Amendment No. 2 to Form 20-F

20-F/A 1 d20fa.htm AMENDMENT NO. 2 TO FORM 20-F Amendment No. 2 to Form 20-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 2

Form 20-F

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

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

FOR THE FISCAL YEAR ENDED

MARCH 31, 2006

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

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

Date of event requiring this shell company report

Commission file number 333-111396

North American Energy Partners Inc.

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

Canada

(Jurisdiction of Incorporation or Organization)

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

(Address of Principal Executive Offices)


Securities registered or to be registered pursuant to Section 12(b) of the Act:		NONE

Securities registered or to be registered pursuant to Section 12(g) of the Act:		NONE

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:		NONE

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.		100 Common Shares, Without Par Value, at March 31, 2006

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES ¨ NO x

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. YES x NO ¨

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 whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer x

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

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

TABLE OF CONTENTS


			Page
PART I
	ITEM 1:	IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS	4
	ITEM 2:	OFFER STATISTICS AND EXPECTED TIMETABLE	4
	ITEM 3:	KEY INFORMATION	4
	ITEM 4:	INFORMATION ON THE COMPANY	17
	ITEM 5:	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	29
	ITEM 6:	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	46
	ITEM 7:	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	53
	ITEM 8:	FINANCIAL INFORMATION	57
	ITEM 9:	THE OFFER AND LISTING	58
	ITEM 10:	ADDITIONAL INFORMATION	58
	ITEM 11:	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	60
	ITEM 12:	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	60
PART II
	ITEM 13:	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	60
	ITEM 14:	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	60
	ITEM 15:	CONTROLS AND PROCEDURES	60
	ITEM 16:	[RESERVED]	61
	ITEM 16A	AUDIT COMMITTEE FINANCIAL EXPERT	61
	ITEM 16B	CODE OF ETHICS	61
	ITEM 16C	PRINCIPAL ACCOUNTANT FEES AND SERVICES	61
	ITEM 16D	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES	61
	ITEM 16E	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS	61
PART III
	ITEM 17:	FINANCIAL STATEMENTS	61
	ITEM 18:	FINANCIAL STATEMENTS	62
	ITEM 19:	EXHIBITS	62

Explanatory Note

This Amendment No. 2 to our Annual Report on Form 20-F for the fiscal year ended March 31, 2006, filed with the U.S. Securities and Exchange Commission (the “SEC”) on August 30, 2006 (the “Original Report”), is being filed for the purpose of making a change in the Original Report pursuant to comments received from the Staff of the SEC with respect to the disclosure contained in Item 15 “Controls and Procedures.” The disclosure in Item 15 “Controls and Procedures” has been revised in accordance with such comments.

We are including in this amendment currently-dated certifications by our Principal Executive Officer and our Principal Financial Officer.

Other than the foregoing items, no part of the Original Report is being amended. Accordingly, this Amendment No. 2 does not reflect events occurring after the filing of our Original Report and should not be understood to mean that any other statements contained herein are accurate as of any date subsequent to August 30, 2006.

As used in this annual report on Form 20-F, unless the context otherwise indicates, the terms “NAEPI,” “we,” “us,” “our,” and the “Company” mean 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, 2006, the noon buying rate as quoted by the Bank of Canada was $1.1670 equals US$1.00. (See Item 3 for further exchange rate information to U.S. currency.) Except as otherwise indicated, financial statements of, and information regarding, North American Energy Partners Inc. are presented in Canadian dollars.

STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This document contains forward-looking statements. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management, based on information currently available to management. Forward-looking statements are those that do not relate strictly to historical or current facts, and can be identified by the use of the future tense or other forward-looking words such as “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “should,” “may,” “objective,” “projection,” “forecast,” “continue,” “strategy,” 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:

•

the timing and success of business development efforts;

•

changes in oil and gas prices;

•

our ability to hire and retain a skilled labor force;

•

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

•

our ability to establish and maintain effective internal controls;

•

our substantial debt, which could make us more vulnerable to adverse economic conditions and affect our ability to comply with the terms of the agreements governing our indebtedness;

•

restrictive covenants in our debt agreements, which may restrict the manner in which we operate our business;

•

foreign currency exchange rate fluctuations, capital markets conditions and inflation rates;

•

weather conditions;

•

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

•

decreases in outsourcing work by our customers or shut-downs or cutbacks at major businesses that use our services;

•

our ability to purchase or lease equipment;

•

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 successfully identify and acquire new businesses and assets and integrate them into our existing operations; and

•

those other factors discussed in the Item 3.D “Risk Factors.”

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

PART I

ITEM 1:

IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not applicable.

ITEM 2:

OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.

ITEM 3:

KEY INFORMATION

A.	SELECTED FINANCIAL DATA

We were initially formed in October 2003 in connection with the acquisition on November 26, 2003 (the “Acquisition”) of certain businesses from Norama Ltd. as discussed under Item 4.A “History and Development of the Company.” As a result, the selected financial data presented below as of and for each of the fiscal years ended March 31, 2002 and 2003 and for the period from April 1, 2003 to November 25, 2003 is derived from the audited consolidated financial statements of Norama Ltd., our predecessor. The selected financial data presented below for the period from November 26, 2003 to March 31, 2004 and as of and for each of the fiscal years ended March 31, 2005 and 2006 is derived from our audited consolidated financial statements. As a result of the Acquisition, the consolidated financial data for the periods before November 26, 2003 is not necessarily comparable to the consolidated financial data for periods after November 25, 2003. In the discussion below, any historical financial data for the year ended March 31, 2004 has 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 information presented below should be read in conjunction with Item 5 “Operating and Financial Review and Prospects” and our audited consolidated financial statements and related notes included at Item 17. All of the financial information presented below has been prepared in accordance with Canadian GAAP, which differs in certain significant respects from U.S. GAAP. For a discussion of the principal differences between Canadian GAAP and U.S. GAAP as they pertain to us for the years ended March 31, 2006 and 2005, and the period from November 26, 2003 to March 31, 2004 and for Norama Ltd. for the period April 1 to November 25, 2003, see note 24 to our consolidated financial statements included at Item 17.


	Predecessor (a)
	Year Ended March 31,						April 1, 2003 to November 25, 2003			November 26, 2003 to March 31, 2004			Year Ended March 31,
	2002			2003			April 1, 2003 to November 25, 2003			November 26, 2003 to March 31, 2004			2005			2006
	(Dollars in thousands)
Statement of operations data:
Revenue(b)	$	249,351		$	344,186		$	250,652		$	127,611		$	357,323		$	492,237

Project costs		127,996			219,979			156,976			83,256			240,919			308,949
Equipment costs		56,693			55,871			43,484			13,686			52,831			64,832
Equipment operating lease expense		20,596			16,357			10,502			1,430			6,645			16,405
Depreciation		11,299			10,974			6,566			6,674			20,762			21,725

Gross profit		32,767			41,005			33,124			22,565			36,166			80,326
General and administrative		12,794			12,233			7,783			6,065			22,863			30,898
Gain on sale of capital assets		(218	)		(2,265	)		(49	)		131			494			(733	)
Amortization of intangible assets		—			—			—			12,928			3,368			730

Operating income		20,191			31,037			25,390			3,441			9,441			49,431
Management fee (c)		14,400			8,000			41,070			—			—			—
Interest expense		3,510			4,162			2,457			10,079			31,141			68,776
Foreign exchange gain		(17	)		(234	)		(7	)		(661	)		(19,815	)		(13,953	)
Other (income) expense		—			—			(367	)		(230	)		(421	)		1,118
Realized and unrealized loss on derivative financial instruments		—			—			—			12,205			43,113			14,689

Income (loss) before income taxes		2,298			19,109			(17,763	)		(17,952	)		(44,577	)		(21,199	)
Income taxes (benefit)		689			6,620			(6,622	)		(5,670	)		(2,264	)		737

Net income (loss)(d)	$	1,609		$	12,489		$	(11,141	)	$	(12,282	)	$	(42,313	)	$	(21,936	)


Balance sheet data (end of period):
Cash	$	436		$	651					$	36,595		$	17,922		$	42,704
Property, plant and equipment, net		56,759			76,234						167,905			177,089			185,566
Total assets		120,431			158,584						489,974			540,153			586,911
Total debt		50,137			63,401						325,064			310,402			314,959
Series A preferred shares		—			—						—			—			375
Series B preferred shares		—			—						—			—			42,193
Total shareholder’s equity (e)		17,379			29,818						115,355			73,539			52,526

Other financial data:
EBITDA (f)	$	17,107		$	34,245		$	(8,740	)	$	11,729		$	10,694		$	70,032
Consolidated EBITDA (f)		16,872			31,746			(8,796	)		23,541			34,983			70,958

(a)

The historical balance sheet and statement of operations data as at and for the years ended March 31, 2003 and 2002 and the period from April 1 to November 25, 2003 have been derived from the historical financial statements of Norama Ltd. The financial statements for periods ended before November 26, 2003 are not necessarily comparable in all respects to the financial statements for periods ended after November 25, 2003.

(b)

Effective April 1, 2005, we changed our accounting policy regarding the recognition of revenue on claims. This change in accounting policy has been applied retroactively. Prior to this change, revenue from claims was included in total estimated contract revenue when awarded or received. After this change, claims are included in total estimated contract revenue, only to the extent that contract costs related to the claim have been incurred and when it is probable that the claim will result in a bona fide addition to contract value and can be reliably estimated. Those two conditions are satisfied when (1) the contract or other evidence provides a legal basis for the claim or a legal opinion is obtained providing a reasonable basis to support the claim, (2) additional costs incurred were caused by unforeseen circumstances and are not the result of deficiencies in our performance, (3) costs associated with the claim are identifiable and reasonable in view of work performed and (4) evidence supporting the claim is objective and verifiable. No profit is recognized on claims until final settlement occurs. This can lead to a situation where costs are recognized in one period and revenue is recognized when customer agreement is obtained or claim resolution occurs, which can be in subsequent periods. Historical claim recoveries should not be considered indicative of future claim recoveries. The change in policy resulted in an increase in claims revenue and unbilled revenue of approximately $12.9 million for the year ended March 31, 2006, but did not result in any adjustments to prior periods. Substantially all of the amounts recognized as claims revenue have been collected subsequent to March 31, 2006.

(c)	Management fees paid to the corporate shareholder of our predecessor company, Norama Ltd., represented fees for services rendered and were determined with reference to taxable income. Subsequent to the Acquisition on November 26, 2003, these fees are no longer paid.

(d)	Our consolidated financial statements have been prepared in accordance with Canadian GAAP, which differs in certain material respects from U.S. GAAP. If U.S. GAAP were employed, our net income (loss) would be adjusted as follows (in thousands):


	Predecessor
	Year Ended March 31,				April 1, 2003 to November 25, 2003			November 26, 2003 to March 31, 2004			Year Ended March 31,
	2002		2003		April 1, 2003 to November 25, 2003			November 26, 2003 to March 31, 2004			2005			2006
Net income (loss) — Canadian GAAP	$	1,609	$	12,489	$	(11,141	)	$	(12,282	)	$	(42,313	)	$	(21,936	)
Capitalized interest(1)		—		—		—			—			—			847
Amortization using effective interest method(2)		—		—		—			—			—			590
Realized and unrealized loss on derivative financial instruments(3)		—		—		—			—			—			(484	)

Income (loss) before income taxes		1,609		12,489		(11,141	)		(12,282	)		(42,313	)		20,983
Income taxes: Deferred income taxes		—		—		—			—			—			—

Net income (loss) — U.S. GAAP	$	1,609	$	12,489	$	(11,141	)	$	(12,282	)	$	(42,313	)	$	20,983

(1)	U.S. GAAP requires capitalization of interest costs as part of the historical cost of acquiring certain qualifying assets that require a period of time to prepare for their intended use. This is not required under Canadian GAAP.

(2)

Under Canadian GAAP, we defer and amortize debt issuance costs on a straight-line basis over the stated term of the related debt. Under U.S. GAAP, we are required to amortize financing costs over the stated term of the related debt using the effective interest method resulting in a consistent interest rate over the term of the debt.

(3)

U.S. GAAP requires that every derivative instrument (including certain derivative instruments embedded in other contracts and debt instruments) be recorded in the balance sheet as either an asset or liability measured at its fair value. The issuances of our 8³/4% senior notes and 9% senior secured notes both included certain contingent embedded derivatives which provided for the acceleration of redemption by the holder at a premium in certain instances. These embedded derivatives met the criteria for bifurcation from the debt contract and separate measurement at fair value. Under U.S. GAAP, the embedded derivatives have been measured at fair value and classified as part of the carrying amount of the senior notes on the consolidated balance sheet, with changes in the fair value being recorded in net income (loss) as realized and unrealized (gain) loss on derivative financial instruments for the period. Under Canadian GAAP, separate accounting of embedded derivatives from the host contract is not permitted.

(e)	The cumulative effect of material differences between Canadian and U.S. GAAP on shareholders’ equity is as follows (in thousands):


	March 31, 2004 (1)		March 31, 2005		March 31, 2006
Shareholder’s equity (as reported) — Canadian GAAP	$	115,355	$	73,539	$	52,526
Capitalized interest(2)		—		—		847
Amortization using effective interest method(3)		—		—		590
Realized and unrealized loss on derivative financial instruments(4)		—		—		(484	)
Excess of fair value of amended Series B preferred shares over carrying value of original Series B preferred shares(5)		—		—		(3,707	)

Shareholder’s equity — U.S. GAAP	$	115,355	$	73,539	$	49,772

(1)

The historical financial data for the year ended March 31, 2004 has 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.

(2)	U.S. GAAP requires capitalization of interest costs as part of the historical cost of acquiring certain qualifying assets that require a period of time to prepare for their intended use. This is not required under Canadian GAAP.

(3)

(4)

(5)

carrying amount to the December 31, 2011 redemption value of $69.6 million using the effective interest method. Under U.S. GAAP, the Company recognized the fair value of the Series B preferred shares as temporary equity in accordance with EITF Topic D-98 and recognized a charge of $3.7 million to retained earnings for the difference between the fair value and the carrying amount of the Series B preferred shares on the modification date. Under U.S. GAAP, we accrete the initial fair value of the Series B preferred shares of $45.9 million to the December 31, 2011 redemption value of $69.6 million using the effective interest method. The accretion charge is recognized as a charge to retained earnings under U.S. GAAP and interest expense in our financial statements under Canadian GAAP.

(f)

EBITDA is calculated as net income (loss) before interest expense, income taxes, depreciation and amortization. Consolidated EBITDA is defined as EBITDA, excluding the effects of foreign exchange gain or loss, realized and unrealized gain or loss on derivative financial instruments, non-cash stock-based compensation expense and loss (gain) on disposal of plant and equipment. We believe that EBITDA is a meaningful measure of the performance of our business because it excludes items, such as depreciation and amortization, interest and taxes, that are not directly related to the operating performance of our business. Management reviews EBITDA to determine whether capital assets are being allocated efficiently. In addition, our revolving credit facility requires us to maintain a minimum Consolidated EBITDA. Non-compliance with this financial covenant could result in our being required to immediately repay all amounts outstanding under our revolving credit facility. We are required to maintain a minimum Consolidated EBITDA through December 31, 2006 of $65.5 million, with this minimum amount increasing periodically until maturity. However, EBITDA and Consolidated EBITDA are not measures of performance under Canadian GAAP or U.S. GAAP and our computations of EBITDA and Consolidated EBITDA may vary from others in our industry. EBITDA and Consolidated EBITDA should not be considered as alternatives to operating income or net income as measures of operating performance or cash flows as measures of liquidity. EBITDA and Consolidated EBITDA have important limitations as analytical tools, and you should not consider them in isolation, or as substitutes for analysis of our results as reported under Canadian GAAP or U.S. GAAP. For example, EBITDA and Consolidated EBITDA:

•

do not reflect our cash expenditures or requirements for capital expenditures or capital commitments;

•

do not reflect changes in, or cash requirements for, our working capital needs;

•

do not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;

•

exclude tax payments that represent a reduction in cash available to us; and

•

do not reflect any cash requirements for assets being depreciated and amortized that may have to be replaced in the future.

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

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


	Predecessor
	Year Ended March 31,				April 1, 2003 to November 25, 2003			November 26, 2003 to March 31, 2004			Year Ended March 31,
	2002		2003		April 1, 2003 to November 25, 2003			November 26, 2003 to March 31, 2004			2005			2006
Net income (loss)	$	1,609	$	12,489	$	(11,141	)	$	(12,282	)	$	(42,313	)	$	(21,936	)
Adjustments:
Depreciation		11,299		10,974		6,566			6,674			20,762			21,725
Amortization		—		—		—			12,928			3,368			730
Interest expense		3,510		4,162		2,457			10,079			31,141			68,776
Income taxes (benefit)		689		6,620		(6,622	)		(5,670	)		(2,264	)		737

EBITDA	$	17,107	$	34,245	$	(8,740	)	$	11,729		$	10,694		$	70,032

A reconciliation of EBITDA to consolidated EBITDA is as follows:


	Predecessor
	Year Ended March 31,						April 1, 2003 to November 25, 2003			November 26, 2003 to March 31, 2004			Year Ended March 31,
	2002			2003			April 1, 2003 to November 25, 2003			November 26, 2003 to March 31, 2004			2005			2006
EBITDA	$	17,107		$	34,245		$	(8,740	)	$	11,729		$	10,694		$	70,032
Adjustments:
Foreign exchange gain		(17	)		(234	)		(7	)		(661	)		(19,815	)		(13,953	)
Loss (gain) on disposal of plant and equipment		(218	)		(2,265	)		(49	)		131			494			(733	)
Realized and unrealized loss on derivative financial instruments		—			—			—			12,205			43,113			14,689
Non-cash stock-based compensation expense		—			—			—			137			497			923

Consolidated EBITDA	$	16,872		$	31,746		$	(8,796	)	$	23,541		$	34,983		$	70,958

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 Bank of Canada (the “Noon Buying Rate”). On July 31, 2006, the Noon Buying Rate was $1.00 = US$0.8843.


	2006
	March	April	May	June	July
High for period	0.8832	0.8926	0.9099	0.9099	0.9041
Low for period	0.8530	0.8533	0.8902	0.8893	0.8760

	Year Ended March 31
	2002	2003	2004	2005	2006
Average for period	0.6392	0.6455	0.7412	0.7836	0.8378

B.	CAPITALIZATION AND INDEBTEDNESS

Not applicable.

C.	REASONS FOR THE OFFER AND USE OF PROCEEDS

Not applicable.

D.	RISK FACTORS

Anticipated major projects in the oil sands may not materialize.

Notwithstanding the estimates regarding new investment and growth in the Canadian oil sands discussed under Item 4.B “Business Overview,” planned and anticipated projects in the oil sands and other related projects may not materialize. The underlying assumptions on which the projects are based are subject to significant uncertainties, and actual investments in the oil sands could be significantly less than estimated. Projected investments and new projects may be postponed or cancelled for any number of reasons, including among others:

•

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

•

shortage of pipeline capacity to transport production to major markets;

•

lack of sufficient governmental infrastructure to support growth;

•

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

•

cost overruns on announced projects.

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

Due to the amount of capital investment required to build an oil sands project, or construct a significant expansion to an existing project, investment decisions by oil sands operators are based upon long-term views of the economic viability of the project. Economic viability is dependent upon the anticipated revenues the project will produce, the anticipated amount of capital investment required and the anticipated cost of operating the project. One of the most important considerations is the price of oil. The long-term outlook for the price of oil is influenced by many factors, including the condition of developed and developing economies and the resulting demand for oil and gas, the level of supply of oil and gas, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political conditions in oil producing nations, including those in the Middle East, war or the threat of war in oil producing regions and the availability of fuel from alternate sources. If our customers believe the long-term outlook for the price of oil is not favorable or believe oil sands projects are not viable for any other reason, they may delay, reduce or cancel plans to construct new oil sands projects or expansions to existing projects. Delays, reductions or cancellations of major oil sands projects could have a material adverse impact on our financial condition and results of operations.

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

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

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

The development in the oil sands region has put a great strain on the existing government infrastructure, necessitating substantial improvements to accommodate the growth in the region. The local government having responsibility for a majority of the oil sands region has been exceptionally impacted by this growth and is not currently in a position to provide the necessary additional infrastructure. In an effort to delay further development until infrastructure funding issues are resolved, the local governmental authority has sought to intervene in a hearing in July 2006 to consider an application by a major oil sands company to the Alberta Energy and Utilities Board, or EUB, for approval to expand its operations and may take similar action with respect to any future applications. If the necessary infrastructure is not put in place, future growth of our customers’ operations could be delayed, reduced or canceled which could in turn adversely affect our prospects and could have a material adverse impact on our financial condition and results of operations.

Shortages of qualified personnel or significant labor disputes could adversely affect our business.

Alberta, and in particular the oil sands area, has had and continues to have a shortage of skilled labor and other qualified personnel. New mining projects in the area will only make it more difficult for us and our customers to find and hire all the employees required to work on these projects. We are continuously seeking ways to hire the people we need, including more project managers, trades people and other employees with the required skills. We have expanded our efforts to find qualified candidates outside of Canada who might relocate to our area. In addition, we have undertaken more extensive training of existing employees and we are enhancing our use of technology and developing programs to provide better working conditions. We believe the labor shortage, which affects us and all of our major customers, will

continue to be a challenge for everyone in the mining and oil and gas industries in western Canada for the foreseeable future. If we are not able to recruit and retain enough employees with the appropriate skills, we may be unable to maintain our customer service levels, and we may not be able to satisfy any increased demand for our services. This, in turn, could have a material adverse effect on our business, financial condition and results of operations. If our customers are not able to recruit and retain enough employees with the appropriate skills, they may be unable to develop projects in the oil sands area.

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

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.

Our ability to grow our operations in the future may be hampered by our inability to obtain long lead time equipment, particularly tires, which are currently in limited supply.

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

Global demand for tires of the size and specifications we require is exceeding the available supply. For example, we currently have four trucks that we cannot utilize because we cannot get tires of the appropriate size and specifications. We expect the supply/demand imbalance for certain tires to continue for several years. Our inability to procure tires to meet the demands for our existing fleet as well as to secure tires to meet new demand for our services could have an adverse effect on our ability to grow our business.

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

We receive most of our revenues from providing services to a small number of major oil sands mining companies. Revenue from our five largest customers represented approximately 68% and 69% of our total revenue for the fiscal years ended March 31, 2005 and 2006, respectively, and those customers are expected to continue to account for a significant percentage of our revenues in the future. For the year ended March 31, 2006, Canadian Natural Resources Limited (“CNRL”), Syncrude Canada Ltd. (“Syncrude”) and Grande Cache Coal Corp. were our three largest customers, accounting for 32%, 16% and 10%, respectively, of our total revenue. For the last five fiscal years, the majority of our revenues in our pipeline business resulted from work performed for EnCana Corporation (“EnCana”). If we lose or experience a significant reduction of business from one or more of our significant customers, we may not be able to replace the lost work with work from other customers. Our long-term contracts typically allow our customers to unilaterally reduce or eliminate the work which we are to perform under the contract. Our contracts generally allow the customer to terminate the contract without cause. The loss of or significant reduction in business with one or more of our major customers, whether as a result of completion of a contract, early termination or failure or inability to pay amounts owed to us, could have a material adverse effect on our business and results of operations.

Because most of our customers are Canadian energy companies, a downturn in the Canadian energy industry could result in a decrease in the demand for our services.

Most of our customers are Canadian energy companies. A downturn in the Canadian energy industry 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.

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

Approximately 51% and 58% of our revenue for the fiscal years ended March 31, 2005 and 2006, respectively, was derived from lump sum and unit-price contracts. See Item 5.A “Operating and Financial Review and Prospects — Operating Results — Critical Accounting Policies and Estimates — Revenue Recognition.” Lump sum and unit-price contracts require us to guarantee the price of the services we provide and thereby expose us to losses if our estimates of project costs are lower than the actual project costs we incur. Our profitability under these contracts is dependent upon our ability to accurately predict the costs associated with our services. The costs we actually incur may be affected by a variety of factors beyond our control. Factors that may contribute to actual costs exceeding estimated costs and which therefore affect profitability include, without limitation:

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site conditions differing from those assumed in the original bid;

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scope modifications during the execution of the project;

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the availability and cost of skilled workers in the geographic location of the project;

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the availability and proximity of materials;

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unfavorable weather conditions hindering productivity;

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

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

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

When we are unable to accurately estimate the costs of lump sum and unit-price contracts, or when we incur unrecoverable cost overruns, the related projects result in lower margins than anticipated or may incur losses, which could adversely impact our results of operations, financial condition and cash flow. For example, on a recent major site preparation and underground installation contract, a combination of unfavorable weather conditions hindering productivity, higher than expected costs due to labor shortages, schedule acceleration and higher than expected costs resulting from underestimation of the project’s complexity at the time the contract bid was prepared led to significant cost overruns. This had a significant impact on our operations. See “Item 5.A “Operating and Financial Review and Prospects — Operating Results — Consolidated and Segmented Financial Results — Revenue — Mining and Site Preparation.”

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

We have financial reporting obligations arising from the indentures governing our 8³/4% senior notes and 9% senior secured notes. We have had continuing problems providing accurate and timely financial information and reports and have restated our financial statements three times since the beginning of our 2005 fiscal year. In November 2004, we had to restate our financial statements for the first and second quarters of fiscal 2005 to properly account for costs incurred in those quarters. In January 2006, we had to restate our financial statements for each period after November 26, 2003 through to the three months and nine months ended December 31, 2004 to eliminate the impact of hedge accounting with respect to the derivative financial instruments. We also had to restate our financial statements for the first quarter of fiscal 2006 to correct the accounting for various aspects of the refinancing transactions which occurred in May 2005. Each of these restatements resulted in our inability to file our financial statements within the deadlines imposed by covenants in the indentures governing our 8³/4% senior notes and 9% senior secured notes.

In connection with the audits of our financial statements since inception, our auditors identified a number of significant weaknesses (as defined under Canadian auditing standards) in our financial reporting processes and internal controls. As a result, there can be no assurance that we will be able to generate accurate financial reports in a timely manner. Failure to do so would cause us to breach the reporting requirements of U.S. and Canadian securities regulations in the future as well as the covenants applicable to our indebtedness. This could, in turn, have a material adverse effect on our business and financial condition. Until we establish and maintain effective internal controls and procedures for financial reporting, we may not have appropriate measures in place to eliminate financial statement inaccuracies and avoid delays in financial reporting.

If, as of the end of our 2008 fiscal year, we are unable to assert that our internal control over financial reporting is effective, or if our auditors are unable to confirm our assessment, investors could lose confidence in our reported financial information and our business could be adversely affected.

We are in the process of documenting, and plan to test our internal control procedures in order to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act, commencing with our fiscal year ending March 31, 2008. The Sarbanes-Oxley Act requires an annual assessment by management of the effectiveness of internal control over financial reporting and an attestation report by independent auditors addressing this assessment. We cannot be certain that we will be able to comply with all of our reporting obligations and successfully complete the procedures, certification and attestation requirements of Section 404 of the Sarbanes-Oxley Act in a timely manner. During the course of our testing we may identify deficiencies that we may not be able to remedy in time to meet the deadline imposed by the Sarbanes-Oxley Act for compliance with the requirements of Section 404. Effective internal control over financial reporting is important to help produce reliable financial reports and to prevent financial fraud. If we are unable to assert that our internal control over financial reporting is effective as of the end of our 2008 fiscal year, or if our independent auditors are unable to attest as of the end of our 2009 fiscal year that our management’s report is fairly stated or are unable to express an opinion on management’s evaluation or on the effectiveness of our internal controls, we could be subject to heightened regulatory scrutiny, investors could lose confidence in our reported financial information and our ability to maintain confidence in our business could be adversely affected.

