North American Construction 6-K Current report (foreign)

FORM 6-K

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Report of Foreign Private Issuer

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

under the Securities Exchange Act of 1934

For the month of February 2004

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):                    .

Reports included:

1. Interim consolidated financial statements of North American Energy Partners Inc. for the period from November 26, 2003 to December 31, 2003.

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

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Financial Statements

For the period from November 26, 2003 to December 31, 2003

(Expressed in thousands of Canadian dollars)

(Unaudited)

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Balance Sheets

(In thousands of Canadian dollars)

	December 31, 2003			Predecessor Company March 31, 2003 (Derived from audited financial statements)
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	22,364		$	651
Accounts receivable (note 9(a))		41,393			56,622
Unbilled revenue		10,259			24,777
Prepaid expenses		608			300
		74,624			82,350
Capital assets (note 4)		176,673			76,234
Goodwill (note 3)		197,927			—
Intangible assets, net of accumulated amortization of $1,968 (note 3)		17,241			—
Deferred financing costs, net of accumulated amortization of $202 (note 3)		16,266			—
	$	482,731		$	158,584
Liabilities and Shareholder’s Equity
Current liabilities:
Outstanding cheques	$	1,339		$	3,147
Operating line of credit		—			516
Revolving credit facility (note 5)		—			—
Accounts payable (note 9(b))		19,607			28,820
Accrued liabilities		10,308			10,423
Current portion of term credit facility (note 5)		6,000			14,601
Current portion of capital lease obligations (note 6)		641			4,842
Future income taxes		4,000			12,300
Current portion of advances from Norama Inc. (note 11(c))		—			3,100
		41,895			77,749
Term credit facility (note 5)		44,000			7,525
Capital lease obligations (note 6)		2,376			3,943
Senior notes (note 7)		258,480			—
Derivative financial instruments (note 12(c))		4,520			—
Future income taxes		6,660			10,675
Advances from Norama Inc. (note 11(c))		—			28,874
Shareholder’s equity:
Share capital (note 8)		127,500			1
Retained earnings (deficit)		(2,700	)		29,817
		124,800			29,818
Commitments (note 13)
Subsequent event (note 14)
United States generally accepted accounting principles (note 15)
	$	482,731		$	158,584

See accompanying notes to interim consolidated financial statements.

1

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Statements of Operations and Retained Earnings

(In thousands of Canadian dollars)

(Unaudited)

	For the period from November 26, 2003 to December 31, 2003			Predecessor Company
				for the period from October 1, 2003 to November 25, 2003			for the three months ended December 31, 2002			for the period April 1, 2003 to November 25, 2003			for the nine months ended December 31, 2002
Revenue	$	24,444		$	55,420		$	90,178		$	251,679		$	228,237
Project costs		17,467			38,729			58,817			156,835			149,615
Equipment costs		3,653			10,992			17,367			53,847			48,218
Depreciation		1,364			1,177			2,555			6,566			6,963
		22,484			50,898			78,739			217,248			204,796
Gross profit		1,960			4,522			11,439			34,431			23,441
General and administrative		1,065			2,026			2,688			7,893			7,788
Amortization of intangible assets		1,968			—			—			—			—
Operating income (loss)		(1,073	)		2,496			8,751			26,538			15,653
Management fees (note 11(c))		—			18,751			7,000			41,951			13,600
Interest expense, net (note 9(c))		3,050			431			1,554			2,357			3,041
Foreign exchange (gain) loss		12			(7	)		(240	)		(7	)		(235	)
		3,062			19,175			8,314			44,301			16,406
Income (loss) before income taxes		(4,135	)		(16,679	)		437			(17,763	)		(753	)
Income taxes:
Current income taxes		264			13			(20	)		218			(20	)
Future income taxes		(1,699	)		(6,175	)		621			(6,840	)		200
		(1,435	)		(6,162	)		601			(6,622	)		180
Net loss		(2,700	)		(10,517	)		(164	)		(11,141	)		(933	)
Dividends		—			—			—			—			(50	)
Retained earnings, beginning of period		—			29,193			16,559			29,817			17,378
Retained earnings (deficit), end of period	$	(2,700	)	$	18,676		$	16,395		$	18,676		$	16,395

See accompanying notes to interim consolidated financial statements.

2

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Statements of Cash Flows

(In thousands of Canadian dollars)

(Unaudited)

	For the period from November 26, 2003 to December 31, 2003			Predecessor Company
				for the period from October 1, 2003 to November 25, 2003			for the three months ended December 31, 2002			for the period April 1, 2003 to November 25, 2003			for the nine months ended December 31, 2002
Cash provided by (used in):
Operating activities:
Net loss	$	(2,700	)	$	(10,517	)	$	(164	)	$	(11,141	)	$	(933	)
Items not affecting cash:
Depreciation		1,364			1,177			2,555			6,566			6,963
Amortization of intangible assets		1,968			—			—			—			—
Amortization of deferred financing costs		202			—			—			—			—
Gain on sale of capital assets		—			—			(59	)		(49	)		(1,540	)
Bad debt expense (recovery)		—			71			9			110			(55	)
Future income taxes		(1,699	)		(6,175	)		621			(6,840	)		200
Net changes in non-cash working capital (note 9(e))		2,752			(462	)		12,395			12,790			1,908
		1,887			(15,906	)		15,357			1,436			6,543
Investing activities:
Acquisition (note 3)		(369,071	)		—			—			—			—
Purchase of capital assets		(734	)		(156	)		(7,503	)		(5,102	)		(20,112	)
Proceeds on disposal of capital assets		287			6			198			609			3,068
		(369,518	)		(150	)		(7,305	)		(4,493	)		(17,044	)
Financing activities:
Issuance of share capital		92,500			—			—			—			—
Issuance of senior notes		263,000			—			—			—			—
Proceeds from term credit facility		50,000			—			5,550			—			13,500
Financing costs		(16,468	)		—			—			—			—
Increase (decrease) in operating line of credit		—			—			(14,127	)		(516	)		1,966
Repayment of term bank loans		—			(1,094	)		(1,464	)		(4,428	)		(3,586	)
Repayments of capital lease obligations		(57	)		(767	)		(962	)		(3,289	)		(1,974	)
Increase (decrease) in outstanding cheques		1,020			(3	)		(211	)		(2,828	)		(2,266	)
Advances from Norama Inc.		—			15,412			3,848			18,637			3,167
Dividends paid		—			—			—			—			(50	)
		389,995			13,548			(7,366	)		7,576			10,757
Increase (decrease) in cash		22,364			(2,508	)		686			4,519			256
Cash, beginning of period		—			7,678			6			651			436
Cash, end of period	$	22,364		$	5,170		$	692		$	5,170		$	692

Cash consists of cash and cash equivalents. Supplemental cash flow information in note 9(d).

See accompanying notes to interim consolidated financial statements.

3

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the period from November 26, 2003 to December 31, 2003

(Amounts in thousands of Canadian dollars unless otherwise specified.)

