UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

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

under

the Securities Exchange Act of 1934

For the month of August 2007

Commission File Number 001-33161

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 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): 82-             

Included herein:

1. Interim consolidated financial statements of North American Energy Partners Inc. for the three months ended June 30, 2007.

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/ Douglas A. Wilkes
Name: Title:	Douglas A. Wilkes Vice President, Finance and Chief Financial Officer

Date: August 14, 2007

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Financial Statements

For the three months ended June 30, 2007

(Expressed in thousands of Canadian dollars)

(Unaudited)

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Balance Sheets

(in thousands of Canadian dollars)

	June 30, 2007			March 31, 2007
	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	9,480		$	7,895
Accounts receivable		110,562			93,220
Unbilled revenue		57,029			82,833
Inventory		156			156
Asset held for sale		—			8,268
Prepaid expenses and deposits		8,248			11,932
Other assets		6,330			10,164
Future income taxes		16,067			14,593
		207,872			229,061
Future income taxes (note 3(a))		22,990			14,364
Plant and equipment (note 6)		255,434			255,963
Goodwill		200,056			199,392
Intangible assets, net of accumulated amortization of $18,556 (March 31, 2007—$17,608) (notes 3(a) and 7)		3,065			600
Deferred financing costs, net of accumulated amortization of $nil (March 31, 2007—$7,595) (notes 3(a) and 7)		—			11,356
	$	689,417		$	710,736
Liabilities and Shareholders’ Equity
Current liabilities:
Revolving credit facility (note 7(a))	$	20,000		$	20,500
Accounts payable		81,320			94,548
Accrued liabilities		18,979			23,393
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		5,459			2,999
Current portion of capital lease obligations		3,221			3,195
Current portion of derivative financial instruments (note 11(b))		3,920			2,669
Future income taxes		6,849			4,154
		139,748			151,458
Deferred lease inducements (note 8)		1,108			—
Capital lease obligations		5,699			6,514
Senior notes (notes 3(a) and 7(b))		204,820			230,580
Derivative financial instruments (notes 3(a) and 11(b))		83,843			58,194
Future income taxes (note 3(a))		20,921			19,712
		456,139			466,458
Shareholders’ equity:
Common shares (authorized – unlimited number of voting and non-voting common shares; issued and outstanding – 35,339,660 voting common shares and 412,400 non-voting common shares (March 31, 2007 – 35,192,260 voting common shares and 412,400 non-voting common shares)) (note 9(a))		297,216			296,198
Contributed surplus (note 9(b))		3,687			3,606
Deficit		(67,625	)		(55,526	)
		233,278			244,278
Guarantee (note 16)
Subsequent events (note 17)
	$	689,417		$	710,736

See accompanying notes to unaudited interim consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Statements of Operations, Comprehensive Income (loss) and Deficit

(in thousands of Canadian dollars)

(unaudited)

	Three months ended June 30,
	2007			2006
Revenue	$	167,627		$	138,100
Project costs		94,673			67,009
Equipment costs		45,139			23,935
Equipment operating lease expense		3,935			7,200
Depreciation		8,976			7,312
Gross profit		14,904			32,644
General and administrative costs		14,627			9,235
Loss on disposal of plant and equipment		269			113
Loss on disposal of asset held for sale		316			—
Amortization of intangible assets		70			183
Operating income before the undernoted		(378	)		23,113
Interest expense (note 10)		6,809			10,168
Foreign exchange gain		(17,100	)		(13,466	)
Realized and unrealized loss on derivative financial instruments (note 11(a))		23,949			7,996
Other income		(108	)		(583	)
Income (loss) before income taxes		(13,928	)		18,998
Income taxes (note 12(c)):
Current income taxes		21			(132	)
Future income taxes		(3,626	)		1,236
Net income (loss) and comprehensive income (loss) for the period		(10,323	)		17,894
Deficit, beginning of period – as previously reported		(55,526	)		(76,546	)
Change in accounting policy related to financial instruments (note 3(a))		(1,776	)		—
Deficit, end of period	$	(67,625	)	$	(58,652	)
Net income (loss) per share – basic (note 9(c))	$	(0.29	)	$	0.96
Net income (loss) per share – diluted (note 9(c))	$	(0.29	)	$	0.71

See accompanying notes to unaudited interim consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

Consolidated Statements of Cash Flows

(in thousands of Canadian dollars)

(unaudited)

	Three months ended June 30,
	2007			2006
Cash provided by (used in):
Operating activities:
Net income (loss) for the period	$	(10,323	)	$	17,894
Items not affecting cash:
Depreciation		8,976			7,312
Amortization of intangible assets		70			183
Amortization of deferred financing costs		71			887
Loss on disposal of plant and equipment		269			113
Loss on disposal of asset held for sale		316			—
Unrealized foreign exchange gain on senior notes		(17,150	)		(13,571	)
Amortization of bond issue costs (note 3(a))		397			—
Unrealized loss on derivative financial instruments		23,281			7,419
Stock-based compensation expense (note 14)		359			312
Accretion of redeemable preferred shares		—			945
Future income taxes		(3,626	)		1,236
Net changes in non-cash working capital (note 12(b))		406			(7,680	)
		3,046			15,050
Investing activities:
Acquisition (note 5)		(1,581	)		—
Purchase of plant and equipment		(10,193	)		(11,843	)
Additions to assets held for sale		(2,248	)		—
Proceeds on disposal of plant and equipment		3,690			473
Proceeds on disposal of assets held for sale		10,200			—
		(132	)		(11,370	)
Financing activities:
Decrease in revolving credit facility		(500	)		—
Repayment of capital lease obligations		(802	)		(773	)
Financing costs (notes 7 and 17(b))		(767	)		(618	)
Issue of common shares (note 9(a))		740			—
		(1,329	)		(1,391	)
Increase in cash and cash equivalents		1,585			2,289
Cash and cash equivalents, beginning of period		7,895			42,804
Cash and cash equivalents, end of period	$	9,480		$	45,093

Supplemental cash flow information (note 12(a))

See accompanying notes to unaudited interim consolidated financial statements.

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three months ended June 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

1. Nature of operations

On November 26, 2003, North American Energy Partners Inc. (the “Company”) purchased all the issued and outstanding shares of North American Construction Group Inc. (“NACGI”), including subsidiaries of NACGI, from Norama Ltd. which had been operating continuously in Western Canada since 1953. The Company had no operations prior to November 26, 2003.

The Company undertakes several types of projects including contract mining, industrial and commercial site development, pipeline and piling installations in Canada.

2. Basis of presentation

These unaudited interim consolidated financial statements (the “financial statements”) are prepared in accordance with Canadian generally accepted accounting principles (“GAAP”) for interim financial statements and do not include all of the disclosures normally contained in the Company’s annual consolidated financial statements. Since the determination of many assets, liabilities, revenues and expenses is dependent on future events, the preparation of these financial statements requires the use of estimates and assumptions. In the opinion of management, these financial statements have been prepared within reasonable limits of materiality. Except as disclosed in note 3, these financial statements follow the same significant accounting policies as described and used in the most recent annual consolidated financial statements of the Company for the year ended March 31, 2007 and should be read in conjunction with those consolidated financial statements.

Certain comparative figures have been reclassified to conform with the basis of presentation adopted in the period ended June 30, 2007.

These financial statements include the accounts of the Company, its wholly-owned subsidiary, NACGI, the Company’s joint venture, Noramac Ventures Inc. and the following wholly-owned subsidiaries of NACGI:

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

3. Accounting policy changes

a) Financial instruments – recognition and measurement

Effective April 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants (“CICA”) Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, and Handbook Section 3865, “Hedges”. These standards have been applied retroactively without restatement as discussed below and, accordingly, comparative amounts for prior periods have not been restated.

5

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three months ended June 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

On April 1, 2007, the Company made the following transitional adjustments to the consolidated balance sheet to adopt the new standards:

	Increase (decrease)
Deferred financing costs	$	(9,734	)
Long-term future income tax asset		2,588
Senior notes		(12,634	)
Derivative financial instruments		7,246
Long-term future income tax liability		18
Opening deficit		1,776

CICA Handbook Sections 3855 and 3865 provide guidance on when a financial asset, financial liability or non-financial derivative is to be recognized on the balance sheet of the Company and on what basis these assets, liabilities and derivatives should be valued. Under the standards:

• Financial assets are classified as loans and receivables, held-to-maturity, held-for-trading or available-for-sale. Loans and receivables include all loans and receivables and are accounted for at amortized cost. Held-to-maturity classification is restricted to fixed maturity instruments that the Company intends and is able to hold to maturity and are accounted for at amortized cost. Held-for-trading instruments are recorded at fair value with realized and unrealized gains and losses reported in net income. The remaining financial assets are classified as available-for-sale. These are recorded at fair value with unrealized gains and losses reported in other comprehensive income until the investment is derecognized at which time the amounts would be recorded in net income. On adoption of the standard, the Company has classified its cash and cash equivalents, certain accounts receivable and unbilled revenue as loans and receivables. The Company did not hold any financial assets that were held-for-trading, available-for-sale or held-to-maturity;

• Financial liabilities are classified as either held-for-trading or other financial liabilities. Held-for-trading instruments are recorded at fair value with realized and unrealized gains and losses reported in net income. Other financial liabilities are accounted for at amortized cost with gains and losses reported in net income in the period that the liability is derecognized. The Company has classified its revolving credit facility, accounts payable, certain accrued liabilities, capital lease obligations and senior notes as other financial liabilities; and

• Derivative financial instruments are classified as held-for-trading and measured at fair value unless designated as hedging instruments or exempted from derivative treatment as a normal purchase and sale. Certain derivatives embedded in other contracts are also measured at fair value.

In determining the fair value of financial instruments, the Company used a variety of methods and assumptions that are based on market conditions and risks existing on each reporting date. Counterparty confirmations and standard market conventions and techniques, such as discounted cash flow analysis and option pricing models, are used to determine the fair value of the Company’s financial instruments, including derivatives. All methods of fair value measurement result in a general approximation of value and such value may never actually be realized.

6

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three months ended June 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

The Company elected April 1, 2003 as the transition date for identifying contracts with embedded derivatives. The adoption of these standards resulted in the following adjustments as of April 1, 2007 in accordance with the transition provisions:

• Transaction costs that are directly attributable to the acquisition or issue of financial assets or liabilities are accounted for as a part of the respective asset or liability’s carrying value at inception. Deferred financing costs related to the issue of the senior notes that were previously presented as a separate asset on the consolidated balance sheet are now included in the carrying value of the senior notes and are being amortized using the effective interest method over the remaining term of the debt. Prior to April 1, 2007, these deferred financing costs were amortized on a straight line basis over the term of the debt. As a result of the change in method of accounting, deferred financing costs were remeasured and amortized using the effective interest method. This remeasurement resulted in a $9,734 decrease in deferred financing costs, a decrease of $9,815 in senior notes, a decrease of $63 in opening deficit and an increase of $18 in the future income tax liability.

