UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

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

under the Securities Exchange Act of 1934

For the month of August 2004

Commission File Number 333-111396

NORTH AMERICAN ENERGY PARTNERS INC.

Acheson Industrial Park #2

53016-Highway 60

Spruce Grove, Alberta

Canada T7X 3G7

(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):                     .

Reports included:

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

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

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Financial Statements

Period ended June 30, 2004

(Expressed in thousands of Canadian dollars)

(Unaudited)

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Balance Sheets

(in thousands of Canadian dollars)

	June 30, 2004			March 31, 2004
	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	19,339		$	36,595
Accounts receivable (note 10(a))		36,466			33,647
Unbilled revenue		11,515			27,676
Inventory		1,160			1,609
Prepaid expenses		1,205			1,272
		69,685			100,799
Capital assets (note 4)		175,304			167,905
Goodwill (note 3)		198,549			198,549
Intangible assets, net of accumulated amortization of $14,358 (notes 3 and 5)		3,440			4,870
Deferred financing costs, net of accumulated amortization of $1,439 (note 3)		16,821			17,266
Derivative financial instruments (note 13(c))		3,760			—
	$	467,559		$	489,389
Liabilities and Shareholder’s Equity
Current liabilities:
Revolving credit facility (note 6)	$	—		$	—
Accounts payable		15,295			23,187
Accrued liabilities		6,976			20,808
Current portion of term credit facility (note 6)		8,500			7,250
Current portion of capital lease obligations (note 7)		823			787
Future income taxes		1,170			5,260
		32,764			57,292
Term credit facility (note 6)		38,500			41,250
Capital lease obligations (note 7)		2,650			2,251
Senior notes (note 8)		266,760			262,260
Derivative financial instruments		—			740
Future income taxes		4,790			2,515
Shareholder’s equity:
Share capital (note 9)		127,500			127,500
Contributed surplus (note 16)		249			137
Deficit		(5,654	)		(4,556	)
		122,095			123,081
Commitments (note 14)
United States generally accepted accounting principles (note 18)
	$	467,559		$	489,389

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
Revenue	$	70,021		$	93,730
Project costs		42,421			56,393
Equipment costs		10,881			21,996
Depreciation		4,519			2,562
		57,821			80,951
Gross profit		12,200			12,779
General and administrative		4,882			3,040
Gain on disposal of capital assets		(6	)		(70	)
Amortization of intangible assets		1,430			—
Operating income		5,894			9,809
Management fees (note 12(c))		—			9,000
Interest expense, net (note 10(b))		7,840			913
Foreign exchange (gain) loss (note 13(d))		154			(8	)
Other income		—			(163	)
		7,994			9,742
Income (loss) before income taxes		(2,100	)		67
Income taxes:
Current income taxes		813			118
Future income taxes		(1,815	)		25
		(1,002	)		143
Net loss		(1,098	)		(76	)
Retained earnings (deficit), beginning of period		(4,556	)		29,817
Retained earnings (deficit), end of period	$	(5,654	)	$	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
Cash provided by (used in):
Operating activities:
Net loss	$	(1,098	)	$	(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
Stock-based compensation expense (note 16)		112			—
Future income taxes		(1,815	)		25
Net changes in non-cash working capital (note 10(d))		(7,733	)		9,530
		(4,099	)		11,988
Investing activities:
Purchase of capital assets		(11,307	)		(1,564	)
Proceeds on disposal of capital assets		104			256
		(11,203	)		(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”) was incorporated under the Canada Business Corporations Act on October 17, 2003. The Company had no operations prior to November 26, 2003. After giving effect to the acquisition described in note 3, the Company completes all forms of civil projects including contract mining, industrial and commercial site development, pipeline and piling installations. The Company is a wholly-owned subsidiary of NACG Preferred Corp. which in turn is a wholly-owned subsidiary of NACG Holdings Inc.

2. Significant accounting policies

a) Basis of presentation:

These interim consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles (“GAAP”). Material inter-company transactions and balances are eliminated on consolidation. Material items that could give rise to measurement differences to these consolidated financial statements under United States GAAP are outlined in note 18.