(Unaudited)

1. Nature of operations:

North American Energy Partners Inc. (the “Company”) was incorporated under the Canada Business Corporations Act on October 17, 2003. The Company had no operations prior to November 26, 2003. After giving effect to the acquisition described in note 3, the Company completes all forms of earth works projects including contract mining, industrial and commercial site development, pipeline and piling installation, underground water and sewer installation and road building. The Company is a wholly-owned subsidiary of NACG Preferred Corp. which in turn is a wholly-owned subsidiary of NACG Holdings Inc.

2. Significant accounting policies:

(a) Basis of presentation:

These unaudited consolidated interim financial statements, in the opinion of management, contain all adjustments (consisting solely of normal recurring adjustments) necessary to present fairly the financial information for such unaudited periods and the accounting policies applied therein are consistent with those described below.

The consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles (“GAAP”). Material inter-company transactions and balances are eliminated on consolidation. Material items that could give rise to measurement differences to these consolidated financial statements under United States GAAP are outlined in note 15.

As described in note 3, on November 26, 2003, NACG Preferred Corp. and NACG Acquisition Inc. (“Acquisition”), a wholly owned subsidiary of the Company, acquired from Norama Ltd. (the “Predecessor Company”) all of the outstanding common shares of North American Construction Group Inc. (“NACGI”) and Acquisition acquired substantially all of the capital assets and prepaid expenses of North American Equipment Ltd. (“NAEL”). NACG Preferred Corp. contributed the shares of NACGI it acquired from Norama Ltd. to the Company who then contributed those shares to Acquisition. Acquisition and NACGI amalgamated on the same day and the successor company continued as NACGI. The results of NACGI’s operations have been included in the consolidated financial statements of the Company since that date.

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

4

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the period from November 26, 2003 to December 31, 2003

(Amounts in thousands of Canadian dollars unless otherwise specified.)

(Unaudited)

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

(b) Use of estimates:

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

(c) Revenue recognition:

The Company performs its projects under all of the following types of contracts: (i) time-and-materials at marked-up rates; (ii) cost-plus-incentive-fee where incentive is based on cost; (iii) unit-price; and (iv) fixed-price or lump-sum. For time-and-materials and cost-plus-incentive-fee contracts, revenue is recognized as costs are incurred. Revenue from unit-price contracts is recognized based on quantities of units performed and delivered. Revenue on lump-sum contracts is recognized on the percentage-of-completion method, measured by the ratio of costs incurred to date to estimated total costs.

Contract project costs include all direct labour, material, subcontractors and those indirect costs related to contract performance such as indirect labour, supplies, and tool costs. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Changes in job performance, job conditions, and estimated profitability, including those arising from contract penalty provisions and final contract settlements may result in revisions to costs and income and are recognized in the period in which such adjustments are determined. Profit incentives are included in revenue when their realization is reasonably assured. Claims are included in revenue when awarded or received.

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

(d) Cash and cash equivalents:

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

(e) Allowance for doubtful accounts:

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

5

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the period from November 26, 2003 to December 31, 2003

(Amounts in thousands of Canadian dollars unless otherwise specified.)

(Unaudited)

(f) Capital assets:

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

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

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

(g) Goodwill:

Goodwill represents the excess purchase price paid by the Company over the fair value of the tangible and identifiable intangible assets and liabilities acquired. Goodwill is not being amortized, but instead will be tested for impairment at least annually. Impairment is tested at the reporting unit level by comparing the reporting unit’s carrying amount to its fair value. The fair value of the reporting units is estimated using a combination of market approach and discounted cash flows. To the extent a reporting unit’s carrying amount exceeds its fair value, an impairment of goodwill exits. As of December 31, 2003, the Company does not believe any impairment of goodwill has occurred.

(h) Intangible assets:

Intangible assets acquired include customer contracts in progress, customer relationships and trade names, all of which are amortized on a straight-line basis over the remaining terms of each individual contract. Also acquired are employee arrangements which are amortized on a straight-line basis over the expected benefit period.

(i) Deferred financing costs:

Costs relating to the issuance of the senior notes and the senior secured credit facility have been deferred and are being amortized on a straight-line basis over the terms of the debt which are 8 years and 5 years, respectively.

6

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the period from November 26, 2003 to December 31, 2003

(Amounts in thousands of Canadian dollars unless otherwise specified.)

(Unaudited)

(j) Impairment of long-lived assets:

In accordance with CICA Handbook Section 3063, “Impairment or Disposal of Long-Lived Assets” and the revised Section 3475 “Disposal of Long-Lived Assets and Discontinued Operations,” the Company has classified assets as either held-for-use or available-for-sale. An impairment loss is recognized when the carrying amount of an asset that is held and used exceeds the projected undiscounted future net cash flows expected from its use and disposal. The loss is measured as the amount by which the carrying amount of the asset exceeds its fair value, which is measured by discounted cash flows when quoted market prices are not available. For assets available-for-sale, an impairment loss is recognized when the carrying amount exceeds the fair value less costs to sell.

(k) Foreign currency translation and hedging:

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

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

The Company does not hold or issue derivative financial instruments for trading or speculative purposes. Derivative financial instruments are subject to standard credit terms and conditions, financial controls, management and risk monitoring procedures.

(l) Income taxes:

The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, future tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and

7

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the period from November 26, 2003 to December 31, 2003

(Amounts in thousands of Canadian dollars unless otherwise specified.)

(Unaudited)

liabilities and their respective tax bases. Future tax assets and liabilities are measured using enacted or substantively enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on future tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date of enactment or substantive enactment.

3. Acquisition:

On November 26, 2003, NACG Preferred Corp. and NACG Acquisition Inc. (“Acquisition”), a wholly owned subsidiary of the Company, acquired from Norama Ltd. (the “Predecessor Company”) all of the outstanding common shares of North American Construction Group Inc. (“NACGI”) and Acquisition acquired substantially all of the capital assets and prepaid expenses of North American Equipment Ltd. (“NAEL”). NACG Preferred Corp. contributed the shares of NACGI it acquired from Norama Ltd. to the Company who then contributed those shares to Acquisition. Acquisition and NACGI amalgamated on the same day and the successor company continued as NACGI. The purchase price was approximately $230 million for the NACGI common shares and $175 million for the capital assets and prepaid expenses of NAEL. The purchase price is subject to an adjustment based on the closing working capital of NACGI at November 25, 2003 which is estimated to be an additional $1.0 million and has been accounted for as increased goodwill.

The Company accounted for the acquisition as a business combination using the purchase method. The following table summarizes the fair value of the assets acquired and liabilities assumed at the date of acquisition.

Current assets, including cash of $19,961	$	84,360
Capital assets, including capital leases of $2,131		176,647
Intangible assets		19,209
Goodwill		197,927
Total assets acquired		478,143
Current liabilities		(39,621	)
Future income taxes		(12,359	)
Capital lease obligations		(2,131	)
Total liabilities assumed		(54,111	)
Net assets acquired	$	424,032

8

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the period from November 26, 2003 to December 31, 2003

(Amounts in thousands of Canadian dollars unless otherwise specified.)

