||||
| (Loss) income before income taxes |
$ | (28,385 | ) | $(41,098 | ) | $41,898 | ||||||||||
| Tax rate |
26.25% | 27.75% | 28.91% | |||||||||||||
| Expected (benefit) expense |
$(7,451 | ) | $(11,405 | ) | $12,113 | |||||||||||
| Increase (decrease) related to: |
||||||||||||||||
| Impact of enacted future statutory income tax rates |
278 | 164 | (673 | ) | ||||||||||||
| Income tax adjustments and reassessments |
313 | 909 | 1,442 | |||||||||||||
| Valuation allowance |
(91 | ) | 962 | – | ||||||||||||
| Stock-based compensation |
(393 | ) | 1,443 | 617 | ||||||||||||
| Non deductible portion of capital losses |
– | 1,063 | – | |||||||||||||
| Other |
121 | 416 | 180 | |||||||||||||
| Income tax (benefit) expense |
$(7,223 | ) | $(6,448 | ) | $13,679 | |||||||||||
|
Classified as:
|
||||||||||||||||
| 2012 | 2011 | 2010 | ||||||||||||||
| Year ended March 31, |
||||||||||||||||
| Current income tax (benefit) expense |
$(677 | ) | $2,892 | $3,803 | ||||||||||||
| Deferred income tax (benefit) expense |
(6,546 | ) | (9,340 | ) | 9,876 | |||||||||||
| $(7,223 | ) | $(6,448 | ) | $13,679 | ||||||||||||
The deferred tax assets and liabilities are summarized below:
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Deferred tax assets: |
||||||||||
| Non-capital losses carried forward |
$51,614 | $41,581 | ||||||||
| Derivative financial instruments |
2,296 | 2,895 | ||||||||
| Billings in excess of costs on uncompleted contracts |
1,887 | 508 | ||||||||
| Capital lease obligations |
2,689 | 2,247 | ||||||||
| Intangible assets |
– | 473 | ||||||||
| Long term portion of liabilities related to equipment leases |
– | 2,029 | ||||||||
| Deferred lease inducements |
134 | 161 | ||||||||
| Stock-based compensation |
1,402 | 1,656 | ||||||||
| Other |
420 | 99 | ||||||||
| $60,442 | $51,649 | |||||||||
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Deferred tax liabilities: |
||||||||||
| Unbilled revenue and uncertified revenue included in accounts receivable |
$13,039 | $24,418 | ||||||||
| Assets held for sale |
462 | 189 | ||||||||
| Accounts receivable – holdbacks |
8,071 | 3,154 | ||||||||
| Property, plant and equipment |
52,323 | 44,105 | ||||||||
| Deferred financing costs |
224 | 71 | ||||||||
| Intangible assets |
8 | 76 | ||||||||
| Other |
173 | 40 | ||||||||
| $74,300 | $72,053 | |||||||||
| Net deferred income tax liability |
$(13,858 | ) | $(20,404 | ) | ||||||
Classified as:
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Current asset |
$2,991 | $1,729 | ||||||||
| Long term asset |
57,451 | 49,920 | ||||||||
| Current liability |
(21,512 | ) | (27,612 | ) | ||||||
| Long term liability |
(52,788 | ) | (44,441 | ) | ||||||
| $(13,858 | ) | $(20,404 | ) | |||||||
| 2012 Annual Report | 83 |
The Company and its subsidiaries file income tax returns in the Canadian federal jurisdiction, five provincial jurisdictions and US federal and Texas state jurisdiction. For years before 2007, the Company is no longer subject to Canadian federal or provincial examinations.
The Company has a full valuation allowance against capital losses in deferred tax benefits of $962 as at March 31, 2012 (2011 – $962; 2010 – $nil). At March 31, 2012, the Company has non-capital losses for income tax purposes of $205,565 which predominately expire after 2027.
| March 31, 2012 |
||||
| 2027 |
$2,973 | |||
| 2028 |
7,222 | |||
| 2029 |
13,676 | |||
| 2030 |
25,707 | |||
| 2031 |
93,267 | |||
| 2032 |
62,720 | |||
| $205,565 | ||||
18. Shares
a) Common shares
Authorized:
Unlimited number of voting common shares
Unlimited number of non-voting common shares
Issued and outstanding:
| Number of Shares |
Amount | |||||||||
| Voting common shares |
||||||||||
| Issued and outstanding at March 31, 2009 |
36,038,476 | $303,431 | ||||||||
| Issued upon exercise of stock options |
10,800 | 53 | ||||||||
| Transferred from additional paid-in capital on exercise of stock options |
– | 21 | ||||||||
| Issued and outstanding at March 31, 2010 |
36,049,276 | $303,505 | ||||||||
| Issued upon exercise of stock options |
193,250 | 963 | ||||||||
| Transferred from additional paid-in capital on exercise of stock options |
– | 386 | ||||||||
| Issued and outstanding at March 31, 2011 |
36,242,526 | $304,854 | ||||||||
| Issued upon exercise of stock options |
8,480 | 35 | ||||||||
| Transferred from additional paid-in capital on exercise of stock options |
– | 19 | ||||||||
| Issued and outstanding at March 31, 2012 |
36,251,006 | $304,908 | ||||||||
b) Net (loss) income per share
| 2012 | 2011 | 2010 | ||||||||||||||
| Year ended March 31, |
||||||||||||||||
| Net (loss) income available to common shareholders |
$(21,122 | ) | $(34,709 | ) | $28,219 | |||||||||||
| Weighted average number of common shares |
36,249,082 | 36,119,356 | 36,040,857 | |||||||||||||
| Basic net (loss) income per share |
$(0.58 | ) | $(0.96 | ) | $0.78 | |||||||||||
| 2012 | 2011 | 2010 | ||||||||||||||
| Year ended March 31, |
||||||||||||||||
| Net (loss) income available to common shareholders |
$(21,122 | ) | $(34,709 | ) | $28,219 | |||||||||||
| Weighted average number of common shares |
36,249,082 | 36,119,356 | 36,040,857 | |||||||||||||
| Dilutive effect of stock options, deferred performance share units and stock award plan |
– | – | 680,169 | |||||||||||||
| Weighted average number of diluted common shares |
36,249,082 | 36,119,356 | 36,721,026 | |||||||||||||
| Diluted net (loss) income per share |
$(0.58 | ) | $(0.96 | ) | $0.77 | |||||||||||
For the year ended March 31, 2012, there were 1,834,794 and 50,000 stock options and stock awards, respectively, which were anti-dilutive (March 31, 2011 – 1,647,474, 75,591 and 150,000 stock options, deferred performance share units and stock awards, respectively; March 31, 2010 – 820,641 and 57,311 stock options and deferred performance share units, respectively) and therefore were not considered in computing diluted earnings per share.