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

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

In preparation for the acquisition described in note 3, effective July 31, 2003, all of the issued common shares of NACGI and North American Equipment Ltd. (“NAEL”) were transferred from Norama Inc. to its new wholly-owned subsidiary, Norama Ltd. (the “Predecessor Company”). The consolidated financial statements of Norama Ltd. are depicted in these financial statements as the Predecessor Company and have been prepared using the continuity of interest method of accounting to reflect the combined carrying values of the assets, liabilities and shareholder’s equity as well as the combined operating results of NAEL and NACGI for all comparative periods presented. The consolidated financial statements for periods ended before November 26, 2003 are not comparable in all respects to the consolidated financial statements for periods ending after November 25, 2003.

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

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-fixed-fee; unit-price; and fixed-price or lump-sum. For time-and-materials and cost-plus-fixed-fee contracts, revenue is recognized as costs are incurred. Revenue from unit-price contracts is recognized based on quantities of units performed and delivered. Revenue on lump-sum contracts is recognized on the percentage-of-completion method, measured by the ratio of costs incurred to date to estimated total costs.

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

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

d) Cash and cash equivalents:

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

e) Allowance for doubtful accounts:

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

f) Inventory:

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

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 and hedging:

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

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

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

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)

m) Income taxes:

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

n) Stock–based compensation plan:

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 vesting period.

o) Hedging relationships:

Effective April 1, 2004, the Company prospectively adopted the provisions of the CICA’s 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 hedges qualify for hedge accounting in accordance with AcG-13.

p) 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.

q) Revenue recognition:

Effective April 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.

r) Recent Canadian accounting pronouncements:

(i) 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 without additional subordinated financial support and/or entities whose equity investors lack one or

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)

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 2005 fiscal year. The adoption of this standard is not expected to have a material impact on the consolidated financial statements.

3. Acquisition

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

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

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 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 $18.1 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).

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.

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)

4. Capital assets

June 30, 2004	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	158,446	$	7,339	$	151,107
Major component parts in use		4,212		591		3,621
Spare component parts		395		—		395
Other equipment		10,501		1,075		9,426
Licensed motor vehicles		11,324		1,803		9,521
Office and computer equipment		1,598		364		1,234
	$	186,476	$	11,172	$	175,304

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 3.

5. Intangible assets

At June 30, 2004, identifiable intangible assets purchased in the acquisition described in note 3 consisted of the following:

Identifiable intangible assets	Cost		Accumulated amortization		Net book value
Customer contracts in progress and related relationships	$	15,323	$	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

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)

6. Senior secured credit facility

On November 26, 2003, the Company secured a $120 million senior credit facility with a syndicate of lenders. The facility is comprised of a $70 million revolving credit facility, subject to borrowing base limitations, and a $50 million term credit facility, both of which bear interest at the Canadian prime rate plus 2 - 2.5% or Canadian bankers’ acceptances rate plus 3 - 3.5%. The credit facility is secured by a first priority lien on the Company’s capital stock and the capital stock of its subsidiaries and on substantially all the assets of the Company and its subsidiaries. Concurrent with the acquisition on November 26, 2003 (note 3), a letter of credit in the amount of $10 million was issued to support bonding requirements associated with the Company’s customer contracts. Except for the letter of credit, no amounts were drawn down on the revolving credit facility.

	June 30, 2004		March 31, 2004
Term credit facility, due November 26, 2008	$	47,000	$	48,500
Less: current portion		8,500		7,250
	$	38,500	$	41,250

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

Year ended June 30,	Repayment
2005	$	8,500
2006		11,000
2007		11,000
2008		11,000
2009		5,500
	$	47,000

7. Capital lease obligations

The Company leases a portion of its licensed motor vehicles for which the minimum lease payments due in each of the next 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

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)

8. Senior notes

The senior notes were issued on November 26, 2003 in the amount of US$200 million. These notes mature on December 1, 2011 and bear interest at 8.75% payable semi-annually on June 1 and December 1 of each year. By way of swap agreements, the notes have an effective interest rate of 9.765% for the duration for which the senior notes are outstanding.

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

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

The foreign exchange exposure relating to the senior notes has been hedged – see note 13(c).

