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 November 2010

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 and six months ended September 30, 2010.

2.	Management’s Discussion and Analysis for the three and six months ended September 30, 2010.

3.	Canadian Supplement to Management’s Discussion and Analysis for the three and six months ended September 30, 2010.

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: November 2, 2010

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

(Expressed in thousands of Canadian Dollars)

(Unaudited)

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Interim Consolidated Balance Sheets

(Expressed in thousands of Canadian Dollars)

(Unaudited)


	September 30, 2010			March 31, 2010
ASSETS
Current assets:
Cash and cash equivalents		$56,180			$103,005
Accounts receivable, net (allowance for doubtful accounts of $236, March 2010 – $1,691)		101,525			111,884
Unbilled revenue		137,197			84,702
Inventories (note 5)		4,906			3,047
Prepaid expenses and deposits		10,511			6,881
Deferred tax assets		2,785			3,481

		313,104			313,000
Prepaid expenses and deposits		3,214			4,005
Assets held for sale		2,233			838
Property, plant and equipment (note 6)		331,314			331,355
Investment in and advances to unconsolidated joint venture (note 7)		3,691			2,917
Intangible assets, net (accumulated amortization of $5,850 March 2010 – $4,591)		8,433			7,669
Goodwill		25,111			25,111
Deferred financing costs (note 8)		8,398			6,725
Deferred tax assets		44,109			10,997

		$739,607			$702,617

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$106,231			$66,876
Accrued liabilities		33,475			47,191
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		4,024			1,614
Current portion of capital lease obligations		4,416			5,053
Current portion of term facilities (note 9(a))		14,000			6,072
Current portion of derivative financial instruments (note 12)		2,743			22,054
Deferred tax liabilities		31,435			16,781

		196,324			165,641
Long term accrued liabilities		16,625			14,943
Capital lease obligations		6,212			8,340
Deferred lease inducements		707			761
Term facilities (note 9(a))		59,446			22,374
8³/4% senior notes (note 9(b))		–			203,120
Series 1 debentures (note 9(c))		225,000			–
Derivative financial instruments (note 12)		12,790			75,001
Other long term obligations (note 15(a))		7,547			3,578
Asset retirement obligation		377			360
Deferred tax liabilities		42,199			27,441

		567,227			521,559
Shareholders’ equity:
Common shares (authorized – unlimited number of voting common shares; issued and outstanding – September 30, 2010 – 36,110,436 (March 31, 2010 – 36,049,276) (note 10(a))		303,927			303,505
Additional paid-in capital		6,279			7,439
Deficit		(137,826	)		(129,886	)

		172,380			181,058

		$739,607			$702,617

Subsequent events (note 19)
See accompanying notes to unaudited interim consolidated financial statements.

2 Financial Statements North American Energy Partners Inc.

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Interim Consolidated Statements of Operations and Comprehensive Income (Loss)

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

(Unaudited)


	Three Months Ended September 30,						Six Months Ended September 30,
	2010			2009			2010			2009
Revenue		$234,858			$170,702			$418,452			$317,221
Project costs		132,440			65,437			209,717			119,699
Equipment costs		46,358			44,359			111,361			90,403
Equipment operating lease expense		18,909			15,684			36,400			28,033
Depreciation		8,054			11,426			16,257			20,150

Gross profit		29,097			33,796			44,717			58,936
General and administrative costs		15,286			13,918			29,015			28,894
Loss on disposal of property, plant and equipment		585			260			581			301
(Gain) loss on disposal of assets held for sale		(25	)		41			(25	)		(276	)
Amortization of intangible assets		672			417			1,260			910
Equity in loss of unconsolidated joint venture (note 7)		274			223			517			32

Operating income before the undernoted		12,305			18,937			13,369			29,075
Interest expense, net (note 11)		7,708			6,409			15,437			12,961
Foreign exchange loss (gain)		49			(18,045	)		(1,648	)		(37,481	)
Realized and unrealized (gain) loss on derivative financial instruments (note 12)		(1,308	)		25,154			1,700			35,175
Loss on debt extinguishment (note 8 and 9(b))		–			–			4,346			–
Other (income) expense		(9	)		(200	)		(9	)		333

Income (loss) before income taxes		5,865			5,619			(6,457	)		18,087
Income taxes (benefit) (note 13(c)):
Current		3,259			1,264			4,487			1,264
Deferred		237			56			(3,004	)		2,597

Net income (loss) and comprehensive income (loss) for the period		2,369			4,299			(7,940	)		14,226

Net income (loss) per share – basic (note 10(b))		$0.07			$0.12			$(0.22	)		$0.39

Net income (loss) per share – diluted (note 10(b))		$0.06			$0.12			$(0.22	)		$0.39

See accompanying notes to unaudited interim consolidated financial statements.

North American Energy Partners Inc. Financial Statements 3

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Interim Consolidated Statements of Changes in Shareholders’ Equity

(Expressed in thousands of Canadian Dollars)

(Unaudited)


	Common shares		Additional paid-in capital			Deficit			Total
Balance at March 31, 2008		$301,894		$4,351			$(22,701	)		$283,544
Net loss		–		–			(135,404	)		(135,404	)
Share option plan		–		1,888			–			1,888
Deferred performance share unit plan		–		61			–			61
Reclassification on exercise of stock options		834		(834	)		–			–
Issued upon exercise of stock options		703		–			–			703

Balance at March 31, 2009		$303,431		$5,466			$(158,105	)		$150,792
Net income		–		–			28,219			28,219
Share option plan		–		2,135			–			2,135
Deferred performance share unit plan		–		123			–			123
Reclassified to restricted share unit liability		–		(20	)		–			(20	)
Reclassification on exercise of stock options		21		(21	)		–			–
Cash settlement of stock options		–		(244	)		–			(244	)
Issued upon exercise of stock options		53		–			–			53

Balance at March 31, 2010		$303,505		$7,439			$(129,886	)		$181,058
Net loss		–		–			(7,940	)		(7,940	)
Share option plan		–		757			–			757
Deferred performance share unit plan		–		(87	)		–			(87	)
Stock award plan		–		524			–			524
Reclassification on exercise of stock options		117		(117	)		–			–
Issued upon exercise of stock options		305		–			–			305
Senior executive stock options plan		–		(2,237	)		–			(2,237	)

Balance at September 30, 2010		$303,927		$6,279			$(137,826)			$172,380

See accompanying notes to unaudited interim consolidated financial statements.

4 Financial Statements North American Energy Partners Inc.

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Interim Consolidated Statements of Cash Flows

(Expressed in thousands of Canadian Dollars)

(Unaudited)


	Three Months Ended September 30,						Six Months Ended September 30,
Cash provided by (used in):	2010			2009			2010			2009
Operating activities:
Net income (loss) for the period		$2,369			$4,299			$(7,940	)		$14,226
Items not affecting cash:
Depreciation		8,054			11,426			16,257			20,150
Equity in loss of unconsolidated joint venture		274			223			517			32
Amortization of intangible assets		672			417			1,260			910
Amortization of deferred lease inducements		(27	)		(35	)		(54	)		(61	)
Amortization of deferred financing costs		357			838			883			1,643
Loss on disposal of property, plant and equipment		585			260			581			301
(Gain) loss on disposal of assets held for sale		(25	)		41			(25	)		(276	)
Unrealized foreign exchange gain on 8³/4% senior notes		–			(18,060	)		(732	)		(37,600	)
Unrealized (gain) loss on derivative financial instruments measured at fair value		(1,308	)		21,290			1,700			27,975
Loss on debt extinguishment		–			–			4,346			–
Stock-based compensation expense (note 15(a))		2,087			632			2,926			2,449
Accretion of asset retirement obligation		9			(21	)		17			(12	)
Deferred income taxes (benefit)		237			56			(3,004	)		2,597
Net changes in non-cash working capital (note 13(b))		(16,496	)		2,364			(4,140	)		(16,326	)

		(3,212	)		23,730			12,592			16,008

Investing activities:
Acquisition		–			(4,880	)		–			(4,880	)
Purchase of property, plant and equipment		(10,759	)		(23,239	)		(16,777	)		(42,460	)
Addition to intangible assets		(1,453	)		(316	)		(2,024	)		(805	)
Additions to assets held for sale		(1,703	)		(933	)		(1,703	)		(933	)
Investment in and advances to unconsolidated joint venture (note 7)		(750	)		(486	)		(1,291	)		(986	)
Proceeds on disposal of property, plant and equipment		–			558			60			696
Proceeds on disposal of assets held for sale		300			152			300			1,112
Net changes in non-cash working capital (note 13(b))		(1,252	)		3,919			(4,020	)		2,647

		(15,617	)		(25,225	)		(25,455	)		(45,609	)

Financing activities:
Repayment of term facilities		(2,500	)		(652	)		(5,000	)		(652	)
Increase in term facilities		–			21,200			50,000			33,000
Financing costs (note 9(a) and 9(c))		(216	)		(8	)		(7,920	)		(1,123	)
Redemption of 8³/4% senior notes (note 9(b))		–			–			(202,410	)		–
Issuance of series 1 debentures (note 9(c))		–			–			225,000			–
Settlement of swap liabilities (note 12)		–			–			(91,125	)		–
Cash settlement of stock options		–			(66	)		–			(66	)
Proceeds from stock options exercised		241			–			305			–
Repayment of capital lease obligations		(1,384	)		(1,477	)		(2,812	)		(2,947	)

		(3,859	)		18,997			(33,962	)		28,212

(Decrease) increase in cash and cash equivalents		(22,688	)		17,502			(46,825	)		(1,389	)
Cash and cash equivalents, beginning of period		78,868			79,989			103,005			98,880

Cash and cash equivalents, end of period		$56,180			$97,491			$56,180			$97,491

Supplemental cash flow information (note 13(a))

See accompanying notes to unaudited interim consolidated financial statements.

North American Energy Partners Inc. Financial Statements 5

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

(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., 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, industrial and commercial site development and pipeline and piling installations in Canada.

2. Basis of presentation

These unaudited interim consolidated financial statements are prepared in accordance with US GAAP for interim financial statements and do not include all of the disclosures normally contained in the Company’s annual consolidated financial statements and as such these interim consolidated financial statements should be read in conjunction with the most recent annual financial statements. Material items that give rise to measurement differences to the consolidated financial statements under Canadian GAAP are outlined in note 20.

3. United States accounting pronouncements recently adopted

i) Improvements to financial reporting by enterprises involved with variable interest entities

In December 2009, the FASB issued ASU No. 2009-17, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities”, which amends ASC 810, “Consolidation”. The amendments give guidance and clarification of how to determine when a reporting entity should include the assets, liabilities, non-controlling interests and results of activities of a variable interest entity in its consolidated financial statements. The Company adopted this ASU effective April 1, 2010. The adoption of this standard did not have a material effect on the Company’s interim consolidated financial statements.

ii) Embedded credit derivatives

In March 2010, the FASB issued ASU No. 2010-11, “Scope Exception Related to Embedded Credit Derivatives”, which clarifies that financial instruments that contain embedded credit-derivative features related only to the transfer of credit risk in the form of subordination of one instrument to another are not subject to bifurcation and separate accounting. The scope exception only applies to an embedded derivative feature that relates to subordination between tranches of debt issued by an entity and other features that relate to another type of risk must be evaluated for separation as an embedded derivative. The Company adopted this ASU effective July 1, 2010. The adoption of this standard did not have a material effect on the Company’s interim consolidated financial statements.

4. Recent United States accounting pronouncements not yet adopted

i) Revenue recognition

In October 2009, the FASB issued ASU No. 2009-13, “Revenue Recognition: Multiple-Deliverable Revenue Arrangements”, which addresses the accounting for multiple-deliverable arrangements to enable vendors to account for products or services separately rather than as a combined unit. The amendments establish a selling price hierarchy for determining the selling price of a deliverable. The amendments also eliminate the residual method of allocation and require that arrangement consideration be allocated at the inception of the arrangement to all deliverables using the relative selling price method. For the Company, this ASU is effective prospectively for revenue arrangements entered into or materially modified on or after April 1, 2011. The Company is currently evaluating the effect of this ASU on its consolidated financial statements.

ii) Share based payment awards

In April 2010, the FASB issued ASU No. 2010-13, “Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades”, which clarifies that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. This ASU will amend ASC 718, “Compensation – Stock Compensation” and it is effective for the Company beginning on April 1, 2011. The Company is currently evaluating the effect of this ASU on its consolidated financial statements.

6 Notes to Consolidated Financial Statements North American Energy Partners Inc.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)

5. Inventories


	September 30, 2010		March 31, 2010
Spare tires		$3,727		$1,868
Job materials		1,179		1,179

		$4,906		$3,047

6. Property, plant and equipment


September 30, 2010	Cost		Accumulated Deprecation		Net Book Value
Heavy equipment		$342,742		$103,042		$239,700
Major component parts in use		43,499		10,660		32,839
Other equipment		29,043		12,484		16,559
Licensed motor vehicles		18,142		12,844		5,298
Office and computer equipment		10,983		4,630		6,353
Buildings		21,657		7,574		14,083
Land		281		–		281
Leasehold improvements		9,311		3,255		6,056
Assets under capital lease		22,492		12,347		10,145

		$498,150		$166,836		$331,314


March 31, 2010	Cost		Accumulated Deprecation		Net Book Value
Heavy equipment		$339,312		$95,473		$243,839
Major component parts in use		36,064		8,297		27,767
Other equipment		25,666		10,910		14,756
Licensed motor vehicles		16,296		10,692		5,604
Office and computer equipment		9,746		3,786		5,960
Buildings		21,710		6,832		14,878
Land		281		–		281
Leasehold improvements		9,314		2,960		6,354
Assets under capital lease		24,304		12,388		11,916

		$482,693		$151,338		$331,355

Assets under capital lease are comprised predominately of licensed motor vehicles.

During the three and six months ended September 30, 2010, additions to property, plant and equipment included $nil and $47 respectively, of assets that were acquired by means of capital leases (three and six months ended September 30, 2009 – $33 and $656 respectively). Depreciation of equipment under capital lease of $710 and $1,418 for the three and six months ended September 30, 2010, respectively, was included in depreciation expense (three and six months ended September 30, 2009 – $978 and $2,137 respectively).

7. Investment in and advances to unconsolidated joint venture

The Company is engaged in a joint venture, Noramac Joint Venture (JV), of which the Company has joint control (50% proportionate interest) of the entity. The JV was formed for the purpose of expanding the Company’s market opportunities and establishing strategic alliances in Northern Alberta. The Company owns a 49% interest in Noramac Ventures Inc., a nominee company established by the two joint venture partners.

As of September 30, 2010, the Company’s investment in and advances to the unconsolidated joint venture totalled $3,691 (March 31, 2010 – $2,917). The condensed financial data for investment in and advances to unconsolidated joint venture is summarized as follows:


	September 30, 2010		March 31, 2010
Current assets		$9,078		$8,952
Long term assets		1,311		153
Current liabilities		3,009		3,271
Long term liabilities		8,520		5,940

North American Energy Partners Inc. Notes to Consolidated Financial Statements 7

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)


	Three Months Ended September 30,						Six Months Ended September 30,
	2010			2009			2010			2009
Gross revenues		$1,652			$816			$5,998			$2,068
Gross profit		443			(228	)		802			379
Net loss		(547	)		(445	)		(1,033	)		(63	)

Equity in loss of unconsolidated joint venture		$(274	)		$(223	)		$(517	)		$(32	)

8. Deferred financing costs


September 30, 2010	Cost		Accumulated Amortization		Net Book Value
8³/4% senior notes		$16,521		$16,521		$–
Term & Revolving Facilities		5,362		3,499		1,863
Series 1 Debentures		6,886		351		6,535

		$28,769		$20,371		$8,398


March 31, 2010	Cost		Accumulated Amortization		Net Book Value
8³/4% senior notes		$16,521		$12,014		$4,507
Term & Revolving Facilities		4,328		3,150		1,178
Series 1 Debentures		1,040		–		1,040

		$21,889		$15,164		$6,725

Amortization of deferred financing costs of $357 and $883 respectively, was included in interest expense for the three and six months ended September 30, 2010 (three and six months ended September 30, 2009 – $838 and $1,643 respectively).

Upon redemption of the 8³/4% senior notes on April 28, 2010, the unamortized deferred financing costs related to the 8³/4% senior notes of $4,324 were expensed and included in the loss on debt extinguishment (note 9(b)). In addition, $183 related to amortization of deferred financing costs incurred up to the redemption date was included in interest expense.

9. Long term debt

a) Credit Facilities


	September 30, 2010			March 31, 2010
Term A Facility		$26,572			$28,446
Term B Facility		46,874			–

Total term facilities		$73,446			$28,446
Less: current portion		(14,000	)		(6,072	)

		$59,446			$22,374

On April 30, 2010, the Company entered into an amended and restated credit agreement to extend the term of the credit facilities and increase the amount of the term loans. These facilities mature on April 30, 2013.

The new credit facilities include an $85.0 million Revolving Facility (previously $90.0 million), a $28.4 million Term A Facility and a $50.0 million Term B Facility. Advances under the Revolving Facility may be repaid from time to time at the Company’s option. The term facilities include scheduled repayments totalling $10.0 million per year with $2.5 million paid on the last day of each quarter commencing June 30, 2010. In addition, the Company must make annual payments within 120 days of the end of its fiscal year in the amount of 50% of Consolidated Excess Cash Flow (as defined in the credit agreement) to a maximum of $4.0 million. As at September 30, 2010, the Company anticipates making the maximum payment of $4.0 million in July 2011.

As of September 30, 2010, the Company had outstanding borrowings of $73.4 million (March 31, 2010 – $28.4 million) under the term facilities, $nil under the Revolving Facility and had issued $16.3 million (March 31, 2010 – $10.4 million) in letters of credit under the Revolving Facility to support performance guarantees associated with customer contracts. The funds available for borrowing under the Revolving Facility are reduced by any outstanding letters of credit. The Company’s unused borrowing availability under the credit facility was $68.7 million at September 30, 2010.

8 Notes to Consolidated Financial Statements North American Energy Partners Inc.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)

During the three and six months ended September 30, 2010, financing fees of $nil and $1,034 respectively were incurred in connection with the modifications made to the amended and restated credit agreement. These fees have been recorded as deferred financing costs and are being amortized using the effective interest method over the term of the credit agreement (note 8).

Interest on Canadian prime rate loans is paid at variable rates based on the Canadian prime rate plus the applicable pricing margin (as defined in the credit agreement). Interest on US base rate loans is paid at a rate per annum equal to the US base rate plus the applicable pricing margin. Interest on Canadian prime rate and US base rate loans is payable monthly in arrears and computed on the basis of a 365 day or 366 day year, as the case may be. Interest on LIBOR loans is paid during each interest period at a rate per annum, calculated on a 360 day year, equal to the LIBOR rate with respect to such interest period plus the applicable pricing margin. Stamping fees and interest related to the issuance of Bankers’ Acceptances is paid in advance upon the issuance of such Bankers’ Acceptance.

The credit facilities are secured by a first priority lien on substantially all of the Company’s existing and after-acquired property and contain certain restrictive covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions, paying dividends or redeeming shares 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 September 30, 2010.

b) 8³/4% Senior Notes


	September 30, 2010		March 31, 2010
8³/4% senior unsecured notes due 2011 ($US)		$–		$200,000
Unrealized foreign exchange		–		3,120

		$–		$203,120

On April 28, 2010, the Company redeemed the 8³/4% senior notes for $202,410 and recorded a $4,346 loss on debt extinguishment including a $4,324 write off of deferred financing costs (note 8).

c) Series 1 Debentures

On April 7, 2010, the Company issued $225.0 million of 9.125% Series 1 Debentures (the “Series 1 Debentures”). The Series 1 Debentures mature on April 7, 2017. The Series 1 Debentures bear interest at 9.125% per annum and such interest is payable in equal instalments semi-annually in arrears on April 7 and October 7 in each year, commencing on October 7, 2010.

The Series 1 Debentures 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 Series 1 Debentures are effectively subordinated to all secured debt to the extent of collateral on such debt.

At any time prior to April 7, 2013, the Company may redeem up to 35% of the aggregate principal amount of the Series 1 Debentures with the net cash proceeds of one or more public equity offerings at a redemption price equal to 109.125% of the principal amount, plus accrued and unpaid interest to the date of redemption, so long as:

i)	at least 65% of the original aggregate amount of the Series 1 Debentures remains outstanding after each redemption; and

ii)	any redemption by the Company is made within 90 days of the equity offering.

At any time prior to April 7, 2013, the Company may on one or more occasions redeem the Series 1 Debentures, in whole or in part, at a redemption price which is equal to the greater of (a) the Canada Yield Price (as defined in the trust indenture) and (b) 100% of the aggregate principal amount of Series 1 Debentures redeemed, plus, in each case, accrued and unpaid interest to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

The Series 1 Debentures are redeemable at the option of the Company, in whole or in part, at any time on or after: April 7, 2013 at 104.563% of the principal amount; April 7, 2014 at 103.042% of the principal amount; April 7, 2015 at 101.520% of the principal amount; April 7, 2016 and thereafter at 100% 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 debenture holder’s Series 1 Debentures, at a purchase price in cash equal to 101% of the principal amount of the Series 1 Debentures offered for repurchase plus accrued interest to the date of purchase.

