UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K/A

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

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. This was accomplished by recognizing the foreign exchange gain or loss relating 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 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/A to reflect the restatement of its interim unaudited consolidated financial statements for the three and nine months ended December 31, 2004 and for the period November 23, 2003 to December 31, 2003. 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 restatement, 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/A do not reflect events occurring after the original filing date of the Form 6-K on April 15, 2005.

Included herein:

1. Interim consolidated financial statements of North American Energy Partners Inc. for the three and nine months ended December 31, 2004 (Restated) and for the period November 26, 2003 to December 31, 2003 (restated).

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

2

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Balance Sheets

(in thousands of Canadian dollars)

	December 31, 2004			March 31, 2004
	(unaudited)
	Restated (note 3)			Restated (note 3)
Assets
Current assets:
Cash and cash equivalents	$	3,344		$	36,595
Accounts receivable		45,631			33,647
Unbilled revenue		24,713			27,676
Inventory		1,302			1,609
Prepaid expenses		1,862			1,272
		76,852			100,799
Capital assets		176,105			167,905
Goodwill		198,549			198,549
Intangible assets, net of accumulated amortization of $15,899		1,899			4,870
Deferred financing costs, net of accumulated amortization of $2,736		15,986			17,266
Future income taxes (note 9)		9,590			285
	$	478,981		$	489,674
Liabilities and Shareholder’s Equity
Current liabilities:
Revolving credit facility (note 8)	$	10,000		$	—
Accounts payable		45,563			29,301
Accrued liabilities		3,723			14,694
Current portion of term credit facility (note 8)		11,000			7,250
Current portion of capital lease obligations		1,474			787
Term credit facility scheduled repayments due beyond one year (note 8)		33,000			—
Future income taxes (note 9)		9,590			5,260
		114,350			57,292
Term credit facility (note 8)		—			41,250
Capital lease obligations		4,405			2,251
Senior notes		240,400			262,260
Derivative financial instruments		46,078			11,266
Advances from parent company (note 10)		288			—
Shareholder’s equity:
Share capital (note 11)		127,500			127,500
Contributed surplus		444			137
Deficit		(54,484	)		(12,282	)
		73,460			115,355
Basis of presentation - future operations (note 1)
Subsequent event (note 8(b))
United States generally accepted accounting principles (note 12)
	$	478,981		$	489,674

See accompanying notes to interim consolidated financial statements.

3

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Statements of Operations and Retained Earnings (Deficit)

(in thousands of Canadian dollars)

(unaudited)

										Predecessor Company
	For the three months ended December 31, 2004			For the nine months ended December 31, 2004			For the period from November 26, 2003 to December 31, 2003			For the period from October 1, 2003 to November 25, 2003			For the period from April 1, 2003 to November 25, 2003
	Restated (note 3)			Restated (note 3)			Restated (note 3)
Revenue	$	80,992		$	234,532		$	25,203		$	54,639		$	250,652
Project costs		66,721			167,644			17,436			38,831			156,976
Equipment costs		14,644			39,741			3,564			11,081			53,986
Depreciation		5,286			14,946			1,364			1,177			6,566
		86,651			222,331			22,364			51,089			217,528
Gross profit (loss)		(5,659	)		12,201			2,839			3,550			33,124
General and administrative		5,354			15,349			1,065			1,956			7,783
Loss (gain) on disposal of capital assets		260			509			—			—			(49	)
Amortization of intangible assets		484			2,971			1,968			—			—
Operating income (loss)		(11,757	)		(6,628	)		(194	)		1,594			25,390
Management fees		—			—			—			17,870			41,070
Interest expense		7,617			22,822			2,836			441			2,457
Foreign exchange gain		(11,902	)		(21,344	)		(4,508	)		(7	)		(7	)
Other income		(38	)		(261	)		(51	)		(31	)		(367	)
Realized and unrealized (gain) loss on derivative financial instruments		23,255			36,801			15,479			—			—
		18,932			38,018			13,756			18,273			43,153
Loss before income taxes		(30,689	)		(44,646	)		(13,950	)		(16,679	)		(17,763	)
Income taxes:
Current income taxes		888			2,531			264			13			218
Future income taxes		850			(4,975	)		(4,499	)		(6,175	)		(6,840	)
		1,738			(2,444	)		(4,235	)		(6,162	)		(6,622	)
Net loss		(32,427	)		(42,202	)		(9,715	)		(10,517	)		(11,141	)
Retained earnings (deficit), beginning of period		(22,057	)		(12,282	)		—			29,193			29,817
Retained earnings (deficit), end of period	$	(54,484	)	$	(54,484	)	$	(9,715	)	$	18,676		$	18,676

See accompanying notes to interim consolidated financial statements.

4

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Statements of Cash Flows

(in thousands of Canadian dollars)

(unaudited)

										Predecessor Company
	For the three months ended December 31, 2004			For the nine months ended December 31, 2004			For the period from November 26, 2003 to December 31, 2003			for the period from October 1, 2003 to November 25, 2003			for the period from April 1, 2003 to November 25, 2003
	Restated (note 3)			Restated (note 3)			Restated (note 3)
Cash provided by (used in):
Operating activities:
Net loss	$	(32,427	)	$	(42,202	)	$	(9,715	)	$	(10,517	)	$	(11,141	)
Items not affecting cash:
Depreciation		5,286			14,946			1,364			1,177			6,566
Amortization of intangible assets		484			2,971			1,968			—			—
Amortization of deferred financing costs		668			1,922			202			—			—
Loss (gain) on disposal of capital assets		260			509			—			—			(49	)
Increase (decrease) in allowance for doubtful accounts		13			(99	)		(31	)		102			141
Foreign exchange gain on senior notes		(11,920	)		(21,860	)		(4,520	)		—			—
Unrealized change in fair value of derivative financial instruments		22,588			34,812			15,216			—			—
Stock-based compensation expense		79			307			—			—			—
Future income taxes		850			(4,975	)		(4,499	)		(6,175	)		(6,840	)
Net changes in non-cash working capital (note 4(b))		(1,362	)		(3,914	)		290			580			13,832
		(15,481	)		(17,583	)		275			(14,833	)		2,509
Investing activities:
Purchase of capital assets		(6,081	)		(20,494	)		(734	)		(288	)		(5,234	)
Proceeds on disposal of capital assets		357			491			287			6			609
Acquisition		—			—			(367,778	)		—			—
		(5,724	)		(20,003	)		(368,225	)		(282	)		(4,625	)
Financing activities:
Increase in revolving credit facility		10,000			10,000			—			—			—
Repayment of term credit facility		(1,500	)		(4,500	)		—			(1,094	)		(4,428	)
Repayment of capital lease obligations		(373	)		(811	)		(57	)		(767	)		(3,289	)
Financing costs		(8	)		(642	)		(16,468	)		—			—
Advances from parent company		—			288			—			—			—
Issuance of share capital		—			—			92,500			—			—
Issuance of senior notes		—			—			263,000			—			—
Proceeds from term credit facility		—			—			50,000			—			—
Advances from Norama Inc.		—			—			—			14,471			17,696
Decrease in cheques issued in excess of cash deposits		—			—			—			—			(2,496	)
Decrease in operating line of credit		—			—			—			—			(516	)
		8,119			4,335			388,975			12,610			6,967
Increase (decrease) in cash and cash equivalents		(13,086	)		(33,251	)		21,025			(2,505	)		4,851
Cash and cash equivalents, beginning of period		16,430			36,595			—			7,356			—
Cash and cash equivalents, end of period	$	3,344		$	3,344		$	21,025		$	4,851		$	4,851

See accompanying notes to interim consolidated financial statements.

