EX-99.1 2 dex991.htm ANNUAL INFORMATION FORM FOR THE FISCAL YEAR ENDED MARCH 31, 2011

##### Table of Contents

Exhibit 99.1

NORTH AMERICAN ENERGY PARTNERS INC.

ANNUAL INFORMATION FORM

June 2, 2011

##### Table of Contents

Table of Contents

EXPLANATORY NOTES |  |  | 1 |
INDUSTRY DATA AND FORECASTS |  |  | 1 |
FORWARD-LOOKING INFORMATION |  |  | 1 |
ASSUMPTIONS |  |  | 3 |
ADOPTION OF US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (GAAP) |  |  | 3 |
NON-GAAP FINANCIAL MEASURES |  |  | 3 |
CORPORATE STRUCTURE |  |  | 5 |
DESCRIPTION OF OUR BUSINESS |  |  | 6 |
BUSINESS OVERVIEW |  |  | 6 |
HISTORY AND DEVELOPMENT OF THE BUSINESS |  |  | 6 |
OUR COMPETITIVE STRENGTHS |  |  | 7 |
OUR STRATEGY |  |  | 8 |
OUR OPERATIONS AND SEGMENTS |  |  | 9 |
OUR REVENUE SOURCES |  |  | 10 |
OUR MARKETS |  |  | 11 |
OUR CONTRACT TYPES |  |  | 15 |
PROJECTS |  |  | 16 |
ACTIVE PROJECTS |  |  | 16 |
RECENTLY COMPLETED PROJECTS |  |  | 17 |
RESOURCES AND KEY TRENDS |  |  | 17 |
OUR FLEET AND EQUIPMENT |  |  | 17 |
CAPITAL EXPENDITURES |  |  | 18 |
FACILITIES |  |  | 19 |
COMPETITION |  |  | 19 |
MAJOR SUPPLIERS |  |  | 20 |
VARIABILITY OF RESULTS |  |  | 20 |
LEGAL AND LABOUR MATTERS |  |  | 21 |
LAWS, REGULATIONS AND ENVIRONMENTAL MATTERS |  |  | 21 |
EMPLOYEES AND LABOUR RELATIONS |  |  | 22 |
DESCRIPTION OF SHARE CAPITAL |  |  | 22 |
SHARES |  |  | 22 |
DIVIDENDS |  |  | 23 |
DESCRIPTION OF CERTAIN INDEBTEDNESS |  |  | 24 |
DEBT RESTRUCTURING |  |  | 24 |
CREDIT FACILITIES |  |  | 24 |
9.125% SERIES 1 DEBENTURES |  |  | 25 |
LETTERS OF CREDIT |  |  | 26 |
DEBT RATINGS |  |  | 26 |
DIRECTORS AND OFFICERS |  |  | 28 |
THE BOARD AND BOARD COMMITTEES |  |  | 30 |
AUDIT COMMITTEE |  |  | 31 |
COMPENSATION COMMITTEE |  |  | 31 |
GOVERNANCE COMMITTEE |  |  | 31 |
HEALTH, SAFETY, ENVIRONMENT AND BUSINESS RISK COMMITTEE |  |  | 31 |
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS |  |  | 32 |
LEGAL PROCEEDINGS AND REGULATORY ACTIONS |  |  | 33 |
TRANSFER AGENT AND REGISTRAR |  |  | 33 |
MATERIAL CONTRACTS |  |  | 33 |
RISKS AND UNCERTAINTIES |  |  | 34 |
RISKS RELATED TO OUR BUSINESS |  |  | 34 |
RISKS RELATED TO OUR COMMON SHARES |  |  | 40 |
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |  |  | 42 |
GLOSSARY |  |  | 43 |
EXHIBIT A |  |  | i |
AUDIT COMMITTEE CHARTER |  |  | i |
APPENDIX A: AUDIT COMMITTEE FINANCIAL EXPERT |  |  | vi |

##### Table of Contents

NAEP

NORTH AMERICAN ENERGY PARTNERS INC.

Annual Information Form

June 2, 2011

EXPLANATORY NOTES

The information in this Annual Information Form (AIF) is stated as at June 2, 2011, unless otherwise indicated. For an explanation of the capitalized terms and expressions and certain defined terms, please refer to the “Glossary” at the end of this AIF. All references in this AIF to “we”, “us”, “NAEPI” or the “Company”, unless the context otherwise requires, mean North American Energy Partners Inc. and its Subsidiaries (as defined below).

INDUSTRY DATA AND FORECASTS

This Annual Information Form includes industry data and forecasts that we have obtained from publicly available information, various industry publications, other published industry sources and our internal data and estimates. For example, information regarding actual and anticipated production as well as reserves and current and scheduled projects in the Canadian oil sands was obtained from the Energy Resources Conservation Board (“ERCB”) and the Canadian Energy Research Institute. Information regarding historical capital expenditures in the oil sands was obtained from the Canadian Association of Petroleum Producers (“CAPP”).

Industry publications and other published industry sources generally indicate that the information contained therein was obtained from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. Although we believe that these publications and reports are reliable, we have not independently verified the data. Our internal data, estimates and forecasts are based upon information obtained from our customers, trade and business organizations and other contacts in the markets in which we operate and our management’s understanding of industry conditions. Although we believe that such information is reliable, we have not had such information verified by any independent sources. References to barrels of oil related to the oil sands in this document are quoted directly from source documents and refer to both barrels of bitumen and barrels of bitumen that have been upgraded into synthetic crude oil, which is considered synthetic because its original hydrocarbon mark has been altered in the upgrading process. We understand that there is generally some shrinkage of bitumen volumes through the upgrading process. The shrinkage is approximately 11% according to the Canadian National Energy Board. We have not made any estimates or calculations with regard to these volumes and have quoted these volumes as they appeared in the related source documents.

FORWARD-LOOKING INFORMATION

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

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

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

b) | The expectation that further market improvement could occur in fiscal 2012;

c) | That we anticipate the awarding of a new five-year master services agreement with Suncor;

d) | The expectation that we will capitalize on further recurring services opportunities related to the ongoing processing of tailings and reclamation of tailings ponds;

e) | The expectation that the demand for recurring oil sands services will grow;

f) | The expectation that we will continue providing construction services to in situ projects;

g) | The expectation that investments by Suncor and Syncrude will create opportunities for our new Tailings and Environmental Construction division to support the construction and operation of the new reclamation processes;

h) | The expectation that the Horizon project will recommence oil production in a number of stages, returning to full capacity by the end of 2011;

i) | The expectation that three of the four active oil sands mines will be operating later this year;

j) | The expectation that we will benefit from increased construction spending in the private sector;

2011 Annual Information Form |  | | NOA | |  |  | 1 |

##### Table of Contents

k) | The expectation that mine development projects under consideration for permits and environmental approvals in British Columbia and will create strong demand for mining services;

l) | The expectation that rising demand outside the oil sands not only creates opportunities for us to compete for this work but also could reduce the number of competitors looking for work in the oil sands;

m) | The expectation that Canada’s power transmission sector will receive significant investment over the next decade;

n) | The expectation that resource mining development activity will return to the robust levels that prevailed prior to the economic downturn, with capital investment in exploration and development expected to reach increased levels in 2011;

o) | The expectation that the additional 855,000 barrels per day of pipeline capacity that has been approved could go into service over the next few years;

p) | The expectation that increasing near-term demand for small and large pipeline projects and expansions and for large maintenance contracts should support improved pricing and reduced risk on new contracts;

q) | The expectation that conditions are expected to improve following the announcement of various pipeline projects in Western Canada;

r) | The expectation that the writedown related to the Canadian Natural contract will not negatively impact any of our other operations;

s) | The expectation that the mechanically stabilized earth (MSE) wall at Canadian Natural’s facilities will be completed in June 2011;

t) | The expectation that future mining expansions could ultimately increase total production capacity to 500,000 BPD;

u) | The expectation that volumes and rates under the proposed contract with Suncor will be renegotiated after 2.5 years to reflect changing market conditions;

v) | The expectation that Syncrude will increase total production capacity to 600,000 BPD by 2020;

w) | The expectation that Phase 1 of the Exxon Kearl project will achieve 100,000 bbl with first oil production by August, 2012;

x) | The expectation that we will bid on the construction of MSE walls for Syncrude;

y) | The expectation that tire supply will tighten in the coming year;

z) | The expectation that we will continue supplementing our tire allocation from Bridgestone and Michelin with supply from third party brokers;

aa) | Management’s expectation that a labour settlement will be reached without disruption;

bb) | The expectation that any future determination to pay dividends will be at the discretion of our board of directors and will depend on our financial condition, results of operations, capital requirements and other factors;

cc) | The expectation that none of the litigation or legal proceedings in which we are currently involved could have a material adverse effect on our business, financial condition or results of operations;

dd) | The expectation that Canadian Natural’s acceptance of the revised indices is probable;

ee) | Our intention to work with Canadian Natural to identify any equipment or personnel we can redeploy to other higher margin projects in the region; and

ff) | We expect the anticipated growth in the oil sands region will attract new and sometimes larger competitors to enter the region and compete against us for projects.

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” and “Risks related to our business” below and risk factors highlighted in materials filed with the securities regulatory authorities filed in the United States and Canada from time to time, including, but not limited to, our most recent Management’s Discussion and Analysis (MD&A) for the year ended March 31, 2011.

2 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

ASSUMPTIONS

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

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

• |  | The demand for recurring services remaining strong;

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

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

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

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

• |  | The mine projects in British Columbia will generally be approved;

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

• |  | Our ability to secure specific types of rental equipment to support project development activity will allow us to meet our customers’ variable service requirements while balancing the need to maximize equipment utilization with the need to achieve the lowest ownership costs;

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

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

ADOPTION OF US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (GAAP)

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

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

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

NON-GAAP FINANCIAL MEASURES

The body of generally accepted accounting principles applicable to us is commonly referred to as “GAAP”. A non-GAAP financial measure is generally defined by the Securities and Exchange Commission (SEC) and by the Canadian securities regulatory authorities as one that purports to measure historical or future financial performance, financial position or cash flows, but excludes or includes amounts that would not be so adjusted in the most comparable GAAP measures. In our MD&A, we use non-GAAP financial measures such as “net income before interest expense, income taxes, depreciation and amortization” (EBITDA) and “Consolidated EBITDA” (as defined in our fourth amended and restated credit agreement, our “credit agreement”). Consolidated EBITDA is defined as EBITDA, excluding the effects of unrealized foreign exchange gain or loss, realized and unrealized gain or loss on derivative financial instruments, non-cash stock-based compensation expense, gain or loss on disposal of plant and equipment, the impairment of goodwill, the amendment related to the $42.5 million revenue writedown on the Canadian Natural overburden removal contract and certain other non-cash items included in the calculation of net income. We believe that EBITDA is a meaningful measure of the performance of our business because it excludes items, such as depreciation and amortization, interest and taxes that are not directly related to the operating performance of our business. Management reviews EBITDA to determine whether plant and equipment are being allocated

2011 Annual Information Form |  | | NOA | |  |  | 3 |

##### Table of Contents

efficiently. In addition, our credit facility requires us to maintain a minimum interest coverage ratio and a maximum senior leverage ratio, both of which are calculated using Consolidated EBITDA. Non-compliance with these financial covenants could result in our being required to immediately repay all amounts outstanding under our credit facility. As EBITDA and Consolidated EBITDA are non-GAAP financial measures, our computations of EBITDA and Consolidated EBITDA may vary from others in our industry. EBITDA and Consolidated EBITDA should not be considered as alternatives to operating income or net income as measures of operating performance or cash flows as measures of liquidity. EBITDA and Consolidated EBITDA have important limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under US GAAP or Canadian GAAP. For example, EBITDA and Consolidated EBITDA do not:

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

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

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

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

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

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

A reconciliation of net income (loss) to EBITDA and Consolidated EBITDA can be found in our annual Management’s Discussion and Analysis for the year ended March 31, 2011, available on SEDAR at www.sedar.com and EDGAR at www.sec.gov.

4 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

CORPORATE STRUCTURE

The Company was amalgamated under the Canada Business Corporations Act on November 28, 2006, and was the entity continuing from the amalgamation of NACG Holdings Inc. with its wholly-owned subsidiaries, NACG Preferred Corp. and North American Energy Partners Inc. The amalgamated entity continued under the name North American Energy Partners Inc. The Company’s corporate office is located at Suite 2400, 500 4 th Avenue SW, Calgary, Alberta, T2P 2V6.

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

All of our Subsidiaries are incorporated under the Business Corporations Act (Alberta), except NACGI which is amalgamated under the Canada Business Corporations Act, North American Construction Ltd. which is continued under the Canada Business Corporations Act, Drillco Foundation Co. Ltd. and DF Investments Limited which are incorporated under the Business Corporations Act (Ontario) and Cyntech U.S. Inc. which is incorporated under the Texas Business Organizations Code.

2011 Annual Information Form |  | | NOA | |  |  | 5 |

##### Table of Contents

DESCRIPTION OF OUR BUSINESS

BUSINESS OVERVIEW

We provide a wide range of heavy construction and mining, piling and pipeline installation services to customers in the Canadian oil sands, industrial construction, commercial and public construction and pipeline construction markets. Our primary market is the Canadian oil sands, where we support our customers’ mining operations and capital projects. While we provide services through all stages of an oil sands project’s lifecycle, our core focus is on providing recurring services, such as contract mining, during the operational phase. For the year ended March 31, 2011, recurring services represented 81% of our oil sands business. Our principal oil sands customers include all four producers that are currently mining bitumen in Alberta: Syncrude 1, Suncor 2, Shell 3 and Canadian Natural 4. We focus on building long-term relationships with our customers. For example, we have been providing services to Syncrude and Suncor for over 30 years.

We believe that we operate the largest fleet of equipment of any contract resource services provider in the oil sands. Our total fleet (owned, leased and rented), most of which is located in the oil sands, includes approximately 780 pieces of diversified heavy construction equipment supported by over 750 ancillary vehicles. While our expertise covers mining, heavy construction, tailings management and mine reclamation services, underground services installation (fire lines, sewer, water, etc.) for industrial projects, and piling and pipeline installation in many different types of locations, we have a specific capability operating in the harsh climate and difficult terrain of northern Canada, particularly in the Canadian oil sands in Alberta.

We believe that our excellent safety record coupled with our significant oil sands knowledge, experience, long-term customer relationships, equipment capacity, scale of operations and broad service offering differentiate us from our competition. In addition, we believe that these capabilities will enable us to support our customers’ new oil sands developments and expansions, as well as the ever-increasing volume of recurring services generated by existing oil sands mines.¿

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

HISTORY AND DEVELOPMENT OF THE BUSINESS

We completed an Initial Public Offering (IPO) of our common shares and a related reorganization in November 2006 in order to reduce the leverage on our balance sheet and provide additional financial capacity as we pursued our growth strategy. The common shares began trading on the New York Stock Exchange on November 22, 2006 and became fully tradable on the Toronto Stock Exchange on November 28, 2006. Through the IPO, we raised a total of $152.6 million 5 in net proceeds. These funds were primarily used to restructure our balance sheet, reduce outstanding debt and buy out a number of equipment operating leases.

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

During the first half of fiscal 2009, activity levels in all of our segments and markets were at peak levels as a result of record commodity prices and unprecedented commercial and industrial construction spending, particularly in Western Canada and the Canadian oil sands. In the second half of fiscal 2009, market conditions began to change and by the end of fiscal 2009, the Canadian economy was in a recession. Lower commodity prices and restricted access to capital forced a number of customers across our key end-markets to delay or defer capital intensive projects. This, in turn, reduced the backlog of new development projects and negatively impacted all three of our business segments.