During the three and six months ended September 30, 2010, financing fees of $216 and $5,846 respectively were incurred in connection with the issuance of the Series 1 Debentures in addition to $1,040 that was incurred in March 2010. These fees have been recorded as deferred financing costs and are being amortized using the effective interest method over the term of the Series 1 Debentures (note 8).

North American Energy Partners Inc. Notes to Consolidated Financial Statements 9

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)

10. Shares

a) Common shares

Authorized:

Unlimited number of voting common shares

Unlimited number of non-voting common shares

Issued and outstanding:


	Number of Shares		Amount
Voting common shares

Issued and outstanding at March 31, 2010		36,049,276		$303,505
Issued upon exercise of options		61,160		305
Transferred from additional paid-in capital on exercise of stock options		–		117

Issued and outstanding at September 30, 2010		36,110,436		$303,927

b) Net income (loss) per share


	Three Months Ended September 30,				Six Months Ended September 30,
	2010		2009		2010		2009
Net income (loss) available to common shareholders		$2,369		$4,299		$(7,940)		$14,226
Weighted average number of common shares		36,071,972		36,038,476		36,064,522		36,038,476
Basic net income (loss) per share		$0.07		$0.12		$(0.22)		$0.39

Net income (loss) available to common shareholders		$2,369		$4,299		$(7,940)		$14,226
Weighted average number of common shares		36,071,972		36,038,476		36,064,522		36,038,476
Dilutive effect of stock options and deferred performance share units		577,682		668,955		–		615,232

Weighted average number of diluted common shares		36,649,654		36,707,431		36,064,522		36,653,708
Diluted net income (loss) per share		$0.06		$0.12		$(0.22)		$0.39

For the three and six months ended September 30, 2010, there were 865,400 and 701,507, respectively, stock options which were anti-dilutive and therefore were not considered in computing diluted earnings per share (three and six months ended September 30, 2009 – 922,126 and 859,783, respectively, stock options and deferred performance share units).

11. Interest expense


	Three Months Ended September 30,				Six Months Ended September 30,
	2010		2009		2010		2009
Interest on 8³/4% senior notes and swaps		$–		$4,737		$1,238		$9,881
Interest on capital lease obligations		182		270		390		561
Amortization of deferred financing costs		357		838		883		1,643
Interest on term facilities		1,298		197		2,264		492
Interest on Series 1 Debentures		5,133		–		9,867		–

Interest on long term debt		$6,970		$6,042		$14,642		$12,577
Other interest		738		367		795		384

		$7,708		$6,409		$15,437		$12,961

12. Financial instruments

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

The fair values of the Company’s cash and cash equivalents, accounts receivable, unbilled revenue, accounts payable and accrued liabilities approximate their carrying amounts due to the relatively short periods to maturity for the instruments.

10 Notes to Consolidated Financial Statements North American Energy Partners Inc.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)

The fair values of amounts due under the Term Facilities are based on management estimates which are determined by discounting cash flows required under the instruments at the interest rate currently estimated to be available for instruments with similar terms. Based on these estimates and by using the outstanding balance of $73.4 million at September 30, 2010 and $28.4 million at March 31, 2010, the fair value of amounts due under the Term Facilities as at September 30, 2010 and March 31, 2010 are not significantly different than their carrying value.

Financial instruments with carrying amounts that differ from their fair values are as follows:

September 30, 2010

March 31, 2010

Carrying Amount

Fair Value

Carrying Amount

Fair Value

8³/4% senior notes ⁽ⁱ⁾

$–

$203,120

$203,526

Capital lease obligations ⁽ⁱⁱ⁾

10,628

13,393

13,291

Series 1 Debentures ⁽ⁱⁱⁱ⁾

225,000

233,680

–

(i)

The US Dollar denominated 8³/4% senior notes were redeemed during the three months ended June 30, 2010. The fair value of the 8³/4% senior notes on March 31, 2010 was based upon the period end closing market price translated into Canadian Dollars at period end exchange rates as at March 31, 2010. Expected discounted cash flows were not included in the fair value calculation.

(ii)	The fair values of amounts due under capital leases are based on management estimates which are determined by discounting cash flows required under the instruments at the interest rates currently estimated to be available for instruments with similar terms.

(iii)

The fair value of the Series 1 Debentures is based upon the expected discounted cash flows and the period end market price of similar financial instruments.

Fair value hierarchy of financial instruments

The Company has segregated all financial assets and financial liabilities that are measured at fair value on a recurring basis into the most appropriate level within the fair value hierarchy based on the inputs used to determine the fair value at the measurement date.

The fair values of the Company’s embedded derivatives are based on appropriate price modeling commonly used by market participants to estimate fair value. Such modeling includes option pricing models and discounted cash flow analysis, using observable market based inputs including foreign currency rates and discount factors to estimate fair value. The Company considers its own credit risk or the credit risk of the counterparty in determining fair value, depending on whether the fair values are in an asset or liability position. Fair value determined using valuation models requires the use of assumptions concerning the amount and timing of future cash flows. Fair value amounts reflect management’s best estimates using external, readily observable, market data such as future prices, interest rate yield curves, foreign exchange rates and discount rates for time value. It is possible that the assumptions used in establishing fair value amounts will differ from future outcomes and the effect of such variations could be material.

At September 30, 2010, the Company had no financial assets or financial liabilities measured at fair value on a recurring basis which were classified as Level 1 or Level 3 under the fair value hierarchy. Since the Company primarily uses observable inputs of similar instruments and discounted cash flows in its valuation of its derivative financial instruments, these fair value measurements are classified as Level 2 of the fair value hierarchy. Financial assets and liabilities measured at fair value net of accrued interest on a recurring basis, all of which are classified as “Derivative financial instruments” on the Interim Consolidated Balance Sheets are summarized below:


September 30, 2010	Carrying Value
Embedded price escalation features in a long term customer construction contract		$6,080
Embedded price escalation features in certain long term supplier contracts		9,453

		$15,533
Less: current portion		(2,743	)

		$12,790


March 31, 2010	Carrying Value
Cross-currency swaps for US dollar 8³/4% senior notes		$66,268
Interest rate swaps for US dollar 8³/4% senior notes		14,843

Cross-currency and interest rate swaps for US dollar 8³/4% senior notes		$81,111
Embedded price escalation features in a long term customer construction contract		6,481
Embedded price escalation features in certain long term supplier contracts		9,463

		$97,055
Less: current portion		(22,054	)

		$75,001

On April 8, 2010, the Company settled the cross-currency and interest rate swaps, including accrued interest for a total of $91,125 in conjunction with the settlement of the 8³/4% senior notes (note 9(b)).

North American Energy Partners Inc. Notes to Consolidated Financial Statements 11

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)

Assets held for sale are re-measured at fair value on a non-recurring basis. Assets held for sale with a carrying amount of $2,266 were written down to their fair value of $2,233, resulting in a loss of $33, which was included in depreciation expense in the Consolidated Statements of Operations and Comprehensive Income for the three and six months ended September 30, 2010. The fair value of the assets held for sale is determined internally by analyzing recent auction prices for equipment with similar specifications and hours used, the net book value, the residual value of the asset and the useful life of the asset. The inputs to estimate the fair value of the assets held for sale are classified under Level 3 of the fair value hierarchy.

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


	Three Months Ended September 30,						Six Months Ended September 30,
	2010			2009			2010			2009
Realized and unrealized loss on cross-currency and interest rate swaps		$–			$22,847			$2,111			$46,018
Unrealized loss (gain) on embedded price escalation features in a long term customer construction contract		348			2,986			(402	)		6,273
Unrealized (gain) loss on embedded price escalation features in certain long term supplier contracts		(1,656	)		460			(9	)		(13,704	)
Unrealized gain on early redemption option on 8³/4% senior notes		–			(1,139	)		–			(3,412	)

		$(1,308	)		$25,154			$1,700			$35,175

13. Other information

a) Supplemental cash flow information


	Three Months Ended September 30,				Six Months Ended September 30,
	2010		2009		2010		2009
Cash paid during the period for:
Interest		$3,235		$5,573		$20,055		$25,241
Income taxes		571		1,545		1,172		7,608
Cash received during the period for:
Interest		338		2,780		1,105		6,140
Income taxes		17		–		17		–
Non-cash transactions:
Acquisition of property, plant and equipment by means of capital leases		–		33		47		656
Lease inducements		–		195		–		195

b) Net change in non-cash working capital


	Three Months Ended September 30,						Six Months Ended September 30,
	2010			2009			2010			2009
Operating activities:
Accounts receivable, net		$(11,600	)		$(12,755	)		$10,359			$(4,470	)
Unbilled revenue		(46,913	)		(9,060	)		(52,495	)		(11,547	)
Inventories		2,867			(2,303	)		(1,859	)		1,794
Prepaid expenses and deposits		592			1,467			(2,839	)		(1,282	)
Accounts payable		35,636			14,449			43,375			9,343
Accrued liabilities		657			5,869			(4,773	)		(15,042	)
Long term accrued liabilities		1,308			2,569			1,682			2,836
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		957			2,128			2,410			2,042

		$(16,496	)		$2,364			$(4,140	)		$(16,326	)

Investing activities:
Accounts payable		$(1,252	)		$3,919			$(4,020	)		$2,647

c) Income taxes

Income tax expense as a percentage of income before income taxes for the three and six months ended September 30, 2010 differs from the statutory rate of 27.77% primarily due to the effect of changes in enacted tax rates and the benefit from changes in the timing of the reversal of temporary differences. Additionally, this ratio was impacted by CRA audit adjustments from 2007 and 2008 which are included in the current and deferred income tax accounts. Income tax

12 Notes to Consolidated Financial Statements North American Energy Partners Inc.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)

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

14. 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:

_Ÿ

Heavy Construction and Mining:

The Heavy Construction and Mining segment provides mining and site preparation services, including overburden removal and reclamation services, project management, underground utility construction, equipment rental to a variety of customers, environmental services including construction and modification of tailing ponds and reclamation of completed mine sites to environmental standards throughout Canada.

_Ÿ

Piling:

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

_Ÿ

Pipeline:

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

The accounting policies of the reportable operating segments are the same as those described in the significant accounting policies in note 3 of the annual consolidated financial statements of the Company for the year ended March 31, 2010. 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 resources used to provide these services.

b) Results by business segment


Three Months Ended September 30, 2010	Heavy Construction and Mining		Piling		Pipeline			Total
Revenues from external customers		$171,628		$26,563		$36,667			$234,858
Depreciation of property, plant and equipment		6,042		714		164			6,920
Segment profits		22,234		4,782		879			27,895
Capital expenditures		9,661		563		1,171			11,395


Three Months Ended September 30, 2009	Heavy Construction and Mining		Piling		Pipeline			Total
Revenues from external customers		$154,055		$15,058		$1,589			$170,702
Depreciation of property, plant and equipment		9,199		845		25			10,069
Segment profits		21,922		1,950		(137	)		23,735
Capital expenditures		19,382		–		–			19,382


Six Months Ended September 30, 2010	Heavy Construction and Mining		Piling		Pipeline			Total
Revenues from external customers		$335,237		$45,709		$37,506			$418,452
Depreciation of property, plant and equipment		11,851		1,353		184			13,388
Segment profits		44,481		6,176		156			50,813
Capital expenditures		12,790		1,756		1,519			16,065

Six Months Ended September 30, 2009	Heavy Construction and Mining		Piling		Pipeline			Total
Revenues from external customers		$285,881		$29,676		$1,664			$317,221
Depreciation of property, plant and equipment		15,921		1,407		247			17,575
Segment profits		45,437		4,634		229			50,300
Capital expenditures		36,054		2		–			36,056

North American Energy Partners Inc. Notes to Consolidated Financial Statements 13

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)


September 30, 2010	Heavy Construction and Mining		Piling		Pipeline		Total
Segment assets		$425,380		$100,853		$50,228		$576,461

March 31, 2010	Heavy Construction and Mining		Piling		Pipeline		Total
Segment assets		$435,098		$92,980		$14,765		$542,843

c) Reconciliations

i) Income (loss) before income taxes


	Three Months Ended September 30,						Six Months Ended September 30,
	2010			2009			2010			2009
Total profit for reportable segments		$27,895			$23,735			$50,813			$50,300
Less: unallocated corporate expenses
General and administrative costs		15,286			13,918			29,015			28,894
Loss on disposal of property, plant and equipment		585			260			581			301
(Gain) loss on disposal of assets held for sale		(25	)		41			(25	)		(276	)
Amortization of intangible assets		672			417			1,260			910
Equity in loss of unconsolidated joint venture		274			223			517			32
Interest expense, net		7,708			6,409			15,437			12,961
Foreign exchange loss (gain)		49			(18,045	)		(1,648	)		(37,481	)
Realized and unrealized (gain) loss on derivative financial instruments		(1,308	)		25,154			1,700			35,175
Loss on debt extinguishment		–			–			4,346			–
Other (income) expense		(9	)		(200	)		(9	)		333
Unallocated equipment (recoveries) costs⁽ⁱ⁾		(1,202	)		(10,061	)		6,096			(8,636	)

Income (loss) before income taxes		$5,865			$5,619			$(6,457)			$18,087

(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.

ii) Total assets


	September 30, 2010		March 31, 2010
Corporate assets:
Cash and cash equivalents		$56,180		$103,005
Property, plant and equipment		23,413		17,883
Deferred income taxes		46,894		14,478
Other		36,659		24,408

Total corporate assets		$163,146		$159,774
Total assets for reportable segments		576,461		542,843

Total assets		$739,607		$702,617

The Company’s goodwill of $25,111 is assigned to the Piling segment. All of the Company’s assets are located in Canada.

iii) Depreciation of property, plant and equipment


	Three Months Ended September 30,				Six Months Ended September 30,
	2010		2009		2010		2009
Total depreciation for reportable segments		$6,920		$10,069		$13,388		$17,575
Depreciation for corporate assets		1,134		1,357		2,869		2,575

Total depreciation		$8,054		$11,426		$16,257		$20,150

iv) Capital expenditures for property, plant and equipment


	Three Months Ended September 30,				Six Months Ended September 30,
	2010		2009		2010		2009
Total capital expenditures for reportable segments		$11,395		$19,382		$16,065		$36,056
Capital expenditures for corporate assets		817		4,173		2,736		7,209

Total capital expenditures		$12,212		$23,555		$18,801		$43,265

14 Notes to Consolidated Financial Statements North American Energy Partners Inc.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)

d) Customers

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


	Three Months Ended September 30,				Six Months Ended September 30,
	2010		2009		2010		2009
Customer A		32%		13%		32%		16%
Customer B		28%		55%		34%		55%
Customer C		7%		12%		7%		11%

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

15. Stock-based compensation plan

a) Stock-based compensation

Stock-based compensation expenses included in general and administrative costs are as follows:


	Three Months Ended September 30,					Six Months Ended September 30,
	2010			2009		2010			2009
Share option plan (b)		$352			$425		$757			$1,354
Senior executive stock option plan (c)		1,245			–		1,245			–
Deferred performance share unit plan (d)		(92	)		64		(87	)		278
Restricted share unit plan (e)		113			–		416			–
Director’s deferred stock unit plan (f)		(55	)		143		71			817
Stock award plan (g)		524			–		524			–

		$2,087			$632		$2,926			$2,449

Stock-based compensation liability included in Other long-term obligations are as follows:


	September 30, 2010		March 31, 2010
Senior executive stock option plan (c)		$3,482		$ –
Restricted share unit plan (e)		1,446		1,030
Director’s deferred stock unit plan (f)		2,619		2,548

		$7,547		$3,578

b) 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 September 30,
	2010						2009
	Number of options			Weighted average exercise price ($ per share)			Number of options			Weighted average exercise price ($ per share)
Outstanding, beginning of period		2,237,244			7.85			2,181,504			7.64
Granted		60,000			8.58			–			–
Exercised⁽ⁱ⁾		(48,400	)		(4.98	)		–			–
Forfeited		(12,800	)		(9.11	)		(26,880	)		(9.09	)
Modified⁽ⁱⁱ⁾		(550,000	)		(5.00	)		–			–

Outstanding, end of period		1,686,044			8.88			2,154,624			7.62

(i)	All stock options exercised resulted in new common shares being issued.

(ii)	550,000 options were modified as senior executive stock options on September 22, 2010 (note 15(c)).

North American Energy Partners Inc. Notes to Consolidated Financial Statements 15

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)


	Six Months Ended September 30,
	2010						2009
	Number of options			Weighted average exercise price ($ per share)			Number of options			Weighted average exercise price ($ per share)
Outstanding, beginning of period		2,250,804			7.84			2,071,884			7.53
Granted		60,000			8.58			160,000			8.28
Exercised⁽ⁱ⁾		(61,160	)		(4.98	)		–			–
Options settled for cash		–			–			(40,000	)		(5.00	)
Forfeited		(13,600	)		(9.37	)		(37,260	)		(8.37	)
Modified⁽ⁱⁱ⁾		(550,000	)		(5.00	)		–			–

Outstanding, end of period		1,686,044			8.88			2,154,624			7.62

(i)	All stock options exercised resulted in new common shares being issued.

(ii)	550,000 options were modified as senior executive stock options on September 22, 2010 (note 15(c)).

At September 30, 2010, the weighted average remaining contractual life of outstanding options is 6.8 years (March 31, 2010 – 6.6 years). At September 30, 2010, the Company had 824,300 exercisable options (March 31, 2010 – 1,244,908) with a weighted average exercise price of $7.73 (March 31, 2010 – $6.46).

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 September 30,				Six Months Ended September 30,
	2010		2009		2010		2009
Number of options granted		60,000		–		60,000		160,000
Weighted average fair value per option granted ($)		5.91		–		5.91		5.89
Weighted average assumptions:
Dividend yield		Nil%		–		Nil%		Nil%
Expected volatility		78.67%		–		78.67%		77.47%
Risk-free interest rate		2.23%		–		2.23%		3.44%
Expected life (years)		6.06		–		6.06		6.5

c) Senior executive stock option plan

On September 22, 2010, the Company modified a senior executive employment agreement to allow the option holder the right to settle options in cash which resulted in 550,000 stock options (senior executive stock options) changing classification from equity to a long term liability. The Company classifies senior executive stock options as a liability. The liability is measured at fair value using the Black-Scholes model at the modification date and subsequently at each period end date. Previously recognized compensation cost related to the senior executive stock option plan of $2,237 was transferred from additional paid-in capital to the senior executive stock option liability on the modification date. Incremental compensation cost of $1,245 was recognized (note 15(a)) for the three and six months ended September 30, 2010. Changes in fair value of the liability are recognized in the Consolidated Statements of Operations and Comprehensive Income (Loss).

The weighted average assumptions used in estimating the fair value of the senior executive stock options as at September 30, 2010 are as follows:


	Three and Six Months Ended September 30 2010,
Number of senior executive stock options modified		550,000
Weighted average fair value per option granted ($)		6.33
Weighted average assumptions:
Dividend yield		Nil%
Expected volatility		84.97%
Risk-free interest rate		2.14%

d) Deferred performance share unit plan

Deferred Performance Share Units (“DPSUs”) are granted each fiscal year with 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

16 Notes to Consolidated Financial Statements North American Energy Partners Inc.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)

DPSUs is the maturity date for such DPSUs. At the maturity date, the Compensation Committee assesses the participant against the performance criteria and determines the number of DPSUs that have been earned (earned DPSUs).

The settlement of the participant’s entitlement is made at the Company’s option either in cash in an amount equivalent to the number of earned DPSUs multiplied by 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 are purchased on the open market or through the issuance of shares from treasury.


	Three Months Ended September 30,						Six Months Ended September 30,
	2010			2009			2010			2009
Outstanding, beginning of period		504,001			820,795			507,295			91,005
Granted		–			–			–			748,791
Exercised		–			–			–			–
Forfeited		(12,013	)		(12,894	)		(15,307	)		(31,895	)

Outstanding, end of period		491,988			807,901			491,988			807,901

The weighted average exercise price per unit is $nil.

At September 30, 2010, the weighted average remaining contractual life of outstanding DPSU Plan units is 1.71 years (March 31, 2010 – 2.2 years). Compensation expense was 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 September 30, 2010, there was approximately $385 of total unrecognized compensation cost related to non-vested share-based payment arrangements under the DPSU Plan (September 30, 2009 – $1,050), which is expected to be recognized over a weighted average period of 1.71 years and is subject to performance adjustments.

e) Restricted share unit plan

Restricted Share Units (“RSUs”) are granted each fiscal year with respect to services to be provided in that fiscal year and the following two fiscal years. The RSUs vest at the end of a three-year term. The Company classifies RSUs as a liability as the Company has the ability and intent to settle the awards in cash.

Compensation expense is calculated based on the weighted average number of vested shares multiplied by the fair value of each RSU as determined by the closing value of the Company’s common shares on each period end date. The Company recognizes compensation expense over the vesting period of the RSU term.

Three Months Ended
September 30,

Six Months Ended
September 30,

2010

2009

2010

2009

Outstanding, beginning of period

453,251

–

468,815

–

Granted

–

Exercised

–

Forfeited

(19,704

)

–

(35,268

)

–

Outstanding, end of period

433,547

–

433,547

–

At September 30, 2010, the redemption value of these units was $8.37/unit (March 31, 2010 – $9.68/unit).

