Edgar Filing: North American Energy Partners Inc.

Form 6-K

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 2009

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 of Form 20-F or Form 40-F.

Form 20-F Form 40-F X

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):

Documents Included as Part of this Report

1.	Interim consolidated financial statements of North American Energy Partners Inc. for the three months ended June 30, 2009.

2.	Management’s Discussion and Analysis for the three months ended June 30, 2009.

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/ David Blackley
Name: David Blackley Title: Chief Financial Officer

Date: August 4, 2009

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Financial Statements

For the three months ended June 30, 2009

(Expressed in thousands of Canadian Dollars)

(Unaudited)

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Interim Consolidated Balance Sheets

(In thousands of Canadian Dollars)


	June 30, 2009			March 31, 2009
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	80,273		$	98,880
Accounts receivable		70,247			78,323
Unbilled revenue		59,064			55,907
Inventories		7,717			11,814
Prepaid expenses and deposits		8,799			4,781
Future income taxes		7,865			7,033

		233,965			256,738
Future income taxes		9,628			12,432
Assets held for sale		2,117			2,760
Prepaid expenses and deposits		2,215			3,504
Plant and equipment (note 5)		340,513			329,705
Goodwill		23,872			23,872
Intangible assets		1,938			1,041

	$	614,248		$	630,052

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	50,375		$	56,204
Accrued liabilities		31,491			52,135
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		2,069			2,155
Current portion of capital lease obligations		5,395			5,409
Current portion of derivative financial instruments (note 9)		4,639			11,439
Current portion of long term debt (note 6(a))		2,065			—
Future income taxes		8,981			7,749

		105,015			135,091
Deferred lease inducements		810			836
Capital lease obligations		11,243			12,075
Long term debt (note 6(a))		9,735			—
Senior notes (note 6(b))		231,527			252,899
Director deferred stock unit liability (note 12(c))		1,220			546
Derivative financial instruments (note 9)		60,015			50,562
Asset retirement obligation		395			386
Future income taxes		31,012			30,220

		450,972			482,615
Shareholders’ equity:
Common shares (authorized — unlimited number of voting and non-voting common shares; issued and outstanding — June 30, 2009 — 36,038,476 voting common shares (March 31, 2009 — 36,038,476 voting common shares) (note 7(a))		299,973			299,973
Contributed surplus (note 7(b))		6,340			5,275
Deficit		(143,037	)		(157,811	)

		163,276			147,437

	$	614,248		$	630,052

Revolving credit facility (note 6(a))
Contingencies (note 13)
Subsequent event (note 17)

See accompanying notes to unaudited interim consolidated financial statements.

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

(Expressed in thousands of Canadian Dollars, except per share amounts)


	Three months ended June 30,
	2009			2008
	(Unaudited)
Revenue	$	147,103		$	258,987
Project Costs		54,553			148,631
Equipment costs		46,044			45,811
Equipment operating lease expense		12,349			8,798
Depreciation		9,347			8,158

Gross profit		24,810			47,589
General and administrative costs		15,066			19,215
Loss on disposal of plant and equipment		41			1,144
(Gain) loss on disposal of assets held for sale		(317	)		22
Amortization of intangible assets		248			278

Operating income before the undernoted		9,772			26,930
Interest expense, net (note 8)		8,637			6,449
Foreign exchange gain		(19,215	)		(1,641	)
Realized and unrealized loss (gain) on derivative financial instruments (note 9(a))		1,046			(2,265	)
Other expense (income)		533			(18	)

Income before income taxes		18,771			24,405
Income taxes (note 10(c)):
Current income taxes		—			—
Future income taxes		3,997			5,309

Net income and comprehensive income for the period		14,774			19,096
Deficit, beginning of period — as previously reported		(157,811	)		(19,287	)
Change in accounting policy related to inventories		—			991


(Deficit) retained earnings , end of period	$	(143,037	)	$	800


Net income per share — basic (note 7(c))	$	0.41		$	0.53


Net income per share — diluted (note 7(c))	$	0.40		$	0.52

See accompanying notes to unaudited interim consolidated financial statements.

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Interim Consolidated Statements of Cash Flows

(Expressed in thousands of Canadian Dollars)


	Three months ended June 30,
	2009			2008
	(Unaudited)
Cash provided by (used in):
Operating activities:
Net income for the period	$	14,774		$	19,096
Items not affecting cash:
Depreciation		9,347			8,158
Amortization of intangible assets		248			278
Amortization of deferred lease inducements		(26	)		(26	)
Amortization of bond issue costs, premiums and financing costs		221			174
Loss on disposal of plant and equipment		41			1,144
(Gain) loss on disposal of assets held for sale		(317	)		22
Unrealized foreign exchange gain on senior notes		(19,319	)		(1,831	)
Unrealized change in the fair value of derivative financial instruments		379			(2,933	)
Stock-based compensation expense (note 12)		1,805			636
Accretion of asset retirement obligation		9			49
Future income taxes		3,997			5,309
Net changes in non-cash working capital (note 10(b))		(19,097	)		2,938

		(7,938	)		33,014
Investing activities:
Purchase of plant and equipment		(19,710	)		(59,349	)
Proceeds on disposal of plant and equipment		138			1,352
Proceeds on disposal of assets held for sale		960			192
Net changes in non-cash working capital (note 10(b))		(1,272	)		43,473

		(19,884	)		(14,332	)
Financing activities:
Increase in credit facilities		11,800			—
Stock options exercised		—			677
Financing costs (note 6(a))		(1,115	)		—
Repayment of capital lease obligations		(1,470	)		(1,225	)

		9,215			(548	)

(Decrease) increase in cash and cash equivalents		(18,607	)		18,134
Cash and cash equivalents, beginning of period		98,880			31,863

Cash and cash equivalents, end of period	$	80,273		$	49,997


Supplemental cash flow information (note 10(a))

See accompanying notes to unaudited interim consolidated financial statements

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Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2009

(Expressed in thousands of Canadian Dollars, except per share amounts or unless otherwise specified)

(Unaudited)

1. Nature of Operations

North American Energy Partners Inc. (the “Company”), formerly NACG Holdings Inc. (“NACG”), was incorporated under the Canada Business Corporations Act on October 17, 2003. On November 26, 2003, 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 heavy construction, commercial and industrial site development and 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, 2009 and should be read in conjunction with those consolidated financial statements.

These consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, NACGI and NACG Finance LLC, the Company’s proportionate share of the assets, liabilities, revenues, expenses and cash flows of its joint venture, Noramac Ventures Inc. and the following 100% owned subsidiaries of NACGI:

• North American Caisson Ltd.

• North American Construction Ltd.

• North American Engineering Ltd.

• North American Enterprises Ltd.

• North American Industries Inc.

• North American Mining Inc.

• North American Maintenance Ltd.

• North American Pipeline Inc.

• North American Road Inc.

• North American Services Inc.

• North American Site Development Ltd.

• North American Site Services Inc.

• North American Pile Driving Inc.

3. Recently adopted Canadian accounting pronouncements

i) Goodwill and intangible assets

Effective April 1, 2009, the Company adopted, on a retrospective basis, CICA Handbook Section 3064, “Goodwill and Intangible Assets”, which replaces Section 3062, Goodwill and Other Intangible Assets, and Section 3450, Research and Development Costs and establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The provisions relating to the definition and initial recognition of intangible assets, including internally generated intangible assets, are equivalent to the corresponding provisions of International Accounting Standard IAS 38, Intangible Assets. The adoption of this standard did not have a material impact on the Company’s interim consolidated financial statements.

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Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2009

(Expressed in thousands of Canadian Dollars, except per share amounts or unless otherwise specified)

(Unaudited)

4. Recent Canadian accounting pronouncements not yet adopted

i) Business combinations

In January 2009, the CICA issued Handbook Section 1582, “Business Combinations”, which replaces the existing standard. This section establishes standards for the accounting of business combinations, and states that all assets and liabilities of an acquired business will be recorded at fair value. Obligations for contingent considerations and contingencies will also be recorded at fair value at the acquisition date. The standard also states that acquisition related costs will be expensed as incurred, that restructuring charges will be expensed in periods after the acquisition date and that non-controlling interests should be measured at fair value at the date of acquisition. This standard is equivalent to International Financial Reporting Standards on business combinations. This standard is to be applied prospectively to business combinations with acquisition dates on or after January 1, 2011 and earlier adoption is permitted. The Company is currently evaluating the impact of this standard.

ii) Consolidated financial statements

In January 2009, the CICA issued Handbook Section 1601, “Consolidated Financial Statements”, which replaces Section 1600 — Consolidated Financial Statements. This Section carries forward existing Canadian guidance for preparing consolidated financial statements other than guidance for non-controlling interests. This standard is effective for interim and annual financial statements beginning on or after January 1, 2011 and earlier adoption is permitted. The Company is currently evaluating the impact of this standard.

iii) Non-controlling interests

In January 2009, the CICA issued Handbook Section 1602, “Non-Controlling Interests”, which establishes standards for the accounting of non-controlling interests of a subsidiary in the preparation of consolidated financial statements subsequent to a business combination. This standard is equivalent to the International Financial Reporting Standards on consolidated and separate financial statements. This standard is effective for interim and annual financial statements beginning on or after January 1, 2011 and earlier adoption is permitted. The Company is currently evaluating the impact of this standard.

iv) Accounting changes

In June 2009, the CICA amended Handbook Section 1506, “Accounting Changes”, to exclude from its scope changes in accounting policies upon the complete replacement of an entity’s primary basis of accounting. The amendment applies to interim and annual financial statements relating to fiscal years beginning on or after July 1, 2009.

v) Financial instruments — recognition and measurement

In June 2009, the CICA amended Handbook Section 3855, “Financial Instruments — Recognition and Measurement”, to clarify the application of the effective interest method after a debt instrument has been impaired. The Section has also been amended to clarify when an embedded prepayment option is separated from its host instrument for accounting purposes. The amendments apply to interim and annual financial statements relating to fiscal years beginning on or after May 1, 2009 for the amendments relating to the effective interest method and on or after January 1, 2011 for the amendments relating to embedded prepayment options. The Company is currently evaluating the impact of the amendments.

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Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2009

(Expressed in thousands of Canadian Dollars, except per share amounts or unless otherwise specified)

(Unaudited)

vi) Financial instruments — disclosure

In June 2009, the CICA amended Handbook Section 3862, “Financial Instruments — Disclosures”, to include additional disclosure requirements about fair value measurements of financial instruments and to enhance liquidity risk disclosure requirements. The amendments apply to annual financial statements relating to fiscal years ending after September 30, 2009. The Company is currently evaluating the impact of the amendments to the standard.

vii) International Financial Reporting Standards (IFRS)

In 2006, the Canadian Accounting Standards Board (“AcSB”) published a new strategic plan that significantly affects financial reporting requirements for Canadian public companies. The AcSB strategic plan outlines the convergence of Canadian GAAP with IFRS over an expected five-year transitional period. In February 2008, the AcSB confirmed that IFRS will be mandatory in Canada for profit-oriented publicly accountable entities for fiscal periods beginning on or after January 1, 2011, unless, as permitted by Canadian securities regulations, the Company was to adopt U.S. GAAP on or before this date. Should the Company decide to adopt IFRS, its first annual IFRS financial statements would be for the year ending March 31, 2012 and would include the comparative period of 2011 and starting in the first quarter of fiscal 2012, the Company would provide unaudited consolidated financial information in accordance with IFRS including comparative figures for fiscal 2011. The Company has completed a preliminary analysis of the accounting and reporting differences under IFRS, Canadian GAAP and U.S. GAAP, however, management has not yet finalized its determination of the impact of these differences on the consolidated financial statements. This analysis will, in part, determine whether the Company adopts IFRS or U.S. GAAP once Canadian GAAP ceases to exist.

The Company is also closely monitoring standard-setting activity and regulatory developments in Canada, the United States and internationally that may affect the timing of its adoption of either IFRS or U.S. GAAP in future periods.

5. Plant and equipment


June 30, 2009	Cost		Accumulated Depreciation		Net Book Value
Heavy equipment	$	335,786	$	80,838	$	254,948
Major component parts in use		26,372		3,648		22,724
Other equipment		21,947		8,848		13,099
Licensed motor vehicles		14,183		8,778		5,405
Office and computer equipment		15,931		6,429		9,502
Buildings		19,822		5,269		14,553
Leasehold improvements		7,508		2,079		5,429
Assets under capital lease		26,252		11,399		14,853

	$	467,801	$	127,288	$	340,513

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Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2009

(Expressed in thousands of Canadian Dollars, except per share amounts or unless otherwise specified)

(Unaudited)


March 31, 2009	Cost		Accumulated Depreciation		Net Book Value
Heavy equipment	$	319,706	$	76,130	$	243,576
Major component parts in use		25,187		2,535		22,652
Other equipment		22,056		8,268		13,788
Licensed motor vehicles		12,760		7,445		5,315
Office and computer equipment		14,614		5,644		8,970
Buildings		19,822		4,956		14,866
Leasehold improvements		6,494		1,845		4,649
Assets under capital lease		27,953		12,064		15,889

	$	448,592	$	118,887	$	329,705

During the three months ended June 30, 2009, additions to plant and equipment included $624 of assets that were acquired by means of capital leases (three months ended June 30, 2008 — $1,164). Depreciation of equipment under capital lease of $1,159 (three months ended June 30, 2008 — $648) was included in depreciation expense.

6. Debt

a) Credit facilities

On June 24, 2009, the Company entered into an amended and restated credit agreement to provide for borrowings of up to $125.0 million under which revolving loans, term loans and letters of credit may be issued. This facility matures on June 8, 2011.

