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 three and six months ended September 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 three and six months ended September 30, 2004 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 three and six months ended September 30, 2004 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 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 in the derivative instruments for 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 three and six months ended September 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 November 29, 2004.

Included herein:

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

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

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Balance Sheet

(in thousands of Canadian dollars)

	September 30, 2004			March 31, 2004
	(Unaudited) Restated (note 3)			Restated (note 3)
Assets
Current assets:
Cash and cash equivalents	$	16,430		$	36,595
Accounts receivable		26,843			33,647
Unbilled revenue		38,232			27,676
Inventory		1,694			1,609
Prepaid expenses		711			1,272
		83,910			100,799
Capital assets		174,366			167,905
Goodwill		198,549			198,549
Intangible assets, net of accumulated amortization of $15,414		2,383			4,870
Deferred financing costs, net of accumulated amortization of $2,069		16,646			17,266
Future income taxes		9,450			285
	$	485,304		$	489,674
Liabilities and Shareholder’s Equity
Current liabilities:
Accounts payable	$	33,863		$	29,301
Accrued liabilities		10,744			14,694
Current portion of term credit facility (note 8)		9,750			7,250
Current portion of capital lease obligations		1,147			787
Term credit facility scheduled repayments due beyond one year (note 8)		35,750			—
Future income taxes		8,600			5,260
		99,854			57,292
Term credit facility (note 8)		—			41,250
Capital lease obligations		3,544			2,251
Senior notes		252,320			262,260
Derivative financial instruments		23,490			11,266
Advances from parent company (note 9)		288			—
Shareholder’s equity:
Share capital (note 10)		127,500			127,500
Contributed surplus		365			137
Deficit		(22,057	)		(12,282	)
		105,808			115,355
Basis of presentation - future operations (note 1)
Subsequent event (note 8(b))
United States generally accepted accounting principles (note 11)
	$	485,304		$	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)

	Three months ended September 30						Six months ended September 30
	2004			Predecessor Company 2003			2004			Predecessor Company 2003
	Restated (note 3)						Restated (note 3)
Revenue	$	82,681		$	102,282		$	153,540		$	196,012
Project costs		54,885			61,735			100,923			118,145
Equipment costs		12,896			20,909			25,098			42,905
Depreciation		5,141			2,827			9,660			5,389
		72,922			85,471			135,681			166,439
Gross profit		9,759			16,811			17,859			29,573
General and administrative		4,956			2,804			9,995			5,827
Loss (gain) on disposal of capital assets		255			21			249			(49	)
Amortization of intangible assets		1,057			—			2,487			—
Operating income		3,491			13,986			5,128			23,795
Management fees		—			14,200			—			23,200
Interest expense		7,874			1,069			15,205			2,016
Foreign exchange (gain) loss		(14,096	)		7			(9,442	)		(1	)
Other income		(78	)		(139	)		(224	)		(336	)
Realized and unrealized (gain) loss in derivative financial instruments		16,077			—			13,546			—
		9,777			15,137			19,085			24,879
Loss before income taxes		(6,286	)		(1,151	)		(13,957	)		(1,084	)
Income taxes:
Current income taxes		830			87			1,643			205
Future income taxes		(2,425	)		(690	)		(5,825	)		(665	)
		(1,595	)		(603	)		(4,182	)		(460	)
Net loss		(4,691	)		(548	)		(9,775	)		(624	)
Retained earnings (deficit), beginning of period		(17,366	)		29,741			(12,282	)		29,817
Retained earnings (deficit), end of period	$	(22,057	)	$	29,193		$	(22,057	)	$	29,193

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)

	Three months ended September 30						Six months ended September 30
	2004			Predecessor Company 2003			2004			Predecessor Company 2003
	Restated (note 3)						Restated (note 3)
Cash provided by (used in):
Operating activities:
Net loss	$	(4,691	)	$	(548	)	$	(9,775	)	$	(624	)
Items not affecting cash:
Depreciation		5,141			2,827			9,660			5,389
Amortization of intangible assets		1,057			—			2,487			—
Amortization of deferred financing costs		629			—			1,254			—
Loss (gain) on disposal of capital assets		255			21			249			(49	)
Increase (decrease) in allowance for doubtful accounts		21			22			(112	)		39
Foreign exchange gain on senior notes		(14,440	)		—			(9,940	)		—
Unrealized change in fair value of derivative financial instruments		15,410			—			12,224			—
Stock based compensation expense		116			—			228			—
Future income taxes		(2,425	)		(690	)		(5,825	)		(665	)
Net changes in non-cash working capital (note 4(b))		862			3,729			(2,552	)		13,259
		1,935			5,361			(2,102	)		17,349
Investing activities:
Purchase of capital assets		(3,044	)		(3,383	)		(14,413	)		(4,946	)
Proceeds on disposal of capital assets		30			348			134			603
		(3,014	)		(3,035	)		(14,279	)		(4,343	)
Financing activities:
Repayment of term credit facility		(1,500	)		(1,659	)		(3,000	)		(3,334	)
Repayment of capital lease obligations		(164	)		(1,244	)		(438	)		(2,522	)
Financing costs		(454	)		—			(634	)		—
Advances from parent company		288			—			288			—
Decrease in operating line of credit		—			—			—			(516	)
Decrease in cheques issued in excess of cash deposits		—			—			—			(2,496	)
Advances (to) from Norama Inc.		—			(332	)		—			3,225
		(1,830	)		(3,235	)		(3,784	)		(5,643	)
Increase (decrease) in cash and cash equivalents		(2,909	)		(909	)		(20,165	)		7,363
Cash and cash equivalents, beginning of period		19,339			8,272			36,595			—
Cash and cash equivalents, end of period	$	16,430		$	7,363		$	16,430		$	7,363

See accompanying notes to interim consolidated financial statements.

3

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

1. Basis of presentation - future operations

These unaudited interim consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”) for interim financial statements and do not include all of the disclosures normally contained in the Company’s annual consolidated financial statements. Since the determination of many assets, liabilities, revenues and expenses is dependent on future events, the preparation of these unaudited interim financial statements requires the use of estimates and assumptions. In the opinion of management, these unaudited interim financial statements have been prepared within reasonable limits of materiality. Except as noted below, these unaudited interim financial statements follow the same significant accounting policies as described and used in the most recent annual consolidated financial statements of the Company for the year ended March 31, 2004 and should be read in conjunction with those financial statements.

These consolidated financial statements have been prepared on a going concern basis in accordance with Canadian GAAP. The going concern basis of presentation reflects the assumption that the Company will continue in operation for a reasonable period of time and will be able to realize its assets and discharge its liabilities and commitments in the normal course of business.

