UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 20-F

¨ REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934

or

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED MARCH 31, 2005

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

or

¨ SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report                     

Commission file number 333-111396

North American Energy Partners Inc.

(Exact Name of the Registrant as Specified in its Charter)

Canada

(Jurisdiction of Incorporation or Organization)

Zone 3, Acheson Industrial Area, 2-53016 Hwy 60, Acheson, Alberta T7X 5A7

(Address of Principal Executive Offices)

Securities registered or to be registered pursuant to Section 12(b) of the Act:	NONE
Securities registered or to be registered pursuant to Section 12(g) of the Act:	NONE
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:	NONE
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.	100 Common Shares, Without Par Value, at March 31, 2005

Indicate by check mark whether the Company: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Company was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    YES  x    NO  ¨

Indicate by check mark which financial statement item the Company has elected to follow.     Item 17  x    Item 18  ¨

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes  ¨    No  x

TABLE OF CONTENTS

			Page
PART I
	ITEM 1:	IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS	2
	ITEM 2:	OFFER STATISTICS AND EXPECTED TIMETABLE	2
	ITEM 3:	KEY INFORMATION	2
	ITEM 4:	INFORMATION ON THE COMPANY	12
	ITEM 5:	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	27
	ITEM 6:	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	39
	ITEM 7:	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	48
	ITEM 8:	FINANCIAL INFORMATION	51
	ITEM 9:	THE OFFER AND LISTING	52
	ITEM 10:	ADDITIONAL INFORMATION	52
	ITEM 11:	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	54
	ITEM 12:	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	54
PART II
	ITEM 13:	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	54
	ITEM 14:	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	55
	ITEM 15:	CONTROLS AND PROCEDURES	55
	ITEM 16:	[RESERVED]	55
	ITEM 16A	AUDIT COMMITTEE FINANCIAL EXPERT	55
	ITEM 16B	CODE OF ETHICS	55
	ITEM 16C	PRINCIPAL ACCOUNTANT FEES AND SERVICES	55
	ITEM 16D	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES	55
	ITEM 16E	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS	56
PART III
	ITEM 17:	FINANCIAL STATEMENTS	56
	ITEM 18:	FINANCIAL STATEMENTS	56
	ITEM 19:	EXHIBITS	56

Restatement

As previously disclosed in a Form 6-K filed on October 12, 2005, the Company has reviewed the accounting treatment of the Company’s derivative financial instruments and has concluded that there have been technical deficiencies in the hedge documentation relating to the cross-currency swap and interest rate swap contracts used to manage its foreign exchange risk exposure related to the U.S. $ denominated 8  ³/4 % senior notes since the inception of the derivative financial contracts on November 26, 2003, which deficiencies could not be corrected retroactively. Therefore, the Company has determined that it is necessary to restate all reported periods after November 26, 2003 to eliminate the impact of hedge accounting. This was accomplished by recognizing the foreign exchange gain or loss relating to the senior notes each period and recording the derivative financial instruments at fair value and the realized and unrealized gains and losses on the derivative instruments each period through the Consolidated Statement of Operations, along with the associated future income tax effects.

Please see Note 3 to the Consolidated Financial Statements and the “Restatement” section included in Item 5, Management’s Discussion and Analysis of Financial Condition and Results of Operations, for a detailed discussion of the restatement.

As used in this annual report on Form 20-F, unless the context otherwise indicates, the terms “NAEPI,” “we,” “us,” “our,” or the “Company” means North American Energy Partners Inc. and its consolidated subsidiaries.

EXCHANGE RATE INFORMATION

Unless otherwise indicated, all monetary references herein are denominated in Canadian dollars; references to “dollars” or “$” are to Canadian dollars and references to “US$” or “U.S. dollars” are to United States dollars. As at March 31, 2005, the noon buying rate as quoted by the Federal Reserve Bank of New York was $1.2094 equals US$1.00. (See Item 3 for further exchange rate information to U.S. currency.) Except as otherwise indicated, financial statements of, and information regarding, North American Energy Partners Inc. are presented in Canadian dollars.

STATEMENT REGARDING FORWARD LOOKING INFORMATION

This document contains forward-looking statements. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management, based on information currently available to management. Forward-looking statements are those that do 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,” “objective,” “projection,” “forecast,” “management believes,” “continue,” “strategy,” “position,” or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, express or implied, concerning future operating results or the ability to generate income or cash flow are forward-looking statements. Forward-looking statements include the information concerning possible or assumed future results of our operations set forth under “Item 4: Information on the Company,” “Item 5: Operating and Financial Review and Prospects,” “Item 11: Quantitative and Qualitative Disclosures About Market Risk,” and elsewhere in this annual report on Form 20-F.

Forward-looking statements are not guarantees of performance. They involve risks, uncertainties, and assumptions. Future actions, conditions, or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond management’s ability to control or predict. Specific factors that could cause actual results to vary from those in the forward-looking statements include:

• our ability to bid successfully on new projects and accurately forecast costs associated with unit price or lump sum contracts;

• the effectiveness of our internal controls;

• our ability to comply with the terms of the agreements governing our indebtedness;

• our ability to obtain surety bonds as required by some of our customers;

• foreign currency exchange rates;

• changes in oil and gas prices;

• decreases in outsourcing work by our customers;

• shut-downs or cutbacks at major businesses that use our services;

• changes in laws or regulations, third party relations and approvals, and decisions of courts, regulators, and governmental bodies that may adversely affect our business or the business of the customers we serve;

• our ability to hire and retain a skilled labor force;

• our ability to purchase or lease equipment;

• provincial, regional, and local economic, competitive, and regulatory conditions and developments;

• technological developments;

• capital markets conditions;

• inflation;

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• interest rates;

• weather conditions;

• the timing and success of business development efforts; and

• our ability to successfully identify and acquire new businesses and assets and integrate them into our existing operations.

We believe the forward-looking statements in this document are reasonable; however, you should not place undue reliance on any forward-looking statements, which are based on our current expectations. Further, forward-looking statements speak only as of the date they are made, and we undertake no obligation to update publicly any of them in light of new information or future events.

PART I

ITEM 1: IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not applicable.

ITEM 2: OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.

ITEM 3: KEY INFORMATION

A. SELECTED FINANCIAL DATA

North American Energy Partners Inc. was incorporated under the Canada Business Corporations Act on October 17, 2003 and had no operations prior to November 26, 2003. As a result, the selected financial data presented below as of and for each of the fiscal years ended March 31, 2001, 2002, and 2003 is derived from the audited financial statements of our predecessor, Norama Ltd., referred to as the “Predecessor Company.” The selected financial data presented below as of and for the year ended March 31, 2004 is derived from the historical financial statements of the Predecessor Company for the period from April 1, 2003 to November 25, 2003 and the historical financial statements of North American Energy Partners Inc. for the period November 26, 2003 through March 31, 2004.

We prepare our financial statements in accordance with Canadian Generally Accepted Accounting Principles (“Canadian GAAP”). For a discussion of the principal differences between Canadian GAAP and U.S. Generally Accepted Accounting Principles (“U.S. GAAP”) as they relate to us, see Note 21 to our consolidated financial statements at Item 17.

The following table should be read in conjunction with “Item 4: Business Overview”, “Item 5: Operating and Financial Review and Prospects” and our consolidated financial statements included in Item 17.

	Predecessor
	Year Ended March 31,
	2001		2002		2003		2004(a)		2005
							Restated(h)
Statement of Operations Data:
Revenue	$	247,267	$	249,351	$	344,186	$	378,263	$	357,323
Project costs		120,728		127,996		219,979		240,232		240,919
Equipment costs		71,518		77,289		72,228		69,102		59,476
Depreciation		10,409		11,299		10,974		13,240		20,762

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	Predecessor
	Year Ended March 31,
	2001			2002			2003			2004(a)			2005
										Restated (h)
Gross profit		44,612			32,767			41,005			55,689			36,166
General and administrative		9,582			12,794			12,233			13,848			22,863
Loss (gain) on sale of property, plant and equipment		(979	)		(218	)		(2,265	)		82			494
Amortization of intangible assets (b)		—			—			—			12,928			3,368
Operating income		36,009			20,191			31,037			28,831			9,441
Management fees (c)		36,550			14,400			8,000			41,070			—
Interest expense		3,034			3,510			4,162			12,536			31,141
Foreign exchange gain		—			(17	)		(234	)		(668	)		(19,815	)
Other income		—			—			—			(597	)		(421	)
Realized and unrealized (gain) loss on derivative financial instruments		—			—			—			12,205			43,113
Income (loss) before income taxes		(3,575	)		2,298			19,109			(35,715	)		(44,577	)
Income taxes		(3,667	)		689			6,620			(12,292	)		(2,264	)
Net income (loss)	$	92		$	1,609		$	12,489		$	(23,423	)	$	(42,313	)
Balance Sheet Data (end of period)
Cash	$	11,247		$	436		$	651		$	36,595		$	17,922
Total assets		129,527			120,431			158,584			489,674			526,668
Total debt (d)		54,678			50,137			63,401			325,064			362,125
Total shareholder’s equity		16,770			17,379			29,818			115,355			73,539
Other Financial Data
EBITDA (e)	$	9,868		$	17,107		$	34,245		$	2,989		$	10,694
Capital expenditures		18,547			8,668			22,932			7,735			25,679
Ratio of earnings to fixed charges (f)		—			1.7			5.6			—			—
Other Data:
Equipment hours (g)		644,087			583,071			673,811			695,148			763,920

(a) The historical statement of operations and other financial data for the year ended March 31, 2004 have been derived from the historical financial statements of Norama Ltd. for the period from April 1, 2003 to November 25, 2003, and the historical financial statements of North American Energy Partners Inc. for the period from November 26, 2003 to March 31, 2004. The balance sheet data as of March 31, 2004 has been derived from the North American Energy Partners Inc. financial statements.

(b) Intangible assets are being amortized over the useful lives of the related customer contracts in progress and related relationships, trade names, non-competition agreement, and employee arrangements.

(c) Management fees paid to the corporate shareholder of our predecessor company, Norama Ltd., represent fees for services rendered and were determined with reference to taxable income.

(d) Debt is defined as amounts owing on our senior notes, derivative financial instruments, capital lease obligations and our senior secured credit facility (including current portions thereon). It excludes amounts owing to our parent company.

(e) EBITDA is defined as earnings before interest expense, income taxes, and depreciation and amortization. EBITDA is not a measure of performance under Canadian GAAP or U.S. GAAP. We believe that EBITDA is a meaningful liquidity measure for our business because it excludes items, such as depreciation, interest, and taxes, that are not directly related to the operating performance of our employees and equipment. Management reviews EBITDA to determine whether property, plant and equipment are being allocated efficiently. Also, management uses EBITDA as a benchmark for performance bonuses for its staff. However, EBITDA does not represent, and should not be used as a substitute for, net income or cash flows from operations as determined in accordance with Canadian GAAP or U.S.

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GAAP, and EBITDA is not necessarily an indication of whether cash flow will be sufficient to fund our cash requirements.

A reconciliation of EBITDA to net income (loss) as set forth in our consolidated statements of operations is as follows:

	Predecessor
	Year Ended March 31,
	2001			2002		2003		2004(a)			2005
								Restated (h)
Net income (loss)	$	92		$	1,609	$	12,489	$	(23,423	)	$	(42,313	)
Adjustments:
Depreciation		10,409			11,299		10,974		13,240			20,762
Amortization		—			—		—		12,928			3,368
Interest expense		3,034			3,510		4,162		12,536			31,141
Income taxes		(3,667	)		689		6,620		(12,292	)		(2,264	)
EBITDA	$	9,868		$	17,107	$	34,245	$	2,989		$	10,694

(f) For the purposes of calculating the ratio of earnings to fixed charges (Exhibit 7.1), (1) earnings consist of earnings (loss) before fixed charges and income taxes and (2) fixed charges consist of interest expense on all indebtedness, including capital lease obligation. During the periods presented, no interest costs have been capitalized. The amount by which fixed charges exceeded earnings was $3,575 for the fiscal year ended March 31, 2001, $35,715 for the year ended March 31, 2004, and $44,577 for the fiscal year ended March 31, 2005.

(g) Calculated as actual hours of operations for heavy equipment. Revenue and operating profit per equipment hour is used by management to evaluate the relative efficiency of projects, depending on the size of equipment.

(h) See “Item 4: Business Overview” for description of restatement.

EXCHANGE RATE DATA

The following tables set forth the exchange rates for one Canadian dollar, expressed in U.S. dollars, based on the inverse of the noon buying rate in the city of New York for cable transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York (the “Noon Buying Rate”). On August 31, 2005, the Noon Buying Rate was $1.00 = US$0.8408.

	2005
	March	April	May	June	July	August
High for period	0.8322	0.8233	0.8082	0.8159	0.8300	0.8412
Low for period	0.8024	0.7957	0.7872	0.7950	0.8041	0.8207

	Year Ended March 31,
	2001	2002	2003	2004	2005
Average for period	0.6651	0.6392	0.6455	0.7412	0.7836

B. CAPITALIZATION AND INDEBTEDNESS

Not applicable.

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C. REASONS FOR THE OFFER AND USE OF PROCEEDS

Not applicable.

D. RISK FACTORS

We rely on a small number of customers from whom we receive a significant amount of our revenues.

We provide our services primarily to a small number of major integrated and independent oil and gas and other natural resources companies operating in western Canada. Revenue from our five largest customers represented approximately 68% of our total revenue for the year ended March 31, 2005 and those customers are expected to continue to provide a significant percentage of our revenues in the future. Each period any one of our customers may constitute a significant portion of our revenue. For example, for the fiscal year ended March 31, 2005, revenue generated from work for Syncrude Canada Ltd. (“Syncrude”) constituted approximately 26% of our total revenue due to several large projects with Syncrude and our status as one of their preferred contractors. We may not be able to replace the work generated by these projects with work from other customers. Our services to our customers are typically provided under contracts with terms ranging from six months to ten years, some of which have terms allowing for automatic or optional renewals of the contract. However, a significant number of our contracts terminate upon completion of the project without having a definite termination date, and the contracts typically allow the customer to reduce or eliminate the work which we are to perform. In addition, the customers may choose not to extend the existing contracts or enter into new contracts. The loss of or significant reduction in business with one or more of these customers could have a material adverse effect on our business.

Lump sum and unit-price contracts with our customers expose us to losses when our estimates of project costs are too low or when we fail to perform within our cost estimates.

Our recent operating results have been adversely affected by losses we have incurred on lump sum and unit-price contracts. The terms of these contracts require us to guarantee the price of the services we provide and assume the risk that our costs to perform the services and provide the materials will be greater than anticipated. Our profitability under such contracts is therefore dependent upon our ability to accurately predict the costs associated with our services. Cost estimating is therefore a critical function that has a major impact on our success or failure. Estimates must be adequately prepared and reviewed because inaccurately prepared bids can result in unsuccessful bids for contracts or losses on contracts actually received.

Not only is our ability to estimate costs important, the costs we actually incur may be affected by a variety of factors, some of which may be beyond our control. Factors that contribute to differences in the costs we actually incur as compared to our estimates and which therefore affect profitability include, without limitation, site conditions which differ from those assumed in the original bid, the availability and skill level of workers in the geographic location of the project, inclement weather, equipment productivity and timing differences that result from actual project starting time as compared to projected starting time and the general coordination of work inherent in all substantial projects we undertake. When we are unable to accurately estimate the costs of lump sum and unit-price contracts, or when we incur unrecoverable cost overruns, some projects will have lower margins than anticipated or incur losses, which adversely impact our results of operations, financial condition and cash flow.

Approximately 51% and 21% of our revenue for the fiscal years ended March 31, 2005 and March 31, 2004, respectively, was derived from lump sum and unit-price contracts. Going forward, the percentage of our revenue derived from lump sum and unit-price contracts is expected to increase as several of our long-term contracts, including the 10-year overburden removal contract for Canadian Natural Resources Ltd., or CNRL, are unit-price and/or lump sum contracts. Given the magnitude of the

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projected revenues from these contracts as compared to the revenues expected to be earned from other contracts, if we underestimated the costs to perform these contracts, or if we were to incur unrecoverable cost overruns on these projects, it is likely that we would be unable to service our debt obligations.

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

We had to restate our financial statements for the first and second quarters of fiscal 2005, primarily due to certain inaccurate expense accruals. During the preparation of our financial statements for the third quarter of fiscal 2005, we discovered a number of invoices recorded in the third quarter which were related to costs actually incurred in the first and second quarters of fiscal 2005. A review of our accounting and control procedures identified a number of deficiencies in our financial reporting processes and internal controls that contributed to several misstated amounts as discussed earlier in this document. We are endeavoring to address these deficiencies. Our auditors have advised us that unless we have appropriate procedures and controls in place with respect to accounting for our contracts and with respect to our purchases and accounts payable, we will not be able to report our results on a timely basis.

While we have evaluated our accounting and control procedures surrounding the causes for the misstatements, we may be unable to implement the changes required to provide accurate and timely operating and financial reports. Failure to do so would cause us to breach the reporting requirements under our revolving credit facility and the indenture governing our 8¾% senior notes and 9% senior secured notes, as well as have a material adverse effect on our business, financial condition and results of operations. Until we establish and maintain effective internal controls and procedures for financial reporting, we may not have appropriate procedures in place to eliminate financial statement inaccuracies and avoid delays in financial reporting in the future.

We have also had to subsequently restate our financial statements for each fiscal quarter of fiscal 2005 to eliminate the impact of hedge accounting. This was accomplished by recognizing the foreign exchange gain or loss relating to the senior notes each period and recording the derivative financial instruments at fair value and the realized and unrealized gains and losses in the derivative instruments for each period through the Consolidated Statement of Operations, along with the associated future income tax effects.

If our access to the surety market were to be restricted in the future, or if our demand for surety bonds were to increase significantly, our business could be impaired.

Like all businesses providing similar services, we are at times required to post bid or performance bonds issued by a financial institution known as a surety. The surety industry experiences periods of unsettled and volatile markets, usually in the aftermath of substantial loss exposures or corporate bankruptcies with significant surety exposure. Historically, these types of events have caused reinsurers and sureties to reevaluate their committed levels of underwriting and required returns. As needed in the ordinary course of business, we typically have been able to secure necessary bonds. However, we recently were not awarded a contract on which we bid, in part due to our inability to obtain a bid bond for a project whose size exceeded our current bonding capacity. If for any reason, whether because of our financial condition, our level of secured debt or general conditions in the bond market, our bonding capacity becomes insufficient to satisfy our future bonding requirements, our business could be impaired.

We are dependent upon continued outsourcing by our customers of mining and site preparation services.

Outsourced mining and site preparation services constitute a large portion of the work we perform for our customers. For example, our mining and site preparation project revenues constituted approximately 74% and 62% of our revenues in the fiscal years ended March 31, 2005 and 2004, 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.

Changes in oil and gas prices could cause our customers to slow down or curtail their current production and future expansions which would in turn reduce our revenue from those customers.

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The profitability and growth of our customers may be impacted by the prices of oil and gas. Prices for oil are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil, market uncertainty and a variety of additional factors beyond our control. Such factors include weather conditions, the condition of the Canadian and U.S. economies, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political stability in the Middle East, increasing foreign demand for oil and gas, war or the threat of war in oil producing regions, the foreign supply of oil and the availability of fuel from alternate sources. In addition, our customers make their major expansion investment decisions based on their long-term outlook for the prices of oil and gas and their profitability based on those prices. If they believe the prices of those commodities will remain at depressed levels or that their profitability will be adversely affected by fluctuations in currency exchange rates, they may delay or curtail their current expansion plans. Such a delay or curtailment could have a material adverse impact on our financial condition and results of operations.

Our operations are subject to weather-related factors that may cause delays in our completion of projects.

Because our operations are located in western Canada and northern Ontario, we are often subject to extreme weather conditions. While our operations are not significantly affected by normal seasonal weather patterns, extreme weather, including heavy rain and snow, can cause us to delay the completion of a project, which could result in lower margins than estimated.

Insufficient pipeline and refining capacity for heavy crude products could cause our customers to slow down or curtail their current production and future expansions which would, in turn, reduce our revenue from those customers.

While current pipeline capacity is sufficient to transport existing oil sands production to market, future production growth will require increased pipeline capacity. If such increases do not materialize, our customers may be unable to efficiently deliver increased production to market. Additionally, we expect that increases in oil sands production will require added heavy crude oil refinery capacity. Similarly, if such increased capacity or alternative markets do not materialize future growth in demand for our customers’ products could be reduced.

Because most of our customers are located or operate in western Canada, a downturn in the energy industry in western Canada could result in a decrease in the demand for our services by our customers.

Most of our customers are located or operate in western Canada. In the fiscal year ended March 31, 2005, we generated approximately 69% of our revenues from the Alberta oil sands. A downturn in the energy industry in western Canada could cause our customers to slow down or curtail their current production and future expansions which would, in turn, reduce our revenue from those customers. Such a delay or curtailment could have a material adverse impact on our financial condition and results of operations.

Shortages of skilled labor, work stoppages or other labor disruptions at our operations or those of our principal customers or service providers could have an adverse effect on our profitability and financial condition.

Our ability to provide high-quality services on a timely basis requires an adequate number of skilled workers such as engineers, trades people and equipment operators. We cannot assure you that we will be able to maintain an adequate skilled labor force or that our labor expenses will not increase. A shortage of skilled labor would require us to curtail our planned internal growth or may require us to use less skilled labor which could adversely affect our ability to perform work.

Substantially all of our hourly employees are subject to collective bargaining agreements to which we are a party or are otherwise subject because of a bargaining relationship with the particular trade union that is a party to the collective bargaining agreement. Any work stoppage resulting from a strike or lockout could have a material adverse effect on our financial condition and results of operations.

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In the province of Alberta, collective bargaining in the construction industry is conducted by sector, by registered groups consisting of an employers’ organization, on behalf of the employers, and a defined group of trade unions, on behalf of the unions in that sector. An employers’ organization which has been registered by the Labour Relations Board bargains with the trade unions named in the certificate on behalf of all employers who work in that part of the construction industry described in the certificate with whom the unions have a bargaining relationship. Any collective agreement entered into by the employers’ organization is binding on all such employers. We do not have control over the terms of such agreements but will be bound by these because of the provisions of the Labour Relations Code and the registrations.

In addition, our customers employ workers under other collective bargaining agreements. Any work stoppage or labor disruption at our key customers could significantly reduce the amount of services that we provide.

Our ability to grow our operations in the future is, in part, dependent on our ability to secure tires for our equipment.

Currently, global demand for tires of the size and specifications we require is exceeding the available supply. While we have been able to secure the necessary tires to date to keep our equipment running, there is no guarantee that this will be the case in the future.

Because approximately 80% of the major projects that we pursue are awarded to us based on bid proposals, competitors with lower overhead cost structures may underbid us, subsequently impeding our growth.

Approximately 80% of the major projects that we pursue are awarded to us based on bid proposals. We may compete in the future for these projects against companies that may have substantially greater financial and other resources than we do. Some smaller competitors may have lower overhead cost structures and may be able to provide their services at lower rates than we can. Further, public sector work is often performed by governmental agencies. Our growth may be impacted to the extent that we are unable to successfully bid against these companies.

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. As new projects are contemplated or built, 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, causing an adverse effect on our financial condition.

A significant amount of our revenues are generated by providing non-recurring services.

Approximately 74% of our revenue for the fiscal year ended March 31, 2005 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. Future revenues from these types of services will depend upon customers expanding existing mines and developing new projects.

Penalty clauses in our customer contracts could expose us to losses if total project costs exceed original estimates or if projects are not completed by specified completion date milestones.

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A portion of our revenue is derived from contracts which have performance incentives and penalties depending on the total cost of a project as compared to the original estimate. We could incur significant penalties based on cost overruns. In addition, the total project cost as defined in the contract may include not only our work, but also work performed by other contractors. As a result, we could incur penalties due to work performed by others over which we have no control. We may also incur penalties if projects are not completed by specified completion date milestones. Such penalties, if incurred, could have a significant impact on our profitability under these contracts.

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 Alberta oil sands and natural gas production. The operations of these companies, including the mining operations in the oil sands, are subject to or impacted by a wide array of regulations in the jurisdictions where they operate, including those directly impacting mining activities and those indirectly affecting their businesses, such as applicable environmental laws. As a result of changes in regulations and laws relating to the energy production industry including the operation of mines, our customers’ operations could be disrupted or curtailed by governmental authorities. The high cost of compliance with applicable regulations may induce 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 in and around sensitive environmental areas.

Our operations are subject to numerous environmental protection laws and regulations that are complex and stringent. Contracts with our customers require us to operate in compliance with these laws and regulations. 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 non-compliance 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 provide for joint and several strict liability for remediation of releases of hazardous substances, rendering a person liable for environmental damage, without regard to negligence or fault on the part of such person. In addition to potential liabilities that may be incurred in satisfying these requirements, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances. These laws and regulations may expose us to liability arising out of the conduct of operations or conditions caused by others, or for our acts which were in compliance with all applicable laws at the time these acts were performed.

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 upon which fuel may have been spilled, or hydrocarbons or other wastes which may have been disposed of or released. 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, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of hazardous substances into the environment. Under such laws, we could be required to remove or remediate previously disposed wastes and clean up contaminated property.

We are dependent on our ability to lease equipment.

A portion of our equipment fleet is currently leased from third parties. Further, we anticipate leasing substantial amounts of equipment to perform the work on contracts for which we have been engaged in the upcoming year, particularly, the overburden removal contract with CNRL.

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Other projects on which we are engaged in the future may require us to lease additional equipment. If equipment lessors are unable or unwilling to provide us with the equipment we need to perform our work, our results of operations will be materially adversely affected.

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

We install deep foundations in congested areas and provide construction management services for significant projects. Notwithstanding the fact that we will generally 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. If we do not successfully integrate acquisitions, we may not realize anticipated operating advantages and cost savings. The integration of companies that have previously operated separately involves a number of risks, including:

• demands on management related to the increase in our size after an acquisition;

• the diversion of our management’s attention from the management of daily operations;

• difficulties in implementing or unanticipated costs of accounting, estimating, reporting and other systems;

• difficulties in the assimilation and retention of employees; and

• potential adverse effects on operating results.

We may not be able to maintain the levels of operating efficiency that acquired companies will have achieved or might achieve separately. Successful integration of each of their 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 after these acquisitions which would harm our financial condition and results of operations.

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

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

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

We have a significant amount of debt outstanding and have significant debt service requirements. As of March 31, 2005, we had outstanding $362.1 million of consolidated debt, $120.2 million of which, including capital leases, was secured debt.

Our high level of debt could have important consequences, such as:

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

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• limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make payments on our debt;

• limiting our ability to obtain bonding which is required by some of our customers;

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

• increasing our vulnerability to adverse economic and industry conditions; and

• increasing our vulnerability to increases in interest rates because borrowings under our new revolving credit facility are subject to variable interest rates.

Our ability to satisfy our debt obligations will depend upon, among other things, our future operating performance and our ability to refinance debt when necessary. Each of these factors is to a large extent dependent on economic, financial, competitive and other factors beyond our control. If, in the future, we cannot generate sufficient cash from operations to meet our obligations, we will need to refinance some or all of our debt, obtain additional financing or sell assets or we would be unable to generate cash flow, or obtain funding, sufficient to satisfy our debt service requirements.