5

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 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 December 31, 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 period from April 1, 2003 to November 25, 2003 reflects 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 nine-month periods ended December 31, 2004 due to 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 accounting standards related to purchase accounting.

6

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

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

2. Recently adopted Canadian accounting pronouncements:

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 Arrangements 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

In preparing the financial statements for the fiscal year ended March 31, 2005, the Company reviewed the accounting treatment of its 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 hedge documentation, the Company determined that it was necessary to restate all reported periods after November 26, 2003 to eliminate the impact of hedge accounting. This was accomplished by recognizing the foreign exchange gain or loss relating to the senior notes each period and recording the derivative financial instruments at fair value and the realized and unrealized gains and losses on the derivative financial instruments through the Consolidated Statement of Operations, along with the associated future income tax effects. A valuation allowance of $5.5 million was recorded against any future income tax asset since it is not more likely than not the asset will be realized.

The Company did not violate any covenants under the Credit Agreement (note 8) as a result of the 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 December 31, 2004	As previously reported			Adjustments			As restated
Interest expense	$	8,284		$	(667	)	$	7,617
Foreign exchange loss (gain)		18			(11,920	)		(11,902	)
Change in fair value of derivative financial instruments		—			23,255			23,255
Loss before income taxes		(20,021	)		(10,668	)		(30,689	)
Future income taxes		(2,050	)		2,900			850
Net loss	$	(18,859	)	$	(13,568	)	$	(32,427	)
For the nine months ended December 31, 2004	As previously reported			Adjustments			As restated
Interest expense	$	24,811		$	(1,989	)	$	22,822
Foreign exchange loss (gain)		516			(21,860	)		(21,344	)
Change in fair value of derivative financial instruments		—			36,801			36,801
Loss before income taxes		(31,694	)		(12,952	)		(44,646	)
Future income taxes		(7,775	)		2,800			(4,975	)
Net loss	$	(26,450	)	$	(15,752	)	$	(42,202	)
For the period from November 26, 2003 to December 31, 2003	As previously reported			Adjustments			As restated
Interest expense	$	3,099		$	(263	)	$	2,836
Foreign exchange loss (gain)		12			(4,520	)		(4,508	)
Realized and unrealized (gain) loss on derivative financial instruments		—			15,479			15,479
Loss before income taxes		(3,254	)		(10,696	)		(13,950	)
Future income taxes		(1,699	)		(2,800	)		(4,499	)
Net loss	$	(1,819	)	$	(7,896	)	$	(9,715	)

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

As at December 31, 2004	As previously reported			Adjustments			As restated
Derivative financial instruments	$	22,600		$	23,478		$	46,078
Deficit	$	(31,006	)	$	(23,478	)	$	(54,484	)
As at March 31, 2004	As previously reported			Adjustments			As restated
Future income taxes — asset	$	—		$	285		$	285
Derivative financial instruments		740			10,526			11,266
Future income taxes — liability		2,515			(2,515	)		—
Deficit	$	(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 December 31, 2004	As previously reported			Adjustments			As restated
Net loss	$	(18,859	)	$	(13,568	)	$	(32,427	)
Foreign exchange gain on senior notes		—			(11,920	)		(11,920	)
Unrealized change in fair value of derivative financial instruments		—			22,588			22,588
Future income taxes	$	(2,050	)	$	2,900		$	850
For the nine months ended December 31, 2004	As previously reported			Adjustments			As restated
Net loss	$	(26,450	)	$	(15,752	)	$	(42,202	)
Foreign exchange gain on senior notes		—			(21,860	)		(21,860	)
Unrealized change in fair value of derivative
financial instruments		—			34,812			34,812
Future income taxes	$	(7,775	)	$	2,800		$	(4,975	)
For the period from November 26, 2003 to December 31, 2003	As previously reported			Adjustments			As restated
Net loss	$	(1,819	)	$	(7,896	)	$	(9,715	)
Foreign exchange gain on senior notes		—			(4,520	)		(4,520	)
Unrealized change in fair value of derivative financial instruments		—			15,216			15,216
Future income taxes	$	(1,699	)	$	(2,800	)	$	(4,499	)

4. Other information

a) Supplemental cash flow information:

							Predecessor Company
	For the three months ended December 31, 2004		For the nine months ended December 31, 2004		For the period from November 26, 2003 to December 31, 2003		for the period from October 1, 2003 to November 25, 2003		for the period from April 1, 2003 to November 25, 2003
Cash paid during the period for:
Interest	$	13,830	$	29,584	$	59	$	510	$	2,431
Income taxes		225		3,408		5		18		325
Cash received during the period for:
Interest		32		305		49		10		100
Income taxes		—		—		—		—		—
Non-cash transactions:
Capital leases	$	1,561	$	3,652	$	943	$	—	$	—

7

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

b) Net change in non-cash working capital:

										Predecessor Company
	For the three months ended December 31, 2004			For the nine months ended December 31, 2004			For the period from November 26, 2003 to December 31, 2003			for the period from October 1, 2003 to November 25, 2003			for the period from April 1, 2003 to November 25, 2003
Accounts receivable	$	(18,801	)	$	(11,885	)	$	11,781		$	(13,149	)	$	3,338
Unbilled revenue		13,519			2,963			(771	)		3,596			15,289
Inventory		392			307			—			—			—
Prepaid expenses		(1,151	)		(590	)		369			—			(544	)
Accounts payable		11,700			16,262			(6,419	)		7,962			(2,794	)
Accrued liabilities		(7,021	)		(10,971	)		(4,670	)		2,171			(1,457	)
	$	(1,362	)	$	(3,914	)	$	290		$	580		$	13,832

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:

	December 31, 2004
Assets
Cash	$	395
Accounts receivable		789
Unbilled revenue		4,558
	$	5,742
Liabilities
Accounts payable	$	994
Accrued liabilities		891
Venturer’s equity		3,857
	$	5,742

8

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

										Predecessor Company
	For the three months ended December 31, 2004			For the nine months ended December 31, 2004			For the period from November 26, 2003 to December 31, 2003			for the period from October 1, 2003 to November 25, 2003			for the period from April 1, 2003 to November 25, 2003
Revenue	$	4,025		$	7,631		$	2		$	170		$	170
Project costs		4,107			8,840			14			154			154
General and administrative		—			—			2			3			3
Net income (loss)	$	(82	)	$	(1,209	)	$	(14	)	$	13		$	13
										Predecessor Company
	For the three months ended December 31, 2004			For the nine months ended December 31, 2004			For the period from November 26, 2003 to December 31, 2003			for the period from October 1, 2003 to November 25, 2003			for the period from April 1, 2003 to November 25, 2003
Cash used in:
Operating activities	$	(3,292	)	$	(4,668	)	$	(56	)	$	(76	)	$	(76	)
Investing activities		—			—			—			—			—
Financing activities		3,290			5,061			56			76			76
	$	(2	)	$	393		$	—		$	—		$	—

The Company was contingently liable at December 31, 2004 for obligations of its incorporated joint venture totaling $57 (March 31, 2004 - $6), representing the other venturer’s proportionate share of the joint venture’s liabilities. The assets of the joint venture are available for the purpose of satisfying such obligations.

The Company enters into transactions in the normal course of operations with its joint venture. These transactions are measured at the exchange amount, being the amount of consideration established and agreed to by the parties involved. During the three-month and nine-month periods ended December 31, 2004, the Company provided $2,267 and $4,777 of labour and equipment services to the joint venture, respectively (April 1, 2003 – November 25, 2003 - $101; November 26, 2003 – December 31, 2003 - $16). Additionally the Company recovered costs of $nil and $268 from the joint venture for the three-month and nine-month periods ended December 31, 2004 (April 1, 2003 – November 25, 2003 - $23; November 26, 2003 – December 31, 2003 - $6).

