UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K/A2

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16

under the Securities Exchange Act of 1934

For the month of November 2005

Commission File Number 333-111396

NORTH AMERICAN ENERGY PARTNERS INC.

Zone 3 Acheson Industrial Area

2-53016 Highway 60

Acheson, Alberta

Canada T7X 5A7

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F x    Form 40-F ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨

Indicate by check mark whether by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes ¨    No x

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):                     .

EXPLANATORY NOTE

First Restatement

Beginning in January 2005, North American Energy Partners Inc. (the “Company” or “we”) conducted a review of its financial statements for the fiscal quarters ended June 30, 2004 and September 30, 2004 and a related review of its system of internal controls. As a result of this review, the Company restated its financial statements for the quarters ended June 30, 2004 and September 30, 2004 (the “first restatement”).

The Company filed a Form 6-K/A for the quarter ended June 30, 2004 on April 15, 2005 to reflect the following adjustments related to the first restatement: (1) corrections to accounts payable, project costs, equipment costs and general and administrative expenses in respect to accounts payable invoices which were not previously reflected in the June 30, 2004 quarter and which were not then adequately accrued; (2) additional revenue which is associated with the additional project costs relating to time-and-material and cost-plus projects; (3) reduction in revenue in respect to data which was incorrectly processed through our billing system; (4) an increase in capital assets resulting from certain equipment costs that were expensed in the June 30, 2004 quarter but should have been capitalized; (5) a reduction in the management bonus accrual due to the lower financial results being below the minimum threshold target; (6) the related impact to future income taxes in respect to the above adjustment; and (7) an increase in revenue, project costs, accounts receivable, unbilled revenue, inventory, accounts payable and accrued liabilities due to an increase in the Company’s proportionate share of an investment in a joint venture.

Second Restatement

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

The Company is filing this amended Quarterly Report on Form 6-K/A2 for the quarter ended June 30, 2004 to reflect the second restatement. Please see Note 3 to the Interim Consolidated Financial Statements and the “Restatement” section included in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations (Restated), for a detailed discussion of the restatement.

Other than the changes relating to the restatements, the financial statements and related footnotes and the Management’s Discussion and Analysis of Financial Condition and Results of Operations (Restated) included in this Form 6-K/A2 do not reflect events occurring after the original filing date of the Form 6-K on August 28, 2004.

Included herein:

1. Interim consolidated financial statements of North American Energy Partners Inc. for the three months ended June 30, 2004 (Restated).

2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Restated).

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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

Date: November 29, 2005

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Balance Sheets

(in thousands of Canadian dollars)

	June 30, 2004			March 31, 2004
	(unaudited) Restated (note 3)			Restated (note 3)
Assets
Current assets:
Cash and cash equivalents	$	19,339		$	36,595
Accounts receivable (note 11(a))		36,203			33,647
Unbilled revenue		12,561			27,676
Inventory		1,195			1,609
Prepaid expenses		1,205			1,272
		70,503			100,799
Capital assets (note 5)		175,366			167,905
Goodwill (note 4)		198,549			198,549
Intangible assets, net of accumulated amortization of $14,358 (notes 4 and 6)		3,440			4,870
Deferred financing costs, net of accumulated amortization of $1,439 (note 4)		16,821			17,266
Future income taxes		—			285
		$464,679		$	489,674
Liabilities and Shareholder’s Equity
Current liabilities:
Accounts payable	$	22,614		$	29,301
Accrued liabilities		4,794			14,694
Current portion of term credit facility (note 7)		8,500			7,250
Current portion of capital lease obligations (note 8)		823			787
Term credit facility scheduled repayments due beyond one year (note 7)		38,500			—
Future income taxes		—			5,260
		75,231			57,292
Term credit facility (note 7)		—			41,250
Capital lease obligations (note 8)		2,650			2,251
Senior notes (note 9)		266,760			262,260
Derivative financial instruments (note 14(c))		8,080			11,266
Future income taxes		1,575			—
Shareholder’s equity:
Share capital (note 10)		127,500			127,500
Contributed surplus (note 17)		249			137
Deficit		(17,366	)		(12,282	)
		110,383			115,355
Commitments (note 15)
Subsequent event (note 7(c))
United States generally accepted accounting principles (restated) (note 19)
	$	464,679		$	489,674

See accompanying notes to interim consolidated financial statements.

1

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Statements of Operations and Retained Earnings (Deficit)

(in thousands of Canadian dollars)

(unaudited)

	For the three months ended June 30, 2004			Predecessor Company for the three months ended June 30, 2003
	Restated (note 3)
Revenue	$	70,860		$	93,730
Project costs		46,038			56,393
Equipment costs		12,202			21,996
Depreciation		4,519			2,562
		62,759			80,951
Gross profit		8,101			12,779
General and administrative		5,040			3,040
Gain on disposal of capital assets		(6	)		(70	)
Amortization of intangible assets		1,430			—
Operating income		1,637			9,809
Management fees (note 13(c))		—			9,000
Interest expense (note 11(b))		7,331			947
Foreign exchange (gain) loss (note 14(c))		4,654			(8	)
Other income		(146	)		(197	)
Realized and unrealized (gain) loss on derivative financial instruments		(2,531	)		—
		9,308			9,742
Income (loss) before income taxes		(7,671	)		67
Income taxes:
Current income taxes		813			118
Future income taxes		(3,400	)		25
		(2,587	)		143
Net loss		(5,084	)		(76	)
Retained earnings (deficit), beginning of period		(12,282	)		29,817
Retained earnings (deficit), end of period	$	(17,366	)	$	29,741

See accompanying notes to interim consolidated financial statements.

2

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Statements of Cash Flows

(in thousands of Canadian dollars)

(unaudited)

	For the three months ended June 30, 2004			Predecessor Company for the three months ended June 30, 2003
	Restated (note 3)
Cash provided by (used in):
Operating activities:
Net loss	$	(5,084	)	$	(76	)
Items not affecting cash:
Depreciation		4,519			2,562
Amortization of intangible assets		1,430			—
Amortization of deferred financing costs		625			—
Gain on disposal of capital assets		(6	)		(70	)
Increase (decrease) in allowance for doubtful accounts		(133	)		17
Unrealized foreign exchange loss on senior notes		4,500			—
Unrealized change in fair value of derivative financial instruments		(3,186	)		—
Stock-based compensation expense (note 17)		112			—
Future income taxes		(3,400	)		25
Net changes in non-cash working capital (note 11(d))		(3,414	)		9,530
		(4,037	)		11,988
Investing activities:
Purchase of capital assets		(11,369	)		(1,564	)
Proceeds on disposal of capital assets		104			256
		(11,265	)		(1,308	)
Financing activities:
Repayment of term credit facility		(1,500	)		(1,675	)
Repayment of capital lease obligations		(274	)		(1,278	)
Financing costs		(180	)		—
Decrease in operating line of credit		—			(516	)
Decrease in cheques issued in excess of cash deposits		—			(2,496	)
Advances from Norama Inc.		—			3,557
		(1,954	)		(2,408	)
Increase (decrease) in cash and cash equivalents		(17,256	)		8,272
Cash and cash equivalents, beginning of period		36,595			—
Cash and cash equivalents, end of period	$	19,339		$	8,272

See accompanying notes to interim consolidated financial statements.

3

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

1. Nature of operations

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

2. Significant accounting policies

a) Basis of presentation:

These interim consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles (“GAAP”) requirements for annual financial statements. These interim consolidated financial statements should be read in conjunction with the Company’s most recent annual consolidated financial statements as at and for the year ended March 31, 2004. Material inter-company transactions and balances are eliminated on consolidation. Material items that could give rise to measurement differences to these consolidated financial statements under United States GAAP are outlined in note 19.

These consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, NACG Finance LLC and North American Construction Group Inc. (“NACGI”), the Company’s proportionate share of the assets, liabilities, revenues, expenses and cash flows of its joint venture (note 11(e)), and the following subsidiaries:

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

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

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

4

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

b) Use of estimates:

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

c) Revenue recognition:

The Company performs the majority of its projects under the following types of contracts: time-and-materials; cost plus; unit-price; and fixed-price or lump-sum. For time-and-materials and cost plus type contracts, revenue is recognized as costs are incurred. Revenue from unit-price contracts is recognized based on quantities of units performed and delivered. Revenue on lump-sum contracts is recognized on the percentage-of-completion method, measured by the ratio of costs incurred to date to estimated total costs.