Restrictive covenants in our debt agreements may restrict the manner in which we can operate our business.

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

• incur or guarantee additional debt, issue disqualified capital stock or enter into sale and leaseback transactions;

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

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

• issue stock of subsidiaries;

• make certain investments or acquisitions;

• create liens on our assets to secure debt;

• enter into transactions with affiliates;

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

• transfer or sell assets, including capital stock of our subsidiaries.

Our new credit facility and its implications are discussed under “Sources of Liquidity”.

If we fail to comply with these covenants, we would be in default under our new revolving credit facility and the indentures governing our new 9% senior secured notes and our 8¾% senior notes due 2011. The principal and accrued interest on the notes and our other outstanding indebtedness may become due and payable.

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. Our new revolving credit facility also requires us, and our future credit facilities 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. The breach of any of these covenants could result in a default under our new revolving credit facility or any future credit facilities. Upon the occurrence of an event of default under our new revolving credit facility or future credit facilities, the lenders could elect to declare all amounts outstanding under such credit facilities, including accrued interest or other obligations, to be immediately due and payable. If amounts outstanding under such credit facilities were to be accelerated, our assets may not be sufficient to repay in full that indebtedness and our other indebtedness.

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

Our ability to generate net cash flow provided by operating activities and to make scheduled payments on our indebtedness will depend on our future financial performance. Our future performance will be affected 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, or other events beyond our control 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 effect any of these alternative strategies on satisfactory terms, if at all, or they may not yield sufficient funds to make required payments on our indebtedness

Currency rate fluctuations could adversely affect our ability to repay our new 9% senior secured notes and to borrow under the new revolving credit facility.

Substantially all of our revenues and costs are incurred in Canadian dollars. However, the obligation represented by our 9% senior secured notes is denominated in U.S. dollars. If the Canadian dollar loses value against the U.S. dollar while other factors remain constant, our ability to pay interest and principal on these notes may be diminished.

Our 8.75% senior unsecured notes are denominated in U.S. dollars but are economically managed through a cross currency swap and interest rate swaps.

Our ability to borrow under the new revolving credit facility is limited, in part, by the mark-to-market liabilities under our swap agreements. If the Canadian dollar increases in value against the U.S. dollar, the mark-to-market liabilities under the swap agreements will increase, which may adversely affect our liquidity or even cause a default under the new revolving credit facility if the mark-to-market liabilities were to increase to the extent that the amount of outstanding borrowings and letters of credit would exceed the reduced availability under the new revolving credit facility. As discussed under “Item 5.B. Liquidity and Capital Resources—Sources of Liquidity”, this situation has occurred on more than one occasion recently, reducing to zero the amount of available borrowings under the facility. We and the lenders under our revolving credit facility have agreed upon a resolution that reduces, but does not eliminate, the consequences of these currency fluctuations. This is likely to be a continuing issue, and we are working with the lenders to arrive at a more permanent resolution.

ITEM 4: INFORMATION OF THE COMPANY

A. HISTORY AND DEVELOPMENT OF THE COMPANY

North American Energy Partners Inc. was incorporated under the Canada Business Corporations Act on October 17, 2003. On October 31, 2003, NACG Preferred Corp., our corporate parent, and NACG Acquisition Inc., our wholly-owned subsidiary, as the buyers, entered into a purchase and sale agreement with Norama Ltd. and its subsidiary North American Equipment Ltd., as the sellers, and Martin Gouin and Roger Gouin, the ultimate owners of Norama Ltd. On November 26, 2003, pursuant to the purchase and sale agreement, Norama Ltd. sold to NACG Preferred Corp. 30 shares of North American Construction Group Inc. in exchange for $35.0 million of its Series A Preferred Shares and sold the remaining 170 shares of North American Construction Group Inc. to NACG Acquisition Inc. Additionally, North American Equipment Ltd., a wholly-owned subsidiary of Norama Ltd., sold to NACG Acquisition Inc. substantially all of the assets of North American Equipment Ltd. in exchange for $175.0 million in cash. The total consideration paid by NACG Preferred Corp. and NACG Acquisition Inc. to the sellers was approximately $401 million, net of cash received and including the impact of certain post-closing adjustments. The sellers utilized a portion of the proceeds to repay existing indebtedness of Norama Ltd. and for the buyout of various existing equipment leases upon closing.

Our head office is located at Zone 3, Acheson Industrial Area, 2 – 53016 Hwy 60, Acheson,

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Alberta, T7X 5A7. Our telephone and facsimile numbers are (780) 960-7171 and (780) 960-7103, respectively. As of March 31, 2005, our authorized capital consisted of an unlimited number of common shares, of which 100 were issued and outstanding. Subsequent to March 31, 2005, we amended our Articles of Incorporation to provide for an unlimited amount of Series A and B Preferred Shares. On May 19, 2005, we issued $1.0 million and $7.5 million respectively of Series A and B Preferred Shares. This is further discussed in “Sources of Liquidity.”

B. BUSINESS OVERVIEW

General

We are one of the largest providers of mining and site preparation, piling, and pipeline installation services in western Canada in terms of revenue. We provide our services primarily to major oil and natural gas, petrochemical, and other natural resource companies operating in this geographic region. In serving our customers, we operate over 475 pieces of heavy construction equipment and over 600 support vehicles, and we have developed expertise operating in the difficult working conditions created by the climate and terrain of the Alberta oil sands and other areas of western Canada. Our work on private sector oil sands and pipeline installation projects results from focusing on our asset deployment on the more technically difficult and profitable revenue opportunities rather than traditional public sector construction activity. Our services consist of:

• surface mining for oil sands and other natural resources; overburden removal; hauling sand and gravel; supplying labor and equipment to support customers’ mining operations; construction of infrastructure associated with mining operations and reclamation activities; clearing, stripping, excavating, and grading for mining operations and other general construction projects; and underground utility installation for plant, refinery, and commercial building construction;

• installation of all types of driven and drilled piles, caissons, and earth retention and stabilization systems for commercial buildings, industrial projects, and infrastructure projects; and

• installation of transmission and distribution pipe made of steel, plastic, and fiberglass materials in sizes up to, and including, 52 inches in diameter for oil and natural gas transmission.

For the fiscal year ended March 31, 2005, we had revenue of $357.3 million.

We generate approximately 69% of our revenue from energy producers in the Alberta oil sands by providing reliable mining and site preparation and piling services. The Alberta oil sands are spread across 140,800 square kilometers, or 54,363 square miles, of remote landscape in the northeastern portion of the province of Alberta. Most of the oil sands are buried under sand, gravel, silts and clay, collectively called overburden, and in some places up to 16 meters of muskeg. According to Alberta Energy and Utilities Board, or AEUB, there are approximately 174 billion barrels of economically recoverably oil in the sands, which makes the Alberta oil sands proved reserves second only to those of Saudi Arabia, the largest oil producing country in the world. Alberta Economic Development, or AED, estimates that from 1996 to 2003, approximately $28 billion was invested in the Alberta oil sands. From 2004 to 2013, AED projects that approximately $75 billion will be spent to sustain and expand existing oil sands projects and develop new projects.

We have long-term, stable relationships with our customers, some of whom we have been serving for over 30 years. We believe we are the principal provider of mining and site preparation and piling services in the Alberta oil sands to many major operators in the area, including Syncrude Canada Ltd., our largest customer and the largest producer of bitumen in the oil sands. In addition, our joint venture, Noramac, has entered into a 10-year overburden removal contract with the newest oil sands operator, CNRL. We also provide pipeline installation and piling services in western Canada to EnCana Corporation.

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Restatement

In preparing the financial statements for the fiscal year ended March 31, 2005, the Company reviewed the accounting treatment of the Company’s derivative financial instruments and has concluded that there have been technical deficiencies in the hedge documentation relating to the cross-currency swap and interest rate swap contracts used to manage its foreign exchange risk exposure related to the U.S. $ denominated 8 ¾ % senior notes since the inception of the derivative financial contracts on November 26, 2003, which deficiencies could not be corrected retroactively. Therefore, the Company has determined that it is necessary to restate all reported periods after November 26, 2003 to eliminate the impact of hedge accounting. This was accomplished by recognizing the foreign exchange gain or loss relating the senior notes each period and recording the derivative financial instruments at fair value and the realized and unrealized gains and losses in the derivative instruments each period through the Consolidated Statement of Operations, along with the associated future income tax effects.

The resulting accounting does not impact our risk management activities and has no impact on the timing or amount of cash flows related to our 8 ¾ % senior notes or swap agreements. It does not affect our ability to make required payments on our outstanding debt obligations. Finally, our economic risk measurement strategies have not required amendment.

See Note 3 to the financial statements included at Item 17 for a detailed summary of the impact of the restatements on our Consolidated Statements of Operations and Cash Flows and Consolidated Balance Sheets.

Our Operations

We provide our services in three interrelated yet distinct business units: mining and site preparation, piling, and pipeline. Over the past 50 years, we have developed an expertise operating in the difficult working conditions created by the climate and terrain of western Canada. We provide these services primarily for our oil and gas and other natural resource customers.

The chart below shows the revenues generated by each operating segment for the fiscal years ended March 31, 2001 through March 31, 2005:

	Predecessor
	Year Ended March 31,
	2001				2002				2003				2004(a)				2005
	(dollars in thousands)
Mining and Site Preparation	$	153,152	61.9	%	$	186,141	74.6	%	$	245,235	71.3	%	$	235,772	62.4	%	$	264,835	74.1	%
Piling		36,709	14.9			35,132	14.1			61,006	17.7			48,982	12.9			61,006	17.1
Pipeline		57,406	23.2			28,078	11.3			37,945	11.0			93,509	24.7			31,482	8.8
Total	$	247,267	100.0	%	$	249,351	100.0	%	$	344,186	100.0	%	$	378,263	100.0	%	$	357,323	100.0	%

(a) The historical statement of operations and other financial data for the year ended March 31, 2004 have been derived from the historical financial statements of Norama Ltd. For the period from April 1, 2003 to November 25, 2003, and the historical financial statements of North American Energy Partners Inc. for the period from November 26, 2003 to March 31, 2004.

Mining and site preparation

Our mining and site preparation segment encompasses a wide variety of services. Our contract mining business represents an outsourcing of the equipment and labor component of the oil and gas and other natural resources mining business. Our site preparation services include clearing, stripping, excavating, and grading for mining operations and other general construction projects, as well as underground utility installation for plant, refinery, and commercial building construction. This business utilizes the vast majority of our equipment fleet and employs over 800 people. The majority of the employees and equipment associated with this business unit are located in the Alberta oil sands area.

For the fiscal year ended March 31, 2005, revenues from this segment accounted for 74% of our total revenues.

Many Alberta oil sands and natural resource mining companies utilize contract services for mine site operations in order to focus their resources on exploration and property development. Our mining services consist of overburden removal; the hauling of sand and gravel; mining of the ore body and delivery of the ore to the crushing facility; supply of labor and equipment to support the owners’ mining operations; construction of infrastructure associated with mining operations; and reclamation activities, which include contouring of waste dumps and placement of secondary materials and muskeg. The major producers outsource mine site operations to contractors such as our company to allow them to benefit from a variety of cost efficiencies that we can provide. We believe mining contractors typically have wage rates lower than those of the mining company and more flexible operating arrangements with personnel allowing for improved uptime and performance. We believe we are one of the principal outsourced mining service providers in the Alberta oil sands because of our ability to operate efficiently and profitably in some of the most challenging mine sites in western Canada.

Oil sands operators use our site preparation services to prepare their leased properties for the construction of the mining infrastructure, including extraction plants and upgrading facilities, and for the eventual mining of the oil sands ore located on their properties. Outside of the Alberta oil sands, our site preparation services are used to assist in the construction of roads, natural resource mines, plants, refineries, commercial buildings, dams and irrigation systems. In order to successfully provide these types of services in the Alberta oil sands, our highly skilled operators are required to use heavy equipment to transform barren terrain and difficult soil or rock conditions into a stable environment for site development. Our extensive fleet of equipment is

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used for clearing the earth of vegetation and removing topsoil that is not usable as a stable subgrade and site grading, which includes grading, leveling and compacting the site to provide a solid foundation for transportation or building. We also provide utility pipe installation for the private and public sectors in western Canada. We are experienced in working with piping materials such as HDPE, concrete, PVC and steel. This work involves similar methods as those used for field, transmission and distribution pipelines in the oil and gas industry, but is generally more intricate and time consuming as the work is typically performed in existing plants with numerous tie-ins to live systems.

Piling

In providing piling services, we currently operate a variety of crawler-mounted drill rigs, a fleet of 25 to 100-ton capacity piling cranes, and pile driving hammers of all types from our Edmonton, Calgary, Regina, Vancouver, and Fort McMurray locations. Piles and caissons are deep foundation systems that extend up to 30 meters below a structure. Piles are long narrow shafts that distribute a load from a supported structure (such as a building or bridge) throughout the underlying soil mass and are necessary whenever the available footing area beneath a structure is insufficient to support the load above it. The foundation chosen for any particular structure depends on the strength of the rock or soil, magnitude of structural loads, and depth of groundwater level.

Our capabilities include the installation of all types of driven and drilled piles, caissons and earth retention and stabilization systems for commercial buildings; private industrial projects, such as plants and refineries; and infrastructure projects, such as bridges. Our piling business employs approximately 100 people. Oil and gas companies developing the oil sands and related infrastructure represent two-thirds of our piling clients. The remaining one-third of our piling clients are primarily commercial construction builders operating in the Edmonton, Calgary, Regina and Vancouver areas.

For the fiscal year ended March 31, 2005, revenues from this segment accounted for 17% of our total revenues.

Pipeline

We install field, transmission, and distribution pipe made of steel, plastic and fiberglass materials in all sizes up to and including 52 inches in diameter. We employ our fleet of construction equipment and skilled technical operators to build and test the pipelines for the delivery of oil and natural gas from the producing field to the consumer. Our pipeline teams have expertise in hand welding selected grade pipe and in operating in the harsh conditions of remote regions in western and northern Canada.

For the fiscal years ended March 31, 2005, 2004, 2003, and 2002, over 99% of our revenues and profitability in our pipeline business resulted from work performed for EnCana. For the fiscal year ended March 31, 2001, services provided to EnCana accounted for approximately 72% of our pipeline revenue, with the remainder generated by services provided to TransCanada Pipelines Limited. Recently, EnCana has significantly reduced its regional development program, resulting in a significant reduction in our pipeline segment revenues. Despite our limited client base in this segment over the past four years, we believe there are significant opportunities to increase our market share by capitalizing on the projected growth in the natural gas industry in western Canada.

For the fiscal year ended March 31, 2005, revenues from this segment accounted for 9% of our total revenues.

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Our Markets

The western Canadian markets that we serve are primarily related to the energy industry and have experienced substantial growth in recent years. We provide our services to three primary markets: the Alberta oil sands market, the conventional oil and gas and minerals mining services market, and the commercial and public construction services market.

Alberta oil sands

In serving the Alberta oil sands market, we currently operate approximately 275 pieces of heavy equipment and employ approximately 750 people. Our customers typically require our services in three separate phases of the construction and operation of their oil sands mines. In the pre-operation phase, as they construct the initial mining infrastructure including the extraction and related upgrading facilities, our customers will engage us to provide site preparation and piling services. We believe that approximately 10% to 20% of this work is available to independent service providers such as us. When the mines become operational, some customers choose to outsource a portion of the recurring mining and site preparation services. We believe the operators on average outsource approximately 20% to 25% of these services to independent service providers. As the mine capacity is increased through the expansion and modernization of the related infrastructure, the operators will again engage third-party service providers to perform additional mining and site preparation and piling services.

Alberta oil sands market summary: The Alberta oil sands are spread across 140,800 square kilometers, or 54,363 square miles, of remote landscape in the northeastern portion of the province of Alberta. Most of the Alberta oil sands are buried under sand, gravel, silt and clay, collectively called overburden, and in some places up to 16 meters of muskeg. The Alberta oil sands themselves lie in a band, often 50 meters thick, below the overburden and above a layer of limestone bedrock.

The Alberta oil sands are developed primarily through the two techniques of open pit surface mining and in-situ, or in-place, production. Our mining and site preparation revenue is primarily derived from projects which utilize the open pit surface mining technique. In open pit surface mining, Alberta oil sands operators, such as Syncrude, Suncor, Albian, and CNRL, expose the oil sands by removing the muskeg and overburden. The muskeg is saved for reclamation while the overburden is used for mine and plant site development or to build dykes for tailings ponds required as part of the mining process or placed in a waste dump. Trucks, shovels and other heavy equipment remove the oil sands and take it to the nearby extraction and upgrading plants for processing into a high-quality, light, sweet synthetic crude oil. The extraction process removes the sand through a process of adding, among other things, hot water and agitation. The result is the bitumen. Recovered bitumen that is clean and diluted can be marketed as a conventional crude oil product. To date, the mining developments have combined the raw bitumen recovery with upgrading processes to produce an upgraded light oil (synthetic), which is marketed as an equivalent to light sweet crude oil. Eventually, as mining operations move into new areas, earlier parts of the old mine have to be reclaimed. Reclamation, which is a part of mining, is intended to return the mined area to a natural state, which can be productive for agriculture. Approximately 64% of oil sands production is currently derived by open pit mining. The remaining 36% of current oil sands production is developed through in-situ production. The in-situ technique is typically utilized when oil sands deposits lie 80 meters or more below the ground surface. Steam is used to heat the bitumen, separating it from the sand. Once separated, it can be pumped to the surface, where it is combined with a condensate to make it transportable to refineries suited to heavier crude feedstocks. In order to operate the in-situ process, the operators rely on vast quantities of steam which is produced by using natural gas as a fuel source. As a result, fluctuations in the prices of natural gas can have a significant impact on operating costs.

According to CAPP, there are approximately 6.9 billion barrels of proved reserves at currently producing oil sands properties. According to AEUB, oil sands production is currently

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approximately one million barrels per day, and accounts for approximately 35% of total Canadian oil production. By 2012, CAPP estimates that oil sands production will be nearly 2.5 times 2003 production levels. According to AED, from 1996 through 2003, an estimated $28 billion was invested in the Alberta oil sands, either to sustain and expand existing projects or develop new projects. From 2004 to 2013, based on a compilation of announced projects, approximately $75 billion is projected to be spent sustaining and expanding existing projects as well as developing new projects. Of this projected spending, we estimate that approximately 10% to 20% will relate to services we perform and upon which we may bid, though there is no assurance that we will be successful in obtaining any of this work.

The substantial investment in the development of the Alberta oil sands can be attributed to low finding and development costs, high recovery rates, and long reserve lives as compared to conventional oil and gas deposits. Since Alberta oil sands reserves are not trapped in wells deep underground, the reserves are relatively accessible and their size and quality can be readily confirmed. Additionally, oil sands mining projects can experience resource recovery rates of greater than 90%. The typical reserve decline curves do not apply as oil sands reserves can be developed for decades. The long reserve lives in the oil sands result in reduced commodity price volatility risk to producers as they are able to sell their production over a long period of time.

Given the inherent advantages to oil sands production, successful development of the Alberta oil sands will be dependent on the following: (i) additional advances in mining technologies, (ii) increasing demand for crude oil and natural gas in the United States, and (iii) supportive government regulation in the form of competitive royalty and fiscal regimes.

Historically, high costs prevented the development of additional Alberta oil sands mining projects beyond the operations of Syncrude and Suncor. However, much of the recent rapid increase in the development of the oil sands is attributable to technological advances in mining techniques. For example, a National Energy Board publication estimates operating costs to have been US$11 to US$14 per barrel in 2000 and projects further reductions to US$10 per barrel in 2005. At these levels, we understand that operating costs in the oil sands are 2.5 to 3.0 times higher than the average operating costs experienced in conventional oil production. However, lower finding and development costs partially offset the higher operating costs when compared to conventional oil production. The most significant technological advancements were a change in mining technique to truck and shovel operations from the dragline/bucket method and the development of hydrotransport which has made the separation of the sand and bitumen easier. As a result, extraction plants are now located at satellite mines.

Over the long-term, we expect development of the Alberta oil sands to benefit from increases in U.S. and Canadian oil consumption. According to the U.S. Energy Information Association, or EIA, U.S. consumption of petroleum is expected to increase by 1.5% annually between 2003 and 2025. Over that same time period, net imports as a percentage of supply are expected to increase from 56.2% in 2003 to 68.4% in 2025. Canada already ranks as the largest foreign supplier of oil to the United States and its position as a primary supplier is expected to continue, according to EIA. Additionally, due to unstable political circumstances surrounding several major U.S. foreign oil suppliers, the United States may benefit from a more secure, reliable source of oil in the future. The Alberta oil sands currently account for approximately 35% of total Canadian crude output. By 2005, sales of synthetic crude oil and bitumen are expected to account for approximately 50% of Canadian crude oil output. Therefore, Alberta oil sands production is expected to capture an increasing share of a growing Canadian market.

Continued government support of the Alberta oil sands will be important to the future development of the industry. The Alberta government, as owner of the oil sands resources, directly influences the development of Alberta oil sands projects primarily through its control of the regulatory approval process and the royalty requirements it places on the oil sands operators. The federal Canadian government impacts oil sands projects through taxation and its support of the Canadian oil industry in the geopolitical arena (e.g., the implementation of the Kyoto Accord).

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Historically, regulatory approval has not been a significant impediment to Alberta oil sands project development. Typically, negotiation is required with various concerned parties, but a satisfactory solution is generally achievable. A new royalty regime was designed to accelerate investment in the oil sands by providing royalty visibility to operators while offering a fair return to the resource owners. That regime, known as the generic royalty regime, was adopted by the Government of Alberta in 1997 and applies a consistent royalty standard to all future oil sands projects. Prior to the implementation of the generic royalty regime, royalty arrangements were negotiated on a project-by-project basis. Under the generic royalty regime, all new projects and expansions of existing projects will essentially pay royalties according to the following schedule:

• in the pre-payout period, or before the project has recovered all its project costs plus a return allowance, the applicable royalty is 1% of gross revenue from project sales;

• in the past-payout period, or after the project has recovered all its project costs plus a return allowance, the applicable royalty is the greater of 25% of project net revenue or 1% of gross revenue;

• in the year incurred, all cash costs (operating and capital) are 100% deductible; and

• the return allowance is set at the Government of Canada Long Term Bond Rate.

This royalty regime provides an economic incentive for oil sands producers to continue to invest capital and thereby benefit from the tax incentive structure.

Conventional oil and gas and minerals mining services

We provide pipeline installation to natural gas producers and transporters, as well as mining and site preparation and piling services to natural resources mining companies in western Canada. In serving this market, we currently operate 100 pieces of equipment and employ approximately 250 people.

We believe there are many opportunities to grow our revenue base in this market. The increase in demand for natural gas has prompted the industry to announce plans to expand existing pipelines and increase plant-processing capacity. In addition, the proliferation of diamond mines and the continued expansion of other mineral and metal mines in western and northern Canada has lead to numerous site preparation, piling, and contract mining opportunities for independent service providers such as ourselves.

Natural gas industry summary: Canada is one of the world’s largest producers of natural gas. Like oil, natural gas is found in sedimentary rock. Raw material gas flowing out of the ground must be processed before it can be injected into long-distance pipeline systems or used by consumers. Generally, producers in western Canada have contractors build the gathering pipelines needed to move raw gas from wells to processing plants. After processing, marketable gas is delivered by producers to distributors through high-pressure steel pipeline systems.

Canada produces 6.3 trillion cubic feet of natural gas annually. The main gas producing area in Canada is the southern portion of the Western Canadian Sedimentary Basin, with about 80% of gas production coming from Alberta. The Mackenzie Valley Pipeline, a large Canadian pipeline project, has been planned to transport natural gas from the Beaufort Sea to the Fort McMurray area, southern Alberta and also into the United States. For this project, several leading energy companies previously announced their intention to jointly construct the pipeline. In October 2004, the companies applied for regulatory approvals for the $7 billion project. We anticipate participating in this and other expansion projects.

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Commercial and public construction services

We provide site preparation and piling services to commercial construction companies operating in western Canada, specifically in the Edmonton, Calgary, Regina, and Vancouver areas. In serving this market, we currently operate over 25 pieces of equipment and employ approximately 75 people. Over the past 10 years, many commercial construction companies in these areas have consistently selected us to provide site preparation and piling services in connection with the construction of commercial buildings, private industrial projects such as plants and refineries, and infrastructure projects such as bridges. In bidding for projects in these markets, we are willing to accept the role of general contractor or subcontractor depending on the nature of the project.

We believe there will be opportunities to expand our revenue base in our existing locations, as well as establish a presence in other areas of western Canada. The continued strength of the western Canadian economy has led to the planned commercial development of many urban centers in western Canada and to the improvement of public facilities and infrastructure. We are well-positioned to profit from these opportunities.

Western Canada, consisting of Manitoba, Saskatchewan, Alberta, British Columbia, the Yukon, the Northwest Territories, and Nunavut, experienced real GDP growth of 2.8% in 2003. By comparison, Alberta’s real GDP grew 2.7% during this period. Alberta’s attractive tax structure provides incentives to both businesses and individuals to locate in the province, and the population has been growing at approximately 1.5 times the national pace. According to the Alberta government, the provincial economy is expected to experience average real GDP growth of 3.2% from 2004 through 2007. The Alberta government has responded to the strain this growth will have on public facilities and infrastructure by allocating approximately $6.5 billion for improvement and expansion projects from 2004 to 2007. We expect to bid on a small percentage of these projects.

In addition to expenditures by provincial and municipal governments, the success of the energy industry in western Canada is leading to the commercial development of many urban centers in northern British Columbia, specifically Fort St. John, and Alberta, particularly Edmonton, Calgary, and Fort McMurray.

Customers

We derive a significant amount of our revenues from a small number of major and independent oil and gas companies. Our customer base includes major integrated energy companies such as Syncrude, Albian, EnCana, Suncor, and CNRL. We also have large mining customers outside of the Alberta oil sands, including Grand Cache Coal. We also perform commercial construction-related services for other customers in the public and private sectors. Our largest customer, Syncrude, accounted for 26%, 52% and 64%, of our revenues for the fiscal years ended March 31, 2005, 2004, and 2003, respectively. Collectively, our largest five customers represented approximately 68%, 91% and 93% of our revenues for the same periods.

Contracts

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

A cost-plus contract is where all work is completed based on actual costs incurred to complete the work. These costs include all labor, equipment, materials, and any subcontractor’s costs. In addition to these direct costs, all site and corporate overheads costs are charged to the job. An agreed upon fee 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.

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A time-and-materials contract involves taking all the components of a cost-plus job and rolling them into rates for the supply of labor and equipment. In this regard, all components of the rates are fixed and we are compensated for each hour of labor and equipment supplied. The risk associated with this type of contract is the estimation of the rates and incurring expenses in excess of a specific component of the agreed upon rate. Therefore, any overrun must come out of the fixed margin included in the rates.