The total amount of the credit facility remains unchanged at $125 million and includes a $75 million Revolving Facility and a $50 million Term Facility. Advances under the Revolving Facility may be repaid and borrowed from time to time at the option of the Company. The Term Facility commitments are available until August 31, 2009 and aggregate borrowings under this facility must exceed $25 million. Any undrawn amount under the Term Facility, up to a maximum of $15 million, may be reallocated to the Revolving Facility. Beginning September 30, 2009, and at the end of each fiscal quarter thereafter, the Company must make quarterly payments of principal in an amount equal to 4.375% of the outstanding principal drawn under the Term Facility at August 31, 2009. The credit facility bears interest at Canadian prime rate, U.S. Dollar Base Rate, Canadian bankers’ acceptance rate or London interbank offered rate (LIBOR) (all such terms as used or defined in the credit facility), plus applicable margins. In each case, the applicable pricing margin depends on the Company’s credit rating.

The credit facility is secured by a first priority lien on substantially all of 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 share of capital stock. The Company is also required to meet certain financial covenants under the credit agreement and was in compliance with these covenants at June 30, 2009.

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Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2009

(Expressed in thousands of Canadian Dollars, except per share amounts or unless otherwise specified)

(Unaudited)

As of June 30, 2009, the Company had outstanding borrowings of $11.8 million (March 31, 2009 — $nil) under the Term Facility and had issued $20.3 million (March 31, 2009 — $20.8 million) in letters of credit under the Revolving Facility to support performance guarantees associated with customer contracts. The funds available under the Revolving Facility are reduced by any outstanding letters of credit. The Company’s unused borrowing availability under the credit facility was $92.9 million at June 30, 2009.

During the three months ended June 30, 2009, financing fees of $1.1 million were incurred in connection with the modifications made to the amended and restated credit agreement. These fees have been recorded as an intangible asset and are being amortized on a straight-line basis over the remaining term of the credit facility.

b) Senior notes


	June 30, 2009			March 31, 2009
8³/4% senior unsecured notes due 2011 ($US)	$	200,000		$	200,000
Unrealized foreign exchange		32,500			52,040
Unamortized financing costs and premiums, net		(2,416	)		(2,857	)
Fair value of embedded prepayment and early redemption options (note 9)		1,443			3,716

	$	231,527		$	252,899

The 8³/4% senior notes were issued on November 26, 2003 in the amount of U.S. $200 million (Canadian $263 million). These notes mature on December 1, 2011 with interest payable semi-annually on June 1 and December 1 of each year. The 8³/4% senior notes are unsecured senior obligations and rank equally with all other existing and future unsecured senior debt and senior to any subordinated debt that may be issued by the Company or any of its subsidiaries. The notes are effectively subordinated to all secured debt to the extent of the outstanding amount of such debt.

The 8³/4% senior notes are redeemable at the option of the Company, in whole or in part, at any time on or after: December 1, 2007 at 104.4% of the principal amount; December 1, 2008 at 102.2% of the principal amount; December 1, 2009 at 100.0% of the principal amount; plus, in each case, interest accrued to the redemption date.

If a change of control occurs, the Company will be required to offer to purchase all or a portion of each holder’s 8³/4% senior notes, at a purchase price in cash equal to 101.0% of the principal amount of the notes offered for repurchase plus accrued interest to the date of purchase. As at June 30, 2009, the Company’s effective weighted average interest rate on its 8³/4% senior notes, including the effect of financing costs and premiums, net, was approximately 9.42%.

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Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2009

(Expressed in thousands of Canadian Dollars, except per share amounts or unless otherwise specified)

(Unaudited)

7. Shares

a) Common shares

Authorized:

Unlimited number of common voting shares

Unlimited number of common non-voting shares Issued and outstanding:


	Number of Shares	Amount
*Common voting shares*
Issued and outstanding at March 31, 2009 and June 30, 2009	36,038,476	$	299,973

b) Contributed surplus


Balance, March 31, 2009	$	5,275
Stock-based compensation (note 12(a))		917
Deferred performance share unit plan (note 12(b))		214
Settlement of stock options		(66	)

Balance, June 30, 2009	$	6,340

c) Net income per share


	Three months ended June 30,
	2009		2008
Net income available to common shareholders	$	14,774	$	19,096
Weighted average number of common shares		36,038,746		35,968,046

Basic net income per share	$	0.41	$	0.53


Net income available to common shareholders	$	14,774	$	19,096
Weighted average number of common shares		36,038,476		35,968,046
Dilutive effect of stock options		558,592		1,011,713
Weighted average number of diluted common shares		36,597,068		36,979,759

Diluted net income per share	$	0.40	$	0.52

At June 30, 2009, 836,754 options were anti-dilutive and therefore were not considered in computing diluted earnings per share.

d) Capital disclosures

The Company’s overall strategy with respect to capital risk management remains unchanged from March 31, 2009.

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Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2009

(Expressed in thousands of Canadian Dollars, except per share amounts or unless otherwise specified)

(Unaudited)

8. Interest expense


	Three months ended June 30,
	2009			2008
Interest on senior notes	$	10,979		$	5,834
Interest on capital lease obligations		291			282
Amortization of bond issue costs and premiums		221			174
Interest on credit facilities		165			—
Interest income⁽ⁱ⁾		(3,166	)		—

Interest on long-term debt		8,490			6,290
Other interest		147			159

	$	8,637		$	6,449

⁽ⁱ⁾

As a result of the U.S. Dollar interest rate swap cancelation, the Company now receives floating quarterly interest payments from its SWAP counterparties at a rate of 4.2% over three-month LIBOR. These floating interest payments occur every March 1, June 1, September 1, and December 1 until the notes mature on December 1, 2011.

9. Financial instruments and risk management

There have been no significant changes to the Company’s risk management strategies since March 31, 2009.

Derivative financial instruments consist of the following:


June 30, 2009	Derivative Financial Instruments		Senior Notes
Cross-currency and interest rate swaps	$	53,077	$	—
Embedded price escalation features in a long-term revenue construction contract		2,963		—
Embedded price escalation features in certain long-term supplier contracts		8,614		—
Embedded prepayment and early redemption options on senior notes		—		1,443

Total fair value of derivative financial instruments		64,654		1,443
Less: current portion		4,639		—

	$	60,015	$	1,443

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Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2009

(Expressed in thousands of Canadian Dollars, except per share amounts or unless otherwise specified)

(Unaudited)


March 31, 2009	Derivative Financial Instruments			Senior Notes
Cross-currency and interest rate swaps	$	39,547		$	—
Embedded price escalation features in a long-term revenue construction contract		(324	)		—
Embedded price escalation features in certain long-term supplier contracts		22,778			—
Embedded prepayment and early redemption options on senior notes		—			3,716

Total fair value of derivative financial instruments		62,001			3,716
Less: current portion		11,439			—

	$	50,562		$	3,716

The realized and unrealized loss (gain) on derivative financial instruments is comprised as follows:


	Three months ended June 30,
	2009			2008
Realized and unrealized loss/(gain) on cross-currency and interest rate swaps	$	14,196		$	(454	)
Unrealized loss/(gain) on embedded price escalation features in a long-term revenue construction contract		3,287			(634	)
Unrealized gain on embedded price escalation features in certain long-term supplier contracts		(14,164	)		(201	)
Unrealized gain on embedded prepayment and early redemption options on senior notes		(2,273	)		(976	)

	$	1,046		$	(2,265	)

10. Other information

a) Supplemental cash flow information


	Three months ended June 30,
	2009		2008
Cash paid during the period for:
Interest	$	21,241	$	13,468
Income taxes		6,063		—
Cash received during the period for:
Interest		3,329		7
Non-cash transactions:
Acquisition of plant and equipment by means of capital leases		624		1,164

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Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2009

(Expressed in thousands of Canadian Dollars, except per share amounts or unless otherwise specified)

(Unaudited)

b) Net change in non-cash working capital


	Three months ended June 30,
	2009			2008
Operating activities:
Accounts receivable	$	8,153		$	38,112
Allowance for doubtful accounts		(77	)		9
Unbilled revenue		(3,157	)		(18,650	)
Inventory		4,097			(5,407	)
Prepaid expenses and deposits		(2,760	)		706
Other assets		—			3,703
Accounts payable		(4,623	)		(8,038	)
Accrued liabilities		(20,644	)		(15,053	)
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		(86	)		7,556

	$	(19,097	)	$	2,938

Investing activities:
Accounts payable	$	(1,272	)	$	43,473

c) Income taxes

Income tax expense as a percentage of income before income taxes for the three months ended June 30, 2009 differs from the statutory rate of 28.91% primarily due to the impact of changes in enacted tax rates and the benefit from changes in the timing of the reversal of temporary differences. Income tax as a percentage of income before income taxes for the three months ended June 30, 2008 differed from the statutory rate of 29.38% primarily due to the benefit from changes in the timing of the reversal of temporary differences.

11. Segmented information

a) General overview

The Company operates in the following reportable business segments, which follow the organization, management and reporting structure within the Company:

•

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 Canada.

•

Piling:

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

•

Pipeline:

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

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Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2009

(Expressed in thousands of Canadian Dollars, except per share amounts or unless otherwise specified)

(Unaudited)

The accounting policies of the reportable operating segments are the same as those described in the significant accounting policies in note 3. Certain business units of the Company have been aggregated into the Heavy Construction and Mining segment as they have similar economic characteristics. These business units are considered to have similar economic characteristics based on similarities in the nature of the services provided, the customer base and the similarities in the production process and the resources used to provide these services.

b) Results by business segment


Three months ended June 30, 2009	Heavy Construction and Mining		Piling		Pipeline		Total
Revenues from external customers	$	132,410	$	14,618	$	75	$	147,103
Depreciation of plant and equipment		6,894		562		222		7,678
Segment profits		23,636		2,684		367		26,687
Segment assets		384,093		85,759		7,506		477,358
Capital expenditures		16,672		2		—		16,674

Three months ended June 30, 2008	Heavy Construction and Mining		Piling		Pipeline		Total
Revenues from external customers	$	189,405	$	42,503	$	27,079	$	258,987
Depreciation of plant and equipment		5,223		820		227		6,270
Segment profits		21,402		8,661		8,925		38,988
Segment assets		529,431		123,108		74,975		727,514
Capital expenditures		48,842		5,830		4,649		59,321

c) Reconciliations

i) Income before income taxes


Three months ended June 30,	2009			2008
Total profit for reportable segments	$	26,687		$	38,988
Unallocated corporate expenses:
General and administrative expense		15,066			19,215
Loss on disposal of plant and equipment		41			1,144
(Gain) loss on disposal of assets held for sale		(317	)		22
Amortization of intangibles		248			278
Interest expense		8,637			6,449
Foreign exchange gain		(19,215	)		(1,641	)
Realized and unrealized (loss) gain on derivative financial instruments		1,046			(2,265	)
Other (expense) income		533			(18	)
Unallocated equipment recoveries & (costs)⁽ⁱ⁾		1,877			(8,601	)

Income before income taxes	$	18,771		$	24,405

⁽ⁱ⁾

Unallocated equipment costs represent actual equipment costs, including non-cash items such as depreciation, which have not been allocated to reportable segments. Unallocated equipment recoveries arise when actual equipment costs charged to the reportable segment exceed actual equipment costs incurred.

LOGO

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2009

(Expressed in thousands of Canadian Dollars, except per share amounts or unless otherwise specified)

(Unaudited)

ii) Total assets


	June 30, 2009		March 31, 2009
Total assets for reportable segments	$	477,358	$	478,597
Corporate assets:
Cash		80,273		98,880
Plant and equipment		29,120		25,549
Future income taxes		17,493		19,465
Other		10,004		7,561

Total corporate assets		136,890		151,455

Total assets	$	614,248	$	630,052

The Company’s goodwill of $23,872 is assigned to the Piling segment. All of the Company’s assets are located in Canada.

iii) Depreciation of plant and equipment


Three months ended June 30,	2009		2008
Total depreciation for reportable segments	$	7,678	$	6,270
Depreciation for corporate assets		1,669		1,888

Total depreciation	$	9,347	$	8,158

iv) Capital expenditures for plant and equipment


Three months ended June 30,	2009		2008
Total capital expenditures for reportable segments	$	16,674	$	59,321
Capital expenditures for corporate assets		3,036		28

Total capital expenditures	$	19,710	$	59,349

d) Customers

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


Three months ended June 30,	2009		2008
Customer A	55	%	24	%
Customer B	18	%	15	%
Customer C	10	%	15	%
Customer D	5	%	22	%

The revenue by major customer was earned in Heavy Construction and Mining, Piling and Pipeline segments.

LOGO

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2009

(Expressed in thousands of Canadian Dollars, except per share amounts or unless otherwise specified)

(Unaudited)

12. Stock-based compensation plan

a) Share option 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.


	Three months ended June 30,
	2009				2008
	Number of options		Weighted average exercise price ($ per share)		Number of options		Weighted average exercise price ($ per share)
Outstanding, beginning of period	2,071,884		7.53		2,036,364		7.54
Granted	160,000		8.28		—		—
Exercised	(40,000	)	(5.00	)	(107,000	)	(6.32	)
Forfeited	(10,380	)	(6.51	)	(101,000	)	(10.58	)

Outstanding, end of period	2,181,504		7.64		1,828,364		7.44

At June 30, 2009, the weighted average remaining contractual life of outstanding options is 7.0 years (March 31, 2009 — 7.0 years). At June 30, 2009, the Company had 1,184,184 exercisable options (March 31, 2009 — 1,055,924) with a weighted average exercise price of $5.99 (March 31, 2009 — $5.85).

For the three months ended June 30, 2009, the 40,000 options exercised were settled in cash.

The Company recorded $917 of compensation expense related to the stock options for the three months ended June 30, 2009 (three months ended June 30, 2008 — $254), with such amount being credited to contributed surplus.

The fair value of each option granted by the Company was estimated on the grant date using the Black-Scholes option-pricing model with the following assumptions:


	Three months ended June 30,
	2009		2008
Number of options granted	160,000		—
Weighted average fair value per option granted ($)	5.89		—
Weighted average assumptions:
Dividend yield	Nil	%	—
Expected volatility	77.47	%	—
Risk-free interest rate	3.44	%	—
Expected life (years)	6.5		—

LOGO

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2009

(Expressed in thousands of Canadian Dollars, except per share amounts or unless otherwise specified)

(Unaudited)

b) Deferred performance share unit plan

On March 19, 2008, the Company approved a Deferred Performance Share Unit (“DPSU”) Plan which became effective April 1, 2008.