(Unaudited)

The acquisition was financed as follows:

Proceeds from issuance of senior notes	$	263,000
Proceeds from issuance of share capital		127,500
Proceeds from initial borrowing under the new:
Term credit facility		50,000
Revolving credit facility		—
Less: deferred financing costs		(16,468	)
	$	424,032

The net cash cost of the acquisition is:

Net assets acquired	$	424,032
Less: non-cash portion of share capital		(35,000	)
Less: cash acquired from acquisition and financing		(19,961	)
	$	369,071

The intangible assets relate to customer relationships and contracts and employee arrangements and are subject to amortization. The goodwill was assigned to mining and site preparation, piling and pipeline segments in the amounts of $125,055, $40,222, and $32,650, respectively. None of the goodwill is expected to be deductible for income tax purposes.

The current assets include $19,961 in cash acquired, of which $15,623 was surplus cash from the financing. Common shares valued at $35 million were issued in exchange for a portion of the NACGI shares acquired from NACG Preferred Corp.

4. Capital assets:

December 31, 2003	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	153,418	$	872	$	152,546
Major component parts in use		2,462		36		2,426
Spare component parts		450		—		450
Other equipment		9,987		149		9,838
Licensed motor vehicles		10,288		259		10,029
Office and computer equipment		1,432		48		1,384
	$	178,037	$	1,364	$	176,673

The above amounts include $3,017 of assets under capital lease and accumulated depreciation of $75 related thereto. During the period November 26, 2003 to December 31, 2003, capital additions included $943 of assets which were acquired by means of capital leases.

5. Senior Secured Credit Facility:

On November 26, 2003, the Company secured a $120 million senior credit facility with a syndicate of lenders. The facility is comprised of a $70 million revolving credit facility, subject to borrowing base

9

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the period from November 26, 2003 to December 31, 2003

(Amounts in thousands of Canadian dollars unless otherwise specified.)

(Unaudited)

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

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

2004	$	6,000
2005		11,000
2006		11,000
2007		11,000
2008		11,000
	$	50,000

6. Capital lease obligations:

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

	December 31, 2003
	(Unaudited)
2004	$	905
2005		742
2006		742
2007		923
		3,312
Less amount representing interest - average rate of 5.3%		(295	)
Present value of minimum capital lease payments		3,017
Less: current portion		(641	)
	$	2,376

7. Senior notes:

The senior notes were issued on November 26, 2003 in the amount of US$ 200 million. These notes mature on December 1, 2011 and bear interest at 8.75% payable semi-annually on June 1 and December 1 of each year, which has been swapped into a fixed rate of 9.765% for the duration for which the senior notes are outstanding.

The notes are unsecured senior obligations and rank equally with all other existing and future unsecured and unsubordinated debt and senior to all subordinated debt of the Company. The notes are effectively subordinated to all secured debt, including debt under the secured credit facility (note 5), to the extent of the value of the assets securing such debt.

10

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the period from November 26, 2003 to December 31, 2003

(Amounts in thousands of Canadian dollars unless otherwise specified.)

(Unaudited)

The foreign exchange exposure relating to the senior notes has been hedged – see note 12 (c).

8. Share capital:

Authorized:

Unlimited number of common voting shares.

Issued:

	Number of shares	Amount
Balance December 31, 2003	100	$	127,500

Common shares were issued to NACG Preferred Corp. for cash consideration of $92.5 million and NACGI shares valued at $35 million.

9. Other information:

(a) Accounts receivable:

	December 31, 2003			Predecessor Company March 31, 2003
	(Unaudited)
Accounts receivable – trade	$	33,382		$	51,328
Accounts receivable – holdbacks		8,271			4,671
Accounts receivable – other		2			775
Allowance for doubtful accounts		(262	)		(152	)
	$	41,393		$	56,622

Reflective of its normal business, a majority of the Company’s accounts receivable are due from large companies operating in the resource sector. The Company regularly monitors the activity and balances in these accounts to manage its credit risk and provides an allowance for any doubtful accounts. At December 31, 2003, one customer represented 40% (March 31, 2003 – 50%), of accounts receivable and unbilled revenue.

11

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the period from November 26, 2003 to December 31, 2003

(Amounts in thousands of Canadian dollars unless otherwise specified.)

(Unaudited)

(b) Accounts payable:

	December 31, 2003		Predecessor Company March 31, 2003
	(Unaudited)
Accounts payable – trade	$	18,953	$	28,777
Accounts payable – holdbacks		654		43
	$	19,607	$	28,820

(c) Interest expense, net:

	For the period from November 26, 2003 to December 31, 2003			Predecessor Company
				for the period from October 1, 2003 to November 25, 2003			for the three months ended December 31, 2002			for the period from April 1, 2003 to November 25, 2003			for the nine months ended December 31, 2002
Interest on senior notes	$	2,532		$	—		$	—		$	—		$	—
Interest on senior secured credit facility		350			79			197			599			456
Interest on capital lease obligations		9			57			73			294			143
Interest on advances from Norama Inc.		—			297			594			1,468			1,585
Interest on long-term debt		2,891			433			864			2,361			2,184
Amortization of deferred financing costs		202			—			—			—			—
Other interest		6			8			692			96			860
Interest income		(49	)		(10	)		(2	)		(100	)		(3	)
	$	3,050		$	431		$	1,554		$	2,357		$	3,041

(d) Supplemental cash flow information:

	For the period from November 26, 2003 to December 31, 2003		Predecessor Company
			for the period from October 1, 2003 to November 25, 2003		for the three months ended December 31, 2002		for the period from April 1, 2003 to November 25, 2003		for the nine months ended December 31, 2002
	(Unaudited)
Cash paid during the period for:
Interest	$	524	$	510	$	950	$	2,431	$	1,454
Income taxes		5		18		60		325		190
Interest received		49		10		2		100		3

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the period from November 26, 2003 to December 31, 2003

(Amounts in thousands of Canadian dollars unless otherwise specified.)

(Unaudited)

(e) Net change in non-cash working capital:

	For the period from November 26, 2003 to December 31, 2003			Predecessor Company
				for the period from October 1, 2003 to November 25, 2003			for the three months ended December 31, 2002		for the period from April 1, 2003 to November 25, 2003			for the nine months ended December 31, 2002
	(Unaudited)
Accounts receivable	$	11,781		$	(13,149	)	$	8,700	$	3,338		$	(4,775	)
Unbilled revenue		(11	)		2,836			—		14,529			12,723
Prepaid expenses		369			—			389		(544	)		(164	)
Accounts payable		(6,419	)		7,962			2,722		(2,794	)		(3,713	)
Accrued liabilities		(2,968	)		1,889			584		(1,739	)		(2,163	)
	$	2,752		$	(462	)	$	12,395	$	12,790		$	1,908

10. Segmented information:

(a) General overview:

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

• Mining and Site Preparation:

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

• Piling:

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

• Pipeline:

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

(b) Results by business segment:

For the period from November 26, 2003 to December 31, 2003	Mining & Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	10,098	$	3,025	$	11,321	$	24,444
Depreciation of capital assets		526		125		102		753
Segment profits		859		810		2,070		3,739
Segment assets		282,861		76,775		62,244		421,880
Expenditures for segment capital assets		40		—		578		618

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the period from November 26, 2003 to December 31, 2003

(Amounts in thousands of Canadian dollars unless otherwise specified.)

