UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 20-F

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

or

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

FOR THE FISCAL YEAR ENDED

MARCH 31, 2007

or

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

or

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

Commission file number 001-33161

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:

Title Common Shares, No Par Value	Name of Exchange on which Registered New York Stock Exchange Toronto Stock Exchange
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: 35,604,660 Common Shares at March 31, 2007

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  ¨    NO  x

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

Indicate by check mark 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  ¨    Item 18  x

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	5
	ITEM 2:	OFFER STATISTICS AND EXPECTED TIMETABLE	5
	ITEM 3:	KEY INFORMATION	5
	ITEM 4:	INFORMATION ON THE COMPANY	21
	ITEM 5:	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	34
	ITEM 6:	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	56
	ITEM 7:	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	64
	ITEM 8:	FINANCIAL INFORMATION	67
	ITEM 9:	THE OFFER AND LISTING	68
	ITEM 10:	ADDITIONAL INFORMATION	68
	ITEM 11:	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	69
	ITEM 12:	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	70
PART II
	ITEM 13:	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	71
	ITEM 14:	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	71
	ITEM 15:	CONTROLS AND PROCEDURES	71
	ITEM 16:	[RESERVED]	72
	ITEM 16A	AUDIT COMMITTEE FINANCIAL EXPERT	72
	ITEM 16B	CODE OF ETHICS	72
	ITEM 16C	PRINCIPAL ACCOUNTANT FEES AND SERVICES	72
	ITEM 16D	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES	73
	ITEM 16E	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS	73
PART III
	ITEM 17:	FINANCIAL STATEMENTS	73
	ITEM 18:	FINANCIAL STATEMENTS	73
	ITEM 19:	EXHIBITS	73

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

EXCHANGE RATE INFORMATION

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 May 31, 2007, the Noon Buying Rate was $1.00 = US$ 0.9347.

	2006 December	2007
		January	February	March	April	May
High for period	0.8787	0.8598	0.8467	0.8696	0.9051	0.9376
Low for period	0.8569	0.844	0.8419	0.8462	0.8621	0.8958

	Year Ended March 31,
	2003	2004	2005	2006	2007
Average for period	0.6455	0.7412	0.7836	0.8378	0.8738

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;

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• 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 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.

NON-GAAP FINANCIAL MEASURES

The body of generally accepted accounting principles applicable to us is commonly referred to as “GAAP.” A non-GAAP financial measure is generally defined by the Securities and Exchange Commission, or SEC, and by the Canadian securities regulatory authorities as one that purports to measure historical or future financial performance, financial position or cash flows, but excludes or includes amounts that would not be so adjusted in the most comparable GAAP measures. 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, gain or loss on disposal of plant and equipment and certain other non cash items included in the calculation of net income (loss). 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, which 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 interest coverage ratio and a maximum senior leverage ratio, which includes the reference to 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. 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 US GAAP. Our methods of calculating EBITDA and Consolidated EBITDA may vary from others in our industry.

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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 the fiscal year ended March 31, 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, 2006 and 2007 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.

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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 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, 2007, 2006 and 2005, see note 27 to our consolidated financial statements included at Item 17.

										November 26, 2003 to March 31, 2004			Predecessor (a)
	Year Ended March 31,												April 1, 2003 to November 25, 2003			Year Ended March 31, 2003
	2007			2006			2005
	(Dollars in thousands except shares and per share amounts)
Statement of operations data:
Revenue (b)	$	629,446		$	492,237		$	357,323		$	127,611		$	250,652		$	344,186
Project costs		363,930			308,949			240,919			83,256			156,976			219,979
Equipment costs		122,306			64,832			52,831			13,686			43,484			55,871
Equipment operating lease expense		19,740			16,405			6,645			1,430			10,502			16,357
Depreciation		31,034			21,725			20,762			6,674			6,566			10,974
Gross profit		92,436			80,326			36,166			22,565			33,124			41,005
General and administrative costs		39,769			30,903			22,873			6,065			7,783			12,233
Loss (gain) on sale of plant and equipment		959			(733	)		494			131			(49	)		(2,265	)
Amortization of intangible assets		582			730			3,368			12,928			—			—
Operating income		51,126			49,426			9,431			3,441			25,390			31,037
Management fee (c)		—			—			—			—			41,070			8,000
Interest expense (d)		37,249			68,776			31,141			10,079			2,457			4,162
Foreign exchange gain		(5,044	)		(13,953	)		(19,815	)		(661	)		(7	)		(234	)
Gain on repurchase of NACG Preferred Corp. Series A preferred shares (e)		(9,400	)		—			—			—			—			—
Loss on extinguishment of debt (e)		10,935			2,095
Other income		(904	)		(977	)		(421	)		(230	)		(367	)		—
Realized and unrealized (gain) loss on derivative financial instruments		(196	)		14,689			43,113			12,205			—			—
Income (loss) before income taxes		18,486			(21,204	)		(44,587	)		(17,952	)		(17,763	)		19,109
Income taxes (benefit)		(2,593	)		737			(2,264	)		(5,670	)		(6,622	)		6,620
Net income (loss) (f)	$	21,079		$	(21,941	)	$	(42,323	)	$	(12,282	)	$	(11,141	)	$	12,489
Earnings Per Share
Basic	$	0.87		$	(1.18	)	$	(2.28	)	$	(0.66	)		N/A			N/A
Diluted	$	0.83		$	(1.18	)	$	(2.28	)	$	(0.66	)		N/A			N/A
Weighted average number of common shares
Basic		24,352,156			18,574,800			18,539,720			18,500,000			N/A			N/A
Diluted		25,443,907			18,574,800			18,539,720			18,500,000			N/A			N/A
Balance sheet data (end of period):
Cash	$	7,895		$	42,804		$	17,924		$	36,595					$	651
Property, plant and equipment, net		255,963			184,562			177,089			167,905						76,234
Total assets		710,736			568,682			540,155			489,974						158,584
Total debt (g)		260,789			314,959			310,402			313,798						63,401
Other long-term financial liabilities (g)		60,863			141,179			86,723			46,266						—
Total long-term financial liabilities (g)		297,957			453,092			395,354			352,027						40,342
NACG Preferred Corp. Series A preferred shares (e)		—			35,000			35,000			35,000						—
NAEPI Series A preferred shares (e)		—			375			—			—						—
NAEPI Series B preferred shares (e)		—			42,193			—			—						—
Total shareholder’s equity (e)		244,278			18,111			38,829			80,355						29,818
Other financial data:
EBITDA (h)	$	87,351		$	70,027		$	10,684		$	11,729		$	(8,740	)	$	34,245
Consolidated EBITDA (h)		90,235			72,422			34,448			23,462			(8,789	)		31,980

(a) The historical balance sheet and statement of operations and other financial data as at and for the years ended March 31, 2003 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,

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(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.

Claims revenue recognized was $14.5 million for the year ended March 31, 2007 (2006 – $12.9 million; 2005 – $nil), $8.4 million of which is included in unbilled revenue and remains uncollected at the end of the year (2005 – $nil). Of the amount included in unbilled revenue at March 31, 2007, $6.6 million was 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.

(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) Interest expense consists of the following:

									Predecessor
	Year Ended March 31,						November 26, 2003 to March 31, 2004		April 1, 2003 to November 25, 2003
	2007		2006		2005
	(Dollars in thousands)
Interest on senior notes	$	27,417	$	28,838	$	23,189	$	8,096	$	—
Interest on capital lease obligations		725		457		230		—		—
Interest on senior secured credit facility		—		564		3,274		1,089		599
Interest on NACG Preferred Corp. Series A preferred shares		1,400		—		—		—		—
Accretion and change in redemption value of NAEPI Series B preferred shares		2,489		34,668		—		—		—
Accretion of NAEPI Series A preferred shares		625		54		—		—		—
Interest on long-term debt		32,656		64,581		26,693		9,185		599
Amortization of deferred financing costs		3,436		3,338		2,554		814		—
Other interest		1,157		857		1,894		80		1,858
Interest expense	$	37,249	$	68,776	$	31,141	$	10,079	$	2,457

(e) On November 28, 2006, prior to the consummation of the initial public offering (“IPO”) discussed below, NACG Holdings Inc. (“Holdings”) amalgamated with its wholly-owned subsidiaries, NACG Preferred Corp. and North American Energy Partners Inc. (“NAEPI”). The amalgamated entity continued under the name North American Energy Partners Inc. The voting common shares of the new entity, North American Energy Partners Inc., were the shares sold in the IPO.

On November 28, 2006, prior to the amalgamation:

• Holdings acquired the NACG Preferred Corp. Series A preferred shares with a carrying value of $35.0 million together with related accrued and subsequently forfeited dividends of $1.4 million in exchange for a promissory note in the amount of $27.0 million. The Company recorded a gain of $9.4 million on the repurchase of the NACG Preferred Corp. Series A preferred shares.

• Holdings repurchased the NAEPI Series A preferred shares for their redemption value of $1.0 million. Holdings also cancelled the consulting and advisory services agreement with The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc., and SF Holding Corp. (collectively, the “Sponsors”), under which Holdings had received ongoing consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements and other matters. The consideration paid for the cancellation of the consulting and advisory services agreement on the closing of the offering was $2.0 million, which was recorded as general and administrative expense in the consolidated statement of operations. Under the consulting and advisory services agreement, the Sponsors also received a fee of $0.9 million, 0.5% of the aggregate gross proceeds to the Company from the offering, which was recorded as a share issue cost.

• Each holder of NAEPI Series B preferred shares received 100 common shares of Holdings for each NAEPI Series B preferred share held as a result of Holdings exercising a call option to acquire the NAEPI Series B preferred shares. Upon exchange, the carrying value in the amount of $44.7 million for the NAEPI Series B preferred shares on the exercise date was transferred to share capital.

On November 28, 2006, the Company completed an IPO of 8,750,000 common voting shares for total gross proceeds of $158.5 million. Net proceeds from the IPO, after deducting underwriting fees and offering expenses, were $140.9 million. Subsequent to the IPO, the underwriters exercised their overallotment option to purchase 687,500 additional voting common shares of the Company for gross proceeds of $12.6 million. Net proceeds from the overallotment, after deducting underwriting fees and offering expenses, were $11.7 million. Total net proceeds from the IPO and subsequent overallotment were $152.6 million.

The net proceeds from the IPO and subsequent overallotment were used:

• to repurchase all of the Company’s outstanding 9% senior secured notes due 2010 for $74.7 million plus accrued interest of $3.0 million. The notes were redeemed at a premium of 109.26% resulting in a loss on extinguishment of $6.3 million. The loss on extinguishment, along with the write-off of deferred financing fees of $4.3 million and other costs of $0.3 million, was recorded as a loss on extinguishment of debt in the consolidated statement of operations;

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• to repay the promissory note in respect of the repurchase of the NACG Preferred Corp. Series A preferred shares for $27.0 million as described above;

• to purchase certain equipment leased under operating leases for $44.6 million;

• to cancel the consulting and advisory services agreement with the Sponsors for $2.0 million; and

• for general corporate purposes.

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

										November 26, 2003 to March 31, 2004			Predecessor
	Year Ended March 31,												April 1, 2003 to November 25, 2003			Year Ended March 31, 2003
	2007			2006			2005
	(Dollars in thousands)
Net income (loss)—Canadian GAAP	$	21,079		$	(21,941	)	$	(42,323	)	$	(12,282	)	$	(11,141	)	$	12,489
Capitalized interest(1)		249			847			—			—			—			—
Depreciation of capitalized interest(1)		(143	)		—			—			—			—			—
Amortization using effective interest method(2)		1,246			590			—			—			—			—
Realized and unrealized loss on derivative financial instruments(3)		348			(484	)		—			—			—			—
Difference between accretion of Series B Preferred Shares(4)		249			—			—			—			—			—
Income (loss) before income taxes		23,028			(20,988	)		(42,323	)		(12,282	)		(11,141	)		12,489
Income taxes: Deferred income taxes		(954	)		—			—			—			—			—
Net income (loss)—U.S. GAAP	$	22,074		$	(20,988	)	$	(42,323	)	$	(12,282	)	$	(11,141	)	$	12,489
Net income (loss) per share—Basic—U.S. GAAP	$	0.91		$	(1.13	)	$	(2.28	)	$	(0.66	)
Net income (loss) per share—Diluted—U.S. GAAP	$	0.87		$	(1.13	)	$	(2.28	)	$	(0.66	)

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

	March 31, 2007			March 31, 2006			March 31, 2005
	(Dollars in thousands)
Shareholders’ equity (as reported)—Canadian GAAP	$	244,278		$	18,111		$	38,829
Capitalized interest(1)		1,096			847			—
Depreciation of capitalized interest(1)		(143	)
Amortization using effective interest method(2)		1,836			590			—
Realized and unrealized loss on derivative financial instruments(3)		(136	)		(484	)		—
Excess of fair value of amended Series B preferred shares over carrying value of original series B preferred shares(4)		—			(3,707	)		—
Deferred income taxes		(954	)		—			—
Shareholders’ equity—U.S. GAAP	$	245,977		$	15,357		$	38,829

(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. Accordingly, the capitalized amount is subject to depreciation in accordance with the Company’s policies when the asset is placed into service.

(2) Under Canadian GAAP, the Company defers and amortizes debt issue 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”).

(3) 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 8 ³/4% senior notes for US$200 million (Canadian $263 million). On May 19, 2005 the Company issued 9% senior secured notes for US$60.4 million (Canadian $76.3 million), subsequently retired on November 28, 2006. Both of these issues 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.

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(4) Prior to the modification of the terms of the NAEPI Series B preferred shares, there were no differences between Canadian GAAP and U.S. GAAP related to the NAEPI Series B preferred shares. As a result of the modification of terms of NAEPI’s Series B preferred shares on March 30, 2006, under Canadian GAAP, the Company continued to classify the NAEPI Series B preferred shares as a liability and was accreting the carrying amount of $42.2 million on the amendment date (March 30, 2006) to their 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 amended NAEPI Series B preferred shares as minority interest as such amount was recognized as temporary equity in the accounts of NAEPI 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 amendment date. Under U.S. GAAP, the Company was accreting the initial fair value of the amended NAEPI Series B preferred shares of $45.9 million recorded on their amendment date (March 30, 2006) to the December 31, 2011 redemption value of $69.6 million using the effective interest method, which was consistent with the treatment of the NAEPI Series B preferred shares as temporary equity in the financial statements of NAEPI. The accretion charge was recognized as a charge to minority interest (as opposed to retained earnings in the accounts of NAEPI) under US GAAP and interest expense in the Company’s financial statements under Canadian GAAP.

(g) Total Debt as of March 31, 2007 consists of the following (in thousands):

Revolving line of credit	$	20,500
Obligations under capital leases, including current portion		9,709
8 3/4% senior notes due 2011		230,580
Total debt	$	260,789

Our 8 ³/4% senior notes are stated at the current exchange rate at each balance sheet date. We have entered into cross-currency and interest rate swaps, which represent an economic hedge of the 8 ³/4% senior notes. At maturity, we will be required to pay $263 million in order to retire these senior notes and the swaps. This amount reflects the fixed exchange rate of C$1.315=US$1.00 established as of November 26, 2003, the date of inception of the swap contracts.

Other long-term financial liabilities consist of derivative financial instruments and redeemable preferred shares.

Total long-term financial liabilities consists of total debt, excluding current portion, plus our redeemable shares and the value of the cross-currency and interest rate swaps recognized on our balance sheet.

(h) 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, gain or loss on disposal of plant and equipment and certain other non cash items included in the calculation of net income (loss). 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 interest coverage ratio and a maximum senior leverage ratio, which are calculated using Consolidated EBITDA. Non-compliance with these financial covenants could result in our being required to immediately repay all amounts outstanding under our revolving credit facility. 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. A reconciliation of net income (loss) to EBITDA and Consolidated EBITDA is as follows:

										November 26, 2003 to March 31, 2004			Predecessor
	Year Ended March 31,												April 1, 2003 to November 25, 2003			Year Ended March 31, 2003
	2007			2006			2005
	(Dollars in thousands)
Net income (loss)	$	21,079		$	(21,941	)	$	(42,323	)	$	(12,282	)	$	(11,141	)	$	12,489
Adjustments:
Interest expense		37,249			68,776			31,141			10,079			2,457			4,162
Income taxes (benefit)		(2,593	)		737			(2,264	)		(5,670	)		(6,622	)		6,620
Depreciation		31,034			21,725			20,762			6,674			6,566			10,974
Amortization of intangible assets		582			730			3,368			12,928			—			—
EBITDA	$	87,351		$	70,027		$	10,684		$	11,729		$	(8,740	)	$	34,245

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A reconciliation of EBITDA to Consolidated EBITDA is as follows:

										November 26, 2003 to March 31, 2004			Predecessor
	Year Ended March 31,												April 1, 2003 to November 25, 2003			Year Ended March 31, 2003
	2007			2006			2005
	(Dollars in thousands)
EBITDA	$	87,351		$	70,027		$	10,684		$	11,729		$	(8,740	)	$	34,245
Adjustments:
Unrealized foreign exchange gain on senior notes	$	(5,017	)		(14,258	)		(20,340	)		(740	)		—			—
Realized and unrealized (gain) loss on derivative financial instruments	$	(196	)		14,689			43,113			12,205			—			—
Loss (gain) on disposal of plant and equipment	$	959			(733	)		494			131			(49	)		(2,265	)
Stock-based compensation expense	$	2,101			923			497			137			—			—
Write-off of deferred financing costs	$	4,342			1,774			—			—			—			—
Write down of other assets to replacement cost	$	695			—			—			—			—			—
Consolidated EBITDA	$	90,235		$	72,422		$	34,448		$	23,462		$	(8,789	)	$	31,980

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EXCHANGE RATE DATA

The following tables set forth the exchange rates for one Canadian dollar, expressed in U.S. dollars, based on the inverse of the noon buying rate in the city of New York for cable transfers in Canadian dollars as certified for customs purposes by the Bank of Canada (the “Noon Buying Rate”). On May 31, 2007, the Noon Buying Rate was $1.00 = US$ 0.9347.

	2006 December	2007
		January	February	March	April	May
High for period	0.8787	0.8598	0.8467	0.8696	0.9051	0.9376
Low for period	0.8569	0.844	0.8419	0.8462	0.8621	0.8958

	Year Ended March 31,
	2003	2004	2005	2006	2007
Average for period	0.6455	0.7412	0.7836	0.8378	0.8738

B. CAPITALIZATION AND INDEBTEDNESS

Not applicable.

C. REASONS FOR THE OFFER AND USE OF PROCEEDS

Not applicable.

D. RISK FACTORS

Risk Factors

Anticipated major projects in the oil sands may not materialize.

Notwithstanding the National Energy Board’s estimates regarding new investment and growth in the Canadian oil sands, 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. The most important consideration is the customer’s view of the long-term price of oil which is influenced by many factors, including the condition of developed and developing economies and the resulting demand for

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

For our customers to operate successfully in the oil sands, they must be able to transport the bitumen produced to upgrading facilities and transport the upgraded oil to refineries. Some oil sands projects have upgraders at mine site and others transport bitumen to upgraders located elsewhere. While current pipeline and upgrading capacity is sufficient for current production, future increases in production from new oil sands projects and expansions to existing projects will require increased upgrading and pipeline capacity. If these increases do not materialize, whether due to inadequate economics for the sponsors of such projects, shortages of 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 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 intervened in two recent hearings considering applications by major oil sands companies to the EUB for approval to expand their operations. Similar action could be taken with respect to any future applications. The EUB has issued conditional approval for the expansion in respect of one of the hearings despite the intervention by the local government authority, and a decision in the second hearing is pending. The EUB has indicated that it believes that additional infrastructure investment in the oil sands region is needed and that there is a short window of opportunity to make these investments in parallel with continued oil sands development. If the necessary infrastructure is not put in place, future growth of our customers’ operations could be delayed, reduced or 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 exploring innovative ways to hire the people we need, which include project managers, trades people and other skilled employees. 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

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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. 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 and 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 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, two of our trucks are currently not in service because we cannot get tires for these particular trucks. 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 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.

Most of our revenue comes from the provision of services to a small number of major oil sands mining companies. Revenue from our five largest customers represented approximately 65%, 70% and 68% of our total revenue for 2007, 2006 and 2005, respectively, and those customers are expected to continue to account for a significant percentage of our revenues in the future. In addition, the majority of our Pipeline revenues in previous fiscal years resulted from work performed for one customer. If we lose or experience a significant reduction of business 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.

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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 lower than actual costs.

Approximately 66%, 58% and 51% of our revenue for 2007, 2006 and 2005, respectively, was derived from lump-sum and unit-price contracts. See “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:

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

• scope modifications during the execution of the project;

• the availability and cost of skilled workers;

• the availability and proximity of materials;

• unfavorable weather conditions hindering productivity;

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

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

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

When we are unable to accurately estimate 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.

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 our listings on the New York Stock Exchange and the Toronto Stock Exchange. We have had continuing problems providing accurate and timely financial information and reports and restated NAEPI’s financial statements three times since the beginning of our 2005 fiscal year. In April of 2005, we had to restate NAEPI’s financial statements for the first and second quarters of 2005 to properly account for costs incurred in those quarters. During 2006, we had to restate NAEPI’s financial statements for each period after November 26, 2003 to the quarter ended December 31, 2004 and the quarter ended June 30, 2005 to eliminate the impact of hedge accounting with respect to the derivative financial instruments. We also had to restate NAEPI’s financial statements for the first quarter of 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 NAEPI’s financial statements within the deadlines imposed by covenants in the indentures governing our 8 ³/4% senior notes and 9% senior secured notes.

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We have identified a number of significant weaknesses (as defined under Canadian auditing standards) in our financial reporting processes and internal controls. See “Significant Weaknesses in Financial Reporting 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 U.S. and Canadian securities regulations with respect to reporting requirements 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 the trading price of our common shares 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 year ending March 31, 2008. Effective 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 on the effectiveness of internal control over financial reporting. 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, as of the end of fiscal 2008, we are unable to assert that our internal control over financial reporting is effective, or if our independent auditors are unable to attest that our internal control over financial reporting is effective, we could be subject to heightened regulatory scrutiny, investors could lose confidence in our reported financial information and the trading price of our common shares 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, 2007, we had outstanding $240.3 million of debt, including $9.7 million of capital leases. We also had cross-currency and interest rate swaps with a balance sheet liability of $60.9 million as of March 31, 2007. These swaps are secured equally and ratably with our revolving credit facility. We also had $25.0 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:

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

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

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

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

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

• 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.

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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 indenture governing our notes limit, among other things, our ability and the ability of our subsidiaries to:

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

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

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

• issue equity securities of subsidiaries;

• make certain investments or acquisitions;

• create liens on our assets;

• enter into transactions with affiliates;

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

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

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 an event of default under our revolving credit facility or any future credit facilities or under the indenture governing our notes. Under our revolving credit facility, our failure to pay certain amounts when due to other creditors, including to certain equipment lessors, or the acceleration of such other indebtedness, would also result in an event of default. Upon the occurrence of an event of default under our revolving credit facility or future credit facilities, the lenders could elect to stop lending to us or declare all amounts outstanding under such credit facilities to be immediately due and payable. Similarly, upon the occurrence of an event of default under the indenture 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 indenture were to be accelerated, or if we were not able to borrow under our revolving credit facility, we could become insolvent or be forced into insolvency proceedings and you could lose your investment in us.

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 was amended and restated on July 19, 2006, which we replaced with our current amended and restated credit agreement dated as of June 7, 2007.

Our inability to file NAEPI’s financial statements for the periods ended December 31, 2004, March 31, 2005 and September 30, 2005 with the SEC within the deadlines imposed by the regulators caused us to be out of

16

compliance with the covenants in the indentures governing our 8 ³/4% senior notes and our 9% senior secured notes (the latter indenture having been subsequently repaid and terminated on November 28, 2006). 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 2005, we had negative operating cash flow of $5.7 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 repay our 8 ³/4% senior notes and may affect the cost of goods we purchase.

We have entered into cross-currency and interest rate swaps that represent economic hedges of our 8 ³/4% 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 8 ³/4% senior notes prior to their maturity in 2011, we will have to pay this liability.