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

9

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

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 December 31, 2004	Mining and Site Preparation			Piling		Pipeline		Total
Revenues from external customers	$	63,872		$	13,319	$	3,801	$	80,992
Depreciation of capital assets		2,618			562		40		3,220
Segment profits		(9,183	)		2,320		390		(6,473	)
Segment assets		299,211			79,470		45,204		423,885
Expenditures for segment capital assets		2,784			27		773		3,584
For the nine months ended December 31, 2004	Mining and Site Preparation			Piling		Pipeline		Total
Revenues from external customers	$	173,250		$	43,957	$	17,325	$	234,532
Depreciation of capital assets		7,231			1,860		122		9,213
Segment profits		(130	)		9,100		2,378		11,348
Segment assets		299,211			79,470		45,204		423,885
Expenditures for segment capital assets		15,418			85		773		16,276
For the period from November 26, 2003 to December 31, 2003	Mining and Site Preparation			Piling		Pipeline		Total
Revenues from external customers	$	10,857		$	3,025	$	11,321	$	25,203
Depreciation of capital assets		526			125		102		753
Segment profits		596			810		2,070		3,476
Segment assets		282,203			76,775		62,244		421,222
Expenditures for segment capital assets		173			—		578		751

10

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

Predecessor Company
For the period from October 1, 2003 to November 25, 2003	Mining and Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	34,878	$	8,565	$	11,196	$	54,639
Depreciation of capital assets		473		229		70		772
Segment profits		3,285		977		2,123		6,385
Segment assets		77,906		31,792		15,904		125,602
Expenditures for segment capital assets		164		11		—		175
Predecessor Company
For the period from April 1, 2003 to November 25, 2003	Mining and Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	182,368	$	39,417	$	28,867	$	250,652
Depreciation of capital assets		3,590		1,256		158		5,004
Segment profits		17,745		8,330		5,054		31,129
Segment assets		77,906		31,792		15,904		125,602
Expenditures for segment capital assets		2,591		417		—		3,008

c) Reconciliations:

(i) Income (loss) before income taxes:

										Predecessor Company
	For the three months ended December 31, 2004			For the nine months ended December 31, 2004			For the period from November 26, 2003 to December 31, 2003			for the period from October 1, 2003 to November 25, 2003			for the period from April 1, 2003 to November 25, 2003
	Restated (note 3)			Restated (note 3)			Restated (note 3)
Total profit for reportable segments	$	(6,473	)	$	11,348		$	3,476		$	6,385		$	31,129
Unallocated corporate expenses		(24,795	)		(56,277	)		(16,758	)		(20,333	)		(51,077	)
Unallocated equipment revenue		579			283			(668	)		(2,731	)		2,185
Loss before income taxes	$	(30,689	)	$	(44,646	)	$	(13,950	)	$	(16,679	)	$	(17,763	)

(ii) Total assets:

	December 31, 2004		March 31, 2004
	Restated (note 3)		Restated (note 3)
Total assets for reportable segments	$	423,885	$	410,469
Corporate assets		55,096		79,205
Total assets	$	478,981	$	489,674

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

11

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 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 21,258 are still available for issue as at December 31, 2004. As at December 31, 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 4.26 percent; volatility of nil percent; and an expected option life of 10 years.

The stock options outstanding at December 31, 2004 are as follows:

	Number of options		Weighted average exercise price $ per share
Outstanding at March 31, 2004	54,130		100.00
Granted	19,112		100.00
Exercised	—
Forfeited	(2,000	)	100.00
Outstanding at December 31, 2004	71,242		100.00

At December 31, 2004, the range of exercise prices, the weighted average exercise price and the weighted average remaining contractual life are as follows:

		Options outstanding
Exercise price		Number outstanding	Weighted average remaining contractual life (years)	Weighted average exercise price
$	100	71,242	9.1	$	100

The Company recorded $79 of compensation expense related to the stock options during the three months ended December 31, 2004 (nine months ended December 31, 2004 – $307) 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.

12

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

8. Senior secured credit facility

a) General terms:

The Company refers to the revolving credit facility and the term loan collectively as the “senior secured credit facility.” The Credit Agreement dated November 26, 2003 related to the senior secured credit facility (the “Credit Agreement”) imposes certain restrictions on the Company, including restrictions on the Company’s ability to incur indebtedness, pay dividends, make investments, grant liens, sell assets and engage in certain other activities. In addition, the Credit Agreement requires the Company to maintain certain financial ratios (“covenants”) including: achieving certain levels of earnings before interest, taxes, depreciation and amortization (“EBITDA”); maintaining interest and fixed-charge coverage ratios above a specified minimum level; limiting capital expenditures to specified amounts; and maintaining leverage ratios below 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 at December 31, 2004, the Company had $10.0 million in 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 $44.0 million outstanding under the term loan portion of the senior secured credit facility at December 31, 2004.

b) Subsequent event:

After December 31, 2004, 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 8 ³/4% 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.

13

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

At December 31, 2004, without the waivers referred to above, the Company would have been in breach of several financial covenants under the Credit Agreement. 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 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. Future income taxes

The future income tax asset has been reduced by a valuation allowance to the extent that it is more likely than not that some portion or all of the assets will not be realized.

10. Related party balance

Advances from parent company of $288 as at December 31, 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.

11. Share capital

Authorized:

Unlimited number of common voting shares.

14

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

Issued:

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

12. 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 is recorded in each period and the derivative financial instruments are recorded at fair value and the realized and the unrealized gains and losses on derivative financial instruments have been recognized as either an increase or decrease in the Consolidated Statement of Operations, along with the associated future income tax effects.

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

Reporting comprehensive income:

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

15

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2004

(amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

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.

Recent United States accounting pronouncements:

Statement on Financial Accounting Standards No. 123R, “Share-Based Payment” (“SFAS 123R”) requires companies to recognize in the income statement, the grant-date fair value of stock options and other equity-based compensation issued to employees. The fair value of liability-classified awards is remeasured subsequently at each reporting date through the settlement date, while the fair value of equity-classified awards is not subsequently remeasured. The alternative to use the intrinsic value method of APB Opinion 25 is eliminated with this revised standard. The Company is currently evaluating the impact of this revised standard. The revised standard is effective for non-public companies beginning the first annual reporting period that begins after December 15, 2005, in the case of the Company beginning April 1, 2006. The Company is required to adopt this standard using the modified prospective or modified retrospective transaction method.

Statement on Financial Accounting Standards No. 153, “Exchanges of Non-monetary Assets – an Amendment of APB Opinion 29” (“SFAS 153”), was issued in December 2004. Accounting Principles Board (“APB”) Opinion 29 is based on the principle that exchanges of non-monetary assets should be measured based on the fair value of assets exchanged. SFAS 153 amends APB Opinion 29 to eliminate the exception for non-monetary exchanges of similar productive assets and replaces it with a general exception for exchanges of non-monetary assets that do not have commercial substance. The standard is effective for the Company for non-monetary asset exchanges occurring in fiscal 2006 and will be applied prospectively. The Company is currently evaluating the impact of this revised standard.

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

16

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

Management’s Discussion and Analysis

Three-month and Nine-month Periods Ended December 31, 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: the effectiveness of our internal controls; our ability to comply with the terms of our credit agreement or our indenture, or in the event of our breach of such terms, our ability to receive waivers or amendments from the lenders under our credit agreement or our indenture; potential alternative financing arrangements; our ability to continue to bid successfully on new projects and accurately forecast costs associated with unit price or fixed price contracts; our ability to obtain surety bonds as required by some of our customers; decreases in outsourcing work by our customers; changes in oil and gas prices; 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 hire and retain a skilled labor force; 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; and 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 herein under “Risk Factors.” You are cautioned not to put undue reliance on any forward-looking statements, and we undertake no obligation to update those statements.

