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, 2004

or

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

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, 2004

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  ¨    NO  x

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

TABLE OF CONTENTS

			Page
GLOSSARY OF CERTAIN TERMS AND DEFINITIONS
PART I
	ITEM 1:	IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS	4
	ITEM 2:	OFFER STATISTICS AND EXPECTED TIMETABLE	4
	ITEM 3:	KEY INFORMATION	4
	ITEM 4:	INFORMATION ON THE COMPANY	10
	ITEM 5:	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	22
	ITEM 6:	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	34
	ITEM 7:	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	40
	ITEM 8:	FINANCIAL INFORMATION	45
	ITEM 9:	THE OFFER AND LISTING	45
	ITEM 10:	ADDITIONAL INFORMATION	46
	ITEM 11:	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	47
	ITEM 12:	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	47
PART II
	ITEM 13:	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	47
	ITEM 14:	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	48
	ITEM 15:	CONTROLS AND PROCEDURES	48
	ITEM 16:	[RESERVED]	48
	ITEM 16A	AUDIT COMMITTEE FINANCIAL EXPERT	48
	ITEM 16B	CODE OF ETHICS	48
	ITEM 16C	PRINCIPAL ACCOUNTANT FEES AND SERVICES	48
	ITEM 16D	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES	48
	ITEM 16E	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS	49
PART III
	ITEM 17:	FINANCIAL STATEMENTS	49
	ITEM 18:	FINANCIAL STATEMENTS	49
	ITEM 19:	EXHIBITS	49

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As used in this annual report on Form 20-F, unless the context otherwise indicates, the terms “NAEPI”, “we”, “us”, “our” or the “Company” refer to 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, 2004, the noon buying rate as quoted by the Federal Reserve Bank of New York was $1.3100 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.

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

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:

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

• our ability to retain a skilled labor force and continue to bid successfully on new projects;

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

• technological developments;

• capital markets conditions;

• inflation;

• foreign currency exchange rates;

• interest rates;

• weather conditions;

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• 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.

You are cautioned not to put undue reliance on any forward-looking statements, and we undertake no obligation to update those statements.

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, 2000, 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 from 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 19 to our consolidated financial statements at Item 18.

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The following table should be read in conjunction with “Item 5: Operating and Financial Review and Prospects” and our consolidated financial statements included in Item 18.

	Predecessor Year Ended March 31,
	2000			2001			2002			2003			2004(a)
	(dollars in thousands)
Statement of Operations Data:
Revenue	$	181,157		$	247,267		$	249,351		$	344,186		$	378,533
Project costs		96,039			120,728			127,996			219,979			240,043
Equipment costs		40,728			71,518			77,289			72,228			69,102
Depreciation		7,736			10,409			11,299			10,974			13,240
Gross Profit		36,654			44,612			32,767			41,005			56,148
General and administrative		7,222			9,582			12,794			12,233			14,037
Loss (gain) on sale of capital assets		(406	)		(979	)		(218	)		(2,265	)		82
Amortization of intangible assets (b)		—			—			—			—			12,928
Operating Income		29,838			36,009			20,191			31,037			29,101
Management fee (c)		13,420			36,550			14,400			8,000			41,070
Interest expense, net		1,276			3,034			3,510			4,162			13,148
Foreign exchange (gain) loss		—			—			(17	)		(234	)		72
Income (loss) before income taxes		15,142			(3,575	)		2,298			19,109			(25,189	)
Income taxes		6,897			(3,667	)		689			6,620			(9,492	)
Net earnings (loss)	$	8,245		$	92		$	1,609		$	12,489		$	(15,697	)
U.S. GAAP:
Other comprehensive income		—			—			—			—		$	(10,905	)
Balance Sheet Data (end of period):
Cash	$	1,924		$	11,247		$	436		$	651		$	36,595
Total assets		97,237			129,527			120,431			158,584			489,389
Total debt		31,675			54,678			50,137			63,401			314,538
Total shareholder’s equity		16,678			16,770			17,379			29,818			123,081
Other Financial Data:
EBITDA (d)	$	24,154		$	9,868		$	17,107		$	34,245		$	14,127
Capital expenditures		15,624			18,547			8,668			22,932			7,735
Ratio of earnings to fixed charges (e)		5.4x			—			1.3x			4.1x			—
Other Data:
Equipment hours (f)		472,973			644,087			583,071			673,811			695,081

(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, trade names, customer relationships, non-competition agreement and employee retention bonuses.

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

(d) 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 measure of the performance of 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 capital assets 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. GAAP, and EBITDA is not necessarily an indication of whether cash flow will be sufficient to fund our cash requirements. In addition, our definition of EBITDA may differ from that of other companies. EBITDA has been reduced by management fees and equipment leases and rentals as reflected in the statement of operations above. In connection with the acquisition, these management fees were terminated upon the closing and a substantial portion of our equipment leases and rentals expense were terminated as a result of the purchase of the related equipment also at the closing date.

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

	Predecessor
	Year Ended March 31,
	2000		2001			2002		2003		2004
Net earnings (loss)	$	8,245	$	92		$	1,609	$	12,489	$	(15,697	)
Adjustments:
Depreciation		7,736		10,409			11,299		10,974		13,240
Amortization		—		—			—		—		12,928
Interest expense, net		1,276		3,034			3,510		4,162		13,148
Income taxes		6,897		(3,667	)		689		6,620		(9,492	)
EBITDA	$	24,154	$	9,868		$	17,107	$	34,245	$	14,127

(e) For the purposes of calculating the ratio of earnings to fixed charges, (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 obligations. During the periods presented, no interest costs have been capitalized. The dollar amount of the deficiency as calculated in accordance with U.S. GAAP was $3,575 for the fiscal year ended March 31, 2001, and $25,189 for the year ended March 31, 2004.

(f) Calculated as actual hours of operation 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 the equipment.

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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, 2004, the Noon Buying Rate was $1.00 = US$0.7595.

	2004
	March	April	May	June	July	August
High for period	0.7645	0.7637	0.7364	0.7459	0.7644	0.7714
Low for period	0.7418	0.7293	0.7177	0.7261	0.7489	0.7506

	Year Ended March 31,
	2000	2001	2002	2003	2004
Average for period	0.6725	0.6651	0.6392	0.6455	0.7412

B. CAPITALIZATION AND INDEBTEDNESS

Not applicable.

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 91% of our total revenue for the fiscal year ended March 31, 2004 and those customers are expected to continue to provide a significant percentage of our revenues in the future. Each year any one of our customers may constitute a significant portion of our revenue. For example, for the fiscal year ended March 31, 2004, revenue generated from work for Syncrude constituted approximately 52% of our total revenue primarily 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 five 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.

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

Approximately 52% of our revenue for the fiscal year ended March 31, 2004 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.

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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 project revenues constituted approximately 29%, 29% and 52% of our revenues in the fiscal years ended March 31, 2004, 2003 and 2002, 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.

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, 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.

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.

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, 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.

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.

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.

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.

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, 2004 we generated approximately 67% of our operating 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.

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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.

In the province of Alberta, collective bargaining in the construction industry is subject to registration. A registered employer’s 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 employer’s organization is binding on all such employers. The primary term of some of these collective agreements has expired, however the agreements continue in force from year to year until they are terminated by a strike or lockout. Negotiations are underway between representatives of the employers organization and the union in respect of some of these agreements. New agreements may not be reached without a work stoppage or, if reached, the terms may significantly increase our costs. We do not have control over the terms of such agreements but will be bound by these because of registration.

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

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.

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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.

Fixed price contracts with our customers could expose us to losses if our estimates of project costs are too low or if we fail to perform within our cost estimates.

A portion of our revenue is derived from fixed price (lump sum) 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 in this market is therefore dependent upon our ability to accurately predict the costs associated with our services. These costs may be affected by a variety of factors, some of which may be beyond our control. If we are unable to accurately estimate the costs of fixed price contracts, or if we incur unrecoverable cost overruns, some projects could have lower margins than anticipated or even incur losses, which could have a material adverse effect on our business. Approximately 5% of our revenue for the fiscal year ended March 31, 2004 was derived from fixed price contracts.

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.

If our access to the surety market were to be restricted in the future, 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 have been able to secure necessary bonds and we will seek opportunities to expand our surety relationships. However, if for any reason, whether because of our 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.

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.

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;

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• 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.

Loss of key personnel could adversely affect our business.

Many of our senior officers are important to our management and direction. In particular, Gordon Parchewsky, our President, and William Koehn, our Vice President, Operations, are considered to be key due to their long-term relationships with our largest customers. Our future success depends on our ability to retain these officers. Competition in recruiting replacement personnel could be significant. If we are not successful in retaining our key personnel or replacing them, our business, financial condition or results of operations could be adversely affected. We do not maintain key personnel insurance.

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.

ITEM 4: INFORMATION ON 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. for approximately $191 million in cash, net of cash received and including the impact of various post-closing adjustments. NACG Preferred Corp. contributed the 30 shares of North American Construction Group Inc. it received to us, and we contributed these shares to NACG Acquisition Inc. Additionally, North American Equipment Ltd., a wholly-owned subsidiary of Norma 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, Alberta, T7X 5A7. Our telephone and facsimile numbers are (780) 960-7171 and (780) 960-7103, respectively. Our authorized capital consists of an unlimited number of common shares of which 100 were issued and outstanding as of March 31, 2004.

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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 the major integrated and independent oil and gas, petrochemical and other natural resources companies operating in this geographic region. In serving our customers, we operate over 400 pieces of heavy equipment and over 500 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 is a result of focusing 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; site preparation, which includes 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;

• piling installation for plant, refinery and commercial building construction; and

• pipeline installation for oil and gas transmission.

For the fiscal year ended March 31, 2004, we had revenue of $378.5 million. Our revenues grew at a compounded annual growth rate of over 20% from fiscal 2000 to 2004.

We generate approximately 80% 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 Canadian Association of Petroleum Producers, or CAPP, there are approximately 6.9 billion barrels of proved oil reserves at currently producing oil sands properties. Alberta Economic Development, or AED, estimates that from 1996 to 2002, approximately $23 billion was invested in the Alberta oil sands. From 2003 to 2012, AED estimates that if all announced projects are completed as planned, approximately $71 billion will be spent to sustain and expand existing oil sands projects and develop new projects. We believe that approximately 10% to 20% of these expenditures will relate to services we perform and on which we may bid, though there is no assurance that we will be successful in obtaining any of this work.

We have long-term, stable relationships with our customers, some of whom we have been serving for over 40 years. We believe we are the principal provider of mining and site preparation and piling services in the Alberta oil sands to Syncrude Canada Ltd., our largest customer and the largest producer of bitumen in the oil sands, and other major operators in the area. We also provide pipeline installation services in British Columbia to EnCana Corporation. We estimate that over 90% of our revenues from fiscal year 2001 to 2004 was attributable to private sector oil and gas projects in Alberta and British Columbia.

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 business unit for the fiscal years ended March 31, 2000 through March 31, 2004:

	Year Ended March 31,
	2000				2001				2002				2003				2004
	(dollars in thousands)
Mining and site preparation	$	100,420	55.4	%	$	153,152	61.9	%	$	186,141	74.6	%	$	245,235	71.3	%	$	236,092	62.4	%
Piling		52,301	28.9			36,709	14.9			35,132	14.1			61,006	17.7			48,933	12.9
Pipeline		28,436	15.7			57,406	23.2			28,078	11.3			37,945	11.0			93,508	24.7
Total	$	181,157	100.0	%	$	247,267	100.0	%	$	249,351	100.0	%	$	344,186	100.0	%	$	378,533	100.0	%

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Mining and site preparation

Our mining and site preparation business unit 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 500 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, 2004, revenues from this segment accounted for 62% of our total revenues. Revenues for this segment grew at a compounded annual growth rate of 24% from fiscal 2000 through fiscal 2004.

Many progressive Alberta oil sands and natural resource mining companies are increasingly utilizing 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 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, 2004, revenues from this segment accounted for 13% of our total revenues. Revenues for this segment have declined at a compounded annual rate of 2% from fiscal 2000 through fiscal 2004.

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Pipelines

We install field, transmission and distribution pipe made of steel, plastic and fiberglass materials in all sizes up to and including 36 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, 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. Despite our limited client base in this segment over the past three 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, 2004, revenues from this segment accounted for 25% of our total revenues. Revenues for this segment grew at a compounded annual growth rate of 35% from fiscal 2000 through fiscal 2004.

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. Favorable dynamics in each of these markets have resulted in a significant increase in the demand for our services over the last five years.

The following table reflects our revenues by market segment for the fiscal years ended March 31, 2000 through March 31, 2004:

	Year Ended March 31,
	2000				2001				2002				2003				2004
	(dollars in thousands)
Alberta oil sands	$	133,457	73.7	%	$	169,385	68.5	%	$	187,774	75.3	%	$	276,462	80.3	%	$	252,869	66.8	%
Conventional oil and gas and minerals	$	40,472	22.3		$	65,139	26.3		$	34,502	13.8		$	42,470	12.3		$	106,994	28.3
Commercial and public	$	7,228	4.0		$	12,743	5.2		$	27,075	10.9		$	25,254	7.4		$	18,670	4.9
Total	$	181,157	100.0	%	$	247,267	100.0	%	$	249,351	100.0	%	$	344,186	100.0	%	$	378,533	100.0	%

Alberta oil sands

Revenue generated by providing services in the Alberta oil sands market accounted for $252.8 million, or 67%, of our total revenue during the fiscal year ended March 31, 2004. Over the four year period from fiscal year ended March 31, 2000 to 2004, we realized a revenue compounded annual growth rate of 17% in this market by providing mining and site preparation and piling services to our oil and gas customers operating in the Alberta oil sands. In serving this market, we currently operate approximately 200 pieces of heavy equipment and employ approximately 1,000 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 and Albian, 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

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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 60% of oil sands production is currently derived by open pit mining. The remaining 40% 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 CAPP, oil sands production is currently approximately one million barrels per day, and accounts for approximately 31% of total Canadian oil production. By 2010, CAPP estimates that oil sands production will be nearly double 2003 production levels. According to AED, from 1996 through 2002, an estimated $23 billion was invested in the Alberta oil sands, either to sustain and expand existing projects or develop new projects. From 2003 to 2012, based on a compilation of announced projects, approximately $71 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 1.8% annually between 2001 and 2020. Over that same time period, net imports as a percentage of supply are expected to increase from 55.4% in 2001 to 65.3% in 2020. 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 31% 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.