In the oil sands, the economic downturn during 2009 contributed to a temporary reduction in demand for project development services supporting new construction. In contrast, demand for recurring services remained steady, reflecting the inherent stability of operational oil sands mines. The economy began to stabilize in the second half of fiscal 2010 and by the end of fiscal 2011, commodity prices had somewhat recovered. Oil sands producers began announcing plans to restart construction on previously postponed expansions and greenfield projects, signalling a return to growth in the oil sands.

1 | 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%).

2 | Suncor Energy Inc. (Suncor).

3 | 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%).

4 | Canadian Natural Resources Limited (Canadian Natural).

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

5 | All denominations refer to Canadian dollars ($) unless otherwise specified.

6 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

The commercial construction sector was also negatively affected by the weaker economic conditions of fiscal 2009, resulting in reduced demand for piling services. This impact was partially offset by an increase in public infrastructure spending related to federal and provincial government economic stimulus programs. Activity levels in the commercial construction sector began to recover in fiscal 2011 and indications point to further market improvement in fiscal 2012.¿

In the conventional oil and gas sector, the recession led to a scaling back of plans for new pipeline construction and expansion projects. While companies in the late planning stages of their projects continued to move forward, competition for these projects was intense and characterized by a high number of bidders willing to assume more risk at lower margins. During fiscal 2010, we secured and executed three relatively small, low-margin pipeline contracts. We incurred weather and other risks on these contracts and our Pipeline segment recorded a loss for the year. Market conditions remained challenging through fiscal 2011, however we secured and executed two large projects and several smaller jobs, achieving financial results that were closer to breakeven. By late fiscal 2011, the outlook for future pipeline construction activity had improved as a result of the recovery in commodity prices and the resurgence of oil sands production plans.

We have undertaken several strategic initiatives in the past three years to help us respond to changing market conditions and prepare for the future. Our initiatives include strengthening our financial position with a debt refinancing, capital spending reductions, organizational restructuring, cost-reduction initiatives and focused cash management. We have also focused attention on those areas of our business that provide opportunities for profitable revenue generation, particularly recurring services. In the Heavy Construction and Mining segment, we were awarded multi-year agreements with major oil sands customers including:

• |  | a three-year master services agreement with Shell;

• |  | a three-year muskeg removal contract with Shell; and

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

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

We also identified a service opportunity related to new regulations governing tailings pond management (Directive 74) and moved quickly to develop and market a capability that supports our clients’ requirements. While this industry development is still in its early stages, we have already been involved in the construction of several pilot plants and some of the initial commercial developments. Going forward, we expect to capitalize on further recurring services opportunities related to the ongoing processing of tailings and reclamation of tailings ponds.¿

In the Piling segment, we have continued to position ourselves for the future by expanding our geographic reach and service offering with the acquisition of two piling companies. In fiscal 2010, we completed the acquisition of DF Investments Inc. and its subsidiary, Drillco Foundation Co. Ltd. This transaction established our presence in the large Ontario construction market. We followed up with the acquisition of Cyntech Corporation 6 in fiscal 2011. Cyntech provided us with screw piling capabilities, a patented pipeline anchoring system and maintenance capabilities for above-ground storage tanks, while also bringing us international business opportunities.

OUR COMPETITIVE STRENGTHS

We believe our competitive strengths are as follows:

Leading market position

We believe we are the largest provider of contract mining services in the Alberta oil sands area and we believe we are the largest piling foundations installer in Western Canada. We have operated in Western Canada for over 50 years and have participated in every significant oil sands mining project since operators first began developing this resource over 30 years ago. This has given us extensive experience operating in the challenging working conditions created by the harsh climate and difficult terrain of the oil sands and Northern Canada. We have amassed what we believe is the largest fleet of any contract services provider in the oil sands. We believe the combination of our significant size, extensive experience and broad service offerings makes us one of only a few companies capable of taking on long-term, large-scale mining and heavy construction projects in the oil sands.

Large, well-maintained equipment fleet

As of March 31, 2011, we had a heavy equipment fleet of 780 units, made up of–shovels, excavators, trucks and dozers as well as loaders, graders, scrapers, cranes, pipe layers and drill rigs. Over the past three years we have invested over $478.7 million in our fleet including upgrades, new equipment purchases and equipment leases. As a result, we believe we now have

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

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

2011 Annual Information Form |  | | NOA | |  |  | 7 |

##### Table of Contents

an unmatched, modern fleet of equipment to service our clients’ needs. Our fleet includes some of the largest-shovels in the world which are designed for use in the largest earthmoving and mining applications globally. Being the only contractor in the oil sands to operate shovels of this size and one of only two contractors to operate trucks larger than 240 tons capacity gives us a competitive advantage with respect to both skill base and equipment availability. The size and diversity of our fleet enables us to respond on short notice and provide customized fleet solutions for each specific job.

A well-maintained fleet is critical in the harsh climatic and environmental conditions we encounter. We operate four significant maintenance and repair centers on our customers’ oil sands sites. These facilities are capable of accommodating the largest pieces of equipment in our fleet. In addition, we have a major repair facility located at our administrative offices near Edmonton, Alberta. This facility can perform the same major maintenance and repair activities as our facilities in the oil sands and provides back-up in the event of peak maintenance or repair requirements for oil sands equipment. We believe our combination of onsite and offsite service capabilities increases our efficiency. This, in turn, reduces costs and increases our equipment utilization, thereby enhancing our competitive edge and profitability.

Broad service offering across a project’s lifecycle

We are considered to be a “first-in, last-out” service provider in the oil sands because we provide services through the entire lifecycle of an oil sands project. Our work typically begins with the initial consulting services provided during the planning phase, including constructability, engineering reviews and budgeting. This leads into the construction phase during which we provide a full range of services, including clearing, muskeg removal, site preparation, mine infrastructure construction, piling, pipeline and underground utility installation. As the mine moves into production, we support the preparation of the mine by providing ongoing site maintenance and upgrading, equipment and labour supply, overburden removal and land reclamation. Given the long-term nature of oil sands projects, we believe that our broad service offering enables us to establish ongoing relationships with our customers through a continuous supply of services as we transition from one stage of the project to the next.

Long-term customer relationships

We have established strong, long-term relationships with major oil sands producers and conventional oil and gas producers. Our largest oil sands customers by revenue are Syncrude, Suncor, Shell Canada and Canadian Natural. We have worked with each of these customers since they began operations in the oil sands. In the case of Syncrude and Suncor, our relationships date back over 30 years. The longevity of our customer relationships reflects our ability to deliver a strong safety and performance record, a well-maintained, highly capable fleet with specific equipment dedicated to individual customers and a staff of well-trained, experienced supervisors, operators and mechanics. In addition, our practice of maintaining offices and maintenance facilities directly on most of our oil sands customers’ sites enhances the relationship. Our proximity and close working relationships typically result in advance notice of projects, enabling us to anticipate our customers’ needs and align our resources accordingly.

Operational flexibility

The combination of our onsite fleets and relationships with multiple oil sands operators makes it possible for us to efficiently transfer equipment and other resources among projects. This keeps us highly responsive to customer needs and is an essential element in securing recurring services business. In this part of the business, lead times are short and the work is usually conducted outside of long-term contracts. The nature of this work acts as a disincentive for potential new competitors who may be unwilling to take on the risk of mobilizing a fleet for a single project or without the benefit of secure contracts. The fact that we work on every major site in the oil sands contributes to our flexibility, enhances the stability of our business model and enables us to continue bidding profitably on new contracts. This has helped us through the recent economic downturn.

OUR STRATEGY

Our strategy is to be an integrated service provider for the developers and operators of resource-based industries in a broad and often challenging range of environments. More specifically, our strategy is to:

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

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

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

• |  | Leverage and expand our complementary services: Our service segments, Heavy Construction and Mining, Pipeline and Piling are complementary to one another and allow us to compete for many different kinds of business opportunities. We intend to build on our “first-in” position to cross-sell our many services, while also pursuing selective acquisition opportunities that expand our complementary service offerings, increase our recurring revenues and/or reduce the overall capital intensity of the business.

8 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

• |  | Enhance operating efficiencies to improve revenues and margins: We aim to increase the availability and efficiency of our equipment through enhanced maintenance, providing the opportunity for improved revenue, margins and profitability.

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

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

OUR OPERATIONS AND SEGMENTS

Our business is organized into three operating segments: (i) Heavy Construction and Mining, (ii) Piling and (iii) Pipeline. Revenue generated from these three segments for the year ended March 31, 2011 is represented in the chart below:

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

Heavy Construction and Mining

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

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

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

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

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

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

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

Piling

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

Our Canadian piling operations extend from British Columbia to Ontario and more recently, into the US and abroad. The international operations acquired as part of our November 2010 acquisition of Cyntech Corporation 7 include a small manufacturing facility in Texas and a small but well-established customer base for screw pile and pipeline anchor supply in the US, Malaysia, Indonesia, Thailand and Russia.

7 | 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.

2011 Annual Information Form |  | | NOA | |  |  | 9 |

##### Table of Contents

Pipeline

Our Pipeline segment focuses on infrastructure development for oil and gas pipeline systems including gathering and processing, transmission, storage and distribution, complete with related maintenance and other specialty services. Our Pipeline segment is respected in the industry and is known for its ability to execute technically and environmentally challenging projects for Canada’s largest energy companies. The Pipeline segment has capacity and resources to handle pipe ranging in size from 2-inch to 60-inches in diameter and operates across numerous remote geographical locations simultaneously.

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

The table below shows the revenues generated by each operating segment for the years ended March 31, 2011, 2010 and 2009:

|  | Year ended March 31, |
(dollars in thousands) |  | 2011 |  |  |  |  |  | 2010 |  |  |  |  |  | 2009 |
Heavy Construction & Mining |  |  | $667,037 |  |  |  | 77.7% |  |  |  |  |  |  |  | $665,514 |  |  |  | 87.7% |  |  |  |  |  |  |  | $716,053 |  |  |  | 73.6% |
Piling |  |  | 105,559 |  |  |  | 12.3 |  |  |  |  |  |  |  | 68,531 |  |  |  | 9.0 |  |  |  |  |  |  |  | 155,076 |  |  |  | 16.0 |
Pipeline |  |  | 85,452 |  |  |  | 10.0 |  |  |  |  |  |  |  | 24,920 |  |  |  | 3.3 |  |  |  |  |  |  |  | 101,407 |  |  |  | 10.4 |
Total |  |  | 858,048 |  |  |  | 100.0% |  |  |  |  |  |  |  | 758,965 |  |  |  | 100.0% |  |  |  |  |  |  |  | 972,536 |  |  |  | 100.0% |

OUR REVENUE SOURCES

Revenue by Category

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

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

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

10 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

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

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

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

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

OUR MARKETS

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

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

Canadian Oil Sands Market

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

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

Although we have provided and intend to continue providing construction services to in situ projects, we currently provide most of our services to customers that access the oil sands through open pit mines. The three-to-four year initial construction and development phase of a new mine or in situ project creates demand for our project development services, such as clearing, site preparation, piling and underground utilities installation. Once the construction phase of an in situ

2011 Annual Information Form |  | | NOA | |  |  | 11 |

##### Table of Contents

project is complete, there is little opportunity for us to provide recurring services. In contrast, after the initial construction phase of a mining project is complete, the mine moves into the 30-40 year operational phase and demand shifts from project development services to recurring services such as surface mining, overburden removal, labour and equipment supply, mine infrastructure development and maintenance and land reclamation.¿

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

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

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

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

The requirement for recurring services also typically grows as mines age. Mine operators tend to construct their plants closest to the easy-to-access bitumen deposits (less overburden and/or higher quality bitumen) to maximize profitability and cash-flow at the beginning of their projects. As the mines move through their typical 40+ year life cycle, easy-to-access, high quality bitumen deposits are depleted and operators must go greater distances and move more material to secure the required volume of oil sand to feed the plant at capacity.8 As a result, the total capacity of digging and hauling equipment must increase, together with an increase in the ancillary equipment and services needed to support these activities. In addition, as the mine extends to new areas of the lease, operators will often relocate mine infrastructure in order to reduce haul distances. This creates demand for mine construction services in the expansion area, as well as reclamation services to remediate the mined-out area. Accordingly, the demand for recurring oil sands services continues to grow even during periods of stable production because the geographical footprints of existing mines continue to expand under normal operation.¿

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

8 | 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.

12 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

Current Canadian Oil Sands Business Conditions

Project Development: As economic conditions have strengthened, several oil sands projects have returned to the active planning and development stages. Suncor and Total 9 are pooling their manpower and capital resources and sharing risk with a strategic alliance to develop Suncor’s Fort Hills 10 mine and Voyageur 11 upgrader project and Total’s Joslyn 12 mine project. Exxon continues with construction of its Kearl 13 mine as the project moves to the above ground construction and mine development phase of the project and Syncrude is planning a number of major mining projects, including the relocation of four mine trains.

A number of in-situ projects are also proceeding, including Husky Energy’s Sunrise 14, ConocoPhillips’ Surmont 15, Cenovus Energy’s Foster Creek and Christina Lake 16, as well as Devon Canada’s 17 Jackfish projects. In addition, Suncor is proceeding with additional stages of its Firebag in situ project. The increase in activity is reflected in CAPP’s revised estimate of industry capital spending for oil sands development, which increased to $13 billion for 2010, compared to $11 billion in 2009.

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

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

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

Commercial and Public Construction Market

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

Current Commercial and Public Construction Business Conditions

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

Industrial Construction Market

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

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

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

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

12 | 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.

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

14 | 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.

15 | 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.

16 | 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.

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

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

2011 Annual Information Form |  | | NOA | |  |  | 13 |

##### Table of Contents

The resource mining industry presents a special interest for us, with Canada being one of the largest mining nations in the world, producing more than 60 different minerals and metals. In particular, Canada is the world’s largest producer of potash, accounting for more than one third of the world’s potash production and exports. We have recently begun providing services to this sector through our Piling segment. With several potash mine expansions and new developments in the planning stages, we believe this is a growing market for our construction services.

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

The conventional oil and gas industry is another source of industrial construction projects. Currently, we are providing industrial and piling services to CCRL’s 18 heavy oil upgrader revamp and expansion project in Regina. Through our recent acquisition of Cyntech, we have also added screw piling, pipeline anchors and tank services capabilities, all of which have expanded our presence in the conventional oil and gas industry. We believe our newly acquired screw piling capabilities will also position us to service Canada’s power transmission sector, which is expected to experience significant investment over the next decade.¿

Current Industrial Construction Business Conditions

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

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

Pipeline Construction Market

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

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

Current Pipeline Construction Business Conditions

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

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

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

14 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

OUR CONTRACT TYPES

We complete work under the following types of contracts: cost-plus, time-and-materials, unit-price and lump-sum. Each type of contract contains a different level of risk. The following table demonstrates our revenue by contract type:

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

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

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

Cost-plus. A cost-plus contract is a contract in which all the work is completed based on actual costs incurred to complete the work. These costs include all labour, equipment, materials and any subcontractors’ costs. In addition to these direct costs, all site and corporate overhead costs are charged to the job. An agreed-upon fee that represents a profit in the form of a fixed percentage is then applied to all costs charged to the project. This type of contract is utilized where the project involves a large amount of risk or the scope of the project cannot be readily determined.