DPSUs will be granted effective April 1 of each fiscal year in respect of services to be provided in that fiscal year and the following two fiscal years. The DPSUs vest at the end of a three-year term and are subject to the performance criteria approved by the Compensation Committee of the Board of Directors at the date of grant. Such performance criterion includes the passage of time and is based upon return on invested capital calculated as operating income divided by average operating assets. The date of the third fiscal year-end following the date of the grant of DPSUs shall be the maturity date for such DPSUs. At the maturity date, the Compensation Committee shall assess the participant against the performance criteria and determine the number of DPSUs that have been earned (earned DPSUs).

The settlement of the participant’s entitlement shall be made in either cash at the value of the earned DPSUs equivalent to the number of earned DPSUs at the value of the Company’s common shares at the date of maturity or in a number of common shares equal to the number of earned DPSUs. If settled in common shares, the common shares shall be purchased on the open market or through the issuance of shares from treasury.

The fair value of each unit under the DPSU Plan was estimated on the date of the grant using Black-Scholes option pricing model. The weighted average assumptions used in estimating the fair value of the units issued under the DPSU Plan are as follows:


	Three months ended June 30,
	2009		2008
Number of units granted	748,791		111,020
Weighted average fair value per unit granted ($)	3.65		12.34
Weighted average assumptions:
Dividend yield	Nil	%	Nil	%
Expected volatility	95.49	%	56.25	%
Risk-free interest rate	1.35	%	2.83	%
Expected life (years)	3.0		3.0


	Three months ended June 30,
	2009		2008
	Number of units		Number of units
Outstanding, beginning of period	91,005		—
Granted	748,791		111,020
Exercised	—		—
Forfeited	(19,001	)	—

Outstanding, end of period	820,795		111,020

The weighted average exercise price per unit is $nil.

LOGO

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2009

(Expressed in thousands of Canadian Dollars, except per share amounts or unless otherwise specified)

(Unaudited)

At June 30, 2009, the weighted average remaining contractual life of outstanding DPSU Plan units is 2.64 years (March 31, 2009 — 2.0 years). For the three months ended June 30, 2009, the Company granted 748,791 units under the Plan and recorded compensation expense of $214 (three months ended June 30, 2008 — $113) which is included in general and administrative costs. This compensation expense was adjusted based upon management’s assessment of performance against return on invested capital targets and the ultimate number of units expected to be issued. As at June 30, 2009, there was approximately $2,051 of total unrecognized compensation cost related to non-vested share-based payment arrangements under the DPSU Plan, which is expected to be recognized over a weighted average period of 2.64 years and is subject to performance adjustments.

c) Director’s deferred stock unit plan

On November 27, 2007, the Company approved a Directors’ Deferred Stock Unit (“DDSU”) Plan, which became effective January 1, 2008. Under the DDSU Plan, non-officer directors of the Company shall receive 50% of their annual fixed remuneration (which is included in general and administrative costs) in the form of DDSUs and may elect to receive all or a part of their annual fixed remuneration in excess of 50% in the form of DDSUs. The number of DDSUs to be credited to the participants deferred share unit account shall be determined by dividing the amount of the participant’s deferred remuneration by the Canadian Dollar equivalent of the Company’s weighted average share price of the last five trading days on the New York Stock Exchange at the end of the period. The DDSUs vest immediately upon grant and are only redeemable upon death or retirement of the participant for cash determined by the market price of the Company’s common shares for the five trading day’s immediately preceding death or retirement. Directors, who are not US taxpayers, may elect to defer the maturity date until a date no later than December 1^st of the calendar year following the year in which the actual maturity date occurred.


	Three months ended June 30,
	2009	2008
Outstanding, beginning of period	139,691	11,807
Granted	33,317	8,967
Exercised	—	—
Forfeited	—	—

Outstanding, end of period	173,008	20,774

For the three months ended June 30, 2009, the Company recorded an expense of $674 (three months ended June 30, 2008 — $269) related to grants of DDSUs.

At June 30, 2009, the redemption value of these units was $7.05/unit (March 31, 2009 — $3.91/unit). There is no unrecognized compensation expense related to deferred share units, since these awards vest immediately when granted.

13. Contingencies

During the normal course of the Company’s operations, various legal and tax matters are pending. In the opinion of management, these matters will not have a material effect on the Company’s consolidated financial position or results of operations.

LOGO

Notes to Interim Consolidated Financial Statements

For the three months ended June 30, 2009

(Expressed in thousands of Canadian Dollars, except per share amounts or unless otherwise specified)

(Unaudited)

14. 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. In addition to revenue variability, gross margins can be negatively impacted in less active periods because the Company is likely to incur higher maintenance and repair costs due to its equipment being available for service.

15. Claims revenue

At June 30, 2009, due to the timing of receipt of signed change orders, Heavy Construction and Mining had approximately $0.7 million in claims revenue recognized to the extent of costs incurred. None of the claims revenue recognized during the three months ended June 30, 2009 has been collected.

16. Comparative figures

Certain of the comparative figures have been reclassified from statements previously presented to conform to the presentation of the current year consolidated financial statements.

17. Subsequent event

On August 1, 2009, the Company acquired all of the issued and outstanding shares of DF Investments Ltd. and its subsidiary Drillco Foundation Co. Ltd. located in Ontario, Canada for cash consideration of $4,880. This acquisition gives the Company access to Piling markets and customers in the region. The acquisition of DF Investments Ltd., and any post closing purchase price adjustments, will be reflected in the Company’s consolidated financial statements beginning August 1, 2009.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

The following discussion and analysis is as of August 4, 2009 and should be read in conjunction with the attached unaudited consolidated financial statements for the three months ended June 30, 2009, the audited consolidated financial statements for the fiscal year ended March 31, 2009, together with our most recent annual Management’s Discussion and Analysis. These statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). Except where otherwise specifically indicated, all dollar amounts are expressed in Canadian dollars. These audited consolidated financial statements, our most recent annual Management’s Discussion and Analysis and additional information relating to our business, including our most recent Annual Information Form (AIF), are available on the Canadian Securities Administrators’ SEDAR System at www.sedar.com and the Securities and Exchange Commission’s website at www.sec.gov.

August 4, 2009

TABLE OF CONTENTS


A.	FINANCIAL RESULTS	2
	Consolidated Three Month Results	2
	Analysis of Results	3
	Segment Results	5
	Non-Operating Income and Expense	6
	Summary of Quarterly Results	8
	Consolidated Financial Position	10
	Claims and Change Orders	10
B.	KEY TRENDS	11
	Canadian and US Dollar Exchange Rate	11
	Backlog	11
	Other Key Trends	12
C.	OUTLOOK	12
D.	LEGAL AND LABOUR MATTERS	13
	Laws and Regulations and Environmental Matters	13
	Employees and Labour Relations	14
E.	RESOURCES AND SYSTEMS	14
	Outstanding Share Data	14
	Liquidity	14
	Debt Ratings	18
	Cash Flow and Capital Resources	20
	Capital Commitments	22
	Related Parties	22
	Internal Systems and Processes	22
	Significant Accounting Policies	23
	Recently Adopted Canadian Accounting Pronouncements	24
	Recent Canadian Accounting Pronouncements Not Yet Adopted	24
G.	FORWARD-LOOKING INFORMATION AND RISK FACTORS	25
	Forward-Looking Information	25
	Risk Factors	28
	Quantitative and Qualitative Disclosures about Market Risk	29
H.	GENERAL MATTERS	31
	Additional Information	31

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

A. FINANCIAL RESULTS

Consolidated Three Month Results


	Three Months Ended June 30,
(dollars in thousands, except per share information)	2009		% of Revenue		2008		% of Revenue		Change			% Change
Revenue	$	147,103	100.0	%	$	258,987	100.0	%	$	(111,884	)	-43.2	%
Project costs		54,553	37.1	%		148,631	57.4	%		(94,078	)	-63.3	%
Equipment costs		46,044	31.3	%		45,811	17.7	%		233		0.5	%
Equipment operating lease expense		12,349	8.4	%		8,798	3.4	%		3,551		40.4	%
Depreciation		9,347	6.4	%		8,158	3.1	%		1,189		14.6	%
Gross profit		24,810	16.9	%		47,589	18.4	%		(22,779	)	-47.9	%
General & administrative costs		15,066	10.2	%		19,215	7.4	%		(4,149	)	-21.6	%
Operating income		9,772	6.6	%		26,930	10.4	%		(17,158	)	-63.7	%
Net income		14,774	10.0	%		19,096	7.4	%		(4,322	)	-22.6	%
Per share information
Net income - basic	$	0.41			$	0.53			$	(0.12	)
Net income - diluted		0.40				0.52				(0.12	)
EBITDA⁽¹⁾	$	37,003	25.2	%	$	39,290	15.2	%	$	(2,287	)	-5.8	%
Consolidated EBITDA⁽¹⁾		19,585	13.3	%		36,727	14.2	%		(17,142	)	-46.7	%
(as defined within our credit agreement)

⁽¹⁾

Non-GAAP Financial measures — The body of generally accepted accounting principles applicable to us is commonly referred to as “GAAP”. A non-GAAP financial measure is generally defined by the Securities and Exchange Commission (SEC) and by the Canadian securities regulatory authorities as one that purports to measure historical or future financial performance, financial position or cash flows, but excludes or includes amounts that would not be so adjusted in the most comparable GAAP measures. EBITDA is calculated as net income before interest expense, income taxes, depreciation and amortization. “Consolidated EBITDA” is a measure defined by our credit agreement. This measure is defined as EBITDA, excluding the effects of unrealized 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. 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 plant and equipment are being allocated efficiently. In addition, our credit facility requires us to maintain a minimum interest coverage ratio and a maximum senior leverage ratio, which are calculated using Consolidated EBITDA. Non-compliance with these financial covenants could result in our being required to immediately repay all amounts outstanding under our credit facility. EBITDA and Consolidated EBITDA are non-GAAP financial measures 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 should not be considered 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;

•

reflect changes in our cash requirements for our working capital needs;

•

reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;

•

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

•

reflect any cash requirements for assets being depreciated and amortized that may have to be replaced in the future.

Consolidated EBITDA excludes unrealized foreign exchange gains and losses and realized and unrealized 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.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

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


	Three Months Ended June 30,
(dollars in thousands)	2009			2008
Net income	$	14,774		$	19,096
Adjustments:
Interest expense		8,637			6,449
Income taxes		3,997			5,309
Depreciation		9,347			8,158
Amortization of intangible assets		248			278

EBITDA	$	37,003		$	39,290
Adjustments:
Unrealized foreign exchange gain on senior notes		(19,319	)		(1,831	)
Realized and unrealized loss (gain) on derivative financial instruments		1,046			(2,265	)
(Gain) loss on disposal of plant and equipment and assets held for sale		(276	)		1,166
Stock-based compensation (excluding director deferred stock unit expense)		1,131			367

Consolidated EBITDA	$	19,585		$	36,727

Analysis of Results

Revenue

For the three months ended June 30, 2009, revenues of $147.1 million were $111.9 million lower than in the same period last year. As we anticipated, continued weakness in commercial construction markets, reduced development activity in the oil sands and a sharp decline in Pipeline segment revenues following our completion of the TMX¹ pipeline project resulted in lower project development revenues. Recurring services revenues were also down compared to the same period last year. This was primarily due to lower volumes under our long-term overburden removal contract with Canadian Natural² following a temporary shutdown during the customer’s production start-up period. While we began to gradually ramp up overburden removal activity at the site during the current three month period, production is not yet back to planned levels.

Gross Profit

Gross profit for the three months ended June 30, 2009 was $24.8 million, a decrease of $22.8 million, primarily as a result of lower revenue. Margins remained solid at 16.9% of revenue, reflecting the benefits of higher-margin site services work and company-wide efforts to improve efficiency and reduce expenses. Prior-year margins of 18.4% were bolstered by the $5.3 million settlement of claims revenue on a pipeline project. Excluding this benefit, margins would have been 16.3% for the three-month period last year, demonstrating a relatively stable year-on-year performance.

¹	Kinder Morgan’s Trans Mountain Expansion (TMX) Anchor Loop pipeline

²	Canadian Natural Resources Limited (Canadian Natural) Horizon project

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

Project costs, as a percent of revenue, decreased to 37.1% during the three months ended June 30, 2009, compared to 57.4% in the same period last year. Lower project costs were offset by an increase in equipment costs to 31.3% of revenue during the three months ended June 30, 2009, compared to 17.7% of revenue in the same period last year. The change in cost-mix reflects an increased contribution from the equipment-intensive work in our Heavy Construction and Mining segment in the current period versus a strong contribution of materials and sub contractor work in our Pipeline segment during the prior period. Equipment operating lease expense increased $3.6 million year-over-year to $12.3 million, reflecting our commissioning of a second new electric cable shovel at the Canadian Natural site in December 2008, as well as growth in the size of our leased equipment fleet. Depreciation also increased to 6.4% of revenue in the current three month period ended June 30, 2009, compared to 3.1% in the same period last year, reflecting the increased contribution from the Heavy Construction and Mining segment, a reduction in the use of rental equipment and an accelerated depreciation charge of $1.8 million, compared to $0.6 million in the same period last year, as certain aging equipment was prepared for resale.

Operating income

For the three months ended June 30, 2009 we recorded operating income of $9.8 million, or 6.6% of revenue, compared to operating income of $26.9 million or 10.4% of revenue during the same period last year. General and administrative (G&A) expense decreased by $4.1 million compared to the same three month period last year. The benefits of reorganization and cost-reduction initiatives implemented in the three months ended March 31, 2009, as well as process improvements implemented in the second half of the prior fiscal year contributed to the lower G&A expense in the current period. A $1.2 million year-over-year increase to stock-based compensation, deferred performance share unit and director deferred share unit costs, which were triggered by the volatility of our share price, lessened the effect of the aforementioned reorganization and cost reduction initiatives.