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, 2007 and May 31, 2007, the Canadian dollar/U.S. dollar exchange rate varied from a high of 0.9376 Canadian dollars per U.S. dollar to a low of 0.8419 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 second amended and restated revolving credit facility provides for the issuance of letters of credit up to $125.0 million,

17

and at March 31, 2007, we had $25.0 million of issued letters of credit outstanding. One of our major contracts allows the customer to require up to $50.0 million in letters of credit. If we were unable to provide letters of credit in the amount requested by this customer, we could lose business from such customer and our business and cash flow would be adversely affected. If our capacity to issue letters of credit under our revolving credit facility and our cash on hand are insufficient to satisfy our customers, 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% to 75% of our revenues in each of 2007, 2006 and 2005. 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 project work.

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

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

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

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

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

More than 66% of our revenue for 2007 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.

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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 noncompliance with environmental laws and regulations, and our contracts generally require us to indemnify our customers for environmental claims suffered by them as a result of our actions. In addition, some environmental laws impose strict, joint and several liability for investigative and remediation costs in relation to releases of harmful substances. These laws may impose liability without regard to negligence or fault. We also may be subject to claims alleging personal injury or property damage if we cause the release of, or any exposure to, harmful substances.

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

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

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

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

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, Supply Chain. In June 2006, we hired a new Vice President, Human Resources, Health, Safety and Environment. In September 2006, we hired a new Chief Financial Officer. Our Chief Operating Officer has resigned effective July 31, 2007. 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.

We will incur significantly higher costs as a result of being a public company.

As a public company, we will incur significantly higher legal, accounting and other expenses than we did as a private company. In addition, the Sarbanes-Oxley Act of 2002, as well as similar or related rules adopted by the Securities and Exchange Commission, Canadian securities regulatory authorities, the New York Stock Exchange and the Toronto Stock Exchange, have imposed substantial requirements on public companies, including requiring changes in corporate governance practices and requirements relating to internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act. We expect these rules and regulations will increase our legal and financial compliance costs and make some activities more time-consuming and costly.

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ITEM 4: INFORMATION ON THE COMPANY

A. HISTORY AND DEVELOPMENT OF THE COMPANY

NACG Holdings Inc. (“Holdings”) was formed in October 2003 in connection with the Acquisition discussed below. Prior to the Acquisition, NACG Holdings Inc. had no operations or significant assets and the Acquisition was primarily a change of ownership of the businesses acquired.

On October 31, 2003, two wholly-owned subsidiaries of Holdings, as the buyers, entered into a purchase and sale agreement with Norama Ltd. and one of its subsidiaries, as the sellers. On November 26, 2003, pursuant to the purchase and sale agreement, Norama Ltd. sold to the buyers the businesses comprising North American Construction Group in exchange for total consideration of approximately $405.5 million, net of cash received and including the impact of certain post-closing adjustments. The businesses we acquired from Norama Ltd. have been in operation since 1953. Subsequent to the Acquisition, we have operated the businesses in substantially the same manner as prior to the Acquisition.

On November 28, 2006, prior to the consummation of the initial public offering (“IPO”) discussed below, Holdings amalgamated with its wholly-owned subsidiaries, NACG Preferred Corp and North American Energy Partners Inc. The amalgamated entity continued under the name North American Energy Partners Inc. The voting common shares of the new entity, North American Energy Partners Inc., were the shares sold in the IPO and related secondary offering. On November 28, 2006, we completed the IPO in the United States and Canada of 8,750,000 voting common shares and a secondary offering of 3,750,000 voting common shares for $18.38 per share (U.S. $16.00 per share).

On November 22, 2006 our common shares commenced trading on the New York Stock Exchange and on the Toronto Stock Exchange on an “if, as and when issued” basis. On November 28, 2006, our common shares became fully tradable on the Toronto Stock Exchange.

Net proceeds from the IPO were $140.9 million (gross proceeds of $158.5 million, less underwriting discounts and costs and offering expenses of $17.6 million). On December 6, 2006, the underwriters exercised their option to purchase an additional 687,500 common shares from us. The net proceeds from the exercise of the underwriters’ option were $11.7 million (gross proceeds of $12.6 million, less underwriting fees of $0.9 million). Total net proceeds were $152.6 million (total gross proceeds of $171.1 million less total underwriting discounts and costs and offering expenses of $18.5 million). As of March 31, 2007, our authorized capital consists of an unlimited number of voting and non-voting common shares, of which 35,192,260 voting and 412,400 non voting common shares were issued and outstanding.

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.

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 Alberta 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 690 pieces of diversified heavy construction equipment supported by over 660 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.

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Our core market is the Alberta oil sands, where we generated 72% of our fiscal 2007 revenue. The oil sands are located in three regions of northern Alberta: Athabasca, Cold Lake and Peace River. 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, 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 have also provided 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 2007 were derived from recurring, long-term contracts, which assists in providing stability in our operations.

Our Operations

We provide our services through 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 our services primarily to oil and gas and other natural resource companies.

The chart below shows the revenues generated by each operating segment for the fiscal years ended March 31, 2005 through March 31, 2007:

	Year Ended March 31,
	2007				2006				2005
	(Dollars in thousands)
Mining and site preparation	$	473,179	75.2	%	$	366,721	74.5	%	$	264,835	74.1	%
Piling		109,266	17.3			91,434	18.6			61,006	17.1
Pipeline installation		47,001	7.5			34,082	6.9			31,482	8.8
Total	$	629,446	100.0	%	$	492,237	100.0	%	$	357,323	100.0	%

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 900 people. The majority of the employees and equipment associated with this business unit are located in the Alberta oil sands area.

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For the fiscal years ended March 31, 2005, 2006 and 2007, revenues from this segment accounted for 74%, 75% 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 150 people. Oil and gas companies developing the oil sands and related infrastructure represented approximately 50% of our piling clients for fiscal 2007. The remaining 50% 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, 2006 and 2007, revenues from this segment accounted for 17%, 19% and 17% 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

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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.

Prior to fiscal 2007 virtually all of our revenues in our pipeline business resulted from work performed for EnCana. During fiscal 2007 we expanded our client base in the pipeline division performing work for Canadian Natural Resources Limited, Suncor Energy Inc. and Husky Energy Inc. We believe there are significant opportunities to further increase our market share by capitalizing on the projected pipeline expansion in Canada.

For the fiscal years ended March 31, 2005, 2006 and 2007, revenues from this segment accounted for 9%, 7% and 8% 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. Under the revised royalty structure, oil sands operators pay a royalty of 1% of gross revenue until the operator has recovered all its allowed costs in respect of a project plus a return allowance, after which the royalty increases to the greater of 25% of net revenue or 1% of gross revenue.

Outlook

According to the Canadian Association of Petroleum Producers, or CAPP, approximately $42 billion was invested in the oil sands from 1998 through 2005. 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

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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, including:

• Kinder Morgan Canada’s proposal to expand the TransMountain pipeline system, which transports oil from the oil sands area to Burnaby, British Columbia.

• Enbridge Inc.’s proposed Gateway pipeline, which will transport oil from the oil sands area to Kitimat, British Columbia.

• The proposed Access Pipeline (a joint venture between MEG Energy Corp. and Devon ARL Canada Corp.), which will transport bitumen from the oil sands to refineries in Edmonton, Alberta and diluent from Edmonton, Alberta to the oil sands area.

• TransCanada Corporation’s proposed Keystone pipeline project, which will transport oil from Hardisty, Alberta to the Chicago area.

• The proposed Spirit pipeline system (a joint venture between Kinder Morgan Canada and Pembina Pipeline Corporation), which will transport condensate from Kitimat, British Columbia to Edmonton, Alberta.

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 additional 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 more than 60 different minerals and metals. In 2006, the mining and minerals processing industries contributed $40 billion to the Canadian economy, an amount equal to approximately 3.7% of GDP. The value of minerals produced (excluding petroleum and natural gas) reached $33.6 billion in 2006.

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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 13.2 million carats of production in 2006, representing a compounded annual growth rate of approximately 38%, 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.

Canada is the world leader in uranium mining. The two largest high-grade deposits in the world have been discovered in Canada. According to Natural Resources Canada, 80% of Canada’s recoverable reserve base is categorized as “low-cost”. Historically, exploration and production have taken place primarily in Saskatchewan. Recently, however, significant exploration efforts are underway in the Northwest Territories, Yukon, Nunavut, Quebec, Newfoundland and Labrador, Ontario, Manitoba and Alberta, with as many as 90 junior exploration companies involved.

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 2007 estimate, the capital and repair expenditures needed to support the minerals mining industry would be over $8 billion in 2007.

Commercial and Public Construction

According to the government agency, Statistics Canada, the Canadian commercial and public construction market was approximately $25 billion in 2006. 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 $18.2 billion to improvement and expansion projects from 2008 to 2010. 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 May 2007, the inventory of commercial, retail and residential projects in Alberta was valued at approximately $14.1 billion. These large expenditures will be further supplemented by the 2010 Olympic Winter Games, which will be held in the Vancouver area. The City of Vancouver estimates that the 2010 Olympic Winter Games will require an additional $4.0 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.

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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.

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, 2007, our contracts consisted of 6% cost-plus, 28% time-and-materials, 53% unit-price and 13% 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 Syncrude, Suncor and Albian.

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. This joint venture was 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,

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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 Cow Harbour, 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.

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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, 2005, 2006 and 2007 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, 2007, we had over 200 salaried and over 1,500 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 1,300 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 expired. This contract is currently being negotiated. 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

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specialty collective agreements under which we complete work, and the primary terms of all of these agreements 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,
	2007		2006		2005
	(Dollars in thousands)
Mining & Site Preparation	$	95,829	$	25,090	$	16,888
Piling		8,940		880		202
Pipeline		1,918		82		774
Other		3,332		2,800		6,975
Total	$	110,019	$	28,852	$	24,839

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C. ORGANIZATIONAL STRUCTURE

North American Energy Partners Inc. is the parent company of North American Construction Group Inc. and its operating subsidiaries. All of the entities in the chart are wholly-owned by their respective parents as at the date of filing of this Form 20-F.

(1) Midwest Foundations Technologies Ltd. purchased September 1, 2006 dissolved January 25, 2007.

D. PLANT AND EQUIPMENT

We operate and maintain 690 pieces of diversified heavy equipment, including crawlers, graders, loaders, mining trucks, compactors, scrapers and excavators, as well as over 660 ancillary vehicles, including various service and maintenance vehicles. The equipment is in good condition, normal wear and tear excepted. Our revolving credit facility is secured by liens on substantially all of our equipment. We lease some of this equipment under lease terms that include purchase options.

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The following table sets forth our heavy equipment fleet as at March 31, 2007:

Category	Capacity Range	Horsepower Range	Number in Fleet	Number Leased
Mining and site preparation:
Articulating trucks	30-42 tons	305-460	54	—
Mining trucks	50-330 tons	650-2,700	128	13
Shovels	36-58 cubic yards	2,600-3,760	5	2
Excavators	1-20 cubic yards	94-1,350	135	3
Crawler tractors	N/A	120-1,350	113	8
Graders	14-24 feet	150-500	25	3
Scrapers	28-31 cubic yards	450	14	—
Loaders	1.5-16 cubic yards	110-690	52	—
Skidsteer loaders	1-2.25 cubic yards	70-150	47	—
Packers	44,175-68,796 lbs	216-315	25	—
Pipeline:
Snow cats	N/A	175	4	—
Trenchers	N/A	165	2	—
Pipelayers	16,000-140,000 lbs	78-265	35	—
Piling:
Drill rigs	60-135 feet (drill depth)	210-1,500	37	—
Cranes	25-100 tons	200-263	14	—
Total			690	29

For the fiscal years ended March 31, 2005, 2006 and 2007 we incurred expenses of $52.8 million, $64.8 million and $122.3 million respectively, to maintain our equipment in good working condition.

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.

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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 New Westminister, British Columbia; and Regina and Martensville, 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, which 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 is secured by liens on substantially all of our properties. The following table describes our primary facilities.

Location	Function	Owned or Leased	Lease Expiration Date
Acheson, Alberta	Corporate Headquarters and major equipment repair facility	Leased	11/30/2007
Calgary, Alberta	Regional office and major equipment repair facility—piling operations	Building Owned Land Leased	12/31/2010
Syncrude Mine Site South End	Regional office and major equipment repair facility—earth works and mining operations	Building Owned Land Provided	N/A
Fort McMurray, Alberta Syncrude Plant Site	Satellite office and minor repair facility—all operations	Building Owned Land Leased	11/30/2009
Fort McMurray, Alberta CNRL Plant Site	Site office and maintenance facility	Facility Owned Land Provided	N/A
Fort McMurray, Alberta Aurora Mine Site	Satellite office and equipment facility—all operations	Building Leased Land Provided	month-to-month
Fort McMurray, Alberta Albian Sands Mine Site	Satellite office and equipment facility—all operations	Building Leased Land Provided	month-to-month
New Westminster, British Columbia	Regional office and equipment repair facility piling operations	Building Owned Land Leased	3/31/2010
Fort Nelson, British Columbia	Satellite office—pipeline operations	Leased	7/10/2008
Regina, Saskachewan	Regional office and equipment repair facility—piling operations	Leased	3/14/2008
Martensville, Saskachewan	Regional office and equipment repair facility—piling operations	Leased	5/31/2012
Calgary, Alberta	Satellite office and shop for micropile division	Leased	month-to-month
Edmonton, Alberta	Satellite office and warehouse storage facility	Leased	3/31/2017
Edmonton, Alberta	Termporary satellite office	Leased	month-to-month

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

None

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ITEM 5: OPERATING AND FINANCIAL REVIEW AND PROSPECTS

A. OPERATING RESULTS

Reorganization and Initial Public Offering (“IPO”)

On November 28, 2006, prior to the consummation of the IPO discussed below, NACG Holdings Inc. (“Holdings”) amalgamated with its wholly-owned subsidiaries, NACG Preferred Corp. and North American Energy Partners Inc. (“NAEPI”). The amalgamated entity continued under the name North American Energy Partners Inc. The voting common shares of the new entity, North American Energy Partners Inc., were the shares sold in the IPO.

On November 28, 2006, prior to the amalgamation, the following transactions took place:

• Holdings repurchased the Series A preferred shares issued by NAEPI for their redemption value of $1.0 million and terminated the advisory services agreement (the “Advisory Services Agreement”) with The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc., and SF Holding Corp. (collectively, the “Sponsors”), under which we had received ongoing consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. We paid the Sponsors a fee of $2.0 million to terminate the agreement, which was charged to income in 2007. Under the consulting and advisory services agreement, the Sponsors also received a fee of $0.9 million, equal to 0.5% of our aggregate gross proceeds from the IPO, which was included in share issue costs.

• The $35.0 million of Series A preferred shares issued by NACG Preferred Corp. were acquired by Holdings for a $27.0 million promissory note issued to the holders of such shares and the forfeiture of accrued dividends of $1.4 million.

• Each holder of the Series B preferred shares issued by NAEPI received 100 Holdings common shares for each Series B preferred share held.

On November 28, 2006 we completed our IPO in the United States and Canada of 8,750,000 voting common shares for $18.38 per share (U.S. $16.00 per share). On November 22, 2006 our common shares commenced trading on the New York Stock Exchange and on an “if, as and when issued” basis on the Toronto Stock Exchange. On November 28, 2006, our common shares became fully tradable on the Toronto Stock Exchange. Net proceeds from the IPO were $140.9 million (gross proceeds of $158.5 million, less underwriting discounts and costs and offering expenses of $17.6 million). In addition, on December 6, 2006, the underwriters exercised their option to purchase an additional 687,500 common shares from us. The net proceeds from the exercise of the underwriters’ option were $11.7 million (gross proceeds of $12.6 million, less underwriting fees of $0.9 million). Total net proceeds were $152.6 million (total gross proceeds of $171.1 million less total underwriting discounts and costs and offering expenses of $18.5 million).

We used the net proceeds from the IPO:

• to repurchase all of our outstanding 9% senior secured notes due 2010 for $74.7 million plus accrued interest of $3.0 million on November 28, 2006. The notes were repurchased at a premium of 109.26%, resulting in a loss on extinguishment of $6.3 million and the write-off of deferred financing fees of approximately $4.3 million and third-party transaction costs of $0.3 million. These items were charged to income in 2007;

• to repay the $27.0 million promissory note issued in respect of the repurchase of the NACG Preferred Corp. Series A preferred shares;

• to purchase certain leased equipment for $44.6 million;

• to pay the $2.0 million fee required to terminate the Advisory Services Agreement with the Sponsors; and

• $1.3 million for general corporate purposes.

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Following the offering and the above noted transactions the number of issued and outstanding common shares of the Company was 35,604,660.

The impact of the reorganization and IPO on income before income taxes and EBITDA (as defined below) for the year ended March 31, 2007 is as follows:

	Income before income taxes			EBITDA
	(in thousands)
Accretion of NAEPI Series A preferred shares	$	(625	)	$	(625	)
Termination of Advisory Services Agreement		(2,000	)		(2,000	)
Loss on retirement of 9% senior secured notes		(10,935	)		(6,338	)
Gain on repurchase NACG Preferred Corp. Series A preferred shares		9,400			9,400
	$	(4,160	)	$	437

Consolidated Financial Highlights

	Year Ended March 31,
	2007				2006					2005
	(in thousands)
Revenue	$	629,446			$	492,237				$	357,323
Gross profit		92,436	14.7	%		80,326		16.3	%		36,166		10.1	%
General & administrative costs		39,769	6.3	%		30,903		6.3	%		22,873		6.4	%
Operating income		51,126	8.1	%		49,426		10.0	%		9,431		2.6	%
Net income (loss)		21,079	3.3	%		(21,941	)	(4.3	%)		(42,323	)	(11.8	%)
Per unit/share information
Net Income (loss)—basic		0.87				(1.18	)				(2.28	)
Net income (loss)—diluted		0.83				(1.18	)				(2.28	)
EBITDA(1)		87,351	13.9	%		70,027		14.2	%		10,684		3.0	%
Consolidated EBITDA(1)		90,235	14.3	%		72,422		14.7	%		34,448		9.6	%

(1) 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, gain or loss on disposal of plant and equipment and certain other non cash items included in the calculation of net income (loss). 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 interest coverage ratio and a maximum senior leverage ratio, which are calculated using Consolidated EBITDA. Non-compliance with these financial covenants could result in our being required to immediately repay all amounts outstanding under our revolving credit facility. 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 US GAAP. A reconciliation of net income (loss) to EBITDA is as follows:

	Year ended March 31,
	2007			2006			2005
	(in thousands)
Net income (loss)	$	21,079		$	(21,941	)	$	(42,323	)
Adjustments:
Interest expense		37,249			68,776			31,141
Income taxes		(2,593	)		737			(2,264	)
Depreciation		31,034			21,725			20,762
Amortization of intangible assets		582			730			3,368
EBITDA	$	87,351		$	70,027		$	10,684

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A reconciliation of EBITDA to Consolidated EBITDA is as follows:

	Year ended March 31,
	2007			2006			2005
	(in thousands)
EBITDA	$	87,351		$	70,027		$	10,684
Adjustments:
Unrealized foreign exchange (gain) loss on senior notes		(5,017	)		(14,258	)		(20,340	)
Realized and unrealized loss on derivative financial instruments		(196	)		14,689			43,113
Loss (gain) on disposal of plant and equipment		959			(733	)		494
Stock-based compensation		2,101			923			497
Write-off of deferred financing costs		4,342			1,774			—
Write-down of other assets to replacement cost		695			—			—
Consolidated EBITDA	$	90,235		$	72,422		$	34,448

For Year Ended March 31, 2007 Compared to March 31, 2006

For the year ended March 31, 2007, our consolidated revenue increased to $629.4 million, from $492.2 million in 2006. While gains were achieved in all operating segments, the $137.2 million, or 27.9%, improvement was primarily due to increased project work in the Mining and Site Preparation segment, most notably at Albian’s Jackpine Mine.

Gross profit increased by 15.1% to $92.4 million in 2007, from $80.3 million in 2006 as a result of the increased revenue. As a percentage of revenue, gross profit declined to 14.7% in 2007, from 16.3% in 2006 resulting from losses on three pipeline projects. Gross profit was also reduced by a $3.6 million impairment charge recognized on a major piece of construction equipment and higher operating expenses. The increase in operating expenses reflects higher equipment, repair and maintenance, and shop overhead costs related to our fleet expansion, increased activity and escalating tire costs. Operating lease expense also increased in 2007 reflecting the addition of new leased equipment to support new projects, including the 10-year CNRL overburden removal project. The impact of higher operating costs and reduced Pipeline profitability was partially offset by improved project performance in the Mining & Site Preparation and Piling segments.

Operating income for 2007 increased to $51.1 million, from $49.4 million in 2006. This $1.7 million, or 3.4%, improvement was primarily due to the $12.1 million increase in gross profit discussed above, partially offset by a $8.9 million, or 28.7%, increase in general and administrative costs. The increase in general and administrative costs reflects increased employee costs related to our growing employee base, the payment of fees to the Sponsors for termination of the Advisory Services Agreement and higher professional fees for audit, legal and general consulting services. We recorded a loss of $1.0 million on the disposal of plant and equipment as a result of the sale and write down of certain heavy equipment, compared to a gain of $0.7 million in 2006.

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

Consolidated 2006 revenue increased to $492.2 million from $357.3 million in 2005. This $134.9 million, or 37.8%, improvement was due to increased project work in the Mining and Site Preparation segment, as well as growth in our Piling division.

Gross profit in 2006 increased to $80.3 million from $36.2 million in 2005, and as a percentage of revenue, gross profit increased to 16.3%, from 10.1% in 2005. The increase in gross profit reflects improved project performance in the Mining and Site Preparation and Piling segments and the recognition of $12.9 million of revenue from claims and unapproved change orders, in 2006 for which corresponding costs were recognized in 2005. These favorable impacts were partially offset by an increase in equipment costs, operating lease expense and depreciation. The increase in equipment costs and depreciation was primarily due to increased fleet size and activity levels, higher repair and maintenance costs caused by increased usage of larger equipment, increased

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cost of parts, primarily tires, and overhead and shop costs. The increase in operating lease expense for 2006 primarily relates to the addition of new leased equipment to support new projects, including the 10-year CNRL overburden removal project.

Operating income for 2006 increased to $49.4 million, from $9.4 million in 2005. This $40.0 million, or 424.1%, increase reflects the $44.1 million increase in gross profit discussed above, partially offset by higher general and administrative costs. General and administrative costs increased by $8.0 million, or 35.1%, as a result of increased professional fees relating to financing transactions in 2006, increased employee costs and higher bonuses. We also recorded a gain of $0.7 million on disposal of plant and equipment in 2006, compared to a loss of $0.5 million in 2005.

Segment Operations

Segment profit is determined based on internal performance measures used to assess the performance of each business in a given period. Segmented profit includes revenue earned from the performance of our projects, including amounts arising from change orders and claims, less all direct projects expenses, including direct labour, short-term equipment rentals, materials, payments to subcontractors, indirect job costs and internal charges for use of capital equipment.

	Year ended March 31,
	2007					2006				2005
	(in thousands)
Revenue by operating segment:
Mining and site preparation	$	473,179		75.2	%	$	366,721	74.5	%	$	264,835	74.1	%
Piling		109,266		17.3			91,434	18.6			61,006	17.1
Pipeline		47,001		7.5			34,082	6.9			31,482	8.8
Total	$	629,446		100.0	%	$	492,237	100.0	%	$	357,323	100.0	%
Segment profit:
Mining and site preparation	$	71,062		74.9	%	$	50,730	61.7	%	$	11,617	38.9	%
Piling		34,395		36.2			22,586	27.4			13,319	44.6
Pipeline		(10,539	)	(11.1	)		8,996	10.9			4,902	16.5
Total	$	94,918		100.0	%	$	82,312	100.0	%	$	29,838	100.0	%
Equipment hours by operating segment:
Mining and site preparation		909,361		91.6	%		811,891	93.0	%		673,613	88.2	%
Piling		47,965		4.8			37,300	4.3			56,460	7.4
Pipeline		35,588		3.6			24,197	2.8			33,847	4.4
Total		992,914		100.0	%		873,388	100.0	%		763,920	100.0	%

Mining and Site Preparation

For Year Ended March 31, 2007 Compared to March 31, 2006

Mining and Site Preparation revenue increased 29.0% to $473.2 million in 2007, from $366.7 million in 2006. The growth in revenue was primarily due to higher oil sands activity relating to large site preparation projects at Albian’s Jackpine Mine and Birch Mountain Resources, combined with the continued ramp up on the CNRL overburden removal project and the De Beers Victor Mine project in northern Ontario.