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

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

2011 Annual Information Form |  | | NOA | |  |  | 15 |

##### Table of Contents

PROJECTS

ACTIVE PROJECTS

Canadian Natural19: Overburden Removal Project

Canadian Natural completed construction of its Horizon Oil Sands Project and achieved first oil production in early 2009. This oil sands mining project has a targeted production capacity of 110,000 BPD from Phase 1. Canadian Natural has plans to ultimately increase total production capacity to 500,000 BPD through future expansions. Phases 2 and 3 of the mine expansion plan are currently in the planning stages.

We have been working at the Horizon mine since 2005 when we secured a contract with Canadian Natural to remove approximately 400 million bank cubic meters (“BCM”) of overburden and use 300 million BCM of that material to build a tailings dyke at the site. This is a unit-price contract worth approximately $1.3 billion over the 10-year life of the contract.

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

As announced in our press release, issued on May 18, 2011, we applied a writedown to the long-term overburden removal contract between our subsidiary, North American Construction Group Inc. (NACG) and Canadian Natural, for the Horizon Oil Sands mine near Fort McMurray, Alberta. This isolated issue is not expected to negatively impact any of our other operations and despite the writedown on this contract our current financial position is not materially affected. For further information refer to the Explanatory Notes—Significant Business Event in our MD&A.¿

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

Canadian Natural: MSE Wall

In November 2010, we completed the major construction of a 4000m2 MSE wall at the facility at Canadian Natural’s Ore Processing Plant mine including piling and foundations work. Ancillary support work continues with completion anticipated in June 2011.¿

Shell Muskeg River and Jackpine Mines

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

In June 2009, we signed a three-year earthmoving and mine support services agreement with Shell. The contract covers the provision of recurring services including construction, earthmoving and mine support and replaced an expiring two-year master services agreement (MSA). Work under the agreement covers general master services work and includes three years of defined scope and volumes for pre-strip and base-of-feed cleanup mining at the Muskeg River Mine. This type of work is typically performed under a time-and-materials arrangement and is not reflected in our reported backlog.

In December 2010, we signed an additional three-year agreement to provide muskeg removal services at Shell’s Jackpine Mine. This is a time-and-materials contract and is in addition to the agreement mentioned above.

Suncor

Suncor’s current mining operation includes the Steepbank and Millennium mines, which have a combined production capacity in excess of 300,000 BPD. An additional 120,000 BPD of production capacity is anticipated from the planned development of the Voyageur South mine. Following the merger with Petro-Canada and a strategic alliance with Total, Suncor’s minable assets have expanded to include a 40.8% interest in the Fort Hills oil sands project and a 36.75% interest in the Total-operated Joslyn North Mine Project.

Our contract to supply mining equipment to Suncor has recently been extended to the end of December 2011. We also supply services under time and materials and unit rate pricing arrangements without an MSA.

We are in negotiations to secure a 5 year contract to provide reclamation, civil construction and mine services at Suncor’s Millennium and Steepbank oil sands mine operations with volumes and rates to be renegotiated after 2.5 years to reflect changing market conditions.¿

Syncrude

Syncrude’s current mining operations include Base Mine (Mildred Lake) and Aurora Mine, which have a current combined production capacity of approximately 350,000 BPD. Further planned expansions include the development of a new mine (Aurora South), which is expected to increase total production capacity to 600,000 BPD by 2020.¿

19 | Canadian Natural Resources Limited (Canadian Natural).

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

16 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

In November 2010, Imperial Oil Ltd. awarded us a new four-year master services agreement, which enables us to execute various types of projects for this customer. Construction work authorizations are issued for each piece of work under both time-and-materials and unit-price arrangements and are generally not reflected in our reported backlog.

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

In July 2009 we were awarded the CCRL heavy oil upgrader revamp and expansion project in Regina, Saskatchewan. Work continues on this site as we complete tank farm earthworks construction, associated piping and pipelines and other heavy civil works as required by the client under an open services agreement. Our Piling team is also installing piling foundations inside the operating facility and outside of the plant limits in the new expansion areas.

RECENTLY COMPLETED PROJECTS

Exxon’s Kearl: MSE Wall

The first of three phases is being constructed for the Kearl project. The targeted production capacity for the entire project will be 345,000 BPD. Phase 1 expects to achieve 100,000 BPD with first oil production by August, 2012.¿

In December 2010, we completed a unit-price contract to construct an MSE wall and associated truck dump pad and to complete grading at the base of the wall.

Syncrude: MSE Wall

In September 2010, we completed the construction of a 440 meter long MSE wall including shear key, backfill and construction of the wall. Syncrude is currently planning two mine train moves in the next 3-4 years, each requiring two large MSE walls for a total of four MSE walls to be constructed which we expect to bid on.¿

Syncrude: Reclamation

Between November 2010 and March 2011, we completed a winter reclamation project moving 5.1 million BCM of reclamation material at Syncrude’s Base Mine. 2.1 million BCM was direct-placed resulting in 156 hectares of reclaimed land for Syncrude.

Suncor: Reclamation

Between December 2010 and March 2011, we completed a winter reclamation project, moving 4 million BCM of material in Suncor’s Millenium Mine.

Spectra Energy20: Maxhamish Loop—South

In December 2010 we completed a 30 kilometre, 24-inch diameter natural gas pipeline installation project in the Fort Nelson area of British Columbia for Spectra Energy. The looping project is designed to support the upcoming Horn River area development commitments. This project carried on from where last winter’s North Maxhamish project ended.

Transcanada Pipelines21: Groundbirch Mainline Project

In November 2010 we completed a four month contract to build 77 kilometres of 36-inch diameter pipeline. This was our first automated welding project.

Joint Venture

The participants in the Noramac Joint Venture entered into a Mutual Termination of Joint Venture Agreement under which the joint venture was terminated effective March 25, 2011. The business of the joint venture is currently in the process of being wound-up under the terms of that Agreement.

RESOURCES AND KEY TRENDS

OUR FLEET AND EQUIPMENT

We operate and maintain a heavy equipment fleet, including crawlers, graders, loaders, mining trucks, compactors, scrapers and excavators. We also maintain a fleet of ancillary vehicles including various service and maintenance vehicles. Overall, the equipment is in good condition, subject to normal wear and tear. Our credit facility is secured by liens on substantially all of our equipment. We lease some of this equipment under lease terms that include purchase options.

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

20 | Spectra Energy Partners, LP (Spectra Energy).

21 | TransCanada Pipelines Limited (TransCanada Pipelines), a wholly owned subsidiary of TransCanada Corporation.

2011 Annual Information Form |  | | NOA | |  |  | 17 |

##### Table of Contents

The following table sets forth our owned and leased heavy equipment fleet (does not include rental equipment) as at March 31, 2011:

Category |  | Capacity Range |  | Horsepower Range |  |  | Number in Fleet |  |  | Number Leased |
Heavy Construction and Mining: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Articulating trucks |  | 30 to 40 tons |  |  | 305 - 406 |  |  |  | 20 |  |  |  | 0 |
Mining trucks |  | 40 to 330 tons |  |  | 476 - 2,700 |  |  |  | 177 |  |  |  | 73 |
Shovels |  | 35-80 cubic yards |  |  | 2,600 - 3,760 |  |  |  | 8 |  |  |  | 6 |
Excavators |  | 1 to 29 cubic yards |  |  | 90 - 1,944 |  |  |  | 102 |  |  |  | 25 |
Dozers |  | 20,741 lbs to 230,100 lbs |  |  | 96 - 850 |  |  |  | 124 |  |  |  | 56 |
Graders |  | 14 to 24 feet |  |  | 150 - 500 |  |  |  | 29 |  |  |  | 10 |
Loaders |  | 1.5 to 16 cubic yards |  |  | 110 - 690 |  |  |  | 85 |  |  |  | 0 |
Packers |  | 14,175 to 68,796 lbs |  |  | 216 - 315 |  |  |  | 7 |  |  |  | 0 |
Articulating Water Trucks |  | 8,000 gallon |  |  | 406 |  |  |  | 3 |  |  |  | 0 |
Scraper Water Wagons |  | 10,000 gallon |  |  | 462 |  |  |  | 2 |  |  |  | 0 |
Float Trucks |  | 250 tons |  |  | 703 |  |  |  | 5 |  |  |  | 0 |
Heavy Oil Recovery Barge Heavy Oil Recovery Barge |  | 30,000 US gal per hour |  |  | 125 |  |  |  | 1 |  |  |  | 0 |
Tractors |  | 43,000 lbs |  |  | 460 |  |  |  | 2 |  |  |  | 0 |
Pipeline: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Trenchers |  | 60,000 lbs |  |  | 165 |  |  |  | 1 |  |  |  | 0 |
Pipe layers |  | 20,000 to 202,000 lbs |  |  | 78 - 265 |  |  |  | 39 |  |  |  | 0 |
Piling: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Drill rigs |  | Up to 267 feet (drill depth) |  |  | 210 - 1,500 |  |  |  | 53 |  |  |  | 4 |
Cranes |  | 25 to 150 tons |  |  | 200 - 263 |  |  |  | 25 |  |  |  | 0 |
Total |  |  |  |  |  |  |  |  | 687 |  |  |  | 174 |

For the fiscal years ended March 31, 2011, 2010 and 2009, we incurred expenses of $234.9 million, $209.4 million and $217.1 million, respectively, to maintain our equipment.

Many of our heavy equipment units are among the largest pieces of equipment in the world and are designed for use in the largest earthmoving and mining applications globally. Our large, diverse fleet gives us flexibility in scheduling jobs and we believe that this allows us to be responsive to our customers’ needs. A well maintained fleet is critical in the harsh climate and environmental conditions in which we operate. We operate four significant maintenance and repair centers on the sites of the major oil sands projects, which are capable of accommodating the largest pieces of equipment in our fleet. These factors help us to be more efficient, thereby reducing costs to our customers to further improve our competitive position, while concurrently increasing our equipment utilization and thereby improving our profitability.

CAPITAL EXPENDITURES

The following table sets out capital expenditures for long-lived assets for our main operating segments for the periods indicated, excluding new capital leases:

|  | Year Ended March 31, |
(dollars in thousands) |  | 2011 |  |  |  |  |  | 2010 |  |  |  |  |  | 2009 |
Heavy Construction & Mining |  |  | $29,577 |  |  |  |  |  |  |  | $40,431 |  |  |  |  |  |  |  | $76,354 |
Piling |  |  | 2,560 |  |  |  |  |  |  |  | 1,081 |  |  |  |  |  |  |  | 8,679 |
Pipeline |  |  | 1,124 |  |  |  |  |  |  |  | 948 |  |  |  |  |  |  |  | 75 |
Other |  |  | 7,904 |  |  |  |  |  |  |  | 12,790 |  |  |  |  |  |  |  | 5,096 |
Total |  |  | $41,165 |  |  |  |  |  |  |  | $55,250 |  |  |  |  |  |  |  | $90,204 |

18 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

FACILITIES

We own and lease a number of buildings and properties for use in our business, the locations of which were chosen for their geographic proximity to our major customers. Our corporate offices are located in Calgary, Alberta. Our primary administrative functions are carried out from offices in Edmonton, Alberta and Acheson, Alberta, where we also have a major equipment maintenance facility. Additional project management and equipment maintenance functions are carried out from leased and owned regional facilities in Calgary and Fort McMurray, Alberta; New Westminster, British Columbia; Regina and Martensville, Saskatchewan; and Milton, Ontario. The operations of our U.S. subsidiary, Cyntech U.S. Inc., are carried out from leased premises in Plantersville, Texas. We also occupy, without charge, some customer-provided lands. The following table describes our primary facilities:

Location |  | Function |  | Owned or Leased |  | Lease Expiration Date
Acheson, Alberta |  | Administrative office and major equipment repair facility |  | Leased |  | 11/30/2012
Calgary, Alberta (Corporate Office) |  | Corporate head office |  | Leased |  | 1/29/2012
Calgary, Alberta (Piling Office) |  | Regional office for piling operations and major equipment repair facility |  | Leased |  | 09/30/2020
Calgary, Alberta (Cyntech Office) |  | Regional office for piling operations |  | Leased |  | 10/31/2013
Edmonton, Alberta (Mayfield) |  | Administrative office and regional office for piling operations |  | Leased |  | 3/31/2017
Fort McMurray, Alberta (Timberlea) |  | Regional office for mining operations |  | Leased |  | 2/28/2022
Fort McMurray, Alberta (CNRL site) |  | Site office and maintenance facility |  | Building owned Land provided |  | Term of CNRL contract
Fort McMurray, Alberta (Shell Canada Muskeg River Mine site) |  | Site office and maintenance facility |  | Building leased Land provided |  | Term of Shell Canada contract
Fort McMurray, Alberta (Syncrude Ruth Lake site) |  | Regional office and maintenance facility for all operations |  | Building owned Land provided |  | 8/31/2021 Currently finalizing extension
New Westminster, BC (Premises) |  | Regional office and equipment repair facility for piling operations |  | Leased |  | 12/31/2014
New Westminster, BC (Water Rights) |  | Water rights adjacent to piling office premises |  | Leased |  | 3/31/2015
Martensville, Saskatchewan |  | Regional office and equipment repair facility for piling operations |  | Leased |  | 4/30/2012
Regina, Saskatchewan |  | Regional office and equipment repair facility for piling operations |  | Leased |  | 3/14/2013
Milton, Ontario (Drillco) |  | Regional office and equipment repair facility for piling operations |  | Owned |  | N/A
Plantersville, Texas |  | Offices of Cyntech U.S. Inc. |  | Leased |  | 10/31/2013

COMPETITION

The majority of our new business is secured through formal bidding processes in which we are required to compete against other suppliers. Factors that impact success on competitive bids include price, safety, reliability, scale of operations, equipment and labour availability and quality of service. Our industry is highly competitive in each of our markets and competition on project bids increased noticeably during the year ended March 31, 2011 as a result of continued weaker

2011 Annual Information Form |  | | NOA | |  |  | 19 |

##### Table of Contents

economic conditions. As a result of several oil sands competitors experiencing financial difficulty, we have seen a change in our competitive environment with several competitors being acquired over the past two years. This included smaller competitors such as Cross-Terra Construction and Atcon Group, as well as a larger competitor, Cow Harbour Construction Ltd. which had been operating under creditor protection until being acquired by Aecon Group Inc. in August, 2010. Our principal competitors in the Heavy Construction and Mining segment include Klemke Mining Corporation, Aecon Group Inc., Graham Construction Ltd, Ledcor Construction Limited, Peter Kiewit and Sons Co., Tercon Contractors Ltd., Sureway Construction Ltd. and Thompson Bros. (Construction) Ltd. In underground utilities installation (a part of our Heavy Construction and Mining segment), Voice Construction Ltd., Ledcor Construction Limited and I.G.L. Industrial Services are our major competitors.

The main competition to our deep foundation piling operations in Western Canada comes from Agra Foundations Limited, Double Star Drilling and Pacer Industries, and in Eastern Canada our main competitors include Deep Foundations, Anchor Shoring and Bermingham Construction. In the public sector, we compete against national firms, as well as local competitors within individual geographic markets. Most of our public sector customers are local governments that are focused on serving only their regions. Competition in the public sector continues to increase and we typically choose to compete on projects only where we can utilize our equipment and operating strengths to secure profitable business.

The primary competitors in the pipeline installation business include Ledcor Construction Limited, Washcuk Pipe Line Construction Ltd., O.J. Pipelines Canada and Willbros Group Inc.