| 84 | 2012 Annual Report |
NOA
19. Interest expense
| 2012 | 2011 | 2010 | ||||||||||||||
| Year ended March 31, |
||||||||||||||||
| Interest on 8 3/4% senior notes and swaps |
$– | $1,238 | $19,041 | |||||||||||||
| Interest on capital lease obligations |
445 | 689 | 1,032 | |||||||||||||
| Amortization of deferred financing costs |
1,591 | 1,609 | 3,348 | |||||||||||||
| Interest on credit facilities |
7,430 | 5,361 | 2,375 | |||||||||||||
| Interest on Series 1 Debentures |
20,531 | 20,132 | – | |||||||||||||
| Interest on long term debt |
$29,997 | $29,029 | $25,796 | |||||||||||||
| Other interest |
328 | 962 | 284 | |||||||||||||
| $30,325 | $29,991 | $26,080 | ||||||||||||||
20. Claims revenue
| 2012 | 2011 | 2010 | ||||||||||||||
| Year ended March 31, |
||||||||||||||||
| Claims revenue recognized |
$35,211 | $5,278 | $4,541 | |||||||||||||
| Claims revenue uncollected (classified as unbilled revenue) |
22,759 | 2,174 | 785 | |||||||||||||
21. Financial instruments and risk management
In determining the fair value of financial instruments, the Company uses a variety of methods and assumptions that are based on market conditions and risks existing on each reporting date. Standard market conventions and techniques, such as discounted cash flow analysis and option pricing models, are used to determine the fair value of the Company’s financial instruments, including derivatives. All methods of fair value measurement result in a general approximation of value and such value may never actually be realized.
The fair values of the Company’s cash and cash equivalents, accounts receivable, unbilled revenue, accounts payable and accrued liabilities approximate their carrying amounts due to the relatively short periods to maturity for the instruments.
The fair values of amounts due under the Credit Facilities are based on management estimates which are determined by discounting cash flows required under the instruments at the interest rate currently estimated to be available for instruments with similar terms. Based on these estimates and by using the outstanding balance of $78.8 million at March 31, 2012 and $72.0 million at March 31, 2011 (note 15 (b)), the fair value of amounts due under the Credit Facilities as at March 31, 2012 and March 31, 2011 are not significantly different than their carrying value.
Financial instruments with carrying amounts that differ from their fair values are as follows:
| March 31, 2012 | March 31, 2011 | |||||||||||||||||||||
| Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value |
|||||||||||||||||||
| Capital lease obligations (i) |
$10,701 | $10,657 | $8,693 | $8,658 | ||||||||||||||||||
| Series 1 Debentures (ii) |
225,000 | 203,624 | 225,000 | 238,651 | ||||||||||||||||||
| (i) | The fair values of amounts due under capital leases are based on management estimates which are determined by discounting cash flows required under the instruments at the interest rates currently estimated to be available for instruments with similar terms. |
| (ii) | The fair value of the Series 1 Debentures is based upon the expected discounted cash flows and the period end market price of similar financial instruments. |
a) Fair value measurements
The Company has segregated all financial assets and financial liabilities that are measured at fair value on a recurring basis into the most appropriate level within the fair value hierarchy based on the inputs used to determine the fair value at the measurement date.
The fair values of the Company’s embedded derivatives are based on appropriate price modeling commonly used by market participants to estimate fair value. Such modeling includes option pricing models and discounted cash flow analysis, using observable market based inputs including foreign currency rates, implied volatilities and discount factors to estimate fair value. The Company considers its own credit risk or the credit risk of the counterparty in determining fair value, depending on whether the fair values are in an asset or liability position. Fair value determined using valuation models requires the use of assumptions concerning the amount and timing of future cash flows. Fair value amounts reflect management’s best estimates using external, readily observable, market data such as futures prices, interest rate yield curves, foreign exchange rates and discount rates for time value. It is possible that the assumptions used in establishing fair value amounts will differ from future outcomes and the effect of such variations could be material.
| 2012 Annual Report | 85 |
At March 31, 2012, the Company had no financial assets or financial liabilities measured at fair value on a recurring basis which were classified as Level 1 or Level 3 under the fair value hierarchy. Since the Company primarily uses observable inputs of similar instruments and discounted cash flows in its valuation of its derivative financial instruments, these fair value measurements are classified as Level 2 of the fair value hierarchy. Financial assets and liabilities measured at fair value net of accrued interest on a recurring basis, all of which are classified as “Derivative financial instruments” on the Consolidated Balance Sheets are summarized below:
| March 31, 2012 | Carrying Amount |
|||
| Embedded price escalation features in certain long term supplier contracts |
$9,146 | |||
| Less: current portion |
(3,220 | ) | ||
| $5,926 | ||||
| March 31, 2011 | Carrying Amount |
|||
| Embedded price escalation features in a long term customer construction contract |
$5,877 | |||
| Embedded price escalation features in certain long term supplier contracts |
5,651 | |||
| $11,528 | ||||
| Less: current portion |
(2,474 | ) | ||
| $9,054 | ||||
On April 8, 2010, the Company settled the cross-currency and interest rate swaps, including accrued interest for a total of $91,125 in conjunction with the settlement of the 8 3/4% senior notes (note 15 (d)).
The realized and unrealized (gain) loss on derivative financial instruments is comprised as follows:
| Year ended March 31, | 2012 | 2011 | 2010 | |||||||||||||
| Realized and unrealized loss on cross-currency and interest rate swaps |
$– | $2,111 | $64,637 | |||||||||||||
| Unrealized (gain) loss on embedded price escalation features in a long term customer construction contract |
(5,877 | ) | (604 | ) | 6,805 | |||||||||||
| Unrealized loss (gain) on embedded price escalation features in certain long term supplier contracts |
3,495 | (3,812 | ) | (13,315 | ) | |||||||||||
| Unrealized gain on early redemption option on 8 3/4% senior notes |
– | – | (3,716 | ) | ||||||||||||
| $(2,382 | ) | $(2,305 | ) | $54,411 | ||||||||||||
Non-financial assets that were measured at fair value on a non-recurring basis as at March 31, 2012 and 2011 in the financial statements are summarized below:
| March 31, 2012 | March 31, 2011 | |||||||||||||||||||
| Carrying Amount | Change in Fair Value | Carrying Amount | Change in Fair Value | |||||||||||||||||
| Assets held for sale |
$1,841 | $(8,748 | ) | $721 | $(141 | ) | ||||||||||||||
Assets held for sale are measured at fair value less cost to sell on a non-recurring basis. For the year ended March 31, 2012, assets held for sale with a carrying amount of $10,589 (2011 – $862) were written down to their fair value less cost to sell of $1,841 (2011 – $721), resulting in a loss of $8,748 (2011 – $141), which was included in depreciation expense in the Consolidated Statements of Operations. The fair value less cost to sell of the assets held for sale is determined internally by analyzing recent auction prices for equipment with similar specifications and hours used, the residual value of the asset and the useful life of the asset. The inputs to estimate the fair value of the assets held for sale are classified under Level 3 of the fair value hierarchy.
b) Risk Management
The Company is exposed to market and credit risks associated with its financial instruments. The Company will from time to time use various financial instruments to reduce market risk exposures from changes in foreign currency exchange rates and interest rates. The Company does not hold or use any derivative instruments for trading or speculative purposes.