Segment profit from our Mining and Site Preparation activities increased 40.1%, to $71.1 million, from $50.7 million in 2006, reflecting increased revenues. Segment profit in 2007 also benefited from the

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recognition of $12.7 million in claims revenue related to two large site preparation project completed in 2006 and 2005. The corresponding costs of these projects were recognized in fiscal years 2006 and 2005.

For Year Ended March 31,2006 compared to March 31, 2005

Mining and Site Preparation revenue increased 38.5% to $366.7 million in 2006, from $264.8 million in 2005. This increase primarily reflects our involvement in large site preparation, underground utility installation and overburden removal at the CNRL oil sands project in Fort McMurray. We also provided significant mining services for Grande Cache Coal Corporation during the year. In addition, we recognized $12.9 million of revenue from claims and unapproved change orders for 2006 in which corresponding costs were recognized in previous years.

Mining and Site Preparation segment profit for 2006 increased 336.7% to $50.7 million, from $11.6 million in 2005, reflecting increased project activity, more efficient use of equipment and a loss incurred on a large steam-assisted gravity drainage site project in 2005. Our segment profit also benefited from claims revenue being recognized in 2006 for which corresponding costs were recognized in previous years.

Piling

For Year Ended March 31, 2007 Compared to March 31, 2006

Piling revenue increased 19.5% to $109.3 million, from $91.4 million in 2006. This increase was primarily due to strong economic conditions, which supported a higher volume of construction projects in the Fort McMurray and Calgary regions, and to a single large project in the Edmonton region.

Piling segment profit increased 52.3% to $34.4 million, from $22.6 million in 2006, resulting from increased volume and our execution of higher-margin projects.

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

Piling revenue increased 49.9% to $91.4 million, from $61.0 million in 2005. The increase was driven by a higher volume of projects in the Fort McMurray, Vancouver and Regina regions as a result of the strong economic environment and an increase in construction activities.

Piling segment profit increased 69.6% to $22.6 million, from $13.3 million in 2005, as a result of increased volumes and higher-margin work.

Pipeline

For Year Ended March 31, 2007 Compared to March 31, 2006

Pipeline revenue for 2007 increased 37.9% to $47.0 million, from $34.1 million in 2006, as a result of our involvement in three significant pipeline projects. The increase in 2007 revenue was partially offset by reduced work from Encana.

Our Pipeline segment recorded a loss of $10.5 million in 2007, compared to a profit of $9.0 million in 2006. The 2007 result relates primarily to losses on three large pipeline projects, which were caused primarily by increased scope and condition changes not recovered from our clients. We are currently working through several unapproved change orders and claims as a result of these losses.

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

Our Pipeline revenue increased 8.3% to $34.1 million, from $31.5 million in 2005, primarily as a result of increased work for EnCana and CNRL.

Pipeline profit increased 83.5% to $9.0 million, from $4.9 million in 2005, reflecting the combination of increased volume and higher-margin work during the 2006 period.

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Non-operating expenses (income)

	Year ended March 31,
	2007			2006			2005
	(in thousands)
Interest expense
Interest on long term debt	$	29,542		$	29,295		$	23,419
Accretion and change in redemption value of mandatorily redeemable preferred shares		3,114			34,722			—
Interest on senior secured credit facility		—			564			3,274
Amortization of deferred financing costs		3,436			3,338			2,554
Other interest		1,157			857			1,894
Total interest expense	$	37,249		$	68,776		$	31,141
Foreign exchange loss (gain)	$	(5,044	)	$	(13,953	)	$	(19,815	)
Realized and unrealized (gain) loss on derivative financial instruments		(196	)		14,689			43,113
Gain on repurchase of NACG Preferred Corp. Series A preferred shares		(9,400	)		—			—
Loss on extinguishment of debt		10,935			2,095			—
Other income		(904	)		(977	)		(421	)
Income tax (recovery) expense		(2,593	)		737			(2,264	)

Non-operating expenses (income): For Year Ended March 31, 2007 Compared to March 31, 2006

Total interest expense decreased by $31.5 million in 2007 compared to 2006, primarily due to the amendment to the terms of NAEPI’s mandatorily redeemable Series B preferred shares on March 30, 2006 (as described in note 17(a) to the 2007 annual consolidated financial statements). Changes in the redemption value of the Series B preferred shares were charged to interest expense prior to the amendment date. In 2007, the accretion of redeemable preferred shares amounted to $2.5 million of interest expense, compared to $34.7 million in 2006 which related to both accretion and change in redemption value of mandatory redeemable preferred shares. In addition, as a result of the repurchase of NAEPI’s Series A preferred shares, $0.6 million of additional interest expense was recognized for 2007, in order to accrete up to the full redemption value of $1.0 million for these preferred shares. On November 28, 2006, each Series B preferred share was exchanged for 100 common shares of Holdings. On exchange, the carrying amount of the preferred shares, $44.7 million, was reclassified to common stock.

Substantially all of the $5.0 million foreign exchange gain recognized in 2007 relates to the exchange difference between the Canadian and U.S. dollar on conversion of the US$60.5 million of 9% senior secured notes (subsequently retired on November 28, 2006) and the US$200.0 million of 8 ³/4% senior notes.

We recorded a $0.2 million realized and unrealized gain on derivative financial instruments in 2007, compared to a $14.7 million realized and unrealized loss in 2006. We employ derivative financial instruments to provide an economic hedge for our 8 ³/4% senior notes. The subsequent gain or loss reflects changes in the fair value of these derivatives. See “Liquidity and Capital Resources—Liquidity Requirements” for further information regarding these derivative financial instruments.

We recognized a 2007 gain of $9.4 million on the repurchase of $27.0 million of the $35.0 million of NACG Preferred Corp. Series A preferred shares and related forfeited dividends of $1.4 million. Upon retiring NAEPI’s 9% senior secured notes, we recorded a loss of $10.9 million, which includes a $6.3 million loss on extinguishment of the notes, a $4.3 million write-off of deferred financing fees and related transaction costs of $0.3 million.

We recorded an income tax recovery of $2.6 million in 2007, compared to an income tax expense of $0.7 million for 2006. The effective rate is significantly lower than the statutory tax rate primarily due to the impact of the enacted rate changes during the year, the reversal of the valuation allowance that existed at March 31, 2006 and the net impact of permanent differences relating to various income (charges) recognized for accounting

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purposes related to mandatorily redeemable shares and other financing transactions which were non-taxable. Income tax expense in the prior year primarily reflects the federal large corporation tax, which is a form of minimum tax, as a full valuation allowance was recorded against our net future tax asset given the uncertainty of recognizing the benefit of the net future tax asset at the end of 2006.

Non-operating expenses (income): For Year Ended March 31, 2006 Compared to March 31, 2005

Our total interest expense increased by $37.6 million in 2006 compared to 2005, primarily due to interest charges of $34.7 million resulting from the issuance in May 2005 of NAEPI’s mandatorily redeemable Series B preferred shares and a $5.9 million increase in interest on long-term debt resulting from the issuance in May 2005 of NAEPI’s 9% senior secured notes. These increases in interest expense were partially offset by decreased interest expense resulting from the full repayment in May 2005 of the borrowings under NAEPI’s senior secured credit facility.

Substantially all of the $14.0 million foreign exchange gain recognized in 2006 relates to the exchange difference between the Canadian and U.S. dollar on conversion of the US$60.5 million of 9% senior secured notes and the US$200.0 million of 8 ³/4% senior notes. By comparison, our 2005 foreign exchange gain related only to the US$200.0 million of 8 ³/4% senior notes.

In 2006, we recorded a $14.7 million realized and unrealized loss on derivative financial instruments relating to the change in the fair value of these derivatives. By comparison, we recorded a realized and unrealized loss of $43.1 million on our derivative financial instruments in 2005. See “Liquidity and Capital Resources—Liquidity requirements” for further information regarding the derivative financial instruments.

We recognized a loss on extinguishment of debt of $2.1 million in 2006 as a result of $0.3 million of issue costs related to NAEPI’s Series A preferred shares and the write off of deferred financing fees of $1.8 million resulting from the May 2005 repayment of NAEPI’s previous senior secured credit facility.

We recorded an income tax expense of $0.7 million in 2006, compared to a net income tax recovery of $2.3 million in 2005. Income tax expense primarily reflects only the federal large corporation tax, which was a form of minimum tax, as a full valuation allowance was recorded against our net future tax asset given the uncertainty of recognizing the benefit of the net future tax asset at the end of 2006.

Comparative Quarterly Results

A number of factors contribute to variations in our quarterly results between periods, including 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.

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We generally experience a decline in revenues during the first quarter of each fiscal year due to seasonality, as weather conditions make operating during this period difficult. The level of activity in the Mining and Site Preparation and Pipeline 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 it has a direct impact on our activity levels. Revenues during the fourth quarter of each fiscal year are typically highest as ground conditions are most favourable in our operating regions. As a result, full-year results are not likely to be a direct multiple of any particular quarter or combination of quarters.

	Fiscal Year 2007									Fiscal Year 2006
	Q4		Q3		Q2			Q1		Q4		Q3		Q2		Q1
	( dollars in millions, except per share amounts)
Revenue	$	205.3	$	155.9	$	130.1		$	138.1	$	142.3	$	121.5	$	124.0	$	104.4
Gross profit		13.6		26.0		20.2			32.6		31.7		13.8		21.9		12.9
Operating income		4.5		13.8		9.7			23.1		22.4		5.9		15.9		5.2
Net income(loss)		1.4		6.6		(4.8	)		17.9		13.7		2.1		11.5		(49.2	)
EPS—basic(1)		0.04		0.27		(0.26	)		0.96		0.73		0.11		0.62		(2.65	)
EPS—diluted(1)		0.04		0.26		(0.26	)		0.71		0.73		0.11		0.47		(2.65	)
Equipment hours		268,565		239,341		236,711			248,297		231,633		221,355		234,649		185,751

(1) Net income (loss) per share for each quarter has been computed based on the weighted average number of shares issued and outstanding during the respective quarter; therefore, quarterly amounts may not add to the annual total. Per share calculations are based on full dollar and share amounts.

Consolidated Fourth Quarter Results: For Three Months Ended March 31, 2007 Compared to March 31, 2006

For the fourth quarter ended March 31, 2007, our consolidated revenue increased to $205.3 million, from $142.3 million in 2006. This $63.0 million, or 44.3%, increase was primarily due to increased project work at Albian’s Jackpine Mine in the Mining and Site Preparation segment, as well as growth in our Pipeline division.

Gross profit decreased by 56.9% to $13.6 million in 2007, from $31.7 million in 2006, as a result of project losses in the Pipeline segment, a $3.6 million asset impairment charge and higher equipment operating expenses. Equipment costs were driven by higher activity levels, significant increases in tire costs and increased shop labour and overhead. Operating lease expense decreased in the fourth quarter of 2007 due to the buy out of numerous leases as part of the proceeds from the IPO. As a result of the pipeline losses, asset impairment charge and higher equipment operating costs, gross profit as a percentage of revenue, was 6.6% in 2007, compared to 22.3% in 2006.

Operating income for the fourth quarter ended March 31, 2007 decreased to $4.5 million, from $22.4 million in 2006. This $17.9 million, or 79.9%, decrease was due to the reduction in gross profit discussed above. General and administrative costs remained largely unchanged in the fourth quarter ended March 31, 2007 as increased stock compensation expense was offset by decreased employee costs.

Segmented Fourth Quarter Results: For Three Months Ended March 31, 2007 Compared to March 31, 2006

Mining and Site Preparation revenue for the fourth quarter ended March 31, 2007 increased 48.9% to $150.1 million in 2007, from $100.9 million in 2006. The growth in revenue was primarily due to higher oil sands and mining activity relating to large site preparation projects at Albian, continued ramp up on the CNRL overburden removal project and increased project work at the De Beers Canada Victor Diamond Mine in northern Ontario. Piling revenue for the fourth quarter ended March 31, 2007 increased 6.2% to $29.9 million, from $28.1 million in 2006. This increase was primarily due to higher volume of construction projects in the Fort McMurray region and a large project in the Edmonton region. Pipeline revenue increased 91.0% to $25.4 million, from $13.3 million in 2006, as a result of a large pipeline project for Suncor.

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Segment profit from our Mining and Site Preparation activities decreased 0.6%, to $23.5 million, from $23.6 million in 2006. Increased revenues and a claim settlement related to a large site preparation project completed in fiscal 2006, was entirely offset by margin reductions on a large site preparation project in the fourth quarter of 2007. Challenging soil and water conditions on this project resulted in the recognition of $4.7 million in additional costs, with no associated revenue. We are actively negotiating change orders with the client relating to these changed conditions. Fourth quarter Piling segment profit increased 6.1% to $8.8 million in 2007, from $8.3 million in 2006, reflecting the impact of increased volume. Our Pipeline segment recorded a loss of $9.8 million for the fourth quarter ended March 31, 2007, compared to a profit of $3.9 million in 2006. This change in profitability reflects the negative impact of increased scope, condition changes and difficult weather conditions on a large pipeline project that resulted in $8.0 million of additional costs being recognized during the quarter without any associated revenue. We are in the process of requesting change orders from our customers to recover all or a portion of these additional costs, but did not meet the criteria to recognize this revenue for the fourth quarter ended March 31, 2007.

Consolidated Financial Position

	March 31, 2007			March 31, 2006			% Change
	(in thousands)
Current assets	$	229,061		$	161,628		41.7	%
Current liabilities		(148,789	)		(92,096	)	61.6	%
Working capital		80,272			69,532		15.4	%
Plant and equipment		255,963			184,562		38.7	%
Total assets		710,736			568,682		25.0	%
Capital Lease obligations (including current portion)		(9,709	)		(10,952	)	(11.3	%)
Total long-term financial liabilities		(297,957	)		(453,092	)	(34.2	%)

At March 31, 2007, we had net working capital (current assets less current liabilities) of $80.3 million, compared to $69.5 million at March 31, 2006. The increase in working capital resulted from an increase in accounts receivable and unbilled revenue as a result of increased projects in process, partially offset by a reduction of cash due to capital equipment purchases and an increase in borrowings from our secured credit facility.

Plant and equipment, net of depreciation, increased by $71.4 million from March 31, 2006 to March 31, 2007 primarily as a result of the acquisition of several large mining trucks and the buy-out of certain leased equipment using the proceeds of the IPO.

Capital lease obligations, including the current portion, decreased by $1.2 million from March 31, 2006 to March 31, 2007 due to required repayments, the sale of a drill rig and repayment of the associated obligations, partially offset by the addition of new vehicles acquired by means of capital lease.

Total long-term financial liabilities are determined as non-current liabilities, excluding current portion of capital lease obligations and future income taxes. The decrease in 2007 is primarily as a result of the amalgamation and the IPO, as described in “Reorganization and Initial Public Offering”.

Backlog

Backlog is a measure of the amount of secured work we have outstanding and as such is an indicator of future revenue potential. Backlog is not a GAAP measure and as a result, the definition and determination will vary among different organizations ascribing a value to backlog. Although backlog reflects business that we consider to be firm, cancellations or reductions may occur and may reduce backlog and future income. We did not measure this amount in the prior year.

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We define backlog as that work that has a high certainty of being performed as evidenced by the existence of a signed contract or work order specifying job scope, value and timing. We have also set a policy that our definition of backlog will be limited to contracts or work orders with values exceeding $500,000 and work that will be performed in the next five years, even if the related contracts extend beyond five years.

We work with our customers using cost-plus, time-and-materials, unit-price and lump-sum contracts, and the mix of contract types varies year-by-year. For 2007, our contract revenue consisted of 6% cost-plus, 28% time-and-materials, 53% unit-price and 13% lump-sum. Our definition of backlog results in the exclusion of cost-plus and time-and-material contracts performed under master service agreements. While contracts exist for a range of services to be provided, the work scope and value are not clearly defined under those contracts. For 2007, the total amount of all cost-plus and time-and-material based revenue was $220.9 million (34% of total revenues).

Our estimated backlog as at March 31, 2007 was (in millions):

By Segment			By Contract Type
Mining & Site Preparation	$	732.0	Unit-Price	$	778.0
Piling		40.0	Lump-Sum		10.0
Pipeline		16.0	Time & Material, Cost-Plus		—
Total	$	788.0	Total	$	788.0

A contract with a single customer represented approximately $680 million of the March 31, 2007 backlog. It is expected that approximately $255 million of the backlog will be performed and realized in 2008.

Claims and Unapproved Change Orders

Due to the complexity of the projects we undertake, changes often occur after work has commenced. These changes include, but are not limited to:

• Client requirements, specifications and design

• Materials and work schedules

• Changes in anticipated ground and weather conditions

Contract change management processes require that we prepare and submit change orders to the client requesting approval of scope and/or price adjustments to the contract. Accounting guidelines require that management consider changes in cost estimates that have occurred up to the release of the financial statements and reflect the impact of these changes in the financial statements. Conversely, potential revenue associated with increases in cost estimates is not included in financial statements until an agreement is reached with the client or specific criteria for the recognition of revenue from unapproved change orders and claims are met. This can, and often does, lead to costs being recognized in one period and revenue being recognized in subsequent periods.

Occasionally, disagreements arise regarding changes, their nature, measurement, timing, and other characteristics that impact costs and revenue under the contract. If a change becomes a point of dispute between our customer and us, we then consider it as a claim. Historical claim recoveries should not be considered indicative of future claim recoveries.

As a result of changed conditions discussed above, we have recognized $18 million in additional contract costs from a number of contracts for the year ended March 31, 2007, with no associated increase in contract value. We are working with our customers to come to resolution on the amounts, if any, to be paid to us in respect to these additional costs.

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Outstanding Share Data

We are authorized to issue an unlimited number of common voting shares and an unlimited number of common non-voting shares. As at June 8, 2007, 35,292,260 common voting shares were outstanding and 412,400 common non-voting common shares were outstanding compared to 18,207,600 and 412,400, respectively, as at March 31, 2006. We had no outstanding preferred shares at March 31, 2007.

Stock-Based Compensation

Some of our directors, officers, employees and service providers have been granted options to purchase common shares under the Amended and Restated 2004 Share Option Plan. In June and September 2006 we granted 127,760 and 187,760 options, respectively, with an exercise price of $5.00 and $16.75 per share, respectively. In September 2006, we had a valuation performed by an unrelated valuation specialist, which valued our common shares at $16.10 per share. The plan and outstanding balances are disclosed in note 25 to our consolidated financial statements for 2007.

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 Step 1 of this test during the quarter ended December 31, 2006 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 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 contracts are generally less than one year in duration, we do have several long-term contracts. The mix of contract types varies year-by-year. For the year ended March 31, 2007, our contracts consisted of 6% cost-plus, 28% time-and-materials, 53% unit-price and 13% 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. Claims and unapproved change orders are included in

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total estimated contract revenue, only to the extent that contract costs related to the claim or unapproved change order have been incurred, when it is probable that the claim or unapproved change order will result in a bona fide addition to contract value and the amount of revenue can be reliably estimated.

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, sizable changes in cost estimates, particularly in larger, more complex projects, can have a significant effect on profitability.

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

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

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

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

• the availability and proximity of materials;

• unfavorable weather conditions hindering productivity;

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

• 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 have long lives 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 monthly based on daily actual operating 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 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.

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Goodwill

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

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. The primary factors affecting fair value are the changes in the interest rate term structures in the US and Canada, the life of the swap and the CAD/USD foreign exchange spot rate.

Recently Adopted Canadian Accounting Pronouncements

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 early 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.

Stock-based compensation for employees eligible to retire before the vesting date

In July 2006, the CICA Emerging Issues Committee issued Abstract No. 162, ‘‘Stock-Based Compensation for Employees Eligible to Retire Before the Vesting Date’’ (‘‘EIC-162’’). EIC-162 requires that the compensation cost attributable to awards granted to employees eligible to retire at the grant date should be recognized on the grant date if the award’s exercisability does not depend on continued service. Additionally, awards granted to employees who will become eligible to retire during the vesting period should be recognized over the period from the grant date to the date the employee becomes eligible to retire. The Company adopted this standard for the interim period ended December 31, 2006 retroactively, with restatement of prior periods for all stock-based compensation awards. The adoption of this standard had no impact on the Company’s consolidated financial statements.

Determining the variability to be considered in applying the VIE standards

In September 2006, the CICA issued Emerging Issues Committee Abstract No. 163, “Determining the Variability to be Considered in Applying AcG-15” (“EIC-163”). This guidance provides additional clarification on how to analyze and consolidate a VIE. EIC-163 concludes that the “by-design” approach should be the method used to assess variability (that is created by risks the entity is designed to create and pass along to its interest holders) when applying the VIE standards. The “by-design” approach focuses on the substance of the risks created over the form of the relationship. The guidance may be applied to all entities (including newly created entities) with which an enterprise first becomes involved and to all entities previously required to be analyzed under the VIE standards when a reconsideration event has occurred and is effective for interim and annual periods beginning on or after January 1, 2007. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

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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. 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.

Effective April 1, 2007, the Company will also be required to adopt CICA Handbook Section 3861, “Financial Instruments—Disclosure and Presentation” (“CICA 3861”), which requires entities to provide disclosures in their financial statements that enable users to evaluate: (1) the significance of financial instruments on the entity’s financial performance; and (2) the nature and extent of risks arising from the use of financial instruments by the entity during the period and at the balance sheet date, and how the entity manages those risks. The Company is currently assessing the impact of this standard.

In March 2007, the CICA issued Handbook Section 3862, “Financial Instruments—Disclosures”, which replaces CICA 3861 and provides expanded disclosure requirements that provide additional detail by financial assets and liability categories. This standard harmonizes disclosures with International Financial Reporting Standards. The standard applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.

In March 2007, the CICA issued Handbook Section 3863, “Financial Instruments—Presentation” to enhance financial statement users’ understanding of the significance of financial instruments to an entity’s financial position, performance and cash flows. This Section establishes standards for presentation of financial instruments and non-financial derivatives. It deals with the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, gains and losses, and the circumstances in which financial assets and financial liabilities are offset. This standard harmonizes disclosures with International Financial Reporting Standards and applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.

Equity

On April 1, 2007, the Company will adopt CICA Handbook Section 3251, “Equity”, which establishes standards for the presentation of equity and changes in equity during the reporting period. The requirements in this section are in addition to those of CICA Handbook Section 1530 and recommend that an enterprise should present separately the following components of equity: retained earnings, accumulated other comprehensive income, and the total for retained earnings and accumulated other comprehensive income, contributed surplus, share capital and reserves. The Company is currently evaluating the impact of this standard.

Accounting changes

In July 2006, the CICA revised Handbook Section 1506, “Accounting Changes”, which requires that: (1) voluntary changes in accounting policy are made only if they result in the financial statements providing reliable and more relevant information; (2) changes in accounting policy are generally applied retrospectively;

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and (3) prior period errors are corrected retrospectively. This revised standard is effective for fiscal years beginning on or after January 1, 2007, specifically April 1, 2007 for the Company, and is not expected to have a material impact on the Company’s consolidated financial statements.

Capital disclosures

In December 2006, the CICA issued Handbook Section 1535, “Capital Disclosures”. This standard requires that an entity disclose information that enables users of its financial statements to evaluate an entity’s objectives, policies and processes for managing capital, including disclosures of any externally imposed capital requirements and the consequences of non-compliance. The new standard applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.