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 8¾% 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. This was accomplished by recognizing the foreign exchange gain or loss relating the senior notes each period and recording the derivative financial instruments and the realized and unrealized gains and losses on the derivative instruments each period through the Consolidated Statement of Operations, along with the associated future income tax effects.

The 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 and Consolidated Balance Sheets for the periods presented.

17

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

Overview

We provide services primarily to major oil and natural 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 customers’ 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, 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 natural 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 over 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 nine-month periods ended December 31, 2003 are largely the results of operations of Norama Ltd. (“Norama” or the “Predecessor Company”) preceding the acquisition that occurred on November 26, 2003. Included in the comparative information presented for the three-month and nine-month periods ended December 31, 2003 are the results of the Predecessor Company up to November 25, 2003 plus the results of the Successor Company, NAEPI, for the period from November 26, 2003 to December 31, 2003. The information as of December 31, 2004 may not be directly comparable to the comparative information provided 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 purchase accounting pursuant to Canadian and United States (“U.S.”) generally accepted accounting principles (“GAAP”).

Consolidated Financial Results

	Three months ended December 31										Nine months ended December 31
(in millions of Canadian dollars)		2004					Predecessor Company Oct 1/03 to Nov 25/03 Successor Company Nov 26/03 to Dec 31/03 2003					2004					Predecessor Company Apr 1/03 to Nov 25/03 Successor Company Nov 26/03 to Dec 31/03 2003
	Restated1					Restated1					Restated1					Restated1
Revenue	$	81.0		100.0	%	$	79.9		100.0	%	$	234.5		100.0	%	$	275.9		100.0	%
Project costs		66.7		82.3	%		56.3		70.5	%		167.6		71.5	%		174.4		63.2	%
Equipment costs		14.6		18.0	%		14.6		18.3	%		39.7		16.9	%		57.6		20.9	%
Depreciation		5.3		6.5	%		2.5		3.1	%		15.0		6.4	%		7.9		2.9	%
Gross profit (loss)		(5.6	)	-6.9	%		6.5		8.1	%		12.2		5.2	%		36.0		13.0	%
General and administrative		5.3		6.5	%		3.0		3.8	%		15.4		6.6	%		8.8		3.2	%
Loss (gain) on disposal of capital assets		0.3		0.4	%		—		0.0	%		0.5		0.2	%		—		0.0	%
Amortization of intangible assets		0.5		0.6	%		2.0		2.5	%		3.0		1.3	%		2.0		0.7	%
Operating income (loss)		(11.7	)	-14.4	%		1.5		1.9	%		(6.7	)	-2.9	%		25.2		9.1	%
Management fees		—		0.0	%		17.9		22.4	%		—		0.0	%		41.1		14.9	%
Interest expense		7.6		9.4	%		3.3		4.1	%		22.8		9.7	%		5.3		1.9	%
Foreign exchange gain		(11.9	)	-14.7	%		(4.5	)	-5.6	%		(21.3	)	-9.1	%		(4.5	)	-1.6	%
Other income		—		0.0	%		(0.1	)	-0.1	%		(0.3	)	-0.1	%		(0.4	)	-0.1	%
Realized and unrealized (gain) loss on derivative financial instruments		23.3		28.8	%		15.5		19.4	%		36.8		15.7	%		15.5		5.6	%
Loss before income taxes	$	(30.7	)	-37.9	%	$	(30.6	)	-38.3	%	$	(44.7	)	-19.1	%	$	(31.8	)	-11.5	%

¹ See note 3 to the unaudited interim consolidated financial statements for the three and nine months ended December 31, 2004

for an explanation of the changes made.

18

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

Revenue

Revenue for the three-month period ended December 31, 2004 increased by $1.2 million (1.4 percent) from the same period in the prior year primarily due to a number of new mining and site preparation contracts entered into by the Company and increased piling activity in the three month period ended December 31, 2004. Revenue from these new projects in the current period more than offset the declines in revenue primarily due to the substantial completion of a large site preparation contract and a large piling contract in the prior year, as well as the significant decrease in pipeline activity resulting from a deferred capital spending program instituted by our major pipeline customer in the current period.

Revenue for the nine-month period ended December 31, 2004 decreased by $41.3 million (15.0 percent) from the same period in the prior year primarily due to the substantial completion of the large site preparation and piling contracts in the prior year as discussed above. Revenue also decreased due to the deferred capital spending program instituted by our major pipeline customer in the current period. These decreases were partially offset by revenue generated by increased piling activity and a number of new mining and site preparation contracts as discussed in the Segmented Results of Operations section of this MD&A.

Project costs

Project costs for the three-month period ended December 31, 2004 increased by $10.5 million (18.6 percent) from the same period in the prior year primarily due to higher activity levels and the abnormally high costs incurred on one of our major projects as discussed in more detail in the Segmented Results of Operations section of this MD&A.

Project costs for the nine-month period ended December 31, 2004 decreased by $6.8 million (3.9 percent) from the same period in the prior year primarily due to less activity in the current year.

As a percentage of revenue, project costs were higher in the three-month and nine-month periods ended December 31, 2004 than in the comparative periods primarily due to the high costs incurred on one of our major projects as discussed above.

Equipment costs

Equipment costs for the three-month period ended December 31, 2004 were essentially unchanged from the same period in the prior year. Equipment costs for the nine-month period ended December 31, 2004 decreased by $17.8 million (30.9 percent) from the same period in the prior year primarily due to lower lease and rental expense in the current period as compared to the prior period as a result of the buy-out of most of our leased and rented equipment concurrent with the acquisition on November 26, 2003.

Depreciation

Depreciation expense for the three-month and nine-month periods ended December 31, 2004 increased by $2.7 million (108.0 percent) and $7.0 million (88.5 percent), respectively, from the corresponding periods in the prior year. The increases were primarily due to increased depreciable asset values resulting from 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 leased and rented equipment in November 2003 also contributed to the increased depreciation expense for the current periods.

19

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

General and administrative expenses

General and administrative expenses increased by $2.3 million (77.2 percent) and $6.5 million (73.5 percent), respectively, from the corresponding periods in the prior year. These increases were primarily attributable to: higher staff levels; increased salaries, travel costs, insurance costs, and consulting costs; and increased costs related to corporate governance, including reporting responsibilities as an SEC filing company.

Amortization of intangible assets

The amortization of intangible assets in both the current and prior periods 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 as of December 31, 2004 as the majority of the cost relates to customer contracts acquired in the acquisition in November 2003 that are being amortized at a rapid rate due to their short-term nature.

Management fees

Management fee expense was $nil for the three-month and nine-month periods ended December 31, 2004 as compared to $17.9 million and $41.1 million, respectively, for the three-month and nine-month periods ended December 31, 2003. These fees incurred in the prior periods 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 nine-month periods ended December 31, 2004 increased significantly from the corresponding periods in the prior year due to the additional 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 rate on the debt of the Predecessor Company.

Foreign exchange gain

The foreign exchange gains in both the current and prior periods 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.

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 $22.6 million, respectively. The change in both the current and prior periods 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.

20

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

													Predecessor Company
	Fiscal Year 2005									Fiscal Year 2004												Fiscal Year 2003
(in millions of Canadian dollars, except equipment hours)	Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4
	Restated			Restated			Restated			Restated			Restated
Revenue	$	81.0		$	82.7		$	70.9		$	102.4		$	79.9		$	102.3		$	93.7		$	115.9
Gross profit		(5.6	)		9.8			8.1			19.8			6.5			16.8			12.8			17.6
Net income (loss)		(32.4	)		(4.7	)		(5.1	)		(2.6	)		(20.2	)		(0.5	)		(0.1	)		13.4
Equipment hours		191,555			193,205			137,434			188,557			128,153			200,499			177,939			227,645

The lower revenues experienced over the recent four quarters compared to prior periods primarily resulted from the substantial completion in the prior year of a number of large contracts, including two contracts related to Syncrude Canada Ltd.’s (“Syncrude”) Upgrader Expansion 1 (“UE1”) project.

