UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

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

under the Securities Exchange Act of 1934

For the month of January 2006

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):                     .

Included herein:

1. Interim consolidated financial statements of North American Energy Partners Inc. for the three and six months ended September 30, 2005 and 2004 (Restated).

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

SIGNATURES

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

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

Date: January 13, 2006

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Expressed in thousands of Canadian dollars)

(unaudited)

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Balance Sheets

(in thousands of Canadian dollars)

	September 30, 2005			March 31, 2005
	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	17,935		$	17,922
Accounts receivable (note 10(a))		61,901			57,745
Unbilled revenue		52,908			41,411
Inventory		22			134
Prepaid expenses		1,911			1,862
Future income taxes		11,600			15,100
		146,277			134,174
Property, plant and equipment (note 3)		179,077			177,089
Goodwill		198,549			198,549
Intangible assets, net of accumulated amortization of $16,661 (March 31, 2005 - $16,296) (note 4)		1,137			1,502
Deferred financing costs, net of accumulated amortization of $6,710 (March 31, 2005 - $3,368) (note 5)		19,497			15,354
	$	544,537		$	526,668
Liabilities and Shareholder’s Equity
Current liabilities:
Accounts payable	$	49,744		$	59,090
Accrued liabilities (note 10(b))		19,400			15,201
Billings in excess of costs on uncompleted contracts		1,966			1,325
Current portion of capital lease obligations (note 7)		2,181			1,771
Future income taxes		11,600			15,100
		84,891			92,487
Senior secured credit facility (note 6(a))		—			61,257
Capital lease obligations (note 7)		6,096			5,454
Senior notes (note 6(b))		302,861			241,920
Derivative financial instruments (note 13(c))		69,076			51,723
Mandatory redeemable preferred shares (note 9(a))		45,168			—
Advances from parent company (note 8)		282			288
		508,374			453,129
Shareholder’s equity:
Common shares (note 9(b))		127,500			127,500
Contributed surplus (notes 9(c) and 16)		957			634
Deficit		(92,294	)		(54,595	)
		36,163			73,539
Subsequent event (note 9(a))
Commitments (note 14)
United States generally accepted accounting principles (note 18)
	$	544,537		$	526,668

See accompanying notes to unaudited interim consolidated financial statements.

1

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Statements of Operations and Deficit

(in thousands of Canadian dollars)

(unaudited)

	Three months ended September 30						Six months ended September 30
	2005			2004			2005			2004
Revenue	$	124,004		$	82,681		$	228,363		$	153,540
Project costs		79,924			54,885			146,470			100,923
Equipment costs		13,585			12,128			30,599			23,611
Operating lease expense		3,086			768			5,984			1,487
Depreciation		5,493			5,141			10,482			9,660
		102,088			72,922			193,535			135,681
Gross profit		21,916			9,759			34,828			17,859
General and administrative (note 12)		6,451			4,956			13,699			9,995
(Gain) loss on disposal of property, plant and equipment		(593	)		255			(321	)		249
Amortization of intangible assets		183			1,057			366			2,487
Operating income		15,875			3,491			21,084			5,128
Interest expense (note 10(c))		3,292			7,874			53,155			15,205
Foreign exchange gain		(16,461	)		(14,096	)		(15,240	)		(9,442	)
Other income		(68	)		(78	)		(268	)		(224	)
Financing costs (note 5)		—			—			2,095			—
Realized and unrealized loss on derivative financial instruments		17,515			16,077			18,797			13,546
		4,278			9,777			58,539			19,085
Income (loss) before income taxes		11,597			(6,286	)		(37,455	)		(13,957	)
Income taxes:
Current income taxes		94			830			244			1,643
Future income taxes		—			(2,425	)		—			(5,825	)
		94			(1,595	)		244			(4,182	)
Net income (loss) for the period		11,503			(4,691	)		(37,699	)		(9,775	)
Deficit, beginning of period		(103,797	)		(17,366	)		(54,595	)		(12,282	)
Deficit, end of period	$	(92,294	)	$	(22,057	)	$	(92,294	)	$	(22,057	)

See accompanying notes to unaudited interim consolidated financial statement

2

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Statements of Cash Flows

(in thousands of Canadian dollars)

(unaudited)

	Three months ended September 30						Six months ended September 30
	2005			2004			2005			2004
Cash provided by (used in):
Operating activities:
Net income (loss) for the period	$	11,503		$	(4,691	)	$	(37,699	)	$	(9,775	)
Items not affecting cash:
Depreciation		5,493			5,141			10,482			9,660
Amortization of intangible assets		183			1,057			366			2,487
Amortization of deferred financing costs (note 5)		896			629			1,568			1,254
Financing costs		—			—			2,095			—
Loss (gain) on disposal of property, plant and equipment		(593	)		255			(321	)		249
Unrealized foreign exchange gain on senior notes		(16,333	)		(14,440	)		(15,405	)		(9,940	)
Unrealized loss on derivative financial instruments		16,766			15,410			17,353			12,224
Decrease in allowance for doubtful accounts		(5	)		21			(72	)		(112	)
Stock-based compensation expense (note 16)		135			116			323			228
Change in redemption value and accretion of mandatorily redeemable preferred shares		(5,011	)		—			36,496			—
Future income taxes		—			(2,425	)		—			(5,825	)
Net changes in non-cash working capital (note 10(e))		(2,335	)		862			(20,615	)		(2,552	)
		10,699			1,935			(5,429	)		(2,102	)
Investing activities:
Purchase of property, plant and equipment		(7,529	)		(3,044	)		(13,222	)		(14,413	)
Net changes in non-cash working capital (note 10(e))		(1,760	)		—			590			—
Proceeds on disposal of property, plant and equipment		2,665			30			3,053			134
		(6,624	)		(3,014	)		(9,579	)		(14,279	)
Financing activities:
Repayment of senior secured credit facility		—			(1,500	)		(61,257	)		(3,000	)
Repayment of capital lease obligations		(493	)		(164	)		(927	)		(438	)
Advances (to) from parent company		(6	)		288			(6	)		288
Issuance of 9% senior secured notes		—			—			76,345			—
Issuance of mandatorily redeemable preferred shares		851			—			8,351			—
Financing costs		(104	)		(454	)		(7,485	)		(634	)
		248			(1,830	)		15,021			(3,784	)
Increase (decrease) in cash and cash equivalents		4,323			(2,909	)		13			(20,165	)
Cash and cash equivalents, beginning of period		13,612			19,339			17,922			36,595
Cash and cash equivalents, end of period	$	17,935		$	16,430		$	17,935		$	16,430

See accompanying notes to unaudited interim consolidated financial statements.

3

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(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. The Company completes all forms of civil projects including contract mining, industrial and commercial site development, pipeline and piling installations. The Company is a wholly-owned subsidiary of NACG Preferred Corp. which in turn is a wholly-owned subsidiary of NACG Holdings Inc.

2. Significant accounting policies

a) Basis of presentation:

These interim consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles (“GAAP”) and do not include all of the disclosures normally contained in the Company’s annual consolidated financial statements. Material inter-company transactions and balances are eliminated on consolidation. Material items that give rise to measurement differences to these consolidated financial statements under United States GAAP are outlined in note 18.

These interim consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, NACG Finance LLC and North American Construction Group Inc. (“NACGI”), the Company’s proportionate share of the assets, liabilities, revenues, expenses and cash flows of its joint venture (note 10(f)), and the following subsidiaries:

	% owned
•   North American Caisson Ltd.	100	%
•   North American Construction Ltd.	100	%
•   North American Engineering Ltd.	100	%
•   North American Enterprises Ltd.	100	%
•   North American Industries Inc.	100	%
•   North American Mining Inc.	100	%
•   North American Maintenance Ltd.	100	%
•   North American Pipeline Inc.	100	%
•   North American Road Inc.	100	%
•   North American Services Inc.	100	%
•   North American Site Development Ltd.	100	%
•   North American Site Services Inc.	100	%
•   Griffiths Pile Driving Inc.	100	%

b) Use of estimates:

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

4

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

c) Revenue recognition:

The Company performs the majority of its projects under the following types of contracts: time-and-materials; cost-plus; unit-price; and lump sum. For time-and-materials and cost-plus contracts, revenue is recognized as costs are incurred. Revenue on unit-price and lump sum contracts is recognized on the percentage-of-completion method, measured by the ratio of costs incurred to date to estimated total costs. Excluded from costs incurred to date, particularly in the early stages of the contract, are the costs of items that do not relate to performance of our contracted work.

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

The asset entitled “unbilled revenue” represents revenue recognized in advance of amounts invoiced. The liability entitled “billings in excess of costs on uncompleted contracts” represents amount invoiced in excess of revenue recognized.

d) Cash and cash equivalents:

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

e) Allowance for doubtful accounts:

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

f) Inventory:

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

g) Property, plant and equipment:

Property, plant and equipment are recorded at cost. Major components of heavy construction equipment in use such as engines, transmissions, and undercarriages are recorded separately. Spare component parts are charged to earnings when they are put into use. Equipment under capital lease is recorded at the present value of minimum lease payments at the inception of the lease. Depreciation is not recorded until an asset is put into service. Depreciation for each category is calculated based on

5

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

the cost, net of the estimated residual value, over the estimated useful life of the assets on the following bases and annual rates:

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

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

h) Goodwill:

Goodwill represents the excess purchase price paid by the Company over the fair value of the tangible and identifiable intangible assets and liabilities acquired. Goodwill is not amortized but instead is tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. The impairment test is carried out in two steps. In the first step, the carrying amount of the reporting unit, including goodwill, is compared with its fair value. When the fair value of the reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to be impaired and the second step of the impairment test is unnecessary. The second step is carried out when the carrying amount of a reporting unit exceeds its fair value, in which case, the implied fair value of the reporting unit’s goodwill, determined in the same manner as the value of goodwill is determined in a business combination, is compared with its carrying amount to measure the amount of the impairment loss, if any.

The Company tested goodwill for impairment at December 31, 2004 as a result of events and changes in circumstances and determined that there was no impairment in carrying value. The Company conducts its annual assessment of goodwill on January 1 on each year.

i) Intangible assets:

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

j) Deferred financing costs:

Costs relating to the issuance of the senior notes and the revolving credit facility have been deferred and are being amortized on a straight-line basis over the term of the related debt. Deferred financing costs related to debt that has been extinguished is written off in the period of extinguishment.

6

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

k) Impairment of long-lived assets:

Long-lived assets and certain identifiable intangibles are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is assessed by a comparison of the carrying amount of an asset to future undiscounted cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment loss is recognized for the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of by sale are reported at the lower of their carrying amount or fair value less costs to sell.

l) Foreign currency translation:

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

m) Derivative financial instruments:

The Company uses derivative financial instruments to manage economic risks from fluctuations in exchange rates and interest rates. These instruments include cross-currency swap agreements and interest rate swap agreements. All such instruments are only used for risk management purposes. 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.

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

n) Income taxes:

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

7

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(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. A valuation allowance is recorded against any future income tax asset if it is more likely than not that the asset will not be realized.

o) Stock–based compensation plan:

Effective November 26, 2003, the Company 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. Under a fair value method (Black-Scholes method), compensation cost is measured at the fair value using the minimum value approach at the grant date and is expensed over the award’s vesting period.

p) Accounting policy changes:

i. Revenue recognition:

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

Effective April 1, 2005, the Company amended its accounting policy regarding the recognition of revenue on claims. This change in accounting policy has been applied retroactively. Once contract performance is underway, we often experience changes in conditions, client requirements, specifications, designs, materials and work schedule. Generally, a “change order” will be negotiated with our customer to modify the original contract to approve both the scope and price of the change. Occasionally, however, disagreements arise regarding changes, their nature, measurement, timing and other characteristics that impact costs and revenue under the contract. When a change becomes a point of dispute between our customer and us, we then consider it as a claim.