• Transaction costs incurred in connection with the Company’s revolving credit facility of $1,622 were reclassified from deferred financing costs to intangible assets on April 1, 2007 and these costs continue to be amortized on a straight-line basis over the term of the facility.

• The Company determined that the issuer’s early prepayment option included in the senior notes should be bifurcated from the host contract, along with a contingent embedded derivative in the senior notes that provide for accelerated redemption by the holders in certain instances. These embedded derivatives were measured at fair value at the inception of the senior notes and the residual amount of the proceeds was allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of the senior notes is accreted to the par value over the term of the notes using the effective interest method and is recognized as interest expense. At transition on April 1, 2007, the Company recorded the fair value of $8,519 related to these embedded derivatives and a corresponding decrease in opening deficit of $7,305, net of future income taxes of $1,214. The impact of the bifurcation of these embedded derivatives at issuance of the senior notes resulted in an increase of senior notes $5,700 and an increase in opening deficit of $3,963, net of income taxes of $1,737 after applying the effective interest method to the premium resulting from the bifurcation of these embedded derivatives on April 1, 2007.

• The Company determined that a price escalation feature in a revenue construction contract is an embedded derivative that is not closely related to the host contract. The embedded derivative has been measured at fair value and included in derivative financial instruments on the consolidated balance sheet, with changes in the fair value recognized in net income. The Company recorded the fair value of $7,246 related to this embedded derivative on April 1, 2007, with a corresponding increase in opening deficit of $5,181, net of future income taxes of $2,065.

b) Financial instruments – disclosure and presentation

Revised CICA Handbook Section 3861, “Financial Instruments – Disclosure and Presentation” replaces CICA Handbook Section 3860, “Financial Instruments – Disclosure and Presentation”, and establishes standards for presentation of financial instruments and non-financial derivatives, and identifies information that should be disclosed. There was no material effect on the Company’s financial statements upon adoption of CICA Handbook Section 3861 effective April 1, 2007.

7

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three months ended June 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

c) Comprehensive income and equity

CICA Handbook Section 1530, “Comprehensive Income” establishes standards for the reporting and display of comprehensive income. The new section defines other comprehensive income to include revenues, expenses, and gains and losses that, in accordance with primary sources of GAAP, are recognized in comprehensive income but excluded from net income. The standard does not address issues of recognition or measurement for comprehensive income and its components. The adoption of CICA Handbook Section 1530 effective April 1, 2007 did not have a material impact on the Company’s financial statement presentation in the current period.

CICA Handbook Section 3251, “Equity” establishes standards for the presentation of equity and changes in equity during the reporting period. The requirements in this section are in addition to those of Section 1530 and recommend that an enterprise should present separately the following components of equity: retained earnings, accumulated other comprehensive income, the total for retained earnings and other comprehensive income, contributed surplus, share capital and reserves. The adoption of CICA Handbook Section 3251 effective April 1, 2007 did not have an impact on the Company’s financial statement presentation in the current period. The Company currently has no other comprehensive income components.

d) Accounting changes

In July 2006, the CICA revised Handbook Section 1506, “Accounting Changes”, which requires that: (1) voluntary changes in accounting policy are made only if they result in the financial statements providing reliable and more relevant information; (2) changes in accounting policy are generally applied retrospectively; and (3) prior period errors are corrected retrospectively. This guidance was adopted by the Company on April 1, 2007 and did not have a material impact on the consolidated financial statements.

4. Recent accounting pronouncements not yet adopted

a) Financial instruments

In March 2007, the CICA issued Handbook Section 3862, “Financial Instruments – Disclosures”, which replaces CICA Handbook Section 3861 and provides expanded disclosure requirements that provide additional detail by financial asset and liability categories. This standard harmonizes disclosures with International Financial Reporting Standards. The standard applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.

In March 2007, the CICA issued Handbook Section 3863, “Financial Instruments – Presentation” to enhance financial statement users’ understanding of the significance of financial instruments to an entity’s financial position, performance and cash flows. This section establishes standards for presentation of financial instruments and non-financial derivatives. It deals with the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, gains and losses, and the circumstances in which financial assets and financial liabilities are offset. This standard harmonizes disclosures with International Financial

8

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three months ended June 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

Reporting Standards and applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.

b) Capital disclosures

In December 2006, the CICA issued Handbook Section 1535, “Capital Disclosures”. This standard requires that an entity disclose information that enables users of financial statements to evaluate an entity’s objectives, policies and processes for managing capital, including disclosures of any externally imposed capital requirements and the consequences of non-compliance. The new standard applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.

c) Inventories

In June 2007, the CICA issued Handbook Section 3031, “Inventories” to harmonize accounting for inventories under Canadian GAAP with International Financial Reporting Standards. This standard requires the measurement of inventories at the lower of cost and net realizable value and includes guidance on the determination of cost, including allocation of overheads and other costs to inventory. The standard also requires the consistent use of either first-in, first out (FIFO) or weighted average cost formula to measure the cost of other inventories and requires the reversal of previous write-downs to net realizable value when there is a subsequent increase in the value of inventories. The new standard applies to interim and annual financial statements relating to fiscal years beginning on or after January 1, 2008, specifically April 1, 2008 for the Company. The Company is currently evaluating the impact of this standard.

5. Acquisition

On May 1, 2007, the Company acquired all of the assets of Active Auger Services 2001 Ltd., a piling company specializing in the design and installation of screw piles in north central Saskatchewan, for total cash consideration and acquisition costs of $1,581. The transaction has been accounted for by the purchase method with the results of operations included in the financial statements from the date of acquisition. The details of the acquisition are as follows:

Net assets acquired at assigned values:
Working capital	$	—
Plant and equipment		700
Intangible assets		217
Goodwill		664
	$	1,581

The allocation of the purchase price to the fair value of the assets acquired and liabilities assumed is preliminary and is subject to adjustment.

9

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three months ended June 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

6. Plant and equipment

June 30, 2007	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	250,439	$	47,430	$	203,009
Major component parts in use		8,401		3,073		5,328
Other equipment		16,050		6,030		10,020
Licensed motor vehicles		23,091		12,743		10,348
Office and computer equipment		5,580		2,531		3,049
Buildings		16,443		1,030		15,413
Leasehold improvements		5,531		768		4,763
Assets under construction		3,504		—		3,504
	$	329,039	$	73,605	$	255,434
March 31, 2007	Cost		Accumulated depreciation		Net book value
Heavy equipment	$	254,107	$	46,609	$	207,498
Major component parts in use		7,884		2,489		5,395
Other equipment		16,001		5,651		10,350
Licensed motor vehicles		23,345		12,121		11,224
Office and computer equipment		4,841		2,249		2,592
Buildings		16,443		716		15,727
Leasehold improvements		2,992		664		2,328
Assets under construction		849		—		849
	$	326,462	$	70,499	$	255,963

The above amounts include $15,329 (March 31, 2007 – $15,422) of assets under capital lease and accumulated depreciation of $7,835 (March 31, 2007 – $7,302) related thereto. During the three months ended June 30, 2007, additions of plant and equipment included $13 for capital leases (2006 – $1,758). Depreciation of equipment under capital leases of $533 (2006 – $630) is included in depreciation expense.

7. Debt

a) Revolving credit facility

On June 7, 2007, the Company modified its amended and restated credit agreement to provide for borrowings of up to $125.0 million (previously $55.0 million) under which revolving loans and letters of credit may be issued. Based upon the Company’s current credit rating, prime rate and swing line revolving loans under the agreement will bear interest at the Canadian prime rate plus 0.5% per annum, Canadian bankers’ acceptances have stamping fees equal to 2.0% per annum and letters of credit are subject to a fee of 1.5% per annum.

The credit facility is secured by a first priority lien on substantially all the Company’s existing and after-acquired property and contains certain restrictive covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions or to pay dividends or redeem shares of capital stock. The Company is also required to meet certain financial covenants under the new credit agreement.

10

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three months ended June 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

As of June 30, 2007, the Company had outstanding borrowings of $20.0 million under the revolving credit facility and had issued $25.0 million in letters of credit to support bonding requirements and performance guarantees associated with customer contracts and operating leases. The Company’s borrowing availability under the facility was $80.0 million at June 30, 2007.

During the three months ended June 30, 2007, financing fees of $767 were incurred in connection with the modifications to the amended and restated credit agreement and were recorded as intangible assets.

b) Senior notes

	June 30, 2007			March 31, 2007
Principal outstanding ($US)	$	200,000		$	200,000
Unrealized foreign exchange		13,430			30,580
Unamortized financing costs and discounts (premiums), net		(3,718	)		—
Fair value of embedded prepayment and early redemption options		(4,892	)		—
	$	204,820		$	230,580

8. Deferred lease inducements

Lease inducements applicable to lease contracts are deferred and amortized as a reduction of general and administrative costs on a straight-line basis over the lease term, which includes the initial lease term and renewal periods only where renewal is determined to be reasonably assured.

During the three months ended June 30, 2007, the Company received inducements from a lessor in the form of leasehold improvements to an office facility. Included in accrued liabilities at June 30, 2007 is $392 payable to the lessor as part of this lease agreement.

11

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three months ended June 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

9. Shares

a) Common shares

Authorized:

Unlimited number of common voting shares

Unlimited number of common non-voting shares

Issued:

	Number of Shares	Amount
Common voting shares
Outstanding at March 31, 2007	35,192,260	$	294,136
Issued on exercise of options	147,400		740
Transferred from contributed surplus on exercise of options	—		278
Outstanding at June 30, 2007	35,339,660	$	295,154
Common non-voting shares
Outstanding at March 31 and June 30, 2007	412,400	$	2,062
Total common shares	35,752,060	$	297,216

b) Contributed surplus

Balance, March 31, 2007	$	3,606
Stock-based compensation (note 14)		359
Transferred to common shares on exercise of options		(278	)
Balance, June 30, 2007	$	3,687

12

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three months ended June 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

c) Net income (loss) per share

	Three months ended June 30,
	2007			2006
Basic net income (loss) per share
Net income (loss) available to common shareholders	$	(10,323	)	$	17,894
Weighted average number of common shares		35,671,220			18,620,000
Basic net income (loss) per share	$	(0.29	)	$	0.96
Diluted net income (loss) per share
Net income (loss) available to common shareholders	$	(10,323	)	$	17,894
Dilutive effect of NAEPI Series B preferred shares		—			630
Net income (loss), assuming dilution		(10,323	)		18,524
Weighted average number of common shares		35,671,220			18,620,000
Dilutive effect of:
NAEPI Series B preferred shares		—			7,524,400
Stock options		—			11,200
Weighted average number of diluted common shares		35,671,220			26,155,600
Diluted net income (loss) per share	$	(0.29	)	$	0.71

For the three months ended June 30, 2007 the effect of outstanding stock options on loss per share was anti-dilutive. As such, the effect of outstanding stock options used to calculate the diluted net loss per share has not been disclosed.