Overall, the Company’s Board of Directors has responsibility for the establishment and approval of the Company’s risk management policies. Management performs a risk assessment on a continual basis to help ensure that all significant risks related to the Company and its operations have been reviewed and assessed to reflect changes in market conditions and the Company’s operating activities.
c) Market Risk
Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices such as foreign currency exchange rates and interest rates. The level of market risk to which the Company is exposed at any point in time varies depending on market conditions, expectations of future price or market rate movements and composition of the Company’s financial assets and liabilities held, non-trading physical assets and contract portfolios.
| 86 | 2012 Annual Report |
NOA
To manage the exposure related to changes in market risk, the Company uses various risk management techniques including the use of derivative instruments. Such instruments may be used to establish a fixed price for a commodity, an interest bearing obligation or a cash flow denominated in a foreign currency.
The sensitivities provided below are hypothetical and should not be considered to be predictive of future performance or indicative of earnings on these contracts.
i) Foreign exchange risk
The Company regularly transacts in foreign currencies when purchasing equipment and spare parts as well as certain general and administrative goods and services. These exposures are generally of a short-term nature and the impact of changes in exchange rates has not been significant in the past. The Company may fix its exposure in either the Canadian Dollar or the US Dollar for these short term transactions, if material.
ii) Interest rate risk
The Company is exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of its financial instruments. Interest expense on borrowings with floating interest rates, including the Company’s Credit Facilities, varies as market interest rates change. At March 31, 2012, the Company held $78.8 million of floating rate debt pertaining to its Credit Facilities (March 31, 2011 – $72.0 million). As at March 31, 2012, holding all other variables constant, a 100 basis point change to interest rates on floating rate debt will result in $0.8 million corresponding change in annual interest expense. This assumes that the amount of floating rate debt remains unchanged from that which was held at March 31, 2012.
The fair value of financial instruments with fixed interest rates, such as the Company’s Series 1 Debentures, fluctuate with changes in market interest rates. However, these fluctuations do not affect earnings, as the Company’s debt is carried at amortized cost and the carrying value does not change as interest rates change.
The Company manages its interest rate risk exposure by using a mix of fixed and variable rate debt and may use derivative instruments to achieve the desired proportion of variable to fixed-rate debt.
d) Credit Risk
Credit risk is the risk that financial loss to the Company may be incurred if a customer or counterparty to a financial instrument fails to meet its contractual obligations. The Company manages the credit risk associated with its cash by holding its funds with what it believes to be reputable financial institutions. The Company is also exposed to credit risk through its accounts receivable and unbilled revenue. Credit risk for trade and other accounts receivables, and unbilled revenue are managed through established credit monitoring activities.
The Company has a concentration of customers in the oil and gas sector. The concentration risk is mitigated primarily by the customers being large investment grade organizations. The credit worthiness of new customers is subject to review by management through consideration of the type of customer and the size of the contract.
At March 31, 2012 and March 31, 2011, the following customers represented 10% or more of accounts receivable and unbilled revenue:
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Customer A |
31% | 40% | ||||||||
| Customer B |
11% | 5% | ||||||||
| Customer C |
10% | 14% | ||||||||
| Customer D |
3% | 12% | ||||||||
The Company reviews its accounts receivable amounts regularly and amounts are written down to their expected realizable value when outstanding amounts are determined not to be fully collectible. This generally occurs when the customer has indicated an inability to pay, the Company is unable to communicate with the customer over an extended period of time, and other methods to obtain payment have been considered and have not been successful. Bad debt expense is charged to project costs in the Consolidated Statements of Operations in the period that the account is determined to be doubtful. Estimates of the allowance for doubtful accounts are determined on a customer-by-customer evaluation of collectability at each reporting date taking into consideration the following factors: the length of time the receivable has been outstanding, specific knowledge of each customer’s financial condition and historical experience.
The Company’s maximum exposure to credit risk for accounts receivable and unbilled revenue is as follows:
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Trade accounts receivables |
$213,051 | $127,678 | ||||||||
| Other receivables |
1,078 | 804 | ||||||||
| Total accounts receivable |
$214,129 | $128,482 | ||||||||
| Unbilled revenue |
$86,859 | $102,939 | ||||||||
| 2012 Annual Report | 87 |
On a geographic basis as at March 31, 2012, approximately 95% (March 31, 2011 – 95%) of the balance of trade accounts receivable (before considering the allowance for doubtful accounts) was due from customers based in Western Canada.
Payment terms are generally net 30 days. As at March 31, 2012 and 2011, trade receivables are aged as follows:
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Not past due |
$166,362 | $98,626 | ||||||||
| Past due 1-30 days |
27,617 | 18,911 | ||||||||
| Past due 31-60 days |
8,476 | 3,444 | ||||||||
| More than 61 days (including holdbacks of $nil (2011 $nil)) |
10,596 | 6,697 | ||||||||
| Total |
$213,051 | $127,678 | ||||||||
As at March 31, 2012, the Company has recorded an allowance for doubtful accounts of $210 (March 31, 2011 – $30) of which 100% relates to amounts that are more than 61 days past due.
The allowance is an estimate of the March 31, 2012 trade receivable balances that are considered uncollectible. Changes to the allowance are as follows:
| Year ended March 31, | 2012 | 2011 | 2010 | |||||||||||||
| Opening balance |
$30 | $1,691 | $2,597 | |||||||||||||
| Payments received on provided balances |
– | (682 | ) | (846 | ) | |||||||||||
| Current year allowance |
180 | 518 | 334 | |||||||||||||
| Write-offs |
– | (1,497 | ) | (394 | ) | |||||||||||
| Ending balance |
$210 | $30 | $1,691 | |||||||||||||
Credit risk on derivative financial instruments arises from the possibility that the counterparties to the agreements may default on their respective obligations under the agreements. This credit risk only arises in instances where these agreements have positive fair value for the Company.