Costs related to change orders and claims are recognized when they are incurred. Change orders are included in total estimated contract revenue when it is probable that the change order will result in a bona fide addition to contract value and can be reliably estimated. Prior to April 1, 2005, revenue from claims was included in total estimated contract revenue when awarded or received. After April 1, 2005, claims are included in total estimated contract revenue, only to the extent that contract costs related to the claim have been incurred, when it is probable that the claim will result in a bona fide addition to contract value and can be reliably estimated. Those two conditions are satisfied when (1) the contract or other evidence provides a legal basis for the claim or a legal opinion is obtained providing a reasonable basis to support the claim, (2) additional costs incurred were caused by unforeseen circumstances and are not the result of deficiencies in our

8

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

performance, (3) costs associated with the claim are identifiable and reasonable in view of work performed and (4) evidence supporting the claim is objective and verifiable. No profit is recognized on claims until final settlement occurs. This can lead to a situation where costs are recognized in one period and revenue is recognized when customer agreement is obtained or claim resolution occurs, which can be in subsequent periods. Historical claim recoveries should not be considered indicative of future claim recoveries.

The change in policy resulted in an increase in revenue and unbilled revenue of $4,429 for the three months ended September 30, 2005 and $9,729 for the six months ended September 30, 2005, but did not result in any adjustments to prior periods.

ii. Consolidation of variable interest entities:

Effective January 1, 2005, the Company prospectively adopted the Canadian Institute of Chartered Accountants’ new Accounting Guideline 15, “Consolidation of Variable Interest Entities” (“VIEs”) (“AcG-15”). VIEs are entities that have insufficient equity at risk to finance their operations without additional subordinated financial support and/or entities whose equity investors lack one or more of the specified essential characteristics of a controlling financial interest. AcG-15 provides specific guidance for determining when an entity is a VIE and who, if anyone, should consolidate the VIE. The Company has determined the joint venture in which it has an investment (note 10(f)) qualifies as a VIE.

iii. Arrangements containing a lease:

Effective January 1, 2005, the Company adopted the new Canadian Accounting Standard EIC-150, “Determining Whether an Arrangement Contains a Lease.” EIC-150 addresses a situation where an entity enters into an arrangement, comprising a transaction that does not take the legal form of a lease but conveys a right to use a tangible asset in return for a payment or series of payments. The Company has determined that it has not currently committed to any arrangements to which this standard would apply.

iv. Vendor rebates:

In April 2005, the Company adopted the amended Canadian Accounting Standard EIC-144, “Accounting by a Customer (Including a Reseller) for Certain Consideration Received from a Vendor.” EIC-144 requires companies to recognize the benefit of non-discretionary rebates for achieving specified cumulative purchasing levels as a reduction of the cost of purchases over the relevant period, provided the rebate is probable and reasonably estimable. Otherwise, the rebates would be recognized as purchasing milestones are achieved. The implementation of this new standard did not have a material impact on the Company’s consolidated financial statements.

9

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

q) Recent Canadian accounting pronouncements not yet adopted:

i. Financial instruments:

In January 2005, the CICA issued Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, Handbook Section 1530, “Comprehensive Income”, and Handbook Section 3865, “Hedges”. The new standards will be effective for interim and annual financial statements commencing in 2007. Earlier adoption is permitted. The new standards will require presentation of a separate statement of comprehensive income under specific circumstances. Foreign exchange gains and losses on the translation of the financial statements of self-sustaining subsidiaries previously recorded in a separate section of shareholder’s equity will be presented in comprehensive income. Derivative financial instruments will be recorded in the balance sheet at fair value and the changes in fair value of derivatives designated as cash flow hedges will be reported in comprehensive income. The Company is currently assessing the impact of the new standards.

ii. Non-monetary transactions:

In June 2005, the CICA replaced Handbook Section 3830, “Non-monetary Transactions”, with the new Handbook Section 3831, “Non-monetary Transactions”. The requirements of the new standard apply to non-monetary transactions initiated in periods beginning on or after January 1, 2006, though earlier adoption is permitted as of periods beginning on or after July 1, 2005. The standard requires all non-monetary transactions to be measured at fair market value unless:

• the transaction lacks commercial substance;

• the transaction is an exchange of production or property held for sale in the ordinary course of business for production or property to be sold in the same line of business to facilitate sales to customers other than the parties to the exchange;

• neither the fair value of the assets or services received nor the fair value of the assets or services given up is reliably measurable; or

• the transaction is a non-monetary, non-reciprocal transfer to owners that represents a spin-off or other form of restructuring or liquidation.

The Company does not expect the adoption of this standard to have a material impact on its results of operations or financial position.

10

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

3. Property, plant and equipment

September 30, 2005	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	168,390	$	24,226	$	144,164
Major component parts in use		4,996		1,480		3,516
Spare component parts		383		—		383
Other equipment		13,022		3,397		9,625
Licensed motor vehicles		17,679		6,457		11,222
Office and computer equipment		2,640		1,337		1,303
Assets under construction		8,864		—		8,864
	$	215,974	$	36,897	$	179,077
March 31, 2005	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	165,296	$	17,966	$	147,330
Major component parts in use		4,659		1,182		3,477
Spare component parts		841		—		841
Other equipment		12,088		2,473		9,615
Licensed motor vehicles		16,043		4,670		11,373
Office and computer equipment		2,088		791		1,297
Assets under construction		3,156		—		3,156
	$	204,171	$	27,082	$	177,089

The above amounts include $10,609 (March 31, 2005 – $8,637) of assets under capital lease and accumulated depreciation of $3,130 (March 31, 2005 – $1,968) related thereto. During the three months ended September 30, 2005, additions of property, plant and equipment included $998 of assets that were acquired by means of capital leases (three months ended September 30, 2004 – $1,382). For the six months ended September 30, 2005, $1,979 of assets were acquired by means of capital leases (six months ended September 30, 2004 - $2,091). For the three months ended September 30, 2005, depreciation of equipment under capital leases of $618 (three months ended September 30, 2004 – $267) is included in depreciation expense. For the six months ended September 30, 2005, depreciation of equipment under capital leases was $1,162 (six months ended September 30, 2004 - $611).

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

4. Intangible assets

Identifiable intangible assets	Cost		Accumulated amortization		Net book value
Customer contracts in progress and related relationships	$	15,323	$	15,323	$	—
Trade names		350		63		287
Non-competition agreement		100		37		63
Employee arrangements		2,025		1,238		787
Balance, September 30, 2005	$	17,798	$	16,661	$	1,137
Identifiable intangible assets	Cost		Accumulated amortization		Net book value
Customer contracts in progress and related relationships	$	15,323	$	15,323	$	—
Trade names		350		47		303
Non-competition agreement		100		26		74
Employee arrangements		2,025		900		1,125
Balance, March 31, 2005	$	17,798	$	16,296	$	1,502

Amortization of intangible assets of $183 was recorded for the three months ended September 30, 2005 (three months ended September 30, 2004 - $1,057). For the six months ended September 30, 2005, amortization of intangible assets was $365 (six months ended September 30, 2004 – $2,487)

5. Deferred financing costs

For the three months ended September 30, 2005, financing costs of $104 were incurred in connection with the issuance of the 9% senior secured notes and the new revolving credit facility (note 6) and were recorded as deferred financing costs. For the three months ended September 30, 2004, financing costs of $454 were incurred in connection with the issuance of the 8 ³/4% senior notes and were recorded as deferred financing costs.

For the six months ended September 30, 2005, financing costs of $7,485 were incurred in connection with the issuance of the 9% senior secured notes and revolving credit facility (note 6) and were recorded as deferred financing costs. In addition, $321 of financing costs was incurred in connection with the issuance of the mandatorily redeemable Series A preferred shares. For the six months ended September 30, 2004, financing costs of $634 were incurred in connection with the issuance of the 8 ³/4% senior notes and were recorded as deferred financing costs.

In connection with the repayment of the senior secured credit facility on May 19, 2005, the Company wrote off deferred financing costs of $1,774 (note 6(a)).

Amortization of deferred financing costs of $896 was recorded for the three months ended September 30, 2005 (three months ended September 30, 2004 - $629). Amortization of deferred financing costs of $1,568 was recorded for the six months ended September 30, 2005 (six months ended September 30, 2004 - $1,254).

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

6. Long-term debt

a) Senior secured credit facility:

	September 30, 2005		March 31, 2005
Revolving credit facility	$	—	$	20,007
Term credit facility		—		41,250
	$	—	$	61,257

The Company refers to the revolving credit facility and the term loan collectively as the “senior secured credit facility.”

On May 19, 2005, the Company repaid its entire indebtedness under the senior secured credit facility using the net proceeds from the issuance of the 9% senior secured notes (note 6(b)) and the Series B mandatorily redeemable preferred shares (note 9(a)).

b) Senior notes:

	September 30, 2005		March 31, 2005
8 3/4% senior notes due 2011	$	232,540	$	241,920
9% senior secured notes due 2010		70,321		—
	$	302,861	$	241,920

The 8 ³/4% senior notes were issued on November 26, 2003 in the amount of US$200 million (Canadian $263 million). These notes mature on December 1, 2011 and bear interest at 8 ³/4% payable semi-annually on June 1 and December 1 of each year.

The 8 ³/4% senior notes are unsecured senior obligations and rank equally with all other existing and future unsecured and unsubordinated debt and senior to any subordinated debt that may be issued by the Company. The notes are effectively subordinated to all secured debt to the extent of the value of the assets securing such debt.

The 8 ³/4% senior notes are redeemable at the option of the Company, in whole or in part, at any time on or after: December 1, 2007 at 104.375% of the principal amount; December 1, 2008 at 102.188% of the principal amount; December 1, 2009 at 100.00% of the principal amount; plus, in each case, interest accrued to the redemption date.

The 9% senior secured notes were issued on May 19, 2005 in the amount of US$60.481 million (Canadian $76.345). These notes mature on June 1, 2010 and bear interest at 9% payable semi-annually on June 1 and December 1 of each year. The Company has not hedged its exposure to changes in the U.S. to Canadian dollar exchange rate resulting from the issuance of these notes.

The 9% senior secured notes are senior secured obligations and rank senior in right of payment to all existing subordinated debt and the 8 ³/4% senior notes. They rank equally in right of payment to all existing and future senior debt of the Company. However, the notes are effectively subordinated to the Company’s swap agreements and new revolving credit facility to the extent of the value of the assets securing such debt.

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

The 9% senior secured notes are redeemable at the option of the Company, in whole or in part, at any time on or after: June 1, 2008 at 104.50% of the principal amount; June 1, 2009 at 102.25% of the principal amount; June 1, 2010 at 100.00% of the principal amount; plus, in each case, interest accrued to the redemption date. At any time, or from time to time, on or before June 1, 2007 the Company may, at its option, use the net cash proceeds of one or more public equity offering, to redeem up to 35% of the principal amount of the 9% senior secured notes at a redemption equal to 109.0% of the principal amount of the 9% senior secured notes redeemed plus accrued and unpaid interest, if any, to the date of redemption; provided that: at least 65% of the principal amount of 9% senior secured notes remains outstanding immediately after any such redemption; and the Company makes such redemption within 90 days after the closing of any such public equity offering. If a change of control Occurs, the Company will be required to offer to purchase all or a portion of each holder’s 9% senior secured notes, at a purchase price in cash equal to 101% of the principal amount of notes repurchased plus accrued interest to the date of purchase.

c) Revolving credit facility:

On May 19, 2005, the Company entered into a new revolving credit facility with a syndicate of lenders. The new revolving facility provides for borrowings of up to $40.0 million, subject to borrowing base limitations, under which revolving loans may be made and letters of credit, up to a limit of $30.0 million, may be issued. The facility bears interest at the Canadian prime rate plus 2% or Canadian bankers’ acceptance rate plus 3%. The indebtedness under the revolving credit facility is secured by substantially all of the Company’s assets and those of its subsidiaries, including accounts receivable, inventory and property, plant and equipment, and a pledge of the Company’s capital stock and that of its subsidiaries.