Inventories

In June 2007, the CICA issued Handbook Section 3031, “Inventories” to harmonize accounting for inventories under Canadian GAAP with International Financial Reporting Standards. This standard requires the measurement of inventories at the lower of cost and net realizable value and includes guidance on the determination of cost, including allocation of overheads and other costs to inventory. The standard also requires the consistent use of either first-in, first out (FIFO) or weighted average cost formula to measure the cost of other inventories and requires the reversal of previous write-downs to net realizable value when there is a subsequent increase in the value of inventories. The new standard applies to interim and annual financial statements relating to fiscal years beginning on or after January 1, 2008, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.

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 27 to our consolidated financial statements.

United States accounting pronouncements recently 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 adopted SFAS 123R prospectively since we use the minimum value method for purposes of complying with Statement 123. The adoption of this standard did not have a material impact on our consolidated financial statements.

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 Opinion 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 was effective for the Company for accounting changes and corrections of errors made by the Company in its fiscal year beginning on April 1, 2006. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

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In September 2006, the U.S. Securities and Exchange Commission issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. It establishes an approach that requires quantification of financial statements misstatements based on the effects of the misstatements on each of the Company’s financial statements and the related financial statement disclosures. SAB 108 was effective for the Company’s annual financial statements for the fiscal year ending March 31, 2007. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

Recent United States accounting pronouncements not yet adopted

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 2008 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 the Company’s 2008 fiscal year. The Company is currently reviewing the impact of this Interpretation.

In May 2007, the FASB issued FASB Staff Position No. FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48”, which provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. This FASB Staff Position is effective upon the initial adoption of FIN 48 and the Company is currently assessing the impact of this guidance.

Statement of Financial Accounting Standards No. 157, “Fair Value Measurement” (“SFAS 157”) was issued September 2006. The Statement provides guidance for using fair value to measure assets and liabilities. The Statement also expands disclosures about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurement on earnings. This Statement applies under other accounting pronouncements that require or permit fair value measurements. This Statement does not expand the use of fair value measurements in any new circumstances. Under this Statement, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. SFAS 157 is effective for the Company for fair value measurements and disclosures made by the Company in its fiscal year beginning on April 1, 2008. The Company is currently reviewing the impact of this statement.

Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”) was issued in February 2007. The statement permits entities to choose to measure many financial instruments and certain other items at fair value, providing the opportunity to mitigate

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volatility in reported earnings caused by measuring related assets and liabilities differently without the need to apply hedge accounting provisions. SFAS 159 is effective for fiscal years beginning after November 15, 2007, specifically April 1, 2008 for the Company, with earlier adoption permitted. The Company is currently reviewing the impact of this pronouncement.

B. LIQUIDITY AND CAPITAL RESOURCES

	Year Ended March 31,
	2007			2006			2005
	(in thousands)
Cash provided by (used in) operating activities	$	10,052		$	35,092		$	(5,673	)
Cash used in investing activities		(107,972	)		(23,396	)		(24,215	)
Cash provided by financing activities		63,011			13,184			11,217
Net increase (decrease) in cash and cash equivalents	$	(34,909	)	$	24,880		$	(18,671	)

Operating activities

Operating activities in 2007 resulted in a net increase in cash of $10.1 million, compared to an increase of $35.1 million in 2006 and a decrease of $5.7 million in 2005. The lower cash generated in 2007 compared to 2006 is the result of movements in net non-cash working capital from increased accounts receivable balances and tire purchases including deposits on tire purchases. The higher cash generated in 2006 compared to 2005 reflects improved earnings performance and the increased add back of non-cash items related to unrealized gains or losses on financial instruments and movements in future income taxes.

Investing activities

Sustaining capital expenditures are those that are required to keep our existing fleet of equipment at its optimal useful life through capital maintenance or replacement. Growth capital expenditures relate to equipment additions required to perform larger or a greater number of projects.

During 2007, we invested $7.6 million in sustaining capital expenditures (2006 – $7.4 million; 2005 – $7.5 million) and invested $102.4 million in growth capital expenditures (2006 – $21.5 million; 2005 – $17.3 million), for total capital expenditures of $110.0 million (2006 – $28.9 million; 2005 – $24.8 million). The significant increase in 2007 growth capital expenditures compared to the previous two years reflects the purchase of certain leased equipment for $44.6 million using a portion of the net IPO proceeds and the purchase of several large trucks to accommodate the increasing volume of available work.

Financing activities

Financing activities in 2007 resulted in a cash inflow of $63.0 million primarily provided by the net proceeds of our IPO as described in the following paragraph, partially offset by the repayment of our 9% senior secured notes. Financing activities during 2006 resulted in net cash inflow of $13.2 million. This inflow reflects proceeds received from our May 19, 2005 issuance of the US$60.5 million of 9% senior secured notes and $7.5 million of Series B preferred shares of NAEPI. A portion of the proceeds from these issues was used to repay the amount outstanding under our senior secured credit facility at the time. Financing activities during 2005 resulted in a net cash inflow of $11.2 million, which related primarily to net borrowings under our revolving credit facility and repayment of capital lease obligations.

In connection with our IPO on November 28, 2006, which was completed after the transactions and amalgamation described above under the heading “Initial Public Offering and Reorganization,” we received net proceeds of $152.6 million (gross proceeds of $171.2 million, less underwriting discounts and commissions and

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offering expenses of $18.5 million). We used net proceeds from the offering to purchase certain equipment under operating leases for $44.6 million, to repurchase all of our outstanding 9% senior secured notes due in 2010 for $74.7 million plus accrued interest of $3.0 million, to repay the $27.0 million promissory note issued in respect of the repurchase of the NACG Preferred Corp. Series A preferred shares and to pay the $2.0 million fee to terminate the Advisory Services Agreement with the Sponsors.

Liquidity Requirements

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

Our long-term debt includes US$200 million of 8 ³/4% senior notes due in 2011. The foreign currency risk relating to both the principal and interest payments on these senior notes has been managed with a cross-currency swap and interest rate swaps, which went into effect concurrent with the issuance of the notes on November 26, 2003. Interest totaling $13.0 million on the 8 ³/4% senior notes and the swap is payable semi-annually in June and December of each year until the notes mature on December 1, 2011. The swap agreements are an economic hedge, but has not been designated as a hedge for accounting purposes. There are no principal repayments required on the 8 ³/4% senior notes until maturity.

On November 28, 2006, we repurchased all of the outstanding 9% senior secured notes due in 2010 with a portion of the net proceeds from our IPO as described above.

One of our major customer contracts allows the customer to require that we provide up to $50 million in letters of credit. As at March 31, 2007, we had provided $25.0 million in letters of credit in connection with this contract. Any increase in the value of the letters of credit required by this customer must be requested by November 1, 2007 for an issue date of January 1, 2008.

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, they are replaced as it becomes cost prohibitive to continue to maintain them. As a result, we are continually acquiring new equipment to replace retired units and to support growth as new projects are awarded to us. It is important to adequately maintain a 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 maintain a balance of owned and leased equipment, we have financed a portion of our large pieces of heavy construction equipment through operating leases. In addition, we continue to lease our motor vehicle fleet.

Our cash requirements during 2007 increased due to continued growth and additional operating and capital expenditures associated with new projects. Our cash requirements for 2008 include funding operating lease obligations, debt and interest repayment obligations and working capital.

We expect our sustaining capital expenditures to range from $35.0 million to $45.0 million per year over the next two years. We expect our total capital expenditures in 2008 to range from $75.0 million to $85.0 million. 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 June 7, 2007, our amended and restated revolving credit facility was modified to provide for borrowings of up to $125.0 million under which revolving loans and letters of credit may be issued. Our previous revolving credit facility was subject to borrowing base limitations, under which revolving loans and letters of credit up to a limit of $55.0 million may have been issued. As of March 31, 2007, we had approximately $9.5 million of available borrowings under the revolving credit facility after taking into account $20.5 million of borrowings and

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$25.0 million of outstanding and undrawn letters of credit to support performance guarantees associated with customer contracts. The indebtedness under the revolving credit facility is secured by a first priority lien on substantially all of our existing and after-acquired property.

Our revolving credit facility contains covenants that restrict our activities, including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions. Under the revolving credit facility, Consolidated Capital Expenditures during any applicable period cannot exceed 120% of the amount in the capital expenditure plan. In addition, we are also required to satisfy certain financial covenants, including a minimum interest coverage ratio and a maximum senior leverage ratio, both of which are calculated using Consolidated EBITDA, as well as a minimum current ratio.

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 or if satisfied by the issue of new equity, 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 Canadian GAAP.

Interest coverage is determined based on a ratio of Consolidated EBITDA to consolidated cash interest expense, and the senior leverage is determined as a ratio of senior debt to Consolidated EBITDA. Measured as of the last day of each fiscal quarter on a trailing four-quarter basis, Consolidated EBITDA shall not be less than 2.5 times consolidated cash interest expense (2.35 times at June 30, 2007). Also, measured as of the last day of each fiscal quarter on a trailing four-quarter basis, senior leverage shall not exceed 2 times Consolidated EBITDA. We believe Consolidated EBITDA as defined in the credit facility is an important measure of our liquidity.

C. RESEARCH AND DEVELOPMENT

Not applicable.

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D. TREND INFORMATION

The following charts show our Revenue, Growth in Segment Revenue, Gross Profit, Net Income and Consolidated EBITDA for the three fiscal years 2007, 2006 and 2005.

(1) The compound annual growth rate (“CAGR”)

(2) Refer to “Consolidated Financial Highlights” for a reconciliation of Net income (loss) to Consolidated EBITDA

Our consolidated financial results over the last three years reflect the positive impact of rising natural resource commodity prices on the western Canadian natural resource sector. In particular, our business has benefited from increased oil sands development in Northern Alberta.

According to the Alberta Energy and Utilities Board (“EUB”), Canadian oil sands are estimated to contain nearly 315 billion barrels of oil with established reserves of almost 174 billion barrels as of the end of 2004, however the extraction of oil from bitumen is significantly more complex and costly than in conventional oil operations. In recent years, higher oil prices have made oil sands production economically viable, and a diverse range of oil companies and consortiums are moving swiftly to develop this resource. Interest in the oil sands has been further bolstered by political unrest in the Middle East and the subsequent desire of Western economies to seek oil supplies from more stable regions.

As a leading supplier of construction and mining services to oil sands operators, our business has benefited from these developments. We have significantly grown our equipment fleet and employee base over the past three years to serve the needs of existing oil sands producers like Syncrude Canada Ltd. (“Syncrude”), Suncor

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Energy Inc. (“Suncor”) and Albian Sands Energy Inc. (“Albian”) (a joint venture of Shell Canada Limited, Chevron Canada Limited and Western Oil Sands Inc.). We have also been expanding our relationships with newer operators including Canadian Natural Resources Ltd. (“CNRL”), which is currently developing a bitumen-mining project in the Fort McMurray region of the oil sands.

In 2007, we recorded record revenue of $629.4 million, up from $492.2 million in 2006 and $357.3 million in 2005. This represents a compound annual growth rate of 32.7%. The higher revenues, together with a focus on higher-margin projects led to an even more significant improvement in profitability. Gross profit from our consolidated operations increased to $92.4 million in 2007, from $80.3 million in 2006 and $36.2 million in 2005, representing a compound annual growth rate of 59.8%.

Of our three operating segments, Mining and Site Preparation (74.7% and 64.4% of total three-year consolidated revenues and total three-year segment profits, respectively) has benefited most from oil sands development. This segment has enjoyed significant growth in revenue and gross profit since 2005 as a result of our expanding relationships with oil sands customers, as well as the positive impact of our contract with De Beers Canada at their Victor Diamond Mine in northern Ontario, where we are providing winter road construction and maintenance and overburden removal services. All of the growth in this segment has been achieved organically. Segment profit has increased from $11.6 million in 2005 to $71.1 million in 2007, representing a compound annual growth rate of 147.3%.

Growth in our Piling business (17.7% and 34.0% of total three-year consolidated revenues and total three-year segment profits, respectively) has been driven both by oil sands development and by western Canada’s strong economy, which has supported a high level of commercial and industrial construction activity. In addition, the Piling segment has realized benefits from the acquisition of Midwest Foundation Technologies Inc. (“Midwest Micropile”) in 2007, which has helped us expand into niche, higher-margin segments of the piling industry. Segment profit has increased from $13.3 million in 2005 to $34.4 million in 2007, representing a compound annual growth rate of 60.8%.

Our Pipeline business (7.6% and 1.6% of total three-year consolidated revenues and total three-year segment profits, respectively) has also achieved revenue growth in the past three years. Revenues increased to $47.0 million in 2007, from $34.1 million in 2006 and $31.5 million in 2005 as a result of large contracts with CNRL, Husky Energy Inc. and Suncor. However, profitability in this segment has been negatively affected by cost overruns related to poor weather and challenging ground conditions. Segment profit increased from $4.9 million in 2005 to $9.0 million in 2006. However, due to the conditions described above, we have incurred a segment loss of $10.5 million in 2007. To reduce the potential for similar impacts on future projects, we are revising our Pipeline contract strategy. Going forward, our Pipeline segment will primarily focus on cost-reimbursable contracts and we will only undertake fixed-price contracts on rare occasions when we perceive the risk to be very low. The new $170 million contract for the construction of Kinder Morgan Canada Inc.’s (“Kinder Morgan”) TMX pipeline will not be a fixed-price contract.

Our outlook for 2008 is positive. With world economic growth continuing to positively impact oil demand and price, we expect to experience increasing project activity in our core market, the Canadian oil sands. Activity in the Fort McMurray area remains very strong with a number of high-profile projects underway including the CNRL expansion, Albian’s Jackpine Mine, Suncor’s Voyageur project and the planned Fort Hills project (a partnership between Petro-Canada Oil Sands Inc., UTS Energy Corp., Teck Cominco Ltd. and Fort Hills Energy Corp.). Our 2007 acquisition of new equipment ideally suited to heavy earth moving in the oil sands area has strengthened our ability to bid competitively and profitably into this expanding market, and we have secured contract wins on many of these new projects.

In our Mining and Site Preparation operating segment, we are actively pursuing a strategy of retaining our leading position as a provider of mining and construction services in the Fort McMurray oil sands area, while concurrently expanding our order backlog by bidding on Canadian opportunities in resource areas outside the oil

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sands. Our significant involvement with De Beers Canada at their Victor Diamond Mine project in northern Ontario is the first of such projects for our Company. We anticipate that our Piling business will continue to enjoy strong demand in 2008 as a result of the oil sands development and continued strong construction activity in western Canada. Our outlook for our Pipeline segment is also very positive with the $170 million Kinder Morgan TMX project which is scheduled to commence construction in the summer of 2007.

Overall, we expect our operating performance will continue to improve in 2008 as a result of the strong market demand for our services and a number of internal initiatives undertaken and/or completed in 2007. These include the restructuring of our management team, the strengthening of our financial and operating controls, and the implementation of a major business improvement project aimed at increasing productivity and equipment utilization.

E. OFF-BALANCE SHEET ARRANGEMENTS

The Company has no off-balance sheet arrangements in place at this time.

F. TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

Our principal contractual obligations relate to our long-term debt and capital and operating leases. The following table summarizes our future contractual obligations, excluding interest payments unless otherwise noted, as of March 31, 2007.

	Payments Due by Fiscal Year
	Total		2008		2009		2010		2011		2012 and After
	(In millions)
Senior notes (a)	$	230.6	$	—	$	—	$	—	$	—	$	230.6
Capital leases (including interest)		10.7		3.9		3.1		2.1		1.4		0.2
Operating leases		40.6		13.9		13.3		10.3		3.0		0.1
Total contractual obligations	$	281.9	$	17.8	$	16.4	$	12.4	$	4.4	$	230.9

(a) We have entered into cross-currency and interest rate swaps, which represent an economic hedge of the 8 ³/4% senior notes. At maturity, we will be required to pay $263.0 million in order to retire these senior notes and the swaps. This amount reflects the fixed exchange rate of C$1.315=US$1.00 established as of November 26, 2003, the inception of the swap contracts. At March 31, 2007 the carrying value of the derivative financial instruments was $60.9 million, inclusive of the interest components.

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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 May 31, 2007. 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, 2-53016 Highway 60, Acheson, Alberta, T7X 5A7.

Name and Municipality of Residence	Age	Position
Rodney J. Ruston     Edmonton, Alberta	56	Director, President and Chief Executive Officer
Douglas A. Wilkes     Surrey, British Columbia	52	Vice President, Finance and Chief Financial Officer
Robert G. Harris     Edmonton, Alberta	59	Vice President, Human Resources, Health, Safety & Environment
Christopher J. Hayman     St. Albert, Alberta	44	Vice President, Supply Chain
William M. Koehn     Spruce Grove, Alberta	45	Vice President, Operations and Chief Operating Officer
Miles W. Safranovich     Spruce Grove, Alberta	42	Vice President, Business Development and Estimating
Ronald A. McIntosh     Calgary, Alberta	65	Chairman of the Board
George R. Brokaw     Southampton, New York	39	Director
John A. Brussa     Calgary, Alberta	50	Director
Peter W. Tomsett     Vancouver, British Columbia	49	Director
John D. Hawkins     Houston, Texas	43	Director
William C. Oehmig     Houston, Texas	57	Director
Richard D. Paterson     San Francisco, California	64	Director
Allen R. Sello     West Vancouver, British Columbia	67	Director
Rick K. Turner     Little Rock, Arkansas	49	Director

Rodney J. Ruston became President and Chief Executive Officer of NAEPI on May 9, 2005 and took the company public with a listing on both the NYSE and TSX on November 22, 2006. Previously, Mr. Ruston was Managing Director and Chief Executive Officer of Ticor Limited, a publicly-listed, Australian natural resources company with operations in Australia, South Africa, and Madagascar. He was a Principal with Ruston Consulting Services Pty. Ltd., a management consultant company providing business advice to the natural resources industry, from September 1999 to June 2000. Mr. Ruston has spent his entire career in the natural resources industry, holding management positions with Pasminco Limited, Savage Resources Limited, Wambo Mining Corporation, Oakbridge Limited, and Kembla Coal & Coke Pty. Limited. He was Chairman of the Australian Minerals Tertiary Education Council from July 2003 until May 2005 and received his Masters of Business

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Administration from the University of Wollongong and Bachelor of Engineering (Mining) from the University of New South Wales in Australia.

Douglas A. Wilkes became our Vice President, Finance and Chief Financial Officer on September 18, 2006. From January 2005 to September 2006, Mr. Wilkes was a self-employed consultant. During this period, Mr. Wilkes also served as Chief Financial Officer of Liberty Copper Corporation from June 2005 to December 2005. From April 2004 to December 2004, he served as Chief Financial Officer for Canfor Corporation. Mr. Wilkes was Chief Financial Officer of Slocan Forest Products Ltd. between April 2002 and March 2004 and of BCR Group of Companies between May 2000 and March 2002. Mr. Wilkes was also Chief Financial Officer of Tolko Industries from 1992 to 2000. His early career experiences include financial leadership roles with Weyerhaeuser Company and BC Hydro after serving five years with a major global audit accounting firm. He is a Chartered Accountant and holds a Bachelor of Commerce from the University of British Columbia.

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 United States. 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 and Vice President, Supply Chain on September 18, 2006. 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 has announced his resignation, effective July 31, 2007. Mr. 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 chairmen 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

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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. Investment entities controlled by Perry Corp. are holders of common shares of North American Energy Partners Inc. 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.

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 Partner since 1999. An investment entity affiliated with The Sterling Group is a holder of common shares of North American Energy Partners Inc. 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. 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 on May 20, 2004. He is a Partner with The Sterling Group, L.P., a private equity investment firm. An investment entity affiliated with The Sterling Group is a holder of common shares of North American Energy Partners Inc. 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. Certain investment entities controlled by Genstar are holders of common shares of North American Energy Partners Inc. 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 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 1964 as an auditor with Coopers & Lybrand in Montreal. He is currently a Director of INSTALLS Inc. LLC, American Pacific Enterprises LLC, Propex Inc., Woods Equipment Company and Altra Industrial Motion, Inc. Mr. Paterson earned a Bachelor of Commerce from Concordia University and is a Chartered Accountant.

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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 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.

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

K. Rick Turner became one of our Directors on November 26, 2003. Mr. Turner has been employed by Stephens’ family entities since 1983. An investment entity controlled by SF Holding Corp. is a holder of common shares of North American Energy Partners Inc. 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. He currently serves on the board of three publicly-held companies: Energy Transfer Partners, Energy Transfer Equity and North American Construction Group. He also serves on numerous private company boards, including JV Industrial; SmartSignal Corporation; BTEC Turbines, LP; Spitzer Industries, Inc.; JEBCO Seismic, LP; Seminole Energy Services, LLC; Multi-Shot, LLC; and Vestcom International, Inc. 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. 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 bonuses of $205,000 in June 2005, $163,733 in July 2006 and $106,543 in March 2007. Mr. Ruston does not receive director compensation.

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In addition, our directors have received grants of stock options under the 2004 Share Option Plan. Effective November 2003, each director, excluding Messrs. Brokaw, Tomsett, McIntosh, Paterson, Sello and Ruston, received options to purchase 27,760 common shares. Mr. McIntosh received options to acquire 70,000 common shares in May 2004, Mr. Paterson received options to purchase 27,760 common shares in November 2005, Mr. Sello received options to purchase 27,760 common shares in February 2006 and Mr. Brokaw received options to purchase 27,760 common shares in June 2006. All the options have an exercise price of $5 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 Brokaw and Paterson has been accelerated as if they had been issued effective November 2003. Mr. Tomsett was granted options to acquire 27,760 common shares in September 2006. These options have an exercise price of $16.75 per share, vest at the rate of 20% per year over five years and expire ten years after their grant date.

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. One director, Mr. Oehmig, accepted this option. The stock options of the other directors remained unchanged.

Executive Compensation

The following summary compensation table sets forth the total value of compensation earned by our Chief Executive Officer, Chief Financial Officer and each of the other three most highly compensated officers as of March 31, 2007, collectively called the named executive officers, for services rendered in all capacities to us for the fiscal years ended March 31, 2005, 2006 and 2007.

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)	2007 2006 2005	$ $	500,000 536,539 —	$	300,000 —	(d)	(c (c —	) )	—   550,000 —
Douglas A. Wilkes Vice President Finance and Chief Financial Officer (Hired September 2006)	2007 2006 2005	$	134,615 —   —		—   —	(d)	(c —   —	)	100,000 —   —
William M. Koehn Vice President, Operations and Chief Operating Officer	2007 2006 2005	$	249,000 240,000 224,000		241,385 —	(d) (b)	(c (c (c	) ) )	—   —   —
Miles W. Safranovich Vice President, Business Development & Estimating (Hired November 2004)	2007 2006 2005	$	218,000 195,808 61,385		210,384 —	(d) (b)	(c (c (c	) ) )	—   40,000 60,000
Christopher J. Hayman Vice President, Finance (Hired January 2005)	2007 2006 2005	$	207,100 183,641 56,250		186,910 —	(d) (b)	(c (c (c	) ) )	—   40,000 60,000

(a) Consists of options to purchase our common shares. The options granted to Mr. Ruston expire on May 8, 2015. The options granted in fiscal 2007 to Mr. Wilkes expire on September 18, 2016. The options granted to Mr. Koehn 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) The amount of other annual compensation does not exceed the lesser of $50,000 and 10% of the salary and bonus for the fiscal year.

(d) Fiscal 2007 bonuses have not been calculated as at the filing date of this Form 20-F. The Company will disclose fiscal 2007 executive bonuses through a Form 6-K filing subsequent to the calculation of such bonuses.

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Option Grants in Fiscal 2007

Name	Number of Securities Underlying Options Granted	Percentage of Total Options Granted to Employees and Directors in Fiscal Year		Exercise Price (a)		Expiration Date	Grant Date Value (b)
Robert G. Harris	100,000	32	%	$	5.00	28-Jun-16	1,238,671
Peter W. Tomsett	27,760	9	%	$	16.75	20-Sep-16	214,807
Douglas A. Wilkes	100,000	32	%	$	16.75	20-Sep-16	808,576
George R. Brokaw	27,760	9	%	$	5.00	28-Jun-13	341,469

(a) In September 2006, we had a valuation performed by an unrelated valuation specialist, which valued our common shares at $16.10 per share. The plan and outstanding balances are disclosed in note 25 to our consolidated financial statements for 2007.