MAJOR SUPPLIERS

We have long-term relationships with the following equipment suppliers: Finning International Inc. (over 45 years), Wajax Income Fund (over 20 years) Brandt Tractor Ltd. (over 30 years), and SMS Equipment (over 5 years). Finning is a major Caterpillar heavy equipment dealer for Canada. Wajax is a major Hitachi equipment supplier to us for both mining and construction equipment. We purchase or rent John Deere equipment, including excavators, loaders and small bulldozers, from Brandt Tractor. SMS Equipment is a major Komatsu equipment supplier for our large mining trucks. In addition to the supply of new equipment, each of these companies is a major supplier for equipment rentals, parts and service labour. We are also actively working with these suppliers to identify cost savings opportunities such as reducing our rental fleet and focusing on parts management.

Tire supply has been a challenge for our haul truck fleet over the past few years because we have not had a long term contract with major tire suppliers. In the past three years supply contracts with Bridgestone and Fountain Tire plus an allocation from Michelin through Kal Tire have helped us to maintain tire inventories to keep our fleet fully operational. We have also relied on third party tire brokers in the United States for a large portion of our tires which can be at greatly inflated prices. Tire usage forecasting by our tire group for giant heavy haul tires or off the road (OTR) tires has provided information and identified predicted shortages on 63, 57 and 51 inch tires and this has enabled us to acquire tires from third parties when they become available to supplement current supplies from Bridgestone and Michelin. As a result of a shortage of raw materials caused by poor climatic conditions and increased world wide tire demand, specifically in China, tire supply is expected to tighten worldwide in the coming year. We expect to continue supplementing our tire allocation from Bridgestone and Michelin with supply from third party brokers.¿

VARIABILITY OF RESULTS

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

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

The timing of large projects can influence quarterly revenues. For example, in the past two fiscal years, Pipeline segment revenues were as low as $0.1 million in the three months ended June 30, 2009 and as high as $42.2 million for the three months ended December 31, 2010. The Heavy Construction and Mining segment experienced reduced volumes in the three months ended March 31, 2009 as a result of the temporary shut-down of overburden removal at the Horizon project while Canadian Natural prepared for operations start-up. Subsequent periods reflect the ramp up of overburden removal activities

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

20 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

at the Horizon project through the three months ended December, 2010, where activity returned to planned activity levels. The project write-down for this contract negatively affected results for the three months ended March 31, 2011. Changes in demand under our master services agreements with Shell positively affected fiscal 2010 results with increased demand for mine services during the commissioning of Shell’s Jackpine mine. Activity subsequently declined in fiscal 2011 as Shell commissioned the Jackpine mine and concurrently undertook related integration activities at the Muskeg River mine

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

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

We have also experienced net income variability in all periods up to the three months ended June 30, 2010, due to the recognition of unrealized non-cash gains and losses on both derivative financial instruments and our previously held US dollar denominated 8 3/4% senior notes, primarily driven by changes in the Canadian/US dollar exchange rate. The 8 3/4% senior notes were redeemed on April 28, 2010 and the associated currency and interest rate swaps were terminated on April 8, 2010.

LEGAL AND LABOUR MATTERS

LAWS, REGULATIONS AND ENVIRONMENTAL MATTERS

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

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

• |  | building and similar codes and zoning ordinances;

• |  | laws and regulations relating to consumer protection; and

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

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

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

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

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

2011 Annual Information Form |  | | NOA | |  |  | 21 |

##### Table of Contents

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

EMPLOYEES AND LABOUR RELATIONS

As of March 31, 2011, we had approximately 533 salaried employees and approximately 2,279 hourly employees. The growth in our salaried employee work force can be primarily attributed to our conversion of hourly site supervision staff to salaried employees during the fiscal year. Our hourly workforce fluctuates according to the seasonality of our business and the staging and timing of projects by our customers. The hourly workforce typically ranges in size from 1,000 employees to approximately 3,000 employees depending on the time of year and duration of awarded projects. We also utilize the services of subcontractors in our construction business. An estimated 8% to 10% of the construction work we do is performed by subcontractors. Approximately 2,000 employees are members of various unions and work under collective bargaining agreements. The majority of our work is done through employees governed by our mining overburden collective bargaining agreement with the International Union of Operating Engineers Local 955, the primary term of which expires on March 31, 2015. Other collective agreements in operation include the provincial Industrial, Commercial and Institutional (ICI) agreements in Alberta and Ontario with both the Operating Engineers and Labourers Unions, Piling sector collective agreements in Saskatchewan with the Operating Engineers, Pipeline sector agreements in both British Columbia and Alberta with the Christian Labour Association of Canada (CLAC) as well as an all-sector agreement with CLAC in Ontario. We are subject to other industry and specialty collective agreements under which we complete work and the primary terms of all of these agreements are currently in effect. The provincial collective agreement between the International Union of Operating Engineers (IUOE) Local 955 and the Alberta Roadbuilders and Heavy Construction Association (ARBHCA) expired February 28, 2011 and the Association is currently amidst negotiations with the Operating Engineers for the renewal of this Agreement. NACG has a representative on the ARBHCA bargaining committee. Management expects that a settlement will be reached without disruption. We believe that our relationships with all our employees, both union and non-union, are strong. We have not experienced a strike or lockout.¿

DESCRIPTION OF SHARE CAPITAL

SHARES

General

Our articles of amalgamation authorize us to issue an unlimited number of voting common shares and an unlimited number of non-voting common shares. As of June 2, 2011, we had 36,249,086 common shares outstanding (36,242,526 outstanding as at March 31, 2011).

Some of the statements contained herein are summaries of the material provisions of our articles of amalgamation relating to dividends, distribution of assets upon dissolution, liquidation or windingup and are qualified in their entirety by reference to our articles of amalgamation which can be found on www.sedar.com.

Voting Common Shares

Each voting common share has an equal and ratable right to receive dividends to be paid from our assets legally available therefore when, as and if declared by our board of directors.

In the event of our dissolution, liquidation or winding up, the holders of common shares are entitled to share equally and ratably in the assets available for distribution after payments are made to our creditors. Holders of common shares have no pre-emptive rights or other rights to subscribe for our securities. Each common share entitles the holder thereof to one vote in the election of directors and all other matters submitted to a vote of shareholders, and holders of common shares have no rights to cumulate their votes in the election of directors.

Non-Voting Common Shares

Regulatory requirements applicable to affiliates of one of our shareholders limited-the amount of our voting shares it may own. Therefore, in addition to our voting common shares that it owns, it also owned all of our non-voting common shares, which it acquired on November 26, 2003. Except as prescribed by Canadian law and except in limited circumstances, the non-voting common shares have no voting rights but are otherwise identical to the voting common shares in all respects. The non-voting common shares are convertible into voting common shares on a share-for-share basis at the option of the holder if it transfers, sells or otherwise disposes of the converted voting common shares: (i) in a public offering of our voting common shares; (ii) to a third party that, prior to such sale, controls us; (iii) to a third party that, after such sale, is a beneficial owner of not more than 2% of our outstanding voting shares; (iv) in a transaction that complies with Rule 144 under the Securities Act of 1933, as amended; or (v) in a transaction approved in advance by regulatory bodies.

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

22 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

On July 27, 2007, the holder of the Company’s non-voting common shares exchanged its non-voting common shares for voting common shares. Each holder-of the non-voting common shares received one voting common share for each non-voting share held on the exchange date.

Trading Price and Volume

The following tables summarize the highest trading price, lowest trading price and volume for our common shares on the Toronto Stock Exchange (in Canadian dollars) and on the New York Stock Exchange (in US dollars) on a monthly basis from April 1, 2010 to May 31, 2011:

Toronto Stock Exchange |
Date |  | High ($s) |  |  | Low ($s) |  |  | Volume |
May 2011 |  |  | 11.06 |  |  |  | 6.89 |  |  |  | 752,857 |
April 2011 |  |  | 12.05 |  |  |  | 9.89 |  |  |  | 231,050 |
March 2011 |  |  | 13.80 |  |  |  | 11.13 |  |  |  | 341,453 |
February 2011 |  |  | 13.42 |  |  |  | 10.89 |  |  |  | 220,146 |
January 2011 |  |  | 12.50 |  |  |  | 10.91 |  |  |  | 259,183 |
December 2010 |  |  | 12.55 |  |  |  | 9.28 |  |  |  | 347,778 |
November 2010 |  |  | 9.99 |  |  |  | 8.68 |  |  |  | 219,458 |
October 2010 |  |  | 9.50 |  |  |  | 7.88 |  |  |  | 108,979 |
September 2010 |  |  | 9.25 |  |  |  | 8.30 |  |  |  | 168,109 |
August 2010 |  |  | 10.21 |  |  |  | 8.81 |  |  |  | 131,863 |
July 2010 |  |  | 10.43 |  |  |  | 8.65 |  |  |  | 273,997 |
June 2010 |  |  | 11.33 |  |  |  | 9.00 |  |  |  | 162,102 |
May 2010 |  |  | 11.35 |  |  |  | 8.80 |  |  |  | 233,382 |
April 2010 |  |  | 11.76 |  |  |  | 9.68 |  |  |  | 429,557 |

New York Stock Exchange |
Date |  | High [US $] |  |  | Low [US $] |  |  | Volume |
May 2011 |  |  | 11.64 |  |  |  | 7.15 |  |  |  | 12,381,080 |
April 2011 |  |  | 12.51 |  |  |  | 10.25 |  |  |  | 5,536,502 |
March 2011 |  |  | 14.23 |  |  |  | 11.24 |  |  |  | 4,885,663 |
February 2011 |  |  | 13.74 |  |  |  | 11.00 |  |  |  | 6,129,220 |
January 2011 |  |  | 12.67 |  |  |  | 10.97 |  |  |  | 5,408,772 |
December 2010 |  |  | 12.58 |  |  |  | 9.27 |  |  |  | 7,221,477 |
November 2010 |  |  | 9.86 |  |  |  | 8.52 |  |  |  | 4,543,771 |
October 2010 |  |  | 9.30 |  |  |  | 7.76 |  |  |  | 3,326,992 |
September 2010 |  |  | 8.96 |  |  |  | 8.05 |  |  |  | 3,020,602 |
August 2010 |  |  | 10.16 |  |  |  | 8.27 |  |  |  | 2,822,510 |
July 2010 |  |  | 10.17 |  |  |  | 8.20 |  |  |  | 3,668,265 |
June 2010 |  |  | 11.00 |  |  |  | 8.49 |  |  |  | 5,044,362 |
May 2010 |  |  | 11.44 |  |  |  | 8.15 |  |  |  | 4,777,909 |
April 2010 |  |  | 11.68 |  |  |  | 9.51 |  |  |  | 4,191,250 |

DIVIDENDS

We have not declared or paid any dividends on our common shares since our inception, and we do not anticipate declaring or paying any dividends on our common shares for the foreseeable future. We currently intend to retain any future earnings to finance future growth. Any future determination to pay dividends will be at the discretion of our board of directors and will depend on our financial condition, results of operations, capital requirements and other factors the board of directors considers relevant. In addition, our ability to declare and pay dividends is restricted by our governing statute, as well as the terms of our credit agreement and the indenture that governs our Series 1 Debentures (as defined herein).

2011 Annual Information Form |  | | NOA | |  |  | 23 |

##### Table of Contents

DESCRIPTION OF CERTAIN INDEBTEDNESS

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 9.125% Series 1 Debentures due 2017 (the “Series 1 Debentures”) for gross proceeds of $225.0 million and net proceeds after commissions and related expenses of $218.1 million. A more detailed discussion on the Series 1 Debentures can be found under “9.125% Series 1 Debentures” in the “Liquidity and Capital Resources” section of our MD&A.

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.

$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 agreement. At April 30, 2010, the second term facility was fully drawn at $50.0 million. The new term facility, along with the existing term facility, matures on April 30, 2013. A more detailed discussion on the April 30, 2010 fourth amended and restated credit agreement can be found under “Credit Facilities” in the next section.

CREDIT FACILITIES

On April 30, 2010, we entered into a fourth amended and restated credit agreement to extend the term of the credit facilities and increase the amount of the term loans. The new credit facilities provide for total borrowings of up to $163.4 million (previously $125.0 million) under which revolving loans, term loans and letters of credit may be issued. The Revolving Facility of $85.0 million (previously $90.0 million) was undrawn at closing. The new agreement includes two term facilities providing for borrowings of up to $78.4 million. At April 30, 2010, the Term A Facility and Term B Facility, as defined in the credit agreement (the Term Facilities), were both fully drawn at $28.4 million and $50.0 million, respectively. The new Term Facilities mature on April 30, 2013.

Advances under the Revolving Facility may be repaid from time to time at our option. The Term Facilities include scheduled repayments totalling $10.0 million per year with $2.5 million paid on the last day of each quarter commencing June 30, 2010. In addition, we must make annual payments within 120 days of the end of our fiscal year in the amount of 50% of Consolidated Excess Cash Flow (as defined in the credit agreement) to a maximum of $4.0 million. Based on the calculation of Consolidated Excess Cash Flow at March 31, 2011, we will not be required to make an additional principal payment in fiscal year 2012.

The facilities bear interest at variable rates based on the Canadian prime rate plus the applicable pricing margin (as defined within the credit agreement). Interest on US base rate loans is paid at a rate per annum equal to the US base rate plus the applicable pricing margin. Interest on Canadian prime and US base rate loans is payable monthly in arrears and computed on the basis of a 365-day or 366-day year, as the case may be. Interest on US dollar LIBOR loans is paid during each interest period at a rate per annum, calculated on a 360-day year, equal to the US dollar LIBOR rate with respect to such interest period plus the applicable pricing margin. Stamping Fees (as defined in the credit agreement) and interest on advances of Bankers’ Acceptances (as defined in the credit agreement) are paid in advance, at the time of issuance.

The applicable pricing margin (as defined within the credit agreement) is connected to our credit rating from Standard & Poor’s. If our credit rating were to be downgraded by this rating agency, we would receive a 1% increase in our applicable pricing margin (as defined within the credit agreement).

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

24 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

required to meet certain financial covenants defined in the credit agreement including: (i) Senior Leverage Ratio (Senior Leverage to Consolidated EBITDA) which must be less than 2.0 times, (ii) Consolidated Interest Coverage Ratio (Consolidated EBITDA to Consolidated Cash Interest Expense) which must be greater than 2.5 times, and (iii) Current Ratio (Current Assets to Current Liabilities) which must be greater than 1.25 times. Continued access to the facilities is not contingent on the maintenance of a specific credit rating. The definition of these covenants is unchanged from the previous third amended and restated credit agreement. As a result of the revenue writedown on the Canadian Natural long-term overburden removal contract, discussed in the Explanatory Notes — Significant Business Event section of our MD&A, we were not in compliance with certain existing financial covenants as at March 31, 2011 on our credit agreement. On May 20, 2011, we received an amendment to our credit agreement, from our lenders, to exclude the $42.5 million revenue writedown on our long-term overburden removal contract with Canadian Natural when determining Consolidated EBITDA (as defined in our credit agreement) related covenant compliance. This amendment ensures that this writedown will not result in a breach of Consolidated EBITDA (as defined in our credit agreement) related covenant compliance at March 31, 2011 or any future date. As a result of this amendment, we remain in compliance with the financial covenants on our credit agreement.

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

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

The credit facility may be prepaid in whole or in part without penalty, except for bankers’ acceptances, which are not pre-payable prior to their maturity. However, the credit facility requires prepayments under various circumstances, such as: (i) 100% of the net cash proceeds of certain asset dispositions, (ii) 100% of the net cash proceeds from our issuance of equity (unless the use of such securities’ proceeds is otherwise designated by the applicable offering document) and (iii) 100% of all casualty insurance and condemnation proceeds, subject to exceptions.