In connection with the new revolving credit facility, the Company was required to amend its existing swap agreements to increase the effective rate of interest on its 8 ³/4% senior notes from 9.765% to 9.889% (note 13(c)) and issue to one of the counterparties to the swap agreements $1.0 million of Series A redeemable preferred shares (note 9(a)).

As of September 30, 2005, the Company had no outstanding borrowings or borrowing availability under the revolving credit facility and had issued $22.0 million in letters of credit to support bonding requirements and performance guarantees associated with customer contracts.

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

7. Capital lease obligations

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

For the year ending September 30,
2006	$	2,552
2007		2,492
2008		2,163
2009		1,413
2010		584
		9,204
Less: amount representing interest – average rate of 4.48%		927
Present value of minimum capital lease payments		8,277
Less: current portion		2,181
	$	6,096

8. Advances from parent company

Advances from parent company of $282 as at September 30, 2005 represent a non-interest bearing note payable to the Company’s ultimate parent, NACG Holdings Inc. The note was transacted in the normal course of operations and recorded at the exchange value and on terms as agreed to by the parties. As the parent company has indicated in writing that it will not demand payment within the next 12 months, this amount has been classified as long-term.

9. Shares

a) Mandatorily redeemable preferred shares:

Authorized:

i. Unlimited number of Series A Preferred Shares

The Series A Preferred shares are non-voting and are not entitled to any dividends. The Series A preferred shares are mandatorily redeemable at $1,000 per share on the earlier of (1) December 31, 2011 and (2) an Accelerated Redemption Event, specifically (i) the occurrence of a change in control, or (ii) if there is an initial public offering of common shares, the later of (a) the consummation of the initial public offering or (b) the date on which all of the Company’s 8 ³/4% senior unsecured notes and the Company’s 9% senior secured notes are no longer outstanding.

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

The Company may redeem the Series A preferred shares, in whole or in part, at $1,000 per share at any time.

ii. Unlimited number of Series B Preferred Shares

The Series B preferred shares are non-voting and are entitled to cumulative dividends at an annual rate of 15% of the issue price of each share. No dividends are payable on common shares or other classes of preferred shares (defined as Junior Shares) unless all cumulative dividends have been paid on the Series B preferred shares and the Company declares a Series B preferred share dividend equal to 25% of the Junior Share dividend (except for dividends paid as part of employee and officer arrangements, intercompany administrative charges of up to $1 million annually and tax sharing arrangements). As long as any Series A preferred shares remain outstanding and subject to the restrictions contained within the 8 ³/4% senior unsecured notes and the 9% senior secured notes, dividends shall not be paid (but shall otherwise accrue) on the Series B preferred shares. Subject to the prior redemption of the Series A preferred shares, the Series B preferred shares are mandatorily redeemable on the earlier of (1) December 31, 2011 and (2) an Accelerated Redemption Event, specifically (i) a change in control or (ii) if there is an initial public offering of common shares, the later of (a) the consummation of the initial public offering or (b) the date when the 8 ³/4% notes and 9% notes are no longer outstanding. Subject to the restrictive covenants contained within the indenture agreement for the 9% senior secured notes, the indenture agreement for the 8 ³/4% senior unsecured notes and the credit facility agreement, the Company may redeem the Series B preferred shares, in whole or in part, at any time.

The payment of dividends and the redemption of the Series B mandatorily redeemable preferred shares are restricted by the indenture agreements governing the Company’s 9% senior secured notes due 2010 and the 8 ³/4% senior notes due 2011, as well as the Company’s credit facility agreement. Such payments cannot be made by the Company or its subsidiaries unless: (1) the Company is not continuing to and will not default on any clause of the indenture agreements; (2) the Company is able to incur at least $1.00 in additional indebtedness under the indenture; and (3) the aggregate amount of such payments made since the date the notes were issued does not exceed 50% of the consolidated net income (or 100% of consolidated net loss) from January 1, 2004 to the end of the latest fiscal quarter plus 100% of cash proceeds received from the issuance of additional shares since the date the notes were issued (the indenture for 9% senior secured notes specifically excludes the $7.5 million received on the issuance of the Series B mandatorily redeemable preferred shares) plus 100% of the principal amount of any indebtedness converted into or exchanged for equity plus the net cash proceeds received from any public equity offering. The indentures, however, specifically allow for the payment of dividends or redemption of shares for additional shares of the Company or when additional shares are issued concurrently for cash, and allow for such payments to be made, regardless of the of the previous restrictions, in an amount not to exceed $15 million in the aggregate in the indenture governing the 8 ³/4% senior notes and $8.5 million in the indenture governing the 9% senior secured notes. Subject to the prior redemption of the Series A preferred shares, the Series B preferred shares are mandatorily redeemable at the earlier of (1) December 31, 2011 and (2) an Accelerated Redemption Event,

16

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

specifically (i) a change in control or (ii) if there is an initial public offering of common shares, the later of (a) the consummation of the initial public offering or (b) the date when the 8 ³/4% senior notes and 9% senior secured notes are no longer outstanding.

The redemption price of the Series B preferred shares is an amount equal to the greatest of (i) two times the issue price, less the amount, if any, of dividends previously paid in cash on the Series B preferred shares; (ii) an amount, taking into account the amount, if any, of any dividends previously paid in cash on such Series B preferred shares that provides for a 40% rate of return, compounded annually, on the issue price from the date of issuance, which is limited to a redemption price of $100 million; and (iii) an amount equal to 25% of the arm’s length fair market value of the common shares without taking into account the Series B preferred shares, which is limited to a redemption price of $100 million.

Issued:

	Number of Shares	Amount
Series A Preferred Shares (i)
Outstanding at March 31, 2005	—	$	—
Issued	1,000		321
Accretion	—		9
Outstanding at June 30, 2005	1,000	$	330
Accretion	—		14
Outstanding at September 30, 2005	1,000	$	344
Series B Preferred Shares(ii)
Outstanding at March 31, 2005	—	$	—
Issued	75,000		7,500
Change in redemption amount	—		41,498
Outstanding at June 30, 2005	75,000	$	48,998
Issued	8,218		851
Change in redemption amount	—		(5,025	)
Outstanding at September 30, 2005	83,218	$	44,824
Total Mandatorily Redeemable Preferred Shares		$	45,168

The Series A preferred shares were issued to one of the counterparties to the Company’s swap agreements on May 19, 2005 (note 13(c)) in connection with the new revolving credit facility (note 6(c)). These shares are not entitled to accrue or receive dividends and are required to be redeemed on or before December 31, 2011 for $1.0 million.

The Series A preferred shares were initially recorded at their fair value on the date of issuance, which was estimated to be $321 based on the present value of the required cash flows using the rate implicit

17

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

at inception. Each reporting period, the Company will accrete the carrying value to the present value of the redemption amount at the balance sheet date and record the accretion as interest expense. For the three months ended September 30, 2005, the Company recognized $14 of accretion as interest expense. For the six months ended September 30, 2005, the Company recognized $23 of accretion as interest expense. The carrying value of the Series A preferred shares is $344 at September 30, 2005.

The Series B preferred shares were issued to existing non-employee shareholders of the Company’s ultimate parent company, NACG Holdings Inc., for cash proceeds of $7.5 million on May 19, 2005. Each reporting period, the Company is required to measure the Series B mandatorily redeemable preferred shares at the amount of cash that would be paid under the conditions specified in the contract if settlement occurred at the reporting date. At September 30, 2005, management estimates the redemption amount to be $44.0 million. As a result, the Company has recognized the decrease in the carrying value of $5.0 million as a reduction in interest expense for the three months ended September 30, 2005. For the six months ended September 30, 2005, interest expense has increased by $36.5 million due to the change in the carrying value of the Series B preferred shares from their initial fair value of $7.5 million to $44.0 million.

On June 15, 2005, the Series B preferred shares were split 10-for-1.

On May 19, 2005, the Series B preferred shares were initially issued for cash proceeds of $7.5 million to certain non-employee shareholders, with the agreement that an offer to purchase these Series B preferred shares would also be extended to other existing shareholders of NACG Holdings Inc. on a pro rata basis to their interest in the common shares. During the three months ended September 30, 2005, the Company made an offer to sell the Series B preferred shares to the other holders of common shares of NACG Holdings Inc. on a pro rata basis. As a result, the Company issued 8,218 Series B preferred shares for consideration of $851 to certain shareholders of the Company’s ultimate parent company, NACG Holdings Inc., on August 31, 2005.

On November 1, 2005, the Company repurchased and cancelled, for cash consideration of $851, 8,218 of Series B preferred shares held by the original non-employee shareholders that subscribed to these preferred shares on May 19, 2005.

b) Common shares:

Authorized:

Unlimited number of common voting shares.

Issued:

	Number of Shares	Amount
Outstanding at March 31, 2005	100	$	127,500
Issued	—		—
Redeemed	—		—
Outstanding at September 30, 2005	100	$	127,500

18

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

c) Contributed surplus:

Balance, March 31, 2005	$	634
Stock-based compensation (note 16)		188
Balance, June 30, 2005		822
Stock-based compensation (note 16)		135
Balance, September 30, 2005	$	957

10. Other information

a) Accounts receivable:

	September 30, 2005			March 31, 2005
Accounts receivable – trade	$	44,197		$	45,379
Accounts receivable – holdbacks		17,616			12,476
Accounts receivable – other		180			54
Allowance for doubtful accounts		(92	)		(164	)
	$	61,901		$	57,745

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

At September 30, 2005, the following customers represented 10% or more of accounts receivable and unbilled revenue:

	September 30, 2005		March 31, 2005
Customer A	10.1	%	8.6	%
Customer B	38.4	%	32.8	%
Customer C	8.2	%	11.0	%

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

19

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

b) Accrued liabilities:

	September 30, 2005		March 31, 2005
Accrued interest payable	$	10,988	$	9,127
Payroll liabilities		4,717		2,283
Income and other taxes		1,423		1,679
Liabilities related to equipment leases		2,272		2,112
	$	19,400	$	15,201

c) Interest expense:

	Three months ended September 30					Six months ended September 30
	2005			2004		2005		2004
Interest on senior notes	$	7,389		$	5,968	$	13,924	$	11,665
Interest on senior secured credit facility		—			739		564		1,432
Interest on capital lease obligations		104			44		193		82
Change in redemption value of Series B mandatorily redeemable preferred shares		(5,025	)		—		36,473		—
Accretion of Series A mandatorily redeemable preferred shares		14			—		23		—
Interest on long-term debt		2,482			6,751		51,177		13,179
Amortization of deferred financing costs		896			629		1,568		1,254
Other interest		(86	)		494		410		772
	$	3,292		$	7,874	$	53,155	$	15,205

d) Supplemental cash flow information:

	Three months ended September 30				Six months ended September 30
	2005		2004		2005		2004
Cash paid during the period for:
Interest	$	4,253	$	1,473	$	12,978	$	15,753
Income taxes		93		1,452		244		3,183
Cash received during the period for:
Interest		55		77		163		273
Income taxes		—		—		—		—
Non-cash transactions:
Capital leases		998		1,382		1,979		2,091
Series A preferred shares		—		—		321		—

20

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

e) Net change in non-cash working capital:

	Three months ended September 30						Six months ended September 30
	2005			2004			2005			2004
Operating activities:
Accounts receivable	$	(7,547	)	$	9,339		$	(4,084	)	$	6,916
Unbilled revenue		(4,757	)		(25,671	)		(11,497	)		(10,556	)
Inventory		86			(499	)		112			(85	)
Prepaid expenses		908			494			(49	)		561
Accounts payable		(4,835	)		11,249			(9,865	)		4,562
Accrued liabilities		12,322			5,950			4,128			(3,950	)
Billings in excess of costs and estimated earnings		1,488			—			641			—
	$	(2,335	)	$	862		$	(20,614	)	$	(2,552	)
Investing activities:
Accounts payable	$	(879	)	$	—		$	519		$	—
Accrued liabilities		(881	)		—			71			—
	$	(1,760	)	$	—		$	590		$	—

f) Investment in joint venture:

The Company has determined that the joint venture in which it participates is a variable interest entity (“VIE”) as defined by AcG-15 and that the Company is the primary beneficiary. Accordingly, the joint venture has been consolidated on a prospective basis effective January 1, 2005. During the fourth quarter of fiscal 2005, the arrangement of this joint venture has been amended such that the Company is responsible for all of its activities and revenues. As a result, no minority interest has been recorded.