As discussed in note 8, at September 30, 2004, the Company would have been in breach of several financial covenants under its Credit Agreement without a series of waivers from its lenders. Without the waivers, the lenders would have the right to demand immediate repayment of all amounts outstanding under the facility. There is uncertainty with respect to the ability of the Company to comply with its debt covenants during the next twelve months without an amendment or waiver of the covenants. As a result, the Company has reclassified the term credit facility’s scheduled repayments due beyond one year as current. Management is currently exploring alternatives to resolve the issue, including seeking alternate financing sources; however, there is no certainty that their efforts will be successful.

The ability of the Company to continue as a going concern and to realize the carrying value of its assets and discharge its liabilities when due, is dependent upon the Company’s ability to find new sources of financing or its ability to negotiate a significant amendment to the current covenants that would result in the full amount of the revolving credit facility becoming available. These financial statements do not reflect adjustments that would be necessary if the going concern assumption were not appropriate. If the going concern basis was not appropriate for these financial statements, then significant adjustments would likely be necessary in the carrying value of assets and liabilities, the reporting revenues and expenses, and the balance sheet classifications used.

The comparative information presented for the three-month and six-month periods ended September 30, 2003 reflect the results of operations of Norama Ltd. (“Norama” or the “Predecessor Company”) preceding the acquisition that occurred on November 26, 2003. The comparative results presented may not be directly comparable to the Company’s results for the three-month and six-month periods ended September 30, 2004 due to the buy-out of equipment leases and the effect of the revaluation of

4

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

assets and liabilities to their estimated fair market values in accordance with the application of accounting standards related to purchase accounting.

The Company proportionally consolidates the assets, liabilities, revenues, expenses and cash flows of joint ventures in which it has an investment.

2. Accounting policy changes

a) Hedging relationships:

Effective November 26, 2003, the Company prospectively adopted the provisions of the Canadian Institute of Chartered Accountants’ 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.

b) Revenue recognition:

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

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.

5

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

These interim consolidated financial statements for the three and six months ended September 30, 2004 reflect the following adjustments related to the first restatement:

a) Cost cut-off:

Project costs, equipment costs, general and administrative expenses, deferred financing costs and capital assets were increased by $2,512 for the three months and $7,209 for the six months ended September 30, 2004 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 and six months ended September 30, 2004.

b) Revenue:

Revenue has been increased by $80 for the three months ended September 30, 2004 and $1,477 for the six months ended September 30, 2004 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 $989 for the three months and $1,752 for the six months ended September 30, 2004 in respect to data incorrectly processed through the Company’s billing system.

6

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

c) Component capitalization:

The Company’s capital asset policy 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 $722 for the three months and $1,083 for the six months ended September 30, 2004 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 $117 for the three months and $217 for the six months ended September 30, 2004 has been reversed.

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 loss carry forward balance.

f) Joint venture:

Due to an increase in the Company’s proportionate economic interest in a joint venture from 50% to 70%, revenue has been increased by $826 for the three months ended September 30, 2004 and $1,031 for the six months ended September 30, 2004, and project costs have increased by $623 for the three months ended September 30, 2004 and $1,494 for the six months ended September 30, 2004. This also resulted in an increase in the Company’s proportionate share of cash and cash equivalents, accounts receivable, unbilled revenue, accounts payable and accrued liabilities as at September 30, 2004.

g) Reclassifications:

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

7

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

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 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 8¾ % 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 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 8) 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 September 30, 2004	As previously reported			First restatement			As restated			Second restatement			As restated
Revenue	$	82,764		$	(83	)	$	82,681		$	—		$	82,681
Project costs		52,318			2,567			54,885			—			54,885
Equipment costs		13,691			(795	)		12,896			—			12,896
Gross profit		11,614			(1,855	)		9,759			—			9,759
General and administrative		4,777			179			4,956			—			4,956
Operating income		5,525			(2,034	)		3,491			—			3,491
Interest expense		8,541			—			8,541			(667	)		7,874
Foreign exchange loss		344			—			344			(14,440	)		(14,096	)
Realized and unrealized (gains) losses on derivative financial instruments		—			—			—			16,077			16,077
Loss before income taxes		(3,282	)		(2,034	)		(5,316	)		(970	)		(6,286	)
Future income taxes		(2,150	)		(475	)		(2,625	)		200			(2,425	)
Net loss	$	(1,962	)	$	(1,559	)	$	(3,521	)	$	(1,170	)	$	(4,691	)
For the six months ended September 30, 2004	As previously reported			First restatement			As restated			Second restatement			As restated
Revenue	$	152,785		$	755		$	153,540		$	—		$	153,540
Project costs		94,739			6,184			100,923			—			100,923
Equipment costs		24,572			526			25,098			—			25,098
Gross profit		23,814			(5,955	)		17,859			—			17,859
General and administrative		9,659			336			9,995			—			9,995
Operating income		11,419			(6,291	)		5,128			—			5,128
Interest expense		16,527			—			16,527			(1,322	)		15,205
Foreign exchange loss (gain)		498			—			498			(9,940	)		(9,442	)
Realized and unrealized (gains) losses on derivative financial instruments		—			—			—			13,546			13,546
Loss before income taxes		(5,382	)		(6,291	)		(11,673	)		(2,284	)		(13,957	)
Future income taxes		(3,965	)		(1,760	)		(5,725	)		(100	)		(5,825	)
Net loss	$	(3,060	)	$	(4,531	)	$	(7,591	)	$	(2,184	)	$	(9,775	)

8

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

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

As at September 30, 2004	As previously reported			First restatement			As restated			Second restatement			As restated
Cash and cash equivalents	$	16,318		$	112		$	16,430		$	—		$	16,430
Accounts receivable		29,076			(2,233	)		26,843			—			26,843
Unbilled revenue		36,854			1,378			38,232			—			38,232
Deferred financing costs		16,305			341			16,646			—			16,646
Future income taxes		4,435			2,115			6,550			2,900			9,450
Capital assets		173,461			905			174,366			—			174,366
Accounts payable		21,873			11,990			33,863			—			33,863
Accrued liabilities		15,930			(5,186	)		10,744			—			10,744
Future income taxes		8,245			355			8,600			—			8,600
Derivative financial instruments		10,680			—			10,680			12,810			23,490
Advances from parent company		298			(10	)		288			—			288
Deficit	$	(7,616	)	$	(4,531	)	$	(12,147	)	$	(9,910	)	$	(22,057	)