Using the redemption value of $8.37/unit at September 30, 2010, there was approximately $2,183 of total unrecognized compensation cost related to non-vested share-based payment arrangements under the RSU Plan and these costs are expected to be recognized over the weighted average remaining contractual life of the RSUs of 1.8 years (March 31, 2010 – 2.3 years).

f) Director’s deferred stock unit plan

Under the Directors’ Deferred Stock Unit (“DDSU”) Plan, non-officer directors of the Company 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 unit account is 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 days immediately preceding death or retirement. Directors, who are not US

North American Energy Partners Inc. Notes to Consolidated Financial Statements 17

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)

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 September 30,				Six Months Ended September 30,
	2010		2009		2010		2009
Outstanding, beginning of period		284,155		173,008		263,266		139,691
Granted		22,564		36,706		43,453		70,023

Outstanding, end of period		306,719		209,714		306,719		209,714

At September 30, 2010, the redemption value of these units was $8.54/unit (March 31, 2010 – $9.68/unit).

g) Stock award plan

On September 24, 2009, the Chief Executive Officer’s (CEO) employment agreement was extended by the Board of Directors for a further period of two years, to May 8, 2012. In addition to the existing conditions in his employment agreement, the CEO was awarded the right to receive 150,000 common shares of the Company as follows:

_Ÿ

50,000 shares on May 8, 2011;

_Ÿ

50,000 shares on November 8, 2011; and

_Ÿ

50,000 shares on May 8, 2012.

These shares will be awarded to the CEO provided he remains employed on the award dates above. As of September 24, 2010, the effective date, the CEO will be granted a right to receive 150,000 common shares of the Company or at the discretion of the Company, the cash equivalent thereof.

The CEO’s entitlement, upon the above release dates, shall be settled in common shares purchased on the open market or through the issuance of common shares from treasury, in each case net of required withholdings. The CEO’s entitlement may be settled with newly issued common shares from treasury, if all necessary shareholder approvals and regulatory approvals, if any, are obtained. The Company has no intention to settle in cash.

The estimate of the fair value of the stock award on the grant date was determined using the Black-Scholes option pricing model and the weighted average assumptions used in estimating the fair value of the stock awards are as follows:

Three Months Ended
September 30,

Six Months Ended
September 30,

2010

2009

2010

2009

Number of stock awards granted

–

150,000

–

150,000

Weighted average fair value per award granted ($)

–

7.00

–

7.00

Weighted average assumptions:

Dividend yield

–

Nil%

–

Nil%

Expected volatility

–

117.72%

–

117.72%

Risk-free interest rate

–

1.48%

–

1.48%

Expected life (years)

–

2.6

–

2.6

None of the stock awards have vested as of September 30, 2010. At September 30, 2010, the weighted average remaining contractual life of outstanding Stock Award Plan units is 1.1 years (March 31, 2010 – 1.6 years). As at September 30, 2010, there was approximately $526 of total unrecognized compensation cost related to non-vested share-based payment arrangements under the stock award plan, which is expected to be recognized over a weighted average period of 1.1 years (March 31, 2010 – 1.6 years).

16. 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 effect 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 affected in less active periods because the Company is likely to incur higher maintenance and repair costs due to its equipment being available for service.

18 Notes to Consolidated Financial Statements North American Energy Partners Inc.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)

17. Claims revenue

For the three and six months ended September 30, 2010, due to the timing of receipt of signed change orders, the Heavy Construction and Mining segment had approximately $0.1 million and $0.7 million respectively in claims revenue recognized to the extent of costs incurred, the Piling segment had $0.5 million and $1.8 million respectively in claims revenue recognized to the extent of costs incurred, and the Pipeline segment had $nil million and $0.1 million respectively in claims revenue recognized to the extent of costs incurred.

18. Comparative figures

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

19. Subsequent events

On November 1, 2010, the Company acquired all of the assets of Cyntech Corporation and its wholly owned subsidiary, Cyntech Anchor Systems LLC (collectively Cyntech) a piling company specializing in screw piling, pipeline anchor design and manufacturing capabilities. The Company will gain access to screw piling, pipeline anchor design and manufacturing capabilities. The company will also gain oil and gas storage tank repair and maintenance capabilities which will complement the Company’s existing service offering. The acquisition is expected to be reflected in the Company’s interim consolidated financial statements for the period ended December 31, 2010.

20. United States and Canadian accounting policy differences

These consolidated financial statements have been prepared in accordance with US GAAP, which differs in certain respects from Canadian GAAP. If Canadian GAAP were employed, the Company's net income (loss) would be adjusted as follows:


Consolidated Statements of Operations, Comprehensive Income and Deficit - Three months ended September 30, 2010	US GAAP			Adjustments			Canadian GAAP
Revenue ^(e)		$234,858			$826			$235,684
Project costs ^(e)		132,440			605			133,045
Equipment costs		46,358			–			46,358
Equipment operating lease expense		18,909			–			18,909
Depreciation ^(a)		8,054			(24	)		8,030

Gross profit		29,097			245			29,342
General and administrative costs ^(c) and ^(e)		15,286			(759	)		14,527
Loss on disposal of property, plant and equipment		585			–			585
Gain on disposal of assets held for sale		(25	)					(25	)
Amortization of intangible assets ^(b)		672			174			846
Equity in loss of unconsolidated joint venture ^(e)		274			(274	)		–

Operating income before the undernoted		12,305			1,104			13,409
Interest expense, net ^(b)		7,708			(266	)		7,442
Foreign exchange loss		49			–			49
Realized and unrealized gain on derivative financial instruments ^(d)		(1,308	)		(2,170	)		(3,478	)
Other income		(9	)		–			(9	)

Income before income taxes		5,865			3,540			9,405
Income taxes:
Current		3,259			–			3,259
Deferred ^(f)		237			292			529

Net income and comprehensive income for the period		2,369			3,248			5,617
Deficit, beginning of period		(140,195	)		4,091			(136,104	)

Deficit, end of period		$(137,826)			$7,339			$(130,487)

Net income per share – basic		$0.07			$0.09			$0.16

Net income per share – diluted		$0.06			$0.09			$0.15

North American Energy Partners Inc. Notes to Consolidated Financial Statements 19

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)


Consolidated Statements of Operations, Comprehensive Loss and Deficit - Six months ended September 30, 2010	US GAAP			Adjustments			Canadian GAAP
Revenue ^(e)		$418,452			$2,999			$421,451
Project costs ^(e)		209,717			2,598			212,315
Equipment costs		111,361			–			111,361
Equipment operating lease expense		36,400			–			36,400
Depreciation ^(a)		16,257			(56	)		16,201

Gross profit		44,717			457			45,174
General and administrative costs ^(c) and ^(e)		29,015			(349	)		28,666
Loss on disposal of property, plant and equipment		581			–			581
Gain on disposal of assets held for sale		(25	)		–			(25	)
Amortization of intangible assets ^(b)		1,260			349			1,609
Equity in loss of unconsolidated joint venture ^(e)		517			(517	)		–

Operating income before the undernoted		13,369			974			14,343
Interest expense, net ^(b)		15,437			(647	)		14,790
Foreign exchange gain		(1,648	)		–			(1,648	)
Realized and unrealized loss (gain) on derivative financial instruments ^(d)		1,700			(3,061	)		(1,361	)
Loss on debt extinguishment ^(b)		4,346			(2,884	)		1,462
Other income		(9	)		–			(9	)

(Loss) income before income taxes		(6,457	)		7,566			1,109
Income taxes (benefit):
Current		4,487			–			4,487
Deferred ^(f)		(3,004	)		1,308			(1,696	)

Net loss and comprehensive loss for the period		(7,940	)		6,258			(1,682	)
Deficit, beginning of period		(129,886	)		1,081			(128,805	)

Deficit, end of period		$(137,826	)		$7,339			$(130,487	)

Net loss per share – basic		$(0.22	)		$0.17			$(0.05	)

Net loss per share – diluted		$(0.22	)		$0.17			$(0.05	)


Consolidated Statements of Operations, Comprehensive Income and Deficit - Three months ended September 30, 2009	US GAAP			Adjustments			Canadian GAAP
Revenue ^(e)		$170,702			$408			$171,110
Project costs ^(e)		65,437			522			65,959
Equipment costs		44,359			–			44,359
Equipment operating lease expense		15,684			–			15,684
Depreciation ^(a)		11,426			(31	)		11,395

Gross profit		33,796			(83	)		33,713
General and administrative costs ^(c) and ^(e)		13,918			97			14,015
Loss on disposal of property, plant and equipment		260			–			260
Loss on disposal of assets held for sale		41			–			41
Amortization of intangible assets ^(b)		417			204			621
Equity in loss of unconsolidated joint venture ^(e)		223			(223	)		–

Operating income before the undernoted		18,937			(161	)		18,776
Interest expense, net ^(b)		6,409			(619	)		5,790
Foreign exchange gain ^(b)		(18,045	)		183			(17,862	)
Realized and unrealized loss on derivative financial instruments ^(d)		25,154			(2,328	)		22,826
Other income		(200	)		–			(200	)

Income before income taxes		5,619			2,603			8,222
Income taxes:
Current		1,264			–			1,264
Deferred ^(f)		56			411			467

Net income and comprehensive income for the period		4,299			2,192			6,491
Deficit, beginning of period		(148,178	)		269			(147,909	)

Deficit, end of period		$(143,879)			$2,461			$(141,418)

Net income per share – basic		$0.12			$0.06			$0.18

Net income per share – diluted		$0.12			$0.06			$0.18

20 Notes to Consolidated Financial Statements North American Energy Partners Inc.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)


Consolidated Statements of Operations, Comprehensive Income and Deficit - Six months ended September 30, 2009	US GAAP			Adjustments			Canadian GAAP
Revenue ^(e)		$317,221			$992			$318,213
Project costs ^(e)		119,699			813			120,512
Equipment costs		90,403			–			90,403
Equipment operating lease expense		28,033			–			28,033
Depreciation ^(a)		20,150			(62	)		20,088

Gross profit		58,936			241			59,177
General and administrative costs ^(c) and ^(e)		28,894			187			29,081
Loss on disposal of property, plant and equipment		301			–			301
Gain on disposal of assets held for sale		(276	)		–			(276	)
Amortization of intangible assets ^(b)		910			413			1,323
Equity in loss of unconsolidated joint venture ^(e)		32			(32	)		–

Operating income before the undernoted		29,075			(327	)		28,748
Interest expense, net ^(b)		12,961			(1,203	)		11,758
Foreign exchange gain		(37,481	)		404			(37,077	)
Realized and unrealized loss on derivative financial instruments ^(d)		35,175			(2,328	)		32,847
Other expense		333			–			333

Income before income taxes		18,087			2,800			20,887
Income taxes:
Current		1,264			–			1,264
Deferred ^(f)		2,597			465			3,062

Net income and comprehensive income for the period		14,226			2,335			16,561
Deficit, beginning of period		(158,105	)		126			(157,979	)

Deficit, end of period		$(143,879)			$2,461			$(141,418)

Net income per share – basic		$0.39			$0.07			$0.46

Net income per share – diluted		$0.39			$0.06			$0.45

North American Energy Partners Inc. Notes to Consolidated Financial Statements 21

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)

The cumulative effect of material differences between US and Canadian GAAP on the Consolidated Balance Sheets of the Company is as follows:


Consolidated Balance Sheets – September 30, 2010	US GAAP			Adjustments			Canadian GAAP
Assets
Current assets:
Cash and cash equivalents ^(e)		$56,180			$992			$57,172
Accounts receivable, net ^(e)		101,525			1,979			103,504
Unbilled revenue ^(e)		137,197			1,554			138,751
Inventories		4,906			–			4,906
Prepaid expenses and deposits ^(e)		10,511			13			10,524
Deferred tax assets		2,785			–			2,785

		313,104			4,538			317,642
Prepaid expenses and deposits		3,214			–			3,214
Assets held for sale		2,233			–			2,233
Property, plant and equipment ^(a) and ^(e)		331,314			61			331,375
Investment in and advances to unconsolidated joint venture ^(e)		3,691			(3,691	)		–
Intangible assets ^(b)		8,433			1,850			10,283
Goodwill		25,111			–			25,111
Deferred financing costs ^(b)		8,398			(8,398	)		–
Deferred tax assets		44,109			–			44,109

		$739,607			$(5,640)			$733,967

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable ^(e)		$106,231			$1,504			$107,735
Accrued liabilities ^(e)		33,475			–			33,475
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		4,024			–			4,024
Current portion of capital lease obligations		4,416			–			4,416
Current portion of term facilities		14,000			–			14,000
Current portion of derivative financial instruments		2,743			–			2,743
Deferred tax liabilities		31,435			–			31,435

		196,324			1,504			197,828
Long term accrued liabilities		16,625			–			16,625
Capital lease obligations		6,212			–			6,212
Deferred lease inducements		707			–			707
Term facilities		59,446			–			59,446
Series 1 debentures ^(b) and ^(d)		225,000			(9,777	)		215,223
Derivative financial instruments		12,790			–			12,790
Other long term obligations^(c)		7,547			(1,628	)		5,919
Asset retirement obligation		377			–			377
Deferred tax liabilities ^(f)		42,199			256			42,455

		567,227			(9,645	)		557,582
Shareholders’ equity:
Common shares (authorized – unlimited number of voting common shares; issued and outstanding – September 30, 2010 – 36,110,436)		303,927			(3,458	)		300,469
Additional paid-in capital ^(c) and ^(f)		6,279			124			6,403
Deficit ^{(a – f)}		(137,826	)		7,339			(130,487	)

		172,380			4,005			176,385

		$739,607			$(5,640)			$733,967

22 Notes to Consolidated Financial Statements North American Energy Partners Inc.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)


Consolidated Balance Sheets – March 31, 2010	US GAAP			Adjustments			Canadian GAAP
Assets
Current assets:
Cash and cash equivalents ^(e)		$103,005			$1,240			$104,245
Accounts receivable, net ^(e)		111,884			1,432			113,316
Unbilled revenue ^(e)		84,702			1,794			86,496
Inventories		3,047			–			3,047
Prepaid expenses and deposits ^(e)		6,881			87			6,968
Deferred taxes assets		3,481			–			3,481

		313,000			4,553			317,553
Prepaid expenses and deposits		4,005			–			4,005
Assets held for sale		838			–			838
Property, plant and equipment ^(a)		331,355			(536	)		330,819
Investment in and advances to unconsolidated joint venture ^(e)		2,917			(2,917	)		–
Intangible assets ^(b)		7,669			1,051			8,720
Goodwill		25,111			–			25,111
Deferred financing costs ^(b)		6,725			(5,685	)		1,040
Deferred tax assets		10,997			–			10,997

		$702,617			$(3,534)			$699,083

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable ^(e)		$66,876			$1,637			$68,513
Accrued liabilities		47,191			–			47,191
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		1,614			–			1,614
Current portion of capital lease obligations		5,053			–			5,053
Current portion of term facilities		6,072			–			6,072
Current portion of derivative financial instruments		22,054			(1,506	)		20,548
Deferred tax liabilities		16,781			–			16,781

		165,641			131			165,772
Long term accrued liabilities		14,943			–			14,943
Capital lease obligations		8,340			–			8,340
Deferred lease inducements		761			–			761
Term facilities		22,374			–			22,374
8³/4% senior notes ^(b) and ^(d)		203,120			(1,506	)		201,614
Derivative financial instruments		75,001			1,506			76,507
Other long term obligations		3,578			–			3,578
Asset retirement obligation		360			–			360
Deferred tax liabilities ^(f)		27,441			(1,052	)		26,389

		521,559			(921	)		520,638
Shareholders’ equity:
Common shares (authorized – unlimited number of voting common shares; issued and outstanding – March 31, 2010 – 36,049,276)		303,505			(3,458	)		300,047
Additional paid-in capital ^(c) and ^(f)		7,439			(236	)		7,203
Deficit ^{(a – f)}		(129,886	)		1,081			(128,805	)

		181,058			(2,613	)		178,445

		$702,617			$(3,534	)		$699,083

North American Energy Partners Inc. Notes to Consolidated Financial Statements 23

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)

The cumulative effect of material differences between US and Canadian GAAP on the consolidated statement of cash flows of the Company is as follows:


Consolidated Statements of Cash Flows – Three months ended September 30, 2010
Cash provided by (used in):	US GAAP			Adjustments			Canadian GAAP
Operating activities:
Net income for the period		$2,369			$3,248			$5,617
Items not affecting cash:
Depreciation		8,054			(24	)		8,030
Equity in loss of unconsolidated joint venture		274			(274	)		–
Amortization of intangible assets		672			174			846
Amortization of deferred lease inducements		(27	)		–			(27	)
Amortization of deferred financing costs		357			(175	)		182
Amortization of premium on series 1 debentures		–			(91	)		(91	)
Loss on disposal of property, plant and equipment		585			–			585
Gain on disposal of assets held for sale		(25	)		–			(25	)
Unrealized loss on derivative financial instruments measured at fair value		(1,308	)		(2,170	)		(3,478	)
Stock-based compensation expense		2,087			(1,256	)		831
Accretion of asset retirement obligation		9			–			9
Deferred income taxes		237			292			529
Net changes in non-cash working capital		(16,496	)		(315	)		(16,811	)

		(3,212	)		(591	)		(3,803	)
Investing activities:
Purchase of property, plant and equipment		(10,759	)		10			(10,749	)
Addition to intangible assets		(1,453	)		(1	)		(1,454	)
Additions to assets held for sale		(1,703	)		–			(1,703	)
Investment in and advances to unconsolidated joint venture		(750	)		750			–
Proceeds on disposal of assets held for sale		300			–			300
Net changes in non-cash working capital		(1,252	)		–			(1,252	)

		(15,617	)		759			(14,858	)
Financing activities:
Repayment of term facilities		(2,500	)		–			(2,500	)
Financing costs		(216	)		–			(216	)
Proceeds from stock options exercised		241			–			241
Repayment of capital lease obligations		(1,384	)		–			(1,384	)

		(3,859	)		–			(3,859	)

Decrease in cash and cash equivalents		(22,688	)		168			(22,520	)
Cash and cash equivalents, beginning of period		78,868			824			79,692

Cash and cash equivalents, end of period		$56,180			$992			$57,172

24 Notes to Consolidated Financial Statements North American Energy Partners Inc.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)


Consolidated Statements of Cash Flows – Six months ended September 30, 2010
Cash provided by (used in):	US GAAP			Adjustments			Canadian GAAP
Operating activities:
Net loss for the period		$(7,940	)		$6,258			$(1,682	)
Items not affecting cash:
Depreciation		16,257			(56	)		16,201
Equity in loss of unconsolidated joint venture		517			(517	)		–
Amortization of intangible assets		1,260			349			1,609
Amortization of deferred lease inducements		(54	)		–			(54	)
Amortization of deferred financing costs		883			(466	)		417
Amortization of premium on Series 1 Debentures		–			(181	)		(181	)
Loss on disposal of property, plant and equipment		581			–			581
Gain on disposal of assets held for sale		(25	)		–			(25	)
Unrealized foreign exchange gain on 8³/4% senior notes		(732	)		–			(732	)
Unrealized loss (gain) on derivative financial instruments measured at fair value		1,700			(3,061	)		(1,361	)
Loss on debt extinguishment		4,346			(2,884	)		1,462
Stock-based compensation expense		2,926			(1,268	)		1,658
Accretion of asset retirement obligation		17			–			17
Deferred income taxes (benefit)		(3,004	)		1,308			(1,696	)
Net changes in non-cash working capital		(4,140	)		(366	)		(4,506	)

		12,592			(884	)		11,708
Investing activities:
Purchase of property, plant and equipment		(16,777	)		(541	)		(17,318	)
Addition to intangible assets		(2,024	)		(114	)		(2,138	)
Additions to assets held for sale		(1,703	)		–			(1,703	)
Investment in and advances to unconsolidated joint venture		(1,291	)		1,291			–
Proceeds on disposal of property, plant and equipment		60			–			60
Proceeds on disposal of assets held for sale		300			–			300
Net changes in non-cash working capital		(4,020	)		–			(4,020	)

		(25,455	)		636			(24,819	)
Financing activities:
Repayment of term facilities		(5,000	)		–			(5,000	)
Increase in term facilities		50,000			–			50,000
Financing costs		(7,920	)		–			(7,920	)
Redemption of 8³/4% senior notes		(202,410	)		–			(202,410	)
Issuance of series 1 debentures		225,000			–			225,000
Settlement of swap liabilities		(91,125	)		–			(91,125	)
Proceeds from stock options exercised		305			–			305
Repayment of capital lease obligations		(2,812	)		–			(2,812	)

		(33,962	)		–			(33,962	)

Decrease in cash and cash equivalents		(46,825	)		(248	)		(47,073	)
Cash and cash equivalents, beginning of period		103,005			1,240			104,245

Cash and cash equivalents, end of period		$56,180			$992			$57,172

North American Energy Partners Inc. Notes to Consolidated Financial Statements 25

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)