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

	September 30, 2005		March 31, 2005
Assets
Cash	$	302	$	—
Accounts receivable		21,694		11,749
Unbilled revenue		22,492		20,932
	$	44,488	$	32,681
Liabilities
Accounts payable	$	9,604	$	5,065
Accrued liabilities		1,011		2,050
Venturer’s equity		33,873		25,566
	$	44,488	$	32,681

21

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

	Three months ended September 30						Six months ended September 30
	2005			2004			2005			2004
Revenue	$	48,207		$	2,890		$	84,195		$	3,606
Project costs		(43,644	)		(3,067	)		(76,571	)		(4,733	)
General and administrative		(2	)		—			(2	)		—
Net income (loss)	$	4,561		$	(177	)	$	7,622		$	(1,127	)
	Three months ended September 30						Six months ended September 30
	2005			2004			2005			2004
Cash used in:
Operating activities	$	5,196		$	(431	)	$	(383	)	$	(1,376	)
Investing activities		—			—			—			—
Financing activities		(4,894	)		823			685			1,771
	$	302		$	392		$	302		$	395

11. Segmented information

a) General overview:

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

• Mining and Site Preparation:

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

• Piling:

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

• Pipeline:

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

22

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

b) Results by business segment:

For the three months ended September 30, 2005	Mining and Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	93,536	$	22,115	$	8,353	$	124,004
Depreciation of property, plant and equipment		2,238		426		164		2,828
Segment profits		9,508		4,833		1,773		16,114
Segment assets		337,192		80,277		41,526		458,995
Expenditures for segment property, plant and equipment		8,203		58		—		8,261
For the three months ended September 30, 2004	Mining and Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	62,614	$	17,382	$	2,685	$	82,681
Depreciation of property, plant and equipment		2,547		711		32		3,290
Segment profits		5,562		3,802		351		9,715
Segment assets		297,009		81,201		43,099		421,309
Expenditures for segment property, plant and equipment		1,991		—		—		1,991
For the six months ended September 30, 2005	Mining and Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	176,030	$	42,301	$	10,031	$	228,363
Depreciation of property, plant and equipment		4,585		858		252		5,695
Segment profits		20,110		7,938		1,875		29,923
Segment assets		337,192		80,277		41,526		458,995
Expenditures for segment property, plant and equipment		11,317		249		—		11,566
For the six months ended September 30, 2004	Mining and Site Preparation		Piling		Pipeline		Total
Revenues from external customers	$	109,377	$	30,639	$	13,524	$	153,540
Depreciation of property, plant and equipment		4,754		1,320		88		6,162
Segment profits		9,053		6,780		1,988		17,821
Segment assets		297,009		81,201		43,099		421,309
Expenditures for segment property, plant and equipment		12,634		58		—		12,692

23

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

c) Reconciliations:

i. Loss before income taxes:

	Three months ended September 30						Six months ended September 30
	2005			2004			2005			2004
Total profit for reportable segments	$	16,114		$	9,715		$	29,923		$	17,821
Unallocated corporate expenses		(10,901	)		(15,773	)		(72,894	)		(31,482	)
Unallocated equipment revenue(cost)		6,384			(228	)		5,516			(296	)
Income (loss) before income taxes	$	11,597		$	(6,286	)	$	(37,455	)	$	(13,957	)

ii. Total assets:

	September 30, 2005		March 31, 2005
Total assets for reportable segments	$	458,995	$	439,350
Corporate assets		85,542		87,318
Total assets	$	544,537	$	526,668

The Company’s goodwill was assigned to the Mining and Site Preparation, Piling and Pipeline segments in the amounts of $125,447, $40,349, and $32,753, respectively.

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

d) Customers:

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

For the three months ended September 30,	2005		2004
Customer A	37.0	%	0.0	%
Customer B	14.0	%	33.0	%
Customer C	7.0	%	5.0	%
Customer D	5.0	%	6.0	%

24

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

For the Six months ended September 30,	2005		2004
Customer A	36	%	3.0	%
Customer B	15.0	%	38.0	%
Customer C	12.0	%	3.0	%
Customer D	7.0	%	5.0	%

This revenue by major customer was earned in all three business segments: Mining and Site Preparation, Pipeline and Piling.

12. Related party transactions

All related party transactions described below are measured at the exchange amount of consideration established and agreed to by the related parties.

a) Transactions with Sponsors:

The Sterling Group, L.P. (“Sterling”), Genstar Capital, L.P., Perry Strategic Capital Inc., and Stephens Group, Inc., (the “Sponsors”), entered into an agreement with NACG Holdings Inc. and certain of its subsidiaries, including the Company, to provide consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. As compensation for these services an annual advisory fee of $100 for the three months ended September 30, 2005 (three months ended September 30, 2004 – $100) is payable to the Sponsors, as a group. Additionally, 7,500 Series B preferred shares were issued to the above Sponsor group in exchange for cash of $7.5 million (see note 9(a)).

b) Office rent:

Pursuant to several office lease agreements, for the three months ended September 30, 2005 the Company paid $361 (three months ended September 30, 2004 – $294) to a company owned, indirectly and in part, by one of the Directors. For the six months ended September 30, 2005 the company paid $654 (six months ended September 30, 2004 - $468)

13. Financial instruments

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

a) Fair value:

The fair values of the Company’s cash and cash equivalents, accounts receivable, unbilled revenue, inventory, prepaid expenses, accounts payable, accrued liabilities, and billings in excess of costs on uncompleted contracts approximate their carrying amounts.

The fair value of the revolving credit facility, senior notes and capital lease obligations (collectively “the debt”) are based on management estimates which are determined by discounting cash flows required

25

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

under the debt at the interest rate currently estimated to be available for loans with similar terms. Based on these estimates, the fair value of the Company’s revolving credit facility, 9% senior notes and capital lease obligations as at September 30, 2005 are not significantly different than their carrying values. The market value of the 8 ³/4% notes as at September 30, 2005 is $220,913 compared to a carrying value of $232,540.

b) Interest rate risk:

The Company is subject to interest rate risk on the revolving credit facility and capital lease obligations. At September 30, 2005, for each 1% annual fluctuation in the interest rate, the annual cost of financing will change by approximately $78.

The Company also leases equipment (as described in note 14) with a variable lease payment component that is tied to prime rates. At September 30, 2005, for each 1% annual fluctuation in these rates, annual lease expense will change by approximately $245.

c) Foreign currency risk and derivative financial instruments:

The Company has 8  ³/4% senior notes denominated in U.S. dollars in the amount of US$200 million. In order to reduce its exposure to changes in the U.S. to Canadian dollar exchange rate, the Company, concurrent with the closing of the acquisition on November 26, 2003, entered into a cross-currency swap agreement to manage this foreign currency exposure for both the principal balance due on December 1, 2011 as well as the semi-annual interest payments through the whole period beginning from the issuance date to the maturity date. In conjunction with the cross-currency swap agreement, the Company also entered into a U.S. dollar interest rate swap and a Canadian dollar interest rate swap with the net effect of converting the 8.75% rate payable on the senior notes into a fixed rate of 9.765% for the duration that the senior notes are outstanding. On May 19, 2005 in connection with the Company’s new revolving credit facility, this fixed rate was increased to 9.889% for the remainder of the duration the 8 ³/4% senior notes are outstanding. These derivative financial instruments do not qualify for hedge accounting.

The Company has not hedged its exposure to changes in the U.S. to Canadian dollar exchange rate resulting from the issuance of the 9% senior secured notes.

The carrying amount and fair value of the Company’s derivative financial instruments at September 30, 2005 are as follows:

	Carrying amount			Fair value
Cross-currency and interest rate swaps	$	(69,076	)	$	(69,076	)

At September 30, 2005, the notional principal amount of the cross-currency swap was US$200 million. The notional principal amounts of the interest rate swaps were US$200 million and Canadian $263 million.

26

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

d) Operating leases:

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

14. Commitments

The annual future minimum lease payments in respect of operating leases for the next five years are as follows:

For the year ending September 30,
2006	$	15,280
2007		14,152
2008		6,309
2009		3,564
2010		3,057
	$	42,362

15. Employee contribution plans

The Company and its subsidiaries match voluntary contributions made by the employees to their Registered Retirement Savings Plans to a maximum of 5% of base salary for each employee. Contributions made by the Company during the three months ended September 30, 2005 were $97 (three months ended September 30, 2004 – $78). For the six months ended September 30, 2005 contributions made by the Company was $190 (six months ended September 30, 2004 - $128).

16. Stock-based compensation plan

Under the 2004 Share Option Plan, Directors, Officers, employees and service providers to the Company are eligible to receive stock options to acquire common shares in NACG Holdings Inc. The stock options expire in ten years or on termination of employment. Options may be exercised at a price determined at the time the option is awarded, and vest as follows: no options vest on the award date and twenty per cent vest on each of the five following award date anniversaries. The maximum number of common shares issuable under this plan may not exceed 92,500, of which 16,258 are still available for issue as at September 30, 2005.

27

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

The fair value of each option granted by NACG Holdings Inc. was estimated using the Black-Scholes option-pricing model assuming the following weighted average assumptions: a dividend yield of nil%; a risk-free interest rate of 4.63%; volatility of nil%; and an expected option life of 10 years.

	Number of options		Weighted average exercise price $ per share
Outstanding at June 30, 2005	74,242		$	100.00
Granted	—			—
Exercised	—			—
Forfeited	(3,200	)		100.00
Outstanding at September 30, 2005	71,042		$	100.00
	Number of options		Weighted average exercise price $ per share
Outstanding at June 30, 2004	58,742		$	100.00
Granted	9,500			100.00
Exercised	—			—
Forfeited	—			100.00
Outstanding at September 30, 2004	68,242		$	100.00

At September 30, 2005, the range of exercise prices, the weighted average exercise price and the weighted average remaining contractual life are as follows:

	Options outstanding
Exercise price	Number outstanding	Weighted average remaining contractual life (years)	Weighted average exercise price
$100	71,042	8.3	$	100.00

The Company recorded $135 of compensation expense related to the stock options in the three months ended September 30, 2005 (three months ended September 30, 2004 – $116) with such amount being credited to contributed surplus. For the six months ended September 30, 2005 the Company recorded $323 of compensation expense related to the stock options (six months ended September 30, 2004 - $228).

17. Comparative figures

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

28

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

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

These interim consolidated financial statements have been prepared in accordance with Canadian GAAP which differs in certain respects from U.S. GAAP. For the periods presented herein, material issues that could give rise to measurement differences in the interim consolidated financial statements are as follows:

Capitalization of interest:

U.S. GAAP requires capitalization of interest costs as part of the historical cost of acquiring certain qualifying assets that require a period of time to prepare for their intended use. This is not required under Canadian GAAP.

Deferred charges:

Under Canadian GAAP, the Company defers and amortizes debt issuance costs on a straight-line basis over the stated term of the related debt. Under U.S. GAAP, the Company is required to amortize financing costs over the stated term of the related debt using the effective interest method resulting in a consistent interest rate over the term of the debt in accordance with Accounting Principles Board Opinion No. 12 (“APB 12”). As a result, the net loss under U.S. GAAP for the three months ended September 30, 2005 and the six months ended September 30, 2005 would have been reduced by $180 and $223 respectively using the effective interest method.

