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 February 2011

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 nine months ended December 31, 2010.

2.	Management’s Discussion and Analysis for the three and nine months ended December 31, 2010.

3.	Canadian Supplement to Management’s Discussion and Analysis for the three and nine months ended December 31, 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: February 1, 2011

NORTH AMERICAN ENERGY PARTNERS INC.

Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

(Expressed in thousands of Canadian Dollars)

(Unaudited)

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Interim Consolidated Balance Sheets

(Expressed in thousands of Canadian Dollars)

(Unaudited)


	December 31, 2010			March 31, 2010
ASSETS
Current assets:
Cash and cash equivalents		$748			$103,005
Accounts receivable, net (allowance for doubtful accounts of $90, March 2010 – $1,691)		131,509			111,884
Unbilled revenue		134,283			84,702
Inventories (note 7)		6,829			3,047
Prepaid expenses and deposits		9,367			6,881
Deferred tax assets		2,331			3,481

		285,067			313,000
Prepaid expenses and deposits		2,781			4,005
Assets held for sale		807			838
Property, plant and equipment (note 8)		331,680			331,355
Investment in and advances to unconsolidated joint venture (note 9)		3,332			2,917
Intangible assets, net (accumulated amortization of $6,843, March 2010 – $4,591)		15,708			7,669
Goodwill (note 5)		32,649			25,111
Deferred financing costs (note 10)		8,038			6,725
Deferred tax assets		47,031			10,997

		$727,093			$702,617

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$97,201			$66,876
Accrued liabilities		27,470			47,191
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		1,849			1,614
Current portion of capital lease obligations		4,783			5,053
Current portion of term facilities (note 11(a))		10,000			6,072
Current portion of derivative financial instruments (note 14)		2,566			22,054
Deferred tax liabilities		35,854			16,781

		179,723			165,641
Capital lease obligations		4,713			8,340
Term facilities (note 11(a))		60,946			22,374
8³/4% senior notes (note 11(b))		–			203,120
Series 1 debentures (note 11(c))		225,000			–
Derivative financial instruments (note 14)		10,927			75,001
Other long term obligations (note 17)		26,216			19,642
Deferred tax liabilities		42,666			27,441

		550,191			521,559
Shareholders’ equity:
Common shares (authorized – unlimited number of voting common shares; issued and outstanding – December 31, 2010 – 36,177,866 (March 31, 2010 – 36,049,276) (note 12(a))		304,387			303,505
Additional paid-in capital		6,619			7,439
Deficit		(134,084	)		(129,886	)
Accumulated other comprehensive loss		(20	)		–

		176,902			181,058

		$727,093			$702,617

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 December 31,						Nine Months Ended December 31,
	2010			2009			2010			2009
Revenue		$265,086			$221,175			$683,538			$538,396
Project costs		148,019			89,207			357,736			208,906
Equipment costs		58,819			57,512			170,180			147,915
Equipment operating lease expense		16,940			16,287			53,340			44,320
Depreciation		10,501			10,543			26,758			30,693

Gross profit		30,807			47,626			75,524			106,562
General and administrative costs		16,482			14,532			45,497			43,426
Loss on disposal of property, plant and equipment		847			743			1,428			1,044
Loss on disposal of assets held for sale		873			649			848			373
Amortization of intangible assets		992			528			2,252			1,438
Equity in loss (earnings) of unconsolidated joint venture (note 9)		359			(98	)		876			(66	)

Operating income before the undernoted		11,254			31,272			24,623			60,347
Interest expense, net (note 13)		7,193			6,764			22,630			19,725
Foreign exchange gain		(42	)		(5,449	)		(1,690	)		(42,930	)
Realized and unrealized (gain) loss on derivative financial instruments (note 14)		(2,040	)		8,010			(340	)		43,185
Loss on debt extinguishment (note 10 and 11(b))		–			–			4,346			–
Other expense		27			471			18			804

Income (loss) before income taxes		6,116			21,476			(341	)		39,563
Income taxes (benefit) (note 15(c)):
Current		(51	)		591			4,436			1,855
Deferred		2,425			5,949			(579	)		8,546

Net income (loss)		3,742			14,936			(4,198	)		29,162

Other comprehensive loss
Unrealized foreign currency translation loss		20			–			20			–

Comprehensive income (loss)		3,722			14,936			(4,218	)		29,162

Net income (loss) per share – basic (note 12(b))		$0.10			$0.41			$(0.12	)		$0.81

Net income (loss) per share – diluted (note 12(b))		$0.10			$0.41			$(0.12	)		$0.79

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

Accumulated other
comprehensive
loss

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

–

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

)

–

Cash settlement of stock options

–

(244

)

–

(244

)

Issued upon exercise of stock options

–

Balance at March 31, 2010

$303,505

$7,439

$(129,886

)

$–

$181,058

Net loss

–

(4,198

)

–

(4,198

)

Unrealized foreign currency translation loss

–

(20

)

(20

)

Share option plan

–

1,066

–

1,066

Deferred performance share unit plan

–

(57

)

–

(57

)

Stock award plan

–

653

–

653

Reclassification on exercise of stock options

245

(245

)

–

Issued upon exercise of stock options

637

–

637

Senior executive stock options plan

–

(2,237

)

–

(2,237

)

Balance at December 31, 2010

$304,387

$6,619

$(134,084

)

$(20

)

$176,902

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 December 31,						Nine Months Ended December 31,
	2010			2009			2010			2009
Cash provided by (used in):
Operating activities:
Net income (loss) for the period		$3,742			$14,936			$(4,198	)		$29,162
Items not affecting cash:
Depreciation		10,501			10,543			26,758			30,693
Equity in loss (earnings) of unconsolidated joint venture (note 9)		359			(98	)		876			(66	)
Amortization of intangible assets		992			528			2,252			1,438
Amortization of deferred lease inducements		(26	)		(19	)		(80	)		(80	)
Amortization of deferred financing costs (note 13)		360			847			1,243			2,489
Loss on disposal of property, plant and equipment		847			743			1,428			1,044
Loss on disposal of assets held for sale		873			649			848			373
Unrealized foreign exchange gain on 8³/4% senior notes		–			(5,120	)		(732	)		(42,720	)
Unrealized (gain) loss on derivative financial instruments measured at fair value		(2,040	)		3,818			(340	)		31,793
Loss on debt extinguishment		–			–			4,346			–
Stock-based compensation expense (note 18(a))		4,451			1,439			7,377			3,888
Accretion of asset retirement obligation		9			8			26			(4	)
Deferred income taxes (benefit)		2,425			5,949			(579	)		8,546
Net changes in non-cash working capital (note 15(b))		(49,113	)		(23,839	)		(53,253	)		(40,164	)

		(26,620	)		10,384			(14,028	)		26,392

Investing activities:
Acquisition (note 6)		(20,820	)		(530	)		(20,820	)		(5,410	)
Purchase of property, plant and equipment		(10,576	)		(3,542	)		(27,353	)		(46,002	)
Additions to intangible assets		(731	)		(1,232	)		(2,755	)		(2,037	)
Additions to assets held for sale		–			(125	)		(1,703	)		(1,058	)
Investment in and advances to unconsolidated joint venture (note 9)		–			(1,887	)		(1,291	)		(2,873	)
Proceeds on disposal of property, plant and equipment		360			454			420			1,150
Proceeds on disposal of assets held for sale		445			1,170			745			2,282
Net changes in non-cash working capital (note 15(b))		5,881			(2,998	)		1,861			(351	)

		(25,441	)		(8,690	)		(50,896	)		(54,299	)

Financing activities:
Repayment of term facilities		(2,500	)		(3,037	)		(7,500	)		(3,688	)
Increase in term facilities		–			–			50,000			33,000
Financing costs (note 11(a) and 11(c))		–			–			(7,920	)		(1,123	)
Redemption of 8³/4% senior notes (note 11(b))		–			–			(202,410	)		–
Issuance of series 1 debentures (note 11(c))		–			–			225,000			–
Settlement of swap liabilities (note 14)		–			–			(91,125	)		–
Cash settlement of stock options		–			–			–			(66	)
Proceeds from stock options exercised		332			–			637			–
Repayment of capital lease obligations		(1,176	)		(1,271	)		(3,988	)		(4,219	)

		(3,344	)		(4,308	)		(37,306	)		23,904

Decrease in cash and cash equivalents		(55,405	)		(2,614	)		(102,230	)		(4,003	)
Effect of exchange rate on changes in cash		(27	)		–			(27	)		–
Cash and cash equivalents, beginning of period		56,180			97,491			103,005			98,880

Cash and cash equivalents, end of period		$748			$94,877			$748			$94,877

Supplemental cash flow information (note 15(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 nine months ended December 31, 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. Significant accounting policy

i) 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 22.

These consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, North American Construction Group Inc. (“NACGI”) and North American Fleet Company Ltd. (“NAFCL”), and the following 100% owned subsidiaries of NACGI:


_ŸNorth American Caisson Ltd.		_ŸNorth American Services Inc.
_ŸNorth American Construction Ltd.		_ŸNorth American Site Development Ltd.
_ŸNorth American Engineering Inc.		_ŸNorth American Site Services Inc.
_ŸNorth American Enterprises Ltd.		_ŸNorth American Tailings and Environmental Ltd.
_ŸNorth American Industries Inc.		_ŸDF Investments Limited
_ŸNorth American Maintenance Ltd.		_ŸDrillco Foundation Co. Ltd.
_ŸNorth American Mining Inc.		_ŸCyntech Canada Inc.
_ŸNorth American Pile Driving Inc.		_ŸCyntech Services Inc.
_ŸNorth American Pipeline Inc.		_ŸCyntech U.S. Inc.
_ŸNorth American Road Inc.

ii) Foreign currency translation

Accounts of the Company’s US-based subsidiary, which has a US dollar functional currency, are translated into Canadian Dollars using the current rate method. Assets and liabilities are translated at the rate of exchange in effect at the balance sheet date, and revenue and expense items (including depreciation and amortization) are translated at the average rate of exchange for the period. The resulting unrealized exchange gains and losses from these translation adjustments are included as a separate component of shareholders’ equity in Accumulated Other Comprehensive Income (Loss). The effect of exchange rate changes on cash balances held in foreign currencies is separately reported as part of the reconciliation of the change in cash and cash equivalents for the period.

The functional currency of the Company is Canadian Dollars. Transactions denominated in foreign currencies are recorded at the rate of exchange on the transaction date. Monetary assets and liabilities, denominated in foreign currencies, are translated into Canadian Dollars at the rate of exchange prevailing at the balance sheet date. Foreign exchange gains and losses are included in the determination of earnings.

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

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)

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.

iii) Intangibles – Goodwill and Other

In December 2010, the FASB issued ASU No. 2010-28, “When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts”, which amends ASC 350, “Intangibles-Goodwill and Other” to modify step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts, to require an entity to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that impairment may exist. For the Company, this ASU is effective for the fiscal year and interim periods beginning April 1, 2011. Early adoption is not permitted. The amendments in this ASU will have no material effect on the Company’s consolidated financial statements.

iv) Business Combinations

In December 2010, the FASB issued ASU No. 2010-29, “Disclosure of Supplementary Pro Forma Information for Business Combinations”, which amends ASC 805, “Business Combinations”, to require that pro-forma information be presented as if the business combination occurred at the beginning of the prior annual reporting period for the purposes of calculating both the current reporting period and the prior reporting period pro forma financial information. The ASU also requires the disclosure be accompanied by a narrative description of the nature and amount of material, nonrecurring pro forma adjustments. For the Company, this ASU is effective prospectively for business combinations for which the acquisition date is on or after April 1, 2011. Early adoption is permitted. This standard will impact disclosures made for business combinations completed by the Company after the effective date.

5. Goodwill

The change in goodwill during the three and nine months ended December 31, 2010 is as follows:


	December 31, 2010
Opening balance		$25,111
Acquisition of goodwill (assigned to the Piling segment) (note 6)		7,538

Closing balance		$32,649

The Company conducted its annual goodwill impairment test on October 1, 2010 and concluded there was no impairment.

6. Acquisition

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”), for a consideration of $24,126 of which $20,820 has been paid.

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)

The difference of $3,306 remains outstanding at December 31, 2010 until the finalization of purchase price consideration. Cyntech designs and manufactures screw piles and pipeline anchoring systems as well as provides tank maintenance services to the petro-chemical industry and is based in Calgary, Alberta. 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 results of operations of Cynetech are included in the financial statements from the date of acquisition and acquisition related costs were recorded in general and administrative costs. The goodwill acquired is deductable for tax purposes. The following table summarizes the amounts of estimated fair value of the assets acquired and liabilities assumed at the acquisition date:


Net assets acquired at assigned values:
Accounts receivable	$7,097
Inventories	1,521
Prepaid expenses and deposits	63
Plant and equipment	1,346
Intangible assets	7,536
Goodwill	7,538
Accounts payable	(975	)

	$24,126

The purchase price consideration and the fair value of the assets acquired and liabilities assumed may be subject to post-closing adjustments.

7. Inventories


	December 31, 2010		March 31, 2010
Spare tires		$4,079		$1,868
Job materials		2,076		1,179
Finished goods		674		–

		$6,829		$3,047

8. Property, plant and equipment


December 31, 2010	Cost		Accumulated Deprecation		Net Book Value
Heavy equipment		$345,500		$105,214		$240,286
Major component parts in use		40,873		11,831		29,042
Other equipment		31,089		13,697		17,392
Licensed motor vehicles		21,097		15,377		5,720
Office and computer equipment		11,321		5,121		6,200
Buildings		21,657		7,866		13,791
Land		281		–		281
Leasehold improvements		14,247		4,126		10,121
Assets under capital lease		19,435		10,588		8,847

		$505,500		$173,820		$331,680


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 nine months ended December 31, 2010, additions to property, plant and equipment included $44 and $91 respectively, of assets that were acquired by means of capital leases (three and nine months ended

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)

December 31, 2009 – $449 and $1,105 respectively). Depreciation of equipment under capital lease of $651 and $2,069 for the three and nine months ended December 31, 2010, respectively, was included in depreciation expense (three and nine months ended December 31, 2009 – $1,019 and $3,156 respectively).