10. Interest expense

	Three months ended June 30,
	2007		2006
Interest on senior notes	$	5,834	$	7,346
Interest on capital lease obligations		181		154
Interest on NACG Preferred Corp. Series A preferred shares		—		700
Accretion of NAEPI Series A and NAEPI Series B preferred shares		—		945
Interest on long-term debt		6,015		9,145
Amortization of deferred financing costs		468		887
Interest on revolving credit facility and other interest		326		136
	$	6,809	$	10,168

13

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three months ended June 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

11. Derivative financial instruments

a) Realized and unrealized loss on derivative financial instruments

	Three months ended June 30,
	2007		2006
Realized and unrealized loss on cross-currency and interest rate swaps	$	14,321	$	7,996
Unrealized loss on embedded price escalation clauses in long-term revenue construction contract		6,001		—
Unrealized loss on embedded prepayment and early redemption options on senior notes		3,627		—
	$	23,949	$	7,996

b) Fair value of derivative financial instruments

June 30, 2007	Derivative financial instruments			Senior notes
Cross-currency and interest rate swaps	$	74,516		$	—
Embedded price escalation clauses in long-term revenue construction contract		13,247			—
Embedded prepayment and early redemption options on senior notes		—			(4,892	)
Total fair value of derivative financial instruments		87,763			(4,892	)
Less: current portion		(3,920	)		—
	$	83,843		$	(4,892	)
April 1, 2007	Derivative financial instruments			Senior notes
Cross-currency and interest rate swaps	$	60,863		$	—
Embedded price escalation clauses in long-term construction contracts		7,246			—
Embedded prepayment and early redemption options on senior notes		—			(8,519	)
Total fair value of derivative financial instruments		68,109			(8,519	)
Less: current portion		(2,669	)		—
	$	65,440		$	(8,519	)

14

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three months ended June 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

12. Other information

a) Supplemental cash flow information

	Three months ended June 30,
	2007		2006
Cash paid during the period for:
Interest	$	13,397	$	15,844
Income taxes		22		190
Cash received during the period for:
Interest		106		486
Non-cash transactions:
Capital leases		13		1,758
Lease inducements		1,500		—

b) Net change in non-cash working capital

	Three months ended June 30,
	2007			2006
Operating activities:
Accounts receivable	$	(17,342	)	$	(9,067	)
Unbilled revenue		25,804			5,375
Inventory		—			44
Prepaid expenses and deposits		3,684			505
Other assets		3,834			(2,507	)
Accounts payable		(13,228	)		(582	)
Accrued liabilities		(4,806	)		(2,940	)
Billings in excess of costs and estimated earnings		2,460			1,492
	$	406		$	(7,680	)

c) Income taxes

Income tax expense as a percentage of income before income taxes for the three months ended June 30, 2007 differs from the statutory rate of 31.72% primarily due to the impact of the enacted rate changes during the period, and the impact of new accounting standards for the recognition and measurement of financial instruments as certain embedded derivatives are considered capital in nature for income tax purposes. Income tax as a percentage of income before income taxes for the three months ended June 30, 2006 differed from the statutory rate of 31.72% primarily due to the elimination of the valuation allowance of $5,858 that was recorded during that period.

13. Segmented information

a) General overview

The Company conducts business in three business segments: Heavy Construction and Mining (formerly referred to as “Mining and Site Preparation”), Piling and Pipeline.

• Heavy Construction and Mining:

The Heavy Construction and Mining 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.

15

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three months ended June 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

• Piling:

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

• Pipeline:

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

b) Results by business segment

Three months ended June 30, 2007	Heavy Construction and Mining		Piling		Pipeline			Total
Revenues from external customers	$	126,914	$	35,522	$	5,191		$	167,627
Depreciation of plant and equipment		4,320		846		109			5,275
Segment profits		19,489		9,247		(1,189	)		27,547
Segment assets		438,030		104,981		51,683			594,694
Expenditures for segment plant and equipment		7,677		364		358			8,399
Three months ended June 30, 2006	Heavy Construction and Mining		Piling		Pipeline			Total
Revenues from external customers	$	111,387	$	23,276	$	3,437		$	138,100
Depreciation of plant and equipment		4,947		648		132			5,727
Segment profits		24,127		7,976		659			32,762
Segment assets		338,280		82,632		40,541			461,453
Expenditures for segment plant and equipment		6,984		1,330		—			8,314

c) Reconciliations

i. Income (loss) before income taxes

	Three months ended June 30,
	2007			2006
Total profit for reportable segments	$	27,547		$	32,762
Unallocated corporate expenses		(31,200	)		(13,533	)
Unallocated equipment costs		(10,275	)		(231	)
Income (loss) before income taxes	$	(13,928	)	$	18,998

16

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three months ended June 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

ii. Total assets

	June 30, 2007		March 31, 2007
Total assets for reportable segments	$	594,694	$	621,636
Corporate assets		94,723		89,100
Total assets	$	689,417	$	710,736

The Company’s goodwill was assigned to the Heavy Construction and Mining, Piling and Pipeline segments in the amounts of $125,447, $41,856, 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.

c) Customers

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

	Three months ended June 30,
	2007		2006
Customer A	28	%	5	%
Customer B	16	%	15	%
Customer C	15	%	11	%
Customer D	13	%	6	%

This revenue by major customer was earned in the Heavy Construction and Mining segment.

14. Stock-based compensation plan

Under the 2004 Amended and Restated Share Option Plan, directors, officers, employees and certain service providers to the Company are eligible to receive stock options to acquire voting common shares in the Company. Each stock option provides the right to acquire one common share in the Company and expires ten years from the grant date or on termination of employment. Options may be exercised at a price determined at the time the option is awarded, and vest as follows: no options vest on the award date and twenty percent vest on each subsequent anniversary date.

17

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three months ended June 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

	Three months ended June 30,
	2007					2006
	Number of options		Weighted average exercise price ($ per share)			Number of options		Weighted average exercise price ($ per share)
Outstanding, beginning of period	2,146,840		$	6.03		2,066,360		$	5.00
Granted	—			—		127,760			5.00
Exercised	(147,400	)		(5.00	)	—			—
Forfeited	—			—		(123,280	)		5.00
Outstanding, end of period	1,999,440		$	6.10		2,070,840		$	5.00

At June 30, 2007, the weighted average remaining contractual life of outstanding options is 7.5 years (March 31, 2007 – 7.7 years). The Company recorded $359 of compensation expense related to the stock options in the three months ended June 30, 2007 (2006 – $312) with such amount being credited to contributed surplus.

15. Seasonality

The Company generally experiences a decline in revenues during the first quarter of each fiscal year due to seasonality, as weather conditions make operations in the Company’s operating regions difficult during this period. The level of activity in the Heavy Construction and Mining and Pipeline segments declines when frost leaves the ground and many secondary roads are temporarily rendered incapable of supporting the weight of heavy equipment. The duration of this period is referred to as “spring breakup” and has a direct impact on the Company’s activity levels. Revenues during the fourth quarter of each fiscal year are typically highest as ground conditions are most favorable in the Company’s operating regions. As a result, full-year results are not likely to be a direct multiple of any particular quarter or combination of quarters.

16. Guarantee

In connection with a heavy equipment financing agreement, the Company has guaranteed a $7.0 million debt owed to the equipment manufacturer by a third party finance company. The Company’s guarantee of this indebtedness will expire when the equipment is commissioned, which is expected to be December 31, 2007. The Company has determined that the fair value of this financial instrument at inception and June 30, 2007 was not significant.

17. Subsequent events

a) On July 27, 2007, the Company’s non-voting common shares were exchanged for voting common shares. Each holder of the non-voting common shares received one voting common share for each non-voting share held on the exchange date.

b) On August 7, 2007, certain of the Company’s shareholders completed a secondary offering for the sale of 8,358,604 voting common shares, including 1,090,253 voting common shares sold pursuant to the

18

NORTH AMERICAN ENERGY PARTNERS INC.

Notes to the Interim Consolidated Financial Statements

For the three months ended June 30, 2007

(Amounts in thousands of Canadian dollars unless otherwise specified)

(unaudited)

exercise of an overallotment option granted to the underwriters of the offering. The Company will not receive any proceeds from the secondary offering. During the three months ended June 30, 2007, the Company incurred costs of $164 related to the secondary offering which were charged to general and administrative expense. Based on the estimate of costs prepared at the closing of the offering, the Company expects that it will incur additional costs of approximately $1.2 million during the quarter ended September 30, 2007.

19

NORTH AMERICAN ENERGY PARTNERS INC.

(Formerly NACG Holdings Inc.)

Management’s Discussion and Analysis

For the three months ended June 30, 2007

The following discussion and analysis is as of August 13, 2007 and should be read in conjunction with the attached unaudited interim consolidated financial statements for the three months ended June 30, 2007 and the audited consolidated financial statements included in our annual report on Form 20-F for the fiscal year ended March 31, 2007, which have been prepared in accordance with Canadian generally accepted accounting principles (GAAP), and except where otherwise specifically indicated all dollar amounts are expressed in Canadian dollars. Additional information relating to our business is available on SEDAR at www.sedar.com and EDGAR at www.sec.gov. Unless otherwise indicated, references to “2008,” “2007” and “2006” refer to the fiscal years ended March 31, 2008, 2007 and 2006, respectively.

This document contains forward-looking statements. Our forward-looking statements are subject to known and unknown risks 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”, “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 but are not limited to, those risk factors set forth in Management’s Discussion and Analysis for the year ended March 31, 2007 as described in our Prospectus dated July 31, 2007 filed with the Securities and Exchange Commission under the Securities Act of 1933 (a copy of which can be found at www.sec.gov) and also described in our Prospectus dated July 31, 2007 , filed with the securities regulatory authorities in the provinces and territories in Canada (a copy of which can be found at www.sedar.com), collectively, the “Prospectus” and our annual report on Form 20-F for 2007. You are cautioned not to put undue reliance on any forward-looking statements, and we undertake no obligation to update such statements.