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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). 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. Revenue generated by providing services in the conventional oil and gas and minerals mining services market accounted for $107 million, or approximately 28%, of our total revenue during the fiscal year ended March 31, 2004. Over the four year period from fiscal year ended March 31, 2000 to 2004, we realized a compounded annual growth rate of 27%. 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 the world’s third largest producer and second largest exporter 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 Northwest Territories and the Yukon are thought to hold great potential for new gas discoveries. In addition, 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, five leading energy companies have announced their intention to jointly spend $5 billion to construct the pipeline. We anticipate participating in this and other expansion projects.

Commercial and public construction services

Revenue generated by providing services in this market accounted for $18.7 million, or 5%, of our total revenue during the fiscal year ended March 31, 2004. Less than $4.8 million of this revenue was generated from publicly bid government work. Over the four

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year period from fiscal year ended March 31, 2000 to 2004, we realized a revenue compounded annual growth rate of 27% in this market by providing mining and 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 GDP growth of 1.5% in 2002. By comparison, Alberta’s GDP grew 1.7% 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 double the national pace. According to the Alberta government, the provincial economy is expected to experience average GDP growth of 3.6% from 2003 to 2004 and 3.4% through 2006. The Alberta government has responded to the strain this growth will have on public facilities and infrastructure by allocating approximately $5.5 billion over the next three years for improvement and expansion projects. 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 and Suncor. We also have large mining customers outside of the Alberta oil sands. For example, we are currently performing a coal mine services contract for Kemess Mines Ltd. with an estimated value of over $15 million. We also perform commercial construction-related services for other customers in the public and private sectors. Our largest customer, Syncrude, accounted for 52%, 64%, and 38%, of our revenues for the fiscal years ended March 31, 2004, 2003 and 2002, respectively. Collectively, our largest five customers represented approximately 91%, 93%, and 88% 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 fixed price. 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. For the fiscal year ended March 31, 2004, approximately 4% of our revenue was generated from this type of contract.

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. For the fiscal year ended March 31, 2004, approximately 67% of our revenue was generated from this type of contract.

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 mining and site preparation 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

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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. For the fiscal year ended March 31, 2004, approximately 24% of our revenue was generated from this type of contract.

A fixed price, or 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. For the fiscal year ended March 31, 2004, approximately 5% of our revenue was generated from this type of contract.

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.

Major Suppliers

We have preferred supplier relationships with the following equipment suppliers: Finning Canada Ltd. (45 years), Wajax Industries Ltd. (20 years) and Brandt Tractor (30 years). Finning Canada Ltd. 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.

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 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, 2002 through 2004 were

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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.

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.

Capital Expenditures

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

	Year Ended March 31,
	2002		2003			2004
	(thousands)
Mining & Site Preparation	$	5,386	$	16,046	(1)	$	2,519
Piling		74		4,422			447
Pipeline		—		—			1,671
Other		3,208		2,464			3,098
Total	$	8,668	$	22,932		$	7,735

⁽¹⁾ excludes $10,500 in new capital leases.

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. was formed in connection with the acquisition and has no business operations. The following chart depicts our organizational structure. All of the entities in the chart are wholly-owned by their respective parent.

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D. PROPERTY, PLANTS AND EQUIPMENT

Equipment

We operate and maintain over 400 pieces of heavy equipment, including crawlers, graders, loaders, mining trucks, compactors, scrapers and excavators, as well as over 500 support vehicles, including various service and maintenance vehicles. The equipment is in good condition, normal wear and tear excepted.

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The following table sets forth our fleet of heavy equipment as of March 31, 2004:

Category	Manufacturer	Average		Number in Fleet
		Capacity(a)	Horsepower
Mining and site preparation:
Articulating trucks	Caterpillar, Hitachi	34 tons	322	18
Mining trucks	Caterpillar, Euclid/Hitachi, Titan	170 tons	1,625	58
Shovels	Hitachi, O&K	42 cubic yards	3,050	3
Excavators	Komatsu, John Deere, Hitachi, Caterpillar	3 cubic yards	307	82
Crawler tractors	John Deere, Komatsu, Caterpillar	n/a	299	56
Graders	Caterpillar	n/a	275	15
Scrapers	Caterpillar	n/a	450	14
Loaders	Michigan, Caterpillar, Case, Volvo, Komatsu, John Deere	3 cubic yards	140	36
Skidsteer loaders	Case, Melroe, Skidsteer, Gehl, John Deere	1 cubic yard	87	34
Packers	Caterpillar, Ingersoll Rand	28,500 lbs	173	16
Pipeline:
Snow cats	Terra Tucker	n/a	174	1
Trenchers	Barber Green	n/a	330	2
Pipelayers	John Deere, Caterpillar	110,000 lbs	263	34
Piling:
Drill rigs	Texoma, Drilling Technique Ltd., Soil Mec, Watson 2500	76 ft(b)	194	27
Cranes	P&H, Link-Belt, American, Sumitomo, Bucyrus, Lima	64 tons	196	17
			Total:	413

(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 76 of these large earthmoving vehicles that have a total hauling capacity of approximately 10,500 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, 2004, 2003 and 2002, we spent $48.1 million, $44.1 million, and $50.0 million, respectively, to maintain our equipment in superior working condition. We possess a relatively young mining equipment fleet with an average life of approximately 5 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 2004 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
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.

(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, 2005.

(h) Lease expires July 10, 2008.

(i) Lease expires March 14, 2008.

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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

Overview

We provide mining and site preparation, piling and pipeline installation services in western Canada. We provide our services primarily to the major integrated and independent oil and gas, petrochemical and other natural resources companies operating in this geographic region. Our services consist of:

• surface mining for oil sands and other natural resources, including 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 owner’s mining operations, construction of infrastructure associated with mining operations and reclamation activities; site preparation, which includes 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;

• piling installation, including 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; and

• pipeline installation, including the installation of transmission and distribution pipe made of steel, plastic and fiberglass materials in sizes up to and including 36 inches in diameter for oil and gas transmission.

With over 50 years of operations, we are one of the largest independent equipment owners in western Canada. In serving our customers, we operate over 400 pieces of heavy equipment and over 500 support vehicles. Our fleet size allows us to offer greater flexibility in scheduling contract services on a timely basis and to take on long-term, large-scale projects with the major operators in the oil sands development and in other energy sectors.

Financial statement presentation

Pursuant to a corporate reorganization, effective July 31, 2003, all the issued common shares of North American Equipment Ltd., or “NAEL,” and North American Construction Group Inc., or “NACGI,” were transferred from Norama Inc. to its new wholly-owned subsidiary, Norama Ltd. The financial statements of Norama Ltd. have been prepared using the continuity-of-interest method of accounting. Accordingly, the consolidated financial statements of Norama Ltd. reflect the combined carrying values of the assets, liabilities and shareholder’s equity, and the combined operating results of NAEL and NACGI for all periods presented. Material intercompany transactions and balances are eliminated on consolidation.

The Acquisition

We are wholly owned by NACG Preferred Corp., which is in turn wholly owned by NACG Holdings Inc. The common equity of NACG Holdings Inc. is primarily owned by an investor group which includes The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc., Stephens Group, Inc. and BNP Paribas Private Capital Group, through Paribas North America, Inc., as well as our management and employees.

Prior to November 26, 2003, NAEL and NACGI were wholly owned subsidiaries of Norama Ltd., sometimes referred to as the “predecessor company”. On November 26, 2003, Norama sold 30 common shares of NACGI to NACG Preferred Corp. and all of the remaining 170 common shares of NACGI to NACG Acquisition Inc., our wholly owned subsidiary. In addition, Norama sold substantially all of NAEL’s assets to NACG Acquisition Inc. The preceding events are referred to in this section as the “acquisition”. Immediately after the consummation of the acquisition, NACG Acquisition Inc. was amalgamated with NACGI and the successor company continued as NACGI.

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The information as of March 31, 2004 and for the period from November 26, 2003 to March 31, 2004, may not be directly comparable to the information provided related to the predecessor company as a result of 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 U.S. GAAP.

Critical Accounting Policies

The following critical and significant accounting policies are more fully described in note 2 to our consolidated financial statements included in Item 18. Some accounting policies require management to make significant estimates and assumptions about future events that affect the amounts reported in its 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

The majority of our contracts with our clients fall under the following types of contracts: time-and-materials, unit price, cost-plus-fixed-fee, and fixed price (lump sum) and are generally less than one year in duration.

• Time-and-materials — This type of contract requires us to provide equipment and labor on an hourly basis to perform tasks requested by our clients. The labor and equipment hourly billing rates are calculated by us through careful consideration of all costs expected to be incurred as a result of providing the required services. In addition, we incorporate a mark-up within the billing rates to generate the required profit margin.

Revenue is recognized as the labor and equipment hours are incurred and supplied to our client, and as materials, subcontractors and other costs are incurred.

• Unit price — Under this type of contract, we are paid a specified amount for every unit of work performed, for example, cubic meters of earth moved, lineal meters of pipe installed or completed piles. The price per unit of work performed is calculated by estimating all of the costs expected to be incurred by us in performing the unit of work and adding an appropriate amount to the rate to generate the required profit margin.

Revenues related to unit price contracts are recognized as applicable quantities, i.e., cubic meters, lineal meters, completed piles, are completed.

• Cost-plus-fixed-fee — Under this type of contract, we bill our clients based on our actual costs incurred to provide the required services. We are reimbursed for all allowable or otherwise defined costs incurred plus a pre-arranged fee that represents profit to us.

Revenues are recognized as the costs are incurred, and the revenues related to the fixed fee are recognized pro-rata based on actual incurred costs to date, as compared to total expected costs.

• Fixed Price (lump sum) — Under this type of contract, 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 client are priced incrementally to the original bid or lump sum. Similar to unit price contracts, the price charged to the client for the services performed is calculated by estimating all of the costs expected to be incurred by us in performing services required by the contract and adding an appropriate amount to the contract price to generate the required profit margin. This type of contract historically represents only a small portion of our overall work.

Revenues on fixed price (lump sum) contracts are recognized on the percentage-of-completion method, measured by the ratio of costs incurred to date to estimated total costs. In the absence of reliable output measures like cubic meters, lineal meters or completed piles, 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 an agreement has been reached with clients as to both the scope of work and

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price. Revenue from claims is recognized when an agreement is reached with clients as to the value of the claims, which in some instances may not occur until after completion of work under the contract. Costs incurred for bidding and obtaining contracts are expensed as incurred.

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 highly detailed “bottom up” approach and 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 more 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. 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.

Capital assets

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

Another key estimate is the expected cash flows from the use of an asset and the expected disposal proceeds in applying CICA Handbook Section 3063 “Impairment or Disposal of Long-Lived Assets” and the revised Section 3475 “Disposal of Long-Lived Assets and Discontinued Operations.” This standard requires 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 assets over its fair value. Equally important is the expected fair value of assets which are available-for-sale.

Hedge accounting

We entered into a cross currency swap agreement and interest rate swap agreements to hedge our exposure to foreign currency exchange fluctuations on our U.S. dollar denominated senior notes. The initial assessment as well as the on-going review of the effectiveness of the hedge is critical as no foreign exchange gain or loss has been recorded on the income statement.

Repair and maintenance costs

The parts, shop labor and overhead costs on our income statement represent the cost of maintaining our fleet in optimal condition. It is our policy to expense these costs as they are incurred.

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Results of Operations

The following table sets forth information about our results of operations as a percentage of revenue:

	Year ended March 31,								April 1, 2003 to				November 26, 2003 to
	2002				2003				November 25, 2003				March 31, 2004
	(dollars in thousands)
Revenue	$	249,351	100.0	%	$	344,186	100.0	%	$	250,919	100.0	%	$	127,614	100.0	%
Project costs		127,996	51.4			219,979	63.9			156,835	62.5			83,208	65.2
Equipment costs		77,289	31.0			72,228	21.0			53,986	21.5			15,116	11.9
Depreciation		11,299	4.5			10,974	3.2			6,566	2.6			6,674	5.2
		216,584	86.9			303,181	88.1			217,387	86.6			104,998	82.3
Gross Profit	$	32,767	13.1	%	$	41,005	11.9	%	$	33,532	13.4	%	$	22,616	17.7	%
Other Data:
Equipment hours:		583,071				673,811				469,698				225,383

Post-acquisition period from November 26, 2003 to March 31, 2004

Revenue

Revenue for the period November 26, 2003 to March 31, 2004 was $127.6 million. Average revenue per day decreased to $1.013 million in the post-acquisition period compared to $1.049 million in the pre-acquisition period from April 1, 2003 to November 25, 2003. This decrease is primarily due to lower revenue realized in providing mining and site preparation as well as piling services, offset by a significant increase in pipeline services.

Project costs

Project costs for the period November 26, 2003 to March 31, 2004 were $83.2 million. As a percentage of revenue, project costs increased from 62.5% in the pre-acquisition period from April 1, 2003 to November 25, 2003 to 65.2% in the post-acquisition period. This increase is due in part to the inclusion of rentals in project costs post-acquisition, as well as the mix in contract types.

Equipment costs

Equipment costs for the period November 26, 2003 to March 31, 2004 were $15.1 million. As a percentage of revenue, equipment costs were 11.9% in the post-acquisition period compared to 21.5% in the pre-acquisition period from April 1, 2003 to November 25, 2003. This decrease is due to the buy out of most leases and rentals concurrent with the acquisition.