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 September 30, 2004	As previously reported			First restatement			As restated			Second restatement			As restated
Net loss	$	(1,962	)	$	(1,559	)	$	(3,521	)	$	(1,170	)	$	(4,691	)
Foreign exchange gain on senior notes		—			—			—			(14,440	)		(14,440	)
Unrealized change in fair value of derivative financial instruments		—			—			—			15,410			15,410
Future income taxes		(2,150	)		(475	)		(2,625	)		200			(2,425	)
Net changes in non-cash working capital		(2,478	)		3,340			862			—			862
Purchase of capital assets		(2,201	)		(843	)		(3,044	)		—			(3,044	)
Financing costs		(113	)		(341	)		(454	)		—			(454	)
Advances from parent company	$	298		$	(10	)	$	288		$	—		$	288
For the six months ended September 30, 2004	As previously reported			First restatement			As restated			Second restatement			As restated
Net loss	$	(3,060	)	$	(4,531	)	$	(7,591	)	$	(2,184	)	$	(9,775	)
Foreign exchange gain on senior notes		—			—			—			(9,940	)		(9,940	)
Unrealized change in fair value of derivative financial instruments		—			—			—			12,224			12,224
Future income taxes		(3,965	)		(1,760	)		(5,725	)		100			(5,825	)
Net changes in non-cash working capital		(10,211	)		7,659			(2,552	)		—			(2,552	)
Purchase of capital assets		(13,508	)		(905	)		(14,413	)		—			(14,413	)
Financing costs		(293	)		(341	)		(634	)		—			(634	)
Advances from parent company	$	298		$	(10	)	$	288		$	—		$	288

9

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

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

For the three months ended September 30, 2004	Mining & Site Preparation			Piling			Pipeline		Total
Revenue, as previously reported	$	62,981		$	17,346		$	2,437	$	82,764
First restatement		(367	)		36			248		(83	)
Revenue, as restated		62,614			17,382			2,685		82,681
Second restatement		—			—			—		—
Revenue, as restated	$	62,614		$	17,382		$	2,685	$	82,681
For the three months ended September 30, 2004	Mining & Site Preparation			Piling			Pipeline		Total
Segment profits, as previously reported	$	5,353		$	3,727		$	84	$	9,164
First restatement		209			75			267		551
Segment profits, as restated		5,562			3,802			351		9,715
Second restatement		—			—			—		—
Segment profits, as restated	$	5,562		$	3,802		$	351	$	9,715
For the six months ended September 30, 2004	Mining & Site Preparation			Piling			Pipeline		Total
Revenue, as previously reported	$	109,393		$	30,058		$	13,334	$	152,785
First restatement		(16	)		581			190		755
Revenue, as restated		109,377			30,639			13,524		153,540
Second restatement		—			—			—		—
Revenue, as restated	$	109,377		$	30,639		$	13,524	$	153,540
For the six months ended September 30, 2004	Mining & Site Preparation			Piling			Pipeline		Total
Segment profits, as previously reported	$	8,017		$	6,925		$	1,914	$	16,856
First restatement		1,036			(145	)		74		965
Segment profits, as restated		9,053			6,780			1,988		17,821
Second restatement		—			—			—		—
Segment profits, as restated	$	9,053		$	6,780		$	1,988	$	17,821

10

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

4. Other information

a) Supplemental cash flow information:

	Three months ended September 30				Six months ended September 30
	2004		Predecessor Company 2003		2004		Predecessor Company 2003
Cash paid during the period for:
Interest	$	1,473	$	996	$	15,753	$	1,921
Income taxes		1,452		92		3,183		307
Cash received during the period for:
Interest		77		56		273		90
Income taxes		—		—		—		—
Non-cash transactions:
Capital leases	$	1,382	$	—	$	2,091	$	—

b) Net change in non-cash working capital:

	Three months ended September 30						Six months ended September 30
	2004			Predecessor Company 2003			2004			Predecessor Company 2003
	Restated (note 3)						Restated (note 3)
Accounts receivable	$	9,339		$	18,508		$	6,916		$	16,583
Unbilled revenue		(25,671	)		(12,022	)		(10,556	)		11,693
Inventory		(499	)		—			(85	)		—
Prepaid expenses		494			355			561			(548	)
Accounts payable		11,249			(1,104	)		4,562			(10,731	)
Accrued liabilities		5,950			(2,008	)		(3,950	)		(3,738	)
	$	862		$	3,729		$	(2,552	)	$	13,259

11

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

c) 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:

	September 30, 2004
	Restated (note 3)
Assets
Cash	$	397
Accounts receivable		1,024
Unbilled revenue		36
	$	1,457
Liabilities
Accounts payable	$	808
Venturer’s equity		649
	$	1,457

	Three months ended September 30					Six months ended September 30
	2004			Predecessor Company 2003		2004			Predecessor Company 2003
	Restated (note 3)					Restated (note 3)
Revenue	$	2,890		$	—	$	3,606		$	—
Project costs		3,067			—		4,733			—
Net loss	$	(177	)	$	—	$	(1,127	)	$	—

	Three months ended September 30					Six months ended September 30
	2004			Predecessor Company 2003		2004			Predecessor Company 2003
	Restated (note 3)					Restated (note 3)
Cash used in:
Operating activities	$	(431	)	$	—	$	(1,376	)	$	—
Investing activities		—			—		—			—
Financing activities		823			—		1,771			—
	$	392		$	—	$	395		$	—

The Company was contingently liable at September 30, 2004 for obligations of its incorporated joint venture totaling $346 (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.

12

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

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 and six-month periods ended September 30, 2004, the Company provided $1,797 and $2,510 of labour and equipment services to the joint venture, respectively (three-month and six-month periods ended September 30, 2003 - $nil). Additionally the Company recovered costs of $196 and $268 from the joint venture for the three-month and six-month periods ended September 30, 2004 (three-month and six-month periods ended September 30, 2003 - $nil).

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

5. Segmented information

a) General overview:

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

• Mining and Site Preparation:

The Mining and Site Preparation operating 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 operating segment provides deep foundation construction and design-build services to a variety of industrial and commercial customers throughout Western Canada.