Monday August 13, 2007

Reorganization and Initial Public Offering (“IPO”)

On November 28, 2006, prior to the consummation of the IPO discussed below, NACG Holdings Inc. (“Holdings”) amalgamated with its wholly-owned subsidiaries, NACG Preferred Corp. and North American Energy Partners Inc. (“NAEPI”). The amalgamated entity continued under the name North American Energy Partners Inc. The voting common shares of the new entity, North American Energy Partners Inc., were the shares sold in the IPO.

On November 28, 2006, prior to the amalgamation, the following transactions took place:

• Holdings repurchased the Series A preferred shares issued by NAEPI for their redemption value of $1.0 million and terminated the advisory services agreement (the “Advisory Services Agreement”) with The Sterling Group, L.P., Genstar Capital, L.P., Perry Strategic Capital Inc., and SF Holding Corp. (collectively, the “Sponsors”), under which we had received ongoing consulting and advisory services with respect to the organization of the companies, employee benefit and compensation arrangements, and other matters. We paid the Sponsors a fee of $2.0 million to terminate the agreement, which was charged to income in 2007. Under the consulting and advisory services agreement, the Sponsors also received a fee of $0.9 million, equal to 0.5% of our aggregate gross proceeds from the IPO, which was included in share issue costs.

• The $35.0 million of Series A preferred shares issued by NACG Preferred Corp. were acquired by Holdings for a $27.0 million promissory note issued to the holders of such shares and the forfeiture of accrued dividends of $1.4 million.

• Each holder of the Series B preferred shares issued by NAEPI received 100 Holdings common shares for each Series B preferred share held.

        On November 28, 2006 we completed our IPO in the United States and Canada of 8,750,000 voting common shares for $18.38 per share (U.S. $16.00 per share). On November 22, 2006 our common shares commenced trading on the New York Stock Exchange and on an “if, as and when issued” basis on the Toronto Stock Exchange. On November 28, 2006, our common shares became fully tradable on the Toronto Stock Exchange. Net proceeds from the IPO were $140.9 million (gross proceeds of $158.5 million, less underwriting discounts and costs and offering expenses of $17.6 million). In addition, on December 6, 2006, the underwriters exercised their option to purchase an additional 687,500 common shares from us. The net proceeds from the exercise of the underwriters’ option were $11.7 million (gross proceeds of $12.6 million, less underwriting fees of $0.9 million). Total net proceeds were $152.6 million (total gross proceeds of $171.1 million less total underwriting discounts and costs and offering expenses of $18.5 million).

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2007

We used the net proceeds from the IPO:

• to repurchase all of our outstanding 9% senior secured notes due 2010 for $74.7 million plus accrued interest of $3.0 million on November 28, 2006. The notes were repurchased at a premium of 109.26%, resulting in a loss on extinguishment of $6.3 million and the write-off of deferred financing fees of approximately $4.3 million and third-party transaction costs of $0.3 million. These items were charged to income in 2007;

• to repay the $27.0 million promissory note issued in respect of the repurchase of the NACG Preferred Corp. Series A preferred shares;

• to purchase certain leased equipment for $44.6 million;

• to pay the $2.0 million fee required to terminate the Advisory Services Agreement with the Sponsors; and

• $1.3 million for general corporate purposes.

Consolidated Financial Highlights

	For three months ended June 30,
(in thousands)	2007					2006
Revenue	$	167,627				$	138,100
Gross Profit		14,904		8.9	%		32,644	23.6	%
General & administrative costs		14,627		8.7	%		9,235	6.7	%
Operating income		(378	)	-0.2	%		23,113	16.7	%
Net income (loss)		(10,323	)	-6.2	%		17,894	13.0	%
Per unit/share information				0.0	%			0.0	%
Net Income (loss) - basic	$	(0.29	)	0.0	%	$	0.96	0.0	%
Net Income (loss) - diluted		(0.29	)	0.0	%		0.71	0.0	%
EBITDA (1)	$	1,927		1.1	%	$	36,661	26.5	%
Consolidated EBITDA (1)		9,670		5.8	%		31,511	22.8	%

EBITDA is calculated as net income (loss) before interest expense, income taxes, depreciation and amortization. Consolidated EBITDA is defined as EBITDA, excluding the effects of foreign exchange gain or loss, realized and unrealized gain or loss on derivative financial instruments, non-cash stock-based compensation expense, gain or loss on disposal of plant and equipment and certain other non cash items included in the calculation of net income (loss). We believe that EBITDA is a meaningful measure of the performance of our business because it excludes items, such as depreciation and amortization, interest and taxes, that are not directly related to the operating performance of our business. Management reviews EBITDA to determine whether capital assets are being allocated efficiently. In addition, our revolving credit facility requires us to maintain a minimum interest coverage ratio and a maximum senior leverage ratio, which are calculating using Consolidated EBITDA. Non-compliance with these financial covenants could result in our being required to immediately repay all amounts outstanding under our revolving credit facility. EBITDA and Consolidated EBITDA are not measures of performance under Canadian GAAP or U.S. GAAP and our computations of EBITDA and Consolidated EBITDA may vary from others in our industry. EBITDA and Consolidated EBITDA should not be considered as alternatives to operating income or net income as measures of operating performance or cash flows as measures of liquidity. EBITDA and Consolidated EBITDA have important limitations as analytical tools, and you should not consider them in isolation, or as substitutes for analysis of our results as reported under Canadian GAAP or US GAAP. For example, EBITDA and Consolidated EBITDA:

• do not reflect our cash expenditures or requirements for capital expenditures or capital commitments;

• do not reflect changes in, or cash requirements for, our working capital needs;

• do not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;

• exclude tax payments that represent a reduction in cash available to us; and

• do not reflect any cash requirements for assets being depreciated and amortized that may have to be replaced in the future.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2007

In addition, Consolidated EBITDA excludes foreign exchange gains and losses and unrealized and realized gains and losses on derivative financial instruments, which, in the case of unrealized losses, may ultimately result in a liability that will need to be paid and, in the case of realized losses, represents an actual use of cash during the period.

A reconciliation of net income (loss) to EBITDA and Consolidated EBITDA is as follows:

	Three Months ended June 30,
(in thousands)	2007			2006
Net income (loss)	$	(10,323	)	$	17,894
Adjustments:
Interest expense		6,809			10,168
Income taxes		(3,605	)		1,104
Depreciation		8,976			7,312
Amortization of intangible assets		70			183
EBITDA	$	1,927		$	36,661
A reconciliation of EBITDA to consolidated EBITDA is as follows:
Adjustments:
EBITDA	$	1,927		$	36,661
Unrealized foreign exchange (gain) loss on senior notes		(17,150	)		(13,571	)
Realized and unrealized loss on derivative financial instruments		23,949			7,996
Loss (gain) on disposal of plant and equipment		585			113
Stock-based compensation		359			312
Consolidated EBITDA	$	9,670		$	31,511

Results for the three months ended June 30, 2007 were mixed. We achieved record first-quarter revenue of $167.6 million, a 21% increase over the same period in the prior year. However, in the first quarter gross profit was down to $14.9 million compared to $32.6 million over the same period in the prior year as a result of the negative impacts of increased equipment operating costs, a loss on disposal of surplus equipment recorded as depreciation and a loss in our Pipeline division. The increased equipment operating costs resulted primarily from higher tire and maintenance costs. The loss in our Pipeline division is related to the second and final phase of a fixed-price contract, and resulted from a customer reducing the scope of work.

Operating income was lower in the quarter due to impacts on gross profit discussed above and higher general and administrative expenses (resulting from growth in the business) and discretionary bonuses for past service.

Net income was impacted by new Canadian accounting standards that require us to account for changes in the fair value of embedded derivative financial instruments in various contracts and to modify the method of amortizing deferred financing costs. These changes resulted in a charge to income of approximately $10 million. As discussed further in this Management Discussion and Analysis, these accounting changes do not impact operations, Consolidated EBITDA or how we evaluate our business. The total impact of past service bonuses, the disposal of surplus equipment and the implementation of the new accounting standards was to lower pre-tax income by approximately $16 million. As a result of the foregoing together with the impacts from equipment cost increases and the Pipeline segment loss, we recorded a net loss of $10.3 million, or $0.29 per share in the quarter.

Overview and Outlook

We provide services primarily to major oil and natural gas, and other natural resource companies operating in Canada. These services are offered through three operating segments: Heavy Construction and Mining, Piling and Pipeline.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2007

Heavy Construction and Mining, our largest division (accounting for 75.7% and 70.7% of consolidated revenues and segment profits, respectively, for the three months ended June 30, 2007), has benefited greatly from oil sands development. This segment has enjoyed significant growth in revenue and gross profit since 2005 as a result of our expanding relationships with oil sands companies. In addition, we have a significant contract with De Beers Canada at their Victor Diamond Mine in northern Ontario, where we are providing winter road construction and maintenance and overburden removal services. All of the growth in this segment has been achieved organically.

Growth in our Piling division (accounting for 21.2% and 33.6% of consolidated revenues and segment profits, respectively, for the three months ended June 30, 2007) has been driven both by oil sands development and by western Canada’s strong economy, which has supported a high level of commercial and industrial construction activity. In addition, the Piling business has realized benefits from the introduction of Continuous Flight Auger (“CFA”) technology into Canada, the acquisition of Midwest Foundation Technologies Inc. (“Midwest Micropile”) in 2007 and the opening of a new branch office in Saskatoon in the first quarter of fiscal 2008.

Our Pipeline division (accounting for 3.1% and -4.3% of consolidated revenues and segment profits, respectively, for the three months ended June 30, 2007) has also achieved revenue growth. However, profitability in this segment has been negatively impacted in prior periods by cost overruns related to poor weather, challenging ground conditions and changing work scope. As a result of a customer changing the scope of work on a fixed price contract, we have incurred additional forecast losses in the current period. These forecast losses have come about as a result of the customer exercising a contractual right allowing the customer to require us to commence work prior to negotiating changes to contract pricing flowing from the scope change. The contract is near completion and we are working with our client, who has agreed in principle that a contract change is warranted, to resolve these and prior year impacts related to changed working conditions. To reduce the potential for similar financial impacts on future projects, we have changed our Pipeline contract strategy to move away from fixed price contracts. Going forward, our Pipeline segment will focus primarily on cost-reimbursable contracts and we will only undertake fixed-price contracts on rare occasions when we perceive the risk to be very low. The new $185 million contract for the construction of Kinder Morgan Canada Inc.’s (“Kinder Morgan”) TMX pipeline is not a fixed price contract.