Net income

We recorded net income of $14.8 million (basic income per share of $0.41 and diluted income per share of $0.40) for the three months ended June 30, 2009, compared to net income of $19.1 million (basic income per share of $0.53 and diluted income per share of $0.52) during the same period last year. Non-cash items positively affecting net income included the impact of the improving Canadian dollar on our 8³/4% senior notes and non-cash gains on embedded derivatives in a long-term supplier contract. This was partially negated by a loss in our cross-currency and interest rate swaps and a non-cash loss relating to embedded derivatives in a long-term customer contract. Excluding these non-cash items in the current and prior period, net income would have been $0.4 million (basic income per share of $0.01 and diluted income per share of $0.01) down from net income of $15.2 million (basic income per share of $0.42 and diluted income per share of $0.41).

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

Segment Results

Heavy Construction and Mining


	Three Months Ended June 30,
(dollars in thousands)	2009		% of Revenue		2008		% of Revenue		2009 vs. 2008
(dollars in thousands)	2009		% of Revenue		2008		% of Revenue		Change			% Change
Segment revenue	$	132,410			$	189,405			$	(56,995	)	-30.1	%
Segment profit	$	23,636	17.9	%	$	21,402	11.3	%	$	2,234		10.4	%

For the three months ended June 30, 2009, the Heavy Construction and Mining segment reported revenues of $132.4 million, a $57.0 million decrease compared to the same period last year. The benefit of increased master service activity at Shell Albian’s³ sites was partially offset by the temporary reduction in activity on our long-term overburden removal contract initiated by the customer to align our overburden removal activity with the customer’s production schedule. Overburden removal activity has gradually begun to ramp up at the site during the current three month period and is expected to return to normal levels over the next six months. Current period revenues were also negatively affected by the decline of sub-contractor activity at the Syncrude⁴ sites brought about by a major maintenance program undertaken at the upgrader by this client. Activity in the prior year included project development at the Fort Hills⁵ site, which has been deferred, along with site development activity at the Suncor⁶ sites, which were completed in the first nine months of fiscal 2009. These projects contributed significantly to the revenue for the three month period ended June 30, 2008. Also contributing to the prior year revenue for the Heavy Construction and Mining segment was a pass-through fuel supply contract that generated revenue but was executed at zero margin. The contract was completed in June 2008.

For the three months ended June 30, 2009, segment profit of $23.6 million (17.9% of revenue) increased $2.2 million from the same period last year. Margins in the current period benefited from lower costs realized from the reduced use of rental equipment. By contrast, segment profit in the three-month period ended June 30, 2008 was adversely affected by the recognition of a loss due to unfavourable haul road conditions and site congestion at a single mine project, timing of customer approval of submitted change orders and the fuel supply contract at zero margin. Excluding these negative impacts, prior year margins would have been 17.3% of revenue.

Shell Canada Energy, a division of Shell Canada Limited, the operator of the Shell Albian Sands’ (Shell Albian) oils sands mining and extraction operations on behalf of Athabasca Oil Sands Project (AOSP), a joint venture amongst Shell Canada Limited (60%), Chevron Canada Limited (20%) and Marathon Oil Canada Corporation (20%). Prior to January 1, 2009, these operations were run by Albian Sands Energy Inc.

⁴

Syncrude Canada Limited (Syncrude), a joint venture between Canadian Oil Sands Limited (36.74%), Imperial Oil Resources (25.0%), Petro-Canada Oil and Gas (12.0%), ConocoPhillips Oil Sand Partnership II (9.03%), Nexen Oil Sands Partnership (7.23%), Mocal Energy Limited (5.0%), and Murphy Oil Company Ltd. (5.0%). Syncrude is the project operator.

⁵	Fort Hills LP (Fort Hills) a limited partnership between Petro-Canada Limited (60%), UTS Energy Corporation (20%) and Teck Resources Limited (20%). Petro-Canada Limited is the project operator.

⁶	Suncor Energy Inc. (Suncor)

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

Piling


	Three Months Ended June 30,
(dollars in thousands)	2009		% of Revenue		2008		% of Revenue		2009 vs. 2008
(dollars in thousands)	2009		% of Revenue		2008		% of Revenue		Change			% Change
Segment revenue	$	14,618			$	42,503			$	(27,885	)	-65.6	%
Segment profit	$	2,684	18.4	%	$	8,661	20.4	%	$	(5,977	)	-69.0	%

The Piling segment recorded revenues of $14.6 million for the three months ended June 30, 2009, a decrease of $27.9 million compared to the same period last year. The change in Piling revenues reflects declining activity levels in the commercial construction market, as well as a reduction in high-volume oil sands projects.

For the three months ended June 30, 2009, Piling segment margins decreased to 18.4%, from 20.4% a year ago, reflecting the negative impact of the declining commercial construction market and increased competition for available work.

Pipeline


	Three Months Ended June 30,
(dollars in thousands)	2009		% of Revenue		2008		% of Revenue		2009 vs. 2008
(dollars in thousands)	2009		% of Revenue		2008		% of Revenue		Change			% Change
Segment revenue	$	75			$	27,079			$	(27,004	)	-99.7	%
Segment profit	$	367	489.3	%	$	8,925	33.0	%	$	(8,558	)	-95.9	%

Pipeline revenues for the three months ended June 30, 2009 declined $27.0 million compared to the same period a year ago, reflecting completion of the TMX project in October 2008. Segment profit for the current three-month period reflects the resolution of warranty work provided for in the previous year. Segment profit for the prior three-month period includes the benefit of a $5.3 million settlement of claims revenue.

Non-Operating Income and Expense


	Three Months Ended June 30,
(dollars in thousands)	2009			2008			2009 vs. 2008
(dollars in thousands)	2009			2008			Change			% Change
Interest expense
Interest on 8³/4% senior notes	$	10,979		$	5,834		$	5,145		88.2	%
Interest on revolving credit facility and term loan		165			—			165		—
Interest on capital lease obligations		291			282			9		3.2	%
Amortization of deferred bond issue costs		221			174			47		27.0	%
Interest income		(3,166	)		—			(3,166	)	—
Other interest		147			159			(12	)	-7.5	%

Total Interest expense	$	8,637		$	6,449		$	2,188		33.9	%

Foreign exchange gain on senior notes	$	(19,215	)	$	(1,641	)	$	(17,574	)	1,070.9	%
Realized and unrealized loss (gain) on derivative financial instruments		1,046			(2,265	)		3,311		-146.2	%
Other expense (income)		533			(18	)		551		-3,061.1	%
Income tax expense		3,997			5,309			(1,312	)	-24.7	%

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

Interest expense

For the three months ended June 30, 2009, total interest expense increased $2.2 million compared to a year ago. We are currently exposed to increased interest rate risk resulting from the third party cancellation of our US dollar interest rate swap on February 2, 2009. This is partially offset by floating quarterly interest payments we receive from our swap counterparties at a rate of 4.2% over the three-month US LIBOR, which we record as interest income. As of March 1, 2009, we now receive these floating interest payments quarterly every March 1, June 1, September 1 and December 1 until the notes mature on December 1, 2011. A more detailed discussion about our interest rate risk can be found under “Qualitative and Quantitative Disclosures about Market Risk — interest rate risk”.

Foreign exchange (gain) on senior notes

The foreign exchange gains recognized in the current and prior year three-month periods relate primarily to changes in the strength of the Canadian dollar against the US dollar on conversion of the US$200 million 8³ /4% senior notes. A significant increase in the value of the Canadian dollar, from 0.7935 CAN/US at March 31, 2009 to 0.8602 CAN/US at June 30, 2009, resulted in a significant unrealized foreign exchange gain. A more detailed discussion about our foreign currency risk can be found under “Qualitative and Quantitative Disclosures about Market Risk — Foreign currency risk”.

Realized and unrealized loss (gain) on derivative financial instruments

Realized and unrealized gains and losses on derivative financial instruments for the three months ended June 30, 2009 and 2008 reflect changes in the fair value of the cross-currency and interest rate swaps that we employ to provide an economic hedge for our US dollar denominated 8¾% senior notes and also include changes in the fair value of derivatives embedded in our US dollar denominated 8¾% senior notes, in a long-term construction contract and in supplier maintenance agreements.

Changes in the fair value of the cross-currency and interest rate swaps generally have an offsetting effect to changes in the value of our 8¾% senior notes (and resulting foreign exchange gains and losses), with both being triggered by variations in the Canadian/US foreign exchange rate. However, the valuations of the derivative financial instruments are also impacted by changes in interest rates and the remaining present value of scheduled interest payments on the 8¾% senior notes, which occur in June and December of each year until maturity. The change in the realized and unrealized gain / loss of the cross-currency and interest rate swaps resulted in a loss of $14.2 million in the three month period ended June 30, 2009 compared to a gain of $0.5 million in the three month period ended June 30, 2008.

With respect to the early redemption provision in the 8³/4% 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. Changes in fair value result from changes in long-term bond interest rates during a period. The valuation process presumes a 100% probability of our implementing the inferred transaction (early redemption of the 8³/4% senior notes) and does not permit a reduction in the probability if there are other factors that would impact the decision. The change in value of the embedded derivative for the early prepayment and redemption options resulted in a gain of $2.3 million in the three-month period ended June 30, 2009, compared to a gain of $1.0 million in the three-month period ended June 30, 2008.

With respect to the long-term construction contract, there is a provision that requires an adjustment to billings to reflect actual exchange rates and price indices. The embedded derivative instrument takes into account

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

the impact on revenues, but does not consider the impact on costs as a result of fluctuations in these measures. The change in value of the embedded derivative for the long-term construction contract resulted in a loss of $3.3 million in the three months ended June 30, 2009, compared to a gain of $0.6 million in the three-month period ended June 30, 2008.

With respect to the supplier contracts, the embedded derivative related to our equipment purchase agreement was reduced with the commissioning of certain pieces of heavy equipment in the three months ended June 30, 2009. In addition, the embedded derivative related to a long-term maintenance contract was reduced as a result of the removal of certain pieces of heavy equipment from the repair and maintenance program in the supplier contract. Included in the embedded derivative valuation was the impact of fluctuations in provisions that require a price adjustment to reflect the actual Canadian versus US dollar exchange rate and the United States government published Producers’ Price Index for Mining Machinery and Equipment (US-PPI) changes from the contract amount. The change in value of the embedded derivative for the long-term supplier contracts resulted in a gain of $14.2 million in the three months ended June 30, 2009, compared to a gain of $0.2 million in the three-month period ended June 30, 2008.

The measurement of embedded derivatives, as required by GAAP, causes our reported earnings to fluctuate as Canadian versus US dollar exchange rates, interest rates and the US-PPI for Mining Machinery and Equipment change. The accounting for these derivatives has no impact on operations, Consolidated EBITDA (as defined within our credit agreement) or how we evaluate performance.

Income tax expense

For the three months ended June 30, 2009, we recorded future income tax expense of $4.0 million and no current income tax expense. This compares to combined income tax expense of $5.3 million for the same period last year.

For the three months ended June 30, 2009, income tax expense as a percentage of income before income taxes differs from the statutory rate of 28.91% primarily due to the impact of changes in enacted tax rates and the benefit from changes in the timing of the reversal of temporary differences. For the three-month period ended June 30, 2008, income tax expense as a percentage of income before income taxes differed from the statutory rate of 29.38% primarily due to the benefit from changes in the timing of the reversal of temporary timing differences.

Summary of Quarterly Results


	Three Month Periods Ended:
	Fiscal 2010		Fiscal 2009											Fiscal 2008
(dollars in millions, except per share amounts)	Jun 30, 2009		Mar 31, 2009			Dec 31, 2008			Sept 30, 2008			Jun 30, 2008		Mar 31, 2008		Dec 31, 2007		Sept 30, 2007
Revenue	$	147.1	$	174.7		$	258.6		$	280.3		$	259.0	$	323.6	$	274.9	$	223.6
Gross profit		24.8		32.5			51.0			44.3			47.6		62.6		50.6		35.2
Operating income (loss)		9.8		(129.5	)		(2.2	)		23.0			26.9		42.6		33.2		17.1
Net income (loss)		14.8		(142.7	)		(14.7	)		(1.2	)		19.1		20.5		24.7		3.2
Income (loss) per share - Basic⁽¹⁾	$	0.41	$	(3.96	)	$	(0.41	)	$	(0.03	)	$	0.53	$	0.57	$	0.69	$	0.09
Income (loss) per share - Diluted⁽¹⁾		0.40		(3.96	)		(0.41	)		(0.03	)		0.52		0.56		0.67		0.09

⁽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.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

A number of factors have the potential to contribute to variations in our quarterly results between periods, including 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 Canadian and world economies.

We generally experience a decline in revenues during the first three months of each fiscal year due to seasonality, as weather conditions make performance in our 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 our activity levels. Revenues during the three months ended March 31 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 three-month period or combination of three-month periods. In addition to revenue variability, gross margins can be negatively impacted in less active periods because we are likely to incur higher maintenance and repair costs due to our equipment being available for servicing.

The timing of large projects can influence quarterly revenues. For example, Pipeline segment revenues were as high as $87.5 million in the three month period ended March 31, 2008 and as low as $0.1 million in the three months ended June 30, 2009. The Heavy Construction and Mining segment experienced reduced volumes in the three-month periods ending December 31, 2008 and March 31, 2009 as a result of the temporary shut-down of overburden removal at the Horizon project while Canadian Natural prepared for operations start-up. Changes in demand under our master service agreements with Albian and Syncrude were responsible for increases in revenues for the three-month periods ended June 30, 2008, September 30, 2008 and December 31, 2008, respectively, and decreases in revenues for the three-month periods ended March 31, 2009 and June 30, 2009.

Variations in quarterly results can also be caused by changes in our operating leverage. During periods of higher activity we have experienced improvements in operating margin. This reflects the impact of relatively fixed costs, such as general and administrative expenses, being spread over higher revenue levels. If activity decreases, these same fixed costs are spread over lower revenue levels. Net income and income per share are also subject to operating leverage as provided by fixed interest expense.