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

The asset entitled “unbilled revenue” represents revenue recognized in advance of amounts invoiced.

d) Cash and cash equivalents:

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

e) Allowance for doubtful accounts:

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

f) Inventory:

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

5

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

g) Capital assets:

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

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

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

h) Goodwill:

Goodwill represents the excess purchase price paid by the Company over the fair value of the tangible and identifiable intangible assets and liabilities acquired. Goodwill is not amortized but instead is tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. The impairment test is carried out in two steps. In the first step, the carrying amount of the reporting unit, including goodwill, is compared with its fair value. When the fair value of the reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to be impaired and the second step of the impairment test is unnecessary. The second step is carried out when the carrying amount of a reporting unit exceeds its fair value, in which case, the implied fair value of the reporting unit’s goodwill, determined in the same manner as the value of goodwill is determined in a business combination, is compared with its carrying amount to measure the amount of the impairment loss, if any. As of June 30, 2004, no impairment of goodwill has occurred.

i) Intangible assets:

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

6

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

j) Deferred financing costs:

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

k) Impairment of long-lived assets:

The Company recognizes an impairment loss for a long-lived asset to be held and used when changes in circumstances cause its carrying value to exceed the total undiscounted cash flows expected from its use. An impairment loss, if any, is determined as the excess of the carrying value of the asset over its fair value.

l) Foreign currency translation:

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

m) Derivative financial instruments:

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

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

7

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

n) Income taxes:

The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, future tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Future tax assets and liabilities are measured using enacted or substantively enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on future tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date of enactment or substantive enactment.

o) Stock–based compensation plan:

The Company records all stock-based compensation payments at fair value. Compensation cost is measured at the fair value, determined using the Black-Scholes method, at the grant date and is expensed over the award’s expected life.

p) Recently adopted Canadian accounting pronouncements:

i) Hedging relationships:

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

ii) Generally accepted accounting principles:

Effective November 26, 2003, the Company adopted CICA Handbook Section 1100, “Generally Accepted Accounting Principles,” which establishes standards for financial reporting in accordance with Canadian GAAP, and describes what constitutes Canadian GAAP and its sources. This section also provides guidance on sources to consult when selecting accounting policies and determining appropriate disclosures when the primary sources of Canadian GAAP are silent. There have been no changes in accounting policies as a result of the adoption of this standard.

iii) Revenue recognition:

Effective January 1, 2004, the Company prospectively adopted the new Canadian accounting standard EIC-141, “Revenue Recognition,” which incorporates the principles and guidance under U.S. GAAP for revenue recognition. No changes to the recognition or classification of revenue were made as a result of the adoption of this standard.

q) Recent Canadian accounting pronouncements not yet adopted:

Consolidation of variable interest entities:

In June 2003, the CICA issued Accounting Guideline 15 “Consolidation of Variable Interest Entities” (“VIEs”) (AcG-15”). VIE’s are entities that have insufficient equity at risk to finance their operations

8

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

without additional subordinated financial support and/or entities whose equity investors lack one or more of the specified essential characteristics of a controlling financial interest. AcG-15 provides specific guidance for determining when an entity is a VIE and who, if anyone, should consolidate the VIE. The standard will be effective on a prospective basis for the Company’s interim period beginning January 1, 2005. The adoption of this standard is not expected to have a material impact on the consolidated financial statements.

3. Restatement

First Restatement

In preparing the financial statements for the three and nine-month periods ended December 31, 2004, the Company determined that its previously issued interim unaudited consolidated financial statements for the three months ended June 30, 2004 and the three and six months ended September 30, 2004 contained cost and revenue cut-off errors and as a result, those financial statements required restatement.

9

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

The interim consolidated financial statements for the three months ended June 30, 2004 reflect the following adjustments related to the first restatement:

a) Cost cut-off:

Project costs, equipment costs, general and administrative expenses and capital assets were increased by $4,742 as a result of supplier invoices which were not previously recorded in accounts payable and were not appropriately accrued and reported in the financial statements for the three months ended June 30, 2004.

b) Revenue:

Revenue has been increased by $1,397 where it is associated with project costs described in (a) above in respect to certain time-and-materials and cost-plus contracts. In addition, revenue has been decreased by $763 in respect to data incorrectly processed through the Company’s billing system. A further restatement adjustment to revenue is described below in

(f).

c) Component capitalization:

The Company’s capital asset policy (see note 2 (g)) states that major components of heavy construction equipment such as engines, transmissions and undercarriages are recorded separately as individual capital assets and depreciated over their respective useful lives. In performing its review, management identified certain equipment costs totalling $360 related to the replacement of heavy construction equipment component parts which were expensed and should have otherwise been capitalized in accordance with our capitalization policy.

d) Bonus accrual:

As a result of the increased costs in this period, the financial results are below the minimum threshold under the Company’s Management Incentive Plan, and accordingly the previously accrued management bonus of $100 has been reversed.

10

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

e) Income taxes:

None of the above adjustments had any impact on current income taxes but they all had an impact on the provision for future income taxes in respect to the temporary differences in capital assets and non-capital tax losses carry forward balance.

f) Joint venture:

Due to an increase in the Company’s proportionate share of an investment in a joint venture from 50% to 70%, revenue has been increased by $205 and project costs have increased by $870. This also resulted in an increase in the Company’s proportionate share of accounts receivables, unbilled revenue, inventory, accounts payable and accrued liabilities as at June 30, 2004.

g) Reclassifications:

In connection with the restatement, the Company reclassified the term credit facility scheduled repayments due beyond one year to current as discussed in note 7.

Certain amounts were also reclassified in connection with the restatement of the interim consolidated financial statements for the three-month period ended June 30, 2004 in order to conform with current reclassification of the related amounts in the interim consolidated financial statements for the nine-month period ended December 31, 2004.

Second Restatement

In preparing the financial statements for the fiscal year ended March 31, 2005, the Company reviewed the accounting treatment of the Company’s derivative instruments (described in note 14(c)) and concluded that there were technical deficiencies in the hedge documentation relating to the cross-currency swap and interest rate swap contracts used to manage its foreign exchange risk exposure related to the U.S. $ denominated 8 ¾ % senior notes since the inception on November 26, 2003, which deficiencies could not be corrected retroactively. Complete and accurate documentation is required to support the effectiveness of the hedge and the use of hedge accounting under the Canadian Institute of Chartered Accountants Accounting Guideline 13, “Hedging Relationships.”

As a result of the deficiencies in the hedge documentation, the Company determined that it was necessary to restate all reported periods after November 26, 2003 to eliminate the impact of hedge accounting. This was accomplished by recognizing the foreign exchange gain or loss relating to the senior notes each period and recording the derivative financial instruments at fair value and the realized and unrealized gains and losses on the derivative financial instruments through the Consolidated Statement of Operations, along with the associated future income tax effects.

The Company did not violate any covenants under the Credit Agreement (note 7) as a result of the second restatement. Furthermore the Company repaid its entire indebtedness under the senior secured credit facility on May 19, 2005.

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

For the three months ended June 30, 2004	As previously reported			First restatement			As restated			Second restatement			As restated
Revenue	$	70,021		$	839		$	70,860		$	—		$	70,860
Project costs		42,421			3,617			46,038			—			46,038
Equipment costs		10,881			1,321			12,202			—			12,202
Gross profit		12,200			(4,099	)		8,101			—			8,101
General and administrative		4,882			158			5,040			—			5,040
Operating income		5,894			(4,257	)		1,637			—			1,637
Interest expense		7,986			—			7,986			(655	)		7,331
Foreign exchange loss		154			—			154			4,500			4,654
Realized and unrealized (gains) losses on derivative financial instruments		—			—			—			(2,531	)		(2,531	)
Loss before income taxes		(2,100	)		(4,257	)		(6,357	)		(1,314	)		(7,671	)
Future income taxes		(1,815	)		(1,285	)		(3,100	)		(300	)		(3,400	)
Net loss	$	(1,098	)	$	(2,972	)	$	(4,070	)	$	(1,014	)	$	(5,084	)