(b) Value estimated using the Black-Scholes option-pricing model. For assumptions used, see note 25 to our consolidated financial statements included at Item 17.

Aggregated Option Exercises in Fiscal 2007 and Fiscal Year End Option Values

Name	Shares Acquired on Exercise	Value Realized	Number of Securities Underlying Unexercised Options at March 31, 2007 (Exercisable/ Unexercisable)	Value of Unexercised In-The-Money Options at March 31, 2007 (Exercisable/ Unexercised) (a)
Rod Ruston	—	—	110,000/440,000	$2,090,000/$8,360,000
William Koehn	—	—	60,000/40,000	$1,140,000/$760,000
Miles Safranovich	—	—	32,000/68,000	$608,000/$1,292,000
Christopher Hayman	—	—	32,000/68,000	$608,000/$1,292,000
Douglas A. Wilkes	—	—	—/100,000	$—/$725,000
Robert G. Harris	—	—	—/100,000	$—/$1,900,000

(a) March 31, 2007 option values are determined using the Friday, March 30, 2007 closing price on the Toronto stock Exchange.

Retirement Benefits for Executive Officers and Directors

For the fiscal year ended March 31, 2007, the total amount we set aside for pension, retirement and similar benefits for our executive officers and directors was $50,015 consisting of employer matching contributions to our executive officers’ Registered Retirement Savings Plan, a Canadian tax-deferred retirement savings plan, of up to 5% of salary.

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

Our board has approved the Amended and Restated 2004 Share Option Plan. The amended plan was approved by our shareholders on November 3, 2006 and became effective on November 28, 2006. The amended

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option plan is administered by the Compensation Committee. Option grants under the amended option plan may be made to our directors, officers, employees and consultants selected by the Compensation Committee. The amended option plan provides for the discretionary grant of options to purchase common shares. Options granted under the amended plan will be evidenced by an agreement, which will specify the vesting, exercise price and expiration of such options. Options to be granted under the amended option plan will have an exercise price of not less than the volume weighted average trading price of the common shares on the Toronto Stock Exchange or the New York Stock Exchange at the time of grant. The amended option plan provides that up to 10% of our issued and outstanding common shares from time to time may be reserved for issuance or issued from treasury.

In the event of certain change of control events as defined in the amended option plan, all outstanding options will become immediately vested and exercisable. The amended option plan provides that our board can make certain specified amendments to the option plan subject to receipt of shareholder and regulatory approval, and further authorizes the board to make all other amendments to the plan, subject only to regulatory approval but without shareholder approval. The amendments the board may make without shareholder approval include:

• amendments of a housekeeping nature,

• changes to the vesting provisions of an option or the option plan,

• changes to the termination provisions of an option or the option plan which do not entail an extension beyond the original expiry date,

• the discontinuance of the option plan, and

• the addition of provisions relating to phantom share units, such as restricted share units and deferred share units which result in participants receiving cash payments, and the terms governing such features.

The amended option plan provides that each option includes a cashless exercise alternative which provides a holder of an option with the right to elect to receive cash in lieu of purchasing the number of shares under the option. Notwithstanding such right, the amended option plan provides that we may elect, at our sole discretion, to net settle the option with stock.

As of March 31, 2007 there were 837,352 shares issuable upon exercise of outstanding share options.

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. The listing requirements of the NYSE applicable to domestic listed companies require that our board of directors be composed of a majority of independent directors within one year of the listing of our common shares on the NYSE. Accordingly, we have adjusted the board membership to comply with this requirement.

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Our board has established the following committees:

• 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 reviews the audit findings report, approves quarterly financial statements and recommends annual financial statements for approval to the board. Rule 10A-3 under the Securities Exchange Act of 1934, as amended, and the listing requirements of the NYSE and the requirements of the Canadian securities regulatory authorities require that our audit committee be composed solely of independent directors within one year of the effectiveness date of the registration statement. Accordingly, we have adjusted the composition of the audit committee so that all members are now independent. One member of the audit committee is designated as the audit committee financial expert, as defined by Item 401(h) of Regulation S-K of the Exchange Act. Our board of directors has adopted a written charter for the audit committee that is available on our website. The Audit Committee is currently composed of Messrs. Brokaw, 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 listing requirements of the NYSE applicable to domestic listed companies require that our compensation committee be composed of a majority of independent directors within 90 days of the listing of our common shares on the NYSE and that it be composed solely of independent directors within one year of such listing. Accordingly, we have adjusted the composition of the compensation committee so that all members are now independent. Our board of directors has adopted a written charter for the compensation committee that is available on our website. The Compensation Committee is currently composed of Messrs. Brussa, Oehmig, Paterson and Sello, with Mr. Paterson serving as Chairman.

• The Governance Committee is responsible for recommending to the board of directors proposed nominees for election to the board of directors by the shareholders at annual meetings, including an annual review as to the renominations of incumbents and proposed nominees for election by the board of directors to fill vacancies that occur between shareholder meetings, and making recommendations to the board of directors regarding corporate governance matters and practices. The listing requirements of the NYSE applicable to domestic listed companies require that we establish a nominating and corporate Governance Committee composed of a majority of independent directors within 90 days of the listing of our common shares on the NYSE and that it be composed solely of independent directors and have at least three members within one year of such listing. Accordingly, we have adjusted the composition of the governance committee so that all members are now independent. Our board of directors has adopted a written charter for the Governance Committee that is available on our website. The Governance Committee is currently composed of Messrs. Brussa, Hawkins, Paterson, Tomsett and Turner, with Mr. Tomsett serving as Chairman.

• The Risk Committee is responsible for overseeing all of our non-financial risks, approving our risk management policies and reviewing the risks and related risk mitigation plans within our strategic plan. The Risk Committee is currently composed of Messrs. Brokaw, McIntosh, Oehmig and Tomsett, with Mr. Oehmig serving as Chairman.

The board may also establish other committees.

D. EMPLOYEES

As of March 31, 2007 we had over 200 salaried and over 1,500 hourly employees.

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E. SHARE OWNERSHIP

The following presents information regarding the beneficial ownership of our voting common shares and options to purchase common shares by our executive officers and directors as of March 31, 2007.

Name of Beneficial Owner	Number of Common Shares	Options (1)	% of Outstanding Common Shares	Exercise Price
Rodney J. Ruston	16,700	110,000	*	$	5.00
Douglas A. Wilkes	7,500	—	*		—
Robert G. Harris	—	—	—		—
Miles W. Safranovich	14,100	32,000	*	$	5.00
William M. Koehn	100,000	60,000	*	$	5.00
Christopher J. Hayman	28,100	32,000	*	$	5.00
George R. Brokaw	—	16,656	*	$	5.00
John A. Brussa	112,400	16,656	*	$	5.00
John D. Hawkins	—	16,656	*	$	5.00
Ronald A. McIntosh	56,200	28,000	*	$	5.00
William C. Oehmig	205,460	—	*		—
Richard D. Paterson	—	16,656	*	$	5.00
Allen R. Sello	28,100	5552	*	$	5.00
Rick K. Turner	—	16,656	*	$	5.00
Peter W. Tomsett	—	—	—		—

 * Less than 1%

(1) Amount represents the number of options which had vested as of March 31, 2007. All options entitle the holder to purchase one common share per option and expire 10 years from date of issue.

ITEM 7: MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

A. MAJOR SHAREHOLDERS

The following presents information regarding the beneficial ownership of each person who was the beneficial owner of more than 5% of our outstanding voting common shares based on information available at the time of filing this Form 20-F.

Name of Beneficial Owner	Number of Common Shares	% of Outstanding Common Shares
Sterling Group Partners I, L.P. (a)	6,351,265	17.8
Genstar Capital Partners III, L.P. (b)	4,439,233	12.5
Richard Perry (c)	4,598,466	12.9
MFS Investment Management	3,748,290	10.5
Stephens - NACG LLC. (d)	3,065,409	8.6
FMR Corp.	2,986,800	8.4
Perry Partners L.P. (c)	2,161,361	6.1

(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. Sterling Group Partners I, L.P. is an affiliate of The Sterling Group, L.P.

(b) Genstar Capital Partners III, L.P. directly holds 4,439,233 common shares. Stargen III, L.P. directly holds 159,249 common shares. Genstar Capital III, L.P. is the sole general partner of each of Genstar Capital Partners III, L.P. and Stargen III, L.P., 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. Genstar Capital Partners III, L.P. and Stargen III, L.P. are affiliates of Genstar Capital, L.P.

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(c) Perry Partners, L.P. directly holds 2,161,361 common shares. Perry Luxco S.A.R.L. directly holds 1,718,443 common shares. Perry Partners International, Inc. directly holds 718,662 common shares. Richard Perry is the President and sole shareholder of Perry Corp., which is the investment manager of Perry Partners International, Inc. and the managing general partner of Perry Partners, L.P. Perry Partners International, Inc. is the indirect sole shareholder of the class of securities owned by Perry Luxco S.A.R.L. As such, Mr. Perry may be deemed to have beneficial ownership over the respective common shares owned by Perry Luxco S.A.R.L., Perry Partners, L.P. and Perry Partners International, Inc.; 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.

(d) Stephens-NACG LLC directly holds 3,065,409 common shares. SF Holding Corp. is the sole manager of Stephens-NACG LLC. Warren A. Stephens and W.R. Stephens, Jr. each own a substantial portion of the capital shares of SF Holding Corp. and are co-chairmen of the board of SF Holding Corp. In such capacity, each may be deemed to have shared voting and investment power over the common shares which are or may be deemed to be beneficially owned by Stephens-NACG LLC and SF Holding Corp., but each disclaims such beneficial ownership. Additionally, Warren A. Stephens may be deemed to have shared voting and investment power over the following: (i) 37,947 common shares owned by Stephens Inc., a registered broker-dealer of which Warren A. Stephens is president and sole owner, (ii) 7,593 common shares owned by Stephens Investments Holdings LLC, a private holding company of which Warren A. Stephens is the sole manager, and (iii) 5,631 common shares held by Stephens Inc. in discretionary trading accounts for investment advisory customers, as to which Warren A. Stephens disclaims beneficial ownership.

MFS Investment Management and FMR Corp. acquired such shares after our initial public offering on November 28, 2006. Each of the other beneficial owners in the table above acquired such shares on November 26, 2003. With the exception of Sterling Group Partners I, L.P., from which we repurchased 348,160 shares in January 2004, there was no significant change in the percentage ownership held by such beneficial owners between November 26, 2003 and November 28, 2006, the date of our initial public offering, when such beneficial owners sold significant portions of their respective shareholdings.

B. RELATED PARTY TRANSACTIONS

Advisory Services Agreement

We were party to an advisory services agreement, dated November 26, 2003, with The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc., and SF Holding Corp. (collectively, the “Sponsors”). The advisory services agreement was terminated upon the completion of our IPO.

Voting and Corporate Governance Agreement

We were party to a voting agreement, dated November 26, 2003, with affiliates of the sponsors. The voting agreement was terminated upon the completion of our IPO.

We have entered into a letter agreement with each sponsor pursuant to which we have engaged such sponsor to provide their expertise and advice to us for no fee, which is in their interest because of their investment in us. In order for the sponsors to provide such advice, we have agreed to

• provide them copies of all documents, reports, financial data and other information regarding us,

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

• permit them to discuss our company’s affairs, finances and accounts with our officers, directors and outside accountants,

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

• permit them to attend, to the extent that a director is not related to the sponsor, to designate and send a representative to attend all meetings of our board of directors in a non-voting observer capacity,

• provide them copies of certain of our financial statements and reports, and

• provide them copies of all materials sent by us to our board of directors, other than materials relating to transactions in which the sponsor has an interest.

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We may terminate a sponsor’s letter agreement in certain circumstances.

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

Shareholders Agreements

All holders of our common shares who were also our employees or employees of any of our subsidiaries were parties to an employee shareholders agreement. All other holders of our common shares were parties to an investor shareholders agreement. Both shareholders agreements were terminated upon the completion of our IPO.

Registration Rights Agreement

We are party to a registration rights agreement with certain shareholders, including affiliates of each of the sponsors, Paribas North America, Inc. and Mr. William Oehmig, one of our directors. After our IPO, the shareholders party to the agreement and their permitted transferees are entitled, subject to certain limitations, to include their common shares in a registration of common shares we initiate under the Securities Act of 1933, as amended. In addition, after the 120th day following our IPO, any one or more shareholders party to the agreement has the right to require us to effect the registration of all or any part of such shareholders’ common shares under the Securities Act, referred to as a “demand registration,” so long as the amount of common shares to be registered has an aggregate fair market value of at least US$5.0 million and, at such time, the SEC has ordered or declared effective fewer than four demand registrations initiated by us pursuant to the registration rights agreement. 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.

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

• up to 120 days if we have

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

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

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

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

The registration rights agreement contains customary provisions whereby we and the shareholders party to the agreement 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

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under the Securities Act. The registration rights agreement requires us to pay the expenses associated with any registration other than sales discounts, commissions, transfer taxes and amounts to be borne by underwriters or as otherwise required by law.

Properties and Facilities

Pursuant to several office lease agreements, in 2007 we paid $572,000 (2006 – $836,000; 2005 – $824,000) to a company owned, indirectly and in part, by one of our directors. Effective November 28, 2006, the director resigned from the board.

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 businesses 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 former subsidiary, 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.

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ITEM 9: THE OFFER AND LISTING

A. OFFER AND LISTING DETAILS

Not applicable.

B. PLAN OF DISTRIBUTION

Not applicable.

C. MARKETS

Not applicable.

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 3.3 and 3.4 to our Form F-1 (Registration No. 333-135943), filed with the SEC and incorporated herein by reference.

C. MATERIAL CONTRACTS

We are party to the following contracts, other than contracts entered into in the ordinary course of business, all of which are filed as exhibits to this Form 20-F:

Employment Arrangements with Executive Officers

Amended and Restated Credit Agreement

Indenture Governing Our 8 ³/4% Senior Notes due 2011

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.

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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

For more complete information about us you should read our disclosure documents that we have filed with the SEC and the CSA. You may obtain these documents for free by visiting EDGAR on the SEC website at www.sec.gov or SEDAR on the CSA website at www.sedar.com.

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 8 ³/4% senior notes are denominated in U.S. dollars and all of our revenues and most of our expenses are denominated in Canadian dollars. To manage the foreign currency risk and potential cash flow impact on our $200 million in U.S. dollar-denominated notes, we have entered into currency swap and interest rate swap agreements. These financial instruments consist of three components: a U.S. dollar interest rate swap; a U.S. dollar-Canadian dollar cross-currency basis swap; and a Canadian dollar interest rate swap. The cross currency and interest rate swap agreements 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 repurchased at par if cancelled after December 1, 2009.

Interest rate risk

We are exposed to interest rate risk on the revolving credit facility, capital lease obligations and certain operating leases with a variable payment that is tied to prime rates. We do not use derivative financial instruments to reduce our exposure to these risks. The estimated financial impact as a result of fluctuations in interest rates is not significant.

69

Inflation

Inflation has not had a material impact on our operations as many of our contracts contain a provision for annual price increases. Inflation is not expected to have a material impact on our operations in the foreseeable future provided the rate of inflation remains consistent with recent levels and we are able to continue passing costs increases along to our customers.

ITEM 12: DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

Not applicable.

70

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

Evaluation of disclosure controls and procedures

Under the supervision and with the participation of management, including our President and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures as of March 31, 2007, as defined in Canada by Multilateral Instrument 52-109, “Certification of Disclosure in Issuer’s Annual and Interim Fillings” and in the United States by Rule 13(a)-15(e) under the Securities Exchange Act of 1934, as amended, as of March 31, 2007. Based on this evaluation, our President and Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective.

Internal Control over Financial Reporting (“ICFR”)

Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and of the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Management is responsible for establishing and maintaining adequate internal controls appropriate to the nature and size of the business to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting for the Company.

In the course of preparing our 2007 financial statements, we identified a number of material weaknesses in our ICFR. A control deficiency is a material weakness in ICFR if the deficiency, or a combination of control deficiencies is such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim consolidated financial statements will not be prevented or detected.

We noted the following material weaknesses in ICFR as at March 31, 2007:

• Revenue recognition—a formal process to track claims and unapproved change orders and sufficient monitoring controls over the completeness and accuracy of forecasts, including the consideration within project changes subsequent to the end of each reporting period were not effectively implemented. The accounts that could potentially be affected by these deficiencies are revenue, project costs and their related accounts.

• Income taxes—there was a lack of review and monitoring controls as well as a lack of segregation of duties of the income tax function. The accounts that could potentially be affected by these deficiencies are future income tax assets, future income tax liabilities and future income tax expense.

• Accounts payable and procurement—The Company did not have an effectively implemented procurement process to track purchase commitments, reconcile vendor accounts and accurately accrue costs not invoiced by vendors at each reporting date. The accounts that could potentially be affected by these deficiencies are accounts payable, accrued liabilities, project costs, unbilled revenue, equipments costs, general and administrative costs and other expenses.

• IT General Controls (“ITGCs”)—a number of deficiencies in ITGCs existed, including appropriate controls around spreadsheets and end user computing, controls over access and accuracy of one of our systems, as well as general maintenance of access rights and nominal program change controls. When aggregated, these deficiencies represented a material weakness in ICFR.

71

In anticipation of providing an annual report on ICFR by March 31, 2008, management is currently evaluating the effectiveness of our system of internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Changes in Internal Control over Financial Reporting

We are currently addressing these deficiencies through the implementation of the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 in the United States and Multilateral Instrument 52-109 in Canada. We are in the remediation phase of a procurement project in which we implemented the purchase order functionality in our financial systems and trained our staff in the effective use of purchase orders to track our commitments and to record our expenses in a timely manner. We are implementing and testing a project controls improvement initiative over the claims and unapproved change orders process, as well as the completeness and accuracy of project forecasts. We are also in the final stages of upgrading our enterprise resource management software, which includes addressing the ITGC deficiencies noted above.

We have added to our finance staff, and in particular we now have in-house Canadian GAAP expertise and a working knowledge of U.S. GAAP, which is supplemented by outside expertise. We have created a Corporate Controller position and added a Corporate Accounting Manager and Tax Manager. In addition, we have instituted standardized procedures for financial reporting and review, including the procedures by which general ledger transactions are closed, reviewed and consolidated.

Other than the continuing impact of the corrective actions discussed above, there were no changes in our ICFR since March 31, 2006 that have materially affected, or are reasonably likely to affect, our ICFR.

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 Chief Financial Officer. Our code of ethics is available on our website at www.naepi.ca

ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Our auditors are KPMG LLP. Our Audit Committee pre-approved the engagement of KPMG to perform the audit of our financial statements for the fiscal year ended March 31, 2007.

Audit Fees

KPMG billed us $2,375,000 in 2007, $2,617,000 in 2006 and $1,330,000 in 2005 for audit services. Audit fees were incurred for the audit of our annual financial statements, related audit work in connection with registration statements and other filings with various regulatory authorities, and quarterly interim reviews of the consolidated financial statements.

72

Audit Related Fees

KPMG billed us $52,000 in 2007, $62,000 in 2006 and $31,000 in 2005 for planning and scoping work and advice relating to compliance and internal controls over financial reporting.

Tax Fees

KPMG billed us $16,640 in 2007, $15,000 in 2006 and $25,000 in 2005 for tax compliance services.

All Other Fees

KPMG did not perform any other services for us.

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

Not applicable.

ITEM 18. FINANCIAL STATEMENTS

The Auditors’ Report and Financial Statements for the Company are attached hereto as itemized under Item 19(a) and are incorporated herein by reference. Such Financial Statements have been prepared on the basis of Canadian GAAP. A reconciliation to U.S. GAAP appears in Note 27 thereto.

ITEM 19. EXHIBITS

(a) Financial Statements (see attached pages F-1 through F-44)

(i) Auditors’ Report.

(ii) Balance Sheets as at March 31, 2006 and 2007.

(iii) Statements of Operations and Deficit for the years ended March 31, 2005, 2006 and 2007.

(iv) Statements of Cash Flows for the years ended March 31, 2005, 2006 and 2007.

(v) Notes to the Financial Statements.

(b) Schedule of Valuation and Qualifying Accounts (see attached page S-1).

73

(c) Exhibits

1.1	Form of Articles of Amalgamation of North American Energy Partners Inc. (filed as Exhibit 3.3 to Amendment No. 3 to Form F-1 (Registration No. 333-135943), filed on October 23, 2006 and incorporated herein by reference).
1.2	Form of By-Law No. 2 of NACG Holdings Inc. (filed as Exhibit 3.4 to Amendment No. 4 to Form F-1 (Registration No. 333-135943), filed on November 3, 2006 and incorporated herein by reference).
2.1	Registration Rights Agreement, dated as of November 26, 2003, among NACG Holdings Inc. and the shareholders party thereto (filed as Exhibit 4.1 to Form F-1 (Registration No. 333-135943), filed on July 21, 2006 and incorporated herein by reference).
2.2	Form of Amended and Restated 2004 Share Option Plan (filed as Exhibit 4.2 to Amendment No. 3 to Form F-1 (Registration No. 333-135943), filed on October 23, 2006 and incorporated herein by reference).
2.3	Form of Letter Agreement between North American Energy Partners Inc. and its sponsors (filed as Exhibit 4.3 to Amendment No. 3 to Form F-1 (Registration No. 333-135943), filed on October 23, 2006 and incorporated herein by reference).
4.1	Second Amended and Restated Credit Agreement, dated as of June 7, 2007, among North American Energy Partners Inc., the lenders named therein and Canadian Imperial Bank of Commerce, as Administrative Agent.
4.2	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 Form F-4 (Registration No. 333-111396), filed on December 19, 2003 and incorporated herein by reference).
4.3	Employment Agreement with Rodney J. Ruston (filed as Exhibit 10.6 to Amendment No. 3 to Form F-1 (Registration No. 333-135943), filed on October 23, 2006 and incorporated herein by reference).
4.4	Employment Agreement with Robert G. Harris (filed as Exhibit 10.8 to Amendment No. 3 to Form F-1 (Registration No. 333-135943), filed on October 23, 2006 and incorporated herein by reference).
4.5	Employment Agreement with Christopher J. Hayman (filed as Exhibit 10.9 to Amendment No. 3 to Form F-1 (Registration No. 333-135943), filed on October 23, 2006 and incorporated herein by reference).
4.6	Employment Agreement with William M. Koehn (filed as Exhibit 10.10 to Amendment No. 3 to Form F-1 (Registration No. 333-135943), filed on October 23, 2006 and incorporated herein by reference).
4.7	Employment Agreement with Miles W. Safranovich (filed as Exhibit 10.11 to Amendment No. 3 to Form F-1 (Registration No. 333-135943), filed on October 23, 2006 and incorporated herein by reference).
4.8	Employment Agreement with Douglas A. Wilkes (filed as Exhibit 10.19 to Amendment No. 3 to Form F-1 (Registration No. 333-135943), filed on October 23, 2006 and incorporated herein by reference).
4.9	Overburden Removal and Mining Services Contract, dated November 17, 2004, between Canadian Natural Resources Limited and Noramac Ventures Inc. (filed as Exhibit 10.12 to Amendment No. 6 to Form F-1 (Registration No. 333-135943), filed on November 17, 2006 and incorporated herein by reference).
4.10	Amended and Restated Joint Venture Agreement, dated September 30, 2004, among North American Construction Group Inc., Fort McKay Construction Ltd. and Noramac Ventures Ltd., including the assignment of contract from Noramac Ventures Ltd. to North American Construction Group Inc., dated February 27, 2006 (filed as Exhibit 10.13 to Amendment No. 1 to Form F-1 (Registration No. 333-135943), filed on September 8, 2006 and incorporated herein by reference).