A unit-price contract is utilized in the execution of projects with large repetitive quantities of work to be completed and is commonly utilized for site preparation, mining, and pipeline work. We are compensated for each unit of work we perform. Within the unit price contract, there is an allowance for labor, equipment, materials, and any subcontractor’s costs. Once these costs are calculated, we add in any site and corporate overheads 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 achieving the required production in the execution phases of the project.

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

Going forward, the percentage of our revenue derived from lump sum and unit-price contracts is expected to increase as several of the contracts recently entered into between our joint venture Noramac and CNRL, including the 10-year overburden removal contract and a large site grading contract, are unit price and/or lump sum contracts.

In addition to the contracts listed above, we also use master service agreements for work in the oil and gas sector where the scope of the project is not known and timing is critical to ensure the work gets completed. The master service agreement is a form of a time-and-materials agreement that specifies what rates will be charged for the supply of labor and equipment to undertake work. The agreement does not identify any specific scope or schedule of work. In this regard, the customer’s representative establishes what work is to be done at each location. We use master service agreements with the work we perform for EnCana.

We also complete a substantial amount of work as subcontractors where we are governed by contracts to which we are not a party. These subcontracts vary in type and conditions with respect to the pricing and terms and are governed by one specific prime contract that governs a large project generally. In such cases, the contract with the subcontractors contains more specific provisions regarding a specified aspect of a project.

Seasonality

We have experienced very little seasonality in our operations. While pipeline work has historically been performed more in the winter months when conditions are more favorable to move equipment on the soil, more recently the pipeline segment has been working year round.

Joint Venture

We are a partner in a joint venture called Noramac which was awarded contracts with CNRL to perform initial site preparation services for CNRL’s new oil sands mining project and overburden removal on the site over a ten year period. The joint venture agreement provides that we, along with our partner, will determine on a contract by contract basis what percentage of work each of us will perform. With regard to the site preparation contract, our partner and we jointly determined that we would perform substantially all of the work on that project. In addition, our joint venture partner has indicated that it does not intend to participate in a material way in the

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overburden removal contract. However, by mutual agreement, the partners may elect to alter their respective participation levels in the future on this project. The division of work under any additional contract which are awarded to Noramac will be determined by the partners at the time those contracts are awarded or services are to be provided.

Major Suppliers

We have preferred supplier relationships with the following equipment suppliers: Finning (Canada) (45 years), Wajax Industries Ltd. (20 years), and Brandt Tractor (30 years). Finning (Canada) is a major heavy equipment Caterpillar dealer for Canada. In addition to the supply of new equipment, they are also a major supplier for equipment rentals, parts, and service labor. Wajax Industries Ltd. 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.

Competition

Our business is competitive in each of our markets. Historically, the majority of our new business was awarded to us based on past client relationships without a formal bidding process, in which typically a small number of pre-qualified firms submit bids for the project work. Recently, in order to generate new business with new customers, we have had to participate in formal bidding processes. As new major projects arise in our markets, we expect to have to participate in bidding processes on a meaningful portion of the work available to us on these projects. Factors that impact competition include price, safety, reliability, scale of operations, availability, and quality of service. Most of our clients and potential clients in the oil sands area operate their own heavy mining equipment fleet. However, these operators have consistently contracted for a significant portion of their mining and site preparation operations and other construction services.

Our principal competitors in the mining and site preparation segment include Cross Construction, Klemke Mining Corporation, Ledcor Limited, Neegan Development Corporation Ltd., Peter Kiewit & Sons, Tercon, Sureway, and Thompson Brothers Ltd. The main competition to our deep foundation piling operations comes from Agra Foundations and Double Star. The primary competitors in the pipeline installation business include Ledcor, Washcuk, and Midwest Pipelines. Voice and IGL Industrial Inc. are the major competitors in the underground utilities segment.

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

Law and Regulations and Environmental Matters

Many aspects of our operations are subject to various federal, provincial and local laws and regulations, including, among others, (1) permitting and licensing requirements applicable to contractors in their respective trades, (2) building and similar codes and zoning ordinances, (3) laws and regulations relating to consumer protection, and (4) laws and regulations relating to worker safety and protection of human health. We believe we have all material required permits and licenses to conduct our operations and are in substantial compliance with applicable regulatory requirements relating to our operations. Our failure to comply with the applicable regulations could result in substantial fines or revocation of our operating permits.

Our operations are subject to numerous federal, provincial and municipal environmental laws and regulations, including those governing the release of substances, the remediation of contaminated soil and ground water, vehicle emissions and air and water emissions. These laws and regulations are administered by federal, provincial and municipal authorities, such as Alberta

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Environment, Saskatchewan Environment, the British Columbia Ministry of Water, Land and Air Protection, and other governmental agencies. The technical 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 expose us to the risk of claims with respect to such matters, and there can be no assurance that material costs or liabilities will not be incurred with such claims. For example, some laws can impose strict, joint and several liability on past and present owners or operators of facilities at, from or to which a release of hazardous substances has occurred, on parties who generated hazardous substances that were released at such facilities and on parties who arranged for the transportation of hazardous substances to such facilities. If we were found to be a responsible party under these statutes, we could be held liable for all investigative and remedial costs associated with addressing such contamination, even though the releases were caused by a prior owner or operator or third party. We are not considered an operator because we do not own or lease any of the properties on which we perform services. We are not currently named as a responsible party, or the Canadian equivalent, for any environmental liabilities on any of the properties on which we currently perform or have performed services. However, our leases typically include covenants which obligate us to comply with all applicable environmental regulations and to remediate any environmental damage caused by us to the leased premises. In addition, claims alleging personal injury or property damage may be brought against us as a result of alleged exposure to hazardous substances resulting from our operations. Capital expenditures relating to environmental matters during the fiscal years ended March 31, 2001 through 2005 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 existing environmental laws and regulations to which we are subject. 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 Labor Relations

We currently have over 100 full-time permanent and over 1,000 hourly employees. We also utilize the services of subcontractors in our construction business. Approximately 10% to 15% of the construction work we do is done through subcontractors. Approximately 1,000 employees are members of various unions and work under collective bargaining agreements. The majority of our work is done through employees governed by a collective bargaining agreement with the International Union of Operating Engineers Local 955, the primary term of which was recently extended to October 31, 2009, and under a collective bargaining agreement with the Road Building and Heavy Construction Association and the International Union of Operating Engineers Local 955, the primary term of which expires on February 28, 2007. Additionally, we recently signed a 5-year labour agreement for the mining work at Grand Cache Coal and in Fort McMurray for the oil sands. We are subject to other industry and specialty collective agreements under which we complete work, the primary terms of all of which are currently in effect. We believe that our relationships with all our employees, both union and non-union, are generally excellent. In addition, we have never experienced a strike or lockout.

Capital expenditures

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

	Predecessor
	Year Ended March 31,
	2003		2004(a)		2005
	(thousands)
Mining & Site Preparation	$	16,046	$	2,652	$	16,888
Piling		4,422		447		202
Pipeline		—		1,671		774
Other		2,464		2,956		7,815
Total	$	22,932	$	7,735	$	25,679

(a) The historical statement of operations and other financial data for the year ended March 31, 2004 have been derived from the historical financial statements of Norama Ltd. For the period from April 1, 2003 to November 25, 2003, and the historical financial statements of North American Energy Partners Inc. for the period from November 26, 2003 to March 31, 2004. The balance sheet data as of March 31, 2004 has been derived from the North American Energy Partners Inc. financial statements.

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C. ORGANIZATIONAL STRUCTURE

We are a wholly-owned subsidiary of NACG Preferred Corp., a company without any business operations. NACG Preferred Corp. is a wholly-owned subsidiary of NACG Holdings Inc., our ultimate parent. NACG Holdings Inc. has no business operations. All of the entities in the chart are wholly-owned by their respective parents. The following chart depicts our organizational structure.

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D. PROPERTY, PLANT, AND EQUIPMENT

We operate and maintain over 475 pieces of heavy equipment, including crawlers, graders, loaders, mining trucks, compactors, scrapers, and excavators, as well as over 600 support vehicles, including various service and maintenance vehicles. The equipment is in good condition, normal wear and tear excepted.

The following table sets forth our fleet of heavy equipment as of March 31, 2005:

Category	Manufacturer	Average		Number in Fleet
		Capacity(a)	Horsepower
Mining and Site Preparation:
Articulating trucks	Caterpillar	33 tons	316	21
Mining trucks	Caterpillar, Euclid/Hitachi, Titan	157 tons	1,523	76
Shovels	Hitachi, O&K	46 cubic yards	3,300	4
Excavators	Komatsu, John Deere, Hitachi, Caterpillar	3.9 cubic yards	347	99
Crawler tractors	John Deere, Komatsu, Caterpillar	n/a	319	66
Graders	Caterpillar	n/a	275	19
Scrapers	Caterpillar	n/a	450	14
Loaders	Michigan, Caterpillar, Case, Volvo, Komatsu, John Deere	3.4 cubic yards	185	39
Skidsteer loaders	Case, Melroe, Skidsteer, Gehl, John Deere	1.2 cubic yards	84	34
Packers	Caterpillar, Ingersoll Rand	32,588 lbs	197	19
Pipeline:
Snow cats	Terra Tucker, Bombardier	n/a	175	2
Trenchers	Barber Green	n/a	165	2
Pipelayers	John Deere, Caterpillar	100,118 lbs	246	34
Piling:
Drill rigs	Texoma, Drilling Technique Ltd., Magnum, Soil Mec, Watson 2500	73 ft(b)	220	31
Cranes	P&H, Link-Belt, American, Sumitomo, Bucyrus, Lima	64 tons	196	16
			Total:	476

(a) Capacities are weighted by fleet

(b) Drill depth

We have the largest fleet of off-highway construction and mining trucks in the Fort McMurray area. We operate 97 of these large earthmoving vehicles that have a total hauling capacity of approximately 12,000 tons. Our extensive fleet of off-highway trucks allows us to respond to our customers’ requirements in a cost efficient manner while providing a barrier to entry for our competitors.

We attempt to optimize fleet utilization by pooling equipment for use by all business units. We regularly rent our labor and available assets to many clients who intermittently require additional equipment for their mining activities. Providing rental arrangements to clients maximizes equipment utilization and strengthens client relationships. We view these arrangements as an important first step toward obtaining contract mining work from these clients.

We believe that we are an industry leader in equipment maintenance, repair and refurbishment operations. Our fleet of earthmoving and heavy construction equipment is subjected to a stringent maintenance program. We constantly evaluate the maintenance requirements of our equipment fleet and consistently replace or refurbish key components of each significant piece of equipment to maximize the efficiency of the fleet and ensure that we have the equipment available to meet our customers’ demands. For the fiscal years ended March 31, 2005, 2004 and 2003, we spent $52.1 million, $48.1 million, and $44.1 million, respectively, to maintain our equipment in superior working condition. We possess a relatively young mining equipment fleet with an average life of approximately 6 years. Because a substantial portion of the fleet’s value is based on the age and condition of the major components of each piece of equipment, our rigorous maintenance and refurbishment schedules help maintain the value of our equipment despite its utilization.

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Properties and Facilities

We own and lease a number of buildings and properties for use in our business. Our administrative functions are located at our headquarters near Edmonton, Alberta, which also houses a major equipment maintenance facility. Project management and equipment maintenance are also performed at regional facilities in Calgary and Fort McMurray, Alberta; Vancouver, Fort Nelson, and Prince George, British Columbia; and Regina, Saskatchewan. We occupy office and shop space in British Columbia, Alberta, and Saskatchewan under leases which expire between 2005 and 2009, subject to renewal and termination rights as provided under the particular leases. We also occupy, without charge, some customer-provided lands.

Address	Function	Owned or Leased
Zone 3, Acheson Industrial Area 2 - 53016 Highway 60 Acheson, Alberta	Corporate headquarters and major equipment repair facility	Leased (a)
2289 Alyth Place S.E. Calgary, Alberta	Regional office and equipment repair facility – piling operations	Building Owned Land Leased (b)
Syncrude Mine Site, South End Fort McMurray, Alberta	Regional office and major equipment repair facility – earthworks and mining operations	Building Owned Land Provided
Syncrude Plant Site Fort McMurray, Alberta	Satellite office and minor repair facility – all operations	Building Rented (c) Land Provided
CNRL Plant Site Fort McMurray, Alberta	Site office and maintenance facility (under construction)	Repair Facility Owned Office Rented Land Provided
Grande Cache Goal Company Site Grande Cache, Alberta	Satellite office and equipment repair facility	Maintenance and Office Facility Provided Land Provided
Aurora Mine Site Fort McMurray, Alberta	Satellite office and equipment repair facility – all operations	Repair Facility Owned Office Rented (d) Land Provided
Albian Sands Mine Site Fort McMurray, Alberta	Satellite office and equipment repair facility – all operations	Building Leased (e) Land Provided
9076 River Road Delta, British Columbia	Regional office and equipment repair facility – piling operations	Building Owned Land Leased (f)
2150 Steel Road Prince George, British Columbia	Regional office for all business units	Leased (g)
4307 55th Street Fort Nelson, British Columbia	Satellite office – pipeline operations	Leased (h)
2010 Industrial Drive Sherwood Industrial Park Regina, Saskatchewan	Regional office and equipment repair facility – piling operations	Leased (i)

(a) Lease expires November 30, 2007.

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(b) Lease expires December 31, 2005.

(c) Term of rental through November 30, 2009.

(d) Term of rental through November 30, 2009

(e) Lease expires November 30, 2009.

(f) No formal lease.

(g) Lease expires March 31, 2006.

(h) Lease expires July 10, 2008.

(i) Lease expires March 14, 2008.

Our locations were chosen for their geographic proximity to major customers. This proximity allows us to build on strong relationships with customers and create a presence in the regional marketplace. We believe the owned, leased, and rented properties are sufficient to meet our needs for the foreseeable future.

ITEM 5: OPERATING AND FINANCIAL REVIEW AND PROSPECTS

A. OPERATING RESULTS

Restatement

In preparing the financial statements for the fiscal year ended March 31, 2005, the Company reviewed the accounting treatment of the Company’s derivative financial instruments and has concluded that there have been technical deficiencies in the hedge documentation of the cross-currency swap and interest rate swap contracts used to manage our foreign exchange risk exposure related to the U.S. $ denominated 8 ¾ % senior notes since the inception of the derivative financial contracts on November 26, 2003, which deficiencies could not be corrected retroactively. Therefore, the Company has determined that it is necessary to restate all reported periods after November 26, 2003 to eliminate the impact of hedge accounting. This was accomplished by recognizing the foreign exchange gain or loss relating the senior notes each period and recording the derivative financial instruments at fair value and the realized and unrealized gains and losses in the derivative instruments each period through the Consolidated Statement of Operations, along with the associated future income tax effects.

The resulting accounting does not impact our risk management activities and has no impact on the timing or amount of cash flows related to our 8 ¾ % senior notes or swap agreements. It does not affect our ability to make required payments on our outstanding debt obligations. Finally, our economic risk measurement strategies have not required amendment.

See Note 3 to the consolidated financial statements included at Item 17 for a detailed summary of the impact of the restatements on our Consolidated Statements of Operations and Cash Flows and Consolidated Balance Sheets.

Overview

We provide services primarily to major oil and natural gas, petrochemical, and other natural resource companies operating in western Canada. These services are offered through three operating segments: Mining and Site Preparation, Piling, and Pipeline. The Mining and Site Preparation operating segment is involved in a variety of activities, including: surface mining for oil sands and other natural resources; overburden removal; hauling sand and gravel; supplying labor and equipment to support customers’ mining operations; construction of infrastructure associated with mining operations and reclamation activities; clearing, stripping, excavating, and grading for mining operations and other general construction projects; and underground utility installation for plant, refinery, and commercial building construction. The Piling operating segment installs all types of driven and drilled piles, caissons, and earth retention and stabilization systems for commercial buildings, industrial projects, and infrastructure projects. The Pipeline operating segment installs transmission and distribution pipe made of steel, plastic, and fiberglass materials in sizes up to, and including, 52 inches in diameter for oil and natural gas transmission.

We have been operating for over 50 years and maintain one of the largest independently-owned equipment fleets in western Canada. In serving our customers, we operate over 475 pieces of heavy construction equipment and over 600 support vehicles. Our fleet size provides flexibility in scheduling and completing contract services on a timely basis and allows us to undertake long-term, large-scale projects with major operators in oilsands development and other energy sectors.

The comparative information presented for the fiscal year ended March 31, 2004 is largely the result of operations of Norama Ltd. (“Norama” or the “Predecessor Company”) preceding the acquisition that occurred on November 26, 2003. Included in the comparative information presented for the year ended March 31, 2004 are the results of the Predecessor Company up to November 25, 2003 plus the results of the Successor Company, NAEPI, for the period from November 26, 2003 to March 31, 2004. The information for the periods that occurred after November 25, 2003 may not be directly comparable to the information provided for the pre-acquisition periods as a result of the buy-out of equipment leases and the effect of the revaluation of assets and liabilities to their estimated fair market values in accordance with the application of purchase accounting pursuant to Canadian and United States (“U.S.”) generally accepted accounting principles (“GAAP”).

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Consolidated Financial Results

	Three months ended March 31,										Year ended March 31,
(in millions of Canadian dollars)	2005					2004(a)					2005					2004(a)
						Restated(b)										Restated(b)
Revenue	$	122.8		100.0	%	$	102.4		100.0	%	$	357.3		100.0	%	$	378.3		100.0	%
Project costs		73.3		59.7	%		65.8		64.3	%		240.9		67.4	%		240.3		63.5	%
Equipment costs		19.7		16.0	%		11.6		11.3	%		59.5		16.7	%		69.1		18.3	%
Depreciation		5.8		4.7	%		5.3		5.2	%		20.7		5.8	%		13.2		3.5	%
Gross profit		24.0		19.5	%		19.7		19.2	%		36.2		10.1	%		55.7		14.7	%
General and administrative		7.5		6.1	%		5.0		4.9	%		22.9		6.4	%		13.9		3.7	%
Loss on disposal of property, plant and equipment		—		0.0	%		0.1		0.1	%		0.5		0.1	%		0.1		0.0	%
Amortization of intangible assets		0.4		0.3	%		11.0		10.7	%		3.4		1.0	%		12.9		3.4	%
Operating income		16.1		13.1	%		3.6		3.5	%		9.4		2.6	%		28.8		7.6	%
Interest expense		8.3		6.8	%		7.2		7.0	%		31.1		8.7	%		12.5		3.3	%
Foreign exchange (gain) loss		1.5		1.2	%		3.8		3.7	%		(19.8	)	-5.5	%		(0.7	)	-0.2	%
Other income		(0.1	)	-0.1	%		(0.2	)	-0.2	%		(0.4	)	-0.1	%		(0.6	)	-0.2	%
Realized and unrealized (gain) loss on derivative financial instruments		6.3		5.1	%		(3.3	)	-3.2	%		43.1		12.1	%		12.2		3.2	%
Management fees		—		0.0	%		—		0.0	%		—		0.0	%		41.1		10.9	%
Income (loss) before income taxes	$	0.1		0.1	%	$	(3.9	)	-3.8	%	$	(44.6	)	-12.5	%	$	(35.7	)	-9.4	%

(a) The historical statement of operations and other financial data for the year ended March 31, 2004 have been derived from the historical financial statements of Norama Ltd. For the period from April 1, 2003 to November 25, 2003, and the historical financial statements of North American Energy Partners Inc. for the period from November 26, 2003 to March 31, 2004.

(b) See “Item 4: Business Overview” for description of restatement.

Revenue

Revenue for the three months ended March 31, 2005 increased by $20.4 million (19.9 percent) from the same period in the prior year primarily due to a number of new mining and site preparation contracts, including the large site preparation and underground utility installation project for Canadian Natural Resources Ltd. (“CNRL”) and the mining contract for Grande Cache Coal Corporation, and increased piling activity. Revenue from these new projects in the current period more than offset the declines in revenue primarily due to the substantial completion of the Syncrude UE-1 piling and site grading contracts, as well as the significant decrease in pipeline activity.

Revenue for the fiscal year ended March 31, 2005 decreased by $21.0 million (5.6 percent) from the prior fiscal year. The decrease is primarily due to the reduction in revenue from the Syncrude UE-1 project as the contract nears completion, decrease of revenue from the Syncrude Aurora II and UE-1 piling contracts which were mostly completed in the prior year, and the decreases in revenue from the Albian mining services contract and pipeline division as the customers lowered their demand for our services. Offsetting these decreases was revenue from several new projects in the current year, including the site preparation and underground utility installation project for CNRL, the mining contract for Grande Cache Coal Corporation, and the OPTI/Nexen Long Lake project.

Project costs

Project costs for the three months ended March 31, 2005 increased by $7.5 million (11.4 percent) from the same period in the prior year primarily due to higher activity levels. As a percentage of revenue, project costs were 59.7 percent of revenue in the current period as compared to 64.3 percent in the comparative period in the prior fiscal year. This variance is due to the change in the mix of projects to more equipment-intensive work in the current period than in the comparative period.

Project costs for the fiscal year ended March 31, 2005 increased by $0.6 million (0.2 percent) from the same period in the prior year. As a percentage of revenue, project costs were 67.4 percent of revenue in the current fiscal year as compared to 63.5 percent in the comparative fiscal year. In the current fiscal year, abnormally high costs as a percentage of revenue were incurred on a single large steam assisted gravity drainage site project.

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Equipment costs

Equipment costs for the three months ended March 31, 2005 increased by $8.1 million (69.8 percent) from the same period in the prior fiscal year primarily due to higher operated hours due to increased activity levels and higher leasing costs.

Equipment costs for the fiscal year ended March 31, 2005 decreased by $9.6 million (13.9 percent) from the prior fiscal year. The decrease is primarily due to lower lease and rental expense in the current period as compared to the prior period as a result of the buy-out of most of our leased and rented equipment concurrent with the acquisition on November 26, 2003, partially offset by higher operating hours due to increased activity levels.

Depreciation

Depreciation expense for the three months ended March 31, 2005 increased by $0.5 million (9.4 percent) from the corresponding period in the prior year. The increase was primarily due to the increase in equipment hours related to higher activity levels, as our heavy equipment fleet is depreciated based on operated hours.

Depreciation expense for the fiscal year ended March 31, 2005 increased by $7.5 million (56.8 million) from the prior fiscal year. The increase was primarily due to increased depreciable asset values resulting from the revaluation of assets to their estimated fair market values in accordance with the application of purchase accounting in connection with the acquisition on November 26, 2003. The addition of new equipment resulting from the buy-out of the leased and rented equipment in November 2003 and the year-over-year increase in equipment hours also contributed to the increased depreciation expense for the current fiscal year.

General and administrative expenses

General and administrative expenses for the three months and fiscal year ended March 31, 2005 increased by $2.5 million (50.0 percent) and $9.0 million (64.7 percent), respectively, from the corresponding periods in the prior fiscal year. The increase was primarily attributable to: higher staff levels; increased salaries; higher consulting costs; and increased accounting and audit fees related to our restatement of two quarters of financial statements in the current fiscal year.

Amortization of intangible assets

The amortization of intangible assets in both the current and comparative periods was related to the customer contracts in progress and related relationships, trade names, non-competition agreement, and employee arrangements that were acquired in the acquisition on November 26, 2003. Substantially all of the cost of the intangible assets has been amortized as of March 31, 2005 as the majority of the cost related to customer contracts acquired in the acquisition in November 2003 that were amortized at a rapid rate due to their short-term nature.

Management fees

Management fee expense was $nil for the three months and fiscal year ended March 31, 2005 as compared to $nil and $41.1 million, respectively, for the three months and fiscal year ended March 31, 2004. These fees incurred in the prior fiscal year were charged by Norama Inc., the parent company of Norama, for management services provided to the Predecessor Company. The fees were paid in reference to taxable income. Subsequent to the acquisition on November 26, 2003, no similar management fees have been paid and the agreement with Norama Inc. was terminated.

Interest expense

Interest expense for the three months and fiscal year ended March 31, 2005 increased by $1.1 million (15.3 percent) and $18.6 million (148.8 percent), respectively, from the corresponding periods in the prior fiscal year primarily due to the additional debt (8¾% senior notes and senior secured credit facility).

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Foreign exchange gain

The foreign exchange gains in both the current and prior periods related primarily to the change in the balance owing on the senior notes due to the fluctuation in the Canadian dollar-U.S. dollar exchange rate.

Realized and unrealized (gain) loss on derivative financial instruments

The realized and unrealized gains and losses on the Company’s cross-currency and interest rate swap agreements, which do not qualify for hedge accounting, are $2.7 million and $40.4 million respectively. The change in both the current and prior periods related primarily to the mark-to-market change in the fair value of the derivatives in the period.

Comparative Quarterly Results

A number of factors contribute to variations in our results between periods, such as: weather, customer capital spending on large oilsands and natural gas related projects; our ability to manage our project related business so as to avoid or minimize periods of relative inactivity; and the strength of the western Canadian economy.

																			Predecessor
	Fiscal Year 2005												Fiscal Year 2004
(in millions of Canadian dollars, except equipment hours)	Q4			Q3			Q2			Q1			Q4			Q3(a)			Q2			Q1
				Restated(b)			Restated			Restated			Restated			Restated
Revenue	$	122.8		$	81.0		$	82.7		$	70.9		$	102.4		$	79.9		$	102.3		$	93.7
Gross profit		24.0			(5.6	)		9.8			8.1			19.8			6.5			16.8			12.8
Net loss		(0.1	)		(32.4	)		(4.7	)		(5.1	)		(2.6	)		(20.2	)		(0.5	)		(0.1	)
Equipment hours		241,727			191,555			193,205			137,434			188,557			128,153			200,499			177,939

(a) The historical statement of operations and other financial data for the year ended March 31, 2004 have been derived from the historical financial statements of Norama Ltd. For the period from April 1, 2003 to November 25, 2003, and the historical financial statements of North American Energy Partners Inc. for the period from November 26, 2003 to March 31, 2004.

(b) See “Item 4: Business Overview” for description of restatement.

The higher revenues experienced over the most recent quarter compared to prior periods primarily resulted from new mining and site preparation contracts, including the CNRL site preparation and underground utility installation contracts and Grande Cache Coal mining services contract, and higher activity in the piling division.

Segmented Results of Operations

We report our operations under three operating segments: Mining and Site Preparation, Piling and Pipeline.

Selected Segmented Information

													Predecessor
	Three months ended March 31								Year ended March 31
(in millions of Canadian dollars, except equipment hours)	2005				2004				2005				2004(a)
Revenue by operating segment
Mining and Site Preparation	$	91.6	74.6	%	$	42.6	41.6	%	$	264.8	74.1	%	$	235.8	62.3	%
Piling		17.0	13.8	%		6.5	6.3	%		61.0	17.1	%		49.0	13.0	%
Pipeline		14.2	11.6	%		53.3	52.1	%		31.5	8.8	%		93.5	24.7	%
Total	$	122.8	100.0	%	$	102.4	100.0	%	$	357.3	100.0	%	$	378.3	100.0	%
Profit by operating segment
Mining and Site Preparation	$	11.7	63.6	%	$	7.6	37.8	%	$	11.6	38.9	%	$	25.9	47.4	%
Piling		4.2	22.8	%		1.7	8.5	%		13.3	44.6	%		10.8	19.8	%
Pipeline		2.5	13.6	%		10.8	53.7	%		4.9	16.5	%		17.9	32.8	%
Total	$	18.4	100.0	%	$	20.1	100.0	%	$	29.8	100.0	%	$	54.6	100.0	%

(a) The historical statement of operations and other financial data for the year ended March 31, 2004 have been derived from the historical financial statements of Norama Ltd. For the period from April 1, 2003 to November 25, 2003, and the historical financial statements of North American Energy Partners Inc. for the period from November 26, 2003 to March 31, 2004. The balance sheet data as of March 31, 2004 has been derived from the North American Energy Partners Inc. financial statements.