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

As at June 30, 2004	As previously reported			First  restatement			As restated			Second  restatement			As restated
Accounts receivable	$	36,466		$	(263	)	$	36,203		$	—		$	36,203
Unbilled revenue		11,515			1,046			12,561			—			12,561
Inventory		1,160			35			1,195			—			1,195
Capital assets		175,304			62			175,366			—			175,366
Derivative financial instruments		3,760			—			3,760			(3,760	)		—
Accounts payable		15,295			7,319			22,614			—			22,614
Accrued liabilities		6,976			(2,182	)		4,794			—			4,794
Future income taxes		1,170			(1,170	)		—			—			—
Derivative financial instruments		—			—			—			8,080			8,080
Future income taxes		4,790			(115	)		4,675			(3,100	)		1,575
Deficit	$	(5,654	)	$	(2,972	)	$	(8,626	)	$	(8,740	)	$	(17,366	)

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

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

For the three months ended June 30, 2004	As previously reported			First restatement			As restated			Second restatement			As restated
Net loss	$	(1,098	)	$	(2,972	)	$	(4,070	)	$	(1,014	)	$	(5,084	)
Future income taxes		(1,815	)		(1,285	)		(3,100	)		(300	)		(3,400	)
Foreign exchange gain on senior notes		—			—			—			4,500			4,500
Unrealized change in fair value of derivative financial instruments		—			—			—			(3,186	)		(3,186	)
Net changes in non-cash working capital		(7,733	)		4,319			(3,414	)		—			(3,414	)
Purchase of capital assets	$	(11,307	)	$	(62	)	$	(11,369	)	$	—		$	(11,369	)

The impact of the restatements on the Segmented Reporting is as follows:

For the three months ended June 30, 2004	Mining & Site Preparation			Piling			Pipeline			Total
Revenue, as previously reported	$	46,410		$	12,713		$	10,898		$	70,021
First restatement		354			544			(59	)		839
Revenue, as restated		46,764			13,257			10,839			70,860
Second restatement		—			—			—			—
Revenue, as restated	$	46,764		$	13,257		$	10,839		$	70,860
For the three months ended June 30, 2004	Mining & Site Preparation			Piling			Pipeline			Total
Segment profits, as previously reported	$	5,751		$	3,198		$	1,830		$	10,779
First restatement		(2,260	)		(219	)		(192	)		(2,671	)
Segment profits, as restated		3,491			2,979			1,638			8,108
Second restatement		—			—			—			—
Segment profits, as restated	$	3,491		$	2,979		$	1,638		$	8,108

4. Acquisition

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

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

11

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

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

Current assets, including cash of $19,642	$	83,910
Capital assets, including capital leases of $2,131		176,779
Intangible assets		17,798
Goodwill		198,549
Total assets acquired		477,036
Current liabilities		(40,662	)
Future income taxes		(11,823	)
Capital lease obligations		(2,131	)
Total liabilities assumed		(54,616	)
Net assets acquired	$	422,420
The acquisition was financed as follows:
Proceeds from issuance of senior notes	$	263,000
Proceeds from issuance of share capital		127,500
Proceeds from initial borrowing under the new:
Term credit facility		50,000
Revolving credit facility		—
Less: deferred financing costs		(18,080	)
		$422,420
The net cash cost of the acquisition is:
Net assets acquired	$	422,420
Less: non-cash portion of share capital		(35,000	)
Less: cash acquired from acquisition and financing		(19,642	)
		$367,778

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

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

Transaction costs of $25.1 million were incurred on the acquisition, $7.0 million of which have been accounted for as increased goodwill and $18.2 million of which have been recorded as deferred financing costs. The deferred financing costs were subject to amortization of $625 during the three months ended June 30, 2004 (three months ended June 30, 2003 - $nil).

12

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

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

5. Capital assets

June 30, 2004	Cost		Accumulated depreciation		Net book value
	Restated (note 3)				Restated (note 3)
Heavy equipment	$	159,417	$	7,561	$	151,856
Major component parts in use		3,248		369		2,879
Spare component parts		395		—		395
Other equipment		10,532		1,075		9,457
Licensed motor vehicles		11,335		1,803		9,532
Office and computer equipment		1,611		364		1,247
	$	186,538	$	11,172	$	175,366
March 31, 2004	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	149,704	$	4,444	$	145,260
Major component parts in use		2,260		374		1,886
Spare component parts		395		—		395
Other equipment		10,160		605		9,555
Licensed motor vehicles		10,561		1,049		9,512
Office and computer equipment		1,491		194		1,297
	$	174,571	$	6,666	$	167,905

The above amounts include $4,029 (March 31, 2004 – $3,228) of assets under capital lease and accumulated depreciation of $587 (March 31, 2004 – $320) related thereto. During the three months ended June 30, 2004, capital asset additions included $709 of assets that were acquired by means of capital leases (three months ended June 30, 2003 – $nil). Depreciation of equipment under capital leases of $267 (three months ended June 30, 2003 – $300) is included in depreciation expense. As at June 30, 2004, capital assets reflect the effects of applying push down accounting due to the acquisition described in note 4.

13

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

6. Intangible assets

At June 30, 2004, identifiable intangible assets purchased in the acquisition described in note 4 consisted of the following:

Identifiable intangible assets	Cost		Accumulated amortization		Net book value
Customer contracts in progress and related relationships	$	15,323	$	13,931	$	1,392
Trade names		350		21		329
Non-competition agreement		100		12		88
Employee arrangements		2,025		394		1,631
Balance, June 30, 2004	$	17,798	$	14,358	$	3,440

7. Term credit facility

a) General terms:

The Company refers to the revolving credit facility and the term loan collectively as the “senior secured credit facility.” The Credit Agreement dated November 26, 2003 related to the senior secured credit facility (the “Credit Agreement”) imposes certain restrictions on the Company, including restrictions on the Company’s ability to incur indebtedness, pay dividends, make investments, grant liens, sell assets and engage in certain other activities. In addition, the Credit Agreement requires the Company to maintain certain financial ratios (“covenants”) including: achieving certain levels of earnings before interest, taxes, depreciation and amortization (“EBITDA”); maintaining interest and fixed-charge coverage ratios above a specified minimum level; limiting capital expenditures to specified amounts; and maintaining leverage ratios below a specified maximum level. The indebtedness under the senior secured credit facility, including the contingent liability under the Company’s foreign currency hedging agreement, is secured by substantially all of the Company’s assets and those of its subsidiaries, including accounts receivable and capital assets. As of June 30, 2004, the Company did not have any outstanding borrowings under the revolving credit facility and had issued $10.0 million in letters of credit to support bonding requirements associated with customer contracts. There was $47.0 million outstanding under the term loan portion of the senior secured credit facility at June 30, 2004.

b) Current classification:

Even though the Company was in compliance with all of its financial covenants at June 30, 2004, the Company reclassified the term credit facility scheduled repayments due beyond one year to current, as required by accounting standards under Emerging Issues Committee Abstract EIC-59, “Long-term Debt with Covenant Violations”. Under this accounting standard, in circumstances where at the balance sheet date, the debtor would have been in violation of one or more financial covenants giving the creditor the right to demand repayment absent the modification of financial covenants and, it is likely that the debtor will violate one or more of its financial covenants within one year of the balance sheet, then the debtor must classify its non-current debt as current.

c) Subsequent event:

The Company has obtained a series of waivers from the lenders, waiving its non-compliance with certain financial covenants for several quarterly periods of fiscal 2005, its failure to deliver financial statements for the periods ended December 31, 2004, January 31, 2005 and February 28, 2005 by specified dates, and any default that would arise under the Credit Agreement as a result of being out of compliance with the corresponding covenants in the indenture governing the Company’s 8¾% senior notes requiring delivery of its December 31, 2004 financial statements by March 1, 2005. The most recent waivers expire on the earlier of April 15, 2005 or the date the lack of compliance becomes an event of default under the indenture.

In connection with the first waiver, which was obtained on January 14, 2005, the lenders allowed the Company to increase its borrowings under the revolving credit facility to $20 million and increase the amount of outstanding letters of credit issued to $20 million. The lending banks have not provided any additional funding since that date. The revolving credit facility would otherwise provide the Company with borrowing capacity up to $70 million in total, subject to borrowing base limitations. In addition, during the waiver period, the Company was obligated to update various information regarding its assets, provide more

14

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

current financial information regarding its operations than currently required by the Credit Agreement and cooperate with a third party engaged by the banks to evaluate the Company’s accounting and control procedures surrounding the causes for the restatement of its financial statements for the quarters ended June 30, 2004 and September 30, 2004 and to review the Company’s current customer contacts.