9. 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 December 31, 2010, the Company’s investment in and advances to the unconsolidated joint venture totalled $3,332 (March 31, 2010 – $2,917). The condensed financial data for investment in and advances to unconsolidated joint venture is summarized as follows:


	December 31, 2010		March 31, 2010
Current assets		$8,554		$8,952
Long term assets		1,312		153
Current liabilities		3,198		3,271
Long term liabilities		8,520		5,940


	Three Months Ended December 31,					Nine Months Ended December 31,
	2010			2009		2010			2009
Gross revenues		$2,019			$3,077		$8,017			$5,163
Gross profit		33			847		835			1,226
Net (loss) income		(718	)		195		(1,751	)		132

Equity in (loss) earnings of unconsolidated joint venture		$(359	)		$98		$(876	)		$66

10. Deferred financing costs


December 31, 2010	Cost		Accumulated Amortization		Net Book Value
8³/4% senior notes		$16,521		$16,521		$–
Term & Revolving Facilities		5,362		3,676		1,686
Series 1 Debentures		6,886		534		6,352

		$28,769		$20,731		$8,038


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 $360 and $1,243 respectively, was included in interest expense for the three and nine months ended December 31, 2010 (three and nine months ended December 31, 2009 – $847 and $2,489 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 11(b)). In addition, $183 related to amortization of deferred financing costs incurred up to the redemption date was included in interest expense.

11. Long term debt

a) Credit Facilities


	December 31, 2010			March 31, 2010
Term A Facility		$25,635			$28,446
Term B Facility		45,311			–

Total term facilities		$70,946			$28,446
Less: current portion		(10,000	)		(6,072	)

		$60,946			$22,374

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)

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 December 31, 2010, the Company does not anticipate making the maximum payment of $4.0 million in July 2011.

As of December 31, 2010, the Company had outstanding borrowings of $70.9 million (March 31, 2010 – $28.4 million) under the term facilities, $nil under the Revolving Facility and had issued $12.3 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 $72.7 million at December 31, 2010.

During the three and nine months ended December 31, 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 10).

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 December 31, 2010.

b) 8³/4% Senior Notes


	December 31, 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 10).

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

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)

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 nine months ended December 31, 2010, financing fees of $nil 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 10).

12. 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		128,590		637
Transferred from additional paid-in capital on exercise of stock options		–		245

Issued and outstanding at December 31, 2010		36,177,866		$304,387

b) Net income (loss) per share


	Three Months Ended December 31,				Nine Months Ended December 31,
	2010		2009		2010			2009
Net income (loss) available to common shareholders		$3,742		$14,936		$(4,198	)		$29,162
Weighted average number of common shares		36,126,877		36,038,476		36,085,384			36,038,476
Basic net income (loss) per share		$0.10		$0.41		$(0.12	)		$0.81

Net income (loss) available to common shareholders		$3,742		$14,936		$(4,198	)		$29,162
Weighted average number of common shares		36,126,877		36,038,476		36,085,384			36,038,476
Dilutive effect of stock options and deferred performance share units		753,118		651,550		–			672,960

Weighted average number of diluted common shares		36,879,995		36,690,026		36,085,384			36,711,436
Diluted net income (loss) per share		$0.10		$0.41		$(0.12	)		$0.79

For the three and nine months ended December 31, 2010, there were 635,839 and 573,065, respectively, stock options which were anti-dilutive and therefore were not considered in computing diluted earnings per share (three and nine months ended December 31, 2009 – 155,576 and 159,244, respectively, stock options and deferred performance share units).

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)

13. Interest expense


	Three Months Ended December 31,				Nine Months Ended December 31,
	2010		2009		2010		2009
Interest on 8³/4% senior notes and swaps		$–		$4,517		$1,238		$14,468
Interest on capital lease obligations		155		244		545		805
Amortization of deferred financing costs		360		847		1,243		2,489
Interest on credit facilities		1,416		893		3,680		1,385
Interest on Series 1 Debentures		5,132		–		14,999		–

Interest on long term debt		$7,063		$6,501		$21,705		$19,147
Other interest		130		263		925		578

		$7,193		$6,764		$22,630		$19,725

14. 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.

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 $70.9 million at December 31, 2010 and $28.4 million at March 31, 2010, the fair value of amounts due under the Term Facilities as at December 31, 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:

December 31, 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⁾

9,496

9,431

13,393

13,291

Series 1 Debentures ⁽ⁱⁱⁱ⁾

225,000

237,935

–

(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 December 31, 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

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)

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:


December 31, 2010	Carrying Value
Embedded price escalation features in a long term customer construction contract		$6,156
Embedded price escalation features in certain long term supplier contracts		7,337

		$13,493
Less: current portion		(2,566	)

		$10,927


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 11(b)).

Assets held for sale are re-measured at fair value less cost to sell on a non-recurring basis. Assets held for sale with a carrying amount of $948 were written down to their fair value less cost to sell of $807, resulting in a loss of $141, which was included in depreciation expense in the Consolidated Statements of Operations and Comprehensive Income (Loss) for the period ended December 31, 2010. The fair value less cost to sell 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 December 31,						Nine Months Ended December 31,
	2010			2009			2010			2009
Realized and unrealized loss on cross-currency and interest rate swaps		$–			$8,108			$2,111			$54,126
Unrealized loss (gain) on embedded price escalation features in a long term customer construction contract		77			342			(325	)		6,615
Unrealized gain on embedded price escalation features in certain long term supplier contracts		(2,117	)		(254	)		(2,126	)		(13,958	)
Unrealized gain on early redemption option on 8³/4% senior notes		–			(186	)		–			(3,598	)

		$(2,040	)		$8,010			$(340	)		$43,185

15. Other information

a) Supplemental cash flow information


	Three Months Ended December 31,				Nine Months Ended December 31,
	2010		2009		2010		2009
Cash paid during the period for:
Interest		$11,793		$23,895		$31,848		$49,068
Income taxes		2,977		1,562		4,149		9,113
Cash received during the period for:
Interest		62		2,424		1,167		8,495
Income taxes		2,015		453		2,032		453
Non-cash transactions:
Acquisition of property, plant and equipment by means of capital leases		44		449		91		1,105
Lease inducements		–		–		–		195

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)

b) Net change in non-cash working capital


	Three Months Ended December 31,						Nine Months Ended December 31,
	2010			2009			2010			2009
Operating activities:
Accounts receivable, net		$(22,887	)		$(2,938	)		$(12,528	)		$(7,408	)
Unbilled revenue		2,914			(13,943	)		(49,581	)		(25,490	)
Inventories		(402	)		1,991			(2,261	)		3,785
Prepaid expenses and deposits		1,640			(2,858	)		(1,199	)		(4,140	)
Accounts payable		(15,886	)		9,364			27,489			18,706
Accrued liabilities		(9,311	)		(14,053	)		(14,084	)		(29,093	)
Over hour accrued liabilities		(3,006	)		894			(1,324	)		3,730
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		(2,175	)		(2,296	)		235			(254	)

		$(49,113	)		$(23,839	)		$(53,253	)		$(40,164	)

Investing activities:
Accounts payable		$5,881			$(2,998	)		$1,861			$(351	)

c) Income taxes

Income tax expense as a percentage of income before income taxes for the three and nine months ended December 31, 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 expense as a percentage of income before income taxes for the three and nine months ended December 31, 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.

16. 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. It also designs and manufactures screw piles and pipeline anchoring systems and provides tank maintenance services to the petro-chemical industry across Canada and the United States.

_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.

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)

b) Results by business segment


Three Months Ended December 31, 2010	Heavy Construction and Mining		Piling		Pipeline			Total
Revenues from external customers		$185,325		$37,594		$42,167			$265,086
Depreciation of property, plant and equipment		7,251		1,458		271			8,980
Segment profits		20,293		10,324		(1,641	)		28,976
Capital expenditures		8,371		324		280			8,975


Three Months Ended December 31, 2009	Heavy Construction and Mining		Piling		Pipeline			Total
Revenues from external customers		$183,631		$20,592		$16,952			$221,175
Depreciation of property, plant and equipment		8,191		701		51			8,943
Segment profits		36,237		4,505		1,072			41,814
Capital expenditures		1,573		305		53			1,931


Nine Months Ended December 31, 2010	Heavy Construction and Mining		Piling		Pipeline			Total
Revenues from external customers		$520,562		$83,303		$79,673			$683,538
Depreciation of property, plant and equipment		19,102		2,811		455			22,368
Segment profits		64,774		16,500		(1,485	)		79,789
Capital expenditures		21,836		2,080		1,124			25,040


Nine Months Ended December 31, 2009	Heavy Construction and Mining		Piling		Pipeline			Total
Revenues from external customers		$469,512		$50,268		$18,616			$538,396
Depreciation of property, plant and equipment		24,113		2,108		298			26,519
Segment profits		81,730		9,139		1,301			92,170
Capital expenditures		37,627		307		53			37,987


December 31, 2010	Heavy Construction and Mining		Piling		Pipeline			Total
Segment assets		$456,112		$114,809		$43,826			$614,747


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

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)

c) Reconciliations

i) Income (loss) before income taxes


	Three Months Ended December 31,						Nine Months Ended December 31,
	2010			2009			2010			2009
Total profit for reportable segments		$28,976			$41,814			$79,789			$92,170
Less: unallocated corporate expenses
General and administrative costs		16,482			14,532			45,497			43,426
Loss on disposal of property, plant and equipment		847			743			1,428			1,044
Loss on disposal of assets held for sale		873			649			848			373
Amortization of intangible assets		992			528			2,252			1,438
Equity in loss (earnings) of unconsolidated joint venture		359			(98	)		876			(66	)
Interest expense, net		7,193			6,764			22,630			19,725
Foreign exchange gain		(42	)		(5,449	)		(1,690	)		(42,930	)
Realized and unrealized (gain) loss on derivative financial instruments		(2,040	)		8,010			(340	)		43,185
Loss on debt extinguishment		–			–			4,346			–
Other expense		27			471			18			804
Unallocated equipment (recoveries) costs ⁽ⁱ⁾		(1,831	)		(5,812	)		4,265			(14,392	)

Income (loss) before income taxes		$6,116			$21,476			$(341	)		$39,563

(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


	December 31, 2010		March 31, 2010
Corporate assets:
Cash and cash equivalents		$748		$103,005
Property, plant and equipment		22,427		17,883
Deferred income taxes		49,362		14,478
Other		39,809		24,408

Total corporate assets		$112,346		$159,774
Total assets for reportable segments		614,747		542,843

Total assets		$727,093		$702,617

The Company’s goodwill of $32,649 is assigned to the Piling segment. All of the Company’s assets are located in Canada and the United States.

iii) Depreciation of property, plant and equipment


	Three Months Ended December 31,				Nine Months Ended December 31,
	2010		2009		2010		2009
Total depreciation for reportable segments		$8,980		$8,943		$22,368		$26,519
Depreciation for corporate assets		1,521		1,600		4,390		4,174

Total depreciation		$10,501		$10,543		$26,758		$30,693

iv) Capital expenditures for property, plant and equipment


	Three Months Ended December 31,				Nine Months Ended December 31,
	2010		2009		2010		2009
Total capital expenditures for reportable segments		$8,975		$1,931		$25,040		$37,987
Capital expenditures for corporate assets		2,332		2,843		5,068		10,052

Total capital expenditures		$11,307		$4,774		$30,108		$48,039

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 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 December 31,				Nine Months Ended December 31,
	2010		2009		2010		2009
Customer A		36%		20%		34%		17%
Customer B		19%		45%		28%		51%
Customer C		8%		10%		8%		11%

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

17. Other long term obligations

Other long term obligations are as follows:


	December 31, 2010		March 31, 2010
Over hour accrued liabilities		$13,619		$14,943
Deferred lease inducements		681		761
Asset retirement obligation		386		360
Senior executive stock option plan (note 18(c))		5,423		–
Restricted share unit plan (note 18(e))		2,244		1,030
Director’s deferred stock unit plan (note 18(f))		3,863		2,548

		$26,216		$19,642

18. Stock-based compensation plan

a) Stock-based compensation

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


	Three Months Ended December 31,					Nine Months Ended December 31,
	2010		2009			2010			2009
Share option plan (b)		$309		$414			$1,066			$1,768
Senior executive stock option plan (c)		1,941		–			3,186			–
Deferred performance share unit plan (d)		30		(65	)		(57	)		213
Restricted share unit plan (e)		798		619			1,214			619
Director’s deferred stock unit plan (f)		1,244		471			1,315			1,288
Stock award plan (g)		129		–			653			–

		$4,451		$1,439			$7,377			$3,888

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 December 31,
	2010						2009
	Number of options			Weighted average exercise price ($ per share)			Number of options			Weighted average exercise price ($ per share)
Outstanding, beginning of period		1,686,044			8.88			2,154,624			7.62
Granted		200,000			10.13			–			–
Exercised ⁽ⁱ⁾		(67,430	)		(4.93	)		(560	)		(3.69	)
Forfeited		(80,860	)		(10.62	)		(25,400	)		(9.60	)

Outstanding, end of period		1,737,754			9.10			2,128,664			7.60

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

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)


	Nine Months Ended December 31,
	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		260,000			9.77			160,000			8.28
Exercised ⁽ⁱ⁾		(128,590	)		(4.96	)		–			–
Options settled for cash		–			–			(40,560	)		(4.98	)
Forfeited		(94,460	)		(10.44	)		(62,660	)		(8.87	)
Modified ⁽ⁱⁱ⁾		(550,000	)		(5.00	)		–			–

Outstanding, end of period		1,737,754			9.10			2,128,664			7.60

(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 18(c)).