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										Predecessor
	Three months ended March 31						Year ended March 31
(in millions of Canadian dollars, except equipment hours)	2005			2004			2005			2004(a)
Equipment hours by operating segment
Mining and Site Preparation	212,722	88.0	%	106,790	56.6	%	673,613	88.2	%	511,546	73.6	%
Piling	10,531	4.4	%	6,562	3.5	%	56,460	7.4	%	57,569	8.3	%
Pipeline	18,474	7.6	%	75,205	39.9	%	33,847	4.4	%	126,033	18.1	%
Total	241,727	100.0	%	188,557	100.0	%	763,920	100.0	%	695,148	100.0	%

(a) The historical statement of operations and other financial data for the year ended March 31, 2004 have been derived from the historical financial statements of Norama Ltd. For the period from April 1, 2003 to November 25, 2003, and the historical financial statements of North American Energy Partners Inc. for the period from November 26, 2003 to March 31, 2004.

Mining and Site Preparation

Revenue for the three months ended March 31, 2005 increased by $49.0 million (115.0 percent) from the same period in the prior fiscal year primarily due to activity in the OPTI/Nexen Long Lake contract, the mining services work for Grande Cache Coal Corporation, Syncrude’s South West Quadrant Replacement (“SWQR”) contract and the site preparation and underground utility contract for CNRL. Revenue generated by these projects in the current period more than offset the decrease in revenue from the Syncrude UE-1 project, which is nearing completion.

Revenue for the fiscal year ended March 31, 2005 increased by $29.0 million (12.3 percent) from the prior fiscal year. Contributing to this increase was revenue from new projects such as the underground utility installation contract for CNRL and the mining services contract for Grande Cache Coal, as well as the OPTI / Nexen Long Lake project. Offsetting these increases were decreases in the Syncrude UE-1 project revenue as this contract nears completion, the Syncrude Aurora II as this contract which was completed in the prior year, and the Albian site as they lowered their demand for contract services in the current period.

Operating segment profits for the three months ended March 31, 2005 increased by $4.1 million (53.9 percent) from the comparative period in the prior fiscal year primarily due to the higher volume of work in the period.

Operating segment profit for the fiscal year ended March 31, 2005 decreased by $14.3 million (55.2 percent) from the prior fiscal year. The majority of the decrease in operating segment profit was due to the substantial loss incurred on a single large steam assisted gravity drainage site project in the current year. A number of factors contributed to the loss on the project, including: unfavorable weather conditions hindering productivity; higher than expected costs due to labor shortages; schedule acceleration; and higher than expected costs resulting from an underestimation of the project’s complexity at the time the contract bid was prepared.

Piling

Piling revenue for the three months and fiscal year ended March 31, 2005 increased by $10.5 million (161.5 percent) and $12.0 million (24.5 percent), respectively, from the comparative prior periods primarily due to a higher volume of contracts in the Vancouver, Regina, and Fort McMurray regions due to strong economic activity, as well as the addition of large piling contracts for Flint Infrastructure Services Ltd. and Suncor Energy. This additional work more than offset the loss of revenue generated by the Syncrude UE-1 piling contract in the prior period.

Profit for the Piling operating segment for the three months and fiscal year ended March 31, 2005 increased by $2.5 million (147.1 percent) and $2.5 million (23.1 percent), respectively, from the comparative prior periods, primarily due to increase in volume discussed above.

Pipeline

Pipeline operating segment revenue for the three months and fiscal year ended March 31, 2005 decreased by $39.1 million (73.4 percent) and $62.0 million (66.3 percent), respectively, from the comparative prior periods primarily due to a decrease in work performed for our major pipeline customer in the current periods. The decrease in volume was primarily due to our customer repositioning its efforts in the region and drilling a much lower number of gas wells.

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Profit for this operating segment for the three months and fiscal year ended March 31, 2005 decreased by $8.3 million (76.9 percent) and $13.0 million (72.6 percent), respectively, from the comparative prior period primarily as a result of the lower activity in the current periods.

Consolidated Financial Position

At March 31, 2005, we had net working capital of $41.7 million compared to a net working capital position of $43.5 million at March 31, 2004. Accounts receivable increased by $24.1 million (71.6 percent) and unbilled revenue increased by $13.7 million (49.6 percent) from March 31, 2004 as a result of the increased activity in the current period as compared to the prior period, as well as longer payment terms under present contracts as compared to the payment terms under the contracts active at the end of the prior fiscal year. Accounts payable increased by $29.8 million (101.7 percent) at March 31, 2005 from the balance at the end of the prior fiscal year due to a change in our cash management policy and higher volumes of activity. Also contributing to the decrease was a reduction in cash and cash equivalents at March 31, 2005 as compared to March 31, 2004, which was partially offset by the classification of the entire balance outstanding under the senior secured credit facility as long-term at March 31, 2005, as discussed under “Liquidity and Capital Resources.”

Property, plant and equipment increased by $9.2 million at March 31, 2005 from March 31, 2004 primarily due to the purchase of new equipment required to perform the various contracts awarded over the past nine months, primarily the mining contract for Grande Cache Coal. A portion of the increase also resulted from the expansion of our head office and the ongoing construction of a shop to support the maintenance requirements of our 10-year overburden removal project for CNRL, as well as equipment purchases to replace retired equipment. The increase in property, plant and equipment at March 31, 2005 was partially offset by depreciation expense incurred over the period.

The senior secured credit facility balance increased by $12.8 million at March 31, 2005 from the balance of $48.5 million at March 31, 2004 due to the $20.0 million in advances on the revolving portion of the facility received in the year, net of the scheduled quarterly term debt repayments.

Capital lease obligations, including the current portion, increased by $4.2 million at March 31, 2005 from the balance at March 31, 2004 due to the addition of new leased vehicles to support new projects.

Impairment of Goodwill

In accordance with Canadian Institute of Chartered Accountants’ Handbook Section 3062, “Goodwill and Other Intangible Assets”, we review our goodwill for impairment annually or whenever events or changes in circumstances suggest that the carrying amount may not be recoverable. We are required to test our goodwill for impairment at the reporting unit level and we have determined that we have three reporting units. The test for goodwill impairment is a two-step process:

• Step 1 – We compare the carrying amount of each reporting unit to its fair value. If the carrying amount of a reporting unit exceeds its fair value, we have to perform the second step of the process. If not, no further work is required.

• Step 2 – We compare the implied fair value of each reporting unit’s goodwill to its carrying amount. If the carrying amount of a reporting unit’s goodwill exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess.

We completed this test during the third quarter of the fiscal year ended March 31, 2005 as a result of facts and circumstances that indicated an impairment may have occurred. We were not required to record an impairment loss on goodwill. As part of our annual assessment the test was completed to March 31, 2005 and there was no impairment in goodwill.

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Accounting Policies

Certain accounting policies require management to make significant estimates and assumptions about future events that affect the amounts reported in our financial statements and the accompanying notes. Future events and their effects cannot be determined with absolute certainty. Therefore, the determination of estimates requires the exercise of management’s judgment. Actual results could differ from those estimates, and any such differences may be material to our financial statements.

Revenue recognition

Our contracts with customers fall under the following contract types: time-and-materials, unit-price, cost-plus and lump sum. The contracts are generally less than one year in duration although we do have several long-term contracts.

• Time-and-materials — We provide equipment and labor on an hourly basis to fulfill customer requests. Hourly billing rates are calculated by us through careful consideration of all costs expected to be incurred to provide the requested services and incorporating a mark-up to generate the required profit margin. Revenue is recognized as the labor, equipment, materials, subcontract costs, and other services are supplied to the customer.

• Unit-price — For every unit of work performed, we are paid a specified amount (for example: cubic meters of earth moved; lineal meters of pipe installed; completed piles). The price per unit of work performed is calculated by estimating all of the costs expected to be incurred and adding a mark-up to generate the required profit margin. Revenue related to unit-price contracts is recognized as applicable quantities are completed.

• Cost-plus — Under this contract type, we charge and are reimbursed for all allowable or otherwise defined costs incurred to provide the requested services plus a pre-arranged fixed or variable fee that represents profit. Revenue recognition is based on actual incurred costs to date plus the applicable fee.

• Lump sum — The price for services performed is established at the outset of the contract and is not subject to any adjustment based on the costs incurred or our performance under the scope of the original contract. Changes in scope added by the customer are priced incrementally to the original bid or lump sum. Similar to unit-price contracts, the price charged to the customer for the services performed is calculated by estimating all of the costs expected to be incurred in performing services required by the contract and adding an appropriate amount to the contract price to generate the required profit margin. Revenue on lump sum contracts is recognized using the percentage-of-completion method, calculated using output measures like cubic meters, lineal meters, or completed piles to date. In the absence of reliable output measures, we recognize revenue based upon input measures such as costs incurred to date.

Profit for each type of contract is included in revenue when its realization is reasonably assured. Estimated contract losses are recognized in full when determined. Revenue from change orders, extra work, and variations in the scope of work is recognized after both the costs are incurred or services are provided and realization is assured beyond a reasonable doubt. Revenue from claims is recognized when it is determined to be probable that the claim will result in additional contract revenue and the amount can be reliably estimated. Costs incurred for bidding and obtaining contracts are expensed as incurred.

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The accuracy of our revenue and profit recognition in a given period is almost solely dependent on the accuracy of our estimates of the cost to complete each project. Our cost estimates use a detailed “bottom up” approach. We believe our experience allows us to produce materially reliable estimates; however, our projects can be highly complex, and in almost every case, the profit margin estimates for a project will either increase or decrease to some extent from the amount that was originally estimated at the time of bid. Because we have many projects of varying levels of complexity and size in process at any given time, these changes in estimates can offset each other without materially impacting our profitability; however, large changes in cost estimates, particularly in the bigger, more complex projects, can have a significant effect on profitability.

Factors that can contribute to changes in estimates of contract cost and profitability include, without limitation: site conditions that differ from those assumed in the original bid, to the extent that contract remedies are unavailable; the availability and skill level of workers in the geographic location of the project; the availability and proximity of materials; the accuracy of the original bid and subsequent estimates; inclement weather and timing; and coordination issues inherent in all projects. Until we feel we can accurately estimate job profitability, no profit on the related project is recognized. The foregoing factors, as well as the stage of completion of contracts in process and the mix of contracts at different margins, may cause fluctuations in gross profit between periods, and these fluctuations may be significant.

Property, plant and equipment

The most significant estimate in accounting for property, plant and equipment is the expected useful life of the asset and the expected residual value. Most of our property, plant and equipment has a long life which can exceed 20 years with proper repair work and preventative maintenance. Useful life is measured in operated hours, excluding idle hours, and a depreciation rate is calculated for each type of unit. Depreciation expense is determined each day based on actual operated hours.

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

Repair and maintenance costs

The parts, shop labor, and overhead costs, which are included in equipment costs on our statement of operations, represent the total cost of operating our equipment and maintaining it in an acceptable condition. It is our policy to expense these costs as they are incurred.

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Foreign currency risk

We are subject to currency exchange risk as the 8¾% senior notes and the subsequently issued 9% senior secured notes (see “Sources of Liquidity” below for description of these notes) are denominated in U.S. dollars and all of our revenues and most of our expenses are denominated in Canadian dollars. As noted above, we have entered into cross currency swap and interest rate swap agreements to manage the foreign currency risk on the 8¾% senior notes. The derivative financial instrument consists of three components: a U.S. dollar interest rate swap: a U.S. dollar-Canadian dollar cross currency basis swap; and a Canadian dollar interest rate swap that results in us mitigating our exposure to the variability of cash flows caused by currency fluctuations relating to the U.S. $200 million senior notes. The transaction can be cancelled at the counterparty’s option at any time after December 1, 2007 if the counterparty pays a cancellation premium. The premium is equal to 4.375 percent of the U.S. $200 million if exercised between December 1, 2007 and December 1, 2008; 2.1875 percent if exercised between December 1, 2008 and December 1, 2009; and 0.000 percent if cancelled after December 1, 2009. We have not hedged the foreign currency risk on the 9% senior secured notes. Each $0.01 increase or decrease in the U.S. dollar to Canadian dollar exchange rate would change the interest cost on these notes by $0.05 million per year.

Interest rate risk

We are subject to interest rate risk in connection with our revolving credit facility. The facility bears interest at variable rates based on the Canadian prime rate plus 2 percent or Canadian bankers’ acceptance rate plus 3 percent. Assuming the revolving credit facility is fully drawn at $18.0 million, excluding the $22 million of outstanding letters of credit at September 23, 2005, each 1.0 percent increase or decrease in the applicable interest rate would change the interest cost by $0.2 million per year. In the future, we may enter into interest rate swaps involving the exchange of floating for fixed rate interest payments, to reduce interest rate volatility.

Inflation

The rate of inflation has not had a material impact on our operations as many of our contracts contain a provision for annual escalation. If inflation remains at its recent levels, it is not expected to have a material impact on our operations in the foreseeable future.

B. LIQUIDITY AND CAPITAL RESOURCES

Operating activities

Cash provided by operating activities for the three months ended March 31, 2005 totalled $12.8 million due to the net income in the period. Cash from operating activities for the three months ended March 31, 2004 totalled $15.2 million, with collection of accounts receivable primarily contributing to the results.

Operating activities for the fiscal year ended March 31, 2005 resulted in net usage of cash totalling $4.8 million during the period. This was mainly due to the net loss in the period which was primarily due to the substantial net loss incurred on a single large steam assisted gravity drainage site project, as well as billing delays. Cash provided from operating activities for the fiscal year ended March 31, 2004 totalled $18.0 million, with collection of accounts receivable primarily contributing to the results.

Investing activities

During the three months ended March 31, 2005, we invested $1.2 million in sustaining capital expenditures and $4.0 million in growth capital expenditures compared to $nil and $2.0 million, respectively, during the same period in the prior fiscal year. In addition, we financed new vehicles by way of capital leases totalling $1.7 million during the three months ended March 31, 2005

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compared to $0.3 million during the same period in the prior fiscal year. During the fiscal year ended March 31, 2005, we invested $7.5 million in sustaining capital expenditures and $18.2 million in growth capital expenditures compared to $4.5 million and $3.2 million, respectively, in the prior fiscal year. In addition, we financed new vehicles by way of capital leases totalling $5.4 million during the fiscal year ended March 31, 2005 compared to $3.3 million during the same period in the prior year. We expect our future sustaining capital expenditures to range from $3.0 million to $5.0 million per year. Sustaining capital expenditures are those that are required to maintain our existing fleet of equipment at its optimum average age. Growth capital expenditures relate to equipment additions required to perform increased sizes or numbers of projects.

Cash used in investing activities in the prior fiscal year also included $367.8 million in cash to fund the acquisition on November 26, 2003, which is net of the $4.0 million cash balance acquired and $15.6 million in surplus cash from the acquisition financing.

Financing activities

Financing activities during the fiscal year ended March 31, 2005 primarily related to borrowings under our revolving credit facility, term credit facility scheduled repayments, and repayment of capital lease obligations. Financing activities for the fiscal year ended March 31, 2004 related almost entirely to the acquisition which occurred on November 26, 2003. The cash required to complete the acquisition was financed by $92.5 million in proceeds from the issuance of common shares by NACG Holdings Inc. and the contribution of such proceeds to us, $263.0 million in proceeds from the issuance of the 8¾% senior notes, and $50.0 million from the proceeds of the term credit facility. $18.1 million of the proceeds were used to pay fees and expenses related to the acquisition. The remaining financing activities in the fiscal year related to scheduled repayments of our term credit facility and capital lease obligations.

Liquidity Requirements

Our primary uses of cash are to purchase property, plant and equipment, fulfill debt repayment and interest payment obligations, and finance working capital requirements.

We were required to make monthly interest payments under the $20.0 million revolving portion of our senior secured credit facility, as well as quarterly principal and monthly interest payments under the $41.3 million term portion of our senior secured credit facility. The senior secured credit facility bore interest at a floating rate based upon either the Canadian prime rate plus 2.0% or Canadian bankers’ acceptance rate plus 3.0%. For the three months ended March 31, 2005, the weighted-average interest rate on the senior secured credit facility was 6.75 percent. Additional prepayments were required under certain circumstances, and no new advances were available under the senior secured credit facility at March 31, 2005. The entire amount outstanding under the term credit facility and revolver was repaid subsequent to March 31, 2005 as discussed below.

Our US$200 million of 8¾% senior notes were issued concurrent with the acquisition on November 26, 2003 pursuant to a private placement. On October 5, 2004, we registered substantially identical notes with the United States Securities and Exchange Commission and exchanged them for the notes issued in the private placement. As the registration and exchange were not completed within a specified number of days of the original issuance, as required by a registration rights agreement entered into in connection with the original issuance, we were required to pay additional interest to the holders of the notes in the amount of U.S. $0.2 million on the December 1, 2004 scheduled interest payment. There are no principal payments required on the 8¾% senior notes until maturity.

The foreign currency risk relating to both the principal and interest payments on the 8¾% senior notes has been managed with a cross-currency swap and interest rate swaps which went into effect concurrent with the issuance.

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The interest expense of $12.8 million is payable semi-annually in June and December of each year until the notes mature on December 1, 2011. The swap agreements are economic hedges of the changes in the Canadian dollar—U.S. dollar exchange rate, but they do not meet the criteria to qualify for hedge accounting.

We maintain a significant equipment and vehicle fleet comprised of units with various remaining useful lives. Once units reach the end of their useful lives, it becomes more cost effective to replace them than to maintain them. As a result, we are continually acquiring new equipment to replace retired units and to expand the fleet to meet growth as new contracts are awarded to us. It is important to adequately maintain the large revenue-producing fleet in order to avoid equipment downtime which can impact our revenue stream and inhibit our ability to satisfactorily perform our contracts. We have financed our recent requirements for large pieces of heavy construction equipment through operating leases. In addition, we continue to lease a portion of our motor vehicle fleet and assumed several heavy equipment operating leases from the Predecessor Company.

Our cash requirements during the three months ended March 31, 2005 increased due to our continued growth through recent contract awards. Our cash requirements for the next fiscal year consist of lease obligations, interest payment obligations, and working capital requirements as activity levels are expected to increase.

Sources of Liquidity

Our principal sources of cash during fiscal 2005 were funds from operations and borrowings under our senior secured credit facility. We refer to the revolving credit facility and the term loan collectively as the “senior secured credit facility.” The Credit Agreement dated November 26, 2003, related to the senior secured credit facility (the “Credit Agreement”), imposed certain restrictions on us, including restrictions on our ability to incur indebtedness, pay dividends, make investments, grant liens, sell assets, and engage in certain other activities. In addition, the Credit Agreement required us to maintain certain financial ratios (“covenants”), including: achieving certain levels of earnings before interest, taxes, depreciation and amortization (“EBITDA”); maintaining interest and fixed-charge coverage ratios above a specified minimum level; limiting capital expenditures to specified amounts; and maintaining leverage ratios below a specified maximum level. The indebtedness under the senior secured credit facility, including the contingent obligation under the currency hedging agreement discussed above, was secured by substantially all of our assets and those of our subsidiaries, including accounts receivable and property, plant, and equipment.

As of March 31, 2005, we had $20.0 million in outstanding borrowings under the revolving credit facility and had issued $20.0 million in letters of credit to support bonding requirements and performance guarantees associated with customer contracts. There was $41.3 million outstanding under the term loan portion of the senior secured credit facility at March 31, 2005.

Without several waivers obtained from the lenders and a forbearance agreement which was to expire on July 15, 2005, we would have been in breach of several covenants under the Credit Agreement related to the year ended March 31, 2005. Accounting standards under Emerging Issues Committee Abstract EIC-59, “Long-term Debt with Covenant Violations” typically require the classification of long-term debt as current in circumstances where, at the balance sheet date, the debtor would have been in violation of one or more financial covenants giving the creditor the right to demand repayment absent the modification of financial covenants and the Company expects to violate one or more covenants within one year of the balance sheet date. We would have otherwise reclassified this obligation as a current liability because we could not meet the financial covenants in the next year. However, we repaid all amounts outstanding under the senior secured credit facility subsequent to March 31, 2005 and entered into a new financing agreement, as discussed below. We expect to comply with all of the covenants of the new agreement during the next year. Therefore, we have classified the entire amount outstanding under the senior secured credit facility as long-term at March 31, 2005 as required by accounting

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standards under Emerging Issues Committee Abstract EIC-122 “Balance Sheet Classification of Callable Debt Obligations and Debt Obligations Expected to be Refinanced”. Under this accounting standard, the debt may be classified as long-term if at the balance sheet date an obligation that is otherwise callable by the lender has been subsequently refinanced on a long-term basis and is not expected to violate any covenants within one year of the balance sheet date.

On May 19, 2005, we issued senior secured notes in the amount of US$60.481 million. The notes mature on June 1, 2010 and bear interest at 9% payable semi-annually on June 1 and December 1 of each year. These notes are senior secured obligations and rank senior in right of payment to all existing subordinated debt and rank equally in right of payment to all our existing and future senior debt, including the new revolving credit facility. However, the notes are effectively subordinated to our swap agreements and new revolving credit facility to the extent of the value of the assets securing such debt. The notes are redeemable at our option, up to 35% of the original aggregate principal amount, at any time on or after: June 1, 2008 at 104.50% of the principal amount; June 1, 2009 at 102.25% of the principal amount; and June 1, 2010 at 100.00% of the principal amount; plus, in each case, interest accrued to the redemption date. We have not hedged our exposure to changes in the U.S. to Canadian dollar exchange rate resulting from the issuance of these notes. On July 26, 2005, the senior secured notes issued on May 19, 2005 were exchanged for substantially identical notes registered under the Securities Act.

Also on May 19, 2005, we entered into a new revolving credit facility with a syndicate of lenders that, together with the senior secured notes, replaced our senior secured credit facility. The new revolving facility provides for borrowings of up to $40.0 million, subject to borrowing base limitations, under which revolving loans may be made and letters of credit, up to a limit of $30.0 million, may be issued. The facility bears interest at the Canadian prime rate plus 2% or Canadian bankers’ acceptance rate plus 3%. The indebtedness under the revolving credit facility is secured by substantially all of our assets and those of our subsidiaries, including accounts receivable, inventory and property, plant and equipment, and a pledge of our capital stock and that of our subsidiaries.

In connection with the new revolving credit facility, we were required to amend our existing swap agreements to increase the effective rate of interest on our 8¾% senior notes from 9.765% to 9.889% and issue to one of the counterparties to the swap agreements $1.0 million of mandatorily redeemable preferred shares. These preferred shares are not entitled to accrue or receive dividends and are required to be redeemed on or before December 31, 2011.

Recent strengthening of the Canadian dollar versus the U.S. dollar has caused the mark-to-market liabilities under our swap agreements to increase to the extent that on more than one occasion during the month of September the amount of available borrowings under our new revolving credit facility has been reduced to zero. We and the lenders under the revolving credit facility have agreed upon a resolution that provides us with borrowing capacity and reduces, but does not eliminate, the consequences of these currency fluctuations. This is likely to be a continuing issue, and we are working with the lenders to arrive at a more permanent resolution. However, we currently have sufficient cash on hand to meet our anticipated needs for at least the balance of the fiscal year.

On May 19, 2005 we issued 7,500 mandatorily redeemable preferred shares to the major existing shareholders of NACG Holdings Inc. (the “Sponsors”) for total proceeds of $7.5 million. These shares pay cumulative dividends of 15% per year, which are payable-in-kind so long as the 9% senior secured notes due 2010 and 8¾% senior notes due 2011 are outstanding. The shares are redeemable at our option at any time, and are required to be redeemed on or before December 31, 2011. The redemption amount is the greater of:

a) $15.0 million less the amount, if any, of dividends previously paid in cash;

b) an amount that, when combined with the amount, if any, of dividends previously paid in cash, provides a 40% internal rate of return, compounded annually from the date of issue; and

c) 25% of the fair market value of the equity of the company, and in any event, will not exceed $100 million under the terms of the agreement.

The net proceeds from the issuance of the senior secured notes and the sale of the preferred shares to the Sponsors were used to repay the indebtedness under our senior secured credit facility, to pay related fees and expenses, and for general corporate purposes.

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On April 27, 2005, Moody’s lowered its rating of our 8¾% senior notes to Caa1 from B3 and lowered our long-term corporate rating to B3 from B2. In addition, Moody’s assigned a rating of B3 to the new 9% senior secured notes. On May 19, 2005, Standard & Poor’s lowered its rating of our 8¾% senior notes to CCC+ from B- and our long-term corporate credit rating to B- from B, while assigning a rating of B to our new senior secured notes. The lower credit ratings will have no effect on the interest rates associated with our 8¾% senior notes or 9% senior secured notes.

Stock-Based Compensation

Certain of our directors, officers, employees, and service providers have been granted options to purchase common shares of NACG Holdings Inc., our ultimate parent company, under a stock-based compensation plan. The plan and outstanding balances are disclosed in note 19 to our consolidated financial statements for the year ended March 31, 2005.

C. RESEARCH AND DEVELOPMENT

Not applicable.

D. TREND INFORMATION

Our market place is expected to remain robust in the near term with numerous large projects in the inception and planning stages. The price of both oil and gas continues to be strong and is fueling direct growth in that sector and the supporting infrastructure, primarily in the Province of Alberta where the economy grew by 2.7% in 2004 according to Alberta Economic Development. As well, commodity pricing, particular in coal and diamonds, has added diversity to our potential markets.

E. OFF-BALANCE SHEET ARRANGEMENTS

We have a material investment in a variable interest entity at March 31, 2005. See Note 13(f) to our financial statements at Item 17. We have available undrawn capacity under our revolving credit facility at March 31, 2005. See Note 7 to our financial statements at Item 17.

F. TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

Our principal contractual obligations relate to our senior notes, our senior secured credit facility, and capital and operating leases. The following table summarizes our future contractual obligations, excluding interest payments unless otherwise noted, as of March 31, 2005.

	Payments Due by Period
	Total		2006		2007		2008		2009		2010 and after
	(dollars in millions)
Contractual Obligations:
Long-term debt	$	354.9	$	—	$	—	$	—	$	—	$	354.9
Capital leases (including interest)		7.9		2.0		2.1		2.0		1.4		0.4
Operating leases (a)		31.2		11.5		11.5		7.3		0.6		0.3
Total contractual cash obligations (b)	$	394.0	$	13.5	$	13.6	$	9.3	$	2.0	$	355.6

(a) Includes property leases and leases on forty-two pieces of heavy equipment.

(b) See note 22 to our Financial Statements at Item 17 for changes in contractual obligations subsequent to year end.