In the event that the Company fails to obtain additional waivers or an amendment of the Credit Agreement by April 15, 2005, its lenders would be in a position to demand immediate repayment on the Company’s senior secured credit facility. Management is currently exploring alternatives to resolve the matters including seeking alternative financing sources. However, the Company cannot provide any assurances that a modification of the Credit Agreement or new financing agreement will be consummated or that the Company will have access to such capital when required to fund its future operations.

8. Capital lease obligations

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

	June 30, 2004
2005	$	986
2006		970
2007		1,080
2008		738
2009		45
		3,819
Less: amount representing interest – average rate of 4.95%		346
Present value of minimum capital lease payments		3,473
Less: current portion		823
	$	2,650

9. Senior notes

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

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

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

15

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

10. Share capital

Authorized:

Unlimited number of common voting shares.

Issued:

	Number of Shares	Amount
Outstanding at March 31, 2004	100	$	127,500
Issued	—		—
Redeemed	—		—
Outstanding at June 30, 2004	100	$	127,500

11. Other information

a) Accounts receivable:

	June 30, 2004			March 31, 2004
	Restated (note 3)
Accounts receivable – trade	$	32,954		$	29,991
Accounts receivable – holdbacks		3,347			3,838
Accounts receivable – other		2			51
Allowance for doubtful accounts		(100	)		(233	)
	$	36,203		$	33,647

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

At June 30, 2004, the following customers represented 10% or more of accounts receivable and unbilled revenue:

	June 30, 2004	March 31, 2004
	Restated (note 3)
Customer A	37.6%	28.7%
Customer B	6.6%	43.6%

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

16

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

b) Interest expense:

For the three months ended June 30,	2004		Predecessor Company 2003
Interest on senior notes	$	5,698	$	—
Interest on senior secured credit facility		692		189
Interest on capital lease obligations		39		173
Interest on advances from Norama Inc.		—		534
Interest on long-term debt		6,429		896
Amortization of deferred financing costs		625		—
Other interest(1)		277		51
	$	7,331	$	947

⁽¹⁾ Included in Other interest is $254 for amendment fees paid in respect of the senior secured credit facility.

c) Supplemental cash flow information:

For the three months ended June 30,	2004		Predecessor Company 2003
Cash paid during the period for:
Interest	$	14,906	$	925
Income taxes		1,731		215
Cash received during the period for:
Interest		196		34
Income taxes		—		—
Non-cash transactions:
Capital leases		709		—

17

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

d) Net change in non-cash working capital:

For the three months ended June 30,	2004			Predecessor Company 2003
	Restated (note 3)
Accounts receivable	$	(2,423	)	$	(1,925	)
Unbilled revenue		15,115			23,715
Inventory		414			—
Prepaid expenses		67			(903	)
Accounts payable		(6,687	)		(9,627	)
Accrued liabilities		(9,900	)		(1,730	)
	$	(3,414	)	$	9,530

e) Investment in joint venture

The Company participates in an incorporated joint venture. The consolidated financial statements include the Company’s proportionate share of the assets, liabilities, revenues, expenses, net loss and cash flows of the joint venture, as set out in the following tables:

	June 30, 2004
	Restated (note 3)
Assets
Cash	$	5
Accounts receivable		586
Unbilled revenue		165
Inventory		123
	$	879
Liabilities
Accounts payable	$	860
Accrued liabilities		16
Venturer’s equity		3
	$	879

	For the three months ended June 30, 2004			Predecessor Company For the three months ended June 30, 2003
	Restated (note 3)
Revenue	$	716		$	—
Project costs		1,666			—
Net loss	$	(950	)	$	—

18

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

	For the three months ended June 30, 2004			Predecessor Company For the three months ended June 30, 2003
	Restated (note 3)
Cash used in:
Operating activities	$	(945	)	$	—
Investing activities		—			—
Financing activities		948			—
	$	3		$	—

The Company was contingently liable at June 30, 2004 for obligations of its incorporated joint venture totaling $375 (March 31, 2004 - $6), representing the other venturer’s proportionate share of the joint venture’s liabilities. The assets of the joint venture are available for the purpose of satisfying such obligations.

The Company enters into transactions in the normal course of operations with its joint venture. These transactions are measured at the exchange amount, being the amount of consideration established and agreed to by the parties involved. During the three month period ended June 30, 2004, the Company provided $713 of labour, equipment and other services to the joint venture (three months ended June 30, 2003 - $nil). Additionally the Company recovered costs of $71 (three months ended June 30, 2003 - $nil) from the joint venture in the current period.

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

12. Segmented information

a) General overview:

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

• Mining and Site Preparation:

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

• Piling:

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

• Pipeline:

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

19

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

b) Results by business segment:

For the three months ended June 30, 2004	Mining & Site Preparation		Piling		Pipeline		Total
Restated (note 3)
Revenues from external customers	$	46,764	$	13,257	$	10,839	$	70,860
Depreciation of capital assets		2,207		610		55		2,872
Segment profits		3,491		2,979		1,638		8,108
Segment assets		285,430		77,951		44,588		407,969
Expenditures for segment capital assets		10,643		58		—		10,701
Predecessor Company For the three months ended June 30, 2003	Mining & Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	69,755	$	15,267	$	8,708	$	93,730
Depreciation of capital assets		1,520		500		27		2,047
Segment profits		7,217		3,633		1,066		11,916
Segment assets		82,895		34,701		6,067		123,663
Expenditures for segment capital assets		294		—		—		294

c) Reconciliations:

(i) Income (loss) before income taxes:

For the three months ended June 30,	2004			Predecessor Company 2003
	Restated (note 3)
Total profit for reportable segments	$	8,108		$	11,916
Unallocated corporate expenses		(15,696	)		(12,783	)
Unallocated equipment revenue (costs)		(83	)		934
Income (loss) before income taxes	$	(7,671	)	$	67

(ii) Total assets:

	June 30, 2004		March 31, 2004
	Restated (note 3)		Restated (note 3)
Total assets for reportable segments	$	407,969	$	410,469
Corporate assets		56,710		79,205
Total assets	$	464,679	$	489,674

20

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

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

d) Customers:

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

For the three months ended June 30,	2004		Predecessor Company 2003
	Restated (note 3)
Customer A	44.3	%	67.1	%
Customer B	15.2	%	9.3	%

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

13. Related party transactions

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

a) Transactions with Sponsors:

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

b) Office rent:

Pursuant to several office lease agreements, for the three months ended June 30, 2004 the Company paid $166 (three months ended June 30, 2003 – $162) to a company owned, indirectly and in part, by one of the Directors. The office lease agreements were in effect prior to the acquisition described in note 4.

c) Predecessor company transactions:

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

21

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

14. Financial instruments

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

a) Fair value:

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

The fair value of the term credit facility, senior notes and capital lease obligations (collectively “the debt”) are based on management estimates which are determined by discounting cash flows required under the debt at the interest rate currently estimated to be available for loans with similar terms. Based on these estimates, the fair value of the Company’s debt as at June 30, 2004 is not significantly different than its carrying value.

b) Interest rate risk:

The Company is subject to interest rate risk on the senior secured credit facility and capital lease obligations. At June 30, 2004, for each 1% annual fluctuation in the interest rate, the annual cost of financing will change by approximately $454.

The Company also leases equipment (as described in note 15) with a variable lease payment component that is tied to prime rates. At June 30, 2004, for each 1% annual fluctuation in these rates, annual lease expense will change by approximately $83.

c) Foreign currency risk and derivative financial instruments:

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

The carrying amount and fair value of the Company’s derivative financial instruments as at June 30, 2004 are as follows:

	Carrying Amount			Fair Value
	Restated (note 3)
Cross-currency and interest rate swaps	$	(8,080	)	$	(8,080	)

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

At June 30, 2004, the notional principal amount of the cross-currency swap was US$200 million. The notional principal amounts of the interest rate swaps were US$200 million and Cdn$263 million.

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

22

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

d) Operating leases:

The Company is subject to foreign currency risk on U.S. dollar operating lease commitments as the Company has not entered into a cross currency swap agreement to hedge this foreign currency exposure.