9.125% SERIES 1 DEBENTURES22

On April 7, 2010, we closed a private placement of Series 1 Debentures for gross proceeds of $225.0 million and net proceeds after commissions and related expenses of $218.1 million. Financing fees of $6.9 million were incurred in connection with the Series 1 Debentures and were recorded as deferred financing costs.

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

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

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

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

At any time prior to April 7, 2013 we may on one or more occasions redeem the Series 1 Debentures, in whole or in part, at a redemption price that 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.

22 | The following description of our Series 1 Debentures does not purport to be complete and reference should be made to the Indenture and the Supplemental Indenture in respect of the Series 1 Debentures referred to under “Material Contracts” and available at www.sedar.com and on EDGAR at www.sec.gov.

2011 Annual Information Form |  | | NOA | |  |  | 25 |

##### Table of Contents

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

The Series 1 Debentures were rated B+ by Standard & Poor’s and B3 by Moody’s as at March 31, 2011 (see “Debt Ratings”).

LETTERS OF CREDIT

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

DEBT RATINGS

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

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

Our credit ratings from these two agencies are as follows:

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

# | Loss Given Default

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

A credit rating is a current opinion of the credit worthiness of an obligor with respect to a specific financial obligation, a specific class of financial obligations, or a specific financial program (including ratings on medium-term note programs and commercial paper programs). It takes into consideration the credit worthiness of guarantors, insurers, or other forms of credit enhancement on the obligation and takes into account the currency in which the obligation is denominated. The opinion evaluates the obligor’s capacity and willingness to meet its financial commitments as they come due, and may assess terms, such as collateral security and subordination, which could affect ultimate payment in the event of default. A credit rating is not a statement of fact or recommendation to purchase, sell, or hold a financial obligation or make any investment decisions nor is it a comment regarding an issuer’s market price or suitability for a particular investor. A credit rating speaks only as of the date it is issued and can be revised upward or downward or withdrawn at any time by the issuing rating agency if it decides circumstances warrant a revision. Definitions of the categories of each rating and the factors considered during the evaluation of each rating have been obtained from each respective rating organization’s website as outlined below.23

Standard and Poor’s

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

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

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

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

26 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

Moody’s

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

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

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

2011 Annual Information Form |  | | NOA | |  |  | 27 |

##### Table of Contents

DIRECTORS AND OFFICERS

The following table sets forth information about our directors and executive officers. Ages reflected are as at May 31, 2011. Each director is elected for a one-year term or until such person’s successor is duly elected or appointed, unless his office is earlier vacated. Unless otherwise indicated below, the business address of each of our directors and executive officers is Suite 2400, 500 4 th Avenue SW, Calgary, Alberta, T2P 2V6. As at May 31, 2011, the directors and executive officers of the Company, as a group, beneficially owned, directly or indirectly, or exercised control or direction over 913,755 common shares of the Company (representing approximately 2.5% of all issued and outstanding common shares).

Name and Municipality of Residence |  | Age |  |  | Position
Rodney J. Ruston Calgary, Alberta, Canada |  |  | 60 |  |  | Director, President and Chief Executive Officer
David Blackley Calgary, Alberta, Canada |  |  | 50 |  |  | Chief Financial Officer
Joseph C. Lambert Calgary, Alberta, Canada |  |  | 46 |  |  | Vice President, Oil Sands Operations
Bernard T. Robert Calgary, Alberta, Canada |  |  | 44 |  |  | Vice President, Corporate Affairs & Business Strategy
Christopher R. Yellowega Airdrie, Alberta, Canada |  |  | 40 |  |  | Vice President, Business Services & Construction
Ronald A. McIntosh Calgary, Alberta, Canada |  |  | 69 |  |  | Chairman of the Board
George R. Brokaw New York, New York, United States |  |  | 43 |  |  | Director
John A. Brussa Calgary, Alberta, Canada |  |  | 54 |  |  | Director
Peter R. Dodd Sydney, Australia |  |  | 61 |  |  | Director
John D. Hawkins Houston, Texas, United States |  |  | 47 |  |  | Director
William C. Oehmig Houston, Texas, United States |  |  | 61 |  |  | Director
Allen R. Sello West Vancouver, British Columbia, Canada |  |  | 71 |  |  | Director
Peter W. Tomsett West Vancouver, British Columbia, Canada |  |  | 53 |  |  | Director
K. Rick Turner Houston, Texas, United States |  |  | 53 |  |  | Director

Rodney J. Ruston became President, Chief Executive Officer of NAEPI on May 9, 2005 and a Director of NAEPI on June 15, 2005. He took the Company public with a listing on both the NYSE and TSX on November 22, 2006. In 2007, Mr. Ruston joined Northern Alberta Institute of Technology’s President’s Advisory Committee. Previously, Mr. Ruston was Managing Director and Chief Executive Officer of Ticor Limited, a publicly listed Australian natural resources company with operations in Australia, South Africa, and Madagascar. Mr. Ruston has spent his entire career in the natural resources industry, holding management positions with Pasminco Limited, Savage Resources Limited, Wambo Mining Corporation, Oakbridge Limited and Kembla Coal & Coke Pty. Limited. He was Chairman of the Australian Minerals Tertiary Education Council from July 2003 until May 2005 and received his Masters of Business Administration from the University of Wollongong and Bachelor of Engineering (Mining) from the University of New South Wales in Australia.

David Blackley became Chief Financial Officer of NAEPI on June 11, 2009. Mr. Blackley joined NAEPI as Vice-President, Finance on January 14, 2008, bringing extensive experience leading accounting and financial reporting teams and overseeing the design and implementation of internal financial controls and processes. Previously Mr. Blackley served as Vice-President, Finance of Lafarge North America’s Aggregates and Concrete division. A Chartered Accountant, Mr. Blackley holds a Bachelor of Commerce from Rhodes University in South Africa.

Joseph C. Lambert joined NACG in 2008 as General Manager of Mining after an extensive career in the mining industry and was promoted to Vice President, Oil Sands Operations in September of 2010. Prior to that, Joe’s career began in the gold industry where he spent 17 years in roles of increasing responsibility in engineering and operations both open pit and

28 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

underground. Joe’s more recent contracting and oil sands experience included positions as General Manager with Ledcor and Mine Development Manager, Oil Sands with Shell. Joe graduated from the South Dakota School of Mines and Technology with a B.S. in Mining Engineering in 1986.

Bernard T. Robert joined us in March 1998 as Controller and held various positions within the Finance department including Director, Project Accounting and Treasurer until his transfer to the position of Director, Business Development in 2006. Mr. Robert held this position until he was appointed Vice-President, Business Development and Estimating on September 1, 2007. On January 23, 2009, Mr. Robert was appointed Vice-President, Corporate Affairs and Business Strategy. Prior to joining us, Mr. Robert worked as the Manager, Budgets & Forecasts for Telus Communications in Edmonton. Mr. Robert began his career at Enbridge Pipelines Inc. (formerly Interprovincial Pipelines Inc.) where he worked in various roles within the Finance and Regulatory areas. Mr. Robert is a Certified General Accountant having graduated in 1995.

Christopher R. Yellowega became Vice-President, Major Mining Projects on April 1, 2008 bringing with him an extensive oil sands development and operations experience. He was appointed Vice-President, Operations on January 23, 2009. Prior to joining us, Mr. Yellowega served as Vice President, Upstream Operations with Synenco Energy Inc., where he played a leadership role in planning and designing a major oil sands mining development. Before that, Mr. Yellowega served at the Athabasca Oilsands Project Expansion (Albian Sands) as Superintendent responsible for leading the expansion project team for upstream operations. A Mining Engineer, Mr. Yellowega is currently a member of the Board of Directors for the Alberta Chamber of Resources and is recognized as a Registered Professional Engineer.

Ronald A. McIntosh became Chairman of our Board of Directors on May 20, 2004. From January 2004 until August of 2006, Mr. McIntosh was Chairman of NAV Energy Trust, a Calgary based oil and natural gas investment fund. Between October 2002 and January 2004, he was President and Chief Executive Officer of Navigo Energy Inc. and was instrumental in the conversion of Navigo into NAV Energy Trust. He was Senior Vice President and Chief Operating Officer of Gulf Canada Resources Limited from December 2001 to July 2002 and Vice President, Exploration and International of Petro-Canada from April 1996 through November 2001. Mr. McIntosh’s significant experience in the energy industry includes the former position of Chief Operating Officer of Amerada Hess Canada. Mr. McIntosh is on the Board of Directors of Advantage Oil & Gas Ltd. and Fortress Energy Inc.

George R. Brokaw became one of our Directors on June 28, 2006. Mr. Brokaw joined Perry Capital, L.L.C., an affiliate of Perry Corp., in August 2005. Mr. Brokaw is a Managing Partner of Perry Corp. From January 2003 to May 2005, Mr. Brokaw was Managing Director (Mergers & Acquisitions) of Lazard Frères & Co. LLC, which he joined in 1996. Between 1994 and 1996, Mr. Brokaw was an investment banking associate for Dillon Read & Co. Mr. Brokaw received a Bachelor of Arts degree from Yale University and a Juris Doctorate and Masters of Business Administration from the University of Virginia. He is admitted to practice law in the State of New York. Investment entities controlled by Perry Corp. are holders of our common shares. (See our most recent information circular that involved the elections of directors for details.)

John A. Brussa became one of our Directors on November 26, 2003. Mr. Brussa is a senior partner and head of the Tax Department at the law firm of Burnet, Duckworth & Palmer LLP, a leading natural resource and energy law firm located in Calgary. He has been a partner since 1987 and has worked at the firm since 1981. Mr. Brussa is Chairman of Penn West Petroleum Ltd. and Crew Energy Inc. Mr. Brussa also serves as a director of a number of natural resource and energy companies. He is a member and former Governor of the Executive Committee of the Canadian Tax Foundation. Mr. Brussa attended the University of Windsor and received his Bachelor of Arts in History and Economics in 1978 and his Bachelor of Law in 1981.

Peter R. Dodd retired as Chief Financial Officer of NAEPI on June 10, 2009 and became a non-independent director of the Corporation. Mr. Dodd has over 25 years experience in strategic business planning, corporate finance and investment banking. Prior to joining NAEPI, Mr. Dodd served as Director of Strategy and Development for CSR Ltd., an Australian based conglomerate with sugar, building products, aluminium and property divisions. Previously, Mr. Dodd was Managing Director and Global Head of Corporate Finance for ABN AMRO in London, England, managing corporate finance teams in 23 countries. Mr. Dodd has a PhD in Accounting and Finance from the William E. Simon School of Management at the University of Rochester and is currently Deputy Vice-Chancellor & Chief Operating Officer of Macquarie University in Sydney, Australia.

John D. Hawkins became one of our Directors on October 17, 2003. Mr. Hawkins joined The Sterling Group, L.P., a private equity investment firm, in 1992 and has been a Partner since 1999. An affiliate of The Sterling Group is a holder of our common shares. (See our most recent information circular that involved the elections of directors for details.) Mr. Hawkins currently serves as chairman of the board of Saxco Holdings International and serves on the board of directors of Velcon Filters and B&G Crane. Before joining Sterling he was on the professional staff of Arthur Andersen & Co. from 1986 to 1990. He received a Bachelor of Science in Business Administration in Accounting from the University of Tennessee and his Masters of Business Administration from the Owen Graduate School of Management at Vanderbilt University.

William C. Oehmig served as Chairman of our Board of Directors from November 26, 2003 and until passing off this position and assuming the role of Director and chair of the Executive Committee on May 20, 2004. He now serves as chairman of the Risk Committee and on the Compensation Committee. Mr. Oehmig is a Partner with The Sterling Group, L.P., a private

2011 Annual Information Form |  | | NOA | |  |  | 29 |

##### Table of Contents

equity investment firm. An investment entity affiliated with The Sterling Group is a holder of our common shares. (See our most recent information circular that involved the elections of directors for details.) Prior to joining Sterling in 1984, Mr. Oehmig worked in banking, mergers and acquisitions, and represented foreign investors in purchasing and managing U.S. companies in the oilfield service, manufacturing, distribution, heavy equipment and real estate sectors. He began his career in Houston in 1974 at Texas Commerce Bank. Mr. Oehmig currently serves on the board of Universal Fibers Inc. In the past he has served as Chairman of Royster-Clark, Purina Mills, Exopack and Sterling Diagnostic Imaging and has served on the board of several portfolio companies since joining Sterling. Mr. Oehmig serves or has served on numerous other corporate non-profit boards. Mr. Oehmig received his Bachelor of Business Administration (B.B.A.) in Economics from Transylvania University and his Masters of Business Administration (M.B.A.) from the Owen Graduate School of Management at Vanderbilt University.

Allen R. Sello became one of our Directors on January 26, 2006. His career began at Ford Motor Company of Canada in 1964, where he held finance and marketing management positions, including Treasurer. In 1979, Mr. Sello joined Gulf Canada Limited, at which he held various senior financial positions, including Vice-President and Controller. He was appointed Vice-President, Finance of its successor company Gulf Canada Resources Limited in 1987 and Chief Financial Officer in 1988. Mr. Sello then joined International Forest Products Ltd. in 1996 as Chief Financial Officer. From 1999 until his retirement in 2004 he held the position of Senior Vice-President and Chief Financial Officer for UMA Group Limited. Mr. Sello is currently a director of Sterling Shoes Inc., former director of software development companies Infowave Software Inc. and Braintech Inc., and former Chair of the Vancouver Board of Trade Government Budget and Finance Committee. Mr. Sello received his Bachelor of Commerce from the University of Manitoba and his Masters of Business Administration from the University of Toronto

Peter W. Tomsett became one of our Directors on September 20, 2006. From September 2004 to January 2006, Mr. Tomsett was President & Chief Executive Officer of Placer Dome Inc. based in Vancouver. He joined the Placer Dome Group in 1986 as a Mining Engineer with the Project Development group in Sydney, Australia. After various project and operating positions, he assumed the role of Executive Vice-President, Asia-Pacific for Placer Dome Inc. in 2001. In 2004, Mr. Tomsett also took on responsibility for Placer Dome Africa which included mines in South Africa and Tanzania. Mr. Tomsett has been a Director of the Minerals Council of Australia, the World Gold Council and the International Council for Mining & Metals. Mr. Tomsett graduated with a Bachelor of Engineering (Honours) in Mining Engineering from the University of New South Wales and also attained a Master’s of Science (Distinction) in Mineral Production Management from Imperial College, London. Mr. Tomsett is also Chairman of Silver Standard Resources Inc. and Equinox Minerals Ltd., and a director of Talisman Energy Inc.

K. Rick Turner became one of our Directors on November 26, 2003. Mr. Turner has been employed by Stephens’ family entities since 1983. Mr. Turner is currently Senior Managing Director of The Stephens Group, LLC. He first became a private equity principal in 1990 after serving as the Assistant to the Chairman, Jackson T. Stephens. His areas of focus have been oil and gas exploration, natural gas gathering, processing industries and power technology. Mr. Turner currently serves as a director of Atlantic Oil Corporation; JV Industrials, LLC; Seminole Energy Services, LLC; the General Partner of Energy Transfer Partners, LP (“ETP”); and the General Partner of Energy Transfer Equity, LP (“ETE”). Prior to joining Stephens, Mr. Turner was employed by Peat, Marwick, Mitchell and Company. Mr. Turner earned his Bachelor of Science in Business Administration (B.S.B.A.) from the University of Arkansas and is a non-practicing Certified Public Accountant.