Depreciation

Depreciation expense was $6.7 million for the period November 26, 2003 to March 31, 2004. As a percentage of revenue, depreciation was 5.2% in the post-acquisition period compared to 2.6% in the pre-acquisition period from April 1, 2003 to November 25, 2003. This increase is due primarily to the revaluation of assets and liabilities to their estimated fair market values in accordance with the application of purchase accounting in connection with the acquisition.

General and administrative expenses

General and administrative expenses were $6.1 million for the period November 26, 2003 to March 31, 2004. As a percentage of revenue, general and administrative expenses increased from 3.2% in the pre-acquisition period from April 1, 2003 to November 25, 2003 to 4.8% in the post-acquisition period. This increase is primarily attributable to higher staff levels and salary increases, increased travel, insurance and consultants, and to new expenses related to the change in ownership.

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Loss (gain) on sale of capital assets

The loss on sale of capital assets was $0.1 million for the period November 26, 2003 to March 31, 2004. Losses on the sale of capital assets arise when the carrying value exceeds the proceeds of disposition. There were no significant gains or losses during the period.

Interest expense, net

Interest expense, net of interest income, was $10.8 million for the period November 26, 2003 to March 31, 2004. As a percentage of revenue, interest expense, net increased from 0.9% in the pre-acquisition period to 8.5% in the post-acquisition period, due to larger debt balances with higher associated interest rates incurred in connection with the acquisition.

Management fees

There were no management fees paid to our parent company in the post-acquisition period from November 26, 2003 to March 31, 2004, and there will be no such management fees going forward.

Foreign exchange (gain) loss

The foreign exchange (gain) loss is relatively small and relates primarily to the exchange differences between the Canadian and US dollar for a US dollar denominated bank account.

Pre-acquisition period from April 1, 2003 to November 25, 2003 compared to Twelve Months Ended March 31, 2003

Revenue

Revenue for the period April 1, 2003 to November 25, 2003 decreased by $93.3 million to $250.9 million compared to $344.2 million for the twelve months ended March 31, 2003. This decrease was primarily a result of fewer days in the pre-acquisition period as compared to the prior year. Revenue per day increased to $1.049 million in the pre-acquisition period, up from $0.943 million in the comparable period. This increase was driven by a larger volume of pipeline installation services for EnCana. The increase was partially offset by reductions in revenues from the substantial completion of the Syncrude Aurora II project and piling services related to the Syncrude UE-1 project.

Project costs

Project costs for the period April 1, 2003 to November 25, 2003 decreased by $63.1 million to $156.8 million as compared to $220.0 million for the twelve months ended March 31, 2003. This decrease was primarily a result of fewer days in the pre-acquisition period as compared to the prior year. As a percentage of revenue, project costs decreased from 63.9% for the twelve months ended March 31, 2003 to 62.5% for the pre-acquisition period. This is due to a reduction in the proportion of lower margin cost plus and fixed fee jobs.

Equipment costs

Equipment costs for the period April 1, 2003 to November 25, 2003 decreased by $18.2 million to $54.0 million as compared to $72.2 million for the twelve months ended March 31, 2003. This decrease was primarily a result of fewer days in the pre-acquisition period as compared to the prior year. As a percentage of revenue, equipment costs increased slightly from 21.0% for the twelve months ended March 31, 2003 to 21.5% for the pre-acquisition period due primarily to increased shop labor costs due to an increase in fleet size. On a pro forma basis, equipment costs would have been $56.3 million, or 14.9% of pro forma revenue, for the fiscal year ended March 31, 2004. This decrease from the prior fiscal year primarily relates to lower lease and rental expense due to the buy out of most leases and rental concurrent with the acquisition.

Depreciation

Depreciation expense decreased by $4.4 million to $6.6 million for the period April 1, 2003 to November 25, 2003, as compared to $11.0 million for the twelve months ended March 31, 2003. This decrease was primarily a result of fewer days in the pre-acquisition

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period as compared to the prior year. As a percentage of revenue, depreciation decreased slightly from 3.2% for the twelve months ended March 31, 2003 to 2.6% for the pre-acquisition period. On a pro forma basis, depreciation would have been $21.6 million, or 5.7% of pro forma revenue, for the fiscal year ended March 31, 2004. This increase over the prior fiscal year is due primarily to the revaluation of assets and liabilities to their estimated market values in accordance with the application of purchase accounting in connection with the acquisition.

General and administrative expenses

General and administrative expenses decreased by $4.3 million to $7.9 million for the period April 1, 2003 to November 25, 2003 as compared to $12.2 million for the twelve months ended March 31, 2003. This decrease was primarily a result of fewer days in the pre-acquisition period as compared to the prior year. As a percentage of revenue, general and administrative expenses decreased slightly from 3.6% for the twelve months ended March 31, 2003 to 3.2% for the pre-acquisition period.

Loss (gain) on sale of capital assets

The gain on sale of capital assets was $0.1 million for the period April 1, 2003 to November 25, 2003 compared to a gain of $2.3 million for the twelve months ended March 31, 2003. Gains on the sale of capital assets arise when the proceeds of disposition exceeds the carrying value. There were no significant gains or losses during the period.

Interest expense, net

Interest expense, net of interest income, decreased by $1.8 million to $2.4 million for the period April 1, 2003 to November 25, 2003, as compared to $4.2 million for the twelve months ended March 31, 2003. This decrease was primarily a result of fewer days in the pre-acquisition period as compared to the prior year and a decrease in the average level of debt.

Management fees

Management fee expense increased by $33.1 million to $41.1 million for the period April 1, 2003 to November 25, 2003, as compared to $8.0 million for the twelve months ended March 31, 2003. 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.

Foreign exchange (gain) loss

The foreign exchange (gain) loss is relatively small and relates primarily to the exchange differences between the Canadian and US dollar for a US dollar denominated bank account.

Fiscal Year Ended March 31, 2003 Compared to Fiscal Year Ended March 31, 2002

Revenue

Revenue increased by $94.8 million to $344.2 million in fiscal 2003, as compared to $249.4 million in fiscal 2002. The increase was driven by a larger volume of mining and site preparation and piling services related to the UE-1 project, commencement of work on the Athabasca oil sands project, increased pipeline installation services to EnCana and increased mining and site preparation services on the Albian FOM project. These increases were offset by reductions in revenue from two significant projects which were completed in fiscal 2002.

Project costs

Project costs increased by $92.0 million to $220.0 million in fiscal 2003, as compared to $128.0 million in fiscal 2002. This increase was primarily due to labor, material and subcontract costs associated with increased activity at the UE-1 project which experienced a lower usage of heavy equipment in fiscal 2003 as compared to fiscal 2002. This combination of low equipment utilization and increased labor, material and subcontract costs resulted in an increase in job costs as a percentage of revenue for fiscal 2003 as compared to the prior year.

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Equipment costs

Equipment costs decreased by $5.1 million to $72.2 million in fiscal 2003, as compared to $77.3 million in fiscal 2002. The decrease was primarily attributable to the completion of a greater number of scheduled major overhauls of the heavy equipment in fiscal 2002 as compared to fiscal 2003.

In addition, equipment lease and rental expense decreased in fiscal 2003, as compared to fiscal 2002. This decrease was largely attributable to the conversion of the leases on six pieces of heavy equipment from operating leases to capital leases in fiscal 2003.

Depreciation

Depreciation expense decreased by $0.3 million to $11.0 million in fiscal 2003, as compared to $11.3 million in fiscal 2002. The decrease was primarily attributable to lower usage of large mining trucks on the Albian project as compared to the prior year. This was partially offset, however, by the increase in depreciable hours on one of the large shovels utilized on the Albian site.

General and administrative expense

General and administrative expense decreased slightly by $0.6 million to $12.2 million in fiscal 2003, as compared to $12.8 million in fiscal 2002. This decrease was primarily attributable to a reduction in professional fees, telecommunication expenses and other overhead expenses.

Gain on sale of capital assets

Gain on sale of capital assets was $2.3 million for the fiscal year ended March 31, 2003 compared to a gain of $0.2 million for the fiscal year ended March 31, 2002. Gains on the disposal of fixed assets arise when the proceeds of disposition exceed the carrying value of the assets. There were no significant gains or losses during the period.

Interest expense, net

Interest expense increased by $0.7 million to $4.2 million in fiscal 2003, as compared to $3.5 million in fiscal 2002. The balance of the term bank loans increased in fiscal 2003, resulting in higher interest expense. This increase was partially offset by a lower average prime interest rate of 4.40% for fiscal 2003, as compared to 5.23% for fiscal 2002.

Management fees

Management fee expense decreased by $6.4 million to $8.0 million in fiscal 2003, as compared to $14.4 million in fiscal 2002. Management fees represent fees for services rendered that are paid to the corporate shareholder of Norama Ltd., our predecessor company, which are determined with reference to taxable income. The decrease in this period was attributable to a decrease in taxable income.

Segmented Results of Operations

Our management evaluates and monitors segment performance primarily by way of operating profit which is calculated by deducting all direct project costs from segment revenues as well as an allocation of equipment costs including depreciation. The equipment costs are allocated based on equipment hours at pre-established hourly rates. Unallocated equipment costs represent the difference between actual equipment costs incurred and the equipment costs allocated to the segments via internal equipment rates. Unallocated corporate costs include general and administrative costs, interest expense, net of interest income, and management fees.

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	Year Ended March 31,				April 1, 2003 to			November 26, 2003 to
	2002		2003		November 25, 2003			March 31, 2004
	(dollars in thousands)
Revenue
Mining and site preparation	$	186,141	$	245,235	$	182,685		$	53,407
Piling		35,132		61,006		39,368			9,565
Pipeline		28,078		37,945		28,866			64,642
Total Revenue		249,351		344,186		250,919			127,614
Operating Profit
Mining and site preparation		30,921		31,415		27,801			8,154
Piling		8,108		12,483		8,318			2,501
Pipeline		6,111		6,300		5,054			12,892
Total operating profit		45,140		50,198		41,173			23,547
Unallocated costs
Corporate cost		30,999		24,559		51,344			29,911
Equipment cost		11,843		6,530		7,592			1,062
Income (loss) before income taxes	$	2,298	$	19,109	$	(17,763	)	$	(7,426	)
Other data:
Equipment hours
Mining and site preparation		494,973		539,928		384,859			126,620
Piling		44,310		82,312		48,434			9,135
Pipeline		43,788		51,571		36,405			89,628
		583,071		673,811		469,698			225,383

Post-acquisition period from November 26, 2003 to March 31, 2004

Mining and Site Preparation

Revenue for the period November 26, 2003 to March 31, 2004 was $53.4 million. Average revenue per day decreased to $0.424 million in the post-acquisition period, down from $0.764 in the pre-acquisition period from April 1, 2003 to November 25, 2003. This decrease is due primarily to lower revenue from the Syncrude Upgrader Expansion (“UE1”) project, which is nearing completion, and the Syncrude Fully Operated and Maintained (“FOM”) project.

Segment operating profits were $8.2 million in the post-acquisition period.

Piling

Revenue for the period November 26, 2003 to March 31, 2004 was $9.6 million. Average revenue per day decreased to $0.076 million in the post-acquisition period, down from $0.165 in the pre-acquisition period from April 1, 2003 to November 25, 2003. This decrease is due primarily to lower revenue from the Syncrude UE1 piling contract as work on this project is nearing completion.

Piling segment operating profits were $2.5 million in the post-acquisition period.

Pipeline

Revenue for the period November 26, 2003 to March 31, 2004 was $64.6 million. Average revenue per day increased to $0.513 million in the post-acquisition period, up from $0.121 million in the pre-acquisition period from April 1, 2003 to November 25, 2003. Installations of larger diameter pipe, particularly 12”, at the Sierra pipeline project in British Columbia and a greater number of well site tie-ins have contributed to this increase.

Pipeline segment operating profits were $12.9 million in the post-acquisition period.

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Pre-acquisition period from April 1, 2003 to November 25, 2003 compared to Twelve Months Ended March 31, 2003

Mining and Site Preparation

Revenue for the period April 1, 2003 to November 25, 2003 decreased by $62.5 million to $182.7 million compared to $245.2 million for the twelve months ended March 31, 2003. This decrease was primarily a result of fewer days in the pre-acquisition period as compared to the prior year. Revenue per day increased to $0.764 million in the pre-acquisition period, up from $0.672 million in the comparable period. This increase is primarily attributable to increased per day revenue at the Syncrude UE1 project and the Albian project, partially offset by a decrease in per day revenue at the Aurora II project which was nearing completion.

Segment operating profits decreased by $3.6 million in the pre-acquisition period to $27.8 million as compared to $31.4 million for the twelve months ended March 31, 2003. This decrease was primarily a result of fewer days in the pre-acquisition period compared to the prior year, offset by the increase in daily activity in the period.

Piling

Revenue for the period April 1, 2003 to November 25, 2003 decreased by $21.6 million to $39.4 million compared to $61.0 million for the twelve months ended March 31, 2003. This decrease was primarily a result of fewer days in the pre-acquisition period as compared to the prior year. Revenue per day decreased slightly to $0.165 million in the pre-acquisition period, down from $0.167 million in the comparable period.

Piling segment operating profits decreased by $4.2 million in the pre-acquisition period to $8.3 million compared to $12.5 million for the twelve months ended March 31, 2003 primarily due to decrease in the number of days in the pre-acquisition period compared to the prior year.

Pipeline

Revenue for the period April 1, 2003 to November 25, 2003 decreased by $9.0 million to $28.9 million compared to $37.9 million for the twelve months ended March 31, 2003. This decrease was primarily a result of fewer days in the pre-acquisition period as compared to the prior year. Revenue per day increased to $0.121 million in the pre-acquisition period, up from $0.104 million in the comparable period. Installations of larger diameter pipe, particularly 12”, and a greater number of well site tie-ins have contributed to this increase. As well, a larger number of ancillary services, such as pipeline weight installations, have resulted in the higher revenue. Further, management believes the increased demand for natural gas and the provincial government royalty incentive program have combined to create a favorable environment for increased activity in this segment.