At December 31, 2010, the weighted average remaining contractual life of outstanding options is 6.3 years (March 31, 2010 – 6.6 years). At December 31, 2010, the Company had 833,210 exercisable options (March 31, 2010 –1,244,908) with a weighted average exercise price of $8.10 (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 December 31,				Nine Months Ended December 31,
	2010		2009		2010		2009
Number of options granted		200,000		–		260,000		160,000
Weighted average fair value per option granted ($)		7.05		–		6.79		5.89
Weighted average assumptions:
Dividend yield		Nil%		–		Nil%		Nil%
Expected volatility		78.57%		–		78.59%		77.47%
Risk-free interest rate		2.78%		–		2.65%		3.44%
Expected life (years)		6.10		–		6.09		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 $1,941 and $3,186 was recognized for the three and nine months ended December 31, 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 December 31, 2010 are as follows:


Number of senior executive stock options			550,000
Weighted average fair value per option granted ($)			9.86
Weighted average assumptions:
Dividend yield			Nil%
Expected volatility			85.09%
Risk-free interest rate			2.14%
Expected life (years)			5.00

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

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)

income divided by average operating assets. The date of the third fiscal year-end following the date of the grant of 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 December 31,						Nine Months Ended December 31,
	2010			2009			2010			2009
Outstanding, beginning of period		491,988			807,901			507,295			91,005
Granted		–			–			–			748,791
Exercised		–			–			–			–
Forfeited		(38,276	)		(42,194	)		(53,583	)		(74,089	)
Converted to RSUs		–			(389,204	)		–			(389,204	)

Outstanding, end of period		453,712			376,503			453,712			376,503

The weighted average exercise price per unit is $nil.

At December 31, 2010, the weighted average remaining contractual life of outstanding DPSU Plan units is 1.45 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 December 31, 2010, there was approximately $321 of total unrecognized compensation cost related to non-vested share-based payment arrangements under the DPSU Plan (December 31, 2009 – $442), which is expected to be recognized over a weighted average period of 1.45 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 market value of each RSU as determined by the volume weighted average trading price of the Company’s common shares for the five trading days immediately preceding the day on which the fair market value is to be determined. The Company recognizes compensation expense over the vesting period of the RSU term.


	Three Months Ended December 31,					Nine Months Ended December 31,
	2010			2009		2010			2009
Outstanding, beginning of period		433,547			–		468,815			–
Converted from DPSUs at a conversion factor of 80%		–			311,358		–			311,358
Granted		–			–		–			–
Exercised		–			–		–			–
Forfeited		(55,480	)		–		(90,748	)		–

Outstanding, end of period		378,067			311,358		378,067			311,358

At December 31, 2010, the redemption value of these units was $12.01/unit (March 31, 2010 – $9.68/unit).

Using the redemption value of $12.01/unit at December 31, 2010, there was approximately $2,376 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 1.5 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

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)

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 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 December 31,				Nine Months Ended December 31,
	2010		2009		2010		2009
Outstanding, beginning of period		306,719		209,714		263,266		139,691
Granted		14,840		31,570		58,293		101,593

Outstanding, end of period		321,559		241,284		321,559		241,284

At December 31, 2010, the redemption value of these units was $12.01/unit (March 31, 2010 – $9.68/unit). There is no unrecognized compensation expense related to the DDSUs, since these awards vest immediately when granted.

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:


Number of stock awards granted			150,000
Weighted average fair value per award granted ($)			7.00
Weighted average assumptions:
Dividend yield			Nil%
Expected volatility			117.72%
Risk-free interest rate			1.48%
Expected life (years)			2.6

None of the stock awards have vested as of December 31, 2010. At December 31, 2010, the weighted average remaining contractual life of outstanding Stock Award Plan units is 0.9 years (March 31, 2010 – 1.6 years). As at December 31, 2010, there was approximately $397 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 0.9 years (March 31, 2010 – 1.6 years).

19. 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.

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)

20. Claims revenue

For the three and nine months ended December 31, 2010, due to the timing of receipt of signed change orders, the Heavy Construction and Mining segment had approximately $0.3 million and $1.0 million respectively in claims revenue recognized to the extent of costs incurred, the Piling segment had $0.5 million and $2.3 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.

21. 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.

22. 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 comprehensive income (loss) would be adjusted as follows:


Consolidated Statements of Operations, Comprehensive Income and Deficit – Three months ended December 31, 2010	US GAAP			Adjustments			Canadian GAAP
Revenue ^(e)		$265,086			$1,010			$266,096
Project costs ^(e)		148,019			993			149,012
Equipment costs		58,819			–			58,819
Equipment operating lease expense		16,940			–			16,940
Depreciation ^(a)		10,501			(27	)		10,474

Gross profit		30,807			44			30,851
General and administrative costs ^(c) and ^(e)		16,482			155			16,637
Loss on disposal of property, plant and equipment		847			–			847
Loss on disposal of assets held for sale		873			–			873
Amortization of intangible assets ^(b)		992			177			1,169
Equity in loss of unconsolidated joint venture ^(e)		359			(359	)

Operating income before the undernoted		11,254			71			11,325
Interest expense, net ^(b)		7,193			(271	)		6,922
Foreign exchange gain		(42	)		–			(42	)
Realized and unrealized gain on derivative financial instruments ^(d)		(2,040	)		(1,569	)		(3,609	)
Other expense		27			–			27

Income before income taxes		6,116			1,911			8,027
Income taxes:
Current		(51	)		–			(51	)
Deferred ^(f)		2,425			216			2,641

Net income		3,742			1,695			5,437
Other comprehensive loss
Unrealized foreign currency translation loss		20			–			20

Comprehensive income		3,722			1,695			5,417
Deficit, beginning of period		(137,826	)		7,339			(130,487	)

Deficit, end of period		$(134,084	)		$9,034			$(125,050	)

Net income per share – basic		$0.10			$0.05			$0.15

Net income per share – diluted		$0.10			$0.05			$0.15

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)


Consolidated Statements of Operations, Comprehensive Loss and Deficit – Nine months ended December 31, 2010	US GAAP			Adjustments			Canadian GAAP
Revenue ^(e)		$683,538			$4,009			$687,547
Project costs ^(e)		357,736			3,591			361,327
Equipment costs		170,180			–			170,180
Equipment operating lease expense		53,340			–			53,340
Depreciation ^(a)		26,758			(83	)		26,675

Gross profit		75,524			501			76,025
General and administrative costs ^(c) and ^(e)		45,497			(194	)		45,303
Loss on disposal of property, plant and equipment		1,428			–			1,428
Loss on disposal of assets held for sale		848			–			848
Amortization of intangible assets ^(b)		2,252			526			2,778
Equity in loss of unconsolidated joint venture ^(e)		876			(876	)		–

Operating income before the undernoted		24,623			1,045			25,668
Interest expense, net ^(b)		22,630			(918	)		21,712
Foreign exchange gain		(1,690	)		–			(1,690	)
Realized and unrealized gain on derivative financial instruments ^(d)		(340	)		(4,630	)		(4,970	)
Loss on debt extinguishment ^(b)		4,346			(2,884	)		1,462
Other expense		18			–			18

(Loss) income before income taxes		(341	)		9,477			9,136
Income taxes (benefit):
Current		4,436			–			4,436
Deferred ^(f)		(579	)		1,524			945

Net (loss) income		(4,198	)		7,953			3,755
Other comprehensive loss
Unrealized foreign currency translation loss		20			–			20

Comprehensive (loss) income		(4,218	)		7,953			3,735
Deficit, beginning of period		(129,886	)		1,081			(128,805	)

Deficit, end of period		$(134,084	)		$9,034			$(125,050	)

Net loss (income) per share – basic		$(0.12	)		$0.22			$0.10

Net loss (income) per share – diluted		$(0.12	)		$0.22			$0.10


Consolidated Statements of Operations, Comprehensive Income and Deficit – Three months ended December 31, 2009	US GAAP			Adjustments			Canadian GAAP
Revenue ^(e)		$221,175			$1,539			$222,714
Project costs ^(e)		89,207			1,115			90,322
Equipment costs		57,512			–			57,512
Equipment operating lease expense		16,287			–			16,287
Depreciation ^(a)		10,543			(31	)		10,512

Gross profit		47,626			455			48,081
General and administrative costs ^(c) and ^(e)		14,532			315			14,847
Loss on disposal of property, plant and equipment		743			–			743
Loss on disposal of assets held for sale		649			–			649
Amortization of intangible assets ^(b)		528			210			738
Equity in earnings of unconsolidated joint venture ^(e)		(98	)		98			–

Operating income before the undernoted		31,272			(168	)		31,104
Interest expense, net ^(b)		6,764			(637	)		6,127
Foreign exchange gain ^(b)		(5,449	)		46			(5,403	)
Realized and unrealized loss on derivative financial instruments ^(d)		8,010			(392	)		7,618
Other expenses		471			–			471

Income before income taxes		21,476			815			22,291
Income taxes:
Current		591			–			591
Deferred ^(f)		5,949			174			6,123

Net income and comprehensive income for the period		14,936			641			15,577
Deficit, beginning of period		(143,879	)		2,461			(141,418	)

Deficit, end of period		$(128,943	)		$3,102			$(125,841	)

Net income per share – basic		$0.41			$0.02			$0.43

Net income per share – diluted		$0.41			$0.02			$0.43

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)


Consolidated Statements of Operations, Comprehensive Income and Deficit – Nine months ended December 31, 2009	US GAAP			Adjustments			Canadian GAAP
Revenue ^(e)		$538,396			$2,531			$540,927
Project costs ^(e)		208,906			1,928			210,834
Equipment costs		147,915			–			147,915
Equipment operating lease expense		44,320			–			44,320
Depreciation ^(a)		30,693			(93	)		30,600

Gross profit		106,562			696			107,258
General and administrative costs ^(c) and ^(e)		43,426			502			43,928
Loss on disposal of property, plant and equipment		1,044			–			1,044
Loss on disposal of assets held for sale		373			–			373
Amortization of intangible assets ^(b)		1,438			623			2,061
Equity in earnings of unconsolidated joint venture ^(e)		(66	)		66			–

Operating income before the undernoted		60,347			(495	)		59,852
Interest expense, net ^(b)		19,725			(1,840	)		17,885
Foreign exchange gain		(42,930	)		450			(42,480	)
Realized and unrealized loss on derivative financial instruments ^(d)		43,185			(2,720	)		40,465
Other expenses		804			–			804

Income before income taxes		39,563			3,615			43,178
Income taxes:
Current		1,855			–			1,855
Deferred ^(f)		8,546			639			9,185

Net income and comprehensive income for the period		29,162			2,976			32,138
Deficit, beginning of period		(158,105	)		126			(157,979	)

Deficit, end of period		$(128,943	)		$3,102			$(125,841	)

Net income per share – basic		$0.81			$0.08			$0.89

Net income per share – diluted		$0.79			$0.08			$0.87

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 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 – December 31, 2010	US GAAP			Adjustments			Canadian GAAP
Assets
Current assets:
Cash and cash equivalents ^(e)		$748			$903			$1,651
Accounts receivable, net ^(e)		131,509			1,595			133,104
Unbilled revenue ^(e)		134,283			1,733			136,016
Inventories		6,829			–			6,829
Prepaid expenses and deposits ^(e)		9,367			46			9,413
Deferred tax assets		2,331			–			2,331

		285,067			4,277			289,344
Prepaid expenses and deposits		2,781			–			2,781
Assets held for sale		807			–			807
Property, plant and equipment ^(a) and ^(e)		331,680			49			331,729
Investment in and advances to unconsolidated joint venture ^(e)		3,332			(3,332	)		–
Intangible assets ^(b) and ^(e)		15,708			1,712			17,420
Goodwill		32,649			–			32,649
Deferred financing costs ^(b)		8,038			(8,038	)		–
Deferred tax assets		47,031			–			47,031

		$727,093			$(5,332	)		$721,761

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable ^(e)		$97,201			$1,553			$98,754
Accrued liabilities ^(e)		27,470			46			27,516
Billings in excess of costs incurred and estimated earnings on uncompleted contracts		1,849			–			1,849
Current portion of capital lease obligations		4,783			–			4,783
Current portion of term facilities		10,000			–			10,000
Current portion of derivative financial instruments		2,566			–			2,566
Deferred tax liabilities		35,854			–			35,854

		179,723			1,599			181,322
Capital lease obligations		4,713			–			4,713
Term facilities		60,946			–			60,946
Series 1 debentures ^(b) and ^(d)		225,000			(11,257	)		213,743
Derivative financial instruments		10,927			–			10,927
Other long term obligations		26,216			(1,452	)		24,764
Deferred tax liabilities ^(f)		42,666			472			43,138

		550,191			(10,638	)		539,553
Shareholders’ equity:
Common shares (authorized – unlimited number of voting common shares; issued and outstanding – December 31, 2010 – 36,177,866)		304,387			(3,458	)		300,929
Additional paid-in capital ^(c) and ^(f)		6,619			(270	)		6,349
Deficit ^{(a – f)}		(134,084	)		9,034			(125,050	)
Accumulated other comprehensive loss		(20	)		–			(20	)

		176,902			5,306			182,208

		$727,093			$(5,332	)		$721,761

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 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
Capital lease obligations		8,340			–			8,340
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		19,642			–			19,642
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 25

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 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 December 31, 2010	US GAAP			Adjustments			Canadian GAAP
Cash provided by (used in):
Operating activities:
Net income for the period		$3,742			$1,695			$5,437
Items not affecting cash:
Depreciation		10,501			(27	)		10,474
Equity in loss of unconsolidated joint venture		359			(359	)		–
Amortization of intangible assets		992			177			1,169
Amortization of deferred lease inducements		(26	)		–			(26	)
Amortization of deferred financing costs		360			(178	)		182
Amortization of premium on series 1 debentures		–			(93	)		(93	)
Loss on disposal of property, plant and equipment		847			–			847
Loss on disposal of assets held for sale		873			–			873
Unrealized gain on derivative financial instruments measured at fair value		(2,040	)		(1,569	)		(3,609	)
Stock-based compensation expense		4,451			(218	)		4,233
Accretion of asset retirement obligation		9			–			9
Deferred income taxes		2,425			216			2641
Net changes in non-cash working capital		(49,113	)		267			(48,846	)