22. Other information
a) Supplemental cash flow information
| Year ended March 31, | 2012 | 2011 | 2010 | |||||||||||||
| Cash paid during the year for: |
||||||||||||||||
| Interest, including realized interest on interest rate swap |
$27,521 | $33,559 | $49,999 | |||||||||||||
| Income taxes |
1,415 | 4,149 | 10,395 | |||||||||||||
| Cash received during the year for: |
||||||||||||||||
| Interest |
1 | 1,168 | 10,998 | |||||||||||||
| Income taxes |
5,347 | 2,260 | 453 | |||||||||||||
| Non-cash transactions: |
||||||||||||||||
| Acquisition of property, plant and equipment by means of capital leases |
7,215 | 427 | 1,523 | |||||||||||||
| Additions to assets held for sale |
(10,322 | ) | (1,675 | ) | (1,739 | ) | ||||||||||
| Net increase (decrease) in accounts payable related to purchase of property, plant and equipment |
1,380 | (3,879 | ) | 1,840 | ||||||||||||
| Disposition of property, plant and equipment related to the buyout of contract-related assets |
(27,063 | ) | – | – | ||||||||||||
| Disposition of intangible assets related to the buyout of contract-related assets |
(1,119 | ) | – | – | ||||||||||||
| Increase in accounts receivable related to the buyout of contract-related assets |
66,055 | – | – | |||||||||||||
| Decrease in unbilled revenue related to the buyout of contract-related assets |
(16,457 | ) | – | – | ||||||||||||
| Decrease in inventory related to the buyout of contract-related assets |
(8,483 | ) | – | – | ||||||||||||
| Increase in accounts payable related to the buyout of contract-related assets |
12,933 | – | – | |||||||||||||
| Increase in accrued liabilities related to current portion of RSU liability |
2,066 | – | – | |||||||||||||
b) Net change in non-cash working capital
| Year ended March 31, | 2012 | 2011 | 2010 | |||||||||||||
| Operating activities: |
||||||||||||||||
| Accounts receivable, net |
$(19,592 | ) | $(9,534 | ) | $(29,428 | ) | ||||||||||
| Unbilled revenue |
(377 | ) | (18,237 | ) | (28,795 | ) | ||||||||||
| Inventories |
(12,603 | ) | (2,661 | ) | 6,214 | |||||||||||
| Prepaid expenses and deposits |
3,413 | 308 | (2,620 | ) | ||||||||||||
| Accounts payable |
70,764 | 21,382 | 6,620 | |||||||||||||
| Accrued liabilities |
1,915 | (5,434 | ) | 1,150 | ||||||||||||
| Long term portion of liabilities related to equipment leases |
(9,578 | ) | (2,196 | ) | 7,809 | |||||||||||
| Billings in excess of costs incurred and estimated earnings on uncompleted contracts |
5,510 | 390 | (541 | ) | ||||||||||||
| $39,452 | $(15,982 | ) | $(39,591 | ) | ||||||||||||
| 88 | 2012 Annual Report |
NOA
23. Segmented information
a) General overview
The Company operates in the following reportable business segments, which follow the organization, management and reporting structure within the Company:
| • | Heavy Construction and Mining: |
The Heavy Construction and Mining segment provides mining and site preparation services, including overburden removal and reclamation services, project management, underground utility construction, equipment rental to a variety of customers, environmental services including construction and modification of tailing ponds and reclamation of completed mine sites to environmental standards throughout Canada.
| • | Piling: |
The Piling segment provides deep foundation construction and design build services to a variety of industrial and commercial customers throughout Western Canada and Ontario. It also designs and manufactures screw piles and pipeline anchoring systems and provides tank maintenance services to the petro-chemical industry across Canada and the United States and sells pipeline anchoring systems globally.
| • | Pipeline: |
The Pipeline segment provides both small and large diameter pipeline construction and installation services as well as equipment rental to energy and industrial clients throughout Western Canada.
The accounting policies of the reportable operating segments are the same as those described in the significant accounting policies in note 2. Certain business units of the Company have been aggregated into the Heavy Construction and Mining segment as they have similar economic characteristics based on the nature of the services provided, the customer base and the resources used to provide these services.
b) Results by business segment
| For the year ended March 31, 2012 | Heavy Construction and Mining |
Piling | Pipeline | Total | ||||||||||||||||||
| Revenue from external customers |
$670,720 | $185,321 | $150,504 | $1,006,545 | ||||||||||||||||||
| Depreciation of property, plant and equipment |
35,804 | 3,912 | 1,045 | 40,761 | ||||||||||||||||||
| Segment profits (loss) |
86,567 | 46,012 | (11,322 | ) | 121,257 | |||||||||||||||||
| Segment assets |
426,625 | 142,131 | 70,602 | 639,358 | ||||||||||||||||||
| Capital expenditures |
42,001 | 12,570 | 4,110 | 58,681 | ||||||||||||||||||
| For the year ended March 31, 2011 | Heavy Construction and Mining |
Piling | Pipeline | Total | ||||||||||||||||||
| Revenue from external customers |
$667,037 | $105,559 | $85,452 | $858,048 | ||||||||||||||||||
| Depreciation of property, plant and equipment |
28,832 | 3,636 | 550 | 33,018 | ||||||||||||||||||
| Segment profits (loss) |
50,703 | 18,455 | (3,034 | ) | 66,124 | |||||||||||||||||
| Segment assets |
423,947 | 116,623 | 37,053 | 577,623 | ||||||||||||||||||
| Capital expenditures |
29,577 | 2,560 | 1,124 | 33,261 | ||||||||||||||||||
| For the year ended March 31, 2010 | Heavy Construction and Mining |
Piling | Pipeline | Total | ||||||||||||||||||
| Revenue from external customers |
$665,514 | $68,531 | $24,920 | $758,965 | ||||||||||||||||||
| Depreciation of property, plant and equipment |
34,419 | 2,842 | 153 | 37,414 | ||||||||||||||||||
| Segment profits (loss) |
111,016 | 11,288 | (3,851 | ) | 118,453 | |||||||||||||||||
| Segment assets |
435,098 | 92,980 | 14,765 | 542,843 | ||||||||||||||||||
| Capital expenditures |
40,431 | 1,081 | 948 | 42,460 | ||||||||||||||||||
| 2012 Annual Report | 89 |
c) Reconciliations
i) Income (loss) before income taxes