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 December 31									Nine months ended December 31
(in millions of Canadian dollars, except equipment hours)	2004					Predecessor Company Oct 1/03 to Nov. 25/03 Successor Company Nov. 26/03 to Dec.31/03 2003				2004					Predecessor Company Apr. 1/03 to Nov. 25/03 Successor Company Nov. 26/03 to Dec. 31/03 2003
Revenue by operating segment
Mining and Site Preparation	$	63.9		78.9	%	$	45.8	57.3	%	$	173.3		73.9	%	$	193.2	70.1	%
Piling		13.3		16.4	%		11.6	14.5	%		43.9		18.7	%		42.4	15.4	%
Pipeline		3.8		4.7	%		22.5	28.2	%		17.3		7.4	%		40.2	14.5	%
Total	$	81.0		100.0	%	$	79.9	100.0	%	$	234.5		100.0	%	$	275.9	100.0	%
Profit by operating segment
Mining and Site Preparation	$	(9.2	)	141.5	%	$	3.9	39.4	%	$	(0.1	)	-0.9	%	$	18.2	52.6	%
Piling		2.3		-35.4	%		1.8	18.2	%		9.1		79.8	%		9.3	26.9	%
Pipeline		0.4		-6.1	%		4.2	42.4	%		2.4		21.1	%		7.1	20.5	%
Total	$	(6.5	)	100.0	%	$	9.9	100.0	%	$	11.4		100.0	%	$	34.6	100.0	%
Equipment hours by operating segment
Mining and Site Preparation		175,970		91.9	%		90,617	70.0	%		460,891		88.3	%		405,968	79.9	%
Piling		13,013		6.8	%		10,093	7.8	%		45,929		8.8	%		51,033	10.0	%
Pipeline		2,572		1.3	%		28,681	22.2	%		15,374		2.9	%		50,828	10.0	%
Total		191,555		100.0	%		129,391	100.0	%		522,194		100.0	%		507,829	100.0	%

21

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

Mining and Site Preparation

Revenue for the three-month period ended December 31, 2004 increased by $18.1 million (39.7 percent) from the same period in the prior year primarily due to activity in the current period related to the OPTI/Nexen Long Lake project, the mining services contract for Grande Cache Coal Corporation, and Syncrude’s Southwest Quadrant Replacement (“SWQR”) project. In addition, work commenced late in the third quarter of fiscal 2005 on a large site preparation and underground utility installation project for CNRL. Revenue generated by these projects in the current period more than offset the decline in revenue resulting from the completion of the UE1 project in the prior year.

Revenue for the nine-month period ended December 31, 2004 decreased by $20.0 million (10.3 percent) from the same period in the prior year primarily due to our inability to entirely replace the two large UE1 contracts that were substantially completed in the prior year. We were successful in partially replacing that work with a number of significant new contracts entered into by the Company in the current period, including the OPTI/Nexen Long Lake contract, the mining services work for Grande Cache Coal Corporation, Syncrude’s SWQR contract and the site preparation and underground utility contract for CNRL.

Operating segment profit for the three-month and nine-month periods ended December 31, 2004 decreased by $13.1 million (336.6 percent) and $18.5 million (100.7 percent), respectively, from the comparative periods. The majority of the year-over-year decrease in operating segment profit in both periods was due to the substantial loss incurred on a single large steam assisted gravity drainage site project. A number of factors contributed to the loss on the project, including: unfavorable weather conditions hindering productivity; higher than expected costs due to labor shortages; schedule acceleration; and higher than expected costs resulting from an underestimation of the project’s complexity at the time the contract bid was prepared. At December 31, 2004, the project was approximately 85 percent complete with the majority of the remaining work scheduled to be completed in the spring of 2005. As required under generally accepted accounting principles, the total estimated loss on the project has been reflected in the results for the third quarter ended December 31, 2004.

Piling

Piling revenue for the three-month period ended December 31, 2004 increased by $1.7 million (14.9 percent) from the comparative prior period primarily due to stronger economic activity in the current period, as well as our success in replacing the revenue generated by the large UE1 piling contract in the prior period with revenue generated by a number of smaller contracts entered into by the Company in the current period. Piling revenue for the nine-month period ended December 31, 2004 increased by $1.5 million (3.6 percent) from the comparative prior period primarily due to the revenue generated by a number of small contracts entered into by the Company which was more than the decline in revenue resulting from the completion of the large UE1 piling project in the prior year.

Profit for the Piling operating segment increased by $0.5 million (29.8 percent) for the three-month period ended December 31, 2004 and remained essentially unchanged for the nine-month period ended December 31, 2004 as compared to the respective prior periods. The higher volume of contracts in the current periods more than offset a decline in operating profit margin in the current periods as compared to the prior periods. This decline in operating margins was due to a higher proportion of lower margin driven pile work completed in the current periods as compared to the prior periods.

Pipeline

Pipeline operating segment revenue for the three-month and nine-month periods ended December 31, 2004 decreased by $18.7 million (83.1 percent) and $20.9 million (56.9 percent), respectively, from the comparative prior periods primarily due to a significant reduction in the regional development program by our major pipeline customer in the current period.

Profit for this operating segment for the three-month and nine-month periods ended December 31, 2004 decreased by $3.8 million (90.7 percent) and $4.7 million (66.6 percent), respectively, from the comparative prior periods primarily as a result of the lower activity in the current periods.

22

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

Consolidated Financial Position

At December 31, 2004, we had a net working capital deficiency of $37.5 million compared to a positive net working capital position of $43.5 million at March 31, 2004. The decrease was primarily due to the reclassification of scheduled repayments due beyond one year related to our term credit facility in the first quarter of this fiscal year, resulting in the balance being classified as a current liability, as discussed under “Liquidity and Capital Resources”. Also contributing to the decrease were a reduction in cash and cash equivalents at December 31, 2004 as compared to March 31, 2004 and a revolving credit facility balance of $10 million owing at December 31, 2004 where none existed at March 31, 2004. Accounts receivable increased from March 31, 2004 due to longer payment terms under present contracts as compared to the payment terms under the contracts active at the end of the prior fiscal year. Unbilled revenue decreased from March 31, 2004 as a result of improving cycle time in our billing preparation process. Accounts payable and accrued liabilities increased slightly at December 31, 2004 from the balances at the end of the prior fiscal year due to a delay in paying certain vendors as a result of the discovery of unrecorded invoices late in the quarter as described above.

Capital assets increased by $8.2 million at December 31, 2004 from March 31, 2004 due to the purchase of new equipment required to perform the various contracts awarded over the past nine months, including the large site preparation and underground utility installation project in progress for CNRL. A portion of the increase also resulted from equipment purchases to replace retired equipment. The increase in capital assets at December 31, 2004 was partially offset by depreciation expense incurred over the nine-month period.

The term credit facility balance decreased by $4.5 million at December 31, 2004 from the balance at the end of the prior fiscal year due to the scheduled quarterly term debt repayments.

Capital lease obligations, including the current portion, increased by $2.8 million at December 31, 2004 from the balance at March 31, 2004 due to the addition of new leased vehicles to support new projects.

Impairment of Goodwill

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

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

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

We completed this test during the third quarter of fiscal 2005 and were not required to record an impairment loss on goodwill.