Consolidated Statements of Cash Flows – Three months ended September 30, 2009
Cash provided by (used in):	US GAAP			Adjustments			Canadian GAAP
Operating activities:
Net income for the period		$4,299			$2,192			$6,491
Items not affecting cash:
Depreciation		11,426			(31	)		11,395
Equity in loss of unconsolidated joint venture		223			(223	)		–
Amortization of intangible assets		417			204			621
Amortization of deferred lease inducements		(35	)		–			(35	)
Amortization of deferred financing costs		838			(619	)		219
Loss on disposal of property, plant and equipment		260			–			260
Loss on disposal of assets held for sale		41			–			41
Unrealized foreign exchange gain on 8³/4% senior notes		(18,060	)		183			(17,877	)
Unrealized loss on derivative financial instruments measured at fair value		21,290			(2,328	)		18,962
Stock-based compensation expense		632			(12	)		620
Accretion of asset retirement obligation		(21	)		–			(21	)
Deferred income taxes		56			411			467
Net changes in non-cash working capital		2,364			(322	)		2,042

		23,730			(545	)		23,185
Investing activities:
Acquisition		(4,880	)		–			(4,880	)
Purchase of property, plant and equipment		(23,239	)		–			(23,239	)
Addition to intangible assets		(316	)		–			(316	)
Additions to assets held for sale		(933	)		–			(933	)
Investment in and advances to unconsolidated joint venture		(486	)		486			–
Proceeds on disposal of property, plant and equipment		558			–			558
Proceeds on disposal of assets held for sale		152			–			152
Net changes in non-cash working capital		3,919			–			3,919

		(25,225	)		486			(24,739	)
Financing activities:
Repayment of term facilities		(652	)		–			(652	)
Increase in term facilities		21,200			–			21,200
Financing costs		(8	)		–			(8	)
Cash settlement of stock options		(66	)		–			(66	)
Repayment of capital lease obligations		(1,477	)		–			(1,477	)

		18,997			–			18,997

Increase in cash and cash equivalents		17,502			(59	)		17,443
Cash and cash equivalents, beginning of period		79,989			284			80,273

Cash and cash equivalents, end of period		$97,491			$225			$97,716

26 Notes to Consolidated Financial Statements North American Energy Partners Inc.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)


Consolidated Statements of Cash Flows – Six months ended September 30, 2009
Cash provided by (used in):	US GAAP			Adjustments			Canadian GAAP
Operating activities:
Net income for the period		$14,226			$2,335			$16,561
Items not affecting cash:
Depreciation		20,150			(62	)		20,088
Equity in loss of unconsolidated joint venture		32			(32	)		–
Amortization of intangible assets		910			413			1,323
Amortization of deferred lease inducements		(61	)		–			(61	)
Amortization of deferred financing costs		1,643			(1,203	)		440
Loss on disposal of property, plant and equipment		301			–			301
Gain on disposal of assets held for sale		(276	)		–			(276	)
Unrealized foreign exchange gain on 8³/4% senior notes		(37,600	)		404			(37,196	)
Unrealized loss on derivative financial instruments measured at fair value		27,975			(2,328	)		25,647
Stock-based compensation expense		2,449			(24	)		2,425
Accretion of asset retirement obligation		(12	)		–			(12	)
Deferred income taxes		2,597			465			3,062
Net changes in non-cash working capital		(16,326	)		(729	)		(17,055	)

		16,008			(761	)		15,247
Investing activities:
Acquisition		(4,880	)		–			(4,880	)
Purchase of property, plant and equipment		(42,460	)		–			(42,460	)
Addition to intangible assets		(805	)		–			(805	)
Additions to assets held for sale		(933	)		–			(933	)
Investment in and advances to unconsolidated joint venture		(986	)		986			–
Proceeds on disposal of property, plant and equipment		696			–			696
Proceeds on disposal of assets held for sale		1,112			–			1,112
Net changes in non-cash working capital		2,647			–			2,647

		(45,609	)		986			(44,623	)
Financing activities:
Repayment of term facilities		(652	)		–			(652	)
Increase in term facilities		33,000			–			33,000
Financing costs		(1,123	)		–			(1,123	)
Cash settlement of stock options		(66	)		–			(66	)
Repayment of capital lease obligations		(2,947	)		–			(2,947	)

		28,212			–			28,212

Decrease in cash and cash equivalents		(1,389	)		225			(1,164	)
Cash and cash equivalents, beginning of period		98,880			–			98,880

Cash and cash equivalents, end of period		$97,491			$225			$97,716

The areas of material difference between Canadian and US GAAP and their effect on the Company's consolidated financial statements are described below:

a) Capitalization of interest

US GAAP requires capitalization of interest costs as part of the historical cost of acquiring certain qualifying assets that require a period of time to prepare for their intended use. This is not required under Canadian GAAP. The capitalized amount is subject to depreciation in accordance with the Company’s policies when the asset is placed into service.

b) Financing costs, discounts and premiums

Under US GAAP, deferred financing costs incurred in connection with the Company's 9.125% Series 1 Debentures and 8³/4% senior notes were being amortized over the term of the related debt using the effective interest method. Prior to April 1, 2007, the transaction costs on the 8³/4% senior notes were recorded as a deferred asset under Canadian GAAP and these deferred financing costs were being amortized on a straight-line basis over the term of the debt.

Effective April 1, 2007, the Company adopted CICA Handbook Section 3855, "Financial Instruments – Recognition and Measurement", on a retrospective basis without restatement. Although Section 3855 also requires the use of the effective interest method to account for the amortization of finance costs, the requirement to bifurcate the issuer's early prepayment option on issuance of debt (which is not required under US GAAP) resulted in an additional premium of $3,497 on the Series 1 Debentures that is being amortized over the term of the Series 1 Debentures under Canadian GAAP. The same was being done on the extinguished 8³/4% senior notes. The unamortized premium is disclosed as part of the carrying amount of the “Series 1 debentures” in the Interim Consolidated Balance Sheets. Foreign denominated

North American Energy Partners Inc. Notes to Consolidated Financial Statements 27

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)

transaction costs, discounts and premiums on the 8³/4% senior notes were considered as part of the carrying value of the related financial liability under Canadian GAAP and were subject to foreign currency gains or losses resulting from periodic translation procedures as they were treated as a monetary item under Canadian GAAP. Under US GAAP, foreign denominated transaction costs are considered non-monetary and are not subject to foreign currency gains and losses resulting from periodic translation procedures. The unamortized discounts and premiums on the 8³/4% senior notes were expensed on the settlement of the 8³/4% senior notes under both Canadian and US GAAP with a difference of $2,884.

In connection with the adoption of Section 3855, transaction costs incurred in connection with the Company’s amended and restated credit agreement of $1,622 were reclassified from deferred financing costs to intangible assets on April 1, 2007 under Canadian GAAP and these costs continued to be amortized on a straight-line basis over the term of the credit facilities. Under US GAAP, the Company continues to amortize these transaction costs over the stated term of the related facilities using the effective interest method. The Company discloses the unamortized deferred financing costs related to the Series 1 Debentures, the 8³/4% senior notes and the credit facilities as “Deferred financing costs” on the Interim Consolidated Balance Sheets (September 30, 2010 – $8,398; March 31, 2010 – $6,725) with the amortization charge classified as “Interest expense” on the Interim Consolidated Statement of Operations and Comprehensive Income (Loss). Under Canadian GAAP, the unamortized financing costs related to the Series 1 Debentures (September 30, 2010 – $6,535) and the 8³/4% senior notes (March 31, 2010 – $1,506) are included in “Series 1 debentures” and “8³/4% senior notes” respectively whilst the unamortized deferred financing costs in connection with the credit facilities (September 30, 2010 – $1,735; March 31, 2010 – $1,051) are included in “Intangible assets” on the Interim Consolidated Balance Sheets resulting in a Canadian and US GAAP presentation difference.

c) Stock-based compensation

Up until April 1, 2006, the Company followed the provisions of ASC 718, “Share-Based Payment”, for US GAAP purposes. As the Company uses the fair value method of accounting for all stock-based compensation payments under Canadian GAAP, there were no differences between Canadian and US GAAP prior to April 1, 2006. On April 1, 2006, the Company adopted the provisions of SFAS No. 123(R), "Share-Based Payment", which is now a part of ASC 718. As the Company used the minimum value method for purposes of complying with ASC 718, it was required to adopt the provisions under the revised guidance prospectively. Under Canadian GAAP, the Company was permitted to exclude volatility from the determination of the fair value of stock options granted until the filing of its initial registration statement relating to the initial public offering of voting shares on July 21, 2006. As a result, for options issued between April 1, 2006 and July 21, 2006, there is a difference between Canadian and US GAAP relating to the determination of the fair value of options granted.

On September 22, 2010, the Company modified a senior executive employment agreement to allow the option holder the right to settle options in cash, which resulted in 550,000 stock options changing classification from equity to a long term liability. Under US GAAP, such modification is measured at fair value using a model such as Black-Scholes. Under Canadian GAAP, stock options that are cash settled are measured at the amount by which the quoted market value of the shares of the Company's stock covered by the grant exceeds the option price. This resulted in a measurement difference between US and Canadian GAAP. At September 30, 2010, the liability under US GAAP was measured at $3,482 of which $2,237 was transferred from additional paid-in capital and the difference of $1,245 was recognized as incremental compensation cost in the Interim Consolidated Statements of Operations and Comprehensive Income (Loss) under General and administrative costs. Under Canadian GAAP, the liability was measured at $1,854 resulting in a transfer of the same amount from additional paid-in capital and the difference of $384 remaining in additional paid-in capital. There was no incremental compensation cost since the liability was less than the amount already previously recognized.

d) Derivative financial instruments

Under Canadian GAAP, the Company determined that the issuer's early prepayment option included in the Series 1 Debentures of $3,895 should be bifurcated from the host contract, along with a contingent embedded derivative liability of $398 in the Series 1 Debentures that provides for accelerated redemption by the holders in certain instances. These embedded derivatives were measured at fair value at April 7, 2010, the inception date of the Series 1 Debentures with the residual amount of the proceeds being allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of the Series 1 Debentures is accreted to par value over the term of the Series 1 Debentures using the effective interest method and is recognized as interest expense as discussed in b) above. The same accounting treatment was used on the extinguished 8³/4% senior notes.

28 Notes to Consolidated Financial Statements North American Energy Partners Inc.

Notes to Interim Consolidated Financial Statements

For the three and six months ended September 30, 2010

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

(Unaudited)

embedded derivative in the 8³/4% senior notes was measured at fair value and changes in fair value recorded in net income for all periods presented. The issuer's early prepayment option included in both the Series 1 Debentures and the 8³/4% senior notes did not meet the criteria as an embedded derivative under ASC 815 and was not bifurcated from the host contract resulting in a US GAAP and Canadian GAAP difference.

e) Joint venture

Under US GAAP, the Company records its share of earnings of the JV using the equity method of accounting. Under Canadian GAAP, the Company uses the proportionate consolidation method of accounting for the JV. Under the proportionate consolidation method the Company recognizes its share of the results of operations, cash flows, and financial position of the JV on a line-by-line basis in its consolidated financial statements. While there is no effect on net income or earnings per share as a result of the US GAAP treatment of the joint venture, as compared to Canadian GAAP, there are presentation differences affecting the disclosures in the interim consolidated financial statements and the supporting notes. Under Canadian GAAP, the following assets, liabilities, revenues and expenses and cash flows would be recorded using the proportionate consolidation method:


	September 30, 2010			March 31, 2010
Current assets		$4,538			$4,476
Long term assets		656			77
Current liabilities		1,504			1,636
Long term liabilities		4,260			2,970

Net equity		$(570	)		$(53	)


	Three Months Ended September 30,						Six Months Ended September 30,
	2010			2009			2010			2009
Gross revenues		$826			$408			$2,999			$1,043
Gross profit		221			(115	)		401			189
Expense		(495	)		(108	)		(918	)		(221	)

Net loss		$(274	)		$(223	)		$(517	)		$(32	)


	Three Months Ended September 30,						Six Months Ended September 30,
	2010			2009			2010			2009
Cash flow resulting from operating activities		$(591	)		$59			$(884	)		$225
Cash flow resulting from investing activities		759						636			–

Increase (decrease) in cash and cash equivalents		$168			$59			$(248	)		$225

f) Other matters

Other adjustments relate to the tax effect of items (a) through (d) above. The tax effects of temporary differences are described as future income taxes under Canadian GAAP whereas in these financial statements such amounts are described as deferred income taxes under US GAAP. In addition, Canadian GAAP generally refers to additional paid-in capital as contributed surplus for financial statement presentation purposes.

g) Recent Canadian accounting pronouncements not yet adopted

i) 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 January 1, 2011 for the amendments relating to embedded prepayment options. The Company is currently evaluating the effect of the amendments to the standard.

ii) Multiple deliverable arrangements

In December 2009, the CICA issued Emerging Issues Committee (EIC) 175, “Multiple deliverable arrangements”. This abstract addresses how to determine whether an arrangement involving multiple deliverables contains more than one unit of accounting. It also addresses how arrangement consideration should be measured and allocated to the separate units of accounting in the arrangement. For the Company, this abstract is effective on a prospective basis to all revenue arrangements with multiple deliverables entered into or materially modified in the fiscal period beginning April 1, 2011. The Company is currently evaluating the effect of this abstract on the Company’s interim consolidated financial statements.

North American Energy Partners Inc. Notes to Consolidated Financial Statements 29

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2010

LOGO

TABLE OF CONTENTS


A.	Explanatory Notes	3
	Caution Regarding Forward-Looking Information	3
	Non-GAAP Financial Measures	3
	Adoption of United States GAAP	4
B.	Financial Results	5
	Analysis of Consolidated Results	6
	Segment Results	8
	Non-Operating Income and Expense	9
	Backlog	11
	Claims and Change Orders	12
	Summary of Consolidated Quarterly Results	12
	Summary of Consolidated Financial Position	13
	Summary of Consolidated Cash Flows	14
C.	Outlook	15
D.	Legal and Labour Matters	16
	Laws and Regulations and Environmental Matters	16
	Employees and Labour Relations	16
E.	Resources and Systems	16
	Outstanding Share Data	16
	Liquidity and Capital Resources	16
	Capital Commitments	20
	Debt Ratings	21
	Related Parties	22
	Internal Systems and Processes	22
	Recently Adopted Accounting Policies	22
	Recent Accounting Pronouncements Not Yet Adopted	23
F.	Forward-Looking Information and Risk Factors	23
	Forward-Looking Information	23
	Risk Factors	25
	Quantitative and Qualitative Disclosures about Market Risk	25
G.	General Matters	26
	Additional Information	26

2 Management’s Discussion and Analysis North American Energy Partners Inc.

Management’s Discussion and Analysis

For the three and six months ended September 30, 2010

A. Explanatory Notes

November 2, 2010

The following interim Management’s Discussion and Analysis (MD&A) should be read in conjunction with the attached unaudited consolidated financial statements for the three and six months ended September 30, 2010. These statements have been prepared in accordance with United States (US) generally accepted accounting principles (GAAP) and reconciled to Canadian GAAP. This interim MD&A should also be read in conjunction with the audited consolidated financial statements for the year ended March 31, 2010, together with our annual MD&A for the year ended March 31, 2010. The consolidated financial statements, and additional information relating to our business, including our Annual Information Form (AIF), are available on the Canadian Securities Administrators’ SEDAR System at www.sedar.com, the Securities and Exchange Commission’s website at www.sec.gov and our company web site at www.nacg.ca.

Caution Regarding Forward-Looking Information

Our MD&A is intended to enable readers to gain an understanding of our current results and financial position. To do so, we provide information and analysis comparing results of operations and financial position for the current period to those of the preceding periods. We also provide analysis and commentary that we believe is necessary to assess our future prospects. Accordingly, certain sections of this report contain forward-looking information that is based on current plans and expectations. This forward-looking information is affected by risks and uncertainties that could have a material impact on future prospects. Please refer to “Forward-Looking Information and Risk Factors” for a discussion of the risks and uncertainties related to such information. Readers are cautioned that actual events and results may vary.

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. In our MD&A, we use non-GAAP financial measures such as “net income before interest expense, income taxes, depreciation and amortization” (EBITDA) and “Consolidated EBITDA” (as defined in our credit agreement). Consolidated EBITDA 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. As EBITDA and Consolidated EBITDA are non-GAAP financial measures, 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 US GAAP or Canadian GAAP. For example, EBITDA and Consolidated EBITDA do not:

_Ÿ

reflect our cash expenditures or requirements for capital expenditures or capital commitments;

_Ÿ

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

_Ÿ

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

_Ÿ

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

_Ÿ

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. Where relevant, particularly for earnings-based measures, we provide tables in this document that reconcile non-GAAP measures used to amounts reported on the face of the consolidated financial statements.

North American Energy Partners Inc. Management’s Discussion and Analysis 3

Adoption of United States GAAP

As a Canadian-based company, we have historically prepared our consolidated financial statements in accordance with Canadian GAAP and provided reconciliations to United States (US) GAAP. In 2006, the Canadian Accounting Standards Board (“AcSB”) published a new strategic plan that significantly affected financial reporting requirements for Canadian public companies. The AcSB strategic plan outlined the convergence of Canadian GAAP with International Financial Reporting Standards (IFRS) over an expected five-year transitional period. In February 2008, the AcSB confirmed that IFRS would be mandatory in Canada for profit-oriented publicly accountable entities for fiscal periods beginning on or after January 1, 2011, unless we, as a Securities and Exchange Commission (SEC) registrant and as permitted by National Instrument 52-107, were to adopt US GAAP on or before this date.

After significant analysis and consideration regarding the merits of reporting under IFRS or US GAAP, we decided to adopt US GAAP, commencing in fiscal 2010, as our primary reporting standard for our consolidated financial statements. Our interim consolidated financial statements for the three and six months ended September 30, 2009, including related notes and accompanying MD&A, were restated based on US GAAP on June 10, 2010 and are available on the Canadian Securities Administrators’ SEDAR System at www.sedar.com, the Securities and Exchange Commission’s website at www.sec.gov and our company web site at www.nacg.ca. All comparative figures contained in our current interim consolidated financial statements for the three and six months ended September 30, 2010, including related notes and this MD&A, reflect our results in accordance with US GAAP as our reporting standard.

As required by National Instrument 52-107, for the fiscal year of adoption of US GAAP and one subsequent fiscal year, we will provide a Canadian Supplement to our MD&A that restates, based on financial information reconciled to Canadian GAAP, those parts of our MD&A that would contain material differences if they were based on financial statements prepared in accordance with Canadian GAAP. In support of the adoption of US GAAP commencing in fiscal 2010, we provided a Canadian Supplement MD&A for our audited consolidated financial statements, related notes and accompanying MD&A, for the year ended March 31, 2010. As well, we provided a Canadian Supplement MD&A for each of the restated interim periods for fiscal 2010. The Canadian Supplement MD&A will continue to be provided through fiscal 2011 for each of the reporting periods.

4 Management’s Discussion and Analysis North American Energy Partners Inc.

B. Financial Results

Consolidated Three and Six Month Results


	Three Months Ended September 30,
(dollars in thousands, except per share amounts)	2010			% of Revenue			2009		% of Revenue		Change
Revenue	$	234,858			100.0%		$	170,702		100.0%	$	64,156
Project costs		132,440			56.4%			65,437		38.3%		67,003
Equipment costs		46,358			19.7%			44,359		26.0%		1,999
Equipment operating lease expense		18,909			8.1%			15,684		9.2%		3,225
Depreciation		8,054			3.4%			11,426		6.7%		(3,372	)

Gross profit		29,097			12.4%			33,796		19.8%		(4,699	)
General and administrative costs		15,286			6.5%			13,918		8.2%		1,368

Operating income		12,305			5.2%			18,937		11.1%		(6,632	)
Net income		2,369			1.0%			4,299		2.5%		(1,930	)
Per share information												–
Net income – basic	$	0.07					$	0.12			$	(0.05	)
Net income – diluted		0.06						0.12				(0.06	)
EBITDA⁽¹⁾	$	22,299			9.5%		$	23,871		14.0%	$	(1,572	)
Consolidated EBITDA⁽¹⁾ (as defined within the credit agreement)	$	22,609			9.6%		$	31,978		18.7%	$	(9,369	)


	Six Months Ended September 30,
(dollars in thousands, except per share amounts)	2010			% of Revenue			2009		% of Revenue		Change
Revenue	$	418,452			100.0%		$	317,221		100.0%	$	101,231
Project costs		209,717			50.1%			119,699		37.7%		90,018
Equipment costs		111,361			26.6%			90,403		28.5%		20,958
Equipment operating lease expense		36,400			8.7%			28,033		8.8%		8,367
Depreciation		16,257			3.9%			20,150		6.4%		(3,893	)

Gross profit		44,717			10.7%			58,936		18.6%		(14,219	)
General and administrative costs		29,015			6.9%			28,894		9.1%		121

Operating income		13,369			3.2%			29,075		9.2%		(15,706	)
Net (loss) income		(7,940	)		(1.9%	)		14,226		4.5%		(22,166	)
Per share information
Net (loss) income – basic	$	(0.22	)				$	0.39			$	(0.61	)
Net (loss) income – diluted		(0.22	)					0.39				(0.61	)
EBITDA⁽¹⁾	$	26,497			6.3%		$	52,108		16.4%	$	(25,611	)
Consolidated EBITDA⁽¹⁾ (as defined within the credit agreement)	$	34,788			8.3%		$	51,372		16.2%	$	(16,584	)

⁽¹⁾	A reconciliation of net income (loss) to EBITDA and Consolidated EBITDA is as follows:

North American Energy Partners Inc. Management’s Discussion and Analysis 5


	Three Months Ended September 30,						Six Months Ended September 30,
(dollars in thousands)	2010		2009		Change		2010		2009		Change
Net income (loss)		$2,369		$4,299		$(1,930)		$(7,940)		$14,226		$(22,166)
Adjustments:
Interest expense		7,708		6,409		1,299		15,437		12,961		2,476
Income taxes		3,496		1,320		2,176		1,483		3,861		(2,378)
Depreciation		8,054		11,426		(3,372)		16,257		20,150		(3,893)
Amortization of intangible assets		672		417		255		1,260		910		350

EBITDA		$22,299		$23,871		$(1,572)		$26,497		$52,108		$(25,611)
Adjustments:
Unrealized foreign exchange (gain) loss on senior notes		–		(18,060)		18,060		–		(37,600)		37,600
Realized and unrealized (gain) loss on derivative financial instruments		(1,308)		25,154		(26,462)		1,700		35,175		(33,475)
(Gain) Loss on disposal of plant and equipment and assets held for sale		560		301		259		556		25		531
Stock-based compensation expense		784		489		295		1,194		1,632		(438)
Equity in earnings of unconsolidated joint venture		274		223		51		517		32		485
Loss on debt extinguishment		–		–		–		4,324		–		4,324

Consolidated EBITDA		$22,609		$31,978		$(9,369)		$34,788		$51,372		$(16,584)

Analysis of Consolidated Results

Revenue

For the three months ended September 30, 2010, consolidated revenues increased to $234.9 million, $64.2 million higher than in the same period last year. This improvement reflects higher project development revenues from all three operating segments. In our oil sands business, tailings-related construction projects at Shell Albian¹, together with site development projects at Canadian Natural’s² Horizon mine and Exxon’s Kearl³ mine contributed to the growth in project development revenues. Outside of the oil sands, improving commercial and industrial construction market conditions led to increased piling activity, despite a continuation of unseasonably high precipitation levels. Pipeline revenues were also higher year-over-year as a result of two new projects in northern British Columbia, which commenced during the period. Recurring services revenues declined as we reduced activity with Shell Albian during the commissioning of the Jackpine mine. The reduction at Shell Albian was partially offset by increased overburden removal activity under our long-term contract with Canadian Natural and by the continued provision of mine support services to both Syncrude⁴ and Suncor⁵.