Profitability also varies from period-to-period as a result of claims and change orders. Claims and change orders are a normal aspect of the contracting business but can cause variability in profit margin due to the unmatched recognition of costs and revenues. For further explanation, see “Claims and Change Orders”. As an example, during the three-month period ending June 30, 2008, a $5.3 million claim was recognized causing gross margins for the Pipeline segment to be higher than normal. The additional costs relating to this claim were incurred and recognized in the year ended March 31, 2007 and in the three-month period ended June 30, 2007.

We also have experienced earnings variability in all periods due to the recognition of unrealized non-cash gains and losses on both derivative financial instruments and foreign exchange, primarily driven by changes in the Canadian and US dollar exchange rates.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

Consolidated Financial Position


(dollars in thousands)	As at June 30, 2009			As at March 31, 2009			Change			% Change
Current assets	$	233,965		$	256,738		$	(22,773	)	-8.9	%
Current liabilities		(105,015	)		(135,091	)		30,076		-22.3	%
Net working capital		128,950			121,647			7,303		6.0	%
Plant and equipment		340,513			329,705			10,808		3.3	%
Total assets		614,248			630,052			(15,804	)	-2.5	%
Capital lease obligations (including current portion)		(16,638	)		(17,484	)		846		-4.8	%
Total long-term financial liabilities⁽¹⁾		(313,740	)		(316,082	)		2,342		-0.7	%

⁽¹⁾	Total long-term financial liabilities exclude the current portions of capital lease obligations, current portions of derivative financial instruments, long-term lease inducements, asset retirement obligation and both current and non-current future income tax balances.

At June 30, 2009, net working capital (current assets less current liabilities) was $129.0 million compared to $121.6 million at March 31, 2009, an increase of $7.3 million.

Current assets decreased $22.8 million between March 31, 2009 and June 30, 2009 from an $18.6 million decrease in cash, as a result of our semi-annual interest payment on our 8³/4% senior notes and a $4.1 million decrease in inventory. The planned consumption of tires, previously stockpiled for new leased haul trucks (haul trucks do not arrive with tires included) contributed to the inventory reduction. Offsetting these reductions was a $3.2 million increase in unbilled revenue.

Current liabilities during the three-month period decreased by $30.1 million reflecting a $5.8 million reduction in accounts payable and a $20.6 million reduction in accrued liabilities from the semi-annual payment of our accrued interest on our 8³/4% senior notes. Equipment purchases of $3.2 million, which are scheduled to be paid after the quarter-end, are included in accounts payable as of June 30, 2009.

Plant and equipment increased by $10.8 million between March 31, 2009 and June 30, 2009. This reflects the capital investment of $20.3 million (including capital leases) during the current three-month period, offset by equipment disposals of $0.2 million (net book value) and depreciation of $9.3 million.

Total long-term financial liabilities decreased by $2.3 million between March 31, 2009 and June 30, 2009, due largely to a $21.4 million decrease in the carrying amount of our 8³/4% senior notes and a $6.4 million decrease related to the long-term portion of the embedded derivatives in long-term supplier contracts. This was partially offset by an increase of $13.5 million related to the cross-currency and interest rate swap agreements, an increase of $2.3 million in the value of the long-term portion of the embedded derivatives in a long-term revenue construction contract and an increase of $9.7 million in the long-term portion of our term loan resulting from new term loans under our amended and restated credit agreement.

Claims and 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:

•

changes in client requirements, specifications and design;

•

changes in materials and work schedules; and

•

changes in ground and weather conditions.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

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 we 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 a 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 to be a claim. Historical claim recoveries should not be considered indicative of future claim recoveries.

At June 30, 2009, due to the timing of receipt of signed change orders, Heavy Construction and Mining had approximately $0.7 million in claims revenue recognized to the extent of costs incurred. We are working with our customers to come to resolution on additional amounts, if any, to be paid to us in respect to these additional costs.

None of the claims revenue recognized during the three months ended June 30, 2009 has been collected to date.

B. KEY TRENDS

A number of factors contribute to variations in our quarterly results, 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, the Canadian and US dollar exchange rate and the strength of the Western Canadian economy.

Canadian and US Dollar Exchange Rate

We have experienced earnings variability in all periods due to the recognition of realized and unrealized non-cash gains and losses on derivative financial instruments and foreign exchange primarily driven by changes in the Canadian and US dollar exchange rates.

Backlog

Backlog is a measure of the amount of secured work we have outstanding and, as such, is an indicator of a base level of future revenue potential. Backlog is not a GAAP measure. As a result, the definition and determination of a backlog 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 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.

Our measure of backlog does not define what we expect our future workload to be. We work with our customers using cost-plus, time-and-materials, unit-price and lump-sum contracts. This mix of contract types

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

varies year-by-year. 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 under these service agreements, the work scope and value are not clearly defined. For the three months ended June 30, 2009, the total amount of revenue earned from time-and-material contracts performed under our master services agreements was approximately $83.5 million.

Our estimated backlog by segment and contract type as at June 30, 2009 and 2008 and March 31, 2009 was:


	As at June 30,				As at March 31,
(dollars in thousands)	2009		2008		2009
Heavy Construction and Mining	$	696,412	$	849,766	$	667,674
Piling		5,731		22,799		8,538
Pipeline		—		59,035		—

Total	$	702,143	$	931,600	$	676,212

	As at June 30,				As at March 31,
(dollars in thousands)	2009		2008		2009
Unit-Price	$	698,550	$	855,011	$	672,725
Lump-Sum		2,165		17,554		3,487
Time-and-Material, Cost-Plus		1,428		59,035		—

Total	$	702,143	$	931,600	$	676,212

A contract with a single customer represented approximately $674.6 million of our June 30, 2009 backlog compared to $664.1 million reported as backlog in our annual Management’s Discussion and Analysis for the year ended March 31, 2009. The increase in the five-year backlog for this customer relates to the timing of scheduled volumes through the life of the contract. We expect that approximately $149.8 million of total backlog will be performed and realized in the 12 months ending June 30, 2010.*

Other Key Trends

For a more detailed discussion of all of our key trends, see our most recent annual Management’s Discussion and Analysis.

C. OUTLOOK

With investment in new oil sands development constrained by macro-economic conditions and some continued variability anticipated in our recurring services revenue, our expectations for the second quarter of fiscal 2010 remain cautious. Overall, however, we continue to see positive developments that improve our longer-term outlook.*

Our Pipeline division was recently awarded a three-year contract to complete pipeline integrity excavations and hydrostatic retests on TransCanada Pipeline’s mainline system in British Columbia, Saskatchewan, Manitoba and Ontario. The three-year contract is significant because it gives our Pipeline operations a steady base workload to perform between larger projects and provides stability for our core group of Pipeline project

* This paragraph contains forward-looking information. Please refer to “Forward-Looking Information and Risk Factors” for a discussion on the risks and uncertainties related to such information.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

managers and key field personnel. The contract also expands our historic geographic construction area further across Canada and provides entry into the pipeline integrity field, which is an area we have been strategically targeting.

In the area of oil sands project development, we believe that a combination of reduced project costs and a gradual strengthening of oil prices is creating a more attractive environment for investment. Imperial Oil’s decision to proceed with the Kearl project is an example of this. In addition, the announced merger between Suncor and Petro-Canada is expected to have a positive impact on oil sands investment by creating a single entity with the resources to support large capital projects.*

On the recurring services front, we expect to see growth resuming in the second half of fiscal 2010 as a result of increased volumes under service agreements and a gradual ramp-up of service on our overburden removal contract with Canadian Natural’s Horizon project. We began to mobilize equipment back to this site on April 1, 2009 and volumes have been gradually returning to planned levels since then. We are seeing strong results regarding oil production from the newly commissioned plant and this augers well for continued sustainable growth in the services we provide to this customer. Our recently signed a three-year service agreement with Shell Albian Sands’ Muskeg River Mine is also expected to provide better stability to our recurring revenue. Longer term, we expect that demand for recurring services will remain largely unaffected by changes in oil prices as operational oil sands mines must operate at full capacity in order to defray high fixed costs and maintain low unit costs. Furthermore, demand for recurring services typically grows as new mines come on-line and maturing mines expand their geographic footprint.*

Our outlook for the commercial and industrial construction market continues to improve marginally as a result of several previously announced small contract wins by both our Heavy Construction and Mining and Piling segments. Overall, however, commercial and industrial construction activity remains well below fiscal 2007 and 2008 market levels. Our Piling division, which has been negatively affected by the slowdown in commercial and industrial construction, continues to pursue its geographic expansion strategy. On August 1, 2009, we completed the acquisition of Drillco Foundation Co. Ltd., a small piling company located in Milton, Ontario. This follows on our opening of an office in Toronto in April 2009 and accelerates our expansion into the Ontario construction market. We are actively bidding on commercial and industrial construction projects in the Ontario market and we expect to benefit from some of the $32.5 billion in announced federal and provincial government spending slated for this market over the next two years.*

As we work through the current market conditions, we intend to continue leveraging our strong market position, high-quality equipment fleet and experienced management team to secure profitable business. We will also continue to focus on strengthening our balance sheet through careful management of capital spending, working capital management and tight cost control.*

D. LEGAL AND LABOUR MATTERS

Laws and Regulations and Environmental Matters

Many aspects of our operations are subject to various federal, provincial and local laws and regulations, including, among others:

•

permitting and licensing requirements applicable to contractors in their respective trades;

* This paragraph contains forward-looking information. Please refer to “Forward-Looking Information and Risk Factors” for a discussion on the risks and uncertainties related to such information.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

•

building and similar codes and zoning ordinances;

•

laws and regulations relating to consumer protection; and

•

laws and regulations relating to worker safety and protection of human health.

For a more detailed discussion of laws and regulations and environmental matters applicable to us, see our most recent annual Management’s Discussion and Analysis.

Employees and Labour Relations

As of June 30, 2009, we had 283 salaried employees and over 1,230 hourly employees. Our hourly workforce fluctuates according to the seasonality of our business and the staging and timing of projects by our customers. The hourly workforce typically ranges in size from 1,000 employees to approximately 2,000 employees depending on the time of year and duration of awarded projects. We also utilize the services of subcontractors in our construction business. An estimated 8% to 10% of the construction work we do is performed by subcontractors. Approximately 1,000 employees are members of various unions and work under collective bargaining agreements. The majority of our work is done through employees governed by our mining overburden collective bargaining agreement with the International Union of Operating Engineers Local 955, the primary term of which expires on October 31, 2009. A small portion of our employees work under a collective bargaining agreement with the Alberta Road Builders and Heavy Construction Association and the International Union of Operating Engineers Local 955, the primary term of which expired February 28, 2009. These negotiations continue as of the date of writing and we expect that a deal will be reached without issue later in the year. In June 2008, we signed an agreement with the International Union of Operating Engineers Local 955 covering the small group of employees working in our Acheson shop. This agreement will expire on June 30, 2011. We are subject to other industry and specialty collective agreements under which we complete work and the primary terms of all of these agreements are currently in effect. We believe that our relationships with all our employees, both union and non-union, are satisfactory. We have not experienced a strike or lockout.*

E. RESOURCES AND SYSTEMS

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 4, 2009, there were 36,038,476 voting Common Shares outstanding (36,038,476 as at March 31, 2009). In comparison, 35,929,476 voting Common Shares were outstanding as at March 31, 2008. We had no Non-Voting Common Shares outstanding on any of the foregoing dates.

Liquidity

Liquidity requirements

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

We maintain a significant equipment and vehicle fleet comprised of units with remaining useful lives covering a variety of time spans. It is important to adequately maintain our large revenue-producing fleet in order

* This paragraph contains forward-looking information. Please refer to “Forward-Looking Information and Risk Factors” for a discussion on the risks and uncertainties related to such information.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

to avoid equipment downtime, which can impact our revenue stream and inhibit our ability to satisfactorily perform on our projects. 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 both to replace retired units and to support our growth as we take on new 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 through our capital lease facilities.

We require between $30 million and $40 million annually for sustaining capital expenditures and our total capital requirements typically range from $125 million to $200 million depending on our growth capital requirements. Given the current demand for heavy equipment in the oil sands we expect our capital needs to be approximately $75 million to $100 million in the current fiscal year. We are currently evaluating our growth capital strategy to meet future oil sands demand. With the potential future customer demand for larger-sized heavy equipment we anticipate we may require a further $50 million to $100 million of growth capital.

We typically finance approximately 30% to 50% of our total capital requirements through our operating lease facilities and the remainder from cash flow from operations. We believe our operating and capital lease facilities and cash flow from operations will be sufficient to meet these requirements. Our equipment is currently split among owned (50%), leased (40%) and rented equipment (10%). Approximately 41% of our leased fleet is specific to one long-term overburden removal project. This equipment mix is a change from the mix reported in previous periods as a result of our declining need for the same levels of rental equipment along with the conversion of some rental equipment to operating leases to meet our volume demands. This mix allows us to respond to variations in construction activity and still maintain positive cash flow from operations. We are continually evaluating our capital needs and continue to monitor equipment lead times with suppliers to ensure that we limit our capital spending while still being able to look for strategic opportunities with our clients.*

We continue to receive interest from finance companies to support our current lease requirements and we have availability under one of our supplier’s leasing program to meet our current equipment needs from this supplier. We are currently negotiating with these finance companies to secure financing for our other equipment needs over the balance of the fiscal year.

Our long-term debt includes US$200.0 million of 8³/4% senior notes due in December 2011. Prior to February 2, 2009, the foreign currency risk relating to both the principal and interest portions of these 8³/4% senior notes was 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. The swap agreements were an economic hedge but had not been designated as hedges for accounting purposes. Interest totaling C$13.0 million on the 8³/4% 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 US$200.0 million principal amount was fixed at C$1.315=US$1.000, resulting in a principal repayment of $263.0 million due on December 1, 2011. There are no principal repayments required on the 8³ /4% senior notes until maturity. Effective February 2, 2009, the US dollar interest rate swap was terminated by the counterparties and our interest expense increased by US$6.8 million per annum (based on the then current US LIBOR rates) for the remaining life of the 8³/4% senior notes. This increase is net of US dollar floating interest payments on the cross-currency swap agreement we now receive every March 1, June 1, September 1 and December 1, effective March 1, 2009 until the notes mature on December 1, 2011. The value of the quarterly floating rate US dollar payments is the prevailing three-month US LIBOR rate plus a spread of 4.2% on the

* This paragraph contains forward-looking information. Please refer to “Forward-Looking Information and Risk Factors” for a discussion on the risks and uncertainties related to such information.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

notional amount of US$200.0 million. Our Canadian dollar interest rate swap and cross-currency swap agreements are not cancelable at the option of the counterparties and remain in effect.