Our outlook for the remainder of 2008 is positive. With world economic growth continuing to positively impact oil demand and price, we expect to experience increasing project activity in our core market, the Canadian oil sands. Activity in the Fort McMurray area remains very strong with a number of high-profile projects underway including Canadian Natural’s Horizon Mine, Albian’s Jackpine Mine and Suncor’s Voyageur project. In addition, there have been several new projects announced in the area, including Shell’s mining and related upgrader project, the planned Fort Hills project (a partnership between Petro-Canada Oil Sands Inc., UTS Energy Corp., Teck Cominco Ltd. and Fort Hills Energy Corp.) and Suncor’s plans to further expand its Voyageur mining operation. Our recent acquisitions of new equipment ideally suited to heavy earth moving in the oil sands area together with the addition of a significant number of new employees has strengthened our ability to bid competitively and profitably into this expanding market, and we have secured contract wins on many of these new projects.

In our Heavy Construction and Mining operating segment, we are actively pursuing a strategy of retaining our leading position as a provider of mining and construction services in the Canadian oil sands area, while concurrently expanding our presence outside of the oil sands by bidding on other Canadian resource opportunities. Our significant involvement with De Beers Canada at its Victor Diamond Mine project in northern Ontario is the first of such projects for us. We anticipate that our Piling business will continue to enjoy strong demand in fiscal 2008 as a result of the oil sands development and continued strong construction activity in western Canada. Our outlook for our Pipeline segment is also very positive with mobilization of people and equipment for the $185 million Kinder Morgan TMX project now underway.

Overall, we expect our operating performance will improve over the balance of 2008 as a result of the strong market demand for our services and a number of internal initiatives undertaken and/or completed in 2007. These initiatives include the restructuring of our management team, the strengthening of our financial and operating controls, the implementation of a major business improvement project aimed at increasing productivity and equipment utilization and the change in contract strategy for our Pipeline segment.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2007

For the Three Months Ended June 30, 2007 Compared to the Three Months Ended June 30, 2006

For the three months ended June 30, 2007, our consolidated revenue increased to $167.6 million, from $138.1 million in the same period in 2006. While gains were achieved in all operating segments, the $29.5 million, or 21.4%, improvement was primarily due to increased project work in the Heavy Construction and Mining and Piling segments driven by increased activity levels in the oil sands and strong commercial and industrial activity in western Canada.

Gross profit decreased by 54.3% to $14.9 million in 2007, from $32.6 million over the same period in 2006. As a percentage of revenue, gross profit declined to 8.9% in the current quarter from 23.6% over the same period in 2006. The primary reasons for the gross profit decline were higher equipment costs of $21.2 million, performance of some lower margin work, a loss on disposal of surplus equipment recorded as depreciation and a loss on a pipeline project. Last year’s margins were positively impacted by the settlement of a claim of $6.1 million relating to fiscal 2005 work.

Equipment costs significantly increased as a result of our fleet expansion, increased activity and higher parts costs (primarily for tires). The world wide imbalance in supply and demand for large truck tires continues to have a significant impact on our costs, a situation that we believe will continue through calendar 2008. Equipment shop labour and overhead costs also increased due to higher activity levels and increased wage rates resulting from recent settlements with unions. Increased equipment costs were partially offset by a reduction in operating lease expenses resulting from the buy-out of certain equipment leases with proceeds from our IPO in fiscal 2007.

Consolidated gross profit in the quarter ended June 30, 2006 included the recognition of $6.1 million of claims as a result of a settlement from a site preparation project completed during fiscal 2005. Gross profit in the current quarter was impacted by the execution of a mix of lower margin work compared to last year. Projects executed in the Heavy Construction and Mining segment included a higher percentage of lower margin material and subcontractor component work. The Piling segment executed a higher percentage of lower margin driven piling projects compared to the prior year. Pipeline experienced a $1.2 million loss resulting from a change in scope on the second and final phase of a fixed-price pipeline contract that started in fiscal 2007. This contract was approximately 70% complete as at June 30^th and is expected to be completed in the second quarter of fiscal 2008.

Operating income for 2007 decreased to a loss of $0.4 million, from $23.1 million in 2006. This $23.5 million, or 101.6%, decrease was primarily due to the $17.7 million decrease in gross profit discussed above, and a $5.4 million, or 58.4% increase in general and administrative costs. The increase in general and administrative costs reflects increased employee costs and compensation related to our growing employee base and for discretionary bonuses for past service.

For the three months ended June 30, 2007 net loss was $10.3 million compared to net income of $17.9 million from the prior year. The change is a result of the impacts to operating income discussed above and the impacts of the new Canadian accounting standards that require us to account for changes in the fair value of embedded derivative financial instruments in various contracts and to modify the method of amortizing deferred financing costs. These changes resulted in a charge to income of approximately $10 million.

Segment Operations

Segmented profit includes revenue earned from the performance of our projects, including amounts arising from approved change orders and claims that have been resolved, less all direct projects expenses, including direct labour, short-term equipment rentals, materials, payments to subcontractors, indirect job costs and internal charges for use of capital equipment.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2007

(in thousands)	Three months ended June 30,
	2007					2006
Revenue by operating segment:
Heavy Construction & Mining	$	126,914		75.7	%	$	111,387	80.7	%
Piling		35,522		21.2	%		23,276	16.9	%
Pipeline		5,191		3.1	%		3,437	2.5	%
Total	$	167,627		100.0	%	$	138,100	100.0	%
Profit (loss) by operating segment
Heavy Construction & Mining	$	19,489		70.7	%	$	24,127	73.6	%
Piling		9,247		33.6	%		7,976	24.3	%
Pipeline		(1,189	)	-4.3	%		659	2.0	%
Total	$	27,547		100.0	%	$	32,762	100.0	%
Equipment hours by operating segment
Heavy Construction & Mining		249,426					236,098
Piling		19,694					11,097
Pipeline		9,119					1,102
Total		278,239					248,297

Heavy Construction and Mining

For the Three Months Ended June 30, 2007 Compared to the Three Months Ended June 30, 2006

Heavy Construction and Mining revenue increased 13.9% to $126.9 million in 2007, from $111.4 million in the same period in 2006. The growth in revenue was primarily due to work on the Suncor Millennium expansion and continued ramp up on the Canadian Natural overburden removal project.

Segment profit from our Heavy Construction and Mining activities decreased 19.2%, to $19.5 million, from $24.1 million in the same period in 2006. The prior year results were positively impacted by a claim settlement for $6.1 million and in the current year period we undertook an increased percentage of lower margin work compared to the prior year period. In order to both respond to our customers needs and to broaden our overall service offering, we have recently entered into a number of contracts where, in addition to our own work, we will also act as the general contractor. In this expanded role we will supervise a variety of subcontractors, procure supplies and materials for projects, and coordinate with other contractors. These services, although additive to revenues and earnings, are performed at lower margins than heavy equipment work but with very little capital employed.

Piling

For the Three Months Ended June 30, 2007 Compared to the Three Months Ended June 30, 2006

Piling revenue increased 52.6% to $35.5 million from $23.3 million in the same period in 2006. This increase was primarily due to strong business activity in all regions, particularly in Fort McMurray and Calgary, and to a single large project in the Edmonton region.

Piling segment profit increased 15.9% to $9.2 million up from $8.0 million in the same period in 2006. This resulted from increased business volume offset by a higher percentage of lower margin driven pile work undertaken compared to the prior year period and from a change in contracting strategy by some of our customers to move away from higher margin fixed price contracts.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2007

Pipeline

For the Three Months Ended June 30, 2007 Compared to the Three Months Ended June 30, 2006

Pipeline revenue for 2007 increased 51.0% to $5.2 million, from $3.4 million over the same period in 2006 as a result of our involvement in two large pipeline projects. The increase in 2007 revenue was partially offset by reduced work from Encana.

Our Pipeline segment recorded a loss of $1.2 million in 2007, compared to a profit of $0.7 million in the same period in 2006. As a result of a customer changing the scope of work on a fixed price contract, we have incurred additional forecast losses in the current period. These forecast losses have come about as a result of the customer enforcing a contractual right for us to commence work prior to renegotiating changes to contract pricing flowing from the scope change. The contract is near completion and we are working with our client to resolve these and prior year impacts related to changed scope and working conditions.

Non-operating expenses (income)

(in thousands)	Three Months ended June 30,
	2007			2006
Interest expense
Interest on senior debt	$	5,834		$	7,346
Accretion of mandatorily redeemable		—			1,645
Interest on capital lease obligations		181			154
Amortization of deferred financing costs		468			887
Interest on revolving credit facility and other interest		326			136
Total interest expense	$	6,809		$	10,168
Foreign exchange gain	$	(17,100	)	$	(13,466	)
Realized and unrealized loss on derivative financial instruments		23,949			7,996
Other income		(108	)		(583	)
Income tax (recovery) expense		(3,605	)		1,104

Non-Operating expenses (income): For the three months ended June 30, 2007 Compared to June 30, 2006

Total interest expense decreased by $3.4 million in 2007 compared to the same period in 2006, primarily due to the retirement of the senior secured 9% notes with proceeds from our IPO in fiscal 2007 and the exchange of the Series B preferred shares for common shares as part of the re-organization that occurred prior to the IPO.

Substantially all of the $17.1 million foreign exchange gain recognized in the three months ended June 30, 2007 relates to the change in exchange rates between the Canadian and U.S. dollar on conversion of the US$200.0 million of 8 ³/4 % senior notes.

We recorded a $23.9 million realized and unrealized loss on derivative financial instruments in 2007, compared to an $8.0 million loss in the same period in 2006. We employ derivative financial instruments to provide an economic hedge for our 8 ³/4 % senior notes. The subsequent gain or loss reflects changes in the fair value of these derivatives. See “Liquidity and Capital Resources – Liquidity Requirements” for further information regarding these derivative financial instruments. The change in the fair value of the derivative instrument associated with the economic hedge resulted in a $13.7 million loss during the quarter, with the balance resulting from the adoption of a new Canadian accounting standard regarding financial instruments, as discussed below.