(Unaudited)

Predecessor Company For the period from October 1, 2003 to November 25, 2003	Mining & Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	35,786	$	8,439	$	11,195	$	55,420
Depreciation of capital assets		473		229		70		772
Segment profits		5,569		1,295		2,123		8,987
Segment assets		78,564		31,792		15,904		126,260
Expenditures for segment capital assets		31		11		—		42
Predecessor Company For the three months ended December 31, 2002	Mining & Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	67,053	$	15,931	$	7,194	$	90,178
Depreciation of capital assets		1,251		631		36		1,918
Segment profits		6,550		3,297		1,063		10,910
Segment assets		74,689		32,581		10,417		117,687
Expenditures for segment capital assets		10,161		620		—		10,781
Predecessor Company For the period from April 1, 2003 to November 25, 2003	Mining & Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	183,445	$	39,368	$	28,866	$	251,679
Depreciation of capital assets		3,590		1,256		158		5,004
Segment profits		28,314		8,318		5,054		41,686
Segment assets		78,564		31,792		15,904		126,260
Expenditures for segment capital assets		2,458		417		—		2,875
Predecessor Company For the nine months ended December 31, 2002	Mining & Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	169,833	$	47,249	$	11,155	$	228,237
Depreciation of capital assets		3,286		1,872		76		5,234
Segment profits		20,321		9,878		1,207		31,406
Segment assets		74,689		32,581		10,417		117,687
Expenditures for segment capital assets		19,454		3,519		—		22,973

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the period from November 26, 2003 to December 31, 2003

(Amounts in thousands of Canadian dollars unless otherwise specified.)

(Unaudited)

(c) Reconciliations:

(i) Income (loss) before income taxes:

	For the period from November 26, 2003 to December 31, 2003			Predecessor Company
				for the period from October 1, 2003 to November 25, 2003			for the three months ended December 31, 2002			for the period from April 1, 2003 to November 25, 2003			for the nine months ended December 31, 2002
	(Unaudited)
Total profit for reportable segments	$	3,739		$	8,987		$	10,910		$	41,686		$	31,406
Unallocated corporate expenses		(6,094	)		(21,201	)		(11,002	)		(52,194	)		(24,193	)
Unallocated equipment revenues (costs)		(1,780	)		(4,465	)		529			(7,255	)		(7,966	)
Income (loss) before income taxes	$	(4,135	)	$	(16,679	)	$	437		$	(17,763	)	$	(753	)

(ii) Total assets:

	December 31, 2003		Predecessor Company March 31, 2003
	(Unaudited)
Total assets for reportable segments	$	421,880	$	143,460
Corporate assets		60,851		15,124
Total enterprise assets	$	482,731	$	158,584

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

11. Related party transactions:

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

(a) Transactions with Sponsors:

On November 21, 2003, The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc., and Stephens Group, Inc., (the “Sponsors”), entered into an agreement with NACG Holdings Inc. and certain of its subsidiaries, including the Company. Pursuant to this agreement, the Sponsors provided consulting and advisory services with respect to the organization of the companies, the structuring of the acquisition as described in Note 3 and the related financing, employee benefit and compensation arrangements and other matters. The agreement also provides that each of the companies, jointly and

15

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the period from November 26, 2003 to December 31, 2003

(Amounts in thousands of Canadian dollars unless otherwise specified.)

(Unaudited)

severally, will indemnify the Sponsors against liabilities relating to their services. As compensation for these services, the Company paid, at the closing of the acquisition, a one-time transaction fee of US$3.0 million to Sterling and a one-time transaction fee of US$3.0 million that was shared among the Sponsors and BNP Paribas Private Capital Group on a pro rata basis in accordance with their respective equity commitments to NACG Holdings Inc. In addition, the Company paid US$486 to reimburse the Sponsors and BNP Paribas Private Capital Group for their travel and other expenses incurred in connection with the acquisition. In accordance with the terms of the agreement, at the closing of the acquisition, the Company paid to the Sponsors a pro rated advisory fee for the period from closing until March 31, 2004 totalling $133. In addition, as compensation for the services provided by the Sponsors after the closing of the acquisition, the agreement provides that on each June 30 through June 30, 2013, the Company will pay the Sponsors whose services have not terminated in accordance with the agreement, as a group, an annual advisory fee in cash totalling the greater of $400 and 0.5% of the Company’s EBITDA for the previous twelve month period ended March 31.

(b) Office rent:

Pursuant to a five year office lease agreement which expires on November 1, 2007, for the period from November 26, 2003 to December 31, 2003, the Company paid $50 to a company owned, indirectly and in part, by one of the Directors.

(c) Predecessor company transactions:

Norama Inc., the parent company of Norama Ltd., charged a fee for management services provided to NACGI. The management fee represented an amount equivalent to the estimated taxable income with the result that no current taxes were payable by NACGI. The advances from Norama Inc. were interest bearing at prime plus 2% without any fixed terms of repayment.

Subsequent to the acquisition, Norama Inc. paid bonuses to employees of the Company in the amount of $1,414.

12. Financial instruments:

The Company is exposed to market risks related to foreign currency fluctuations. To mitigate these risks, the Company uses derivative financial instruments such as foreign currency swap contracts. The Company is also exposed to market risks associated with changes in interest rates. To manage these risks, the Company uses interest rate swaps.

(a) Fair value:

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

The fair value of the senior credit facility, senior notes and capital lease obligations (collectively “the debt”) are based on management estimates which are determined by discounting cash flows required under the debt at the interest rate currently estimated to be available for loans with similar terms.

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the period from November 26, 2003 to December 31, 2003

(Amounts in thousands of Canadian dollars unless otherwise specified.)

(Unaudited)

Based on these estimates, the fair value of the Company’s debt as at December 31, 2003 is not significantly different than its carrying value.

The fair value of the advances from Norama Inc. is not determinable.

(b) Interest rate risk:

The Company is subject to interest rate risk on the senior credit facility and capital lease obligations. At December 31, 2003, for each 1% annual fluctuation in the interest rate, the annual cost of financing will change by approximately $527.

The Company also leases equipment (as described in note 13) with a variable lease payment component that is tied to prime rates. At December 31, 2003, for each 1% annual fluctuation in these rates, annual lease expense will change by approximately $60.

(c) Foreign currency risk and derivative financial instruments:

The Company has senior notes denominated in U.S. dollars in the amount of US$ 200 million. In order to reduce its exposure to changes in the U.S. to Canadian dollar exchange rate, the Company, concurrent with the closing of the acquisition on November 26, 2003, entered into a cross currency swap agreement to hedge this foreign currency exposure and buy U.S. dollars for both the principal balance due on December 1, 2011 as well as the semi-annual interest payments through the whole period beginning from the issuance date to the maturity date. As part of the cross currency swap agreement, the Company also entered into a U.S. dollar interest rate swap and a Canadian dollar interest rate swap with the net effect of converting the 8.75% rate payable on the senior notes into a fixed rate of 9.765% for the duration that the senior notes are outstanding.

The carrying amount and fair value of the Company’s derivative financial instruments are as follows:

	Carrying Amount			Fair Value
Cross currency and interest rate swaps	$	(4,520	)	$	(15,216	)

At December 31, 2003, the notional principal amount of the cross-currency swap was US$200 million. The notional principal amounts of the interest rate swaps were US$200 million.