9. 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

10. Other information

a) Accounts receivable:

	June 30, 2004			March 31, 2004
Accounts receivable – trade	$	33,232		$	29,991
Accounts receivable – holdbacks		3,332			3,838
Accounts receivable – other		2			51
Allowance for doubtful accounts		(100	)		(233	)
	$	36,466		$	33,647

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)

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
Customer A	37.3	%	28.7	%
Customer B	6.9	%	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.

b) Interest expense, net:

				Predecessor Company 2003
For the three months ended June 30,	2004
Interest on senior notes	$	6,353		$	—
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		7,084			896
Amortization of deferred financing costs		625			—
Other interest(1)		277			51
Interest income		(146	)		(34	)
	$	7,840		$	913

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

c) Supplemental cash flow information:

			Predecessor Company 2003
For the three months ended June 30,	2004
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		—		—

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)

10. Other information, continued

d) Net change in non-cash working capital:

				Predecessor Company 2003
For the three months ended June 30,	2004
Accounts receivable	$	(2,686	)	$	(1,925	)
Unbilled revenue		16,161			23,715
Inventory		449			—
Prepaid expenses		67			(903	)
Accounts payable		(7,892	)		(9,627	)
Accrued liabilities		(13,832	)		(1,730	)
	$	(7,733	)	$	9,530

11. Segmented information

a) General overview:

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

• Mining and Site Preparation:

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

• Piling:

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

• Pipeline:

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

b) Results by business segment:

For the three months ended June 30, 2004	Mining & Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	46,410	$	12,713	$	10,898	$	70,021
Depreciation of capital assets		2,207		610		55		2,872
Segment profits		5,751		3,198		1,830		10,779
Segment assets		284,509		77,959		44,585		407,053
Expenditures for segment capital assets		10,681		—		—		10,681

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)

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		7,287		3,633		1,066		11,986
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
Total profit for reportable segments	$	10,779		$	11,986
Unallocated corporate expenses		(14,306	)		(12,783	)
Unallocated equipment revenue (costs)		1,427			864
Income (loss) before income taxes	$	(2,100	)	$	67

(ii) Total assets:

	June 30, 2004		March 31, 2004
Total assets for reportable segments	$	407,053	$	410,469
Corporate assets		60,506		78,920
Total assets	$	467,559	$	489,389

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
Customer A	44.3	%	67.1	%
Customer B	15.6		9.3

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

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)

12. 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 3.

c) Predecessor company transactions:

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

13. Financial instruments

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

a) Fair value:

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

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

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)

b) Interest rate risk:

The Company is subject to interest rate risk on the senior 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 14) 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 hedge this foreign currency exposure and buy U.S. dollars for both the principal balance due on December 1, 2011 as well as the semi-annual interest payments through the whole period beginning from the issuance date to the maturity date. As part of the cross currency swap agreement, the Company also entered into a U.S. dollar interest rate swap and a Canadian dollar interest rate swap with the net effect of converting the 8.75% rate payable on the senior notes into a fixed rate of 9.765% for the duration that the senior notes are outstanding. Each period, an amount equal to the gain or loss resulting on the remeasurement of the hedged item at spot rates is recorded as an offset to the foreign currency gains or losses otherwise recorded.

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

	Carrying amount		Fair value
Cross currency and interest rate swaps	$	3,760	$	(8,080	)

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.

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.

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)

14. 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

15. 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).

16. 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.

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.

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)

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
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.

17. Comparative figures

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

18. United States generally accepted accounting principles

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

In accordance with the provisions of SFAS 133 “Accounting for Derivatives and Hedging Activities”, all derivatives are recognized as assets and liabilities on the balance sheet and measured at fair value. As of June 30, 2004, the fair value of the derivatives was $(8,080). The Company has elected to measure and assess effectiveness based on total changes in the cash flows generated by hedging instruments. Each period, an amount equal to the gain or loss resulting on the remeasurement of the hedged item at spot rates is reclassified from Other Comprehensive Income and recorded as an offset to the foreign currency gains or losses otherwise recorded. In addition, the Company reclassifies an amount to reflect the cost element of the hedging instrument. During the three months ended June 30, 2004, $(2,859) (net of tax of $(1,788)) was reclassified from Other Comprehensive Income and included in income.