| Year ended March 31, | 2012 | 2011 | 2010 | |||||||||||||
| Total profit for reportable segments |
$121,257 | $66,124 | $118,453 | |||||||||||||
| Less: Unallocated equipment costs (recoveries) (i) |
60,356 | 7,988 | (20,832 | ) | ||||||||||||
| Gross profit |
$60,901 | $58,136 | $139,285 | |||||||||||||
| Less: unallocated corporate items: |
||||||||||||||||
| General and administrative expenses |
54,400 | 59,828 | 62,516 | |||||||||||||
| Loss on disposal of property, plant and equipment |
1,741 | 1,948 | 1,233 | |||||||||||||
| (Gain) loss on disposal of assets held for sale |
(466 | ) | 825 | 373 | ||||||||||||
| Amortization of intangible assets |
5,702 | 3,540 | 1,719 | |||||||||||||
| Equity in (earnings) loss of unconsolidated joint venture |
(86 | ) | 2,720 | (44 | ) | |||||||||||
| Interest expense, net |
30,325 | 29,991 | 26,080 | |||||||||||||
| Foreign exchange loss (gain) |
52 | (1,659 | ) | (48,901 | ) | |||||||||||
| Realized and unrealized (gain) loss on derivative financial instruments |
(2,382 | ) | (2,305 | ) | 54,411 | |||||||||||
| Loss on debt extinguishment |
– | 4,346 | – | |||||||||||||
| (Loss) income before income taxes |
$(28,385 | ) | $(41,098 | ) | $41,898 | |||||||||||
| (i) | Unallocated equipment costs represent actual equipment costs, including non-cash items such as depreciation, which have not been allocated to reportable segments. Unallocated equipment recoveries arise when actual equipment costs charged to the reportable segment exceed actual equipment costs incurred. |
ii) Total assets
| March 31, 2012 |
March 31, 2011 |
|||||||||||
| Corporate assets: |
||||||||||||
| Cash and cash equivalents |
$1,400 | $722 | ||||||||||
| Property, plant and equipment |
23,017 | 24,831 | ||||||||||
| Deferred tax assets |
60,442 | 51,649 | ||||||||||
| Other |
25,776 | 28,132 | ||||||||||
| Total corporate assets |
$110,635 | $105,334 | ||||||||||
| Total assets for reportable segments |
639,358 | 577,623 | ||||||||||
| Total assets |
$749,993 | $682,957 | ||||||||||
The Company’s goodwill of $32,901 is assigned to the Piling segment. All of the Company’s assets are located in Canada and the United States.
iii) Depreciation of property, plant and equipment
| Year ended March 31, | 2012 | 2011 | 2010 | |||||||||||||
| Total depreciation for reportable segments |
$40,761 | $33,018 | $37,414 | |||||||||||||
| Depreciation for corporate assets |
8,139 | 6,422 | 5,222 | |||||||||||||
| Total depreciation |
$48,900 | $39,440 | $42,636 | |||||||||||||
iv) Capital expenditures for long-lived assets
| Year ended March 31, | 2012 | 2011 | 2010 | |||||||||||||
| Total capital expenditures for reportable segments |
$58,681 | $33,261 | $42,460 | |||||||||||||
| Capital expenditures for corporate assets |
6,615 | 7,904 | 12,790 | |||||||||||||
| Total capital expenditures for long-lived assets |
$65,296 | $41,165 | $55,250 | |||||||||||||
d) Customers
The following customers accounted for 10% or more of total revenues:
| Year ended March 31, | 2012 | 2011 | 2010 | |||||||||||||
| Customer A |
21% | 29% | 51% | |||||||||||||
| Customer B |
16% | 8% | 5% | |||||||||||||
| Customer C |
11% | 10% | 9% | |||||||||||||
| Customer D |
10% | 24% | 19% | |||||||||||||
The revenue by major customer was earned mainly by the Heavy Construction and Mining segment.
| 90 | 2012 Annual Report |
NOA
e) Geographic information
i) The geographic revenue distribution for the Company is as follows:
| Year ended March 31, | 2012 | 2011 | 2010 | |||||||||||||
| Canada |
$996,916 | $855,963 | $758,965 | |||||||||||||
| International |
6,935 | 1,046 | – | |||||||||||||
| United States |
2,694 | 1,039 | – | |||||||||||||
| $1,006,545 | $858,048 | $758,965 | ||||||||||||||
ii) The geographic distribution of long-lived assets is as follows:
| March 31, 2012 |
March 31, 2011 |
|||||||||
| Canada |
$367,240 | $381,577 | ||||||||
| United States |
179 | 96 | ||||||||
| $367,419 | $381,673 | |||||||||
24. Related party transactions
Sterling Group Partners I, L.P., Perry Partners, L.P. and Perry Partners International, Inc. are collectively “the Sponsors” of the Company. The Company may receive consulting and advisory services provided by the Sponsors (principals or employees of such Sponsors are directors of the Company) with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters, and no fee is charged for these consulting and advisory services.
In order for the Sponsors to provide such advisory and consulting services, the Company provides reports, financial data and other information to the Sponsors. This permits them to consult with and advise the Company’s management on matters relating to its operations, company affairs and finances. In addition, this permits them to visit and inspect any of the Company’s properties and facilities.
There were no material related party transactions during the years ended March 31, 2012, 2011 and 2010. All related party transactions were in the normal course of operations and were measured at the exchange amount, being the consideration established and agreed to by the related parties.
25. Commitments
The annual future minimum lease payments for heavy equipment, office equipment and premises in respect of operating leases, excluding contingent rentals, for the next five years and thereafter are as follows:
| For the year ending March 31, |
||||
| 2013 |
$54,542 | |||
| 2014 |
38,553 | |||
| 2015 |
19,014 | |||
| 2016 |
4,248 | |||
| 2017 and thereafter |
– | |||
| $116,357 |
Total contingent rentals on operating leases consisting principally of usage (recoveries) charges in excess of minimum contracted amounts for the years ended March 31, 2012, 2011 and 2010 amounted to $(8,449), $1,881 and $10,246 respectively.
26. Employee benefit plans
The Company and its subsidiaries match voluntary contributions made by employees to their Registered Retirement Savings Plans to a maximum of 5% of base salary for each employee. Contributions made by the Company during the year ended March 31, 2012 were $2,083 (2011 – $1,689; 2010 — $1,393).