Corporate Cease Trade Orders, Bankruptcies, Penalties or Sanctions

Mr. Ron McIntosh is a director of Fortress Energy Inc. (“Fortress”). On March 3, 2011 the TSX suspended trading in the securities of Fortress due to Fortress having been granted a stay under the Companies’ Creditors Arrangement Act (Canada). Fortress announced that it applied for the stay in order to enable it to challenge a reassessment by the Canada Revenue Agency in the amount of approximately $18 million which Fortress believes is not sustainable and which it intends to vigorously dispute. Fortress announced that, without the stay, it would have been compelled to immediately remit $9 million to the CRA and that it does not have sufficient funds to do so, although it does have $18 million of assets in excess of its liabilities with sufficient liquid assets to pay all other liabilities and trade payables. Further, on February 23, 2011, Fortress announced that that it did not meet the listing requirements of the TSX by virtue of the sale of substantially all of its oil and gas assets to Terra Energy Corp. on September 1, 2010. Fortress was notified by the TSX that its formal listing committee determined on February 25, 2011, that Fortress would be delisted from the TSX on March 30, 2011, which it was.

John A. Brussa was a director of Imperial Metals Limited, a corporation engaged in oil and natural gas and mining operations, during the year prior to that corporation implementing a plan of arrangement under the Company Act (British Columbia) and under the Companies’ Creditors’ Arrangement Act (Canada) which resulted in the separation of its two businesses. The reorganization resulted in the creation of two public corporations, Imperial Metals Corporation, engaged in the mining business, and IEI Energy Inc. (subsequently renamed Rider Resources Ltd.), engaged in the oil and gas business. The plan of arrangement was completed in April 2002.

THE BOARD AND BOARD COMMITTEES

Our board supervises the management of our business as provided by Canadian law. We comply with the listing requirements of the New York Stock Exchange applicable to domestic listed companies, which require that our board of

30 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

directors be composed of a majority of independent directors. Accordingly, a majority of our board members are independent.

Our board has established the following committees:

AUDIT COMMITTEE

The Audit Committee recommends independent public accountants to the board of directors, reviews the quarterly and annual financial statements and related MD&A, press releases, auditor reports and the fees paid to our auditors. The Audit Committee approves quarterly financial statements and recommends annual financial statements for approval to the board of directors. In accordance with Rule 10A-3 under the Securities Exchange Act of 1934, as amended, the listing requirements of the New York Stock Exchange and the requirements of the Canadian Securities regulatory authorities, our board of directors has affirmatively determined that our Audit Committee is composed solely of independent directors. The board of directors has determined that Mr. Allen R. Sello is the audit committee financial expert, as defined by Item 407(d) (5) of the SEC’s Regulation S-K. Our board of directors has adopted a written charter for the Audit Committee that is attached as Exhibit A to this AIF. The Audit Committee is currently composed of Messrs. Brokaw, Hawkins, McIntosh, Sello and Turner, with Mr. Sello serving as Chairman. Based on their experience (see “Directors and Officers” above), each of the members of the Audit Committee is financially literate. The members of the audit committee have significant exposure to the complexities of financial reporting associated with us and are able to provide due oversight and the necessary governance over, our financial reporting.

Our auditors are KPMG LLP. Our Audit Committee pre-approved the engagement of KPMG to perform the audit of our financial statements for the fiscal year ended March 31, 2011.

The fees we have paid to KPMG for services rendered by them include:

• |  | Audit Fees – KPMG billed us $1,130,800, $1,862,800, and $2,374,000 for audit fees during the years ended March 31, 2011, 2010 and 2009, respectively. Audit fees were incurred for the audit of our annual financial statements, the audit of compliance and internal controls over financial reporting, related audit work in connection with registration statements and other filings with various regulatory authorities, and quarterly interim reviews of the consolidated financial statements.

• |  | Audit Related Fees – KPMG billed us $nil, $394,645 and $nil during the years ended March 31, 2011, 2010 and 2009, respectively, for professional services related to the conversion of US GAAP and for planning and scoping work and advice relating to internal controls over financial reporting.

• |  | Tax Fees – KPMG billed us $nil, $7,500 and $62,000 for the years ended March 31, 2011, 2010 and 2009, respectively, for income tax advisory and compliance services.

• |  | All Other Fees – KPMG billed us $nil, $nil and $64,000 for the years ended March 31, 2011, 2010 and 2009, respectively, for fees related to analysis of the conversion to US GAAP and International Financial Reporting Standards (IFRS), respectively. KPMG did not perform any other services for us in the years ended March 31, 2011 and 2010, respectively.

COMPENSATION COMMITTEE

The Compensation Committee is responsible for supervising executive compensation policies for us and our Subsidiaries, administering the employee incentive plans, reviewing officers’ salaries, approving significant changes in executive employee benefits and recommending to the board such other forms of remuneration as it deems appropriate. In accordance with the listing requirements of the New York Stock Exchange applicable to domestic listed companies and applicable Canadian securities laws, our board of directors has affirmatively determined that our Compensation Committee is composed solely of independent directors. Our board of directors has adopted a written charter for the Compensation Committee that is available on our website at www.nacg.ca. The Compensation Committee is currently comprised of Messrs. Brussa, Oehmig, Sello and Tomsett, with Mr. Tomsett serving as Chairman. None of the members of the Compensation Committee is or has been one of our officers or employees, and none of our executive officers served during fiscal 2010 on a board of directors of another entity which has employed any of the members of the Compensation Committee.

GOVERNANCE COMMITTEE

The Governance Committee is responsible for recommending to the board of directors proposed nominees for election to the board of directors by the shareholders at annual meetings and for conducting an annual review as to the re-nominations of incumbents and proposed nominees for election by the board of directors to fill vacancies that occur between shareholder meetings. The Governance Committee also makes recommendations to the board of directors regarding corporate governance matters and practices. In accordance with the listing requirements of the New York Stock Exchange applicable to domestic listed companies and applicable Canadian securities laws, our board of directors has affirmatively determined that our Governance Committee is composed solely of independent directors. Our board of directors has adopted a written charter for the Governance Committee that is available on our website at www.nacg.ca. The Governance Committee is currently comprised of Messrs. Brussa, Hawkins, McIntosh and Turner, with Mr. Hawkins serving as Chairman.

HEALTH, SAFETY, ENVIRONMENT AND BUSINESS RISK COMMITTEE

The Health, Safety, Environment and Business Risk Committee (the “HSE&B Risk Committee”) is responsible for monitoring, evaluating, advising and making recommendations on matters relating to the health and safety of our employees, the

2011 Annual Information Form |  | | NOA | |  |  | 31 |

##### Table of Contents

management of our health, safety and environmental risks, due diligence related to health, safety and environment matters, as well as the integration of health, safety, environment, economics and social responsibility into our business practices. The HSE&B Risk Committee is also responsible for overseeing all of our non-financial risks, approving our risk management policies, monitoring risk management performance, reviewing the risks and related risk mitigation plans within our strategic plan, reviewing and approving tenders and contracts greater than $50 million in expected revenue and any other matter where board guidelines require approval at a level above President & CEO, and reviewing and monitoring all insurance policies including directors and officers insurance coverage. Our board of directors has affirmatively determined that our HSE&B Risk Committee is composed solely of independent directors. Our board of directors has adopted a written charter for the HSE&B Risk Committee that is available on our website at www.nacg.ca. The HSE&B Risk Committee is currently comprised of Messrs. Brokaw, Dodd, McIntosh, Oehmig and Tomsett, with Mr. Oehmig serving as Chairman.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

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;

• |  | permit them to attend, to the extent that a director is not related to the significant shareholder, 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.

Registration Rights Agreement

We are party to a registration rights agreement with certain shareholders, including affiliates of each of the significant shareholders, Paribas North America, Inc. and Mr. William Oehmig, one of our directors. The shareholders party to the agreement and their permitted transferees are entitled, subject to certain limitations, to include their common shares in a registration of common shares we initiate under the Securities Act of 1933, as amended. In addition, after the 120th day following our IPO, any one or more shareholders party to the agreement has the right to require us to effect the registration of all or any part of such shareholders’ common shares under the Securities Act, referred to as a “demand registration,” so long as the amount of common shares to be registered has an aggregate fair market value of at least US$5.0 million and, at such time, the SEC has ordered or declared effective fewer than four demand registrations initiated by us pursuant to the registration rights agreement. If the aggregate number of common shares that the shareholders party to the agreement request us to include in any registration, together, in the case of a registration we initiate, with the common shares to be included in such registration, exceeds the number which, in the opinion of the managing underwriter, can be sold in such offering without materially affecting the offering price of such shares, the number of shares of each shareholder to be included in such registration will be reduced pro rata based on the aggregate number of shares for which registration was requested. The shareholders party to the agreement have the right to require, after four demand registrations, one registration in which their common shares will not be subject to pro rata reduction with others entitled to registration rights.

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

• |  | up to 120 days if:

| • |  | we have decided to file a registration statement for an underwritten public offering of our common shares, the net proceeds of which are expected to be at least US$20.0 million; or

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

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

32 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

Our right to delay the filing of a registration statement if we possess information that we deem advisable not to disclose does not obviate any disclosure obligations which we may have under the Exchange Act or other applicable laws; it merely permits us to avoid filing a registration statement if our management believes that such a filing would require the disclosure of information which otherwise is not required to be disclosed and the disclosure of which our management believes is premature or otherwise inadvisable.

The registration rights agreement contains customary provisions whereby we and the shareholders party to the agreement covenant to indemnify and contribute to each other with regard to losses caused by the misstatement of any information or the omission of any information required to be provided in a registration statement filed under the Securities Act. The registration rights agreement requires us to pay the expenses associated with any registration other than sales discounts, commissions, transfer taxes and amounts to be borne by underwriters or as otherwise required by law.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

From time to time, we are a party to litigation and legal proceedings that we consider to be a part of the ordinary course of business. While no assurance can be given, we believe that, taking into account reserves and insurance coverage, none of the litigation or legal proceedings in which we are currently involved or know to be contemplated could reasonably be expected to have a material adverse effect on our business, financial condition or results of operations. We may, however, become involved in material legal proceedings in the future that could have such a material adverse effect.¿

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar of the Company is CIBC Mellon Trust Co. and the address of CIBC Mellon Trust Co. is 600 The Dome Tower, 333 – 7 Avenue SW, Calgary, Alberta, T2P 2Z1.

MATERIAL CONTRACTS

We are party to the following material contracts, which are contracts other than those entered into in the ordinary course of our business:

• |  | Indemnity Agreement between NACG Holdings Inc., NACG Preferred Corp., North American Energy Partners Inc., North American Construction Group Inc. and their respective officers and directors Please refer to the most recently filed management information circular for details;

• |  | Indenture, dated as of April 7, 2010, among North American Energy Partners Inc., the guarantors named therein and CIBC Mellon Trust Company, as Trustee, and Supplemental Indenture dated as of April 7, 2010, among North American Energy Partners Inc., the guarantors named therein and CIBC Mellon Trust Company, as Trustee. Please refer to “Description of Certain Indebtedness – 9.125% Series 1 Debentures” for details;

• |  | Registration Rights Agreement, dated as of November 26, 2003, among NACG Holdings Inc. and the shareholders party thereto. Please refer to “Interest of Management and Others in Material Transactions – Registration Rights Agreement” for details;

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

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

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

• |  | Overburden Removal and Mining Services Contract, dated November 17, 2004, between Canadian Natural Resources Ltd. and Noramac Ventures Inc. Please see “Projects – Active Projects – Canadian Natural: Overburden Removal Project”

• |  | Lease dated December 1, 1997, between NAR Group Holdings Ltd., as landlord, and North American Construction Group Inc., as tenant, as renewed by a Renewal Lease Agreement dated December 1, 2002, between Norama Inc. (successor to NAR Group Holdings Ltd.), as landlord, and North American Construction Group Inc., as tenant, as amended by a Lease Amendment and Consent Agreement dated November 26, 2003, between Acheson Properties Ltd. (successor to Norama Inc.), as landlord, and North American Construction Group Inc., as tenant, and as further amended by an Amending Agreement to Lease Amendment and Consent Agreement dated September 29, 2006, between Acheson Properties Ltd., as landlord, and North American Construction Group Inc., as tenant. This lease is for our offices in Acheson, Alberta. Please refer to “Resources and Key Trends – Facilities” for details; and

• |  | Fourth Amended and Restated Credit Agreement dated as of April 30, 2010, among North American Energy Partners Inc., Canadian Imperial Bank of Commerce, HSBC Bank Canada, and the lenders party thereto from time to time. Please refer to “Description of Certain Indebtedness – Credit Facilities” for details.

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

2011 Annual Information Form |  | | NOA | |  |  | 33 |

##### Table of Contents

RISKS AND UNCERTAINTIES

RISKS RELATED TO OUR BUSINESS

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

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

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

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

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

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

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

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

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

Approximately 63%, 39% and 29% of our revenue for the fiscal years ended March 31, 2011, 2010 and 2009, respectively, was derived from lump-sum and unit-price contracts. Lump-sum and unit-price contracts require us to guarantee the price of the services we provide and thereby expose us to losses if our estimates of project costs are lower than the actual project costs we incur. Our profitability under these contracts is dependent upon our ability to accurately predict the costs associated with our services. The costs we actually incur may be affected by a variety of factors including those which are beyond our control. Factors that may contribute to actual costs exceeding estimated costs and which therefore affect profitability include, without limitation:

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

| • |  | scope modifications during the execution of the project;

| • |  | the availability and cost of skilled workers;

| • |  | the availability and proximity of materials;

| • |  | unfavourable weather conditions hindering productivity;

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

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

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

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

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

Our ability to maintain planned project margins on longer-term contracts with contracted price escalators is dependent on the contracted price escalators accurately reflecting increases in our costs. If the contracted price escalators do not reflect

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

34 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

actual increases in our costs we will experience reduced project margins over the remaining life of these longer-term contracts.

In strong economic times, the cost of labour, equipment, materials and sub-contractors is driven by the market demand for these project inputs. The level of increased demand for project inputs may not have been foreseen at the inception of the longer-term contracts with fixed or indexed price escalators resulting in reduced margins over the remaining life of the longer-term contracts. Certain of these price escalators could be considered derivative financial instruments (see “Significant Accounting Policies – Derivative Financial Instruments” in our audited consolidated financial statements for the year ended March 31, 2011).

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

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

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

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

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

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

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

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

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

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

• |  | We may not be able to access sufficient funds to finance our capital growth.

We have a substantial amount of debt outstanding and significant debt service requirements. As of March 31, 2011, we had outstanding $463.6 million of debt 24, including $8.7 million of capital leases. Our substantial indebtedness restricts our flexibility, consequently it:

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

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

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

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

24 | Debt includes all liabilities with the exception of deferred income taxes

2011 Annual Information Form |  | | NOA | |  |  | 35 |

##### Table of Contents

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

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

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

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

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

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

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

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

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

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

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

| • |  | lack of sufficient governmental infrastructure funding to support growth;

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

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

| • |  | cost overruns on announced projects.