15. Commitments

The future minimum lease payments in respect of operating leases amount to approximately $7,669. Annual payments in the next five years are:

Year ended June 30,
2005	$	3,412
2006		2,202
2007		1,750
2008		304
2009		1
	$	7,669

16. Employee contribution plans

The Company and its subsidiaries match voluntary contributions made by the employees to their Registered Retirement Savings Plans to a maximum of 3% of base salary for each employee. Contributions made by the Company during the three months ended June 30, 2004 were $50 (three months ended June 30, 2003 – $45).

17. Stock-based compensation plan

Under the 2004 Share Option Plan, Directors, Officers, employees and service providers to the Company are eligible to receive stock options to acquire common shares in NACG Holdings Inc. The stock options expire in ten years or on termination of employment. Options may be exercised at a price determined at the time the option is awarded, and vest as follows: no options vest on the award date and twenty per cent vest on each of the five following award date anniversaries. The maximum number of common shares issuable under this plan may not exceed 92,500, of which 33,758 are still available for issue as at June 30, 2004. As at June 30, 2004, none of these stock options were exercisable. No stock options were granted by the Predecessor Company.

23

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

The fair value of each option granted by NACG Holdings Inc. was estimated using the Black-Scholes option-pricing model assuming: a dividend yield of nil%; a risk-free interest rate of 4.66%; volatility of nil%; and an expected option life of 10 years.

The stock options outstanding at June 30, 2004 are as follows:

	Number of options	Weighted average exercise price $ per share
Outstanding at March 31, 2004	54,130	$	100.00
Granted	4,612		100.00
Exercised	—
Forfeited	—
Outstanding at June 30, 2004	58,742	$	100.00

The Company recorded $112 of compensation expense related to the stock options during the three months ended June 30, 2004 (three months ended June 30, 2003 – $nil) with such amount being credited to contributed surplus.

18. Comparative figures

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

24

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

19. United States generally accepted accounting principles (Restated)

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

Restatement related to derivative financial instruments and hedging activities:

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

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

Reporting comprehensive income:

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

Investment in joint venture:

Under Canadian GAAP, investments in joint ventures are accounted for using the proportionate consolidation method. 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 (“SEC”) 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 arrangement, jointly controlled by all parties having an equity interest in the joint venture. In addition, the Company disclosed in note 11(e) the major components of its financial statements resulting from the use of the proportionate consolidation method to account for its interests in joint ventures.

Recent United States accounting pronouncements:

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

25

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2004

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

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

26

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three months ended June 30, 2004

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS (RESTATED)

The following discussion should be read in conjunction with the attached unaudited interim financial statements and the notes thereto and our audited consolidated financial statements and Management’s Discussion and Analysis for the fiscal year ended March 31, 2004. This document contains forward-looking statements. Such forward-looking statements involve known and unknown risks, uncertainties, and other factors that may cause future actions, conditions, or events to differ materially from the anticipated actions, conditions or events expressed or implied by such forward-looking statements. Forward-looking statements are those that do not relate strictly to historical or current fact, 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,” “believes,” “continue,” “strategy,” “position,” or the negative of those terms or other variations of them or comparable terminology. Forward-looking statements included in this document include statements regarding: financial resources; capital spending; the outlook for our business; and our results generally. Factors that could cause actual results to vary from those in the forward-looking statements include: changes in oil and gas prices; decreases in outsourcing work by our customers; shut-downs or cutbacks at major businesses that use our services; changes in laws or regulations, third party relations and approvals, and decisions of courts, regulators and governmental bodies that may adversely affect our business or the business of the customers we serve; our ability to obtain surety bonds as required by some of our customers; our ability to hire and retain a skilled labor force; our ability to continue to bid successfully on new projects and accurately forecast costs associated with unit price or fixed price contracts; provincial, regional and local economic, competitive and regulatory conditions and developments; technological developments; capital market conditions; inflation rates; foreign currency exchange rates; interest rates; weather conditions; the timing and success of business development efforts; our ability to successfully identify and acquire new businesses and assets and integrate them into our existing operations; and the other risk factors set forth in our most recent Annual Report on Form 20-F filed with the United States Securities and Exchange Commission. You are cautioned not to put undue reliance on any forward-looking statements, and we undertake no obligation to update those statements.

First Restatement

During the fiscal third quarter ended December 31, 2004, management discovered a number of accounts payable invoices recorded in the third fiscal quarter which were related to costs actually incurred in the first and second quarters of the current fiscal year. Management proceeded to review the matter and discovered a number of additional accounting errors, leading management to conduct a review of our accounts and balances. The review identified a number of deficiencies in our processes and internal controls that contributed to several misstated amounts in our unaudited interim consolidated financial statements for the three months ended June 30, 2004. As a result, our financial statements for the quarter have been restated and set forth in this report.

Circumstances Contributing to the Misstatements

A significant amount of our work is performed on remote project sites located in northern Alberta at a considerable distance from our corporate office where the majority of our administration and transaction processing is performed. With project staff located on site, documents such as accounts payable invoices historically were sent to the sites for project management approval and then forwarded to the corporate office for recording and processing for payment. At the end of the previous fiscal year, management recognized that our control procedures surrounding such processing of invoices were weak in light of our new financial reporting requirements under United States securities regulations. As a result, management recognized the need to enhance our controls and processes including the need to prepare detailed project cost forecasts and more accurate and timely project cost reporting, to be achieved

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three months ended June 30, 2004

through the implementation of electronic purchase orders. At the beginning of the quarter ended June 30, 2004, a plan was developed to implement electronic purchase orders across our company. A small team was assembled to develop the necessary policies and processes with gradual implementation scheduled to commence in the fiscal second quarter. By the end of the fiscal second quarter, the implementation was not yet complete, and as a result, we encountered significant difficulties in the accurate and timely accounting for third party costs.

A large steam assisted gravity drainage site project undertaken for a new customer was particularly challenging from the outset due to its complexity, delays, unfavorable weather conditions, and other factors. As a result, an exceptional amount of the project management team’s effort was required to successfully complete the work, detracting from the time that would have otherwise been spent on project cost control and processing of accounts payable invoices. Once management commenced a review of the matter, they discovered that the backlog of unprocessed accounts payable invoices was not isolated to one project but rather a condition that existed in a number of projects and our equipment maintenance division.

Restatement Adjustments

Management’s review identified project, equipment, and general and administrative expenses related to the previously reported three months ended June 30, 2004 and three months and six months ended September 30, 2004 that had not been recorded in the appropriate periods. The understated expenses resulted primarily from our failure to accrue in a timely manner the related costs of unprocessed accounts payable invoices. In addition, in performing its review, management also identified certain equipment costs related to the replacement of heavy construction equipment component parts which were expensed and should have otherwise been capitalized in accordance with our capital assets policy. As a result, in the restatement we recorded adjustments to capitalize certain equipment costs previously expensed. Finally, we reduced the management bonus provision accordingly in light of the reduction in earnings as a result of the restatement adjustments. The net total amount of additional project, equipment, and general and administrative costs reflected in the restated financial statements is $5.1 million for the three months ended June 30, 2004.

In addition to the increase in costs resulting from our review, several errors related to revenues were also discovered. Certain of the costs described above that should have been recorded in the three months ended June 30, 2004 related to projects under cost plus and time-and-material type contracts. Revenues under these types of contracts are recognized as costs are incurred. Consequently, the understatement of costs for the three months ended June 30, 2004 resulted in an understatement of the related revenues. Additionally, we determined that we had understated our proportionate share of revenues related to our interest in a joint venture. These increases in revenues were partially offset by an overstatement of revenues from one customer due to incorrect billing rates as well as duplicate and non-billable transactions in our financial systems. The net total amount of additional revenues reflected in the restated financial statements for the quarter ended June 30, 2004 was $0.8 million.

All of the adjustments for the three months ended June 30, 2004 resulted in an increase in the recovery of future income taxes of approximately $1.3 million and an increase in our net loss of approximately $3.0 million.

In connection with the restatement, we reclassified the term credit facility scheduled repayments due beyond one year to current as explained below under the Liquidity and Capital Resources section of this Management’s Discussion and Analysis.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three months ended June 30, 2004

Certain amounts were also reclassified in connection with the restatement of the interim consolidated financial statements for the three-month period ended June 30, 2004 in order to conform with the current classification of the related amounts in the interim consolidated financial statements for the nine-month period ended December 31, 2004.