27. Stock-based compensation
a) Stock-based compensation expenses
Stock-based compensation expenses included in general and administrative expenses are as follows:
| Year ended March 31, | 2012 | 2011 | 2010 | |||||||||||||
| Share option plan (note 27(b)) |
$1,373 | $1,455 | $2,135 | |||||||||||||
| Senior executive stock option plan (note 27(c)) |
(2,878 | ) | 2,878 | – | ||||||||||||
| Deferred performance share unit plan (note 27(d)) |
– | (44 | ) | 123 | ||||||||||||
| Restricted share unit plan (note 27(e)) |
733 | 1,603 | 1,010 | |||||||||||||
| Director’s deferred stock unit plan (note 27(f)) |
(1,747 | ) | 1,484 | 2,002 | ||||||||||||
| Stock award plan (note 27(g)) |
256 | 780 | – | |||||||||||||
| $(2,263 | ) | $8,156 | $5,270 | |||||||||||||
| 2012 Annual Report | 91 |
b) Share option plan
Under the 2004 Amended and Restated Share Option Plan, which was approved and became effective in 2006, directors, officers, employees and certain service providers to the Company are eligible to receive stock options to acquire voting common shares in the Company. Each stock option provides the right to acquire one common share in the Company and expires ten years from the grant date or on termination of employment. Options may be exercised at a price determined at the time the option is awarded, and vest as follows: no options vest on the award date and twenty percent vest on each subsequent anniversary date.
| Number of options | Weighted average $ per share |
|||||||
| Outstanding at March 31, 2009 |
2,071,884 | 7.53 | ||||||
| Granted |
375,700 | 8.88 | ||||||
|
Exercised(i) |
(10,800 | ) | 4.90 | |||||
| Options settled for cash |
(95,720 | ) | 4.95 | |||||
| Forfeited |
(90,260 | ) | 8.53 | |||||
| Outstanding at March 31, 2010 |
2,250,804 | 7.84 | ||||||
| Granted |
260,000 | 9.77 | ||||||
|
Exercised(i) |
(193,250 | ) | 4.98 | |||||
| Forfeited |
(120,080 | ) | 10.30 | |||||
| Modified(ii) |
(550,000 | ) | 5.00 | |||||
| Outstanding at March 31, 2011 |
1,647,474 | 9.25 | ||||||
| Granted |
287,700 | 6.56 | ||||||
|
Exercised(i) |
(8,480 | ) | 4.15 | |||||
| Forfeited |
(91,900 | ) | 10.42 | |||||
| Outstanding at March 31, 2012 |
1,834,794 | 8.79 | ||||||
| (i) | All stock options exercised resulted in new common shares being issued (note 18(a)); |
| (ii) | 550,000 stock options were modified as senior executive stock options on September 22, 2010 (note 27(c)). |
Cash received from the option exercises for the year ended March 31, 2012 was $35 (2011—$963; 2010 – $53). Cash paid for options settled for cash for the year ended March 31, 2012 was $nil (2011 – $nil; 2010 – $244).The total intrinsic value of options exercised, calculated as market value at the exercise date less exercise price, multiplied by the number of units exercised, for the years ended March 31, 2012, 2011 and 2010 was $48, $1,084 and $277, respectively.
The following table summarizes information about stock options outstanding at March 31, 2012:
| Options outstanding | Options exercisable | |||||||||||||||||||||||||||||||||
| Exercise price | Number | Weighted average remaining life |
Weighted average exercise price |
Number | Weighted average remaining life |
Weighted average exercise price |
||||||||||||||||||||||||||||
| $3.69 |
127,320 | 6.7 years | $3.69 | 73,840 | 6.7 years | $3.69 | ||||||||||||||||||||||||||||
| $5.00 |
437,294 | 2.7 years | $5.00 | 437,294 | 2.7 years | $5.00 | ||||||||||||||||||||||||||||
| $6.56 |
277,100 | 9.7 years | $6.56 | – | – | – | ||||||||||||||||||||||||||||
| $8.28 |
130,000 | 7.2 years | $8.28 | 52,000 | 7.2 years | $8.28 | ||||||||||||||||||||||||||||
| $8.58 |
60,000 | 8.5 years | $8.58 | 12,000 | 8.5 years | $8.58 | ||||||||||||||||||||||||||||
| $9.33 |
159,280 | 7.9 years | $9.33 | 64,720 | 7.9 years | $9.33 | ||||||||||||||||||||||||||||
| $10.13 |
174,480 | 8.7 years | $10.13 | 35,440 | 8.7 years | $10.13 | ||||||||||||||||||||||||||||
| $13.21 |
75,000 | 5.8 years | $13.21 | 60,000 | 5.8 years | $13.21 | ||||||||||||||||||||||||||||
| $13.50 |
201,560 | 5.7 years | $13.50 | 161,720 | 5.7 years | $13.50 | ||||||||||||||||||||||||||||
| $15.37 |
40,000 | 6 years | $15.37 | 32,000 | 6 years | $15.37 | ||||||||||||||||||||||||||||
| $16.01 |
75,000 | 6 years | $16.01 | 45,000 | 6 years | $16.01 | ||||||||||||||||||||||||||||
| $16.46 |
50,000 | 6 years | $16.46 | 30,000 | 6 years | $16.46 | ||||||||||||||||||||||||||||
| $16.75 |
27,760 | 4.5 years | $16.75 | 27,760 | 4.5 years | $16.75 | ||||||||||||||||||||||||||||
| 1,834,794 | 6.3 years | $8.79 | 1,031,774 | 4.8 years | $8.82 | |||||||||||||||||||||||||||||
At March 31, 2012, the weighted average remaining contractual life of outstanding options is 6.3 years (March 31, 2011 – 6.8 years). The fair value of options vested during the year ended March 31, 2012 was $1,652 (March 31, 2011 – $1,892). At March 31, 2012, the Company had 1,031,774 exercisable options (March 31, 2011 – 830,482) with a weighted average exercise price of $8.82 (March 31, 2011 – $8.52).
At March 31, 2012, the total compensation costs related to non-vested awards not yet recognized was $2,655 (March 31, 2011 – $2,973) and these costs are expected to be recognized over a weighted average period of 3.2 years (March 31, 2011 – 3.4 years).
| 92 | 2012 Annual Report |
NOA
The fair value of each option granted by the Company was estimated on the grant date using the Black-Scholes option pricing model with the following assumptions:
| Year ended March 31, | 2012 | 2011 | 2010 | |||||||||||
| Number of options granted |
287,700 | 260,000 | 375,700 | |||||||||||
| Weighted average fair value per option granted ($) |
4.38 | 6.79 | 6.25 | |||||||||||
| Weighted average assumptions: |
||||||||||||||
| Dividend yield |
Nil% | Nil% | Nil% | |||||||||||
| Expected volatility |
75.22% | 78.59% | 76.27% | |||||||||||
| Risk-free interest rate |
1.32% | 2.65% | 3.39% | |||||||||||
| Expected life (years) |
6.3 | 6.1 | 6.5 | |||||||||||
The Company uses company specific historical data to estimate the expected life of the option, such as employee option exercise and employee post-vesting departure behaviour.
c) Senior executive stock option plan
On September 22, 2010, the Company modified a senior executive employment agreement to allow the option holder the right to settle options in cash which resulted in 550,000 stock options (senior executive stock options) changing classification from equity to a long term liability. The liability is measured at fair value using the Black-Scholes model at the modification date and subsequently at each period end date. Previously recognized compensation cost related to the senior executive stock option plan of $2,237 was transferred from additional paid-in capital to the senior executive stock option liability on the modification date. The fair value of the compensation liability is calculated using the Black-Scholes model at each period end. Changes in fair value of the liability are recognized in the Consolidated Statements of Operations.