• Pipeline:

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

b) Results by operating segment:

For the three months ended September 30, 2004	Mining and Site Preparation		Piling		Pipeline		Total
Restated (note 3)
Revenues from external customers	$	62,614	$	17,382	$	2,685	$	82,681
Depreciation of capital assets		2,547		711		32		3,290
Segment profits		5,562		3,802		351		9,715
Segment assets		297,009		81,201		43,099		421,309
Expenditures for segment capital assets		1,991		—		—		1,991

Predecessor Company For the three months ended September 30, 2003	Mining and Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	77,734	$	15,585	$	8,963	$	102,282
Depreciation of capital assets		1,676		527		61		2,264
Segment profits		7,243		3,720		1,865		12,828
Segment assets		79,631		33,914		4,683		118,228
Expenditures for segment capital assets		2,219		175		—		2,394

13

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

For the six months ended September 30, 2004	Mining and Site Preparation		Piling		Pipeline		Total
Restated (note 3)
Revenues from external customers	$	109,377	$	30,639	$	13,524	$	153,540
Depreciation of capital assets		4,754		1,320		88		6,162
Segment profits		9,053		6,780		1,988		17,821
Segment assets		297,009		81,201		43,099		421,309
Expenditures for segment capital assets		12,634		58		—		12,692

Predecessor Company For the six months ended September 30, 2003	Mining and Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	147,489	$	30,852	$	17,671	$	196,012
Depreciation of capital assets		1,726		813		68		2,607
Segment profits		14,460		7,353		2,931		24,744
Segment assets		79,631		33,914		4,683		118,228
Expenditures for segment capital assets		2,709		491		—		3,200

c) Reconciliations:

(i) Income (loss) before income taxes:

	Three months ended September 30						Six months ended September 30
	2004			Predecessor Company 2003			2004			Predecessor Company 2003
	Restated (note 3)						Restated (note 3)
Total profit for reportable segments	$	9,715		$	12,828		$	17,821		$	24,744
Unallocated corporate expenses		(15,773	)		(17,962	)		(31,482	)		(30,744	)
Unallocated equipment revenue (cost)		(228	)		3,983			(296	)		4,916
Loss before income taxes	$	(6,286	)	$	(1,151	)	$	(13,957	)	$	(1,084	)

(ii) Total assets:

	September 30, 2004		March 31, 2004
	Restated (note 3)		Restated (note 3)
Total assets for reportable segments	$	421,309	$	410,469
Corporate assets		63,995		79,205
Total assets	$	485,304	$	489,674

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

14

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

6. 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 percent vest on each of the five following award date anniversaries. The maximum number of common shares presently authorized under this plan is 92,500, of which 24,258 are still available for issue as at September 30, 2004. As at September 30, 2004, none of these 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 percent; a risk-free interest rate of 4.72 percent; volatility of nil percent; and an expected option life of 10 years.

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

	Number of options	Weighted average exercise price $ per share
Outstanding at June 30, 2004	58,742	100.00
Granted	9,500	100.00
Exercised	—
Forfeited	—
Outstanding at September 30, 2004	68,242	100.00

The Company recorded $116 of compensation expense related to the stock options during the three months ended September 30, 2004 (six months ended September 30, 2004 – $228) with such amount being credited to contributed surplus.

7. Comparative figures

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

8. 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

15

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

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 specified maximum levels. The indebtedness under the senior secured credit facility is secured by substantially all of the Company’s assets and those of its subsidiaries, including accounts receivable and capital assets. As of September 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 $45.5 million outstanding under the term loan portion of the senior secured credit facility at September 30, 2004.

b) Subsequent event:

After becoming aware of the misstatements as described in note 3, the Company’s management informed the lenders under the Credit Agreement of the Company’s potential breach of various covenants under the Credit Agreement. 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 covenant 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. During the waiver period, the lending banks under the senior secured credit facility will not provide any additional funding. The revolving credit facility would otherwise provide the Company with available 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 current financial information regarding its operations than currently required by the Credit Agreement and cooperate with a third party engaged by the lenders to evaluate the Company’s accounting and control procedures surrounding the causes for the misstatements described herein and to review the Company’s current customer contracts.

At September 30, 2004, without the waivers referred to above, the Company would have been in breach of several financial covenants under the Credit Agreement as a result of the restatement adjustments recorded for the six-month period ended September 30, 2004. The specific financial covenants in question were all based on EBITDA measured over a trailing twelve-month period. Under the terms of the Credit Agreement, a breach of covenants constitutes an event of default giving the lenders the right to demand immediate repayment of all amounts outstanding under the senior secured credit facility.

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

16

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

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.

c) Current classification:

The Company has 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.

9. Related party balance

Advances from parent company of $288 as at September 30, 2004 represents a non-interest bearing note payable to the Company’s parent, NACG Holdings Inc. The note was transacted in the normal course of operations and recorded at the exchange value and on terms as agreed to by the parties. The note payable contains no specified repayment terms.

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 September 30, 2004	100	$	127,500

17

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

11. United States generally accepted accounting principles (“U.S. GAAP”) (Restated)

These interim consolidated financial statements have been prepared in accordance with Canadian GAAP which differs in certain respects from U.S. GAAP. For the periods presented herein, material issues that could give rise to measurement differences in the interim 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 are 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 Company’s 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 4(c) the major components of its financial statements resulting from the use of the proportionate consolidation method to account for its interests in joint ventures.

18

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three and six months ended September 30, 2004

Management’s Discussion and Analysis (Restated)

Three-month and Six-month Periods Ended September 30, 2004

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 facts, and can be identified by the use of the future tense or other forward-looking words such as “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “should,” “may,” “objective,” “projection,” “forecast,” “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 markets 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 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 and six months ended September 30, 2004. As a result, our financial statements for such periods 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 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

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three and six months ended September 30, 2004

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 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. Additionally, we previously understated our proportionate share of revenues related to our interest in a joint venture. Finally, we reduced the management bonus provision accordingly in light of the reduction in earnings resulting from the restatement adjustments. The net total amount of additional project, equipment, and general and administrative costs reflected in the restated financial statements is $2.0 million and $7.0 million, respectively, for the three months and six months ended September 30, 2004.

In addition to the increase in costs resulting from our review, several errors related to revenues were also discovered. Certain of the unrecorded costs described above that should have been recorded in the three months and six months ended September 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 and six months ended September 30, 2004 resulted in an understatement of 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 offset by an overstatement of revenues primarily from one customer due to incorrect billing rates as well as duplicate and non-billable transactions in our financial systems. We recorded net total restatement adjustments which reduced revenue by $0.1 million for the three months ended September 30, 2004 and increased revenue by $0.8 million for the six months ended September 30, 2004.

All of the adjustments resulted in increases in the recovery of future income taxes of approximately $0.5 million and $1.8 million and increases in the net loss of $1.6 million and $4.5 million, respectively, for the three months and six months ended September 30, 2004.

Certain amounts were reclassified in connection with the restatement of the interim consolidated financial statements for the three months and six months ended September 30, 2004 in order to conform with the current classification of the related amounts in the interim consolidated financial statements for the nine months ended December 31, 2004.