Consolidated Statement of Other Comprehensive Income:

Net loss in accordance with Canadian and U.S. GAAP	$	(5,654	)
Net gain on cash flow hedges, net of tax of $1,070		2,116
Less: reclassification adjustments, net of tax of $1,788		(2,859	)
Comprehensive loss in accordance with U.S. GAAP	$	(6,397	)

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)

Recent United States accounting pronouncements:

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

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

21

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2004

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with the attached unaudited interim financial statements and the notes thereto. The following discussion contains forward-looking statements, which reflect the expectations, beliefs, plans and objectives of management about future financial performance and assumptions underlying our judgments concerning the matters discussed below. These interim statements, accordingly, involve estimates, assumptions, judgments and uncertainties. In particular, this pertains to management’s comments on financial resources, capital spending and the outlook for our business. Our actual results could differ from those discussed in the forward-looking statements. Factors that could cause or contribute to any differences include, but are not limited to, the competitive environment in our specific market areas; the amount of outsourcing by businesses that use our services; changes in the prevailing interest rates and the availability of and terms of financing to fund the anticipated growth of our business; the ability to retain a skilled labor force; currency exchange rate fluctuations; our significant indebtedness; labor disturbances; oil and natural gas price fluctuations; economic conditions impacting the energy industry in western Canada; changes in federal, provincial and/or local government regulations; and other factors referenced herein.

Overview

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

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

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

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

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

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

1

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2004

their estimated fair market values in accordance with the application of purchase accounting pursuant to Canadian and U.S. GAAP.

Critical Accounting Policies

The following critical and significant accounting policies are more fully described in note 2 to the attached interim financial statements. Some accounting policies require management to make significant estimates and assumptions about future events that affect the amounts reported in its 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 a fixed fee, 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-fixed-fee 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 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.

• 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

2

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2004

generate the required profit margin. This type of contract historically represents only a small portion of our overall work.

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 work under the contract. Costs incurred for bidding and obtaining contracts are expensed as incurred.

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

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

Capital assets

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

Another key estimate is the expected cash flows from the use of an asset and the expected disposal proceeds in applying CICA handbook section 3063 “Impairment or Disposal of Long-Lived Assets” and the revised Section 3475 “Disposal of Long-Lived Assets and Discontinued Operations”. This standard requires the recognition of an impairment loss for a long-lived asset to be held and used when changes in circumstances cause its carrying value to exceed the total undiscounted cash flows expected from its use. An impairment loss, if any, is determined as the

3

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2004

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.

Hedge accounting

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

Results of Operations

($ in thousands)	Quarter ended June 30, 2004				Quarter ended June 30, 2003
Revenue	70,021		100.0	%	93,730		100.0	%
Project costs	42,421		60.6	%	56,393		60.2	%
Equipment costs	10,881		15.5	%	21,996		23.5	%
Depreciation	4,519		6.5	%	2,562		2.7	%
Gross Profit	12,200		17.4	%	12,779		13.6	%
General and administrative	4,882		7.0	%	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 (loss)	5,894		8.4	%	9,809		10.5	%
Interest expense, net	7,840		11.2	%	913		1.0	%
Management fees	—		0.0	%	9,000		9.6	%
Foreign exchange (gain) loss	154		0.2	%	(8	)	0.0	%
Other income	—		0.0	%	(163	)	-0.2	%
Income (loss) before income taxes	(2,100	)	-3.0	%	67		0.1	%
Other data
Equipment hours	137,434				177,912

Quarter Ended June 30, 2004 compared to Quarter Ended June 30, 2003

Revenue

Revenue for the quarter ended June 30, 2004 decreased by $23.7 million to $70.0 million, as compared to $93.7 million for the quarter ended June 30, 2003. The substantial completion of two projects at Syncrude, Upgrader Expansion 1 (“UE1”) and Aurora II, led to the decline in revenue over the comparable quarter 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’s Millenium Coker Unit piling project, partially offset this decrease.

4

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2004

Project costs

Project costs for the quarter ended June 30, 2004 decreased by $14.0 million to $42.4 million as compared to $56.4 million for the quarter 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 only marginally quarter over quarter from 60.2% to 60.6%.