A more detailed discussion of this cancellation can be found below in the “Foreign currency risk” and “Interest rate risk” sections of Quantitative and Qualitative Disclosures about Market Risk.

One of our major contracts allows the customer to require that we provide up to $50.0 million in letters of credit. As at June 30, 2009, we had $20.0 million in letters of credit outstanding in connection with this contract (we have $20.3 million letters of credit outstanding in total for all customers as of June 30, 2009). Any change in the amount of the letters of credit required by this customer must be requested by November 1 in each year for an issue date of January 1 following the date of such request, for the remaining life of the contract. In the event that we require an increase in the value of the letters of credit beyond our current balance, for either this major contract or other contracts, we have included in our June 24, 2009 amended and restated credit agreement an option, on a one-time basis, to request that an increase be provided to the revolving portion of the credit facility by an amount up to the lesser of $25.0 million or the requested increase to the letters of credit for this customer.

Sources of liquidity

Our principal sources of cash are funds from operations and borrowings under our $125 million credit facility. As at June 30, 2009, we had approximately $92.9 million of available borrowings under our credit facility after taking into account $20.3 million of outstanding and undrawn letters of credit to support performance guarantees associated with customer contracts and $11.8 million of outstanding borrowings against the term facility provided for in our amended and restated credit agreement.

As at June 30, 2009, we had $14.0 million in trade receivables that were more than 30 days past due compared to $16.0 million as at March 31, 2009. We have currently provided for potential defaults of trade receivables of $2.5 million ($2.6 million at March 31, 2009) through our allowance for doubtful accounts. We continue to monitor the credit worthiness of our customers. To date our exposure to potential write-downs in trade receivables has been limited to the financial condition of developers of condominiums and high-rise developments.

Working capital fluctuations effect on cash

The seasonality of our work may result in a slow down in cash collections between December and early February, which may result in an increase in our working capital requirements. Our working capital is also significantly affected by the timing of completion of projects. In some cases, our customers are permitted to withhold payment of a percentage of the amount owing to us for a stipulated period of time (such percentage and time period is usually defined by the contract and in some cases provincial legislation). This amount acts as a form of security for our customers and is referred to as a holdback. We are only entitled to collect payment on holdbacks once substantial completion of the contract is performed, there are no outstanding claims by subcontractors or others related to work performed by us and we have met the time period specified by the contract (usually 45 days after completion of the work). As at June 30, 2009, holdbacks totaled $5.9 million, down from $9.4 million as at March 31, 2009. Holdbacks represent 8.5% of our total accounts receivable as at June 30, 2009 (12.0% as at March 31, 2009). This decrease is attributable to the reduction of revenue for the three months ended June 30, 2009 and March 31, 2009 compared to the same periods in the prior year. As at June 30, 2009, we carried $3.6 million in holdbacks for three large customers.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

Cash Requirements

As at June 30, 2009, our cash balance of $80.3 million was $18.6 million lower than our cash balance at March 31, 2009. The decrease in cash balance reflects the timing of our semi-annual interest payment, capital expenditures and the timing of processing change orders and payment certificates. We anticipate that we will generate a net cash surplus at least through September 30, 2009 from cash generated from operations. In the event that we require additional funding, we believe that any such funding requirements would be satisfied by the funds available from our credit facility described immediately below.*

Credit facility

We entered into an amended and restated credit agreement on June 24, 2009 with a syndicate of lenders that provides us with a $125.0 million credit facility, under which revolving loans, term loans and letters of credit may be issued. The facility will mature on June 8, 2011.

The total credit facility commitments remain unchanged at $125.0 million and include a $75.0 million Revolving Facility and a $50.0 million Term Facility. Advances under the Revolving Facility may be repaid from time to time at our option. The Term Facility commitments are available until August 31, 2009 and aggregate borrowings under this facility must exceed $25.0 million at that time. Any undrawn amount under the Term Facility, up to a maximum of $15.0 million, may be reallocated to the Revolving Facility. Beginning September 30, 2009, and at the end of each fiscal quarter thereafter, we must make quarterly payments of principal in an amount equal to 4.375% of the outstanding principal drawn under the Term Facility at August 31, 2009. The credit facility bears interest at the Canadian prime rate, the US dollar base rate, the Canadian bankers’ acceptance rate or the London interbank offered rate (LIBOR) (all such terms as used or defined in the credit facility) plus applicable margins. In each case, the applicable pricing margin depends on our current debt rating. For a discussion on our current debt rating refer to “Debt Ratings” in the Liquidity section of this Management’s Discussion and Analysis.

During the three months ended June 30, 2009, financing fees of $1.1 million were incurred in connection with the modifications to the amended and restated credit agreement. These fees were recorded as an intangible asset and are amortized on a straight-line basis over the remaining term of the agreement.

Included in the amended and restated credit agreement is an option to request an increase to the total revolving credit facility commitments if our requirements for providing letters of credit to our customers exceed $21.0 million. In that event we are permitted to request, on a one-time basis, an increase to the overall revolving credit facility by an amount up to the lesser of $25.0 million or the requested increase to the letters of credit by our customers.

Under the credit agreement, we are required to satisfy certain financial covenants, including an amended minimum interest coverage ratio. The interest coverage covenant is determined based on a ratio of Consolidated EBITDA, as defined within the credit agreement, to consolidated cash interest expense. Measured as of the last day of each fiscal quarter, on a trailing four-quarter basis, the interest coverage ratio shall not be less than 2.0 times at any time up to June 29, 2010 and shall not be less than 2.5 times any time thereafter.

* This paragraph contains forward-looking information. Please refer to “Forward-Looking Information and Risk Factors” for a discussion on the risks and uncertainties related to such information.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

Covenants remaining unchanged in the credit agreement include:

•

The senior leverage covenant, which is determined based on a ratio of senior debt to Consolidated EBITDA, as defined within the credit agreement. Measured as of the last day of each fiscal quarter on a trailing four-quarter basis, the senior leverage ratio shall not exceed 2.0 times.

•

The current ratio covenant is determined based on the ratio of current assets to current liabilities (as defined within the credit agreement). Measured as of the last day of each fiscal quarter, the current ratio shall not be less than 1.25 times.

Consolidated EBITDA is defined within the credit agreement. The amended and restated credit agreement clarifies the definition of Consolidated EBITDA to be the sum, without duplication, of (a) consolidated net income, (b) consolidated interest expense, (c) provision for taxes based on income, (d) total depreciation expense, (e) total amortization expense, (f) costs and expenses incurred by us in entering into the credit facility, (g) accrual of stock-based compensation expense to the extent not paid in cash or if satisfied by the issue of new equity, (h) the non-cash currency translation losses or mark-to-market losses on any hedge agreement (defined in the credit agreement) or any embedded derivative, and (i) other non-cash items including goodwill impairment (other than any such non-cash item to the extent it represents an accrual of or reserve for cash expenditures in any future period) but only, in the case of clauses (b)-(i), to the extent deducted in the calculation of consolidated net income, less (i) the non-cash currency translation gains or mark-to-market gains on any hedge agreement or any embedded derivative to the extent added in the calculation of consolidated net income, and (ii) 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 in conformity with Canadian GAAP. The clarification of the definition of Consolidated EBITDA, in the amended and restated credit agreement, did not change our measurement of Consolidated EBITDA.

The credit facility may be prepaid in whole or in part without penalty, except for bankers’ acceptances, which are not pre-payable prior to their maturity. However, the credit facility requires prepayments under various circumstances, such as: (i) 100% of the net cash proceeds of certain asset dispositions, (ii) 100% of the net cash proceeds from our issuance of equity (unless the use of such securities’ proceeds is otherwise designated by the applicable offering document) and (iii) 100% of all casualty insurance and condemnation proceeds, subject to exceptions. At June 30, 2009 we had an $11.8 M Bankers’ Acceptance outstanding on the Term Facility. This Bankers’ Acceptance matures September 30, 2009, at which time it may be repaid or reissued.

For a complete discussion of our credit facility, see our most recent annual Management’s Discussion and Analysis.

Debt Ratings

Our debt ratings were last assessed in December 2007 by Standard & Poor’s and Moody’s. Standard & Poor’s upgraded our debt rating from the previous rating of “B”. Moody’s maintained the rating of our debt. On June 29, 2009, Standard & Poor’s revised its outlook on our corporate credit rating to ‘negative’ from ‘stable’. At the same time, Standard & Poor’s affirmed its ‘B+’ long-term corporate credit rating and its ‘B+’ senior unsecured debt rating.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

Our corporate credit ratings from these two agencies are as follows:


Standard & Poor’s		B+ (negative outlook)
Moody’s		B2 (stable outlook)

Our 8³/4% senior notes are rated as follows:

Standard & Poor’s		B+ (recovery rating of “4”)
Moody’s		B3 (loss given default rating of “5”)

A credit rating is a current opinion of the credit worthiness of an obligor with respect to a specific financial obligation, a specific class of financial obligations, or a specific financial program (including ratings on medium-term note programs and commercial paper programs). It takes into consideration the creditworthiness of guarantors, insurers, or other forms of credit enhancement on the obligation and takes into account the currency in which the obligation is denominated. The opinion evaluates the obligor’s capacity and willingness to meet its financial commitments as they come due, and may assess terms, such as collateral security and subordination, which could affect ultimate payment in the event of default. The issue credit rating is not a statement of fact or recommendation to purchase, sell, or hold a financial obligation or make any investment decisions nor is it a comment regarding an issuer’s market price or suitability for a particular investor.

A definition of the categories of each rating has been obtained from each respective rating organization’s website as outlined below:

Standard and Poor’s

An obligation rated B is regarded as having speculative characteristics, but the obligor currently has the capacity to meet its financial commitment on the obligation. Adverse business, financial, or economic conditions will likely impair the obligor’s capacity or willingness to meet its financial commitment on the obligation. The ratings from AA to CCC may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories.

A recovery rating of “4” for the 8³/4% senior notes indicates an expectation for an average of 30% to 50% recovery in the event of a payment default.

A Standard & Poor’s rating outlook assesses the potential direction of a long-term credit rating over the intermediate term (typically six months to two years). In determining a rating outlook, consideration is given to any changes in the economic and/or fundamental business conditions. An outlook is not necessarily a precursor of a rating change or future CreditWatch action. A Stable outlook means that a rating is not likely to change.

Moody’s

Obligations rated B are considered speculative and are subject to high credit risk. Moody’s appends numerical modifiers to each generic rating classification from Aa through Caa. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of that generic rating category.

Loss Given Default (LGD) assessments are opinions about expected loss given default on fixed income obligations expressed as a percent of principal and accrued interest at the resolution of the default. An LGD assessment (or rate) is the expected LGD divided by the expected amount of principal and interest due at resolution. A LGD rating of “5” indicates a loss range of greater than or equal to 70% and less than 90%.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

A Moody’s rating outlook is an opinion regarding the likely direction of an issuer’s rating over the medium term. Where assigned, rating outlooks fall into the following four categories: Positive (POS), Negative (NEG), Stable (STA), and Developing (DEV — contingent upon an event). In the few instances where an issuer has multiple ratings with outlooks of differing directions, an “(m)” modifier (indicating multiple, differing outlooks) will be displayed, and Moody’s written research will describe any differences and provide the rationale for these differences. A RUR (Rating(s) Under Review) designation indicates that the issuer has one or more ratings under review for possible change, and thus overrides the outlook designation. When an outlook has not been assigned to an eligible entity, NOO (No Outlook) may be displayed. A Stable outlook means that a rating is not likely to change.

Cash Flow and Capital Resources


	Three Months Ended June 30,
(dollars in thousands)	2009			2008
Cash (used in) provided by operating activities	$	(7,938	)	$	33,014

Cash (used in) investing activities		(19,884	)		(14,332	)

Cash provided by (used in) financing activities		9,215			(548	)

Net (decrease) increase in cash and cash equivalents	$	(18,607	)	$	18,134

Operating activities

Cash provided by operating activities for the three months ended June 30, 2009 was an outflow of $7.9 million, compared to a cash inflow of $33.0 million for the three months ended June 30, 2008. Cash provided by operating activities for three months ended June 30, 2009 was affected by temporary delays in processing change orders and progress payment certificates. We continue to work with our customers to address delays so that we can stay current with change orders and progress payment certificates.

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 equipment additions required to perform larger or a greater number of projects.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

Capital leases, while not considered capital expenditures are restricted under the terms of our credit agreement in the same manner as capital expenditures. Operating leases also are not considered capital expenditures but they are not restricted under the terms of our credit agreement. A summary of equipment additions by nature and by period is shown on the table below:


	Three Months Ended June 30,
(dollars in thousands)	2009		% of Total		2008		% of Total
Capital Expenditures
Sustaining	$	2,161	11	%	$	4,284	7	%
Growth		17,549	89	%		55,065	93	%

Total	$	19,710	100	%	$	59,349	100	%
Capital Leases
Sustaining	$	—	0	%	$	154	13	%
Growth		624	100	%		1,010	87	%

Total	$	624	100	%	$	1,164	100	%

Operating Leases	$	5,608			$	21,263

For the three months ended June 30, 2009, the reduction in sustaining capital expenditures compared to the same period in the prior year is reflective of the timing of equipment replacement, due to lower volumes. The $37.9 million decrease in growth capital additions for the three months ended June 30, 2009 compared to the same period in the previous year reflects the timing of the scheduled equipment additions related to the Canadian Natural overburden project year-over-year and the effect of the slowdown in the economy on development project revenues that require growth capital. The tightening capital market has had a negative effect on the cost to finance equipment additions through operating leases for the current period.