		(26,620	)		(89	)		(26,709	)
Investing activities:
Acquisition		(20,820	)		–			(20,820	)
Purchase of property, plant and equipment		(10,576	)		39			(10,537	)
Additions to intangible assets		(731	)		(39	)		(770	)
Proceeds on disposal of property, plant and equipment		360			–			360
Proceeds on disposal of assets held for sale		445			–			445
Net changes in non-cash working capital		5,881			–			5,881

		(25,441	)		–			(25,441	)
Financing activities:
Repayment of term facilities		(2,500	)		–			(2,500	)
Proceeds from stock options exercised		332			–			332
Repayment of capital lease obligations		(1,176	)		–			(1,176	)

		(3,344	)		–			(3,344	)

Decrease in cash and cash equivalents		(55,405	)		(89	)		(55,494	)
Effect of exchange rate on changes in cash		(27	)		–			(27	)
Cash and cash equivalents, beginning of period		56,180			992			57,172

Cash and cash equivalents, end of period		$748			$903			$1,651

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)


Consolidated Statements of Cash Flows – Nine months ended December 31, 2010	US GAAP			Adjustments			Canadian GAAP
Cash provided by (used in):
Operating activities:
Net loss (income) for the period		$(4,198	)		$7,953			$3,755
Items not affecting cash:
Depreciation		26,758			(83	)		26,675
Equity in loss of unconsolidated joint venture		876			(876	)		–
Amortization of intangible assets		2,252			526			2,778
Amortization of deferred lease inducements		(80	)		–			(80	)
Amortization of deferred financing costs		1,243			(644	)		599
Amortization of premium on Series 1 Debentures		–			(274	)		(274	)
Loss on disposal of property, plant and equipment		1,428			–			1,428
Loss on disposal of assets held for sale		848			–			848
Unrealized foreign exchange gain on 8³/4% senior notes		(732	)		–			(732	)
Unrealized gain on derivative financial instruments measured at fair value		(340	)		(4,630	)		(4,970	)
Loss on debt extinguishment		4,346			(2,884	)		1,462
Stock-based compensation expense		7,377			(1,486	)		5,891
Accretion of asset retirement obligation		26			–			26
Deferred income taxes (benefit)		(579	)		1,524			945
Net changes in non-cash working capital		(53,253	)		(99	)		(53,352	)

		(14,028	)		(973	)		(15,001	)
Investing activities:
Acquisition		(20,820	)		–			(20,820	)
Purchase of property, plant and equipment		(27,353	)		(502	)		(27,855	)
Additions to intangible assets		(2,755	)		(153	)		(2,908	)
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		420			–			420
Proceeds on disposal of assets held for sale		745			–			745
Net changes in non-cash working capital		1,861			–			1,861

		(50,896	)		636			(50,260	)
Financing activities:
Repayment of term facilities		(7,500	)		–			(7,500	)
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		637			–			637
Repayment of capital lease obligations		(3,988	)		–			(3,988	)

		(37,306	)		–			(37,306	)

Decrease in cash and cash equivalents		(102,230	)		(337	)		(102,567	)
Effect of exchange rate on changes in cash		(27	)		–			(27	)
Cash and cash equivalents, beginning of period		103,005			1,240			104,245

Cash and cash equivalents, end of period		$748			$903			$1,651

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)


Consolidated Statements of Cash Flows – Three months ended December 31, 2009	US GAAP			Adjustments			Canadian GAAP
Cash provided by (used in):
Operating activities:
Net income for the period		$14,936			$641			$15,577
Items not affecting cash:
Depreciation		10,543			(31	)		10,512
Equity in earnings of unconsolidated joint venture		(98	)		98			–
Amortization of intangible assets		528			210			738
Amortization of deferred lease inducements		(19	)		–			(19	)
Amortization of deferred financing costs		847			(637	)		210
Loss on disposal of property, plant and equipment		743			–			743
Loss on disposal of assets held for sale		649			–			649
Unrealized foreign exchange gain on 8³/4% senior notes		(5,120	)		46			(5,074	)
Unrealized loss on derivative financial instruments measured at fair value		3,818			(392	)		3,426
Stock-based compensation expense		1,439			(11	)		1,428
Accretion of asset retirement obligation		8			–			8
Deferred income taxes		5,949			174			6,123
Net changes in non-cash working capital		(23,839	)		(644	)		(24,483	)

		10,384			(546	)		9,838
Investing activities:
Acquisition		(530	)		–			(530	)
Purchase of property, plant and equipment		(3,542	)		–			(3,542	)
Additions to intangible assets		(1,232	)		–			(1,232	)
Additions to assets held for sale		(125	)		–			(125	)
Investment in and advances to unconsolidated joint venture		(1,887	)		1,887			–
Proceeds on disposal of property, plant and equipment		454			–			454
Proceeds on disposal of assets held for sale		1,170			–			1,170
Net changes in non-cash working capital		(2,998	)		–			(2,998	)

		(8,690	)		1,887			(6,803	)
Financing activities:
Repayment of term facilities		(3,037	)		–			(3,037	)
Repayment of capital lease obligations		(1,271	)		–			(1,271	)

		(4,308	)		–			(4,308	)

Decrease in cash and cash equivalents		(2,614	)		1,341			(1,273	)
Cash and cash equivalents, beginning of period		97,491			225			97,716

Cash and cash equivalents, end of period		$94,877			$1,566			$96,443

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)


Consolidated Statements of Cash Flows – Nine months ended December 31, 2009	US GAAP			Adjustments			Canadian GAAP
Cash provided by (used in):
Operating activities:
Net income for the period		$29,162			$2,976			$32,138
Items not affecting cash:
Depreciation		30,693			(93	)		30,600
Equity in earnings of unconsolidated joint venture		(66	)		66			–
Amortization of intangible assets		1,438			623			2,061
Amortization of deferred lease inducements		(80	)		–			(80	)
Amortization of deferred financing costs		2,489			(1,840	)		649
Loss on disposal of property, plant and equipment		1,044			–			1,044
Loss on disposal of assets held for sale		373			–			373
Unrealized foreign exchange gain on 8³/4% senior notes		(42,720	)		450			(42,270	)
Unrealized loss on derivative financial instruments measured at fair value		31,793			(2,720	)		29,073
Stock-based compensation expense		3,888			(35	)		3,853
Accretion of asset retirement obligation		(4	)		–			(4	)
Deferred income taxes		8,546			639			9,185
Net changes in non-cash working capital		(40,164	)		(1,373	)		(41,537	)

		26,392			(1,307	)		25,085
Investing activities:
Acquisition		(5,410	)		–			(5,410	)
Purchase of property, plant and equipment		(46,002	)		–			(46,002	)
Additions to intangible assets		(2,037	)		–			(2,037	)
Additions to assets held for sale		(1,058	)		–			(1,058	)
Investment in and advances to unconsolidated joint venture		(2,873	)		2,873			–
Proceeds on disposal of property, plant and equipment		1,150			–			1,150
Proceeds on disposal of assets held for sale		2,282			–			2,282
Net changes in non-cash working capital		(351	)		–			(351	)

		(54,299	)		2,873			(51,426	)
Financing activities:
Repayment of term facilities		(3,688	)		–			(3,688	)
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		(4,219	)		–			(4,219	)

		23,904			–			23,904

Decrease in cash and cash equivalents		(4,003	)		1,566			(2,437	)
Cash and cash equivalents, beginning of period		98,880			–			98,880

Cash and cash equivalents, end of period		$94,877			$1,566			$96,443

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

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 2010

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

(Unaudited)

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 $2,884.

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 (December 31, 2010 – $8,038; 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 (December 31, 2010 – $6,352) 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 (December 31, 2010 – $1,558; 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 December 31, 2010, the liability under US GAAP was measured at $5,423 of which $2,237 was transferred from additional paid-in capital and the difference of $3,186 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 $3,971 resulting in a transfer of the same amount from additional paid-in capital and the difference of $1,734 was recognized as incremental compensation cost.

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.

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

Notes to Interim Consolidated Financial Statements

For the three and nine months ended December 31, 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:


	December 31, 2010			March 31, 2010
Current assets		$4,277			$4,476
Long term assets		656			77
Current liabilities		1,599			1,636
Long term liabilities		4,260			2,970

Net equity		$(926	)		$(53	)


	Three Months Ended December 31,						Nine Months Ended December 31,
	2010			2009			2010			2009
Gross revenues		$1,010			$1,539			$4,009			$2,582
Gross profit		16			424			417			613
Expense		(375	)		(326	)		(1,293	)		(547	)

Net (loss) income		$(359	)		$98			$(876	)		$66


	Three Months Ended December 31,						Nine Months Ended December 31,
	2010			2009			2010			2009
Cash flow resulting from operating activities		$(89	)		$(546	)		$(973	)		$(1,307	)
Cash flow resulting from investing activities		–			1,887			636			2,873

(Decrease) increase in cash and cash equivalents		$(89	)		$1,341			$(337	)		$1,566

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.

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.

North American Energy Partners Inc. Notes to Consolidated Financial Statements 31

NORTH AMERICAN ENERGY PARTNERS INC.

Management’s Discussion and Analysis

For the three and nine months ended December 31, 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	13
	Summary of Consolidated Financial Position	14
	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	17
	Capital Commitments	21
	Debt Ratings	21
	Related Parties	22
	Internal Systems and Processes	22
	Significant Accounting Policies	23
	Recently Adopted Accounting Policies	23
	Recent Accounting Pronouncements Not Yet Adopted	24
F.	Forward-Looking Information and Risk Factors	24
	Forward-Looking Information	24
	Business Risk Factors	26
	Quantitative and Qualitative Disclosures about Market Risk	27
G.	General Matters	27
	Additional Information	27

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

Management’s Discussion and Analysis

For the three and nine months ended December 31, 2010

A. Explanatory Notes

February 1, 2011

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 nine months ended December 31, 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 “EBITDA” (net income before interest expense, income taxes, depreciation and amortization) 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 nine months ended December 31, 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 nine months ended December 31, 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 Nine Month Results


	Three Months Ended December 31,
(dollars in thousands, except per share amounts)	2010			% of Revenue		2009		% of Revenue		Change
Revenue	$	265,086			100.0%	$	221,175		100.0%	$	43,911
Project costs		148,019			55.8%		89,207		40.3%		58,812
Equipment costs		58,819			22.2%		57,512		26.0%		1,307
Equipment operating lease expense		16,940			6.4%		16,287		7.4%		653
Depreciation		10,501			4.0%		10,543		4.8%		(42	)

Gross profit		30,807			11.6%		47,626		21.5%		(16,819	)
General and administrative costs		16,482			6.2%		14,532		6.6%		1,950

Operating income		11,254			4.2%		31,272		14.1%		(20,018	)
Net income		3,742			1.4%		14,936		6.8%		(11,194	)
Per share information											–
Net income – basic	$	0.10				$	0.41			$	(0.31	)
Net income – diluted		0.10					0.41				(0.31	)
EBITDA ⁽¹⁾	$	24,802			9.4%	$	39,311		17.8%	$	(14,509	)
Consolidated EBITDA ⁽¹⁾ (as defined within the credit agreement)	$	25,309			9.5%	$	43,844		19.8%	$	(18,535	)


	Nine Months Ended December 31,
(dollars in thousands, except per share amounts)	2010			% of Revenue		2009		% of Revenue		Change
Revenue	$	683,538			100.0%	$	538,396		100.0%	$	145,142
Project costs		357,736			52.3%		208,906		38.8%		148,830
Equipment costs		170,180			24.9%		147,915		27.5%		22,265
Equipment operating lease expense		53,340			7.8%		44,320		8.2%		9,020
Depreciation		26,758			3.9%		30,693		5.7%		(3,935	)

Gross profit		75,524			11.0%		106,562		19.8%		(31,038	)
General and administrative costs		45,497			6.7%		43,426		8.1%		2,071

Operating income		24,623			3.6%		60,347		11.2%		(35,724	)
Net (loss) income		(4,198	)		-0.6%		29,162		5.4%		(33,360	)
Per share information
Net (loss) income – basic	$	(0.12	)			$	0.81			$	(0.93	)
Net (loss) income – diluted		(0.12	)				0.79				(0.91	)
EBITDA ⁽¹⁾	$	51,299			7.5%	$	91,419		17.0%	$	(40,120	)
Consolidated EBITDA ⁽¹⁾ (as defined within the credit agreement)	$	60,097			8.8%	$	95,216		17.7%	$	(35,119	)

⁽¹⁾	See reconciliation of net income (loss) to EBITDA and Consolidated EBITDA below:

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

Reconciliation of Net Income (loss) to EBITDA and Consolidated EBITDA


	Three Months Ended December 31,									Nine Months Ended December 31,
(dollars in thousands)	2010			2009			Change			2010			2009			Change
Net income (loss)		$3,742			$14,936			$(11,194	)		$(4,198	)		$29,162			$(33,360	)
Adjustments:
Interest expense		7,193			6,764			429			22,630			19,725			2,905
Income taxes		2,374			6,540			(4,166	)		3,857			10,401			(6,544	)
Depreciation		10,501			10,543			(42	)		26,758			30,693			(3,935	)
Amortization of intangible assets		992			528			464			2,252			1,438			814

EBITDA		$24,802			$39,311			$(14,509	)		$51,299			$91,419			$(40,120	)
Adjustments:
Unrealized foreign exchange gain on senior notes		–			(5,120	)		5,120			–			(42,720	)		42,720
Realized and unrealized (gain) loss on derivative financial instruments		(2,040	)		8,010			(10,050	)		(340	)		43,185			(43,525	)
Loss on disposal of property, plant and equipment and assets held for sale		1,720			1,392			328			2,276			1,417			859
Stock-based compensation expense		468			349			119			1,662			1,981			(319	)
Equity in loss (earnings) of unconsolidated joint venture		359			(98	)		457			876			(66	)		942
Loss on debt extinguishment		–			–			–			4,324			–			4,324

Consolidated EBITDA		$25,309			$43,844			$(18,535	)		$60,097			$95,216			$(35,119	)

Analysis of Consolidated Results

Revenue

For the three months ended December 31, 2010, consolidated revenues increased to $265.1 million, $43.9 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, the completion of tailings-related construction projects at Shell Albian¹, together with site development projects at Canadian Natural’s² Horizon mine and Exxon’s Kearl³ mine were key factors in the increase. Outside of the oil sands, improving commercial and industrial construction market conditions and more stable weather conditions led to an increase in piling projects. Pipeline revenues were also higher year-over-year as a result of activity on two projects in northern British Columbia (BC), which commenced earlier in the current fiscal year. Recurring services revenues were lower year-over-year, reflecting the decline in demand for mine services at Shell Albian’s Jackpine mine following the mine’s commissioning. This was partially offset by increased overburden removal activity under our long-term contract with Canadian Natural and by increased reclamation and overburden work and the continued provision of mine support services to both Syncrude⁴ and Suncor⁵.