23

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

Liquidity and Capital Resources

Operating activities

Operating activities for the three-month and nine-month periods ended December 31, 2004 resulted in net usages of cash totalling $15.5 million and $17.6 million during the respective periods. This was mainly due to the substantial net loss incurred on a single large steam assisted gravity drainage site project and billing delays encountered by the Company in both periods.

Operating activities during the three-month period ended December 31, 2003 resulted in a net usage of cash totalling $14.6 million primarily due to the net loss for the period. During the nine-month period ended December 31, 2003, operating activities contributed $2.8 million in cash mainly due to the collection of accounts receivable.

Investing activities

During the three-month period ended December 31, 2004, we invested $1.5 million in sustaining capital expenditures and $4.6 million in growth capital expenditures compared to $1.0 million and $nil, respectively, during the same period in the prior year. In addition, we financed new vehicles by way of capital leases totalling $1.6 million during the quarter ended December 31, 2004 compared to $0.9 million during the same period in the prior year. During the nine-month period ended December 31, 2004, we invested $4.6 million in sustaining capital expenditures and $15.9 million in growth capital expenditures compared to $4.7 million and $1.2 million, respectively, in the comparative prior period. We financed new vehicles by way of capital leases totalling $3.7 million during the nine-month period ended December 31, 2004 compared to $3.0 million during the same period in the prior year. 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 existing fleet of equipment at its optimum average age. Growth capital expenditures relate to equipment additions required to perform increased sizes or numbers of projects.

Financing activities

Financing activities during the three-month and nine-month periods ended December 31, 2004 primarily related to borrowings under our revolving credit facility, term credit facility scheduled repayments, and repayment of capital lease obligations.

Financing activities for the three-month period ended December 31, 2003 included the issuance of senior notes, share capital, and the related financing costs incurred in connection with the acquisition on November 26, 2003 and borrowings under the term credit facility. For the nine-month period ended December 31, 2003, significant financing activities also included scheduled repayments under the Predecessor Company’s credit facility, advances from the Predecessor Company’s parent company, and repayment of capital lease obligations.

Liquidity Requirements

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

We are required to make quarterly principal and monthly interest payments under our $44.0 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 December 31, 2004, the weighted-average interest rate on the term credit facility was 6.7 percent. Additional prepayments are required under certain circumstances, and no new advances are available under the term credit facility.

24

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

Our U.S. $200 million of 8 ³/4 percent 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 were required to pay additional interest to the holders of the notes in the amount of U.S. $0.2 million on the December 1, 2004 scheduled interest payment. There are no principal payments required on the senior notes until maturity.

The foreign currency risk relating to both the principal and interest payments on the 8 ³/4% senior notes has been managed with a cross currency swap and interest rate swaps which 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 expense of $12.8 million is payable semi-annually in June and December of each year until the notes mature on December 1, 2011.

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

Our cash requirements during the three-month and nine-month periods ended December 31, 2004 increased due to the project loss discussed earlier in this MD&A and our continued growth through recent contract awards. Our cash requirements for the remainder of the fiscal year consist of lease obligations, interest payment obligations, and working capital requirements as activity levels are expected to increase. In addition, we will require cash to finance additional vehicle and equipment acquisitions in the last quarter of fiscal 2005 in preparation for new projects commencing in the spring of 2005.

Sources of Liquidity

Our principal sources of cash are funds from operations and borrowings under our senior secured credit facility. 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 a specified maximum level. The indebtedness under the senior secured credit facility, including the contingent obligation under the currency hedging agreement discussed above, is secured by substantially all of our assets and those of our subsidiaries, including accounts receivable and capital assets.

25

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 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: 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 requirement to deliver our December 31, 2004 financial statements by March 1, 2005 under the corresponding covenant in the indenture governing our 8 ³/4% senior notes. The most recent waivers expire on the earlier of April 15, 2005 or the date the lack of compliance becomes an event of default under the indenture. In connection with the first waiver, which was obtained on January 14, 2005, the lenders allowed the Company to increase its borrowings under the revolving credit facility to $20 million and increase the amount of outstanding letters of credit issued to $20 million. The lending banks have not provided any additional funding since that date. The revolving credit facility would otherwise provide the Company with borrowing capacity up to $70 million in total, subject to borrowing base limitations. In addition, during the waiver period, 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 December 31, 2004, without the waivers referred to above, we would have been in breach of several financial covenants under the Credit Agreement. 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.

We have classified the term credit facility scheduled repayments due beyond one year as 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.

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 issue 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.

On January 19, 2005, both Moody’s and Standard & Poor’s lowered our credit ratings. Moody’s lowered its rating of our 8 ³/4% 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 8 ³/4% 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.

26

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 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 interim unaudited consolidated financial statements for the period ended December 31, 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

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

• 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 costs, 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.

27

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

• 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 recognition is 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.

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. Until we feel we can accurately estimate job profitability, no profit on the related project is recognized. 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.

28

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

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 that are available-for-sale.

Repair and maintenance costs

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

Risk Factors

We rely on a small number of customers from whom we receive a significant amount of our revenues.

We provide our services primarily to a small number of major integrated and independent oil and gas and other natural resources companies operating in Western Canada. Revenue from our five largest customers represented approximately 91% of our total revenue for the fiscal year ended March 31, 2004 and those customers are expected to continue to provide a significant percentage of our revenues in the future. Each year any one of our customers may constitute a significant portion of our revenue. For example, for the fiscal year ended March 31, 2004, revenue generated from work for Syncrude constituted approximately 52% of our total revenue primarily due to several large projects with Syncrude and our status as one of their preferred contractors. We may not be able to replace the work generated by these projects with work from other customers. Our services to our customers are typically provided under contracts with terms ranging from six months to ten years, some of which have terms allowing for automatic or optional renewals of the contract. However, a significant number of our contracts terminate upon completion of the project without having a definite termination date, and the contracts typically allow the customer to reduce or eliminate the work which we are to perform. In addition, the customers may choose not to extend the existing contracts or enter into new contracts. The loss of or significant reduction in business with one or more of these customers could have a material adverse effect on our business.

29

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

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

Our recent operating results have been adversely affected by losses we have incurred on fixed price and unit price contracts. The terms of these contracts require us to guarantee the price of the services we provide and assume the risk that our costs to perform the services and provide the materials will be greater than anticipated. Our profitability under such contracts is therefore dependent upon our ability to accurately predict the costs associated with our services. Cost estimating is therefore a critical function that has a major impact on our success or failure. Estimates must be adequately prepared and reviewed because inaccurately prepared bids can result in unsuccessful bids for contracts or losses on contracts actually received.

Not only is our ability to estimate costs important, the costs we actually incur may be affected by a variety of factors, some of which may be beyond our control. Factors that contribute to differences in the costs we actually incur as compared to our estimates and which therefore affect profitability include, without limitation, site conditions which differ from those assumed in the original bid, the availability and skill level of workers in the geographic location of the project, inclement weather, equipment productivity and timing differences that result from actual project starting time as compared to projected starting time and the general coordination of work inherent in all substantial projects we undertake. When we are unable to accurately estimate the costs of fixed price and unit price contracts, or when we incur unrecoverable cost overruns, some projects will have lower margins than anticipated or incur losses, which adversely impact our results of operations, financial condition and cash flow.

Approximately 29% and 56% of our revenue for the fiscal year ended March 31, 2004 and for the nine months ended December 31, 2004, respectively, was derived from fixed price and unit price contracts. However, going forward, the percentage of our revenue derived from fixed price and unit price contracts is expected to increase as several of the contracts recently entered into between our joint venture Noramac and CNRL, including the 10-year overburden removal contract and a large site grading contract, are unit price and/or fixed price contracts. Given the magnitude of the projected revenues from these contracts with CNRL as compared to the revenues expected to be earned from other contracts, if we underestimated the costs to perform these contracts, or if we were to incur unrecoverable cost overruns on these projects, it is likely that we would be unable to service our debt obligations.