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

We have a substantial amount of debt outstanding and significant debt service requirements. As of March 31, 2006, we had outstanding approximately $315.0 million of debt, including approximately $81.5 million of secured indebtedness and capital leases. We also have cross-currency and interest rate swaps with a balance sheet liability of $63.6 million as of March 31, 2006 and which are secured equally and ratably with our revolving credit facility. We also had $18.0 million of outstanding, undrawn letters of credit, which reduce the amount of available borrowings under our revolving credit facility. Our substantial indebtedness could have serious consequences, such as:

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

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

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

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

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increasing our vulnerability to, and reducing our flexibility in planning for, adverse changes in economic, industry and competitive conditions; and

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

The potential consequences of our substantial indebtedness make us more vulnerable to defaults and place us at a competitive disadvantage. Further, if we do not have sufficient earnings to service our debt, we would need to refinance all or part of our existing debt, sell assets, borrow more money or sell securities, none of which we can guarantee we will be able to achieve on commercially reasonable terms, if at all.

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

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

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

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

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

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issue equity securities of subsidiaries;

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make certain investments or acquisitions;

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create liens on our assets;

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enter into transactions with affiliates;

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

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transfer or sell assets, including shares of our subsidiaries.

Our revolving credit facility and some of our equipment lease programs also require us, and our future credit facilities may require us, to maintain specified financial ratios and satisfy specified financial tests, some of which become more restrictive over time. Our ability to meet these financial ratios and tests can be affected by events beyond our control, and we may be unable to meet those tests.

As a result of these covenants, our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be significantly restricted, and we may be prevented from engaging in transactions that might otherwise be considered beneficial to us. The breach of any of these covenants could result in a default under our revolving credit facility or any future credit facilities or under the indentures governing our notes. Upon the occurrence of an event of default under our revolving credit facility or future credit facilities, the lenders could elect to stop lending to us or declare all amounts outstanding under such credit facilities to be immediately due and payable. Similarly, upon the occurrence of an event of default under the indentures governing our notes, the outstanding principal and accrued interest on the notes may become immediately due and payable. If amounts outstanding under such credit facilities and indentures were to be accelerated, or if we were not able to borrow under our revolving credit facility, we could become insolvent or be forced into insolvency proceedings.

Between March 31, 2004 and May 19, 2005, it was necessary to obtain a series of waivers and amend our then-existing credit agreement to avoid or to cure our default of various covenants contained in that credit agreement. We ultimately replaced that credit agreement with a new credit agreement on May 19, 2005, which we replaced with our current amended and restated credit agreement on July 19, 2006.

our 9% senior secured notes caused us to be out of compliance with such covenants. In each case, we filed these financial statements before the lack of compliance became an event of default under the indentures.

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

For the year ended March 31, 2005, we had negative operating cash flow of $4.8 million. Our ability to generate sufficient operating cash flow to make scheduled payments on our indebtedness and meet other capital requirements will depend on our future operating and financial performance. Our future performance will be impacted by a range of economic, competitive and business factors that we cannot control, such as general economic and financial conditions in our industry or the economy generally.

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

Currency rate fluctuations could adversely affect our ability to borrow under our revolving credit facility and to repay our 8³/4% senior notes and 9% senior secured notes and may affect the cost of goods we purchase.

Our ability to borrow under our revolving credit facility is limited, in part, by the mark-to-market liabilities under our interest rate and cross-currency swap agreements. If the Canadian dollar increases in value against the U.S. dollar, as it has in the recent past, the mark-to-market liabilities under the swap agreements will increase, which may adversely affect our liquidity or even cause a default under our revolving credit facility if the mark-to-market liabilities were to increase to the extent that the amount of outstanding borrowings and letters of credit would exceed the reduced availability under our revolving credit facility.

We have entered into cross-currency and interest rate swaps that represent economic hedges of our 8³/4% senior notes, which are denominated in U.S. dollars. The current exchange rate between the Canadian and U.S. dollars as compared to the rate implicit in the swap agreement has resulted in a large liability on the balance sheet under the caption “derivative financial instruments.” If the Canadian dollar increases in value or remains at its current value against the U.S. dollar, then if we repay the 8³/4% senior notes prior to their maturity in 2011, we will have to pay this liability.

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

Exchange rate fluctuations may also cause the price of goods to increase or decrease for us. For example, a decrease in the value of the Canadian dollar compared to the U.S. dollar would proportionately increase the cost of equipment which is sold to us or priced in U.S. dollars. Between January 1, 2006 and June 30, 2006, the Canadian dollar/U.S. dollar exchange rate varied from a high of 0.9100 Canadian dollars per U.S. dollar to a low of 0.8528 Canadian dollars per U.S. dollar.

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

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

Some of our customers require letters of credit to secure our performance commitments. Our revolving credit facility provides for the issuance of letters of credit up to $55.0 million, and at June 30, 2006, we had $18.0 million of issued letters of credit outstanding. One of our major contracts allows the customer to request up to $50.0 million in letters of credit. While this level has not been requested to date, we would either have to lower other letters of credit or cash collateralize other obligations to provide this amount of letters of credit. If we were unable to provide letters of credit in the amount requested by this customer, we could lose business from such customer and our business and cash flow would be adversely affected. In addition, the company that provides our surety bonds currently requires $10.0 million of security in the form of either letters of credit, cash collateralization or a combination thereof. If our capacity to issue letters of credit under our revolving credit facility and our cash on hand are insufficient to satisfy our customers and surety, our business and results of operations could be adversely affected.

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

Outsourced mining and site preparation services constitute a large portion of the work we perform for our customers. For example, our mining and site preparation project revenues constituted approximately 74% of our revenues in each of the fiscal years ended March 31, 2005 and March 31, 2006. The election by one or more of our customers to perform some or all of these services themselves, rather than outsourcing the work to us, could have a material adverse impact on our business and results of operations.

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

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

We are dependent on our ability to lease equipment, and a tightening of this form of credit could adversely affect our ability to bid for new work and/or supply some of our existing contracts.

A portion of our equipment fleet is currently leased from third parties. Further, we anticipate leasing substantial amounts of equipment to perform the work on contracts for which we have been engaged in the upcoming year, particularly the overburden removal contract with CNRL. Other projects on which we are engaged in the future may require us to lease additional equipment. If equipment lessors are unable or unwilling to provide us with the equipment we need to perform our work, our results of operations will be materially adversely affected.

Competitors may outbid us on major projects that are awarded based on bid proposals.

Approximately 80% of the major projects that we pursue are awarded to us based on bid proposals, and projects are typically awarded based in large part on price. We often compete for these projects against companies that have substantially greater financial and other resources than we do and therefore can better bear the risk of underpricing projects. We also compete against smaller competitors that may have lower overhead cost structures and, therefore, may be able to provide their services at lower rates than we can. In addition, we expect the growth in the oil sands region will attract new and sometimes larger competitors to enter the region and compete against us for projects. Our business may be adversely impacted to the extent that we are unable to successfully bid against these companies.

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

More than 60% of our revenue for the year ended March 31, 2006 was derived from projects which we consider to be non-recurring. This revenue primarily relates to site preparation and piling services provided for the construction of extraction, upgrading and other oil sands mining infrastructure projects. Future revenues from these types of services will depend upon customers expanding existing mines and developing new projects.

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

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. These penalties, if incurred, could have a significant impact on our profitability under these contracts.

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

Our principal customers are energy companies involved in the development of the oil sands and in natural gas production. The operations of these companies, including their mining operations in the oil sands, are subject to or impacted by a wide array of regulations in the jurisdictions where they operate, including 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 cause customers to discontinue or limit their operations, and may discourage companies from continuing development activities. As a result, demand for our services could be substantially affected by regulations adversely impacting the energy industry.

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

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

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

Failure by our customers to obtain required permits and licenses may affect the demand for our services.

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

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

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

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

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

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

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

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

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

Many of our senior officers have either recently joined the company or have just been promoted and have only worked together as a management team for a short period of time.

We recently made several significant changes to our senior management team. In May 2005, we hired a new Chief Executive Officer and promoted our Vice President, Operations to Chief Operating Officer. In January 2005 we hired a new Treasurer, who is now our Vice President, Finance. In June 2006, we hired a new Vice President, Human Resources, Health, Safety and Environment. We are currently searching for a Chief Financial Officer. As a result of these and other recent changes in senior management, many of our officers have only worked together as a management team for a short period of time and do not have a long history with us. Because our senior management team is responsible for the management of our business and operations, failure to successfully integrate our senior management team could have an adverse impact on our business, financial condition and results of operations.

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. Additionally, North American

Equipment Ltd., a wholly-owned subsidiary of Norama Ltd., sold to NACG Acquisition Inc. substantially all of the assets of North American Equipment Ltd. in exchange for $175.0 million in cash. The total consideration paid by NACG Preferred Corp. and NACG Acquisition Inc. to the sellers was approximately $401 million, net of cash received and including the impact of certain post-closing adjustments.

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. As of March 31, 2006, our authorized capital consists of an unlimited number of common shares, of which 100 were issued and outstanding. In addition an unlimited amount of Series A and B Preferred Shares were authorized and 1,000 and 75,244 respectively, were issued and outstanding.

Subsequent Events

On July 19, 2006, the Company amended and restated its existing credit agreement to provide for borrowings of up to $55.0 million, subject to borrowing base limitations, under which revolving loans and letters of credit may be issued. Prime rate revolving loans under the amended and restated agreement will bear interest at the Canadian prime rate plus 2.0% per annum and swing line revolving loans will bear interest at the Canadian prime rate plus 1.5% per annum. Canadian bankers’ acceptances have stamping fees equal to 3.0% per annum and letters of credit are subject to a fee of 3.0% per annum.

Advances under the amended and restated agreement are margined with a borrowing base calculation defined as the aggregate of 60.0% of the net book value of the Company’s plant and equipment, 75.0% of eligible accounts receivable and un-pledged cash in excess of $15.0 million. The sum of all borrowings (including issued letters of credit) and the mark-to-market value of the Company’s liability under existing swap agreements must not exceed the borrowing base. The amended and restated credit facility is secured by a first priority lien on substantially all of the Company’s existing and after-acquired property.

The facility contains certain restrictive covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments (including acquisitions), paying dividends or redeeming shares of capital stock. The Company is also required to meet certain financial covenants.

On July 21, 2006, NACG Holdings Inc. filed an initial registration statement with the U.S. Securities and Exchange Commission and a preliminary prospectus with securities commissions in every jurisdiction in Canada relating to the initial public offering of voting common shares.

Prior to, or concurrent with, the consummation of the proposed offering, NACG Holdings Inc., NACG Preferred Corp. and the Company are planning to amalgamate into one new entity, North American Energy Partners Inc. In addition, NACG Holdings Inc. is planning a share split prior to the proposed offering being completed. The voting common shares of the new entity, North American Energy Partners Inc., will be the shares offered in the proposed offering.

Prior to the amalgamation referred to above, it is the Company’s intention to repurchase the Series A preferred shares for their redemption value of $1.0 million and to cancel the consulting and advisory services agreement with the Sponsors, under which the Company has received ongoing consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. The consideration to be paid for the cancellation of the consulting and advisory services agreement is still to be negotiated between the parties. In addition, it is planned that each holder of the Company’s Series B preferred shares will receive, for each Series B preferred share held, five common shares (the number of common shares will be adjusted for the planned share split) in the amalgamated North American Energy Partners Inc. As part of the amalgamation, existing common and non-voting common shareholders of NACG Holdings Inc. will receive common and non-voting common shares, respectively, of the amalgamated North American Energy Partners Inc.

The anticipated net proceeds from the offering, after deducting underwriting fees and estimated offering expenses, are being proposed to be used to purchase certain equipment currently under operating leases and tender for all or a portion of the outstanding principal of and accrued interest on the Company’s 9% senior secured notes due 2010. The balance of the anticipated net proceeds would be available for general corporate purposes including working capital, capital expenditures and potential acquisitions.

The completion of the proposed offering, including the planned reorganization described above, is subject to a number of approvals by the shareholders of the Company, NACG Preferred Corp. (including preferred shareholders of NACG Preferred Corp.) and NACG Holdings Inc. and the effectiveness of the registration statement in the United States and the acceptance of the prospectus by securities regulatory authorities in Canada.

B.	BUSINESS OVERVIEW

General

We are a leading resource services provider to major oil and natural gas and other natural resource companies, with a primary focus in the Canadian oil sands. We provide a wide range of mining and site preparation, piling and pipeline installation services to our customers across the entire lifecycle of their projects. We are the largest provider of contract mining services in the oil sands area, and we believe we are the largest piling foundations installer in western Canada. In addition, we believe that we operate the largest fleet of equipment of any contract resource services provider in the oil sands. Our total fleet includes over 525 pieces of diversified heavy construction equipment supported by over 540 ancillary vehicles. While our expertise covers heavy earth moving, piling and pipeline installation in any location, we have a specific capability operating in the harsh climate and difficult terrain of the oil sands and northern Canada. By understanding the terrain, having skilled personnel and a diverse, well-maintained and well positioned fleet, we are able to meet the demands of a growing customer base.

Our core market is the Canadian oil sands, where we generated 71% of our fiscal 2006 revenue. The oil sands are located in three regions of northern Alberta: Athabasca, Cold Lake and Peace River. Oil sands operators produce and process bitumen, which is the extremely heavy oil trapped in the sands. According to the Alberta Energy and Utilities Board, or EUB, Canada’s oil sands are estimated to hold 315 billion barrels of ultimately recoverable oil reserves, with established reserves of almost 174 billion barrels as of the end of 2004, second only to Saudi Arabia. According to the Canadian National Energy Board, or NEB, oil sands production of bitumen is expected to increase from 1.1 million barrels per day, or “bpd,” in 2005 to approximately 3.0 million bpd by 2015 and account for 75% of total Canadian oil output, compared to approximately 50% of output today. In order to achieve this increase in production, the NEB estimates that over $95 billion of capital expenditures by companies operating in the oil sands will be required through 2015.

Our significant knowledge, experience, equipment capacity and scale of operations in the oil sands differentiates us from our competition. Our principal customers are the major operators in the oil sands, including all three of the producers that currently mine bitumen, being Syncrude Canada Ltd., Suncor Energy Inc. and Albian Sands Energy Inc. (a joint venture among Shell Canada Limited, Chevron Canada Limited and Western Oil Sands Inc.). Canadian Natural Resources Limited, or CNRL, another significant customer, is developing a bitumen-mining project in the oil sands. We provide services to every company in the oil sands that uses surface mining techniques for its production. These surface mining techniques account for over 70% of total oil sands production. We also provide site construction services for in-situ producers, which use horizontally drilled wells to inject steam into deposits and pump bitumen to the surface.

We have long-term relationships with most of our customers. For example, we have been providing services to Syncrude and Suncor since they pioneered oil sands development over 30 years ago. We believe our customers’ leases have an average remaining productive life of over 35 years. In addition, 34% of our revenues in fiscal 2006 were derived from recurring, long-term contracts, which assists in providing stability in our operations.

Our Operations

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

The chart below shows the revenues generated by each operating segment for the fiscal years ended March 31, 2002 through March 31, 2006:


	Year Ended March 31,
	2004 (a)				2005				2006
	(Dollars in thousands)
Mining and site preparation	$	235,772	62.4	%	$	264,835	74.1	%	$	366,721	74.5	%
Piling		48,982	12.9			61,006	17.1			91,434	18.6
Pipeline installation		93,509	24.7			31,482	8.8			34,082	6.9

Total	$	378,263	100.0	%	$	357,323	100.0	%	$	492,237	100.0	%

(a)

The historical statement of operations and other financial data for the year ended March 31, 2004 have been derived from the historical financial statements of Norama Ltd., prior to the acquisition, 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, after the acquisition. The pre- and post-Acquisition periods during fiscal 2004 have strictly been added together. No pro forma adjustments have been made to attempt to reflect the results of operations that would have been attained had the Acquisition occurred at the beginning of the period. GAAP does not allow for such a combination of pre- and post-Acquisition periods. The Acquisition was primarily a change in ownership of the business we acquired from Norama Ltd. and we have operated the business in substantially the same manner as Norama Ltd. did before the Acquisition. Therefore, the pre- and post-Acquisition periods are presented on a combined basis to allow for a meaningful comparison to other full fiscal years. Any references to the fiscal year ended March 31, 2004 below shall refer to the combined periods.

Mining and site preparation

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

For the fiscal years ended March 31, 2005 and 2006, revenues from this segment accounted for 74% and 75% of our total revenues, respectively.

Many oil sands and natural resource mining companies utilize contract services for mine site operations. 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 focus their resources on exploration and property development and 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.

Oil sands operators use our services to prepare their sites 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 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 oil sands, our 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

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 represented approximately two-thirds of our piling clients for fiscal 2006. The remaining one-

third of our piling clients were primarily commercial construction builders operating in the Edmonton, Calgary, Regina and Vancouver areas.

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.

For the fiscal years ended March 31, 2005 and 2006, revenues from this segment accounted for 17% and 19% of our total revenues, respectively.

Pipeline Installation

We install field, transmission and distribution pipe made of steel, plastic and fiberglass materials. 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 last five fiscal years virtually all of our revenues in our pipeline business resulted from work performed for EnCana. Despite our limited client base in this segment over the past five years, we believe there are significant opportunities to increase our market share by capitalizing on the projected pipeline expansion in western Canada.

For the fiscal years ended March 31, 2005 and 2006, revenues from this segment accounted for 9% and 6% of our total revenues, respectively.

Our Markets

Our business is primarily driven by the demand for our services from the development, expansion and operation of oil sands projects. Decisions by oil sands operators to make capital investments are driven by a number of factors, with one of the most important being the expected long-term price of oil.

Canadian Oil Sands

Oil sands are grains of sand covered by a thin layer of water and coated by heavy oil, or bitumen. Bitumen, because of its structure, does not flow, and therefore requires non-conventional extraction techniques to separate it from the sand and other foreign matter. There are currently two main methods of extraction: open pit mining, where bitumen deposits are sufficiently close to the surface to make it economically viable to recover the bitumen by treating mined sand in a surface plant; and in-situ, where bitumen deposits are buried too deep for open pit mining to be cost effective, and operators instead inject steam into the deposit so that the bitumen can be separated from the sand and pumped to the surface. We currently provide most of our services to companies operating open pit mines to recover bitumen reserves. These customers utilize our services for surface mining, site preparation, piling, pipe installation, site maintenance, equipment and labor supply and land reclamation.

According to the EUB, the oil sands contained almost 174 billion barrels of established oil reserves as of the end of 2005, approximately 32 billion barrels of which is recoverable by open pit mining techniques. This is second only to Saudi Arabia’s 264 billion barrels and approximately six times the recoverable reserves in the United States. Beginning in the mid-1990’s, increasing global energy demand and improvements in mining and in-situ technology resulted in a significant increase in oil sands investments. This increased level of investment was also driven by a revised royalty regime adopted by the Government of Alberta in 1997, which was designed to accelerate investment in the oil sands.

Outlook

According to the Canadian Association of Petroleum Producers, or CAPP, approximately $36 billion was invested in the oil sands from 1996 through 2004. Oil sands production has grown four-fold since 1990 and exceeded one million barrels

per day in 2005. The NEB expects oil sands production to reach approximately 3.0 million barrels per day and account for over 75% of total Canadian oil production by 2015. By comparison, the Ghawar field in Saudi Arabia currently produces 5.0 million barrels per day, representing over 6% of the world’s total production and over 50% of Saudi Arabia’s production.

According to the NEB’s 2006 Energy Market Assessment, between 2006 and 2015 $8.5 billion to $10.9 billion of annual capital expenditures, for a total of $95 billion, will be required to achieve expected increases in production. According to the NEB, as of June 2006, there were 21 mining and upgrader projects in various stages, ranging from announcement to construction, with start-up dates through 2010. If all of these projects proceed as scheduled, the planned investment in new projects for 2006 through 2010 will exceed $38 billion and an additional $17 billion will be invested in project additions or existing projects over the same period. Beyond 2010, several new multibillion dollar projects and a number of smaller multimillion dollar projects are being considered by various oil sands operators. We intend to pursue business opportunities from these projects.

Pipeline Infrastructure and Construction

To transport the increased production expected from the oil sands and to provide natural gas as an energy source to the oil sands region, significant investment will be required to expand pipeline capacity. To date, there have been significant greenfield and expansion projects announced. We are in various stages of discussions to provide services for some of these projects. We believe that our service offerings and pipeline construction experience position us well to compete for the sizeable pipeline opportunities required for the expected growth in oil sands production.

Conventional Oil and Gas

We provide services to conventional oil and gas producers, in addition to our work in the oil sands. The Canadian Energy Pipeline Association estimates that over $20 billion of pipeline investment in Canada will be required for the development of new long haul pipelines, feeder systems and other related pipeline construction. Conventional oil and gas producers require pipeline installation services in order to connect producing wells to nearby pipeline systems. According to CAPP, Canada is one of the world’s largest producers of oil and gas, producing approximately 2.5 million barrels of oil per day and approximately 17.1 billion cubic feet of natural gas per day. Canadian natural gas production is expected to increase with the development of arctic gas reserves. A producer group has been formed by Imperial Oil Limited, ConocoPhillips Canada Limited, Shell Canada and the Aboriginal Pipeline Group for the purpose of bidding for work on construction of a pipeline proposed to extend 1,220 kilometers (758 miles) from the MacKenzie River delta in the Beaufort Sea to existing natural gas pipelines in northern Alberta. Under the group’s proposal, Imperial Oil will lead the construction and operate the pipeline. We are actively working with Imperial Oil and have provided it with constructability and planning reviews. We hope to repeat our history of providing initial engineering assistance on projects and then subsequently being awarded contracts on these projects.

Minerals Mining

According to the government agency Natural Resources Canada, Canada is also one of the largest mining nations in the world, producing approximately 70 different minerals and metals. In 2004, the mining and minerals processing industries contributed $41.8 billion to the Canadian economy, an amount equal to approximately 4.0% of GDP. The value of minerals produced (excluding petroleum and natural gas) reached $26.4 billion in 2005. According to the EUB, Canada ranks tenth in the world in total proven coal reserves. Alberta contains 70% of Canada’s coal reserves and, by volume, produces approximately half of the coal mined in Canada annually.

The diamond mining industry in Canada is relatively new, having extracted diamonds for only eight years. According to Natural Resources Canada, the industry has grown from 2.6 million carats of production in 2000 to an estimated 12.3 million carats of production in 2005, representing a compounded annual growth rate of approximately 36%, and establishing Canada as the third largest diamond producing country in the world by value after Botswana and Russia. We believe Canadian diamond mining will continue to grow as existing mines increase production and new mine projects are developed. Outside the oil sands, we have identified the growing Canadian diamond mining industry as a primary target for new business opportunities.

We intend to build on our core services and strong regional presence to capitalize on the opportunities in the minerals mining industries of Canada. According to Natural Resources Canada’s 2004 estimate, the capital and repair expenditures needed to support the minerals mining industry would be over $5.6 billion in 2005.

Commercial and Public Construction

According to the government agency Statistics Canada, the Canadian commercial and public construction market was approximately $22 billion in 2005. According to the Alberta government, the commercial and public construction market in Alberta is expected to grow 3% annually through 2009. As a result of the significant activity in the energy sector, western Canada has experienced and is expected to continue to experience strong economic and population growth. The Alberta government has responded to the potential strain that this growth will have on public facilities and infrastructure by allocating approximately $6.5 billion to improvement and expansion projects from 2004 to 2007. This need for infrastructure to support growth, along with historic under investment in infrastructure, provides for a strong infrastructure spending outlook.

The success of the energy industry in western Canada is also leading to increased commercial development in many urban centers in British Columbia and Alberta. According to the Alberta government, as of June 2006, the inventory of commercial, retail and residential projects in Alberta was valued at approximately $5.1 billion. These large expenditures will be further supplemented by the 2010 Olympic Winter Games, which will be held in the Vancouver area. The Organizing Committee of the Olympic Games estimates that the 2010 Olympic Winter Games will require an additional $3.0 billion in infrastructure and construction spending. The significant resources and capital intensive nature of the core infrastructure and construction services required to meet these demands, along with our strong local presence and significant regional experience, position us to implement our business model to capitalize on the large and growing infrastructure and construction demands of western Canada.

Contracts

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

Cost-plus. 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 overhead 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.

Time-and-materials. A time-and-materials contract involves using the components of a cost-plus job to calculate 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 cost overrun must come out of the fixed margin included in the rates.

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

Lump sum. A lump sum contract is utilized when a detailed scope of work is known for a specific project. Thus, the associated costs can be readily calculated and a firm price provided to the customer for the execution of the work. The risk lies in the fact that there is no escalation of the price if the work takes longer 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 the project.

The mix of contract types varies year-by-year. For the fiscal year ended March 31, 2006, our contracts consisted of 15% cost-plus, 27% time-and-materials, 44% unit-price and 14% lump sum.

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

Seasonality

We generally experience a decline in revenues during our first quarter of each fiscal year due to seasonality, as weather conditions make operations in our operating regions difficult during this period. The level of activity in our mining and site preparation and pipeline installation segments declines when frost leaves the ground and many secondary roads are temporarily rendered incapable of supporting the weight of heavy equipment. The duration of this period is referred to as “spring breakup” and has a direct impact on our activity levels. Our fourth quarter revenues are typically our highest as ground conditions are best and customers often begin spending their new capital expenditure budgets. As a result, full-year results are not likely to be a direct multiple of any particular quarter or combination of quarters.

Joint Venture

We are party to a joint venture operated through a corporation called Noramac Ventures Inc., or Noramac, with Fort McKay Construction Ltd. created for the purpose of performing contracts for the construction, development and operation of open-pit mining projects within a 50 kilometre radius of Fort McKay, Alberta, which require the provision of heavy construction equipment. The affairs of Noramac are managed, and all decisions and determinations with respect to Noramac are made, by a management committee equally represented by us and our partner. The management committee is responsible for determining the percentage of work in relation to each contract that will be performed by us and by our partner, provided that contracts for a duration of less than two years and of a tender value between $10.0 million and $100.0 million which require a parent guarantee or performance bond will be subcontracted to us. The joint venture agreement provides that if the management committee does not tender for a contract, or fails to reach agreement on the terms upon which Noramac will tender for a contract, we or our partner may pursue the contract in our respective capacities without hindrance, interference or participation by the other party. The joint venture agreement does not prohibit or restrict us from undertaking and performing, for our own account, any work for existing customers other than work to be performed by Noramac pursuant to an existing contract between Noramac and such customer. The joint venture is accounted for as a variable interest entity and consolidated in our financial statements.

Major Suppliers

We have long-term relationships with the following equipment suppliers: Finning International Inc. (45 years), Wajax Income Fund (20 years) and Brandt Tractor Ltd. (30 years). Finning is a major Caterpillar heavy equipment dealer for Canada. Wajax is a major Hitachi equipment supplier to us for both mining and construction equipment. We purchase or rent John Deere equipment, including excavators, loaders and small bulldozers, from Brandt Tractor. In addition to the supply of new equipment, each of these companies is a major supplier for equipment rentals, parts and service labor.

We obtain tires for our equipment from local distributors. Tires of the size and specifications we require are generally in short supply. We expect the supply/demand imbalance for certain tires to continue for some time.

Competition

Our business is highly competitive in each of our markets. Historically, the majority of our new business was awarded to us based on past client relationships without a formal bidding process, in which typically a small number of pre-qualified firms submit bids for the project work. Recently, in order to generate new business with new customers, we have had to participate in formal bidding processes. As new major projects arise, we expect to have to participate in bidding processes on a meaningful portion of the work available to us on these projects. Factors that impact competition include price, safety, reliability, scale of operations, availability and quality of service. Most of our clients and potential clients in the oil

sands area operate their own heavy mining equipment fleet. However, these operators have historically outsourced a significant portion of their mining and site preparation operations and other construction services.

Our principal competitors in the mining and site preparation segment include Cross Construction Ltd., Klemke Mining Corporation, Ledcor Construction Limited, Neegan Development Corporation Ltd., Peter Kiewit Sons Co., Tercon Contractors Ltd., Sureway Construction Ltd. and Thompson Bros. (Constr) Ltd. The main competition to our deep foundation piling operations comes from Agra Foundations Limited and Double Star Co. The primary competitors in the pipeline installation business include Ledcor Construction Limited, Washcuk Pipe Line Construction Ltd. and Midwest Management (1987) Ltd. Voice Construction Ltd. and I.G.L. Industrial Services are the major competitors in underground utilities installation.