ITEM 6: DIRECTORS, SENIOR MANAGEMENT, AND EMPLOYEES

A. DIRECTORS AND SENIOR MANAGEMENT

Unless otherwise indicated below, each of the following directors and executive officers holds the

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-indicated positions with North American Energy Partners Inc., NACG Holdings Inc., and NACG Preferred Corp. Each director is elected for a one-year term or until such person’s successor is duly elected and qualified.

Name	Age	Position
Ronald A. McIntosh	63	Chairman
Gordon Parchewsky	56	Vice Chairman
Rodney J. Ruston	54	President and Chief Executive Officer
William Koehn	43	Vice President, Operations and Chief Operating Officer
Vincent Gallant	47	Vice President, Corporate
Chris Hayman	43	Vice President, Finance
Miles Safranovich	41	Vice President, Contracts and Technical Services
E.J. Antonio III	40	Director
John A. Brussa	48	Director
Jim G. Gardiner	60	Director
Donald R. Getty	72	Director
Martin Gouin	44	Director
John D. Hawkins	41	Director
William C. Oehmig	56	Director
Richard D. Paterson	62	Director
K. Rick Turner	47	Director
Gary K. Wright	60	Director

Ronald A. McIntosh became the Chairman of our Board of Directors on May 20, 2004. Since January 2004, Mr. McIntosh has been Chairman of NAV Energy Trust, a Calgary-based oil and natural gas investment trust. Between October 2002 and January 2004, he was President and Chief Executive Officer of Navigo Energy Inc. and oversaw the conversion of Navigo into NAV Energy Trust and C1 Energy Ltd. From July 2002 to October 2002, Mr. McIntosh managed his personal investments. 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 is also currently a director of C1 Energy Ltd., Advantage Energy Income Trust and Crispin Energy Inc.

Gordon Parchewsky became the Vice Chairman of NACG Holdings Inc. on April 25, 2005. He was one of our Directors from November 5, 2003 to April 25, 2005 and was our President from November 26, 2003 to April 25, 2005. Previously, he was President of the predecessor company, North American Construction Group Inc., a position he had held since 2002. Prior to that, Mr. Parchewsky was Vice President of Operations from 1984 to 2002 and was employed by North American Construction Group Inc. since 1971. Mr. Parchewsky has over 30 years of high-level management experience in the heavy construction industry with North American Construction Group Inc. Mr. Parchewsky has managed numerous civil, industrial, pipeline, and mine related projects throughout his career. He has been a board member for numerous industry associations including the Canadian Construction Association, Western Canada Roadbuilders Association, Alberta Roadbuilders and Heavy Construction Association, and Alberta Chamber of Resources. Mr. Parchewsky graduated in 1971 from the University of Alberta with a Bachelor of Science Degree in Civil Engineering.

Rodney J. Ruston became President and Chief Executive Officer of NAEPI on May 9, 2005. 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. He was a Principal with Ruston Consulting Services Pty. Ltd., a management consultant company providing business advice to the natural resources industry, from September 1999 to June 2000. 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.

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William Koehn became our Vice President, Operations on November 26, 2003 and our Chief Operating Officer on December 8, 2004. Previously, he served as Vice President, Operations for the predecessor company, North American Construction Group Inc., since 2002. Prior to 2002, Mr. Koehn had served as Ft. McMurray Regional Manager since 1997, before which he had served as Project Manager since 1992. Before joining North American Construction Group Inc., he was a Senior Civil Engineer with Quintette Coal Limited. Mr. Koehn joined Quintette in 1986. Mr. Koehn has extensive working knowledge of the oil sands industry and has completed various projects involving oil sands operations, underground piping and piling. He graduated from the University of Alberta in 1983 with a Bachelor of Science Degree in Civil Engineering and has completed his Masters Degree in Construction Engineering and Management. Mr. Koehn has over 19 years of earthworks and mining experience.

Vincent Gallant became our Vice President, Corporate, on June 15, 2005. Previously, he was our Vice President, Finance from November 26, 2003 to June 15, 2005 and served in that same capacity at the predecessor company, North American Construction Group Inc., a position he held since the beginning of 1997. Mr. Gallant has been instrumental in providing financial analysis and reporting, as well as guiding the financing of our growth over the last seven years. Prior to joining North American Construction Group Inc., Mr. Gallant served for three years as Controller of Edmonton Telephones and seven years with Alberta Energy Company Ltd., the last two years as Comptroller. Mr. Gallant graduated from the University of Alberta in 1980 with a Bachelor of Arts Degree, majoring in economics. He has been a Canadian Chartered Accountant since 1983 and worked on the professional staff of Peat, Marwick, Mitchell and Company from 1980 until 1985.

Chris Hayman became our Vice President, Finance on June 15, 2005. Previously, he held the position of Treasurer from January 17, 2005 to June 15, 2005. Prior to joining our company, Mr. Hayman worked for Finning (Canada) from November 1998 to January 14, 2005; from January 2003 to January 2005, Mr. Hayman was the Vice President and Controller, from August 2001 to December 2003 he served as their Controller and he was the Assistant Controller from November 1998 to August 2001. Prior to being with Finning (Canada), Mr. Hayman worked for Enbridge Pipeline for nine years and for Telus Communications for two year. Mr. Hayman graduated from the University of Alberta in 1984 with a Bachelor of Commerce degree majoring in accounting. He has been a Canadian Chartered Accountant since 1987 and worked on the professional staff of Thorne, Ernst and Whinney from 1984 to 1987.

Miles Safranovich became our Vice President, Contracts and Technical Services on June 15, 2005. Previously, he held the position of General Manager, Industrial and Heavy Civil from November 29, 2004 to June 15, 2005. Prior to joining our company, Mr. Safranovich was employed full-time by Voice Construction Ltd. from May 1992 to November 2004, as well as holding various summer positions at the company from 1985 through 1991. From May 2000 to November 2004, Mr. Safranovich was the Operations Manager, from May 1993 to April 2000 he served as Construction Manager, and from May 1992 to April 1993 as well as during the summers of 1990 and 1991 he was a Project Engineer. Mr. Safranovich has two degrees from the University of Alberta, a Bachelor of Science majoring in biology obtained in 1986 and a Bachelor of Science in Civil Engineering, specializing in construction management, obtained in 1992.

E.J. Antonio III became one of our Directors on January 29, 2004. Mr. Antonio joined Perry Capital, a private investment firm, in May 2002 as a Managing Director, the position he holds currently. Perry Capital provides certain services to us pursuant to an advisory services agreement, and an investment entity controlled by Perry is a common shareholder in NACG Holdings Inc. and a preferred shareholder in North American Energy Partners Inc. Mr. Antonio worked in Deutsche Bank’s Corporate Finance and Mergers, Acquisitions and Corporate Advisory Group as an Associate and Senior Associate from 1998 to March 2002 where

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he led transaction teams advising clients in the industrial sector. Prior to 1998, Mr. Antonio spent 13 years with General Motors and Delphi Corp. in various senior operating management and business development capacities in the U.S. and Europe. While working for General Motors, he earned an M.B.A. from the Harvard Business School in 1993, an M.S. in manufacturing systems engineering from The Pennsylvania State University in 1988 and a B.S. in industrial engineering and operations research cum laude from Syracuse University in 1987.

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. Mr. Brussa has been a partner at the firm since 1987 and has worked at the firm since 1981. Mr. Brussa currently serves as a director of a number of natural resource and energy companies, several mutual fund trusts, and non-profit or charitable organizations. Mr. Brussa received his Bachelor of Laws Degree from the University of Windsor.

Jim G. Gardiner became one of our Directors on November 26, 2003. Mr. Gardiner was President of Fording Canadian Coal Trust and Elk Valley Coal Partnership, operators of coal mines, from March 2003 until his retirement in March 2004. From 1993 to March 2003, he was President and Chief Executive Officer of Fording Income Trust and Fording Inc. Mr. Gardiner became a Trustee of the Westshore Terminals Income Fund in June 2004. He is the past Chairman of the Coal Industry Advisory Board of the International Energy Agency, a past member of the Sectoral Advisory Group in International Trade (SAGIT), Energy, Chemical and Plastics Division, the past Chairman of the Coal Association of Canada, and past Deputy Chairman of the World Coal Institute. Mr. Gardiner received a B.S. in civil engineering from the University of Saskatchewan.

Donald R. Getty became one of our Directors on November 26, 2003. Mr. Getty is President and Chief Executive Officer of Sunnybank Investments Ltd., a private investment and consulting firm based in Edmonton, Alberta. Mr. Getty has held this position since December 1992 when he retired as Premier of Alberta. Mr. Getty was the 11th Premier of Alberta since the province was formed in 1905. As Premier of Alberta, Mr. Getty’s government as successful in emphasizing development of non-conventional oil projects and diversifying Alberta’s economy, among other initiatives. Before serving as Premier of Alberta, Mr. Getty had a distinguished career in both the public and private sectors. Mr. Getty graduated from the University of Western Ontario with a degree in Honours Business Administration. He currently serves on the boards of Guyanor Resources, S.A., West Isle Energy Inc. (formerly Mera Petroleum Inc.) and Nationwide Resources Inc. and is a director and vice chairman of Horse Racing Alberta, a non-profit organization. On January 28, 2004, Mr. Getty became Chairman and a director of K.C.P. Innovative Services Inc., and on November 15, 2004, he became Chairman and a director of Canglobe International Inc. In addition, in 1998, Mr. Getty was appointed an officer of the Order of Canada and in 1994 as a member of the Alberta Order of Excellence. In 2003, he received an Honorary Degree of Law from the University of Lethbridge.

Martin Gouin became one of our Directors on November 26, 2003. Mr. Gouin is President of Norama, a holding and management company, a position he has held since April 1, 1996. Mr. Gouin was also President and Chief Executive Officer of North American Construction Group Inc. from 1995 to November 2003. Prior to becoming President and Chief Executive Officer in 1995, Mr. Gouin held numerous positions at North American Construction Group Inc., including Vice-President, Operations. He has 24 years of experience servicing the oil sands industries. He has been a director of numerous companies serving the metals and plastics industries and was president of Cynergy Fireplace International for three years prior to divesting the operation in 1988. Mr. Gouin attended the University of Alberta and majored in economics.

John D. Hawkins became one of our Directors on October 17, 2003. Mr Hawkins has been a Principal with The Sterling Group, L.P., a private equity investment firm, since 1999. The Sterling Group provides certain services to us pursuant to an advisory services agreement, and an investment entity controlled by The Sterling Group is a common shareholder in NACG Holdings Inc. and a preferred shareholder in North American Energy Partners Inc. Mr.

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Hawkins joined Sterling as an Associate in 1992. From 1986 to 1990, he was on the professional staff of Arthur Andersen & Co. Mr. Hawkins currently serves on the board of Exopack Holding Corp. Mr. Hawkins received a B.S.B.A. in Accounting from the University of Tennessee and an M.B.A. with honors from the Owen Graduate School of Management at Vanderbilt University.

William C. Oehmig became the Chairman of our Board of Directors on November 26, 2003 and assumed the role of Director on May 20, 2004. Mr. Oehmig has been a Principal with The Sterling Group, L.P., a private equity investment firm, since 1984, having worked previously in banking, mergers and acquisitions, and as Chief Executive Officer and Chief Financial Officer of several companies. The Sterling Group provides certain services to us pursuant to an advisory services agreement, and an investment entity controlled by The Sterling Group is a common shareholder in NACG Holdings Inc. and a preferred shareholder in North American Energy Partners Inc. In the past, Mr. Oehmig has served as Chairman of Royster Company and PM Holdings Corp. (parent of Purina Mills, Inc.), chaired the executive committee of SDI Holdings, Inc. (parent of Sterling Diagnostic Imaging, Inc.) and Airtron, Inc., and served on the boards of Walter International, an international oil and gas company; Atlantic Coast Airlines, a regional passenger airline; and Rives Carlberg, an advertising firm. He is past Chairman and currently a director of Exopack Holding Corp. and Propex Fabric Holdings Inc. Mr. Oehmig is also Past Chairman of the board of trustees at The Baylor School in Chattanooga, Tennessee. Mr. Oehmig received his B.B.A. in Economics from Transylvania University and his M.B.A. from the Owen Graduate School of Management at Vanderbilt University.

Richard D. Paterson became one of the Directors of North American Energy Partners Inc. on August 18, 2005 and a Director of NACG Holdings Inc. on September 15, 2005. Mr. Paterson is a Managing Director of Genstar Capital, responsible for acquisitions, divestitures and oversight of portfolio companies. Genstar Capital provides certain services to us pursuant to an advisory services agreement, and certain investment entities controlled by Genstar are common shareholders in NACG Holdings Inc. and preferred shareholders in North American Energy Partners Inc. Before founding Genstar Capital, Mr. Paterson served as Senior Vice President and CFO of Genstar Corporation, a $4 billion NYSE company, where he was responsible for finance, tax, information systems and public reporting. He has been active in corporate acquisitions for more than 20 years. Mr. Paterson started his career as an auditor with Coopers & Lybrand in Montreal. He is a Chartered Accountant and earned a Bachelor of Commerce from Concordia University. He serves as Chairman of the Board of New A.C., Inc. He is also a Director INSTALLS Inc., LLC, American Pacific Enterprises, LLC, Propex Fabrics, Inc., Woods Equipment Company and Altra Industrial Motion, Inc.

K. Rick Turner became one of our Directors on November 26, 2003. Mr. Turner has been a Principal of Stephens Group, Inc.’s merchant banking activities since 1990. Stephens Group, Inc. is the parent of Stephens, Inc., an investment banking firm. Stephens provides certain services to us pursuant to an advisory services agreement, and an investment entity controlled by Stephens is a common shareholder in NACG Holdings Inc. and a preferred shareholder in North American Energy Partners Inc. Mr. Turner joined Stephens in 1983. His areas of focus have been oil and gas exploration, natural gas gathering, processing industries and power technology. Prior to joining Stephens in 1983, he was employed by Peat, Marwick, Mitchell and Company. Mr. Turner currently serves as a director of Atlantic Oil Corporation, SmartSignal Corporation, Jebco Seismic LLC and the general partner of Energy Transfer Partners. Mr. Turner earned his Bachelor of Science in Business Administration at the University of Arkansas and is a Certified Public Accountant.

Gary K. Wright became one of our Directors on November 26, 2003. Mr. Wright was President of LNB Energy Advisors, a unit of The Laredo National Bank that provides banking and advisory services to small and mid-sized oil and gas producers, from June 2003 until his retirement in September 2004. Between August 2001 and June 2003 Mr. Wright was an independent consultant to the energy industry. From 1998 to August 2001, Mr. Wright was North American Senior Credit Officer for the Global Oil and Gas Group of Chase Manhattan Bank. From 1992 to 1998, he served as Managing Director and Senior Client Manager in the Southwest. Between 1990 and 1992, Mr. Wright was Manager of the Chemical Bank Worldwide Energy Group. Prior to that he held various positions with Texas Commerce Bank. Mr. Wright currently serves on the board of Penn Virginia Corporation. He holds a B.S. in Petroleum Engineering from Louisiana State University and a Juris Doctor from Loyola School of Law.

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B. COMPENSATION

Director Compensation

Directors of NACG Holdings Inc. and North American Energy Partners Inc. each receive an annual aggregate retainer of $32,500 and a fee of $1,500 for each meeting of the board or any committee of the board that they attend, and are reimbursed for reasonable out-of-pocket expenses incurred in connection with their services pursuant to NACG Holdings Inc.’s policies. Martin Gouin and directors who are also our employees do not receive director compensation.

In addition, our directors have received grants of stock options under NACG Holdings Inc.’s 2004 Share Option Plan. Each director, excluding Martin Gouin and directors who are also our employees, received options to purchase 1,388 NACG Holdings Inc. common shares, with the exception of McIntosh, our Chairman, who received options to acquire 3,500 shares. All the options have an exercise price of $100 per share, vest on a straight-line basis over five year, and expire on November 26, 2013.

Executive Compensation

The following summary compensation table sets forth the total value of compensation earned by our chief executive officer and each of the other four most highly compensated officers as of March 31, 2005, collectively called the named executive officers, for services rendered in all capacities to us for the fiscal years ended March 31, 2005, 2004 and 2003.

Summary Compensation Table

	Annual Compensation									Long-Term Compensation
Name and Principal Position	Fiscal Year	Salary		Bonus			Other Annual Compensation			Securities Underlying Options (a)
Gordon Parchewsky	2005	$	240,000	$	40,000			(c	)	—
President	2004		186,000		1,300,000	(b)		(c	)	6,000	(d)
	2003		144,000		275,000			(c	)	—
William Koehn	2005	$	224,000	$	40,000			(c	)	—
Vice President, Operations and Chief Operating Officer	2004		170,000		1,300,000	(b)		(c	)	5,000
	2003		132,000		275,000			(c	)	—
Vincent Gallant	2005	$	204,000	$	40,000			(c	)	—
Vice President, Finance	2004		162,000		1,250,000	(b)		(c	)	5,000
	2003		126,000		225,000			(c	)	—
William S. Mackenzie(f)	2005	$	219,000	$	3,000		$	27,545(g	)	—
Superintendent	2004		178,099		48,125	(e)		(c	)	500
	2003		147,420		27,500			(c	)	—
Robert Cochrane(f)	2005	$	148,500	$	122,500			(c	)	—
Division Manager, Pipeline	2004		114,000		357,500	(e)		(c	)	2,000
	2003		114,000		90,000			(c	)	—

(a) Consists of options to purchase NACG Holdings Inc. common shares

(b) Includes a $750,000 transaction bonus and a $250,000 performance bonus, both paid by Norama Ltd., upon closing of the acquisition.

(c) The amount of other annual compensation does not exceed the lesser of $50,000 and 10% of the salary and bonus for the fiscal year.

(d) In accordance with Mr. Parchewsky’s revised duties, as discussed, above under “Directors

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and Senior Management”, 3,200 of the options granted in fiscal 2004 were cancelled effective April 25, 2005. Of the remaining 2,800 options, 1,200 vested on November 26, 2004 and the remaining 1,600 will vest ratably on each November 26 of the next four years. All other terms of the stock options are unchanged.

(e) Includes a $200,000 transaction bonus and a performance bonus of $116,500, in the case of Mr. Humphries, and a $200,000 transaction bonus and a $67,500 performance bonus in the case of Mr. Cochrane, all of which was paid by Norama Inc., the parent of Norama Ltd., upon closing of the acquisition.

(f) Messrs. Mackenzie and Cochrane are not executive officers but are included in the summary compensation table pursuant to Item 402(a)(3)(iii) of Regulation S-K.

(g) Consists of employer contributions to a retirement savings plan, pension plan contributions and subsistence payments.

Option Grants in Last Fiscal Year(a)

Name	Number of Securities Underlying Options Granted	% of Total Options Granted to Employees in Fiscal Year		Exercise Price Per Share		Expiration Date	Grant Date Present Value
Gordon Parchewsky	—	0.00	%	$	—	—	$	—
William Koehn	—	0.00	%		—	—		—
Vincent Gallant	—	0.00	%		—	—		—
William S. Mackenzie	—	0.00	%		—	—		—
Robert Cochrane	—	0.00	%		—	—		—

(a) For material terms of the NACG Holdings Inc. 2004 Share Option Plan, see note 19 to our consolidated financial statements included in Item 17.

Aggregated Option Exercises in Last Fiscal Year and Fiscal Year End Option Values

Name	Shares Acquired on Exercise	Value Realized	Number of Securities Underlying Unexercised Options at March 31, 2005 (Exercisable/ Unexercisable)	Value of Unexercised In-the-Money Options at March 31, 2005 (Exercisable/ Unexercisable)
Gordon Parchewsky	—	—	/6,000	/
William Koehn	—	—	/5,000	/
Vincent Gallant	—	—	/5,000	/
William S. Mackenzie	—	—	/   500	/
Robert Cochrane	—	—	/2,000	/

Retirement Benefits for Executive Officers and Directors

For the fiscal year ended March 31, 2005, the total amount we set aside for pension, retirement and similar benefits for our executive officers and directors was $38,327, consisting of employer matching contributions to our executive officers’ Registered Retirement Savings Plan accounts of up to 5% of salary.

Retention Bonus

Norama Inc., the parent of Norama Ltd., will pay to each of Messrs. Parchewsky, Koehn, and Gallant a retention bonus of $750,000 on November 26, 2006, three years after the closing of our acquisition of North American Construction Group Inc., provided they are still employed by us.

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Annual Incentive Plan

NACG Holdings Inc. has established a management incentive plan. The incentive plan is administered by the compensation committee of the board of directors. The plan will establish a bonus pool to be paid to participants if a target level of financial performance is achieved. If our actual financial performance exceeds or falls short of the targeted level of performance, the amount of the pool available to be paid will increase or decrease, respectively. The compensation committee will recommend to the board of directors the total pool, the target financial performance, the participants, and each participant’s share of the potential pool.

Stock Option Plan

NACG Holdings Inc. has adopted the 2004 Share Option Plan. The option plan is administered by the compensation committee of the board of directors. Option grants under the option plan may be made to directors, officers, employees, and service providers selected by the compensation committee. The option plan provides for the discretionary grant of options to purchase common shares. The exercise price of stock options must not be less than the fair market value of common shares on the date of grant, as determined by the committee in its sole discretion. The committee may provide that the options will vest immediately or in increments over a period of time.

Profit Sharing Plan

NACG Holdings Inc. has established a profit sharing plan covering all full-time salaried employees, including executive officers. The profit sharing plan is administered by the compensation committee. Amounts paid under the profit sharing plan will constitute taxable income in the year received and will be based on our financial performance over a period of time to be determined. The compensation committee will recommend to the board of directors for approval, a target level of financial performance to be achieved and an amount to be set aside for profit sharing if the target is met. If financial performance exceeds this minimum level, we may make distributions to employees. The compensation committee may change the amount set aside for profit sharing and the proportion of such amount allocate to an individual employee or group of employees.

President and Chief Executive Officer

We have agreed to the terms of employment of Rodney Ruston, our new President and Chief Executive Officer. The definitive employment agreement provides the following terms. The initial term of Mr. Ruston’s employment is five years, unless earlier terminated. If his employment is terminated by us without cause or if his employment is not renewed at the end of the initial five year term, Mr. Ruston will receive a severance payment equal to his then-annual salary plus the amount of his bonus payment in the year preceding the termination date. The agreement provides for a $600,000 annual salary, to be reviewed annually by the board of directors, plus a grant of options to purchase 20,000 NACG Holdings Inc. common shares, with an exercise price of $100 per share and subject to vesting at the rate of 20% per year. During the term of the agreement, Mr. Ruston is eligible for an annual cash bonus of up to 50% of his annual salary, to be prorated in 2005, and will receive an annual travel allowance of $25,000 to cover the costs of traveling to and from his home country of Australia.

C. BOARD PRACTICES

The Board and Board Committees

Our board supervises the management of North American Energy Partners Inc. as provided by Canadian law.

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NACG Holdings Inc.’s board has established the following committees:

• The Executive Committee, which possesses all the powers and authority of NACG Holdings Inc.’s board with respect to the management and direction of the business and affairs of NACG Holdings Inc., except as limited by Section 115(3) of the Canada Business Corporations Act. The Executive Committee is currently composed of Messrs. Antonio, Hawkins, Oehmig, Paterson, Ruston and Turner, with Mr. Oehmig serving as Chair;

• The Audit Committee, which recommends independent public accountants to NACG Holdings Inc.’s board, reviews the annual audit reports of NACG Holdings Inc. and reviews the fees paid to NACG Holdings Inc.’s chartered accountants. The Audit Committee reports its findings and recommendations to the board for ratification. The Audit Committee is currently composed of Messrs. Antonio, Brussa, Gouin, Hawkins, Turner and Wright, with Mr. Hawkins serving as Chair; and

• The Compensation Committee, which is charged with the responsibility for supervising executive compensation policies for NACG Holdings Inc. and its 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. The Compensation Committee is currently composed of Messrs. Brussa, Gardiner, Getty, Gouin, Oehmig and Paterson, with Mr. Paterson serving as Chair.

NACG Holdings Inc.’s board, acting as a committee of the whole board, has the responsibility for considering nominations for prospective board members of each of NACG Holdings Inc., NACG Preferred Corp. and us. The board will consider nominees recommended by other directors, shareholders and management, provided that nominations by shareholders are made in accordance with NACG Holdings Inc.’s bylaws. NACG Holdings Inc.’s board may also establish other committees.

D. EMPLOYEES

As of March 31, 2005, the Company employed 1,127 salaried and hourly employees:

Geographic Location	Employees
Calgary, Alberta	29
Edmonton, Alberta & area	112
Fort McMurray, Alberta	737
Grande Cache, Alberta	107
Prince George, British Columbia	3
Vancouver, British Columbia	21
Other British Columbia	75
Saskatchewan	11
Ontario	32
	1,127

E. SHARE OWNERSHIP

The following presents information regarding the ownership of shares of NACG Holdings Inc.’s voting common shares and options to purchase NACG Holdings Inc. common shares by our executive officers and directors as of August 31, 2005.

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Name of Beneficial Owner	Number of Common Shares	Options(1)	% of Outstanding Common Shares
E.J. Antonio III	—	277	*
John A. Brussa	4,000	277	*
Vincent Gallant	5,000	1,000	*
Jim G. Gardiner	250	277	*
Donald R. Getty	1,000	277	*
Martin Gouin	—	—	—
John D. Hawkins	—	277	*
Chris Hayman	—	—	—
William Koehn	5,000	1,000	*
Ronald A. McIntosh	2,000	700	*
William C. Oehmig	13,150	277	1.48
Gordon Parchewsky	5,000	1,200	*
Richard D. Paterson	—	—	—
Rodney J. Ruston	—	—	—
Miles Safranovich	—	—	—
K. Rick Turner	—	277	*
Gary K. Wright	986	277	*

 * Less than 1%

(1) Amount represents number of options which have vested as of August 31, 2005. All options entitle the holder to purchase one NACG Holdings Inc. common share per option and have an exercise price of $100 per share and expire 10 years from date of issue.

ITEM 7: MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

A. MAJOR SHAREHOLDERS

All of our capital shares are owned by NACG Preferred Corp., and all of its capital shares are owned by NACG Holdings Inc. The following presents information regarding the beneficial ownership of each person who was the beneficial owner of more than 5% of the outstanding voting common shares of NACG Holdings Inc. as of August 31, 2005.

Name of Beneficial Owner	Number of Common Shares	% of Outstanding Common Shares
Sterling Group Partners I, L.P.	272,456	30.03
Perry Partners International, Inc.	104,542	11.52
Perry Partners, L.P.	92,707	10.22
Genstar Capital Partners III, L.P.	190,412	20.98
Stephens-NACG LLC	131,500	14.49
Richard Perry (b)	197,279	21.74

(a) Sterling Group Partners I GP, L.P. is the sole general partner of Sterling Group Partners I, L.P. Sterling Group Partners I GP, L.P. has five general partners, each of which is wholly-owned by one of

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Frank J. Hevrdejs, William C. Oehmig, T. Hunter Nelson, John D. Hawkins and C. Kevin Garland. Each of these individuals disclaims beneficial ownership of the shares owned by Sterling Group Partners I, L.P.