For the nine months ended December 31, 2010, revenues increased to $683.5 million, $145.1 million higher than during the same period last year. This improvement reflects higher project development revenues which 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. Recurring services revenues were lower year-over-year as a result of the reduced activity at Shell Albian during the commissioning of the Jackpine mine but were mitigated by higher volumes of work at the Canadian Natural, Syncrude and Suncor sites.

Gross Profit

Gross profit for the three months ended December 31, 2010 was $30.8 million (11.6% of revenue), compared to $47.6 million (21.5% of revenue) during the same period last year. The change in gross profit reflects lower margins in the Heavy Construction and Mining segment and a loss in the Pipeline segment, partially offset by higher margins in the Piling segment. The change in Heavy Construction and Mining margins reflects continuing competitive pressure, a change in work mix and client-related start-up delays together with the associated equipment rental costs related to winter reclamation and overburden work. The Pipeline segment loss reflects productivity and weather challenges for the projects in northern BC along with significantly increased scope for one of these projects. We are currently developing

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%), Sinopec Corp. (9.03%) (Previously owned by ConocoPhillips Oil Sand Partnership II), 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.

change-order requests to present to our clients for start-up delays and significant changes to project scope in accordance with the terms of our contract. The increase in Piling segment margins reflects improving market conditions and profit recovery from the approval and processing of outstanding change-orders from prior periods.

Project costs were $148 million or 55.8% of revenue during the three months ended December 31, 2010, up from $89.2 million or 40.3% of revenue in the same period last year. The increase in project development activity in the more labour, material and subcontractor intensive Piling and Pipeline segments drove this change. Project costs were also impacted by the client start-up delays and increased scope on some lump-sum projects.

For the three months ended December 31, 2010, equipment costs were similar to last year but decreased to 22.2% of revenue, from 26.0% last year, reflecting increased project development activity discussed above. Equipment operating lease expense increased $0.7 million to $16.9 million, but decreased as a percentage of revenue to 6.4%, as compared to 7.4% in the same period last year. Use of rentals also increased during the period as we worked to supply 100-to-150 ton trucks to our growing volume of construction projects while increased utilization of our leased mining fleet for a long-term overburden removal project and the reduction in other oil sands recurring services resulted in lower utilization of our larger 240 ton fleet compared to the same period last year.

Gross profit for the nine months ended December 31, 2010 was $75.5 million, a decrease of $31.0 million compared to the same period last year. As a percentage of revenue, gross profit margin decreased to 11.0%, reflecting a shift in work mix, increased volumes of lower-margin activity under our long-term overburden removal contract, reduced activity levels at Shell Albian, the impact of adverse weather conditions on our construction business during the first half of the fiscal year and losses related to the two pipeline projects in northern BC. Margin performance for the current nine-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 were $357.7 million or 52.3% of revenue during the nine months ended December 31, 2010, an increase from $208.9 million or 38.8% of revenue 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. Equipment costs were $170.2 million or 24.9% of revenue for the first nine months up from $147.9 million or 27.5% of revenue during the same period last year, reflecting the increase in less equipment-intensive project development activity. Equipment operating lease expense increased by $9.0 million year-over-year to $53.3 million, reflecting additions to our overburden removal equipment fleet in the latter part of fiscal 2010. For the nine months ended December 31, 2010, depreciation expense declined by $3.9 million to $26.8 million compared to the same period last year. This decrease reflects increased utilization of rentals and smaller construction equipment, additions to our leased overburden removal equipment fleet, as well as the impact of reduced utilization of our own mining fleet. Depreciation expense for the prior year nine-month period included accelerated depreciation of $3.4 million as certain aging equipment was prepared for sale.

Operating income

For the three months ended December 31, 2010, we recorded operating income of $11.3 million or 4.2% of revenue, compared to operating income of $31.3 million or 14.1% of revenue, during the same period last year. General and administrative (G&A) costs increased by $2.0 million compared to last year. The increase in G&A costs reflects the impact of share price increases on our stock-based compensation which was partially offset by a reduced payout forecast for our short-term employee incentive plan.

For the nine months ended December 31, 2010, we recorded operating income of $24.6 million or 3.6% of revenue, compared to operating income of $60.3 million or 11.2% of revenue during the same period last year. G&A costs increased by $2.1 million, year-over-year, reflecting a partial stock option plan restructuring and the impact of share price increases on our stock-based compensation.

Net income (loss)

For the three months ended December 31, 2010, we recorded net income of $3.7 million (basic income per share and diluted income per share of $0.10), compared to net income of $14.9 million (basic and diluted income per share of $0.41) 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 the positive foreign exchange impact of the strengthening Canadian dollar on our 8³/4% senior notes, gains relating to embedded derivatives in long-term supplier contracts and redemption options in our 8³/4% senior notes. These items were partially offset by a loss relating to embedded derivatives in a long-term customer contract and a loss on our cross currency and interest rate swaps. Excluding the above items, net income for the three months ended December 31, 2010 would have been $2.2 million (basic and diluted income per share of $0.06), compared to net income of $13.9 million during the same period last year (basic income per share of $0.39 and diluted income per share of $0.38).

For the nine months ended December 31, 2010, we recorded a net loss of $4.2 million (basic loss per share of $0.12) compared to net income of $29.2 million (basic income per share of $0.81 and diluted income per share of $0.79)

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

during the same period last year. The non-cash items affecting current-year results included the write-off of deferred financing costs on the settlement of the 8³/4% senior notes and losses on the 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 relating to embedded derivatives in long-term supplier contracts, interest rate swap and redemption options in our 8³/4% senior notes. These items were partially offset by losses relating to embedded derivatives in a long-term customer contract and cross currency swap. Excluding the above items, net loss for the nine months ended December 31, 2010 would have been $0.5 million (basic loss per share of $0.01), compared to net income of $21.0 million during the same period last year (basic income per share of $0.58 and diluted income per share of $0.57).

Segment Results

Heavy Construction and Mining


	Three Months Ended December 31,							Nine Months Ended December 31,
(dollars in thousands)	2010		2009		Change			2010		2009		Change
Segment revenue		$185,325		$183,631		$1,694			$520,562		$469,512		$51,050
Segment profit		$20,293		$36,237		$(15,944	)		$64,774		$81,730		$(16,956	)
Project margin		10.9%		19.7%					12.4%		17.4%

For the three months ended December 31, 2010, revenues from the Heavy Construction and Mining segment increased $1.7 million compared to the same period last year. This gain reflects higher project development activity in the oil sands, including the completion of tailings-related construction projects for Shell Albian and mine development projects for Exxon and Canadian Natural. Recurring services revenues decreased year-over-year as a result of reduced activity at Shell Albian following the commissioning of the Jackpine mine. This was partially offset by increased activity on our long-term overburden contract with Canadian Natural and increased reclamation and overburden activity at both Syncrude and Suncor.

For the nine months ended December 31, 2010, the Heavy Construction and Mining segment reported revenues of $520.6 million, a $51.1 million increase compared to the same period last year. The improved revenues reflects a higher level of project development activity as we completed mine construction projects with Exxon, Syncrude and Canadian Natural, as well as tailings-related construction projects at Shell Albian. Nine-month recurring services revenues were lower than the same period last year.

For the three months ended December 31, 2010, Heavy Construction and Mining profit margin was 10.9% of revenue, compared to 19.7% of revenue during the same period last year. The year-over-year change in profit margin reflects continuing competitive pressure on margins, the increased volume of lower-margin overburden removal work in the work mix and an increase in equipment rentals. Included in the current quarter was a reduction of margin at Shell due to a contractual pain/gain sharing mechanism whereby we missed our safety performance targets. Although the financial impact was negative our client values that we included safety commitments in our contract and based on historical performance we typically exceed those targets. Segment margins in the prior year were higher than normal due to the successful completion of two high-margin construction contracts. The financial impact of a foreign exchange-related increase in our profit forecast for our long-term overburden removal contract was offset by increased project costs that exceeded price escalators defined in our contract. We are in the process of developing change-order requests to submit to our customers with whom we intend to work with to address cost increases and re-align the price escalators with current market standards.

For the nine months ended December 31, 2010, Heavy Construction and Mining profit margin decreased to 12.4% of revenue, from 17.4% during the same period last year. The change in margin reflects the higher proportion of low margin overburden work, increased rental requirements, and ramping up for increased winter workload, some of which we believe will be offset with higher winter equipment utilization. Adding to the lower margins were unrecovered costs related to client start-up delays on a construction project and lower project efficiency due to adverse weather earlier in the year. We are currently negotiating with our clients to recover costs related to start-up and weather delays in contracts where these are a shared risk. We are in the process of developing change-order requests for our long-term overburden contact, as is permitted in the contract, to address cost increases and re-align the price escalators with current market standards.

Piling


	Three Months Ended December 31,						Nine Months Ended December 31,
(dollars in thousands)	2010		2009		Change		2010		2009		Change
Segment revenue		$37,594		$20,592		$17,002		$83,303		$50,268		$33,035
Segment profit		$10,324		$4,505		$5,819		$16,500		$9,139		$7,361
Project margin		27.5%		21.9%				19.8%		18.2%

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

For the three and nine months ended December 31, 2010, Piling segment revenues climbed to $37.6 million and $83.3 million respectively, an increase of $17.0 and $33.0 million respectively compared to the same period last year. Revenue increases in both the three and nine month periods were driven by a higher level of activity in the commercial and industrial construction markets, including an increase in high-volume oil sands projects, as well as a full nine months of contribution from our new piling company in Ontario, compared to five months contribution in the prior year. The stronger revenues in the third quarter also reflect the completion of jobs originally delayed by both adverse weather and the late awarding of jobs by customers during the previous quarters. Current year results also include two months of revenue contribution from the Cyntech acquisition, completed on November 1, 2010.

For the three months ended December 31, 2010, Piling profit margin increased to 27.5% of revenue, from 21.9% during the same period last year. This increase reflects the approval and processing of change-orders outstanding from prior periods and improving market conditions. For the nine months ended December 31, 2010, the Piling segment project margin increased to 19.8% from 18.2%, reflecting that the market was still very competitive and increased work availability has not yet translated into higher margins. Low productivity due to abnormally high precipitation levels also impacted margins during the first half of the fiscal year.

Pipeline


	Three Months Ended December 31,								Nine Months Ended December 31,
(dollars in thousands)	2010			2009		Change			2010			2009		Change
Segment revenue		$42,167			$16,952		$25,215			$79,673			$18,616		$61,057
Segment profit		$(1,641	)		$1,072		$(2,713	)		$(1,485	)		$1,301		$(2,786	)
Project margin		-3.9%			6.3%					-1.9%			7.0%

For the three months ended December 31, 2010, the Pipeline segment revenues increased to $42.2 million, an improvement of $25.2 million compared to a year ago. For the nine months ended December 31, 2010, Pipeline segment revenues increased to $79.7 million, a year-over-year increase of $61.1 million. The increased segment revenues primarily reflect activity related to two projects in northern BC, both of which were substantially completed in the three months ended December 31, 2010.

For the three months ended December 31, 2010, the Pipeline segment incurred a loss of $1.6 million compared to segment profit of $1.1 million last year. The change in segment profit reflects reduced productivity on one contract, as well as changes in project scope for a second contract. For the nine months ended December 31, 2010, the Pipeline segment incurred a loss of $1.5 million compared to segment profit of $1.3 million last year. This change reflects productivity impacts related to client start-up delays and adverse weather conditions on the two northern BC projects and project completion delays on a project in southern BC. All three projects are unit-price contracts. We are currently developing change-order requests to present to our clients for start-up delays and significant changes to project scope in accordance with the terms of our contract.

Non-Operating Income and Expense


	Three Months Ended December 31,									Nine Months Ended December 31,
(dollars in thousands)	2010			2009			Change			2010			2009			Change
Interest expense
Long term debt
Interest on 8³/4% senior notes and swaps		$–			$4,517		$	(4,517	)		$1,238			$14,468			$(13,230	)
Interest on series 1 debentures		5,132			–			5,132			14,999			–			14,999
Interest on credit facilities		1,416			893			523			3,680			1,385			2,295
Interest on capital lease obligations		155			244			(89	)		545			805			(260	)
Amortization of deferred financing costs		360			847			(487	)		1,243			2,489			(1,246	)

Interest on long term debt		$7,063			$6,501			$562			$21,705			$19,147			$2,558
Other interest		130			263			(133	)		925			578			347

Total Interest expense		$7,193			$6,764			$429			$22,630			$19,725			$2,905
Foreign exchange gain		(42	)		(5,449	)		5,407			(1,690	)		(42,930	)		41,240
Realized and unrealized (gain) loss on derivative financial instruments		(2,040	)		8,010			(10,050	)		(340	)		43,185			(43,525	)
Loss on debt extinguishment		–			–			–			4,346			–			4,346
Other expense		27			471			(444	)		18			804			(786	)
Income taxes expense		2,374			6,540			(4,166	)		3,857			10,401			(6,544	)

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

Interest expense

Total interest expense increased $0.4 million in the three months ended December 31, 2010 and $2.9 million in the nine months ended December 31, 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. The interest expense of $1.2 million on our 8³/4% senior notes during the current nine-month period reflects interest costs to the redemption date. The interest expense of $15.0 million on our Series 1 Debentures for the nine months ended December 31, 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 refinancing risk in December 2011 and have also eliminated the cost of hedging the foreign currency interest rate, which was reflected as a portion of “realized and unrealized (gain) loss on derivative financial instruments”. Prior-year interest hedge costs were $4.2 million and $11.4 million respectively for the three and nine months ended December 31, 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 entered into a fourth amended and restated credit agreement to extend the term of the credit agreement and to add borrowing capacity of up to $50.0 million through a second term facility within the credit agreement. At December 31, 2010, the second term facility was fully drawn. The new term facility, along with the existing term facility, matures on April 30, 2013. At December 31, 2010, we had $70.9 million outstanding on the combined Term Facilities of $163.4 million ($28.4 million outstanding at March 31, 2010). Interest expense for the credit facility was $1.4 million and $3.7 million for the three and nine months ended December 31, 2010, respectively, reflecting the cost of the higher amounts borrowed on the term facilities.