74

4.11	Office Lease, as amended as of November 26, 2003, between Acheson Properties Ltd. and North American Construction Group Inc. (filed as Exhibit 10.14 to Amendment No. 1 to Form F-1 (Registration No. 333-135943), filed on September 8, 2006 and incorporated herein by reference).
4.12	Office Lease, dated as of March 15, 2003, between Acheson Properties Ltd. and North American Construction Group Inc. (filed as Exhibit 10.15 to Amendment No. 1 to Form F-1 (Registration No. 333-135943), filed on September 8, 2006 and incorporated herein by reference).
4.13	Office Lease, dated as of July 1, 2003, between Acheson Properties Ltd. and North American Construction Group Inc. (filed as Exhibit 10.16 to Amendment No. 1 to Form F-1 (Registration No. 333-135943), filed on September 8, 2006 and incorporated herein by reference).
8.1	Subsidiaries of North American Energy Partners Inc. (included in Item 4.C of this report).
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.
15.1	Report and Consent of Independent Registered Public Accounting Firm.

75

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: June 19, 2007	By:	/s/    DOUGLAS A. WILKES
	Name:	Douglas A. Wilkes
	Title:	Vice President, Finance & Chief Financial Officer

76

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

CONSOLIDATED FINANCIAL STATEMENTS

For the years ended March 31, 2007, 2006 and 2005

(Expressed in thousands of Canadian dollars)

INDEX TO FINANCIAL STATEMENTS

Audited Consolidated Financial Statements of North American Energy Partners Inc.

(formerly NACG Holdings Inc.)

Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as at March 31, 2007 and 2006	F-3
Consolidated Statements of Operations and Deficit for the years ended March 31, 2007, 2006 and 2005	F-4
Consolidated Statements of Cash Flows for the years ended March 31, 2007, 2006 and 2005	F-5
Notes to the Consolidated Financial Statements	F-6

F-1

REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors

We have audited the consolidated balance sheets of North American Energy Partners Inc. (formerly NACG Holdings Inc.) as at March 31, 2007 and 2006 and the consolidated statements of operations and deficit and cash flows for each of the years in the three-year period ended March 31, 2007. These consolidated 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 Canadian generally accepted auditing standards. We also 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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of North American Energy Partners Inc. (formerly NACG Holdings Inc.) as of March 31, 2007 and 2006 and the results of its operations and its cash flows for each of the years in the three-year period ended March 31, 2007 in accordance with Canadian generally accepted accounting principles.

As discussed in Note 2(r) to the consolidated financial statements, the Company adopted new accounting pronouncements related to the accounting for stock-based compensation for employees eligible to retire before the vesting date and determining the variability to be considered in applying the variable interest entities standards in 2007.

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 27 to the consolidated financial statements.

/s/    KPMG LLP

Chartered Accountants

Edmonton, Canada

June 19, 2007

F-2

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

CONSOLIDATED BALANCE SHEETS

As at March 31

(in thousands of Canadian dollars)

	2007			2006
Assets
Current assets:
Cash and cash equivalents	$	7,895		$	42,804
Accounts receivable (note 5)		93,220			67,235
Unbilled revenue (note 6)		82,833			43,494
Inventory		156			57
Asset held for sale (note 8)		8,268			—
Prepaid expenses and deposits (note 7)		11,932			1,796
Other assets		10,164			1,004
Future income taxes (note 16)		14,593			5,238
		229,061			161,628
Future income taxes (note 16)		14,364			5,383
Plant and equipment (note 9)		255,963			184,562
Goodwill (note 4)		199,392			198,549
Intangible assets, net of accumulated amortization of $17,608 (March 31, 2006 – $17,026) (note 10)		600			772
Deferred financing costs, net of accumulated amortization of $7,595 (March 31, 2006 – $6,004) (notes 2 and 11)		11,356			17,788
	$	710,736		$	568,682
Liabilities and Shareholders’ Equity
Current liabilities:
Revolving credit facility (notes 12 and 28)	$	20,500		$	—
Accounts payable		94,548			54,085
Accrued liabilities (note 13)		23,393			24,603
Billings in excess of costs incurred and estimated earnings on uncompleted contracts (note 6)		2,999			5,124
Current portion of capital lease obligations (note 14)		3,195			3,046
Future income taxes (note 16)		4,154			5,238
		148,789			92,096
Capital lease obligations (note 14)		6,514			7,906
Senior notes (note 15)		230,580			304,007
Derivative financial instruments (note 22(b))		60,863			63,611
Redeemable preferred shares (notes 2 and 17(a))		—			77,568
Future income taxes (note 16)		19,712			5,383
		466,458			550,571
Shareholders’ equity:
Common shares (authorized—unlimited number of voting and non-voting common shares; issued and outstanding—March 31, 2007 – 35,192,260 voting common shares and 412,400 non-voting common shares (March 31, 2006 – 18,207,600 voting common shares and 412,400 non-voting common shares)) (notes 2 and 17(b))		296,198			93,100
Contributed surplus (notes 17(c) and 25)		3,606			1,557
Deficit		(55,526	)		(76,546	)
		244,278			18,111
Commitments (note 23)
United States generally accepted accounting principles (note 27)
Subsequent events (note 28)
	$	710,736		$	568,682

See accompanying notes to consolidated financial statements.

F-3

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT

For the years ended March 31

(in thousands of Canadian dollars, except per share amounts)

	2007			2006			2005
Revenue	$	629,446		$	492,237		$	357,323
Project costs		363,930			308,949			240,919
Equipment costs		122,306			64,832			52,831
Equipment operating lease expense		19,740			16,405			6,645
Depreciation (note 8)		31,034			21,725			20,762
Gross profit		92,436			80,326			36,166
General and administrative costs (note 21)		39,769			30,903			22,873
Loss (gain) on disposal of plant and equipment		959			(733	)		494
Amortization of intangible assets		582			730			3,368
Operating income before the undernoted		51,126			49,426			9,431
Interest expense (note 18)		37,249			68,776			31,141
Foreign exchange gain (note 22(b))		(5,044	)		(13,953	)		(19,815	)
Realized and unrealized (gain) loss on derivative financial instruments (note 22(b))		(196	)		14,689			43,113
Gain on repurchase of NACG Preferred Corp. Series A preferred shares (notes 2 and 17(a))		(9,400	)		—			—
Loss on extinguishment of debt (notes 2, 11 and 15)		10,935			2,095			—
Other income		(904	)		(977	)		(421	)
Income (loss) before income taxes		18,486			(21,204	)		(44,587	)
Income taxes (note 16):
Current income taxes		(2,975	)		737			2,711
Future income taxes		382			—			(4,975	)
Net income (loss)		21,079			(21,941	)		(42,323	)
Deficit, beginning of year		(76,546	)		(54,605	)		(12,282	)
Premium on repurchase of common shares (note 17(b))		(59	)		—			—
Deficit, end of year	$	(55,526	)	$	(76,546	)	$	(54,605	)
Net income (loss) per share—basic (note 17(d))	$	0.87		$	(1.18	)	$	(2.28	)
Net income (loss) per share—diluted (note 17(d))	$	0.83		$	(1.18	)	$	(2.28	)

See accompanying notes to consolidated financial statements

F-4

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended March 31

(in thousands of Canadian dollars)

	2007			2006			2005
Cash provided by (used in):
Operating activities:
Net income (loss) for the period	$	21,079		$	(21,941	)	$	(42,323	)
Items not affecting cash:
Depreciation		31,034			21,725			20,762
Write-down of other assets to replacement cost (note 3(g))		695			—			—
Amortization of intangible assets		582			730			3,368
Amortization of deferred financing costs		3,436			3,338			2,554
Loss (gain) on disposal of plant and equipment		959			(733	)		494
Unrealized foreign exchange gain on senior notes (note 22(b))		(5,017	)		(14,258	)		(20,340	)
Unrealized (gain) loss on derivative financial instruments (note 22(b))		(2,748	)		11,888			40,457
Stock-based compensation expense (note 25)		2,101			923			497
Gain on repurchase of NACG Preferred Corp. Series A preferred shares (notes 2 and 17(a))		(8,000	)		—			—
Loss on extinguishment of debt (notes 2, 11 and 15)		10,680			2,095			—
Change in redemption value and accretion of redeemable preferred shares		3,114			34,722			—
Future income taxes		382			—			(4,975	)
Net changes in non-cash working capital (note 19(b))		(48,245	)		(3,397	)		(6,167	)
		10,052			35,092			(5,673	)
Investing activities:
Acquisition, net of cash acquired (note 4)		(1,517	)		—			—
Purchase of plant and equipment		(110,019	)		(28,852	)		(24,839	)
Proceeds on disposal of plant and equipment		3,564			5,456			624
		(107,972	)		(23,396	)		(24,215	)
Financing activities:
Increase in revolving credit facility		20,500			—			—
Issue of 9% senior secured notes (note 15)		—			76,345			—
Repayment of 9% senior secured notes (note 15)		(74,748	)		—			—
Repayment of senior secured credit facility (note 11)		—			(61,257	)		(7,250	)
Issue of Series B preferred shares (note 17(a))		—			8,376			—
Repurchase of Series B preferred shares (notes 2 and 17(a))		—			(851	)		—
Repurchase of NAEPI Series A preferred shares (notes 2 and 17(a))		(1,000	)		—			—
Repurchase of NACG Preferred Corp. Series A preferred shares (notes 2 and 17(a))		(27,000	)		—			—
Financing costs (note 11)		(1,346	)		(7,546	)		(642	)
Repayment of capital lease obligations		(6,033	)		(2,183	)		(1,198	)
Increase in senior secured credit facility		—			—			20,007
Issue of common shares (note 2 and 17(b))		171,304			300			300
Share issue costs (notes 2 and 17(b))		(18,582	)		—			—
Repurchase of common shares for cancellation (note 17(b))		(84	)		—			—
		63,011			13,184			11,217
(Decrease) increase in cash and cash equivalents		(34,909	)		24,880			(18,671	)
Cash and cash equivalents, beginning of year		42,804			17,924			36,595
Cash and cash equivalents, end of year	$	7,895		$	42,804		$	17,924

See accompanying notes to consolidated financial statements

F-5

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

1. Nature of operations

NACG Holdings Inc. (the “Company”) was incorporated under the Canada Business Corporations Act on October 17, 2003. On November 26, 2003, the Company purchased all the issued and outstanding shares of North American Construction Group Inc. (“NACGI”), including subsidiaries of NACGI, from Norama Ltd. which had been operating continuously in Western Canada since 1953. The Company had no operations prior to November 26, 2003. The Company undertakes several types of projects including contract mining, industrial and commercial site development, pipeline and piling installations in Canada.

On November 28, 2006, immediately prior to the closing of the initial public offering (“IPO”) of common shares in Canada and the United States (note 2), the Company amalgamated with its wholly-owned subsidiaries, NACG Preferred Corp., and North American Energy Partners Inc. (“NAEPI”). The amalgamated entity was continued as North American Energy Partners Inc. The voting common shares of the new entity, North American Energy Partners Inc., include the shares offered in the IPO and outstanding common shares in North American Energy Partners Inc. that were not sold in the concurrent secondary offering.

2. Reorganization and initial public offering

On November 28, 2006, prior to the amalgamation referred to in note 1, the Company acquired the NACG Preferred Corp. Series A preferred shares with a carrying value of $35,000 in exchange for a promissory note in the amount of $27,000 and the forfeiture of accrued dividends of $1,400 (note 17(a)). The Company recorded a gain of $9,400 on the repurchase of the NACG Preferred Corp. Series A preferred shares.

On November 28, 2006, prior to the amalgamation referred to in note 1, the Company repurchased the NAEPI Series A preferred shares for their redemption value of $1,000. The Company also cancelled the consulting and advisory services agreement with The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc., and SF Holding Corp. (collectively, the “Sponsors”), under which the Company had received ongoing consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements and other matters. The consideration paid for the cancellation of the consulting and advisory services agreement on the closing of the offering was $2,000, which was recorded as general and administrative expense in the consolidated statement of operations. Under the consulting and advisory services agreement, the Sponsors also received a fee of $854, 0.5% of the aggregate gross proceeds to the Company from the offering, which was recorded as a share issue cost.

On November 28, 2006, prior to the amalgamation referred to in note 1, each holder of NAEPI Series B preferred shares received 100 common shares of NACG Holdings Inc. for each NAEPI Series B preferred share held as a result of the Company exercising a call option to acquire the NAEPI Series B preferred shares (note 17(a)). Upon exchange, the carrying value in the amount of $44,682 for the NAEPI Series B preferred shares on the exercise date was transferred to share capital.

On November 28, 2006, the Company completed an IPO for the sale of 8,750,000 common voting shares for total gross proceeds of $158,549. Net proceeds from the IPO, after deducting underwriting fees and offering expenses, were $140,850. Subsequent to the IPO, the underwriters exercised their overallotment option to purchase 687,500 additional voting common shares of the Company for gross proceeds of $12,616. Net proceeds from the overallotment, after deducting underwriting fees and offering expenses, were $11,733. Total net proceeds from the IPO and subsequent overallotment were $152,583 (note 17(b)).

F-6

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

The net proceeds from the IPO and subsequent overallotment were used:

• to repurchase all of the Company’s outstanding 9% senior secured notes due 2010 for $74,748 plus accrued interest of $3,027. The notes were redeemed at a premium of 109.26% resulting in a loss on extinguishment of $6,338. The loss on extinguishment, along with the write-off of deferred financing fees of $4,342 and other costs of $255, was recorded as a loss on extinguishment of debt in the consolidated statement of operations;

• to repay the promissory note in respect of the repurchase of the NACG Preferred Corp. Series A preferred shares for $27,000 as described above;

• to purchase certain equipment leased under operating leases for $44,623;

• to cancel the consulting and advisory services agreement with the Sponsors for $2,000; and

• for general corporate purposes.

3. Significant accounting policies

a) Basis of presentation

These consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles (“GAAP”). Material inter-company transactions and balances are eliminated on consolidation. Material items that give rise to measurement differences to the consolidated financial statements under United States GAAP are outlined in note 27.

These consolidated financial statements include the accounts of the Company, its wholly-owned subsidiary, North American Construction Group Inc. (“NACGI”), the Company’s joint venture, Noramac Ventures Inc. and the following 100% owned subsidiaries of NACGI:

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

b) Use of estimates

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

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 the redemption value of redeemable securities, assumptions used in periodic impairment testing, and estimates and assumptions used in the determination of the

F-7

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

allowance for doubtful accounts and the useful lives of plant and equipment. Actual results could differ materially from those estimates.

c) Revenue recognition

The Company performs 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 using 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 contracted work.

The length of the Company’s contracts varies from less than one year for typical contracts to several years for certain larger contracts. Contract project costs include all direct labour, material, subcontract and equipment costs and those indirect costs related to contract performance such as indirect labour, supplies, and tools. General and administrative 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.

Once a project is underway, the Company will often experience changes in conditions, client requirements, specifications, designs, materials and work schedule. Generally, a “change order” will be negotiated with the customer to modify the original contract to approve both the scope and price of the change. Occasionally, however, disagreements arise regarding changes, their nature, measurement, timing and other characteristics that impact costs and revenue under the contract. When a change becomes a point of dispute between the Company and a customer, the Company will then consider it as a claim.

Costs related to change orders and claims are recognized when they are incurred. Revenues related to 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.

Revenues related to 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 (1) a bona fide addition to contract value and (2) revenues can be reliably estimated. These 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.

Claims revenue recognized was $14.5 million for the year ended March 31, 2007 (2006 – $12.9 million; 2005 – $nil), $8.4 million of which is included in unbilled revenue and remains uncollected at the end of the year (2005 – $nil). Of the amount included in unbilled revenue at March 31, 2007, $6.6 million was collected subsequent to year end.

F-8

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

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.

d) Cash and cash equivalents

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

e) Allowance for doubtful accounts

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

f) Inventory

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

g) Other assets

Other assets consist of tires and spare component parts, and are stated at the lower of weighted average cost or replacement cost. Other assets are charged to earnings when they are put into use. Included in equipment costs for the year ended March 31, 2007 is a $695 write-down of other assets to their replacement cost at March 31, 2007.

h) Plant and equipment

Plant and equipment are recorded at cost. Major components of heavy construction equipment in use such as engines and transmissions are recorded separately. Equipment under capital lease is recorded at the present value of minimum lease payments at the inception of the lease. Depreciation is not recorded until an asset is available for 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
Other equipment	Straight-line	10-20%
Licensed motor vehicles	Declining balance	30%
Office and computer equipment	Straight-line	25%
Buildings	Straight-line	10%
Leasehold improvements	Straight-line	Over shorter of estimated useful life and lease term
Assets under construction	N/A	N/A

F-9

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

The costs for periodic repairs and maintenance are expensed to the extent the expenditures serve only to restore the assets to their normal operating condition without enhancing their service potential or extending their useful lives.

i) Goodwill

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

The Company tested goodwill for impairment at December 31, 2006 and December 31, 2005 and determined that there was no impairment in carrying value. The Company conducts its annual impairment test of goodwill on December 31 of each year.

j) Intangible assets

Intangible assets 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; non-competition agreements, which are being amortized on a straight-line basis between the three and five-year terms of the respective agreements; and employee arrangements, which are being amortized on a straight-line basis over the three-year term of the arrangements.

k) Deferred financing costs

Costs relating to the issue 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 are written-off in the period of extinguishment.

l) Impairment of long-lived assets

Long-lived assets and identifiable intangible assets subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is assessed by a comparison of the carrying value of the asset to future undiscounted cash flows expected to be generated by the asset. If the value of such asset is considered to be impaired, the impairment loss is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset, and is charged to depreciation expense.

Long-lived assets are classified as held for sale when certain criteria are met, which include: management’s commitment to a plan to sell the assets; the assets are available for immediate sale in their present condition; an active program to locate buyers and other actions to the sell the assets have been

F-10

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

initiated; the sale of the assets is probable and their transfer is expected to qualify for recognition as a completed sale within one year; the assets are being actively marketed at reasonable prices in relation to their fair value; and it is unlikely that significant changes will be made to the plan to sell the assets or that the plan will be withdrawn. Assets to be disposed of by sale are reported at the lower of their carrying amount or fair value less costs to sell and are included in current assets. These assets are not depreciated.

m) Foreign currency translation

The functional currency of the Company is Canadian dollars. Transactions denominated in foreign currencies are recorded at the rate of exchange on 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.

n) Derivative financial instruments

The Company uses derivative financial instruments to manage financial risks from fluctuations in exchange rates and interest rates. These instruments include cross-currency 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 related hedged item and if 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-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 in earnings. Premiums paid or received with respect to derivatives that are hedges are deferred and amortized to income over the term of the hedge.

o) 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 from a change in tax rates is recognized in income in the period 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.

F-11

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

p) 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 at the grant date and is expensed over the award’s vesting period, with a corresponding increase to contributed surplus. Upon exercise of a stock option, share capital is recorded at the sum of proceeds received and the related amount of contributed surplus.

q) Net income (loss) per share

Basic net income (loss) per share is computed by dividing net earnings (loss) available to common shareholders by the weighted average number of shares outstanding during the year (see note 17(d)). Diluted per share amounts are calculated using the treasury stock and if-converted methods. The treasury stock method increases the diluted weighted average shares outstanding to include additional shares from the assumed exercise of stock options, if dilutive. The number of additional shares is calculated by assuming that outstanding in-the-money stock options were exercised and that the proceeds from such exercises, including any unamortized stock-based compensation cost, were used to acquire shares of common stock at the average market price during the year. The if-converted method assumes the conversion of convertible securities at the later of the beginning of the reported period or issue date, if dilutive.

r) Recently adopted Canadian accounting pronouncements

i. Consolidation of variable interest entities

Effective January 1, 2005, the Company 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. The Company has determined the joint venture in which it has an investment (note 19(c)) qualifies as a VIE and began consolidating this VIE effective January 1, 2005.

ii. 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.

iii. Vendor rebates

In April 2005, the Company adopted the 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

F-12

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

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.

iv. 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.

v. 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.

vi. 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 early 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.

vii. Stock-based compensation for employees eligible to retire before the vesting date

In July 2006, the CICA Emerging Issues Committee issued Abstract No. 162, ‘‘Stock-Based Compensation for Employees Eligible to Retire Before the Vesting Date’’ (‘‘EIC-162’’). EIC-162 requires that the compensation cost attributable to awards granted to employees eligible to retire at the grant date should be recognized on the grant date if the award’s exercisability does not depend on continued service. Additionally, awards granted to employees who will become eligible to retire during the vesting period should be recognized over the period from the grant date to the date the employee becomes eligible to retire. The Company adopted this standard for the interim period ended December 31, 2006 retroactively, with restatement of prior periods for all stock-based compensation awards. The adoption of this standard had no impact on the Company’s consolidated financial statements.

F-13

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

viii. Determining the variability to be considered in applying the VIE standards

In September 2006, the CICA issued Emerging Issues Committee Abstract No. 163, “Determining the Variability to be Considered in Applying AcG-15” (“EIC-163”). This guidance provides additional clarification on how to analyze and consolidate a VIE. EIC-163 concludes that the “by-design” approach should be the method used to assess variability (that is created by risks the entity is designed to create and pass along to its interest holders) when applying the VIE standards. The “by-design” approach focuses on the substance of the risks created over the form of the relationship. The guidance may be applied to all entities (including newly created entities) with which an enterprise first becomes involved and to all entities previously required to be analyzed under the VIE standards when a reconsideration event has occurred and is effective for interim and annual periods beginning on or after January 1, 2007. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

s) Recent Canadian accounting pronouncements not yet adopted

i. Financial instruments

In January 2005, the CICA issued Handbook Section 3855, “Financial Instruments—Recognition and Measurement”, Handbook Section 1530, “Comprehensive Income”, and Handbook Section 3865, “Hedges”. The new standards 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. 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.

Effective April 1, 2007, the Company will also be required to adopt CICA Handbook Section 3861, “Financial Instruments—Disclosure and Presentation” (“CICA 3861”), which requires entities to provide disclosures in their financial statements that enable users to evaluate: (1) the significance of financial instruments on the entity’s financial performance; and (2) the nature and extent of risks arising from the use of financial instruments by the entity during the period and at the balance sheet date, and how the entity manages those risks. The Company is currently assessing the impact of this standard.

In March 2007, the CICA issued Handbook Section 3862, “Financial Instruments—Disclosures”, which replaces CICA 3861 and provides expanded disclosure requirements that provide additional detail by financial assets and liability categories. This standard harmonizes disclosures with International Financial Reporting Standards. The standard applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.

In March 2007, the CICA issued Handbook Section 3863, “Financial Instruments—Presentation” to enhance financial statement users’ understanding of the significance of financial instruments to an entity’s financial position, performance and cash flows. This Section establishes standards for presentation of financial instruments and non-financial derivatives. It deals with the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, gains and losses, and the circumstances in which financial assets and financial liabilities are

F-14

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

offset. This standard harmonizes disclosures with International Financial Reporting Standards and applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.

ii. Equity

On April 1, 2007, the Company will adopt CICA Handbook Section 3251, “Equity”, which establishes standards for the presentation of equity and changes in equity during the reporting period. The requirements in this section are in addition to those of CICA Handbook Section 1530 and recommend that an enterprise should present separately the following components of equity: retained earnings, accumulated other comprehensive income, and the total for retained earnings and accumulated other comprehensive income, contributed surplus, share capital and reserves. The Company is currently evaluating the impact of this standard.

iii. Accounting changes

In July 2006, the CICA revised Handbook Section 1506, “Accounting Changes”, which requires that: (1) voluntary changes in accounting policy are made only if they result in the financial statements providing reliable and more relevant information; (2) changes in accounting policy are generally applied retrospectively; and (3) prior period errors are corrected retrospectively. This revised standard is effective for fiscal years beginning on or after January 1, 2007, specifically April 1, 2007 for the Company, and is not expected to have a material impact on the Company’s consolidated financial statements.

iv. Capital disclosures

In December 2006, the CICA issued Handbook Section 1535, “Capital Disclosures”. This standard requires that an entity disclose information that enables users of its financial statements to evaluate an entity’s objectives, policies and processes for managing capital, including disclosures of any externally imposed capital requirements and the consequences of non-compliance. The new standard applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.

v. Inventories

In June 2007, the CICA issued Handbook Section 3031, “Inventories” to harmonize accounting for inventories under Canadian GAAP with International Financial Reporting Standards. This standard requires the measurement of inventories at the lower of cost and net realizable value and includes guidance on the determination of cost, including allocation of overheads and other costs to inventory. The standard also requires the consistent use of either first-in, first out (FIFO) or weighted average cost formula to measure the cost of other inventories and requires the reversal of previous write-downs to net realizable value when there is a subsequent increase in the value of inventories. The new standard applies to interim and annual financial statements relating to fiscal years beginning on or after January 1, 2008, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.