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

Due to the amount of capital investment required to build an oil sands project, or construct a significant capital expansion to an existing project, investment decisions by oil sands operators are based upon long-term views of the economic viability of the project. Economic viability is dependent upon the anticipated revenues the capital project will produce, the anticipated amount of capital investment required and the anticipated fixed cost of operating the project. The most important consideration is the customer’s view of the long-term price of oil which is influenced by many factors, including the condition of developed and developing economies and the resulting demand for oil and gas, the level of supply of oil and gas, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political conditions in oil producing nations, including those in the Middle East, war or the threat of war in oil producing regions and the availability of fuel from alternate sources. If our customers believe the long-term outlook for the price of oil is not favourable, or believe oil sands projects are not viable for any other reason, they may delay, reduce or cancel plans to construct new oil sands capital projects or capital expansions to existing projects. In the second half of 2009, the market price of oil decreased significantly which led to a slowdown of the world economy and a lower international demand for oil. As a result of those developments, many of our customers decided to temporarily scale back their capital development plans on oil sands projects until there was a clearer picture on the timing of the recovery of the world economy. Recent events related to the increases in the market price of oil and assertions by many of our customers about renewed confidence in the long-term growth in the oil sands has led to new announcements regarding oil sands capital investment. If there had not been signs of recovery of the world economy there would have been continuing delays, reductions or

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

36 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

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

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

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

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

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

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

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

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

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

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

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

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

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

2011 Annual Information Form |  | | NOA | |  |  | 37 |

##### Table of Contents

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

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

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

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

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

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

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

• |  | Significant labour disputes could adversely affect our business.

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

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

We are at times required to post a bid or performance bond issued by a financial institution, known as a surety, to secure our performance commitments. The surety industry experiences periods of unsettled and volatile markets, usually in the aftermath of substantial loss exposures or corporate bankruptcies with significant surety exposure. Historically, these types of events have caused reinsurers and sureties to re-evaluate their committed levels of underwriting and required returns. If for any reason, whether because of our financial condition, our level of secured debt or general conditions in the surety bond market, our bonding capacity becomes insufficient to satisfy our future bonding requirements, our business and results of operations could be adversely affected.

Some of our customers require letters of credit to secure our performance commitments. Our April 30, 2010 fourth amended and restated credit agreement provides for the issuance of letters of credit up to $85.0 million, and at March 31,

38 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

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

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

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

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

Most of our revenue comes from the provision of services to a small number of major oil sands mining companies. Revenue from our five largest customers represented approximately 77%, 89% and 92% of our total revenue for the fiscal years ended March 31, 2011, 2010 and 2009, respectively, and those customers are expected to continue to account for a significant percentage of our revenues in the future. In addition, the majority of our Pipeline revenues in the previous fiscal years resulted from work performed for one customer. If we lose or experience a significant reduction of business or profit from one or more of our significant customers, we may not be able to replace the lost work or income with work or income from other customers. Our long-term contracts typically allow our customers to unilaterally reduce or eliminate the work which we are to perform under the contract. Our contracts also generally allow the customer to terminate the contract without cause and, in many cases, with minimal or no notice to us. Additionally, certain of these contracts provide for limited compensation following such suspension or termination of operations and we can provide no assurance that we could replace the lost work with work from other customers. The loss of or significant reduction in business with one or more of our major customers, whether as a result of the completion, early termination or suspension of a contract, or failure or inability to pay amounts owed to us, could have a material adverse effect on our business and results of operations.

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

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

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

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

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

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

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

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

| • |  | issue equity securities of subsidiaries;

| • |  | make certain investments or acquisitions;

| • |  | create liens on our assets;

| • |  | enter into transactions with affiliates;

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

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

2011 Annual Information Form |  | | NOA | |  |  | 39 |

##### Table of Contents

Our credit agreement also requires us, and our future credit agreements may require us, to maintain specified financial ratios and satisfy specified financial tests. Our ability to meet these financial ratios and tests can be affected by events beyond our control, and we may be unable to meet those tests.

As a result of these covenants, our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be significantly restricted, and we may be prevented from engaging in transactions that might otherwise be considered beneficial to us. The breach of any of these covenants could result in an event of default under our revolving credit facility or any future credit facilities or under the indenture governing our notes. Under our credit agreement, our failure to pay certain amounts when due to other creditors, including to certain equipment lessors would also result in an event of default. Upon the occurrence of an event of default under our revolving credit facility or future credit facilities, the lenders could elect to stop lending to us or declare all amounts outstanding under such credit facilities to be immediately due and payable. Similarly, upon the occurrence of an event of default under the trust indenture governing our Series 1 Debentures the outstanding principal and accrued interest on the notes may become immediately due and payable. If amounts outstanding under such credit agreements and the trust indenture were to be accelerated, or if we were not able to borrow under our revolving credit facility, we could become insolvent or be forced into insolvency proceedings and you could lose your investment in us.

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

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

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

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

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

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

RISKS RELATED TO OUR COMMON SHARES

• |  | Fluctuations in the value of the Canadian and US dollars can affect the value of our common shares and future dividends, if any.

Our operations and our principal executive offices are in Canada. Accordingly, we report our results in Canadian dollars. The value of a US shareholder’s investment in us will fluctuate as the US dollar rises and falls against the Canadian dollar. Also, if we pay dividends in the future, we will pay those dividends in Canadian dollars. Accordingly, if the US dollar rises in value relative to the Canadian dollar, the US dollar value of the dividend payments received by a US common shareholder would be less than they would have been if exchange rates were stable.

• |  | If our share price fluctuates, an investor could lose a significant part of their investment.

There has been significant volatility in the market price and trading volume of equity securities, which is unrelated to the financial performance of the companies issuing the securities. The market price of our common shares is likely to be similarly volatile, and an investor may not be able to resell our shares at or above the price at which the investor acquired the shares due to fluctuations in the market price of our common shares, including changes in price caused by factors unrelated to our operating performance or prospects.

Specific factors that may have a significant effect on the market price for our common shares include:

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

40 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

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

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

| • |  | reaction to our public announcements;

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

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

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

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

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

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

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

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

• |  | We may issue additional common shares, which would dilute the percentage ownership interest of our existing shareholders.

We may issue our common shares or convertible securities from time to time as consideration for future acquisitions and investments. In the event any such acquisition or investment is significant, the number of common shares or convertible securities that we may issue could be significant. We may also grant registration rights covering those shares or convertible securities in connection with any such acquisitions and investments. Any additional capital raised through the sale of our common shares or securities convertible into our common shares will dilute our common shareholders’ percentage ownership in us.

• |  | We currently do not intend to-pay dividends on our common shares, and our ability to pay dividends is limited by the indenture that governs our notes, our subsidiaries’ ability to distribute to us and Canadian law.

We have never paid cash dividends on our common shares. It is our present intention to retain all future earnings for use in our business, and we do not expect to pay cash dividends on the common shares in the foreseeable future. Any future determination to pay cash dividends will be at the discretion of our board of directors and will depend on our results of operations, financial condition, current and anticipated cash needs, contractual restrictions, restrictions imposed by applicable law and other factors that our board of directors considers relevant. Our ability to declare dividends is restricted by the terms of the indenture that governs our notes. See “Description of Certain Indebtedness.”¿

Substantially all of the assets shown on our consolidated balance sheet are held by our subsidiaries. Accordingly, our earnings and cash flow and our ability to pay dividends are largely dependent upon the earnings and cash flows of our subsidiaries and the distribution or other payment of such earnings to us in the form of dividends.

Our ability to pay dividends is also subject to the satisfaction of a statutory solvency test under Canadian law, which requires that there be no reasonable grounds for believing that (i) we are, or would after the payment be, unable to pay our liabilities as they become due or (ii) the realizable value of our assets would, after payment of the dividend, be less than the aggregate of our liabilities and stated capital of all classes.

• |  | Our principal shareholders are in a position to affect our ongoing operations, corporate transactions and other matters, and their interests may conflict with or differ from the interests of our other common shareholders.

Investment entities controlled by the significant shareholders, collectively hold approximately 25% of our common shares. As a result, the significant shareholders and their affiliates would be able to exert influence over the outcome of most matters submitted to a vote of our shareholders, including the election of members of our board of directors, if they were to act together.

Regardless of whether the significant shareholders maintain a significant interest in our common shares, so long as a designated affiliate of each significant shareholder holds our common shares, such significant shareholder will have certain rights, including the right to obtain copies of financial data and other information regarding us, the right to consult with and advise our management and the right to visit and inspect any of our properties and facilities. See “Interest of Management and Others in Material Transactions – Advisory Agreements”.

For so long as the significant shareholders own a significant percentage of our outstanding common shares, even if less than a majority, the significant shareholders will be able to exercise influence over our business and affairs, including the

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

2011 Annual Information Form |  | | NOA | |  |  | 41 |

##### Table of Contents

incurrence of indebtedness by us, the issuance of any additional common shares or other equity securities, the repurchase of common shares and the payment of dividends, if any, and will have the power to influence the outcome of matters submitted to a vote of our shareholders, including election of directors, mergers, consolidations, sales or dispositions of assets, other business combinations and amendments to our articles of incorporation. The interests of the significant shareholders and their affiliates may not coincide with the interests of our other shareholders. In particular, the significant shareholders and their affiliates are in the business of making investments in companies and they may, from time to time, acquire and hold interests in businesses that compete directly or indirectly with us. The significant shareholders and their affiliates may also pursue, for their own account, acquisition opportunities that may be complementary to our business, and as a result, those acquisition opportunities may not be available to us. So long as the significant shareholders and their affiliates continue to own a significant portion of the outstanding common shares, they will continue to be able to influence our decisions.

• |  | We are a holding company and rely on our subsidiaries for our operating funds, and our subsidiaries have no obligation to supply us with any funds.

We are a holding company with no operations of our own. We conduct our operations through subsidiaries and are dependent upon our subsidiaries for the funds we need to operate. Each of our subsidiaries is a distinct legal entity and has no obligation to transfer funds to us. The ability of our subsidiaries to transfer funds to us could be restricted by the terms of our financings. The payment of dividends to us by our subsidiaries is subject to legal restrictions as well as various business considerations and contractual provisions, which may restrict the payment of dividends and distributions and the transfer of assets to us.

• |  | Actions against us and some of our directors and officers may not be enforceable under US federal securities laws.

We are a corporation incorporated under the Canada Business Corporations Act. Consequently, we are and will be governed by all applicable provincial and federal laws of Canada. Several of our directors and officers reside principally in Canada. Because these persons are located outside the United States, it may not be possible for investors to effect service of process within the United States upon those persons. Furthermore, it may not be possible for you to enforce against us or them, in or outside the United States, judgments obtained in US courts, because substantially all of our assets and the assets of these persons are located outside the United States. We have been advised that there is doubt as to the enforceability, in original actions in Canadian courts, of liabilities based upon the US federal securities laws and as to the enforceability in Canadian courts of judgments of US courts obtained in actions based upon the civil liability provisions of the US federal securities laws. Therefore, it may not be possible to enforce those actions against us, our directors and officers or other persons named in this AIF.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices such as foreign currency exchange rates and interest rates. The level of market risk to which we are exposed at any point in time varies depending on market conditions, expectations of future price or market rate movements and composition of our financial assets and liabilities held, non-trading physical assets and contract portfolios.

To manage the exposure related to changes in market risk, we use various risk management techniques including the use of derivative instruments. Such instruments may be used to establish a fixed price for a commodity, an interest-bearing obligation or a cash flow denominated in a foreign currency.

The sensitivities provided below are hypothetical and should not be considered to be predictive of future performance or indicative of earnings on these contracts.

Foreign exchange risk

Foreign exchange risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to changes in foreign exchange rates. We regularly transact in foreign currencies when purchasing equipment and spare parts as well as certain general and administrative goods and services. These exposures are generally of a short-term nature and the impact of changes in exchange rates has not been significant in the past. We may fix our exposure in either the Canadian dollar or the US dollar for these short-term transactions, if material.

At March 31, 2011, with other variables unchanged, the impact of a $0.01 increase (decrease) in exchange rates of the Canadian dollar to the US dollar on short-term exposures would not have a significant impact to other comprehensive income.

Interest rate risk

We are exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of our financial instruments. Amounts outstanding under our amended credit facilities are subject to a floating rate. Our Series 1 Debentures are subject to a fixed rate. Our interest rate risk arises from long-term borrowings issued at fixed rates that create fair value interest rate risk and variable rate borrowings that create cash flow interest rate risk.

In some circumstances, floating rate funding may be used for short-term borrowings and other liquidity requirements. We may use derivative instruments to manage interest rate risk. We manage our interest rate risk exposure by using a mix of

42 |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

fixed and variable rate debt and may use derivative instruments to achieve the desired proportion of variable to fixed-rate debt.

At March 31, 2011, we held $72.0 million of floating rate debt pertaining to our Credit Facilities within our fourth amended and restated credit agreement (March 31, 2010 – $28.4 million). As at March 31, 2011, holding all other variables constant, a 100 basis point increase (decrease) to interest rates on floating rate debt would result in a $0.7 million increase (decrease) in effective annual interest costs. This assumes that the amount of floating rate debt remains unchanged from that which was held at March 31, 2011.

ADDITIONAL INFORMATION

Experts

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

Additional Information

Additional information, including information in respect of (i) the remuneration and indebtedness of the directors and executive officers of the Company, (ii) the principal holders of our securities; and (iii) securities authorized for issuance under equity compensation plans, is contained in our information circular for our most recent annual meeting of holders of common shares that involved the election of our directors, and our MD&A for the year ended March 31, 2011. Additional financial information is provided in our audited consolidated financial statements for the year ended March 31, 2011.

Additional information relating to us can be found on the Canadian Securities Administrators System for Electronic Document Analysis and Retrieval (SEDAR) database at www.sedar.com, the Securities and Exchange Commission’s Electronic Data Gathering, Analysis and Retrieval (EDGAR) system at www.sec.gov and our Company’s web site at www.nacg.ca.

GLOSSARY

The following are definitions of certain terms commonly used in our industry and this AIF.

“bitumen” means the molasses-like substance that comprises the oil in the oil sands.

“coker” means a vessel in which bitumen is cracked into its fractions and from which coke is withdrawn to start the process of converting bitumen to upgraded crude oil.

“established reserves” means those reserves recoverable under current technology and present and anticipated economic conditions specifically proved by drilling, testing or production, plus the portion of contiguous recoverable reserves that are interpreted to exist from geological, geophysical or similar information with reasonable certainty.

“upgrader” is a facility that upgrades bitumen into synthetic crude oil. Upgrader plants are typically located close to oil sands production.

“muskeg” means a swamp or bog formed by an accumulation of sphagnum moss, leaves and decayed matter resembling peat.

“naphtha” is a refined petroleum product in the lighter classification that is often used to make gasoline.

“oil sands” means the grains of sand covered by a thin layer of water and coated by heavy oil, or bitumen.

“overburden” means the layer of rocky, clay-like material that covers the oil sands.

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

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

“ultimately recoverable oil reserves” means an estimate of the initial established reserves that will have been developed in an area by the time all exploratory and development activity has ceased, having regard for the geological prospects of that area and anticipated technology and economic conditions.

Ultimately recoverable oil reserves include cumulative production, remaining established reserves and future additions through extensions and revisions to existing pools and the discovery of new pools. Ultimate potential can be expressed by the following simple equation: Ultimate potential cumulative production established reserves additions to existing pools future discoveries.

“upgrading” means the conversion of heavy bitumen into a lighter crude oil by increasing the hydrogen to carbon ratio, either through the removal of carbon (coking) or the addition of hydrogen (hydro processing).