Effective April 1, 2007, we adopted the new Canadian CICA Handbook Section 3855 “Financial Instruments – Recognition and Measurements” which resulted in the recognition of derivatives embedded in the senior 8 ³/4 % notes and a long term construction contract as follows:

• The 8 ³/4 % notes include certain embedded derivatives, notably optional redemption and change of control redemption rights. These embedded derivatives met the criteria for separation from the debt contract and separate measurement at fair value. Upon adoption of Section 3855, we recorded a reduction in the carrying amount of our 8 ³/4 % notes of $8.5 million together with related impacts on retained earnings and future income taxes on April 1, 2007. The change in the fair value of these embedded derivatives from that date until June 30, 2007 resulted in a charge to earnings of $3.6 million for the three months ended June 30, 2007.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2007

• A long term construction contract contains a price excalation feature that represent an embedded foreign currency and price index derivative that meets the criteria for separation from the host contract and separate measurement at fair value. Upon adoption of Section 3855, we recorded a liability of $7.2 million together with related impacts on retained earnings and future income taxes on April 1, 2007. The change in the fair value of the liability resulted in a charge to earnings of $6.0 million for the three months ended June 30, 2007.

With respect to the early redemption provision in the senior notes, the process to determine the fair value of the implied derivative was to compare the rate on the notes to the best financial alternative. This resulted in a positive adjustment to opening retained earnings (the value at April 1, 2007), and a charge to first quarter earnings to reflect the change in the fair value over the three month period that resulted from increasing long term bond interest rates during that period. The valuation process presumes a 100% probability of the Company implementing the inferred transaction, and does not permit a reduction in the probability if there are other factors that would impact on the decision.

With respect to the customer contract, there is a provision that requires an adjustment to billings to our customer to reflect actual exchange rate and index changes versus the contract amount. The implied derivative itself is a one-sided calculation that takes into account the impact on revenues but does not consider the other contract offsets that are aimed at ensuring that neither party is advantaged nor disadvantaged as a result of fluctuations in these measures. The economics of the contract are not impacted by this accounting change.

The new accounting guidelines for embedded derivatives will cause our reported earnings to fluctuate as currency exchange and interest rates change. The accounting for these derivatives will have no impact on operations, Consolidated EBITDA or how we will evaluate performance.

We recorded an income tax recovery of $3.6 million for the three months ended June 30, 2007, as compared to an income tax expense of $1.1 million for the three months ended June 30, 2006. Income tax expense as a percentage of income before tax for the three months ended June 30, 2007 differs from the statutory rate of 31.72% primarily due to the impact of the enacted rate changes during the period, and the impact of new accounting standards for the recognition and measurement of financial instruments as certain embedded derivatives are considered capital in nature for income tax purposes. Income tax as a percentage of income before tax for the three months ended June 30, 2006 differed from the statutory rate of 31.72% primarily due to the elimination of the valuation allowance of $5.9 million that was recorded during that period.

Comparative Quarterly Results

A number of factors contribute to variations in our quarterly results between periods, including weather, capital spending by our customers on large oil sands 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.

We generally experience a decline in revenues during the first quarter of each fiscal year due to seasonality, as weather conditions make operating during this period difficult. The level of activity in the Heavy Construction and Mining and Pipeline segments generally declines when frost leaves the ground and many secondary roads are temporarily rendered incapable of supporting the weight of heavy equipment. The duration of this period is referred to as “spring breakup” and it has a direct impact on our activity levels. Revenues during the fourth quarter of each fiscal year are typically highest as ground conditions are most favourable in our operating regions. As a result, full-year results are not likely to be a direct multiple of any particular quarter or combination of quarters.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2007

(dollars in millions, except per share amounts)	Fiscal Year 2008			Fiscal Year 2007									Fiscal Year 2006
	Q1			Q4		Q3		Q2			Q1		Q4		Q3		Q2
Revenue	$	167.6		$	205.3	$	155.9	$	130.1		$	138.1	$	142.3	$	121.5	$	124.0
Gross profit		14.9			13.6		26.0		20.2			32.6		31.7		13.8		21.9
Operating income		(0.4	)		4.5		13.8		9.7			23.1		22.4		5.9		15.9
Net income (loss)		(10.3	)		1.4		6.6		(4.8	)		17.9		13.7		2.1		11.5
EPS–basic(1)		(0.29	)		0.04		0.27		(0.26	)		0.96		0.73		0.11		0.62
EPS–diluted(1)		(0.29	)		0.04		0.26		(0.26	)		0.71		0.73		0.11		0.47
Equipment hours		278,239			268,565		239,341		236,711			248,297		231,633		221,355		234,649

(1) Net income (loss) per share for each quarter has been computed based on the weighted average number of shares issued and outstanding during the respective quarter; therefore, quarterly amounts may not add to the annual total. Per share calculations are based on full dollar and share amounts.

Consolidated Financial Position

(in thousands)	June 30,2007			March 31, 2007			% Change
Current assets	$	207,872		$	229,061		-9.3	%
Current liabilities		(139,748	)		(151,458	)	-7.7	%
Net working capital		68,124			77,603		-12.2	%
Plant and equipment		255,434			255,963		-0.2	%
Total assets		689,417			710,736		-3.2	%
Capital Lease obligations (including current portion)		(8,920	)		(9,709	)	-8.1	%
Total long-term financial liabilities		(295,470	)		(297,957	)	-0.8	%

At June 30, 2007, we had net working capital (current assets less current liabilities) of $68.1 million, compared to $77.6 million at March 31, 2007. The decrease in working capital resulted from a decrease in unbilled revenues and assets held for sale offset by an increase in accounts receivable and decreases in accounts payable and accrued liabilities.

Plant and equipment, net of depreciation, decreased by $0.5 million from March 31, 2007 to June 30, 2007 primarily as a result of depreciation and equipment disposals partially offset by additions to plant and equipment.

Capital lease obligations, including the current portion, decreased by $0.8 million from March 31, 2007 to June 30, 2007 due to required payments.

Total long-term financial liabilities are non-current liabilities excluding the current portion of capital lease obligations, derivative financial instruments and all future income taxes balances. The decrease in the first quarter is primarily as a result of the decrease in the value of the 8 ³/4% senior notes by $25.8 million offset by the increase in fair value of the derivative financial instruments of $25.6 million.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2007

Liquidity and Capital Resources

(in thousands)	Three months ended June 30,
	2007			2006
Cash provided by operating activities	$	3,046		$	15,050
Cash used in investing activities		(132	)		(11,370	)
Cash used in financing activities		(1,329	)		(1,391	)
Net increase in cash and cash equivalents	$	1,585		$	2,289

Operating activities

Operating activities in the three months ended June 30, 2007 resulted in a net increase in cash of $3.0 million, compared to an increase of $15.1 million in the three months ended June 30, 2006. The lower cash generated in the current period compared to the prior year period is the result of lower earnings offset by net changes in non-cash working capital.

Investing activities

Sustaining capital expenditures are those that are required to keep our existing fleet of equipment at its optimal useful life through capital maintenance or replacement. Growth capital expenditures relate to incremental additions to our fleet of equipment.

During the three months ended June 30, 2007, we invested $5.7 million in sustaining capital expenditures (in the same period in 2006, this figure was $4.7 million) and invested $4.5 million in growth capital expenditures (in the same period in 2006, this figure was $7.1 million), for total capital expenditures of $10.2 million (in the same period in 2006, this figure was $11.8 million).

Financing activities

Financing activities in the three months ended June 30, 2007 resulted in a cash outflow of $1.3 million primarily from financing costs and payments for capital lease obligations and repayments on the revolving credit facility. Financing activities during the three months ended June 30, 2006 resulted in net cash outflow of $1.4 million. This outflow reflects payments of capital lease obligations and financing costs.

Liquidity Requirements

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

Our long-term debt includes US$200 million of 8 ³/4% senior notes due in 2011. The foreign currency risk relating to both the principal and interest portions of these senior notes has been managed with a cross-currency swap and interest rate swaps, which went into effect concurrent with the issuance of the notes on November 26, 2003. Interest totaling $13.0 million on the 8 ³ /4% senior notes and the swap is payable semi-annually in June and December of each year until the notes mature on December 1, 2011. The swap agreement is an economic hedge, but has not been designated as a hedge for accounting purposes. There are no principal repayments required on the 8 ³/4% senior notes until maturity.

One of our major customer contracts allows the customer to require that we provide up to $50 million in letters of credit. As at June 30, 2007, we have provided $25 million in letters of credit in connection with this contract. Any increase in the amount of the letters of credit required by this customer must be requested by November 1, 2007 for an issue date of January 1, 2008.

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, they are replaced as it becomes cost prohibitive to continue to maintain them. As a result, we are continually acquiring new equipment to replace retired units and to support growth as new projects are awarded to us. It is important to adequately maintain a large revenue-producing fleet in order to avoid equipment downtime which can impact our revenue stream and inhibit our ability to satisfactorily perform on our projects. In order to maintain a balance of owned and leased equipment, we have financed a portion of our heavy construction fleet through operating leases. In addition, we continue to lease our motor vehicle fleet.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2007

Our cash requirements during the three months ended June 30, 2007 increased due to continued growth and additional operating and capital expenditures associated with new projects. Our cash requirements for fiscal 2008 include funding operating lease obligations, debt and interest repayment obligations and working capital.

We expect our sustaining capital expenditures to range from $35.0 million to $45.0 million per year over the next two years. We expect our total capital expenditures in fiscal 2008 to range from $75.0 million to $85.0 million. It is our belief that working capital will be sufficient to meet these requirements.

Sources of Liquidity

Our principal sources of cash are funds from operations and borrowings under our revolving credit facility. On June 7, 2007, we amended and restated our revolving credit facility to provide for borrowings of up to $125.0 million under which revolving loans and letters of credit may be issued. Our previous revolving credit facility was subject to borrowing base limitations, under which revolving loans and letters of credit up to a limit of $55.0 million could have been issued. As of June 30, 2007, we had approximately $80.0 million of available borrowings under the revolving credit facility after taking into account $20.0 million of borrowings and $25.0 million of outstanding and undrawn letters of credit to support performance guarantees associated with a single customer contract. The indebtedness under the revolving credit facility is secured by a first priority lien on substantially all of our existing and after-acquired property.

Our revolving credit facility contains covenants that restrict our activities, including, but not limited to, incurring additional debt, transferring or selling assets and making investments including acquisitions. Under the revolving credit facility Consolidated Capital Expenditures during any applicable period cannot exceed 120% of the amount in the capital expenditure plan. In addition, we are required to satisfy certain financial covenants, including a minimum interest coverage ratio and a maximum senior leverage ratio, both of which are calculated using Consolidated EBITDA, as well as a minimum current ratio.