Equipment costs

Equipment costs for the quarter ended June 30, 2004 decreased by $11.1 million to $10.9 million as compared to $22.0 million for the quarter ended June 30, 2003. Nearly 70% of the decrease relates 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 $1.9 million to $4.5 million for the quarter ended June 30, 2004, as compared to $2.6 million for the quarter ended June 30, 2003. This increase is due primarily to the revaluation of assets and liabilities to their estimated fair market values in accordance with the application of purchase accounting in connection with the acquisition, offset by lower heavy equipment hours versus the comparable quarter in the prior year.

General and administrative expenses

General and administrative expenses increased by $1.9 million to $4.4 million for the quarter ended June 30, 2004, as compared to $3.0 million for the quarter ended June 30, 2003. This increase was primarily attributable to higher staff levels and salary increases, increased travel costs, increased insurance and consultants costs, and to new expenses related to the change in ownership (directors’ fees, advisory fees, and stock-based compensation expense).

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. Just over 80% of the intangibles have been amortized to date, the vast majority of which relates to customer contracts in progress. These are being amortized at an accelerated rate due to the short term nature of the contracts.

Interest expense, net

Interest expense, net of interest income, increased by $6.9 million to $7.8 million for the quarter 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.

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 NACGI. The management fee was paid in reference to taxable income.

5

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2004

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 (gain) loss is relatively small and relates primarily to the exchange differences between the Canadian and US dollar for a US dollar denominated bank account. The US dollar denominated senior notes are effectively hedged with the cross currency swap and accordingly, no gain or loss is reflected in respect of this debt.

Segmented Results of Operations

Our 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, net of interest income, and management fees.

6

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2004

Segmented Results of Operations

($ in thousands)	Quarter ended June 30, 2004				Quarter ended June 30, 2003
Revenue
Mining and Site Preparation	46,410		66.3	%	69,755		74.4	%
Piling	12,713		18.2	%	15,267		16.3	%
Pipeline	10,898		15.6	%	8,708		9.3	%
Total Revenue	70,021		100.0	%	93,730		100.0	%
Operating Profit
Mining and Site Preparation	5,751		12.4	%	7,287		10.4	%
Piling	3,198		25.2	%	3,633		23.8	%
Pipeline	1,830		16.8	%	1,066		12.2	%
Total Operating Profit	10,779		15.4	%	11,986		12.8	%
Unallocated costs
Corporate cost	14,306				12,783
Equipment cost (revenue)	(1,427	)			(864	)
Income (loss) before income taxes	(2,100	)			67
Equipment Hours
Mining and Site Preparation	112,417				150,227
Piling	15,063				19,368
Pipeline	9,954				8,317
Total Equipment Hours	137,434				177,912

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2004

Quarter Ended June 30, 2004 compared to Quarter Ended June 30, 2003

Mining and Site Preparation

Revenue for the quarter ended June 30, 2004 decreased by $23.4 million to $46.4 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 at Syncrude: Upgrader Expansion 1 (“UE1”) and Aurora II. Revenue from our largest project, UE1, decreased by $16.5 million over the comparable quarter in the prior year, while revenue from Aurora II decreased by $6.7 million. 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 oil sands 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 Southwest Quadrant Replacement (“SWQR”) project.

Mining and site preparation segment operating profits decreased by $1.5 million for the quarter ended June 30, 2004 to $5.8 million as compared to $7.3 million for the quarter ended June 30, 2003 primarily due to the lower volume of work in the quarter, partially offset by higher margins. The latter is due to the lower proportion of time and material work.

Piling

Revenue for the quarter ended June 30, 2004 decreased by $2.6 million to $12.7 million as compared to $15.3 million for the quarter ended June 30, 2003. This decrease is largely due to $8.2 million less revenue from the UE1 piling contract compared to the prior year, as work on this project is nearing completion. Offsetting this decrease is $2.1 million revenue from the new Suncor Millenium 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 operating profits decreased by $0.4 million for the quarter ended June 30, 2004 to $3.2 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 $2.2 million to $10.9 million for the quarter ended June 30, 2004 compared to $8.7 million for the prior year. The winter construction program on the EnCana Sierra project in British Columbia extended into the first quarter of fiscal 2005, resulting in this increase.

Pipeline segment operating profits increased by $0.7 million for the quarter ended June 30, 2004 to $1.8 million as compared to $1.0 million for the quarter ended June 30, 2003. The increase in operating profit is primarily attributable to the increase in activity volumes.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

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 $4.1 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. The Company funds its operations and capital expenditures, and satisfies its debt service obligations through operating cash flow and, from borrowings under its revolving credit facility and other external financing.