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

Law and Regulations and Environmental Matters

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

•

permitting and licensing requirements applicable to contractors in their respective trades,

•

building and similar codes and zoning ordinances,

•

laws and regulations relating to consumer protection and

•

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

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

Our operations are subject to numerous federal, provincial and municipal environmental laws and regulations, including those governing the release of substances, the remediation of contaminated soil and groundwater, vehicle emissions and air and water emissions. These laws and regulations are administered by federal, provincial and municipal authorities, such as Alberta Environment, Saskatchewan Environment, the British Columbia Ministry of Environment, and other governmental agencies. The requirements of these laws and regulations are becoming increasingly complex and stringent, and meeting these requirements can be expensive. The nature of our operations and our ownership or operation of property expose us to the risk of claims with respect to environmental matters, and there can be no assurance that material costs or liabilities will not be incurred 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 currently named as a responsible party for any environmental liabilities on any of the properties on which we currently perform or have performed services. However, our leases typically include covenants which obligate us to comply with all applicable environmental regulations and to remediate any environmental damage caused by us to the leased premises. In addition, claims alleging personal injury or property damage may be brought against us if we cause the release of, or any exposure to, harmful substances.

Capital expenditures relating to environmental matters during the fiscal years ended March 31, 2006, 2005 and 2004 were not material. We do not currently anticipate any material adverse effect on our business or financial position as a result of future compliance with applicable environmental laws and regulations. Future events, however, such as changes in existing laws and regulations or their interpretation, more vigorous enforcement policies of regulatory agencies or stricter or different interpretations of existing laws and regulations may require us to make additional expenditures which may be material.

Employees and Labor Relations

As of March 31, 2006, we had over 130 salaried and over 1,200 hourly employees. We also utilize the services of subcontractors in our construction business. Approximately 10% to 15% of the construction work we do is done through subcontractors. Approximately 1,000 employees are members of various unions and work under collective bargaining agreements. The majority of our work is done through employees governed by a collective bargaining agreement with the International Union of Operating Engineers Local 955, the primary term of which expires on October 31, 2009, and under a collective bargaining agreement with the Alberta Road Builders and Heavy Construction Association and the International Union of Operating Engineers Local 955, the primary term of which expires on February 28, 2007. Additionally, we recently signed a 10-year labor agreement for mining work at the CNRL site in the oil sands. We are subject to other industry and specialty collective agreements under which we complete work, the primary terms of all of which are currently in effect. We believe that our relationships with all our employees, both union and non-union, are satisfactory. We have never experienced a strike or lockout.

Capital Expenditures

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


	*Year Ended March 31,*
	*2004(a)*		*2005*		*2006*
	*(thousands)*
Mining & Site Preparation	$	2,652	$	16,888	$	25,090
Piling		447		202		880
Pipeline		1,671		774		82
Other		2,956		7,815		2,963

Total	$	7,726	$	25,679	$	29,015

(a)

The historical statement of cash flows for the year ended March 31, 2004 has 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 pre- and post-Acquisition cash flows during fiscal 2004 have strictly been added together. No pro forma adjustments have been made to attempt to reflect the cash flows that would have been attained had the Acquisition occurred at the beginning of the period. GAAP does not allow for such a combination of pre- and post-Acquisition periods. The Acquisition was primarily a change in ownership of the business we acquired from Norama Ltd. and we have operated the business in substantially the same manner as Norama Ltd. did before the Acquisition. Therefore, the pre- and post-Acquisition periods are presented on a combined basis to allow for a meaningful comparison to other full fiscal years. Any references to the fiscal year ended March 31, 2004 below shall refer to the combined periods.

C.	ORGANIZATIONAL STRUCTURE

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

LOGO

D.	PLANT AND EQUIPMENT

We operate and maintain over 525 pieces of diversified heavy equipment, including crawlers, graders, loaders, mining trucks, compactors, scrapers and excavators, as well as over 540 ancillary vehicles, including various service and maintenance vehicles. The equipment is in good condition, normal wear and tear excepted. Our revolving credit facility and our 9% senior secured notes are secured by liens on substantially all of our equipment. We lease some of this equipment, which leases contain purchase options.

The following table sets forth our heavy equipment fleet as at March 31, 2006:


*Category*	Capacity Range	Horsepower Range	Number in Fleet	Number Leased
Mining and site preparation:
Articulating trucks	30-42 tons	305-460	32	—
Mining trucks	50-330 tons	650-2,700	74	29
Shovels	36-58 cubic yards	2,600-3,760	4	2
Excavators	1-20 cubic yards	94-1,350	100	15
Crawler tractors	N/A	120-1,350	91	14
Graders	14-24 feet	150-500	20	8
Scrapers	28-31 cubic yards	450	14	—
Loaders	1.5-16 cubic yards	110-690	43	1
Skidsteer loaders	1-2.25 cubic yards	70-150	35	—
Packers	44,175-68,796 lbs	216-315	29	—
Pipeline:
Snow cats	N/A	175	3	—
Trenchers	N/A	165	2	—
Pipelayers	16,000-140,000 lbs	78-265	34	—
Piling:
Drill rigs	60-135 feet (drill depth)	210-1,500	33	1
Cranes	25-100 tons	200-263	13	1

Total			527	71

For the fiscal years ended March 31, 2006, 2005 and 2004, we incurred expense of $64.8 million, $52.8 million and $57.2 million, respectively, to maintain our equipment in good working condition.

As of March 31, 2006, we had a heavy equipment fleet of over 350 units and over 270 ancillary vehicles located in the oil sands. Many of these units are among the largest pieces of equipment in the world and are designed for use in the largest earthmoving and mining applications globally. Our large, diverse fleet gives us flexibility in scheduling jobs and allows us to be responsive to our customers’ needs. A well-maintained fleet is critical in the harsh climatic and environmental conditions we encounter. We operate four significant maintenance and repair centers, which are capable of accommodating the largest pieces of equipment in our fleet, on the sites of the major oil sands projects. These factors help us to be more efficient, thereby reducing costs to our customers to further improve our competitive edge, while concurrently increasing our equipment utilization and thereby improving our profitability.

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 late 2007 and 2011, subject to various renewal and termination rights. We expect to renew our office lease that expires in 2007 with rates that are competitive with the prevailing markets rates at that time. We also occupy, without charge, some customer-provided lands. Our revolving credit facility and our 9% senior secured notes are secured by liens on substantially all of our

properties. The following table describes our primary facilities.


*Location*	Function	Owned or Leased

Acheson, Alberta	Corporate headquarters and major equipment repair facility	Leased(a)

Calgary, Alberta	Regional office and equipment repair facility — piling operations	Building Owned Land Leased(b)

Syncrude Mine Site, South End Fort McMurray, Alberta	Regional office and major equipment repair facility — earthworks and mining operations	Building Owned Land Provided

Syncrude Plant Site Fort McMurray, Alberta	Satellite office and minor repair facility — all operations	Building Rented(c) Land Provided

CNRL Plant Site Fort McMurray, Alberta	Site office and maintenance facility	Facility Owned Land Provided

Aurora Mine Site Fort McMurray, Alberta	Satellite office and equipment repair facility — all operations	Building Under Construction Land Provided

Albian Sands Mine Site Fort McMurray, Alberta	Satellite office and equipment repair facility — all operations	Building Leased(d) Land Provided

New Westminster, British Columbia	Regional office and equipment repair facility — piling operations	Building Owned Land Leased(e)

Fort Nelson, British Columbia	Satellite office — pipeline operations	Leased(f)

Regina, Saskatchewan	Regional office and equipment repair facility — piling operations	Leased(g)

(a)	Lease expires November 30, 2007.

(b)	Lease expires December 31, 2010.

(c)	Lease expires November 30, 2009.

(d)	Leased on a month-to-month basis.

(e)	Lease expires March 31, 2010.

(f)	Lease expires July 10, 2008.

(g)	Lease expires March 14, 2008.

Our locations were chosen for their geographic proximity to our major customers. We believe our facilities are sufficient to meet our needs for the foreseeable future.

ITEM 4A:

UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 5:

OPERATING AND FINANCIAL REVIEW AND PROSPECTS

A.	OPERATING RESULTS

Consolidated and Segmented Financial Results


	2004 (a)					2005					2006
Revenue	$	378,263		100.0	%	$	357,323		100.0	%	$	492,237		100.0	%
Project costs		240,232		63.5			240,919		67.4			308,949		62.8
Equipment costs		57,170		15.1			52,831		14.8			64,832		13.2
Equipment operating lease expense		11,932		3.2			6,645		1.9			16,405		3.3
Depreciation		13,240		3.5			20,762		5.8			21,725		4.4

Gross profit		55,689		14.7			36,166		10.1			80,326		16.3
General and administrative		13,848		3.7			22,863		6.4			30,898		6.3
Loss (gain) on sale of capital assets		82		0.0			494		0.1			(733	)	(0.1	)
Amortization of intangible assets		12,928		3.4			3,368		1.0			730		0.1

Operating income		28,831		7.6			9,441		2.6			49,431		10.0
Interest expense		12,536		3.3			31,141		8.7			68,776		14.0
Foreign exchange gain		(668	)	0.2			(19,815	)	(5.5	)		(13,953	)	(2.8	)
Other income		(597	)	0.2			(421	)	(0.1	)		(977	)	(0.2	)
Financing costs		—		0.0			—		—			2,095		0.4
Realized and unrealized loss on derivative financial instruments		12,205		3.2			43,113		12.1			14,689		3.0
Management fees		41,070		10.9			—		—			—		—

Income (loss) before income taxes		(35,715	)	9.4			(44,577	)	(12.5	)		(21,199	)	(4.4	)
Income taxes (benefit)		(12,292	)	3.2			(2,264	)	(0.6	)		737		0.1

Net income (loss)	$	(23,423	)	6.2	%	$	(42,313	)	(11.8	)%	$	(21,936	)	(4.5	)%

Segmented Results of Operations

Revenue by operating segment:
Mining and site preparation	$	235,772		62.4	%	$	264,835		74.1	%	$	366,721		74.5	%
Piling		48,982		12.9			61,006		17.1			91,434		18.6
Pipeline		93,509		24.7			31,482		8.8			34,082		6.9

Total	$	378,263		100.0	%	$	357,323		100.0	%	$	492,237		100.0	%

Profit by operating segment:
Mining and site preparation	$	25,899		47.4	%	$	11,617		38.9	%	$	50,730		61.7	%
Piling		10,831		19.8			13,319		44.6			22,586		27.4
Pipeline		17,946		32.8			4,902		16.5			8,996		10.9

Total	$	54,676		100.0	%	$	29,838		100.0	%	$	82,312		100.0	%

Equipment hours by operating segment:
Mining and site preparation		511,546		73.6	%		673,613		88.2	%		811,891		93.0	%
Piling		57,569		8.3			56,460		7.4			37,300		4.3
Pipeline		126,033		18.1			33,847		4.4			24,197		2.8

Total		695,148		100.0	%		763,920		100.0	%		873,388		100.0	%

(a)

The historical statement of operations and other financial data for the year ended March 31, 2004 have been derived from the historical financial statements of Norama Ltd. for the period from April 1, 2003 to November 25, 2003, and the historical financial statements of North American Energy Partners Inc. for the period from November 26, 2003 to March 31, 2004. The pre- and post-Acquisition periods during fiscal 2004 have strictly been added together. No pro forma adjustments have been made to attempt to reflect the results of operations that would have been attained had the Acquisition occurred at the beginning of the period. GAAP does not allow for such a combination of pre- and post-Acquisition periods. The Acquisition was primarily a change in ownership of the business we acquired from Norama Ltd. and we have operated the business in substantially the same manner as Norama Ltd. did before the Acquisition. Therefore, the pre- and post-Acquisition periods are presented on a combined basis to allow for a meaningful comparison to other full fiscal years. Any references to the fiscal year ended March 31, 2004 below shall refer to the combined periods.

Fiscal Year Ended March 31, 2006 Compared to Fiscal Year Ended March 31, 2005

Revenue. Revenue increased by $134.9 million, or 37.8%, from $357.3 million for the fiscal year ended March 31, 2005 to $492.2 million for the fiscal year ended March 31, 2006.

•

Mining and Site Preparation. Mining and Site Preparation revenue increased by $101.9 million, or 38.5%, from $264.8 million for the fiscal year ended March 31, 2005 to $366.7 million for the fiscal year ended March 31, 2006,

primarily due to activity in fiscal 2006 related to the large site preparation and underground utility installation and overburden removal project for CNRL and a substantial mining services project for Grande Cache Coal Corporation. Revenue generated by these projects in fiscal 2006 more than offset the decline in revenue resulting from the substantial completion of the Syncrude Upgrader Expansion, or UE-1, and OPTI/Nexen Long Lake projects.

•

Piling. Piling revenue increased by $30.4 million, or 49.9%, from $61.0 million for the fiscal year ended March 31, 2005 to $91.4 million for the fiscal year ended March 31, 2006, primarily due to a higher volume of projects in the Fort McMurray, Vancouver and Regina regions because of strong economic and construction activity, as well as the addition of several large piling projects, including projects for Suncor Energy and Flint Infrastructure Services Ltd.

•

Pipeline. Pipeline revenue increased by $2.6 million, or 8.3%, from $31.5 million for the fiscal year ended March 31, 2005 to $34.1 million for the fiscal year ended March 31, 2006 due to an increase in work performed for EnCana and CNRL in fiscal 2006.

Project costs. Project costs increased by $68.0 million, or 28.2%, from $240.9 million for the fiscal year ended March 31, 2005 to $308.9 million for the fiscal year ended March 31, 2006, primarily due to higher activity levels. As a percentage of revenue, project costs were 62.8% in the fiscal year ended March 31, 2006 as compared to 67.4% in the prior fiscal year. The decline was primarily due to better performance on site preparation projects over the prior fiscal year and a changing project work mix from more labor-intensive projects in the prior fiscal year to more equipment-intensive projects in fiscal 2006.

Equipment costs. Equipment costs increased by $12.0 million, or 22.7%, from $52.8 million for the fiscal year ended March 31, 2005 to $64.8 million for the fiscal year ended March 31, 2006, primarily due to increased activity levels and higher repair and maintenance costs. Our heavy equipment fleet size increased by five units over the prior year fleet size of 457. As a percentage of revenue, equipment costs were 13.2% as compared to 14.8% in the prior fiscal year, primarily due to increased activity levels allowing higher efficiency usage of equipment.

Equipment operating lease expense. Equipment operating lease expense increased by $9.8 million, or 148.5%, from $6.6 million for the fiscal year ended March 31, 2005 to $16.4 million for the fiscal year ended March 31, 2006, primarily due to the addition of new leased equipment to support new projects, including the 10-year CNRL overburden project.

Depreciation. Depreciation expense increased by $0.9 million, or 4.3%, from $20.8 million for the fiscal year ended March 31, 2005 to $21.7 million for the fiscal year ended March 31, 2006. The increase was primarily due to the increase in equipment hours related to higher activity levels, as our heavy equipment fleet is depreciated based on operated hours, which increase was partially offset by the use of more leased equipment. As a percentage of revenue, depreciation decreased to 4.4% from 5.8% primarily due to our use of more leased equipment relative to owned equipment.

Gross profit. Gross profit increased by $44.1 million, or 121.8%, from $36.2 million for the fiscal year ended March 31, 2005 to $80.3 million for the fiscal year ended March 31, 2006. As a percentage of revenue, gross profit increased to 16.3% for the fiscal year ended March 31, 2006 from 10.1% for the fiscal year ended March 31, 2005, primarily due to improved performance on site preparation projects, increased activity levels and more efficient use of equipment.

Segment profit

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Mining and Site Preparation. Mining and Site Preparation operating segment profit increased by $39.1 million over the prior year. This was primarily due to increased project activity and performance combined with efficient use of equipment and the loss recognition on a large steam-assisted gravity drainage site project in fiscal 2005.

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Piling. Piling operating segment profit increased $9.3 million due to increased volume and higher margin work primarily in the Fort McMurray and Calgary regions.

•

Pipeline. Pipeline operating segment profit increased by $4.1 million over the prior year due to the 8.3% increase in revenue combined with higher margin work completed at CNRL Horizon and EnCana in the current year.

General and administrative expenses. General and administrative expenses increased by $8.0 million, or 34.9%, from $22.9 million for the fiscal year ended March 31, 2005 to $30.9 million for the fiscal year ended March 31, 2006. The increase was primarily due to increased professional fees incurred in the first and second quarters of fiscal 2006 as a result of the May 2005 financing transactions and increased salaries as a result of bonus accruals from improved financial performance and our hiring of new executive officers and staff to manage increased activity and corporate requirements. As a percentage of revenue, general and administrative expenses were 6.3% for the fiscal year ended March 31, 2006, as compared to 6.4% for the fiscal year ended March 31, 2005.

Amortization of intangible assets. Amortization of intangible assets decreased by 79.4%, from $3.4 million for the fiscal year ended March 31, 2005 to $0.7 million for the fiscal year ended March 31, 2006. The amortization of intangible assets in both fiscal 2006 and fiscal 2005 was related to the customer contracts in progress, trade names, a non-competition agreement and employee arrangements that were acquired in the Acquisition on November 26, 2003. Substantially all of the cost of the intangible assets had been amortized as of March 31, 2006 as the majority of the cost relates to customer contracts in progress that were amortized at a rapid rate due to their short-term nature.

Operating income. Operating income increased by $40.0 million, or 425.5%, from $9.4 million for the fiscal year ended March 31, 2005 to $49.4 million for the fiscal year ended March 31, 2006. The increase was primarily due to the $44.1 million increase in gross profit, the $0.7 million gain from the disposal of property, plant and equipment and the $2.7 million reduction in amortization of intangible assets, partially offset by the $8.0 million increase in general and administrative expenses.

Interest expense. Interest expense increased by $37.7 million, or 121.2%, from $31.1 million for the fiscal year ended March 31, 2005 to $68.8 million for the fiscal year ended March 31, 2006. Interest expense increased by $5.6 million due to the issuance of US$60.5 million of 9% senior secured notes in May 2005 and by $34.7 million due to the changes in the redemption value of our Series B preferred shares which were issued in May 2005, partially offset by a $3.3 million decrease in interest expense due to full repayment of the borrowings under our senior secured credit facility in May 2005.

Foreign exchange gain. We recognized a foreign exchange gain of $14.0 million for the fiscal year ended March 31, 2006 as compared to a gain of $19.8 million for the prior fiscal year. Substantially all of the gain in fiscal 2006 related to the exchange difference between the Canadian and U.S. dollar on translation of the US$60.5 million of 9% senior secured notes issued in May 2005 and the US$200.0 million of 8³/4% senior notes, while the gain in the prior fiscal year related only to the US$200.0 million of 8³/4% senior notes.

Financing costs. Financing costs were $2.1 million for the fiscal year ended March 31, 2006, and there were no financing costs for the fiscal year ended March 31, 2005. Financing costs included $0.3 million representing the issuance of the Series A preferred shares in May 2005, plus a write off of $1.8 million for deferred financing costs related to the previous senior secured credit facility that was repaid in May 2005.

Realized and unrealized loss on derivative financial instruments. The realized and unrealized loss on the cross-currency and interest rate swap agreements was $14.7 million for the fiscal year ended March 31, 2006. These losses relate primarily to the mark-to-market changes in the fair value of the derivatives, which relate to the 8³/4% senior notes. The realized and unrealized loss on the derivative financial instruments was $43.1 million for the fiscal year ended March 31, 2005.

Income taxes. Income tax expense was $0.7 million for the fiscal year ended March 31, 2006, as compared to a net benefit of $2.3 million for the fiscal year ended March 31, 2005. At March 31, 2006, we had accumulated non-capital losses for income tax purposes of approximately $66.4 million, the majority of which expire in 2012 and 2013. We have recorded a full valuation allowance to reduce the net future income tax asset to zero, reflecting the uncertainty of realizing the benefit of the losses before they expire. The income tax expense reflects only the Large Corporations Tax, which is a form of minimum tax.

Fiscal Year Ended March 31, 2005 Compared to Fiscal Year Ended March 31, 2004

Revenue. Revenue decreased by $21.0 million, or 5.6%, from $378.3 million for the fiscal year ended March 31, 2004 to $357.3 million for the fiscal year ended March 31, 2005.

•

Mining and Site Preparation. Mining and Site Preparation revenue increased by $29.0 million, or 12.3%, from $235.8 million for the fiscal year ended March 31, 2004 to $264.8 million for the fiscal year ended March 31, 2005. Contributing to this increase was revenue from new projects such as the underground utility installation contract for CNRL and the mining services contract for Grande Cache Coal Corporation, as well as the OPTI/Nexen Long Lake project. Offsetting these increases were decreases in revenue from the Syncrude UE-1 project as this contract neared completion, the Syncrude Aurora II project as this contract was completed in the fiscal 2004, and the Albian site as they lowered their demand for contract services in fiscal 2005.

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Piling. Piling revenue increased by $12.0 million, or 24.5% from $49.0 million for the fiscal year ended March 31, 2004 to $61.0 million for the fiscal year ended March 31, 2005, primarily due to a higher volume of contracts in the Vancouver, Regina and Fort McMurray regions due to strong economic activity, as well as the addition of large piling contracts for Flint Infrastructure Services Ltd. and Suncor Energy. This additional work more than offset the loss of revenue generated by the Syncrude UE-1 piling contract in fiscal 2004.

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Pipeline. Pipeline revenue decreased by $62.0 million, or 66.3%, from $93.5 million for the fiscal year ended March 31, 2004 to $31.5 million for the fiscal year ended March 31, 2005, primarily due to a decrease in work performed for EnCana in fiscal 2005. The decrease in volume was primarily due to our customer repositioning its efforts in the region and drilling a much lower number of gas wells.

Project costs. Project costs increased by $0.6 million, or 0.3%, from $240.2 million for the fiscal year ended March 31, 2004 to $240.9 million for the fiscal year ended March 31, 2005. As a percentage of revenue, project costs were 67.4% of revenue in the fiscal year ended March 31, 2005 as compared to 63.5% in the prior fiscal year. In the fiscal year ended March 31, 2005, abnormally high costs as a percentage of revenue were incurred on a large steam-assisted gravity drainage site project.

Equipment costs. Equipment costs decreased by $4.3 million, or 7.6%, from $57.2 million for the fiscal year ended March 31, 2004 to $52.8 million for the fiscal year ended March 31, 2005. As a percentage of revenue, equipment costs were 14.8% as compared to 15.1% in the prior fiscal year. Equipment maintenance costs were lower in fiscal 2005 because newer equipment added during the year required fewer repairs in fiscal 2005.

Equipment operating lease expense. Equipment operating lease expense decreased by $5.3 million, or 44.3%, from $11.9 million for the fiscal year ended March 31, 2004 to $6.6 million for the fiscal year ended March 31, 2005, primarily due to the purchase of equipment under operating leases in connection with the Acquisition on November 26, 2003.

Depreciation. Depreciation expense increased by $7.5 million, or 56.8%, from $13.2 million for the fiscal year ended March 31, 2004 to $20.8 million for the fiscal year ended March 31, 2005. As a percentage of revenue, depreciation increased to 5.8% from 3.5%. The increase was primarily due to the addition of new equipment resulting from the buy-out of the leased and rented equipment in November 2003 and increased depreciable asset values resulting from the revaluation of assets to their estimated fair values in accordance with the application of purchase accounting in connection with the Acquisition on November 26, 2003. The year-over-year increase in equipment hours also contributed to the increased depreciation expense for the fiscal year ended March 31, 2005.

Gross profit. Gross profit decreased by $19.5 million, or 35.1%, from $55.7 million for the fiscal year ended March 31, 2004 to $36.2 million for the fiscal year ended March 31, 2005, primarily due to loss recognition on a large steam-assisted gravity drainage site project and a significant decrease in revenue from our Pipeline segment. As a percentage of revenue, gross profit decreased to 10.1% for the fiscal year ended March 31, 2005 from 14.7% for the fiscal year ended March 31, 2004.

Segment profit

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Mining and Site Preparation. Mining and Site Preparation segment profit decreased by $14.3 million, or 55.2%, from $25.9 million for the fiscal year ended March 31, 2004 to $11.6 million for the fiscal year ended March 31, 2005. This was primarily due to loss recognition on a large steam-assisted gravity drainage site project in fiscal 2005.

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Piling. Piling segment profit increased by $2.5 million, or 23.2% from $10.8 million for the fiscal year ended March 31, 2004 to $13.3 million for the fiscal year ended March 31, 2005, primarily due to a higher volume of contracts in the Vancouver, Regina and Fort McMurray regions due to strong economic activity, as well as the addition of large piling contracts for Flint Infrastructure Services Ltd. and Suncor Energy.

•

Pipeline. Pipeline segment profit decreased by $13.0 million, or 72.6%, from $17.9 million for the fiscal year ended March 31, 2004 to $4.9 million for the fiscal year ended March 31, 2005, primarily due to a decrease in work performed for our major pipeline customer in fiscal 2005.

General and administrative expenses. General and administrative expenses increased by $9.0 million, or 65.2%, from $13.8 million for the fiscal year ended March 31, 2004 to $22.9 million for the fiscal year ended March 31, 2005. As a percentage of revenue, general and administrative expenses increased from 3.7% to 6.4%. The increase was primarily attributable to higher staff levels, increased salaries, higher legal and consulting costs and increased professional fees related to North American Energy Partners’ restatement of two quarters of financial statements in the fiscal year ended March 31, 2005.

Amortization of intangible assets. Amortization of intangible assets decreased by $9.6 million, or 73.9%, from $12.9 million for the fiscal year ended March 31, 2004 to $3.4 million for the fiscal year ended March 31, 2005. The amortization of intangible assets in both fiscal 2005 and fiscal 2004 was related to the customer contracts in progress and related relationships, trade names, a non-competition agreement and employee arrangements acquired in the Acquisition on November 26, 2003. A majority of the cost of the intangible assets had been amortized as of March 31, 2005, as most of the costs related to customer contracts acquired in the Acquisition in November 2003 that were amortized at a rapid rate due to their short-term nature.

Operating income. Operating income decreased by $19.4 million, or 67.3%, from $28.8 million for the fiscal year ended March 31, 2004 to $9.4 million for the fiscal year ended March 31, 2005. The decrease was primarily due to the $19.5 million decrease in gross profit and the $9.0 million increase in general and administrative expenses, partially offset by the $9.6 million decrease in amortization expense.

Interest expense. Interest expense increased by $18.6 million, or 148.4%, from $12.5 million for the fiscal year ended March 31, 2004 to $31.1 million for the fiscal year ended March 31, 2005, primarily due to the addition of our 8 3/4% senior notes issued in November 2003, to finance a portion of the Acquisition and borrowings under our senior secured credit facility.

Foreign exchange gain. We recognized a foreign exchange gain of $19.8 million for the fiscal year ended March 31, 2005 as compared to a gain of $0.7 million for the prior fiscal year. The foreign exchange gains in both the current and prior periods related primarily to the change in the balance owed on the 8 3/4% senior notes due to the appreciation in the value of the Canadian dollar relative to the U.S. dollar.

Realized and unrealized loss on derivative financial instruments. For the fiscal year ended March 31, 2005, the realized and unrealized losses on our cross-currency and interest rate swap agreements related to our 8 3/4% senior notes were $2.7 million and $40.4 million, respectively, as compared to $0.9 million and $11.3 million, respectively, for the fiscal year ended March 31, 2004. The losses in both fiscal 2005 and fiscal 2004 related primarily to the changes in the fair value of the derivatives in the period due to the appreciation in the value of the Canadian dollar relative to the U.S. dollar.

Management fees. We did not incur any management fee expense for the fiscal year ended March 31, 2005. For the fiscal year ended March 31, 2004, we incurred management fee expense of $41.1 million. Management fees were fees charged for management services provided to the predecessor company by Norama Inc., its former parent company. Subsequent to the Acquisition on November 26, 2003, these fees are no longer paid.