For the six months ended September 30, 2010, revenues increased to $418.5 million, $101.2 million higher than during the same period last year. This improvement reflects increases in both recurring services and project development revenues. Recurring services revenues benefited from higher volumes at the Canadian Natural and Suncor sites, which helped to offset the impact of reduced volumes at Shell Albian during the commissioning of the Jackpine Mine. Project development activity benefitted from increased construction spending in the oil sands, improved piling demand from the commercial and industrial construction markets and the start-up of the two new projects in the Pipeline segment.

Gross Profit

Gross profit for the three months ended September 30, 2010 was $29.1 million, a decrease of $4.7 million from the same period last year. This change reflects a reduction in gross profit margins to 12.4% from 19.8%, resulting from lower-margin contracts in the project mix and reduced productivity on certain projects as a result of client start-up delays and unseasonably wet weather. Margins on our recurring services revenue were primarily impacted by an increase in lower-margin activity on our long-term overburden removal contract and reduced activity at Shell Albian. Margins on our project development revenues reflected the impact of low-margin pipeline contracts, as well as productivity impacts related to delayed start-ups and abnormally wet weather conditions on those projects. The decrease in gross margin was partially offset by improved Piling segment margins, which increased significantly despite challenging weather in most regions, reflecting improving markets conditions.

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.

²	Canadian Natural Resources Limited (Canadian Natural) Horizon project.

³	Exxon Kearl (Kearl) oil sands mining and extraction project. Imperial Oil Limited holds a 70.96% participating interest in the Kearl oil sands project, a joint venture with ExxonMobil Canada Properties, a subsidiary of Exxon Mobil Corporation. Imperial Oil Limited is the project operator.

⁴

Syncrude Canada Limited (Syncrude), a joint venture between Canadian Oil Sands Limited (36.74%), Imperial Oil Limited (25.0%), Suncor Energy Inc. (12.0%) (Previously Petro-Canada Ltd.), 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	Suncor Energy Inc. (Suncor).

6 Management’s Discussion and Analysis North American Energy Partners Inc.

Project costs, as a percentage of revenue, increased to 56.4% during the three months ended September 30, 2010, from 38.3% in the same period last year. This change reflects the increase in project development activity, which is traditionally more labour, material and subcontractor-intensive than recurring services work. Client start-up delays on some projects and weather-related productivity issues added to the higher project costs for the period.

For the three months ended September 30, 2010, equipment costs decreased to 19.7% of revenue, from 26.0% last year, reflecting the increase in the less equipment-intensive project development activity. Equipment operating lease expense increased $3.2 million to $18.9 million or 8.1% of revenue, compared to 9.2% of revenue in the same period last year. The increase in equipment operating lease expense reflects additions to our overburden removal equipment fleet in the latter part of fiscal 2010. Depreciation expense decreased by $3.4 million to $8.1 million in the three months ended September 30, 2010, compared to the same period last year. The lower depreciation reflects the increased use of smaller construction equipment in the project development business and the use of rentals to supplement our owned construction fleet during the period. The predominant work undertaken in the period was related to construction which necessitates a large number of 100 to 150 ton trucks working 10 hours per day. The amount of equipment required exceeded our owned fleet capacity in this size of truck. At the same time, there was a reduction in mining type work that resulted in our larger 240 ton fleet being idle in a period it would normally be well utilized on 24 hour per day work. Increased utilization of our leased mining fleet for overburden removal and lower utilization of our owned mining fleet in the recurring services business also contributed to the lower depreciation expense. Depreciation expense for the prior year three-month period included accelerated depreciation of $1.5 million.

Gross profit for the six months ended September 30, 2010 was $44.7 million, a decrease of $14.2 million compared to the same period last year. As a percentage of revenue, gross profit margin decreased to 10.7% reflecting increased volumes of lower-margin activity under our long-term overburden removal contract, lower activity levels at Shell Albian, the impact of poor weather conditions on our construction business and productivity issues related to start-up delays and adverse weather on two pipeline projects. Margin performance for the current six-month period was further affected by higher equipment costs related to the increased repair maintenance activity undertaken during the extended spring breakup period and was exacerbated by the lower than planned utilization of our large mining trucks and shovels.

Project costs, as a percentage of revenue, increased to 50.1% during the six months ended September 30, 2010, from 37.7% in the same period last year. The increase in project development activity, coupled with start-up delays and weather-related productivity issues, were key factors in this increase. Equipment costs for the first six months decreased to 26.6% of revenue, from 28.5% during the same period last year, reflecting the increase in project development activity. Equipment operating lease expense increased by $8.4 million year-over-year to $36.4 million, reflecting additions to our overburden removal equipment fleet in the latter part of fiscal 2010. Depreciation expense declined by $3.9 million to $16.3 million in the six months ended September 30, 2010, compared to the same period last year. The lower depreciation reflects the increased utilization of rentals, smaller construction equipment and the leased overburden removal fleet and reduced utilization of our own mining fleet. Depreciation expense for the prior year six-month period included accelerated depreciation of $3.2 million as certain aging equipment was prepared for sale.

Operating income

For the three months ended September 30, 2010, we recorded operating income of $12.3 million or 5.2% of revenue, compared to operating income of $18.9 million or 11.1% of revenue, during the same period last year. General and administrative (G&A) costs increased by $1.4 million compared to the same period last year. The increase in G&A costs reflects the impact of a partial restructuring of our stock option plan.

For the six months ended September 30, 2010, we recorded operating income of $13.4 million or 3.2% of revenue, compared to operating income of $29.1 million or 9.2% of revenue during the first six months last year. G&A costs remained flat compared to the prior year.

Net income (loss)

For the three months ended September 30, 2010, we recorded net income of $2.4 million (basic income per share of $0.07 and diluted income per share of $0.06), compared to net income of $4.3 million (basic and diluted income per share of $0.12) during the same period last year. The non-cash items affecting results in the current period included gains on embedded derivatives in certain long-term supplier contracts, partially offset by losses on the embedded derivatives in a long-term customer contract. In the prior-year period, the non-cash items affecting net income included losses on our cross-currency and interest rate swaps, losses on embedded derivatives in certain long-term supplier contracts and losses on the embedded derivatives in a long-term customer contract. Partially offsetting these losses was the positive foreign exchange impact of the strengthening Canadian dollar on our 8³/4% senior notes and a gain on an embedded derivative related to redemption options in our 8³/4% senior notes. Excluding the above items, net income for the three months ended September 30, 2010 would have been $1.4 million (basic and diluted income per share of $0.04), compared to net income of $6.9 million during the same period last year (basic and diluted income per share of $0.19).

For the six months ended September 30, 2010, we recorded a net loss of $7.9 million (basic loss per share of $0.22) compared to net income of $14.2 million (basic income and diluted income per share of $0.39) during the same period

North American Energy Partners Inc. Management’s Discussion and Analysis 7

last year. The non-cash items affecting current-year results included the write-off of deferred financing costs at the settlement of the 8³/4% senior notes and losses on cross-currency and interest rate swaps. Partially offsetting these losses were the positive foreign exchange impact of the strengthening Canadian dollar on our 8³/4% senior notes, gains on embedded derivatives in certain long-term supplier contracts and gains on the embedded derivatives in a long-term customer contract. In the prior-year period, non-cash items affecting results included the positive foreign exchange impact of the strengthening Canadian dollar on our 8³/4% senior notes, gains on an embedded derivative related to redemption options in the 8³/4% senior notes and gains embedded derivatives in long-term supplier contracts. Partially offsetting these gains were losses on cross-currency and interest rate swaps and losses on embedded derivatives in a long-term customer contract. Excluding the above items, net loss for the six months ended September 30, 2010 would have been $2.7 million (basic loss per share of $0.07), compared to net income of $6.9 million during the same period last year (basic and diluted income per share of $0.19).

Segment Results

Heavy Construction and Mining


	Three Months Ended September 30,						Six Months Ended September 30,
(dollars in thousands)	2010		2009		Change		2010		2009		Change
Segment revenue	$	171,628	$	154,055	$	17,573	$	335,237	$	285,881	$	49,356
Segment profit	$	22,234	$	21,922	$	312	$	44,481	$	45,437	$	(956	)
Project margin		13.0%		14.2%				13.3%		15.9%

For the three months ended September 30, 2010, Heavy Construction and Mining segment revenues increased $17.6 million compared to the same period last year, reflecting increased project development revenues. The segment benefited from several new oil sands projects, including tailings-related construction projects for Shell Albian and mine development projects for Exxon and Canadian Natural. Recurring services revenues decreased compared to the same period last year as a result of reduced activity at Shell Albian during the commissioning of the Jackpine mine and the resulting integration activities at the Muskeg River mine. Increased activity on our long-term overburden contract with Canadian Natural and increased activity at Suncor helped mitigate this decline in recurring services revenues.

For the six months ended September 30, 2010, the Heavy Construction and Mining segment reported revenues of $335.2 million, a $49.4 million increase compared to the same period last year. Recurring services and project development revenues both increased year-over-year. Recurring services revenues were higher as a result of increased services to Suncor and Canadian Natural helping to offset reduced activity at Shell Albian’s Jackpine and Muskeg River sites. Project development revenues for the current six-month period also improved compared to last year, with the start-up of construction projects at Exxon’s Kearl and Canadian Natural’s Horizon sites and tailings-related construction projects at Shell Albian.

For the three months ended September 30, 2010, Heavy Construction and Mining profit margin was 13.0% of revenue, compared to 14.2% of revenue during the same period last year. The profit margin in the prior-year period was lower than normal due to the impact of a margin adjustment on our long-term overburden removal contract. Excluding this impact, profit margin for the prior-year period would have been 16.8% of revenue. The year-over-year change in Heavy Construction and Mining profit margin primarily reflects an increase in lower-margin overburden removal work, weather-related productivity impacts and start-up delays on a construction project.

For the six months ended September 30, 2010, Heavy Construction and Mining profit margin decreased to 13.3% of revenue, from 15.9% during the same period last year. The change in margin reflects the increase in lower-margin overburden removal work, costs from client start-up delays on a construction project and lower project efficiency due to poor weather.

Piling


	Three Months Ended September 30,						Six Months Ended September 30,
(dollars in thousands)	2010		2009		Change		2010		2009		Change
Segment revenue	$	26,563	$	15,058	$	11,505	$	45,709	$	29,676	$	16,033
Segment profit		$4,782		$1,950		$2,832		$6,176		$4,634		$1,542
Project margin		18.0%		12.9%				13.5%		15.6%

For the three months ended September 30, 2010, Piling segment revenues climbed to $26.6 million, an increase of $11.5 million compared to the same period last year. For the six months ended September 30, 2010, Piling segment revenues increased to $45.7 million, up $16.0 million from same period last year. In both periods, the revenue increase reflects improved activity levels in the commercial and industrial construction markets, including an increase in high-volume oil sands projects. The higher revenues also reflect the start-up of jobs delayed by weather during the first

8 Management’s Discussion and Analysis North American Energy Partners Inc.

For the three months ended September 30, 2010, Piling profit margin increased to 18.0% of revenue, from 12.9% during the same period last year. The increase in margins in the current year reflects improving market conditions and increased demand, partially offset by reduced productivity as a result of abnormally high precipitation levels. For the six months ended September 30, 2010, Piling profit margin decreased to 13.5% from 15.6% a year ago. The year-over-year decline in profit margin reflects reduced productivity as a result of abnormally high precipitation levels and continued delays in the execution of certain project change-orders. We are working with our customers to expedite the execution of these change-orders.

Pipeline


	Three Months Ended September 30,							Six Months Ended September 30,
(dollars in thousands)	2010		2009			Change		2010		2009		Change
Segment revenue	$	36,667	$	1,589		$	35,078	$	37,506	$	1,664	$	35,842
Segment profit	$	879	$	(137	)	$	1,016	$	156	$	229	$	(73	)
Project margin		2.4%		-8.6%					0.4%		13.8%

For the three months ended September 30, 2010, the Pipeline segment increased revenues to $36.7 million, an improvement of $35.1 million compared to a year ago. For the six months ended September 30, 2010, Pipeline revenues increased to $37.5 million, a year-over-year increase of $35.8 million. The significant increase in revenues in both periods reflects the start-up of two new projects in northern British Columbia (BC) and continued progress on an existing project in southern BC.

For the three months ended September 30, 2010, Pipeline profit margins increased to 2.4%, from a loss of 8.6% a year ago. For the six months ended September 30, 2010, segment margin was 0.4%, compared to 13.8% a year ago. The decline in profit margin for the six-month period reflects productivity impacts related to client start-up delays and abnormally wet weather conditions on the two new projects and project completion delays on the existing in southern BC. All three projects are unit-price contracts.

Non-Operating Income and Expense


	Three Months Ended September 30,									Six Months Ended September 30,
(dollars in thousands)	2010			2009			Change			2010			2009			Change
Interest expense
Long term debt
Interest on 8³/4% senior notes and swaps		$–			$4,737		$	(4,737	)		$1,238			$9,881			$(8,643	)
Interest on series 1 debentures		5,133			–			5,133			9,867			–			9,867
Interest on term facilities		1,298			197			1,101			2,264			492			1,772
Interest on capital lease obligations		182			270			(88	)		390			561			(171	)
Amortization of deferred financing costs		357			838			(481	)		883			1,643			(760	)

Interest on long term debt		6,970			6,042			928			14,642			12,577			2,065
Other interest		738			367			371			795			384			411

Total Interest expense		$7,708			$6,409			$1,299			$15,437			$12,961			$2,476
Foreign exchange loss (gain)		49			(18,045	)		18,094			(1,648	)		(37,481	)		35,833
Realized and unrealized (gain) loss on derivative financial instruments		(1,308	)		25,154			(26,462	)		1,700			35,175			(33,475	)
Loss on debt extinguishment		–			–			–			4,346			–			4,346
Other (income) expense		(9	)		(200	)		191			(9	)		333			(342	)
Income tax expense		3,496			1,320			2,176			1,483			3,861			(2,378	)

Interest expense

Total interest expense increased $1.3 million in the three months ended September 30, 2010 and $2.5 million in the six months ended September 30, 2010, compared to the corresponding periods in the prior year. In April 2010, we closed a private placement of 9.125% Series 1 Debentures (Series 1 Debentures) due April 7, 2017 for gross proceeds of $225.0 million. On March 29, 2010, we issued a redemption notice to holders of the 8³/4% senior notes to redeem all outstanding 8³/4% senior notes and, on April 28, 2010, the notes were redeemed and cancelled. The redemption amount included the US$200.0 million principal outstanding and US$7.1 million of accrued interest. On April 8, 2010, we terminated the cross currency and interest rate swaps used to hedge interest rate and currency exposure on the US dollar denominated 8³/4% senior notes. Interest expense on our 8³/4% senior notes of $1.2 million during the current six-month period reflects interest costs to the redemption date. Series 1 Debentures interest expense of $9.9 million for the six months ended September 30, 2010, reflects interest for the partial period that followed the issuance of the Series 1 Debentures on April 7, 2010. The redemption and associated swap agreement terminations eliminate the refinancing risk in December 2011 and also eliminated the cost of hedging the foreign currency interest rate which was

North American Energy Partners Inc. Management’s Discussion and Analysis 9

reflected as a portion of “realized and unrealized (gain) loss on derivative financial instruments”. The prior year interest hedge costs were $3.9 million and $7.2 million, respectively, for the three and six months ended September 30, 2009. A more detailed discussion on the restructuring of our long-term debt can be found under “Liquidity and Capital Resources”.

On April 30, 2010, we also entered into a fourth amended and restated credit agreement to extend the term of the credit agreement and to add additional borrowing capacity of up to $50.0 million through a second term facility within the credit agreement. At September 30, 2010, the second term facility was fully drawn. The new term facility, along with the existing term facility, matures on April 30, 2013. At September 30, 2010, we had $73.4 million outstanding on the Term Facilities ($28.4 million at March 31, 2010). Interest expense for the credit facility was $1.3 million and $2.3 million for the three and six months ended September 30, 2010, respectively, reflecting the cost of the higher amounts borrowed on the term facilities.

Foreign exchange loss (gain)

The foreign exchange gains recognized in the prior year three and six-month periods relate primarily to the effect of changes in the exchange rate of the Canadian dollar against the US dollar on the carrying value of the US$200 million 8³/4% senior notes. The increase in the value of the Canadian dollar, from 0.9846 CAN/US at March 31, 2010 to 0.9874 CAN/US at April 28, 2010 when the 8³/4% senior notes were redeemed, resulted in a realized foreign exchange gain for the current six-month period. A more detailed discussion about our foreign currency risk can be found under “Quantitative and Qualitative Disclosures about Market Risk – Foreign exchange risk”.

Realized and unrealized (gain) loss on derivative financial instruments

The realized and unrealized (gain) loss on derivative financial instruments reflect changes in the fair value of derivatives embedded in our previously held US dollar denominated 8³/4% senior notes, as well as changes in the fair value of the cross-currency and interest rate swaps that we employed to provide an economic hedge for our previously held US dollar denominated 8³/4% senior notes. Realized and unrealized gains and losses also include changes in the value of embedded derivatives in a long-term customer contract and in supplier maintenance agreements. The realized and unrealized gains and losses on these derivative financial instruments, for the three and six months ended September 30, 2010, respectively, are detailed in the table below:


	Three Months Ended September 30,									Six Months Ended September 30,
(dollars in thousands)	2010			2009			Change			2010			2009			Change
Swap liability loss		$–			$18,983		$	(18,983	)		$1,783			$38,818		$	(37,035	)
Redemption option embedded derivative gain		–			(1,139	)		1,139			–			(3,412	)		3,412
Supplier contracts embedded derivatives (gain) loss		(1,656	)		460			(2,116	)		(9	)		(13,704	)		13,695
Customer contract embedded derivative loss (gain)		348			2,986			(2,638	)		(402	)		6,273			(6,675	)
Swap interest payment		–			3,864			(3,864	)		328			7,200			(6,872	)

Total	$	(1,308	)		$25,154		$	(26,462	)		$1,700			$35,175		$	(33,475	)

The measurement of embedded derivatives, as required by GAAP, causes our reported net income to fluctuate as Canadian/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.

The Swap liability loss reflects the changes in the fair value of the cross-currency and interest rate swaps that we employed to provide an economic hedge for our previously held US dollar denominated 8³/4% senior notes. Changes in the fair value of these swaps generally had an offsetting effect to changes in the value of our previously held 8³/4% senior notes (and resulting foreign exchange gains and losses), with both being triggered by variations in the Canadian/US dollar exchange rate. However, the valuations of the derivative financial instruments were also impacted by changes in interest rates and the remaining present value of scheduled interest payments on the swaps, which occurred in June and December of each year until termination of the swap agreements on April 8, 2010.

The redemption option embedded derivative gain in the prior year reflects changes in the fair value of a derivative embedded in our previously held US dollar denominated 8³/4% senior notes. Changes in fair value resulted from changes in long-term bond interest rates during a reporting period.