Foreign exchange gain

The foreign exchange gains recognized in the three and nine month periods ended December 31, 2009, 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 nine-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 long-term customer contracts and in supplier maintenance agreements. The realized and unrealized gains and losses on these derivative financial instruments, for the three and nine months ended December 31, 2010 and 2009, respectively, are detailed in the table below:


	Three Months Ended December 31,									Nine Months Ended December 31,
(dollars in thousands)	2010			2009			Change			2010			2009			Change
Swap liability loss		$–			$3,916		$	(3,916	)		$1,783			$42,733		$	(40,950	)
Redemption option embedded derivative gain		–			(186	)		186			–			(3,598	)		3,598
Supplier contracts embedded derivatives gain		(2,117	)		(254	)		(1,863	)		(2,126	)		(13,958	)		11,832
Customer contract embedded derivative loss
(gain)		77			342			(265	)		(325	)		6,615			(6,940	)
Swap interest payment		–			4,192			(4,192	)		328			11,393			(11,065	)

Total	$	(2,040	)		$8,010		$	(10,050	)		$(340	)		$43,185		$	(43,525	)

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

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

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 long-term supplier contracts decreased as a result of the strengthening of the Canadian dollar against the US dollar during the three months ended December 31, 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.

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 swap interest payment loss for the nine months ended December 31, 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 were exposed to interest rate and foreign currency risk.

Income tax expense

For the three months ended December 31, 2010, we recorded current income taxes of nil and deferred income tax of $2.4 million for a total income tax expense of $2.4 million. This represents a $4.2 million decrease in total income tax expense compared to the same period last year. For the three months ended December 31, 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 an 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 December 31, 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 nine months ended December 31, 2010, we recorded current income taxes of $4.4 million and a deferred income tax recovery of $0.5 million for a total income tax expense of $3.9 million, representing a $6.5 million reduction year-over-year. For the nine months ended December 31, 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 a capital loss on the 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 nine months ended December 31, 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 construction contracts performed under master services agreements where scope is not clearly defined. For the three and nine months ended December 31, 2010, the total amount of revenue earned from time-and-material contracts performed under our master services agreements was approximately $61.1 million and $206.9, respectively.

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

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

By Segment


(dollars in thousands)	December 31, 2010		March 31, 2010		December 31, 2009
Heavy Construction & Mining		$694,867		$800,751		$791,479
Piling		12,435		16,423		9,091
Pipeline		5,294		6,861		14,763

Total		$712,596		$824,035		$815,333


By Contract Type
	December 31, 2010		March 31, 2010		December 31, 2009
Unit-Price		$693,102		$797,694		$795,724
Lump-Sum		16,921		18,429		9,102
Time-and-Material, Cost-Plus		2,573		7,912		10,507

Total		$712,596		$824,035		$815,333

A contract with a single customer represented approximately $655.3 million of our December 31, 2010 backlog compared to $754.5 million reported as backlog in our interim Management’s Discussion and Analysis for the three and nine months ended December 31, 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 $218.2 million of total backlog will be performed and realized in the twelve months ending December 31, 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.

For the three and nine months ended December 31, 2010, due to the timing of receipt of signed change-orders, the Heavy Construction and Mining segment had approximately $0.3 million and $1.0 million respectively in claims revenue recognized to the extent of costs incurred, the Piling segment had $0.5 million and $2.3 million respectively in claims revenue recognized to the extent of costs incurred, and the Pipeline segment had $nil and $0.1 million respectively in claims revenue recognized to the extent of costs incurred. We are working with our customers to come to a resolution on additional amounts, if any, to be paid to us in respect of these additional costs.

^¿	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.

Summary of Consolidated Quarterly Results


	Three month period ended
(dollars in millions, except per share amounts)	Dec 31, 2010		Sep 30, 2010		Jun 30, 2010			Mar 31, 2010			Dec 31, 2009		Sep 30, 2009		Jun 30, 2009		Mar 31, 2009
	Fiscal 2011				Fiscal 2010										Fiscal 2009
Revenue		$265.1		$234.9		$183.6			$220.6			$221.2		$170.7		$146.5		$174.7
Gross profit		30.8		29.1		15.6			32.7			47.6		33.8		25.1		32.9
Operating income (loss)		11.3		12.3		1.1			13.1			31.3		18.9		10.1		(129.2	)
Net income (loss)		3.7		2.4		(10.3	)		(0.9	)		14.9		4.3		9.9		(137.1	)
Income (loss) per share – basic		$0.10		$0.07		$(0.29	)		$(0.03	)		$0.41		$0.12		$0.28		$(3.80	)
Income (loss) per share – diluted		$0.10		$0.06		$(0.29	)		$(0.03	)		$0.41		$0.12		$0.27		$(3.80	)

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 rendered temporarily incapable of supporting the weight of heavy equipment. The duration of this period, which can vary considerably from year to year, 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 a result, full-year results are not likely to be a direct multiple or combination of a quarter or quarters. 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, in the past two fiscal years Pipeline segment revenues were as low as $0.1 million in the three months ended June 30, 2009 and as high as $42.2 million for the three months ended December 31, 2010. The Heavy Construction and Mining segment experienced reduced volumes in 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 periods reflect the ramp up of overburden removal activities at the Horizon project through the three months ended March 31, 2010, where activity returned to planned activity levels. Changes in demand under our master services agreements with Shell Albian positively affected period-over-period comparatives until the three-month periods ended June 30, September 30 and December 31, 2010. During these more recent periods, activity at Shell Albian declined as Shell went through the process of commissioning the Jackpine mine and concurrently undertook related integration activities at the 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, being spread over higher revenue levels. If activity decreases, these same fixed costs are spread over lower revenue levels. Both 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.

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

Summary of Consolidated Financial Position


(dollars in thousands)	December 31, 2010			March 31, 2010			Change
Cash		$748			$103,005		$	(102,257	)
Current assets (excluding cash)		284,319			209,995			74,324
Current liabilities		(179,723	)		(165,641	)		(14,082	)

Net working capital		$105,344			$147,359			$(42,015	)
Property, plant and equipment		331,680			331,355			325
Total assets		727,093			702,617			24,476
Capital Lease obligations (including current portion)		(9,496	)		(13,393	)		3,897
Total long term financial liabilities		(326,735	)		(327,356	)		621

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 December 31, 2010, net working capital (cash and current assets less current liabilities) was $105.3 million, a decrease of $42.0 million from March 31, 2010.

The cash balance at December 31, 2010 was $102.3 million lower than at March 31, 2010, reflecting the Cyntech acquisition ($20.8 million), redemption of the 8³/4% senior notes and associated cross-currency and interest rate swaps ($26.5 million), scheduled principal repayments on our term facilities ($7.5 million), the purchase of equipment and intangible assets ($30.1 million), a Series 1 Debenture coupon payment ($10.3 million) and an increase in working capital. This was partially offset by a cash inflow from operations. During the three months ended December 31, 2010, we borrowed against the revolving facility under the terms of our fourth amended and restated credit agreement, reaching a maximum borrowing of $25.0 million. The full balance of the revolving facility was repaid prior to December 31, 2010.

Current assets excluding cash increased $74.3 million between March 31, 2010 and December 31, 2010, reflecting a $49.6 million increase in unbilled revenue and a $19.6 million increase in trade receivables and holdbacks during the nine months ended December 31, 2010. This reflects increases in revenues in the current period, the billing cycle for the Heavy Construction and Mining segment’s construction projects and the Pipeline segment’s projects in northern British Columbia which achieved substantial completion at the end of the current period. Contributing to the increase in unbilled revenue is the contractual cash flow specified in one of our Pipeline contracts and our Heavy Construction and Mining segment’s long-term overburden contract.

Current liabilities increased by $14.1 million between March 31, 2010 and December 31, 2010, reflecting a $30.3 million increase in accounts payable which was partially offset by a $19.7 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 and the interest payment on the Series 1 Debentures in October 2010. The current portion of embedded derivatives in financial instruments decreased by $19.5 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 $8.2 million, which are scheduled to be paid after December 31, 2010, are included in accounts payable as of December 31, 2010.

Property, plant and equipment values were comparable between March 31, 2010 and December 31, 2010. This reflects the capital investment of $27.4 million of equipment purchases and new capital leases during the nine months ended December 31, 2010, offset by equipment disposals of $1.0 million (net book value) and depreciation of $26.8 million.

Total long-term financial liabilities were substantially unchanged between March 31, 2010 and December 31, 2010. However, the make-up of our long-term financial liabilities were significantly changed due largely to our debt restructuring, described in more detail in “Liquidity and Capital Resources – Long-term debt restructuring”.

Summary of Consolidated Cash Flows


	Three Months Ended December 31,									Nine Months Ended December 31,
(dollars in thousands)	2010			2009			Change			2010			2009			Change
Cash (used in) provided by operating activities	$	(26,620	)	$	10,384		$	(37,004	)		$(14,028	)		$26,392		$	(40,420	)
Cash used in investing activities		(25,441	)		(8,690	)		(16,751	)		(50,896	)		(54,299	)		3,403
Cash (used in) provided by financing activities		(3,344	)		(4,308	)		964			(37,306	)		23,904			(61,210	)
Foreign currency translation loss on cash		(27	)		–			(27	)		(27	)		–			(27	)

Net decrease in cash and cash equivalents	$	(55,432	)		$(2,614	)	$	(52,818	)		$(102,257	)		$(4,003	)	$	(98,254	)

Operating activities

Cash provided by operating activities for the three months ended December 31, 2010 was an outflow of $26.6 million, a decrease of $37.0 million from the cash inflow for the three months ended December 31, 2009, primarily a result of lower gross profit and increased non-cash working capital this year.

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

Cash provided by operating activities for the nine months ended December 31, 2010 was an outflow of $14.0 million, a decrease of $40.4 million from the cash inflow during the same period last year, also primarily a result of lower gross profit and increased non-cash working capital this year.

Investing activities

Cash used in investing activities for the three months ended December 31, 2010 was $25.4 million, an increase of $16.8 million from the same period a year ago. Investing activities in the current period included capital expenditures of $10.6 million, as well as the $20.8 million cash consideration paid for the Cyntech acquisition in the Piling segment. Cash used in investing activities last year included capital expenditures of $3.5 million.

Cash used in investing activities for the nine months ended December 31, 2010 was $50.9 million, a decrease of $3.4 million from the same period a year ago. Current period investing activities included capital expenditures of $27.4 million and the Cyntech acquisition. Cash used in investing activities for the same period in the prior year included capital expenditures of $46.0 million and an outflow for the settlement of the Piling segment’s Drillco acquisition of $5.4 million.

Financing activities

Cash used in financing activities during the three months ended December 31, 2010 was $3.3 million, a $1.0 million reduction from that used in the three months ended December 31, 2009. Both period outflows include scheduled repayments on our term credit facilities and capital lease obligations.

Cash used in financing activities during the nine months ended December 31, 2010 was $37.3 million, a $61.2 million decrease from the cash inflow for the nine months ended December 31, 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 nine-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.

Foreign currency translation loss on cash

During the three months ended December 31, 2010, we established a US-based subsidiary, “Cyntech U.S. Inc.”⁶, which has a US dollar functional currency. The accounts of this subsidiary are translated into Canadian dollars using the current rate method. Assets and liabilities are translated at the rate of exchange in effect at the balance sheet date and revenue and expense items (including depreciation and amortization) are translated at the average rate of exchange for the period. The resulting unrealized exchange gains and losses from these translation adjustments are included as a separate component of shareholders’ equity in Accumulated Other Comprehensive Income (Loss). The effect of exchange rate changes on cash balances held in foreign currencies is separately reported as part of the reconciliation of the change in cash and cash equivalents for the period. This effect was not material for the three and nine months ended December 31, 2010.

C. Outlook

While improving economic conditions and increased opportunities are starting to provide relief from the competitive margin pressure experienced over the past 12 to 18 months, we expect that revenue growth will continue to outpace margin growth in the near term. Longer term, our outlook continues to improve as a result of growing demand and recent contract wins.¿

In our Heavy Construction and Mining segment, we have recently secured two new multi-year master services agreements with key oil sands producers and we are awaiting results on a third large tender. The new contracts include a three-year muskeg removal agreement with Shell Canada and a four-year master services agreement with Syncrude, replacing our previous master services agreement with this customer that expired in November 2010. The agreement with Shell is a time and materials contract and is in addition to our existing three-year master services contract with this customer.¿

While work on our existing long-term overburden removal contract with Canadian Natural could be temporarily affected by a fire that damaged the Horizon Mine’s upgrader, we understand that our client’s preliminary damage assessment suggests that the impact on us is expected to be minimal. To-date, there has been no request for a slowdown in production however, should a production adjustment be required, we believe that some equipment can be profitably redeployed to other customers’ sites to lessen the impact. Overall, we expect to undertake a growing volume of recurring services work through the fourth quarter and into fiscal 2012.¿

⁶

We acquired the assets of Cyntech Corporation, a private Alberta-based company and Cyntech Anchor Systems LLC, its US based subsidiary, (collectively Cyntech) as at November 1, 2010. To facilitate the acquisition of Cyntech’s assets, we established two Canadian subsidiaries: Cyntech Canada Inc.; and Cyntech Services Inc.; and one US subsidiary, Cyntech U.S. Inc.