Income taxes. We had a net benefit from income taxes of $2.3 million for the fiscal year ended March 31, 2005, as compared to a net benefit of $12.3 million for the fiscal year ended March 31, 2004. At March 31, 2005, we had accumulated non-capital losses for income tax purposes of approximately $90.8 million, the majority of which expire in 2012 and 2013. We recorded a full valuation allowance to reduce the net future income tax asset to zero, reflecting the uncertainty of realizing the benefit of the losses before they expire.

Comparative Quarterly Results

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


	Fiscal Year 2005												Fiscal Year 2006
	Q1			Q2			Q3			Q4			Q1			Q2		Q3		Q4
	(In millions of dollars, except equipment hours)
Revenue	$	70.9		$	82.7		$	81.0		$	122.8		$	104.4		$	124.0	$	121.5	$	142.3
Gross profit		8.1			9.8			(5.6	)		24.0			12.9			21.9		13.8		31.7
Net income (loss)		(5.1	)		(4.7	)		(32.4	)		(0.1	)		(49.2	)		11.5		2.1		13.7
Equipment hours		137,434			193,205			191,555			241,727			185,751			234,649		221,355		231,633

Consolidated Financial Position

At March 31, 2006, we had net working capital of $67.9 million compared to a net working capital position of $41.4 million at March 31, 2005. The increase was primarily due to increased cash and cash equivalents of $24.7 million, work in progress generating higher accounts receivable and unbilled revenue by $11.6 million, partially offset by an increase of $9.5 million in accounts payable, accrued liabilities, billings in excess of costs on uncompleted projects and current portion of capital lease obligations. It is our belief that working capital will be sufficient to meet these requirements.

Plant and equipment net of depreciation increased by $8.5 million at March 31, 2006 from March 31, 2005 primarily due to the construction of a shop to support the maintenance requirements of our 10-year overburden removal project for CNRL and the expansion of our head office. A portion of the increase also resulted from equipment purchases to replace retired equipment.

Capital lease obligations, including the current portion, increased by $3.7 million at March 31, 2006 from the balance at March 31, 2005 due to the addition of new leased vehicles and a viper drill to support new projects.

Impairment of Goodwill

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

•

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

•

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

We completed this test during the quarter ended December 31, 2005 and were not required to record an impairment loss on goodwill. We conduct our annual assessment of goodwill in December of each year.

Accounting Policies

Critical Accounting Policies and Estimates

Certain accounting policies require management to make significant estimates and assumptions about future events that affect the amounts reported in our financial statements and the accompanying notes. Therefore, the determination of estimates requires the exercise of management’s judgment. Actual results could differ from those estimates, and any differences may be material to our financial statements.

Revenue recognition

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

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Cost-plus. 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 overhead costs are charged to the project. 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. Revenue recognition is based on actual incurred costs to date plus an applicable fee that represents profit.

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Time-and-materials. A time-and-materials contract involves using the components of a cost-plus job to calculate 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 cost overrun must come out of the fixed margin included in the rates. Revenue is recognized as the labor, equipment, materials, subcontract costs and other services are supplied to the customer.

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Unit-price. A unit-price contract is utilized in the execution of projects with large repetitive quantities of work and is commonly utilized for site preparation, mining and pipeline work. We are compensated for each unit of work we perform (for example, cubic meters of earth moved, lineal meters of pipe installed or completed piles). Within the unit price contract, there is an allowance for labor, equipment, materials and any subcontractor’s costs. Once these costs are calculated, we add any site and corporate overhead costs along with an allowance for the margin we want to achieve. The risk associated with this type of contract is in the calculation of the unit costs with respect to completing the required work. Revenue on unit-price contracts is recognized using the percentage-of-completion method, measured by the ratio of costs incurred to date to estimated total cost.

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Lump sum. A lump sum contract is utilized when a detailed scope of work is known for a specific project. Thus, the associated costs can be readily calculated and a firm price provided to the customer for the execution of the work. The risk lies in the fact that there is no escalation of the price if the work takes longer 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 the project. Revenue on lump sum contracts is recognized using the percentage-of-completion method, measured by the ratio of costs incurred to date to estimated total cost.

The mix of contract types varies year-by-year. For the fiscal year ended March 31, 2006, our contracts consisted of 15% cost-plus, 25% time-and-materials, 45% unit-price and 15% lump sum.

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. Change orders are included in total estimated contract revenue when it is probable that the change order will result in a bona fide addition to contract value and can be reliably estimated. Revenue in excess of costs from unpriced change orders, extra work and variations in the scope of work is recognized after both the costs are incurred or services are provided and realization is assured beyond a reasonable doubt. Claims are included in total estimated contract revenue, only to the extent that contract costs related to the claim have been incurred, when it is probable that the claim will result in a bona fide addition to contract value and the amount of revenue can be reliably estimated. Claims are included in total estimated contract revenue, only to the extent that contract costs related to the claim have been incurred and when it is probable that the claim will result in a bona fide addition to contract value and can be reliably estimated. Those two conditions are satisfied when (1) the contract or other evidence provides a legal basis for the claim or a legal opinion is obtained providing a reasonable basis to support the claim, (2) additional costs incurred were caused by unforeseen circumstances and are not the result of deficiencies in our performance, (3) costs associated with the claim are identifiable and reasonable in view of work performed and (4) evidence supporting the claim is objective and verifiable. No profit is recognized on claims until final settlement occurs. This can lead to a situation where costs are recognized in one period and revenue is recognized when customer agreement is obtained or claim resolution occurs, which can be in subsequent periods. Historical claim recoveries should not be considered indicative of future claim recoveries. Costs incurred for bidding and obtaining contracts are expensed as incurred.

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

Factors that can contribute to changes in estimates of contract cost and profitability include, without limitation:

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

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identification and evaluation of scope modifications during the execution of the project;

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the availability and cost of skilled workers in the geographic location of the project;

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the availability and proximity of materials;

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unfavorable weather conditions hindering productivity;

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

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

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.

Plant and equipment

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

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

Goodwill

We perform our annual goodwill impairment test in the third quarter of each year, and more frequently if events or changes in circumstances indicate that an impairment loss may have been incurred. Impairment is tested at the reporting unit level by comparing the reporting unit’s carrying amount to its fair value. The process of determining fair values is subjective and requires us to exercise judgment in making assumptions about future results, including revenue and cash flow projections at the reporting unit level, and discount rates.

Derivative financial instruments

We use derivative financial instruments to manage economic risks from fluctuations in exchange rates and interest rates. These instruments include cross-currency swap agreements and interest rate swap agreements. These instruments are only used for risk management purposes. We do not hold or issue derivative financial instruments for trading or speculative purposes. Derivative financial instruments are subject to standard credit terms and conditions, financial controls, management and risk monitoring procedures.

Our derivative financial instruments are not designated as hedges for accounting purposes and are recorded on the balance sheet at fair value, which is determined based on values quoted by the counterparties to the agreements.

Series B Preferred Shares

The Series B preferred shares were initially issued to existing non-employee shareholders of the Company’s ultimate parent company, NACG Holdings Inc., for cash proceeds of $7.5 million on May 19, 2005.

Prior to our amendment of the terms of the Series B preferred shares on March 30, 2006, the definition of the redemption price of the Series B preferred shares included a calculation tied to the fair value of our common shares. Under the redemption price mechanism, any increase or decrease in the fair value of our common shares could result in an increase or decrease in the redemption value of the Series B preferred shares based on 25% of the change in fair value of the common shares and, as a consequence, fluctuations in interest expense. The amendment eliminated this calculation from the definition of redemption price. As a result, the Series B preferred shares will now be accreted from $42.2 million to their December 31, 2011 redemption value of $69.6 million, with corresponding periodic charges to interest expense. Please see note 14 (a) to our consolidated financial statements included at Item 17 for more information on the Series B Preferred Shares.

Recently Adopted Canadian Accounting Pronouncements

Hedge relationships

Effective November 26, 2003, we prospectively adopted the provisions of CICA Accounting Guideline 13, “Hedging Relationships” (“AcG-13”), which specifies the circumstances in which hedge accounting is appropriate, including the identification, documentation, designation, and effectiveness of hedges, and the discontinuance of hedge accounting. We determined that all of our then existing derivative financial instruments did not qualify for hedge accounting on the adoption date of AcG-13.

Generally accepted accounting principles

Effective November 26, 2003, we 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 do not provide guidance. The adoption of this standard did not have a material impact on our consolidated financial statements.

Revenue recognition

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

Consolidation of variable interest entities

Effective January 1, 2005, we prospectively adopted CICA Accounting Guideline 15, “Consolidation of Variable Interest Entities” (“AcG-15”). Variable interest entities (“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 variable interest entity (“VIE”) and who, if anyone, should consolidate the VIE. We have determined the joint venture in which we have an investment (see note 16(c) to our consolidated financial statements included at Item 17) qualifies as a VIE and began consolidating this VIE effective January 1, 2005.

Arrangements containing a lease

Effective January 1, 2005, we adopted EIC-150, “Determining Whether an Arrangement Contains a Lease” (“EIC-150”). EIC-150 addresses a situation where an entity enters into an arrangement, comprising a transaction that does not take the legal form of a lease but conveys a right to use a tangible asset in return for a payment or series of payments. The implementation of this standard did not have a material impact on our consolidated financial statements.

Vendor rebates

In April 2005, we adopted amended EIC-144, “Accounting by a Customer (Including a Reseller) for Certain Consideration Received from a Vendor” (“EIC-144”). EIC-144 requires companies to recognize the benefit of non-discretionary rebates for achieving specified cumulative purchasing levels as a reduction of the cost of purchases over the relevant period, provided the rebate is probable and reasonably estimable. Otherwise, the rebates would be recognized as purchasing milestones are achieved. The implementation of this new standard did not have a material impact on our consolidated financial statements.

Accounting for convertible debt instruments

In October 2005, the CICA issued EIC-158 “Accounting for Convertible Debt Instruments” (“EIC-158”) which provides guidance on whether an issuer of certain types of convertible debt instruments should classify the instruments as liabilities or equity and, if a liability, when it should be classified as a current liability. EIC-158 was applicable for convertible debt instruments issued after October 17, 2005. The adoption of this standard did not have an impact on our consolidated financial statements.

Non-monetary transactions

Effective January 1, 2006, we adopted CICA Handbook Section 3831, “Non-monetary Transactions”. The new standard requires that an asset exchanged or transferred in a non-monetary transaction must be measured at its fair value except when: the transaction lacks commercial substance; the transaction is an exchange of production or property held for sale in the ordinary course of business for production or property to be sold in the same line of business to facilitate sales to customers other than the parties to the exchange; neither the fair value of the assets or services received nor the fair value of the assets or services given up is reliably measurable; or the transaction is a non-monetary, non-reciprocal transfer to owners that represents a spin-off or other form of restructuring or liquidation. In these cases, the transaction must be measured at carrying value. The adoption of this standard did not have a material impact on our consolidated financial statements.

Implicit variable interests under AcG-15

Effective January 1, 2006, we adopted EIC-157, “Implicit Variable Interests Under AcG-15” (“EIC-157”). EIC-157 requires a company to assess whether it has an implicit variable interest in a VIE or potential VIE when specific conditions exist. An implicit variable interest acts the same as an explicit variable interest except it involves the absorbing and/or receiving of variability indirectly from the entity (rather than directly). The identification of an implicit variable interest is a matter of judgment that depends on the relevant facts and circumstances. The adoption of this standard did not have a material impact on our consolidated financial statements.

Conditional asset retirement obligations

In November 2005, the CICA issued EIC-159, “Conditional Asset Retirement Obligations” (“EIC-159”) to clarify the accounting treatment for a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Under EIC-159, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the obligation can be reasonably estimated. The guidance is effective April 1, 2006, although early adoption is permitted, and is to be applied retroactively, with restatement of prior periods. We adopted this standard in fiscal 2006, and the adoption did not have a material impact on our consolidated financial statements.

Recent Canadian Accounting Pronouncements Not Yet Adopted

Financial instruments

In January 2005, the CICA issued Handbook Section 3855, “Financial Instruments — Recognition and Measurement”, Handbook Section 1530, “Comprehensive Income”, and Handbook Section 3865, “Hedges”. The new standards are effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2006, specifically April 1, 2007 for us. Earlier adoption is permitted. The new standards will require presentation of a separate statement of comprehensive income under specific circumstances. Foreign exchange gains and losses on the translation of the financial statements of self-sustaining subsidiaries previously recorded in a separate section of shareholder’s equity will be presented in comprehensive income. Derivative financial instruments will be recorded in the balance sheet at fair value and the changes in fair value of derivatives designated as cash flow hedges will be reported in comprehensive income. We are currently assessing the impact of the new standards.

Accounting Policy Changes

Revenue recognition

Effective April 1, 2005, we changed our accounting policy regarding the recognition of revenue on claims by reflecting the amount of claims revenue on unit price contracts and to provide better matching of revenues and expenses under the criteria set forth by AICPA Statement of Position 81-1. Once contract performance is underway, we often experience changes in conditions, client requirements, specifications, designs, materials and work schedule. Generally, a “change order” will be negotiated with our customer to modify the original contract to approve both the scope and price of the change. Occasionally, however, disagreements arise regarding changes, their nature, measurement, timing and other characteristics that impact costs and revenue under the contract. When a change becomes a point of dispute between our customer and us, we then consider it as a claim.

Costs related to change orders and claims are recognized when they are incurred. Change orders are included in total estimated contract revenue when it is probable that the change order will result in a bona fide addition to contract value and can be reliably estimated. Prior to April 1, 2005, revenue from claims was included in total estimated contract revenue when awarded or received. After April 1, 2005, claims are included in total estimated contract revenue, only to the extent that contract costs related to the claim have been incurred, when it is probable that the claim will result in a bona fide addition to contract value and can be reliably estimated. Those two conditions are satisfied when (1) the contract or other evidence provides a legal basis for the claim or a legal opinion is obtained providing a reasonable basis to support the claim, (2) additional costs incurred were caused by unforeseen circumstances and are not the result of deficiencies in our performance, (3) costs associated with the claim are identifiable and reasonable in view of work performed and (4) evidence supporting the claim is objective and verifiable. This can lead to a situation where costs are recognized in one period and revenue, when the above conditions warrant recognition of the claim, occurs in subsequent periods. Historical claim recoveries should not be considered indicative of future claim recoveries. This change in policy resulted in an increase in claims revenue and unbilled revenue of approximately $12.9 million for the year ended March 31, 2006, but did not result in any adjustments to prior periods. For additional information, refer to note 2(c) to our consolidated financial statements included at Item 17.

U.S. Generally Accepted Accounting Principles

Our 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 24 to our consolidated financial statements included at Item 17.

United States accounting pronouncements recently adopted

In December 2003, the U.S. Financial Accounting Standards Board (the “FASB”) issued FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities” (“FIN 46R”), 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,” which was issued in January 2003. We are required to apply FIN 46R to variable interests in 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 was 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. We have has determined the joint venture in which we have an investment (see note 16(c) to our consolidated financial statements included at Item 17) qualifies as a VIE.

Statement of Financial Accounting Standards 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. We adopted the Statement as of January 1, 2004, except for certain mandatorily redeemable financial instruments. For certain mandatorily redeemable financial instruments, we adopted the Statement on January 1, 2005. After the adoption of the standard, the Company issued mandatorily redeemable preferred shares that were within the scope of the standard, which have been disclosed in note 14(a) to our consolidated financial statements included at Item 17.

In November 2004, the FASB issued Statement of Financial Accounting Standards No. 151, “Inventory Costs.” This standard requires the allocation of fixed production overhead costs be based on the normal capacity of the production facilities and unallocated overhead costs recognized as an expense in the period incurred. In addition, other items such as abnormal freight, handling costs and wasted materials require treatment as current period charges rather than being considered an inventory cost. This standard was effective for fiscal 2006 for us. The adoption of this standard did not have a material impact on our financial statements.

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

Statement of Financial Accounting Standards No. 153, “Exchanges of Non-monetary Assets — an Amendment of APB Opinion 29” (“SFAS 153”), was issued in December 2004. Accounting Principles Board (“APB”) Opinion 29 is based on the principle that exchanges of non-monetary assets should be measured based on the fair value of assets exchanged. SFAS 153 amends APB Opinion 29 to eliminate the exception for non-monetary exchanges of similar productive assets and replaces it with a general exception for exchanges of non-monetary assets that do not have commercial substance. The standard is effective for us for non-monetary asset exchanges occurring in fiscal periods beginning after June 15, 2005, beginning July 1, 2005 for us. The adoption of this standard did not have a material impact on our financial statements.

In March 2005, FASB Staff Position FIN 46R-5, “Implicit Variable Interests under FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities”, to address whether a company has an implicit variable interest in a VIE or potential VIE when specific conditions exist. The guidance describes an implicit variable interest as an implied financial interest in an entity that changes with changes in the fair value of the entity’s net assets exclusive of variable interests. An implicit variable interest acts the same as an explicit variable interest except that it involves the absorbing and/or receiving of variability indirectly from the entity (rather than directly). This guidance was adopted in 2006 and did not have a material impact on our consolidated financial statements.

Recent United States accounting pronouncements not yet adopted

Statement of Financial Accounting Standards No. 123R, “Share-Based Payment” (“SFAS 123R”) requires companies to recognize in the income statement, the grant-date fair value of stock options and other equity-based compensation issued to employees. The fair value of liability-classified awards is remeasured subsequently at each reporting date through the settlement date, while the fair value of equity- classified awards is not subsequently remeasured. The revised standard is effective for non-public companies beginning with the first annual reporting period that begins after December 15, 2005, which in our case is the period beginning April 1, 2006. We have used the fair value method under Statement 123 since its inception. We will be required to adopt SFAS 123R prospectively since we use the minimum value method for purposes of complying with Statement 123. We are currently evaluating the other impacts of the revised standard.

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections” (“SFAS 154”) which replaces Accounting Principles Board Opinions No. 20 “Accounting Changes” and Statement of Financial Accounting Standards No. 3, “Reporting Accounting Changes in Interim Financial Statements — An Amendment of APB Opinion No. 28.” SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 and is required to be adopted by us in our fiscal year beginning on April 1, 2006. We are currently evaluating the effect that the adoption

of SFAS 154 will have on our consolidated results of operations and financial position but do not expect it to have a material impact.

Statement of Financial Accounting Standards No. 155, “Accounting for Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 and 140” (“SFAS 155”) was issued February 2006. This Statement is effective for all financial instruments acquired, issued, or subject to a remeasurement (new basis) event occurring after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The fair value election provided for in paragraph 4(c) of this Statement may also be applied upon adoption of this Statement for hybrid financial instruments that had been bifurcated under paragraph 12 of Statement 133 prior to the adoption of this Statement. This states that an entity that initially recognizes a host contract and a derivative instrument may irrevocably elect to initially and subsequently measure that hybrid financial instrument, in its entirety, at fair value with changes in fair value recognized in earnings. SFAS 155 is applicable for all financial instruments acquired or issued in our 2007 fiscal year although early adoption is permitted. We are currently reviewing the impact of this Statement.

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109” (“FIN 48”) which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This Interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition requirements. FIN 48 is effective for fiscal years beginning after December 15, 2006, specifically April 1, 2007 for the Company. We are currently reviewing the impact of this Interpretation.

B.	LIQUIDITY AND CAPITAL RESOURCES

Operating activities

Operating activities for the fiscal year ended March 31, 2006 resulted in a net increase in cash of $33.9 million. Increased earnings and accrued liabilities were partially offset by an increase in accounts receivable. The net usage of cash in operating activities for the fiscal year ended March 31, 2005 was $4.8 million primarily due to an increase in unbilled revenue due to billing delays and poor performance from a major site grading project.

Investing activities

During the fiscal year ended March 31, 2006, we invested $7.4 million in sustaining capital expenditures and $21.6 million in growth capital expenditures, for total capital expenditures of $29.0 million. In the fiscal year ended March 31, 2005, we invested $7.5 million in sustaining capital expenditures and $18.2 million in growth capital expenditures, for total capital expenditures of $25.7 million.

Sustaining capital expenditures are those that are required to keep our existing fleet of equipment at its optimum average age through maintenance or replacement. Growth capital expenditures relate to equipment additions required to perform increased sizes or numbers of projects.

Financing activities

Financing activities during the fiscal year ended March 31, 2006 resulted in a cash inflow of $13.1 million. A portion of the proceeds from the issuance of the US$60.5 million of 9% senior secured notes and $7.5 million of Series B preferred shares was used to repay the amount outstanding under our senior secured credit facility and to pay the fees and expenses related to the refinancing. Payments of $2.2 million were also made on our capital lease obligations. Financing activities during the fiscal year ended March 31, 2005 related primarily to borrowings under our revolving credit facility, term credit facility scheduled repayments and repayment of capital lease obligations.

Liquidity Requirements

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

We have outstanding US$200 million of 8³/4% senior notes due 2011. The foreign currency risk relating to both the principal and interest payments on the 8³/4% senior notes has been managed with a cross-currency swap and interest rate

swaps which went into effect concurrent with the issuance. Interest of US$8.8 million is payable semi-annually in June and December of each year until the notes mature on December 1, 2011. The swap agreements are economic hedges of the changes in the Canadian dollar-U.S. dollar exchange rate, but they do not meet the criteria to qualify for hedge accounting. There are no principal payments required on the 8³/4% senior notes until maturity.

Our US$60.5 million of 9% senior secured notes were issued on May 19, 2005 pursuant to a private placement. On July 26, 2005, we registered substantially identical notes with the United States Securities and Exchange Commission and exchanged them for the notes issued in the private placement. The foreign currency risk relating to both the principal and interest payments on the 9% senior secured notes has not been hedged. Interest of US$2.7 million is payable semi-annually in June and December of each year until the notes mature on June 1, 2010. There are no principal payments required on the 9% senior secured notes until maturity.

Further, one of our major contracts allows the customer to request up to $50 million in letters of credit. While this level has not been requested to date, we would either have to lower other letters of credit or cash collateralize other obligations to provide this amount of letters of credit.

We maintain a significant equipment and vehicle fleet comprised of units with various remaining useful lives. Once units reach the end of their useful lives, it becomes cost prohibitive to continue to maintain them and, therefore, they must be replaced. As a result, we are continually acquiring new equipment to replace retired units and to expand the fleet to meet growth as new projects are awarded to us. It is important to adequately maintain the large revenue-producing fleet in order to avoid equipment downtime which can impact our revenue stream and inhibit our ability to satisfactorily perform on our projects. In order to conserve cash, we have financed our recent requirements for large pieces of heavy construction equipment through operating leases. In addition, we continue to lease a portion of our motor vehicle fleet and assumed several heavy equipment operating leases from Norama Ltd. in connection with the Acquisition on November 26, 2003.

Our cash requirements during the fiscal year ended March 31, 2006 increased due to continued growth and additional operating and capital expenditures associated with new projects. Our cash requirements for fiscal 2007 include funding operating lease obligations, debt and interest repayment obligations and working capital as activity levels are expected to continue to increase. In addition, we will require capital to finance further vehicle and equipment acquisitions for upcoming new projects.

We expect our sustaining capital expenditures to range from $10 million to $15 million per year over the next two years. We expect our total capital expenditures to range from $50 million to $60 million in fiscal 2007. It is our belief that working capital will be sufficient to meet these requirements.

Sources of Liquidity

Our principal sources of cash are funds from operations and borrowings under our revolving credit facility. On July 19, 2006, we amended and restated our revolving credit facility to provide for borrowings and the issuance of letters of credit of up to $55.0 million, subject to borrowing base limitations. As of July 19, 2006, we had approximately $37.0 million of available borrowings under the revolving credit facility after taking into account $18.0 million of outstanding and undrawn letters of credit to support bonding requirements and performance guarantees associated with customer contracts and operating leases. The facility bears interest at the Canadian prime rate plus 2% or Canadian bankers’ acceptance rate plus 3%. The indebtedness under the revolving credit facility, including the liability under the swaps used to manage the foreign currency risk on the 8³/4% senior notes, is secured by substantially all of our assets and those of our subsidiaries, including accounts receivable, inventory and plant and equipment, and a pledge of our common shares and those of our subsidiaries.

Our revolving credit facility contains covenants that restrict our activities, including restrictions on creating liens, engaging in mergers, consolidations and sales of assets, incurring additional indebtedness, giving guaranties, engaging in different businesses, making loans and investments, making certain capital expenditures and making certain dividend, debt and other restricted payments. Under the revolving credit facility, we also are required to satisfy certain financial covenants, including a minimum interest coverage ratio, a maximum leverage ratio and a minimum consolidated EBITDA requirement. Consolidated EBITDA is defined in the credit facility as the sum, without duplication, of (1) consolidated net income, (2) consolidated interest expense, (3) provisions for taxes based on income, (4) total depreciation expense, (5) total amortization expense, (6) costs and expenses incurred by us in entering into the credit facility, (7) accrual of stock-

based compensation expense to the extent not paid in cash, and (8) other non-cash items (other than any such non-cash item to the extent it represents an accrual of or reserve for cash expenditures in any future period), but only, in the case of clauses (2)-(8), to the extent deducted in the calculation of consolidated net income, less other non-cash items added in the calculation of consolidated net income (other than any such non-cash item to the extent it will result in the receipt of cash payments in any future period), all of the foregoing as determined on a consolidated basis for us in conformity with GAAP. The required minimum Consolidated EBITDA through December 31, 2006 is $65.5 million, and this minimum amount increases periodically until the credit facility matures. We believe Consolidated EBITDA as defined in the credit facility is an important measure of our liquidity.

The Series B preferred shares were initially issued for net cash proceeds of $7.5 million on May 19, 2005 to existing common shareholders of NACG Holdings Inc., including the sponsors. For additional information on the Series B preferred shares, see note 14(a) to our consolidated financial statements included at Item 17.

Our inability to file our financial statements for the periods ended December 31, 2004, March 31, 2005 and September 30, 2005 with the SEC within the deadlines imposed by covenants in the indentures governing our 8³/4% senior notes and our 9% senior secured notes caused us to be out of compliance with such covenants. In each case, we filed our financial statements before the lack of compliance became an event of default under the indentures.

Stock-Based Compensation

Some of our directors, officers, employees and service providers have been granted options to purchase common shares of NACG Holdings Inc. under a stock-based compensation plan. See Item 6.

C.	RESEARCH AND DEVELOPMENT

Not applicable.

D.	TREND INFORMATION

We have developed a strong business foundation through our relationships with the key organizations in the oil sands region (Syncrude, CNRL, Suncor, Albian Sands, etc.) coupled with the long-term mining work at CNRL. Our ability to build on this solid foundation continues to be enhanced as world economic growth underpins high prices in the oil and gas industries.

Activity in the oil sands region remains very high and a number of high profile projects have been announced, most recently including the acceleration of CNRL’s expansion plans, Shell’s Jackpine Mine and the Petro-Canada/UTS Fort Hills project. Accordingly, activity levels are expected to remain strong.

Since the beginning of fiscal 2006, we have completed a refinancing of our debt, the management team has been restructured, and a number of initiatives that have strengthened the financial and operating controls have been implemented. The Company launched a major business improvement initiative and re-organization aimed at increasing productivity and equipment utilization. These initiatives, coupled with the acquisition of new equipment ideally suited to heavy earth moving in the oil sands area, have strengthened our ability to bid competitively and profitably into the expanding market.

With respect to the Mining and Site Preparation operating segment, we are actively pursuing a strategy of retaining our leading position as an outsource provider of services in the oil sands region while concurrently reducing risk by bidding into opportunities in other Canadian provinces. Significant work at the Victor diamond project in Northern Ontario support the success of this strategy. At the same time, our Piling segment remains a strong business and with the level of construction in the western provinces alone, it is considered likely that the work load will remain high in the foreseeable future. Similarly, the Pipeline segment had reduced activity last year and a low level of activity compared to expectations in the current year. However, recently awarded prospects as well as a multitude of announced projects in this business area augers well for considerable work over the next few years.

We are not aware of any events, trends, uncertainties, demands or commitments that would materially affect our forecasted revenues, profitability, liquidity or capital resources that would cause reported financial information not to be indicative of future operating results or financial condition.