Remedial Measures

In connection with the review conducted to identify the factors contributing to these issues, management is implementing a number of measures designed to prevent a recurrence of the various problems identified in its review, including the following:

• The initiative to completely implement electronic purchase orders has been expedited. Management has adopted a policy requiring electronic purchase orders for substantially all purchases, and the policy has been communicated to our employees and suppliers. Additional training related to electronic purchase orders will be performed as required. The effective implementation of electronic purchase orders should provide the means for accurate and timely recording of third party costs during the period in which we receive the goods or services rather than having to wait until the vendor invoice has been approved in the field and processed for payment.

• Certain additional measures have been implemented to help ensure that all third party costs are recorded in the period in which they are incurred. For example, we now electronically monitor accounts payable invoices processed after the quarter end to determine whether the related costs were appropriately recorded. In addition, other measures have been taken to expedite document flow between all of our offices and project sites in order to improve the timeliness of all document handling and processing throughout our company.

Management is implementing controls to help ensure that correct billing rates are utilized to generate the billing transactions and new procedures to help ensure that billing transactions are not duplicated. We cannot yet be sure these measures will be adequate to eliminate future financial reporting inaccuracies.

Second Restatement

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

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

See Note 3 to the financial statements included in this report for a detailed summary of the impact of the restatements on our Consolidated Statements of Operations and Cash Flows, Consolidated Balance Sheets, and Segmented Reporting for the periods presented.

Overview

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

• surface mining for oilsands and other natural resources, including overburden removal, the hauling of sand and gravel, mining of the ore body and delivery of the ore to the crushing facility, supply of labor and equipment to support the owner’s mining operations, construction of infrastructure associated with mining operations and reclamation activities; site preparation, which includes clearing, stripping, excavating and grading for mining operations and other general construction projects, as well as underground utility installation for plant, refinery, and commercial building construction;

• piling installation, including the installation of all types of driven and drilled piles, caissons, and earth retention and stabilization systems for commercial buildings, private industrial projects, such as plants and refineries, and infrastructure projects, such as bridges; and

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

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three months ended June 30, 2004

With over 50 years of operations, we are one of the largest independent equipment owners in Western Canada. In serving our customers, we operate over 400 pieces of heavy construction equipment and over 450 support vehicles. Our fleet size allows us to offer greater flexibility in scheduling contract services on a timely basis and to take on long-term, large-scale projects with the major operators in the oilsands development and in other energy sectors.

The information as of June 30, 2004 may not be directly comparable to the information provided related to Norama Ltd. (“Norama” or the “Predecessor Company”) as a result of the effect of the revaluation of assets and liabilities to their estimated fair market values in accordance with the application of purchase accounting pursuant to Canadian and United States (“U.S.”) generally accepted accounting principles (“GAAP”).

Critical Accounting Policies

The following critical and significant accounting policies are more fully described in note 2 to the attached restated interim unaudited consolidated financial statements. Some accounting policies require management to make significant estimates and assumptions about future events that affect the amounts reported in our interim financial statements and the accompanying notes. Future events and their effects cannot be determined with absolute certainty. Therefore, the determination of estimates requires the exercise of management’s judgment. Actual results could differ from those estimates, and any such differences may be material to our interim financial statements.

Revenue recognition

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

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

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

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

Revenue related to unit price contracts is recognized as applicable quantities (i.e., cubic meters, lineal meters, completed piles) are completed.

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

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

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three months ended June 30, 2004

• Fixed price (lump sum) contracts – Under this type of contract, the price for services performed is established at the outset of the contract and is not subject to any adjustment based on the costs incurred or our performance under the scope of the original contract. Changes in scope added by the client are priced incrementally to the original bid or lump sum. Similar to unit price contracts, the price charged to the client for the services performed is calculated by estimating all of the costs expected to be incurred by us in performing services required by the contract and adding an appropriate amount to the contract price to generate the required profit margin.

Revenue on fixed price (lump sum) contracts is recognized on the percentage-of-completion method, measured by the ratio of costs incurred to date to estimated total costs. In the absence of reliable output measures like cubic meters, lineal meters or completed piles, we recognize revenue based upon input measures such as costs incurred to date.

Profit for each type of contract is included in income when its realization is reasonably assured. Estimated contract losses are recognized in full when determined. Revenue from change orders, extra work, and variations in the scope of work is recognized after both the costs are incurred or services are provided and an agreement has been reached with clients as to both the scope of work and price. Revenue from claims is recognized when an agreement is reached with clients as to the value of the claims which in some instances may not occur until after completion of the work under the contract. Costs incurred for bidding and obtaining contracts are expensed as incurred.

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

Factors that can contribute to changes in estimates of contract cost and profitability include, without limitation: site conditions that differ from those assumed in the original bid (to the extent that contract remedies are unavailable), the availability and skill level of workers in the geographic location of the project, the availability and proximity of materials, the accuracy of the original bid and subsequent estimates, inclement weather, and timing and coordination issues inherent in all projects. The foregoing factors, as well as the stage of completion of contracts in process and the mix of contracts at different margins, may cause fluctuations in gross profit between periods, and these fluctuations may be significant.

Capital assets

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

Another key estimate is the expected cash flows from the use of an asset and the expected disposal proceeds in applying CICA Handbook Section 3063 “Impairment or Disposal of Long-Lived Assets” and the revised Section 3475

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three months ended June 30, 2004

“Disposal of Long-Lived Assets and Discontinued Operations”. This standard requires the recognition of an impairment loss for a long-lived asset to be held and used when changes in circumstances cause its carrying value to exceed the total undiscounted cash flows expected from its use. An impairment loss, if any, is determined as the excess of the carrying value of the assets over its fair value. Equally important is the expected fair value of assets that are available-for-sale.

Results of Operations

($ in thousands)

	Three months ended June 30, 2004					Predecessor Company Three months ended June 30, 2003
	(Restated)1
Revenue	$	70,860		100.0	%	$	93,730		100.0	%
Project costs		46,038		65.0	%		56,393		60.2	%
Equipment costs		12,202		17.2	%		21,996		23.5	%
Depreciation		4,519		6.4	%		2,562		2.7	%
Gross profit		8,101		11.4	%		12,779		13.6	%
General and administrative		5,040		7.1	%		3,040		3.2	%
Gain on disposal of capital assets		(6	)	0.0	%		(70	)	-0.1	%
Amortization of intangibles		1,430		2.0	%		—		0.0	%
Operating income		1,637		2.3	%		9,809		10.5	%
Interest expense		7,331		10.4	%		947		1.0	%
Management fees		—		0.0	%		9,000		9.6	%
Foreign exchange (gain) loss		4,654		6.6	%		(8	)	0.0	%
Other income		(146	)	-0.2	%		(197	)	-0.2	%
Realized and unrealized (gains) losses on derivative financial instruments		(2,531	)	-3.6	%		—		0.0	%
Income (loss) before income taxes		(7,671	)	-10.9	%		67		0.1	%
Other data
Equipment hours		137,434					177,939

¹ See note 3 to the unaudited interim consolidated financial statements for the three months ended June 30, 2004 for an explanation of the changes made.

Three Months Ended June 30, 2004 compared to Three Months Ended June 30, 2003

Revenue

Revenue for the three months ended June 30, 2004 decreased by $22.9 million to $70.9 million, as compared to $93.7 million for the three months ended June 30, 2003. The substantial completion of two Syncrude Canada Ltd. (“Syncrude”) projects, Upgrader Expansion 1 (“UE1”) and Aurora II, late in fiscal 2004 contributed to the decline in revenue over the comparable period in the prior year. The extension of the winter construction program on the EnCana Sierra project in British Columbia, together with revenue from new projects including: The Opti Canada Inc. / Nexen Inc. joint venture (“OPTI/Nexen”) project south of Fort McMurray, Alberta; Syncrude’s Southwest Quadrant Replacement (“SWQR”) project; and Suncor Energy Inc.’s (“Suncor”) Millennium Coker Unit piling project, partially offset this decrease.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three months ended June 30, 2004

Project costs

Project costs for the three months ended June 30, 2004 decreased by $10.4 million to $46.0 million as compared to $56.4 million for the three months ended June 30, 2003. The decrease was primarily attributable to the lower volume of services provided in the current fiscal quarter. As a percentage of revenue, project costs increased quarter over quarter from 60.2% to 64.5% due primarily to the poor results related to two particular projects that commenced in the first fiscal quarter ended June 30, 2004.