The weighted average assumptions used in estimating the fair value of the senior executive stock options as at March 31, 2012 are as follows:
| Year ended March 31, | 2012 | 2011 | ||||||||
| Number of senior executive stock options |
550,000 | 550,000 | ||||||||
| Weighted average fair value per option granted ($) |
2.40 | 9.3 | ||||||||
| Weighted average assumptions: |
||||||||||
| Dividend yield |
Nil% | Nil% | ||||||||
| Expected volatility |
74.99% | 76.74% | ||||||||
| Risk-free interest rate |
0.54% | 1.77% | ||||||||
| Expected life (years) |
3.11 | 4.10 | ||||||||
d) Deferred performance share unit plan
The company has no outstanding Deferred Performance Share Units (“DPSUs”) at this time. DPSUs were granted each fiscal year with respect of services to be provided in that fiscal year and the following two fiscal years. The DPSUs vested the end of a three-year term and were subject to the performance criteria approved by the Compensation Committee of the Board of Directors at the date of grant. Such performance criterion included the passage of time and was based upon return on invested capital calculated as operating income divided by average operating assets. The maturity date for such DPSUs was the last day of the third fiscal year following the grant date. At the maturity date, the Compensation Committee assesses the participant against the performance criteria and determines the number of DPSUs that were earned (earned DPSUs).
The settlement of the participant’s entitlement was made at the Company’s option either in cash, in an amount equivalent to the number of earned DPSUs multiplied by the fair market value of the Company’s common shares as determined by the volume weighted average trading price of the Company’s common shares for the five trading days immediately preceding the date of maturity, or in a number of common shares equal to the number of earned DPSUs. If settled in common shares, the common shares were purchased on the open market or through the issuance of shares from treasury.
The fair value of each unit under the DPSU Plan was estimated on the date of the grant using Black-Scholes option pricing model. There were no DPSUs granted in fiscal 2011 and 2012. The weighted average assumptions used in estimating the fair value of the share options issued under the DPSU Plan during the year ended March 31, 2010 is as follows:
| Number of units granted |
908,165 | |||
| Weighted average fair value per unit granted ($) |
4.71 | |||
| Weighted average assumptions: |
||||
| Dividend yield |
Nil% | |||
| Expected volatility |
96.89% | |||
| Risk-free interest rate |
1.47% | |||
| Expected life (years) |
3.00 |
| 2012 Annual Report | 93 |
| Number of units | ||||
| Outstanding at March 31, 2009 |
91,005 | |||
| Granted |
908,165 | |||
| Forfeited |
(102,671 | ) | ||
| Converted to RSUs (note 27(e)) |
(389,204 | ) | ||
| Outstanding at March 31, 2010 |
507,295 | |||
| Forfeited |
(74,776 | ) | ||
| Outstanding at March 31, 2011 |
432,519 | |||
| Expired |
(41,117 | ) | ||
| Converted to RSUs (note 27(e)) |
(391,402 | ) | ||
| Outstanding at March 31, 2012 |
– | |||
On April 1, 2011, the Company converted 262,737 and 128,665 Deferred Performance Share Units (“DPSUs”) into Restricted Share Units (“RSUs”) for the April 1, 2009 and March 31, 2010 grants at a conversion factor of 50% and 75% respectively (note 27(e)).
At March 31, 2012 there were nil outstanding DPSUs. At March 31, 2011, there were 111,020 units vested and the weighted average remaining contractual life of outstanding DPSU units was 1.2 years. Compensation expense was adjusted based upon management’s assessment of performance against return on invested capital targets and the ultimate number of units expected to be issued. As at March 31, 2011, there was approximately $242 of total unrecognized compensation cost related to non-vested share-based payment arrangements under the DPSU Plan, which was expected to be recognized over a weighted average period of 1.2 years and was subject to performance adjustments. On December 18, 2009, the Company converted 26,059 and 363,145 DPSUs into RSUs for the April 1, 2008 and April 1, 2009 grants respectively at a conversion factor of 80% (note 27(e)).
e) Restricted share unit plan
Restricted Share Units (“RSUs”) are granted each fiscal year with respect to services to be provided in that fiscal year and the following two fiscal years. The RSUs vest at the end of a three–year term. The Company classifies RSUs as a liability as the Company has the ability and intent to settle the awards in cash.
Compensation expense is calculated based on the number of vested shares multiplied by the fair market value of each RSU as determined by the volume weighted average trading price of the Company’s common shares for the five trading days immediately preceding the day on which the fair market value is to be determined. The Company recognizes compensation expense over the three-year term of the RSU in the Consolidated Statements of Operations.
On April 1, 2011, the Company converted the April 1, 2009 and March 31, 2010 DPSUs (note 27(d)) into RSUs at a conversion factor of 50% and 75% respectively. On December 18, 2009, the Company converted certain middle manager’s DPSUs (note 27(d)) into RSUs at a conversion factor of 80%.
| Number of units | ||||
| Outstanding at March 31, 2009 |
– | |||
| Converted from DPSUs (note 27(d)) |
311,358 | |||
| Granted |
169,489 | |||
| Forfeited |
(12,032 | ) | ||
| Outstanding at March 31, 2010 |
468,815 | |||
| Forfeited |
(86,339 | ) | ||
| Outstanding at March 31, 2011 |
382,476 | |||
| Granted |
695,086 | |||
| Settled |
(27,850 | ) | ||
| Forfeited |
(102,022 | ) | ||
| Converted from DPSUs (note 27(d)) |
227,875 | |||
| Outstanding at March 31, 2012 |
1,175,565 | |||
At March 31, 2012, the $2,066 current portion of RSU liabilities were included in accrued liabilities (March 31, 2011 - $nil) and long term portion of RSU liabilities of $1,104 were included in other long term obligations (March 31, 2011 — $2,633) in the Consolidated Balance Sheets. During the year ended March 31, 2012, 27,850 units vested and were settled in cash for $318.