2

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three and six months ended September 30, 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 also 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. $ denominated 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 in the derivative instruments for each period through the Consolidated Statement 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 8¾% 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 services primarily to major oil and gas, petrochemical, and other natural resource companies operating in Western Canada. These services are offered through three operating segments: Mining and Site Preparation, Piling, and Pipeline. The Mining and Site Preparation operating segment is involved in a variety of activities, including: surface mining for oilsands and other natural resources; overburden removal; hauling sand and gravel; supplying labor and equipment to support the customer’s mining operations; construction of infrastructure associated with mining operations and reclamation activities; clearing, stripping, excavating, and grading for mining operations and other general construction projects; and underground utility installation for plant, refinery, and commercial building construction. The Piling operating segment installs all types of driven and drilled piles, caissons, and earth retention and stabilization systems for commercial buildings, private industrial projects, and infrastructure projects. The Pipeline operating segment installs transmission and distribution pipe made of steel, plastic, and fiberglass materials in sizes up to, and including, 36 inches in diameter for oil and gas transmission.

We have been operating for over 50 years and maintain one of the largest independently-owned equipment fleets in Western Canada. In serving our customers, we operate over 400 pieces of heavy construction equipment and almost 500 support vehicles. Our fleet size provides flexibility in scheduling and completing contract services on a timely basis and allows us to undertake long-term, large-scale projects with major operators in oilsands development and other energy sectors.

The comparative information presented for the three-month and six-month periods ended September 30, 2003 are the results of operations of Norama Ltd. (“Norama” or the “Predecessor Company”) preceding the acquisition that occurred on November 26, 2003. The information as of September 30, 2004 may not be directly comparable to the information provided for the Predecessor Company as a result of the buy-out of equipment leases and the effect of the revaluation of assets and liabilities to their estimated fair market values in accordance with the application of

3

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three and six months ended September 30, 2004

purchase accounting pursuant to Canadian and United States (“U.S.”) generally accepted accounting principles (“GAAP”).

Consolidated Financial Results

	Three months ended September 30										Six months ended September 30
(in millions of Canadian dollars)	2004					Predecessor Company 2003					2004					Predecessor Company 2003
	(Restated)1										(Restated)
Revenue	$	82.7		100.0	%	$	102.3		100.0	%	$	153.5		100.0	%	$	196.0		100.0	%
Project costs		54.9		66.4	%		61.7		60.3	%		100.9		65.7	%		118.1		60.3	%
Equipment costs		12.9		15.6	%		20.9		20.4	%		25.1		16.4	%		42.9		21.9	%
Depreciation		5.1		6.2	%		2.8		2.7	%		9.7		6.3	%		5.4		2.8	%
Gross profit		9.8		11.9	%		16.9		16.5	%		17.8		11.6	%		29.6		15.1	%
General and administrative		4.9		5.9	%		2.8		2.7	%		10.0		6.5	%		5.9		3.0	%
Loss (gain) on disposal of capital assets		0.3		0.4	%		—		0.0	%		0.2		0.1	%		(0.1	)	-0.1	%
Amortization of intangible assets		1.1		1.3	%		—		0.0	%		2.5		1.6	%		—		0.0	%
Operating income		3.5		4.2	%		14.1		13.8	%		5.1		3.3	%		23.8		12.1	%
Management fees		—		0.0	%		14.2		13.9	%		—		0.0	%		23.2		11.8	%
Interest expense		7.9		9.6	%		1.1		1.1	%		15.2		9.9	%		2.0		1.0	%
Foreign exchange loss (gain)		(14.1	)	-17.0	%		—		0.0	%		(9.4	)	-6.1	%		—		0.0	%
Other income		(0.1	)	-0.1	%		(0.1	)	-0.1	%		(0.3	)	-0.2	%		(0.3	)	-0.2	%
Realized and unrealized (gain) loss on derivative financial instruments		16.1		19.5	%		—		0.0	%		13.5		8.8	%		—		0.0	%
Loss before income taxes	$	(6.3	)	-7.8	%	$	(1.1	)	-1.1	%	$	(13.9	)	-9.1	%	$	(1.1	)	-0.6	%

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

Revenue

Revenue for the three-month and six-month periods ended September 30, 2004 decreased by $19.6 million (19.2 percent) and $42.5 million (21.7 percent), respectively, from the comparative periods. A significant amount of the earthworks, underground, and piling portions of Syncrude Canada Ltd.’s (“Syncrude”) Upgrader Expansion 1 (“UE1”) project was completed in the prior year, which contributed to the lower revenue in the current periods. Revenue also decreased due to the reduction in the use of our services by Albian Sands Energy Inc. under the mining services contract. Decreases in revenue from these projects were partially offset with revenue from new projects, including: the OPTI/Nexen Long Lake steam assisted gravity drainage site project; the mining services contract for Grande Cache Coal Corporation; and Syncrude’s Southwest Quadrant Replacement (“SWQR”) project. The deferral of capital infrastructure projects by our major pipeline customer also contributed to decreased revenue from the comparative periods.

Project costs

Project costs for the three-month and six-month periods ended September 30, 2004 decreased by $6.9 million (11.1 percent) and $17.2 million (14.6 percent), respectively, from the comparative periods. These decreases were primarily a result of the lower volume of services provided during these periods. As a percentage of revenue, project costs increased by 6.1 percent and 5.4 percent, respectively, for the three-month and six-month periods ended September 30, 2004, from the comparative periods. The increases were mainly a result of the high costs related to two poor-performing projects that commenced in the first fiscal quarter.

Equipment costs

Equipment costs for the three-month and six-month periods ended September 30, 2004 decreased by $8.0 million (38.3 percent) and $17.8 million (41.5 percent), respectively, from the comparative periods due to lower lease and

4

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three and six months ended September 30, 2004

rental expense as a result of the buy-out of most leases and rentals concurrent with the acquisition on November 26, 2003.

Depreciation

Depreciation expense for the three-month and six-month periods ended September 30, 2004 increased from the corresponding periods in the prior year due primarily to the revaluation of assets to their estimated fair market values in accordance with the application of purchase accounting in connection with the acquisition on November 26, 2003. The addition of new equipment resulting from the buy-out of the leases in November 2003 also contributed to the increased depreciation expense for the three-month and six-month periods ended September 30, 2004. Partially offsetting these increases was a decrease in heavy equipment hours from the comparable periods in the prior year.

General and administrative expenses

General and administrative expenses increased by $2.2 million (76.7 percent) and $4.2 million (71.5 percent), respectively, as compared to prior periods. The increase was primarily attributable to higher staff levels and salary increases, increased travel costs, increased insurance and consultant costs, and new expenses related to the change in ownership (Board of Directors’ costs, advisory fees, and stock-based compensation expense).

Amortization of intangible assets

Amortization of intangible assets related to the customer contracts in progress, trade names, non-competition agreement, and employee arrangements that were acquired in the acquisition on November 26, 2003. Substantially all of the cost of the intangible assets has been amortized at September 30, 2004 as the majority of the cost relates to customer contracts in progress that are being amortized at a rapid rate due to the short-term nature of the contracts.