Proceeds from asset disposals for the three months ended June 30, 2009 of $1.1 million and net outflow from non-cash working capital of $1.3 million lessened the effect of capital purchases. Net investment activities, as shown in our Balance Sheet, were an outflow of $19.9 million for the three months ended June 30, 2009, compared with an outflow of $14.3 million for the same period a year ago.

Financing activities

Financing activities during the three-month period ended June 30, 2009 resulted in a cash inflow of $9.2 million due to the $11.8 million financing of capital expenditures through our new term credit facility, partially offset by the repayment of capital lease obligations and financing costs for our amended and restated credit agreement. Cash outflow for the three-month period ended June 30, 2008 of $0.5 million was a result of a $1.2 million repayment of capital lease obligations offset by the proceeds received on the exercise of stock options.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

Capital Commitments

Contractual Obligations and Other Commitments

Our principal contractual obligations relate to our long-term debt, capital and operating leases and supplier contracts. The following table summarizes our future contractual obligations, excluding interest payments, unless otherwise noted, as of June 30, 2009.


	Payments due by fiscal year
(dollars in thousands)	Total		2010		2011		2012		2013		2014 and after
Senior notes⁽¹⁾	$	263,000	$	—	$	—	$	263,000	$	—	$	—
Term Facility		11,800		1,549		2,065		8,186		—		—
Capital leases (including interest)		18,488		4,853		5,589		4,988		2,732		326
Operating leases		153,569		38,430		43,122		34,156		20,800		17,061
Supplier contracts		29,944		4,623		8,178		9,796		7,347		—

Total contractual obligations	$	476,801	$	49,455	$	58,954	$	320,126	$	30,879	$	17,387

⁽¹⁾

We have entered into cross-currency and interest rate swaps, which represent an economic hedge of the 8³/4% senior notes (see “Interest rate risk” in Quantitative and Qualitative Disclosures about Market Risk regarding the cancellation of the US dollar interest rate swap effective February 2, 2009). 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 date of the swap contracts. At June 30, 2009, the carrying value of the derivative financial instruments was $53.1 million, inclusive of the interest components.

Off-Balance Sheet Arrangements

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

Related Parties

We may receive consulting and advisory services provided by the principals or employees of companies owned or operated by certain of our directors (the Sponsors) with respect to the organization of our employee benefit and compensation arrangements, and other matters, and no fee is charged for these consulting and advisory services.

In order for the Sponsors to provide such advice and consulting, we provide the Sponsors with reports, financial data and other information. This permits them to consult with and advise our management on matters relating to our operations, company affairs and finances. In addition, this permits them to visit and inspect any of our properties and facilities. These services are provided in the normal course of operations and are measured at the value of consideration established and agreed to by the related parties.

Internal Systems and Processes

Overview of information systems

We currently use JDE (Enterprise One) as our Enterprise Resource Planning (ERP) tool and deploy the financial system, payroll, procurement, job-costing and equipment maintenance modules from this tool. We supplement this functionality with either third-party software (for our estimating system) or in-house developed tools (for project management).

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

The proper identification of costs is a critical part of our ability to recognize revenues and provide accurate management information for decision-making. We continue to focus resources to address this in our ERP system through the automation of transactional activities. We continue to work on improving the process for tracking and reporting equipment and maintenance costs. We have seen some improvements in the identification and tracking of our procurement costs.

During the year ended March 31, 2009, we completed a user-needs analysis and compared this to the functionality of our ERP system. As part of this analysis, we determined if we could implement additional modules in JDE or whether we needed to commence a review of industry-specific software to supplement our existing ERP functionality. We have started plans for the implementation of specific JDE modules based on this analysis.

Evaluation of Disclosure Controls and Procedures

Management has evaluated whether there were changes in our internal controls over financial reporting (ICFR) during the three month period ended June 30, 2009 that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting. No material changes were identified.

As of March 31, 2009, we assessed the effectiveness of the Company’s ICFR. In making this assessment, we used the criteria set forth in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). During this process we identified a material weakness in internal controls over financial reporting described below and as a result we concluded that the Company’s ICFR is ineffective as of March 31, 2009.

We did not maintain effective processes and controls specific to revenue recognition. We did not effectively develop, communicate and implement an appropriate revenue recognition policy, a formal process to track claims and unapproved change orders and sufficient monitoring controls over the completeness and accuracy of forecasts, including the consideration of project changes subsequent to the end of each reporting period. The accounts that could be affected by these deficiencies are revenue, project costs, unbilled revenue and billings in excess of costs incurred and estimated earnings on uncompleted contracts. This material weakness in ICFR, which is pervasive in nature, resulted in material errors in the financial statements that were corrected prior to release of the financial statements. Further, there is a reasonable possibility that a material misstatement of our financial statements will not be prevented or detected on a timely basis.

In response to the material weakness identified above, during the three months ended and subsequent to March 31, 2009, we formalized our revenue recognition policy to assist in the understanding and consistent application of GAAP, initiated the development of a procedural manual to assist with applying the revenue recognition policy, designed new process-level controls and conducted staff training. As of June 30, 2009, progress has been made on our remediation plans but this material weakness has not been fully remediated. We will evaluate the effectiveness of these controls during the balance of the fiscal year to determine if they adequately address our ability to recognize revenue in accordance with GAAP. For a discussion of the risks associated with such weakness, please see our most recent annual Management’s Discussion and Analysis.

Significant Accounting Policies

In our audited consolidated financial statements for the year ended March 31, 2009 and our most recent annual Management’s Discussion and Analysis we have identified the accounting policies and estimates that are critical to the understanding of our business operations and our results of operations. For the three months ended June 30, 2009, there are no changes to the critical accounting polices and estimates.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

Recently Adopted Canadian Accounting Pronouncements

Goodwill and Intangible Assets

In February 2008, the CICA issued Handbook Section 3064, “Goodwill and Intangible Assets”, which replaces Section 3062, Goodwill and Other Intangible Assets, and Section 3450, Research and Development Costs and establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The provisions relating to the definition and initial recognition of intangible assets, including internally generated intangible assets, are equivalent to the corresponding provisions of International Accounting Standard IAS 38, Intangible Assets. This new standard is effective for our interim and annual consolidated financial statements commencing April 1, 2009. The adoption of this standard did not have a material impact on our interim consolidated financial statements.

Recent Canadian Accounting Pronouncements Not Yet Adopted

Business combinations

In January 2009, the CICA issued Handbook Section 1582, “Business Combinations”, which replaces the existing standard. This section establishes standards for the accounting of business combinations, and states that all assets and liabilities of an acquired business will be recorded at fair value. Obligations for contingent considerations and contingencies will also be recorded at fair value at the acquisition date. The standard also states that acquisition related costs will be expensed as incurred, that restructuring charges will be expensed in the periods after the acquisition date and that non-controlling interest should be measured at fair value at the date of acquisition. This standard is equivalent to International Financial Reporting Standards on business combinations. This standard is to be applied prospectively to business combinations with acquisition dates on or after January 1, 2011 and earlier adoption is permitted. We are currently evaluating the impact of this standard.

Consolidated financial statements

In January 2009, the CICA issued Handbook Section 1601, “Consolidated Financial Statements”, which replaces CICA 1600 — Consolidated Financial Statements. This Section carries forward existing Canadian guidance for preparing consolidated financial statements other than guidance for non-controlling interests. This standard is effective for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011 and earlier adoption is permitted. We are currently evaluating the impact of this standard.

Non-controlling interests

In January 2009, the CICA issued Handbook Section 1602, “Non-Controlling Interests”, which establishes standards for the accounting of non-controlling interests of a subsidiary in the preparation of consolidated financial statements subsequent to a business combination. This standard is equivalent to International Financial Reporting Standards on consolidated and separate financial statements. This standard is effective for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011 and earlier adoption is permitted. We are currently evaluating the impact of this standard.

Accounting changes

In June 2009, the CICA amended Handbook Section 1506, “Accounting Changes”, to exclude from its scope changes in accounting policies arising from the complete replacement of an entity’s primary basis of accounting. The amendment applies to interim and annual financial statements relating to fiscal years beginning on or after July 1, 2009. 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, 2009

Financial Instruments — Recognition and Measurement

In June 2009, the CICA amended Handbook Section 3855, “Financial Instruments — Recognition and Measurement” to clarify the application of the effective interest method after a debt instrument has been impaired. The Section has also been amended to clarify when an embedded prepayment option is separated from its host debt instrument for accounting purposes. The amendments apply to interim and annual financial statements relating to fiscal years beginning on or after May 1, 2009 for the amendments relating to the effective interest method and on or after January 1, 2011 for the amendments relating to embedded prepayment options. We are currently evaluating the impact of the amendments.

Financial Instruments — Disclosures

In June 2009, the CICA amended Handbook Section 3862, “Financial Instruments- Disclosures” to include additional disclosure requirements about fair value measurements of financial instruments and to enhance liquidity risk disclosure requirements. The amendments apply to annual financial statements relating to fiscal years ending after September 30, 2009. We are currently evaluating the impact of the amendments to the standard.

Transition To International Financial Reporting Standards (IFRS)

In February 2008, the AcSB confirmed that IFRS will be mandatory in Canada for profit-oriented publicly accountable entities for fiscal periods beginning on or after January 1, 2011, unless, as permitted by Canadian securities regulations, we were to adopt US GAAP on or before this date. Should we decide to adopt IFRS, our first annual IFRS financial statements would be for the year ending March 31, 2012 and would include the comparative period of the year ending March 31, 2011. Starting for the three months ending June 30, 2011, we would provide unaudited consolidated financial statements in accordance with IFRS including comparative figures for the three-month period ending June 30, 2010.

We have completed a preliminary analysis of the accounting and reporting differences under IFRS, Canadian GAAP and US GAAP, however, we have not yet finalized our determination of these differences on our consolidated financial statements. This analysis will, in part, determine whether we adopt IFRS or US GAAP once Canadian GAAP ceases to exist. We are also closely monitoring standard-setting activity and regulatory developments in Canada, the United States and internationally that may affect the timing of our adoption of either IFRS or US GAAP in future periods.

G. FORWARD-LOOKING INFORMATION AND RISK FACTORS

Forward-Looking Information

This document contains forward-looking information that is based on expectations and estimates as of the date of this document. Our forward-looking information is information that is 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 information. Forward-looking information is information that does not relate strictly to historical or current facts, and can be identified by the

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

use of the future tense or other forward-looking words such as “believe”, “expect”, “anticipate”, “intend”, “plan”, “estimate”, “should”, “may”, “could”, “would”, “target”, “objective”, “projection”, “forecast”, “continue”, “strategy”, “intend”, “position” or the negative of those terms or other variations of them or comparable terminology.

Examples of such forward-looking information in this document include, but are not limited to, statements with respect to the following, each of which is subject to significant risks and uncertainties and is based on a number of assumptions which may prove to be incorrect:

(a)

the amount of our backlog expected to be performed and realized in the twelve months ending June 30, 2010;

(b)

that our expectations for the second quarter of fiscal 2010 will remain cautious;

(c)

the new TransCanada Pipeline project gives our pipeline operations a steady workload between larger projects;

(d)

the announced merger between Suncor and Petro-Canada will have a positive impact on oil sands investment;

(e)

we will experience continued sustainable growth in the services we provide to Canadian Natural;

(f)

we will experience more stability in our recurring revenue as the result of our recently signed a three-year services agreement with Shell Albian Sands’ Muskeg River Mine;

(g)

that reductions in project costs and gradual strengthening of oil prices are creating a more attractive environment for investment;

(h)

the demand for our recurring oil sands services will see the resumption of growth in the second half of fiscal 2010 and the return of volumes on the Horizon project over the next six months;

(i)

demand for recurring services over the longer-term will remain largely unaffected by changes in oil prices;

(j)

demand for recurring services will grow as new mines come on-line and maturing mines expand their geographical footprint;

(k)

the expected benefits to our Piling division from the announced federal and provincial government spending in Ontario;

(l)

the expected agreement between our employees party to the collective bargaining agreement which expired February 28, 2009 and us;

(m)

our operating and lease facilities and cash flow from operations will be sufficient to meet our capital requirements;

(n)

we will generate a net cash surplus through September 30, 2009; and

(o)

any additional funding required by us will be satisfied by the credit facility.

Some of the risks and other factors which could cause results to differ materially from those expressed in the forward-looking information contained in this Management’s Discussion and Analysis include, but are not limited to:

The forward-looking information in paragraphs (a), (b), (c), (d), (e), (f), (g), (h), (i), (k), (m), (n) and (o) rely on certain market conditions and demand for our services and are based on the assumptions that: despite the slow

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

down in the global economy and tightening of credit conditions combined with short term declines in oil prices, which will slow capital development of Canada’s natural resources, in particular the oil sands, we still expect to see strong demand for our recurring services as the oil sands continue to be an economically viable source of energy, our customers and potential customers continue to invest in the oil sands and other natural resources developments; our customers and potential customers will continue to outsource the type of activities for which we are capable of providing service; and the Western Canadian economy continues to develop with additional investment in public construction; and are subject to the following risks and uncertainties that:

•

anticipated new major capital projects in the oil sands may not materialize;

•

demand for our services may be adversely impacted by regulations affecting the energy industry;

•

failure by our customers to obtain required permits and licenses may affect the demand for our services;

•

changes in our customers’ perception of oil prices over the long-term could cause our customers to defer, reduce or stop their capital investment in oil sands projects, which would, in turn, reduce our revenue from those customers;

•

reduced financing as a result of the tightening credit markets may affect our customers’ decisions to invest in infrastructure projects;

•

insufficient pipeline, upgrading and refining capacity or lack of sufficient governmental infrastructure to support growth in the oil sands region could cause our customers to delay, reduce or cancel plans to construct new oil sands projects or expand existing projects, which would, in turn, reduce our revenue from those customers;

•

a change in strategy by our customers to reduce outsourcing could adversely affect our results;

•

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

•

because most of our customers are Canadian energy companies, a further downturn in the Canadian energy industry could result in a decrease in the demand for our services;

•

shortages of qualified personnel or significant labour disputes could adversely affect our business; and

•

unanticipated short term shutdowns of our customers’ operating facilities may result in temporary cessation or cancellation of projects in which we are participating.