Consolidated EBITDA is defined in the credit facility as the sum, without duplication, of (1) consolidated net income, (2) consolidated interest expense, (3) provision for taxes based on income, (4) total depreciation expense, (5) total amortization expense, (6) costs and expenses incurred by us in entering into the credit facility, (7) accrual of stock-based compensation expense to the extent not paid in cash or if satisfied by the issue of new equity, and (8) other non-cash items (other than any such non-cash item to the extent it represents an accrual of or reserve for cash expenditure in any future period), but only, in the case of clauses (2)-(8), to the extent deducted in the calculation of consolidated net income, less other non-cash items added in the calculation of consolidated net income (other than any such non-cash item to the extent it will result in the receipt of cash payments in any future period), all of the foregoing as determined on a consolidated basis for us in conformity with Canadian GAAP.

Interest coverage is determined based on a ratio of Consolidated EBITDA to consolidated interest expense on debt, and the senior leverage is determined as a ratio of senior debt to Consolidated EBITDA. Measured as of the last day of each fiscal quarter on a trailing four-quarter basis, Consolidated EBITDA shall not be less than 2.5 times consolidated cash interest expense (2.35 times at June 30, 2007). Also, measured as of the last day of each fiscal quarter on a trailing four-quarter basis, senior leverage shall not exceed two times Consolidated EBITDA. These permitted ratios change over time during the term of the revolving credit facility. We believe Consolidated EBITDA as defined in the credit facility is an important measure of our liquidity.

Backlog

Backlog is a measure of the amount of secured work we have outstanding and as such is an indicator of future revenue potential. Backlog is not a GAAP measure and as a result, the definition and determination will vary among different organizations ascribing a value to backlog. Although backlog reflects business that we consider to be firm, cancellations or reductions may occur and may reduce backlog and future income.

We define backlog as that work that has a high certainty of being performed as evidenced by the existence of a signed contract or work order specifying job scope, value and timing. We have also set a policy that our definition of backlog will be limited to contracts or work orders with values exceeding $500,000 and work that will be performed in the next five years, even if the related contracts extend beyond five years.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2007

We work with our customers using cost-plus, time-and-materials, unit-price and lump-sum contracts, and the mix of contract types varies year-by-year. For the three months ended June 30, 2007, our contract revenue consisted of 37.7% time-and-materials, 52.5% unit-price and 9.8% lump-sum. Our definition of backlog results in the exclusion of cost-plus and time-and-material contracts performed under master service agreements where scope is not clearly defined. While contracts exist for a range of services to be provided, the work scope and value are not clearly defined under those contracts. For the three months ended June 30, 2007, the total amount of all cost-plus and time-and-material based revenue was $63.2 million.

Our estimated backlog as at June 30, 2007 and 2006 was (in millions):

By Segment	As At June 30,				By Contract Type	As At June 30,
	2007		2006			2007		2006
Heavy Construction & Mining	$	711.0	$	735.0	Unit-Price	$	739.0	$	746.0
Piling		26.0		16.0	Lump-Sum		6.0		5.0
Pipeline		192.0		—	Time & Material, Cost-Plus		184.0		—
Total	$	929.0	$	751.0	Total	$	929.0	$	751.0

A contract with a single customer represented approximately $651 million of the June 30, 2007 backlog. It is expected that approximately $229 million of the backlog will be performed and realized in the 12 months ending June 30, 2008.

Claims and Unapproved Change Orders

Due to the complexity of the projects we undertake, changes often occur after work has commenced. These changes include, but are not limited to:

• Client requirements, specifications and design

• Materials and work schedules

• Changes in ground and weather conditions

Contract change management processes require that we prepare and submit change orders to the client requesting approval of scope and/or price adjustments to the contract. Accounting guidelines require that management consider changes in cost estimates that have occurred up to the release of the financial statements and reflect the impact of these changes in the financial statements. Conversely, potential revenue associated with increases in cost estimates is not included in financial statements until an agreement is reached with the client or specific criteria for the recognition of revenue from unapproved change orders and claims are met. This can, and often does, lead to costs being recognized in one period and revenue being recognized in subsequent periods.

Occasionally, disagreements arise regarding changes, their nature, measurement, timing, and other characteristics that impact costs and revenue under the contract. If a change becomes a point of dispute between our customer and us, we then consider it as a claim. Historical claim recoveries should not be considered indicative of future claim recoveries.

As a result of the changed conditions discussed above, at June 30, 2007 we had recognized approximately $16.0 million in additional contract costs from a number of projects inception to date, with no associated increase in contract value. We are working with our customers to come to resolution on the further amounts, if any, to be paid to us in respect to these additional costs.

Contractual Obligations and Other Commitments

Our principal contractual obligations relate to our long-term debt and capital and operating leases. The following table summarizes our future contractual obligations, excluding interest payments unless otherwise noted, as of June 30, 2007.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2007

	Payments Due by Fiscal Year
	Total		2008		2009		2010		2011		2012 and After
	(In millions)
Senior notes (a)	$	212.7	$	—	$	—	$	—	$	212.7	$	—
Capital leases (including interest)		9.8		3.6		2.9		2.0		1.0		0.2
Operating leases		27.9		16.4		9.1		2.3		0.1		—
Total contractual obligations	$	250.4	$	20.0	$	12.0	$	4.3	$	213.8	$	0.2

(a) We have entered into cross-currency and interest rate swaps, which represent an economic hedge of the 8 ³/4% senior notes. At maturity, we will be required to pay $263.0 million in order to retire these senior notes and the swaps. This amount reflects the fixed exchange rate of C$1.315=US$1.00 established as of November 26, 2003, the inception of the swap contracts. At June 30, 2007 the carrying value of the derivative financial instruments was $74.5 million, inclusive of the interest components.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements in place at this time.

Outstanding Share Data

We are authorized to issue an unlimited number of voting common shares and an unlimited number of non-voting common shares. As at August 13, 2007, 35,752,060 voting common shares were outstanding compared to 35,192,260 voting common shares and 412,400 non-voting common shares as at March 31, 2007.

Stock-Based Compensation

Some of our directors, officers, employees and service providers have been granted options to purchase common shares under the Amended and Restated 2004 Share Option Plan. There have been no options issued in the three month period ending June 30, 2007.

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 Step 1 of this test during the quarter ended December 31, 2006 and were not required to record an impairment loss on goodwill. We conduct our annual assessment of goodwill in December of each year.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2007

Critical Accounting 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. Therefore, the determination of estimates requires the exercise of management’s judgment. Actual results could differ from those estimates, and any differences may be material to our financial statements.

Revenue recognition

Our contracts with customers fall under the following contract types: cost-plus, time-and-materials, unit-price and lump-sum. While contracts are generally less than one year in duration, we do have several long-term contracts. The mix of contract types varies year-by-year. For the three months ended June 30, 2007, our contracts consisted of 37.7% time-and-materials, 52.5% unit-price and 9.8% lump-sum.

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. Claims and unapproved change orders are included in total estimated contract revenue only to the extent that contract costs related to the claim or unapproved change order have been incurred, when it is probable that the claim or unapproved change order will result in a bona fide addition to contract value and the amount of revenue can be reliably estimated.

The accuracy of our revenue and profit recognition in a given period is dependent, in part, on the accuracy of our estimates of the cost to complete each unit-price and lump-sum 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 the related 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, sizable changes in cost estimates, particularly in larger, 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;

• identification and evaluation of scope modifications during the execution of the project;

• the availability and cost of skilled workers in the geographic location of the project;

• the availability and proximity of materials;

• unfavorable weather conditions hindering productivity;

• equipment productivity and timing differences resulting from project construction not starting on time; and

• general coordination of work inherent in all large projects we undertake.

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.

Plant and equipment

The most significant estimate in accounting for plant and equipment is the expected useful life of the asset and the expected residual value. Most of our property, plant and equipment have long lives 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 monthly based on daily actual operating 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 of Long-Lived Assets” and Section 3475 “Disposal of Long-Lived Assets and Discontinued Operations.” These standards require the recognition of an impairment loss for a long-lived asset 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.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2007

Goodwill

Impairment is tested at the reporting unit level by comparing the reporting unit’s carrying amount to its fair value. The process of determining fair values is subjective and requires us to exercise judgment in making assumptions about future results, including revenue and cash flow projections at the reporting unit level, and discount rates.

Financial instruments

Our derivative financial instruments are not designated as hedges for accounting purposes and are recorded on the balance sheet at fair value, which is determined based on values quoted by the counterparties to the agreements. The primary factors affecting fair value are the changes in the interest rate term structures in the US and Canada, the life of the swap and the CAD/USD foreign exchange spot rate.

Effective April 1, 2007, we adopted the new standards issued by the CICA on financial instruments, hedges and comprehensive income. Section 1530, “Comprehensive income”, Section 3855, “Financial instruments-recognition and measurement”, Section 3861, “Financial instruments- disclosure and presentation”, and Section 3865, “Hedges”, were effective for our first quarter of 2007. We were not required to restate prior results.

On April 1, 2007, we made the following transitional adjustments to our consolidated balance sheet to adopt the new standards (in thousands of dollars):

	Increase (decrease)
Deferred financing costs	$	(9,734	)
Long-term future income tax asset		2,588
Senior notes		(12,634	)
Derivative financial instruments		7,246
Long-term income tax liability		18
Opening deficit		1,776

The details of the transitional adjustments are noted below.

The impact of the new standards on our income (loss) before income taxes for the three months ended June 30, 2007 is as follows (in thousands of dollars):

	Three months ended June 30
Decrease in interest expense due to change in method of amortizing deferred financing costs and discounts (premiums), net	$	(124	)
Increase in unrealized foreign exchange loss on senior notes		750
Increase in unrealized loss on derivative financial instruments		9,628
	$	10,254

The new standards require all financial assets and liabilities to be carried at fair value in our consolidated balance sheet, except for loans and receivables, held-to-maturity investments and other financial liabilities, which are carried at their amortized cost. We do not currently have any financial assets designated as available-for-sale. On adoption of the standard, the Company has classified its cash and cash equivalents, certain accounts receivable and unbilled revenue as loans and receivables and revolving credit facility, accounts payable, certain accrued liabilities, capital lease obligations and senior notes as other financial liabilities.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2007

All derivatives, including embedded derivates that must be separately accounted for, are measured at fair value in our consolidated balance sheet. The types of hedging relationships that qualify for hedge accounting have not changed under the new standards. We currently do not designate any of these derivatives as hedging instruments for accounting purposes

Derivatives may be embedded in financial instruments (the “host instrument”). Under the new standards, embedded derivatives are treated as separate derivatives when their economic characteristics and risks are not closely related to those of the host instrument, the terms of the embedded derivative are similar to those of a stand-alone derivative, and the combined contract is not held for trading or designated at fair value. These embedded derivatives are measured at fair value with subsequent changes recognized in income. We have elected April 1, 2003 as our transition date for identifying contracts with embedded derivatives. Currently we have prepayments options that are embedded in our senior notes and foreign exchange rate and price index escalation/de-escalation clauses in a long-term construction contract which meet the criteria for bifurcation. The impact of the prepayment options and escalation/de-escalation clauses on our consolidated financial statements is described under the transitional adjustments below and in note 3.(a) in our interim consolidated financial statements for the three months ended June 30, 2007.