Management fees

Management fee expense was $nil for the three-month and six-month periods ended September 30, 2004 as compared to $14.2 million for the three-month period ended September 30, 2003 and $23.2 million for the six-month period ended September 30, 2003. These fees were charged by Norama Inc., the parent company of Norama, for management services provided to the Predecessor Company. The fees were paid in reference to taxable income. Subsequent to the acquisition, no similar management fees have been paid, and the agreement with Norama Inc. was terminated.

Interest expense

Interest expense for the three-month and six-month periods ended September 30, 2004 increased significantly from the comparative periods in the prior year due to the additional long-term debt (senior notes and senior secured credit facility) issued in connection with the acquisition on November 26, 2003. As well, the average interest rates on the new debt were higher than the interest rates on the debt of the Predecessor Company.

5

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three and six months ended September 30, 2004

Foreign exchange (gain) loss

The foreign exchange gains of $14.1 million and $9.4 million for the three-month and six-month periods ended September 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. In addition, in the three-month period ended September 30, 2004, the payment of foreign exchange on the cancellation of a U.S. dollar forward contract for the purchase of equipment resulted in $0.2 million in foreign exchange loss being recorded. The foreign exchange gains and losses in the comparative periods were 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 and unrealized gains and losses on the Company’s cross-currency and interest rate swap agreements, which do not qualify for hedge accounting, are $0.7 million and $15.4 million, 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 change in fair value of $16.1 million for the three-month period and $13.5 million for the six-month period ended September 30, 2004 related primarily to the mark-to-market change in the fair value of the derivatives in the period.

Comparative Quarterly Results

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

										Predecessor Company
(in millions of Canadian dollars, except equipment hours)	Fiscal Year 2005						Fiscal Year 2004												Fiscal Year 2003
	Q2			Q1			Q4			Q3			Q2			Q1			Q4		Q3
	(Restated)			(Restated)			(Restated)			(Restated)
Revenue	$	82.7		$	70.9		$	102.4		$	79.9		$	102.3		$	93.7		$	115.9	$	90.1
Gross profit		9.8			8.1			19.8			6.5			16.8			12.8			17.6		11.4
Net income (loss)		(4.7	)		(5.1	)		(2.6	)		(20.2	)		(0.5	)		(0.1	)		13.4		(10.5	)
Equipment hours		193,205			137,434			188,557			128,153			200,499			177,939			227,645		171,056

Reduced revenue in the latest two quarters, in comparison to prior periods, was a result of substantial completion of a number of large projects, including UE1, that have not yet been replaced with projects of similar size. There are a number of large capital infrastructure and expansion projects planned by our customers in the near future. Additionally, our current projects are less reliant on large heavy equipment and focus on small equipment and labor which provide lower revenue and margins.

Segmented Results of Operations

We report our operations under three operating segments: Mining and Site Preparation, Piling and Pipeline.

Selected Segmented Information

	Three months ended September 30								Six months ended September 30
(in millions of Canadian dollars, except equipment hours)	2004				Predecessor Company 2003				2004				Predecessor Company 2003
	(Restated)								(Restated)
Revenue by operating segment
Mining and Site Preparation	$	62.6	75.7	%	$	77.7	76.0	%	$	109.4	71.3	%	$	147.5	75.3	%
Piling		17.4	21.0	%		15.6	15.2	%		30.6	19.9	%		30.8	15.7	%
Pipeline		2.7	3.3	%		9.0	8.8	%		13.5	8.8	%		17.7	9.0	%
Total	$	82.7	100.0	%	$	102.3	100.0	%	$	153.5	100.0	%	$	196.0	100.0	%
Profit by operating segment
Mining and Site Preparation	$	5.6	57.1	%	$	7.2	56.3	%	$	9.0	50.6	%	$	14.4	58.3	%
Piling		3.8	38.8	%		3.7	28.9	%		6.8	38.2	%		7.4	30.0	%
Pipeline		0.4	4.1	%		1.9	14.8	%		2.0	11.2	%		2.9	11.7	%
Total	$	9.8	100.0	%	$	12.8	100.0	%	$	17.8	100.0	%	$	24.7	100.0	%
Equipment hours by operating segment
Mining and Site Preparation		172,504	89.3	%		165,097	82.3	%		284,921	86.2	%		315,351	83.3	%
Piling		17,853	9.2	%		21,572	10.8	%		32,916	10.0	%		40,940	10.8	%
Pipeline		2,848	1.5	%		13,830	6.9	%		12,802	3.8	%		22,147	5.9	%
Total		193,205	100.0	%		200,499	100.0	%		330,639	100.0	%		378,438	100.0	%

6

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three and six months ended September 30, 2004

Mining and Site Preparation

Revenue for the three months and six months ended September 30, 2004 decreased by $15.1 million (19.5 percent) and $38.1 million (25.8 percent), respectively, from the corresponding periods in the prior year. The decreases were primarily due to the completion of a significant portion of the earthworks and underground work for the UE1 project in the prior year and a reduction in outsourcing by Albian Sands Energy Inc. on its mining services contract. Revenue from UE1 decreased by $26.3 million over the comparable three-month period in the prior year while revenue from Albian Sands Energy Inc. decreased by $5.7 million. These reductions in revenue were partially offset by revenue from new projects, including the OPTI/Nexen Long Lake project ($17.2 million), the mining services contract for Grande Cache Coal Corporation ($4.3 million), and the SWQR project ($3.2 million).

Profit for the operating segment for the three months and six months ended September 30, 2004 decreased by $1.7 million (23.2 percent) and $5.4 million (37.4 percent), respectively, from the comparative periods. More unit price contracts, which typically provide higher margins and profits than other types of contracts, were undertaken during the current periods than in the comparative periods; however, unforeseen circumstances presented by site and environmental conditions and poor weather reduced the expected margins on these contracts. Additionally, the nature of the work undertaken in the current periods required smaller, less profitable heavy equipment than the work undertaken in the comparative periods.

Piling

Piling revenue increased by $1.8 million (11.5 percent) for the three-month period ended September 30, 2004 and decreased by $0.2 million (0.7 percent) for the six-month period ended September 30, 2004, from the respective, corresponding periods in the prior year. For the three-month period, revenue of $9.3 million from the UE1 piling contract from the prior year was replaced by a number of smaller projects in the current period, including: Suncor Energy Inc.’s (“Suncor”) Millennium Coker Unit; Suncor’s Plant 86 Booster Pump House; EnCana Corporation Foster Creek; and AMEC Americas Ltd.’s portion of the SWQR project.