Reporting comprehensive income:

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

Stock-based compensation:

The Company uses the fair value method of accounting to all stock-based compensation payments under Canadian GAAP. As a result, there are no differences between Canadian GAAP and Statement of Financial Accounting Standards No. 123 (“SFAS 123”).

Derivative Financial Instruments:

Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”) establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts and debt instruments) be recorded in the balance sheet as either an asset or liability measured at its fair value. On May 19, 2005 the company issued 9% senior secured notes for US $60.4 million (Canadian $76.3 million), which included certain contingent embedded derivatives which provided for the acceleration of redemption by the holder at a premium in certain instances (note 7 (b)). These embedded derivatives met the criteria for bifurcation from the debt contract. While initially no value was ascribed at issuance, they have been measured at fair value and classified as part of the carrying amount of Senior Notes on the consolidated balance sheet, with changes in the fair value being recorded in net earning as realized and unrealized (gain) loss on derivative financial instruments for the period under U.S. GAAP. Under Canadian GAAP, separate accounting of embedded derivatives from the host contract is not permitted by EIC-117.

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NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

Effect of Canadian – US GAAP Differences

The effect of material differences between Canadian and U.S. GAAP on the Company’s reported loss is set out below:

	Three months ended September 30						Six months ended September 30
	2005			2004			2005			2004
Net income (loss) (as reported)		11,503			(4,691	)		(37,699	)		(9,775	)
Capitalized interest		143			—			302			—
Amortization using effective interest method		180			—			223			—
Realized and unrealized loss on derivative financial instruments		(406	)		—			(406	)		—
Income (loss) before income taxes		11,420			(4,691	)		(37,580	)		(9,775	)
Income taxes:
Future income taxes		—			—			—			—
Net income (loss) – U.S. GAAP	$	11,420		$	(4,691	)	$	(37,580	)	$	(9,775	)

The cumulative effect of these adjustments on the consolidated shareholder’s equity of the Company is as follows:

	September 30, 2005			March 31, 2005
Shareholder’s equity (as reported) – Canadian GAAP	$	36,163		$	73,539
Capitalized interest		302			—
Amortization using effective interest method		223			—
Realized and unrealized loss on derivative financial instruments		(406	)		—
Shareholder’s equity – U.S. GAAP	$	36,282		$	73,539

United States accounting pronouncements recently adopted:

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

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143” (“FIN 47”), which requires an entity to recognize a

30

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to Consolidated Financial Statements

For the three and six months ended September 30, 2005

(Amounts in thousands of Canadian dollars unless otherwise specified)

(Unaudited)

liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. FIN 47 is effective for fiscal years ending after December 15, 2005. The adoption of this standard did not have a material impact on the Company’s financial statements.

Statement on Financial Accounting Standards No. 153, “Exchanges of Non-monetary Assets – an Amendment of APB Opinion 29” (“SFAS 153”), was issued in December 2004. Accounting Principles Board (“APB”) Opinion 29 is based on the principle that exchanges of non-monetary assets should be measured based on the fair value of assets exchanged. SFAS 153 amends APB Opinion 29 to eliminate the exception for non-monetary exchanges of similar productive assets and replaces it with a general exception for exchanges of non-monetary assets that do not have commercial substance. The standard is effective for the Company for non-monetary asset exchanges occurring in fiscal periods beginning after June 15, 2005, beginning July 1, 2005 for the Company, The adoption of this standard did not have a material impact on the Company’s financial statements.

Recent United States accounting pronouncements not yet adopted:

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

In May 2005, the FASB issued Statement on Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections” (“SFAS 154”) which replaces Accounting Principles Board Opinions No. 20 “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements – An Amendment of APB Opinion No. 28.” SFAS 154 provides guidance on the accounting for and reporting of accounting change and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 and is required to be adopted by the Company in its fiscal year beginning on April 1, 2006. The Company is currently evaluating the effect that the adoption of SFAS 154 will have on its consolidated results of operations and financial condition but does not expect it to have a material impact.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

Management’s Discussion and Analysis

For the Three and Six Months Ended September 30, 2005

The following discussion should be read in conjunction with the attached interim consolidated financial statements for the three and six months ended September 30, 2005. This document contains forward-looking statements. Such forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause future actions, conditions or events to differ materially from the anticipated actions, conditions or events expressed or implied by such forward-looking statements. Forward-looking statements are those that do not relate strictly to historical or current facts, and can be identified by the use of the future tense or other forward-looking words such as “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “should,” “may,” “objective,” “projection,” “forecast,” “believes,” “continue,” “strategy,” “position,” or the negative of those terms or other variations of them or comparable terminology. Forward-looking statements included in this document include statements regarding: financial resources; capital spending; the outlook for our business; and our results generally. Factors that could cause actual results to vary from those in the forward-looking statements include: the effectiveness of our internal controls; our ability to comply with the terms of our credit agreement or our indentures, or in the event of our breach of such terms, our ability to receive waivers or amendments from the lenders under our credit agreement or the trustee under our indentures; potential alternative financing arrangements; our ability to continue to bid successfully on new projects and accurately forecast costs associated with unit-price or lump sum contracts; our ability to obtain surety bonds as required by some of our customers; decreases in outsourcing work by our customers; changes in oil and gas prices; shut-downs or cutbacks at major businesses that use our services; changes in laws or regulations, third party relations and approvals, and decisions of courts, regulators and governmental bodies that may adversely affect our business or the business of the customers we serve; our ability to hire and retain a skilled labor force; provincial, regional and local economic, competitive and regulatory conditions and developments; technological developments; capital markets conditions; inflation rates; foreign currency exchange rates; interest rates; weather conditions; the timing and success of business development efforts; and our ability to successfully identify and acquire new businesses and assets and integrate them into our existing operations and the other risk factors set forth herein under “Risk Factors.” You are cautioned not to put undue reliance on any forward-looking statements, and we undertake no obligation to update those statements.

Overview

We provide services primarily to major oil and natural gas, petrochemical, and other natural resource companies operating in western Canada. These services are offered through three operating segments: Mining and Site Preparation, Piling, and Pipeline. The Mining and Site Preparation operating segment is involved in a variety of activities, including: surface mining for oilsands and other natural resources; overburden removal; hauling sand and gravel; supplying labor and equipment to support customers’ mining operations; construction of infrastructure associated with mining operations and reclamation activities; clearing, stripping, excavating, and grading for mining operations and other general construction projects; and underground utility installation for plant, refinery, and commercial building construction. The Piling operating segment installs all types of driven and drilled piles, caissons, and earth retention and stabilization systems for commercial buildings, industrial projects, and infrastructure projects. The Pipeline operating segment installs transmission and distribution pipe made of steel, plastic, and fiberglass materials in sizes up to, and including, 52 inches in diameter for oil and natural gas transmission.

We and our predecessor company have been operating for over 50 years and maintain one of the largest independently-owned equipment fleets in western Canada. In serving our customers, we operate over 450 pieces of heavy construction equipment and over 600 support vehicles. Our fleet size provides flexibility in scheduling and completing contract services on a timely basis and allows us to undertake long-term, large-scale projects with major operators in oilsands development and other energy sectors.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

Consolidated Financial Results

	Three months ended September 30										Six months ended September 30
(in millions of Canadian dollars)	2005					2004					2005					2004
Revenue	$	124.0		100.0	%	$	82.7		100.0	%	$	228.4		100.0	%	$	153.5		100.0	%
Project costs		79.9		64.4	%		54.9		66.4	%		146.5		64.1	%		100.9		65.7	%
Equipment costs		13.6		11.0	%		12.1		14.6	%		30.6		13.4	%		23.6		15.4	%
Operating lease expense		3.1		2.5	%		0.8		1.0	%		6.0		2.6	%		1.5		1.0	%
Depreciation		5.5		4.4	%		5.1		6.2	%		10.5		4.6	%		9.7		6.3	%
Gross profit		21.9		17.7	%		9.8		11.8	%		34.8		15.3	%		17.8		11.6	%
General and administrative		6.4		5.2	%		4.9		5.9	%		13.7		6.0	%		10.0		6.5	%
(Gain) loss on disposal of property, plant and equipment		(0.6	)	-0.5	%		0.3		0.3	%		(0.3	)	-0.1	%		0.2		0.1	%
Amortization of intangible assets		0.2		0.1	%		1.1		1.3	%		0.4		0.2	%		2.5		1.6	%
Operating income		15.9		12.9	%		3.5		4.3	%		21.0		9.2	%		5.1		3.3	%
Interest expense		3.3		2.7	%		7.9		9.6	%		53.5		23.4	%		15.2		9.9	%
Foreign exchange gain		(16.5	)	-13.3	%		(14.1	)	-17.0	%		(15.3	)	-6.7	%		(9.4	)	-6.1	%
Other income		(0.1	)	-0.1	%		(0.1	)	-0.1	%		(0.3	)	-0.1	%		(0.3	)	-0.2	%
Write-off deferred financing costs		—		0.0	%		—		0.0	%		1.8		0.8	%		—		0.0	%
Realized and unrealized loss on derivative financial instruments		17.5		14.1	%		16.1		19.5	%		18.8		8.2	%		13.5		8.8	%
Income (loss) before income taxes	$	11.7		9.5	%	$	(6.3	)	-7.6	%	$	(37.5	)	-16.4	%	$	(13.9	)	-9.1	%

Revenue

Revenue for the three and six months ended September 30, 2005 increased by $41.3 million (49.9 percent) and $74.9 million (48.8 percent), respectively, from the same periods in the prior year. The increases are primarily due to a number of new mining and site preparation contracts, including the large site preparation and underground utility installation and overburden removal projects for Canadian Natural Resources Ltd. (“CNRL”) and the mining contract for Grande Cache Coal Corporation, and increased piling activity. Revenue from these new projects in the current periods more than offset the declines in revenue primarily due to the substantial completion of the Syncrude UE1 site grading contract and the Opti/Nexen Long Lake project.

Project costs

Project costs for the three months ended September 30, 2005 increased by $25.0 million (45.5 percent) from the same period in the prior year primarily due to higher activity levels. As a percentage of revenue, project costs were 64.4 percent in the three months ended September 30, 2005 as compared to 66.4 percent in the comparative period. This is primarily due to increased activity leading to more efficient management of costs.

Project costs for the six months ended September 30, 2005 increased by $45.6 million (45.2 percent) from the same period in the prior year primarily due to higher levels of work in progress. As a percentage of revenue, project costs were 64.1 percent in the six months ended September 30, 2005 as compared to 65.7 percent in the comparative period.

Equipment costs

Equipment costs for the three months ended September 30, 2005 increased by $1.5 million (12.4 percent) from the same period in the prior year primarily due to higher operated hours due to increased activity levels and higher hauling costs.

Equipment costs for the six months ended September 30, 2005 increased by $7.0 million (29.7 percent) from the same period in the prior year primarily due to increased activity levels and higher repair and maintenance costs.

2

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

Operating lease expense

Operating lease expense for the three and six months ended September 30, 2005 increased by $2.3 million (287.5 percent) and $4.5 million (300.0 percent), respectively, from the corresponding periods in the prior year. This is primarily due to the addition of new leased equipment to support new projects, including the CNRL site-grading project.

Depreciation

Depreciation expense for the three and six months ended September 30, 2005 increased by $0.4 million (7.8 percent) and $0.8 million (8.2 percent), respectively, from the corresponding periods in the prior year. The increase was primarily due to the increase in equipment hours related to higher activity levels, as our heavy equipment fleet is depreciated based on operated hours.

General and administrative expenses

General and administrative expenses for the three months ended September 30, 2005 increased by $1.5 million (30.6 percent) from the corresponding period in the prior year. The increase was primarily attributable to: increased salaries; higher consulting costs; and increased accounting and audit fees related to our restatement of prior fiscal years.