E.	OFF-BALANCE SHEET ARRANGEMENTS

As of March 31, 2006, we had $18.0 million of outstanding, undrawn letters of credit issued under our revolving credit facility.

F.	TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

Our principal contractual obligations relate to our long-term debt (8³/4% senior notes and 9% senior secured notes), preferred shares and capital and operating leases. The following table summarizes our future contractual obligations, excluding interest payments unless otherwise noted, as of March 31, 2006.


	Payments Due by Fiscal Year
	Total		2007		2008		2009		2010		2011 and After
	(In millions)
Long-term debt	$	304.0	$	—	$	—	$	—	$	—	$	304.0
Series A preferred shares(a)		1.0		—		—		—		—		1.0
Series B preferred shares(a)		69.6		—		—		—		—		69.6
Capital leases (including interest)		12.7		3.8		3.6		3.0		2.1		0.2
Operating leases		57.6		21.2		16.5		9.6		8.1		2.2

Total contractual obligations	$	444.9	$	25.0	$	20.1	$	12.6	$	10.2	$	377.0

(a)	Reflected at fully accreted redemption value.

ITEM 6:

DIRECTORS, SENIOR MANAGEMENT, AND EMPLOYEES

A.	DIRECTORS AND SENIOR MANAGEMENT

Directors and Executive Officers

The following sets forth information about our directors and executive officers. Ages reflected are as of July 1, 2006. Each director is elected for a one-year term or until such person’s successor is duly elected or appointed, unless his office is earlier vacated. Unless otherwise indicated below, the business address of each of our directors and executive officers is Zone 3, Acheson Industrial Area, Z-53016 Highway 60, Acheson, Alberta, T7X 5A7.


Name and Municipality of Residence	Age	Position
Rodney J. Ruston	55	Director, President and Chief Executive Officer
Edmonton, Alberta
Vincent J. Gallant	48	Vice President, Corporate
Edmonton, Alberta
Robert G. Harris	58	Vice President, Human Resources, Health,
Edmonton, Alberta		Safety & Environment
Christopher J. Hayman	43	Vice President, Finance
St. Albert, Alberta
William M. Koehn	44	Vice President, Operations and Chief Operating
Spruce Grove, Alberta		Officer
Miles W. Safranovich	42	Vice President, Business Development and
Spruce Grove, Alberta		Estimating
Ronald A. McIntosh	63	Chairman of the Board
Calgary, Alberta
George R. Brokaw	38	Director
Southampton, New York
John A. Brussa	49	Director
Calgary, Alberta
Donald R. Getty	73	Director
Edmonton, Alberta
Martin P. Gouin	45	Director
Edmonton, Alberta
John D. Hawkins	42	Director
Houston, Texas
William C. Oehmig	57	Director
Houston, Texas
Richard D. Paterson	63	Director
San Francisco, California
Allen R. Sello	67	Director
West Vancouver, British Columbia
K. Rick Turner	48	Director
Little Rock, Arkansas

Rodney J. Ruston became our President and Chief Executive Officer and one of our directors on May 9, 2005. Previously, Mr. Ruston was Managing Director and Chief Executive Officer of Ticor Limited an Australian-based natural resources company with operations throughout Australia and in South Africa and Madagascar, from June 2000 to July 2004. From July 2003 until May 2005 he served as Chairman of the Australian Minerals Tertiary Education Council. Mr. Ruston has spent his entire career in the natural resources industry, holding management positions with Pasminco Ltd., Savage Resources Ltd., Wambo Mining Corporation, Oakbridge Ltd. and Kembla Coal & Coke Pty. Ltd. He also served as a Principal with Ruston Consulting Services Pty. Ltd., a management consulting firm providing business advice to the natural resources industry. Mr. Ruston received his Bachelor of Engineering in Mining from the University of New South Wales and a Master of Business Administration from the University of Wollongong.

Vincent J. Gallant was appointed Vice President, Corporate on June 15, 2005. Previously, he served as Vice President, Finance since November 26, 2003. He joined our predecessor company in 1997 as Vice President, Finance. Prior to joining North American, Mr. Gallant held a number of positions, including Comptroller at Alberta Energy Company

Ltd. and Controller for Edmonton Telephones. He obtained his Chartered Accountant Designation in 1983 after articling with Peat, Marwick, Mitchell and Company. Mr. Gallant received his Bachelor of Arts in Economics from the University of Alberta. He obtained his Certified Financial Planning designation in 2001.

Robert G. Harris joined us in June 2006 as Vice President, Human Resources, Health, Safety & Environment. Mr. Harris began his career in 1969 with Chrysler Canada in various personnel and human resources positions before taking on the role of Environmental Health & Safety Manager and subsequently the Labour Relations Supervisor role. In 1982, he accepted a position with IPSCO Inc. where he was responsible for human resources over 6 facilities in Canada and the USA. Since 1987, he has held senior human resources roles at Labatt Breweries of Canada including National Manager, Industrial Relations & Training and Director, Human Resources at both regional and national levels. Mr. Harris graduated in 1969 from the University of Windsor with a Bachelor of Arts in Sociology/Psychology and has received his Certified Human Resources Professional designation.

Christopher J. Hayman joined us in January 2005 as Treasurer, a position he held until being appointed Vice President, Finance in June 2005. He will be appointed Vice President, Supply Chain once a new chief financial officer is appointed. Previously he worked for Finning Canada, from November 1998 to January 2005, initially as Assistant Controller and eventually becoming Vice President and Controller. Prior to this he held positions at Enbridge, Telus and Thorne, Ernst and Whinney. Mr. Hayman received his Bachelor of Commerce with an Accounting major from the University of Alberta and is a Canadian Chartered Accountant.

William M. Koehn became our Vice President, Operations on November 26, 2003 and our Chief Operating Officer on December 8, 2004. Previously, he served as Vice President, Operations for our predecessor company since 2002. He joined our predecessor company in 1989 and became the Fort McMurray Regional Manager in 1997. Prior to this he was a Senior Civil Engineer with Quintette Coal Ltd. Mr. Koehn attended the University of Alberta and received his Bachelor of Science in Civil Engineering and has completed his Masters in Construction Engineering and Management.

Miles W. Safranovich joined us in November 2004 and held the position of General Manager, Industrial and Heavy Civil until he was appointed Vice President, Contracts and Technical Services in July 2005 and Vice President, Business Development and Estimating in July 2006. He has extensive experience in the construction industry, spending most of his career at Voice Construction Ltd. where he held a variety of positions between 2000 and October 2004, including Operations Manager and Construction Manager. Mr. Safranovich attended the University of Alberta and obtained a Bachelor of Science in Biology in 1986 and a Bachelor of Science in Civil Engineering specializing in Construction Management in 1992.

Ronald A. McIntosh became the Chairman of our Board of Directors on May 20, 2004. Mr. McIntosh was chairman of NAV Energy Trust, a Calgary-based oil and natural gas investment fund from January 2004 to August 2006. Between October 2002 and January 2004, he was President and Chief Executive Officer of Navigo Energy Inc. and was instrumental in the conversion of Navigo into NAV Energy Trust. 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’s significant experience in the energy industry includes the former positions of Chief Operating Officer of Amerada Hess Canada and Director of Crispin Energy Inc. Mr. McIntosh is on the Board of Directors of Advantage Oil & Gas Ltd. and C1 Energy Ltd.

George R. Brokaw became one of our Directors on June 28, 2006. Mr. Brokaw joined Perry Capital, L.L.C., an affiliate of Perry Corp., in August 2005 as a Managing Director. Perry Strategic Capital Inc., also an affiliate of Perry Corp., is a private investment firm and provides certain services to us pursuant to an advisory services agreement. Investment entities controlled by Perry Corp. are holders of common shares of NACG Holdings Inc. and our Series B preferred shares. See Item 7 “Major Shareholders and Related Party Transactions.” From January 2003 to May 2005, Mr. Brokaw was Managing Director (Mergers & Acquisitions) of Lazard Frères & Co. LLC, which he joined in 1996. Between 1994 and 1996, he was an investment banking associate for Dillon Read & Co. Mr. Brokaw received a Bachelor of Arts degree from Yale University and a J.D. and M.B.A. from the University of Virginia.

John A. Brussa became one of our Directors on November 26, 2003. Mr. Brussa is a senior partner and head of the Tax Department at the law firm of Burnet, Duckworth & Palmer LLP, a leading natural resource and energy law firm located in Calgary. He has been a partner since 1987 and has worked at the firm since 1981. Mr. Brussa is Chairman of

Penn West Energy Trust, Crew Energy Inc. and Divestco Inc. Mr. Brussa also serves as a director of a number of natural resource and energy companies and mutual fund trusts. He is a member and former Governor of the Executive Committee of the Canadian Tax Foundation. Mr. Brussa attended the University of Windsor and received his Bachelor of Arts in History and Economics in 1978 and his Bachelor of Laws in 1981.

Donald R. Getty became one of our Directors on November 26, 2003. Since 1992, Mr. Getty has been President and Chief Executive Officer of Sunnybank Investments Ltd., a private investment and consulting firm based in Edmonton, Alberta. Mr. Getty was the 11th Premier of Alberta since the province was formed in 1905, a position he held from 1985 to 1992. As Premier, Mr. Getty’s government was successful in emphasizing development of non-conventional oil projects and diversifying Alberta’s economy, among other initiatives. Before serving as Premier of Alberta, Mr. Getty had a distinguished career in both the public and private sectors. Mr. Getty graduated from the University of Western Ontario with an Honours degree in Business Administration and in 2003 he received an Honourary Degree of Law from the University of Lethbridge. In addition, Mr. Getty was appointed an officer of the Order of Canada in 1998 and a member of the Alberta Order of Excellence in 1994.

Martin P. Gouin became one of our Directors on November 26, 2003. Mr. Gouin was President and Chief Executive Officer of North American Construction Group Inc. from 1995 until November 2003. Prior to that he held numerous positions at North American, including Vice President of Operations, and has more than 25 years experience in the industry. Since 2002, Mr. Gouin has been the President of Norama Inc., a management and holding company. He is a director of Tirecraft Group Inc., one of the largest wholesale and retail distributors of tires in North America, and Emerge Developments, with holdings in office and commercial real estate. Mr. Gouin is a member of Young Presidents Organization and attended the University of Alberta, majoring in economics.

John D. Hawkins became one of our Directors on October 17, 2003. Mr. Hawkins joined The Sterling Group, L.P. in 1992 and has been a Principal since 1999. The Sterling Group, a private equity investment firm, provides certain services to us pursuant to an advisory services agreement, and an investment entity affiliated with The Sterling Group is a holder of common shares of NACG Holdings Inc. and our Series B preferred shares. See “Item 7 “Major Shareholders and Related Party Transactions.” Before joining Sterling he was on the professional staff of Arthur Andersen & Co. from 1986 to 1990. Mr. Hawkins previously served on the board of Exopack Holding Corp. He received a Bachelor of Science in Business Administration in Accounting from the University of Tennessee and his M.B.A. from the Owen Graduate School of Management at Vanderbilt University.

William C. Oehmig served as Chairman of our Board of Directors from November 26, 2003 until passing off this position and assuming the role of Director and chair of the Executive Committee on May 20, 2004. He is a Principal with The Sterling Group, L.P., a private equity investment firm. The Sterling Group provides certain services to us pursuant to an advisory services agreement, and an investment entity affiliated with The Sterling Group is a holder of common shares of NACG Holdings Inc. and our Series B preferred shares. See “Item 7 “Major Shareholders and Related Party Transactions.” Prior to joining Sterling in 1984, Mr. Oehmig worked in banking, mergers and acquisitions, and represented foreign investors in purchasing and managing U.S. companies in the oilfield service, manufacturing, distribution, heavy equipment and real estate sectors. He began his career in Houston in 1974 at Texas Commerce Bank. Mr. Oehmig currently serves on the boards of Propex Fabrics Inc. and Panolam Industries International Incorporated. In the past he has served as Chairman of Royster-Clark, Purina Mills, and as a director of Exopack and Sterling Diagnostic Imaging. Mr. Oehmig received his B.B.A. in economics from Transylvania University and his M.B.A. from the Owen Graduate School of Management at Vanderbilt University.

Richard D. Paterson became one of our Directors on August 18, 2005. Mr. Paterson has been a Managing Director of Genstar Capital since 1988. Genstar Capital provides certain services to us pursuant to an advisory services agreement, and certain investment entities controlled by Genstar are holders of common shares of NACG Holdings Inc. and our Series B preferred shares. See “Item 7 “Major Shareholders and Related Party Transactions.” Before founding Genstar Capital, Mr. Paterson served as Senior Vice President and CFO of Genstar Corporation, a $4 billion NYSE company, where he was responsible for finance, tax, information systems and public reporting. He has been active in corporate acquisitions for more than 25 years. Mr. Paterson started his career in 1984 as an auditor with Coopers & Lybrand in Montreal. He currently serves as Chairman of the Board of New A.C. Inc. and is also a Director of INSTALLS Inc. LLC, American Pacific Enterprises LLC, Propex Fabrics Inc., Woods Equipment Company and Altra Industrial Motion, Inc. Mr. Paterson earned a Bachelor of Commerce from Concordia University and is a Chartered Accountant.

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

K. Rick Turner became one of our Directors on November 26, 2003. Mr. Turner has been employed by Stephens’ family entities since 1983. SF Holding Corp, formerly Stephens Group, Inc., provides certain services to us pursuant to an advisory services agreement, and an investment entity controlled by SF Holding Corp. is a holder of common shares of NACG Holdings Inc. and our Series B preferred shares. See “Item 7 “Major Shareholders and Related Party Transactions.” Mr. Turner is currently Senior Managing Principal of The Stephens Group, LLC. He first became a private equity principal in 1990 after serving as the Assistant to the Chairman, Jackson T. Stephens. His areas of focus have been oil and gas exploration, natural gas gathering, processing industries and power technology. Mr. Turner currently serves as a director of Atlantic Oil Corporation, SmartSignal Corporation, JV Industrials, LLC, JEBCO Seismic LLC and the general partner of Energy Transfer Partners, LP (ETP) and the general partner of Energy Transfer Equity, LP (ETE). Prior to joining Stephens, he was employed by Peat, Marwick, Mitchell and Company. Mr. Turner earned his B.S.B.A. from the University of Arkansas and is a non-practicing CPA.

B.	COMPENSATION

Director Compensation

Our directors, other than Messrs. Gouin, McIntosh and Ruston, each receive an annual aggregate retainer of $32,500 and a fee of $1,500 for each meeting of the board or any committee of the board that they attend, and are reimbursed for reasonable out-of-pocket expenses incurred in connection with their services pursuant to our policies. The chairman of our audit committee receives an additional annual retainer of $10,000. Mr. McIntosh, our Chairman of the Board, receives an annual retainer of $150,000. In addition, Mr. McIntosh received a bonus of $205,000 in June 2005 and a bonus of $163,733 in July 2006. Messrs. Gouin and Ruston do not receive director compensation.

In addition, our directors have received grants of stock options of NACG Holdings Inc. under the 2004 Share Option Plan. Effective November 2003, each director, excluding Messrs. Brokaw, Gouin, McIntosh, Paterson, Sello and Ruston, received options to purchase 1,388 common shares. Mr. McIntosh received options to acquire 3,500 common shares in May 2004, Mr. Paterson received options to purchase 1,388 common shares in November 2005, Mr. Sello received options to purchase 1,388 common shares in February 2006 and Mr. Brokaw received options to purchase 1,388 common shares in June 2006. All the options have an exercise price of $100 per share, vest at the rate of 20% per year over five years and expire ten years after their grant date. The vesting of the options granted to Messrs. Brokaw and Paterson has been accelerated as if they had been issued effective November 2003.

On June 29, 2006, NACG Holdings Inc. offered each director holding stock options, excluding Messrs. McIntosh and Ruston, the option to have all of his options become immediately exercisable on the condition that he exercise all such options by September 30, 2006. As of August 29, 2006, one director had accepted this option. The stock options of any director who does not accept this offer will remain unchanged.

Executive Compensation

The following summary compensation table sets forth the total value of compensation earned by our Chief Executive Officer and each of the other four most highly compensated officers as of March 31, 2006, collectively called the named executive officers, for services rendered in all capacities to us for the fiscal years ended March 31, 2006, 2005 and 2004.

Summary Compensation Table


	Annual Compensation								Long-Term Compensation
*Name and Principal Position*	Fiscal Year	Salary		Bonus			Other Annual Compensation		Securities Underlying Options(a)
Rodney J. Ruston President and Chief Executive Officer (Hired May 2005)	2006	$	536,539	$	300,000		(d	)	27,500
William M. Koehn Vice President, Operations and Chief Operating Officer	2006 2005 2004		240,000 224,000 170,000		241,385 — 1,040,000	(b) (b)(c)	(d (d (d	) ) )	— — 5,000
Vincent J. Gallant Vice President, Corporate	2006 2005 2004		204,000 204,000 162,000		235,350 — 1,040,000	(b) (b)(c)	(d (d (d	) ) )	— — 5,000
Miles W. Safranovich Vice President, Business Development & Estimating (Hired November 2004)	2006 2005		195,808 61,385		210,384 —	(b)	(d (d	) )	2,000 3,000
Christopher J. Hayman Vice President, Finance (Hired January 2005)	2006 2005		183,641 56,250		186,910 —	(b)	(d (d	) )	2,000 3,000

(a)

Consists of options to purchase common shares of NACG Holdings Inc. The options granted to Mr. Ruston expire on May 8, 2015. The options granted to Messrs. Koehn and Gallant expire on November 26, 2013. The options granted in fiscal 2005 and 2006 to Mr. Safranovich expire on November 17, 2004 and November 2, 2015, respectively. The options granted in fiscal 2005 and 2006 to Mr. Hayman expire on February 17, 2015 and November 2, 2015, respectively.

(b)	Bonus pursuant to our Annual Incentive Plan.

(c)	Includes a $750,000 transaction bonus and a $250,000 performance bonus, both paid by Norama Inc., the parent company 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 Fiscal 2006


*Name*	Number of Securities Underlying Options Granted	Percentage of Total Options Granted to Employees in Fiscal Year		Exercise Price		Expiration Date	Grant Date Value(a)

Rodney J. Ruston	27,500	79.7	%	$	100	May 9, 2015	$	2,014,302
William M. Koehn	—	—			—	—		—
Vincent J. Gallant	—	—			—	—		—
Miles W. Safranovich	2,000	5.8	%	$	100	November 2, 2015		104,090
Christopher J. Hayman	2,000	5.8	%	$	100	November 2, 2015		104,090

(a)	Value estimated using the Black-Scholes option-pricing model. For assumptions used, see note 22 to our consolidated financial statements included at Item 17.

Aggregated Option Exercises in Fiscal 2006 and Fiscal Year End Option Values


*Name*	Shares Acquired on Exercise	Value Realized	Number of Securities Underlying Unexercised Options at March 31, 2006 (Exercisable/ Unexercisable)	Value of Unexercised In-the-Money Options at March 31, 2006 (Exercisable/ Unexercisable)
Rodney J. Ruston	—	—	—/27,500	—/ —
William M. Koehn	—	—	2,000/3,000	—/ —
Vincent J. Gallant	—	—	2,000/3,000	—/ —
Miles W. Safranovich	—	—	600/4,400	—/ —
Christopher J. Hayman	—	—	600/4,400	—/ —

Retirement Benefits for Executive Officers and Directors

For the fiscal year ended March 31, 2006, the total amount we set aside for pension, retirement and similar benefits for our executive officers and directors was $54,677, consisting of employer matching contributions to our executive officers’ Registered Retirement Savings Plan, a Canadian tax-deferred retirement savings plan, accounts of up to 5% of salary.

Retention Bonus

Norama Inc., the parent of Norama Ltd., will pay to each of Messrs. Koehn and Gallant a retention bonus of $750,000, plus interest, on November 26, 2006, three years after the closing of the Acquisition, provided they are still employed by us.

Annual Incentive Plan

We have established a management incentive plan. The incentive plan is administered by the Compensation Committee. The plan has established an annual 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 amount of the total pool, the target financial performance, the eligible participants and each participant’s share of the potential pool.

Share Option Plan

The board of our parent company has adopted the 2004 Share Option Plan. The option plan is administered by the Compensation Committee. 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. NACG Holdings Inc. has reserved 105,000 common shares for issuance under the option plan. As of March 31, 2006, there were 103,318 shares issuable upon exercise of outstanding share options and 1,682 were available for issuance.

Profit Sharing Plan

Our board has established a profit sharing plan covering all full-time salaried and certain hourly employees, excluding 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 by the Compensation Committee. 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 allocated to an individual employee or group of employees.

C.	BOARD PRACTICES

The Board and Board Committees

Our board supervises the management of our business as provided by Canadian law.

Our board has established the following committees:

•

The Executive Committee has been delegated all of the powers and authority of the board with respect to the management and direction of our business and affairs, except as limited by Section 115(3) of the Canada Business Corporations Act. The Executive Committee is currently composed of Messrs. Brokaw, Hawkins, McIntosh, Oehmig, Paterson, Ruston and Turner, with Mr. Oehmig serving as Chairman.

•

The Audit Committee recommends independent public accountants to the board, reviews the quarterly and annual financial statements and associated audit reports and reviews the fees paid to our auditors. The Audit Committee reports its findings and recommendations to the board for ratification. The Audit Committee is currently composed of Messrs. Brokaw, Brussa, Hawkins, McIntosh, Sello and Turner, with Mr. Sello serving as Chairman.

•

The Compensation Committee is charged with the responsibility for supervising executive compensation policies for us and our subsidiaries, administering the employee incentive plans, reviewing officers’ salaries, approving significant changes in executive employee benefits and recommending to the board such other forms of remuneration as it deems appropriate. The Compensation Committee is currently composed of Messrs. Brussa, Getty, McIntosh, Oehmig and Paterson, with Mr. Paterson serving as Chairman.

•

The Planning Committee is responsible for identifying and addressing significant issues and opportunities and developing strategic plans for us and making periodic reports to the board of directors on its activities, recommendations and actions. The Planning Committee is currently composed of Messrs. Brokaw, Brussa, Oehmig and Ruston, with Mr. Ruston serving as Chairman.

The board may also establish other committees.

D.	EMPLOYEES

As of March 31, 2006, we had over 130 salaried and over 1,200 hourly employees.

E.	SHARE OWNERSHIP

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 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 29, 2006.


*Name of Beneficial Owner*	Number of Common Shares	*Options⁽¹⁾*	% of Outstanding Common Shares
George R. Brokaw	—	555	*
John A. Brussa	4,000	555	*
Vincent Gallant	5,000	2,000	*
Donald R. Getty	1,000	555	*
Martin P. Gouin	—	—	—
John D. Hawkins	—	555	*
Christopher J. Hayman	1,000	600	*
William M. Koehn	5,000	2,000	*
Ronald A. McIntosh	2,000	1,400	*
William C. Oehmig	6,209	—	*
Richard D. Paterson	—	555	*
Rodney J. Ruston	500	5,500	*
Allen R. Sello	1,000	—	*
Miles W. Safranovich	500	600	*
K. Rick Turner	—	555	*

*	Less than 1%

(1)	Amount represents the number of options which had vested as of August 29, 2006. All options entitle the holder to purchase one NACG Holdings Inc. common share per option and have an exercise price of $100 per share and expire 10 years from date of issue.

ITEM 7:

MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

A.	MAJOR SHAREHOLDERS

All of our capital shares are owned by NACG Preferred Corp., and all of its capital shares are owned by NACG Holdings Inc. The following presents information regarding the beneficial ownership of each person who was the beneficial owner of more than 5% of the outstanding voting common shares of NACG Holdings Inc. as of August 29, 2006.


*Name of Beneficial Owner*	Number of Common Shares	% of Outstanding Common Shares
Sterling Group Partners I, L.P. (a)	272,456	29.93
Perry Luxco S.A.R.L. (b)	104,542	11.48
Perry Partners, L.P. (b)	92,707	10.18
Genstar Capital Partners III, L.P. (c)	190,412	20.92
Stephens-NACG LLC (d)	131,500	14.44

(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 Luxco S.A.R.L. and the managing general partner of Perry Partners, L.P. As such, Mr. Perry may be deemed to have beneficial ownership over the respective common shares owned by Perry Luxco S.A.R.L. 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 common shares beneficially owned, or deemed to be beneficially owned, by Genstar III GP LLC, but disclaim such beneficial ownership.

(d)	SF Holding Corp. is the sole manager of Stephens-NACG LLC. Warren A. Stephens owns 50% of the capital shares of SF Holding Corp. and may be deemed to have beneficial ownership of the common shares beneficially owned by Stephens-NACG LLC.

B.	RELATED PARTY TRANSACTIONS

Advisory Services Agreement

Pursuant to an agreement, dated November 21, 2003, among The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc., and SF Holding Corp., referred to in the agreement as the “sponsors,” and NACG Holdings Inc. and its subsidiaries, including us, 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 or 0.5% of our EBITDA for the previous twelve month period ended March 31. The agreement also provides that we will indemnify the sponsors against liabilities relating to their services and will reimburse the sponsors for their expenses in connection with their services.

In addition, the agreement provides that if we or any of our subsidiaries determines within ten years of the date of the closing of the Acquisition 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, reimbursement of 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, reimbursement of any expenses or fees incurred by any sponsor in connection therewith. Actual amounts payable for these services are limited by the terms of our 9% senior secured notes. The terms of the agreement are similar to what would have been obtained from an unaffiliated third party.

The advisory services agreement will be terminated upon the completion of a proposed public offering of common shares of NACG Holdings Inc.

Office Leases

We are party to lease agreements with Acheson Properties Ltd., a company owned, indirectly and in part, by Martin Gouin, one of our directors. Mr. Gouin has a 50% beneficial interest in Acheson Properties Ltd. Pursuant to the agreements, we lease our corporate headquarters in Acheson, Alberta, and our offices in Fort Nelson, British Columbia and Regina, Saskatchewan. See “Business — Properties and Facilities.” For the fiscal years ended March 31, 2005 and 2006, we paid $823,827 and $836,484, respectively, pursuant to these leases. The lease agreements were in place before the Acquisition in November 2003. The terms of the agreement are similar to what would have been obtained from an unaffiliated third party.

Voting and Corporate Governance Agreement

NACG Holdings Inc. is party to a voting agreement, dated November 26, 2003, with affiliates of the sponsors 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 our November 2003 offering of common shares, such shareholder may designate one nominee for election to our board of directors. In addition, as long as Sterling Group Partners I, L.P. 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 nominee for election to our board of directors. Each shareholder party to the agreement agrees to vote the common shares held by it for each of the designated director nominees. The shareholder parties to the agreement have also agreed to vote their common shares in favor of the election to the board of directors 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. Messrs. Hawkins and Oehmig are the director designees of The Sterling Group. Mr. Paterson is the director designee of Genstar Capital. Mr. Brokaw is the director designee of Perry Strategic Capital. Mr. Turner is the director designee of SF Holding Corp.

Permitted Transactions

The voting agreement provides that each shareholder party to the agreement will not, and will not permit any of its affiliates to, enter into, renew, extend or be a party to any transaction or series of transactions with us or any of our 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;

•

the grant of share options or similar rights to employees and directors pursuant to plans approved by the board of directors;

•

loans or advances to executive officers approved by the board of directors;

•

the payment of reasonable fees to our directors and the directors of our subsidiaries who are not our employees or employees of our subsidiaries in their capacities as board members or members of committees of the board as may be approved by the board;

•

any transaction between our subsidiaries; and

•

the registration rights agreement, the shareholders agreement and the advisory services agreement, all described in this “Related Party Transactions” section.

Termination

The voting agreement will terminate upon the completion of a proposed public offering of common shares of NACG Holdings Inc. However, so long as a designated affiliate of each sponsor holds our shares, it will retain the right at its expense

•

to obtain copies of all documents, reports, financial data and other information regarding us,

•

to consult with and advise our management on matters relating to our operations,

•

to discuss our Company’s affairs, finances and accounts with our officers, directors and outside accountants, and

•

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

all upon reasonable notice and at such reasonable times during normal business hours as may be requested.