Pipeline segment operating profits decreased by $1.2 million in the pre-acquisition period to $5.1 million as compared to $6.3 million for the twelve months ended March 31, 2003. This decrease was primarily a result of fewer days in the pre-acquisition period as compared to the prior year, offset by a larger proportion of higher margin work compared to the previous year.

Fiscal Year Ended March 31, 2003 Compared to Fiscal Year Ended March 31, 2002

Mining and Site Preparation

Revenue increased by $59.1 million to $245.2 million, as compared to $186.1 million for fiscal 2002. The increase was primarily due to the higher volume of services provided on the Syncrude UE1 project as our revenues increased from $32.1 million in fiscal 2002 to $107.6 million in fiscal 2003. In addition, revenues for the Syncrude Aurora II project increased $20.1 million as compared to the prior period. These increases were partially offset by a $25.5 million decrease on the Syncrude overburden project as this project was nearing completion and by lower demand for our services on the Syncrude FOM project during this period. Equipment hours increased by 9.1% from 494,973 to 539,928 for the year ended March 31, 2003, as compared to March 31, 2002, contributing to higher revenues in the latter period.

Mining and site preparation segment operating profits increased slightly to $31.4 million as compared to $30.9 million for fiscal 2002. This increase was due primarily to a higher volume of work offset by decreased profit margins due to a larger proportion of lower margin time and materials work in fiscal 2003.

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Piling

Revenue increased by $25.9 million to $61.0 million as compared to $35.1 million for fiscal 2002. The increase is primarily due to significantly higher piling revenues generated on the Syncrude UE1 project during fiscal 2003 as compared to fiscal 2002. Piling equipment hours increased significantly from 44,310 to 82,312 for the year ended March 31, 2003, as compared to March 31, 2002, contributing to higher revenues in the latter period.

Piling segment operating profits increased to $12.5 million as compared to $8.1 million for fiscal 2002 primarily due to the increase in the volume of work offset slightly by a higher proportion of lower margin time and materials contracts in fiscal 2003 as compared to fiscal 2002.

Pipeline

Revenue from the pipeline segment increased to $37.9 million up from $28.1 million for fiscal 2002. This increase is related to the higher volume of work for EnCana in the Sierra region of north eastern British Columbia during fiscal 2003. Equipment hours for the pipeline segment increased by 17.8% from 43,788 to 51,571 for the year ended March 31, 2003, as compared to March 31, 2002, contributing to the increase in revenue in the latter period.

Pipeline segment operating profits increased slightly to $6.3 million as compared to $6.1 million for fiscal 2002 due to the higher volume of activity offset by the realization of lower margins on certain time and materials contracts.

B. LIQUIDITY AND CAPITAL RESOURCES

Operating activities

Cash provided from operating activities for the twelve months ended March 31, 2004 totalled $18.0 million, with collection of accounts receivable primarily contributing to the results. Cash provided from operating activities for the predecessor company for the years ended March 31, 2003 and March 31, 2002 was $16.3 million and $4.2 million respectively. Historically, we have used cash from operations, together with other available sources of liquidity, to fund our working capital needs and capital expenditures. Going forward, we expect to fund our operations and capital expenditures and to satisfy our debt service obligations through operating cash flow and from borrowings under our revolving credit facility and other external financing. Sustaining capital expenditures are those that are required to maintain our fleet of equipment at its optimum average age. Expansion capital expenditures are directly related to new projects, and the commitment to make expansion capital expenditures typically occurs only when we have signed a contract for a new project.

Investing activities

Cash used in investing activities during the twelve months ended March 31, 2004 related almost entirely to the acquisition. The cash used to acquire the shares of NACGI and the assets of NAEL totalled $367.8 million, which is net of the $4.0 million in NACGI cash balances acquired and $15.6 million in surplus cash from the acquisition financing.

During the period from November 26, 2003 to March 31, 2004, we invested $0.5 million in sustaining capital expenditures, and $2.0 million in expansion capital expenditures. In addition, new vehicle capital leases increased by $1.2 million and proceeds from the disposal of capital assets amounted to $6.4 million. We expect our future sustaining capital expenditures to range from $9 million to $18 million per year. During the period from April 1, 2003 to November 25, 2003, the net cash used in investing activities by the predecessor company was $4.6 million, consisting of $4.0 in sustaining capital expenditures and $1.2 in expansion capital expenditures. New vehicle capital leases increased by $2.1 and proceeds on disposal of capital assets were $0.6 million. For the twelve months ended March 31, 2004 total investment in capital expenditures was $7.7 million and total proceeds on disposal of capital assets was $6.4 million.

For the year ended March 31, 2003, the predecessor company invested $4.1 million in sustaining capital expenditures, and $18.8 million in expansion capital expenditures. In addition, new capital leases increased by $9.4 million and proceeds from the disposal of capital assets was $4.2 million.

For the year ended March 31, 2002, the predecessor company invested $5.3 million in sustaining capital expenditures, and $3.3 million in expansion capital expenditures. Proceeds from the disposal of capital assets was $2.2 million.

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Financing activities

Financing activities during the twelve months ended March 31, 2004 related almost entirely to the acquisition. The cash required to complete the acquisition was financed by $92.5 million from the issuance of common shares, $263.0 million in proceeds from the senior notes and $50.0 million from the term loan portion of the senior credit facility net, in the latter two instances, of $18.1 million in issuance costs and fees. Apart from the cash provided to finance the acquisition, only a minimal amount of other financing activity occurred during the twelve months ended March 31, 2004. This financing activity related to payments made on capital leases and the term credit facility.

Financing activities of the predecessor company for the year ended March 31, 2003 included $13.5 million proceeds from a term credit facility, and payments made on the term credit facility and capital leases.

Financing activities of the predecessor company for the year ended March 31, 2002 included $8.0 million proceeds from a term credit facility, and payments made on the term credit facility and capital leases, as well as repayment of advances from Norama Inc.

Liquidity

We have available $60 million, subject to borrowing base limitations, under our $70 million revolving credit facility after taking into account a $10 million letter of credit required to be posted to support bonding requirements associated with customer contracts. In addition, we continue to lease a portion of our motor vehicle fleet and have assumed from the predecessor company four heavy equipment operating leases.

There are no principal payments required on our 8¾% senior notes due 2011 until maturity. The foreign currency risk relating to both the principal and interest payments has been effectively hedged with a cross currency swap and interest rate swaps which went into effect concurrent with the acquisition. The 8.75% rate of interest on the notes has been swapped to an effective rate of 9.765% for the whole 8 year period until maturity. The interest is $12.8 million payable semi-annually in June and December of every year until the notes mature on December 1, 2011.

We are required to make quarterly principal and interest payments under our $50.0 million term loan, which bears interest at a floating rate based upon either the Canadian prime rate plus 2% to 2.5%, or Canadian bankers’ acceptance rate plus 3% to 3.5%. For the period from November 26, 2003 through March 31, 2004, the weighted average interest rate on the term debt was 6.3%. The principal repayments are $7.3 million in fiscal 2005, $11.0 million per year in each of the next three fiscal years, and $8.2 million in 2009. Additional prepayments are required under certain circumstances and no new advances are available under the term facility. We refer to the revolving credit facility and the term loan collectively as the “senior secured credit facility.”

Our new senior credit facility and the indenture relating to the notes impose certain restrictions on us, including restrictions on our ability to incur indebtedness, pay dividends, make investments, grant liens, sell our assets and engage in certain other activities. In addition, the new senior credit facility requires us to maintain certain financial ratios. Our indebtedness under the new senior secured credit facility is secured by substantially all of our assets, including our accounts receivable and capital assets.

In anticipation of the likelihood of not being able to meet several of the financial covenants originally set forth in our bank credit agreement for the period ending March 31, 2004, primarily due to soft demand for our mining and site preparation services, particularly at the Albian mining site, we and the required number of our bank lenders amended our bank credit agreement effective as of March 31, 2004 to (a) decrease the minimum fixed charge coverage ratio through March 31, 2004 from 1.10:1.00 to 0.75:1.00, (b) decrease the minimum interest coverage ratio through March 31, 2004 from 2.10:1.00 to 1.50:1.00, (c) increase the maximum total leverage ratio on March 31, 2004 from 4.25:1.00 to 5.00:1.00, and (d) extend the time for delivery of our 2005 financial plan to the administrative agent from March 2, 2004 to April 30, 2004.

In anticipation of the likelihood of not being able to meet several of the financial covenants originally set forth in our bank credit agreement for the quarters ending June 30, 2004 through March 31, 2005, primarily due to continued soft demand for our mining and site preparation services at the Albian mining site, we and the required number of our bank lenders amended our bank credit agreement effective as of June 30, 2004.

U.S. Generally Accepted Accounting Principles

The consolidated financial statements have been prepared in accordance with Canadian GAAP, which differs in certain material respects from U.S. GAAP. The nature and effect of these differences are set out in note 19 to our financial statements included in Item 18.

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Recent U.S. accounting pronouncements

In November 2002, the Financial Accounting Standards Board, or FASB, issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” or FIN 45. FIN 45 requires the recognition of a liability by a guarantor at the inception of certain guarantee entered into or modified after December 31, 2002. FIN 45 requires the guarantor to recognize a liability for the non-contingent component of certain guarantees; that is, it requires the recognition of a liability for the obligation to stand ready to perform in the event that specified triggering events of conditions occur. The initial measurement of this liability is the fair value of the guarantee at inception. At March 31, 2003 and March 31, 2004, we had not provided any guarantees.

In December 2003, the FASB issued FASB Interpretation No. 46 (revised December 2003), or “FIN 46R,” “Consolidation of Variable Interest Entities,” which addresses how a business enterprise should evaluate whether it has a controlling financial interest in any entity though means other than voting rights and accordingly should consolidate the entity. FIN 46R replaces FASB Interpretation No. 46, “Consolidation of Variable Interest Entities,” which was issued in January 2003. We are required to apply FIN 46R to variable interests in variable interest entities, or “VIE’s,” created after December 31, 2003. With respect to entities that do not qualify to be assessed for consolidation based on voting interests, FIN 46R generally requires a company that has a variable interest(s) that will absorb a majority of the VIE’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur, or both, to consolidate that VIE. For variable interests in VIEs created before January 1, 2004, FIN 46R will be applied beginning on January 1, 2005. For any VIEs that must be consolidated under FIN 46R that were created before January 1, 2004, the assets, liabilities and noncontrolling interests of the VIE initially would be measured at their carrying amounts with any difference between the net amount added to the balance sheet and any previously recognized interest being recognized as the cumulative effect on an accounting change. If determining the carrying amounts is not practicable, fair value at the date FIN 46R first applies may be used to measure the assets, liabilities and noncontrolling interest of the VIE. We do not have any material investments in VIEs at March 31, 2004.

In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” or SFAS 143, which addresses financial accounting and reporting for obligations associated with the retirement of long-lived assets and the associated asset retirement costs. SFAS 143 requires us to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from acquisition, construction, development and/or normal use of the assets. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. If the obligation is settled for other than the carrying amount of the liability, we will recognize a gain or loss on settlement. We were required to adopt the provisions of SFAS 143 effective January 1, 2002. The adoption of this standard did not have a material impact on our consolidated financial statements.

In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit of Disposal Activities,” or SFAS 146, which is effective for exit or disposal activities that are initiated after December 31, 2002. SFAS 146 requires that a liability be recognized for exit or disposal costs only when the liability is incurred, as defined in the FASB’s conceptual framework rather than when a company commits to an exit plan, and that the liability be initially measured at fair value. The adoption of this standard did not have a material impact on our consolidated financial statements.

Recent Canadian GAAP Accounting Rules

In December 2002, the Accounting Standards Board of the Canadian Institute of Chartered Accountants issued Handbook Section 3063, Inpairment of Long-Lived Assets. Section 3063 supersedes the write-down and disposal provisions of Section 3061, Property, plant and equipment. Under Section 3063, long-lived assets are tested for impairment, whenever events or changes in circumstances indicate that the assets might be impaired. The impairment test is carried out in two steps. In the first step, the carrying amount of the asset or asset group is compared with its recoverable amount. The carrying amount of a long-lived asset is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. The second step is carried out when the carrying amount of a long-lived asset is not recoverable, in which case the fair value of the long-lived asset is compared with its carrying amount to measure the amount of the impairment loss, if any. When an impairment loss is recognized, it is presented in income from operations in the income statement. When quoted market prices are not available, the fair value of the long-lived assets is determined using the discounted estimated future cash flow method.

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We adopted Section 3063, effective April 1, 2003. In accordance with the requirement of Section 3063, this change in accounting policy has been applied prospectively and the amounts presented for prior periods have not been restated for this change.

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 nearing inception or in the 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 3.1% in 2003 (Source: Alberta Economic Development). As well, commodity pricing, particularly in coal and diamonds, has added diversity to our potential markets.

E. OFF-BALANCE SHEET ARRANGEMENTS

We did not have any material investments in variable interest entities at March 31, 2004. See Note 19 to our financial statements at Item 18.

F. TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

Our principal contractual obligations relate to the senior notes and the senior secured credit facility, as well as capital and operating leases. The following table summarizes our future contractual obligations, excluding interest payments, as of March 31, 2004.

	Payments Due by Period
	Total		2005		2006		2007		2008		2009 and after
	(dollars in millions)
Contractual Obligations
Long-term debt	$	311.5	$	7.3	$	11.0	$	11.0	$	11.0	$	271.2
Capital leases (including interest)		3.3		0.9		0.8		0.8		0.8		—
Operating leases (a)		5.0		3.0		0.8		0.7		0.5		0.0
Total contractual obligations	$	319.8	$	11.2	$	12.6	$	12.5	$	12.3	$	271.2

(a) includes property leases and leases on four pieces of heavy equipment.