^¿	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 15

Higher oil prices and a renewed commitment to development in the Alberta oil sands by oil sands producers continue to support a positive outlook for oil sands capital projects. Syncrude has recently announced capital spending plans that include an investment of $480 million in tailings management, four mine train relocations to be completed by 2014 and further development of the Aurora South mine. Suncor also recently announced 2011 capital plans that include an investment of $670 million in tailings management, as well as a new partnership with Total⁷ to develop the Fort Hills mine, Voyageur upgrader and the Joslyn mine. These and other developments are expected to translate into additional project tendering opportunities for us during the next fiscal year.¿

In the Piling segment, activity levels are expected to be moderate in the fourth quarter, however, the longer-term outlook remains positive. Improving conditions in the commercial and industrial construction markets, growing opportunities in the oil sands and the recent acquisition of Cyntech are expected to generate new opportunities. In particular, the innovative screw pile technology acquired through Cyntech will enhance our ability to access SAGD oil sands projects.¿

In the Pipeline division, fourth quarter activity is expected to be minimal and we expect to be focused on negotiating the settlement of change orders and evaluating and bidding some significant pipeline work which has recently been put out to tender. While some improvement in market demand is anticipated during fiscal 2012, conditions in this market remain challenging.¿

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 December 31, 2010, we had 527 salaried employees and approximately 2,600 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 3,000 employees depending on the time of year and duration of awarded projects. We also utilize the services of subcontractors in our construction business. An estimated 8% to 10% of the construction work we do is performed by subcontractors. Approximately 2,300 employees are members of various unions and work under collective bargaining agreements. The majority of our work is done through employees governed by our mining overburden collective bargaining agreement with the International Union of Operating Engineers Local 955, the primary term of which expires on March 31, 2015. 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, 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 the International Union of Operating Engineers (IUOE) Local 955 and the Alberta Roadbuilders and Heavy Construction Association expires February 28, 2011. Management expects that 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 January 28, 2011, there were 36,213,966 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.

⁷	Total E&P Canada Ltd. (Total), a wholly owned subsidiary of Total SA.

^¿	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.

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 $40 million and $60 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.¿

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 (42%), leased (44%) and rented (14%) equipment. Approximately 35% 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 increases in our rental fleet. The increased demand for certain sizes of heavy equipment is reflective of the change in work mix experienced by our Heavy Construction and Mining segment and the increased volumes experienced by our Pipeline segment. 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 2012.¿

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.

^¿	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

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”.

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 December 31, 2010, we had $10.0 million in letters of credit outstanding in connection with this contract (we had $12.3 million in letters of credit outstanding in total for all customers as of December 31, 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 December 31, 2010, the credit facility includes the $85.0 million Revolving Facility and the outstanding borrowings of $70.9 million (March 31, 2010 – $28.4 million) under the Term Facilities, after the scheduled principal payments of $2.5 million in the quarter.

As at December 31, 2010, we had $9.9 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 $0.1 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.

Borrowing activity under the Revolving Facility

During the three months ended December 31, 2010, we used our revolving facility to finance our working capital requirements. At December 31, 2010, we had no borrowings drawn on our revolving facility. For the three months ended December 31, 2010, the weighted average amount of our borrowing on the revolving facility was $8.2 million with a weighted average interest rate of 6.5%. The weighted average amount of our borrowing on the revolving facility is calculated based on the weighted average of the outstanding balances in the three month period. The maximum end of month balance for any single month during the three months ended December 31, 2010 was $10.0 million.

As of December 31, 2010, we had issued $12.3 million (March 31, 2010 – $10.4 million) in letters of credit under the Revolving Facility to support performance guarantees associated with customer contracts. As at December 31, 2010, our unused borrowing availability under the Revolving Facility was $72.7 million.

Working capital fluctuations effect on cash

The seasonality of our business usually causes a higher accounts receivable balance and a peak in activity levels between December and early February, which can 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 provided that substantial completion of the contract has been 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 December 31, 2010, holdbacks totaled $20.7 million, up from $3.9 million as at March 31, 2010. Holdbacks represent 15.7% of our total accounts receivable as at December 31, 2010 (3.5% as at March 31, 2010).

Cash requirements

As at December 31, 2010, our cash balance of $0.8 million was $102.3 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. The reduction in the cash balance also reflects the Cyntech acquisition, capital expenditures and the impact of increased working capital

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

balances. We anticipate that we will have generated a net cash surplus from operations for the year ended 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 (as defined in the amended and restated credit agreement) and interest on advances of Bankers’ Acceptances (as defined in the amended and restated credit agreement) are paid in advance, at the time of issuance.

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. We are in compliance with these covenants.

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.

^¿	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 19

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”).

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 December 31,							Nine Months Ended December 31,
(dollars in thousands)	2010		2009		Change			2010		2009		Change
Capital Expenditures
Sustaining		$2,421		$2,626		$(205	)		13,769		$8,821		$4,948
Growth		$10,232		2,148		8,084			17,685		42,372		(24,687	)

Total		12,653		4,774		7,879			31,454		51,193		(19,739	)
Capital Leases
Sustaining		–		449		(449	)		–		449		(449	)
Growth		44		–		44			91		656		(565	)

Total		44		449		(405	)		91		1,105		(1,014	)
Total sustaining capital additions		2,421		3,075		(654	)		13,769		9,270		4,499
Total growth capital additions		10,276		2,148		8,128			17,776		43,028		(25,252	)
Operating Leases		7,179		28,669		(21,490	)		14,124		59,341		(45,217	)

The increase in sustaining capital additions for the nine months ended December 31, 2010, compared to the same period in the prior year, is reflective of increased capital maintenance activity due to higher equipment hours. The lower amount of spending for the three months ended December 31, 2010 reflects the timing of the capital maintenance activity, conducted earlier in the current year.

The reduction in growth capital additions for the nine months ended December 31, 2010, compared to the same period in the prior year, reflects the impact of fewer major customer development projects as a result of the economic slowdown experienced in fiscal 2010. Included in the growth capital additions for the three months ended December 31, 2010 is $1.3 million related to the Cyntech acquisition. Excluding the Cyntech acquisition, the year-over-year increase for

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

the three month period reflects the timing of planned purchases through the current year. With the renewed commitment to Alberta oil sands development by the oil sands producers, we are assessing our growth capital needs for the coming fiscal year. In the interim, we have increased the size of our rental fleet to meet the equipment demands from the increase in development work in the current year.

The decrease in operating leases, for the three and nine months ended December 31, 2010, compared to the same periods in the previous year, reflects the timing of scheduled equipment additions related to the Canadian Natural overburden project.

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 December 31, 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		70,946		2,500		10,000		14,000		44,446		–
Capital leases (including interest)		10,094		1,178		5,231		3,009		484		192
Equipment and building operating leases		175,386		17,363		62,868		44,113		31,220		19,822
Supplier contracts		48,501		3,962		14,997		14,997		12,072		2,473

Total contractual obligations		$529,927		$25,003		$93,096		$76,119		$88,222		$247,487

Off-balance sheet arrangements

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

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 December 2010, respectively. Both agencies also provided a rating for our new Series 1 Debentures in April 2010.

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.⁸

⁸	This information is current as of this report and we undertake no obligation to provide investors with updated information.

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

Standard and Poor’s

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

A recovery rating of “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.

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 December 31, 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 December 31, 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.

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

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 nine months ended December 31, 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 December 31, 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, which was current as of June 10, 2010.

Significant Accounting Policies

For a full discussion on significant accounting policies please see our most recent annual Management’s Discussion and Analysis, which was current as of June 10, 2010.

Financial instruments

The following discussion is intended to provide a clarification to the disclosure previously discussed in “Significant Accounting Policies – Financial Instruments” in our most recent annual Management’s Discussion and Analysis, which was current as of June 10, 2010. In determining the fair value of financial instruments, we use 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 our financial instruments, including derivatives. All methods of fair value measurement result in a general approximation of value and such value may never actually be realized.

We use derivative financial instruments to manage financial risks from fluctuations in exchange rates, interest rates and inflation. These instruments include embedded price escalation features in revenue and supplier contracts. In developing such escalators we rely on industry standards, historical data and management’s experience. We use these price escalation features for risk management purposes only. We do not hold or issue derivative financial instruments for trading or speculative purposes. Derivative financial instruments are subject to standard credit terms and conditions, financial controls, management and risk monitoring procedures. These derivative financial instruments are not designated as hedges for accounting purposes and are recorded at fair value with realized and unrealized gains and losses recognized in the Consolidated Statement of Operations, Comprehensive Income (Loss) and Deficit.

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.

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.

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

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.

Intangibles – Goodwill and Other

In December 2010, the FASB issued ASU No. 2010-28, “When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts”, which amends ASC 350, “Intangibles-Goodwill and Other” to modify step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts, to require an entity to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that impairment may exist. This ASU is effective for our fiscal year and interim periods beginning April 1, 2011. Early adoption is not permitted. The amendments in this ASU will have no material effect on our consolidated financial statements.

Business Combinations

In December 2010, the FASB issued ASU No. 2010-29, “Disclosure of Supplementary Pro Forma Information for Business Combinations”, which amends ASC 805, “Business Combinations”, to require that pro-forma information be presented as if the business combination occurred at the beginning of the prior annual reporting period for the purposes of calculating both the current reporting period and the prior reporting period pro forma financial information. The ASU also requires the disclosure be accompanied by a narrative description of the nature and amount of material, nonrecurring pro forma adjustments. This ASU is effective prospectively for our business combinations for which the acquisition date is on or after April 1, 2011. Early adoption is permitted. This standard will impact disclosures made for our business combinations completed after the effective date.

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;

(b)	that revenue growth will continue to outpace margin growth in the near term;

(c)	that the work scope under the agreement with Shell could be increased;.

(d)	that the impact of the fire that damaged the Horizon Mine upgrader will be minimal;

(e)	that we will be able to profitably redeploy equipment to other customers’ sites if a production adjustment is required;

(f)	our expectation to undertake a growing volume of recurring services work;

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

(g)	that oil sands project developments will translate into more project tendering opportunities for us during the next fiscal year;

(h)	that activities in the Piling segment will be moderate in the four quarter and positive in the longer-term;

(i)	that improving conditions in the commercial and industrial construction markets, growing opportunities in the oil sands and the recent acquisition of Cyntech will generate new opportunities;

(j)	that the innovative screw pile technology acquired through Cyntech will enhance our ability to access SAGD oil sands projects;

(k)	that activities in the Pipeline division will be minimal in the fourth quarter although some improvement in market demand is anticipated during fiscal 2012;

(l)	that a settlement with IUOE Local 955 and the Alberta Roadbuilders and Heavy Construction Association will be reached without disruption;

(m)	that capital needs in the current fiscal year will be approximately $50 million to $75 million;

(n)	that our operating and capital lease facilities and cash flow from operations will be sufficient to meet corresponding capital requirement needs;

(o)	that we will have sufficient lease capacity to meet capital requirements in fiscal 2012; and

(p)	that we will generate a net cash surplus from operations for the year ended March 31, 2011 and if additional funding is required, this would be satisfied by the funds available from our credit facilities.

Assumptions

The material factors or assumptions used to develop the above forward-looking statements include, but are not limited to:

_Ÿ

demand for recurring services remaining strong;

_Ÿ

the oil sands continuing to be an economically viable source of energy;

_Ÿ

our customers and potential customers continuing to invest in the oil sands and other natural resource developments and to outsource activities for which we are capable of providing services;

_Ÿ

our client has accurately gauged the impact of the Horizon Mine upgrader fire;

_Ÿ

the Western Canadian economy continuing to develop and to receive additional investment in public construction;

_Ÿ

our ability to benefit from increased recurring revenue base tied to the operational activities of the oil sands;

_Ÿ

our ability to access sufficient funds to finance our capital growth; and

_Ÿ

our success in executing our growth strategy, managing our business, maintaining and growing our relationships with customers, retaining new customers, integrating our acquisitions, competing in the bidding process to secure new projects and identifying and implementing improvements in our maintenance and fleet management practices.

Risks

The risks and uncertainties that could cause actual results to differ materially from the information presented in the above forward-looking statements include, but are not limited to, the following:

_Ÿ

anticipated new major capital projects in the oil sands not materializing;

_Ÿ

our customers failing to obtain required permits and licenses;

_Ÿ

customers changing their views on oil prices over the long-term causing them to defer, reduce or stop capital investment in oil sands projects;

_Ÿ

customers choosing not to invest in infrastructure projects as a result of reduced financing or a tightening of the credit markets;

_Ÿ

customers delaying, reducing or cancelling plans to construct new oil sands projects or expand existing projects because of insufficient pipeline, upgrading and refining capacity or insufficient governmental infrastructure to support growth in the oil sands region;

_Ÿ

customers changing strategy and reducing outsourcing; customers incurring cost overruns and terminating future projects or expansions;

_Ÿ

unanticipated short-term shutdowns of our customers’ operating facilities resulting in temporary cessation or cancellation of projects in which we are participating;

_Ÿ

the Canadian energy industry undergoing a further economic downturn;

_Ÿ

a shortage of qualified personnel or significant labour disputes;

_Ÿ

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

_Ÿ

tightening of lease financing which would negatively impact our ability to lease equipment and bid for new work and/or supply some or our existing contracts;

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

_Ÿ

failing to obtain surety bonds or letters of credit required by some of our customers;

_Ÿ

failing to successfully integrate Cyntech in order to realize the full potential of its service offerings; competitors outbidding us on major projects;

_Ÿ

losing or receiving less business from a major customer in our concentrated customer base;

_Ÿ

losses from lump-sum or unit-price contracts when our estimates of project costs are lower than actual costs;

_Ÿ

our cost of input being greater than such costs contemplated by the fixed or indexed price escalators in longer-term contracts;

_Ÿ

weather-related factors causing delays in operations;

_Ÿ

regulations affecting the energy industry adversely impacting demand for our services; and

_Ÿ

environmental laws and regulations exposing us to liabilities arising out of our operations or the operations of our customers.