13. Commitments:

The future minimum lease payments in respect of operating leases amount to approximately $4,773. Annual payments in the next five calendar years are: 2004 – $2,417; 2005 - $1,053; 2006 - $665; 2007 - $615; 2008 - $23.

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the period from November 26, 2003 to December 31, 2003

(Amounts in thousands of Canadian dollars unless otherwise specified.)

(Unaudited)

14. Subsequent event:

On January 29, 2004, the Board of Directors of NACG Holdings Inc. granted stock options to certain key employees of the Company and to its directors for the purchase of 54,130 common shares. The options will vest over the next five years at an amount equal to 20% per year of the total approved grant. The Company has adopted the revised CICA Handbook Section 3870, “Stock Based Compensation,” which requires that a fair value method of accounting be applied to all stock-based compensation payments to both employees and non-employees. In accordance with the transitional provisions of Section 3870, the Company has prospectively applied the fair value method of accounting for stock option awards granted after January 1, 2003 and, accordingly, will record compensation expense during the quarter and year ended March 31, 2004.

15. United States generally accepted accounting principles:

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

During the period ended December 31, 2003 the Company entered into a series of derivatives that have been designated as a hedge of the risk of changes in cash flows resulting from the impact of changes in the U.S. to Canadian dollar exchange rate applicable to the payments of interest and principal on the senior notes. In accordance with the provisions of SFAS 133 “Accounting for Derivatives and Hedging Activities”, all derivatives are recognized as assets and liabilities on the balance sheet and measured at fair value. As of December 31, 2003, the fair value of the derivatives was $15,216. The Company has elected to measure and assess effectiveness based on total changes in the cash flows generated by hedging instruments. Each period, an amount equal to the gain or loss resulting on the remeasurement of the hedged item at spot rates is reclassified from Other Comprehensive Income and recorded as an offset to the foreign currency gains or losses otherwise recorded. In addition, the Company reclassifies an amount to reflect the cost element of the hedging instrument. During the period ended December 31, 2003, $1,750 (net of tax of $926) was reclassified from Other Comprehensive Income and included in income.

Recent United States accounting pronouncements:

In December 2003, the U.S. Financial Accounting Standards Board, or FASB, issued FASB Interpretation No. 46 (revised December 2003),Consolidation of Variable Interest Entities, which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity. FIN 46R replaces FASB Interpretation No. 46,Consolidation of Variable Interest Entities (“FIN 46R”), which was issued in January 2003. The Company will be required to apply FIN 46R to variable interests in Variable Interest Entities, or VIEs created after December 31, 2003. With respect to entities that do not qualify to be assessed for consolidation based on voting interests, FIN 46R generally requires a company that has a variable interest(s) that will absorb a

18

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Interim Consolidated Financial Statements

For the period from November 26, 2003 to December 31, 2003

(Amounts in thousands of Canadian dollars unless otherwise specified.)

(Unaudited)

majority of the VIE’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur, or both, to consolidate that VIE. For variable interests in VIEs created before January 1, 2004, the Interpretation will be applied beginning on January 1, 2005. For any VIEs that must be consolidated under FIN 46R that were created before January 1, 2004, the assets, liabilities and noncontrolling interests of the VIE initially would be measured at their carrying amounts with any difference between the net amount added to the balance sheet and any previously recognized interest being recognized as the cumulative effect of an accounting change. If determining the carrying amounts is not practicable, fair value at the date FIN 46R first applies may be used to measure the assets, liabilities and noncontrolling interest of the VIE. The adoption of this standard did not have a material impact on these financial statements.

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

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Overview

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

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

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

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

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

The Acquisition

We are wholly owned by NACG Preferred Corp., which is in turn wholly owned by NACG Holdings Inc. The common equity of NACG Holdings Inc. is primarily owned by an investor group which includes The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc., Stephens Group, Inc. and BNP Paribas Private Capital Group, through Paribas North America, Inc., as well as the Company’s management and employees.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

Prior to November 26, 2003, North American Equipment Ltd., or “NAEL,” and North American Construction Group Inc., or “NACGI,” were wholly owned subsidiaries of Norama Ltd. (“Norama” or the “Predecessor” company). On November 26, 2003, Norama sold 30 common shares of NACGI to NACG Preferred Corp. and all of the remaining 170 common shares of NACGI to NACG Acquisition Inc., our wholly owned subsidiary. In addition, Norama sold substantially all of NAEL’s assets to NACG Acquisition Inc. The preceding events are referred to as the “Acquisition”. Immediately after the consummation of the Acquisition, NACG Acquisition Inc. was amalgamated with NACGI and the successor company continued as NACGI.

The information as of December 31, 2003 and for the period from November 26, 2003 to December 31, 2003, may not be directly comparable to the information provided related to the Predecessor company as a result of the effect of the revaluation of assets and liabilities to their estimated fair market values in accordance with the application of purchase accounting pursuant to Canadian and U.S. GAAP.

Critical Accounting Policies

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

Revenue recognition

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

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

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

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

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

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

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

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

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

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

Profit for each type of contract is included in 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 clients as to both the scope of work and price. Revenue from claims is recognized when an agreement is reached with clients as to the value of the claims, which in some instances may not occur until after completion of work under the contract. Costs incurred for bidding and obtaining contracts are expensed as incurred.

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

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

Capital assets

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

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

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

Hedge accounting

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

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

Results of Operations($ in thousands of Canadian dollars)

	Quarter ended December 31 2003					Quarter ended December 31 2002					Nine months ended December 31 2003					Nine months ended December 31 2002
Revenue	$	79,864		100.0	%	$	90,178		100.0	%	$	276,123		100.0	%	$	228,237		100.0	%
Project costs		56,196		70.4	%		58,817		65.2	%		174,302		63.1	%		149,615		65.6	%
Equipment costs		14,645		18.3	%		17,367		19.3	%		57,500		20.8	%		48,218		21.1	%
Depreciation		2,541		3.2	%		2,555		2.8	%		7,930		2.9	%		6,963		3.1	%
Gross Profit		6,482		8.1	%		11,439		12.7	%		36,391		13.2	%		23,441		10.3	%
General and administrative		3,091		3.9	%		2,688		3.0	%		8,958		3.2	%		7,788		3.4	%
Amortization of intangibles		1,968		2.5	%		—		0.0	%		1,968		0.7	%		—		0.0	%
Operating income (loss)		1,423		1.8	%		8,751		9.7	%		25,465		9.2	%		15,653		6.9	%
Interest expense, net		3,481		4.4	%		1,554		1.7	%		5,407		2.0	%		3,041		1.3	%
Management fees		18,751		23.5	%		7,000		7.8	%		41,951		15.2	%		13,600		6.0	%
Foreign exchange (gain) loss		5		0.0	%		(240	)	-0.3	%		5		0.0	%		(235	)	-0.1	%
Income (loss) before income taxes	$	(20,814	)	-26.1	%	$	437		0.5	%	$	(21,898	)	-7.9	%	$	(753	)	-0.3	%
Other data
Equipment hours		128,190					171,056					506,563					446,167

Quarter Ended December 31, 2003 (Pre-Acquisition period October 1, 2003 to November 25, 2003 and post-Acquisition period November 26, 2003 to December 31, 2003) compared to Quarter Ended December 31, 2002

Revenue

Revenue for the quarter ended December 31, 2003 decreased by $10.3 million to $79.9 million, as compared to $90.2 million for the quarter ended December 31, 2002. This decrease is primarily due to lower revenue realized in providing mining and site preparation as well as piling services offset by a significant increase in pipeline services. Unscheduled maintenance at the Syncrude site as well as start-up delays at the Albian site contributed to the lower mining and site preparation results. Pipeline revenue is up due to increased activity by EnCana in Northeastern British Columbia.