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

We have had to restate our financial statements for the first and second quarters of fiscal 2005, primarily due to certain inaccurate expense accruals. During the preparation of our financial statements for the third quarter of fiscal 2005, we discovered a number of invoices recorded in the third quarter which were related to costs actually incurred in the first and second quarters of fiscal 2005. A review of our accounting and control procedures identified a number of deficiencies in our financial reporting processes and internal controls that contributed to several misstated amounts as discussed earlier in this document. We are endeavoring to address these deficiencies. Our auditors have advised us that unless we have appropriate procedures and controls in place with respect to accounting for our contracts and with respect to our purchases and accounts payable, we will not be able to report our results on a timely basis.

30

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

While we have begun to evaluate our accounting and control procedures surrounding the causes for the misstatements, we may be unable to implement the changes required to provide accurate and timely operating and financial reports. Failure to do so would cause us to breach the reporting requirements under the Credit Agreement and the indenture governing our 8 ³/4% senior notes due 2011, as well as have a material adverse effect on our business, financial condition and results of operations. Until we establish and maintain effective internal controls and procedures for financial reporting, we may not have appropriate procedures in place to eliminate financial statement inaccuracies and avoid delays in financial reporting in the future.

Without waivers by the lenders under our Credit Agreement, we would have been in default under that agreement. After the expiration of those waivers the lenders would be in a position to demand immediate repayment of our debt unless we obtain additional waivers or an amendment or refinancing of the Credit Agreement. In addition, a demand for payment by our lenders could lead to an ability of the holders of our 8 ³/4% senior notes due 2011 to demand immediate repayment of our debt as well.

Without a series of waivers granted by the lenders under our Credit Agreement, at December 31, 2004 we would have been in breach of several financial covenants under that agreement. The waivers also waived other potential defaults. At the filing date of this Form 6-K, those waivers have been extended until April 15, 2005. There is uncertainty with respect to our ability to comply with the financial covenants in the Credit Agreement without a future modification or waiver of those covenants.

In the event that we fail to obtain additional waivers or an amendment of the Credit Agreement or to refinance the indebtedness under that agreement by the expiration of the existing waiver, the bank lenders would be in a position to demand immediate repayment of our debt under the Credit Agreement. An acceleration of the indebtedness under the Credit Agreement that is not rescinded, annulled or otherwise cured by us within 20 days of our receipt of notice of that acceleration also would constitute an Event of Default under the indenture relating to our 8 ³/4% senior notes. If an Event of Default occurs and is continuing under the indenture, the Trustee or the holders of 25% of the principal amount of the notes outstanding under the indenture may accelerate those notes by notice to us.

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 in our Credit Agreement so that the full amount of the revolving credit facility becomes available.

The financial statements included in this report have been prepared on a going concern basis, reflecting the assumption that we will continue in operation for a reasonable period of time and will be able to realize the carrying value of our assets and discharge our liabilities and commitments in the normal course of business. Our ability to continue as a going concern is dependent upon our ability to find new sources of financing or to negotiate a significant amendment to the current covenants that would result in the full amount of our revolving credit facility becoming available. We are currently exploring alternatives to resolve the issue, including seeking alternative financing sources; however, we cannot be sure that a modification of our Credit Agreement or a new financing agreement will be consummated or that we will have access to necessary capital when required to fund our future operations.

If our access to the surety market were to be restricted in the future, or if our demand for surety bonds were to increase significantly, our business could be impaired.

Like all businesses providing similar services, we are at times required to post bid or performance bonds issued by a financial institution known as a surety. The surety industry experiences periods of unsettled and volatile markets,

31

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

usually in the aftermath of substantial loss exposures or corporate bankruptcies with significant surety exposure. Historically, these types of events have caused reinsurers and sureties to reevaluate their committed levels of underwriting and required returns. As needed in the ordinary course of business, we have been able to secure necessary bonds and we will seek opportunities to expand our surety relationships. However, if for any reason, whether because of our financial condition, our level of secured debt or general conditions in the bond market, our bonding capacity becomes insufficient to satisfy our future bonding requirements, our business could be impaired.

We are dependent upon continued outsourcing by our customers of mining and site preparation services.

Outsourced mining and site preparation services constitute a large portion of the work we perform for our customers. For example, our mining project revenues constituted approximately 29%, 29% and 52% of our revenues in the fiscal years ended March 31, 2004, 2003 and 2002, respectively. The election by one or more of our customers to perform some or all of these services themselves, rather than outsourcing the work to us, could have a material adverse impact on our business.

Changes in oil and gas prices could cause our customers to slow down or curtail their current production and future expansions which would in turn reduce our revenue from those customers.

The profitability and growth of our customers may be impacted by the prices of oil and gas. Prices for oil are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil, market uncertainty and a variety of additional factors beyond our control. Such factors include weather conditions, the condition of the Canadian and U.S. economies, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political stability in the Middle East, increasing foreign demand for oil and gas, war or the threat of war in oil producing regions, the foreign supply of oil and the availability of fuel from alternate sources. In addition, our customers make their major expansion investment decisions based on their long-term outlook for the prices of oil and gas and their profitability based on those prices. If they believe the prices of those commodities will remain at depressed levels or that their profitability will be adversely affected by fluctuations in currency exchange rates, they may delay or curtail their current expansion plans. Such a delay or curtailment could have a material adverse impact on our financial condition and results of operations.

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

Because our operations are located in Western Canada and Northern Ontario, we are often subject to extreme weather conditions. While our operations are not significantly affected by normal seasonal weather patterns, extreme weather, including heavy rain and snow, can cause us to delay the completion of a project, which could result in lower margins than estimated.

Insufficient pipeline and refining capacity for heavy crude products could cause our customers to slow down or curtail their current production and future expansions which would, in turn, reduce our revenue from those customers.

While current pipeline capacity is sufficient to transport existing oil sands production to market, future production growth will require increased pipeline capacity. If such increases do not materialize, our customers may be unable to efficiently deliver increased production to market. Additionally, we expect that increases in oil sands production will require added heavy crude oil refinery capacity. Similarly, if such increased capacity or alternative markets do not materialize future growth in demand for our customers’ products could be reduced.

32

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

Because most of our customers are located or operate in Western Canada, a downturn in the energy industry in western Canada could result in a decrease in the demand for our services by our customers.

Most of our customers are located or operate in Western Canada. In the fiscal year ended March 31, 2004, we generated approximately 67% of our operating revenues from the Alberta oil sands. A downturn in the energy industry in Western Canada could cause our customers to slow down or curtail their current production and future expansions which would, in turn, reduce our revenue from those customers. Such a delay or curtailment could have a material adverse impact on our financial condition and results of operations.

Shortages of skilled labor, work stoppages or other labor disruptions at our operations or those of our principal customers or service providers could have an adverse effect on our profitability and financial condition.

Our ability to provide high-quality services on a timely basis requires an adequate number of skilled workers such as engineers, trades people and equipment operators. We cannot assure you that we will be able to maintain an adequate skilled labor force or that our labor expenses will not increase. A shortage of skilled labor would require us to curtail our planned internal growth or may require us to use less skilled labor which could adversely affect our ability to perform work.

Substantially all of our hourly employees are subject to collective bargaining agreements to which we are a party or are otherwise subject because of a bargaining relationship with the particular trade union that is a party to the collective bargaining agreement. Any work stoppage resulting from a strike or lockout could have a material adverse effect on our financial condition and results of operations.