ITEM 6: DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

A. DIRECTORS AND EXECUTIVE OFFICERS

The following table sets forth the name, age and position held by our directors and executive officers, who are also the directors and executive officers of 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
Gordon Parchewsky (3) (4)	55	President and Director
Vincent Gallant	46	Vice President, Finance
William Koehn	42	Vice President, Operations
Ronald A. McIntosh (3)	62	Chairman
William C. Oehmig (2) (3) (4)	55	Director
John D. Hawkins (1) (3)	40	Director
Jean-Pierre L. Conte (2) (3)	41	Director
E.J. Antonio III (1) (3) (4)	39	Director
K. Rick Turner (1) (3)	46	Director

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Name	Age	Position
John A. Brussa (1) (2) (4)	47	Director
Jim G. Gardiner (2) (4)	59	Director
Donald R. Getty (2)	70	Director
Martin Gouin (1) (2)	43	Director
Gary K. Wright (1) (4)	59	Director

(1) Member of the Audit Committee

(2) Member of the Compensation Committee

(3) Member of the Executive Committee

(4) Member of the Planning Committee

Gordon Parchewsky became one of our Directors on November 5, 2003 and our President on November 26, 2003. 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.

Vincent Gallant became our Vice President, Finance, on November 26, 2003. Previously, he served in the 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 six 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.

William Koehn became our Vice President, Operations on November 26, 2003. Previously, he served in the same capacity 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 recently completed his Masters Degree in Construction Engineering and Management. Mr. Koehn has over 16 years of earthworks and mining experience.

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.

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 shareholder in NACG Holdings Inc. See “Related Transactions—Advisory Services Agreement” and “Summary—The Transactions.” 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. 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.

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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 shareholder in NACG Holdings Inc. See “Related Transactions—Advisory Services Agreement” and “Summary—The Transactions.” Mr. 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.

Jean-Pierre L. Conte became one of our Directors on November 26, 2003. Mr Conte has been the Chairman since 2001, and Managing Director since 2000, of Genstar Capital, L.P., a private equity investment firm, and a Managing Director of Genstar Capital LLC since 1996. Genstar provides certain services to us pursuant to an advisory services agreement, and an investment entity controlled by Genstar is a shareholder in NACG Holdings Inc. See “Related Transactions—Advisory Services Agreement” and “Summary—The Transactions.” Mr. Conte joined Genstar in 1995. From 1989 to 1995, Mr. Conte was a Principal at The NTC Group, Inc., a private-equity firm focused on industrial technology companies. Previously he worked in corporate finance and mergers and acquisitions at Drexel Burnham Lambert and Chase Manhattan Bank. He is the Chairman of the Board of both PRA International, Inc. and BioSource International, Inc. (Nasdaq: BIOI) and a director of Installs inc, LLC. Mr. Conte earned an M.B.A. from Harvard University Graduate School of Business and a B.A. from Colgate University.

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 shareholder in NACG Holdings Inc. See “Related Transactions—Advisory Services Agreement” and “Summary—The Transactions.” 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 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. He currently serves as a director of Republic Engineered Products, Inc. and Simonds International Corporation. 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.

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 shareholder in NACG Holdings Inc. See “Related Transactions—Advisory Services Agreement” and “Summary—The Transactions.” 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, Neucoll, Inc., Jebco Seismic LLC and the general partner of LaGrange Energy, LP. Mr. Turner earned his Bachelor of Science in Business Administration at the University of Arkansas and is a Certified Public Accountant.

John 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 is currently President of Fording Canadian Coal Trust, a coal company, and Fording Inc., an operating subsidiary of the Trust. He is also President and Chief Executive Officer of Elk Valley Coal Partnership. From 1993 to 2003, he was President and Chief Executive Officer of predecessor corporations to the Fording Trust. 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.

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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. Mr. Getty has held this position since the end of 1992 when he retired as Premier of Alberta. Mr. Getty was the 11th Premier of Alberta, a position in which he served from 1985 to 1992. As Premier of Alberta, Mr. Getty’s government was successful in emphasizing development of non-conventional oil projects, 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 with honors from the University of Western Ontario with a degree in Business Administration. He currently serves on the boards of Guyanor Resources, S.A., Mera Petroleum Inc., Cen-Pro Technologies Ltd., Nationwide Resources and is a director and Vice-chairman of Horse Racing Alberta. In addition, Mr. Getty is an Officer of the Order of Canada and a member of the Alberta Order of Excellence.

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.

Gary K. Wright became one of our Directors on November 26, 2003. Mr. Wright is 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, a position he has held since June 2003. 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.

B. COMPENSATION

Directors of NACG Holdings Inc. and North American Energy Partners Inc. will 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 will be reimbursed for reasonable out-of-pocket expenses incurred in connection with their services pursuant to NACG Holdings Inc.’s policies. In addition, the directors participate in NACG Holdings Inc.’s 2004 Share Option Plan. Martin Gouin and directors who are also our employees will not receive director compensation.

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 executive officers as of March 31, 2004, collectively called the named executive officers, for services rendered in all capacities to us for the fiscal years ended March 31, 2004, 2003 and 2002.

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	2004	$	186,000	$	1,300,000	(b)	(d)	6,000
President	2003		144,000		275,000		(d)	—
	2002		138,000		300,000		(d)	—
William Koehn	2004	$	170,000	$	1,300,000	(b)	(d)	5,000
Vice President, Operations	2003		132,000		275,000		(d)	—
	2002		132,600		300,000		(d)	—
Vincent Gallant	2004	$	162,000	$	1,250,000	(b)	(d)	5,000
Vice President, Finance	2003		126,000		225,000		(d)	—
	2002		122,250		250,000		(d)	—
James Humphries	2004	$	130,500	$	471,500	(c)	(d)	2,000
Division Manager, Piling	2003		123,000		110,000		(d)	—
	2002		115,350		125,000		(d)	—

		Annual Compensation						Long-Term Compensation
Name and Principal Position	Fiscal Year	Salary		Bonus			Other Annual Compensation	Securities Underlying Options (a)
Robert Cochrane	2004	$	114,000	$	357,500	(c)	(d)	2,000
Division Manager, Pipeline	2003		114,000		90,000		(d)	—
	2002	118,3	50	140	,000		(d)	—

(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 Inc., the parent of Norama Ltd., upon closing of the acquisition.

(c) 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.

(d) 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.

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 (b)
Gordon Parchewsky	6,000	11.08	%	$	100	November 26, 2013	$	228,351
William Koehn	5,000	9.24	%		100	November 26, 2013		190,293
Vincent Gallant	5,000	9.24	%		100	November 26, 2013		190,293
James Humphries	2,000	3.69	%		100	November 26, 2013		76,117
Robert Cochrane	2,000	3.69	%		100	November 26, 2013		76,117

(a) For material terms of the NACG Holdings Inc. 2004 Share Option Plan and the option grants, see note 17 to our consolidated financial statements included in Item 18.

(b) Estimated using the Black-Scholes option pricing model, assuming: a dividend yield of 0%, a risk-free interest rate of 4.79%, volatility of 0%, and an expected life of 10 years.

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

Name	Shares Acquired on Exercise	Value Realized	Number of Securities Underlying Unexercised Options at March 31, 2004 (Exercisable/ Unexercisable)	Value of Unexercised In-the-Money Options at March 31, 2004 (Exercisable/ Unexercisable)
Gordon Parchewsky	—	—	—/6,000	—/—
William Koehn	—	—	—/5,000	—/—
Vincent Gallant	—	—	—/5,000	—/—
James Humphries	—	—	—/2,000	—/—
Robert Cochrane	—	—	—/2,000	—/—

Retirement Benefits for Executive Officers and Directors

For the fiscal year ended March 31, 2004, the total amount we set aside for pension, retirement and similar benefits for our executive officers and directors was $15,540, consisting of employer matching contributions to our executive officers’ Registered Retirement Savings Plan accounts of up to 3% 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 at the end of three years after the closing of the acquisition, 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.

Share 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.

C. BOARD PRACTICES

The Board and Board Committees

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

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 composed of William Oehmig, E.J. Antonio, Jean-Pierre Conte, John Hawkins, Gordon Parchewsky, Rick Turner and Ron McIntosh;

• 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 composed of John Hawkins, E.J. Antonio, John Brussa, Martin Gouin, Rick Turner and Gary Wright;

• 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 composed of Jean-Pierre Conte, John Brussa, Jim Gardiner, Don Getty, William Oehmig and Martin Gouin; and

• The Planning Committee, which identifies and addresses significant issues and opportunities, develops strategic plans for the Company, and makes periodic reports to the board of directors on its activities and recommendations. The Planning Committee is composed of Gordon Parchewsky, E.J. Antonio, John Brussa, Jim Gardiner, William Oehmig and Gary Wright.

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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, 2004, the Company employed 885 salaried and hourly employees, all located in Western Canada. Most of the hourly employees are temporary employees working under various 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 expires on October 31, 2004, 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. We are subject to other industry and specialty collective agreements under which we complete work, the primary terms of some of which have expired. The agreements, however, continue from year-to-year unless terminated by a strike or lockout. We have no indication of a pending strike or lockout, and those employees are continuing to work while a new collective bargaining agreement is negotiated. We cannot estimate when that will occur. 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.

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.

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 1, 2004.

Name of Beneficial Owner	Number of Common Shares	Options(1)
John A. Brussa	4,000	1,388
Jean-Pierre L. Conte	—	1,388
Vincent Gallant	5,000	5,000
Jim G. Gardiner	250	1,388
Donald R. Getty	—	1,388
Martin Gouin	—	—
John D. Hawkins	—	1,388
William Koehn	5,000	5,000
Ronald A. McIntosh	—	3,500
William C. Oehmig	13,150	1,388
Gordon Parchewsky	5,000	6,000
E. J. Antonio III	—	1,388
K. Rick Turner	—	1,388
Gary K. Wright	986	1,388

(1) all options 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 1, 2004.

Name of Beneficial Owner	Number of Common Shares		% of Outstanding Common Shares
Sterling Group Partners I, L.P.	272,466	(a)	30.13
Perry Partners International, Inc.	104,542	(b)	11.56

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Name of Beneficial Owner	Number of Common Shares		% of Outstanding Common Shares
Perry Partners, L.P.	92,707	(b)	10.25
Genstar Capital Partners III, L.P.	190,412	(c)	21.05
Stephens-NACG LLC	131,500	(d)	14.54
Richard Perry	197,249	(b)	21.81

(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 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.

There are no arrangements known to the Company which may at a subsequent date result in a change in control of the Company.

B. RELATED PARTY TRANSACTIONS

Advisory Services Agreement

Pursuant to an agreement 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 transactions, 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, 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., and the companies 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, 2004 totaling approximately $133,000. 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 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.

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Shareholders Agreement

In connection with the offering of common shares of NACG Holdings Inc., it is expected that employees of NACG Holdings or any of its subsidiaries who purchase common shares will enter into an employee shareholders agreement and all other purchasers will enter into an investor shareholders agreement. The shareholders agreements include the following provisions:

Certain Transfers/Rights of First Refusal and Tag Along Rights

Except for certain permitted transfers, the investor shareholders agreement permits the shareholders who are parties to that agreement to transfer their common shares or any interest therein only upon receipt of a written bona fide third-party offer and after offering such shares first to NACG Holdings Inc. and then to the other shareholders that are parties to the agreement at the price and on the terms specified in the third-party offer and offering such other shareholders the right to participate in such transfer on a pro-rata basis. In the event that NACG Holdings Inc. and the other shareholders do not accept all of the shares subject to the offer and the other shareholders expect not to participate in such transfer, the offering shareholder may transfer any remaining shares to the third party on no more favorable terms than those specified in the offer for a limited period of time.

Except for certain permitted transfers, the employee shareholders agreement permits the shareholders who are parties to that agreement to transfer their common shares or any interest therein only (1) upon receipt of a written bona fide third-party offer, (2) after the shareholder has held the shares subject to the agreement for at least two years and (3) after offering such shares to NACG Holdings Inc. at the price and on the terms specified in the third-party offer. In the event that NACG Holdings Inc. does not accept all of the shares subject to the offer, the offering shareholder may transfer any remaining shares to the third-party on no more favorable terms than those specified in the offer for a limited period of time. Also, if an employee shareholder is for any reason no longer employed by NACG Holdings Inc. or any of its subsidiaries before the two-year anniversary of the date the holder becomes a party to the agreement, the holder must sell all of his or her shares to NACG Holdings Inc. at the then fair market value of the shares.

Approved Sales

Each shareholders agreement contains provisions requiring all shareholders who are parties thereto to join in any control disposition, as defined below, to or with an independent third party, as defined below, or group of independent third parties and requiring their consent to the sale of all or substantially all of the consolidated assets of NACG Holdings Inc. and its subsidiaries to an independent third party or a group of independent third parties, in either case if the transaction is approved by the holders of at least two-thirds of the shares subject to the investor shareholders agreement and if, pursuant to the transaction, all of such holders are entitled to receive the same form and amount of consideration with respect to their shares. Each holder that is a party to either agreement agrees to consent to and raise no objections to such an approved transaction, to waive any dissenter’s rights or similar rights and to sell the common shares held by such holder on the terms and conditions approved. A control disposition is defined as any disposition or series of related dispositions which would have the effect of transferring to any transferee or group beneficial ownership of a number of common shares of NACG Holdings Inc. (a) that exceeds 40% of the then-outstanding common shares, on a fully-diluted basis, or (b) if thereafter the proposed transferee would directly or indirectly have beneficial ownership of 50% or more of all the then outstanding common shares, on a fully-diluted basis. An independent third party is defined as any person that does not own more than 5% of the outstanding shares of NACG Holdings Inc. on an as-if converted basis, and any person that is not affiliated with or associated with any such 5% holder.