Project costs

Project costs consist of all direct labor, materials and subcontract expenses. Project costs for the quarter ended December 31, 2003 decreased by $2.6 million to $56.2 million, as compared to $58.8 million for the quarter ended December 31, 2002. The decrease was primarily attributable to the lower revenues as noted above. However, these costs increased as a percentage of revenue due to a higher proportion of lower margin time-and-material contracts as compared to the comparable quarter in 2002.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

Equipment costs

Equipment costs are comprised of repairs and maintenance as well as lease and rental expenses. Equipment costs were $14.6 million in 2003 as compared to $17.4 million in 2002. The decrease related to lower equipment hours and a usage of certain pieces of heavy equipment that were subject to guaranteed maintenance cost per hour contracts with equipment suppliers. Also contributing to the decrease is lower lease and rental expense due to the buy-out of most leases and rentals concurrent with the Acquisition. In future periods, the equipment costs relating to leasing and rentals is expected to be lower due to this buy-out.

Depreciation

Depreciation expense remained constant at $2.5 million for the quarter ended December 31, 2003, as compared to the quarter ended December 31, 2002. While the number of heavy equipment hours decreased in the quarter ended December 31, 2003 as compared to the quarter ended December 31, 2002, the depreciable base was increased as a result of the revaluation of assets and liabilities to their estimated fair market values in accordance with the application of purchase accounting in connection with the Acquisition.

General and administrative expenses

General and administrative expenses increased by $0.4 million to $3.1 million for the three months ended December 31, 2003, as compared to $2.7 million for the quarter ended December 31, 2002. This increase was primarily attributable to $0.5 million in bonuses paid out to employees just prior to the closing of the Acquisition.

Amortization of intangibles

Intangible assets were acquired in the Acquisition and relate to customer contracts, customer relationships and employee arrangements. The intangibles are amortized over the estimated terms of the contracts, which are relatively short on average, and the expected employee retention period of 3 years.

Interest expense, net

Interest expense, net of interest income, increased significantly to $3.5 million for the three months ended December 31, 2003, as compared to $1.6 million for the three months ended December 31, 2002. This increase was primarily due to larger debt balances with higher associated interest rates incurred in connection with the Acquisition.

Management fees

Management fee expense increased from $7.0 million to $18.8 million for the three months ended December 31, 2003, as compared to the three months ended December 31, 2002. Management fees of the Predecessor company represent fees for services rendered consisting of an amount equivalent to the estimated taxable income with the result that no current tax was payable. Subsequent to the Acquisition, no similar management fees will be payable.

Foreign exchange (gain) loss

The foreign exchange (gains) and losses are relatively small and relate primarily to the exchange differences between the Canadian and US dollar for certain leases and equipment related purchases. The US dollar denominated senior notes are effectively hedged with the cross currency swap and accordingly, no gain or loss is reflected in respect of this debt.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

Nine Months Ended December 31, 2003 (Pre-Acquisition period April 1, 2003 to November 25, 2003 and post-Acquisition period November 26, 2003 to December 31, 2003) compared to Nine Months Ended December 31, 2002

Revenue

Revenue for the nine months ended December 31, 2003 increased by $47.9 million to $276.1 million, as compared to $228.2 million for the nine months ended December 31, 2002. Increases in revenues generated by the pipeline and mining and site preparation segments accounted for $29.0 million and $23.7 million, respectively, of the total increase. These increases were partially offset by a $4.9 million decline in revenues generated by the piling segment.

Project costs

Project costs for the nine months ended December 31, 2003 increased to $174.3 million as compared to $149.6 million for the nine months ended December 31, 2002. The increase was primarily attributable to the higher volume of services provided in the period. As a percentage of revenue, project costs decreased from 66% to 63% year over year due to a larger proportion of higher margin unit-price contract work and smaller proportion of lower margin cost-plus work as compared to the prior period.

Equipment costs

Equipment costs increased by $9.3 million to $57.5 million, but remained relatively unchanged as a percentage of revenue. This increase in equipment costs was primarily attributable to the completion of a number of scheduled major equipment overhauls during this period. In addition, the increase related to a higher usage of certain pieces of heavy equipment that were subject to guaranteed maintenance cost per hour contracts with equipment suppliers. Also, the higher level of equipment utilization, as evidenced by the increased equipment hours, resulted in a greater number of parts required to be replaced. Equipment costs also include expenses relating to leasing and rentals. These costs are expected to be lower in future periods as most of the leases were bought out in connection with the Acquisition.

Depreciation

Depreciation expense increased by $0.9 million to $7.9 million for the nine months ended December 31, 2003, as compared to $7.0 million for the nine months ended December 31, 2002. This increase was primarily attributable to an increase in equipment hours on our large shovels. Because these shovels have a relatively high capital cost, the rate of depreciation on a cost per hour basis is also high and therefore the increase in hours significantly affects overall depreciation expense. As a percentage of revenue, depreciation decreased slightly from 3.1% to 2.9%.

General and administrative expenses

General and administrative expenses increased by $1.2 million to $9.0 million for the nine months ended December 31, 2003, as compared to $7.8 million for the nine months ended December 31, 2002. This increase was primarily attributable to general salary increases as well as higher staff levels and to higher travel costs which are associated with management personnel making more frequent site visits.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

Amortization of intangibles

Intangible assets were acquired in the Acquisition and relate to customer contracts, customer relationships and employee arrangements. The intangibles are amortized over the estimated terms of the contracts, which are relatively short on average, and the expected employee retention period of 3 years.

Interest expense, net

Interest expense, net of interest income, increased by $2.4 million to $5.4 million for the nine months ended December 31, 2003, as compared to $3.0 million for the nine months ended December 31, 2002. This increase was primarily due to larger debt balances with higher associated interest rates incurred in connection with the Acquisition.

Management fees

Management fee expense increased by $28.4 million to $42.0 million for the nine months ended December 31, 2003, as compared to $13.6 million for the nine months ended December 31, 2002. Management fees of the Predecessor company represent fees for services rendered consisting of an amount equivalent to the estimated taxable income with the result that no current tax was payable. Subsequent to the Acquisition, no similar management fees will be payable.