General and administrative expenses for the six months ended September 30, 2005 increased by $3.7 million (37.0 percent) from the same period in the prior year. The increase was primarily due to increased professional fees and salaries.

Amortization of intangible assets

The amortization of intangible assets in both the current and comparative periods was related to the customer contracts in progress, trade names, non-competition agreement, and employee arrangements that were acquired in the acquisition on November 26, 2003. Substantially all of the cost of the intangible assets has been amortized as of September 30, 2005 as the majority of the cost relates to customer contracts that were amortized at a rapid rate due to their short-term nature.

Amortization of intangible assets for the three months ending September 30, 2005 was $0.2 million, a decrease of $0.9 million (81.8 percent) from the same period in the prior year. For the six months ending September 30, 2005, amortization of intangible assets was $0.4 million, a decrease of $2.1 million (84.0 percent) over the prior year.

Interest expense

Interest expense for the three months ended September 30, 2005 decreased by $4.6 million (58.2 percent) from the corresponding period in the prior year. Increased interest due to the issuance of US$60.5 million of 9% senior secured notes in the current fiscal year was more than offset by a negative adjustment to interest expense due to the decrease in the redemption value of the Series B preferred shares and a decrease in interest expense due to the full repayment of the senior secured credit facility in the current fiscal year.

For the six months ended September 30, 2005, interest expense increased by $38.3 million (252.0 percent) from the prior year. This is primarily due to the issuance of the US$60.5 million of 9% senior secured notes and the accretion of the Series B preferred shares issued in the current fiscal year to record the shares at their redemption value.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

Foreign exchange gain

The foreign exchange gain for the three months ended September 30, 2005 was $16.5 million as compared to $14.1 million in the comparative period, an increase of 17.0 percent. Substantially all of the gain in the current period is due to the exchange difference between the Canadian and U.S. dollar on translation of the US$60.5 million of 9% senior secured notes issued in the current period and the US$200.0 million of 8 ³/4% senior notes. The 8 ³/4% notes are hedged, but do not qualify for hedge accounting under Accounting Guideline 13. The foreign exchange gain for the three months ended September 30, 2004 related primarily to the US $200 million of 8 ³/4% notes.

The foreign exchange gain for the six months ended September 30, 2005 was $15.3 million as compared to a gain of $9.4 million from the comparative period prior year. Substantially all of the gain in the current period related to the exchange difference between the Canadian and U.S. dollar on translation of the US$60.5 million of 9% senior secured notes issued in the current period and the US$200 million of 8 ³/4% senior notes, while the gain in the comparative period related only to the US$200 million of 8 ³/4% senior notes.

Financing costs

Financing costs of $0.3 million were recorded in the six months ended September 30, 2005 representing the issuance of the Series A mandatorily redeemable preferred shares. In addition, we wrote off $1.8 million of deferred financing costs related to the previous senior secured credit facility.

Realized and unrealized loss on derivative financial instruments

The realized and unrealized losses on the cross-currency and interest rate swap agreements, which do not qualify for hedge accounting, were $17.5 million and $18.8 million for the three and six months ended September 30, 2005, respectively. These losses relate primarily to the mark-to-market changes in the fair value of the derivatives in the current periods. The realized and unrealized losses on the derivative financial instruments were $16.1 million and $13.5 million for the respective comparative periods.

Comparative Quarterly Results

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

The comparative information presented for the fiscal year ended March 31, 2004 is largely the result of operations of Norama Ltd. (“Norama” or the “Predecessor Company”) preceding the acquisition that occurred on November 26, 2003. Included in the comparative information presented for the year ended March 31, 2004 are the results of the Predecessor Company up to November 25, 2003 plus the results of the Successor Company, NAEPI, for the period from November 26, 2003 to March 31, 2004. The information for the periods that occurred after November 25, 2003 may not be directly comparable to the information provided for the pre-acquisition periods as a result of the buy-out of equipment leases and the effect of the revaluation of assets and liabilities to their estimated fair market values in accordance with the application of purchase accounting pursuant to Canadian and United States (“U.S.”) generally accepted accounting principles (“GAAP”).

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

																		Predecessor Company
	Fiscal Year 2006								Fiscal Year 2005									Fiscal Year 2004
(in millions of Canadian dollars, except equipment hours)	Q2		Q1			Q4			Q3			Q2			Q1			Q4			Q3
Revenue	$	124.0	$	104.4		$	122.8		$	81.0		$	82.7		$	70.9		$	102.4		$	79.9
Gross profit		21.9		12.9			24.0			(5.6	)		9.8			8.1			19.8			6.5
Net income (loss)		11.6		(49.1	)		(0.1	)		(32.4	)		(4.7	)		(5.1	)		(2.6	)		(20.2	)
Equipment hours		251,904		202,327			241,727			191,555			193,205			137,434			188,557			128,153

The higher revenues experienced over the recent three quarters compared to prior periods primarily resulted from new mining and site preparation contracts, including the CNRL site preparation and underground utility installation contracts and Grande Cache Coal mining services contract, higher activity in the piling division and summer pipeline work.

Segmented Results of Operations

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

Selected Segmented Information

	Three months ended September 30								Six months ended September 30
(in millions of Canadian dollars, except equipment hours)	2005				2004				2005				2004
Revenue by operating segment
Mining and Site Preparation	$	93.5	75.4	%	$	62.6	75.7	%	$	176.0	77.1	%	$	109.4	71.3	%
Piling		22.1	17.8	%		17.4	21.0	%		42.3	18.5	%		30.6	19.9	%
Pipeline		8.4	6.8	%		2.7	3.3	%		10.1	4.4	%		13.5	8.8	%
Total	$	124.0	100.0	%	$	82.7	100.0	%	$	228.4	100.0	%	$	153.5	100.0	%
Profit by operating segment
Mining and Site Preparation	$	9.5	59.0	%	$	5.6	57.1	%	$	20.1	67.2	%	$	9.0	50.6	%
Piling		4.8	29.8	%		3.8	38.8	%		7.9	26.4	%		6.8	38.2	%
Pipeline		1.8	11.2	%		0.4	4.1	%		1.9	6.4	%		2.0	11.2	%
Total	$	16.1	100.0	%	$	9.8	100.0	%	$	29.9	100.0	%	$	17.8	100.0	%
Equipment hours by operating segment
Mining and Site Preparation		237,908	94.5	%		172,504	89.3	%		425,859	93.7	%		284,921	86.2	%
Piling		7,382	2.9	%		17,853	9.2	%		17,089	3.8	%		32,916	10.0	%
Pipeline		6,614	2.6	%		2,848	1.5	%		11,283	2.5	%		12,802	3.8	%
Total		251,904	100.0	%		193,205	100.0	%		454,231	100.0	%		330,639	100.0	%

Mining and Site Preparation

Revenue for the three and six months ended September 30, 2005 increased by $30.9 million (49.4 percent) and $66.6 million (60.9 percent), respectively, from the same periods in the prior year primarily due to activity in the current periods related to the large site preparation and underground utility installation and overburden removal contracts for CNRL and the mining services contract for Grande Cache Coal Corporation. Revenue generated by these projects in the current periods more than offset the decline in revenue resulting from the substantial completion of the Syncrude UE1 and Opti/Nexen Long Lake projects.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

Segment profits for the three and six months ended September 30, 2005 increased by $3.9 million (69.6 percent) and $11.1 million (123.3 percent), respectively, from the comparative periods in the prior year due to the higher volume of work in the current periods and unusually poor results in the comparative periods related to two relatively large projects that were completed or substantially completed in the prior year.

Piling

Piling revenue for the three and six months ended September 30, 2005 increased by $4.7 million (27.0 percent) and $11.7 million (38.2 percent), respectively, from the comparative prior periods primarily due to a higher volume of contracts in the Vancouver, Regina, and Fort McMurray regions due to strong economic activity, as well as the addition of several large piling contracts, including projects for Flint Infrastructure Services Ltd. and Suncor Energy.

Profit for the Piling operating segment increased by $1.0 million (26.3 percent) and $1.1 million (16.2 percent) for the three and six months ended September 30, 2005, respectively, as compared to the comparative prior period due to the higher volume of work performed in the current periods.

Pipeline

Pipeline operating segment revenue for the three months ended September 30, 2005 increased by $5.7 million (211.1 percent) from the comparative prior period primarily due to an increase in work performed for our major pipeline customer in the current period. Profit for this operating segment for the three months ended September 30, 2005 increased by $1.4 million (350 percent) from the comparative prior period primarily as a result of the higher activity in the current period.

Revenue for this segment for the six months ended September 30, 2005 decreased by $3.4 million (25.2 percent) from the comparative prior period due to a decrease in work performed for our major pipeline customer in the current period. Segment profit for the six months ended September 30, 2005 decreased by $0.1 million (5.0 percent) from the comparative prior period primarily as a result of the lower activity in the current period.

Consolidated Financial Position

At September 30, 2005, we had net working capital of $61.4 million compared to a net working capital position of $41.7 million at March 31, 2005. The increase was primarily due to increased work in progress generating higher invoicing and accounts receivable by $4.2 million. Unbilled revenue increased by $11.5 million from March 31, 2005 as a result of the contractual billing terms on several large projects on-going in the period.

Property, plant and equipment net of depreciation increased by $2.0 million at September 30, 2005 from March 31, 2005 primarily due to the expansion of our head office and the on-going construction of a shop to support the maintenance requirements of our 10-year overburden removal project for CNRL. A portion of the increase also resulted from equipment purchases to replace retired equipment.

Accounts payable and accrued liabilities decreased by $5.1 million primarily as a result of the more timely and efficient payment of invoices, partially offset by additional accrued interest on the 8 ³/4 % senior notes and 9% senior secured notes.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

Capital lease obligations, including the current portion, increased by $1.1 million at September 30, 2005 from the balance at March 31, 2005 due to the addition of new leased vehicles to support new projects.

Impairment of Goodwill

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

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

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

We completed this test during the third quarter of fiscal 2005 and were not required to record an impairment loss on goodwill. No change in circumstances has occurred since the test was completed to September 30, 2005 that would indicate impairment.

Liquidity and Capital Resources

Operating activities

Operating activities for the three months ended September 30, 2005 resulted in a net increase of cash totalling $10.7 million mainly due to increased earnings. Cash provided from operating activities for the three months ended September 30, 2004 was $1.9 million.

Operating activities for the six months ended September 30, 2005 resulted in a net decrease in cash of $5.4 million. Increased earnings were more than offset by increases in unbilled revenue and accounts receivable, along with payments of accounts payable invoices and the semi-annual payment of interest on the 8 ³/4% senior notes. The net usage of cash from operating activities for the six months ended September 30, 2004 was $2.1 million primarily due to an increase in unbilled revenue due to billing delays.

Investing activities

During the three months ended September 30, 2005, we invested $3.6 million in sustaining capital expenditures and $3.9 million in growth capital expenditures compared to $2.1 million and $0.9 million, respectively, during the same period in the prior year. In addition, we financed new vehicles by way of capital leases totalling $1.0 million during the three months ended September 30, 2005 compared to $1.4 million during the same period in the prior year.

During the six months ended September 30, 2005, we invested $4.8 million in sustaining capital expenditures, $8.4 million in growth capital expenditures, and $1.9 million in new vehicle capital leases. In the six months ended September 30, 2004, we invested $3.1 million in sustaining capital expenditures, $11.3 million in growth capital expenditures, and $2.1 million in new vehicle capital leases.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

We expect our future sustaining capital expenditures to range from $5.0 million to $7.0 million per year, not including replacement capital expenditures. Sustaining capital expenditures are those that are required to maintain our existing fleet of equipment at its optimum average age. Growth capital expenditures relate to equipment additions required to perform increased sizes or numbers of projects.