Piling segment profit increased by $0.1 million (2.2 percent) for the three-month period ended September 30, 2004 and decreased by $0.6 million (7.8 percent) for the six-month period ended September 30, 2004, from the respective comparative periods. The increase in segment profit for the three-month period ended September 30, 2004 was due primarily to the increased volume from the comparative quarter. The decrease in segment profit for the six-month period ended September 30, 2004 was primarily a result of lower volumes in addition to slightly lower margins for the period year-over-year.

Pipeline

Pipeline operating segment revenue for the three-month and six-month periods ended September 30, 2004 decreased by $6.3 million (70.0 percent) and $4.1 million (23.5 percent), respectively, from the comparative periods primarily due to a decrease in work performed for our major pipeline customer.

Profit for this operating segment for the three-month and six-month periods ended September 30, 2004 decreased by $1.5 million (81.2 percent) and $0.9 million (32.2 percent), respectively, from the comparative periods in the prior year primarily as a result of lower revenues as discussed above.

Consolidated Financial Position

At September 30, 2004, our net working capital position was $(15.9) million as compared to $43.5 million at March 31, 2004. Contributing to the decrease were: the reclassification of our term credit facility scheduled repayments due beyond one year to current, as discussed below in the section “Liquidity and Capital Resources”; a reduction in cash and cash equivalents at September 30, 2004 compared to March 31, 2004, as discussed below in the section

7

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three and six months ended September 30, 2004

“Liquidity and Capital Resources”; and a decrease in accounts receivable due to lower activity levels, partially offset by an increase in unbilled revenue. The increase in unbilled revenue was primarily due to billing delays related to the terms of the unit price contract on one of our large new projects. Accounts payable increased by $4.6 million at September 30, 2004 from the balance at the end of the prior year primarily due to a backlog of third party invoices accrued in connection with the first restatement discussed in the “Restatement” section of this MD&A. Accrued liabilities decreased by $4.0 million at September 30, 2004 from the balance at the end of the prior year primarily as a result of lower accrued interest payable.

Capital assets increased by $6.5 million at September 30, 2004 from March 31, 2004 due to the acquisition of equipment for growth in anticipation of several upcoming projects, offset by depreciation expense.

The term credit facility decreased by $3.0 million at September 30, 2004 from the balance at the end of the prior year due to the regularly scheduled quarterly debt repayments. Capital lease obligations, including the current portion, increased by $1.3 million at September 30, 2004 from the balance at March 31, 2004 due to the addition of new vehicle leases to support new projects.

Liquidity and Capital Resources

Operating activities

Cash provided from operating activities for the three-month period ended September 30, 2004 was $1.9 million. Cash provided from operating activities for the Predecessor Company for the three-month period ended September 30, 2003 was $5.4 million. The increase in unbilled revenue due to the billing delay previously discussed was the primary contributor to the decrease.

Investing activities

During the three-month period ended September 30, 2004, we invested $2.1 million in sustaining capital expenditures, $0.9 million in growth capital expenditures, and $1.4 million in new vehicle capital leases. In the six-month period ended September 30, 2004, we invested $3.1 million in sustaining capital expenditures, $11.3 million in growth capital expenditures, and $2.1 million in new vehicle capital leases. 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. Growth capital expenditures are directly related to new projects.

During the three-month period ended September 30, 2003, the Predecessor Company invested $2.5 million in sustaining capital expenditures and $0.9 million in growth capital expenditures. In the six-month period ended September 30, 2003, the Predecessor Company invested $3.7 million in sustaining capital expenditures and $1.2 million in growth capital expenditures.

Our capital requirements during the six-month period ended September 30, 2004 increased due to continued growth and acquisition of new projects. Our capital requirements for the remainder of the 2005 fiscal year include funding operating lease obligations, debt and interest repayment obligations, and working capital as activity levels are expected to increase. In addition, we will require capital to finance further vehicle and equipment acquisitions in the second half of fiscal 2005 for upcoming new projects.

8

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three and six months ended September 30, 2004

Financing activities

Financing activities during the three-month and six-month periods ended September 30, 2004 related primarily to payments made on the term credit facility, capital lease obligations, and additional financing costs incurred.

Financing activities of the Predecessor Company for the three-month period ended September 30, 2003 included payments made on the term credit facility, capital leases, and advances of $0.3 million to Norama Inc. Financing activities of the Predecessor Company for the six-month period ended September 30, 2003 included payments made on the term credit facility and capital leases offset by advances of $3.2 million from Norama Inc.

Liquidity

We refer 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 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 Credit Agreement requires us 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 specified maximum levels. 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 our assets and those of our subsidiaries, including accounts receivable and capital assets. As of September 30, 2004, we 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 $45.5 million outstanding under the term loan portion of the senior secured credit facility at September 30, 2004.

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 the following: 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 covenant 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. During the waiver period, the lending banks under the senior secured credit facility will not provide any additional funding. The revolving credit facility would otherwise provide us with available borrowing capacity up to $70.0 million in total, subject to borrowing base limitations. In addition, during the waiver period, we are 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 lenders to evaluate our accounting and control procedures surrounding the causes for the misstatements described herein and to review our current customer contracts.

At September 30, 2004, without the waivers referred to above, we would have been in breach of several financial covenants under the Credit Agreement as a result of the restatement adjustments recorded for the six-month period ended September 30, 2004. The specific financial covenants in question were all based on EBITDA measured over a trailing twelve-month period. 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.

9

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three and six months ended September 30, 2004

We have 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.

We are required to make quarterly principal and monthly interest payments under our $45.5 million term credit facility which bears interest at a floating rate based upon either the Canadian prime rate plus 2.5 percent or Canadian bankers’ acceptance rate plus 3.5 percent. For the three-month period ended September 30, 2004, the weighted-average interest rate on the term credit facility was 6.3 percent. Additional prepayments are required under certain circumstances, and no new advances are available under the term credit facility.

Our U.S. $200 million of 8¾% senior notes were issued concurrent with the acquisition on November 26, 2003 pursuant to a private placement. On October 5, 2004, we registered substantially identical notes with the United States Securities and Exchange Commission and exchanged them for the notes issued in the private placement. As the registration and exchange were not completed within a specified number of days of the original issuance, as required by a registration rights agreement entered into in connection with the original issuance, we are required to pay additional interest to the holders of the notes in the amount of U.S. $0.2 million on the date of the next interest payment, scheduled for December 1, 2004. Such additional interest payment was made.

There are no principal payments required on the 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 that went into effect concurrent with the issuance. 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 percent rate of interest on the senior notes has been swapped to an effective rate of 9.765 percent for the entire 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.