Foreign exchange (gain) loss

The foreign exchange (gains) and losses are relatively small and relate primarily to the exchange differences between the Canadian and US dollar for certain leases and equipment related purchases. The US dollar denominated senior notes are effectively hedged with the cross currency swap and accordingly, no gain or loss is reflected in respect of this debt.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

Segmented Results of Operations

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

$ in thousands	Quarter ended December 31, 2003					Quarter ended December 31, 2002					Nine months ended December 31, 2003					Nine months ended December 31, 2002
Revenue
Mining and Site Preparation	$	45,884				$	67,053				$	193,543				$	169,833
Piling		11,464					15,931					42,393					47,249
Pipeline		22,516					7,194					40,187					11,155
Total Revenue		79,864					90,178					276,123					228,237
Operating Profit
Mining and Site Preparation		6,428					6,550					29,173					20,321
Piling		2,105					3,297					9,128					9,878
Pipeline		4,193					1,063					7,124					1,207
Total Operating Profit		12,726					10,910					45,425					31,406
Unallocated costs
Corporate cost		27,295					11,002					58,288					24,193
Equipment cost (revenue)		6,245					(529	)				9,035					7,966
Income (loss) before income taxes	$	(20,814	)			$	437				$	(21,898	)			$	(753	)
Other data
Equipment hours
Mining and site preparation		88,298		68.9	%		141,958		83.0	%		404,728		79.9	%		372,594		83.5	%
Piling		11,211		8.7	%		20,803		12.2	%		51,007		10.1	%		60,015		13.5	%
Pipeline		28,681		22.4	%		8,295		4.8	%		50,828		10.0	%		13,558		3.0	%
		128,190		100.0	%		171,056		100.0	%		506,563		100.0	%		446,167		100.0	%

Quarter Ended December 31, 2003 (Pre-Acquisition period October 1, 2003 to November 25, 2003 and post-Acquisition period November 26, 2003 to December 31, 2003) compared to Quarter Ended December 31, 2002

Mining and Site Preparation

Mining and site preparation revenue for the quarter ended December 31, 2003 decreased by $21.2 million to $45.9 million as compared to $67.1 million for the quarter ended December 31, 2002. Our largest customer, Syncrude, experienced an unplanned shutdown on one of its two cokers during the current quarter. This shutdown decreased Syncrude’s production capabilities which in turn led to a decline in quarter over quarter revenues from $8.8 million to

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

$5.5 million under the Syncrude Fully Operated and Maintained (“FOM”) contract. Revenues from the Albian project decreased from $11.4 million to $6.1 million. This new oil sands mine in the Fort McMurray region has only recently completed its start–up and commissioning and project cost overruns have resulted in the deferral of some of our work into the quarter ending March 31, 2004 and into the fiscal year ending March 31, 2005. A portion of the work on our largest project, Upgrader Expansion 1 (“UE1”), was rescheduled to 2004 to coincide with Syncrude’s new overall construction timeline and resulted in a $5.3 million decrease in revenue for this period as compared to the prior period. In addition, revenue from the Syncrude Aurora II project declined by $7.2 million as compared to the prior period due to the substantial completion of the project.

Operating profit for mining and site preparation increased as a percentage of revenue. This increase is primarily the result of a higher proportion of revenue generated by heavy equipment billings as compared to the prior period. Revenue generated by the usage of heavy equipment is typically at a higher margin than billings for labor, materials and subcontractors.

Piling

Piling revenue for the quarter ended December 31, 2003 decreased by $4.4 million to $11.5 million as compared to $15.9 million for the quarter ended December 31, 2002. This decrease is primarily due to lower revenue from the UE1 piling contract as work on this project is nearing completion.The decrease is partially offset by a $1.3 million increase in revenue from new piling projects in Vancouver.

Operating profits for the piling segment decreased by $1.2 million to $2.1 million for the quarter ended December 31, 2003 as compared to $3.3 million for the quarter ended December 31, 2002. This is primarily attributable to the lower volume of work in the period as well as slightly lower margins.

Pipeline

Revenue generated from providing services to EnCana in the pipeline segment increased significantly from $7.2 million in the third quarter of 2002 to $22.5 million in the third quarter of 2003. This increase is related to EnCana’s decision to spread their development program in the Sierra region in Northeastern British Columbia over the entire year, versus the previous practice of drilling and installing pipelines in this area only during a compressed winter period. The provincial government has provided specific royalty incentives to the oil and gas industry to encourage summer development in the wetter muskeg-type regions. EnCana has also boosted their drilling program during the summer and fall period of 2003 from past levels, resulting in an earlier start of pipeline, well site hook-up and related activities in the Sierra region.

Pipeline segment operating profits increased $3.1 million to $4.2 million for the three months ended December 31, 2003 due largely to higher revenues as described above as well as a larger proportion of higher margin work.

Nine Months Ended December 31, 2003 (Pre-Acquisition period April 1, 2003 to November 25, 2003 and post-Acquisition period November 26, 2003 to December 31, 2003) compared to Nine Months Ended December 31, 2002

Mining and Site Preparation

Revenue for the nine months ended December 31, 2003 increased by $23.7 million to $193.5 million, as compared to $169.8 million for the nine months ended December 31, 2002. The increase was primarily due to the higher volume

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

of services provided on the Syncrude UE1 project and under the Syncrude FOM contract, as our scope of work increased significantly during the period. In addition, new work at one of our customer’s copper mine sites in British Columbia and higher volume on the site preparation contract for Bird Construction also contributed to the increase. These increases were partially offset by declining revenues for Syncrude Aurora II as this project is nearing completion and to lower activity on the Albian project due to temporary interruptions in operations encountered at the site during this period.

Segment operating profits increased by $8.9 million in the nine months ended December 31, 2003 to $29.2 million as compared to $20.3 million for the nine months ended December 31, 2002. This increase was due primarily to a higher volume of work as well as increased profit margins due to a larger proportion of higher margin unit-price work.

Piling

Revenue for the nine months ended December 31, 2003 decreased by $4.8 million to $42.4 million as compared to $47.2 million for the nine months ended December 31, 2002. The decrease is mainly due to lower commercial activity in the Edmonton and Regina markets offset partially by higher activity in the Vancouver and Fort McMurray markets.

Piling segment operating profits decreased by $0.8 million in the nine months ended December 31, 2003 to $9.1 million as compared to $9.9 million for the nine months ended December 31, 2002 primarily due to the decrease in revenue.

Pipeline

Revenue from the pipeline segment increased significantly to $40.2 million for the nine months ended December 31, 2003 up from $11.2 million for the nine months ended December 31, 2002. This increase is related to EnCana’s decision to spread their development program over the entire year instead of working only in the winter months. High demand for natural gas and the provincial government royalty incentive program have combined to create a favorable environment for year-round activity.

Pipeline segment operating profits increased by $5.9 million in the nine months ended December 31, 2003 to $7.1 million as compared to $1.2 million for the nine months ended December 31, 2002. The increase in profit is primarily attributable to the increase in activity volumes and a larger proportion of higher margin work.