With respect to the supplier contracts, the fair value of the embedded derivative related to a long-term supplier contract decreased as a result of the strengthening of the Canadian dollar against the US dollar during the three months ended September 30, 2010. Included in the embedded derivative valuation was the impact of fluctuations in provisions that require a price adjustment to reflect changes in the Canadian/US dollar exchange rate and the United States government published Producers’ Price Index (US-PPI) for Mining Machinery and Equipment from the original contract amount.

10 Management’s Discussion and Analysis North American Energy Partners Inc.

With respect to the long-term customer contract, there is a provision that requires an adjustment to customer billings to reflect actual exchange rates and price indices. The embedded derivative instrument takes into account the impact on revenues, but does not consider the impact on costs as a result of fluctuations in these measures.

The measurement of the swap interest payment loss for the six months ended September 30, 2010 reflects the realized loss on our previously held interest rate swaps. As of February 2, 2009, one of three swap agreements hedging the interest and currency risk associated with our previously held US dollar denominated 8³/4% senior notes was cancelled by the counterparties. As a result of the counterparties’ cancellation of this US dollar interest rate swap, we were incurring higher interest expense and we were exposed to interest rate and foreign currency risk.

Income tax expense

For the three months ended September 30, 2010, we recorded current income taxes of $3.3 million and deferred income tax of $0.2 million for a total income tax expense of $3.5 million, a $2.2 million increase year-over-year. For the three months ended September 30, 2010, income tax expense as a percentage of income before income taxes differs from the statutory rate of 27.77% primarily due to the impact of changes in enacted tax rates, CRA audit adjustments from 2007 and 2008 which are flowing through the current and deferred income tax accounts and increase in the permanent differences in stock based compensation as a result of a partial restructuring of the stock option plan. For the three months ended September 30, 2009, income tax expense as a percentage of income before income taxes differed from the statutory rate of 28.91% primarily due to the effect of changes in enacted tax rates and the benefit from changes in the timing of the reversal of temporary differences.

For the six months ended September 30, 2010, we recorded current income taxes of $4.5 million and deferred income tax recovery of $3.0 million for a total income tax expense of $1.5 million, a $2.4 million reduction year-over-year. For the six months ended September 30, 2010, income tax expense as a percentage of income before income taxes differs from the statutory rate of 27.77% primarily due to the effect of changes in enacted tax rates, the realization of capital loss on extinguishment of the 8³/4% senior notes and the cross-currency swap, CRA audit adjustments from 2007 and 2008 which are flowing through the current and deferred income tax accounts and increases in the permanent differences in stock based compensation as a result of a partial restructuring of the stock option plan. For the six months ended September 30, 2009, income tax expense as a percentage of income before income taxes differed from the statutory rate of 28.91% primarily due to the effect of changes in enacted tax rates and the benefit from changes in the timing of the reversal of temporary differences.

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 varies year-by-year. Our definition of backlog results in the exclusion of a range of services to be provided under cost-plus and time-and-material contracts performed under master service agreements where scope is not clearly defined. For the three and six months ended September 30, 2010, the total amount of revenue earned from time-and-material contracts performed under our master services agreements was approximately $61.6 million and $145.8 million, respectively.

Our estimated backlog by segment and contract type as at September 30, 2010 and 2009 as well as March 31, 2010 was:

By Segment


(dollars in thousands)	September 30, 2010		March 31, 2010		September 30, 2009
Heavy Construction & Mining		$780,537		$800,751		$811,803
Piling		21,667		16,423		3,630
Pipeline		32,024		6,861		8,207

Total		$834,228		$824,035		$823,640


By Contract Type
Unit-Price		$796,506		$797,694		$813,693
Lump-Sum		28,534		18,429		9,947
Time-and-Material, Cost-Plus		9,188		7,912		–

Total		$834,228		$824,035		$823,640

North American Energy Partners Inc. Management’s Discussion and Analysis 11

A contract with a single customer represented approximately $717.7 million of our September 30, 2010 backlog compared to $758.9 million reported as backlog in our interim Management’s Discussion and Analysis for the three and six months ended September 30, 2009. The decrease 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 $292.6 million of total backlog will be performed and realized in the twelve months ending September 30, 2011.¿

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:

_Ÿ

changes in client requirements, specifications and design;

_Ÿ

changes in materials and work schedules; and

_Ÿ

changes in ground and weather conditions.

Contract change management processes require that we prepare and submit change orders to the client requesting approval of scope and/or price adjustments to the contract. Accounting guidelines require that 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.

Summary of Consolidated Quarterly Results


	Three month period ended
(dollars in millions, except per share amounts)	Sep 30, 2010		Jun 30, 2010			Mar 31, 2010			Dec 31, 2009		Sep 30, 2009		Jun 30, 2009		Mar 31, 2009			Dec 31, 2008
	Fiscal 2011					Fiscal 2010									Fiscal 2009
Revenue		$234.9		$183.6			$220.6			$221.2		$170.7		$146.5		$174.7			$258.6
Gross profit		29.1		15.6			32.7			47.6		33.8		25.1		32.9			51.4
Operating income (loss)		12.3		1.1			13.1			31.3		18.9		10.1		(129.2	)		(1.9	)
Net income (loss)		2.4		(10.3	)		(0.9	)		14.9		4.3		9.9		(137.1	)		(15.0	)
Income (loss) per share – Basic		$0.07		$(0.29	)		$(0.03	)		$0.41		$0.12		$0.28		$(3.80	)		$(0.42	)
Income (loss) per share – Diluted		$0.06		$(0.29	)		$(0.03	)		$0.41		$0.12		$0.27		$(3.80	)		$(0.42	)

±	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.

A number of factors have the potential to contribute to variations in our quarterly financial results between periods, including the capital project-based nature of our project development revenue, seasonal weather and ground conditions, capital spending decisions by our customers on large oil sands projects, the timing of equipment maintenance and repairs, claims and change orders and the accounting for unrealized non-cash gains and losses related to foreign exchange and derivative financial instruments.

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 it 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

^¿	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.

12 Management’s Discussion and Analysis North American Energy Partners Inc.

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 months ended March 31, 2008, as low as $0.1 million in the three months ended June 30, 2009 and are currently at $36.7 million for the three months ended September 30, 2010. The Heavy Construction and Mining segment experienced reduced volumes in the three months ended December 31, 2008 and the three months ended 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. Subsequent three-month periods reflected the ramp up of overburden removal activities at the Horizon project through to the three months ended March 31, 2010, where activity returned to planned activity levels. Changes in demand under our master service agreements with Shell Albian positively affected period-over-period comparatives until the three-month periods ended June 30 and September 30, 2010, as reduced Shell Albian activity resulted from the commissioning of their Jackpine mine and the related integration activities at their Muskeg River mine.

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 G&A costs, 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 quarter-to-quarter 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”.

We have also experienced net income variability in all periods up to the three months ended June 30, 2010, due to the recognition of unrealized non-cash gains and losses on both derivative financial instruments and our previously held US dollar denominated 8³/4% senior notes, primarily driven by changes in the Canadian/US dollar exchange rate. The 8³/4% senior notes were redeemed on April 28, 2010 and the associated currency and interest rate swaps were terminated on April 8, 2010.

Summary of Consolidated Financial Position


(dollars in thousands)	September 30, 2010			March 31, 2010			Change
Cash		$56,180			$103,005		$	(46,825	)
Current assets (excluding cash)		256,924			209,995			46,929
Current liabilities		(196,324	)		(165,641	)		(30,683	)

Net working capital		116,780			147,359			(30,579	)
Property, plant and equipment		331,314			331,355			(41	)
Total assets		739,607			702,617			36,990
Capital Lease obligations (including current portion)		(10,628	)		(13,393	)		2,765
Total long-term financial liabilities		(327,620	)		(327,356	)		(264	)

†	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 obligations and both current and non-current deferred income tax balances.

At September 30, 2010, net working capital (cash and current assets less current liabilities) was $116.8 million, a decrease of $30.6 million from March 31, 2010.

The cash balance at September 30, 2010 was $46.8 million lower than at March 31, 2010, reflecting the redemption of the 8³/4% senior notes and associated cross-currency and interest rate swaps, scheduled principal repayments on our term facilities and the purchase of equipment. This was partially offset by a cash inflow from operations.

Current assets excluding cash increased $46.9 million between March 31, 2010 and September 30, 2010, a $52.5 million increase in unbilled revenue during the six months ended September 30, 2010. This reflected the billing cycle for the Heavy Construction and Mining segment’s new construction projects and the Pipeline segment’s new projects in northern British Columbia which started in the three months ended September 2010. These increases were partially offset by a $10.4 million reduction to trade receivables and holdbacks.

Current liabilities increased $30.7 million between March 31, 2010 and September 30, 2010, reflecting a $39.4 million increase in accounts payable which was partially offset by a $13.7 million reduction in accrued liabilities primarily as a result of our April 2010 interest payment on our 8³/4% senior notes and associated interest rate swaps. The current portion of embedded derivatives in financial instruments decreased $19.3 million primarily as a result of the redemption of both our 8³/4% senior notes and the accompanying cross-currency and interest rate swaps. Equipment purchases of $2.3 million, which are scheduled to be paid after September 30, 2010, are included in accounts payable as of September 30, 2010.

North American Energy Partners Inc. Management’s Discussion and Analysis 13

Property, plant and equipment remained comparable between March 31, 2010 and September 30, 2010. This reflects the capital investment of $16.8 million of equipment purchases and new capital leases during the six months ended September 30, 2010, offset by equipment disposals of $0.6 million (net book value) and depreciation of $16.3 million.

Total long-term financial liabilities increased by $0.3 million between March 31, 2010 and September 30, 2010, due largely to a $225.0 million increase from issuance of the Series 1 Debentures, an increase of $37.1 million in the long-term portion of our term loan resulting from new term loans under amended and restated credit agreement and an increase of $3.5 million in the senior executive special stock option liability resulting from a modified employment agreement. This was substantially offset by $203.1 million decrease in the carrying amount of our 8³/4% senior notes resulting from the redemption of the senior notes, a $61.5 million decrease related to the cross-currency and interest rate swap agreements due to the settlement of the swap liabilities, a decrease of $0.4 million related to the long-term portion of the embedded derivatives in a long-term customer construction contract and a $ 0.3 million decrease related to the long-term portion of the embedded derivatives in long-term supplier contracts.

Summary of Consolidated Cash Flows


	Three Months Ended September 30,									Six Months Ended September 30,
(dollars in thousands)	2010			2009			Change			2010			2009			Change
Cash (used in) provided by operating activities	$	(3,212	)	$	23,730		$	(26,942	)		$12,592			$16,008		$	(3,416	)
Cash used in investing activities		(15,617	)		(25,225	)		9,608			(25,455	)		(45,609	)		20,154
Cash (used in) provided by financing activities		(3,859	)		18,997			(22,856	)		(33,962	)		28,212			(62,174	)

Net (decrease) increase in cash and cash equivalents	$	(22,688	)		$17,502		$	(40,190	)		$(46,825	)		$(1,389	)	$	(45,436	)

Operating activities

Cash provided by operating activities for the three months ended September 30, 2010 was an outflow of $3.2 million, a decrease of $26.9 million from the cash inflow for the three months ended September 30, 2009. The lower cash provided by operating activities in the current period is primarily a result of lower gross profit and increased non-cash working capital.

Cash provided by operating activities for the six months ended September 30, 2010 was an inflow of $12.6 million, comparable to the cash inflow for the six months ended September 30, 2009.

Investing activities

Cash used in net investing activities for the three months ended September 30, 2010 was an outflow of $15.6 million, a reduction of $9.6 million from the outflow for the same period a year ago. Investing activities this year included capital expenditures of $10.8 million. Cash used in investing activities last year included capital expenditures of $23.2 million and an outflow for the settlement of the Piling acquisition of $4.9 million.

Cash used in net investing activities for the six months ended September 30, 2010 was an outflow of $25.5 million, a decrease of $20.2 million from the outflow for the same period a year ago. Current period investing activities included capital expenditures of $16.8 million. Cash used in investing activities for the same period in the prior year included capital expenditures of $42.5 million and an outflow for the settlement of the Piling acquisition of $4.9 million.

Financing activities

Cash used in financing activities during the three months ended September 30, 2010 resulted in a cash outflow of $3.9 million, a $22.9 million reduction from the cash inflow in three months ended September 30, 2009. The current period outflow resulted from the scheduled repayments on our term credit facilities and our capital lease obligations. Cash provided by financing activities for the prior year three-month period resulted from a $21.2 million increase in our term facilities, as part of our third amended and restated credit agreement, partially offset by repayments on our term credit facilities and capital lease obligations.

Cash used in financing activities during the six months ended September 30, 2010 resulted in a cash outflow of $34.0 million, a $62.2 million increase from the cash inflow for the six months ended September 30, 2009. The current period outflow was primarily a result of the debt refinancing and swap cancellation activities, which included $6.9 million of financing costs for the fourth amended and restated credit agreement and the Series 1 Debentures. Additional activity included scheduled repayments on our term facilities and repayment of capital lease obligations. Cash provided by financing activities for the prior year six-month period was a result of the $33.0 million addition of a term facility as part of our third amended and restated credit agreement partly offset by associated financing costs and the scheduled repayments of our term facilities and capital lease obligations.

14 Management’s Discussion and Analysis North American Energy Partners Inc.

C. Outlook

We anticipate a gradual strengthening of demand for services through the second half of the fiscal year, despite some lingering impacts of the global recession.¿

The outlook for our recurring services business remains positive and our recent acquisition of the assets of Calgary-based Cyntech Corporation⁶ is expected to further expand recurring services revenues with the addition of a tank servicing business which involves inspection, cleaning, repair and relocation services for large-diameter petrochemical tanks. Cyntech provides these services under a multi-year master services agreement with a major integrated oil and gas producer. In the oil sands, all of the operating oil sands mines are back in full production for the first time in a year. We are active on all of these sites and are currently bidding on multi-year recurring services opportunities with some of these customers.^¿

We are also successfully developing our environmental and tailings reclamation services offering. Recent investments in specialized barge and dozer equipment and our new partnership with Royal Boskalis International⁷ have now positioned us to offer a complete turnkey environmental service with both earth-moving and water-related services. Over time, this is expected to provide us with a significant new source of project work and recurring services revenue.^¿

The outlook for project development in the oil sands continues to improve. We remain active on Exxon’s Kearl site and see opportunities to further expand our business with this customer. The recent approval of Total’s⁸ plans to construct a 300,000 barrel per day upgrader improves the prospects for the associated Joslyn mine moving forward and tendering for construction contracts could potentially begin as early as the end of next year. North West Upgrading⁹ has also indicated its intention to resume construction planning for its new upgrader project. Other new developments such as Husky Energy Inc.’s Sunrise¹⁰, ConocoPhillips’ Surmont¹¹ and Suncor’s Firebag in situ SAGD projects are moving forward and could eventually provide additional project development opportunities as they reach the construction phase. Our recent acquisition of Cyntech, with its screw piling technology, enhances our service offering with respect to these SAGD projects. While the outlook for project work is positive, it should be noted that much of this work will not become available for tendering in this fiscal year.^¿

In the Piling segment, activity levels are expected to increase as market conditions continue to improve and projects delayed by poor weather conditions in the first half of the year resume construction. Piling’s backlog continued to grow as result of increasing industrial construction activity levels in the oil sands and a growing volume of business in the Ontario market. As mentioned above, the Cyntech acquisition is expected to further expand opportunities for the Piling segment with the addition of screw piling design, manufacturing and installation capabilities. Screw piling is favoured on SAGD and power transmission projects because of its low cost and high efficiency. The Piling segment is also expected to benefit from the addition of revenues related to Cyntech’s pipeline anchoring systems business. To date, Cyntech has established an international market for its patented anchoring systems with customers in Canada, the US, Malaysia, Thailand, Indonesia and Russia and we are now positioned to cross market this technology to our own pipeline customers.^¿

The Pipeline segment anticipates another quarter of improved results as work progresses on TransCanada Pipelines’ NPS Groundbirch Mainline project and Spectra Energy’s Maxhamish Loop project. Both projects are scheduled for completion by the end of the third quarter. The Pipeline segment also expects to complete a small maintenance project for Shell Albian at the Muskeg River Mine. Going forward, this segment will be targeting additional oil sands pipeline maintenance contracts, with the goal of developing a stable base of profitable recurring services work in this segment.^¿

Overall we are encouraged by the improving market conditions and by the new opportunities created by the Cyntech acquisition.

^¿	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.

⁶	Cyntech Corporation, a private Alberta-based company and Cyntech Anchor System LLC, its US based subsidiary, (collectively Cyntech). We acquired the assets of Cyntech as at November 1, 2010.

⁷	Royal Boskalis Westminster NV (Boskalis) is an international group with a leading position in the world market for dredging services.

⁸	Total E&P Canada Ltd. (Total), a wholly owned subsidiary of Total SA.

⁹	North West Upgrading Inc. is a private, Alberta-based company with headquarters in Calgary.

¹⁰	Husky Energy Inc.’s (Husky Energy) Sunrise Oil Sand project is a 50/50 joint venture with BP Canada Energy Company (BP), a wholly owned subsidiary of BP PLC. The Sunrise project is operated by Husky Energy.

¹¹

ConocoPhillips Canada Resources Corporation’s (ConocoPhillips) Surmont Oil Sand project is a 50/50 joint venture between ConocoPhillips Canada, a wholly owned subsidiary of ConocoPhillips Company and Total E&P Canada Ltd. (Total), a wholly owned subsidiary of Total SA. ConocoPhillips Canada is the project operator.

North American Energy Partners Inc. Management’s Discussion and Analysis 15

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:

_Ÿ

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

_Ÿ

building and similar codes and zoning ordinances;

_Ÿ

laws and regulations relating to consumer protection; and

_Ÿ

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 for the year ended March 31, 2010.

Employees and Labour Relations

As of September 30, 2010, we had 500 salaried employees and over 2,200 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 2,500 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 2,000 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 expired on October 31, 2009. As of the end of September 2010 negotiations remained underway for the renewal of this union agreement and we are confident that a renewal agreement will be reached without a labour disruption. Other collective agreements in operation include the provincial Industrial, Commercial and Institutional (ICI) agreements in Alberta and Ontario with both the Operating Engineers and Labourers Unions, Piling sector collective agreements in Saskatchewan with the Operating Engineers and Labourers, Pipeline sector agreements in both British Columbia and Alberta with the Christian Labour Association of Canada (CLAC) as well as an all-sector agreement with CLAC in Ontario. 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. The provincial collective agreement between IUOE Local 955 and the Alberta Roadbuilders and Heavy Construction Association expires February 28, 2011. Management is confident a settlement will be reached without disruption. We believe that our relationships with all our employees, both union and non-union, are strong. 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 October 29, 2010, there were 36,114,896 voting Common Shares outstanding (36,038,476 as at March 31, 2010). We had no Non-Voting Common Shares outstanding on any of the foregoing dates.

Liquidity and Capital Resources

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 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 $75 million to $150 million depending on our growth capital requirements. With the potential future customer demand for larger-sized heavy equipment in the oil sands, we expect our capital needs in the current fiscal year to be approximately $50 million to $75 million.^¿

^¿	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.

16 Management’s Discussion and Analysis North American Energy Partners Inc.

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 fleet value is currently split among owned (40%), leased (44%) and rented equipment (16%). Approximately 36% 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 specific volume demands. Our equipment ownership strategy allows us to meet our customers’ variable service requirements while balancing the need to maximize equipment utilization with the need to achieve the lowest ownership costs. We are continually evaluating our capital needs and continue to monitor equipment lead times with suppliers to ensure that we control our capital spending while still being in a position to respond to opportunities when they materialize.¿

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 anticipate having sufficient lease capacity to meet our capital requirements in fiscal year 2011.^¿

Long-term debt restructuring

Our long-term debt, as at March 31, 2010, included US$200.0 million of 8³/4% senior unsecured notes due in December 2011 (the “8³/4% senior notes”). The foreign currency risk relating to both the principal and interest portions of the 8³/4% senior notes was managed with Canadian dollar interest rate swap and cross-currency swap agreements. The swap agreements were an economic hedge but had not been designated as hedges for accounting purposes. 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.

In April 2010, we issued C$225.0 million of Series 1 Debentures and entered into an amended and restated credit agreement that extended the maturity of our credit facilities to April 2013 and provided a new $50.0 million term loan. The net proceeds of the Series 1 Debentures, combined with the new $50.0 million term loan and cash on hand were used to redeem all outstanding 8³/4% senior notes and terminate the associated swap agreements in April 2010. The full details of this debt restructuring are as follows:

9.125% Series 1 Debentures

On April 7, 2010, we closed a private placement of 9.125% Series 1 Debentures (as defined below) due 2017 (the “Series 1 Debentures”) for gross proceeds of $225.0 million and net proceeds after commissions and related expenses of $218.3 million. A more detailed discussion on the Series 1 Debentures can be found under “9.125% Series 1 Debentures” in this “Liquidity and Capital Resources” section.

8³/4% Senior Notes Redemption

Beginning December 1, 2009, our 8³/4% senior notes were redeemable at 100% of the principal amount. On March 29, 2010, we issued a redemption notice to holders of the notes to redeem all outstanding 8³/4% senior notes and, on April 28, 2010, the notes were redeemed and cancelled. The redemption amount included the US$200.0 million principal outstanding and US$7.1 million of accrued interest. The redemption and associated swap agreement terminations eliminate refinancing risk in December 2011.