Preemptive Rights

Subject to specified exceptions, the investor shareholders agreement provides the holders who are parties thereto preemptive rights in the event of an offering of any capital stock of NACG Holdings Inc. These exceptions include an initial public offering; an approved sale; securities issued upon conversion of convertible securities previously issued in compliance with the agreement; issuances to employees, prospective employees, directors and prospective directors, if approved by the board of directors of NACG Holdings Inc.; issuances of shares resulting in net proceeds to NACG Holdings Inc. of less than an aggregate of US$5.0 million; issuances as consideration for the acquisition of any business entity if NACG Holdings Inc. or any of its subsidiaries owns at least a majority of the voting power of the entity being acquired and the acquisition is approved by the board of directors of NACG Holdings Inc.; issuances to any bank, subordinated debt lender, equipment lessor, landlord or other similar financial institution or investor in connection with a loan transaction or equipment lease or similar commercial transaction provided that any such transaction is

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approved by the board of directors of NACG Holdings Inc.; and issuances in connection with any stock split, stock dividend, distribution or recapitalization by NACG Holdings Inc. The preemptive rights provided under the investor shareholders agreement expire 10 days after the holders receive written notice of the offering, and NACG Holdings Inc. will then have 270 days in which to sell the shares the holders have elected not to purchase.

The employee shareholders agreement does not provide any preemptive rights.

Public Offerings

Each shareholders agreement requires that, at any time that NACG Holdings Inc. is engaged in an underwritten public offering of its securities, each shareholder who is a party to either agreement shall refrain from making any disposition of common shares on a securities exchange or in the over-the-counter or any other public trading market for a period of time not to exceed 180 days. This provision, however, does not limit any shareholder’s right to include common shares held by it in any such underwritten public offering pursuant to any demand or piggyback registration rights that such shareholder may have.

Material Agreements

Each shareholders agreement provides that notwithstanding certain other provisions of the respective agreements permitting transfers of shares, no transfer will be made which would cause, in the reasonable judgment of NACG Holdings Inc., a material breach of or default or acceleration of payments under any agreement to which NACG Holdings Inc. or any of its subsidiaries is a party under which the indebtedness or liability of NACG Holdings Inc. or any of its subsidiaries is more than $1.0 million.

Termination

The employee shareholders agreement will terminate upon any of the following events: (i) our dissolution; (ii) after 10 days notice from us to all the holders party to the agreement; or (iii) a registered public offering of common shares by NACG Holdings Inc. (excluding certain offerings) resulting in net proceeds to it of at least $100 million.

The investor shareholders agreement will terminate upon any of the following events: (i) the dissolution of NACG Holdings Inc.; (ii) any event that reduces the number of shareholders party to the agreement to one in accordance with the terms of the investor shareholders agreement; (iii) a registered public offering of common shares by NACG Holdings Inc. (excluding certain offerings) resulting in net proceeds to it of at least $100 million; or (iv) the written approval of the holders of all common shares subject to the agreement.

Voting and Corporate Governance Agreement

In connection with their purchase of common shares in the offering, NACG Holdings Inc. entered into 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 also 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.;

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• 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 equity registration rights agreement, the shareholders agreement and the advisory services agreement described elsewhere in this prospectus.

Covenants

The agreement provides that NACG Holdings Inc. will not, and will not permit any of its subsidiaries to, engage in specified transactions without the consent of holders of a specified majority of shares subject to the agreement, including, but not limited to:

• issuances of any securities resulting in net proceeds of an aggregate of more than US$5.0 million during the term of the agreement, with some exceptions;

• acquisitions or investments outside the ordinary course of business exceeding US$25.0 million;

• capital expenditures in excess of annually budgeted amounts plus US$10.0 million;

• dividends or repurchases of securities in amounts exceeding an aggregate of US$5.0 million during the term of the agreement, except for dividends on Series A Preferred Stock purchases pursuant to the shareholders agreement and purchases of shares issued to employees and directors; and

• mergers, consolidations or amalgamations with any third party, dissolutions, reorganizations and substantive discussions with an investment banking firm regarding an initial public offering.

The agreement also requires approval by a specified vote to change the size of the board of directors of NACG Holdings Inc. and provides certain information rights and board observer rights to shareholders who are parties thereto.

Termination

It is expected that the voting and corporate governance agreement will terminate upon any of the following events: (i) the dissolution of NACG Holdings Inc.; (ii) the occurrence of any event which reduces the number of shareholders party to the agreement to one; (iii) the completion of an underwritten initial public offering of the common shares of NACG Holdings Inc. resulting in aggregate net proceeds of at least $100 million; (iv) the written vote of the holders of all common shares subject to the agreement.

Registration Rights Agreement

NACG Holdings Inc. has entered into a registration rights agreement with the holders of qualified registrable securities who are signatories thereto. 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 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.

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• 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.

ITEM 8: FINANCIAL INFORMATION

A. CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION

See Item 18: Financial Statements.

Legal Proceedings

We are involved in various legal proceedings arising out of the ordinary course of our business. We believe that the liabilities, if any, arising from all pending legal proceedings in the aggregate will not have a material adverse effect on our financial condition or operations.

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.

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ITEM 10: ADDITIONAL INFORMATION

A. SHARE CAPITAL

Not applicable.

B. MEMORANDUM AND ARTICLES OF ASSOCIATION

Our Articles of Incorporation and By-laws were filed as exhibits to our registration statement on Form F-4/S-4 filed with the Securities and Exchange Commission on December 19, 2003 and are 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.

D. EXCHANGE CONTROLS

There are currently no limitations imposed by Canadian laws, decrees or regulations 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 to file reports and other information with the SEC. These reports, our registration statement with respect to our exchange offer for our 8¾% senior notes due 2011 and other information are or will be available after filing for reading and copying at the SEC Public Reference Room at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., 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 an Internet site at http://www.sec.gov that contains the registration statement and 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 indenture pursuant to which the notes are issued provides 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 reports on Form 6-K which, regardless of 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.

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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 such request should be directed to North American Energy Partners Inc., Vice President, Finance, Zone 3, Acheson Industrial Area, 2-53016 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

Our 8¾% senior notes due 2011 are denominated in U.S. dollars, while our functional currency is the Canadian dollar. In order to reduce our exposure to changes in the U.S. to Canadian dollar exchange rate, concurrent with the closing of the acquisition on November 26, 2003, we entered into a cross currency swap agreement to hedge this foreign currency exposure and buy U.S. dollars 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. As part of the cross currency swap agreement, we 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 notes into a fixed rate of 9.765% until maturity.

We are also subject to interest rate market risk in connection with the senior secured debt facilities. We have $48.5 million outstanding under the term loan and no drawings under the revolving credit facility. Both facilities bear interest at variable rates based in part on the Canadian prime rate or at a Canadian bankers’ acceptance rate, in each case plus an applicable margin. Each 1% increase or decrease in the interest rate on the term loan would change our cost of financing by $0.4 million. Assuming the revolving credit facility is fully drawn at $60 million, each 1% increase or decrease in the applicable interest rate would change the interest cost by $0.6 million. In the future, we may enter into interest rate swaps, involving the exchange or floating for fixed rate interest payments, to reduce interest rate volatility.

For the fiscal year ended March 31, 2003, Norama Ltd. was subject to interest rate risk on its operating loan, bank loans, capital lease obligations and advances from Norama Inc., its sole shareholder. For each 1% annual fluctuation in the interest rate, the cost of financing would have changed by approximately $0.6 million.

For the fiscal year ended March 31, 2003, Norama Ltd. also leased equipment with a variable lease payment component that was tied to prime rates. For each 1% annual fluctuation in these rates, lease expense would have changed by approximately $0.3 million.

The higher sensitivity to changes in interest rates since the closing of the acquisition is due to the higher balance of floating rate term loans and revolving credit facility in the new capital structure as compared to that of Norama Ltd.

The rate of inflation has not had a material impact on our operations as many of our contracts contain provision for annual escalation. If inflation remains at its recent levels, we would not expect it 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.

47

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

None.

ITEM 15: CONTROLS AND PROCEDURES

As of March 31, 2004, our management, including our President and Vice President, Finance, has evaluated the effectiveness of the design and operation 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 the design and operation 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.

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.

ITEM 16B: CODE OF ETHICS

We are in the process of preparing a code of ethics that will apply 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, 2004.

Audit Fees

KPMG billed NAEPI (and the Predecessor Company) $483,000 in 2004 and $272,000 in 2003 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

KPMG billed NAEPI (and the Predecessor Company) $165,000 in 2004 and $16,000 in 2003 for audit-related services, primarily in connection with financial due diligence services for the acquisition.

Tax Fees

KPMG billed NAEPI (and the Predecessor Company) $58,000 in 2004 and $30,000 in 2003 for tax compliance, tax advice, tax planning services and tax due diligence services.

All Other Fees

None.

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

Not applicable.

48

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

Not applicable.

PART III

ITEM 17: FINANCIAL STATEMENTS

Not applicable.

ITEM 18: 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 United States GAAP appears in Note 19 thereto.

ITEM 19: EXHIBITS

(a) Financial Statements

(i) Auditors’ Report.

(ii) Balance Sheets as at March 31, 2003 and 2004.

(iii) Statements of Operations for the years ended March 31, 2002, 2003 and the periods April 1, 2003 to November 25, 2003 and November 26, 2003 to March 31, 2004.

(iv) Statements of Retained Earnings for the years ended March 31, 2002, 2003 and the periods April 1, 2003 to November 25, 2003 and November 26, 2003 to March 31, 2004.

(v) Statements of Cash Flows for the years ended March 31, 2002, 2003 and the periods April 1, 2003 to November 25, 2003 and November 26, 2003 to March 31, 20044.

(vi) Notes to the Financial Statements.

(vii) 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 Incorporation of North American Energy Partners Inc., filed with the Corporations Directorate of Industry Canada on October 17, 2003 (together with amendments thereto).

1.2* By-laws of North American Energy Partners Inc.

2.1* 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.

4.1* Credit Agreement, dated as of November 26, 2003, among North American Energy Partners Inc., the lenders named therein, Royal Bank of Canada, as Administrative Agent, BNP Paribas Securities Corporation and RBC Capital Markets, as Lead Arrangers and Book Managers, and BNP Paribas, as Syndication Agent.

4.2* First Amending Agreement, dated as of March 31, 2004, among North American Energy Partners Inc., the lenders listed therein, Royal Bank of Canada, as Administrative Agent, BNP Paribas Securities Corporation and RBC Capital Markets, as Lead Arrangers and Book Managers, and BNP Paribas, as Syndication Agent.

49

4.3* Second Amending Agreement, dated as of June 30, 2004, among North American Energy Partners Inc., the lenders listed therein, Royal Bank of Canada, as Administrative Agent, BNP Paribas Securities Corporation and RBC Capital Markets, as Lead Arrangers and Book Managers, and BNP Paribas, as Syndication Agent.

8.1* Subsidiaries of North American Energy Partners Inc.

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.

* Incorporated by reference to North American Energy Partner Inc.’s Form F-4/S-4 filed with the Securities and Exchange Commission (Commission File No. 333-111396).

50

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: September 17, 2004	By:	/s/ Vincent J. Gallant
	Name:	Vincent J. Gallant
	Title:	Vice President, Finance

51

NORTH AMERICAN ENERGY PARTNERS INC.

FINANCIAL STATEMENTS

FOR THE YEAR ENDED MARCH 31, 2004

52

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the consolidated balance sheet of North American Energy Partners Inc. as at March 31, 2004 and the consolidated balance sheet of Norama Ltd. (the “Predecessor Company”) as at March 31, 2003 and the consolidated statements of operations and retained earnings and cash flows of North American Energy Partners Inc. for 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 each of the years in the two-year period ended March 31, 2003 and 2002. 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 and 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.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the North American Energy Partners Inc. as at March 31, 2004 and the Predecessor Company as at March 31, 2003 and the results of operations and cash flows of North American Energy Partners Inc. for 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 each of the years in the two-year period ended March 31, 2003 and 2002, in accordance with Canadian generally accepted accounting principles.

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 19 to the consolidated financial statements.

Signed “KPMG LLP”

Chartered Accountants

Edmonton, Canada

June 8, 2004

53

NORTH AMERICAN ENERGY PARTNERS INC.

Consolidated Balance Sheets

(in thousands of Canadian dollars)

	March 31, 2004			Predecessor Company (note 2(a)) March 31, 2003
Assets
Current assets:
Cash and cash equivalents	$	36,595		$	—
Accounts receivable (note 11(a))		33,647			56,622
Unbilled revenue		27,676			24,777
Inventory		1,609			—
Prepaid expenses		1,272			300
		100,799			81,699
Capital assets (note 4)		167,905			76,234
Goodwill (note 3)		198,549			—
Intangible assets, net of accumulated amortization of $12,928 (notes 3 and 5)		4,870			—
Deferred financing costs, net of accumulated amortization of $814 (note 3)		17,266			—
	$	489,389		$	157,933
Liabilities and Shareholder’s Equity
Current liabilities:
Cheques issued in excess of cash deposits	$	—		$	2,496
Revolving credit facility (note 6(a))		—			—
Operating line of credit (note 6(b))		—			516
Accounts payable (note 11(b))		23,187			28,820
Accrued liabilities		20,808			10,423
Current portion of term credit facility (note 6(a))		7,250			14,601
Current portion of capital lease obligations (note 7)		787			4,842
Future income taxes (note 9)		5,260			12,300
Current portion of advances from Norama Inc. (note 13(c))		—			3,100
		57,292			77,098
Term credit facility (note 6(a))		41,250			7,525
Capital lease obligations (note 7)		2,251			3,943
Senior notes (note 8)		262,260			—
Derivative financial instruments (note 14(c))		740			—
Future income taxes (note 9)		2,515			10,675
Advances from Norama Inc. (note 13(c))		—			28,874
Shareholder’s equity:
Share capital (note 10)		127,500			1
Contributed surplus (note 17)		137			—
Retained earnings (deficit)		(4,556	)		29,817
		123,081			29,818
Commitments (note 15)
United States generally accepted accounting principles (note 19)
	$	489,389		$	157,933

See accompanying notes to consolidated financial statements.