In addition, so long as a designated affiliate of a sponsor owns 10% of the shares that it initially purchased in the November 2003 offering of common shares of NACG Holdings Inc., at its request we will deliver to such affiliate all financial information (1) distributed to members of our board of directors and (2) provided pursuant to any senior secured loan agreement or indenture to which we or a subsidiary are a party.

So long as a designated affiliate of Genstar Capital Partners III, L.P. owns any shares of NACG Holdings Inc., it will have the right to receive all information sent to the board of directors of NACG Holdings Inc. and to have a representative attend all board meetings in a nonvoting observer status.

All the foregoing rights will be subject to customary confidentiality requirements subject to security clearance requirements imposed by applicable government authorities.

Shareholders Agreements

All holders of common shares of NACG Holdings Inc. who are also our employees or employees of any of our subsidiaries are parties to an employee shareholders agreement. All other holders of common shares of NACG Holdings Inc. are parties to an investor shareholders agreement. Both shareholders agreements will be terminated upon the completion of a proposed public offering of common shares of NACG Holdings Inc.

Registration Rights Agreement

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

NACG Holdings Inc. may opt to delay the filing of a registration statement required pursuant to any demand registration for:

•

up to 120 days if NACG Holdings Inc. has

•

decided to file a registration statement for an underwritten public offering of its common equity securities, the net proceeds of which are expected to be at least US$20.0 million, or

•

initiated discussions with underwriters in preparation for a public offering of its common equity securities as to which NACG Holdings Inc. expects to receive net proceeds of at least US$20.0 million and the demand registration, in the underwriters’ opinion, would have a material adverse effect on the offering or

•

up to 90 days following a request for a demand registration if NACG Holdings Inc. is in possession of material information that it reasonably deems advisable not to disclose in a registration statement.

NACG Holdings Inc.’s right to delay the filing of a registration statement if it possesses information that it deems advisable not to disclose does not obviate any disclosure obligations which NACG Holdings Inc. may have under the Exchange Act or other applicable laws; it merely permits NACG Holdings Inc. to avoid filing a registration statement if its

management believes that such a filing would require the disclosure of information which otherwise is not required to be disclosed and the disclosure of which its management believes is premature or otherwise inadvisable.

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

Series B Preferred Shares

The Series B preferred shares were initially issued for cash proceeds of $7.5 million on May 19, 2005 to existing common shareholders of NACG Holdings Inc., including the equity sponsors. On June 15, 2005, the Series B preferred shares were split 10-for-1. We subsequently offered and sold $0.9 million of Series B preferred shares to certain existing common shareholders of NACG Holdings Inc. and used the proceeds from this subsequent sale to repurchase a like amount of Series B preferred shares from the equity sponsors. All such Series B preferred shares were issued or repurchased as the case may be, at a price of $100 per share. For additional information on the Series B preferred shares, refer to note 14(a) in our consolidated financial statements included at Item 17.

Recent Sales of Securities to Related Parties

In March 2006, one of our directors was issued 1,000 common shares and 81 Series B preferred shares. In December 2005, three of our officers were issued an aggregate of 2,000 common shares and an aggregate of 163 Series B preferred shares. All such common shares were issued at $100 per share and all such Series B preferred shares were issued at $100 per share.

C.	INTERESTS OF EXPERTS AND COUNSEL

Not applicable.

ITEM 8:

FINANCIAL INFORMATION

A.	CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION

See Item 17 “Financial Statements.”

Legal Proceedings

In February 2005, Renée Gouin and Elaine Busch commenced a claim against their brothers, Martin Gouin and Roger Gouin, their father, Jean Yvon Gouin, and a number of companies, including our subsidiary, North American Construction Group Inc. The plaintiffs allege that they maintain beneficial ownership interests in the Gouin “family business.” The assets of certain of those business were sold to us in the Acquisition. The plaintiffs further allege that the proceeds of such ownership interests, including cash and preferred shares of NACG Preferred Corp., our immediate parent corporation, are being wrongfully held by the Gouin brothers and that certain management fees paid by North American Construction Group Inc. to the corporate shareholder of our predecessor company, Norama Ltd., were excessive. The plaintiffs seek, among other things: damages in the amount of $57.8 million each; a declaration that they hold a beneficial interest in the “family business;” a constructive trust over the “family business;” an accounting and tracing of the sale proceeds, assets and shares; and rectification of share registers.

Pursuant to the purchase agreement relating to the Acquisition, Martin Gouin, Roger Gouin, Norama Ltd., and North American Equipment Ltd. have agreed to indemnify North American Construction Group Inc. We have notified Martin Gouin, Roger Gouin, Norama Ltd., and North American Equipment Ltd. that we are seeking indemnity from them under the purchase agreement for the cost of our defense and any damages arising out of the lawsuit. We have taken the position that North American Construction Group Inc. is not a properly named defendant in the lawsuit. Discoveries are ongoing and we will continue to assess our position as the matter proceeds.

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

B.	SIGNIFICANT CHANGES

Not applicable.

ITEM 9:

THE OFFER AND LISTING

A.	OFFER AND LISTING DETAILS

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

B.	PLAN OF DISTRIBUTION

Not applicable.

C.	MARKETS

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

D.	SELLING SHAREHOLDERS

Not applicable.

E.	DILUTION

Not applicable.

F.	EXPENSES OF THE ISSUE

Not applicable.

ITEM 10:

ADDITIONAL INFORMATION

A.	SHARE CAPITAL

Not applicable.

B.	MEMORANDUM AND ARTICLES OF ASSOCIATION

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

C.	MATERIAL CONTRACTS

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

D.	EXCHANGE CONTROLS

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

E.	TAXATION

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

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

F.	DIVIDENDS AND PAYING AGENTS

Not applicable.

G.	STATEMENTS BY EXPERTS

Not applicable.

H.	DOCUMENTS ON DISPLAY

We are required by the terms of the indentures governing the 8³/4% senior notes and the 9% senior secured notes to file reports and other information with the SEC. These reports and other information are or will be available after filing for reading and copying at the SEC Public Reference Room at Room 1580, 100 F Street NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the Public Reference Room and the SEC’s copying charges. The SEC also maintains an Internet site at http://www.sec.gov that contains the reports and other information that we file electronically with the SEC. As a foreign private issuer, however, we are exempt from the rule under the Securities Exchange Act of 1934, as amended, prescribing the furnishing and content of proxy statements to shareholders. Because we are a foreign private issuer, we, our directors and our officers are also exempt from the short swing profit recovery provisions of Section 16 of the Exchange Act.

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

In the event we are no longer required to file reports with the SEC, we may discontinue filing them with the SEC at any time. During the period in which we are not a reporting issuer under the Exchange Act, we have agreed that, for so long as any notes remain outstanding and are “restricted securities” within the meaning of Rule 144 under the Securities Act, we will furnish to the holders of such notes and prospective purchasers of such notes, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act. Any such request should be directed to North American Energy Partners Inc., Vice President, Corporate, Zone 3, Acheson Industrial Area, 2 – 53106 Highway 60, Acheson, Alberta, T7X 5A7. Our telephone number is (780) 960-7171.

I.	SUBSIDIARY INFORMATION

Not applicable.

ITEM 11:

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Foreign currency risk

We are subject to currency exchange risk as our 8³/4% senior notes and 9% senior secured notes are denominated in U.S. dollars and all of our revenues and most of our expenses are denominated in Canadian dollars. We have entered into cross currency swap and interest rate swap agreements to manage the foreign currency risk on the 8³/4% senior notes. The hedging instrument consists of three components: a U.S. dollar interest rate swap; a U.S. dollar-Canadian dollar cross-currency basis swap; and a Canadian dollar interest rate swap that results in us mitigating our exposure to the variability of cash flows caused by currency fluctuations relating to the US$200 million senior notes. The hedges can be cancelled at the counterparty’s option at any time after December 1, 2007 if the counterparty pays a cancellation premium. The premium is equal to 4.375% of the US$200 million if exercised between December 1, 2007 and December 1, 2008; 2.1875% if exercised between December 1, 2008 and December 1, 2009; and 0.000% if cancelled after December 1, 2009. We have not hedged the foreign currency risk on the 9% senior secured notes. Each $0.01 increase or decrease in the U.S. dollar-Canadian dollar exchange rate would change the interest cost on the 9% senior secured notes by $0.05 million per year.

Interest rate risk

We are subject to interest rate risk in connection with our revolving credit facility. The facility bears interest at variable rates based on the Canadian prime rate plus 2% or Canadian bankers’ acceptance rate plus 3%. Assuming our then-existing revolving credit facility was fully drawn at $40 million, excluding the $18 million of outstanding letters of credit at March 31, 2006, each 1.0% increase or decrease in the applicable interest rate would have changed the interest cost by $0.4 million per year. In the future, we may enter into interest rate swaps involving the exchange of floating for fixed rate interest payments to reduce interest rate volatility.

We also lease equipment with a variable lease payment tied to prime rates. At March 31, 2006, for each 1.0% annual fluctuation in this rate, annual lease expense will change by $0.2 million.

Inflation

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

ITEM 12:

DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

Not applicable.

PART II

ITEM 13:

DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None.

ITEM 14:

MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

None.

ITEM 15:

CONTROLS AND PROCEDURES

As of March 31, 2006, our management, including our President and Vice President, Finance, has evaluated the effectiveness of the design and operations of our disclosure controls and procedures in accordance with Rule 15d-15 under the Securities Exchange Act of 1934. Based upon and as of the date of the evaluation, our President and Vice

President, Finance concluded that while there are certain internal control deficiencies, there are compensating controls in place to provide assurance that the design of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported as and when required. Management is redesigning those internal controls to improve the overall efficiency of our overall internal control framework.

We have had continuing problems providing accurate and timely financial information and reports and have restated our financial statements three times since the beginning of our 2005 fiscal year. In April of 2005, we had to restate our first and second quarters of fiscal 2005 to properly account for costs incurred in those quarters. During fiscal 2006, we had to restate our financial statements for each period after November 26, 2003 to eliminate the impact of hedge accounting with respect to the derivative financial instruments. We also had to restate our financial statements for the first quarter of fiscal 2006 to correct the accounting for various aspects of the refinancing transactions which occurred in May 2005. Each of these restatements resulted in our inability to file our financial statements within the deadlines imposed by covenants in the indentures governing our 8³/4% senior notes and 9% senior secured notes. In each case, we filed our financial statements before the matter developed into an Event of Default under the indentures.

In connection with the audit of our fiscal 2006 financial statements, we identified a number of significant weaknesses (as defined under Canadian auditing standards) in our financial reporting processes and internal controls. A weakness in internal control is significant if the deficiency is such that a material misstatement is not likely to be prevented or detected in the consolidated financial statements being audited. We noted that sufficient documentation to support the recognition of claims revenue was not available on a timely basis during the course of the audit. Also, management’s preparation and analysis of forecast estimates to complete were prepared that differed materially from actual results. Our contract estimating, field reporting, accounting records, committed costs and management reporting were not sufficiently integrated to ensure that the data generated in the accounting records was useful for management’s evaluation of contract progress. Finally, we noted that formal contracts were not always obtained for construction projects and service arrangements. Failure to obtain formally executed contracts increases the risk of disputes regarding the terms of the agreements and/or whether the services have been rendered as agreed. We are currently addressing these deficiencies through the implementation of the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and Multilateral Instrument 52-109 in Canada in connection with the proposed offering of our parent, NACG Holdings Inc. and with a focused effort on the high risk areas. For example, we started a procurement project in the spring of 2005 to implement the purchase order functionality in our financial systems and to train our staff in the effective use of purchase orders to track our commitments and to record our expenses in a timely manner. We also added to our finance staff, and in particular we now have in-house GAAP and financial reporting expertise.

As noted above, in the spring of 2005 we commenced the above changes to our financial reporting processes and internal controls. The changes have not yet been fully implemented; however, once implemented, we anticipate that the changes are reasonably likely to materially affect our internal control over financial reporting.

The term “internal control over financial reporting” is defined as a process designed by, or under the supervision of, the registrant’s principal executive and principal financial officers, or persons performing similar functions, and effected by the registrant’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:

(1)

Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the registrant;

(2)

Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the registrant are being made only in accordance with authorizations of management and directors of the registrant; and

(3)

Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the registrant’s assets that could have a material effect on the financial statements.

The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that are filed under the Exchange Act is recorded, processed, summarized and reported within required time periods. Disclosure controls and procedures are also designed to ensure that the information is accumulated and communicated to our management, including our chief executive officer and Vice President, Finance, to allow timely decisions regarding required disclosure. Disclosure controls and procedures can provide only reasonable, rather than absolute, assurance of achieving the desired control objectives.

ITEM 16:

[RESERVED]

ITEM 16A.

AUDIT COMMITTEE FINANCIAL EXPERT

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

ITEM 16B.

CODE OF ETHICS

Our board of directors has adopted a code of ethics that applies to all employees including our President and Vice President, Finance. Our code of ethics is filed as Exhibit 11.1.

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, 2006.

Audit Fees

KPMG billed NAEPI $2,484,000 in 2006 and $1,330,000 in 2005 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.

Audit Related Fees

KPMG billed NAEPI $62,000 in 2006 and $31,000 in 2005 for planning and scoping work completed around internal controls over financial reporting.

Tax Fees

KPMG billed NAEPI $15,000 in 2006 and $25,000 in 2005 for tax compliance.

All Other Fees

None.

ITEM 16D.

EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

Not applicable.

ITEM 16E.

PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

Not applicable.

ITEM 17.

FINANCIAL STATEMENTS

The Auditors’ Report and Financial Statements for the Company are attached hereto as itemized under Item 19(a) and are incorporated herein by reference. Such Financial Statements have been prepared on the basis of Canadian GAAP. A reconciliation to U.S. GAAP appears in Note 24 thereto.

ITEM 18.

FINANCIAL STATEMENTS

Not applicable.

ITEM 19.

EXHIBITS

(a)	Financial Statements

(i)

Auditors’ Reports.

(ii)

Balance Sheets as at March 31, 2005 and 2006.

(iii)

Statements of Operations for the periods April 1, 2003 to November 25, 2003 and November 26, 2003 to March 31, 2004, and the years ended March 31, 2005 and 2006.

(iv)

Statements of Cash Flows for the periods April 1, 2003 to November 25, 2003 and November 26, 2003 to March 31, 2004, and the years ended March 31, 2005 and 2006.

(v)

Notes to the Financial Statements.

(vi)

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

(b)

Exhibits



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

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

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

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

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

4.1		– First Amended and Restated Credit Agreement, dated as of July 19, 2006, among North American Energy Partners Inc., the lenders named therein and BNP Paribas (Canada), as Administrative Agent and Collateral Agent (filed as Exhibit 10.1 to NACG Holdings Inc.’s registration statement on Form F-1, Registration No. 333-135943, and incorporated herein by reference).

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


4.3		– Form of Indemnity Agreement between NACG Holdings Inc., NACG Preferred Corp., North American Energy Partners Inc., North American Construction Group Inc., and their respective officers and directors (filed as Exhibit 10.3 to the 2005 Registration Statement and incorporated herein by reference).

7.1	*	– Computation of Ratio of Earnings to Fixed Charges.

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

11.1	*	– Code of Business Conduct and Ethics.

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

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

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

*	Previously filed.

SIGNATURE

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


	NORTH AMERICAN ENERGY PARTNERS INC.

Date: November 2, 2006	By:	/s/ Douglas A. Wilkes
	Name:	Douglas A. Wilkes
	Title:	Vice President, Finance and Chief Financial Officer

LOGO

REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

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

We have audited the consolidated balance sheets of North American Energy Partners Inc. as at March 31, 2006 and 2005 and the consolidated statements of operations and retained earnings (deficit) and cash flows of North American Energy Partners Inc. for the years ended March 31, 2006 and 2005, the period from November 26, 2003 to March 31, 2004 and of Norama Ltd. (the “Predecessor Company”) for the period from April 1, 2003 to November 25, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, these consolidated financial statements referred to above present fairly, in all material respects, the financial position of North American Energy Partners Inc. as of March 31, 2006 and 2005 and the results of its operations and its cash flows for the years ended March 31, 2006 and 2005, the period from November 26, 2003 to March 31, 2004, and of the Predecessor Company for the period April 1, 2003 to November 25, 2003 in accordance with Canadian generally accepted accounting principles.

As discussed in Note 2(c) and 2 (p) to the consolidated financial statements, the Company changed its accounting policy with respect to the recognition of revenue on claims and has adopted new accounting pronouncements related to the accounting by a customer (including a reseller) for certain consideration received from a vendor, the accounting for convertible debt instruments, the accounting for non-monetary transactions, the accounting for implicit variable interests and the accounting for conditional asset retirement obligations in 2006.

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 24 to the consolidated financial statements.

LOGO

Chartered Accountants

Edmonton, Canada

June 29, 2006, except as to notes 11(c), 24, and 25, which are as of August 29, 2006

LOGO

AUDITORS’ REPORT TO THE SHAREHOLDERS

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

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of North American Energy Partners Inc. as of March 31, 2006 and 2005 and the results of operations and cash flows of North American Energy Partners Inc. for the years ended March 31, 2006 and 2005, the period from November 26, 2003 to March 31, 2004, and of the Predecessor Company for the period April 1, 2003 to November 25, 2003 in accordance with Canadian generally accepted accounting principles.

LOGO

Chartered Accountants

Edmonton, Canada

June 29, 2006, except as to notes 11(c), 24, and 25, which are as of August 29, 2006

LOGO

NORTH AMERICAN ENERGY PARTNERS INC.

Consolidated Financial Statements

For the year ended March 31, 2006, March 31, 2005, the period from November 26, 2003 to March 31, 2004 and the period from April 1, 2003 to November 25, 2003 of Norama Ltd. (the “Predecessor Company”)

(Expressed in thousands of Canadian dollars)

NORTH AMERICAN ENERGY PARTNERS INC.

Consolidated Balance Sheets

(in thousands of Canadian dollars)


	March 31, 2006			March 31, 2005
Assets
Current assets:
Cash and cash equivalents	$	42,704		$	17,922
Accounts receivable (note 4)		67,235			57,745
Unbilled revenue (note 5)		43,494			41,411
Inventory		57			134
Prepaid expenses		1,796			1,862
Future income taxes (note 13)		5,583			15,100

		160,869			134,174
Future income taxes (note 13)		23,367			13,485
Plant and equipment (note 6)		185,566			177,089
Goodwill (note 3)		198,549			198,549
Intangible assets, net of accumulated amortization of $17,026 (March 31, 2005 - $16,296) (note 7)		772			1,502
Deferred financing costs, net of accumulated amortization of $6,004 (March 31, 2005 - $3,368) (note 8)		17,788			15,354

	$	586,911		$	540,153

Liabilities and Shareholder’s Equity
Current liabilities:
Accounts payable	$	54,088		$	59,090
Accrued liabilities (note 9)		24,603			15,201
Billings in excess of costs incurred and estimated earnings on uncompleted contracts (note 5)		5,124			1,325
Current portion of capital lease obligations (note 10)		3,046			1,771
Advances from parent company (note 12)		482			288
Future income taxes (note 13)		5,583			15,100

		92,926			92,775
Senior secured credit facility (note 11(a))		—			61,257
Capital lease obligations (note 10)		7,906			5,454
Senior notes (note 11(b))		304,007			241,920
Derivative financial instruments (note 19(c))		63,611			51,723
Redeemable preferred shares (note 14(a))		42,568			—
Future income taxes (note 13)		23,367			13,485

		534,385			466,614

Shareholders’ equity:
Common shares (authorized – unlimited number of voting common shares; issued and outstanding – March 31, 2006 and 2005 – 100 voting common shares) (note 14(b))		127,500			127,500
Contributed surplus (notes 14(c) and 22)		1,557			634
Deficit		(76,531	)		(54,595	)

		52,526			73,539

Commitments (note 20)
United States generally accepted accounting principles (note 24)
Subsequent events (note 25)

	$	586,911		$	540,153

See accompanying notes to consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

Consolidated Statements of Operations and Deficit

(in thousands of Canadian dollars)


										Predecessor Company
	Year ended March 31, 2006			Year ended March 31, 2005			Period from November 26, 2003 to March 31, 2004			Period from April 1, 2003 to November 25, 2003
Revenue	$	492,237		$	357,323		$	127,611		$	250,652

Project costs		308,949			240,919			83,256			156,976
Equipment costs		64,832			52,831			13,686			43,484
Equipment operating lease expense		16,405			6,645			1,430			10,502
Depreciation		21,725			20,762			6,674			6,566

		411,911			321,157			105,046			217,528

Gross profit		80,326			36,166			22,565			33,124
General and administrative (note 18(b))		30,898			22,863			6,065			7,783
(Gain) loss on disposal of property, plant and equipment		(733	)		494			131			(49	)
Amortization of intangible assets		730			3,368			12,928			—

Operating income before the undernoted		49,431			9,441			3,441			25,390

Interest expense (note 15)		68,776			31,141			10,079			2,457
Foreign exchange gain (note 19(c))		(13,953	)		(19,815	)		(661	)		(7	)
Realized and unrealized loss on derivative financial instruments (note 19(c))		14,689			43,113			12,205			—
Financing costs (note 8)		2,095			—			—			—
Other income		(977	)		(421	)		(230	)		(367	)
Management fees (note 18(c))		—			—			—			41,070

		70,630			54,018			21,393			43,153

Loss before income taxes		(21,199	)		(44,577	)		(17,952	)		(17,763	)
Income taxes (note 13):
Current income taxes		737			2,711			1,178			218
Future income taxes		—			(4,975	)		(6,848	)		(6,840	)

		737			(2,264	)		(5,670	)		(6,622	)

Net loss for the period		(21,936	)		(42,313	)		(12,282	)		(11,141	)
Retained earnings (deficit), beginning of period		(54,595	)		(12,282	)		—			29,817

Retained earnings (deficit), end of period	$	(76,531	)	$	(54,595	)	$	(12,282	)	$	18,676

See accompanying notes to consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

Consolidated Statements of Cash Flows

(in thousands of Canadian dollars)


										Predecessor Company
	Year ended March 31, 2006			Year ended March 31, 2005			Period from November 26, 2003 to March 31, 2004			Period from April 1, 2003 to November 25, 2003
Cash provided by (used in):
Operating activities:
Net loss for the period	$	(21,936	)	$	(42,313	)	$	(12,282	)	$	(11,141	)
Items not affecting cash:
Depreciation		21,725			20,762			6,674			6,566
Amortization of intangible assets		730			3,368			12,928			—
Amortization of deferred financing costs		3,338			2,554			814			—
Financing costs (note 8)		2,095			—			—
(Gain) loss on disposal of plant and equipment		(733	)		494			131			(49	)
Unrealized foreign exchange gain on senior notes (note 19(c))		(14,258	)		(20,340	)		(740	)		—
Unrealized loss on derivative financial instruments (note 19(c))		11,888			40,457			11,266			—
(Decrease) increase in allowance for doubtful accounts		(94	)		(69	)		(60	)		141
Stock-based compensation expense (note 22)		923			497			137			—
Change in redemption value and accretion of redeemable preferred shares		34,722			—			—			—
Future income taxes		—			(4,975	)		(6,848	)		(6,840	)
Net changes in non-cash working capital (note 16(b))		(4,528	)		(5,258	)		3,457			13,832

		33,872			(4,823	)		15,477			2,509

Investing activities:
Purchase of plant and equipment		(29,015	)		(25,679	)		(2,501	)		(5,234	)
Net changes in non-cash working capital (note 16(b))		1,391			—			—			—
Proceeds on disposal of plant and equipment		5,456			624			5,765			609
Acquisition (note 3)		—			—			(367,778	)		—

		(22,168	)		(25,055	)		(364,514	)		(4,625	)

Financing activities:
Issuance of 9% senior secured notes (note 11(b))		76,345			—			—			—
Repayment of senior secured credit facility (note 11(a))		(61,257	)		(7,250	)		(1,500	)		(4,428	)
Issuance of Series B preferred shares (note 14(a))		8,376			—			—			—
Repurchase of Series B preferred shares (note 14(a))		(851	)		—			—			—
Financing costs (note 8)		(7,546	)		(642	)		(18,080	)		—
Repayment of capital lease obligations		(2,183	)		(1,198	)		(288	)		(3,289	)
Advances from parent company		194			288			—			—
Increase in senior secured credit facility		—			20,007			—			—
Issuance of 8³/4% senior notes		—			—			263,000			—
Issuance of common shares		—			—			92,500			—
Proceeds from term credit facility		—			—			50,000			—
Advances from Norama Inc.		—			—			—			17,696
Decrease in cheques issued in excess of cash deposits		—			—			—			(2,496	)
Decrease in operating line of credit		—			—			—			(516	)

		13,078			11,205			385,632			6,967

Increase (decrease) in cash and cash equivalents		24,782			(18,673	)		36,595			4,851
Cash and cash equivalents, beginning of period		17,922			36,595			—			—

Cash and cash equivalents, end of period	$	42,704		$	17,922		$	36,595		$	4,851

See accompanying notes to consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Consolidated Financial Statements

(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

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 give rise to measurement differences to the consolidated financial statements under United States GAAP are outlined in note 24.

These consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, NACG Finance LLC and North American Construction Group Inc. (“NACGI”), the Company’s joint venture, Noramac Ventures Inc. (note 16(c)), and the following subsidiaries of NACGI:


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

In preparation for the acquisition described in Note 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

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

statements for periods ended before November 26, 2003 are not comparable in all respects to the consolidated financial statements for periods ended after November 25, 2003.

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

Use of estimates:

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

Significant estimates made by management include the assessment of the percentage of completion on unit-price or lump-sum contracts (including estimated total costs and provisions for estimated losses) and the recognition of claims and change orders on contracts, assumptions used to value derivative financial instruments, assumptions used to determine redemption value of redeemable securities, assumptions used in periodic impairment testing, and estimates and assumptions used in the determination of the allowance for doubtful accounts. Actual results could differ materially from those estimates.

Revenue recognition:

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

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

Effective April 1, 2005, the Company changed its accounting policy regarding the recognition of revenue on claims. This change in accounting policy has been applied retroactively. Once contract performance is underway, the Company will often experience changes in conditions, client requirements, specifications, designs, materials and work schedule. Generally, a “change order” will be negotiated with the customer to modify the original contract to approve both the scope and price of the change. Occasionally, however, disagreements arise regarding changes, their nature, measurement, timing and other characteristics that impact costs and revenue under the contract. When a change

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

becomes a point of dispute between the Company and a customer, the Company will then consider it as a claim.

Prior to April 1, 2005, revenue from claims was included in total estimated contract revenue when awarded or received. After April 1, 2005, claims are included in total estimated contract revenue, only to the extent that contract costs related to the claim have been incurred and when it is probable that the claim will result in a bona fide addition to contract value and can be reliably estimated. Those two conditions are satisfied when (1) the contract or other evidence provides a legal basis for the claim or a legal opinion is obtained providing a reasonable basis to support the claim, (2) additional costs incurred were caused by unforeseen circumstances and are not the result of deficiencies in our performance, (3) costs associated with the claim are identifiable and reasonable in view of work performed and (4) evidence supporting the claim is objective and verifiable. No profit is recognized on claims until final settlement occurs. This can lead to a situation where costs are recognized in one period and revenue is recognized when customer agreement is obtained or claim resolution occurs, which can be in subsequent periods. Historical claim recoveries should not be considered indicative of future claim recoveries.

The change in policy resulted in an increase in claims revenue and unbilled revenue of approximately $12,862 for the year ended March 31, 2006, but did not result in any adjustments to prior periods. Substantially all of the amounts recognized as claims revenue have been collected subsequent to year end.

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

Cash and cash equivalents:

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

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.

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.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

Plant and equipment:

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


Asset	Basis	Rate

Heavy equipment	Straight-line	Operating hours

Major component parts in use	Straight-line	Operating hours

Spare component parts	N/A	N/A

Other equipment	Straight-line	10-20%

Licensed motor vehicles	Declining balance	30%

Office and computer equipment	Straight-line	25%

Leasehold improvements	Straight-line	Lease term

Assets under construction	N/A	N/A

The cost of period repairs and maintenance is expensed to the extent that the expenditure serves only to restore the asset to its original condition.