4.    Acquisition

On September 1, 2006, the Company acquired all of the shares of Midwest Foundation Technologies Ltd., a piling company specializing in the design and installation of micropile foundations in western Canada, for cash

F-15

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

consideration and acquisition costs totalling $1,646. The transaction has been accounted for by the purchase method with the results of operations included in the financial statements from the date of acquisition. The final purchase price allocation is as follows:

Net assets acquired at fair values:
Working capital (including cash of $129)	$	170
Plant and equipment		554
Intangible assets
Customer relationships		210
Non-competition agreement		200
Goodwill (assigned to the Piling segment)		843
Future income tax liability		(194	)
Capital lease obligations		(137	)
	$	1,646

5.    Accounts receivable

	March 31, 2007			March 31, 2006
Accounts receivable—trade	$	69,320		$	55,666
Accounts receivable—holdbacks		19,496			10,748
Income and other taxes receivable		3,034			—
Accounts receivable—other		1,458			891
Allowance for doubtful accounts		(88	)		(70	)
	$	93,220		$	67,235

Accounts receivable—holdbacks represent amounts up to 10% under certain contracts that the customer is contractually entitled to withhold until completion of the project or until certain project milestones are achieved.

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

	March 31, 2007			March 31, 2006
Costs incurred and estimated earnings on uncompleted contracts	$	742,186		$	610,006
Less: billings to date		(662,352	)		(571,636	)
	$	79,834		$	38,370

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

	March 31, 2007			March 31, 2006
Unbilled revenue	$	82,833		$	43,494
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		(2,999	)		(5,124	)
	$	79,834		$	38,370

F-16

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

7.    Prepaid expenses and deposits

	March 31, 2007		March 31, 2006
Prepaid insurance and property taxes	$	916	$	345
Prepaid lease payments		3,934		—
Deposits for tires		7,082		1,451
	$	11,932	$	1,796

8.    Asset held for sale

Included in depreciation expense for the year ended March 31, 2007 is an impairment charge of $3,582 (2006 – $nil; 2005 – $nil) relating to a decision to dispose of a heavy construction asset in the Mining & Site Preparation segment. The impairment charge is the amount by which the carrying value of the asset exceeded its fair value less costs to sell. The asset has been reclassified from plant and equipment to current assets as the sale of the asset is expected to occur in fiscal 2008.

9.    Plant and equipment

March 31, 2007	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	254,107	$	46,609	$	207,498
Major component parts in use		7,884		2,489		5,395
Other equipment		16,001		5,651		10,350
Licensed motor vehicles		23,345		12,121		11,224
Office and computer equipment		4,841		2,249		2,592
Buildings		16,443		716		15,727
Leasehold improvements		2,992		664		2,328
Assets under construction		849		—		849
	$	326,462	$	70,499	$	255,963
March 31, 2006	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	174,042	$	31,347	$	142,695
Major component parts in use		5,088		2,091		2,997
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
	$	232,336	$	47,774	$	184,562

F-17

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

The above amounts include $15,422 (March 31, 2006 – $14,559) of assets under capital lease and $7,302 (March 31, 2006 – $4,479) of related accumulated depreciation. During the year ended March 31, 2007 additions to plant and equipment included $4,653 of assets that were acquired by means of capital leases (2006 – $5,910; 2005 – $5,385). Depreciation of equipment under capital lease of $1,481 (2006 – $2,545; 2005 – $1,659) is included in depreciation expense.

10.    Intangible assets

March 31, 2007	Cost		Accumulated amortization		Net book value
Customer contracts in progress and related relationships	$	15,533	$	15,360	$	173
Other intangible assets		2,675		2,248		427
	$	18,208	$	17,608	$	600

March 31, 2006	Cost		Accumulated amortization		Net book value
Customer contracts in progress and related relationships	$	15,323	$	15,323	$	—
Other intangible assets		2,475		1,703		772
	$	17,798	$	17,026	$	772

Amortization of intangible assets of $582 was recorded for the year ended March 31, 2007 (2006 – $730; 2005 – $3,368).

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

For the year ending March 31,
2008	$	156
2009		134
2010		78
2011		49
2012 and thereafter		183
	$	600

11.    Deferred financing costs

For the year ended March 31, 2007, fees of $275 were paid to the holders of the 8 ³/4% senior notes in connection with an amendment of the indenture governing the 8 ³/4% senior notes (note 15). The amendment has been accounted for as a modification, and the fees paid to the note holders, together with the existing unamortized deferred financing costs, were deferred and will be amortized on a straight-line basis over the remaining term of the 8 ³/4% senior notes.

During the year ended March 31, 2007, financing fees totaling $1,071 paid in connection with amendment of the revolving credit facility (note 12) were recorded as deferred financing costs. These costs, together with the

F-18

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

existing unamortized deferred financing costs, were deferred and will be amortized on a straight-line basis over the term of the amended revolving credit facility consistent with accounting for the amendment of the revolving credit facility as a modification.

In connection with the retirement of the 9% senior secured notes on November 28, 2006, the Company wrote off deferred financing costs of $4,342 (notes 2 and 15) during the year ended March 31, 2007.

For the year ended March 31, 2006, financing costs of $7,546 were incurred in connection with the issue 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 issue of the NAEPI Series A redeemable preferred shares and expensed in the year ended March 31, 2006.

On May 19, 2005, the Company repaid its entire indebtedness under a previous revolving credit facility and term loan using the net proceeds from the issue of the 9% senior secured notes (note 15) and the NAEPI Series B preferred shares (note 17(a)). 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 during the year ended March 31, 2006.

Amortization of deferred financing costs of $3,436 was recorded for the year ended March 31, 2007 (2006 – $3,338; 2005 – $2,554).

12.    Revolving credit facility

On May 19, 2005, NAEPI entered into a revolving credit facility with a syndicate of lenders. In connection with the revolving credit facility, NAEPI was required to amend its existing swap agreements to increase the effective rate of interest on its 8 ³/4% senior notes from 9.765% to 9.889% (note 22(c)) and issue to one of the counterparties to the swap agreements $1.0 million of NAEPI Series A redeemable preferred shares (note 17(a)).

On July 19, 2006, the Company amended and restated its credit agreement to provide for borrowings of up to $55.0 million (previously $40.0 million), subject to borrowing base limitations, under which revolving loans and letters of credit may be issued (previously up to a limit of $30.0 million). Prime rate revolving loans under the amended and restated agreement bear interest at the Canadian prime rate plus 2.0% per annum and swing line revolving loans 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 July 19, 2006 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 fair 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. Other terms of the agreement, including the expiry date, did not change. The expiry date of the amended and restated revolving credit facility is March 1, 2010.

F-19

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

As of March 31, 2007, the Company had outstanding borrowings of $20.5 million (2006 – $nil) under the revolving credit facility and had issued $25.0 million in letters of credit to support performance guarantees associated with customer contracts. As of March 31, 2006, the Company 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 was $9.5 million at March 31, 2007 (2006 – $9.3 million).

The Company entered into an amended and restated credit agreement on June 6, 2007 (note 28).

13.    Accrued liabilities

	March 31, 2007		March 31, 2006
Accrued interest payable	$	8,669	$	10,878
Payroll liabilities		7,484		7,423
Liabilities related to equipment leases		7,039		5,061
Income and other taxes payable		201		1,241
	$	23,393	$	24,603

14.    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:

2008	$	3,795
2009		3,133
2010		2,121
2011		1,395
2012		242
		10,686
Less: amount representing interest—weighted average rate of 9.14%		977
Present value of minimum lease payments		9,709
Less: current portion		3,195
	$	6,514

15.    Senior notes

	March 31, 2007		March 31, 2006
8 3/4% senior unsecured notes due 2011	$	230,580	$	233,420
9% senior secured notes due 2010		—		70,587
	$	230,580	$	304,007

F-20

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

The 8 ³/4% 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 with interest payable semi-annually on June 1 and December 1 of each year.

The 8 ³/4% 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 outstanding amount of such debt.

The 8 ³/4% 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.

If a change of control occurs, the Company will be required to offer to purchase all or a portion of each holder’s 8 ³/4% senior notes, at a purchase price in cash equal to 101% of the principal amount of the notes offered for repurchase plus accrued interest to the date of purchase.

On December 21, 2006, the indenture governing the 8 ³/4% senior notes was amended to remove the requirement to provide a reconciliation from Canadian GAAP to United States GAAP in the Company’s interim consolidated financial statements.

The 9% senior secured notes were issued on May 19, 2005 in the amount of US$60.481 million (Canadian $76.345 million). In connection with the IPO (note 2), the Company repurchased the 9% senior secured notes for $74,748 plus accrued interest of $3,027 on November 28, 2006. These notes were redeemed at a premium of 109.26% on November 28, 2006 resulting in a loss on extinguishment of $6,338. The loss on settlement, along with the write-off of deferred financing fees of $4,342 and third party transaction costs of $255, was recorded as a loss on extinguishment of debt in the consolidated statement of operations for the year ended March 31, 2007.

F-21

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

16.    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,
	2007			2006			2005
Income (loss) before income taxes	$	18,486		$	(21,204	)	$	(44,587	)
Statutory tax rate		32.12	%		33.62	%		33.62	%
Expected provision (recovery) at statutory tax rate	$	5,938		$	(7,129	)	$	(14,990	)
Increase (decrease) related to:
Change in future income tax liability, resulting from enacted change in future statutory income tax rates		(2,106	)		—			—
Change in redemption value and accretion of redeemable preferred shares		1,000			11,674			—
Change in future income tax liability, resulting from valuation allowance		(5,858	)		(4,097	)		12,189
Non-taxable gain on repurchase of NACG Preferred Corp. Series A preferred shares		(3,019	)		—			—
Non-deductible financing transactions		1,196			—			—
Large corporations tax		(136	)		716			871
Other		392			(427	)		(334	)
Income tax provision (recovery)	$	(2,593	)	$	737		$	(2,264	)

Classified as:

	Year ended March 31,
	2007			2006		2005
Current income taxes	$	(2,975	)	$	737	$	2,711
Future income taxes		382			—		(4,975	)
	$	(2,593	)	$	737	$	(2,264	)

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

	March 31, 2007		March 31, 2006
Future income tax assets:
Non-capital losses carried forward	$	23,875	$	22,312
Deferred share issue costs		4,547		—
Deferred premium on senior notes		1,614		—
Derivative financial instruments		4,787		6,843
Unrealized foreign exchange loss on senior notes		1,730		2,299
Billings in excess of costs on uncompleted contracts		963		1,723
Capital lease obligations		1,713		1,631
Total future income tax assets		39,229		34,808
Less valuation allowance		—		(5,858	)
Net future income tax assets		39,229		28,950

F-22

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

	March 31, 2007		March 31, 2006
Future income tax liabilities:
Unbilled revenue and uncertified revenue included in accounts receivable		3,751		1,970
Asset held for sale		1,878		—
Accounts receivable—holdbacks		6,262		3,613
Plant and equipment		20,897		20,263
Deferred financing costs		1,176		1,038
Intangible assets		174		130
Unrealized foreign exchange gain on senior notes		—		1,936
Total future income tax liabilities		34,138		28,950
Net future income taxes	$	5,091	$	—

Classified as:

	March 31, 2007			March 31, 2006
Current asset	$	14,593		$	5,238
Long-term asset		14,364			5,383
Current liability		(4,154	)		(5,238	)
Long-term liability		(19,712	)		(5,383	)
	$	5,091		$	—

Future income tax expense for the year ended March 31, 2007 includes a recovery of $5,858 resulting from the elimination of the valuation allowance. Management considers the scheduled reversals of future income tax liabilities, the character of income tax assets and available tax planning strategies of the Company and its subsidiaries when evaluating the expected realization of future income tax assets. Based on management’s estimate of the expected realization of future income tax assets during the current period, the Company eliminated the valuation allowance recorded against future income tax assets to reflect that it is more likely than not that the future income tax assets will be realized.

At March 31, 2007, the Company has non-capital losses for income tax purposes of approximately $75,087 which expire as follows:

2015	$	45,888
2026		9,000
2027		20,199

17.    Shares

a) Redeemable preferred shares

	March 31, 2007		March 31, 2006
NACG Preferred Corp. Series A preferred shares (i)	$	—	$	35,000
NAEPI Series A preferred shares (ii)		—		375
NAEPI Series B preferred shares (iii)		—		42,193
	$	—	$	77,568

F-23

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

i. NACG Preferred Corp. preferred shares

Issued and outstanding:

	Number of Shares		Amount
Issued and outstanding at March 31, 2004, 2005 and 2006	35,000		$	35,000
Repurchased and cancelled	(35,000	)		(35,000	)
Issued and outstanding at March 31, 2007	—		$	—

NACG Preferred Corp. was authorized to issue an unlimited number of Series A preferred shares. The NACG Preferred Corp. Series A preferred shares accrued dividends at a rate of $80.00 per share annually if earnings before interest, taxes, depreciation and amortization (“EBITDA”) for NAEPI was in excess of $75.0 million for the year. The dividends were payable in cash, additional NACG Preferred Corp. Series A preferred shares, or any combination of cash and shares as determined by the Company. The number of shares issuable was .001 of a whole NACG Preferred Corp. Series A preferred share for each $1.00 of dividend declared.

The NACG Preferred Corp. Series A preferred shares, which were issued in connection with the acquisition described in note 1 and were recorded at their guaranteed redemption amount, were redeemable at any time at the option of the Company, and were required to be redeemed on or before November 26, 2012. The redemption price was $1,000.00 per share plus all accrued and unpaid dividends. In the event of a change in control, each holder of NACG Preferred Corp. Series A preferred shares had the right to require the Company to redeem all or any part of such holder’s shares.

On November 28, 2006, the Company acquired the NACG Preferred Corp. Series A preferred shares for a promissory note in the amount of $27,000 and accrued dividends of $1,400 at that time were forfeited resulting in a gain on settlement of $9,400. The promissory note was subsequently repaid with the proceeds from the IPO (note 2).

ii. NAEPI Series A preferred shares

Issued and outstanding:

	Number of Shares		Amount
Issued and outstanding at March 31, 2004 and 2005	—			—
Issued	1,000			321
Accretion	—			54
Issued and outstanding at March 31, 2006	1,000		$	375
Accretion	—			625
Repurchased and cancelled	(1,000	)		(1,000	)
Issued and outstanding at March 31, 2007	—		$	—

NAEPI was authorized to issue an unlimited number of Series A preferred shares. The NAEPI Series A preferred shares were non-voting and were not entitled to any dividends. The NAEPI Series A preferred shares were mandatorily redeemable at $1,000 per share on the earlier of (1) December 31, 2011 and (2) an

F-24

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

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 8 ³/4% senior notes and the Company’s 9% senior secured notes are no longer outstanding. NAEPI had the right to redeem the NAEPI Series A preferred shares, in whole or in part, at $1,000 per share at any time.

The NAEPI Series A preferred shares were issued to one of the counterparties to NAEPI’s swap agreements on May 19, 2005 in connection with obtaining a new revolving credit facility. These shares were not entitled to dividends.

The NAEPI Series A preferred shares were initially recorded at their fair value on the date of issue, which was estimated to be $321 based on the present value of the required cash flows using the discount rate implicit at inception. Each reporting period, the accretion of the carrying value to the present value of the redemption amount at each balance sheet date was recorded as interest expense. For the year ended March 31, 2007, the Company recognized $625 of accretion as interest expense (2006 – $54).

On October 6, 2006, the Board of Directors approved the purchase of the NAEPI Series A preferred shares for $1,000 effective with the consummation of the IPO, and these shares were purchased on November 28, 2006 pursuant to an affiliate purchase right under the terms of the NAEPI Series A preferred shares. Accordingly, the Company recorded the additional accretion charge and the extinguishment of the obligation in the year ended March 31, 2007.

iii. NAEPI Series B preferred shares

Issued and outstanding:

	Number of Shares		Amount
Issued and outstanding at March 31, 2004 and 2005	—			—
Issued	83,462			8,376
Repurchased	(8,218	)		(851	)
Change in redemption amount	—			34,668
Issued and outstanding at March 31, 2006	75,244		$	42,193
Accretion	—			2,489
Transferred to common shares on conversion	(75,244	)		(44,682	)
Issued and outstanding at March 31, 2007	—		$	—

NAEPI was authorized to issue an unlimited number of Series B preferred shares. The NAEPI Series B preferred shares were non-voting and were entitled to cumulative dividends at an annual rate of 15% of the issue price of each share. No dividends were payable on NAEPI common shares or other classes of preferred shares (defined as Junior Shares) unless all cumulative dividends had been paid on the NAEPI Series B preferred shares and NAEPI declared a NAEPI 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). The payment of dividends and the redemption of the NAEPI Series B preferred shares were prohibited by the Company’s revolving credit facility agreement. The payment of dividends and the redemption of the NAEPI Series B preferred shares was also restricted by the indenture agreements governing the Company’s 9% senior secured notes and 8 ³/4% senior notes.

F-25

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

7,500 NAEPI Series B preferred shares were issued to non-employee shareholders of the Company for cash proceeds of $7.5 million on May 19, 2005. The NAEPI Series B preferred shares were initially issued to certain non-employee shareholders with the agreement that an offer to purchase these NAEPI Series B preferred shares would also be extended to other shareholders of the Company on a pro rata basis to their interest in the common shares of the Company.

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

On August 31, 2005, NAEPI issued 8,218 NAEPI Series B preferred shares for cash consideration of $851 to certain shareholders of the Company as a result of this offer. On November 1, 2005, NAEPI repurchased and cancelled 8,218 of the NAEPI Series B preferred shares held by the original non-employee shareholders for cash consideration of $851.

On October 6, 2005, an additional 244 NAEPI Series B preferred shares were issued for cash consideration of $25.

Initially, the redemption price of the NAEPI Series B preferred shares was 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 NAEPI 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 NAEPI Series B preferred shares, provides the holder with a 40% rate of return, compounded annually, on the issue price from the date of issue; and (iii) an amount, not to exceed $100 million, which is equal to 25% of the arm’s length fair market value of NAEPI’s common shares without taking into account the NAEPI Series B preferred shares.

On March 30, 2006, the terms of the NAEPI 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 NAEPI Series B preferred shares on March 30, 2006, the NAEPI Series B preferred shares were considered mandatorily redeemable and the Company was required to measure the NAEPI 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 of $34,668 in the carrying value as an increase in interest expense for the year ended March 31, 2006.

Concurrent with the amendment to the NAEPI Series B preferred shares, the Company entered into a Put/Call Agreement with the holders of the NAEPI Series B preferred shares. The Put/Call Agreement granted to each holder of the NAEPI Series B preferred shares the right (the “Put/Call Right”) to require the Company to exchange each of the holder’s NAEPI Series B preferred shares for 100 common shares (on a post-split basis—note 17(b)) of the Company. The Put/Call Right could only be exercised upon delivery by the Company of an “Event Notice”, being either: (i) a redemption or purchase call for the redemption or purchase of the NAEPI Series B preferred shares in connection with (A) a redemption on December 31, 2011, or (B) an Accelerated Redemption Event (as defined in note 17(a)(ii)); or (ii) a notice in connection with a Liquidation Event (defined as a liquidation, winding-up or dissolution of NAEPI, whether voluntary or involuntary).

The Put/Call Agreement also granted the Company the right to require the holders of the NAEPI Series B preferred shares to exchange each of their NAEPI Series B preferred shares for 100 common shares (on a post-split basis—note 17(b)) of the Company upon delivery of a call notice to shareholders within five business days of an Event Notice.

F-26

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

As a result of the March 30, 2006 amendment to the terms of the NAEPI Series B preferred shares and the concurrent execution of the Put/Call Agreement, the Company accounted for the amendment as a related party transaction at the carrying amount. No value was ascribed to the equity classified Put/Call Right as it was a related party transaction. The NAEPI Series B preferred shares were being 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 to December 31, 2011. For the year ended March 31, 2007, the Company recognized $2,489 of interest expense for this accretion.

On October 6, 2006, the Board of Directors approved the exercise of the call option to acquire all of the issued and outstanding NAEPI Series B preferred shares in exchange for 7,524,400 common shares of the Company and the option was exercised on November 28, 2006. The Company recorded the exchange by transferring the carrying value of the Series B preferred shares on the exercise date of $44,682 to common shares.

b) Common shares

On November 3, 2006, the Board of Directors and common shareholders approved a 20-for-1 share split of the Company’s voting and non-voting common shares. All information relating to the exchange of the NAEPI Series B preferred shares (note 17(a)), the issued and outstanding common shares (below), basic and diluted net income (loss) per share data (note 17(d)), stock options (note 25), and basic and diluted net income (loss) per share data under U.S. GAAP (note 27) have been adjusted retroactively to reflect the impact of the share split in these financial statements. The share split was effective November 3, 2006.

Authorized:

Unlimited number of common voting shares

Unlimited number of common non-voting shares

Issued and outstanding:

	Number of Shares(1)		Amount
Common voting shares
Issued and outstanding at March 31, 2004	18,087,600		$	90,438
Issued	60,000			300
Issued and outstanding at March 31, 2005	18,147,600			90,738
Issued	60,000			300
Issued and outstanding at March 31, 2006	18,207,600			91,038
Issued upon exercise of stock options	27,760			139
Transferred from contributed surplus on exercise of stock options	—			52
Repurchased and cancelled prior to initial public offering	(5,000	)		(25	)
Conversion of NAEPI Series B preferred shares	7,524,400			44,682
Initial public offering	9,437,500			171,165
Share issue costs (net of future income tax recovery of $5,667)	—			(12,915	)
Issued and outstanding at March 31, 2007	35,192,260		$	294,136
Common non-voting shares
Issued and outstanding at March 31, 2004, 2005, 2006 and 2007	412,400		$	2,062
Total common shares at March 31, 2007	35,604,660		$	296,198

(1) The issued and outstanding common shares have been retroactively adjusted to reflect the Company’s 20-for-1 share split effected on November 3, 2006.

F-27

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

During the year ended March 31, 2005, 60,000 common voting shares were issued for cash consideration of $300. During the year ended March 31, 2006, 60,000 common voting shares were issued for cash consideration of $300. During the year ended March 31, 2007, 5,000 common shares were repurchased for cancellation at a cost of $84, of which $25 reduced share capital and $59 increased the Company’s deficit.

c) Contributed surplus

Balance, March 31, 2004	$	137
Stock-based compensation (note 25)		497
Balance, March 31, 2005		634
Stock-based compensation (note 25)		923
Balance, March 31, 2006		1,557
Stock-based compensation (note 25)		2,101
Transferred to common shares on exercise of stock options		(52	)
Balance, March 31, 2007	$	3,606

d) Net income (loss) per share

	Year ended March 31,
	2007		2006			2005
Basic net income (loss) per share
Net income (loss) available to common shareholders	$	21,079	$	(21,941	)	$	(42,323	)
Weighted average number of common shares		24,352,156		18,574,800			18,539,720
Basic net income (loss) per share	$	0.87	$	(1.18	)	$	(2.28	)
Diluted net income (loss) per share
Net income (loss) available to common shareholders	$	21,079	$	(21,941	)	$	(42,323	)
Weighted average number of common shares		24,352,156		18,574,800			18,539,720
Dilutive effect of:
Stock options		1,091,751		—			—
Weighted average number of diluted common shares		25,443,907		18,574,800			18,539,720
Diluted net income (loss) per share	$	0.83	$	(1.18	)	$	(2.28	)

For the year ended March 31, 2007, average stock options of 98,767 were excluded from the calculation of diluted net income per share as the options’ average exercise price was greater than the average market price of the common shares for the year.

For the years ending March 31, 2006 and March 31, 2005, the effect of outstanding stock options and convertible securities on net loss per share was anti-dilutive. As such, the effect of outstanding stock options and convertible securities used to calculate the diluted net loss per share has not been disclosed for these years.