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

Business Risk Factors

For the three and nine months ended December 31, 2010, we have become aware of potential increases to the order lead time for certain types of large mining equipment. We have also been made aware by our tire suppliers that they are projecting significant increases in demand for certain sizes and specifications of large mining equipment tires over the next two years. Our tire suppliers are cautioning their customers that their current tire manufacturing capacity may not be sufficient to meet this anticipated increase in demand. We are actively working with our large mining equipment and tire suppliers to ensure we have a secure and timely supply of large mining equipment and tires to meet both our current demands and the increased demands for our projected operational growth. The potential business impact of increased order lead times on large mining equipment and shortages of tires of the size and specifications we require is described in our most recent annual Management’s Discussion and Analysis, but repeated in this interim Management’s Discussion and Analysis:

Our ability to grow our operations in the future may be hampered by our inability to obtain long lead time equipment and tires, which can be in limited supply during strong economic times.

Our ability to grow our business is, in part, dependent upon obtaining equipment on a timely basis. Due to the long production lead times of suppliers of large mining equipment during strong economic times, we may have to forecast our demand for equipment many months or even years in advance. If we fail to forecast accurately, we could suffer equipment shortages or surpluses, which could have a material adverse impact on our financial condition and results of operations.

In strong economic times, global demand for tires of the size and specifications we require can exceed the available supply. Our inability to procure tires to meet the demands for our existing fleet as well as to meet new demand for our services could have an adverse effect on our ability to grow our business.

As discussed in this Interim Management’s Discussion and Analysis, we have recently entered into two new longer-term contracts. These two new contacts, along with existing longer term contracts have fixed or indexed price escalators that are intended to protect our project margins against inflation. If these contracted price escalators do not accurately reflect increases in our costs, we will experience reduced project margins over the remaining life of these longer-term contracts. The identified business risk is:

Our ability to maintain planned project margins on projects with longer-term contracts with fixed or indexed price escalators may be hampered by the price escalators not accurately reflecting increases in our costs over the life of the contract.

Our ability to maintain planned project margins on longer-term contracts with contracted price escalators is dependent on the contracted price escalators accurately reflecting increases in our costs. If the contracted price escalators do not reflect actual increases in our costs we will experience reduced project margins over the remaining life of these longer-term contracts.

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

In strong economic times, the cost of labour, equipment, materials and sub-contractors is driven by the market demand for these project inputs. The level of increased demand for project inputs may not have been foreseen at the inception of the longer-term contracts with fixed or indexed price escalators resulting in reduced margins over the remaining life of the longer-term contracts. Certain of these price escalators could be considered financial instruments (see “Significant Accounting Policies – Financial Instruments”).

Other than the business risk associated with longer-term contracts and changes to large mining equipment order lead time and the potential shortage of tires of the size and specifications we require, described above, there have been no significant changes in the business 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 December 31, 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 not have a significant 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.

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 December 31, 2010, we held $70.9 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 December 31, 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 December 31, 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.

North American Energy Partners Inc. Management’s Discussion and Analysis 27

NORTH AMERICAN ENERGY PARTNERS INC.

CANADIAN SUPPLEMENT TO:

Interim Management’s Discussion and Analysis

For the three and nine months ended December 31, 2010

LOGO

This document supplements the Interim Management’s Discussion and Analysis for the three and nine months ended December 31, 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 nine months ended December 31, 2010

February 1, 2011

Summary of differences between US GAAP and Canadian GAAP

The interim unaudited consolidated financial statements for the three and nine months ended December 31, 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 nine months ended December 31, 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 nine months ended December 31, 2010 are explained and quantified in note 22 to our interim financial statements for the three and nine months ended December 31, 2010.

The “Consolidated three and nine month results” tables in this supplement highlight the differences between Canadian and US GAAP. The tables in this supplement reporting the “Reconciliation of net income (loss) to EBITDA and Consolidated EBITDA”, “Non-Operating Income and Expense” and “Realized and unrealized (gain) loss on derivative financial instruments” for the three and nine months ended December 31, 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 nine months ended December 31, 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 nine month results


	Three months ended December 31,
(dollars in thousands, except per share information)	2010 (Canadian GAAP)		Adjustments			2010 (US GAAP)		2009 (Canadian GAAP)		Adjustments			2009 (US GAAP)
Revenue (e)		$266,096		$(1,010	)		$265,086		$222,714		$(1,539	)		$221,175
Project costs (e)		149,012		(993	)		148,019		90,322		(1,115	)		89,207
Equipment costs		58,819		–			58,819		57,512		–			57,512
Equipment operating lease expense		16,940		–			16,940		16,287		–			16,287
Depreciation (a)		10,474		27			10,501		10,512		31			10,543

Gross profit		30,851		(44	)		30,807		48,081		(455	)		47,626
General and administrative costs (c) and (e)		16,637		(155	)		16,482		14,847		(315	)		14,532
Operating income		11,325		(71	)		11,254		31,104		168			31,272

Net income		$5,437		$(1,695	)		$3,742		$15,577		$(641	)		$14,936
Per share information
Net income – basic		$0.15		$(0.05	)		$0.10		$0.43		$(0.02	)		$0.41
Net income – diluted		$0.15		$(0.05	)		$0.10		$0.43		$(0.02	)		$0.41
EBITDA		$26,592		$(1,790	)		$24,802		$39,668		$(357	)		$39,311
Consolidated EBITDA (as defined within our credit agreement)		$25,519		$(210	)		$25,309		$43,844		$–			$43,844


	Nine months ended December 31,
(dollars in thousands, except per share information)	2010 (Canadian GAAP)		Adjustments			2010 (US GAAP)			2009 (Canadian GAAP)		Adjustments			2009 (US GAAP)
Revenue (e)		$687,547		$(4,009	)		$683,538			$540,927		$(2,531	)		$538,396
Project costs (e)		361,327		(3,591	)		357,736			210,834		(1,928	)		208,906
Equipment costs		170,180		–			170,180			147,915		–			147,915
Equipment operating lease expense		53,340		–			53,340			44,320		–			44,320
Depreciation (a)		26,675		83			26,758			30,600		93			30,693

Gross profit		76,025		(501	)		75,524			107,258		(696	)		106,562
General and administrative costs (c) and (e)		45,303		194			45,497			43,928		(502	)		43,426
Operating income		25,668		(1,045	)		24,623			59,852		495			60,347

Net income (loss)		$3,755		$(7,953	)		$(4,198	)		$32,138		$(2,976	)		$29,162
Per share information
Net income (loss) – basic		$0.10		$(0.22	)		$(0.12	)		$0.89		$(0.08	)		$0.81
Net income (loss) – diluted		$0.10		$(0.22	)		$(0.12	)		$0.87		$(0.08	)		$0.79
EBITDA		$60,301		$(9,002	)		$51,299			$93,724		$(2,305	)		$91,419
Consolidated EBITDA (as defined within our credit agreement)		$61,550		$(1,453	)		$60,097			$95,216		$–			$95,216

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 December 31,
(dollars in thousands)	2010			2009			Change
Net income		$5,437			$15,577			$(10,140	)
Adjustments:
Interest expense		6,922			6,127			795
Income tax expense		2,590			6,714			(4,124	)
Depreciation		10,474			10,512			(38	)
Amortization of intangible assets		1,169			738			431

EBITDA		$26,592			$39,668			$(13,076	)
Adjustments:
Unrealized foreign exchange gain on senior notes		–			(5,074	)		5,074
Realized and unrealized (gain) loss on derivative financial instruments		(3,609	)		7,618			(11,227	)
Loss on disposal of property, plant and equipment and assets held for sale		1,720			1,392			328
Stock-based compensation expense		457			338			119
Loss (earnings) from unconsolidated joint venture		359			(98	)		457

Consolidated EBITDA (as defined within our credit agreement)		$25,519			$43,844			$(18,325	)

	Nine months ended December 31,
(dollars in thousands)	2010			2009			Change
Net income		$3,755			$32,138			$(28,383	)
Adjustments:
Interest expense		21,712			17,885			3,827
Income tax expense		5,381			11,040			(5,659	)
Depreciation		26,675			30,600			(3,925	)
Amortization of intangible assets		2,778			2,061			717

EBITDA		$60,301			$93,724			$(33,423	)
Adjustments:
Unrealized foreign exchange gain on senior notes		–			(42,270	)		42,270
Realized and unrealized (gain) loss on derivative financial instruments		(4,970	)		40,465			(45,435	)
Loss on disposal of property, plant and equipment and assets held for sale		2,276			1,417			859
Stock-based compensation expense		1,628			1,946			(318	)
Loss (earnings) from unconsolidated joint venture		876			(66	)		942
Loss on debt extinguishment		1,439			–			1,439

Consolidated EBITDA (as defined within our credit agreement)		$61,550			$95,216			$(33,666	)

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

Non-Operating Income and Expense (Canadian GAAP)


	Three months ended December 31,
(dollars in thousands)	2010			2009			Change
Interest expense
Interest on 8³/4% senior notes and swaps		$–			$4,517			$(4,517	)
Interest on capital lease obligations		155			244			(89	)
Amortization of deferred financing costs		182			210			(28	)
Amortization of premium on Series 1 debentures		(93	)		–			(93	)
Interest on credit facilities		1,416			893			523
Interest on Series 1 Debentures		5,132			–			5,132

Interest on long term debt		$6,792			$5,864			$928
Other interest		130			263			(133	)

Total interest expense		$6,922			$6,127			795
Foreign exchange gain		(42	)		(5,403	)		5,361
Realized and unrealized (gain) loss on derivative financial instruments		(3,609	)		7,618			(11,227	)
Other expense		27			471			(444	)
Income tax expense		2,590			6,714			(4,124	)


	Nine months ended December 31,
(dollars in thousands)	2010			2009			Change
Interest expense
Interest on 8³/4% senior notes and swaps		$1,238			$14,468			$(13,230	)
Interest on capital lease obligations		545			805			(260	)
Amortization of deferred financing costs		599			649			(50	)
Amortization of premium on Series 1 Debentures		(274	)		–			(274	)
Interest on credit facilities		3,680			1,385			2,295
Interest on Series 1 Debentures		14,999			–			14,999

Interest on long term debt		$20,787			$17,307			$3,480
Other interest		925			578			347

Total interest expense		$21,712			$17,885			3,827
Foreign exchange gain		(1,690	)		(42,480	)		40,790
Realized and unrealized (gain) loss on derivative financial instruments		(4,970	)		40,465			(45,435	)
Loss on debt extinguishment		1,462			–			1,462
Other expense		18			804			(786	)
Income tax expense		5,381			11,040			(5,659	)

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


	Three months ended December 31,
(dollars in thousands)	2010			2009			Change
Swap liability loss		$–			$3,916			$(3,916	)
Redemption option embedded derivative gain on 8³/4% senior notes		–			(578	)		578
Redemption options embedded derivatives gain on the Series 1 Debentures		(1,569	)		–			(1,569	)
Supplier contracts embedded derivatives gain		(2,117	)		(254	)		(1,863	)
Customer contract embedded derivative loss		77			342			(265	)
Swap interest payment		–			4,192			(4,192	)

Total		$(3,609	)		$7,618			$(11,227	)

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


	Nine months ended December 31,
(dollars in thousands)	2010			2009			Change
Swap liability loss		$1,783			$42,733			$(40,950	)
Redemption option embedded derivative gain on 8³/4% senior notes		–			(6,318	)		6,318
Redemption options embedded derivatives gain on the Series 1 Debentures		(4,630	)		–			(4,630	)
Supplier contracts embedded derivatives gain		(2,126	)		(13,958	)		11,832
Customer contract embedded derivative (gain) loss		(325	)		6,615			(6,940	)
Swap interest payment		328			11,393			(11,065	)

Total		$(4,970	)		$40,465			$(45,435	)

Summary of Consolidated Quarterly Results (Canadian GAAP)


	Dec 31, 2010		Sept 30, 2010		June 30, 2010			March 31, 2010			Dec 31, 2009		Sept 30, 2009		June 30, 2009		March 31, 2009
(dollars in millions)	Fiscal 2011				Fiscal 2010										Fiscal 2009
Revenue		$266.1		$235.7		$185.8			$222.4			$222.7		$171.1		$147.1		$174.7
Gross profit		30.9		29.3		15.8			32.9			48.1		33.7		25.5		33.0
Operating income (loss)		11.3		13.4		0.9			13.0			31.1		18.8		10.0		(129.3	)
Net income (loss)		5.4		5.6		(7.3	)		(3.0	)		15.6		6.5		10.1		(136.7	)
Net income (loss) per share – Basic		$0.15		$0.16		$(0.20	)		$(0.08	)		$0.43		$0.18		$0.28		$(3.79	)
Net income (loss) per share – Diluted		0.15		0.15		(0.20	)		(0.08	)		$0.43		$0.18		$0.28		$(3.79	)

Canadian and United States accounting policies differences

A detailed reconciliation of our results for the three and nine months ended December 31, 2010 is included in note 22 to our interim consolidated financial statements for the three and nine months ended December 31, 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 nine months ended December 31, 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 facilities using the effective interest method. We disclose the unamortized deferred financing costs related to the

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

Series 1 Debentures, the 8³/4% senior notes and the credit facilities as “Deferred financing costs” (December 31, 2010 – $8.0 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 (December 31, 2010 – $6.4 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 (December 31, 2010 – $1.6 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 December 31, 2010, the liability under US GAAP was measured at $5.4 million of which $2.2 million was transferred from additional paid-in capital and the difference of $3.2 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 $3.9 million resulting in a transfer of the same amount from additional paid-in capital and the difference of $1.7 million was recognized as incremental compensation cost.

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 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.

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

f) Other matters

Management’s Discussion and Analysis under US GAAP

Please refer to our interim consolidated financial statements for the three and nine months ended December 31, 2010 and our accompanying MD&A under US GAAP, filed February 1, 2011. 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 nine months ended December 31, 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

FULL CERTIFICATE

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 December 31, 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

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

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

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 description of the material weakness;

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

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 October 1, 2010 and ended on December 31, 2010 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: February 1, 2011

/s/ Rodney J. Ruston

Chief Executive Officer

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

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 December 31, 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

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

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.

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 description of the material weakness;

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

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 October 1, 2010 and ended on December 31, 2010 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: February 1, 2011

/s/ David Blackley

Chief Financial Officer