Equipment costs

Equipment costs for the three months ended June 30, 2004 decreased by $9.8 million to $12.2 million as compared to $22.0 million for the three months ended June 30, 2003. The decrease primarily related to lower lease and rental expense due to the buy out of most leases and rentals concurrent with the acquisition.

Depreciation

Depreciation expense increased by $2.0 million to $4.5 million for the three months ended June 30, 2004, as compared to $2.6 million for the three months ended June 30, 2003. This increase was due primarily to the revaluation of assets and liabilities to their estimated fair market values in accordance with the application of purchase accounting in connection with the acquisition, offset by lower heavy equipment hours versus the comparable period in the prior year.

General and administrative expenses

General and administrative expenses increased by $2.0 million to $5.0 million for the three months ended June 30, 2004, as compared to $3.0 million for the three months ended June 30, 2003. This increase was primarily attributable to higher staff levels and salary increases, increased travel costs, increased insurance and consulting costs, and increased costs related to corporate governance and reporting responsibilities as an SEC filing company.

Amortization of intangibles

Intangible assets were acquired in the acquisition and relate to customer contracts in progress, trade names, a non-competition agreement, and employee arrangements. Over 80% of the intangibles have been amortized at June 30, 2004, the majority of which relates to customer contracts in progress. These are being amortized at a rapid rate due to their short-term nature.

Interest expense

Interest expense increased by $6.4 million to $7.3 million for the three months ended June 30, 2004, as compared to $0.9 million for the quarter ended June 30, 2003. This increase was primarily due to larger debt balances with higher associated interest rates incurred in connection with the acquisition.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three months ended June 30, 2004

Management fees

Management fee expense decreased by $9.0 million to $nil for the quarter ended June 30, 2004, as compared to $9.0 million for the quarter ended June 30, 2003. Norama Inc., the parent company of Norama, charged a fee for management services provided to the Predecessor Company. The management fee was paid in reference to taxable income. Subsequent to the acquisition, no similar management fees have been paid, and the agreement with Norama Inc. has been terminated.

Foreign exchange (gain) loss

The foreign exchange loss of $4.7 million for the three months ended June 30, 2004 related primarily to the change in the balance owing on the senior notes due to the fluctuation in the Canadian dollar-U.S. dollar exchange rate. The foreign exchange gain in the comparative period was relatively small and related primarily to the exchange differences between the Canadian and U.S. dollar for a U.S. dollar bank account.

Realized and unrealized (gain) loss on derivative financial instruments

The realized loss and unrealized gains on the Company’s cross-currency and interest rate swap agreements, which do not qualify for hedge accounting, are $0.7 million loss and $3.2 million gain, respectively. There was no gain or loss for the comparative period as the swap agreements commenced concurrent with the Acquisition on November 26, 2003. The gain on the change in fair value of $2.5 million for the three months ended June 30, 2004 related primarily to the mark-to-market change in the fair value of the derivatives in the period.

Segmented Results of Operations

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

Segmented Results of Operations

($ in thousands)

	Three months ended June 30, 2004					Predecessor Company Three months ended June 30, 2003
	(Restated)
Revenue
Mining and Site Preparation	$	46,764		66.0	%	$	69,755		74.4	%
Piling		13,257		18.7	%		15,267		16.3	%
Pipeline		10,839		15.3	%		8,708		9.3	%
Total revenue	$	70,860		100.0	%	$	93,730		100.0	%
Segment profit
Mining and Site Preparation	$	3,491		43.1	%	$	7,217		60.6	%
Piling		2,979		36.7	%		3,633		30.5	%
Pipeline		1,638		20.2	%		1,066		8.9	%
Total segment profit	$	8,108		100.0	%	$	11,916		100.0	%
Unallocated costs
Corporate cost		15,696					12,783
Equipment cost (revenue)		83					(934	)
Income (loss) before income taxes	$	(7,671	)			$	67
Equipment hours
Mining and Site Preparation		112,417					150,254
Piling		15,063					19,368
Pipeline		9,954					8,317
Total equipment hours		137,434					177,939

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three months ended June 30, 2004

Mining and Site Preparation

Revenue for the quarter ended June 30, 2004 decreased by $23.0 million to $46.8 million, as compared to $69.8 million for the quarter ended June 30, 2003. This decrease was driven by the substantial completion of two projects, UE1 and Aurora II, at the end of the prior year. Revenue from our largest project, UE1, decreased by $14.1 million over the comparable quarter in the prior year while revenue from Aurora II decreased by $6.7 million. Revenue from the Albian project decreased by $2.6 million to $6.3 million compared to $8.9 million for the quarter ended June 30, 2003. This new oilsands mine in the Fort McMurray, Alberta region had production volumes below design rates and non-scheduled maintenance activities resulting in less demand for our services. These decreases were offset partially by revenue from new projects, including the OPTI/Nexen joint venture project south of Fort McMurray, Alberta and Syncrude’s South West Quadrant Replacement project.

Mining and site preparation segment profits decreased by $3.7 million for the quarter ended June 30, 2004 to $3.5 million as compared to $7.2 million for the quarter ended June 30, 2003. The change was primarily due to the lower volume of work in the quarter, poor results in the quarter related to two relatively large projects that commenced in the quarter, and a general year-over-year change in contract mix to lower margin work.

Piling

Revenue for the quarter ended June 30, 2004 decreased by $2.0 million to $13.3 million as compared to $15.3 million for the quarter ended June 30, 2003. This decrease was largely due to $8.0 million less in revenue from the UE1 piling contract compared to the prior year as work on this project is nearing completion. Offsetting this decrease was $2.8 million in revenue from the new Suncor Millennium Coker Unit project, which began in the first quarter of fiscal 2005, and increased revenues from various other new piling projects in the Edmonton, Calgary, and Regina areas.

Piling segment profits decreased by $0.7 million for the quarter ended June 30, 2004 to $3.0 million as compared to $3.6 million for the quarter ended June 30, 2003, primarily due to the lower volume of work in the quarter.

Pipeline

Revenue from the pipeline segment increased by $2.1 million to $10.8 million for the quarter ended June 30, 2004 compared to $8.7 million for the prior year. This increase was a result of the winter construction program on the EnCana Sierra project in British Columbia that extended into the first quarter of fiscal 2005.

Pipeline segment profits increased by $0.6 million for the quarter ended June 30, 2004 to $1.6 million as compared to $1.1 million for the quarter ended June 30, 2003. The increase in segment profit was primarily attributable to the increase in activity volumes.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three months ended June 30, 2004

Liquidity and Capital Resources

Operating activities

Cash deficiency from operating activities for the quarter ended June 30, 2004 was $4.0 million with payment of current liabilities (primarily interest on the senior notes) contributing to the outflow. Cash provided from operating activities for the Predecessor Company for the quarter ended June 30, 2003 was $12.0 million with collection of accounts receivable primarily contributing to the results. We fund our operations and capital expenditures and satisfy our debt service obligations through operating cash flow and from borrowings under our revolving credit facility and other external financing.

Investing activities

During the quarter ended June 30, 2004, we invested $1.0 million in sustaining capital expenditures and $10.4 million in expansion capital expenditures. In addition, new vehicles financed by way of capital leases totalled $0.7 million and proceeds from the disposal of capital assets amounted to $0.1 million during the quarter. We expect our future sustaining capital expenditures to range from $9.0 million to $18.0 million per year. Sustaining capital expenditures are those that are required to maintain our fleet of equipment at its optimum average age. Expansion capital expenditures are directly related to new projects, and the commitment to make expansion capital expenditures typically occurs only when we have signed a contract for a new project.

During the quarter ended June 30, 2003, the Predecessor Company invested $1.3 million in sustaining capital expenditures, and $0.3 million in expansion capital expenditures. Proceeds from the disposal of capital assets were $0.3 million.

Financing activities

Financing activities during the quarter ended June 30, 2004 related to payments made on the term credit facility and capital leases.

Financing activities of the Predecessor Company for the quarter ended June 30, 2003 included payments made on the term credit facility and capital leases, offset by $3.6 million advanced from Norama Inc.

Liquidity

Under the terms of our credit agreement dated November 26, 2003, we are subject to various financial covenants including: achieving certain levels of earnings before interest, taxes, depreciation and amortization (“EBITDA”), maintaining interest and fixed-charge coverage ratios above a specified minimum level, limiting capital expenditures to specified amounts and maintaining leverage ratios below a specified maximum level.