Liquidity and Capital Resources

Operating activities

Cash provided from operating activities for the period from November 26, 2003 to December 31, 2003 totalled $1.9 million, with collection of accounts receivable primarily contributing to the results. Cash provided from operating activities for the Predecessor Company, after adding back the management fees, was positive in all comparative periods. Historically, we have used our cash from operations, together with other available sources of liquidity, to fund our working capital needs and capital expenditures. Going forward, we expect to fund our operations and sustaining capital expenditures and to satisfy our debt service obligations through operating cash flow and finance our expansion related to capital expenditures from borrowings under our revolving credit facility and other external financing.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

Investing activities

Cash used in investing activities during the period from November 26, 2003 to December 31, 2003 related almost entirely to the Acquisition. The cash used to acquire the shares of NACGI and the assets of NAEL totalled $369.1 million, which is net of the $4.3 million in NACGI cash balances acquired and $15.6 million in surplus cash from the Acquisition financing. The cash required to complete the Acquisition was financed by $92.5 million from the issuance of common shares, $263.0 million in proceeds from the senior notes and $50 million from the term loan portion of the senior credit facility, net in the latter two instances, of $16.5 million in issuance costs and fees.

A small amount of sustaining capital expenditures, $0.7 million, was spent in the period. In addition, new vehicle capital leases increased by $0.9 million and disposal of capital assets amounted to $0.3 million. Sustaining capital expenditures are those that are required to maintain our fleet of equipment at its optimum average age. Expansion capital expenditures are directly related to new projects, and the commitment to make expansion capital expenditures typically occurs only when we have signed a contract for a new project. We expect our future sustaining capital expenditures to range from $9 million to $18 million per year.

Financing activities

Apart from the cash provided to finance the Acquisition as described above, only a minimal amount of other financing was provided in the November 26, 2003 to December 31, 2003 period. This financing related to increased amounts of outstanding checks less payments made on capital leases. As of December 31, 2003, we had a cash balance of $22.4 million, of which $20.0 million was provided by the Acquisition.

Liquidity

We have available $60 million, subject to borrowing base limitations, under our $70 million revolving credit facility after taking into account a $10 million letter of credit required to be posted to support bonding requirements associated with customer contracts. In addition, we continue to lease a portion of our motor vehicle fleet and have assumed from the Predecessor Company four heavy equipment operating leases.

There are no principal payments required on our 8.75% US$ 200 million senior notes until maturity. The foreign currency risk relating to both the principal and interest payments has been effectively hedged with a cross currency swap and interest rate swaps which went into effect concurrent with the Acquisition. The 8.75% rate of interest on the senior notes has been swapped to an effective rate of 9.765% for the whole 8 year period until maturity. The interest is $12.8 million payable semi-annually in June and December of every year until the notes mature on December 1, 2011.

We are also required to make quarterly principal and interest payments under our $50 million term loan, which bears interest at a floating rate based upon either the Canadian prime rate plus 2% or Canadian bankers’ acceptance rate plus 3%. For the period from November 26, 2003 through December 31, 2003, the weighted average interest rate on the term debt was 6.5%. The principal repayments are $6.0 million in the calendar year 2004 and $11.0 million per year in the next four calendar years, all payable quarterly. Additional prepayments are required under certain circumstances and no new advances are available under the term facility.

The senior credit facility and the indenture relating to the senior notes impose certain restrictions on us, including restrictions on our ability to incur indebtedness, pay dividends, make investments, grant liens, sell assets and engage

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

in certain other activities. In addition, the senior credit facility requires us to maintain certain financial ratios. The indebtedness under the senior credit facility is secured by substantially all of our assets and those of our subsidiaries, including accounts receivable and capital assets.

Contractual Obligations and Other Commitments

Our principal contractual obligations relate to the senior notes and senior credit facility as well as both capital and operating leases. The following table summarizes our future contractual obligations, excluding interest payments, as of December 31, 2003.

	Payments Due by Period
($ in millions)	Total		2004		2005		2006		2007		2008		2009 and after
Contractual Obligations:
Long-term debt	$	313.0	$	6.0	$	11.0	$	11.0	$	11.0	$	11.0	$	263.0
Capital leases		3.2		0.9		0.7		0.7		0.9		—		—
Operating leases(a)		4.8		2.4		1.1		0.7		0.6		—		—
Total contractual cash obligations	$	321.0	$	9.3	$	12.8	$	12.4	$	12.5	$	11.0	$	263.0

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

U.S. Generally Accepted Accounting Principles

The 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 15 to the interim consolidated financial statements.

Recent U.S. accounting pronouncements

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

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

Recent Canadian Accounting Standards

In December 2002, the Accounting Standards Board of the Canadian Institute of Chartered Accountants issued Handbook Section 3063,Impairment of Long-Lived Assets. Section 3063 supersedes the write-down and disposal provisions of Section 3061,Property, plant and equipment. Under Section 3063, long-lived assets are tested for impairment whenever events or changes in circumstances indicate that the assets might be impaired. The impairment test is carried out in two steps. In the first step, the carrying amount of the asset or asset group is compared with its recoverable amount. The carrying amount of a long-lived asset is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. The second step is carried out when the carrying amount of a long-lived asset is not recoverable, in which case the fair value of the long-lived asset is compared with its carrying amount to measure the amount of the impairment loss, if any. When an impairment loss is recognized, it is presented in income from operations in the income statement. When quoted market prices are not available, the fair value of the long-lived assets is determined using the discounted estimated future cash flow method.

We adopted Section 3063, effective April 1, 2003. In accordance with the requirements of Section 3063, this change in accounting policy has been applied prospectively and the amounts presented for prior periods have not been restated for this change.

Quantitative and Qualitative Disclosures Regarding Market Risk

We are subject to currency exchange risk as the senior notes are denominated in US$ and all of our revenues and most of our expenses are denominated in Cdn$. As noted above, we have entered into cross currency swap and interest rate swap agreements to effectively hedge this risk. The hedging instrument consists of three components: (1) a US$ interest rate swap, (2) a US$-Cdn$ cross currency basis swap, and (3) a Cdn$ interest rate swap that results in us mitigating our exposure to the variability of cash flows caused by currency fluctuations relating to the US$ $200 million senior notes. The transaction can be cancelled at the counterparty’s option at any time after December 1, 2007 if the counterparty pays a cancellation premium to us. The premium is equal to 4.375% of the US$ $200 million if exercised between December 1, 2007 and December 1, 2008; 2.1875% if exercised between December 1, 2008 and December 1, 2009 and 0.000% if cancelled after December 1, 2009.

We are also subject to interest rate market risk in connection with our senior credit facility. The facility bears interest at variable rates based on the Canadian prime rate plus 2% or Canadian bankers’ acceptance rate plus 3%. Each 1% increase or decrease in the interest rate on the term portion of the facility would change the interest cost by $0.5 million in the first year and decreasing thereafter as the principal is repaid. Assuming the revolving credit facility is fully drawn at $60 million, each 1% increase or decrease in the applicable interest rate would change the interest cost by $0.6 million per year. In the future, we may enter into interest rate swaps, involving the exchange of floating for fixed rate interest payments, to reduce interest rate volatility.

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

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

Seasonality

We have experienced very little seasonality in our operations. While pipeline work has historically been performed more in the winter months when conditions are more favourable to move equipment on the soil, more recently, the pipeline segment has been working year round.

34

SIGNATURES

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

NORTH AMERICAN ENERGY PARTNERS INC.
By:	/s/ Gordon Parchewsky
Name:	Gordon Parchewsky
Title:	President

Date: February 27, 2004