Goodwill:

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

The Company tested goodwill for impairment at December 31, 2005 and determined that there was no impairment in carrying value. The Company conducts its annual assessment of goodwill on December 31 of each year.

Intangible assets:

Intangible assets acquired include: customer contracts in progress and related relationships, which are being amortized based on the net present value of the estimated period cash flows over the remaining lives of the related contracts; trade names, which are being amortized on a straight-line basis over their estimated useful life of 10 years; a non-competition agreement, which is being amortized on a straight-

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

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.

Deferred financing costs:

Costs relating to the issuance of the senior notes and the revolving credit facility have been deferred and are being amortized on a straight-line basis over the term of the related debt. Deferred financing costs related to debt that has been extinguished is written-off in the period of extinguishment.

Impairment of long-lived assets:

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

Foreign currency translation:

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

Derivative financial instruments:

The Company uses derivative financial instruments to manage economic risks from fluctuations in exchange rates and interest rates. These instruments include cross-currency swap agreements and interest rate swap agreements. All such instruments are only used for risk management purposes. 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.

A derivative financial instrument must be designated and effective, at inception and on at least a quarterly basis, to be accounted for as a hedge. For cash flow hedges, effectiveness is achieved if the changes in the cash flows of the derivative financial instrument substantially offset the changes in the cash flows of the hedged position and the timing of the cash flows is similar. Effectiveness for fair value hedges is achieved if changes in the fair value of the derivative financial instrument substantially offset changes in the fair value of the hedged item attributable to the risk being hedged. In the event that a derivative financial instrument does not meet the designation or effectiveness criteria, the derivative financial instrument is accounted for at fair value and realized and unrealized gains and losses on the derivative are recognized in the Consolidated Statement of Operations and Deficit in accordance with the Canadian Institute of Chartered Accountants (“CICA”) Emerging Issues Committee Abstract No. 128, “Accounting for Trading, Speculative or Non-Hedging Derivative Financial Instruments” (“EIC-

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

128”). If a derivative financial instrument that previously qualified for hedge accounting no longer qualifies or is settled or de-designated, the fair value on that date is deferred and recognized when the corresponding hedged transaction is recognized. Premiums paid or received with respect to derivatives that are hedges are deferred and amortized to income over the term of the hedge.

Income taxes:

The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, future income 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 income 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 income tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date of enactment or substantive enactment. A valuation allowance is recorded against any future income tax asset if it is more likely than not that the asset will not be realized.

Stock–based compensation plan:

The Company accounts for all stock-based compensation payments in accordance with a fair value based method of accounting. Under this fair value based method, compensation cost is measured using the Black-Scholes model using an expected volatility assumption of nil (the “minimum value” approach) at the grant date and is expensed over the award’s vesting period, with a corresponding increase to contributed surplus.

Recently adopted Canadian accounting pronouncements:

Hedge relationships:

Effective November 26, 2003, the Company prospectively adopted the provisions of CICA Accounting Guideline 13, “Hedging Relationships” (“AcG-13”), which specifies the circumstances in which hedge accounting is appropriate, including the identification, documentation, designation, and effectiveness of hedges, and the discontinuance of hedge accounting. The Company determined that all of its then existing derivative financial instruments did not qualify for hedge accounting on the adoption of AcG-13.

ii.

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 do not provide guidance. The adoption of this standard did not have a material impact on the consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

iii.

Revenue recognition:

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

iv.

Consolidation of variable interest entities:

Effective January 1, 2005, the Company prospectively adopted the CICA Accounting Guideline 15, “Consolidation of Variable Interest Entities” (“AcG-15”). Variable interest entities (“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 variable interest entity (“VIE”) and who, if anyone, should consolidate the VIE. The Company has determined the joint venture in which it has an investment (note 16(c)) qualifies as a VIE and began consolidating this VIE effective January 1, 2005.

Arrangements containing a lease:

Effective January 1, 2005, the Company adopted the CICA Emerging Issues Committee Abstract No. 150, “Determining Whether an Arrangement Contains a Lease (“EIC-150”). EIC-150 addresses a situation where an entity enters into an arrangement, comprising a transaction that does not take the legal form of a lease but conveys a right to use a tangible asset in return for a payment or series of payments. The implementation of this standard did not have a material impact on the Company’s consolidated financial statements.

vi.

Vendor rebates:

In April 2005, the Company adopted CICA Emerging Issues Committee Abstract No. 144, “Accounting by a Customer (Including a Reseller) for Certain Consideration Received from a Vendor” (“EIC-144”). EIC-144 requires companies to recognize the benefit of non-discretionary rebates for achieving specified cumulative purchasing levels as a reduction of the cost of purchases over the relevant period, provided the rebate is probable and reasonably estimable. Otherwise, the rebates would be recognized as purchasing milestones are achieved. The implementation of this new standard did not have a material impact on the Company’s consolidated financial statements.

vii.

Accounting for convertible debt instruments

In October 2005, the CICA issued Emerging Issues Committee Abstract No. 158 “Accounting for Convertible Debt Instruments” (“EIC-158”) which provides guidance on whether an issuer of certain types of convertible debt instruments should classify the instruments as liabilities or equity and, if a

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

liability, when it should be classified as a current liability. EIC-158 was applicable for convertible debt instruments issued after October 17, 2005. The adoption of this standard did not have an impact on the Company’s consolidated financial statements.

viii.

Non-monetary transactions:

Effective January 1, 2006, the Company adopted the requirements of CICA Handbook Section 3831, “Non-monetary Transactions”. The new standard requires that an asset exchanged or transferred in a non-monetary transaction must be measured at its fair value except when: the transaction lacks commercial substance; the transaction is an exchange of production or property held for sale in the ordinary course of business for production or property to be sold in the same line of business to facilitate sales to customers other than the parties to the exchange; neither the fair value of the assets or services received nor the fair value of the assets or services given up is reliably measurable; or the transaction is a non-monetary, non-reciprocal transfer to owners that represents a spin-off or other form of restructuring or liquidation. In these cases, the transaction must be measured at carrying value. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

ix.

Implicit variable interests under AcG-15:

Effective January 1, 2006, the Company adopted the CICA Emerging Issues Committee Abstract No. 157, “Implicit Variable Interests Under AcG-15” (“EIC-157”). EIC-157 requires a company to assess whether it has an implicit variable interest in a VIE or potential VIE when specific conditions exist. An implicit variable interest acts the same as an explicit variable interest except it involves the absorbing and/or receiving of variability indirectly from the entity (rather than directly). The identification of an implicit variable interest is a matter of judgment that depends on the relevant facts and circumstances. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

Conditional asset retirement obligations:

In November 2005, the CICA issued Emerging Issues Committee Abstract No. 159, “Conditional Asset Retirement Obligations” (“EIC-159”) to clarify the accounting treatment for a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Under EIC-159, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the obligation can be reasonably estimated. The guidance is effective April 1, 2006 although earlier adoption is permitted and is to be applied retroactively, with restatement of prior periods. The Company adopted this standard in fiscal 2006 and the adoption did not have a material impact on the Company’s consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

Recent Canadian accounting pronouncements not yet adopted:

Financial instruments:

In January 2005, the CICA issued Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, Handbook Section 1530, “Comprehensive Income”, and Handbook Section 3865, “Hedges”. The new standards are effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2006, specifically April 1, 2007 for the Company. Earlier adoption is permitted. The new standards will require presentation of a separate statement of comprehensive income under specific circumstances. Foreign exchange gains and losses on the translation of the financial statements of self-sustaining subsidiaries previously recorded in a separate section of shareholder’s equity will be presented in comprehensive income. Derivative financial instruments will be recorded in the balance sheet at fair value and the changes in fair value of derivatives designated as cash flow hedges will be reported in comprehensive income. The Company is currently assessing the impact of the new standards.

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 the Predecessor Company all of the outstanding common shares of NACGI. The Predecessor Company sold 30 shares of NACGI to NACG Preferred Corp. in exchange for $35.0 million of NACG Preferred Corp.’s Series A preferred shares. NACG Preferred Corp. then contributed the 30 shares of NACGI to the Company in exchange for common shares. The Company then contributed the 30 shares of NACGI to Acquisition in exchange for common shares. The Predecessor Company sold the remaining 170 shares of NACGI to Acquisition in exchange for approximately $195.5 million in cash including the impact of various post-closing adjustments. In addition, Acquisition acquired substantially all of the property, plant and equipment, prepaid expenses and accounts payable of NAEL for $175.0 million in cash. Acquisition and NACGI amalgamated on the same day and the successor company continued as NACGI.

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

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

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


Current assets, including cash of $19,642	$	83,910
Property, plant and equipment, including capital leases of $2,131		176,779
Intangible assets		17,798
Goodwill		198,549

Total assets acquired		477,036

Current liabilities		(40,662	)
Future income taxes		(11,823	)
Capital lease obligations		(2,131	)

Total liabilities assumed		(54,616	)

Net assets acquired	$	422,420

The acquisition was financed as follows:


Proceeds from issuance of 8³/4 senior notes	$	263,000
Proceeds from issuance of share capital		127,500
Proceeds from initial borrowing under the new:
Term credit facility		50,000
Revolving credit facility		—
Less: deferred financing costs		(18,080	)

	$	422,420

The net cash cost of the acquisition was:


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 deductible for income tax purposes.

Transaction costs of $25,080 were incurred on the acquisition, $7,000 of which were accounted for as increased goodwill and $18,080 of which were recorded as deferred financing costs.

The current assets included $19,642 in cash acquired, of which $15,623 was surplus cash from the financing.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

4.	Accounts receivable


	March 31, 2006			March 31, 2005
Accounts receivable – trade	$	55,666		$	45,379
Accounts receivable – holdbacks		10,748			12,476
Accounts receivable – other		891			54
Allowance for doubtful accounts		(70	)		(164	)

	$	67,235		$	57,745

Accounts receivable – holdbacks represent amounts up to 10% under certain contracts that the customer is contractually entitled to withhold 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.

5.	Costs incurred and estimated earnings net of billings on uncompleted contracts


	March 31, 2006			March 31, 2005
Costs incurred and estimated earnings on uncompleted contracts	$	610,006		$	885,301
Less: billings to date		(571,636	)		(845,215	)

	$	38,370		$	40,086

Costs incurred and estimated earnings net of billings on uncompleted contracts is presented in the consolidated balance sheets under the following captions:


	March 31, 2006			March 31, 2005
Unbilled revenue	$	43,494		$	41,411
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		(5,124	)		(1,325	)

	$	38,370		$	40,086

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

6.	Plant and equipment


March 31, 2006	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	174,042	$	31,347	$	142,695
Major component parts in use		4,922		2,091		2,831
Spare component parts		1,170		—		1,170
Other equipment		13,074		4,186		8,888
Licensed motor vehicles		18,223		8,410		9,813
Office and computer equipment		3,362		1,493		1,869
Leasehold improvements		2,959		247		2,712
Assets under construction		15,588		—		15,588

	$	233,340	$	47,774	$	185,566


March 31, 2005	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	165,296	$	17,966	$	147,330
Major component parts in use		4,659		1,182		3,477
Spare component parts		841		—		841
Other equipment		12,088		2,473		9,615
Licensed motor vehicles		16,043		4,670		11,373
Office and computer equipment		2,088		791		1,297
Assets under construction		3,156		—		3,156

	$	204,171	$	27,082	$	177,089

The above amounts include $14,559 (March 31, 2005 – $8,637) of assets under capital lease and accumulated depreciation of $4,479 (March 31, 2005 – $1,968) related thereto. During the year ended March 31, 2006, additions of property, plant and equipment included $5,910 of assets that were acquired by means of capital leases (year ended March 31, 2005 – $5,385; November 26, 2003 to March 31, 2004 - $1,195; April 1, 2003 to November 25, 2003 - $nil). Depreciation of equipment under capital leases of $2,545 (year ended March 31, 2005 – $1,659; November 26, 2003 to March 31, 2004 - $320; April 1, 2003 to November 25, 2003 - $677) is included in depreciation expense.

7.	Intangible assets


March 31, 2006	Cost		Accumulated amortization		Net book value
Customer contracts in progress and related relationships	$	15,323	$	15,323	$	—
Trade names		350		81		269
Non-competition agreement		100		47		53
Employee arrangements		2,025		1,575		450

	$	17,798	$	17,026	$	772

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)


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

	$	17,798	$	16,296	$	1,502

Amortization of intangible assets of $730 was recorded for the year ended March 31, 2006 (year ended March 31, 2005 – $3,368; November 26, 2003 to March 31, 2004 - $12,928; April 1, 2003 to November 25, 2003 - $nil).

The estimated amortization expense for the next five years is as follows:


For the year ending March 31,
2007	$	505
2008		55
2009		48
2010		35
2011 and thereafter		129

	$	772

8.	Deferred financing costs

For the year ended March 31, 2006, financing costs of $7,546 were incurred in connection with the issuance of the 9% senior secured notes and revolving credit facility and were recorded as deferred financing costs. In addition, financing costs of $321 were incurred in connection with the issuance of the Series A redeemable preferred shares and expensed in the current year.

In connection with the repayment of the senior secured credit facility on May 19, 2005, the Company wrote off deferred financing costs of $1,774 (note 11(a)).

Amortization of deferred financing costs of $3,338 was recorded for the year ended March 31, 2006 (year ended March 31, 2005 - $2,554; November 26, 2003 to March 31, 2004 - $814; April 1, 2003 to November 25, 2003 - $nil).

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

9.	Accrued liabilities


	March 31, 2006		March 31, 2005
Accrued interest payable	$	10,878	$	9,127
Payroll liabilities		7,423		2,283
Income and other taxes payable		1,241		1,679
Liabilities related to equipment leases		5,061		2,112

	$	24,603	$	15,201

10.

Capital lease obligations

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


2007	$	3,766
2008		3,620
2009		2,963
2010		2,090
2011		224

		12,663
Less: amount representing interest – weighted average rate of 6.57%		1,711

Present value of minimum capital lease payments		10,952
Less: current portion		3,046

	$	7,906

11.

Long-term debt

Senior secured credit facility:


	March 31, 2006		March 31, 2005
Revolving credit facility	$	—	$	20,007
Term credit facility		—		41,250

	$	—	$	61,257

The Company refers to the revolving credit facility and the term loan collectively as the “senior secured credit facility.”

On May 19, 2005, the Company repaid its entire indebtedness under the senior secured credit facility using the net proceeds from the issuance of the 9% senior secured notes (note 11(b)) and the Series B redeemable preferred shares (note 14(a)).

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

(b)

Senior notes:


	March 31, 2006		March 31, 2005
8³/4% senior unsecured notes due 2011	$	233,420	$	241,920
9% senior secured notes due 2010		70,587		—

	$	304,007	$	241,920

The 8³/4% senior notes were issued on November 26, 2003 in the amount of US$200 million (Canadian $263 million). These notes mature on December 1, 2011 and bear interest at 8³/4% payable semi-annually on June 1 and December 1 of each year.

The 8³/4% senior notes are unsecured senior obligations and rank equally with all other existing and future unsecured senior debt and senior to any subordinated debt that may be issued by the Company or any of its subsidiaries. The notes are effectively subordinated to all secured debt to the extent of the value of the assets securing such debt.

The 8³/4% 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. At any time, or from time to time, on or before December 1, 2006 the Company may, at its option, use the net cash proceeds of one or more public equity offerings, to redeem up to 35% of the principal amount of the 8³/4% senior notes at a redemption price equal to 108.75% of the principal amount of the 8³/4% senior notes redeemed plus accrued and unpaid interest, if any, to the date of redemption; provided that: at least 65% of the principal amount of 8³/4% senior notes remains outstanding immediately after any such redemption; and the Company makes such redemption within 90 days after the closing of any such public equity offering. If a change of control occurs, the Company will be required to offer to purchase all or a portion of each holder’s 8³/4% senior notes, at a purchase price in cash equal to 101% of the principal amount of notes repurchased plus accrued interest to the date of purchase.

The 9% senior secured notes were issued on May 19, 2005 in the amount of US$60.481 million (Canadian $76.345 million). These notes mature on June 1, 2010 and bear interest at 9% payable semi-annually on June 1 and December 1 of each year.

The 9% senior secured notes are senior secured obligations and rank equally with all other existing and future secured debt and senior to any subordinated debt that may be issued by the Company or any of its subsidiaries. The notes are effectively senior to all existing and future unsecured senior debt including the 8³/4% senior notes and are effectively subordinated to the Company’s swap agreements and new revolving credit facility to the extent of the value of the assets securing such debt.

The 9% senior secured notes are redeemable at the option of the Company, in whole or in part, at any time on or after: June 1, 2008 at 104.50% of the principal amount; June 1, 2009 at 102.25% of the principal amount; June 1, 2010 at 100.00% of the principal amount; plus, in each case, interest accrued to the redemption date. At any time, or from time to time, on or before June 1, 2007 the Company may,

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

at its option, use the net cash proceeds of one or more public equity offerings, to redeem up to 35% of the principal amount of the 9% senior secured notes at a redemption price equal to 109.0% of the principal amount of the 9% senior secured notes redeemed plus accrued and unpaid interest, if any, to the date of redemption; provided that: at least 65% of the principal amount of 9% senior secured notes remains outstanding immediately after any such redemption; and the Company makes such redemption within 90 days after the closing of any such public equity offering. If a change of control occurs, the Company will be required to offer to purchase all or a portion of each holder’s 9% senior secured notes, at a purchase price in cash equal to 101% of the principal amount of notes repurchased plus accrued interest to the date of purchase.

Revolving credit facility:

On May 19, 2005, the Company entered into a revolving credit facility with a syndicate of lenders. The revolving facility provided for borrowings of up to $40.0 million, subject to borrowing base limitations, under which revolving loans may have been made and letters of credit, up to a limit of $30.0 million, may have been issued. The facility bore interest at the Canadian prime rate plus 2% per annum or Canadian bankers’ acceptance stamping fee of 3% per annum. The indebtedness under the revolving credit facility was secured by substantially all of the Company’s assets and those of its subsidiaries, including accounts receivable, inventory and property, plant and equipment, and a pledge of the Company’s capital stock and that of its subsidiaries.

In connection with that revolving credit facility, the Company was required to amend its existing swap agreements to increase the effective rate of interest on its 8³/4% senior notes from 9.765% to 9.889% (note 19(c)) and issue to one of the counterparties to the swap agreements $1.0 million of Series A redeemable preferred shares (note 14(a)).

As of March 31, 2006, the Company had no outstanding borrowings under the revolving credit facility and had issued $18.0 million in letters of credit to support bonding requirements and performance guarantees associated with customer contracts and operating leases. The Company’s borrowing availability under the facility, after taking into account the borrowing base limitations, was $9.3 million at March 31, 2006.

On July 19, 2006, the Company amended and restated the revolving credit facility (note 25).

12.

Advances from parent company

Advances from parent company at March 31, 2006 are non-interest bearing and are payable to the Company’s ultimate parent, NACG Holdings Inc. The advances were transacted in the normal course of operations and were recorded at the exchange amount and on terms as agreed to by the parties. Included in the balance is a $292 non-interest bearing note payable on November 29, 2009.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

13.

Income taxes

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


	Year ended March 31, 2006			Year ended March 31, 2005			Period from November 26, 2003 to March 31, 2004			Predecessor Company
	Year ended March 31, 2006			Year ended March 31, 2005			Period from November 26, 2003 to March 31, 2004			Period from April 1, 2003 to November 25, 2003
Net loss before income taxes	$	(21,199	)	$	(44,577	)	$	(17,952	)	$	(17,763	)
Statutory tax rate		33.62	%		33.62	%		35.20	%		36.60	%

Expected recovery at statutory tax rate	$	(7,127	)	$	(14,987	)	$	(6,319	)	$	(6,501	)
Increase (decrease) related to:
Change in future income tax liability, resulting from substantially enacted change in future statutory income tax rates		—			—			(342	)		(669	)
Change in redemption value and accretion of redeemable preferred shares		11,674			—			—			—
Change in future income tax liability, resulting from valuation allowance		(4,097	)		12,189			—			—
Large corporations tax		716			871			319			137
Other		(429	)		(337	)		672			411

Income tax provision (recovery)	$	737		$	(2,264	)	$	(5,670	)	$	(6,622	)

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

The income tax effects of temporary differences that give rise to future income tax assets and liabilities are as follows:


	March 31, 2006			March 31, 2005
Future income tax assets:
Non-capital losses carried forward	$	22,312		$	30,538
Derivative financial instruments		6,843			8,068
Unrealized foreign exchange on senior notes		2,299			—
Billings in excess of costs on uncompleted contracts		1,723			—
Capital lease obligations		1,631			—

Total future income tax assets		34,808			38,606
Less valuation allowance		(5,858	)		(9,955	)

Net future income tax assets		28,950			28,651

Future income tax liabilities:
Unbilled revenue and uncertified revenue included in accounts receivable		1,970			10,972
Accounts receivable – holdbacks		3,613			4,194
Property, plant and equipment		20,263			12,432
Deferred financing costs		1,038			548
Intangible assets		130			505
Unrealized foreign exchange on senior notes		1,936			—

Total future income tax liabilities		28,950			28,651

Net future income taxes	$	—		$	—

Classified as:


	March 31, 2006			March 31, 2005
Current asset	$	5,583		$	15,100
Long-term asset		23,367			13,485
Current liability		(5,583	)		(15,100	)
Long-term liability		(23,367	)		(13,485	)

	$	—		$	—

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

At March 31, 2006, the Company has non-capital losses for income tax purposes of approximately $66,365 which expire as follows:


2007	$	1
2009		10
2011		312
2012		57,025
2013		9,017

14.

Shares

Redeemable preferred shares:

Issued:


	Number of Shares		Amount
*Series A Preferred Shares*
Outstanding at November 26, 2003	—		$	—
Issued	—			—
Redeemed	—			—

Outstanding at March 31, 2004	—			—
Issued	—			—
Redeemed	—			—

Outstanding at March 31, 2005	—			—
Issued	1,000			321
Accretion	—			54

Outstanding at March 31, 2006	1,000			375


*Series B Preferred Shares*
Outstanding at November 26, 2003	—			—
Issued	—			—
Redeemed	—			—

Outstanding at March 31, 2004	—			—
Issued	—			—
Redeemed	—			—

Outstanding at March 31, 2005	—			—
Issued	83,462			8,376
Repurchased	(8,218	)		(851	)
Change in redemption amount	—			34,668

Outstanding at March 31, 2006	75,244			42,193


*Total Redeemable Preferred Shares*	76,244		$	42,568

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

Series A preferred shares

The Company is authorized to issue an unlimited number of Series A preferred shares. The Series A preferred shares are non-voting and are not entitled to any dividends. The Series A preferred shares are mandatorily redeemable at $1,000 per share on the earlier of (1) December 31, 2011 and (2) an Accelerated Redemption Event, specifically (i) the occurrence of a change of control, or (ii) if there is an initial public offering of common shares, the later of (a) the consummation of the initial public offering or (b) the date on which all of the Company’s 8³/4% senior notes and the Company’s 9% senior secured notes are no longer outstanding. The Company may redeem the Series A preferred shares, in whole or in part, at $1,000 per share at any time.

The Series A preferred shares were issued to one of the counterparties to the Company’s swap agreements on May 19, 2005 in connection with the amendment of the Company’s revolving credit facility. These shares are not entitled to accrue or receive dividends and are required to be redeemed on or before December 31, 2011 for $1.0 million.

The Series A preferred shares were initially recorded at their fair value on the date of issuance, which was estimated to be $321 based on the present value of the required cash flows using the rate implicit at inception. Each reporting period, the Company will accrete the carrying value to the present value of the redemption amount at the balance sheet date and record the accretion as interest expense. For the year ended March 31, 2006, the Company recognized $54 of accretion as interest expense.

ii.

Series B preferred shares

The Company is authorized to issue an unlimited number of Series B preferred shares. The Series B preferred shares are non-voting and are entitled to cumulative dividends at an annual rate of 15% of the issue price of each share. No dividends are payable on common shares or other classes of preferred shares (defined as Junior Shares) unless all cumulative dividends have been paid on the Series B preferred shares and the Company declares a Series B preferred share dividend equal to 25% of the Junior Share dividend (except for dividends paid as part of employee and officer arrangements, intercompany administrative charges of up to $1 million annually and tax sharing arrangements). As long as any Series A preferred shares remain outstanding and subject to the restrictions contained within the 8³/4% senior notes and the 9% senior secured notes, dividends shall not be paid (but shall otherwise accrue) on the Series B preferred shares. Subject to the prior redemption of the Series A preferred shares, the Series B preferred shares are mandatorily redeemable on the earlier of (1) December 31, 2011 and (2) an Accelerated Redemption Event, specifically (i) a change of control or (ii) if there is an initial public offering of common shares, the later of (a) the consummation of the initial public offering or (b) the date on which all of the Company’s 8³/4% senior notes and the Company’s 9% senior secured notes are no longer outstanding. Subject to the restrictive covenants contained within the indenture agreement for the 9% senior secured notes, the indenture agreement for the 8³/4% senior notes and the revolving

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

credit facility agreement, the Company may redeem the Series B preferred shares, in whole or in part, at any time.

The payment of dividends and the redemption of the Series B mandatorily redeemable preferred shares are prohibited by the Company’s revolving credit facility agreement. The payment of dividends and the redemption of the Series B mandatorily redeemable preferred shares is also restricted by the indenture agreements governing the Company’s 9% senior secured notes and 8³/4% senior notes. Cumulative undeclared dividends on the Series B preferred shares amounted to $938 at March 31, 2006.

The Series B preferred shares were issued to existing non-employee shareholders of the Company’s ultimate parent company, NACG Holdings Inc., for cash proceeds of $7.5 million on May 19, 2005. The Series B preferred shares were initially issued to certain non-employee shareholders with the agreement that an offer to purchase these Series B preferred shares would also be extended to other existing shareholders of NACG Holdings Inc. on a pro rata basis to their interest in the common shares. On August 31, 2005, the Company issued 8,218 Series B preferred shares for consideration of $851 to certain shareholders of NACG Holdings Inc. as a result of this offering. On November 1, 2005, the Company repurchased and cancelled 8,218 of the Series B preferred shares held by the original non-employee shareholders for cash consideration of $851.

On June 15, 2005, the Series B preferred shares were split 10-for-1.

Subsequent to initial issuance, an additional 244 Series B preferred shares were issued for cash consideration of $24.

Initially, the redemption price of the Series B preferred shares is an amount equal to the greatest of (i) two times the issue price, less the amount, if any, of dividends previously paid in cash on the Series B preferred shares; (ii) an amount, not to exceed $100 million which, after taking into account any dividends previously paid in cash on such Series B preferred shares, provides the holder with a 40% rate of return, compounded annually, on the issue price from the date of issuance; and (iii) an amount, not to exceed $100 million, which is equal to 25% of the arm’s length fair market value of the common shares without taking into account the Series B preferred shares.

On March 30, 2006, the terms of the Series B preferred shares were amended to eliminate option (iii) from the calculation of the redemption price of the shares.

Prior to the amendment to the terms of the Series B preferred shares on March 30, 2006, the Series B preferred shares were considered mandatorily redeemable and the Company was required to measure the Series B preferred shares at the amount of cash that would be paid under the conditions specified in the contract if settlement occurred at each reporting date prior to the amendment. At March 30, 2006, management estimated the redemption amount to be $42,193. As a result, the Company has recognized the increase in the carrying value of $34,668 as an increase in interest expense for the year ended March 31, 2006.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

Concurrent with the amendment to the Series B preferred shares, the Company entered into a Put/Call Agreement with the holders of the Series B preferred shares and NACG Holdings Inc. The Put/Call Agreement grants to each holder of the Series B preferred shares the right (the “Put/Call Right”) to require NACG Holdings Inc. to exchange each of the holder’s Series B preferred shares for five common shares of NACG Holdings Inc. The Put/Call Right may only be exercised upon delivery by the Company or NACG Holdings Inc. of an “Event Notice”, being either: (i) a redemption or purchase call for the redemption or purchase of the Series B preferred shares in connection with (A) a redemption on December 31, 2011, or (B) an Accelerated Redemption Event; or (ii) a notice in connection with a Liquidation Event (defined as a liquidation, winding-up or dissolution of the Company, whether voluntary or involuntary).