F-28

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

18. Interest expense

	Year ended March 31,
	2007		2006		2005
Interest on senior notes	$	27,417	$	28,838	$	23,189
Interest on capital lease obligations		725		457		230
Interest on senior secured credit facility		—		564		3,274
Interest on NACG Preferred Corp. Series A preferred shares		1,400		—		—
Accretion and change in redemption value of NAEPI Series B preferred shares		2,489		34,668		—
Accretion of NAEPI Series A preferred shares		625		54		—
Interest on long-term debt		32,656		64,581		26,693
Amortization of deferred financing costs		3,436		3,338		2,554
Other interest		1,157		857		1,894
	$	37,249	$	68,776	$	31,141

19. Other information

a) Supplemental cash flow information

	Year ended March 31,
	2007		2006		2005
Cash paid during the year for:
Interest	$	34,061	$	29,978	$	31,398
Income taxes		342		617		3,588
Cash received during the year for:
Interest		1,156		530		362
Income taxes		160		2		—
Non-cash transactions:
Acquisition of plant and equipment by means of capital leases		4,653		5,910		5,385
Issue of Series A preferred shares		—		321		—

b) Net change in non-cash working capital

	Year ended March 31,
	2007			2006			2005
Accounts receivable	$	(25,278	)	$	(9,396	)	$	(24,029	)
Allowance for doubtful accounts		18			(94	)		(69	)
Unbilled revenue		(39,339	)		(2,083	)		(13,735	)
Inventory		(99	)		77			1,475
Prepaid expenses and deposits		(10,133	)		66			(590	)
Other assets		(9,855	)		(163	)		(840	)
Accounts payable		39,995			(5,005	)		29,789
Accrued liabilities		(1,429	)		9,402			507
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		(2,125	)		3,799			1,325
	$	(48,245	)	$	(3,397	)	$	(6,167	)

F-29

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

c) 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.

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:

	Year ended March 31, 2005
Revenue	$	7,631
Project costs		(8,840	)
General and administrative		—
Net income (loss)	$	(1,209	)
	Year ended March 31, 2005
Cash provided by:
Operating activities	$	(4,668	)
Investing activities		—
Financing activities		5,061
	$	393

20.    Segmented information

a) General overview

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

• Mining and Site Preparation:

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

• Piling:

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

• Pipeline:

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

F-30

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

b) Results by business segment:

For the year ended March 31, 2007	Mining and Site Preparation		Piling		Pipeline			Total
Revenues from external customers	$	473,179	$	109,266	$	47,001		$	629,446
Depreciation of plant and equipment		21,855		2,949		946			25,780
Segment profits		71,062		34,395		(10,539	)		94,918
Segment assets		467,315		93,703		66,118			627,136
Expenditures for segment plant and equipment		95,829		8,940		1,918			106,687
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

c) Reconciliations:

i. Income (loss) before income taxes

	Year ended March 31,
	2007			2006			2005
Total profit for reportable segments	$	94,918		$	82,312		$	29,838
Unallocated corporate expenses		(73,950	)		(102,190	)		(80,219	)
(Unallocated) over allocated equipment costs		(2,482	)		(1,326	)		5,794
Income (loss) before income taxes	$	18,486		$	(21,204	)	$	(44,587	)

ii. Total assets:

	March 31, 2007		March 31, 2006
Total assets for reportable segments	$	621,636	$	460,771
Corporate assets		89,100		107,911
Total assets	$	710,736	$	568,682

F-31

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

The Company’s goodwill is assigned to the Mining and Site Preparation, Piling and Pipeline segments in the amounts of $125,447, $41,192, and $32,753, respectively.

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

d) Customers:

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

	Year ended March 31,
	2007		2006		2005
Customer A	17	%	32	%	12	%
Customer B	16	%	5	%	8	%
Customer C	12	%	16	%	26	%
Customer D	10	%	6	%	4	%
Customer E	10	%	2	%	0	%
Customer F	4	%	10	%	9	%
Customer G	1	%	6	%	10	%
Customer H	1	%	2	%	11	%

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

21.    Related party transactions

Prior to the reorganization and IPO described in Note 2, the Company had a consulting and advisory services agreement with the Sponsors, under which the Company and certain of its subsidiaries received consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. An advisory fee of $400 for the year ended March 31, 2007 (2006 – $400; 2005 – $400) was paid for these services and was recorded as part of general and administrative costs in the consolidated statement of operations.

On November 28, 2006, upon closing of the IPO described in Note 2, the consulting and advisory services agreement was cancelled. The consideration paid by the Company on the closing of the offering to cancel the agreement was $2,000, which was recorded as part of general and administrative expense during the year ended March 31, 2007. In addition, the Sponsors also received a fee of $854, 0.5% of the aggregate gross proceeds to the Company from the IPO, which was recorded as a share issue cost.

During the year ended March 31, 2006, 75,000 NAEPI Series B preferred shares (on a post-split basis—note 17(a)(iii)) were issued to the above Sponsor group in exchange for cash of $7.5 million (note 17(a)).

Pursuant to several office lease agreements, for the year ended March 31, 2007 the Company paid $572 (2006 – $836; 2005 – $824) to a company owned, indirectly and in part, by one of the directors. Effective November 28, 2006 the director resigned from the board. Accordingly, the lease agreement is no longer considered to be with a related party.

F-32

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

All related party transactions described above were measured at the exchange amount, being the consideration established and agreed to by the related parties.

22.    Financial instruments and risk management

a) Fair value of financial instruments

The fair values of the Company’s cash and cash equivalents, accounts receivable, unbilled revenue, accounts payable and accrued liabilities approximate their carrying amounts due to the relatively short periods to maturity for the instruments.

The fair value of amounts due under the revolving credit facility 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 amounts due under the revolving credit facility and the Company’s capital lease obligations as at March 31, 2007 and March 31, 2006 are not significantly different than their carrying values. The fair value of the 8 ³/4% notes, based upon their year end trading value as at March 31, 2007, is $239,803 (March 31, 2006 – $228,752) compared to their carrying value of $230,580 (March 31, 2006 – $233,420). The fair value of the 9% senior secured notes, based upon their year end trading value as at March 31, 2006, was $74,646 compared to their carrying value of $70,587.

b) Risk management

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.

i. Foreign currency risk and derivative financial instruments

The Company has 8 ³/4% 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 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 issue 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 8 ³/4% senior notes into a fixed rate of 9.765% for the duration that the 8 ³/4% senior notes are outstanding. On May 19, 2005 in connection with the Company’s new revolving credit facility at that time, this fixed rate was increased to 9.889%. These derivative financial instruments were not designated as a hedge for accounting purposes. At March 31, 2007, the Company’s derivative financial instruments are carried on the consolidated balance sheets at their fair value of $60,863 (March 31, 2006 – $63,611). 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, 2007, 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 is also exposed 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.

F-33

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

ii. Interest rate risk

The Company is exposed to interest rate risk on the revolving credit facility and its capital lease obligations. The Company also leases equipment with a variable lease payment component that is tied to prime rates. The Company does not use derivative financial instruments to reduce its exposure to these risks.

iii. 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 activities and balances in these accounts to manage its credit risk and to assess the need for an allowance for any doubtful accounts.

At March 31, 2007 and March 31, 2006, the following customers represented 10% or more of accounts receivable and unbilled revenue:

	March 31, 2007		March 31, 2006
Customer A	15	%	6	%
Customer B	10	%	5	%
Customer C	10	%	1	%
Customer D	9	%	21	%
Customer E	7	%	11	%

23. 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,
2008	$	13,787
2009		13,331
2010		10,298
2011		3,016
2012 and thereafter		135
	$	40,567

24. 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, 2007 were $645 (2006 – $409; 2005 – $305).

F-34

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

25. Stock-based compensation plan

Under the 2004 Amended and Restated Share Option Plan, directors, officers, employees and certain service providers to the Company are eligible to receive stock options to acquire voting common shares in the Company. Each stock option provides the right to acquire one common share in the Company and expires ten years from the grant date or on termination of employment. Options may be exercised at a price determined at the time the option is awarded, and vest as follows: no options vest on the award date and twenty percent vest on each subsequent anniversary date.

	Number of options(1)		Weighted average exercise price $ per share(1)
Outstanding at March 31, 2004	1,082,600		$	5.00
Granted	482,240			5.00
Exercised	—			—
Forfeited	(40,000	)		(5.00	)
Outstanding at March 31, 2005	1,524,840			5.00
Granted	745,520			5.00
Exercised	—			—
Forfeited	(204,000	)		(5.00	)
Outstanding at March 31, 2006	2,066,360			5.00
Granted	315,520			11.99
Exercised	(27,760	)		(5.00	)
Forfeited	(207,280	)		(5.00	)
Outstanding at March 31, 2007	2,146,840		$	6.03

(1) The number of options and the weighted average exercise price per share have been retroactively adjusted to reflect the impact of the 20-for-1 share split disclosed in note 17(b).

The following table summarizes information about stock options outstanding at March 31, 2007:

	Options outstanding				Options exercisable
Exercise price	Number	Weighted average remaining life	Weighted average exercise price ($)		Number	Weighted average exercise price ($)
$5.00	1,959,080	7.6 years	$	5.00	837,352	$	5.00
$16.75	187,760	9.5 years	$	16.75	—		—
	2,146,840		$	6.03	837,352	$	5.00

At March 31, 2007, the weighted average remaining contractual life of outstanding options is 7.7 years (March 31, 2006 – 8.2 years). The Company recorded $2,101 of compensation expense related to stock options in the year ended March 31, 2007 (2006 – $923; 2005 – $497) with such amount being credited to contributed surplus.

F-35

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

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

	Year ended March 31,
	2007		2006		2005
Number of options granted(1)	315,520		745,520		482,240
Weighted average fair value per option granted ($)(1)	9.91		3.41		3.43
Weighted average assumptions
Dividend yield	nil	%	nil	%	nil	%
Expected volatility	24.73	%	nil	%	nil	%
Risk-free interest rate	4.30	%	4.13	%	4.25	%
Expected life (years)	6.4		10		10

(1) The number of options and the weighted average fair value per option granted have been retroactively adjusted to reflect the impact of the 20-for-1 share split disclosed in note 17(b).

As a result of the filing of a preliminary prospectus on July 21, 2006 with the various Canadian and U.S. securities commissions in preparation for the public sale of common shares, the Company is no longer eligible to use the minimum value method for measuring stock-based compensation. Accordingly, the Company considered the effect of expected volatility in its assumptions using the Black-Scholes option pricing model for options granted after this date. The Company determined its expected volatility based on a statistical analysis of historical volatility for a peer group of companies, which was prepared by an independent valuation firm.

During the year ended March 31, 2007, the Company offered to accelerate the vesting of 222,080 options held by certain members of its Board of Directors, providing for the options to become immediately exercisable on the condition that such options be exercised by September 30, 2006. On July 31, 2006, 27,760 options were exercised pursuant to this offer resulting in additional compensation cost of $24 for the year ended March 31, 2007. The vesting period remained unchanged for stock options held by Directors who did not accept the Company’s offer.

On October 6, 2006, the Company approved the Amended and Restated 2004 Share Option Plan. The amended plan was approved by the shareholders on November 3, 2006 and became effective on the closing of the IPO described in note 2. Option grants under the amended option plan may be made to directors, officers, employees and service providers selected by the Compensation Committee of the Company’s Board of Directors. The Compensation Committee may provide that any options granted will vest immediately or in increments over a period of time. Options to be granted under the amended option plan will have an exercise price of not less than the volume weighted average trading price of the common shares on the Toronto Stock Exchange or the New York Stock Exchange at the time of grant. The amended option plan provides that up to 10% of the Company’s issued and outstanding common shares from time to time may be reserved for issue or issued from treasury under the amended option plan.

In the event of certain change of control events as defined in the amended option plan, all outstanding options will become immediately vested and exercisable. The amended option plan provides that the Company’s Board of Directors can make certain specified amendments to the option plan subject to receipt of shareholder and regulatory approval, and further authorizes the Board of Directors to make all other amendments to the plan, subject only to regulatory approval but without shareholder approval. The amendments the Board of Directors

F-36

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

may make without shareholder approval include amendments of a housekeeping nature, changes to the vesting provisions of an option or the option plan, changes to the termination provisions of an option or the option plan which do not entail an extension beyond the original expiry date, the discontinuance of the option plan, and the addition of provisions relating to phantom share units, such as restricted share units and deferred share units which result in participants receiving cash payments, and the terms governing such features.

The amended option plan provides that each option includes a cashless exercise alternative which provides a holder of an option with the right to elect to receive cash in lieu of purchasing the number of shares under the option. Notwithstanding such right, the amended option plan provides that the Company may elect, at its sole discretion, to net settle the option in common stock.

All outstanding options granted under the 2004 Stock Option Plan remained outstanding after the amended and restated plan became effective.

26. Comparative figures

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

27. United States generally accepted accounting principles

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

	Year ended March 31,
	2007			2006			2005
Net income (loss)—as reported	$	21,079		$	(21,941	)	$	(42,323	)
Capitalized interest (a)		249			847			—
Depreciation of capitalized interest (a)		(143	)		—			—
Amortization using effective interest method (b)		1,246			590			—
Difference between accretion of NAEPI Series B preferred shares under Canadian GAAP and U.S. GAAP (f)		249			—			—
Realized and unrealized loss on derivative financial instruments (e)		348			(484	)		—
Income (loss) before income taxes		23,028			(20,988	)		(42,323	)
Income taxes:
Deferred income taxes (h)		(954	)		—			—
Net income (loss)—U.S. GAAP	$	22,074		$	(20,988	)	$	(42,323	)
Net income (loss) per share—basic—U.S. GAAP (1)	$	0.91		$	(1.13	)	$	(2.28	)
Net income (loss) per share—diluted—U.S. GAAP (1)	$	0.87		$	(1.13	)	$	(2.28	)

(1) Basic net income (loss) per share—U.S. GAAP and diluted net income (loss) per share—U.S. GAAP have been retroactively adjusted to reflect the Company’s 20-for-1 share split effected on November 3, 2006 (see note 17(a)).

F-37

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or 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, 2007			March 31, 2006
Shareholders’ equity (as reported)—Canadian GAAP	$	244,278		$	18,111
Capitalized interest (a)		1,096			847
Depreciation of capitalized interest (a)		(143	)		—
Amortization using effective interest method (b)		1,836			590
Realized and unrealized loss on derivative financial instruments (e)		(136	)		(484	)
Excess of fair value of amended NAEPI Series B preferred shares over carrying value of original NAEPI Series B preferred shares (f)		—			(3,707	)
Deferred income taxes		(954	)		—
Shareholders’ equity—U.S. GAAP	$	245,977		$	15,357

A continuity schedule of each component of the Company’s shareholders’ equity under U.S. GAAP for the year ended March 31, 2007 is as follows:

	Common shares			Contributed surplus			Deficit			Total
April 1, 2004—U.S. GAAP	$	92,500		$	137		$	(12,282	)	$	80,355
Net loss		—			—			(42,323	)		(42,323	)
Stock based compensation (d)		—			497			—			497
Share issue		300			—			—			300
March 31, 2005	$	92,800		$	634		$	(54,605	)	$	38,829
Net loss		—			—			(20,988	)		(20,988	)
Stock based compensation (d)		—			923			—			923
Share issue		300			—			—			300
Excess of fair value of amended NAEPI Series B preferred shares over carrying value of original NAEPI Series B preferred shares (f)		—			—			(3,707	)		(3,707	)
March 31, 2006	$	93,100		$	1,557		$	(79,300	)	$	15,357
Net income		—			—			22,074			22,074
Stock based compensation		—			2,101			—			2,101
Issued upon exercise of stock options		139			—			—			139
Share issues		171,165			—			—			171,165
Share issue costs		(12,915	)		—			—			(12,915	)
Repurchase of common shares		(25	)		—			(59	)		(84	)
Conversion of NAEPI Series B preferred shares		48,140			—			—			48,140
Reclassification on exercise of stock options		52			(52	)		—			—
March 31, 2007—U.S. GAAP	$	299,656		$	3,606		$	(57,285	)	$	245,977

F-38

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

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

a) 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. Accordingly, the capitalized amount is subject to depreciation in accordance with the Company’s policies when the asset is placed into service.

b) Deferred charges

Under Canadian GAAP, the Company defers and amortizes debt issue 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”).

c) 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.

d) Stock-based compensation

Up until April 1, 2006, the Company followed the provisions of Statement of Financial Accounting Standards No. 123, “Stock-Based Compensation” for U.S. GAAP purposes. As the Company uses the fair value method of accounting for all stock-based compensation payments under Canadian GAAP there were no differences between Canadian and U.S. GAAP prior to April 1, 2006. On April 1, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment” (“SFAS 123R”). As the Company used the minimum value method for purposes of complying with Statement of Financial Accounting Standards No. 123, it was required to adopt SFAS 123(R) prospectively.

The methodology for determining the expense to be recognized in each period that is prescribed by SFAS 123(R) differs from that prescribed by Canadian GAAP. Canadian GAAP permits accounting for forfeitures of share-based payments as they occur while U.S. standards require an estimate of forfeitures to be made at the date of grant and thereafter until the requisite service period has been completed or the awards are cancelled. The required adjustment under U.S. GAAP to account for estimated forfeitures was not significant for all periods presented.

During the year ended March 31, 2007, the Company granted 315,520 stock options to employees and a director prior to the completion of the IPO. In determining the grant-date fair value of these stock options, the Company included an expected volatility of 40%. The additional compensation cost for these stock options under U.S. GAAP was not significant.

F-39

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

e) 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 8 ³/4% 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 issues 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.

f) NAEPI Series B Preferred Shares

Prior to the modification of the terms of the NAEPI Series B preferred shares, there were no differences between Canadian GAAP and U.S. GAAP related to the NAEPI Series B preferred shares. As a result of the modification of terms of NAEPI’s Series B preferred shares on March 30, 2006, under Canadian GAAP, the Company continued to classify the NAEPI Series B preferred shares as a liability and was accreting the carrying amount of $42.2 million on the amendment date (March 30, 2006) to their 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 amended NAEPI Series B preferred shares as minority interest as such amount was recognized as temporary equity in the accounts of NAEPI 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 amendment date. Under U.S. GAAP, the Company was accreting the initial fair value of the amended NAEPI Series B preferred shares of $45.9 million recorded on their amendment date (March 30, 2006) to the December 31, 2011 redemption value of $69.6 million using the effective interest method, which was consistent with the treatment of the NAEPI Series B preferred shares as temporary equity in the financial statements of NAEPI. The accretion charge was recognized as a charge to minority interest (as opposed to retained earnings in the accounts of NAEPI) under US GAAP and interest expense in the Company’s financial statements under Canadian GAAP.

On November 28, 2006, the Company exercised a call option to acquire all of the issued and outstanding NAEPI Series B preferred shares in exchange for 7,524,400 common shares of the Company. For Canadian GAAP purposes, the Company recorded the exchange by transferring the carrying value of the NAEPI Series B preferred shares on the exercise date of $44,682 to common shares. For U.S. GAAP purposes, the conversion has been accounted for as a combination of entities under common control as all of the shareholders of the NAEPI Series B preferred shares are also common shareholders of the Company resulting in the reclassification of the carrying value of the minority interest on the exercise date of $48,140 to common shares.

F-40

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

g) 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 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 19(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.

h) 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.

i) United States accounting pronouncements recently adopted

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. For the Company, the Statement was adopted as of January 1, 2004, except for certain mandatorily redeemable financial instruments. For certain mandatorily redeemable financial instruments, the Statement was adopted by the Company on January 1, 2005. The adoption of the standard required the Company to reclassify the carrying value of the NACG Preferred Corp. Series A preferred shares from minority interest to redeemable preferred shares. After the adoption of the standard, the Company issued other mandatorily redeemable preferred shares that were within the scope of the standard, which have been disclosed in note 17(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.

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 the Company’s financial statements.

F-41

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

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, being 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 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 the Company’s consolidated financial statements.

The impact of the adoption of SFAS 123(R) is described in note 27(d).

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 Opinion 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 was effective for the Company for accounting changes and corrections of errors made by the Company in its fiscal year beginning on April 1, 2006. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

In September 2006, the U.S. Securities and Exchange Commission issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. It establishes an approach that requires quantification of financial statements misstatements based on the effects of the misstatements on each of the Company’s financial statements and the related financial statement disclosures. SAB 108 was effective for the Company’s annual financial statements for the fiscal year ending March 31, 2007. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

j) Recent United States accounting pronouncements not yet adopted

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

F-42

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

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 2008 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 the Company’s 2008 fiscal year. The Company is currently reviewing the impact of this Interpretation.

In May 2007, the FASB issued FASB Staff Position No. FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48”, which provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. This FASB Staff Position is effective upon the initial adoption of FIN 48 and the Company is currently assessing the impact of this guidance.

Statement of Financial Accounting Standards No. 157, “Fair Value Measurement” (“SFAS 157”) was issued September 2006. The Statement provides guidance for using fair value to measure assets and liabilities. The Statement also expands disclosures about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurement on earnings. This Statement applies under other accounting pronouncements that require or permit fair value measurements. This Statement does not expand the use of fair value measurements in any new circumstances. Under this Statement, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. SFAS 157 is effective for the Company for fair value measurements and disclosures made by the Company in its fiscal year beginning on April 1, 2008. The Company is currently reviewing the impact of this statement.

Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”) was issued in February 2007. The statement permits entities to choose to measure many financial instruments and certain other items at fair value, providing the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without the need to apply hedge accounting provisions. SFAS 159 is effective for fiscal years beginning after November 15, 2007, specifically April 1, 2008 for the Company, with earlier adoption permitted. The Company is currently reviewing the impact of this pronouncement.

28. Subsequent events

a) On June 7, 2007, the Company modified its amended and restated credit agreement to provide for borrowings of up to $125 million (previously $55.0 million) under which revolving loans and letters of credit

F-43

NORTH AMERICAN ENERGY PARTNERS INC.

(formerly NACG Holdings Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the years ended March 31, 2007, 2006 and 2005

(Amounts in thousands of Canadian dollars, except per share amounts or unless otherwise specified)

may be issued. At the current credit rating, prime rate and swing line revolving loans under the agreement will bear interest at the Canadian prime rate plus 0.5% per annum. At the current credit rating, Canadian bankers’ acceptances have stamping fees equal to 2.0% per annum and letters of credit are subject to a fee of 1.5% per annum.

The credit facility is secured by a first priority lien on substantially all the Company’s existing and after-acquired property and 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 under the new credit agreement.

b) On June 13, 2007, the Company secured financing of $22.3 million for a new piece of heavy equipment. Progress draws under the agreement commenced on June 13, 2007 and the 7.5 year operating lease will be fully funded when the equipment is commissioned, which is expected to be December 31, 2007. During the progress funding period, interest will accrue at the Canadian prime rate plus 1.25% per annum and will be capitalized into the lease. Once fully funded, the Company will choose between a fixed rate (determined as the June 2015 Government of Canada Bond rate plus 3.0% per annum) and a variable rate, being the one-month Canadian bankers’ acceptance rate plus 2.85% per annum.

F-44

Schedule I

SCHEDULE OF VALUATION AND QUALIFYING ACCOUNTS

(In thousands of Canadian dollars)

Allowance for doubtful accounts receivable

	Balance, Beginning of Period	Charged to Costs and Expense (1)	Deductions (2)		Balance, End of Period
April 1, 2004 to March 31, 2005	233,000	40,376	(109,789	)	163,587
April 1, 2005 to March 31, 2006	163,587	93,830	(187,661	)	69,756
April 1, 2006 to March 31, 2007	69,756	18,105	—		87,861

(1) Represents increase (decrease) in allowance for doubtful accounts receivable charged to expense.

(2) Represents the accounts receivable written-off against the allowance for doubtful accounts receivable.

Future income tax asset valuation allowance

	Balance, Beginning of Period	Charged to Costs and Expense (1)		Deductions	Balance, End of Period
April 1, 2004 to March 31, 2005	—	9,955,000		—	9,955,000
April 1, 2005 to March 31, 2006	9,955,000	(4,097,000	)	—	5,858,000
April 1, 2006 to March 31, 2007	5,858,000	(5,858,000	)	—	—

(1) Represents increase (decrease) in valuation allowance charged to provision for future income taxes.

S-1