In connection with the redemption of our 8³/4% senior notes, we wrote off unamortized deferred financing costs of $4.3 million.

Termination of Cross-Currency and Interest Rate Swaps

On April 8, 2010, we terminated the cross-currency and interest rate swaps associated with the 8³/4% senior notes. The payment to the counterparties required to terminate the swaps was $91.1 million and represented the fair value of the swap agreements, including accrued interest.

$50.0 million Term Facility

On April 30, 2010, we entered into a fourth amended and restated credit agreement to extend the term of the credit agreement and also to add additional borrowings of up to $50.0 million through a second term facility within the credit agreement. At April 30, 2010, the second term facility was fully drawn at $50.0 million. The new term facility, along with the existing term facility, matures on April 30, 2013. A more detailed discussion on the April 30, 2010 amended and restated credit agreement can be found under “Credit facilities” in this “Liquidity and Capital Resources” section.

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

^¿	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 17

Letters of credit

One of our major contracts allows the customer to require that we provide up to $50.0 million in letters of credit. As at September 30, 2010, we had $10.0 million in letters of credit outstanding in connection with this contract (we had $16.3 million in letters of credit outstanding in total for all customers as of September 30, 2010). Any change in the amount of the letters of credit required by this customer must be requested by November 1st in each year for an issue date of January 1st following the date of such request, for the remaining life of the contract.

Sources of liquidity

Our principal sources of cash are funds from operations and borrowings under our credit facility. As of September 30, 2010, the credit facility includes the $85.0 million Revolving Facility and the outstanding borrowings of $73.4 million (March 31, 2010 – $28.4 million) under the Term Facilities, after the scheduled principal payments of $2.5 million in the quarter. As of September 30, 2010, we had issued $16.3 million (March 31, 2010 – $10.4 million) in letters of credit under the Revolving Facility to support performance guarantees associated with customer contracts. Our unused borrowing availability under the Revolving Facility was $68.7 million at September 30, 2010.

As at September 30, 2010, we had $7.3 million in trade receivables that were more than 30 days past due compared to $7.5 million as at March 31, 2010. We have currently provided an allowance for doubtful accounts related to our trade receivables of $0.2 million ($1.7 million at March 31, 2010). 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 in our Piling segment.

Working capital fluctuations effect on cash

The seasonality of our business results in a higher accounts receivable balance between December and early February during peak activity levels, which may result in an increase in our working capital requirements. Our working capital is also significantly affected by the timing of the 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”. Typically, 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). However, in some cases, we are able to negotiate the progressive release of holdbacks as the job reaches various stages of completion. As at September 30, 2010, holdbacks totaled $10.8 million, up from $3.9 million as at March 31, 2010. Holdbacks represent 10.6% of our total accounts receivable as at September 30, 2010 (3.5% as at March 31, 2010).¿

Cash requirements

As at September 30, 2010, our cash balance of $56.2 million was $46.8 million lower than our cash balance at March 31, 2010. The change in cash balance reflects the April 2010 settlement of our 8³/4% senior notes and the accompanying cross-currency and interest rate swaps, funded in part by our Series 1 Debentures and the addition of an additional term facility secured through our fourth amended and restated credit facility. We anticipate that we will generate a net cash surplus from operations at least through March 31, 2011. 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 facilities described immediately below.^¿

Credit facilities

On April 30, 2010, we entered into an amended and restated credit agreement to extend the term of the credit facilities and increase the amount of the term loans. The new credit facilities provide for total borrowings of up to $163.4 million (previously $125.0 million) under which revolving loans, term loans and letters of credit may be issued. The Revolving Facility of $85.0 million (previously $90.0 million) was undrawn at closing. The new agreement includes two term facilities providing for borrowings of up to $78.4 million. At April 30, 2010, the Term A Facility and Term B Facility, as defined in the amended and restated credit agreement (the term facilities), were both fully drawn at $28.4 million and $50.0 million, respectively. The new term facilities mature on April 30, 2013.

Advances under the Revolving Facility may be repaid from time to time at our option. The term facilities include scheduled repayments totaling $10.0 million per year with $2.5 million paid on the last day of each quarter commencing June 30, 2010. In addition, we must make annual payments within 120 days of the end of our fiscal year in the amount of 50% of Consolidated Excess Cash Flow (as defined in the credit agreement) to a maximum of $4.0 million.

The facilities bear interest at variable rates based on the Canadian prime rate plus the applicable pricing margin (as defined within the credit agreement). Interest on US base rate loans is paid at a rate per annum equal to the US base rate plus the applicable pricing margin. Interest on Canadian prime and US base rate loans is payable monthly in arrears and computed on the basis of a 365-day or 366-day year, as the case may be. Interest on US dollar LIBOR loans is paid during each interest period at a rate per annum, calculated on a 360-day year, equal to the US dollar LIBOR rate with respect to such interest period plus the applicable pricing margin. Stamping Fees and interest on Bankers’ Acceptance advances, as defined in the amended and restated credit agreement, are paid in advance, at the time of issuance.

^¿	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.

18 Management’s Discussion and Analysis North American Energy Partners Inc.

The new credit facilities are secured by a first priority lien on substantially all of our existing and after acquired property. The amended and restated credit agreement contains customary covenants including, but not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions or paying dividends or redeeming shares of capital stock. We are also required to meet certain financial covenants defined in the amended and restated credit agreement including: (i) Senior Leverage Ratio (Senior Leverage to Consolidated EBITDA) which must be less than 2.0 times, (ii) Consolidated Interest Coverage Ratio (Consolidated EBITDA to Consolidated Interest Expense) which must be greater than 2.5 times, and (iii) Current Ratio (Current Assets to Current Liabilities) which must be greater than 1.25 times. Continued access to the facilities is not contingent on the maintenance of a specific credit rating. The definition of these covenants is unchanged from the previous third amended and restated credit agreement.

Financing fees of $1.0 million were incurred in connection with the amended and restated credit agreement, dated April 30, 2010 and were recorded as deferred financing costs.

Consolidated EBITDA is defined within the credit agreement 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 issuance 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 GAAP.

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.

9.125% Series 1 Debentures

On April 7, 2010, we closed a private placement of Series 1 Debentures for gross proceeds of $225.0 million and net proceeds after commissions and related expenses of $218.1 million. Financing fees of $6.9 million were incurred in connection with the Series 1 Debentures and were recorded as deferred financing costs.

The Series 1 Debentures 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 us or any of our subsidiaries. The Series 1 Debentures are effectively subordinated to all secured debt to the extent of the value of the collateral.

At any time prior to April 7, 2013, we may redeem up to 35% of the aggregate principal amount of the Series 1 Debentures, with the net cash proceeds of one or more of our public equity offerings (as defined in the trust indenture that governs the Series 1 Debentures) at a redemption price equal to 109.125% of the principal amount plus accrued and unpaid interest to the date of redemption, so long as:

i.	at least 65% of the original aggregate amount of the Series 1 Debentures remains outstanding after each redemption; and

ii.	any redemption is made within 90 days of the equity offering.

At any time prior to April 7, 2013, we may on one or more occasions redeem the Series 1 Debentures, in whole or in part, at a redemption price which is equal to the greater of (a) the Canada Yield Price (as defined in the trust indenture that governs the Series 1 Debenture) and (b) 100% of the aggregate principal amount of Debentures redeemed, plus, in each case, accrued and unpaid interest to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

The Series 1 Debentures are redeemable at our option, in whole or in part, at any time on or after: April 7, 2013 at 104.563% of the principal amount; April 7, 2014 at 103.042% of the principal amount; April 7, 2015 at 101.520% of the principal amount; April 7, 2016 and thereafter at 100% of the principal amount; plus, in each case, interest accrued to the redemption date.

If a change of control, as defined in the trust indenture, occurs we will be required to offer to purchase all or a portion of each holder’s Series 1 Debentures at a purchase price in cash equal to 101% of the principal amount of the debentures offered for repurchase plus accrued interest to the date of purchase.

The Series 1 Debentures were rated B+ by Standard & Poor’s and B3 by Moody’s (see “Debt Ratings”).

North American Energy Partners Inc. Management’s Discussion and Analysis 19

Capital resources

We acquire our equipment in three ways: capital expenditures, capital leases and operating leases. Capital expenditures require the outflow of cash for the full value of the equipment at the time of purchase. Capital leases, while not considered capital expenditures, are restricted under the terms of our credit agreement to a maximum of $30.0 million. Operating leases are not considered capital expenditures and are not restricted under the terms of our credit agreement.

We define our equipment requirements as either sustaining capital additions, those that are needed to keep our existing fleet of equipment at its optimal useful life through capital maintenance or replacement, or growth capital additions, those that are needed to perform larger or a greater number of projects.

A summary of equipment additions by nature and by period is shown on the table below:


	Three Months Ended Sep. 30,							Six Months Ended Sept. 30,
(dollars in thousands)	2010		2009		Change			2010		2009		Change
Capital Expenditures
Sustaining		$8,050		$4,034		$4,016			$11,348		$6,195		$5,153
Growth		4,162		22,675		(18,513	)		7,453		40,224		(32,771	)

Total		12,212		26,709		(14,497	)		18,801		46,419		(27,618	)
Capital Leases
Sustaining		–		–		–			–		–		–
Growth		–		33		(33	)		47		657		(610	)

Total		–		33		(33	)		47		657		(610	)
Total sustaining capital additions		8,050		4,034		4,016			11,348		6,195		5,153
Total growth capital additions		4,162		22,708		(18,546	)		7,500		40,881		(33,381	)
Operating Leases		905		27,252		(26,347	)		5,843		32,860		(27,017	)

The increase in sustaining capital additions, for the three and six months ended September 30, 2010, compared to the same periods in the prior year, is reflective of increased capital maintenance activity due to higher volumes.

The reduction in growth capital additions, for both the three and six months ended September 30, 2010, compared to the same periods in the prior year, reflects the impact of fewer development projects as a result of the economic slowdown experienced in fiscal 2010.

The decrease in operating leases, for the three and six months ended September 30, 2010, compared to the same periods in the previous year, reflects the timing of scheduled equipment additions related to the Canadian Natural overburden project along with the impact of fewer development projects as a result of the economic slowdown experienced in fiscal 2010.

Capital Commitments

Contractual obligations and other commitments

Our principal contractual obligations relate to our long-term debt, capital and operating leases (including both equipment and building leases) and supplier contracts. The following table summarizes our future contractual obligations, excluding interest payments, unless otherwise noted, as of September 30, 2010.


	Payments due by fiscal year
(dollars in thousands)	Total		2011		2012		2013		2014		2015 and after
Series 1 debenture		$225,000		$–		$–		$–		$–		$225,000
Term facilities		73,446		5,000		14,000		14,000		40,446		–
Capital leases (including interest)		11,423		2,525		5,248		2,998		474		178
Equipment and Building operating leases		186,440		35,615		60,888		42,133		29,265		18,539
Supplier contracts		60,227		15,288		15,397		14,997		12,072		2,473

Total contractual obligations		$556,536		$58,428		$95,533		$74,128		$82,257		$246,190

Off-balance sheet arrangements

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

20 Management’s Discussion and Analysis North American Energy Partners Inc.

Debt Ratings

Debt Ratings

Moody’s Investor Service, Inc. (“Moody’s”) and Standard & Poor’s Ratings Services (“S&P”) affirmed our corporate credit ratings in March 2010 and April 2010, respectively. S&P increased our Outlook from ‘negative’ to ‘stable’. Both agencies also provided a rating for our new Series 1 Debentures.

A change in our credit ratings, particularly the rating issued by S&P, will affect the interest rate payable on borrowings under our amended and restated credit agreement. Additionally, counterparties to certain agreements may require additional security or other changes in business terms if our credit ratings are downgraded. Furthermore, these ratings are required for us to access the public debt markets, and they affect the pricing of such debt. Any downgrade in our credit ratings from current levels could adversely affect our long-term financing costs, which in turn could adversely affect our ability to pursue business opportunities.

Our credit ratings from these two agencies are as follows:


Category	Standard & Poor’s	Moody’s
Corporate Rating	B+ (‘stable’ outlook)	B2 (‘stable’ outlook)
Series 1 Debentures	B+ (recovery rating of “3”)	B3 (LGD≠ rating of “5”)

≠	Loss Given Default:

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 credit worthiness 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. A 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 credit rating speaks only as of the date it is issued and can be revised upward or downward or withdrawn at any time by the issuing rating agency if it decides circumstances warrant a revision. Definitions of the categories of each rating and the factors considered during the evaluation of each rating have been obtained from each respective rating organization’s website as outlined below.¹²

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 A recovery rating of “3” for the Series 1 Debentures indicates an expectation for an average of 50% to 70% 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 nine 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 “Aaa” through “C”. 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.

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%.

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.

¹²

This information is current as of this report and we undertake no obligation to provide investors with updated information. 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.

North American Energy Partners Inc. Management’s Discussion and Analysis 21

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.

Additionally, we provide shared service support for our joint venture nominee, Noramac Ventures Inc.

Internal Systems and Processes

Evaluation of disclosure controls and procedures

Our disclosure controls and procedures are designed to provide reasonable assurance that information we are required to disclose is recorded, processed, summarized and reported with the time periods specified under Canadian and US securities laws. They include controls and procedures designed to ensure that information is accumulated and communicated to management, including the President and Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosures.

As of September 30, 2010, an evaluation was carried out under the supervision of and with the participation of management, including the President and Chief Executive Officer and the Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) under the US Securities Exchange Act of 1934, as amended, and in National Instrument 52-109 under the Canadian Securities Administrators Rules and Policies. Based on that evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that as a result of the material weaknesses in our internal control over financial reporting (ICFR) discussed below, the disclosure controls and procedures were not effective as of September 30, 2010.

Material changes to internal controls over financial reporting

As of March 31, 2010, we assessed the effectiveness of our 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 continued material weakness in ICFR as described below and as a result, we concluded that our ICFR was ineffective as of March 31, 2010.

Similar to the material weakness identified for the year ended March 31, 2009, we did not maintain effective processes and controls specific to revenue recognition. We did not effectively develop, communicate and implement 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. Notwithstanding the above mentioned weakness, we have concluded that the Consolidated Financial Statements included in this report fairly present our consolidated financial position and consolidated results of operations as of and for the three and six months ended September 30, 2010.

Material changes to internal controls over financial reporting and remediation plans

In response to the continued material weakness in revenue recognition identified above, during the three months ended and subsequent to March 31, 2010, we put a dedicated project team in place, led by a senior member of our Finance team, to develop and implement standard business practices and controls specific to ensuring the accuracy of forecast, including the consideration of project changes subsequent to the end of each reporting period. As of September 30, 2010, progress has been made on our remediation plans and we will evaluate the effectiveness of these controls during 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 for the year ended March 31, 2010.

Recently Adopted Accounting Policies

Improvements to financial reporting by enterprises involved with variable interest entities

In December 2009, the FASB issued ASU No. 2009-17, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities”, which amends ASC 810, “Consolidation”. The amendments give guidance and clarification of how to determine when a reporting entity should include the assets, liabilities, non-controlling interests and results of activities of a variable interest entity in its consolidated financial statements. We adopted this ASU effective April 1, 2010. The adoption of this standard did not have a material effect on our interim consolidated financial statements.

22 Management’s Discussion and Analysis North American Energy Partners Inc.

Embedded credit derivatives

In March 2010, the FASB issued ASU No. 2010-11, “Scope Exception Related to Embedded Credit Derivatives”, which clarifies that financial instruments that contain embedded credit-derivative features related only to the transfer of credit risk in the form of subordination of one instrument to another are not subject to bifurcation and separate accounting. The scope exception only applies to an embedded derivative feature that relates to subordination between tranches of debt issued by an entity and other features that relate to another type of risk must be evaluated for separation as an embedded derivative. We adopted this ASU effective July 1, 2010. The adoption of this standard did not have a material effect on our interim consolidated financial statements.

Recent Accounting Pronouncements Not Yet Adopted

Revenue recognition

In October 2009, the FASB issued ASU No. 2009-13, “Revenue Recognition: Multiple-Deliverable Revenue Arrangements”, which addresses the accounting for multiple-deliverable arrangements to enable vendors to account for products or services separately rather than as a combined unit. The amendments establish a selling price hierarchy for determining the selling price of a deliverable. The amendments also eliminate the residual method of allocation and require that arrangement consideration be allocated at the inception of the arrangement to all deliverables using the relative selling price method. For us, this ASU is effective prospectively for revenue arrangements entered into or materially modified on or after April 1, 2011. We are currently evaluating the effect of this ASU on our interim consolidated financial statements.

Share based payment awards

In April 2010, the FASB issued ASU No. 2010-13, “Effect of Denominating the Exercise Price of Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades”, which clarifies that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. This ASU will amend ASC 718, “Compensation-Stock Compensation” and it is effective for us beginning on April 1, 2011. We are currently evaluating the effect of this ASU on our interim consolidated financial statements.

F. 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 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 September 30, 2011;

(b)	our expectation of continued gradual strengthening of demand of our services through the balance of the year;

(c)

our expectation that demand for recurring services will continue to be strong and our development of our new tailings reclamations services will provide opportunities to further expand our recurring services business, including through our investment in new equipment and our partnership with Boskalis;

(d)	our expectation that the recent acquisition of Cyntech will further expand recurring services revenue;

(e)	our expectation that we will receive project development opportunities as new mine developments such as Husky Energy’s Sunrise, ConocoPhillips’s Surmont, and Suncor’s Firebag projects move forward to the construction phase;

(f)	our expectation that, by the end of the fiscal year, the Piling division will be able to work through the backlog of projects that have built up as a result of projects delayed by poor weather over the last six months;

(g)	our expectation that the Pipeline segment will have a stronger third quarter of improved results with work on two new projects getting underway in August 2010;

North American Energy Partners Inc. Management’s Discussion and Analysis 23

(h)	the expectation for a renewal agreement without labour disruption between our employees party to a collective bargaining agreement which expired October 31, 2009 and us;

(i)	the expectation that the provincial collective agreement between IUOE Local 955 and the Alberta Roadbuilders and Heavy Construction Association expiring on February 28, 2011 will reach a settlement without labour disruption;

(j)	our expectation that our capital needs in fiscal 2011 will be approximately $50-$75 million;

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

(l)	our lease capacity will be sufficient to meet our capital requirements in fiscal 2011;

(m)	the seasonality of our business results may result in an increase in working capital requirements;

(n)	our expectation that we will generate a net cash surplus from operations at least through March 31, 2011; and

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

The forward-looking information in paragraphs (a), (b), (c), (d), (e), (f), (i), (j), (k), (l), (m), (n) and (o) rely on certain market conditions and demand for our services and are based on the assumptions that: despite the slowdown in the global economy and tightening of credit conditions, 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 resource 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, which could cause results to differ materially from those expressed in the forward-looking information contained in this MD&A, but are not limited to:

_Ÿ

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

_Ÿ

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

_Ÿ

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

_Ÿ

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;

_Ÿ

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

_Ÿ

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;

_Ÿ

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

_Ÿ

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;

_Ÿ

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;

_Ÿ

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

_Ÿ

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), (d), (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 integrating out acquisition; 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:

_Ÿ

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 decline in oil prices;

_Ÿ

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

_Ÿ

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;

24 Management’s Discussion and Analysis North American Energy Partners Inc.

_Ÿ

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

_Ÿ

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;

_Ÿ

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

_Ÿ

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

_Ÿ

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

_Ÿ

we are unable to successfully integrate Cyntech to realize the full potential of the addition of its services offerings to us.

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 and six months ended September 30, 2010, 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 10, 2010. 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.

Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices such as foreign currency exchange rates and interest rates. The level of market risk to which we are exposed at any point in time varies depending on market conditions, expectations of future price or market rate movements and composition of our financial assets and liabilities held, non-trading physical assets and contract portfolios.

To manage the exposure related to changes in market risk, we use various risk management techniques including the use of derivative instruments. Such instruments may be used to establish a fixed price for a commodity, an interest-bearing obligation or a cash flow denominated in a foreign currency.

The sensitivities provided below are hypothetical and should not be considered to be predictive of future performance or indicative of earnings on these contracts.

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 regularly transact in foreign currencies when purchasing equipment and 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 September 30, 2010, with other variables unchanged, the impact of a $0.01 increase (decrease) in exchange rates of the Canadian dollar to the US dollar 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 Series 1 Debentures are subject to a fixed rate. Our interest rate risk arises from long-term borrowings issued at fixed rates that create fair value interest rate risk and variable rate borrowings that create cash flow interest rate risk.

North American Energy Partners Inc. Management’s Discussion and Analysis 25

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.

At September 30, 2010, we held $73.4 million of floating rate debt pertaining to our term facilities within our amended and restated credit agreement (March 31, 2010 – $28.4 million). As at September 30, 2010, holding all other variables constant, a 100 basis point increase (decrease) to interest rates on floating rate debt would result in a $0.7 million increase (decrease) in effective annual interest costs. This assumes that the amount of floating rate debt remains unchanged from that which was held at September 30, 2010.

G. General Matters

Our corporate head office is located at Suite 2400, 500 4th Avenue SW, Calgary, Alberta, T2P 2V6. Our corporate head 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 10, 2010, can be found on the Canadian Securities Administrators System for Electronic Document Analysis and Retrieval (SEDAR) database at www.sedar.com, the Securities and Exchange Commission’s website at www.sec.gov and our company’s web site at www.nacg.ca.