The Put/Call Agreement also grants NACG Holdings Inc. the right to require the holders of the Series B preferred shares to exchange each of their Series B preferred shares for 5 common shares in the capital of NACG Holdings Inc. upon delivery of a call notice to shareholders within five business days of an Event Notice.

Upon exercise of the Put/Call Right whereby NACG Holdings Inc. receives the Series B preferred shares, the Company is required to issue 33 common shares to its parent in exchange for and cancellation of the Series B preferred shares.

As a result of the March 30, 2006 amendment to the terms of Series B preferred shares and the concurrent execution of the Put/Call Agreement, the Company has accounted for the amendment as a related party transaction at carrying amount. No value was ascribed to the equity classified Put/Call Right as it was a related party transaction. The Series B preferred shares will now be accreted from their carrying value of $42.2 million on the date of amendment to their redemption value of $69.6 million on December 31, 2011 through a charge to interest expense using the effective interest method over the period until December 31, 2011.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

Common shares:

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
Issued	—		—
Redeemed	—		—

Outstanding at March 31, 2005	100		127,500
Issued	—		—
Redeemed	—		—

Outstanding at March 31, 2006	100	$	127,500

Contributed surplus:


Balance, November 26, 2003	$	—
Stock-based compensation (note 22)		137

Balance, March 31, 2004		137
Stock-based compensation (note 22)		497

Balance, March 31, 2005		634
Stock-based compensation (note 22)		923

Balance, March 31, 2006	$	1,557

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

15.

Interest expense


	Year ended March 31, 2006		Year ended March 31, 2005		Period from November 26, 2003 to March 31, 2004		*Predecessor* *Company*
	Year ended March 31, 2006		Year ended March 31, 2005		Period from November 26, 2003 to March 31, 2004		Period from April 1, 2003 to November 25, 2003
Interest on senior notes	$	28,838	$	23,189	$	8,096	$	—
Interest on senior secured credit facility		564		3,274		1,089		599
Interest on capital lease obligations		457		230		56		294
Change in redemption value of Series B preferred shares		34,668		—		—		—
Accretion of Series A preferred shares		54		—		—		—
Interest on advances from Norama Inc.		—		—		—		1,468

Interest on long-term debt		64,581		26,693		9,241		2,361
Amortization of deferred financing costs		3,338		2,554		814		—
Other interest		857		1,894		24		96

	$	68,776	$	31,141	$	10,079	$	2,457

16.

Other information

Supplemental cash flow information:


	Year ended March 31, 2006		Year ended March 31, 2005		Period from November 26, 2003 to March 31, 2004		Predecessor Company
	Year ended March 31, 2006		Year ended March 31, 2005		Period from November 26, 2003 to March 31, 2004		Period from April 1, 2003 to November 25, 2003
Cash paid during the period for:
Interest	$	28,978	$	31,398	$	1,736	$	2,431
Income taxes		617		3,588		269		325
Cash received during the period for:
Interest		530		362		177		100
Income taxes		2		—		18		—
Non-cash transactions:
Acquisition of plant and equipment by means of capital leases		5,910		5,385		1,195		—
Issuance of Series A preferred shares		321		—		—		—

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

Net change in non-cash working capital:


	Year ended March 31, 2006			Year ended March 31, 2005			Period from November 26, 2003 to March 31, 2004			Predecessor Company
	Year ended March 31, 2006			Year ended March 31, 2005			Period from November 26, 2003 to March 31, 2004			Period from April 1, 2003 to November 25, 2003
Operating activities:
Accounts receivable	$	(9,396	)	$	(24,029	)	$	19,556		$	3,338
Unbilled revenue		(2,083	)		(13,735	)		(17,528	)		15,289
Inventory		77			1,475			(1,609	)		—
Prepaid expenses		66			(590	)		(295	)		(544	)
Accounts payable		(6,206	)		29,789			(2,839	)		(2,794	)
Accrued liabilities		9,215			507			6,172			(1,457	)
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		3,799			1,325			—			—

	$	(4,528	)	$	(5,258	)	$	3,457		$	13,832

Investing activities:
Accounts payable	$	1,204		$	—		$	—		$	—
Accrued liabilities		187			—			—			—

	$	1,391		$	—		$	—		$	—

Investment in joint venture:

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

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

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

Details of the Company’s proportionate share of the results of operations and cash flows of the joint venture, prior to its consolidation, that are included in the consolidated financial statements are as follows:


	Nine months ended December 31, 2004			Period from November 26, 2003 to March 31, 2004			Predecessor Company
	Nine months ended December 31, 2004			Period from November 26, 2003 to March 31, 2004			Period from April 1, 2003 to November 25, 2003
Revenue	$	7,631		$	4		$	340
Project costs		(8,840	)		21			(308	)
General and administrative		—			(37	)		(5	)

Net income (loss)	$	(1,209	)	$	(12	)	$	27


	Nine months ended December 31, 2004			Period from November 26, 2003 to March 31, 2004			Predecessor Company
	Nine months ended December 31, 2004			Period from November 26, 2003 to March 31, 2004			Period from April 1, 2003 to November 25, 2003
Cash provided by:
Operating activities	$	(4,668	)	$	61		$	(49	)
Investing activities		—			—			—
Financing activities		5,061			(59	)		49

	$	393		$	2		$	—

17.

Segmented information

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.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(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.

Results by business segment::


For the year ended March 31, 2006	Mining and Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	366,721	$	91,434	$	34,082	$	492,237
Depreciation of plant and equipment		10,118		2,543		1,352		14,013
Segment profits		50,730		22,586		8,996		82,312
Segment assets		327,850		84,117		48,804		460,771
Expenditures for segment plant and equipment		25,090		880		82		26,052

For the year ended March 31, 2005	Mining and Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	264,835	$	61,006	$	31,482	$	357,323
Depreciation of plant and equipment		10,308		2,335		218		12,861
Segment profits		11,617		13,319		4,902		29,838
Segment assets		315,740		74,975		48,635		439,350
Expenditures for segment plant and equipment		16,888		202		774		17,864

For the period from November 26, 2003 to March 31, 2004	Mining and Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	53,404	$	9,565	$	64,642	$	127,611
Depreciation of plant and equipment		3,116		465		383		3,964
Segment profits		8,154		2,501		12,892		23,547
Segment assets		264,822		76,896		68,751		410,469
Expenditures for segment plant and equipment		61		30		1,671		1,762

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)



*Predecessor Company* For the period from April 1, 2003 to November 25, 2003	Mining and Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	182,368	$	39,417	$	28,867	$	250,652
Depreciation of plant and equipment		3,590		1,256		158		5,004
Segment profits		17,745		8,330		5,054		31,129
Segment assets		77,906		31,792		15,904		125,602
Expenditures for segment plant and equipment		2,591		417		—		3,008

Reconciliations

Loss before income taxes:


										Predecessor Company
	Year ended March 31, 2006			Year ended March 31, 2005			Period from November 26, 2003 to March 31, 2004			Period from April 1, 2003 to November 25, 2003
Total profit for reportable segments	$	82,312		$	29,838		$	23,547		$	31,129
Unallocated corporate expenses		(102,185	)		(80,209	)		(40,437	)		(41,300	)
Unallocated equipment revenue (costs)		(1,326	)		5,794			(1,062	)		(7,592	)

Loss before income taxes	$	(21,199	)	$	(44,577	)	$	(17,952	)	$	(17,763	)

ii.

Total assets:


	March 31, 2006		March 31, 2005
Total assets for reportable segments	$	460,771	$	439,350
Corporate assets		126,140		100,803

Total assets	$	586,911	$	540,153

The Company’s goodwill was assigned to the Mining and Site Preparation, Piling and Pipeline segments in the amounts of $125,447, $40,349, and $32,753, respectively.

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

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

Customers:

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


							Predecessor Company
	Year ended March 31, 2006		Year ended March 31, 2005		Period from November 26, 2003 to March 31, 2004		Period from April 1, 2003 to November 25, 2003
Customer A	32	%	12	%	—		—
Customer B	16	%	26	%	27	%	64	%
Customer C	10	%	9	%	—		—
Customer D	6	%	10	%	51	%	12	%
Customer E	5	%	8	%	11	%	9	%
Customer F	2	%	11	%	4	%	—

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

18.

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.

Transactions with Sponsors:

The Sterling Group, L.P. (“Sterling”), Genstar Capital, L.P., Perry Strategic Capital Inc., and SF Holding Corp. (formerly Stephens Group, Inc.), (the “Sponsors”), entered into an agreement with NACG Holdings Inc. and certain of its subsidiaries, including the Company, to provide consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. As compensation for these services an advisory fee of $400 for the year ended March 31, 2006 (year ended March 31, 2005 – $400; November 26, 2003 to March 31, 2004 - $133; April 1, 2003 to November 25, 2003 - $nil) is payable to the Sponsors, as a group. Additionally, 7,500 Series B preferred shares were issued to the above Sponsor group in exchange for cash of $7.5 million (see note 14(b)).

Office rent:

Pursuant to several office lease agreements, for the year ended March 31, 2006 the Company paid $836 (year ended March 31, 2005 – $824; November 26, 2003 to March 31, 2004 - $292; April 1, 2003 to November 25, 2003 - $387) to a company owned, indirectly and in part, by a member of its Board of Directors.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

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.

19.

Financial instruments

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

Fair value:

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

The fair value of the senior secured credit facility, senior notes and capital lease obligations (collectively “the debt”) are based on management estimates which are determined by discounting cash flows required under the debt at the interest rate currently estimated to be available for loans with similar terms. Based on these estimates, the fair value of the Company’s senior secured credit facility and capital lease obligations as at March 31, 2006 and March 31, 2005 are not significantly different than their carrying values as they bear interest at floating rates. The market value of the 9% senior secured notes as at March 31, 2006 is $74,646 compared to a carrying value of $70,587. The market value of the 8³/4% notes as at March 31, 2006 is $228,752 (March 31, 2005 - $216,750) compared to a carrying value of $233,420 (March 31, 2005 - $241,920).

Interest rate risk:

The Company is subject to interest rate risk on the revolving credit facility and capital lease obligations. At March 31, 2006, for each 1% annual fluctuation in the interest rate, the annual cost of financing will change by approximately $94 (March 31, 2005 - $635).

The Company also leases equipment with a variable lease payment component that is tied to prime rates. At March 31, 2006, for each 1% annual fluctuation in these rates, annual lease expense will change by approximately $244 (March 31, 2005 - $293).

Foreign currency risk and derivative financial instruments:

The Company has 8³/4% senior notes denominated in U.S. dollars in the amount of US$200 million. In order to reduce its exposure to changes in the U.S. to Canadian dollar exchange rate, the Company, concurrent with the closing of the acquisition on November 26, 2003, entered into a cross-currency swap agreement to manage this foreign currency exposure for both the principal balance due on December 1, 2011 as well as the semi-annual interest payments through the whole period beginning from the issuance date to the maturity date. In conjunction with the cross-currency swap agreement, the Company also entered into a U.S. dollar interest rate swap and a Canadian dollar interest rate swap with the net effect of converting the 8.75% rate payable on the 8³/4% senior notes into a fixed rate of 9.765% for the duration that the 8³/4% senior notes are outstanding. On May 19, 2005 in connection with

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

the Company’s revolving credit facility, this fixed rate was increased to 9.889%. These derivative financial instruments do not qualify for hedge accounting. The Company’s derivative financial instruments are carried on the consolidated balance sheets at their fair value of $63,611 (March 31, 2005 - $51,723). The fair values of the Company’s cross-currency and interest rate swap agreements are based on values quoted by the counterparties to the agreements.

At March 31, 2006, the notional principal amount of the cross-currency swap was US$200 million. The notional principal amounts of the interest rate swaps were US$200 million and Canadian $263 million.

The Company has not hedged its exposure to changes in the U.S. to Canadian dollar exchange rate resulting from the issuance of the 9% senior secured notes.

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.

Credit risk:

Reflective of its normal business, a majority of the Company’s accounts receivable are 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, 2006 and March 31, 2005, the following customers represented 10% or more of accounts receivable and unbilled revenue:


	March 31, 2006		March 31, 2005
Customer A	21	%	33	%
Customer B	11	%	9	%
Customer D	9	%	11	%

20.

Commitments

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


For the year ending March 31,
2007	$	21,176
2008		16,506
2009		9,587
2010		8,148
2011 and thereafter		2,232

	$	57,649

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

21.

Employee contribution plans

The Company and its subsidiaries match voluntary contributions made by the employees to their Registered Retirement Savings Plans to a maximum of 5% of base salary for each employee. Contributions made by the Company during the year ended March 31, 2006 were $409 (year ended March 31, 2005 - $305; November 26, 2003 to March 31, 2004 - $68; April 1, 2003 to November 25, 2003 - $122).

22.

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 ten years from the grant date or on termination of employment. Options may be exercised at a price determined at the time the option is awarded, and vest as follows: no options vest on the award date and twenty 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 105,000, of which 1,682 are still available for issue as at March 31, 2006. The Predecessor Company did not have any stock-based compensation plans.


	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
Granted	24,112			100.00
Exercised	—			—
Forfeited	(2,000	)		(100.00	)

Outstanding at March 31, 2005	76,242			100.00
Granted	37,276			100.00
Exercised	—			—
Forfeited	(10,200	)		(100.00	)

Outstanding at March 31, 2006	103,318		$	100.00

At March 31, 2006, the weighted average remaining contractual life of outstanding options is 8.2 years (March 31, 2005 – 10 years). The Company recorded $923 of compensation expense related to the stock options in the year ended March 31, 2006 (year ended March 31, 2005 – $497; period from November 26, 2003 to March 31, 2004 - $137) with such amount being credited to contributed surplus.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

The fair value of each option granted by NACG Holdings Inc. was estimated on the grant date using the Black-Scholes option-pricing model with the following assumptions:


	Year ended March 31, 2006		Year ended March 31, 2005		Period from November 26, 2003 to March 31, 2004
Number of options granted	37,276		24,112		54,130
Weighted average fair value per option granted ($)	68.13		68.50		37.71
Weighted average assumptions
Dividend yield	nil	%	nil	%	nil	%
Expected volatility	nil	%	nil	%	nil	%
Risk-free interest rate	4.13	%	4.25	%	4.79	%
Expected life (years)	10		10		10

23.

Comparative figures

Certain of the comparative figures have been reclassified to conform to the current year’s presentation.

24.

United States generally accepted accounting principles

These consolidated financial statements have been prepared in accordance with Canadian GAAP, which differs in certain material respects from U.S. GAAP. If U.S. GAAP were employed, the Company’s net loss would be adjusted as follows:


	Year ended March 31, 2006			Year ended March 31, 2005			Period from November 26, 2003 to March 31, 2004			Predecessor Company
	Year ended March 31, 2006			Year ended March 31, 2005						Period from April 1, 2003 to November 25, 2003
Net loss (as reported)	$	(21,936	)	$	(42,313	)	$	(12,282	)	$	(11,141	)
Capitalized interest (a)		847			—			—			—
Amortization using effective interest method (b)		590			—			—			—
Realized and unrealized loss on derivative financial instruments (e)		(484	)		—			—			—

Income (loss) before income taxes		(20,983	)		(42,313	)		(12,282	)		(11,141	)
Income taxes:
Deferred income taxes		—			—			—			—

Net loss – U.S. GAAP	$	(20,983	)	$	(42,313	)	$	(12,282	)	$	(11,141	)

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

The cumulative effect of material differences between Canadian and U.S. GAAP on the consolidated shareholder’s equity of the Company is as follows:


	March 31, 2006			March 31, 2005
Shareholders’ equity (as reported) – Canadian GAAP	$	52,526		$	73,539
Capitalized interest (a)		847			—
Amortization using effective interest method (b)		590			—
Realized and unrealized loss on derivative financial instruments (e)		(484	)		—
Excess of fair value of amended Series B preferred shares over carrying value of original Series B preferred shares (f)		(3,707	)		—

Shareholders’ equity – U.S. GAAP	$	49,772		$	73,539

The areas of material difference between Canadian and U.S. GAAP and their impact on the Company’s consolidated financial statements are described below:

Capitalization of interest:

U.S. GAAP requires capitalization of interest costs as part of the historical cost of acquiring certain qualifying assets that require a period of time to prepare for their intended use. This is not required under Canadian GAAP.

Deferred charges:

Under Canadian GAAP, the Company defers and amortizes debt issuance costs on a straight-line basis over the stated term of the related debt. Under U.S. GAAP, the Company is required to amortize financing costs over the stated term of the related debt using the effective interest method resulting in a consistent interest rate over the term of the debt in accordance with Accounting Principles Board Opinion No. 21 (“APB 21”).

Reporting comprehensive income:

Statement of Financial Accounting Standards No. 130, “Reporting Comprehensive Income” (“SFAS 130”) establishes standards for the reporting and display of comprehensive income and its components in a full set of general purpose financial statements. Comprehensive income equals net income (loss) for the period as adjusted for all other non-owner changes in shareholders’ equity. SFAS 130 requires that all items that are required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement. The only component of comprehensive income (loss) is the net income (loss) for the period.

Stock-based compensation:

The Company uses the fair value method of accounting for all stock-based compensation payments under Canadian GAAP. As a result, there are no significant differences between Canadian GAAP and Statement of Financial Accounting Standards No. 123 (“SFAS 123”).

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

Derivative financial instruments:

Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”) establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts and debt instruments) be recorded in the balance sheet as either an asset or liability measured at its fair value. On November 26, 2003, the Company issued 8³/4% senior notes for US$200 million (Canadian $263 million) and on May 19, 2005 the Company issued 9% senior secured notes for US$60.4 million (Canadian $76.3 million). Both of these issuances included certain contingent embedded derivatives which provided for the acceleration of redemption by the holder at a premium in certain instances. These embedded derivatives met the criteria for bifurcation from the debt contract and separate measurement at fair value. The embedded derivatives have been measured at fair value and classified as part of the carrying amount of the Senior Notes on the consolidated balance sheet, with changes in the fair value being recorded in net income as realized and unrealized (gain) loss on derivative financial instruments for the period under U.S. GAAP. Under Canadian GAAP, separate accounting of embedded derivatives from the host contract is not permitted by EIC-117.

Series B Preferred Shares:

Prior to the modification of the terms of the Series B preferred shares, there were no differences between Canadian GAAP and U.S. GAAP related to the Series B preferred shares. As a result of the modification of terms of the Company’s Series B preferred shares on March 30, 2006, under Canadian GAAP, the Company continues to classify the Series B preferred shares as a liability and accretes the carrying amount to the December 31, 2011 redemption value of $69.6 million using the effective interest method. Under U.S. GAAP, the Company recognized the fair value of the Series B preferred shares as temporary equity in the Company’s accounts in accordance with EITF Topic D-98 and recognized a charge of $3.7 million to retained earnings for the difference between the fair value and the carrying amount of the Series B preferred shares on the modification date. Under U.S. GAAP, the Company accretes the initial fair value of the Series B preferred shares of $45.9 million to the December 31, 2011 redemption value of $69.6 million using the effective interest method. The accretion charge is recognized as a charge to retained earnings under U.S. GAAP and interest expense in the Company’s financial statements under Canadian GAAP.

Investment in joint venture

The Company has determined that the joint venture in which it participates is a VIE and that the Company is the primary beneficiary. Accordingly the joint venture has been consolidated on a prospective basis effective January 1, 2005. Prior to its consolidation, the joint venture was accounted for using the proportionate consolidation method under Canadian GAAP. Under U.S. GAAP, investments in joint ventures are accounted for using the equity method. The different accounting treatment affects only the display and classification of financial statement items and not net earnings or shareholders’ equity. Rules prescribed by the Securities and Exchange Commission of the United States permit the use of the proportionate consolidation method in the reconciliation to U.S. GAAP

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

provided the joint venture is an operating entity and the significant financial operating policies are, by contractual agreement, jointly controlled by all parties having an interest in the joint venture. In addition, the Company disclosed in note 16(c) the major components of its financial statements resulting from the use of the proportionate consolidation method to account for its interest in the joint venture prior to its consolidation.

Other matters:

The tax effects of temporary differences under Canadian GAAP are described as future income taxes in these financial statements whereas such amounts are described as deferred income taxes under U.S. GAAP.

United States accounting pronouncements recently adopted:

In December 2003, the U.S. Financial Accounting Standards Board (the “FASB”) issued FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities” (“FIN 46R”), 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”, which was issued in January 2003. The Company is required to apply FIN 46R to variable interests in 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 was 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 Company has determined the joint venture in which it has an investment (note 15(c)) qualifies as a VIE.

Statement on Financial Accounting Standards 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. The Statement was adopted by the Company on January 1, 2004. After the adoption of the standard, the Company issued other mandatorily redeemable preferred shares that were within the

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

scope of the standard, which have been disclosed in note 14(a) to the consolidated financial statements.

In November 2004, the FASB issued Statement on Financial Accounting Standards No. 151, “Inventory Costs”. This standard requires the allocation of fixed production overhead costs be based on the normal capacity of the production facilities and unallocated overhead costs recognized as an expense in the period incurred. In addition, other items such as abnormal freight, handling costs and wasted materials require treatment as current period charges rather than being considered an inventory cost. This standard was effective for fiscal 2006 for the Company. The adoption of this standard did not have a material impact on the Company’s financial statements.

Statement on Financial Accounting Standards No. 153, “Exchanges of Non-monetary Assets – an Amendment of APB Opinion 29” (“SFAS 153”), was issued in December 2004. Accounting Principles Board (“APB”) Opinion 29 is based on the principle that exchanges of non-monetary assets should be measured based on the fair value of assets exchanged. SFAS 153 amends APB Opinion 29 to eliminate the exception for non-monetary exchanges of similar productive assets and replaces it with a general exception for exchanges of non-monetary assets that do not have commercial substance. The standard is effective for the Company for non-monetary asset exchanges occurring in fiscal periods beginning after June 15, 2005, beginning July 1, 2005 for the Company. The adoption of this standard did not have a material impact on the Company’s financial statements.

In March 2005, FASB Staff Position FIN 46(R)-5, “Implicit Variable Interests under FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities”, to address whether a company has an implicit variable interest in a VIE or potential VIE when specific conditions exist. The guidance describes an implicit variable interest as an implied financial interest in an entity that changes with changes in the fair value of the entity’s net assets exclusive of variable interests. An implicit variable interest acts the same as an explicit variable interest except that it involves the absorbing and/or receiving of variability indirectly from the entity (rather than directly). This guidance was adopted in 2006 and did not have a material impact on the Company’s consolidated financial statements.

Recent United States accounting pronouncements not yet adopted:

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

which in the case of the Company is the period beginning April 1, 2006. The Company has used the fair value method under Statement 123 since its inception. The Company will be required to adopt SFAS 123R prospectively since the Company uses the minimum value method for purposes of complying with Statement 123. The Company is currently evaluating the other impacts of the revised standard.

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections” (“SFAS 154”) which replaces Accounting Principles Board Opinions No. 20 “Accounting Changes” and Statement of Financial Accounting Standards No. 3, “Reporting Accounting Changes in Interim Financial Statements – An Amendment of APB Opinion No. 28.” SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 and is required to be adopted by the Company in its fiscal year beginning on April 1, 2006. The Company is currently evaluating the effect that the adoption of SFAS 154 will have on its consolidated results of operations and financial position but does not expect it to have a material impact.

Statement of Financial Accounting Standards No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140” (“SFAS 155”) was issued February 2006. This Statement is effective for all financial instruments acquired, issued, or subject to a remeasurement (new basis) event occurring after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The fair value election provided for in paragraph 4(c) of this Statement may also be applied upon adoption of this Statement for hybrid financial instruments that had been bifurcated under paragraph 12 of Statement 133 prior to the adoption of this Statement. This states that an entity that initially recognizes a host contract and a derivative instrument may irrevocably elect to initially and subsequently measure that hybrid financial instrument, in its entirety, at fair value with changes in fair value recognized in earnings. SFAS 155 is applicable for all financial instruments acquired or issued in the Company’s 2007 fiscal year although early adoption is permitted. The Company is currently reviewing the impact of this statement.

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109” (“FIN 48”) which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This Interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition requirements. FIN 48 is effective for fiscal years beginning after December 15, 2006, specifically April 1, 2007 for the Company. The Company is currently reviewing the impact of this Interpretation.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

25.

Subsequent events

On April 24, 2006, the Company reached an agreement with a customer to settle outstanding claims arising from a mining and site preparation project. The Company received a cash payment of $7,600, of which $6,059 has not previously been recognized as revenue.

On July 19, 2006, the Company entered into a new credit agreement that provides for borrowings of up to $55.0 million, subject to borrowing base limitations, under which revolving loans and letters of credit may be issued. Prime rate revolving loans under the agreement will bear interest at the Canadian prime rate plus 2.0% per annum and swing line revolving loans will bear interest at the Canadian prime rate plus 1.5% per annum. Canadian bankers’ acceptances have stamping fees equal to 3.0% per annum and letters of credit are subject to a fee of 3.0% per annum.

Advances under the agreement are margined with a borrowing base calculation defined as the aggregate of 60.0% of the net book value of the Company’s plant and equipment, 75.0% of eligible accounts receivable and un-pledged cash in excess of $15.0 million. The sum of all borrowings (including issued letters of credit) and the mark-to-market value of the Company’s liability under existing swap agreements must not exceed the borrowing base. The credit facility is secured by a first priority lien on substantially all the Company’s existing and after-acquired property.

The facility contains certain restrictive covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions or to pay dividends or redeem shares of capital stock. The Company is also required to meet certain financial covenants.

Prior to, or concurrent with, the consummation of the proposed offering, the Company, NACG Preferred Corp. and NACG Holdings Inc. are planning to amalgamate into one new entity, North American Energy Partners Inc. In addition NACG Holdings Inc. is planning a share split prior to the proposed offering being completed. The voting common shares of the new entity, North American Energy Partners Inc., will be the shares offered in the proposed offering.

Prior to the amalgamation referred to above, it is the Company’s intention to repurchase the Series A preferred shares for their redemption value of $1.0 million and cancel the consulting and advisory services agreement with the Sponsors. The consideration to be paid for the cancellation of the consulting and advisory services agreement is still to be negotiated between the parties. In addition, it is planned that each holder of Series B preferred shares will, for each Series B preferred share held, receive five common shares (the number of common shares will be adjusted for the planned share split) in the amalgamated North American Energy Partners Inc. As part of the amalgamation, existing common and non-voting common shareholders of NACG Holdings Inc. will receive common and non-voting common shares of the amalgamated North American Energy Partners Inc.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

(Amounts in thousands of Canadian dollars unless otherwise specified)

leases and tender for all or a portion of the outstanding principal of and accrued interest on the Company’s 9% senior secured notes due 2010. The balance of the anticipated net proceeds would be available for general corporate purposes.

The completion of the proposed offering, including the planned reorganization described above, is subject to a number of approvals by the shareholders of the Company, NACG Preferred Corp. (including preferred shareholders of NACG Preferred Corp.) and NACG Holdings Inc., and the acceptance of the registration statement and prospectus by securities regulatory authorities in the United States and Canada.

The Company has offered to accelerate the vesting of stock options held by certain members of its Board of Directors, providing for the options to become immediately exercisable on the condition that any such options are exercised by September 30, 2006. The vesting period for stock options held by any Director that does not accept the Company’s offer will remain unchanged.

Subsequent to March 31, 2006, the Company was informed by the Canadian Revenue Agency and taxation officials from Alberta, Ontario and Quebec that certain financing arrangements and tax structures, which a wholly-owned subsidiary had taken part in, are being reviewed and challenged. If the tax authorities are successful in their challenge, the potential future tax liability is estimated to be $1 million, including estimated interest and penalties. The Company is satisfied that its tax structure met the technical requirements of the tax laws and regulations and the related tax benefit was properly recognized; accordingly, no liability has been accrued as at March 31, 2006. The Company is currently assessing its response to this challenge.