Financing activities

Financing activities during the three months ended September 30, 2005 resulted in a net increase of cash totalling $0.2 million primarily due to the issuance of additional Series B mandatorily redeemable preferred shares, partially offset by payments made on our capital leases and additional financing costs related to the refinancing that occurred in the current fiscal year. Financing activities during the three months ended September 30, 2004 related primarily to payments made on the senior secured credit facility, capital lease obligations, and additional financing costs incurred related to the issuance of the 8 ³/4% senior notes.

Financing activities during the six months ended September 30, 2005 resulted in a cash inflow of $15.0 million. A portion of the proceeds from the issuance of the US$60.5 million of 9% senior secured notes and $7.5 million of Series B preferred shares was used to repay the amount outstanding under our senior secured credit facility and to pay the fees and expenses related to the refinancing. Payments of $0.9 million were also made on our capital lease obligations. Financing activities for the six months ended September 30, 2004 related to payments made on our senior secured credit facility, capital lease obligations, and additional financing costs incurred related to the issuance of the 8 ³/4% senior notes.

Liquidity Requirements

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

Our US$200 million of 8 ³/4% senior notes were issued pursuant to a private placement concurrent with the acquisition on November 26, 2003 pursuant to a private placement. On October 5, 2004, we registered substantially identical notes with the United States Securities and Exchange Commission and exchanged them for the notes issued in the private placement. As the registration and exchange were not completed within a specified number of days of the original issuance, as required by a registration rights agreement entered into in connection with the original issuance, we were required to pay additional interest to the holders of the notes in the amount of US$0.2 million on the December 1, 2004 scheduled interest payment. There are no principal payments required on the senior notes until maturity.

The foreign currency risk relating to both the principal and interest payments on the 8 ³/4% senior notes has been managed with a cross-currency swap and interest rate swaps which went into effect concurrent with the issuance. The interest expense of $12.8 million is payable semi-annually in June and December of each year until the notes mature on December 1, 2011. The swap agreements are economic hedges of the changes in the Canadian dollar-U.S. dollar exchange rate, but they do not meet the criteria to qualify for hedge accounting.

Our US$60.5 million of 9% senior secured notes were issued on May 19, 2005 pursuant to a private placement. On July 26, 2005, we registered substantially identical notes with the United States Securities and Exchange Commission and exchanged them for the notes issued in the private placement.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

The foreign currency risk relating to both the principal and interest payments on the 9% senior secured notes has not been hedged. The interest expense of US$2.7 million is payable semi-annually in June and December of each year until the notes mature on June 1, 2010.

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

Our cash requirements during the six months ended September 30, 2005 increased due to continued growth and acquisition of new projects. Our cash requirements for the remainder of the 2006 fiscal year include funding operating lease obligations, debt and interest repayment obligations, and working capital as activity levels are expected to continue to increase. In addition, we will require capital to finance further vehicle and equipment acquisitions for upcoming new projects.

Sources of Liquidity

Our principal sources of cash are funds from operations and borrowings under our revolving credit facility. The revolving credit facility provides for borrowings of up to $40.0 million, subject to borrowing base limitations, under which revolving loans may be made and letters of credit, up to a limit of $30.0 million, may be issued. As of September 30, 2005, we had no outstanding borrowings under the revolving credit facility and had issued $22.0 million in letters of credit to support bonding requirements and performance guarantees associated with customer contracts. The borrowing base less first lien exposure on our swap agreements at September 30, 2005 was a negative $3.1 million. As such, our borrowing availability under the revolving credit facility at September 30, 2005 was zero. The facility bears interest at the Canadian prime rate plus 2% or Canadian bankers’ acceptance rate plus 3%. The indebtedness under the revolving credit facility is secured by substantially all of our assets and those of our subsidiaries, including accounts receivable, inventory and property, plant and equipment, and a pledge of our capital stock and that of our subsidiaries.

On April 27, 2005, Moody’s lowered its rating of our 8 ³/4% senior notes to Caa1 from B3 and lowered our long-term corporate rating to B3 from B2. In addition, Moody’s assigned a rating of B3 to the new 9% senior secured notes. On May 19, 2005, Standard & Poor’s lowered its rating of our 8 ³/4% senior notes to CCC+ from B- and our long-term corporate credit rating to B- from B, while assigning a rating of B to our new senior secured notes. The lower credit ratings will have no effect on the interest rates associated with our 8 ³/4% senior notes or 9% senior secured notes.

The Series B preferred shares were initially issued for cash proceeds of $7.5 million on May 19, 2005 to the Sponsors referred to under “Related Party Transactions” below. We subsequently offered and sold $0.9 million of Series B preferred shares to other existing shareholders of our ultimate parent company, NACG Holdings Inc.. On November 1, 2005, the proceeds from this subsequent sale were used to repurchase a like amount of Series B preferred shares from the Sponsors, thus the total amount of Series B preferred shares outstanding remained the same. The payment of dividends and the redemption of the shares are restricted by the indenture agreements governing our 8 ³/4% senior

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

notes and 9% senior secured notes, as well as the agreement governing our revolving credit facility. The redemption amount is the greatest of:

i. $15.0 million less the amount, if any, of dividends previously paid in cash;

ii. an amount that, when combined with the amount, if any, of dividends previously paid in cash, provides a 40% internal rate of return, compounded annually from the date of issue, which at September 30, 2005 is calculated to be $8.5 million; and

iii. 25% of the fair market value of our capital shares without taking into account the Series B preferred shares, which management estimates to be $45.2 million at September 30, 2005.

The total redemption amount is limited to $100 million. For additional information on the Series B preferred shares, refer to note 9(a) in our interim consolidated financial statements for the three and six months ended September 30, 2005.

Contractual Obligations

Our principal contractual obligations relate to our long-term debt (senior notes and senior secured notes), Series A and B mandatorily redeemable preferred shares, and capital and operating leases. The following table summarizes our future contractual obligations, excluding interest payments unless otherwise noted, as of September 30, 2005.

	Payments Due by Period
(in millions of Canadian dollars)	Total		2006		2007		2008		2009		2010 and after
Long-term debt	$	302.9	$	—	$	—	$	—	$	—	$	302.9
Mandatorily redeemable preferred shares		45.8		—		—		—		—		45.8
Capital leases (including interest)		9.2		2.5		2.5		2.2		1.4		0.6
Operating leases		42.7		15.3		14.2		6.3		3.6		3.3
Total contractual obligations	$	400.6	$	17.8	$	16.7	$	8.5	$	5.0	$	352.6

Stock-Based Compensation

Certain of our directors, officers, employees, and service providers have been granted options to purchase common shares of NACG Holdings Inc., our ultimate parent company, under a stock-based compensation plan. The plan and outstanding balances are disclosed in note 16 to our interim consolidated financial statements for the three and six months ended September 30, 2005.

Related Party Transactions

The Sterling Group, L.P. (“Sterling”), Genstar Capital, L.P., Perry Strategic Capital Inc., and Stephens Group, Inc., (the “Sponsors”), entered into an agreement with NACG Holdings Inc. and certain of its subsidiaries, including us, to provide consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. As compensation for these services an advisory fee of $100,000 for the three months ended September 30, 2005 (three months ended September 30, 2004 – $100,000) is payable to the Sponsors, as a group. Additionally, $7.5 million of Series B preferred shares were initially issued to the Sponsors.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

Pursuant to several office lease agreements, for the three months ended September 30, 2005 we paid $361,000 (three months ended September 30, 2004 – $294,000) to a company owned, indirectly and in part, by one of our directors. For the six months ended September 30, 2005 we paid $654,000 (six months ended September 30, 2004 - $468,000)

Critical Accounting Policies and Estimates

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

Revenue recognition

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

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

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

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

• Lump sum — The price for services performed is established at the outset of the contract and is not subject to any adjustment based on the costs incurred or our performance under the scope of the original contract. Changes in scope added by the customer are priced incrementally to the original bid or lump sum. Similar to unit-price contracts, the price charged to the customer for the services performed is calculated by estimating all of the costs expected to be incurred in performing services required by the contract and adding an appropriate amount to the contract price to generate the required profit margin. Revenue on lump sum contracts is recognized using the percentage-of-completion method, calculated using output measures like cubic meters, lineal meters, or completed piles to date. In the absence of reliable output measures, we recognize revenue based upon input measures such as costs incurred to date.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

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 realization is assured beyond a reasonable doubt. Revenue from claims is recognized when it is determined to be probable that the claim will result in additional contract revenue and the amount can be reliably estimated. Costs incurred for bidding and obtaining contracts are expensed as incurred.

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

Factors that can contribute to changes in estimates of contract cost and profitability include, without limitation: site conditions that differ from those assumed in the original bid, to the extent that contract remedies are unavailable; the availability and skill level of workers in the geographic location of the project; the availability and proximity of materials; the accuracy of the original bid and subsequent estimates; inclement weather and timing; and coordination issues inherent in all projects. Until we feel we can accurately estimate job profitability, no profit on the related project is recognized. The foregoing factors, as well as the stage of completion of contracts in process and the mix of contracts at different margins, may cause fluctuations in gross profit between periods, and these fluctuations may be significant.

Property, plant and equipment

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

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

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

Repair and maintenance costs

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

Derivative financial instruments

The Company uses derivative financial instruments to manage economic risks from fluctuations in exchange rates and interest rates. These instruments include cross-currency swap agreements and interest rate swap agreements. All such instruments are only used for risk management purposes. 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.

The Company’s derivative financial instruments are recorded on the balance sheet at fair value, which is determined based on values quoted by the counterparties to the agreements.

Series B mandatorily redeemable preferred shares

We are required to estimate the redemption value of the Series B madatorily redeemable preferred shares at each reporting date as if the settlement occurred on that date. When calculating the redemption value, we are required to estimate the arm’s length fair value of our common shares. The process of determining fair value is subjective and requires management to exercise judgment in making assumptions about future results, including revenue and cash flow projections, and discount rates.

Accounting policy changes

Revenue recognition

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

Effective April 1, 2005, we amended our accounting policy regarding the recognition of revenue on claims. Once contract performance is underway, we often experience changes in conditions, client requirements, specifications, designs, materials and work schedule. Generally, a “change order” will be negotiated with our customer to modify the original contract to approve both the scope and price of the change. Occasionally, however, disagreements arise regarding changes, their nature, measurement, timing and other characteristics that impact costs and revenue under the contract. When a change becomes a point of dispute between our customer and us, we then consider it as a claim.

Costs related to change orders and claims are recognized when they are incurred. Change orders are included in total estimated contract revenue when it is probable that the change order will result in a bona fide addition to contract value and can be reliably estimated. Prior to April 1, 2005, revenue from claims was included in total estimated contract revenue when awarded or received. After April 1, 2005, claims are included in total estimated contract revenue, only to the extent that contract costs related to the claim have been incurred, when it is probable that the claim will result in a bona fide addition to contract value and can be reliably estimated. Those two conditions are satisfied when (1) the contract or other evidence provides a legal basis for the claim or a legal opinion is obtained

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

providing a reasonable basis to support the claim, (2) additional costs incurred were caused by unforeseen circumstances and are not the result of deficiencies in our performance, (3) costs associated with the claim are identifiable and reasonable in view of work performed and (4) evidence supporting the claim is objective and verifiable. This can lead to a situation where costs are recognized in one period and revenue, when the above conditions warrant recognition of the claim, occurs in subsequent periods. Historical claim recoveries should not be considered indicative of future claim recoveries. For additional information, refer to note 2(p) in our interim consolidated financial statements for the three and six months ended September 30, 2005.

Consolidation of variable interest entities

Effective January 1, 2005, we prospectively adopted the Canadian Institute of Chartered Accountants’ new Accounting Guideline 15, “Consolidation of Variable Interest Entities” (“VIEs”) (“AcG-15”). VIEs are entities that have insufficient equity at risk to finance their operations without additional subordinated financial support and/or entities whose equity investors lack one or more of the specified essential characteristics of a controlling financial interest. AcG-15 provides specific guidance for determining when an entity is a VIE and who, if anyone, should consolidate the VIE. We have determined the joint venture in which it has an investment qualifies as a VIE.