54

NORTH AMERICAN ENERGY PARTNERS INC.

Consolidated Statements of Operations and Retained Earnings

(in thousands of Canadian dollars)

				Predecessor Company
	for the period November 26, 2003 to March 31, 2004			for the period April 1, 2003 to November 25,			for the year ended March 31, 2003			for the year ended March 31, 2002
Revenue	$	127,614		$	250,919		$	344,186		$	249,351
Project costs		83,208			156,835			219,979			127,996
Equipment costs		15,116			53,986			72,228			77,289
Depreciation		6,674			6,566			10,974			11,299
		104,998			217,387			303,181			216,584
Gross profit		22,616			33,532			41,005			32,767
General and administrative		6,113			7,924			12,233			12,794
Loss (gain) on disposal of capital assets		131			(49	)		(2,265	)		(218	)
Amortization of intangible assets		12,928			—			—			—
Operating income		3,444			25,657			31,037			20,191
Management fees (note 13(c))		—			41,070			8,000			14,400
Interest expense, net (note 11(c))		10,791			2,357			4,162			3,510
Foreign exchange (gain) loss (note 14(d))		79			(7	)		(234	)		(17	)
		10,870			43,420			11,928			17,893
Income (loss) before income taxes		(7,426	)		(17,763	)		19,109			2,298
Income taxes (note 9):
Current income taxes		1,178			218			245			239
Future income taxes		(4,048	)		(6,840	)		6,375			450
		(2,870	)		(6,622	)		6,620			689
Net income (loss)		(4,556	)		(11,141	)		12,489			1,609
Dividends		—			—			(50	)		(1,000	)
Retained earnings, beginning of period		—			29,817			17,378			16,769
Retained earnings (deficit), end of period	$	(4,556	)	$	18,676		$	29,817		$	17,378

See accompanying notes to consolidated financial statements.

55

NORTH AMERICAN ENERGY PARTNERS INC.

Consolidated Statements of Cash Flows

(in thousands of Canadian dollars)

				Predecessor Company
	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			for the year ended March 31, 2002
Cash provided by (used in):
Operating activities:
Net income (loss)	$	(4,556	)	$	(11,141	)	$	12,489		$	1,609
Items not affecting cash:
Depreciation		6,674			6,566			10,974			11,299
Amortization of intangible assets		12,928			—			—			—
Amortization of deferred financing costs		814			—			—			—
Loss (gain) on disposal of capital assets		131			(49	)		(2,265	)		(218	)
Increase (decrease) in allowance for doubtful accounts		(60	)		141			142			274
Stock-based compensation expense		137			—			—			—
Future income taxes		(4,048	)		(6,840	)		6,375			450
Net changes in non-cash working capital (note 11(e))		3,457			13,832			(11,432	)		(9,239	)
		15,477			2,509			16,283			4,175
Investing activities:
Acquisition (note 3)		(367,778	)		—			—			—
Purchase of capital assets		(2,501	)		(5,234	)		(22,932	)		(8,668	)
Proceeds on disposal of capital assets		5,765			609			4,187			2,204
		(364,514	)		(4,625	)		(18,745	)		(6,464	)
Financing activities:
Issuance of share capital		92,500			—			—			—
Issuance of senior notes		263,000			—			—			—
Proceeds from term credit facility		50,000			—			13,500			8,003
Financing costs		(18,080	)		—			—			—
Increase (decrease) in operating line of credit		—			(516	)		(232	)		748
Repayment of term credit facility		(1,500	)		(4,428	)		(5,280	)		(5,614	)
Repayment of capital lease obligations		(288	)		(3,289	)		(3,058	)		(1,250	)
Increase (decrease) in cheques issued in excess of cash deposits		—			(2,496	)		(1,313	)		3,809
Advances from Norama Inc.		—			17,696			(1,105	)		(6,428	)
Dividends paid		—			—			(50	)		(1,000	)
		385,632			6,967			2,462			(1,732	)
Increase (decrease) in cash and cash equivalents		36,595			4,851			—			(4,021	)
Cash and cash equivalents, beginning of period		—			—			—			4,021
Cash and cash equivalents, end of period	$	36,595		$	4,851		$	—		$	—

See accompanying notes to consolidated financial statements.

56

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the period November 26, 2003 to March 31, 2004

(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 3, 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 19.

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

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

In preparation for the acquisition described in note 3, 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 ending after November 25, 2003.

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 generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and 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-fixed-fee; unit-price; and fixed-price or lump-sum. For time-and-materials and cost-plus-fixed-fee contracts, revenue is recognized as costs are incurred. Revenue from unit-price contracts is recognized based on quantities of units performed and delivered. Revenue on lump-sum contracts is recognized on the percentage-of-completion method, measured by the ratio of costs incurred to date to estimated total costs.

57

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the period November 26, 2003 to March 31, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

The length of the Company’s contracts varies, but is typically less than one year. Contract project costs include all direct labour, material, subcontractors and equipment costs and those indirect costs related to contract performance such as indirect labour, supplies, and tool costs. 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 job performance, job conditions, and estimated profitability, including those arising from contract penalty provisions and final contract settlements may result in revisions to costs and income and 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.

d) Cash and cash equivalents:

Cash and cash equivalents include cash on hand, bank balances and short-term liquid investments with maturities of three months or less, 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.

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 and spare component parts.

g) Capital assets:

Capital assets are recorded at cost. Major components of heavy construction equipment in use such as engines, transmissions, and undercarriages are recorded separately as capital assets. 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 of assets 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	%

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 capital assets 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

58

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the period November 26, 2003 to March 31, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

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. As of March 31, 2004, no impairment of goodwill has occurred.

i) Intangible assets:

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

Effective April 1, 2003, the Company has adopted the new recommendations of the CICA Handbook Section 3063, “Impairment or Disposal of Long-Lived Assets” with respect to the measurement and disclosure of the impairment of long-lived assets. This standard requires 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 assets over its fair value.

l) Foreign currency translation and hedging:

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.

The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives to specific assets and liabilities on the balance sheet. The Company also formally assesses, both at the hedge’s inception and at the end of each quarter, whether the derivatives that are used in hedged transactions are effective in offsetting changes in cash flows of hedged items. Foreign exchange translation gains and losses on foreign currency contracts used to hedge foreign-currency denominated amounts are accrued on the balance sheet as assets or liabilities and are recognized currently in the income statement, offsetting the respective translation gains or losses on the foreign-currency denominated amounts. Realized and unrealized gains or losses associated with derivative instruments, which have been terminated or cease to be effective prior to maturity, are deferred under other current, or non-current, assets or liabilities on the balance sheet and recognized in income in the period in which the underlying hedged transaction is recognized. In the event a designated hedged item is sold, extinguished or matures prior to the termination of the related derivative instrument, any realized or unrealized gain or loss on such derivative instrument is recognized in income.

Derivative financial instruments are utilized by the Company in the management of its foreign currency exposure. The Company does not hold or issue derivative financial instruments for trading or speculative purposes. Derivative financial instruments are subject to standard credit terms and conditions, financial controls, management and risk monitoring procedures.

59

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the period November 26, 2003 to March 31, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

m) 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.

n) 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.

o) Recent Canadian accounting pronouncements:

(i) Hedging relationships:

In November 2001, the CICA issued Accounting Guideline 13, “Hedging Relationships” (“AcG-13”), and in November 2002, the CICA amended the effective date of the guideline which establishes new criteria for hedge accounting and will apply to all hedging relationships in effect on or after April 1, 2004. To qualify for hedge accounting, the hedging relationship must be appropriately documented at the inception of the hedge and there must be reasonable assurance, both at the inception and throughout the term of the hedge, that the hedging relationship will be effective. Effectiveness requires a high correlation of changes in fair values or cash flows between the hedged item and the hedging item. The Company has reviewed the requirements of AcG-13 and has determined that all of its current hedges qualify for hedge accounting under the new guideline.

(ii) Consolidation of variable interest entities:

In June 2003, the CICA issued 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 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 standard is effective on a prospective basis for the Company’s 2005 fiscal year. The adoption of this standard is not expected to have a material impact on the consolidated financial statements.

(iii) Generally accepted accounting principles:

Effective November 26, 2003, the Company adopted CICA Handbook Section 1100, “Generally Accepted Accounting Principles,” which establishes standards for financial reporting in accordance with Canadian GAAP, and describes what constitutes Canadian GAAP and its sources. This section also provides guidance on sources to consult when selecting accounting policies and determining appropriate disclosures when the primary sources of Canadian GAAP are silent. The adoption of this standard is not expected to have a material impact on the consolidated financial statements.

(iv) Revenue recognition:

In December 2003, the Emerging Issues Committee released EIC-141, “Revenue Recognition” which is effective on a prospective basis for the Company’s 2005 fiscal year. EIC-141 incorporates the principles and guidance under U.S. GAAP for revenue recognition. The adoption of this standard is not expected to have a material impact on the consolidated financial statements.

60

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the period November 26, 2003 to March 31, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

3. 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 capital assets, 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 capital assets, 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.

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
Capital assets, 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

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the period November 26, 2003 to March 31, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

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 have been accounted for as increased goodwill and $18.1 million of which have been recorded as deferred financing costs. The deferred financing costs were subject to amortization of $814 during the period ended March 31, 2004.

An amount of $2.9 million payable to the vendors related to the purchase price is included in accounts payable at March 31, 2004.

The current assets include $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.

4. Capital assets

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

Predecessor Company March 31, 2003	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	119,006	$	51,726	$	67,280
Major component parts in use		—		—		—
Spare component parts		—		—		—
Other equipment		10,722		4,486		6,236
Licensed motor vehicles		7,371		6,082		1,289
Office and computer equipment		2,865		1,436		1,429
	$	139,964	$	63,730	$	76,234

The above amounts include $3,328 (March 31, 2003 – $12,559) of assets under capital lease and accumulated depreciation of $320 (March 31, 2003 – $1,571) related thereto. During the period November 26, 2003 to March 31, 2004, capital asset additions included

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the period November 26, 2003 to March 31, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

$1,195 of assets that were acquired by means of capital leases (April 1, 2003 – November 25, 2003 – $nil; 2003 – $9,439; 2002 – $nil). Depreciation of equipment under capital leases of $320 (April 1, 2003 – November 25, 2003 – $677; 2003 – $765; 2002 – $530) is included in depreciation expense. As at March 31, 2004, capital assets reflect the effects of applying push down accounting due to the acquisition described in note 3.

5. Intangible assets

At March 31, 2004, identifiable intangible assets purchased in the acquisition described in note 3 consisted of the following:

Identifiable intangible assets	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

6. Senior secured credit facility

a) Credit facility:

On November 26, 2003, the Company secured a $120 million senior 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’ acceptances rate plus 3%. The credit facility is secured by a first priority lien on the Company’s capital stock and the capital stock of its subsidiaries and on substantially all the assets of the Company and its subsidiaries. Concurrent with the acquisition on November 26, 2003 (note 3), a letter of credit in the amount of $10 million was issued to support bonding requirements associated with the Company’s customer contracts. Except for the letter of credit, no amounts were drawn down on the revolving credit facility.

	March 31, 2004		Predecessor Company March 31, 2003
Term credit facility, due November 26, 2008	$	48,500		—
4.5% term debt, due September 2004		—		9,625
Term debt, with maturity dates between July, 2003 and September, 2007, prime plus 0.25%		—		12,501
		48,500		22,126
Less: current portion		7,250		14,601
	$	41,250	$	7,525

The term portion of the credit facility is repayable in quarterly installments over the next five fiscal years as set out below:

2005	$	7,250
2006		11,000
2007		11,000
2008		11,000
2009		8,250
	$	48,500

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the period November 26, 2003 to March 31, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

b) Operating line of credit:

The Predecessor Company had an operating line of credit, authorized to a maximum of $20 million, which was due on demand and bore interest at the lender’s prime rate. The loan was secured by a general security agreement covering all present and after-acquired property held by NACGI and its subsidiaries and the postponement of $2 million advances from Norama Inc. supported by a promissory note. On the date of acquisition described in note 3, the Predecessor Company’s operating line of credit had a balance of nil.

The term bank loans were secured by general security agreements providing a first charge on specific heavy equipment with a carrying value of $27,764 assignment of insurance proceeds and subordination of the advances from the shareholder. All of the Predecessor Company’s term debt was repaid on the date of acquisition described in note 3.

7. 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 four fiscal years are summarized as follows:

	March 31, 2004
2005	$	886
2006		820
2007		778
2008		831
		3,315
Less: amount representing interest - average rate of 5.3%		277
Present value of minimum capital lease payments		3,038
Less: current portion		787
	$	2,251

The Predecessor Company leased a portion of its heavy equipment for which the minimum lease payments due in each of the next three fiscal years would have been as follows:

	Predecessor Company March 31, 2003
2004	$	5,154
2005		3,240
2006		823
		9,217
Less: amount representing interest – prime to prime plus 0.25%		432
Present value of minimum capital lease payments		8,785
Less: current portion		4,842
	$	3,943

8. 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. By way of swap agreements, the notes have an effective interest rate of 9.765% for the duration for which the senior notes are outstanding.

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the period November 26, 2003 to March 31, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

The notes are unsecured senior obligations and rank equally with all other existing and future unsecured and unsubordinated debt and senior to all subordinated debt of the Company. The notes are effectively subordinated to all secured debt, including debt under the secured credit facility (note 6(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.

The foreign exchange exposure relating to the senior notes has been hedged – see note 14 (c).