In the province of Alberta, collective bargaining in the construction industry is conducted by sector, by registered groups consisting of an employers’ organization, on behalf of the employers, and a defined group of trade unions, on behalf of the unions in that sector. An employers’ organization which has been registered by the Labour Relations Board bargains with the trade unions named in the certificate on behalf of all employers who work in that part of the construction industry described in the certificate with whom the unions have a bargaining relationship. Any collective agreement entered into by the employers’ organization is binding on all such employers. We do not have control over the terms of such agreements but will be bound by these because of the provisions of the Labour Relations Code and the registrations.

In addition, our customers employ workers under other collective bargaining agreements. Any work stoppage or labor disruption at our key customers could significantly reduce the amount of services that we provide.

Because approximately 80% of the major projects that we pursue are awarded to us based on bid proposals, competitors with lower overhead cost structures may underbid us, subsequently impeding our growth.

Approximately 80% of the major projects that we pursue are awarded to us based on bid proposals. We may compete in the future for these projects against companies that may have substantially greater financial and other resources than we do. Some smaller competitors may have lower overhead cost structures and may be able to provide their services at lower rates than we can. Further, public sector work is often performed by governmental agencies. Our growth may be impacted to the extent that we are unable to successfully bid against these companies.

33

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

Cost overruns by our customers on their projects may cause our customers to terminate future projects or expansions which could adversely affect the amount of work we receive from those customers.

Oil sands development projects require substantial capital expenditures. In the past, several of our customers’ projects have experienced significant cost overruns, impacting their returns. As new projects are contemplated or built, if cost overruns continue to challenge our customers, they could reassess future projects and expansions which could adversely affect the amount of work we receive from our customers, causing an adverse effect on our financial condition.

A significant amount of our revenues are generated by providing non-recurring services.

Approximately 52% of our revenue for the fiscal year ended March 31, 2004 was derived from projects which we consider to be non-recurring. This revenue primarily relates to site preparation and piling services provided for the construction of extraction, upgrading and other oil sands mining infrastructure projects. Future revenues from these types of services will depend upon customers expanding existing mines and developing new projects.

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

A portion of our revenue is derived from contracts which have performance incentives and penalties depending on the total cost of a project as compared to the original estimate. We could incur significant penalties based on cost overruns. In addition, the total project cost as defined in the contract may include not only our work, but also work performed by other contractors. As a result, we could incur penalties due to work performed by others over which we have no control. We may also incur penalties if projects are not completed by specified completion date milestones. Such penalties, if incurred, could have a significant impact on our profitability under these contracts.

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

Our principal customers are energy companies involved in the development of the Alberta oil sands and natural gas production. The operations of these companies, including the mining operations in the oil sands, are subject to or impacted by a wide array of regulations in the jurisdictions where they operate, including those directly impacting mining activities and those indirectly affecting their businesses, such as applicable environmental laws. As a result of changes in regulations and laws relating to the energy production industry including the operation of mines, our customers’ operations could be disrupted or curtailed by governmental authorities. The high cost of compliance with applicable regulations may induce customers to discontinue or limit their operations, and may discourage companies from continuing development activities. As a result, demand for our services could be substantially affected by regulations adversely impacting the energy industry.

34

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

Environmental laws and regulations may expose us to liability arising out of our operations or the operations of our customers in and around sensitive environmental areas.

Our operations are subject to numerous environmental protection laws and regulations that are complex and stringent. Contracts with our customers require us to operate in compliance with these laws and regulations. We regularly perform work in and around sensitive environmental areas such as rivers, lakes and forests. Significant fines and penalties may be imposed on us or our customers for non-compliance with environmental laws and regulations, and our contracts generally require us to indemnify our customers for environmental claims suffered by them as a result of our actions. In addition, some environmental laws provide for joint and several strict liability for remediation of releases of hazardous substances, rendering a person liable for environmental damage, without regard to negligence or fault on the part of such person. In addition to potential liabilities that may be incurred in satisfying these requirements, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances. These laws and regulations may expose us to liability arising out of the conduct of operations or conditions caused by others, or for our acts which were in compliance with all applicable laws at the time these acts were performed.

We own, or lease, and operate several properties that have been used for a number of years for the storage and maintenance of equipment and other industrial uses upon which fuel may have been spilled, or hydrocarbons or other wastes which may have been disposed of or released. Any release of substances by us or by third parties who previously operated on these properties may be subject to laws which impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of hazardous substances into the environment. Under such laws, we could be required to remove or remediate previously disposed wastes and clean up contaminated property.

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

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

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

We intend to pursue selective acquisitions as a method of expanding our business. If we do not successfully integrate acquisitions, we may not realize anticipated operating advantages and cost savings. The integration of companies that have previously operated separately involves a number of risks, including:

• demands on management related to the increase in our size after an acquisition;

• the diversion of our management’s attention from the management of daily operations;

35

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

• difficulties in implementing or unanticipated costs of accounting, estimating, reporting and other systems;

• difficulties in the assimilation and retention of employees; and

• potential adverse effects on operating results.

We may not be able to maintain the levels of operating efficiency that acquired companies will have achieved or might achieve separately. Successful integration of each of their operations will depend upon our ability to manage those operations and to eliminate redundant and excess costs. Because of difficulties in combining operations, we may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve after these acquisitions which would harm our financial condition and results of operations.

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

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

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 effectively manage this risk. The derivative financial instruments consist of three components: a U.S. dollar interest rate swap: a U.S. dollar-Canadian dollar cross currency basis swap; and a Canadian dollar interest rate swap 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 2.5 percent or Canadian bankers’ acceptance rate plus 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 December 31, 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.

36

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis (Restated)

For the period ended December 31, 2004

We are actively pursuing alternate financing to replace the senior secured credit facility. If we are successful in replacing the credit facility, it is likely that the interest rate associated with the alternate financing will be higher than the interest rate under the existing credit facility given our present credit rating.

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.

Outlook

We have faced a number of challenges over the past few months related to the project loss discussed earlier in this MD&A and the misstatement of our financial statements related to prior interim periods. The project was substantially completed in fiscal 2005 with the remaining work to be completed in the first quarter of fiscal 2006. We are in the process of addressing the problems contributing to the misstatement of our financial statements for the interim periods ended June 30, 2004 and September 30, 2004.

Our contract backlog continues to increase as it enters the fourth quarter. High coal, oil, and natural gas prices are driving demand for the services provided by our Mining and Site Preparation operating segment while high construction activity throughout Western Canada continues to drive demand for services provided by the Piling operating segment. Activity in our Pipeline operating segment is expected to remain relatively low through the fourth quarter of the fiscal year as a result of the reduction in the regional development program by our major pipeline customer.

Demand for our services was affirmed subsequent to December 31, 2004 when our joint venture, Noramac Ventures Inc., signed a ten year contract with CNRL to perform overburden removal services on its Horizon Oil Sands project commencing mid 2005.

We are actively pursuing several alternatives to resolve our financing issues. It is likely we will incur a significant non-recurring debt restructuring charge in connection with placing alternate financing. Although management anticipates that it will be successful in resolving the matter, if we are not successful in completing a refinancing and we are unable to cure the covenant violations in the future or fail to be granted further waivers as required, our creditors could demand immediate repayment of our senior secured credit facilities.

U.S. Generally Accepted Accounting Principles

The interim consolidated financial statements have been prepared in accordance with Canadian GAAP, which differs in certain material respects from U.S. GAAP. The nature and effect of these differences is set out in note 12 to the interim consolidated financial statements for the three and nine months ended December 31, 2004 and note 19 of the audited consolidated financial statements for the fiscal year ended March 31, 2004.

37

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
	Chris Hayman
	Vice President, Finance

Date: November 29, 2005