2011 Annual Information Form |  | | NOA | |  |  | 43 |

##### Table of Contents

NAEP

EXHIBIT A

AUDIT COMMITTEE CHARTER

1. | MANDATE & AUTHORITY

| 1.1 | The Board of Directors (the “Board”) of North American Energy Partners Inc. (the “Company”) has established an Audit Committee (the “Committee”) to assist the Board in meeting its oversight responsibilities. The Committee’s responsibilities are summarized as follows:

| a) | monitor the integrity of the Company’s financial and related information of the Company including its financial statements;

| b) | monitor the system of internal controls over financial reporting;

| c) | monitor the disclosure controls and procedures;

| d) | oversee the work of the external auditor;

| e) | monitor the internal audit function;

| f) | identify and monitor the financial risks of the Company;

| g) | establish the Company’s ethics reporting procedures; and

| h) | monitor the Company’s compliance with legal and regulatory requirements.

| 1.2 | While the Committee shall have the responsibilities and powers set forth in this charter, it shall not be the responsibility of the Committee to determine whether the Company’s financial statements are complete, accurate or prepared in accordance with generally accepted accounting principles, to manage financial risks or to conduct audits. These are the responsibilities of management and the external auditor in accordance with their respective roles.

| 1.3 | The Committee will take reasonable steps to ensure that management establishes and maintains the controls, procedures and processes that comply with all appropriate laws, regulations or policies of the Company. It is not the responsibility of the Committee to conduct investigations or to ensure compliance with laws or regulations or Company policies. Management is responsible for establishing and maintaining the controls, procedures and processes over these matters and the Committee has the responsibility to ensure they exist.

| 1.4 | The Committee has the power to conduct or authorize investigations into any matters within the Committee’s scope of responsibilities. The Committee has the authority to engage independent counsel and other advisors, as it determines necessary to carry out its duties. The Company will provide the resources and funding required by the Committee to carry out its duties.

| 1.5 | The Committee shall also have unrestricted access to the Company’s personnel and documents and will be provided with the resources to carry out its responsibilities. The Committee shall have direct communication channels with the external auditor and the individual responsible for the internal auditor function to discuss and review specific issues as appropriate.

2. | MEMBERSHIP

| 2.1 | The Committee shall be composed of a minimum of three (3) directors of the Company. Each member of the Committee shall be appointed by the Board.

| 2.2 | The Board shall appoint one of the members to be the Chair of the Committee.

| 2.3 | All members of the Committee shall be “independent” as that term is defined under the requirements of applicable securities laws and the standards of any stock exchange on which the Company’s securities are listed, taking into account any transitional provisions that are permitted.

| 2.4 | Members shall serve one year terms and may serve consecutive terms to ensure continuity of experience. Members shall be reappointed each year to the Committee by the Board at the Board meeting that coincides with the annual shareholder meeting. A member of the Committee shall automatically cease to be a member upon ceasing to be a director of the Company. Any member may resign or be removed by the Board from membership on the Committee or as Chair.

| 2.5 | All members of the Committee must be “financially literate” as that qualification is interpreted by the Board or acquire such literacy within a reasonable period of time after joining the Committee. At the present time, the Board interprets “financial literacy” to mean a basic understanding of finance and accounting and the ability to read and understand financial statements (including the related notes) of the sort released or prepared by the Company in the normal course of its business.

| 2.6 | At least one member of the Committee shall be an “audit committee financial expert” who shall possess the attributes outlined in Appendix A.

2011 Annual Information Form |  | | NOA | |  |  | i |

##### Table of Contents

| 2.7 | No director who is currently serving on the audit committee of another public company will be appointed to the Committee unless the Board determines that such simultaneous service would not impair the ability of such member to serve on the Committee. The maximum number of audit committees a director can serve on at any one time is set at three by the NYSE.

| 2.8 | The responsibilities of a member of the Committee are in addition to that member’s duties as a member of the Board.

| 2.9 | The Company is responsible for the orientation and continuing education of the members.

3. | MEETINGS

| 3.1 | Committee meetings will be conducted in a manner consistent with the Company By-laws, the Audit Committee Charter and the applicable business corporation act.

| 3.2 | The Notice of Meeting will be governed by the Company By-laws. Meetings will be called by the Chair or any other member of the Committee as appropriate.

| 3.3 | The Chair shall determine the time, place and procedures for Committee meetings, subject to the requirements of this Charter.

| 3.4 | Any director of the Company may attend Committee meetings, however, only members of the Committee are eligible to vote or establish a quorum.

| 3.5 | The external auditor will be requested to attend the meetings where the Committee is reviewing quarterly or annual financial statements. The Committee or any member may request that the external auditor appear before the Committee at any time.

| 3.6 | The Committee will meet a minimum of four times per year and shall determine whether additional meetings are required.

| 3.7 | The Chair of the Committee shall preside at and chair all meetings of the Committee. If the Chair is absent from a meeting, the remaining members of the Committee shall appoint a member to act as Chair for that meeting.

| 3.8 | A quorum for a meeting will be established if a majority of the members are present. Members of the Committee may participate in a meeting through any means which permits all parties to communicate adequately with each other. Any members not physically present but participating in the meeting through such means is deemed to be present at the meeting. A quorum, once established, is maintained even if members of the Committee leave before the meeting concludes.

| 3.9 | In the event of a tie vote on a resolution, the issue will be forwarded to the full board for a vote.

| 3.10 | A resolution signed by all members of the Committee entitled to vote on that resolution is as valid as if it had been passed at a meeting of the Committee.

| 3.11 | In camera sessions will be held as deemed necessary by the Committee with the external auditor, the individual responsible for the internal audit function, management and the Committee by itself.

| 3.12 | The Corporate Secretary or another person appointed by the Chair will act as secretary of the Committee meetings.

| 3.13 | The secretary of the meeting will keep minutes of each meeting, which shall record the decisions reached by the Committee.

| 3.14 | The minutes shall be distributed to Committee members with copies provided to (a) the Board; (b) the CEO; (c) the Vice President Finance; (d) the external auditor; and (e) the individual responsible for the internal audit function.

| 3.15 | The Corporate Secretary or another person will file the Committee minutes and all meeting material with the corporate minute books.

4. | RESPONSIBILITIES

| 4.1 | General

| 4.1.1 | The Committee will meet as set out in section 3 above.

| 4.1.2 | The Committee will report to the Board on all matters in this charter as well as such matters as the Board may from time to time refer or delegate to the Committee.

| 4.1.3 | The Committee will maintain a formal written Committee charter and annually assess the adequacy of the charter, submit such evaluation to the Board and recommend any proposed changes to the Board for approval.

| 4.1.4 | The Committee members will conduct an assessment of the effectiveness of the Committee.

| 4.2 | Financial reporting and internal controls

| 4.2.1 | Annual financial statements

The Committee is responsible for the assessment of the annual audited financial statements of the Company and to recommend approval of the statements to the Board.

ii |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

| 4.2.2 | Interim financial statements

The Committee is responsible for the assessment and approval of the quarterly interim unaudited financial statements.

| 4.2.3 | Accounting policies

The Committee will review and discuss with management and the external auditor, as appropriate, the Company’s financial reporting policies, including changes in or adoptions of, accounting standards and principles and disclosure practices.

The Committee will review with management and the external auditor their qualitative judgments about the appropriateness, not just the acceptability, of accounting principles and accounting disclosure practices used or proposed to be used and particularly, the degree of aggressiveness or conservatism of the Company’s accounting principles and underlying estimates.

| 4.2.4 | Internal controls over financial reporting

The Committee will review and discuss with management, the external auditor and others, as appropriate, the existence and design of the Company’s internal controls over financial reporting established by management and the effectiveness of such controls.

The Committee will monitor the work undertaken by management to design and implement and to provide an assessment of the effectiveness of its system of internal control over financial reporting. The Committee will review and discuss with the external auditor, when required, the opinion on management’s assessment of the effectiveness of its system of internal controls over financial reporting.

| 4.2.5 | Disclosure controls and procedures

The Committee will review and discuss with management, the external auditor and others, as appropriate, the existence and design of the Company’s disclosure controls and procedures established by management and the effectiveness of such controls.

The Committee will review and approve the disclosure policy of the Company and periodically assess the adequacy of such policy for completeness and accuracy. The Committee will ensure that the Company has satisfactory procedures in place for the review of the Company’s public disclosure of financial information extracted or derived from the Company’s financial statements. The Committee will also monitor and oversee the activities of the Company’s Disclosure Committee.

| 4.2.6 | Other public disclosures

The Committee will review and approve, and in some instances recommend approval to the Board, material financial disclosures in the following documents prior to their public release or filing with securities regulators:

| a) | management’s discussion and analysis;

| b) | any prospectus or offering document;

| c) | annual reports or annual information forms;

| d) | all material financial information required by securities regulations (e.g., Forms 6-K, 20-F and F-4) including all exhibits thereto (including the certifications required of the Company’s principal executive officer and principal financial officer);

| e) | any related party transactions;

| f) | any off balance sheet structures;

| g) | any correspondence with securities regulators or government financial agencies; and

| h) | news or press releases, containing audited or unaudited financial information, including the type and presentation of information and in particular any pro-forma or non-GAAP information.

| 4.3 | External Auditor

| 4.3.1 | The Committee shall recommend to the Board the external auditor to be nominated for the purpose of preparing or issuing the auditor’s report or performing other audit, review or attest services for the Company and the compensation of the external auditor and, as necessary, review and recommend to the Board the discharge of the external auditor.

| 4.3.2 | In the event of a change of external auditor, the Committee shall review all issues and provide documentation to the Board related to the change, including the information to be included in the Notice of Change of Auditors and the planned steps for an orderly transition period.

| 4.3.3 | The Committee shall engage the external auditor for the purpose of preparing or issuing the auditor’s report or performing other audit, review or attest services for the Company.

| 4.3.4 | The Committee shall review the audit scope and plan of the external auditor.

2011 Annual Information Form |  | | NOA | |  |  | iii |

##### Table of Contents

| 4.3.5 | The external auditor shall report directly to the Committee.

| 4.3.6 | The Committee will review and discuss with management and the external auditor, as appropriate, at the completion of the annual audit and each quarterly review:

| a) | the external auditor’s audit or review of the financial statements and its report thereon;

| b) | any significant changes required to be made in the external auditor’s audit plan;

| c) | any serious difficulties or disputes between management and the external auditor during the course of the quarterly review or annual audit;

| d) | any improper influence by officers on the external auditor;

| e) | any special audit or review steps adopted in light of material control deficiencies;

| f) | the summary of adjusted and unadjusted differences;

| g) | any related findings and recommendations of the external auditor together with management’s responses including the status of previous recommendations; and

| h) | any other matters related to the conduct of the external audit, which are to be communicated to the Committee by the external auditor under generally accepted auditing standards.

| 4.3.7 | The Committee shall take reasonable steps to confirm the independence of the external auditor, which shall include but shall not be limited to:

| a) | ensuring receipt, at least annually, from the external auditor of a formal written statement delineating all relationships between the external auditor and the Company, including non-audit services provided to the Company;

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

| c) | enquiring into and determining the appropriate resolution of any conflict of interest in respect of the external auditor;

| d) | reviewing and approving the Company’s hiring policies regarding the hiring of partners, employees and former partners and employees of the Company’s existing and former external auditor;

| e) | requesting the rotation of the lead audit partner every five (5) years; and

| f) | giving consideration to the rotation of the audit firm on a periodic basis.

| 4.3.8 | The Committee shall pre-approve any non-audit services to be provided to the Company or its subsidiaries by the external auditor except that the Committee has delegated a deminimus level of $20,000 per annum to the Audit Committee Chair who will report to the Audit Committee at their next meeting of any work approved within this limit.

| 4.3.9 | The Committee will review the nature of work performed by audit firms (other than the external auditor) to ensure that at least one of the nationally recognized firms remains independent in the event a change in external auditor is necessary or desired.

| 4.4 | Internal Audit Function

| 4.4.1 | The Committee will determine if an internal audit function should exist taking into account any legislative or listing requirements.

| 4.4.2 | The individual responsible for the internal auditor function reports administratively to the President and has a functional reporting relationship to the Chair of the Committee.

| 4.4.3 | The Committee will review management’s proposed appointment, termination or replacement of the internal audit function. If the Company out-sources its internal audit function, the Company’s external auditor cannot be engaged to perform such services.

| 4.4.4 | The Committee will review the responsibility and charter as well as the effectiveness of the internal audit function on an annual basis. The effectiveness assessment will include a review of its reporting relationships, activities, resources, its independence from management and its working relationship with the external auditor.

| 4.4.5 | The Committee will review and approve the annual internal audit plan, scope of work and ensure that the internal audit plan is coordinated with the activities of the external auditor.

| 4.4.6 | The Committee will review all internal audit reports and management’s responses.

| 4.5 | Risk Management

The Committee shall review the significant financial risks and approve the Company’s policies to manage such financial risk including the Antifraud Policy.

iv |  | | NOA | |  | 2011 Annual Information Form

##### Table of Contents

NAEP

| 4.6 | Ethics Reporting

| 4.6.1 | The Committee is responsible for the establishment of a policy and procedures for:

| a) | the receipt, retention and treatment of any complaint received by the Company regarding financial reporting, accounting, internal accounting controls or auditing matters; and

| b) | the confidential, anonymous submissions by employees of the Company of concerns regarding questionable accounting or auditing matters.

| 4.6.2 | The Committee will review, on a timely basis, serious violations of the Code of Conduct and Ethics Policy including all instances of fraud.

| 4.6.3 | The Committee will review on a summary basis at least quarterly all reported violations of the Code of Conduct and Ethics Policy.

| 4.7 | Legal and Regulatory Compliance

| 4.7.1 | The Committee will review any litigation, claim or other contingent liability, including any tax reassessment that could have a material effect on the financial statements.

| 4.7.2 | The Committee will review compliance with applicable financial, tax or securities regulations and the accuracy and timeliness of filings with regulators.

| 4.7.3 | The Committee will review compliance by management in filing and paying all statutory withholdings within the prescribed time.

Prepared By: |  | Approved By: |  | Date of Approval and Issue:
/s/ Vincent Gallant |  | /s/ Allen Sello |  | December 7, 2006
Vincent Gallant Vice President, Corporate and Secretary |  | Allen Sello, Chair Audit Committee |  |

2011 Annual Information Form |  | | NOA | |  |  | v |

##### Table of Contents

Appendix A: Audit Committee Financial Expert

At least one member of the Committee shall be an “audit committee financial expert” who shall possess the attributes outlined below:

1. | An understanding of generally accepted accounting principles and financial statements;

2. | The ability to assess the general application of generally accepted accounting principles in connection with the accounting for estimates, accruals and reserves;

3. | Experience in preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by the Company’s financial statements, or experience in actively supervising one or more persons engaged in such activities;

4. | An understanding of internal control over financial reporting;

5. | An understanding of audit committee functions;

6. | As provided in the rules of the SEC, the designation or identification of a person as an audit committee financial expert does not (a) impose on that person any duties, obligations or liability that are greater than the duties, obligations or liability imposed on that person as a member of the Committee and the Board in the absence of such designation or identification or (b) affect the duties, obligations or liability of any other member of the Committee or the Board; and

7. | A member of the Committee may qualify as an audit committee financial expert as a result of his or her:

| (a) | education and experience as a principal financial officer, principal accounting officer, controller, public accountant or auditor or experience in one or more positions that involve the performance of similar functions;

| (b) | experience actively supervising a principal financial officer, principal accounting officer, controller, public accountant, auditor or person performing similar functions;

| (c) | experience overseeing or assessing the performance of companies or public accountants with respect to the preparation, auditing or evaluation of financial statements; or

| (d) | other relevant experience.

vi |  | | NOA | |  | 2011 Annual Information Form