In determining the fair value of our financial instruments, we used a variety of valuation methods and assumptions that are based on market conditions and risks existing on each reporting date. Standard market conventions and techniques, such as discounted cash flow analysis and option pricing models, are used to determine the fair value of our financial instruments, including derivatives. All methods of fair value measurement result in a general approximation of value and such value may never actually be realized.

The transitional impact of adopting the new financial instruments standards as at April 1, 2007 on our consolidated financial statements is as follow:

• Embedded derivatives:

We determined that the issuer’s early prepayment option included in the senior notes should be bifurcated from the host contract, along with a contingent embedded derivative in the senior notes that provide for accelerated redemption by the holders in certain instances. These embedded derivatives were measured at fair value at the inception of the senior notes and the residual amount of the proceeds was allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of the senior notes is accreted to the par value over the term of the notes using the effective interest method and is recognized as interest expense. At transition on April 1, 2007, we recorded the fair value of $8.5 million related to these embedded derivatives and a corresponding decrease in opening deficit of $7.3 million, net of future income taxes of $1.2 million.

Also there is a foreign exchange rate and price index escalation/de-escalation clauses in a long-term construction contract that qualifies as an embedded derivative which must be separated for reporting in accordance with the new standards. As at April 1, 2007, we separated the fair value of the embedded derivative liability of $7.2 million from the long-term construction contract.

• Effective interest method:

We incurred underwriting commissions and expenses relating to our senior notes offering. Previously, these costs were classified as deferred assets under deferred financing costs and amortized on a straight-line basis over the term of the debt. The new standard requires us to reclassify the costs as a reduction in the cost of debt and to use the effective interest rate method to amortize the deferred amounts to interest expense. As at April 1, 2007, we reclassified $9.7 million of unamortized costs from deferred financing costs to long-term debt and recorded an adjustment in unamortized cost balance to the amount as if the effective interest rate method had been used since inception.

Revised CICA Handbook Section 3861, “Financial Instruments—Disclosure and Presentation” replaces CICA Handbook Section 3860, “Financial Instruments—Disclosure and Presentation”, and establishes standards for presentation of financial instruments and non-financial derivatives, and identifies information that should be disclosed. There was no material effect on our financial statements upon adoption of CICA Handbook Section 3861 effective April 1, 2007.

CICA Handbook Section 1530, “Comprehensive Income” establishes standards for the reporting and display of comprehensive income. The new section defines other comprehensive income to include revenues, expenses, and gains and losses that, in accordance with primary sources of GAAP, are recognized in comprehensive income but excluded from net income. The standard does not address issues of recognition or measurement for comprehensive income and its components. The adoption of CICA Handbook Section 1530 effective April 1, 2007 did not have a material impact on our financial statement presentation in the current period.

Risk Factors

For the three month period ended June 30, 2007 other than noted below, there has been no significant change in our risk factors from those described in our Prospectus dated July 31, 2007 and Management’s Discussion and Analysis for the twelve months ended March 31, 2007 and there are no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to affect, its internal control over financial reporting. As discussed in the Prospectus dated July 31, 2007 and our Annual Management Discussion and Analysis we have identified a number of significant weaknesses (as defined under Canadian auditing standards) in our financial reporting process and internal controls. In addition, during the quarter ended June 30, 2007, we were required to implement new Canadian accounting standards regarding financial instruments. In order to record the related transactions, very complex and non-routine accounting and valuation procedures were undertaken. On review, we determined that we did not apply certain of these procedures correctly. This, therefore, represents a weakness in internal control as it had the potential to result in a material misstatement of the financial statements. This weakness will be addressed in the future by engaging third party experts. As a result, there can be no assurance that we will be able to generate accurate financial reports in a timely manner. Failure to do so would cause us to breach the reporting requirements of Canadian and U.S. securities regulations in the future as well as the covenants applicable to our indebtedness. This could, in turn, have a material adverse effect on our business and financial condition. Until we establish and maintain effective internal controls and procedures for financial reporting, we may not have appropriate measures in place to eliminate financial statement inaccuracies and avoid delays in financial reporting.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2007

There is a possibility of a labour disruption commencing on or about August 23, 2007 involving Alberta Construction Contractors and 10 Building trades unions who have chosen, so far, to reject offers from the Contractors Association Bargaining Agent. Representatives of the Contractors and the involved unions continue to bargain in an attempt to reach agreement; however, the possibility does exist for a labour disruption. Although we are not directly involved, this disruption would have the potential to affect our construction operations in the oil sands and commercial construction projects in Alberta. The Company is currently assessing the potential impact on operations and working with our clients to prepare contingency plans in the event that a labour disruption materializes.

Recently Adopted Canadian Accounting Pronouncements

Financial instruments

In January 2005, the CICA issued Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, Handbook Section 3861, “Financial Instruments – Disclosure and Presentation” (“CICA 3861”), Handbook Section 1530, “Comprehensive Income”, and Handbook Section 3865, “Hedges”. The new standards are effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2006, specifically April 1, 2007 for the Company. The impact of the adoption of the new standards for the Company is discussed above under the heading “Financial Instruments.”

Equity

On April 1, 2007, we adopted CICA Handbook Section 3251, “Equity”, which establishes standards for the presentation of equity and changes in equity during the reporting period. The requirements in this section are in addition to those of CICA Handbook Section 1530 and recommend that an enterprise should present separately the following components of equity: retained earnings, accumulated other comprehensive income and the total for retained earnings and accumulated other comprehensive income, contributed surplus, share capital and reserves. The standard did not have a material impact of our consolidated financial statements in the current period.

Accounting changes

In July 2006, the CICA revised Handbook Section 1506, “Accounting Changes”, which requires that: (1) voluntary changes in accounting policy are made only if they result in the financial statements providing reliable and more relevant information; (2) changes in accounting policy are generally applied retrospectively; and (3) prior period errors are corrected retrospectively. This revised standard is effective for fiscal years beginning on or after January 1, 2007, specifically April 1, 2007 for us, and did not have a material impact on our consolidated financial statements.

Recent Canadian accounting pronouncements not yet adopted

Financial Instruments

In March 2007, the CICA issued Handbook Section 3862, “Financial Instruments – Disclosures”, which replaces CICA 3861 and provides expanded disclosure requirements that provide additional detail by financial assets and liability categories. This standard harmonizes disclosures with International Financial Reporting Standards. The standard applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for us. We are currently evaluating the impact of this standard.

In March 2007, the CICA issued Handbook Section 3863, “Financial Instruments – Presentation” to enhance financial statement users’ understanding of the significance of financial instruments to an entity’s financial position, performance and cash flows. This Section establishes standards for presentation of financial instruments and non-financial derivatives. It deals with the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, gains and losses, and the circumstances in which financial assets and financial liabilities are offset. This standard harmonizes disclosures with International Financial Reporting Standards and applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for us. We are currently evaluating the impact of this standard.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2007

Capital disclosures

In December 2006, the CICA issued Handbook Section 1535, “Capital Disclosures”. This standard requires that an entity disclose information that enables users of its financial statements to evaluate an entity’s objectives, policies and processes for managing capital, including disclosures of any externally imposed capital requirements and the consequences of non-compliance. The new standard applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007, specifically April 1, 2008 for us. We are currently evaluating the impact of this standard.

Inventories

In June 2007, the CICA issued Handbook Section 3031, “Inventories” to harmonize accounting for inventories under Canadian GAAP with International Financial Reporting Standards. This standard requires the measurement of inventories at the lower of cost and net realizable value and includes guidance on the determination of cost, including allocation of overheads and other costs to inventory. The standard also requires the consistent use of either first-in, first out (FIFO) or weighted average cost formula to measure the cost of other inventories and requires the reversal of previous write-downs to net realizable value when there is a subsequent increase in the value of inventories. The new standard applies to interim and annual financial statements relating to fiscal years beginning on or after January 1, 2008, specifically April 1, 2008 for us. We are currently evaluating the impact of this standard.

U.S. Generally Accepted Accounting Principles

Our 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 27 to our annual consolidated financial statements.

Quantitative and Qualitative Disclosures Regarding Market Risk

Foreign currency risk

We are subject to currency exchange risk as our 8 ³/4% senior notes are denominated in U.S. dollars and all of our revenues and most of our expenses are denominated in Canadian dollars. To manage the foreign currency risk and potential cash flow impact on our $200 million in U.S. dollar-denominated notes, we have entered into currency swap and interest rate swap agreements. These financial instruments consist of three components: a U.S. dollar interest rate swap; a U.S. dollar-Canadian dollar cross-currency basis swap; and a Canadian dollar interest rate swap. The cross currency and interest rate swap agreements 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% of the US$200 million if exercised between December 1, 2007 and December 1, 2008; 2.1875% if exercised between December 1, 2008 and December 1, 2009; and repurchased at par if cancelled after December 1, 2009.

Interest rate risk

We are exposed to interest rate risk on the revolving credit facility, capital lease obligations and certain operating leases with a variable payment that is tied to prime rates. We do not use derivative financial instruments to reduce our exposure to these risks. The estimated financial impact as a result of fluctuations in interest rates is not significant.

Inflation

Inflation can have a material impact on our operations due to increasing parts, equipment replacement and labour costs, however, many of our contracts contain provisions for annual price increases. Inflation can have a material impact on our operations provided the rate of inflation and cost increases remains above levels that we are able to pass to our customers.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2007

Additional Information

Additional information relating to us, including our 2007 Annual Information Form, as amended, can be found on the Canadian Securities Administrators System for Electronic Document Analysis and Retrieval (SEDAR) database at www.sedar.com and the website of the Securities and Exchange Commission at www.sec.gov.