Investing activities

During the quarter ended June 30, 2004, the Company invested $2.9 million in sustaining capital expenditures, and $8.4 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 million to $18 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

The Company has available $60.0 million, subject to borrowing base limitations, under its $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 have assumed from the Predecessor Company four heavy equipment operating leases.

We are required to make quarterly principal and 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% to 2.5%, or Canadian bankers’ acceptance rate plus 3% 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 below.) Additional prepayments are required under certain

9

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2004

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.”

There are no principal payments required on our 8.75% US$200 million senior notes until maturity. The foreign currency risk relating to both the principal and interest payments has been effectively hedged with a cross currency swap and interest rate swaps which went into effect concurrent with the acquisition. The 8.75% rate of interest on the 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 every year until the notes mature on December 1, 2011.

The senior notes were issued pursuant to a private placement. The terms of the indenture governing the notes, require the Company to register substantially identical notes with the United States Securities 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 the Company must pay additional interest expense to the holders of the notes. The Company has not yet completed the registration and exchange and has thus incurred additional interest in the amount of $.05 million in the quarter ended June 30, 2004. We expect the registration will be effective late August 2004 after which the exchange offer will commence.

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 credit facility is secured by substantially all of our assets and those of our subsidiaries, including accounts receivable and capital assets.

In anticipation of the likelihood of not being able to meet several of the financial covenants originally set forth in our bank credit agreement for the quarter ending June 30, 2004, we and the required number of our bank lenders amended our bank credit agreement effective as of June 30, 2004 to (a) decrease the minimum fixed charge coverage ratio through June 30, 2004 from 1.25:1.00 to 1.025:1.00, (b) decrease the minimum interest coverage ratio through June 30, 2004 from 2.25:1.00 to 1.75:1.00, (c) increase the maximum total leverage ratio on June 30, 2004 from 4.25:1.00 to 5.25:1.00, and (d) decrease the minimum consolidated earnings before interest, taxes, depreciation and amortization (“EBITDA”) from $67.5 million to $58.0 million. The covenants were also amended for subsequent quarters in the fiscal year ending March 31, 2005.

As of June 30, 2004, the Company had a cash balance of $19.3 million.

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.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2004

Contractual Obligations and Other Commitments

		June 30,
($ in thousands)	Total	2005	2006	2007	2008	2009 and after
Long-term debt	310,000	8,500	11,000	11,000	11,000	268,500
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	321,488	12,898	14,172	13,830	12,042	268,546

^(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 18 to the interim consolidated financial statements.

Recent U.S. accounting pronouncements

In December 2003, the U.S. Financial Accounting Standards Board, or “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. 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, FIN 46R will be applied beginning on January 1, 2005. For any VIEs that must be consolidated under FIN 46R that were created before January 1, 2004, the assets, liabilities and noncontrolling interests of the VIE initially would be measured at their carrying amounts with any difference between the net amount added to the balance sheet and any previously recognized interest being recognized as the cumulative effect of an accounting change. If determining the carrying amounts is not practicable, fair value at the date FIN 46R first applies may be used to measure the assets, liabilities and noncontrolling interest of the VIE. The adoption of this standard is not expected to have a material impact on these financial statements.

FASB Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, was issued in May 2003. This Statement establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. The Statement also includes required disclosures for financial instruments within its scope. For the Company, the Statement will be effective as of January 1, 2004, except for mandatorily redeemable financial instruments. For certain mandatorily redeemable financial instruments, the Statement will be effective for the Company on January 1, 2005. The effective date has been

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2004

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.

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 hedge this risk. The hedging instrument 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.

We are also subject to interest rate market risk in connection with our senior credit facility. The facility bears interest at variable rates based on the Canadian prime rate plus 2% to 2.5% or Canadian bankers’ acceptance rate plus 3% to 3.5%. Each 1% 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 and decreasing thereafter as the principal is repaid. Assuming the revolving credit facility is fully drawn at $60 million, each 1% increase or decrease in the applicable interest rate would change the interest cost by $0.6 million 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.

12

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/ Gordon Parchewsky
Name:	Gordon Parchewsky
Title:	President

Date: August 26, 2004