(b) Richard Perry is the President and sole shareholder of Perry Corp., which is the investment manager of Perry Partners International, Inc. and the managing general partner of Perry Partners, L.P. As such, Mr. Perry may be deemed to have beneficial ownership over the respective securities owned by Perry Partners International, Inc. and Perry Partners, L.P.; however, Mr. Perry disclaims such beneficial ownership, except to the extent of his pecuniary interest, if any, therein. Perry Corp. is an affiliate of Perry Strategic Capital Inc.

(c) Genstar Capital III, L.P. is the sole general partner of each of Genstar Capital Partners III, L.P. and Stargen III, L.P., which owns an additional 6,838 shares, and Genstar III GP LLC is the sole general partner of Genstar Capital III, L.P. Jean-Pierre L. Conte, Richard F. Hoskins and Richard D. Paterson are the managing members of Genstar III GP LLC. In such capacity, Messrs. Conte, Hoskins and Paterson may be deemed to beneficially own shares of common stock beneficially owned, or deemed to be beneficially owned, by Genstar III GP LLC, but disclaim such beneficial ownership.

(d) Stephens Group, Inc. is the sole manager of Stephens-NACG LLC. No natural person may be deemed to beneficially own the shares owned by Stephens-NACG LLC.

B. RELATED PARTY TRANSACTIONS

Advisory Services Agreement

Pursuant to an agreement, dated October 31, 2003, among The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc., and Stephens Group, Inc., referred to in the agreement as the “sponsors,” and NACG Holdings Inc. and certain of its subsidiaries, including us, referred to in the agreement as the “companies,” the sponsors provided consulting and advisory services with respect to the organization of the companies, the structuring of the acquisition of North American Construction Group Inc., employee benefit and compensation arrangements and other matters. The agreement also provides that each of the companies, jointly and severally, will indemnify the sponsors against liabilities relating to their services. Under the agreement, for these services, we paid, at the closing of the transactions pursuant to which we became an indirect subsidiary of NACG Holdings Inc., a one-time transaction fee of US$3.0 million to Sterling and a one-time transaction fee of US$3.0 million to be shared among the sponsors and BNP Paribas Private Capital Group on a pro rata basis in accordance with their respective equity commitments to NACG Holdings Inc. We also reimbursed the sponsors for their expenses. Under the agreement, at the closing of the transactions, we paid to the sponsors a pro rated management fee for the period from closing until March 31, 2005 totaling approximately $400,000. In addition, the agreement provides that on each June 30 through June 30, 2013, we will pay the sponsors whose services have not terminated in accordance with the agreement, as a group, an annual management fee in cash totaling the greater of $400,000 and 0.5% of our EBITDA for the previous twelve month period ended March 31.

In addition, the agreement provides that if any one or more of the companies determines within ten years of the date of the closing of the transactions to acquire any business or assets having a value of US$1.0 million or more, referred to in the agreement as a “future corporate transaction,” or to offer its securities for sale publicly or privately or to otherwise raise any debt or equity financing, referred to in the agreement as a “future securities transaction,” the relevant company will retain one or more of the sponsors, whose services have not been terminated in accordance with the agreement, as a group, as consultants with respect to the transaction. For any future corporate transactions, the relevant sponsors are entitled under the agreement to receive a fee in the amount of 1% of the aggregate consideration paid for the acquisition plus the aggregate amount of assumed liabilities and, regardless of whether such future corporate transaction is consummated, any expenses or fees incurred by any sponsor in connection therewith. For any future securities transactions, the relevant sponsors are entitled to receive under the agreement a

49

fee in the amount of 0.5% of the aggregate gross proceeds to the companies from such transaction and, regardless of whether such future securities transaction is consummated, any expenses or fees incurred by any sponsor in connection therewith.

Office Leases

We are party to lease agreements with Acheson Properties Ltd., a company owned, indirectly and in part, by Martin Gouin, one of our directors. Mr. Gouin has an approximate 50% beneficial interest in Acheson Properties Ltd. Pursuant to the agreements, we lease our corporate headquarters in Acheson, Alberta, and our offices in Fort Nelson, British Columbia and Regina, Saskatchewan. See “Item 9D: Property, Plant and Equipment” for further information regarding these leases. For the fiscal year ended March 31, 2005, we paid a total of approximately $665,000 pursuant to these leases. The lease agreements were in place before the consummation of the transactions pursuant to which we became an indirect subsidiary of NACG Holdings Inc. We believe the terms of the lease agreements are fair and reasonable.

Shareholders Agreements

All employees of NACG Holdings Inc. or any of its subsidiaries who are holders of NACG Holdings Inc.’s common shares are party to an employee shareholders agreement, and all other holders of NACG Holdings Inc.’s common shares are party to an investor shareholders agreement. Each shareholders agreement includes specified transfer restrictions, rights of first refusal and tag along rights. The investor shareholders agreement also provides the holders who are party thereto preemptive rights and tag along rights.

Voting and Corporate Governance Agreement

NACG Holdings Inc. is party to a voting agreement with affiliates of The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc. and Stephens Group, Inc. that includes the following provisions:

Directors

The agreement provides that, as long as a shareholder party to the agreement, along with its affiliates, and various permitted tranferees own at least 50% of the common shares that it initially purchased in the offering of common shares, such shareholder may designate one director of NACG Holdings Inc. In addition, as long as Sterling and various permitted transferees own at least 75% of the common shares that it initially purchased in the offering of common shares, it may designate one additional director. Each shareholder party to the agreement agrees to vote the common shares held by it for each of the designated directors. The shareholder parties to the agreement also agree to vote their common shares in favor of the election to the board of directors of NACG Holdings Inc. of independent directors designated by a specified majority of the shareholder parties to the agreement or their appointed voting representatives. The voting agreement contains similar provisions for the removal of a director designated for removal by the parties to the agreement.

Permitted Transactions

The voting agreement provides that each shareholder party to the agreement will not, and will not permit any of its affiliates to, enter into, renew, extend or be a party to any transaction or series of transactions with NACG Holdings Inc. or any of its subsidiaries without the prior written consent of the holders of a specified majority of shares subject to the agreement, other than such holder or its affiliates, except for:

• issuances of capital shares pursuant to, or the funding of, employment arrangements, share options and share ownership plans approved by the board of directors of NACG Holdings Inc.;

50

• the grant of share options or similar rights to employees and directors pursuant to plans approved by the board of directors of NACG Holdings Inc.;

• loans or advances to executive officers approved by the board of directors of NACG Holdings Inc.;

• the payment of reasonable fees to directors of NACG Holdings Inc. and its subsidiaries who are not employees of NACG Holdings Inc. or its subsidiaries in their capacities as board members or members of committees of the board as may be approved by the board;

• any transaction between subsidiaries of NACG Holdings Inc.; and

• the registration rights agreement, the investor shareholders agreement and the advisory services agreement described above.

Registration Rights Agreement

NACG Holdings Inc. is party to a registration rights agreement with certain of its shareholders. The registration rights agreement includes the following provisions:

• Piggyback Registrations. After an initial public offering of the common shares of NACG Holdings Inc., the holders of qualified registrable securities, as defined in the agreement, will have piggyback registration rights when NACG Holdings Inc. proposes to register such common equity securities in a qualified registration other than a demand registration.

• Demand Registrations. Subject to specified restrictions, after an initial public offering, and upon written request, holders of qualified registrable securities have demand registration rights if such registrable securities to be included have, in the good faith opinion of NACG Holdings Inc., an aggregate fair market value of at least US$20.0 million.

The registration rights agreement also contains customary provisions with respect to registration procedures, indemnification and contribution rights.

Preferred Shares

On May 19, 2005 the Company issued 7,500 mandatorily redeemable preferred shares to existing shareholders of NACG Holdings Inc. for total cash proceeds of $7.5 million. These shares pay cumulative dividends of 15% per year if the 9% senior secured notes due 2010 and 8¾% senior notes due 2011 are outstanding. The shares are redeemable at the option of the Company at any time, and are required to be redeemed on December 31, 2011 or earlier in the event of a change in control or an initial public offering of equity securities and the repayment of 8 ³/4% senior unsecured notes due in 2011 and the 9% senior secured notes due in 2010. The redemption amount is the greater of:

a) $15.0 million less the amount, if any, of dividends previously paid in cash;

b) an amount that, when combined with the amount, if any, of dividends previously paid in cash, provides a 40% internal rate of return, compounded annually from the date of issue; and

c) 25% of the fair market value of the equity of the company, and in any event, will not exceed $100 million under the terms of the agreement.

C. INTERESTS OF EXPERTS AND COUNSEL

Not applicable.

ITEM 8: FINANCIAL INFORMATION

A. CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION

See Item 17: Financial Statements.

Legal Proceedings

In February 2005, certain sisters in the Gouin family sued their brothers and their father. The lawsuit also names us as a defendant. The sisters allege that they maintained beneficial ownership interests in the Gouin family businesses. The assets of those businesses were sold to the equity investors that formed North American Energy Partners as a subsidiary of NACG Holdings Inc. The sisters further allege that the proceeds of such ownership interests, including cash and preferred shares of NACG Preferred Corp., our corporate parent, are being wrongfully held by the Gouin brothers. The sisters seek, among other things, damages from the Gouin brothers and an ownership interest in us. We have notified the Gouin brothers that we are seeking indemnity from them under the agreement relating to the sales transaction for our cost of defense and any damages arising out of the lawsuit. We have answered the lawsuit and are defending our interests. Additionally, we are considering potential claims we may have arising out of the sales transaction.

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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 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.

B. SIGNIFICANT CHANGES

Not applicable.

ITEM 9: THE OFFER AND LISTING

A. OFFER AND LISTING DETAILS

There is no organized trading market, inside or outside the United States, for our securities.

B. PLAN OF DISTRIBUTION

Not applicable.

C. MARKETS

Our securities are not listed on any stock exchange or other regulated market.

D. SELLING SHAREHOLDERS

Not applicable.

E. DILUTION

Not applicable.

F. EXPENSES OF THE ISSUE

Not applicable.

ITEM 10: ADDITIONAL INFORMATION

A. SHARE CAPITAL

Not applicable.

B. MEMORANDUM AND ARTICLES OF ASSOCIATION

See Exhibits 3.1, 3.2 and 3.3 to the North American Energy Partners Inc. For F-4 (Registration No. 333-125610), filed on June 8, 2005 and incorporated herein by reference.

C. MATERIAL CONTRACTS

There are no material contracts, other than contracts entered into in the ordinary course of business, to which we are a party.

52

D. EXCHANGE CONTROLS

There are currently no limitations imposed by Canadian laws, decrees, or regulation that restrict the import or export of capital, including foreign exchange controls, or that affect the remittance of dividends, and interest or other payments to nonresident holders of the Company’s securities.

E. TAXATION

The following information is general and security holders are urged to seek the advice of their own tax advisors, tax counsel, or accountants with respect to the applicability or effect on their own individual circumstances of not only the matters referred to herein, but also any state or local taxes.

Canadian federal tax legislation generally requires a 25% withholding from dividends paid or deemed to be paid to the Company’s nonresident shareholders. However, shareholders resident in the United States will generally have this rate reduced to 15% through the tax treaty between Canada and the United States. The amounts withheld will generally be creditable for United States income tax purposes.

F. DIVIDENDS AND PAYING AGENTS

Not applicable.

G. STATEMENTS BY EXPERTS

Not applicable.

H. DOCUMENTS ON DISPLAY

We are required by the terms of the indentures governing the 8 ³/4% senior notes and the 9% senior secured notes to file reports and other information with the SEC. These reports and other information are or will be available after filing for reading and copying at the SEC Public Reference Room at Room 1580, 100 F Street NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the Public Reference Room and the SEC’s copying charges. The SEC also maintains and Internet site at http://www.sec.gov that contains the reports and other information that we file electronically with the SEC. As a foreign private issuer, however, we are exempt from the rule under the Securities Exchange Act of 1934, as amended, prescribing the furnishing and content of proxy statements to shareholders. Because we are a foreign private issuer, we, our directors, and our officers are also exempt from the short swing profit recovery provisions of Section 16 of the Exchange Act.

The indentures pursuant to which our senior notes and senior secured notes are issued provide that we, whether or not we are subject to Section 13(a) or 15(d) of the Exchange Act, must provide the indenture trustee and holders of notes annual reports on Form 20-F or 40-F, as applicable, and reports on Form 10-Q or Form 6-K which, regardless of the applicable requirements, shall, at a minimum, contain a “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and with respect to any such reports, a reconciliation to U.S. GAAP as permitted by the SEC for foreign private issuers; provided, however, that we shall not be obligated to file such reports with the SEC if the SEC does not permit such filings.

In the event we are no longer required to file reports with the SEC, we may discontinue filing them with the SEC at any time. During the period in which we are not a reporting issuer under the Exchange Act, we have agreed that, for so long as any notes remain outstanding and are “restricted securities” within the meaning of Rule 144 under the Securities Act, we will furnish to the holders of such notes and prospective purchasers of such notes, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act. Any

53

such request should be directed to North American Energy Partners Inc., Vice President, Finance, Zone 3, Acheson Industrial Area, 2 – 53106 Highway 60, Acheson, Alberta, T7X 5A7. Our telephone number is (780) 960-7171.

I. SUBSIDIARY INFORMATION

Not applicable.

ITEM 11: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Foreign currency risk

We are subject to currency exchange risk as the 8¾% senior notes and 9% senior secured notes are denominated in U.S. dollars and all of our revenues and most of our expenses are denominated in Canadian dollars. As noted above, we have entered into cross currency swap and interest rate swap agreements to manage the foreign currency risk on the 8 ¾% senior notes. The derivative financial instruments consist of three components: a U.S. dollar interest rate swap: a U.S. dollar-Canadian dollar cross currency basis swap; and a Canadian dollar interest rate swap that results in us mitigating our exposure to the variability of cash flows caused by currency fluctuations relating to the U.S. $200 million senior notes. The transaction can be cancelled at the counterparty’s option at any time after December 1, 2007 if the counterparty pays a cancellation premium. The premium is equal to 4.375 percent of the U.S. $200 million if exercised between December 1, 2007 and December 1, 2008; 2.1875 percent if exercised between December 1, 2008 and December 1, 2009; and 0.000 percent if cancelled after December 1, 2009. We have not hedged the foreign currency risk on the 9% senior secured notes. Each $0.01 increase or decrease in the U.S. dollar to Canadian dollar exchange rate would change the interest cost on these notes by $0.05 million per year. These derivative financial instruments do not meet the criteria to qualify for hedge accounting.

Interest rate risk

We are subject to interest rate risk in connection with our revolving credit facility. The facility bears interest at variable rates based on the Canadian prime rate plus 2 percent or Canadian bankers’ acceptance rate plus 3 percent. Assuming the revolving credit facility is fully drawn at $38.0 million, excluding the $22 million of outstanding letters of credit at September 23, 2005, each 1.0 percent increase or decrease in the applicable interest rate would change the interest cost by $0.2 million per year. In the future, we may enter into interest rate swaps involving the exchange of floating for fixed rate interest payments, to reduce interest rate volatility.

Inflation

The rate of inflation has not had a material impact on our operations as many of our contracts contain a provision for annual escalation. If inflation remains at its recent levels, it is not expected to have a material impact on our operations in the foreseeable future.

ITEM 12: DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

Not applicable.

PART II

ITEM 13: DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None.

54

ITEM 14: MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

None.

ITEM 15: CONTROLS AND PROCEDURES

As of March 31, 2005, our management, including our President and Vice President, Finance, has evaluated the effectiveness of the design and operations of our disclosure controls and procedures in accordance with Rule 15d-15 under the Securities Exchange Act of 1934. Based upon and as of the date of the evaluation, our President and Vice President, Finance concluded that while there are certain internal control deficiencies, there are compensating controls in place to provide assurance that the design of our disclosure controls and procedures were effective in all material respects to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported as and when required. Management is redesigning those internal controls to improve the overall efficiency of our overall internal control framework.

ITEM 16: [RESERVED]

ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT

Our board of directors has determined that John Hawkins is an audit committee financial expert, as that term is defined by Item 16A of Form 20-F and that Mr. Hawkins is independent, as that term is defined in the New York Stock Exchange listing standards.

ITEM 16B. CODE OF ETHICS

Our code of ethics, as attached hereto under item 19(b), applies to our President and Vice President, Finance, among other members of management.

ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES

NAEPI’s 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, 2005.

Audit Fees

KPMG billed NAEPI $1,330,000 in 2005 and $355,000 in 2004 for audit services. Audit fees were incurred for the audit of our annual financial statements or services provided in connection with statutory and regulatory filings or engagements, the review of interim consolidated financial statements, and information contained in various prospectuses.

Audit Related Fees

None.

Tax Fees

KPMG billed NAEPI $25,000 in 2005 and $50,000 in 2004 for tax compliance, tax advice, and tax planning services.

All Other Fees

KPMG billed NAEPI $31,000 in 2005 and $nil in 2004 for planning and scoping work completed around internal controls over financial reporting.

ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

Not applicable.

55

ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

Not applicable.

PART III

ITEM 17. FINANCIAL STATEMENTS

The Auditors’ Report and Financial Statements for the Company are attached hereto as itemized under Item 19(a) and are incorporated herein by reference. Such Financial Statements have been prepared on the basis of Canadian GAAP. A reconciliation to U.S. GAAP appears in Note 21 thereto.

ITEM 18. FINANCIAL STATEMENTS

Not applicable.

ITEM 19. EXHIBITS

(a) Financial Statements

(i) Auditors’ Report.

(ii) Balance Sheets as at March 31, 2004 and 2005.

(iii) Statements of Operations for the year ended March 31, 2003, the periods April 1, 2003 to November 25, 2003 and November 26, 2003 to March 31, 2004, and the year ended March 31, 2005.

(iv) Statements of Cash Flows for the year ended March 31, 2003, the periods April 1, 2003 to November 25, 2003 and November 26, 2003 to March 31, 2004, and the year ended March 31, 2005.

(v) Notes to the Financial Statements.

(vi) Financial Statement Schedules are omitted because they are not applicable, not required, or because the required information is included in the Financial Statements filed herein.

(b) Exhibits

1.1 – Articles of Amendment of North American Energy Partners Inc., filed with the Corporations Directorate of Industry Canada on May 18, 2005 (filed as Exhibit 3.1 to North American Energy Partners Inc.’s registration statement on Form F-4, Registration No. 333-125610 (the “2005 Registration Statement”), and incorporated herein by reference).

1.2 – Articles of Incorporation of North American Energy Partners Inc., filed with the Corporations Directorate of Industry Canada on October 17, 2003 (together with amendments thereto) (filed as Exhibit 3.1 to North American Energy Partners Inc.’s registration statement on Form F-4, Registration No. 333-111396 (the “2004 Registration Statement”), and incorporated herein by reference.

1.3 – By-laws of North American Energy Partners Inc. (filed as Exhibit 3.2 to the 2004 Registration Statement and incorporated herein by reference).

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2.1 – Indenture, dated as of May 19, 2005, among North American Energy Partners Inc., the guarantors named therein and Wells Fargo Bank, N.A., as Trustee (filed as Exhibit 4.1 to the 2005 Registration Statement and incorporated herein by reference).

2.2 – Indenture, dated as of November 26, 2003, among North American Energy Partners Inc., the guarantors named therein and Wells Fargo Bank, N.A., as Trustee (filed as Exhibit 4.1 to the 2004 Registration Statement and incorporated herein by reference).

4.1 – Credit Agreement, dated as of May 19, 2005, among North American Energy Partners Inc., the lenders named therein, BNP Paribas (Canada), as Administrative Agent, and GE Canada Finance Holding Company, as Collateral Agent (filed as Exhibit 10.1 to the 2005 Registration Statement and incorporated herein by reference).

4.2 – Intercreditor Agreement, dated as of May 19, 2005, between GE Finance Canada Holding Company, Wells Fargo Bank, N.A. and Computershare Trust Company of Canada, and consented to by North American Energy Partners Inc., and its subsidiaries (filed as Exhibit 10.2 to the 2005 Registration Statement and incorporated herein by reference).

4.3 – Form of 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 (filed as Exhibit 10.3 to the 2005 Registration Statement and incorporated herein by reference).

7.1 – Computation of Ratio of Earnings to Fixed Charges.

8.1 – Subsidiaries of North American Energy Partners Inc. (filed as Exhibit 21.1 to the 2004 Registration Statement and incorporated herein by reference).

11.1 – Code of Business Conduct and Ethics.

12.1 – Section 13a-14(a)/15d-14(a) Certification of Principal Executive Officer.

12.2 – Section 13a-14(a)/15d-14(a) Certification of Principal Financial Officer.

13.1 – Section 1350 Certification of Principal Executive Officer and Principal Financial Officer.

57

SIGNATURE

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

	NORTH AMERICAN ENERGY PARTNERS INC.
Date: November 23, 2005	By:	/s/ Chris Hayman
	Name:	Chris Hayman
	Title:	Vice President, Finance

58

	KPMG LLP Chartered Accountants 10125 – 102 Street Edmonton AB T5J  3V8 Canada	Telephone Fax Internet	(780) 429-7300 (780) 429-7379 www.kpmg.ca

AUDITORS’ REPORT TO THE SHAREHOLDERS

We have audited the consolidated balance sheets of North American Energy Partners Inc. as at March 31, 2005 and 2004 and the consolidated statements of operations and retained earnings (deficit) and cash flows of North American Energy Partners Inc. for the year ended March 31, 2005, the period from November 26, 2003 to March 31, 2004, and of Norama Ltd. (the “Predecessor Company”) for the period April 1, 2003 to November 25, 2003 and the year ended March 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of North American Energy Partners Inc. as at March 31, 2005 and 2004 and the results of operations and cash flows of North American Energy Partners Inc. for the year ended March 31, 2005, the period from November 26, 2003 to March 31, 2004, and of the Predecessor Company for the period April 1, 2003 to November 25, 2003 and for the year ended March 31, 2003, in accordance with Canadian generally accepted accounting principles.

Our previous report dated July 28, 2005 has been withdrawn and the consolidated financial statements have been revised as explained in note 3.

Chartered Accountants

Edmonton, Canada

July 28, 2005, except as to note 2(m), 3, 16(c) and 21, which are as of November 11, 2005

KPMG LLP, a Canadian limited liability partnership is the Canadian member firm of KPMG International, a Swiss cooperative.	CELEBRATING	80	YEARS
	IN EDMONTON

[Logo of KPMG LLP Appears here]
	KPMG LLP Chartered Accountants 10125 – 102 Street Edmonton AB T5J 3V8 Canada	Telephone Fax Internet	(780) 429-7300 (780) 429-7379 www.kpmg.ca

REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

To the Board of Directors of North American Energy Partners Inc.

We have audited the consolidated balance sheets of North American Energy Partners Inc. as at March 31, 2005 and 2004 and the consolidated statements of operations and retained earnings (deficit) and cash flows of North American Energy Partners Inc. for the year ended March 31, 2005, the period from November 26, 2003 to March 31, 2004 and of Norama Ltd. (the “Predecessor Company”) for the period April 1, 2003 to November 25, 2003 and the year ended March 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, these consolidated financial statements referred to above present fairly, in all material respects, the financial position of North American Energy Partners Inc. as of March 31, 2005 and 2004 and the results of operations and cash flows of North American Energy Partners Inc. for the year ended March 31, 2005, the period from November 26, 2003 to March 31, 2004, and of the Predecessor Company for the period April 1, 2003 to November 25, 2003 and for the year ended March 31, 2003 in accordance with Canadian generally accepted accounting principles.

As discussed in Note 2(p) to the consolidated financial statements, the Company changed its policy for consolidation in variable interest entities and arrangements containing a lease in 2005.

Canadian generally accepted accounting principles vary in certain significant respects from accounting principles generally accepted in the United States of America. Information relating to the nature and effect of such differences is presented in note 21 to the consolidated financial statements.

As discussed in note 3 to the consolidated financial statements, the consolidated balance sheet as at March 31, 2004 and the consolidated statements of operations and retained earnings (deficit) and cash flows of North American Energy Partners Inc. for the period from November 26, 2003 to March 31, 2004 has been restated to eliminate the use of hedge accounting.

/s/    KPMG LLP

Chartered Accountants

Edmonton, Canada

July 28, 2005 except as to note 2(m), 3, 16(c) and 21, which are as of November 11, 2005

KPMG LLP, a Canadian limited liability partnership is the Canadian member firm of KPMG International, A Swiss cooperative. CELEBRATING 80 YEARS IN EDMONTON

NORTH AMERICAN ENERGY PARTNERS INC.