At March 31, 2012, there were 329,901 units vested and the redemption value of these units was $4.91/unit (March 31, 2011 – $11.96/unit). At March 31, 2012, the weighted average remaining contractual life of the RSUs outstanding was 1.4 years (March 31, 2011 – 1.3 years).
| 94 | 2012 Annual Report |
NOA
Using the redemption value of $4.91/unit at March 31, 2012, there was approximately $2,576 of total unrecognized compensation cost related to non–vested share–based payment arrangements under the RSU Plan and these costs are expected to be recognized over the weighted average remaining contractual life of the RSUs of 1.4 years (March 31, 2011 – 1.3 years). On approval of the RSU Plan in 2009, the Company reclassified $20 from additional paid-in capital to restricted share unit liability related to the conversion of those employees converted from the DPSU Plan to the RSU Plan.
f) Director’s deferred stock unit plan
On November 27, 2007, the Company approved a Directors’ Deferred Stock Unit (“DDSU”) Plan, which became effective January 1, 2008. Under the DDSU Plan, non–officer directors of the Company receive 50% of their annual fixed remuneration (which is included in general and administrative expenses) in the form of DDSUs and may elect to receive all or a part of their annual fixed remuneration in excess of 50% in the form of DDSUs. The number of DDSUs to be credited to the participants deferred unit account is determined by dividing the amount of the participant’s deferred remuneration by the Canadian Dollar equivalent of the volume weighted average trading price of the Company’s common shares for the five trading days immediately preceding the date that participants’ remuneration becomes payable. The DDSUs vest immediately upon issuance and are only redeemable upon death or retirement of the participant for cash determined by the market price of the Company’s common shares for the five trading days immediately preceding death or retirement. Directors, who are not US taxpayers, may elect to defer the redemption date until a date no later than December 1st of the calendar year following the year in which the retirement or death occurred.
| Number of units | ||||
| Outstanding at March 31, 2009 |
139,691 | |||
| Issued |
123,575 | |||
| Outstanding at March 31, 2010 |
263,266 | |||
| Issued |
73,752 | |||
| Outstanding at March 31, 2011 |
337,018 | |||
| Issued |
128,248 | |||
| Outstanding at March 31, 2012 |
465,266 | |||
At March 31, 2012, the redemption value of these units was $4.91/unit (March 31, 2011 – $11.96/unit). There is no unrecognized compensation expense related to the DDSUs, since these awards vest immediately when issued.
g) Stock award plan
On September 24, 2009, the Chief Executive Officer’s (CEO) employment agreement was extended by the Board of Directors for a further period of two years, to May 8, 2012. In addition to the existing conditions in his employment agreement, as of September 24, 2010, the effective date, the CEO was granted the right to receive 150,000 common shares of the Company as follows:
| • | 50,000 shares on May 8, 2011; |
| • | 50,000 shares on November 8, 2011; and |
| • | 50,000 shares on May 8, 2012. |
These shares, or at the discretion of the company, the cash equivalent thereof, will be awarded to the CEO provided he remains employed on the award dates above.
The CEO’s entitlement, upon the above release dates, shall be settled in common shares purchased on the open market or through the issuance of common shares from treasury, in each case net of required withholdings. The CEO’s entitlement may be settled with newly issued common shares from treasury, if all necessary shareholder approvals and regulatory approvals, if any, are obtained. The Company has no intention to settle in cash.
The estimate of the fair value of the stock award on the grant date is equal to the market price of the Company’s common shares.
During the year ended March 31, 2012, 100,000 stock awards vested and were settled in common shares purchased on the open market for $822. The weighted average remaining contractual life of outstanding Stock Award Plan units is 0.1 years (March 31, 2011 – 0.6 years). As at March 31, 2012, there was approximately $14 (March 31, 2011 – $270) of total unrecognized compensation cost related to non–vested share–based payment arrangements under the stock award plan, which is expected to be recognized over a weighted average period of 0.1 years (March 31, 2011 – 0.6 years).
28. Contingencies
During the normal course of the Company’s operations, various legal and tax matters are pending. In the opinion of management, these matters will not have a material effect on the Company’s consolidated financial position or results of operations.
29. Comparative figures
Certain of the comparative figures have been reclassified from statements previously presented to conform to the presentation of the current period consolidated financial statements.
| 2012 Annual Report | 95 |
Board of Directors
Senior Management
1. Ronald A. McIntosh
Director since May 2004 Chair of the Board of Directors
2. George R. Brokaw
Director since June 2006
3. Carl Giesler Jr.
Director since April 2012
4. Jay Thornton
Director since June 2012
5. John D. Hawkins
Director since October 2003 Chair of the Governance Committee
6. William C. Oehmig
Director since November 2003 Chair of the HS&E and Business Risk Committee
7. Martin Ferron
President and CEO since June 2012
8. Allen R. Sello
Director since January 2006 Chair of the Audit Committee
9. Peter W. Tomsett
Director since September 2006 Chair of the Compensation Committee
10. K. Rick Turner
Director since November 2006
11. Martin Ferron
President and Chief Executive Officer
12. David Blackley
Chief Financial Officer
13. Joseph C. Lambert
Vice President, Operations Support
14. Barry W. Palmer
Vice President, Oil Sands Operations
15. Bernard T. Robert
Vice President, Corporate
Corporate Information
Corporate Headquarters
2400, 500 - 4th Avenue SW Calgary, Alberta T2P 2V6
Phone: 403.767.4825 Fax: 403.767.4849
Auditors
KPMG LLP Edmonton, Alberta
Solicitors
Bracewell & Giuliani LLP Houston, Texas
Borden Ladner Gervais LLP Toronto, Ontario
Exchange Listings
Toronto Stock Exchange New York Stock Exchange Ticker Symbol: NOA
Transfer Agent
Computershare Investor Services 100 University Avenue Toronto, Ontario M5J 2Y1
1-800-564-6253 www.computershare.com
Investor Information
Investor Relations
Kevin Rowand
Phone: 780.969.5528 Fax: 780.969.5599 Email: IR@nacg.ca Web: www.nacg.ca
Annual General Meeting
The Annual General Meeting of North American Energy Partners Inc. will be held: Wednesday, September 19, 2012 4:00 p.m.
North American Energy Partners Edmonton Office Zone 3 Acheson Industrial Area
2 - 53016 Hwy 60, Acheson, Alberta
NORTH AMERICAN
ENERGY PARTNERS INC.
NORTH AMERICAN
ENERGY PARTNERS INC.
NOA
LISTED
NYSE
NOA
LISTED
TORONTO stock EXCHANGE
TSX
Printed in Canada
© 2012 North American Energy Partners Inc.