9. 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 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			for the year ended March 31, 2002
Statutory rate		35.2	%		36.6	%		38.6	%		41.1	%
Expected provision (recovery) at statutory rate	$	(2,614	)	$	(6,501	)	$	7,377		$	944
Change in future income tax liability, resulting from reduction in future statutory income tax rates		(342	)		(669	)		(700	)		(506	)
Large corporations tax		319			137			245			239
Other		(233	)		411			(302	)		12
Income tax provision (recovery) for current period	$	(2,870	)	$	(6,622	)	$	6,620		$	689

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

	March 31, 2004			Predecessor Company March 31, 2003
Unbilled revenue and uncertified revenue included in accounts receivable	$	27,906		$	30,900
Accounts receivable—holdbacks		3,838			4,671
Non-capital losses carried forward		(16,649	)		(2,031	)
Difference between tax and carrying basis of capital assets		2,179			29,548
Difference between tax and carrying basis of deferred financing costs		440			(34	)
Intangible assets		4,870			—
Other		550			(271	)
Net temporary differences		23,134			62,783
Tax rate expected to apply		33.6	%		36.6	%
Net future tax liability		7,775			22,975
Less: current portion		5,260			12,300
	$	2,515		$	10,675

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the period November 26, 2003 to March 31, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

10. Share capital

Authorized:

Unlimited number of common voting shares.

Issued:

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

The common shares were issued to NACG Preferred Corp. for cash consideration of $92.5 million and for NACGI shares valued at $35.0 million.

11. Other information

a) Accounts receivable:

	March 31, 2004			Predecessor Company March 31, 2003
Accounts receivable – trade	$	29,991		$	51,328
Accounts receivable – holdbacks		3,838			4,671
Accounts receivable – other		51			775
Allowance for doubtful accounts		(233	)		(152	)
	$	33,647		$	56,622

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.

At March 31, 2004, the following customers represented 10% or more of accounts receivable and unbilled revenue:

	March 31, 2004		Predecessor Company March 31, 2003
Customer A	28.7	%	50.1	%
Customer B	43.6	%	25.1	%

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the period November 26, 2003 to March 31, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

11. Other information, continued

“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) Accounts payable:

	March 31, 2004		Predecessor Company March 31, 2003
Accounts payable – trade	$	23,187	$	28,777
Accounts payable – holdbacks		—		43
	$	23,187	$	28,820

c) Interest expense, net:

				Predecessor Company
	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			for the year ended March 31, 2002
Interest on senior notes	$	9,035		$	—		$	—		$	—
Interest on senior secured credit facility		1,089			599			971			798
Interest on capital lease obligations		56			294			196			15
Interest on advances from Norama Inc.		—			1,468			2,223			2,756
Interest on long-term debt		10,180			2,361			3,390			3,569
Amortization of deferred financing costs		814			—			—			—
Other interest		24			96			783			217
Interest income		(227	)		(100	)		(11	)		(276	)
	$	10,791		$	2,357		$	4,162		$	3,510

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the period November 26, 2003 to March 31, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

11. Other information, continued

d) Supplemental cash flow information:

			Predecessor Company
	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		for the year ended March 31, 2002
Cash paid during the period for
Interest	$	1,736	$	2,431	$	966	$	635
Income taxes		269		325		202		278
Cash received during the period for
Interest		177		100		—		74
Income taxes		18		—		—		—

e) Net change in non-cash working capital:

				Predecessor Company
	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			for the year ended March 31, 2002
Accounts receivable	$	19,556		$	3,338		$	(6,730	)	$	(16,584	)
Unbilled revenue		(17,528	)		15,289			(12,054	)		10,252
Inventory		(1,609	)		—			—			—
Prepaid expenses		(295	)		(544	)		179			(274	)
Accounts payable		(2,839	)		(2,794	)		4,605			7,549
Accrued liabilities		6,172			(1,457	)		2,568			(10,182	)
	$	3,457		$	13,832		$	(11,432	)	$	(9,239	)

12. 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.

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the period November 26, 2003 to March 31, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

•   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 period November 26, 2003 to March 31, 2004	Mining & Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	53,407	$	9,565	$	64,642	$	127,614
Depreciation of capital assets		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 capital assets		61		30		1,671		1,762
Predecessor Company For the period April 1, 2003 to November 25, 2003	Mining & Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	182,685	$	39,368	$	28,866	$	250,919
Depreciation of capital assets		3,590		1,256		158		5,004
Segment profits		27,801		8,318		5,054		41,173
Segment assets		78,564		31,792		15,904		126,260
Expenditures for segment capital assets		2,458		417		—		2,875
Predecessor Company For the year ended March 31, 2003	Mining & Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	245,235	$	61,006	$	37,945	$	344,186
Depreciation of capital assets		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 capital assets		26,546		4,422		—		30,968
Predecessor Company For the year ended March 31, 2002	Mining & Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	186,141	$	35,132	$	28,078	$	249,351
Depreciation of capital assets		7,355		1,568		136		9,059
Segment profits		30,921		8,108		6,111		45,140
Segment assets		65,271		26,771		15,386		107,428
Expenditures for segment capital assets		5,386		74		—		5,460

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the period November 26, 2003 to March 31, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

c) Reconciliations:

(i) Income (loss) before income taxes:

				Predecessor Company
	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			for the year ended March 31, 2002
Total profit for reportable segments	$	23,547		$	41,173		$	50,198		$	45,140
Unallocated corporate expenses		(29,911	)		(51,344	)		(24,559	)		(30,999	)
Unallocated equipment costs		(1,062	)		(7,592	)		(6,530	)		(11,843	)
Income (loss) before income taxes	$	(7,426	)	$	(17,763	)	$	19,109		$	2,298

(ii) Total assets:

	March 31, 2004		Predecessor Company March 31, 2003
Total assets for reportable segments	$	410,469	$	143,460
Corporate assets		78,920		14,473
Total assets	$	489,389	$	157,933

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 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		for the year ended March 31, 2002
Customer A	50.8	%	11.5	%	11.0	%	11.2	%
Customer B	10.7	%	9.1	%	14.6	%	22.7	%
Customer C	—		0.2	%	1.0	%	13.6	%
Customer D	27.0	%	64.4	%	64.1	%	37.6	%

This revenue by major customer was earned in all three business segments: mining and site preparation, pipeline and piling.

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the period November 26, 2003 to March 31, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

13. 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:

On November 21, 2003, 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. Pursuant to this agreement, the Sponsors provided consulting and advisory services with respect to the organization of the companies, the structuring of the acquisition described in note 3, 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. As compensation for these services, the Company paid, at the closing of the transactions, a one-time transaction fee of US$3.0 million to Sterling and a one-time transaction fee of US$3.0 million that was 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. In addition, the Company paid US$486,000 to reimburse the Sponsors and BNP Paribas Private Capital Group for their travel and other expenses incurred in connection with the transactions. In accordance with the terms of the agreement, at the closing of the transactions, the Company paid to the Sponsors a pro-rated advisory fee for the period from closing until March 31, 2004 totaling $133. In addition, as compensation for the services provided by the Sponsors after the closing of the transactions, the agreement provides that on each June 30 through June 30, 2013, the Company will pay the Sponsors whose services have not terminated in accordance with the agreement, as a group, an annual advisory fee in cash totaling the greater of $400 and 0.5% of the Company’s earnings before interest, taxes, depreciation and amortization (“EBITDA”) for the previous twelve month period ended March 31 as defined in the agreement.

b) Office rent:

Pursuant to several office lease agreements, for the period from November 26, 2003 to March 31, 2004 the Company paid $231 (April 1, 2003 – November 25, 2003 – $427; 2003 – $513; 2002 – $480) 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 3.

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. The advances from Norama Inc. were interest bearing at prime plus 2% without any fixed terms of repayment.

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the period November 26, 2003 to March 31, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

14. 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 swap contracts.

a) Fair value:

The fair values of the Company’s cash and cash equivalents, accounts receivable, outstanding cheques and accounts payable and accrued liabilities approximate their carrying amounts.

The fair value of the senior 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, 2004 is not significantly different than its carrying value.

b) Interest rate risk:

The Company is subject to interest rate risk on the senior credit facility and capital lease obligations. At March 31, 2004, for each 1% annual fluctuation in the interest rate, the annual cost of financing will change by approximately $470.

The Company also leases equipment (as described in note 15) with a variable lease payment component that is tied to prime rates. At March 31, 2004, for each 1% annual fluctuation in these rates, annual lease expense will change by approximately $88.

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 hedge this foreign currency exposure and buy U.S. dollars 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. As part of 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. Each period, an amount equal to the gain or loss resulting on the remeasurement of the hedged item at spot rates is recorded as an offset to the foreign currency gains or losses otherwise recorded.

The carrying amount and fair value of the Company’s derivative financial instruments as at March 31, 2004 are as follows:

	Carrying amount		Fair value
Cross currency and interest rate swaps - liability	$	740	$	11,266

At March 31, 2004, 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.

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the period November 26, 2003 to March 31, 2004

(Amounts 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 as the Company has not entered into a cross currency swap agreement to hedge this foreign currency exposure.

15. Commitments

The future minimum lease payments in respect of operating leases amount to approximately $4,960. Annual payments in the next five fiscal years are:

2005	$	2,977
2006		847
2007		665
2008		463
2009		8
	$	4,960

16. 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 3% of base salary for each employee. Contributions made by the Company during the period November 26, 2003 to March 31, 2004 were $68 (April 1, 2003 – November 2003 – $122; 2003 – $166; 2002 – $123).

17. 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 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 38,370 are still available for issue as at March 31, 2004. On January 28, 2004, NACG Holdings Inc. granted options to purchase 54,130 common shares. As at March 31, 2004, none of these stock options were exercisable. No stock options were granted by the Predecessor Company.

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 4.79%; volatility of nil%; and an expected option life of 10 years.

The stock options outstanding at March 31, 2004 are as follows:

	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

The Company recorded $137 of compensation expense related to the stock options in 2004 (2003 – $nil) with such amount being credited to contributed surplus.

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the period November 26, 2003 to March 31, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

18. Comparative figures

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

19. United States generally accepted accounting principles

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:

During the period ended March 31, 2004 the Company entered into a series of derivatives that have been designated as a hedge of the risk of changes in cash flows resulting from the impact of changes in the U.S. to Canadian dollar exchange rate applicable to the payments of interest and principal on the senior notes. In accordance with the provisions of SFAS 133 “Accounting for Derivatives and Hedging Activities”, all derivatives are recognized as assets and liabilities on the balance sheet and measured at fair value. As of March 31, 2004, the fair value of the derivatives was $11,266. The Company has elected to measure and assess effectiveness based on total changes in the cash flows generated by hedging instruments. Each period, an amount equal to the gain or loss resulting on the remeasurement of the hedged item at spot rates is reclassified from Other Comprehensive Income and recorded as an offset to the foreign currency gains or losses otherwise recorded. In addition, the Company reclassifies an amount to reflect the cost element of the hedging instrument. During the period ended March 31, 2004, $1,132 (net of tax of $573) was reclassified from Other Comprehensive Income and included in income.

Consolidated Statement of Other Comprehensive Income:

Net loss in accordance with Canadian and U.S. GAAP	$	(4,556	)
Net loss on cash flow hedges, net of tax of $3,785		(7,481	)
Less: reclassification adjustments, net of tax of $573		1,132
Comprehensive loss in accordance with U.S. GAAP	$	(10,905	)

Recent United States accounting pronouncements:

In December 2003, the U.S. Financial Accounting Standards Board, or FASB issued FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities (“VIE”), which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity. FIN 46R replaces FASB Interpretation No. 46, Consolidation of Variable Interest Entities (“FIN 46R”), which was issued in January 2003. The Company is required to apply FIN 46R to variable interests in Variable Interest Entities, or VIEs created after December 31, 2003. With respect to entities that do not qualify to be assessed for consolidation based on voting interests, FIN 46R generally requires a company that has a variable interest(s) that will absorb a majority of the VIE’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur, or both, to consolidate that VIE. For variable interests in VIEs created before January 1, 2004, the Interpretation will be applied beginning on January 1, 2005. For any VIEs that must be consolidated under FIN 46R that were created before January 1, 2004, the assets, liabilities and noncontrolling interests of the VIE initially would be measured at their carrying amounts with any difference between the net amount added to the balance sheet and any previously recognized interest being recognized as the cumulative effect of an accounting change. If determining the carrying amounts is not practicable, fair value at the date FIN 46R first applies may be used to measure the assets, liabilities and noncontrolling interest of the VIE. The adoption of this standard did not have a material impact on these financial statements.

FASB Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, was issued in May 2003. This Statement establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. The Statement also includes required disclosures for financial instruments within its scope. For the Company, the Statement will be effective as of January 1, 2004, except for mandatorily redeemable financial instruments. For certain mandatorily redeemable financial instruments, the Statement will be effective for the Company on January 1, 2005. The effective date has been deferred indefinitely for certain other types of mandatorily redeemable financial instruments. The Company currently does not have any financial instruments that are within the scope of this Statement.

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Exhibit Index

Exhibits	Description
1.1*	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).
1.2*	By-laws of North American Energy Partners Inc.
2.1*	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.
4.1*	Credit Agreement, dated as of November 26, 2003, among North American Energy Partners Inc., the lenders named therein, Royal Bank of Canada, as Administrative Agent, BNP Paribas Securities Corporation and RBC Capital Markets, as Lead Arrangers and Book Managers, and BNP Paribas, as Syndication Agent.
4.2*	First Amending Agreement, dated as of March 31, 2004, among North American Energy Partners Inc., the lenders listed therein, Royal Bank of Canada, as Administrative Agent, BNP Paribas Securities Corporation and RBC Capital Markets, as Lead Arrangers and Book Managers, and BNP Paribas, as Syndication Agent.
4.3*	Second Amending Agreement, dated as of June 30, 2004, among North American Energy Partners Inc., the lenders listed therein, Royal Bank of Canada, as Administrative Agent, BNP Paribas Securities Corporation and RBC Capital Markets, as Lead Arrangers and Book Managers, and BNP Paribas, as Syndication Agent.
8.1*	Subsidiaries of North American Energy Partners Inc.
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.

* Incorporated by reference to North American Energy Partner Inc.’s Form F-4/S-4 filed with the Securities and Exchange Commission (Commission File No. 333-111396).

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