Consolidated Statements of Operations and Retained Earnings (Deficit)

(in thousands of Canadian dollars)

	March 31, 2005			March 31, 2004
				Restated (note 3)
Assets
Current assets:
Cash and cash equivalents	$	17,922		$	36,595
Accounts receivable (note 13(a))		57,745			33,647
Unbilled revenue		41,411			27,676
Inventory		134			1,609
Prepaid expenses		1,862			1,272
Future income taxes (note 10)		15,100			—
		134,174			100,799
Property, plant and equipment (note 5)		177,089			167,905
Goodwill (note 4)		198,549			198,549
Intangible assets, net of accumulated amortization of $16,296 (March 31, 2004 - $12,928) (notes 4 and 6)		1,502			4,870
Deferred financing costs, net of accumulated amortization of $3,368 (March 31, 2004 - $814) (note 4)		15,354			17,266
Future income taxes (note 10)		—			285
	$	526,668		$	489,674
Liabilities and Shareholder’s Equity
Current liabilities:
Accounts payable	$	59,090		$	29,301
Accrued liabilities (note 13(b))		15,201			14,694
Billings in excess of costs and estimated earnings		1,325			—
Current portion of senior secured credit facility (note 7)		—			7,250
Current portion of capital lease obligations (note 8)		1,771			787
Future income taxes (note 10)		15,100			5,260
		92,487			57,292
Senior secured credit facility (note 7)		61,257			41,250
Capital lease obligations (note 8)		5,454			2,251
Senior notes (note 9)		241,920			262,260
Derivative financial instruments (note 16(c))		51,723			11,266
Advances from parent company (note 11)		288			—
Shareholder’s equity:
Share capital (note 12)		127,500			127,500
Contributed surplus (note 19)		634			137
Deficit		(54,595	)		(12,282	)
		73,539			115,355
Commitments (note 17)
United States generally accepted accounting principles (Restated)(note 21)
Subsequent event (note 22)
	$	526,668		$	489,674

See accompanying notes to consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

Consolidated Statements of Operations and Retained Earnings (Deficit)

(in thousands of Canadian dollars)

							Predecessor Company
	for the year ended March 31, 2005			for the period November 26, 2003 to March 31, 2004			for the period April 1, 2003 to November 25, 2003			for the year ended March 31, 2003
				Restated (note 3)
Revenue	$	357,323		$	127,611		$	250,652		$	344,186
Project costs		240,919			83,256			156,976			219,979
Equipment costs		59,476			15,116			53,986			72,228
Depreciation		20,762			6,674			6,566			10,974
		321,157			105,046			217,528			303,181
Gross profit		36,166			22,565			33,124			41,005
General and administrative		22,863			6,065			7,783			12,233
Loss (gain) on disposal of property, plant and equipment		494			131			(49	)		(2,265	)
Amortization of intangible assets		3,368			12,928			—			—
Operating income		9,441			3,441			25,390			31,037
Management fees (note 15(c))		—			—			41,070			8,000
Interest expense (note 13(c))		31,141			10,079			2,457			4,162
Foreign exchange gain (note 16(d))		(19,815	)		(661	)		(7	)		(234	)
Other income		(421	)		(230	)		(367	)		—
Realized and unrealized (gain) loss on derivative financial instruments		43,113			12,205			—			—
		54,018			21,393			43,153			11,928
Income (loss) before income taxes		(44,577	)		(17,952	)		(17,763	)		19,109
Income taxes (note 10):
Current income taxes		2,711			1,178			218			245
Future income taxes		(4,975	)		(6,848	)		(6,840	)		6,375
		(2,264	)		(5,670	)		(6,622	)		6,620
Net income (loss)		(42,313	)		(12,282	)		(11,141	)		12,489
Dividends		—			—			—			(50	)
Retained earnings (deficit), beginning of period		(12,282	)		—			29,817			17,378
Retained earnings (deficit), end of period	$	(54,595	)	$	(12,282	)	$	18,676		$	29,817

See accompanying notes to consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

Consolidated Statements of Cash Flows

(in thousands of Canadian dollars)

							Predecessor Company
	for the year ended March 31, 2005			for the period November 26, 2003 to March 31, 2004			for the period April 1, 2003 to November 25, 2003			for the year ended March 31, 2003
				Restated (note 3)
Cash provided by (used in):
Operating activities:
Net income (loss)	$	(42,313	)	$	(12,282	)	$	(11,141	)	$	12,489
Items not affecting cash:
Depreciation		20,762			6,674			6,566			10,974
Amortization of intangible assets		3,368			12,928			—			—
Amortization of deferred financing costs		2,554			814			—			—
Loss (gain) on disposal of property, plant and equipment		494			131			(49	)		(2,265	)
Increase (decrease) in allowance for doubtful accounts		(69	)		(60	)		141			142
Unrealized foreign exchange gain on senior notes		(20,340	)		(740	)		—			—
Unrealized loss on derivative financial instruments		40,457			11,266			—			—
Stock-based compensation expense		497			137			—			—
Future income taxes		(4,975	)		(6,848	)		(6,840	)		6,375
Net changes in non-cash working capital (note 13(e))		(5,258	)		3,457			13,832			(11,432	)
		(4,823	)		15,477			2,509			16,283
Investing activities:
Purchase of property, plant and equipment		(25,679	)		(2,501	)		(5,234	)		(22,932	)
Proceeds on disposal of property, plant and equipment		624			5,765			609			4,187
Acquisition (note 4)		—			(367,778	)		—			—
		(25,055	)		(364,514	)		(4,625	)		(18,745	)
Financing activities:
Increase in revolving credit facility		20,007			—			—			—
Repayment of term credit facility		(7,250	)		(1,500	)		(4,428	)		(5,280	)
Repayment of capital lease obligations		(1,198	)		(288	)		(3,289	)		(3,058	)
Financing costs		(642	)		(18,080	)		—			—
Advances from parent company		288			—			—			—
Issuance of share capital		—			92,500			—			—
Issuance of senior notes		—			263,000			—			—
Proceeds from term credit facility		—			50,000			—			13,500
Advances from Norama Inc.		—			—			17,696			(1,105	)
Decrease in cheques issued in excess of cash deposits		—			—			(2,496	)		(1,313	)
Decrease in operating line of credit		—			—			(516	)		(232	)
Dividends paid		—			—			—			(50	)
		11,205			385,632			6,967			2,462
Increase (decrease) in cash and cash equivalents		(18,673	)		36,595			4,851			—
Cash and cash equivalents, beginning of period		36,595			—			—			—
Cash and cash equivalents, end of period	$	17,922		$	36,595		$	4,851		$	—

See accompanying notes to consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

1. Nature of operations

North American Energy Partners Inc. (the “Company”) was incorporated under the Canada Business Corporations Act on October 17, 2003. The Company had no operations prior to November 26, 2003. After giving effect to the acquisition described in note 4, the Company completes all forms of civil projects including contract mining, industrial and commercial site development, pipeline and piling installations. The Company is a wholly-owned subsidiary of NACG Preferred Corp. which in turn is a wholly-owned subsidiary of NACG Holdings Inc.

2. Significant accounting policies

a) Basis of presentation:

These consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles (“GAAP”). Material inter-company transactions and balances are eliminated on consolidation. Material items that could give rise to measurement differences to these consolidated financial statements under United States GAAP are outlined in note 21.

These consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, NACG Finance LLC and North American Construction Group Inc. (“NACGI”), the Company’s investment in Noramac Ventures Inc., a variable interest entity (note 13(f)), and the following subsidiaries:

	% owned
•      North American Caisson Ltd.	100	%
•      North American Construction Ltd.	100	%
•      North American Engineering Ltd.	100	%
•      North American Enterprises Ltd.	100	%
•      North American Industries Inc.	100	%
•      North American Mining Inc.	100	%
•      North American Maintenance Ltd.	100	%
•      North American Pipeline Inc.	100	%
•      North American Road Inc.	100	%
•      North American Services Inc.	100	%
•      North American Site Development Ltd.	100	%
•      North American Site Services Inc.	100	%
•      Griffiths Pile Driving Inc.	100	%

In preparation for the acquisition described in note 4, effective July 31, 2003, all of the issued common shares of NACGI and North American Equipment Ltd. (“NAEL”) were transferred from Norama Inc. to its new wholly-owned subsidiary, Norama Ltd. (the “Predecessor Company”). The consolidated financial statements of Norama Ltd. are depicted in these financial statements as the Predecessor Company and have been prepared using the continuity of interest method of accounting to reflect the combined carrying values of the assets, liabilities and shareholder’s equity as well as the combined operating results of NAEL and NACGI for all comparative periods presented. The consolidated financial statements for periods ended before November 26, 2003 are not comparable in all respects to the consolidated financial statements for periods ended after November 25, 2003.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

The Predecessor Company has been operating continuously in Western Canada since 1953.

b) Use of estimates:

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

c) Revenue recognition:

The Company performs the majority of its projects under the following types of contracts: time-and-materials; cost-plus; unit-price; and lump sum. For time-and-materials and cost-plus contracts, revenue is recognized as costs are incurred. Revenue on unit-price and lump sum contracts is recognized on the percentage-of-completion method, measured by the ratio of costs incurred to date to estimated total costs. Excluded from costs incurred to date, particularly in the early stages of the contract, are the costs of items that do not relate to performance of our contracted work.

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

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

d) Cash and cash equivalents:

Cash and cash equivalents include cash on hand and bank balances net of outstanding cheques.

e) Allowance for doubtful accounts:

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

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

f) Inventory:

Inventory is carried at the lower of cost, on a first-in, first-out basis, and replacement cost, and primarily consists of job materials.

g) Property, plant and equipment:

Property, plant and equipment are recorded at cost. Major components of heavy construction equipment in use such as engines, transmissions, and undercarriages are recorded separately. Spare component parts are charged to earnings when they are put into use. Equipment under capital lease is recorded at the present value of minimum lease payments at the inception of the lease. Depreciation is not recorded until an asset is put into service. Depreciation for each category is calculated based on the cost, net of the estimated residual value, over the estimated useful life of the assets on the following bases and annual rates:

Asset	Basis	Rate
Heavy equipment	Straight-line	Operating hours
Major component parts in use	Straight-line	Operating hours
Spare component parts	N/A	N/A
Other equipment	Straight-line	10-20%
Licensed motor vehicles	Declining balance	30%
Office and computer equipment	Straight-line	25%
Assets under construction	N/A	N/A

The cost of period repairs and maintenance is expensed to the extent that the expenditure serves only to restore the asset to its original condition. Any gain or loss resulting from the sale or retirement of property, plant and equipment is charged to income in the current period.

h) Goodwill:

Goodwill represents the excess purchase price paid by the Company over the fair value of the tangible and identifiable intangible assets and liabilities acquired. Goodwill is not amortized but instead is tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. The impairment test is carried out in two steps. In the first step, the carrying amount of the reporting unit, including goodwill, is compared with its fair value. When the fair value of the reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to be impaired and the second step of the impairment test is unnecessary. The second step is carried out when the carrying amount of a reporting unit exceeds its fair value, in which case, the implied fair value of the reporting unit’s goodwill, determined in the same manner as the value of goodwill is determined in a business combination, is compared with its carrying amount to measure the amount of the impairment loss, if any.

The Company tested goodwill for impairment at December 31, 2004 as a result of events and changes in circumstances. The Company conducts its annual assessment of goodwill on January 1 of each year. The test was completed to March 31, 2005, and the Company determined no impairment in the carrying value existed.

i) Intangible assets:

Intangible assets acquired include: customer contracts in progress and related relationships, which are being amortized based on the net present value of the estimated period cash flows over the remaining

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

lives of the related contracts; trade names, which are being amortized on a straight-line basis over the estimated useful life of 10 years; a non-competition agreement, which is being amortized on a straight-line basis over the five-year term of the agreement; and employee arrangements, which are being amortized on a straight-line basis over the three-year term of the arrangement.

j) Deferred financing costs:

Costs relating to the issuance of the senior notes and the senior secured credit facility have been deferred and are being amortized on a straight-line basis over the terms of the related debt, which are eight years and five years, respectively.

k) Impairment of long-lived assets:

Long-lived assets and certain identifiable intangibles are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is assessed by a comparison of the carrying amount of an asset to future undiscounted cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment loss is recognized for the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of by sale are reported at the lower of their carrying amount or fair value less costs to sell.

(l) Foreign currency translation:

The functional currency of the Company is Canadian dollars. Transactions denominated in foreign currencies are recorded at the rate of exchange prevailing at the transaction date. Monetary assets and liabilities, including long-term debt denominated in U.S. dollars, are translated into Canadian dollars at the rate of exchange prevailing at the balance sheet date.

(m) Derivative financial instruments:

The Company uses derivative financial instruments to manage economic risks from fluctuations in exchange rates and interest rates. These instruments include cross-currency swap agreements and interest rate swap agreements. All such instruments are only used for risk management purposes. Derivative financial instruments are subject to standard credit terms and conditions, financial controls, management and risk monitoring procedures.

A derivative financial instrument must be designated and effective, at inception and on at least a quarterly basis, to be accounted for as a hedge. For cash flow hedges, effectiveness is achieved if the changes in the cash flows of the derivative financial instrument substantially offset the changes in the cash flows of the hedged position and the timing of the cash flows is similar. Effectiveness for fair value hedges is achieved if changes in the fair value of the derivative financial instrument substantially offset changes in the fair value attributable to the hedged item. In the event that a derivative financial instrument does not meet the designation or effectiveness criterion, the derivative financial instrument is accounted for at fair value and realized and unrealized gains and losses on the derivative are recognized in the Statement of Operations in accordance with EIC-128, “Accounting for Trading, Speculative or Non-Hedging Derivative Financial Instruments” (“EIC-128”). If a derivative financial instrument which previously qualified for hedge accounting no longer qualifies or is settled or de-designated, the fair value on that date is deferred and recognized when the corresponding hedged transaction is recognized. Premiums paid or received with respect to derivatives that are hedges are deferred and amortized to income over the term of the hedge.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

n) Income taxes:

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

o) Stock–based compensation plan:

Effective November 26, 2003, the Company adopted the revised CICA Handbook Section 3870, “Stock-Based Compensation” which requires that a fair value method of accounting be applied to all stock-based compensation payments. Under a fair value method (Black-Scholes method), compensation cost is measured at the fair value at the grant date and is expensed over the award’s vesting period.

p) Recently adopted Canadian accounting pronouncements:

i. Hedging relationships:

Effective November 26, 2003, the Company prospectively adopted the provisions of the Canadian Institute of Chartered Accountants’ new Accounting Guideline 13, “Hedging Relationships” (“AcG-13”), that specifies the circumstances in which hedge accounting is appropriate, including the identification, documentation, designation, and effectiveness of hedges, and the discontinuance of hedge accounting. The Company has determined that all of its current derivative financial instruments do not qualify for hedge accounting in accordance with AcG-13.

ii. Revenue recognition:

Effective January 1, 2004, the Company prospectively adopted the new Canadian accounting standards EIC-141, “Revenue Recognition,” and EIC-142, “Revenue Arrangements with Multiple Deliverables,” which incorporate the principles and guidance under United States generally accepted accounting principles (“U.S. GAAP”) for revenue recognition. No changes to the recognition or classification of revenue were made as a result of the adoption of these standards.

iii. Consolidation of variable interest entities:

Effective January 1, 2005, the Company prospectively adopted the Canadian Institute of Chartered Accountants’ new Accounting Guideline 15, “Consolidation of Variable Interest Entities” (“VIEs”) (“AcG-15”). VIEs are entities that have insufficient equity at risk to finance their operations without additional subordinated financial support and/or entities whose equity investors lack one or more of

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

the specified essential characteristics of a controlling financial interest. AcG-15 provides specific guidance for determining when an entity is a VIE and who, if anyone, should consolidate the VIE. The Company has determined the joint venture in which it has an investment (note 13(f)) qualifies as a VIE.

iv. Arrangements containing a lease:

Effective January 1, 2005, the Company adopted the new Canadian Accounting Standard EIC-150, “Determining Whether an Arrangement Contains a Lease.” EIC-150 addresses a situation where an entity enters into an arrangement, comprising a transaction that does not take the legal form of a lease but conveys a right to use a tangible asset in return for a payment or series of payments. The Company has determined that it has not currently committed to any arrangements to which this standard would apply.

q) Recent Canadian accounting pronouncements not yet adopted:

i. Financial instruments:

In January 2005, the CICA issued Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, Handbook Section 1530, “Comprehensive Income”, and Handbook Section 3865, “Hedges”. The new standards will be effective for interim and annual financial statements commencing in 2007. Earlier adoption is permitted. The new standards will require presentation of a separate statement of comprehensive income. Foreign exchange gains and losses on the translation of the financial statements of self-sustaining subsidiaries previously recorded in a separate section of shareholder’s equity will be presented in comprehensive income. Derivative financial instruments will be recorded in the balance sheet at fair value and the changes in fair value of derivatives designated as cash flow hedges will be reporting in comprehensive income. The Company is currently assessing the impact of the new standards.

ii. Vendor rebates:

In January 2005, the CICA amended EIC-144, “Accounting by a customer (including a reseller) for certain consideration received from a vendor.” The consensus is effective retroactively for periods commencing on or after February 15, 2005. The consensus requires companies to recognize the benefit of non-discretionary rebates for achieving specified cumulative purchasing levels as a reduction of the cost of purchases over the relevant period, provided the rebate is probable and reasonably estimable. Otherwise, the rebates would be recognized as purchasing milestones are achieved. The Company is assessing the impact of the new consensus but does not expect it to have a material impact on the consolidated financial statements.

iii. Non-monetary transactions:

In June 2005, the CICA replaced Handbook Section 3830, “Non-monetary Transactions”, with the new Handbook Section 3831, “Non-monetary Transactions”. The requirements of the new standard apply to non-monetary transactions initiated in periods beginning on or after January 1,

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

2006, though earlier adoption is permitted as of periods beginning on or after July 1, 2005. The standard requires all non-monetary transactions to be measured at fair market value unless:

• the transaction lacks commercial substance;

• the transaction is an exchange of production or property held for sale in the ordinary course of business for production or property to be sold in the same line of business to facilitate sales to customers other than the parties to the exchange;

• neither the fair value of the assets or services received nor the fair value of the assets or services given up is reliably measurable; or

• the transaction is a non-monetary, non-reciprocal transfer to owners that represents a spin-off or other form of restructuring or liquidation.

The Company does not expect the adoption of this standard to have a material impact on its results of operations or financial position.

3. Restatement

In preparing the financial statements for the fiscal year ended March 31, 2005, the Company, reviewed the accounting treatment of the Company’s derivative instruments (described in note 16(c)) and concluded that there were technical deficiencies in the hedge documentation relating to the cross-currency swap and interest rate swap contracts used to manage its foreign exchange risk exposure related to the U.S. $ denominated 8 ¾ % senior notes since the inception of the derivative financial contracts on November 26, 2003, which deficiencies could not be corrected retroactively. Complete and accurate documentation is required to support the effectiveness of the hedge and the use of hedge accounting under the Canadian Institute of Chartered Accountants Accounting Guideline 13, “Hedging Relationships.”

As a result of the deficiencies in the documentation, the Company determined that it was necessary to restate all reported periods after November 26, 2003 to eliminate the impact of hedge accounting. This was accomplished by recognizing the foreign exchange gain or loss relating to the senior notes each period and recording the derivative financial instruments at fair value and the realized and unrealized gains and losses on the derivative instruments each period through the Consolidated Statement of Operations, along with the associated future income tax effects. A valuation allowance of $8.1 million was recorded against the future income tax asset since it is more likely than not the asset will not be realized.

The Company did not violate any covenants under the Credit Agreement (note 7) as a result of the restatement. Furthermore the Company repaid its entire indebtedness under the Senior Secured Credit Facility on May 19, 2005 (note 22).

The impact of the restatement on the Consolidated Statements of Operations is as follows:

For the period from November 26, 2003 to March 31, 2004	As previously reported			Adjustments			As restated
Interest expense	$	11,018		$	(939	)	$	10,079
Foreign exchange loss (gain)		79			(740	)		(661	)
Realized and unrealized (gains) losses on derivative financial instruments		—			12,205			12,205
Loss before income taxes		(7,426	)		(10,526	)		(17,952	)
Future income taxes		(4,048	)		(2,800	)		(6,848	)
Net loss	$	(4,556	)	$	(7,726	)	$	(12,282	)

The impact of the restatement on the Consolidated Balance Sheets is as follows:

As at March 31, 2004	As previously reported			Adjustments			As restated
Future income taxes—asset	$	—		$	285		$	285
Derivative financial instruments		740			10,526			11,266
Future income taxes—liability		2,515			(2,515	)		—
Deficit	$	(4,556	)	$	(7,726	)	$	(12,282	)

The impact of the restatement on the Consolidated Statements of Cash Flows is as follows:

For the period from November 26, 2003 to March 31, 2004	As previously reported			Adjustments			As restated
Net loss	$	(4,556	)	$	(7,726	)	$	(12,282	)
Foreign exchange gain on senior notes		—			(740	)		(740	)
Unrealized change in fair value of derivative financial instruments		—			11,266			11,266
Future income taxes	$	(4,048	)	$	(2,800	)	$	(6,848	)

4. Acquisition

On November 26, 2003, NACG Preferred Corp., the parent company, and NACG Acquisition Inc. (“Acquisition”), a wholly-owned subsidiary of the Company, acquired from Norama Ltd. (the “Predecessor Company”) all of the outstanding common shares of North American Construction Group Inc. (“NACGI”). The Predecessor Company sold 30 shares of NACGI to NACG Preferred Corp. in exchange for $35.0 million of NACG Preferred Corp.’s Series A Preferred Shares. NACG Preferred Corp. then contributed the 30 shares of NACGI to the Company in exchange for common shares. The Company then contributed the 30 shares of NACGI to Acquisition in exchange for common shares. The Predecessor Company sold the remaining 170 shares of NACGI to Acquisition in exchange for approximately $195.5 million in cash including the impact of various post-closing adjustments. In addition, Acquisition acquired substantially all of the property, plant and equipment, prepaid expenses and accounts payable of North American Equipment Ltd. (“NAEL”) for $175.0 million in cash. Acquisition and NACGI amalgamated on the same day and the successor company continued as NACGI.

The total purchase price was approximately $230.0 million for the common shares of NACGI and $175.0 million for the property, plant and equipment, prepaid expenses and accounts payable of NAEL. The purchase price was subject to an adjustment of $0.5 million based on the closing working capital of NACGI at November 25, 2003 which has been accounted for as increased goodwill. The total consideration payable by NACG Preferred Corp. and Acquisition to the sellers was approximately $405.5 million including the impact of certain post-closing adjustments. Of the cash consideration, $92.5 million came from the cash contribution to Acquisition by the Company that originated from NACG Holdings Inc.’s sale of its equity.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

The Company accounted for the acquisition as a business combination using the purchase method. The results of NACGI’s operations have been included in the consolidated financial statements of the Company since November 26, 2003. The following table summarizes the fair value of the assets acquired and liabilities assumed at the date of acquisition:

Current assets, including cash of $19,642	$	83,910
Property, plant and equipment, including capital leases of $2,131		176,779
Intangible assets		17,798
Goodwill		198,549
Total assets acquired		477,036
Current liabilities		(40,662	)
Future income taxes		(11,823	)
Capital lease obligations		(2,131	)
Total liabilities assumed		(54,616	)
Net assets acquired	$	422,420

The acquisition was financed as follows:

Proceeds from issuance of senior notes	$	263,000
Proceeds from issuance of share capital		127,500
Proceeds from initial borrowing under the new:
Term credit facility		50,000
Revolving credit facility		—
Less: deferred financing costs		(18,080	)
		$422,420

The net cash cost of the acquisition is:

Net assets acquired	$	422,420
Less: non-cash portion of share capital		(35,000	)
Less: cash acquired from acquisition and financing		(19,642	)
		$367,778

The intangible assets relate to customer contracts in progress and related relationships, trade names, a non-competition agreement, and employee arrangements and are subject to amortization.

The goodwill was assigned to mining and site preparation, piling and pipeline segments in the amounts of $125,447, $40,349, and $32,753, respectively. None of the goodwill is expected to be deductible for income tax purposes.

Transaction costs of $25.1 million were incurred on the acquisition, $7.0 million of which were accounted for as increased goodwill and $18.1 million of which were recorded as deferred financing costs. The deferred financing costs were subject to amortization of $2,554 during the year ended March 31, 2005 (November 26, 2003 to March 31, 2004 - $814; April 1, 2003 to November 25, 2003 - $nil; year ended March 31, 2003 - $nil).

The current assets included $19,642 in cash acquired, of which $15,623 was surplus cash from the financing. Common shares valued at $35 million were issued in exchange for the NACGI shares acquired from NACG Preferred Corp.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

5. Property, plant and equipment

March 31, 2005	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	165,296	$	17,966	$	147,330
Major component parts in use		4,659		1,182		3,477
Spare component parts		841		—		841
Other equipment		12,088		2,473		9,615
Licensed motor vehicles		16,043		4,670		11,373
Office and computer equipment		2,088		791		1,297
Assets under construction		3,156		—		3,156
	$	204,171	$	27,082	$	177,089
March 31, 2004	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	149,704	$	4,444	$	145,260
Major component parts in use		2,260		374		1,886
Spare component parts		395		—		395
Other equipment		10,160		605		9,555
Licensed motor vehicles		10,561		1,049		9,512
Office and computer equipment		1,491		194		1,297
	$	174,571	$	6,666	$	167,905

The above amounts include $8,637 (March 31, 2004 – $3,328) of assets under capital lease and accumulated depreciation of $1,968 (March 31, 2004 – $320) related thereto. During the year ended March 31, 2005, additions of property, plant and equipment included $5,385 of assets that were acquired by means of capital leases (November 26, 2003 to March 31, 2004 – $1,195; April 1, 2003 to November 25, 2003 – $nil; year ended March 31, 2003 – $9,439). Depreciation of equipment under capital leases of $1,659 (November 26, 2003 to March 31, 2004 – $320; April 1, 2003 to November 25, 2003 – $677; year ended March 31, 2003 – $765) is included in depreciation expense. As at March 31, 2005, property, plant and equipment reflect the effects of applying push down accounting due to the acquisition described in note 4.

6. Intangible assets

March 31, 2005	Cost		Accumulated amortization		Net book value
Customer contracts in progress and related relationships	$	15,323	$	15,323	$	—
Trade names		350		47		303
Non-competition agreement		100		26		74
Employee arrangements		2,025		900		1,125
Balance, March 31, 2005	$	17,798	$	16,296	$	1,502

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

March 31, 2004	Cost		Accumulated amortization		Net book value
Customer contracts in progress and related relationships	$	15,323	$	12,684	$	2,639
Trade names		350		12		338
Non-competition agreement		100		7		93
Employee arrangements		2,025		225		1,800
Balance, March 31, 2004	$	17,798	$	12,928	$	4,870

Amortization of intangible assets of $3,368 was recorded for the year ended March 31, 2005 (November 26, 2003 to March 31, 2004 - $12,928; April 1, 2003 to November 25, 2003 - $nil; year ended March 31, 2003 - $nil).

7. Senior secured credit facility

	March 31, 2005		March 31, 2004
Revolving credit facility	$	20,007	$	—
Term credit facility		41,250		48,500
		61,257		48,500
Less: current portion		—		7,250
	$	61,257	$	41,250

The Company refers to the revolving credit facility and the term loan collectively as the “senior secured credit facility”. On November 26, 2003, the Company secured a $120 million senior secured credit facility with a syndicate of lenders. The facility is comprised of a $70 million revolving credit facility, subject to borrowing base limitations, and a $50 million term credit facility, both of which bear interest at the Canadian prime rate plus 2% or Canadian bankers’ acceptance rate plus 3%. The indebtedness under the senior secured credit facility is secured by substantially all of the Company’s assets and those of its subsidiaries, including accounts receivable and property, plant and equipment.

As of March 31, 2005, the Company had $20.0 million in outstanding borrowings under the revolving credit facility and had issued $20.0 million in letters of credit to support bonding requirements and performance guarantees associated with customer contracts. There was $41.3 million outstanding under the term loan portion of the senior secured credit facility at March 31, 2005.

The Credit Agreement dated November 26, 2003 related to the senior secured credit facility (the “Credit Agreement”) imposes certain restrictions on the Company, including restrictions on the Company’s ability to incur indebtedness, pay dividends, make investments, grant liens, sell assets and engage in certain other activities. In addition, the Credit Agreement requires the Company to maintain certain financial ratios (“covenants”) including: achieving certain levels of earnings before interest, taxes, depreciation and amortization (“EBITDA”); maintaining interest and fixed-charge coverage ratios above a specified minimum level; limiting capital expenditures to specified amounts; and maintaining leverage ratios below a specified maximum level. Without several waivers obtained from the lenders and a forbearance agreement which was to expire on July 15, 2005, the Company would have been in breach of several covenants under the Credit Agreement related to the year ended March 31, 2005. Accounting standards under Emerging Issues Committee Abstract EIC-59, “Long-term Debt with Covenant Violations” requires the classification of

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

long-term debt as current in circumstances where, at the balance sheet date, the debtor would have been in violation of one or more financial covenants giving the creditor the right to demand repayment absent the modification of financial covenants and violation of one or more covenants within one year of the balance sheet date is likely. The Company would have otherwise reclassified this obligation as a current liability because it would not meet the financial covenants in the next year. However, subsequent to March 31, 2005, the Company repaid all amounts outstanding under the senior secured credit facility and entered into a new financing agreement where the Company expects to comply with all covenants during the next year (note 22). Therefore, the Company has classified the entire amount outstanding under the senior secured credit facility as long-term at March 31, 2005 as required by accounting standards under Emerging Issues Committee Abstract EIC-122 “Balance Sheet Classification of Callable Debt Obligations and Debt Obligations Expected to be Refinanced”. Under this accounting standard, the debt may be classified as long-term if at the balance sheet date an obligation that is otherwise callable by the lender has been subsequently refinanced on a long-term basis and the Company does not expect to violate any covenants within one year of the balance sheet date.