On January 19, 2005, both Moody’s and Standard & Poor’s lowered our credit ratings. Moody’s lowered its rating of our 8¾% senior notes to B3 from B2 and its rating of our senior secured credit facility to B1 from Ba3. Standard & Poor’s lowered our long-term corporate credit rating to B from B+. In addition, Standard & Poor’s also lowered our senior secured bank facility rating to B+ from BB- and lowered our senior unsecured rating to B- from B. Standard & Poor’s had earlier downgraded our credit ratings on November 5, 2004 when it lowered our long-term corporate credit rating to B+ from BB- and also lowered our senior secured bank facility and senior unsecured ratings to BB- from BB and B from B+ respectively. The lower credit ratings will have no effect on the interest rates associated with our 8¾% senior notes; however, we expect the interest rates under an alternate financing arrangement to be higher than the interest rates presently under the existing senior secured credit facility.

Our principal sources of cash are funds from operations and borrowings under our senior secured credit facility. Our primary uses of cash are to purchase capital assets, fulfill debt repayment obligations, and finance working capital. We continue to lease a portion of our motor vehicle fleet and have assumed several heavy equipment operating leases from the Predecessor Company. It is the opinion of management that operating cash flows will satisfy our working capital requirements in the near-term, even without access to the revolving credit facility; however, we are evaluating several alternatives to address our longer term financing needs.

10

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three and six months ended September 30, 2004

Our ability to continue as a going concern and to realize the carrying value of our assets and discharge our liabilities when due, is dependent upon our ability to find new sources of financing or our ability to negotiate a significant amendment to the current covenants that would result in the full amount of the revolving credit facility becoming available. Our results do not reflect adjustments that would be necessary if this going concern assumption were not appropriate. If this going concern basis was not appropriate, then significant adjustments would likely be necessary in the carrying value of our assets and liabilities as well as the reporting revenues and expenses, and the balance sheet classifications used.

Stock-Based Compensation

Certain of our directors, officers, employees, and service providers have been granted options to purchase common shares of NACG Holdings Inc., the parent company, under a stock-based compensation plan. The plan and outstanding balances are disclosed in note 6 to the restated interim consolidated financial statements for the three and six months ended September 30, 2004.

Accounting Policies

Certain accounting policies require management to make significant estimates and assumptions about future events that affect the amounts reported in our financial statements and the accompanying notes. Future events and their effects cannot be determined with absolute certainty. Therefore, the determination of estimates requires the exercise of management’s judgment. Actual results could differ from those estimates, and any such differences may be material to our financial statements.

Revenue recognition

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

• Time-and-materials — We provide equipment and labor on an hourly basis to fulfill customer requests. Hourly billing rates are calculated by us through careful consideration of all costs expected to be incurred to provide the requested services and incorporating a mark-up to generate the required profit margin. Revenue is recognized as the labor, equipment, materials, subcontract, and other services are supplied to the customer.

• Unit price — For every unit of work performed, we are paid a specified amount (for example: cubic meters of earth moved; lineal meters of pipe installed; completed piles). The price per unit of work performed is calculated by estimating all of the costs expected to be incurred and adding a mark-up to generate the required profit margin. Revenue related to unit price contracts is recognized as applicable quantities are completed.

• Cost plus — Under this contract type, we charge and are reimbursed for all allowable or otherwise defined costs incurred to provide the requested services plus a pre-arranged fixed or variable fee that represents profit. Revenue is recognized based on actual incurred costs to date plus the applicable fee.

• Fixed price (lump sum) — 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 customer are priced incrementally to the original bid or lump sum. Similar to unit price contracts, the price charged to the customer for the services performed is calculated by estimating all of the costs expected to be incurred 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 using the percentage-of-completion method, calculated using output measures like cubic meters, lineal meters, or completed piles to date. In the absence of reliable output measures, we recognize revenue based upon input measures such as costs incurred to date.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three and six months ended September 30, 2004

Profit for each type of contract is included in revenue when its realization is reasonably assured. Estimated contract losses are recognized in full when determined. Revenue from change orders, extra work, and variations in the scope of work is recognized after both the costs are incurred or services are provided and an agreement has been reached with customers as to both the scope of work and price. Revenue from claims is recognized when an agreement is reached with customers as to the value of the claims, which in some instances may not occur until after the 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 detailed “bottom up” approach. We believe our experience allows us to produce materially reliable estimates; however, our projects can be highly complex, and in almost every case, the profit margin estimates for a project will either increase or decrease to some extent from the amount that was originally estimated at the time of bid. Because we have many projects of varying levels of complexity and size in process at any given time, these changes in estimates can offset each other without materially impacting our profitability; however, large changes in cost estimates, particularly in the bigger, more complex projects, can have a significant effect on profitability.

Factors that can contribute to changes in estimates of contract cost and profitability include, without limitation: 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. Useful life is measured in operated hours, excluding idle hours, and a depreciation rate is calculated for each type of unit. Depreciation expense is determined each day based on actual operated hours.

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

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three and six months ended September 30, 2004

Repair and maintenance costs

The parts, shop labor, and overhead costs that are included in equipment costs on our income statement represent the total cost of operating our equipment and maintaining it in an acceptable condition. Our policy is to expense these costs as they are incurred.

Risk Management

Foreign currency 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 manage this risk. The derivative financial instrument consist of three components: a U.S. dollar interest rate swap; a U.S. dollar-Canadian dollar cross currency basis swap; and a Canadian dollar interest rate swap that results in us mitigating our exposure to the variability of cash flows caused by currency fluctuations relating to the U.S. $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. The premium is equal to 4.375 percent of the U.S. $200 million if exercised between December 1, 2007 and December 1, 2008; 2.1875 percent if exercised between December 1, 2008 and December 1, 2009; and 0.000 percent if cancelled after December 1, 2009. These derivative financial instruments do not qualify for hedge accounting.

Interest rate risk

We are subject to interest rate 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 percent to 2.5 percent or Canadian bankers’ acceptance rate plus 3.0 percent to 3.5 percent. Each 1.0 percent 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 $60.0 million, excluding the $10 million of outstanding letters of credit at September 30, 2004, each 1.0 percent 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.

Inflation

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

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the three and six months ended September 30, 2004

Outlook

Due to expansion projects planned by several large resource companies, capital infrastructure and investment activity is expected to remain strong in the industry through the remainder of fiscal 2005. This is expected to increase demand for our mining and site preparation services.

The volume of work for the Piling operating segment is expected to remain constant for the remainder of the year.

Low activity levels related to pipeline installation services performed by the Pipeline operating segment are expected through the remainder of calendar 2004.

U.S. Generally Accepted Accounting Principles

These 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 11 to the restated interim consolidated financial statements for the three and six months ended September 30, 2004 and note 19 of the restated audited consolidated financial statements for the fiscal year ended March 31, 2004.

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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