Arrangements containing a lease

Effective January 1, 2005, we adopted the new Canadian Accounting Standard EIC-150, “Determining Whether an Arrangement Contains a Lease.” EIC-150 addresses a situation where an entity enters into an arrangement, comprising a transaction that does not take the legal form of a lease but conveys a right to use a tangible asset in return for a payment or series of payments. We have determined that we have not currently committed to any arrangements to which this standard would apply.

Vendor rebates

In April 2005, we adopted the amended Canadian Accounting Standard EIC-144, “Accounting by a Customer (Including a Reseller) for Certain Consideration Received from a Vendor.” EIC-144 requires companies to recognize the benefit of non-discretionary rebates for achieving specified cumulative purchasing levels as a reduction of the cost of purchases over the relevant period, provided the rebate is probable and reasonably estimable. Otherwise, the rebates would be recognized as purchasing milestones are achieved. The implementation of this new standard did not have a material impact on our consolidated financial statements.

Recently Issued Accounting Standards

The following recent Canadian accounting pronouncements have not yet been adopted by the Company:

Financial instruments

In January 2005, the CICA issued Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, Handbook Section 1530, “Comprehensive Income”, and Handbook Section 3865, “Hedges”. The new standards will be effective for interim and annual financial statements commencing in 2007. Earlier adoption is permitted. The new standards will require presentation of a separate statement of comprehensive income under specific circumstances. Foreign exchange gains and losses on the translation of the financial statements of self-sustaining subsidiaries previously recorded in a separate section of shareholder’s equity will be presented in comprehensive income. Derivative financial instruments will be recorded in the balance sheet at fair value and the changes in fair value of derivatives designated as cash flow hedges will be reported in comprehensive income. We are currently assessing the impact of the new standards.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

Non-monetary transactions

In June 2005, the CICA replaced Handbook Section 3830, “Non-monetary Transactions”, with the new Handbook Section 3831, “Non-monetary Transactions”. The requirements of the new standard apply to non-monetary transactions initiated in periods beginning on or after January 1, 2006, though earlier adoption is permitted as of periods beginning on or after July 1, 2005. The standard requires all non-monetary transactions to be measured at fair market value unless:

• the transaction lacks commercial substance;

• the transaction is an exchange of production or property held for sale in the ordinary course of business for production or property to be sold in the same line of business to facilitate sales to customers other than the parties to the exchange;

• neither the fair value of the assets or services received nor the fair value of the assets or services given up is reliably measurable; or

• the transaction is a non-monetary, non-reciprocal transfer to owners that represents a spin-off or other form of restructuring or liquidation.

We do not expect the adoption of this standard to have a material impact on our results of operations or financial position.

Risk Factors

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

We provide our services primarily to a small number of major integrated and independent oil and gas and other natural resources companies operating in western Canada. Revenue from our five largest customers represented approximately 75% of our total revenue for both the three and six months ended September 30, 2005 and those customers are expected to continue to provide a significant percentage of our revenues in the future. Each period any one of our customers may constitute a significant portion of our revenue. For example, for the three and six months ended September 30, 2005, revenue generated from work for Canadian Natural Resources Ltd. (“CNRL”) constituted approximately 38% and 36%, respectively, of our total revenue due to several large projects with CNRL including the 10-year overburden removal contract and a large site grading contract. We may not be able to replace the work generated by these projects with work from other customers. Our services to our customers are typically provided under contracts with terms ranging from six months to ten years, some of which have terms allowing for automatic or optional renewals of the contract. However, a significant number of our contracts terminate upon completion of the project without having a definite termination date, and the contracts typically allow the customer to reduce or eliminate the work which we are to perform. In addition, the customers may choose not to extend the existing contracts or enter into new contracts. The loss of or significant reduction in business with one or more of these customers could have a material adverse effect on our business.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

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

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

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

Approximately 60% and 61% of our revenue for the three and six months ended September 30, 2005, respectively, was derived from lump sum and unit-price contracts. Going forward, the percentage of our revenue derived from lump sum and unit-price contracts is expected to increase as several of our long-term contracts, including the 10-year overburden removal contract for CNRL, are unit-price and/or lump sum contracts. Given the magnitude of the projected revenues from these contracts as compared to the revenues expected to be earned from other contracts, if we underestimated the costs to perform these contracts, or if we were to incur unrecoverable cost overruns on these projects, it is likely that we would be unable to service our debt obligations.

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

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

We have also had to subsequently restate our financial statements for each period after November 26, 2003 to eliminate the impact of hedge accounting. This was accomplished by recognizing the foreign exchange gain or loss

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

relating to the senior notes each period and recording the derivative financial instruments at fair value and the realized and unrealized gains and losses in the derivative instruments for each period through the Consolidated Statement of Operations, along with the associated future income tax effects.

The financial statements for the first quarter of fiscal 2006 were also required to be restated to correct the accounting for various aspects of the refinancing transactions which occurred on May 19, 2005, including: recording additional liabilities and interest expense for the increase in the redemption value of the Series B mandatorily redeemable preferred shares issued; discounting the liability associated with the Series A mandatorily redeemable preferred shares issued; and deferring and amortizing most of the transaction costs associated with the new debt issued rather than expensing them in the current period.

While we have evaluated our accounting and control procedures surrounding the causes for the misstatements, we may be unable to implement the changes required to provide accurate and timely operating and financial reports. Failure to do so would cause us to breach the reporting requirements under our revolving credit facility and the indentures governing our 8 ³/4% senior notes due 2011 and 9% senior secured notes due 2010, as well as have a material adverse effect on our business, financial condition and results of operations. Until we establish and maintain effective internal controls and procedures for financial reporting, we may not have appropriate procedures in place to eliminate financial statement inaccuracies and avoid delays in financial reporting in the future.

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

Like all businesses providing similar services, we are at times required to post bid or performance bonds issued by a financial institution known as a surety. The surety industry experiences periods of unsettled and volatile markets, usually in the aftermath of substantial loss exposures or corporate bankruptcies with significant surety exposure. Historically, these types of events have caused reinsurers and sureties to reevaluate their committed levels of underwriting and required returns. As needed in the ordinary course of business, we have been able to secure necessary bonds and we will seek opportunities to expand our surety relationships. However, if for any reason, whether because of our financial condition, our level of secured debt or general conditions in the bond market, our bonding capacity becomes insufficient to satisfy our future bonding requirements, our business could be impaired.

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

Outsourced mining and site preparation services constitute a large portion of the work we perform for our customers. For example, our mining project revenues constituted approximately 20% of our revenues in each of the three and six months ended September 30, 2005. The election by one or more of our customers to perform some or all of these services themselves, rather than outsourcing the work to us, could have a material adverse impact on our business.

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

The profitability and growth of our customers may be impacted by the prices of oil and gas. Prices for oil are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil, market uncertainty and a variety of additional factors beyond our control. Such factors include weather conditions, the condition of the

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

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

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

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

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

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

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

Most of our customers are located or operate in western Canada. In the three and six months ended September 30, 2005, we generated approximately 73% and 67%, respectively, of our operating revenues from the Alberta oil sands. A downturn in the energy industry in western Canada could cause our customers to slow down or curtail their current production and future expansions which would, in turn, reduce our revenue from those customers. Such a delay or curtailment could have a material adverse impact on our financial condition and results of operations.

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

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

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

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

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

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

Our ability to grow our operations in the future is, in part, dependent on our ability to secure tires for our equipment.

Currently, global demand for tires is exceeding the available supply. While we have been able to secure the necessary tires to date to keep our equipment running, there is no guarantee that this will be the case in the future.

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

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

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

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

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

Approximately 45% and 48% of our revenue for the three and six months ended September 30, 2005, respectively, was derived from projects which we consider to be non-recurring. This revenue primarily relates to site preparation

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

and piling services provided for the construction of extraction, upgrading and other oil sands mining infrastructure projects. Future revenues from these types of services will depend upon customers expanding existing mines and developing new projects.

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

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

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

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

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

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

We own, or lease, and operate several properties that have been used for a number of years for the storage and maintenance of equipment and other industrial uses upon which fuel may have been spilled, or hydrocarbons or other

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

wastes which may have been disposed of or released. Any release of substances by us or by third parties who previously operated on these properties may be subject to laws which impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of hazardous substances into the environment. Under such laws, we could be required to remove or remediate previously disposed wastes and clean up contaminated property.

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

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

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

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

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

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

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

• difficulties in the assimilation and retention of employees; and

• potential adverse effects on operating results.

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

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

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

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

Risk Management

Foreign currency risk

We are subject to currency exchange risk as the 8 ³/4% senior notes and 9% senior secured notes are denominated in U.S. dollars and all of our revenues and most of our expenses are denominated in Canadian dollars. As noted above, we have entered into cross currency swap and interest rate swap agreements to manage the foreign currency risk on the 8 ³/4% senior notes. The hedging instrument consists of three components: a U.S. dollar interest rate swap; a U.S. dollar-Canadian dollar cross-currency basis swap; and a Canadian dollar interest rate swap that results in us mitigating our exposure to the variability of cash flows caused by currency fluctuations relating to the 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. The premium is equal to 4.375 percent of the US$200 million if exercised between December 1, 2007 and December 1, 2008; 2.1875 percent if exercised between December 1, 2008 and December 1, 2009; and 0.000 percent if cancelled after December 1, 2009. We have not hedged the foreign currency risk on the 9% senior secured notes. Each $0.01 increase or decrease in the U.S. dollar-Canadian dollar exchange rate would change the interest cost on these notes by $0.05 million per year.

Interest rate risk

We are subject to interest rate risk in connection with our revolving credit facility. The facility bears interest at variable rates based on the Canadian prime rate plus 2 percent or Canadian bankers’ acceptance rate plus 3 percent. Assuming the revolving credit facility is fully drawn at $40 million, excluding the $22 million of outstanding letters of credit at September 30, 2005, each 1.0 percent increase or decrease in the applicable interest rate would change the interest cost by $0.18 million per year. In the future, we may enter into interest rate swaps involving the exchange of floating for fixed rate interest payments, to reduce interest rate volatility.

Inflation

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

Outlook

We have developed a strong business foundation through our relationships with the key organizations in the Fort McMurray oil sands area of Alberta (Syncrude, CNRL, Suncor, Opti/Nexen, etc) coupled with the long-term mining work at CNRL and Grande Cache Coal. Our ability to build on this solid foundation continues to be enhanced as world economic growth underpins high prices in the resource (particularly coal) and oil and gas industries.

Activity in the Fort McMurray area remains very high and a number of high profile projects have been announced, most recently the acceleration of CNRL expansion plans. Accordingly, activity levels are expected to remain strong.

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NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2005

Over the last six months, we have completed a refinancing of our debt and injected some equity, the management team has been restructured, and a number of initiatives that have strengthened the financial and operating controls have been implemented. These initiatives, coupled with the acquisition of new equipment ideally suited to heavy earth moving in the oil sands area, have strengthened our ability to bid competitively and profitably into the expanding market.

With respect to the Mining and Site Preparation operating segment, we are actively pursuing a strategy of retaining our number one position as an outsource provider of services in the Fort McMurray oil sands area while concurrently reducing risk by bidding into opportunities in other Canadian provinces. At the same time, our Piling segment remains a strong business and with the level of construction in the western provinces alone, it is considered likely that the work load will remain high in the foreseeable future. Similarly, while the Pipeline segment had reduced activity last year and a low level of activity in the first six months of the current year, the high number of announced projects in this business area also augers well for considerable work in the winter months over the next few years.

U.S. Generally Accepted Accounting Principles

The interim consolidated financial statements have been prepared in accordance with Canadian GAAP, which differs in certain material respects from U.S. GAAP. The nature and effect of these differences are set out in note 18 of the interim consolidated financial statements for the three and six months ended September 30, 2005.

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