8. Capital lease obligations

The Company leases a portion of its licensed motor vehicles for which the minimum lease payments due in each of the next five fiscal years are summarized as follows:

2006	$	2,038
2007		2,149
2008		2,002
2009		1,402
2010		370
		7,961
Less: amount representing interest - average rate of 5.03%		736
Present value of minimum capital lease payments		7,225
Less: current portion		1,771
	$	5,454

9. Senior notes

The senior notes were issued on November 26, 2003 in the amount of US$200 million. These notes mature on December 1, 2011 and bear interest at 8.75% payable semi-annually on June 1 and December 1 of each year.

The notes are unsecured senior obligations and rank equally with all other existing and future unsecured and unsubordinated debt and senior to any subordinated debt that may be issued by the Company. The notes are effectively subordinated to all secured debt, including debt under the secured credit facility (note 7(a)), to the extent of the value of the assets securing such debt.

The senior notes are redeemable at the option of the Company, in whole or in part, at any time on or after: December 1, 2007 at 104.375% of the principal amount; December 1, 2008 at 102.188% of the principal amount; December 1, 2009 at 100.00% of the principal amount; plus, in each case, interest accrued to the redemption date.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

10. Income taxes

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

							Predecessor Company
	for the year ended March 31, 2005			for the period November 26, 2003 to March 31, 2004			for the period April 1, 2003 to November 25, 2003			for the year ended March 31, 2003
				Restated (note 3)
Statutory rate		33.6	%		35.2	%		36.6	%		38.6	%
Expected provision (recovery) at statutory rate	$	(14,987	)	$	(6,319	)	$	(6,501	)	$	7,377
Change in future income tax liability, resulting from reduction in future statutory income tax rates		—			(342	)		(669	)		(700	)
Change in future income tax liability, resulting from valuation allowance		12,189			—			—			—
Large corporations tax		871			319			137			245
Other		(337	)		672			411			(302	)
Income tax provision (recovery) for current period	$	(2,264	)	$	(5,670	)	$	(6,622	)	$	6,620

The tax effects of temporary differences that give rise to future income tax liabilities are presented below:

	March 31, 2005			March 31, 2004
				Restated (note 3)
Unbilled revenue and uncertified revenue included in accounts receivable	$	32,636		$	27,906
Accounts receivable—holdbacks		12,476			3,838
Non-capital losses carried forward		(90,834	)		(16,649	)
Difference between tax and carrying basis of property, plant and equipment		36,979			2,179
Difference between tax and carrying basis of deferred financing costs		1,631			440
Difference between tax and carrying basis of derivative financial instruments		(23,997	)		(8,236	)
Intangible assets		1,502			4,870
Other		(2	)		550
Net temporary differences		(29,609	)		14,898
Tax rate expected to apply		33.6	%		33.6	%
		(9,955	)		4,975
Valuation allowance		9,955			—
Net future tax liability	$	—		$	4,975

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

	March 31, 2005		March 31, 2004
Future tax asset	$	15,100	$	285
Future tax liability		15,100		5,260
Net future tax liability		—		(4,975	)
Less: current portion		—		(5,260	)
	$	—	$	285

11. Advances from parent company

Advances from parent company of $288 as at March 31, 2005 represent a non-interest bearing note payable to the Company’s ultimate parent, NACG Holdings Inc. The note was transacted in the normal course of operations and recorded at the exchange value and on terms as agreed to by the parties. As the parent company has indicated in writing that it will not demand payment within the next fiscal year, this amount has been classified as long-term.

12. Share capital

	Number of Shares	Amount
Outstanding at November 26, 2003	—	$	—
Issued	100		127,500
Redeemed	—		—
Outstanding at March 31, 2004	100		127,500
Issued	—		—
Redeemed	—		—
Outstanding at March 31, 2005	100	$	127,500

Contributed surplus

Balance, November 26, 2003	$	—
Stock-based compensation (note 19)		137
Balance, March 31, 2004		137
Stock-based compensation (note 19)		497
Balance, March 31, 2005	$	634

13. Other information

a) Accounts receivable:

	March 31, 2005			March 31, 2004
Accounts receivable – trade	$	45,379		$	29,991
Accounts receivable – holdbacks		12,476			3,838
Accounts receivable – other		54			51
Allowance for doubtful accounts		(164	)		(233	)
	$	57,745		$	33,647

Reflective of its normal business, a majority of the Company’s accounts receivable is due from large companies operating in the resource sector. The Company regularly monitors the activity and balances in these accounts to manage its credit risk and provides an allowance for any doubtful accounts.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amount in thousands of Canadian dollars unless otherwise specified)

At March 31, 2005, the following customers represented 10% or more of accounts receivable and unbilled revenue:

	March 31, 2005		March 31, 2004
Customer A	8.6	%	28.7	%
Customer B	11.0	%	43.6	%
Customer C	32.8	%	0.0	%

“Accounts receivable – holdbacks” represent amounts up to 10% of billing that some of our customers have withheld, as part of common industry practice, until completion of the project. The customer is obligated to retain this amount in a lien fund to ensure that subcontractors are paid and to ensure that any remedial or warranty work is performed.

b) Accrued liabilities:

	March 31, 2005		March 31, 2004
Accrued interest payable	$	9,127	$	9,282
Payroll liabilities		2,283		2,849
Income and other taxes		1,679		2,563
Liabilities related to equipment leases		2,112		—
	$	15,201	$	14,694

c) Interest expense:

					Predecessor Company
	For the year ended March 31, 2005		for the period November 26, 2003 to March 31, 2004		for the period April 1, 2003 to November 25, 2003		for the year ended March 31, 2003
			Restated (note 3)
Interest on senior notes	$	23,189	$	8,096	$	—	$	—
Interest on senior secured credit facility		3,274		1,089		599		971
Interest on capital lease obligations		230		56		294		196
Interest on advances from Norama Inc.		—		—		1,468		2,223
Interest on long-term debt		26,693		9,241		2,361		3,390
Amortization of deferred financing costs		2,554		814		—		—
Other interest		1,894		24		96		772
	$	31,141	$	10,079	$	2,457	$	4,162

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amount in thousands of Canadian dollars unless otherwise specified)

d) Supplemental cash flow information:

					Predecessor Company
	for the year ended March 31, 2005		for the period November 26, 2003 to March 31, 2004		for the period April 1, 2003 to November 25, 2003		for the year ended March 31, 2003
Cash paid during the period for:
Interest	$	31,398	$	1,736	$	2,431	$	966
Income taxes		3,588		269		325		202
Cash received during the period for:
Interest		362		177		100		—
Income taxes		—		18		—		—
Non-cash transactions:
Capital leases		5,385		1,195		—		2,001

e) Net change in non-cash working capital:

							Predecessor Company
	for the year ended March 31, 2005			for the period November 26, 2003 to March 31, 2004			for the period April 1, 2003 to November 25, 2003			for the year ended March 31, 2003
Accounts receivable	$	(24,029	)	$	19,556		$	3,338		$	(6,730	)
Unbilled revenue		(13,735	)		(17,528	)		15,289			(12,054	)
Inventory		1,475			(1,609	)		—			—
Prepaid expenses		(590	)		(295	)		(544	)		179
Accounts payable		29,789			(2,839	)		(2,794	)		4,605
Accrued liabilities		507			6,172			(1,457	)		2,568
Billings in excess of costs and estimated earnings		1,325			—			—			—
	$	(5,258	)	$	3,457		$	13,832		$	(11,432	)

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amount in thousands of Canadian dollars unless otherwise specified)

f) Investment in joint venture

The Company has determined that the joint venture in which it participates is a variable interest entity (“VIE”) as defined by AcG-15 and that the Company is the primary beneficiary. Accordingly, the joint venture has been consolidated on a prospective basis effective January 1, 2005. During the fourth quarter of 2005, the arrangement of this joint venture has been amended such that the Company is responsible for all of its activities and revenues. As a result, no minority interest has been recorded.

The Company’s transactions with the joint venture eliminate on consolidation.

	March 31, 2005		March 31, 2004
Assets
Cash and cash equivalents	$	—	$	2
Accounts receivable		11,749		17
Unbilled revenue		20,932		—
	$	32,681	$	19
Liabilities
Accounts payable	$	5,065	$	14
Accrued liabilities		2,050		—
Venturer’s equity		25,566		5
	$	32,681	$	19

							Predecessor Company
	for the year ended March 31, 2005			for the period November 26, 2003 to March 31, 2004			for the period April 1, 2003 to November 25, 2003			for the year ended March 31, 2003
Revenue	$	43,175		$	4		$	340		$	—
Project costs		(41,213	)		21			(308	)		—
General and administrative		(3	)		(37	)		(5	)		—
Net income (loss)	$	1,959		$	(12	)	$	27		$	—
							Predecessor Company
	for the year ended March 31, 2005			for the period November 26, 2003 to March 31, 2004			for the period April 1, 2003 to November 25, 2003			for the year ended March 31, 2003
Cash used in:
Operating activities	$	(23,604	)	$	61		$	(49	)	$	—
Investing activities		–			—			—			—
Financing activities		23,602			(59	)		49			—
	$	(2	)	$	2		$	—		$	—

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amount in thousands of Canadian dollars unless otherwise specified)

14. Segmented information

a) General overview:

The Company conducts business in three business segments: Mining and Site Preparation, Piling and Pipeline.

• Mining and Site Preparation:

The Mining and Site Preparation segment provides mining and site preparation services, including overburden removal and reclamation services, project management and underground utility construction, to a variety of customers throughout Western Canada.

• Piling:

The Piling segment provides deep foundation construction and design build services to a variety of industrial and commercial customers throughout Western Canada.

• Pipeline:

The Pipeline segment provides both small and large diameter pipeline construction and installation services to energy and industrial clients throughout Western Canada.

b) Results by business segment:

For the year ended March 31, 2005	Mining and Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	264,835	$	61,006	$	31,482	$	357,323
Depreciation of property, plant and equipment		10,308		2,335		218		12,861
Segment profits		11,617		13,319		4,902		29,838
Segment assets		315,740		74,975		48,635		439,350
Expenditures for segment property, plant and equipment		16,888		202		774		17,864
For the period November 26, 2003 to March 31, 2004	Mining and Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	53,404	$	9,565	$	64,642	$	127,611
Depreciation of property, plant and equipment		3,116		465		383		3,964
Segment profits		8,154		2,501		12,892		23,547
Segment assets		264,822		76,896		68,751		410,469
Expenditures for segment property, plant and equipment		61		30		1,671		1,762

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amount in thousands of Canadian dollars unless otherwise specified)

Predecessor Company for the period April 1, 2003 to November 25, 2003	Mining and Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	182,368	$	39,417	$	28,867	$	250,652
Depreciation of property, plant and equipment		3,590		1,256		158		5,004
Segment profits		17,745		8,330		5,054		31,129
Segment assets		77,906		31,792		15,904		125,602
Expenditures for segment property, plant and equipment		2,591		417		—		3,008
Predecessor Company for the year ended March 31, 2003	Mining and Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	245,235	$	61,006	$	37,945	$	344,186
Depreciation of property, plant and equipment		5,631		2,111		184		7,926
Segment profits		31,415		12,483		6,300		50,198
Segment assets		89,501		29,289		24,670		143,460
Expenditures for segment property, plant and equipment		16,046		4,422		—		20,468

c) Reconciliations:

(i) Income (loss) before income taxes:

							Predecessor Company
	for the year ended March 31, 2005			for the period November 26, 2003 to March 31, 2004			for the period April 1, 2003 to November 25, 2003			for the year ended March 31, 2003
				Restated (note 3)
Total profit for reportable segments	$	29,838		$	23,547		$	31,129		$	50,198
Unallocated corporate expenses		(80,209	)		(40,437	)		(41,300	)		(24,559	)
Unallocated equipment revenue (costs)		5,794			(1,062	)		(7,592	)		(6,530	)
Income (loss) before income taxes	$	(44,577	)	$	(17,952	)	$	(17,763	)	$	19,109

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amount in thousands of Canadian dollars unless otherwise specified)

(ii) Total assets:

	March 31, 2005		March 31, 2004
			Restated (note 3)
Total assets for reportable segments	$	439,350	$	410,469
Corporate assets		87,318		79,205
Total assets	$	526,668	$	489,674

Substantially all of the Company’s assets are located in Western Canada and the activities are carried out throughout the year.

d) Customers:

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

					Predecessor Company
	for the year ended March 31, 2005		for the period November 26, 2003 to March 31, 2004		for the period April 1, 2003 to November 25, 2003		for the year ended March 31, 2003
Customer A	26.1	%	27.0	%	64.4	%	63.6	%
Customer B	7.7	%	10.7	%	9.1	%	14.6	%
Customer C	12.1	%	—		0.1	%	—
Customer D	9.6	%	50.7	%	11.5	%	11.0	%
Customer E	11.0	%	3.6	%	—		—

This revenue by major customer was earned in all three business segments: Mining and Site Preparation, Pipeline and Piling.

15. Related party transactions

All related party transactions described below are measured at the exchange amount of consideration established and agreed to by the related parties; all transactions are in the normal course of operations.

a) Transactions with Sponsors:

The Sterling Group, L.P. (“Sterling”), Genstar Capital, L.P., Perry Strategic Capital Inc., and Stephens Group, Inc., (the “Sponsors”), entered into an agreement with NACG Holdings Inc. and certain of its subsidiaries, including the Company, to provide consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. As compensation for these services, the Company paid the Sponsors, as a group, an annual advisory fee of $400 for the year ended March 31, 2005 (November 26, 2003 to March 31, 2004 - $133; April 1, 2003 to November 25, 2003 - $nil; year ended March 31, 2003 - $nil).

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amount in thousands of Canadian dollars unless otherwise specified)

b) Office rent:

Pursuant to several office lease agreements, for the year ended March 31, 2005 the Company paid $665 (November 26, 2003 to March 31, 2004 - $231; April 1, 2003 to November 25, 2003 – $427; year ended March 31, 2003 – $513) to a company owned, indirectly and in part, by one of the Directors. The office lease agreements were in effect prior to the acquisition described in note 4.

c) Predecessor company transactions:

Norama Inc., the parent company of Norama Ltd., charged a fee for management services provided to NACGI. The management fee was paid in reference to taxable income.

16. Financial instruments

The Company is exposed to market risks related to interest rate and foreign currency fluctuations. To mitigate these risks, the Company uses derivative financial instruments such as foreign currency and interest rate swap contracts.

a) Fair value:

The fair values of the Company’s cash and cash equivalents, accounts receivable, unbilled revenue, costs in excess of billings, inventory, prepaid expenses, accounts payable, accrued liabilities, and billings in excess of cost approximate their carrying amounts.

The fair value of the senior secured credit facility, senior notes and capital lease obligations (collectively “the debt”) are based on management estimates which are determined by discounting cash flows required under the debt at the interest rate currently estimated to be available for loans with similar terms. Based on these estimates, the fair value of the Company’s debt as at March 31, 2005 is not significantly different than its carrying value.

b) Interest rate risk:

The Company is subject to interest rate risk on the senior secured credit facility and capital lease obligations. At March 31, 2005, for each 1% annual fluctuation in the interest rate, the annual cost of financing will change by approximately $635.

The Company also leases equipment (as described in note 17) with a variable lease payment component that is tied to prime rates. At March 31, 2005, for each 1% annual fluctuation in these rates, annual lease expense will change by approximately $293.

c) Foreign currency risk and derivative financial instruments:

The Company has senior notes denominated in U.S. dollars in the amount of US$200 million. In order to reduce its exposure to changes in the U.S. to Canadian dollar exchange rate, the Company, concurrent with the closing of the acquisition on November 26, 2003, entered into a cross-currency swap agreement to manage this foreign currency exposure for both the principal balance due on December 1, 2011 as well as the semi-annual interest payments through the whole period beginning from the issuance date to the maturity date. In conjunction with the cross-currency swap agreement, the Company also entered into a U.S. dollar interest rate swap and a Canadian dollar interest rate swap with the net effect of converting the 8.75% rate payable on the senior notes into a fixed rate of 9.765% for the duration that the senior notes are outstanding. Due to the technical deficiencies outlined in note 3, these derivative financial instruments do not qualify for hedge accounting.

The carrying amount and fair value of the Company’s derivative financial instruments are as follows:

	Carrying Amount			Fair Value
Cross-currency and interest rate swaps	$	(51,723	)	$	(51,723	)

The fair values of the Company’s cross-currency and interest rate swap agreements are based on values quotes by the counterparties to the agreements.

At March 31, 2005, the notional principal amount of the cross-currency swap was US$200 million. The notional principal amounts of the interest rate swaps were US$200 million and Cdn$263 million.

Credit risk results from the possibility that a counterparty to a derivative in which the Company has an unrealized gain fails to perform according to the terms of the contract. Credit exposure is minimized through the use of established credit management techniques, including formal assessment processes, contractual and collateral requirements, master netting arrangements, and credit exposure limits.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amount in thousands of Canadian dollars unless otherwise specified)

d) Operating leases:

The Company is subject to foreign currency risk on U.S. dollar operating lease commitments.

17. Commitments

The annual future minimum lease payments in respect of operating leases for the next five fiscal years are as follows:

2006	$	11,492
2007		11,511
2008		7,315
2009		618
2010		307
	$	31,243

18. Employee contribution plans

The Company and its subsidiaries match voluntary contributions made by the employees to their Registered Retirement Savings Plans to a maximum of 5% of base salary for each employee. Contributions made by the Company during the year ended March 31, 2005 were $305 (November 26, 2003 to March 31, 2004 - $68; April 1, 2003 to November 25, 2003 - $122; year ended March 31, 2003 - $166).

19. Stock-based compensation plan

Under the 2004 Share Option Plan, Directors, Officers, employees and service providers to the Company are eligible to receive stock options to acquire common shares in NACG Holdings Inc. The stock options expire in ten years or on termination of employment. Options may be exercised at a price determined at the

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amount in thousands of Canadian dollars unless otherwise specified)

time the option is awarded, and vest as follows: no options vest on the award date and twenty per cent vest on each of the five following award date anniversaries. The maximum number of common shares issuable under this plan may not exceed 92,500, of which 16,258 are still available for issue as at March 31, 2005.

The fair value of each option granted by NACG Holdings Inc. was estimated using the Black-Scholes option-pricing model assuming: a dividend yield of nil%; a risk-free interest rate of 4.25%; volatility of nil%; and an expected option life of 10 years.

	Number of options		Weighted average exercise price $ per share
Outstanding at March 31, 2004	54,130		$	100.00
Granted	24,112			100.00
Exercised	—			—
Forfeited	(2,000	)		100.00
Outstanding at March 31, 2005	76,242		$	100.00
	Number of options		Weighted average exercise price $ per share
Outstanding at November 26, 2003	—		$	—
Granted	54,130			100.00
Exercised	—			—
Forfeited	—			—
Outstanding at March 31, 2004	54,130		$	100.00

At March 31, 2005, the range of exercise prices, the weighted average exercise price and the weighted average remaining contractual life are as follows:

	Options outstanding
Exercise price	Number outstanding	Weighted average remaining contractual life (years)	Weighted average exercise price
$100	76,242	8.9	$	100.00

The Company recorded $497 of compensation expense related to the stock options in the year ended March 31, 2005 (November 26, 2003 to March 31, 2004 – $137; April 1, 2003 to November 25, 2003 – $nil; year ended March 31, 2003 – $nil) with such amount being credited to contributed surplus.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amount in thousands of Canadian dollars unless otherwise specified)

20. Comparative figures

Certain of the comparative figures have been reclassified to be consistent with the current period’s presentation.

21. United States generally accepted accounting principles (Restated)

These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in Canada (“Canadian GAAP”) which differ in certain respects from accounting principles generally accepted in the United States (“U.S. GAAP”). For the periods presented herein, material issues that could give rise to measurement differences in the consolidated financial statements are as follows:

Restatement related to derivative financial instruments and hedging activities:

As a consequence of the restatement described in note 3 of the interim consolidated financial statements, the Company determined that it was necessary to restate all reported periods after November 26, 2003 to eliminate the use of hedge accounting. As a result, the foreign exchange gain or loss related to the senior notes are recorded in each period and the derivative financial instruments are recorded at fair value and the realized and the unrealized gains and losses on derivative financial instruments have been recognized as either an increase or decrease in the Company’s Statement of Operations, along with the associated future income tax effects.

As a result of the restatement, there are no measurement or differences related to the accounting for derivative financial instruments under Canadian GAAP in accordance with EIC-128 and U.S. GAAP in accordance with Statement of Financial Accounting Standards No. 133 (“SFAS 133”), as amended.

Reporting comprehensive income:

Statement of Financial Accounting Standards No. 130 (“SFAS 130”), “Reporting Comprehensive Income,” establishes standards for the reporting and display of comprehensive income and its components in a full set of general purpose financial statements. Comprehensive income equals net income (loss) for the period as adjusted for all other non-owner changes in shareholders’ equity. SFAS 130 requires that all items that are not required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement. The only components of comprehensive earnings (loss) are the net earnings (loss) for the period.

Stock-based compensation:

The Company uses the fair value method of accounting to all stock-based compensation payments as prescribed by Statement of Financial Accounting Standards No. 123 (“SFAS 123”).

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amount in thousands of Canadian dollars unless otherwise specified)

Recent United States accounting pronouncements not yet adopted:

Statement on Financial Accounting Standards No. 123R, “Share-Based Payment” (“SFAS 123R”) requires companies to recognize in the income statement, the grant-date fair value of stock options and other equity-based compensation issued to employees. The fair value of liability-classified awards is remeasured subsequently at each reporting date through the settlement date, while the fair value of equity-classified awards is not subsequently remeasured. The alternative to use the intrinsic value method of APB Opinion 25 is eliminated with this revised standard. The Company is currently evaluating the impact of this revised standard. The revised standard is effective for non-public companies beginning of the first annual reporting period that begins after December 15, 2005, in the case of the Company beginning April 1, 2006. The Company is required to adopt this standard using the modified prospective or modified retrospective transition method.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amount in thousands of Canadian dollars unless otherwise specified)

SFAS 153, “Exchanges of Non-monetary Assets – an Amendment of APB Opinion 29”, was issued in December 2004. Accounting Principles Board (“APB”) Opinion 29 is based on the principle that exchanges of non-monetary assets should be measured based on the fair value of assets exchanged. SFAS 153 amends APB Opinion 29 to eliminate the exception for non-monetary exchanges of similar productive assets and replaces it with a general exception for exchanges of non-monetary assets that do not have commercial substance. The standard is effective for the Company for non-monetary asset exchanges occurring in fiscal 2006 and will be applied prospectively. The adoption of this standard is not expected to have a material impact on the Company’s financial statements.

In November 2004, the FASB issued SFAS 151, “Inventory Costs.” This standard requires the allocation of fixed production overhead costs be based on the normal capacity of the production facilities and unallocated overhead costs recognized as an expense in the period incurred. In addition, other items such as abnormal freight, handling costs and wasted materials require treatment as current period charges rather than a portion of the inventory cost. This standard is effective for fiscal 2006 of the Company. The adoption of this standard is not expected to have a material impact on the Company’s financial statements.

In March 2005, the FASB issued FIN 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143” (“FIN 47”), which requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. FIN 47 is effective for fiscal years ending after December 15, 2005. The adoption of this standard is not expected to have a material impact on the Company’s financial statements.

In May 2005, the FASB issued SFAS 154, “Accounting Changes and Error Corrections” (“SFAS 154”) which replaces Accounting Principles Board Opinions No. 20 “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements – An Amendment of APB Opinion No. 28.” SFAS 154 provides guidance on the accounting for and reporting of accounting change and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal year beginning after December 15, 2005 and is required to be adopted by the Company in the fourth quarter of fiscal 2006. The Company is currently evaluating the effect that the adoption of SFAS 154 will have on its consolidated results of operations and financial condition but does not expect it to have a material impact.

22. Subsequent event

On May 19, 2005, the Company issued senior secured notes in the amount of US$60.481 million, repaid the $20.0 million revolving credit facility and the $41.25 million term credit facility and entered into a new revolving credit facility for borrowings up to $40 million, that together with the senior secured notes replaces the company’s previous senior credit facility. The notes mature on June 1, 2010 and bear interest at 9% payable semi-annually on June 1 and December 1 of each year.

The notes are secured obligations and rank senior in right of payment to all existing subordinated debt and rank equally in right of payment to all existing and future senior debt of the Company, including the new revolving credit facility. However, the notes are effectively subordinated to the Company’s swap agreements and new revolving credit facility to the extent of the value of the assets securing such debt.

The senior secured notes are redeemable at the option of the Company at any time on or after: June 1, 2008 at 104.50% of the principal amount; June 1, 2009 at 102.25% of the principal amount; June 1, 2010 at 100.00% of the principal amount; plus, in each case, interest accrued to the redemption date.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the year ended March 31, 2005

(Amount in thousands of Canadian dollars unless otherwise specified)

The Company has not hedged its exposure to changes in the U.S. to Canadian dollar exchange rate resulting from the issuance of these notes.

The new revolving facility provides for borrowings of up to $40.0 million, subject to borrowing base limitations, under which revolving loans may be made and letters of credit, up to a limit of $30.0 million, may be issued. The facility bears interest at the Canadian prime rate plus 2% or Canadian bankers’ acceptance rate plus 3%. The indebtedness under the revolving credit facility is secured by substantially all of the Company’s assets and those of its subsidiaries, including accounts receivable, inventory and property, plant and equipment, and a pledge of the Company’s capital stock and that of its subsidiaries.

In connection with the new revolving credit facility, the Company was required to amend its existing swap agreements to increase the effective rate of interest on its 8¾% senior notes from 9.765% to 9.889% and to issue to one of the counterparties to the swap agreements $1.0 million of mandatorily redeemable preferred shares. These preferred shares are not entitled to accrue or receive dividends and are required to be redeemed on or before December 31, 2011.

On May 19, 2005 the Company issued 7,500 mandatorily redeemable preferred shares to existing shareholders of NACG Holdings Inc. for total cash proceeds of $7.5 million. These shares pay cumulative dividends of 15% per year if the 9% senior secured notes due 2010 and 8¾% senior notes due 2011 are outstanding. The shares are redeemable at the option of the Company at any time, and are required to be redeemed on December 31, 2011 or earlier in the event of a change in control or an initial public offering of equity securities and the repayment of 8 ³/4% senior unsecured notes due in 2011 and the 9% senior secured notes due in 2010. The redemption amount is the greater of:

a) $15.0 million less the amount, if any, of dividends previously paid in cash;

b) an amount that, when combined with the amount, if any, of dividends previously paid in cash, provides a 40% internal rate of return, compounded annually from the date of issue; and

c) 25% of the fair market value of the equity of the company, and in any event, will not exceed $100 million under the terms of the agreement.

The net proceeds from the issuance of the senior secured notes and the preferred shares to the Sponsors were used to repay the Company’s indebtedness under its senior secured credit facility, to pay related fees and expenses, and for general corporate purposes.

On July 26, 2005, the senior secured notes issued on May 19, 2005 were exchanged for substantially identical notes registered under the Securities Act.