Subsequent to the date of the original Credit Agreement, certain financial covenants effective up to, and including, March 31, 2005 were modified under amending agreements to the original Credit Agreement. As at June 30, 2004, under amended terms of the credit agreement, we were required to achieve a modified minimum consolidated EBITDA level of $50.0 million over the trailing 12 months, which we did achieve. Once the financial covenants revert back to the original terms of the credit agreement, effective June 30, 2005, we will be required to achieve compliance with all of the financial covenants under the original terms with certain financial covenants becoming more restrictive. For example, we will be required to achieve minimum consolidated EBITDA levels of $82.5 million for the trailing twelve month period ending June 30, 2005 and $85.0 million for the trailing twelve month period ending September 30, 2005 which are not likely achievable given our current outlook.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three months ended June 30, 2004

Even though we were in compliance with all of our financial covenants at June 30, 2004, we reclassified the term credit facility scheduled repayments due beyond one year to current as required by Emerging Issues Committee Abstract EIC-59, “Long-term Debt with Covenant Violations”. Under this accounting standard, in circumstances where at the balance sheet date the debtor would have been in violation of one or more financial covenants giving the creditor the right to demand repayment absent the modification of financial covenants, and it is likely that the debtor will violate one or more of its financial covenants within one year of the balance sheet, then the debtor must classify its non-current debt as current.

As of June 30, 2004, we had available $60.0 million, subject to borrowing base limitations, under our $70.0 million revolving credit facility after taking into account a $10.0 million letter of credit required to be posted to support bonding requirements associated with customer contracts. In addition, we continue to lease a portion of our motor vehicle fleet and assumed four heavy construction equipment operating leases from the Predecessor Company.

We are required to make quarterly principal and monthly interest payments under our $47.0 million term loan which bears interest at a floating rate based upon either the Canadian prime rate plus 2.0% to 2.5%, or Canadian bankers’ acceptance rate plus 3.0% to 3.5%. For the quarter ended June 30, 2004, the weighted average interest rate on the term debt was 5.75%. The term portion of the credit facility is repayable in quarterly installments over each of the next twelve-month periods as follows: $8.5 million, $11.0 million, $11.0 million, $11.0 million, and $5.5 million (see Contractual Obligations table, which follows). Additional prepayments are required under certain circumstances, and no new advances are available under the term facility. We refer to the revolving credit facility and the term loan collectively as the “senior secured credit facility.”

After becoming aware of the misstatements discussed earlier in this MD&A, our management informed the lenders under the Credit Agreement of our potential breach of various covenants under the Credit Agreement. We have obtained a series of waivers from the lenders, waiving our non-compliance with certain financial covenants for several quarterly periods of fiscal 2005, our failure to deliver financial statements for the periods ended December 31, 2004, January 31, 2005 and February 28, 2005 by specified dates, and any default that would arise under the Credit Agreement as a result of being out of compliance with the corresponding covenants in the indenture governing our 8¾% senior notes requiring delivery of our December 31, 2004 financial statements by March 1, 2005. The most recent waivers expire on the earlier of April 15, 2005 or the date the lack of compliance becomes an event of default under the indenture.

In connection with the first waiver, which was obtained on January 14, 2005, the lenders allowed us to increase our borrowings under the revolving credit facility to $20 million and increase the amount of outstanding letters of credit issued to $20 million. The lending banks have not provided any additional funding since that date. The revolving credit facility would otherwise provide us with borrowing capacity up to $70 million in total, subject to borrowing base limitations. In addition, during the waiver period, we were obligated to update various information regarding our assets, provide more current financial information regarding our operations than currently required by the Credit Agreement and cooperate with a third party engaged by the banks to evaluate our accounting and control procedures surrounding the causes for the restatement of our financial statements for the quarters ended June 30, 2004 and September 30, 2004 and to review our current customer contacts.

In the event that we fail to obtain additional waivers or an amendment of the Credit Agreement by April 15, 2005, our lenders would be in a position to demand immediate repayment on our senior secured credit facility. Management is currently exploring alternatives to resolve the matters including seeking alternative financing sources. However, we cannot provide any assurances that a modification of the Credit Agreement or new financing agreement will be consummated or that we will have access to such capital when required to fund our future operations.

There are no principal payments required on our US$200 million of 8¾% senior notes until maturity. The foreign currency risk relating to both the principal and interest payments has been managed with a cross-currency swap and interest rate swaps which went into effect concurrent with the acquisition. The swap agreements are economic hedges of the changes in the Canadian dollar-U.S. dollar exchange rate, but they do not meet the criteria to qualify for hedge accounting. The 8.75% rate of interest on the senior notes has been swapped to an effective rate of 9.765% for the entire eight-year period until maturity. The interest is $12.8 million payable semi-annually in June and December of each year until the notes mature on December 1, 2011.

The senior notes were issued pursuant to a private placement. The terms under a registration rights agreement entered into in connection with the private placement require us to register substantially identical notes with the United States Securities and Exchange Commission and exchange them for the notes issued in the private placement. This registration and exchange are required to be completed within a certain number of days of the original issuance of the notes or we must pay additional interest expense to the holders of the notes. As of June 30, 2004 we had not yet completed the registration and exchange and have thus incurred additional interest in the amount of $0.05 million in the quarter ended June 30, 2004. The registration was effective on October 5, 2004, after which the exchange offer was completed.

11

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three months ended June 30, 2004

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

Contractual Obligations and Other Commitments

Our principal contractual obligations relate to the senior notes and the senior secured credit facility as well as capital and operating leases. The following table summarizes our future contractual obligations, excluding interest payments, as of June 30, 2004:

Contractual Obligations and Other Commitments

($ in thousands)			June 30,
	Total		2005		2006		2007		2008		2009 and after
Long-term debt	$	313,760	$	8,500	$	11,000	$	11,000	$	11,000	$	272,260
Capital leases		3,819		986		970		1,080		738		45
Operating leases (a)		7,669		3,412		2,202		1,750		304		1
Total contractual obligations	$	325,248	$	12,898	$	14,172	$	13,830	$	12,042	$	272,306

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

U.S. Generally Accepted Accounting Principles

The interim 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 is set out in note 19 to the restated interim consolidated financial statements for the three months ended June 30, 2004 and note 20 of the restated audited consolidated financial statements for the fiscal year ended March 31, 2004.

Recent U.S. accounting pronouncements

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

12

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three months ended June 30, 2004

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

Quantitative and Qualitative Disclosures Regarding Market Risk

We are subject to currency exchange risk as the senior notes are denominated in U.S. dollars, and all of our revenues and most of our expenses are denominated in Canadian dollars. As noted above, we have entered into cross-currency swap and interest rate swap agreements to effectively manage this risk. The derivative financial instruments consists of three components: (1) a U.S. dollar interest rate swap, (2) a U.S. dollar-Canadian dollar cross-currency basis swap, and (3) a Canadian dollar interest rate swap that results in us mitigating our exposure to the variability of cash flows caused by currency fluctuations relating to the US$200 million senior notes. The transaction can be cancelled at the counterparty’s option at any time after December 1, 2007 if the counterparty pays a cancellation premium to us. The premium is equal to 4.375% of the US$200 million if exercised between December 1, 2007 and December 1, 2008; 2.1875% if exercised between December 1, 2008 and December 1, 2009 and 0.000% if cancelled after December 1, 2009. These derivative financial instruments do not qualify for hedge accounting.

We are also subject to interest rate market risk in connection with our senior secured credit facility. The facility bears interest at variable rates based on the Canadian prime rate plus 2.0% to 2.5% or Canadian bankers’ acceptance rate plus 3.0% to 3.5%. Each 1.0% increase or decrease in the interest rate on the term portion of the facility would change the interest cost by $0.5 million in the first year, decreasing thereafter as the principal is repaid. Assuming the revolving credit facility is fully drawn at $60.0 million, each 1.0% increase or decrease in the applicable interest rate would change the interest cost by $0.6 million per year. In the future, we may enter into interest rate swaps involving the exchange of floating for fixed rate interest payments to reduce interest rate volatility.

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

Seasonality

We experience some seasonality in our operations, particularly in the pipeline segment. Conditions are more favourable in the winter months in colder temperature to move equipment on the soil, and accordingly, most of the revenue is earned during the period from November though March.

In the mining and site preparation segment, the spring thaw, which typically occurs in April and May, can result in lower revenues earned in that period.

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