The forward-looking information in paragraphs (a), (b), (c), (e), (f), (g), (h), (i), (j), (k), (l), (m), (n) and (o) rely on our ability to execute our growth strategy and are based on the assumptions that the management team can successfully manage the business; we can maintain and develop our relationships with our current customers; we will be successful in developing relationships with new customers; we will be successful in the competitive bidding process to secure new projects; we will identify and implement improvements in our maintenance and fleet management practices; we will be able to benefit from increased recurring revenue base tied to the operational activities of the oil sands; we will be able to access sufficient funds to finance our capital growth; and are subject to the risks and uncertainties that:

•

continued reduced demand for oil and other commodities as a result of slowing market conditions in the global economy may result in reduced oil production and a further decline in oil prices;

•

if we are unable to obtain surety bonds or letters of credit required by some of our customers, our business could be impaired;

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

•

we are dependent on our ability to lease equipment, and a tightening of this form of credit could adversely affect our ability to bid for new work and/or supply some of our existing contracts;

•

our business is highly competitive and competitors may outbid us on major projects that are awarded based on bid proposals;

•

our customer base is concentrated, and the loss of or a significant reduction in business from a major customer could adversely impact our financial condition;

•

lump-sum and unit-price contracts expose us to losses when our estimates of project costs are lower than actual costs;

•

our operations are subject to weather-related factors that may cause delays in our project work; and

•

environmental laws and regulations may expose us to liability arising out of our operations or the operations of our customers.

While we anticipate that subsequent events and developments may cause our views to change, we do not have an intention to update this forward-looking information, except as required by applicable securities laws. This forward-looking information represents our views as of the date of this document and such information should not be relied upon as representing our views as of any date subsequent to the date of this document. We have attempted to identify important factors that could cause actual results, performance or achievements to vary from those current expectations or estimates expressed or implied by the forward-looking information. However, there may be other factors that cause results, performance or achievements not to be as expected or estimated and that could cause actual results, performance or achievements to differ materially from current expectations. There can be no assurance that forward-looking information will prove to be accurate, as actual results and future events could differ materially from those expected or estimated in such statements. Accordingly, readers should not place undue reliance on forward-looking information. These factors are not intended to represent a complete list of the factors that could affect us. See “Risk Factors” below and risk factors highlighted in materials filed with the securities regulatory authorities filed in the United States and Canada from time to time, including, but not limited to, our most recent Annual Information Form.

Risk Factors

For the three months ended June 30, 2009, other than noted below, there has been no significant change in our risk factors discussed in our most recent annual Management’s Discussion and Analysis, which was current as of June 9, 2009. The risk factors discussed in our most recent annual Management’s Discussion and Analysis should be reviewed in conjunction with this interim Management’s Discussion and Analysis. Significant developments since June 9, 2009 are as follows:

Availability or increased cost of leasing

A portion of our equipment fleet is currently leased from third parties. Further, we anticipate leasing substantial amounts of equipment to meet equipment acquisition commitments related to our long-term overburden removal contract in the upcoming year. Other future projects may require us to lease additional equipment. If equipment lessors are unable or unwilling to provide us with reasonable lease terms within our expectations, it will significantly increase the cost of leasing equipment or may result in more restrictive lease terms that require recognition of the lease as a capital lease. To mitigate this risk, we have secured an increased leasing facility with one of our existing equipment lessors, expanding our leasing capacity by approximately 30%. Our current lease commitments with this supplier now represent 80% of the total capacity available. We are actively pursuing new lessor relationships to dilute our exposure to the loss of one or more of our lessors.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

A change in strategy by our customers to reduce outsourcing could adversely affect our results.

Outsourced Heavy Construction and Mining services constitute a large portion of the work we perform for our customers. For example, our mining and site preparation project revenues constituted approximately 74%, 63% and 75% of our revenues in each of fiscal years 2009, 2008 and 2007, respectively. The election by one or more of our customers to perform some or all of these services themselves, rather than outsourcing the work to us, could have a material adverse impact on our business and results of operations. Certain customers perform some of this work internally and may choose to expand on the use of internal resources to complete this work. Additionally, the recent tightening of the credit market and worldwide economic downturn may result in our customers reducing their spending on outsourced mining and site preparation services if they believe they can perform this work in a more cost effective and efficient manner using their internal resources.

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

We intend to pursue selective acquisitions as a method of expanding our business. However, we may not be able to identify or successfully bid on businesses that we might find attractive. If we do find attractive acquisition opportunities, we might not be able to acquire these businesses at a reasonable price. If we do acquire other businesses, we might not be able to successfully integrate these businesses into our then-existing business. We might not be able to maintain the levels of operating efficiency that acquired companies will have achieved or might achieve separately. Successful integration of acquired operations will depend upon our ability to manage those operations and to eliminate redundant and excess costs. Because of difficulties in combining operations, we may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve through these acquisitions. Any of these factors could harm our financial condition and results of operations.

Quantitative and Qualitative Disclosures about Market Risk

Foreign exchange risk

Foreign exchange risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to changes in foreign exchange rates. We have 8³/4% senior notes denominated in US dollars in the amount of US$200.0 million. In order to reduce our exposure to changes in the United States to Canadian dollar exchange rate, we entered into a cross-currency swap agreement to manage this foreign currency exposure for both the principal balance due on December 1, 2011 as well as the semi-annual interest payments from the issue date to the maturity date. In conjunction with the cross-currency swap agreement, we also entered into a US dollar interest rate swap and a Canadian dollar interest rate swap. These derivative financial instruments were not designated as hedges for accounting purposes. At June 30, 2009 and March 31, 2009, the notional principal amount of the cross-currency swap was US$200.0 million and Canadian $263.0 million.

On December 17, 2008, we received notice that all three swap counterparties had exercised the cancellation option on the US dollar interest rate swap and, effective February 2, 2009, the US dollar interest rate swap was terminated.

Our Canadian dollar interest rate swap and cross-currency swap agreements are not cancellable at the option of the counterparties and remain in effect. We will continue to pay the counterparties an average fixed rate of 9.889% on the notional amount of Canadian $263.0 million or Canadian $13.0 million semi-annually until December 1, 2011. Beginning March 1, 2009, we received quarterly floating rate payments in US dollars on the cross-currency swap agreement at the prevailing three-month US LIBOR rate plus a spread of 4.2% on the notional amount of US$200.0 million.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

As a result of the cancellation of the US dollar interest rate swap, we are exposed to changes in the value of the Canadian dollar versus the US dollar. To the extent that the three-month US LIBOR rate is less than 4.6% (the difference between the 8³/4% senior notes coupon and the 4.2% spread over three-month US LIBOR on the cross-currency swap agreement), we will have to acquire US dollars to fund a portion of our semi-annual coupon payment on our 8³/ 4% senior notes. At the three-month US LIBOR rate of 0.621% at June 30, 2009, a $0.01 increase (decrease) in exchange rates in the Canadian dollar would result in an insignificant decrease (increase) in the amount of Canadian dollars required to fund each semi-annual coupon payment.

We also regularly transact in foreign currencies when purchasing equipment, spare parts as well as certain general and administrative goods and services. These exposures are generally of a short-term nature and the impact of changes in exchange rates has not been significant in the past. We may fix our exposure in either the Canadian dollar or the US dollar for these short-term transactions, if material.

At June 30, 2009, with other variables unchanged, a $0.01 increase (decrease) in exchange rates of the Canadian dollar to the US dollar related to the US dollar denominated 8³/4% senior notes would decrease (increase) net income and decrease (increase) equity by approximately $1.7 million. With other variables unchanged, a $0.01 increase (decrease) in exchange rates in the Canadian to the US dollar related to the cross-currency swap would increase (decrease) net income and increase (decrease) equity by approximately $1.7 million. The impact of similar exchange rate changes on short-term exposures would be insignificant and there would be no impact to other comprehensive income.

Interest rate risk

We are exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of our financial instruments. Amounts outstanding under our amended credit facilities are subject to a floating rate. Our senior notes are subject to a fixed rate. Our interest risk arises from long-term borrowings issued at fixed rates that create fair value interest rate risk and variable borrowings that create cash flow interest rate risk. Changes in market interest rates cause the fair value of long-term debt with fixed interest rates to fluctuate but do not affect earnings, as our debt is carried at amortized cost and the carrying value does not change as interest rates change.

In some circumstances, floating rate funding may be used for short-term borrowings and other liquidity requirements. We may use derivative instruments to manage interest rate risk. We manage our interest rate risk exposure by using a mix of fixed and variable rate debt and may use derivative instruments to achieve the desired proportion of variable to fixed-rate debt.

We also entered into a US dollar interest rate swap and a Canadian dollar interest rate swap with the net effect of economically converting the 8.75% rate payable on the 8³/4% senior notes into a fixed rate of 9.889% for the duration that the 8³/4 % senior notes are outstanding. These derivative financial instruments were not designated as hedges for accounting purposes. As a result of the US dollar interest swap cancellation, we are exposed to changes in interest rates. We have a fixed semi-annual coupon payment of 8³/4% on our US$200.0 million Senior Notes. With the termination of the US dollar interest rate swap, we will no longer receive fixed US dollar payments from the counterparties to offset the coupon payment on our 8³/4% senior notes. As a result of this termination, our annual interest expense at the current US LIBOR rate of 0.621% will increase US$7.9 million. In addition, we are now exposed to interest rate risk where a 100 basis point increase (decrease) in the 3-month US LIBOR rate will result in a US$2.0 million decrease (increase) in annual interest expense.

At June 30, 2009 and March 31, 2009, the notional principal amounts of the interest rate swaps were US$200.0 million and Canadian $263.0 million.

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three months ended June 30, 2009

As at June 30, 2009, holding all other variables constant, a 100 basis point increase (decrease) to Canadian interest rates would impact the fair value of the interest rate swaps by $4.3 million with this change in fair value being recorded in net income. As at June 30, 2009, holding all other variables constant, a 100 basis point increase (decrease) to U.S. interest rates would impact the fair value of the interest rate swaps by $0.2 million, net of tax, with this change in fair value being recorded in net income. As at June 30, 2009, holding all other variables constant, a 100 basis point increase (decrease) of Canadian to U.S. interest rate volatility would impact the fair value of the interest rate swaps by $nil million with this change in fair value being recorded in net income.

At June 30, 2009, we held $11.8 million of floating rate debt pertaining to our term facility within our amended and restated credit facility (March 31, 2009 — $nil). As at June 30, 2009, holding all other variables constant, a 100 basis point increase (decrease) to interest rates on floating rate debt would not have a significant impact on net income or equity. This assumes that the amount of floating rate debt remains unchanged from that which was held at June 30, 2009.

H. GENERAL MATTERS

Our head office is located at Zone 3, Acheson Industrial Area, #2, 53016 Hwy 60, Acheson, Alberta, T7X 5A7. Our telephone and facsimile numbers are 780-960-7171 and 780-960-7103, respectively.

We maintain an executive office, located at Suite 2400, 500 4^th Avenue SW, Calgary, Alberta, T2P 2V6. Our executive office telephone and facsimile numbers are 403-767-4825 and 403-767-4849, respectively.

Additional Information

Additional information relating to us, including our Annual Information Form dated June 9, 2009, can be found on the Canadian Securities Administrators System for Electronic Document Analysis and Retrieval (SEDAR) database at www.sedar.com and the Securities and Exchange Commission’s website at www.sec.gov.

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

I, Rodney J. Ruston, the Chief Executive Officer of North American Energy Partners Inc., certify the following:

1.	*Review:* I have reviewed the interim financial statements and interim MD&A (together, the “interim filings”) of North American Partners Inc. (the “issuer”) for the interim period ended June 30, 2009.

No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial statements together with the other financial information included in the interim filings fairly present in all material respects the financial condition, results of operations and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

5.	*Design:* Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

(a)

designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

(i)

material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

(ii)

information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

(b)

designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

5.1	*Control framework:* The control frameworks the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR are as follows:

(a)

the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework; and

(b)

the Control Objectives for Information and related Technology (“COBIT”) framework created by the Information Systems Audit and Control Association and the IT Governance Institute.

5.2	*ICFR – material weakness relating to design:* The issuer has disclosed in its interim MD&A for each material weakness relating to design existing at the end of the interim period

(a)

a description of the material weakness;

(b)

the impact of the material weakness on the issuer’s financial reporting and its ICFR; and

(c)

the issuer’s current plans, if any, or any actions already undertaken, for remediating the material weakness.

5.3	Limitation on scope of design: N/A

6.	*Reporting changes in ICFR:* The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on April 1, 2009 and ended on June 30, 2009 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date:August 4, 2009

/s/ Rodney J. Ruston

Chief Executive Officer

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

I, David Blackley, the Chief Financial Officer of North American Energy Partners Inc., certify the following:

1.	*Review:* I have reviewed the interim financial statements and interim MD&A (together, the “interim filings”) of North American Partners Inc. (the “issuer”) for the interim period ended June 30, 2009.

5.	*Design:* Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

(a)

designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

(i)

material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

(ii)

(b)

5.1	*Control framework:* The control frameworks the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR are as follows:

(a)

the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework; and

(b)

the Control Objectives for Information and related Technology (“COBIT”) framework created by the Information Systems Audit and Control Association and the IT Governance Institute.

5.2	*ICFR – material weakness relating to design:* The issuer has disclosed in its interim MD&A for each material weakness relating to design existing at the end of the interim period

(a)

a description of the material weakness;

(b)

the impact of the material weakness on the issuer’s financial reporting and its ICFR; and

(c)

the issuer’s current plans, if any, or any actions already undertaken, for remediating the material weakness.

5.3	Limitation on scope of design: N/A

6.	*Reporting changes in ICFR:* The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on April 1, 2009 and ended on June 30, 2009 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date:August 4, 2009

/s/ David Blackley

Chief Financial Officer