26 Management’s Discussion and Analysis North American Energy Partners Inc.

NORTH AMERICAN ENERGY PARTNERS INC.

CANADIAN SUPPLEMENT TO:

Interim Management’s Discussion and Analysis

For the three and six months ended September 30, 2010

LOGO

This document supplements the Interim Management’s Discussion and Analysis for the three and six months ended September 30, 2010 and has been prepared pursuant to Section 5.2 of National Instrument 51-102- Continuous Disclosure Obligations.

Canadian Supplement to Interim Management’s Discussion and Analysis

For the three and six months ended September 30, 2010

November 2, 2010

Summary of differences between US GAAP and Canadian GAAP

The interim unaudited consolidated financial statements for the three and six months ended September 30, 2010 and the accompanying interim Management’s Discussion and Analysis (MD&A) have been prepared in accordance with United States (US) generally accepted accounting principles (GAAP). As required by National Instrument 52-107, for the fiscal year of adoption of US GAAP and one subsequent fiscal year, we are required to provide a Canadian Supplement to our MD&A that restates, based on financial information reconciled to Canadian GAAP, those parts of our MD&A that would contain material differences if they were based on financial statements prepared in accordance with Canadian GAAP. The Canadian Supplement to the MD&A should be read in conjunction with our interim unaudited financial statements and interim MD&A for the three and six months ended September 30, 2010, prepared in accordance with US GAAP, and our annual audited financial statements, related MD&A and Canadian Supplement to the MD&A for the year ended March 31, 2010. The consolidated financial statements 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, the Securities and Exchange Commission’s website at www.sec.gov and our company web site at www.nacg.ca.

The material differences between US GAAP and Canadian GAAP on our financial position and results of operations for the three and six months ended September 30, 2010 are explained and quantified in note 20 to our interim financial statements for the three and six months ended September 30, 2010.

The “Consolidated three and six month results” tables in this supplement highlight the differences between Canadian and US GAAP. The tables in this supplement reporting the “Reconciliation of net (loss) income to EBITDA and Consolidated EBITDA”, “Non-Operating Income and Expense” and “Realized and unrealized loss on derivative financial instruments” for the three and six months ended September 30, 2010 and “Summary of Consolidated Quarterly Results” are prepared in accordance with Canadian GAAP. Amounts included in this supplement are in millions of Canadian dollars, except per share information and amounts included in the tables.

Non-GAAP financial measures

In addition to measures based on US GAAP and Canadian GAAP, we use terms such as “net income before interest expense, income taxes, depreciation and amortization” (EBITDA) and “Consolidated EBITDA” (as defined in our credit agreement). These terms are not defined by US GAAP or Canadian GAAP and readers should refer to “Non-GAAP Financial Measures” in our interim MD&A for the three and six months ended September 30, 2010 and our annual MD&A for the fiscal year ended March 31, 2010.

2 Canadian Supplement to Management’s Discussion and Analysis North American Energy Partners Inc.

Consolidated three and six month results


	Three months ended September 30,
(dollars in thousands, except per share information)	2010 (Canadian GAAP)		Adjustments			2010 (US GAAP)		2009 (Canadian GAAP)		Adjustments			2009 (US GAAP)
Revenue (e)		$235,684		$(826	)		$234,858		$171,110		$(408	)		$170,702
Project costs (e)		133,045		(605	)		132,440		65,959		(522	)		65,437
Equipment costs		46,358		–			46,358		44,359		–			44,359
Equipment operating lease expense		18,909		–			18,909		15,684		–			15,684
Depreciation (a)		8,030		24			8,054		11,395		31			11,426

Gross profit		29,342		(245	)		29,097		33,713		83			33,796
General and administrative costs (c) and (e)		14,527		759			15,286		14,015		(97	)		13,918
Operating income		13,409		(1,104	)		12,305		18,776		161			18,937

Net income		$5,617		$(3,248)			$2,369		$6,491		$(2,192)			$4,299
Per share information
Net income – basic		$0.16		$(0.09)			$0.07		$0.18		$(0.06)			$0.12
Net income – diluted		$0.15		$(0.09)			$0.06		$0.18		$(0.06)			$0.12
EBITDA		$25,723		$(3,424)			$22,299		$26,028		$(2,157)			$23,871
Consolidated EBITDA (as defined within our credit agreement)		$23,852		$(1,243)			$22,609		$31,978		$–			$31,978


	Six months ended September 30,
(dollars in thousands, except per share information)	2010 (Canadian GAAP)		Adjustments			2010 (US GAAP)		2009 (Canadian GAAP)		Adjustments			2009 (US GAAP)
Revenue (e)		$421,451		$(2,999	)		$418,452		$318,213		$(992	)		$317,221
Project costs (e)		212,315		(2,598	)		209,717		120,512		(813	)		119,699
Equipment costs		111,361		–			111,361		90,403		–			90,403
Equipment operating lease expense		36,400		–			36,400		28,033		–			28,033
Depreciation (a)		16,201		56			16,257		20,088		62			20,150

Gross profit		45,174		(457	)		44,717		59,177		(241	)		58,936
General and administrative costs (c) and (e)		28,666		349			29,015		29,081		(187	)		28,894
Operating income		14,343		(974	)		13,369		28,748		327			29,075

Net (loss) income		$(1,682)		$(6,258)			$(7,940)		$16,561		$(2,335)			$14,226
Per share information
Net (loss) income – basic		$(0.05)		$(0.17)			$(0.22)		$0.46		$(0.07)			$0.39
Net (loss) income – diluted		$(0.05)		$(0.17)			$(0.22)		$0.45		$(0.06)			$0.39
EBITDA		$33,709		$(7,212)			$26,497		$54,056		$(1,948)			$52,108
Consolidated EBITDA (as defined within our credit agreement)		$36,031		$(1,243)			$34,788		$51,372		$–			$51,372

North American Energy Partners Inc. Canadian Supplement to Management’s Discussion and Analysis 3

Reconciliation of net income (loss) to EBITDA and Consolidated EBITDA (Canadian GAAP)


	Three months ended September 30,
(dollars in thousands)	2010			2009			Change
Net income		$5,617			$6,491			$(874	)
Adjustments:
Interest expense		7,442			5,790			1,652
Income tax expense		3,788			1,731			2,057
Depreciation		8,030			11,395			(3,365	)
Amortization of intangible assets		846			621			225

EBITDA		$25,723			$26,028			$(305	)
Adjustments:
Unrealized foreign exchange gain on senior notes		–			(17,877	)		17,877
Realized and unrealized (gain) loss on derivative financial instruments		(3,478	)		22,826			(26,304	)
Loss on disposal of property, plant and equipment and assets held for sale		560			301			259
Stock-based compensation expense		773			477			296
Loss from unconsolidated joint venture		274			223			51

Consolidated EBITDA (as defined within our credit agreement)		$23,852			$31,978			$(8,126	)

	Six months ended September 30,
(dollars in thousands)	2010			2009			Change
Net (loss) income		$(1,682	)		$16,561			$(18,243	)
Adjustments:
Interest expense		14,790			11,758			3,032
Income tax expense		2,791			4,326			(1,535	)
Depreciation		16,201			20,088			(3,887	)
Amortization of intangible assets		1,609			1,323			286

EBITDA		$33,709			$54,056			$(20,347)
Adjustments:
Unrealized foreign exchange gain on senior notes		–			(37,196	)		37,196
Realized and unrealized (gain) loss on derivative financial instruments		(1,361	)		32,847			(34,208	)
Loss on disposal of property, plant and equipment and assets held for sale		556			25			531
Stock-based compensation expense		1,171			1,608			(437	)
Loss from unconsolidated joint venture		517			32			485
Loss on debt extinguishment		1,439			–			1,439

Consolidated EBITDA (as defined within our credit agreement)		$36,031			$51,372			$(15,341)

4 Canadian Supplement to Management’s Discussion and Analysis North American Energy Partners Inc.

Non-Operating Income and Expense (Canadian GAAP)


	Three months ended September 30,
(dollars in thousands)	2010			2009			Change
Interest expense
Interest on 8³/4% senior notes and swaps		$–			$4,737			$(4,737	)
Interest on capital lease obligations		182			270			(88	)
Amortization of deferred financing costs		182			219			(37	)
Amortization of premium on Series 1 debentures		(91	)		–			(91	)
Interest on credit facilities		1,298			197			1,101
Interest on Series 1 Debentures		5,133			–			5,133

Interest on long term debt		$6,704			$5,423			$1,281
Other interest		738			367			371

Total interest expense		$7,442			$5,790			1,652
Foreign exchange loss (gain)		49			(17,862	)		17,911
Realized and unrealized (gain) loss on derivative financial instruments		(3,478	)		22,826			(26,304	)
Other income		(9	)		(200	)		191
Income tax expense		3,788			1,731			2,057


	Six months ended September 30,
(dollars in thousands)	2010			2009			Change
Interest expense
Interest on 8³/4% senior notes and swaps		$1,238			$9,881			$(8,643	)
Interest on capital lease obligations		390			561			(171	)
Amortization of deferred financing costs		417			440			(23	)
Amortization of premium on Series 1 Debentures		(181	)		–			(181	)
Interest on credit facilities		2,264			492			1,772
Interest on Series 1 Debentures		9,867			–			9,867

Interest on long term debt		$13,995			$11,374			$2,621
Other interest		795			384			411

Total interest expense		$14,790			$11,758			3,032
Foreign exchange gain		(1,648	)		(37,077	)		35,429
Realized and unrealized (gain) loss on derivative financial instruments		(1,361	)		32,847			(34,208	)
Loss on debt extinguishment		1,462			–			1,462
Other (income) expense		(9	)		333			(342	)
Income tax expense		2,791			4,326			(1,535	)

Realized and unrealized (gain) loss on derivative financial instruments (Canadian GAAP)


	Three months ended September 30,
(dollars in thousands)	2010			2009			Change
Swap liability loss		$–			$18,983			$(18,983	)
Redemption option embedded derivative gain on 8³/4% senior notes		–			(3,467	)		3,467
Redemption options embedded derivatives gain on the Series 1 Debentures		(2,170	)		–			(2,170	)
Supplier contracts embedded derivatives (gain) loss		(1,656	)		460			(2,116	)
Customer contract embedded derivative loss		348			2,986			(2,638	)
Swap interest payment		–			3,864			(3,864	)

Total		$(3,478	)		$22,826			$(26,304	)

North American Energy Partners Inc. Canadian Supplement to Management’s Discussion and Analysis 5


	Six months ended September 30,
(dollars in thousands)	2010			2009			Change
Swap liability loss		$1,783			$38,818			$(37,035	)
Redemption option embedded derivative gain on 8³/4% senior notes		–			(5,740	)		5,740
Redemption options embedded derivatives gain on the Series 1 Debentures		(3,061	)		–			(3,061	)
Supplier contracts embedded derivatives gain		(9	)		(13,704	)		13,695
Customer contract embedded derivative (gain) loss		(402	)		6,273			(6,675	)
Swap interest payment		328			7,200			(6,872	)

Total		$(1,361	)		$32,847			$(34,208	)

Summary of Consolidated Quarterly Results (Canadian GAAP)


	Sept 30, 2010		June 30, 2010			March 31, 2010			Dec 31, 2009		Sept 30, 2009		June 30, 2009		March 31, 2009			Dec 31, 2008
(dollars in millions)	Fiscal 2011					Fiscal 2010									Fiscal 2009
Revenue		$235.7		$185.8			$222.4			$222.7		$171.1		$147.1		$174.7			$258.6
Gross profit		29.3		15.8			32.9			48.1		33.7		25.5		33.0			51.5
Operating income (loss)		13.4		0.9			13.0			31.1		18.8		10.0		(129.3	)		(2.1	)
Net income (loss)		5.6		(7.3	)		(3.0	)		15.6		6.5		10.1		(136.7	)		(14.6	)
Net income (loss) per share – Basic		$0.16		$(0.20	)		$(0.08	)		$0.43		$0.18		$0.28		$(3.79	)		$(0.41	)
Net income (loss) per share – Diluted		0.15		(0.20	)		(0.08	)		$0.43		$0.18		$0.28		$(3.79	)		$(0.41	)

Canadian and United States accounting policies differences

A detailed reconciliation of our results for the three and six months ended September 30, 2010 is included in note 20 to our interim consolidated financial statements for the three and six months ended September 30, 2010.

The differences between US GAAP and Canadian GAAP that have the most significant impact on our financial position and results of operations for the three and six months ended September 30, 2010, include accounting for: capitalization of interest, financing costs, discounts and premiums, derivative financial instruments and stock-based compensation.

a) Capitalization of interest

US GAAP requires capitalization of interest costs as part of the historical cost of acquiring certain qualifying assets that require a period of time to prepare for their intended use. This is not required under Canadian GAAP. The capitalized amount is subject to depreciation in accordance with our policies when the asset is placed into service.

b) Financing costs, discounts and premiums

Under US GAAP, deferred financing costs incurred in connection with our 9.125% Series 1 Debentures and our 8³/4% senior notes were being amortized over the term of the related debt using the effective interest method. Prior to April 1, 2007, the transaction costs on the 8³/4% senior notes were recorded as a deferred asset under Canadian GAAP and these deferred financing costs were being amortized on a straight-line basis over the term of the debt.

Effective April 1, 2007, we adopted CICA Handbook Section 3855, “Financial Instruments – Recognition and Measurement”, on a retrospective basis without restatement. Although Section 3855 also requires the use of the effective interest method to account for the amortization of finance costs, the requirement to bifurcate the issuer’s early prepayment option on issuance of debt (which is not required under US GAAP) resulted in an additional premium of $3.5 million on the Series 1 Debentures that is being amortized over the term of the Series 1 Debentures under Canadian GAAP. The same was being done on the extinguished 8³/4% senior notes. The unamortized premium is disclosed as part of the carrying amount of the “Series 1 Debentures” in the interim Consolidated Balance Sheets. Foreign denominated transaction costs, discounts and premiums on the 8³/4% senior notes were considered as part of the carrying value of the related financial liability under Canadian GAAP and were subject to foreign currency gains or losses resulting from periodic translation procedures as they were treated as a monetary item under Canadian GAAP. Under US GAAP, foreign denominated transaction costs are considered non-monetary and are not subject to foreign currency gains and losses resulting from periodic translation procedures. The unamortized discounts and premiums on the 8³/4% senior notes were expensed on the settlement of the 8³/4% senior notes under both Canadian and US GAAP with a difference of $2.9 million.

In connection with the adoption of Section 3855, transaction costs incurred in connection with our amended and restated credit agreement of $1.6 million were reclassified from deferred financing costs to intangible assets on April 1, 2007 under Canadian GAAP and these costs continued to be amortized on a straight-line basis over the term of the credit facilities. Under US GAAP, we continue to amortize these transaction costs over the stated term of the related

6 Canadian Supplement to Management’s Discussion and Analysis North American Energy Partners Inc.

facilities using the effective interest method. We disclose the unamortized deferred financing costs related to the Series 1 Debentures, the 8³/4% senior notes and the credit facilities as “Deferred financing costs” of $8.4 million (March 31, 2010 – $6.7 million) on the Interim Consolidated Balance Sheets with the amortization charge classified as “Interest expense” on the Interim Consolidated Statement of Operations and Comprehensive Income (Loss). Under Canadian GAAP, the unamortized financing costs related to the Series 1 Debentures (September 30, 2010 – $6.5 million) and the 8³/4% senior notes (March 31, 2010 – $1.5 million) are included in “Series 1 Debentures” and “Senior notes” respectively whilst the unamortized deferred financing costs in connection with the credit facilities (September 30, 2010 – $1.7 million; March 31, 2010 – $1.1 million) are included in “Intangible assets” on the Interim Consolidated Balance Sheets resulting in a Canadian and US GAAP presentation difference.

c) Stock-based compensation

Up until April 1, 2006, we followed the provisions of ASC 718, “Share-Based Payment”, for US GAAP purposes. As we use the fair value method of accounting for all stock-based compensation payments under Canadian GAAP, there were no differences between Canadian and US GAAP prior to April 1, 2006. On April 1, 2006, we adopted the provisions of SFAS No. 123(R), “Share-Based Payment”, which is now a part of ASC 718. As we used the minimum value method for purposes of complying with ASC 718, we were required to adopt the provisions under the revised guidance prospectively. Under Canadian GAAP, we were permitted to exclude volatility from the determination of the fair value of stock options granted until the filing of our initial registration statement relating to our initial public offering of voting shares on July 21, 2006. As a result, for options issued between April 1, 2006 and July 21, 2006, there is a difference between Canadian and US GAAP relating to the determination of the fair value of options granted.

On September 22, 2010, we modified a senior executive employment agreement to allow the option holder the right to settle options in cash which resulted in 550,000 stock options changing classification from equity to a long term liability. Under US GAAP, such modification is measured at fair value using a model such as Black-Scholes. Under Canadian GAAP, stock options that are cash settled are measured at the amount by which the quoted market value of the shares of our stock covered by the grant exceeds the option price. This resulted in a measurement difference between US and Canadian GAAP. At September 30, 2010, the liability under US GAAP was measured at $3.5 million of which $2.2 million was transferred from additional paid-in capital and the difference of $1.2 million was recognized as incremental compensation cost in the Interim Consolidated Statements of Operations and Comprehensive Income (Loss) under General and administrative costs. Under Canadian GAAP, the liability was measured at $1.9 million resulting in a transfer of the same amount from additional paid-in capital and the difference of $0.4 million remaining in additional paid-in capital. There was no incremental compensation cost since the liability was less than the amount already previously recognized.

d) Derivative financial instruments

Under Canadian GAAP, we determined that the issuer’s early prepayment option included in the Series 1 Debentures of $3.9 million should be bifurcated from the host contract, along with a contingent embedded derivative liability of $0.4 million in the Series 1 Debentures that provide for accelerated redemption by the holders in certain instances (as defined in the trust indenture that governs the Series 1 Debentures). These embedded derivatives were measured at fair value at April 7, 2010, the inception date of the Series 1 Debentures and the residual amount of the proceeds was allocated to the debt. Changes in fair value of the embedded derivatives are recognized in net income and the carrying amount of the Series 1 Debentures is accreted to par value over the term of the Series 1 Debentures using the effective interest method and is recognized as interest expense as discussed in b) above. The same accounting treatment was used on the extinguished 8³/4% senior notes.

Under US GAAP, ASC 815, “Derivatives and Hedging”, establishes accounting and reporting standards requiring that every derivative instrument, including certain derivative instruments embedded in other contracts and debt instruments, be recorded on the balance sheet as either an asset or liability measured at its fair value. The contingent embedded derivative in the Series 1 Debentures that provides for accelerated redemption by the holders in certain instances (as defined in the trust indenture that governs the Series 1 Debentures) did not meet the criteria for bifurcation from the debt contract and separate measurement at fair value and was not bifurcated from the host contract and measured at fair value resulting in a US GAAP and Canadian GAAP difference. The contingent embedded derivative in the 8³/4% senior notes that provide for accelerated redemption by the holders in certain instances met the criteria for bifurcation from the debt contract and separate measurement at fair value. The embedded derivative was measured at fair value and changes in fair value recorded in net income for all periods presented. The issuer’s early prepayment option included in both the Series 1 Debentures (as defined in the trust indenture that governs the Series 1 Debentures) and the 8³/4% senior notes did not meet the criteria as an embedded derivative under ASC 815 and was not bifurcated from the host contract resulting in a US GAAP and Canadian GAAP difference.

e) Joint venture

Under US GAAP, we record our share of earnings of the JV using the equity method of accounting. Under Canadian GAAP, we use the proportionate consolidation method of accounting for the JV. Under the proportionate consolidation method, we recognize our share of the results of operations, cash flows, and financial position of the JV on a line-by-line basis in our consolidated financial statements. While there is no impact on net income or earnings per share as a result of the

North American Energy Partners Inc. Canadian Supplement to Management’s Discussion and Analysis 7

US GAAP treatment of the joint venture, as compared to Canadian GAAP, there are presentation differences affecting the disclosures in the consolidated financial statements and supporting notes.

f) Other matters

Management’s Discussion and Analysis under US GAAP

Please refer to our interim consolidated financial statements for the three and six months ended September 30, 2010 and our accompanying MD&A under US GAAP, filed November 2, 2010. Our interim MD&A should also be read in conjunction with the audited consolidated financial statements for the year ended March 31, 2010, together with our annual MD&A and Canadian Supplement to the MD&A for the year ended March 31, 2010. The differences between US GAAP and Canadian GAAP, described above, affect the discussion and analysis in several sections of our interim MD&A for the three and six months ended September 30, 2010.

Additional information

The consolidated financial statements, and additional information relating to our business, including our Annual Information Form (AIF), are available on the Canadian Securities Administrators’ SEDAR System at www.sedar.com, the Securities and Exchange Commission’s website at www.sec.gov and our company web site at www.nacg.ca.

8 Canadian Supplement to Management’s Discussion and Analysis North American Energy Partners Inc.

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 September 30, 2010.

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 framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is COSO and COBIT.

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 July 1, 2010 and ended on September 30, 2010 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: November 2, 2010

/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 September 30, 2010.

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 framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is COSO and COBIT.

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 July 1, 2010 and ended on September 30, 2010 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: November 2, 2010

/s/ David Blackley

Chief Financial Officer